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ERCOT Business Case for Economic Transmission Planning

Presented to:ERCOT RPG Meeting

Presented by:Johannes Pfeifenberger

Judy Chang

March 26, 2013

2

Content

 Objectives of the Effort

 Similar previous engagements

 Work Plan (Tasks 1-7)

 Timeline

 Appendix (Tools, Example Metrics)

3

Objectives of this Effort

Review long-term system assessment (LTSA) process and develop recommendations to enhance/expand business case for (and include additional methods of valuing) transmission.

♦ Provide ERCOT with a careful review and critique of the existing LTSA transmission planning process

• Investigate key stakeholder and industry-wide concerns

• Review LTS and compare to processes in other jurisdictions

♦ Provide ERCOT options for expanding its planning processes to include more comprehensive assessments of transmission expansion benefits

• Develop and demonstrate methodologies for valuing additional (non-conventional) transmission-related societal benefits

♦ Assist ERCOT in optimizing the use of its modeling platforms and tools• Identify the strengths and weaknesses of models and tools

• Recommending “best practices” in modeling applications and procedures

♦ Enable ERCOT deliver repeatable study results in future LTSA planning cycles• Review and critique post-processing tools and automation procedures

♦ Conduct workshop to educate stakeholder and present results and recommendations

4

The “Business Case” for Transmission

 Effective planning for economic and public-policy projects requires developing a proper analytical approach to evaluate projects

♦ Projects often present different options (with different benefits and costs) that can meet the same objective

♦ Some projects serve different purposes and offer different benefits that require different analytical approaches to quantify of explain

♦ Standard analytical tools capture only a portion of economic benefits and can limit the scope of benefit-cost analyses

♦ Lack of established evaluation processes also limits the approach to only using “standard” analyses

 We helped numerous clients in similar engagements to improve their analytical approach and planning frameworks for new transmission, including developing methods to quantify “non-conventional” benefits.

♦ Clients include planning authorities, both traditional and independent transmission owners, and industry groups: SPP, ITC, ATC, AEP-ETA-Exelon, SCE, WIRES, AWC, Cleanline, Greenline

5

Similar Engagements: SPP

 Helped SPP’s “Metrics Task Force” and improve its planning framework for transmission benefit-cost analyses to support Regional Cost Allocation Review effort by Regional State Committee

♦ SPP previously defined numerous “robustness metrics” that did not monetize benefits and double-counted similar benefits

♦ Helped the task force to: • (1) define limitations of standard benefit metrics

• (2) develop methodologies that can monetize additional benefits

• (3) avoid double-counting of similar benefits

♦ Task force confirmed 5 standard metrics and added 8 new metrics to monetize transmission benefits (shown on next slide)

♦ Also recommended additional benefit metrics for future implementation, including mitigation of weather uncertainty and reduced cycling of baseload units

 Now working with SPP to implement recommendations and quantify some of the recommended benefit metrics

6

Similar Engagements: SPP (cont’d)

Benefits Metric Standard Metric

Recommended New Metric

Adjusted Production Cost Benefits

Adjusted Production Costs √

Energy losses benefits √

Mitigation of transmission outage costs √

Capacity for Losses Reduced capacity costs √

Improvements in Reliability

Avoided or delayed reliability projects √

Capital savings associated with reduced capacity margin √

Reduced loss of load probability √

Reduced cost of extreme events √

Assumed benefits of mandated reliability projects √

Reduction of Emission Rates and Values

Reduction of emission rates and values √

Reduced Operating Reserves Benefits

Lower ancillary services needs and costs √

Improvements to Import/Export Limits

Increased wheeling through and out revenues √

Public Policy Benefits Meeting policy goals √

7

Similar Engagements: ITC

Analyzed for ITC both societal and customer benefits for a portfolio of “strategic projects” in the Entergy footprint :

♦ Production cost savings due to congestion and RMR relief♦ Increased transfer capabilities to Western region, SPP, TVA and

associated resource adequacy benefits to Entergy, IPPs, ERCOT, and others

♦ Increased wheeling out and through revenues♦ Avoided or deferred future reliability projects♦ Storm hardening in eastern Texas, southern Louisiana & New Orleans♦ Low-cost options to increase load serving capability in industrial

corridors of eastern Texas and southern Louisiana♦ Economic development benefits♦ More robust grid, increased system reliability and operating flexibility♦ Improved market access and competitive choices, including future

options for lower-cost renewable generation imports into the region

8

Similar Engagements: Others

♦ AEP-ETA-Exelon: helped AEP improve internal modeling capabilities and quantify wide range of benefits for proposed RITELine project;

♦ AEP-ETA: helped AEP understand full range of benefits provided by proposed regional SMARTransmission overlay

♦ ATC: helped ATC improve internal modeling capability and develop new methodologies to quantify non-traditional benefits in context of several proposed transmission projects and overall planning framework

♦ Southern California Edison: helped quantify and explain wide range of California and Arizona benefits for proposed Devers-Palo Verde No. 2 line

♦ Atlantic Wind Connection: quantify range of benefits related to offshore wind integration grid

♦ Cleanline: conducted renewable integration benefit analysis for its project♦ Anbaric: helped independent developer improve benefits framework♦ WIRES: 2011 report on economic stimulus and other benefits of transmission;

currently working on report document “best practices” in transmission benefit-cost analyses

♦ SPP RSC: helped develop inter-regional planning and cost allocation framework

9

Workplan: Overview

Task 1: Kick-off meeting (Feb 13)

Task 2: Review and Critique ERCOT’s Existing LTS Planning Process (mid Feb – end of March)

Task 3: Evaluate Existing Production Modeling Procedures, Training, and Planning Results (late Feb – mid April)

Task 4: Develop Recommendations and Additional Benefit Metrics (late March – early June)

Task 5: ERCOT Staff Briefing (May 17)

Task 6: Stakeholder Workshop (June 3)

Task 7: Prepare Report (early May – June 30, early July)

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Task 1. Project Kick-off (completed)

♦ Confirmed the scope of the analyses and proposed tasks

♦ Agreed on a detailed work plan

♦ Identified key ERCOT staff that will be available to provide data and technical information

♦ Identified key ERCOT, stakeholder, and other documents and data that need to be considered in the review effort

♦ Assemble a list of stakeholders that should be interviewed

11

Task 2. Review and Critique ERCOT’s Existing LTS Planning Process (ongoing)

♦ Review ERCOT’s current process for screening economic transmission projects over its long-term study horizon

♦ Interview ERCOT planning staff to ensure complete understanding

♦ Interview the investors and other stakeholders identified during the kick-off meeting to obtain their thoughts about existing planning process, concerns, and possible improvements

♦ Identify gaps and options to address them

12

Task 3. Evaluate Existing Production Modeling, Training, and Planning Results (ongoing)

♦ Review relevant documentation

♦ Interview ERCOT staff and meet with ERCOT staff on site (and, where efficient, over Web-Ex) to review:

• Production cost modeling procedures, including a review of how each modeling tool is being used. (e.g., PROMOD IV, UPLAN, and KERMIT.)

• In-house training materials and methodologies

• Preliminary modeling results of ERCOT’s most current economic planning efforts

♦ Identify strengths of current analytical and modeling capabilities and identify gaps that should be filled to improve planning process

13

Task 4. Develop Recommendations and Additional Benefit Metrics

♦ Recommend improvements to existing planning and screening process

♦ Propose potential refinements to existing methodology, calculations, and metrics associated with production cost savings

♦ Develop and propose additional metrics of potential benefits to be used in evaluating the societal benefits

• Describe and demonstrate through examples how to calculate the new metrics based on existing ERCOT modeling tools and additional analyses

♦ Explain how value metrics and evaluation techniques fit with ERCOT’s cost recovery mechanisms

♦ Consolidate findings and draft recommendations

14

Task 5. ERCOT Staff BriefingTask 6. Stakeholder Workshop

♦ Conduct day-long on-site meeting with ERCOT staff to review our draft findings and recommendations, prior to workshop

• Include demonstration of the proposed additional benefit evaluation methods

♦ Work with ERCOT Long Term Study Task Force to host on June 3, 2013 (initially April) a workshop to educate the stakeholder community about the “business case” for economic transmission projects

• Draft PowerPoint presentation for stakeholder workshop and finalize with ERCOT input

• Present and lead discussions at the workshop (summarize all of the tasks, findings, and recommendations)

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Task 7. Prepare Report

 We will draft a report that documents the results of our assessment of ERCOT’s long-term economic planning process, including recommendations.

♦ Draft report documenting results of our assessment and recommendations

♦ Begin with an outline by first week of May for ERCOT project team feedback

♦ Prepare initial draft by second week of June and obtain ERCOT’s feedback

♦ Final draft of report on June 30, 2013 (originally May 2013), with last round of feedback and finalizing edits by mid July

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Timeline: Feb ’13 – July ’13

Week Starting (Monday)

Denotes proposed face-to-face or video meetings Denotes final workproduct/deliverable

Task 13-F

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24-A

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1-M

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8-M

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15-M

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22-M

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29-M

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26-J

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3-Ju

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10-J

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17-J

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31-J

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1 Kick-off meetingDeliverable: This task is consistent with as the deliverable required in RFP Section 2.4.2.i. Kick-off meeting to agree to scope, identify data sources and interview targets

2 Review and critique ERCOT's existing LTS Planning Process

i. Review relevant documents

ii. Interview ERCOT staff

iii. Interview investors and other stakeholders

iv Identify gaps and options

3

Deliverable: This task is consistent with the deliverable required in RFP Section 2.4.3.i. Conduct on-site meetings with technical staff

ii. Identify strengths and gaps of existing procedures

4

i. Propose potential refinements to existing methodologies

ii. Develop and propose additional metrics

iii. Explain new metrics and screening process

iv. Propose additional improvements to LTS Planning process

v. Consolidate findings and draft recommendations

5

Deliverable: This task is consistent with the deliverable required in RFP Section 2.4.4.i. Review draft findings and recommendations

ii. Demonstrate benefit evaluation method

6

Deliverable: This task is consistent with the deliverable required in RFP Section 2.4.5.i. Draft presentation and obtain feedback

ii. Present and facilitate workshop

7 Prepare reportDeliverable: This task is consistent with the deliverable required in RFP Section 2.4.1.i Draft report outline for ERCOT project team feedback

ii Prepare draft report and obtain feedback

ii Finalize report

Deliverable: This task is necessary to support the written assessment required in RFP Section 2.4.1.

Evaluate ERCOT’s production cost modeling procedures, in-house training, and economic planning

Develop recommendations and additional benefit metrics

ERCOT staff briefing

Stakeholder workshop

Deliverable: This task is necessary to support written assessment required in RFP Section 2.4.1., the briefing meeting with ERCOT staff required in RFP Section 3.4.4, and the stakeholder seminar required in RFP Section 2.4.5.

17

Important Step: Stakeholder Input

 We welcome your input and are currently interviewing stakeholders.

 Please reach out to Greg or directly to us to set up a time.

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About The Brattle Group / Contact Information

  Climate Change Policy and Planning  Cost of Capital   Demand Forecasting and Weather

Normalization   Demand Response and Energy Efficiency   Electricity Market Modeling  Energy Asset Valuation  Energy Contract Litigation  Environmental Compliance  Fuel and Power Procurement  Incentive Regulation

  Rate Design, Cost Allocation, and Rate Structure   Regulatory Strategy and Litigation Support  Renewables  Resource Planning  Retail Access and Restructuring  Risk Management  Market-Based Rates  Market Design and Competitive Analysis  Mergers and Acquisitions  Transmission

 The Brattle Group provides consulting and expert testimony in economics, finance, and regulation to corporations, law firms, and governmental agencies around the world.

 We combine in-depth industry experience, rigorous analyses, and principled techniques to help clients answer complex economic and financial questions in litigation and regulation, develop strategies for changing markets, and make critical business decisions.

Johannes Pfeifenberger (hannes.pfeifenberger@brattle.com)Judy Chang (judy.chang@brattle.com)

44 Brattle Street, Cambridge, MA 02138617-864-7900 (www.brattle.com)

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Content

 Brattle Project Team

 Work Plan (Tasks 1-7)

 Timeline

 Information Needs

 Appendix (Tools, Example Metrics)

20

Common Tools Supporting Economic Analysis

 Several types of standard modeling tools provide relevant inputs to economic analyses of transmission projects Custom analyses frequently needed for certain transmission benefits (e.g., ancillary service costs of balancing intermittent resources)

Category Purpose Relevant Metrics Frequently Used Models

Production Cost Models

Used to estimate production costs and market prices (LMPs or zonal). Simulation of security-constrained economic dispatch, used to calculate production cost, congestion relief, and market price benefits

APC Load LMPs Emissions

Nodal: PROMOD, GE- MAPS, Dayzer, UPLAN, GridView, PowerWorld

Zonal: MarketSym, Aurora

Power Flow Models

Used mostly for reliability studies (thermal overloads and voltage violations under N-1 or N-2 contingencies); provides inputs for economic analysis of transfer capabilities and transmission losses.

System losses FCITC

PSS/E, PSLF, MUST, POM, PowerWorld

Capacity Expansion Models

Used to estimate approx. impact of change in transmission capabilities (between zones) on generation additions and retirements. Based on least cost and user defined parameters, these models retire existing and “build” additional capacity over 20 - 40 years. Typically used in long-term resource planning exercises.

Total generation costs (investments and operations) Plant additions and retirements

Aurora, EGEAS, Strategist (public)

IPM, NEEM, RECAP (proprietary)

Reliability Assessment Models

Used to estimate loss-of-load-expectation and expected unserved energy

LOLE, LOLP, UNE, required reserve margins

GE MARS, SERVM

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Production Cost Models

 Security-constrained dispatch simulation models or “production cost models” are the most widely-used tool used to assess the economic benefits of transmission projects.

Production cost models:♦ Measure changes in production costs, power flows, LMP, and congestion

♦ Allow for different definitions of “benefits,” reporting of different “metrics,” but provides incomplete picture of total transmission-related value

Limits of production cost models are easily overlooked:♦ Despite fancy modeling tools, results often driven by assumptions and

simplifications (no long-term effects; no transmission outages; no transmission losses; contracts often ignored)

♦ Different (often simplistic) benefit metrics can produce very different results

♦ Limited number of scenarios/cases does not capture disproportional benefits under stressed market conditions and extreme contingencies

♦ Production cost modeling does not capture investment cost impacts (e.g., generation retirement and additions; access to lower-cost generation)

♦ Many “other” transmission benefits not captured in modeling efforts

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Example: Diverse Benefits

Wide-spread nature of transmission benefits creates both planning and analytical challenges

Scope of project and potential effects

• Increased reliability and operational flexibility• Reduced congestion, dispatch costs, and losses • Lower capacity needs and generation costs• Increased competition and market liquidity• Renewables integration and environmental benefits • Insurance and risk mitigation benefits• Fuel diversification and fuel market benefits • Economic development from G&T investments

Geographical spread

• Multiple transmissions service areas and load zones

Effects on market participants

• Customers, generators, transmission owners in regulated and/or deregulated markets

• Individual market participants may capture some benefits but not others

Effects over time• Changing with system conditions with future generation and transmission

additions• Individual market participants may capture different benefits at different times

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Example: Metrics used in Other RTOs

MISO MVP analysis:Quantified1.production cost savings 2.reduced operating reserves3.reduced planning reserves4.reduced transmission losses5.reduced renewable generation investment costs6.reduced future transmission investment costs

Not quantified1.enhanced generation policy flexibility2.increased system robustness3.decreased natural gas price risk4.decreased CO2 emissions output5.decreased wind generation volatility6.increased local investment and job creation(Proposed Multi Value Project Portfolio, Technical Study Task Force and Business Case Workshop August 22, 2011)

SPP ITP analysis:Quantified1.production cost savings2.reduced transmission losses3.wind revenue impacts4.natural gas market benefits5.reliability benefits6.economic stimulus benefits of transmission and wind generation construction

Not quantified1.enabling future markets2.storm hardening3.improving operating practices/maintenance schedules4.lowering reliability margins5.improving dynamic performance and grid stability during extreme events6.societal economic benefits

(SPP Priority Projects Phase II Final Report, SPP Board Approved April 27, 2010; see also SPP Metrics Task Force, Benefits for the 2013 Regional Cost Allocation Review, July, 5 2012.)

CAISO TEAM analysis (DPV2 example)

Quantified1.production cost savings and reduced energy prices from both a societal and customer perspective2.mitigation of market power3.insurance value for high-impact low-probability events4.capacity benefits due to reduced generation investment costs5.operational benefits (RMR)6.reduced transmission losses7.emissions benefit

Not quantified1.facilitation of the retirement of aging power plants2.encouraging fuel diversity3.improved reserve sharing4.increased voltage support(CPUC Decision 07-01-040, January 25, 2007 (Opinion Granting a Certificate of Public Convenience and Necessity)

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ATC - Paddock-Rockdale Project

80

42

6

49

28

15

220

0

50

100

150

200

250

Production Cost

Benefits

Loss Benefitsincl. Refunds

FTR and Congestion

Benefits

CompetitivenessBenefits

(for limited WIMarket-Based

Pricing)

Insurance Benefit DuringSystem Failure

Events

Capacity Savings From

Reduced Losses

Total BenefitsNP

V o

f E

xpec

ted

Ben

efit

s U

nd

er H

igh

En

viro

nm

enta

l Sce

nar

io (

$ M

illi

on)

Source: American Transmission Company, Planning Analysis of the Paddock-Rockdale Project, April 2007.

NPV Cost: 137

Note: adjustment for FTR and congestion benefits was negative in 3 out of 7 scenarios (e.g. a negative $117m offset to $379m inproduction cost savings)

♦ Total benefits exceeded standard production cost savings. ♦ Quantified benefits associated with increased competition, insurance for

system failures, and capacity savings.

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Example: Electricity Market Benefits vs. Costs

Total electricity market benefits of SCE’s DPV2 project in CAISO exceeded project costs by more than 50%

56

20

12

28

2 1191

0

25

50

75

100

125

Production Cost Benefits (Net of FTRs)

CompetitivenessBenefits

OperationalBenefits

(RMR, MLCC)

Generation Investment

Cost Savings

Reduced Losses

Emissions Benefit

Total Annual

Exp

ecte

d A

nnu

al B

enef

its

of D

PV

2 ($

mil

lion

s)

Source: Economic Evaluation of the Palo Verde-Devers Line No. 2 (PVD2), CAISO, February 24, 2005.

Levelized Cost: 71