BIDDERS CONFERENCE July 21, 2009 2009 SOLICITATION RENEWABLES PORTFOLIO STANDARD.
Transcript of BIDDERS CONFERENCE July 21, 2009 2009 SOLICITATION RENEWABLES PORTFOLIO STANDARD.
Agenda
Introduction Commercial Overview Shortlisting Evaluation Methodology Transmission Ranking Costs Interconnection Process Solicitation Documents Q & A
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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
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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)
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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
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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)
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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
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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
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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
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
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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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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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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
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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
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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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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
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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
Proxy Voltage Support Devices*
Other Proxy Transmission
upgrades
Proxy Voltage Support Devices*
Other Proxy Transmission
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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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
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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)
Study Process (45 BD)
Study Process (45 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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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