BIDDERS CONFERENCE July 21, 2009 2009 SOLICITATION RENEWABLES PORTFOLIO STANDARD

BIDDERS CONFERENCE

July 21, 2009

2009 SOLICITATION

RENEWABLESPORTFOLIOSTANDARD

Agenda

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 ScheduleDATE 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: 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

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

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Eligible RPS offers

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

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 (as-

available, baseload, dispatchable) Confirm to EEI Master Agreement for short-term

contracts up to 4 years (Attachment N)

10

PPA Key Commercial Terms

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

As-Available Payment = Contract Price * TOD Factor * MWh

Baseload, Peaking Payment = Contract Price * TOD Factor * MWh

Reductions for not meeting minimum performance

Short-term ERRs may price without TOD

Monthly Period Super-Peak Shoulder NightJun – Sep 2.20 1.12 0.69

Oct.- Dec., Jan. & Feb. 1.06 0.93 0.76Mar. – May 1.15 0.85 0.64

See Section IX of the Solicitation Protocol 12

Key Changes to 2009 Form PPA PPA designed to require minimal negotiation Excused delays in construction start and commercial operation for

force majeure, permitting and transmission 360 days for force majeure and permitting 540 days for transmission Cumulative delays not to exceed 540 days

Force majeure no longer an event of default Guaranteed Energy Production (GEP): PPA specifies minimum

delivery amount 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 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) 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) 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”

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Credit 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:

Offer Deposit and Project Development Security – cash or Letter of Credit

Delivery Term Security – cash, Letter of Credit, or acceptable guaranty

Term 10 years

15 years

20 years

Months Revenue at Minimum Expected Revenue (GEP)

6 9 12

See Sections V and VII of the Solicitation Protocol 17

Delivery Term Security Example

Contract Price = $90/MWh Post-TOD average price = $95/MWh Contract Quantity = 100 GWh/year GEP = 80% of Contract Quantity = 80 GWh year

ResultMinimum expected annual revenue:

$95/MWh * 80 GWh = $7.6 millionDTS: 20 year contract = $7.6 millionDTS: 10 year contract = $3.8 million

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Credit—Short Term Offers

See Sections XX of the Solicitation Protocol

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


5 years Project Development Security: $50/kW




Greater than 5 years, but less than 8 years

Project Development Security: $50/kW Delivery Term Security: 4 months minimum expected revenue



8 years or greater, but less than 10 years

Project Development Security: $50/kW




19

CEC Requirements

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

http://www.pge.com/b2b/energysupply/wholesaleelectricsuppliersolicitation/standardcontractsforpurchase

Term up to 20 years Price set at Market Price Referent

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/PV-Program-PGE_Plea_PGE_20090224-01.pdf

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ShortlistingEvaluation Methodology

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Three Steps to a Shortlist

Evaluate all valid offers Provides a first ranking No transmission cost included

Determine transmission cost Added to offer’s cost

Second ranking using new cost values Shortlist chosen from second ranking

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Evaluation Criteria Ranking based on combination of Quantitative and

Qualitative factors

Quantitative Evaluation Market Valuation Transmission Adders

Qualitative Evaluation 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.

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Market Valuation (continued) Valuation of Contract Types

As-Available 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. Baseload, Peaking Contracts

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.)

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Project Viability

Company/Development Team (25%) Project development experience EPC experience Ownership and O&M experience

Technology (25%) Technical feasibility Resource quality Manufacturing supply chain

Development Milestones (50%) Site control Permitting status Project financing status Interconnection progress Transmission requirements Reasonableness of COD (Commercial Operation Date)

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All offers will be evaluated and scored using modified version of CPUC Project Viability Calculator (PVC)

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

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Credit

Performance Assurance Project Development Security Delivery Term Security

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Consistency with RPS Goals

CPUC-stated Goals Legislative Findings Governor’s Order on biomass Impact on Water Quality PG&E’s Supplier Diversity (WMDVBe)

30WMDVBe: Women-, Minority-, Disabled Veteran-owned Business enterprises

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

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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

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Transmission Ranking Costs

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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

Consideration of Transmission Cost in Bid Ranking

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

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

PG&E Substations Associated with Renewable Resource Clusters

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Oregon California

MalinCaptain Jack

Gates

Tracy

Southern California Edison (SCE)VincentSylmar

TeslaNewark

Vaca-Dixon

Round Mt.

Olinda

Pacific Gas and Electric Co. (PG&E)

Cottonwood

Fulton

PanocheMidway

Bellota

Wilson

Gregg

Helm

SummitTable Mt.

Rio Oso

Los Banos

CaribouDelta Metering

Station

Pit 1

Morro Bay

Renewable resource Cluster

Stagg

Metcalf

Humboldt

Carrizo Plains

Table X.1 Transmission Ranking Cost Where PG&E is the Purchaser

* Cost of Proxy Voltage Support Devices are to be prorated in proportion to the size of the project.

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Peak and Shoulder Night Base Load and As Available

Substation Associated with Cluster of Potential Renewable Generation Level

Year Round Year Round Year Round

Maximum MW of

Potential Generation

In each Level

Cost of Proxy Network Upgrades to

accommodate MW Level of Potential

Generation ($ millions in 2008 dollars)

Maximum MW of

Potential Generation

In each Level

Cost of Proxy Network Upgrades to accommodate MW

Level of Potential Generation ($ millions in

2008 dollars)Maximum

MW of Potential

Generation In each Level

Cost of Proxy Network Upgrades to

accommodate MW Level of Potential

Generation ($ millions in 2008 dollars)

Proxy Voltage Support Devices*

Other Proxy Transmission

upgrades



upgrades



upgrades

Bellota 230 kV

1 1000 70 0 400 28 0 400 28 0

2 500 35 28 500 35 28

3 100 7 15 100 7 15

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

“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."

Offer Level Gen Capacity (MW)

Proxy VAR Support ($Million/MW)

Other ProxyNetwork Upgrades ($Million)

A 1 300 0.07 0

B 1 100 0.07 0

B 2 200 0.07 28

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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.

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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

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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/wholesalegenerators/wdt.pdf

44

Small Generator Interconnection Procedures (SGIP)

Interconnection Request

(IR)

Interconnection Feasibility

Study (IFS)

Interconnection System Impact Study

(ISIS)

Interconnection Facilities Study

(IFAS)

Interconnection Agreement

(SGIA)

Study Process (30 BD)



Negotiation (30 BD)

Cumulative time >= 6 months

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Large Generator Interconnection Procedures (LGIP per GIPR)

Interconnection Request

(IR)

Phase I

Cluster Study

Phase II

Cluster Study

Interconnection Agreement

(LGIA)

Study Process

(1 Year)

Study Process

(1 Year)

Negotiation (60 CD)

Cumulative time >= 2 Years

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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 SolicitationElectric Supply DepartmentPacific Gas & Electric Company245 Market Street, 13th floorSan Francisco, CA 94105

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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/wholesaleelectricsuppliersolicitation/renewables2009/index.shtml

All announcements, updates and Q&As will also be posted on the website

Communications should be directed to: [email protected]

See Section I of the Solicitation Protocol 52

Q & A

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