RENEWABLES
PORTFOLIO
STANDARD
2009 SOLICITATION
BIDDERS CONFERENCE
July 21, 2009
Agenda
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Introduction
Commercial Overview
Shortlisting Evaluation Methodology
Transmission Ranking Costs
Interconnection Process
Solicitation Documents
Q&A
1
Document Conflicts

This presentation is intended to be a summary level
discussion of the information and requirements established in
the RFO materials (it does not include all of the detailed
information in the RFO Materials)

To the extent that there are any inconsistencies between the
information provided in this presentation and the
requirements in the RFO Materials, the RFO Materials shall
govern
2
Commercial Overview
3
RFO Schedule
DATE
EVENT
July 21, 2009
Bidders Conference
1st week of August
Bidder workshop via Web – forms, Q&A
August 24, 2009
10 a.m.
Deadline to submit and receive Offer(s)
October 28, 2009
Shortlist notification
November 6,
2009
Offer deposits due from shortlisted bidders
November 23,
2009
PG&E submits Shortlist to PRG and CPUC
TBD
CPUC issues Market Price Referent (“MPR”)
By June 30, 2009 Negotiate and execute Agreements; PG&E
submits Agreements for Regulatory Approval
See Section II of the Solicitation Protocol
4
Independent Evaluator

Primary role of the IE is to:



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Monitor RFO processes to ensure fair and equal treatment of all
potential counterparties
Monitor evaluation processes to ensure PG&E has implemented
methodology as described and that bids are treated consistently
Ensure utility ownership and PPA offers are treated consistently
Report on proposed transactions to CPUC when filed for CPUC
approval
The IE performs an independent review of all proposals
The IE may review all proposal data and monitor all
negotiations
2009 IE is Arroyo Seco Consulting (Lewis Hashimoto)
5
New for 2009

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Sellers may offer joint development/ownership project
PG&E as Scheduling Coordinator for projects in CAISO control area
Substantially modified PPA to streamline negotiations
Expedited approval process for PPAs up to 4 years in length that
meet certain criteria
Changes to credit and collateral



Increased project development security and “capped” damages
Reduced delivery term security
Use of Project Viability Calculator to score offers
6
Eligible RPS offers
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Eligible resources
 All eligible renewable resources as determined by CEC
Target volumes---1-2% of bundled sales (800-1600 GWh)
Products
 As-Available
 Baseload
 Dispatchable
Delivery term
 Seller may bid delivery term of one month up to 20 years or more
Project location & delivery point
 Delivery points in CAISO control area
 Delivery points outside CAISO control area; Seller to provide
price for delivery to CAISO
7
Eligible Offer Structures
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Power Purchase Agreement (PPA)
PPA with Buyout Option
Turnkey Ownership - Participants may propose
to develop, permit, and construct a facility for
purchase by PG&E upon commercial operation
Joint Development/Ownership
Site Offers

For development or expansion by PG&E
See Section III and Attachments I and J of the Solicitation Protocol
8
Power Purchase Agreement (PPA)
Offer Variations


Up to six discrete Offers for a PPA for each Project. Offers may vary
by:
 Size
 Commercial Operation Date
 Delivery Term
 Generation Profile
 Credit Terms
Pricing variations
 With and without PTC/ITC/other financing
 If not already in price, premium for delivery to CAISO
See Section VIII of the Solicitation Protocol
9
PPA Contracts


One form (Attachment H) for most PPAs (asavailable, baseload, dispatchable)
Confirm to EEI Master Agreement for short-term
contracts up to 4 years (Attachment N)
10
PPA Key Commercial Terms
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Contract Price is $/MWh (all-in) for all products except:
 Dispatchable - $/kW-year for capacity, $/MWh for energy
 Seller receives Contract Price as adjusted by TOD Factors
Delivery Point is PNode for those projects delivering energy onto the
CAISO system
Minimum performance criteria apply to all products
Certain non-modifiable terms (highlighted in form PPA)
PG&E is Scheduling Coordinator for projects in CAISO control area
Seller commitment to construction start date and commercial
operation date; Provisions for excused delay for force majeure,
transmission and permitting
See Attachments H and N of the Solicitation Protocol
11
Time of Delivery (TOD) Factors
Monthly Period
Jun – Sep
Oct.- Dec., Jan. & Feb.
Mar. – May

Night
0.69
0.76
0.64
Payment = Contract Price * TOD Factor * MWh
Baseload, Peaking


Shoulder
1.12
0.93
0.85
As-Available


Super-Peak
2.20
1.06
1.15
Payment = Contract Price * TOD Factor * MWh
 Reductions for not meeting minimum performance
Short-term ERRs may price without TOD
See Section IX of the Solicitation Protocol
12
Key Changes to 2009 Form PPA

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PPA designed to require minimal negotiation
Excused delays in construction start and commercial operation for
force majeure, permitting and transmission


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
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Force majeure no longer an event of default
Guaranteed Energy Production (GEP): PPA specifies minimum
delivery amount



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360 days for force majeure and permitting
540 days for transmission
Cumulative delays not to exceed 540 days
80% of contract quantity for solar
90% of contract quantity for baseload
P-95 for wind
Shortfalls in GEP can be “cured” with higher generation the following
year or payment to PG&E
13
Key Changes to 2009 PPA (cont’d)

PG&E as Scheduling Coordinator (SC) for projects in
CAISO control area



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Seller responsible for providing meteorological and project
availability data PG&E needs to act as SC
PG&E to use data to forecast for intermittent resources and
to schedule generation for all resources
As-available projects eligible for CAISO’s Eligible
Intermittent Resource (EIRP) program must become EIRP
certified and remain eligible for duration of the Delivery
Term. PG&E will use EIRP as needed
PG&E bears imbalance risk as long as Seller provides data
Seller subject to forecasting penalty if data not provided
14
Short-Term PPA Key Commercial
Terms

Contract Price is $/MWh (all-in)

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Price may be fixed $/MWh or
Index price (e.g. NP15, COB) + $/MWh adjustment
Seller may propose price with or without TOD factors
No bid deposit or exclusive negotiations required
Relaxed performance requirements
Sellers in CAISO control area to use Attachment H; See
Attachment N for alternate provisions for Sellers outside
CAISO control area
See Attachment H and N of the Solicitation Protocol
15
Expedited Approval Process (CPUC
D.09-06-050)


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Establishes price benchmarks and expedited contract review and
approval process
CPUC approval process for PPAs up to 4 years
 Tier 2 Advice Letter Process
 CPUC approval effective in 30 days from advice letter filing
unless suspended by CPUC staff
Facility must be in commerical operation or in commercial
operation within 6 months of PPA execution
PPA price(including firming and shaping) does not exceed:
 – 150% of forward price for a same term, non-renewable energy
contract and
 – 90% of the MPR for a contract of 10 years
PPA must be based on approved pro-forma contracts with only
“minor modifications”
16
Credit



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Offer Deposit of $3/kW upon Shortlisting
Initial Project Development Security of $15/kW upon contract
execution
Following CPUC Approval, Project Development Security of $100/kW
* capacity factor (minimum of $50/kW)
Upon commercial operation, Delivery Term Security:
Term
Months Revenue at Minimum
Expected Revenue (GEP)


10
15
years years
6
9
20
years
12
Offer Deposit and Project Development Security – cash or Letter of
Credit
Delivery Term Security – cash, Letter of Credit, or acceptable
guaranty
See Sections V and VII of the Solicitation Protocol
17
Delivery Term Security Example
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Contract Price = $90/MWh
Post-TOD average price = $95/MWh
Contract Quantity = 100 GWh/year
GEP = 80% of Contract Quantity = 80 GWh year
Result
Minimum expected annual revenue:
$95/MWh * 80 GWh = $7.6 million
DTS: 20 year contract = $7.6 million
DTS: 10 year contract = $3.8 million
18
Credit—Short Term Offers
Term
New ERRs
Existing ERRs
Less than 1 year
Project Development Security: None
Delivery Term Security: None
Pre-Delivery Term Security: None
Delivery Term Security: None
One year or greater, but less than 5
years
Project Development Security:
$25/kW
Delivery Term Security: 2 months
minimum expected revenue
Pre-Delivery Term Security: $3/kW
Delivery Term Security: 2 months
minimum expected revenue
5 years
Project Development Security:
$50/kW
Delivery Term Security: 3 months
minimum expected revenue
Pre-Delivery Term Security: $5/kW
Delivery Term Security: 3 months
minimum expected revenue
Greater than 5 years, but less than 8
years
Project Development Security:
$50/kW Delivery Term Security: 4
months minimum expected
revenue
Pre-Delivery Term Security: $5/kW
Delivery Term Security: 4 months
minimum expected revenue
8 years or greater, but less than 10
years
Project Development Security:
$50/kW
Delivery Term Security: 5 months
minimum expected revenue
Pre-Delivery Term Security: $5/kW
Delivery Term Security: 5 months
minimum expected revenue
See Sections XX of the Solicitation Protocol
19
CEC Requirements
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RPS Eligible Renewable Energy Resources (ERR)
must be CEC Certified
 CEC Pre-Certification should be obtained prior to
construction start
ERRs must participate in CEC Generation Tracking
System (WREGIS)
See updated guidebooks at:
http://www.energy.ca.gov/renewables/documents/
See Section IV of the Solicitation Protocol
20
Not Part of RPS Solicitation

Resources less than 1.5 MW

Standard tariff available to all eligible renewable resources



Term up to 20 years
Price set at Market Price Referent




http://www.pge.com/b2b/energysupply/wholesaleelectricsuppliersolicitation/sta
ndardcontractsforpurchase
Based on combined cycle cost
Determined by CPUC on an annual basis
Levelized price depends on contract term and online date
PG&E’s Proposed 500 MW PV Program



Application included proposed PV PPA at $246/MWh and associated
RFO
Currently under review by CPUC
Link to the Application

https://www.pge.com/regulation/PV-Program-PGE/Pleadings/PGE/2009/PVProgram-PGE_Plea_PGE_20090224-01.pdf
21
Shortlisting
Evaluation Methodology
22
Three Steps to a Shortlist

Evaluate all valid offers

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Determine transmission cost

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Provides a first ranking
No transmission cost included
Added to offer’s cost
Second ranking using new cost values

Shortlist chosen from second ranking
23
Evaluation Criteria

Ranking based on combination of Quantitative and
Qualitative factors

Quantitative Evaluation

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Market Valuation
Transmission Adders
Qualitative Evaluation

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Project Viability
Portfolio Fit
Credit
Consistency with RPS Goals
Modifications to Form Agreements
See Section XI and Attachment K of the Solicitation Protocol
24
Market Valuation

Market-Based Valuation


Value of contract is capacity plus the net of the energy
benefit and cost.
The energy benefit is computed using market prices,
volatilities, and correlations.


Locational Marginal Pricing (LMP) multipliers applied
Capacity value is based on:


The net economic carrying cost of a gas-fired power plant
Contribution to PG&E’s Resource Adequacy requirements.
25
Market Valuation (continued)

Valuation of Contract Types

As-Available Contracts



Baseload, Peaking Contracts



Contract benefit is evaluated based on (deterministic) market forward prices,
but with variable quantity, and the value of capacity.
Cost is calculated as energy generation times offer price times TOD factors for
each period.
Contract benefit is evaluated based on (deterministic) market forward
prices and the value of capacity.
Cost is calculated as energy generation times offer price times TOD
factors for each period.
Dispatchable Contracts


Contract is evaluated as call option on energy. Benefit is the value of capacity
and the expected value of energy.
Cost is the energy generation times the expected offer price, plus a capacity
charge distributed monthly by a Time of Availability factor. (Details for the TOA
factor specified in the Protocol.)
26
Project Viability
All offers will be evaluated and scored using modified
version of CPUC Project Viability Calculator (PVC)

Company/Development Team (25%)
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Technology (25%)

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Project development experience
EPC experience
Ownership and O&M experience
Technical feasibility
Resource quality
Manufacturing supply chain
Development Milestones (50%)

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
Site control
Permitting status
Project financing status
Interconnection progress
Transmission requirements
Reasonableness of COD (Commercial Operation Date)
27
Portfolio Fit
Differentiates offers by the firmness of their
energy delivery and by their energy delivery
patterns
Firmness (predictability) is preferred
Delivery when PG&E is short is preferred





Earlier delivery is preferred over later delivery
Dispatchability is preferred
28
Credit

Performance Assurance


Project Development Security
Delivery Term Security
29
Consistency with RPS Goals





CPUC-stated Goals
Legislative Findings
Governor’s Order on biomass
Impact on Water Quality
PG&E’s Supplier Diversity (WMDVBe)
WMDVBe: Women-, Minority-, Disabled Veteran-owned Business enterprises
30
First Ranking

Shortlist rankings are relative





No fixed cut-off price
No fixed procurement limit
Based on quantitative and qualitative factors
First ranking done on the basis of market value
with adjustments for qualitative criteria
Then, introduce transmission adders
31
Transmission Adder - “the lower of”

Use “the lower of” the result of the
Transmission Ranking Cost Report or
Alternative Commercial Arrangements
(remarketing, swaps, or as-available
transmission)

When no Alternative Commercial
Arrangement is feasible, and no transmission
study results are available, use the TRCR
32
Second Ranking



Market Valuation is adjusted for Transmission
Adders, resulting in a Net Value
Offers are re-ranked, just like first ranking, but
using the new Net Value instead of Market Value
Ranking is a relative one




Strong offers relative to others will be near the top
Weak offers relative to others will be closer to the
bottom
Shortlist chosen from second ranking
Shortlist will err on side of greater inclusion
33
Consultation with PRG and IE



Discuss proposed shortlist and evaluation
methodology
Solicit feedback on whether certain offers
should be included and whether certain
offers should be excluded
Incorporate feedback and finalize shortlist
34
Transmission Ranking Costs
35
Consideration of Transmission
Cost in Bid Ranking

Pursuant to D.04-06-013 and D. 05-07-040

Generator Cost responsibility - Include in bid price
 Direct Assignment Facilities (Gen-tie)



Identify if desire PG&E to evaluate potential for sharing
Wheeling Charges to Delivery Point
Customer Cost Responsibility – Considered in bid
evaluation
 Network Upgrades
 Costs estimates from


CAISO Interconnection Process (ISIS/IFAS)
Transmission Ranking Cost Report
See Section X of the Solicitation Protocol
36
Transmission Ranking Cost




For Projects that have not completed the
ISIS/IFAS
Solely for bid ranking in this solicitation
Based on proxy transmission facilities or
conceptual transmission plan (PG&E, SCE, or
SDG&E
Successful bidders must complete the ISO
Interconnection Process
37
PG&E Substations Associated with
Renewable Resource Clusters
Captain Jack
Pacific Gas and Electric Co. (PG&E)
Malin
Oregon
California
Pit 1
Humboldt



Clusters for Bid
Evaluation
Purposes only
Clusters do not
have to be Points
of Interconnection
Out of area
resources:



North:Round Mountain
South:Midway
East: Summit
Olinda
Delta Metering
Station
Round Mt.
Caribou
Table Mt.
Summit
Cottonwood
Bellota
Fulton
Rio Oso
Vaca-Dixon
Wilson
Tracy
Stagg
Tesla
Newark
Gregg
Metcalf
Helm
Los Banos
Gates
Panoche
Midway
Morro Bay
Carrizo Plains
Renewable resource Cluster
Southern California Edison (SCE)
Sylmar
Vincent
38
Table X.1 Transmission Ranking Cost
Where PG&E is the Purchaser
Substation
Associated
with Cluster
of Potential
Renewable
Generation
Bellota
230 kV
Peak and Shoulder
Night
Base Load and As Available
Year Round
Year Round
Year Round
Cost of Proxy Network
Upgrades to
accommodate MW
Level of Potential
Generation ($ millions
in 2008 dollars)
Level
Maximum
MW of
Potential
Generation
In each
Level
Proxy
Voltage
Support
Devices*
Other Proxy
Transmission
upgrades
Maximum
MW of
Potential
Generation
In each
Level
1
1000
70
0
Cost of Proxy Network Upgrades
to accommodate MW
Level of Potential
Generation ($ millions in
2008 dollars)
Cost of Proxy Network
Upgrades to
accommodate MW
Level of Potential
Generation ($ millions
in 2008 dollars)
Proxy
Voltage
Support
Devices*
Other Proxy
Transmission
upgrades
Maximum
MW of
Potential
Generation
In each
Level
400
28
0
400
28
0
2
500
35
28
500
35
28
3
100
7
15
100
7
15
Proxy
Voltage
Support
Devices*
Other Proxy
Transmission
upgrades
* Cost of Proxy Voltage Support Devices are to be prorated in proportion to the size of the project.
39
Example
 Two Offers received:

A: 300 MW (base load)

B: 300 MW (base load)
 Offer A ranks higher than Offer B
Transmission Ranking Cost to be used in Evaluation
Offer
Level
Gen Capacity
(MW)
Proxy VAR Support
($Million/MW)
Other Proxy
Network Upgrades ($Million)
A
1
300
0.07
0
B
1
100
0.07
0
B
2
200
0.07
28
“In ranking RPS bids, PG&E, SCE, and SDG&E shall each allocate costs of transmission upgrades that
would be used by more than one RPS project on a pro rata basis, based on the percentage of transfer
capacity added by the proposed upgrade that would be used by the RPS project: This pro rata allocation
of upgrade costs shall be applied only if sufficient renewables potential exists, as identified by the
California Energy Commission, to fully utilize the transmission facility sometime in the future."
40
Ways to avoid triggering Next Level
of Transmission Ranking Cost
Attachment D to the Protocol

Energy Pricing Sheet


Optional “Dispatch Down” or “Curtailment” Provision
 Specify the MW of curtailable capacity
Gen Profile Sheet


Generation profile that does not trigger transmission
upgrades
Forecast of average-day net output energy
production, in MW by hour, by month and by year
* This provision is optional and is supplemental to the standard Curtailment or Dispatch Down
provision.
41
Interconnection Process
42
Generation Interconnection
Study Process



Interconnection process must be complete in order for
generator to deliver power to the grid and meet
obligations of RPS contract
Generator responsible for all generation
interconnection costs
Generator responsible for timely applications with
CAISO and timely completion of the process


Not part of RPS Solicitation
Process should be started early
43
Generation Interconnection
Study Process

Transmission Interconnections
 All applications must be submitted with the CAISO
 Generators less than or equal to 20 MW, Small Generator
Interconnection Procedures (SGIP)
 Generators greater than 20 MW, follow Large Generator
Interconnection Procedures (LGIP)
 Information on the SGIP and LGIP found on CAISO Website,
http://www.caiso.com/docs/2002/06/11/2002061110300427214.html

Distribution Interconnections
 Follow Attachment E of WDT
http://www.pge.com/includes/docs/pdfs/b2b/newgenerator/wholesal
egenerators/wdt.pdf
44
Small Generator Interconnection
Procedures (SGIP)
Interconnection
Agreement
(SGIA)
Interconnection
Facilities Study
(IFAS)
Interconnection
System Impact
Study
(ISIS)
Interconnection
Feasibility
Study
(IFS)
Interconnection
Request
(IR)
Study
Process
(30 BD)
Negotiation
(30 BD)
Study
Process
(45 BD)
Study
Process
(45 BD)
Cumulative time >= 6 months
45
Large Generator Interconnection
Procedures (LGIP per GIPR)
Interconnection
Agreement
(LGIA)
Phase II
Negotiation
(60 CD)
Cluster Study
Phase I
Cluster Study
Study
Process
(1 Year)
Interconnection
Request
(IR)
Study
Process
Cumulative time >= 2 Years
(1 Year)
46
Solicitation Documents
47
Offer Submittal

Offers must be received by PG&E by Monday,
August 24, 2009 at 10 a.m. (PDT)

Both Electronic and Hard Copies


Electronic copies - two (2) flash drives
Hard copies (3 Bound & 1 Unbound) delivered to:
RPS Solicitation
Electric Supply Department
Pacific Gas & Electric Company
245 Market Street, 13th floor
San Francisco, CA 94105
48
Information due August 24






Signed RPS Solicitation Protocol Agreement
(Attachment A)
Fully Completed Offer Form (Attachment D)
FERC Order 717 Waiver (Attachment F)
Applicable Form of PPA (Attachment H or Attachment
N), including proposed modifications
Buyout Offers must also include a fully completed
term sheet (Attachment I) in addition to PPA
Ownership Offers must include a fully completed term
sheet (Attachment J) instead of a PPA
See Section VIII.C. of the Solicitation Protocol
49
Information due August 24

Project Description (includes, but is not limited to):









Technology and equipment type
Environmental issues and permit status
Community Development Plans
Contribution to RPS Goals
Site Control
Milestone Schedule
Transmission/Interconnection
Experience and Qualifications
Supplemental CEC Funding
See Section VIII.C. of the Solicitation Protocol
50
Additional forms if Shortlisted

By November 6th
 Offer Deposit
 Confidentiality Agreement (Attachment G)
 Participant Credit-Related Information Form
(Attachment E)
See Section XIV of the Solicitation Protocol
51
Communications and Website

All RFO documents are available on PG&E’s website
at: www.pge.com/rfo and click on 2009 Renewable
RFO,
or paste and bookmark the following in your browser:
http://www.pge.com/b2b/energysupply/wholesaleelectricsuppliersolicitat
ion/renewables2009/index.shtml

All announcements, updates and Q&As will also be
posted on the website

Communications should be directed to:
RenewableRFO@pge.com
See Section I of the Solicitation Protocol
52
Q&A
53