1

Energy Division Workshops:

LTPP Planning Standards (Part 1)&

Procurement Rulebook

June 11, 2010 Workshop

R.10-05-006, Tracks 1, 2, & 3

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Energy Division Staff Proposal on LTPP Planning Standards

Part 1

June 11, 2010 Workshop

R.10-05-006, Tracks 1 & 2

Nathaniel Skinner & Rebecca LeeCPUC Energy Division

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Workshop Objectives

• Help participants understand the purpose of the Planning Standards (Part 1)

• Facilitate helpful comments on Staff Proposals:– June 21– June 28, Replies

• Separate workshops will be held for:– Planning Standards (Part 2): RPS– Planning Standards (Part 3): EE

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Agenda

• Planning Standard Goals

• Standardized L&R Tables

• Portfolio Evaluation Criteria

• Scenarios

• Base Case Assumptions

• Sensitivity Analysis

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Planning Standards Goals

• For a core set of analyses– Internally consistent system plans– Easily comparable

• To produce for the Scoping Memo– Finalized planning standards– Finalized L&R Table Templates– Full descriptions of required scenarios

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Guiding Principles

• Assumptions should– Take a realistic view of policy-driven resource

achievements to ensure electric reliability and track progress toward resource policy goals

– Reflect behavior of market participants

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• Resource Plans should– Be informed by an open and transparent

process– Consider whether significant new investments

in transmission and flexible resources would be needed to reliably integrate and deliver new resources to loads

Guiding Principles

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• Resource scenarios should provide useful information

• Resource portfolios should be substantially unique from each other

Guiding Principles

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Who does the analysis?

• May 28th 2010 Planning Standard Ruling requires the three largest IOUs (PG&E, SCE, SDG&E) to be responsible for the system plans for their individual service areas

• Other LSEs are encouraged to actively participate

Note: The system resource plans prepared by the IOUs with specific Commission guidance are not IOU proposals

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Planning Standards (Part 1)

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Background

• In R.08-02-007, the Commission considered proposals to standardize the IOUs’ resource planning practices, assumptions, and analytical techniques

• July 1, 2009 Staff Proposal contained specific recommendations

• Based on the record in R.08-02-007, Staff proposes that the IOUs’ filing of system resource plans (Track I), and bundled LTPPs (Track II) should be based on a limited set of planning standards

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Standardized L&R Tables

• Purposes– To help improve comparability across plans– To create summaries of the “managed forecasts”

used for the LTPP

• Developed by ED and the IOUs– Supported by other parties to R.08-02-007

• Staff anticipates templates will be finalized in the Scoping Memos for Tracks 1 and 2

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Load & Resources Tables for System Resource Planning

Attachment 1

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Line*SYSTEM AND SERVICE AREA LOAD FORECASTS: 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020

1 System 1-in-2 Peak Summer Demand 25,0002 Service Area 1-in-2 Peak Summer Demand 23,000

SERVICE AREA SPECIFIC LINE ADJUSTMENTS:3 Uncommitted EE 3004 Net Qualifying Capacity (NQC) of Price Sensitive Demand Response (DR) 5005 NQC of Interruptible/Curtailable DR 400

6 Residual Service Area Peak Demand (Line 2 - Sum (Lines 3 thru Line 5) 21,800

SYSTEM RESOURCES:7 Existing Generation NQC 25,0008 Retirements (Announced) (100)9 Retirements (Assumed for this scenario) (200)10 Known/High Probability Additions 10011 RPS Additions NQC (Including Imports) 10012 Other Utility Planned Additions NQC 30013 Other non-Utility Planned Additions NQC 10014 Net Interchange (Sum Lines 15 thru 17) 20015 Non-Firm Imports (Require Reserves) 2,30016 Firm Imports (Do Not Require Reserves) 70017 Exports (2,800)

18 Total System Resources (Sum Lines 7 thru Line 14) 25,500

19 Service Area Portion of System Resources (Line 18 * (Line 2/Line 1)) 23,460

SERVICE AREA PLANNING RESERVES:20 Available Planning Reserve - not adjusted for firm imports (Line 19 - Line 6) 1,66021 Available Planning Reserve (Percentage) (Line 20/Line 6) 7.6%22 Lower Bound of Planning Reserve Requirement (Line 6 * 15%) 3,27023 Upper Bound of Planning Reserve Requirement (Line 6 * 17%) 3,706

1-in-2 SERVICE AREA SURPLUS (DEFICIT):24 Lower Bound 1-in-2 Service Area Surplus (Deficit), Adjusted for Firm Imports (1,505)25 Upper Bound 1-in-2 Service Area Surplus (Deficit), Adjusted for Firm Imports (1,927)

* See notes by line number on folowing page

MW

Utility NamePhysical North of Path 26 (NP26)/South of Path 26 (SP26) Capacity Need

Scenario: xx

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Line*LOCAL RELIABILITY AREA LOAD FORECASTS: 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020

1 Service Area 1-in-2 Peak Summer Demand 25,000

LOCAL RELIABILITY AREA SPECIFIC LINE ADJUSTMENTS:2 Uncommitted EE 3003 Net Qualifying Capacity (NQC) of Price Sensitive Demand Response (DR) 5004 NQC of Interruptible/Curtailable DR 400

5 Residual Service Area Peak Demand (Line 1 - Sum (Lines 2 thru Line 4) 23,800

LOCAL RELIABILITY AREA RESOURCES:6 Existing Generation NQC 25,0007 Retirements (Announced) (100)8 Retirements (Assumed for this scenario) (200)9 Known/High Probability Additions 100

10 RPS Additions NQC (Including Imports) 10011 Other Utility Planned Additions NQC 30012 Other non-Utility Planned Additions NQC 10013 Net Interchange (Sum Lines 14 thru 16) 20014 Non-Firm Imports (Require Reserves) 2,30015 Firm Imports (Do Not Require Reserves) 70016 Exports (2,800)

17 Total Service Area Resources (Sum Lines 6 thru Line 13) 25,500

SERVICE AREA PLANNING RESERVES:18 Available Planning Reserve - not adjusted for firm imports (Line 17 - Line 5) 1,70019 Available Planning Reserve (Percentage) (Line 18/Line 5) 7.1%20 Lower Bound of Planning Reserve Requirement (Line 5 * 15%) 3,57021 Upper Bound of Planning Reserve Requirement (Line 5 * 17%) 4,046

1-in-2 SERVICE AREA SURPLUS (DEFICIT):22 Lower Bound 1-in-2 Service Area Surplus (Deficit), Adjusted for Firm Imports (1,765)23 Upper Bound 1-in-2 Service Area Surplus (Deficit), Adjusted for Firm Imports (2,227)

* See notes by line number on following page.

MW

San Diego Gas & ElectricPhysical Capacity Need for SDG&E

Scenario: xx

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Load & Resources Tables for Bundled LTPP Filings

Attachment 3

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IEPR Table 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020Line Line PEAK LSE LOAD CALCULATIONS:

1 1 Forecast Total Peak-Hour 1-in-2 Demand 10,000

2 2 CCA & Departing/Arriving-New Municipal Loads (-/+) (100)3 3 Uncommitted Energy Efficiency (-) (100)4 4 Demand Response/Interruptible Programs (-) (100)5 5 Self Generation (Total, Non-CSI) (-) (100)6 6 California Solar Initiative (-) (10)7 7 Direct Access Loads (-/+) (1,000)

8 8 Subtotal: Adjustments to Peak-Hour Demand (Lines 2 thru 7) (1,410)

9 9 Adjusted Peak-Hour Demand for End-Use Customers (Sum Line 1 + Line 8) 8,59010 10 Coincidence Adjustment (-) (50)

11 11 Net Peak-Hour Demand (Sum Line 9 + Line 10) 8,54012 12 Specified Planning Reserve Margin (such as 15%) (Line 11 * 15%) 1,28113 13 Firm Sales Obligations (+) 0

14 14 Firm LSE Peak-Hour Resource Requirement (Sum Lines 11 thru 13) 9,821

EXISTING & PLANNED RESOURCES:15 15 LSE-Owned Fossil Resources 2,00016 16 LSE-Owned Nuclear Resources 1,00017 17 LSE-Owned Hydroelectric Resources (1 in 5) 1,00018 18 LSE-Owned Renewable Resources 10019 19 DWR Contractual Resources 1,00020 20 Qualifying Facility (QF) Contractual Resources 1,00021 21 Renewable Energy Contractual Resources 1,00022 22 Other Bilateral Contractual Resources 500

23 23 Total Existing and Planned Resources (Sum Lines 15 thru 22) 7,600

24 24 (Resource Need) or Surplus (Line 23 - Line 14) (2,221)25 25 Specified Planning Reserve Margin (Percentage) 15%

MW

Electricity Resource Planning Form S-1[Utility Name's] Capacity Resource Accounting Table

Bundled Customer Need - Scenario: xx

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IEPR Table 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020Line Line PEAK LSE LOAD CALCULATIONS:

1 1 Forecast Total Energy Demand/Consumption 50,0002 2 CCA & Departing/Arriving-New Municipal Loads (-/+) (500)3 3 Uncommitted Energy Efficiency (-) (500)4 4 Demand Response/Interruptible Programs (-) (500)5 5 Self Generation (Non-CSI) (-) (500)6 6 California Solar Initiative (-) (25)7 7 Direct Access Loads (-/+) (5,000)

8 8 Subtotal: Adjustments to Energy Demand (Lines 2 thru 7) (7,025)

9 9 Adjusted Energy Demand/Consumption (Line 1 + Line 8) 42,97510 10 Firm Sales Obligations (+) 0

11 11 Firm LSE Energy Requirement (Sum Lines 9 thru 10) 42,975

EXISTING & PLANNED RESOURCES:12 12 LSE-Owned Fossil Resources 8,00013 13 LSE-Owned Nuclear Resources 8,00014 14 LSE-Owned Hydroelectric Resources (1 in 2) 1,00015 15 LSE-Owned Renewable Resources 1,00016 16 DWR Contractual Resources 1,00017 17 Qualifying Facility (QF) Contractual Resources 4,00018 18 Renewable Energy Contractual Resources 6,00019 19 Other Bilateral Contractual Resources 50020 20 Spot Market Purchases 2,50021 21 Short Term Sales (-) (1,000)

22 22 Total Existing and Planned Resources (Sum Lines 12 thru 21) 31,000

23 23 (Energy Need) or Surplus (Line 22 - Line 11) (11,975)

Generic Energy Resource Needs:24 24 Renewable Energy 3,000

25 25 Non-Renewable Baseloaded Energy 6,000

26 26 Non-Renewable Peaking Energy 2,975

27 27 Total Generic Energy Resource Needs 11,975

GWh

Electricity Resource Planning Form S-2[Utility Name's] Energy Balance Resource Accounting Table

Bundled Customer Need - Scenario: xx

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Portfolio Evaluation Criteria

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Table 1: Required Evaluation Criteria for Resource Plans (Attachment 2, pp. 3-4)

Table 5: Required Evaluation Criteria for Bundled LTPPs (Attachment 4, pp. 2-3)

Portfolio Evaluation Criteria

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Cost Criteria - PVRR• Present Value Revenue Requirement

– All costs required to meet service area demand that are expected to enter into rates

– Total utility revenue requirements summed for each year and discounted back to base year dollars using an appropriate discount rate

– Must include CO2 allowance cost forecast

– Shall be calculated over a minimum of 20 years

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Cost Criteria – Utility Average Rate

• Calculated for each year as the revenue requirement of each portfolio divided by total sales in that year

• Present value of the utility average rate shall also be calculated – PVRR / present value of total sales

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Cost Criteria - TRC

• Total Resource Cost (customer and utility)

– Used to include the costs of customer contributions in addition to utility support

– Customer and utility costs should be calculated for all utility-sector programs administered by the Commission

– Includes EE, DR, CSI, CHP, and others• Excludes incentives the utility pays to the customer• Not necessary to calculate programs administered outside of utility

programs such as building codes and standards

Note: This criterion is only used for system plans

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Risk Criteria• Robust scenario analysis for system plans

– ED RPS scenarios– Proposed alternative scenarios

• Robust sensitivity analysis

• TEVaR for bundled plans

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Risk Criteria – RPS Scenarios

• Staff Draft Report expected week of June 14th

• Presented in workshop on June 18th

• Comments on RPS Scenarios due July 9th

• Replies on RPS Scenarios due July 16th

Note: These criteria are only used for system plans

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Risk Criteria – Alternate Scenarios

• IOUs or other parties may propose for the Commission to consider

• Anticipated that the Assigned Commissioner will determine a reasonable minimum set of scenarios for the Scoping Memo based on parties’ comments

• Must be consistent with Guiding Principles

Note: This criterion is only used for system plans

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Risk Criteria - Sensitivities

• System– Sensitivities conducted only on the Base Case scenario– Assumed that resource portfolio and dispatch will not change– Discussion of required sensitivities is later in the presentation

• Bundled– Risk metrics shall measure the sensitivity of each portfolio’s

average cost to changes in key cost parameters– IOUs shall also continue to calculate formal risk metrics, such as

TEVaR

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GHG Emissions

• Total GHG Emissions

• Average, per ton Cost of GHG Emissions Abatement

• Qualitative assessment of Long-Term GHG Implications

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GHG – Total Emissions

• Resource plans shall report the total GHG emissions associated with each portfolio during each year of the planning horizon

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GHG – Average Abatement Cost

• Abatement costs are compared against meeting all future resource needs with only new natural gas fired resources– Used for benchmarking purposes only

• Average, per ton cost of CO2 emissions reductions relative to the all gas case– Calculated based on change in PVRR of the portfolios

versus the “all gas” portfolio

• Discounted to present day values

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GHG – Long-Term Implications

• Qualitative assessment of each portfolio’s impacts on the state achieving long-term GHG goals– 80% below 1990 levels by 2050– Potential impact of portfolio choice to influence long-

term technology transformation– Not intended to be highly specific and quantitative in

nature– Interested in parties’ perspective as to which

technologies hold the most promise for long-term benefits

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Required Base Case Portfolio Assumptions

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Common AssumptionsSystem & Bundled

• Load Forecast

• Energy Efficiency

• Demand Response

• Peak Capacity Value

• Planning Reserve Margin

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Assumptions - Load Forecast

Most recent IEPR 1-in-2 base case load forecast

• System only:– Local RA needs assessments use 1-in-10 load

forecast

• Bundled only:– 1-in-2 load forecast, including CEC assumptions

about departing load

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Assumptions - EE• Committed EE

– Embedded utility EE program savings in the most recent IEPR base case load forecast

• Uncommitted EE– Levels of EE savings that are incremental to the most recent IEPR base

case load forecast– Will be covered more fully in Planning Standards (Part 3) Workshop on

June 25th

• Data Sources Include– California Energy Demand 2009– CEC Committee Report on Incremental Impacts of Energy Efficiency– Itron Consultant Report on Incremental Impacts of Energy Efficiency– CPUC EE Goals (D.08-07-047)

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Assumptions – DR

• Provided in the form of ex-ante annual load impact forecasts for 2011-2020

• Use the August Monthly System Peak Load Day under a 1-in-2 weather condition

• If estimates are significantly revised between the Scoping Memo and the utilities’ filed resource plans (est. Q1 2011), parties will be able to comment on revised estimates

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Assumptions – DR

• IOUs propose forecasted Demand Response load impacts based on April 1st Load Impact Report Compliance Filing, pursuant to D.08-04-050, OP 4 which

– Reflect current DR program plans (2009-2011)

– DR programs approved through other proceedings

– Other anticipated DR programs/resources anticipated, such as Automated Metering Infrastructure (AMI) systems

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Assumptions – Peak Capacity

• Net Qualifying Capacity values per the RA proceeding

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Assumptions – PRM

• Planning Reserve Margin will be 15%-17% of peak demand, or as modified in R.08-04-012

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Assumptions System Only

• Customer-side DG

• Resource Additions and Retirements

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System Assumptions – DG

Customer-side DG, including CSI, are assumed to be the embedded levels of self-generation in the most recent IEPR base case load forecast

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System Assumptions - Resources

• IOUs will propose assumptions on resource additions, totals will be listed in L&R Tables– Specify which additions and retirements are assumed– Known/High Probability Additions

• Contract in place, permitted, and under construction• “Other” fields should include contracted resources that have

not yet begun construction

• The Scoping Memo will specify an approach for plant retirements consistent with OTC policy

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Common Cost Variable Assumptions

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Cost AssumptionsFor System and Bundled Plans

• Renewable Resource Availability / Cost• New Generation Tax and Financing Cost • Traditional Transmission & Distribution Cost• Renewables Transmission Cost • Conventional and Other Resource Cost• Natural Gas Price• Carbon Price• GHG Policy Assumption

(Compliance Cost)• Generic Renewable Resource Cost

Sys

tem

Bu

nd

led

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Renewable Resource Availability and Cost

• Will be proposed by Staff in the forthcoming Draft RPS Planning Standards

• Will be presented and discussed in the June 18th 2010 Workshop

• Data sources include– RETI– Energy Division RPS Contract Database– E3 Assessment of REC Availability

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New Generation Tax and Financing Cost

• For new renewable generation, Staff will propose tax and financing cost assumptions in the forthcoming Draft RPS Planning Standards

• For non-renewable generation, IOUs propose tax and financing assumptions for CPUC consideration

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Traditional T&D Cost Assumptions

• In R.04-04-025, the CPUC adopted the E3 Avoid Cost Methodology for calculating the avoided cost. (D.05-04-024)

• The methodology calculates avoided electric T&D cost (differentiated by hour, utility, planning area, and climate zones)

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Renewables Transmission Cost

• For transmission to access new renewable resources, ED staff will propose transmission cost assumptions in the forthcoming Draft RPS Planning Standards

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Cost Assumptions From Market Price Referent (MPR)

• MPR includes cost methods and inputs to calculate– Non-fuel cost assumptions for conventional resources– Natural gas price forecast– Carbon price (estimated GHG compliance cost)

• MPR is currently employed to assess the cost reasonableness of renewable contracts. MPR represents the “all-in” cost to own and operate a baseload combined cycle gas turbine power plant over various time periods

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Generic Non-Fuel Cost Assumption from MPR

Install Capital Cost Inputs (2008$)

(Million $) $/kW (Million $) $/kW (Million $) $/kW

Capital Cost Investment - Overnight Costs 506.20 $912 510.83 $1,022 684.40 $1,042

Interconnection (natural gas, water, electric) $24.55 $49 $0.00 $0

Environmental Review & Permitting

Emissions offsets

Dry Cooling Adjustment $29 $52 $26 $52

Contingency - - - - - -

AFUDC - - - - - -

EITC - - - - - -

Other or Subtotal 91.75 $165 - - - -

Total "Turn-Key" Capital Costs (2008$) $627 $1,129 $561 $1,123 $684 $1,042

Average Installed Capital Costs (2009 $/kW) $1,098

Palomar (San Diego)Combined-Cycle

555 MW

Cosumnes (SMUD)Combined-Cycle

500 MW

Colusa (PG&E)Combined-Cycle

657 MW

Included in Instant Capital Costs Shown Above

Included in Instant Capital Costs Shown Above

Included in Instant Capital Costs Shown Above

Included in Instant Capital Costs Shown Above

Included in Instant Capital Costs Shown Above

Included in Instant Capital Costs Shown Above

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MPR Natural Gas Price Forecast (D.08-10-026)

Year2009 MPR Henry

Hub Forecast (Nominal$)

2009 MPR CA Gas Forecast (Nominal$)

2010 $5.89 $6.202011 $6.73 $7.042012 $6.91 $7.242013 $7.02 $7.362014 $7.15 $7.502015 $7.30 $7.662016 $7.44 $7.812017 $7.59 $7.972018 $7.74 $8.132019 $7.89 $8.292020 $8.04 $8.452021 $8.19 $8.61

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Carbon Price from 2009 MPR (Res E-4298)

CO2 Conversion 2012 2015 2020

MPR GHG compliance cost in short

tons(nominal$ / CO2

ton)

$10.44/ CO2 ton

$24.35/ CO2 ton

$43.52/ CO2 ton

Conversion to Metric Ton

(nominal$ /MT CO2)

$11.51/ MT CO2

$26.84/ MT CO2

$47.97/ MT CO2

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Sensitivity of Portfolio Cost

• Natural gas price

• Carbon price

• Need determination

• Generation resource technology cost (system planning)

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Sensitivities

• We are seeking comments and/or alternative proposals on what sensitivity values should be established in the Scoping Memo– High and Low values

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Thank you!For Additional Information:

www.cpuc.ca.gov/PUC/energy/Procurement/LTPP/LTPP2010

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Extra Slides

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Attachment 1 – L&R Table Notes

Notes by Line Number:

1 System peak demand represents peak demand in CAISO's control area, North of Path 26 (NP26) or South of Path 26 (SP26). This includes the PG&E service area and participating publicly owned utilities in the NP26

region served by the CAISO.

2 Service area peak demand represents the peak demand in the PG&E service area, independent of LSE providing service. Service area peak demand includes bundled and direct access (DA)

customer peak demand, and excludes publicly owned utility (POU) peak.

7 Resources included here match the CEC's most recent resource assessment from [date and document source].

10 System resource additions that have a contract in place, have been permitted, and have construction well under way.

12 System resource additions resources that have a contract, but have not yet begun construction.

13 System resource additions resources that have a contract, but have not yet begun construction.

14 Sum of all imports and exports into service area.

19 Service Area Portion of System Resources = Total System Resources *( Service Area Demand/System Demand)

20 Available Planning Reserve = Service Area Resources - Service Area Demand (not adjusted to account for the difference between firm and non-firm imports)

21 Available Planning Reserve = Available Planning Reserve/Service Area Demand

22 Service Area Demand * 15%

23 Service Area Demand * 17%

24 Line 20 + (adjusted for firm imports by adding 15% of Line 16) - Line 22

25 Line 20 + (adjusted for firm imports by adding 17% of Line 16) - Line 23

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Attachment 1 – L&R Table Notes for SDG&E

NOTES (by Line number):

1 Based on CEC's 2009 IEPR 1-in-2 peak demand, which embeds self-served load and committed EE.

6 Resources included here match the CEC's most recent resource assessment from [date and document source].

9 System Resource additions that meet predetermined criteria.

13 Sum of all imports and exports into service area.

18 Available Planning Reserve = Service Area Resources - Service Area Demand (not adjusted to account for the difference between firm and non-firm imports)

19 Available Planning Reserve = Available Planning Reserve/Service Area Demand

20 Service Area Demand * 15%

21 Service Area Demand * 17%

22 Line 19 + (adjusted for firm imports by adding 15% of Line 15) - Line 21

23 Line 19 + (adjusted for firm imports by adding 17% of Line 15) - Line 22