Southwest Power Pool REGIONAL ALLOCATION REVIEW TASK … · Tom DeBaun, KCC Tom Wright, KCC Michael...

Minutes No. 3

Southwest Power Pool

REGIONAL ALLOCATION REVIEW TASK FORCE MEETING

August 18, 2011 Conference Call

• M I N U T E S •

Agenda Items 1 and 2 – Call to Order, Preliminary Matters

SPP Chair Michael Siedschlag called the meeting to order at 1:30 p.m. with the declaration of a quorum. Role was called and the following phone participants were confirmed: Task Force Members: Michael Siedschlag, Chair Thomas Wright, KCC Butch Reeves, APSC Bary Warren, Empire District Electric Co. Phil Crissup, OG&E Harry Skilton, SPP Director Paul Suskie, SPP Staff Secretary Phone Participants: Pat Mosier, APSC Bernie Liu, SPS Tom DeBaun, KCC Tom Wright, KCC Michael C. Moffet, SUNC Rich Kosch, LES Mike Proctor, SPP RSC David Ried, OPPD Traci Bender Steve Gaw, Wind Coalition William Leung Jennifer Weatherford, GRDA John Bell, KCC Gerald Deaver, SPS Dan Lenihan, OPPD Elena Larson, KCC Charles Cates, SPP Staff Dan Jones, SPP Staff RARTF’s August 4 and 5, 2011 Minutes were approved. Agenda Item 3 – Discussion

a. Review of Action Items

A good discussion was held at the RARTF’s conference call about the tasks of the RARTF. Chairman Siedschlag asked for a second letter requesting any changes to the RARTF White Paper in anticipation of the transition of the White Paper to the RARTF Recommendation, as well as a request for presentations to be given at the September 22 - 23 face-to-face meeting in

Minutes No. 3

Dallas, with an estimated time to present. Paul Suskie said that SPP Staff will prepare and send a second letter. Harry Skilton requested a list of assumptions/criteria used to develop models used in groupings of upgrades, i.e. Priority Projects fuel prices by type, etc. SPP Staff indicated that such information will be provided at the next RARTF meeting. Charles Cates, SPP, suggested a change log of assumptions and subsequent B/C ratios over iterations of studies and time. Tom DeBaun, KCC, asked where the Priority Projects benefits will come from. He also asked if we would be considering the updated cost estimates in our B/C analysis. SPP Staff responded that the report will use the most current cost estimates in our updated B/C analysis for informational purposes at the next RARTF meeting.

b. Review of Draft Transition from Staff White Paper to RARTF Recommendation

Paul Suskie reviewed the changes converting the Staff White Paper to the RARTF Recommendations. Phil Crissup noted a couple of additional changes that were needed.

c. Call for Stakeholder Feedback on Staff Whitepaper A brief discussion took place about the request for stakeholder feedback on the Staff’s White Paper.

d. Call for Stakeholder Proposals for the RARTF

The invitation was again extended to present at the Sept 22 - 23, 2011 meeting in Dallas. Dr. Proctor indicated that he plans on presenting.

Agenda Item 4 – Scheduling of Next Regular Meeting, Special Meetings or Event

Next meeting: September 22 - 23, 2011, at the DFW Hyatt Hotel in Dallas, TX. Charles shared that the fall planning summit will be September 21 - 22, 2011 also in Dallas.

Oct 17, 2011 and Nov 14, 2011 weeks were proposed to follow with a possible phone call on Oct. 6, 2011.

Chairman Siedschlag adjourned the meeting at 2:25 p.m. Respectfully Submitted, Paul Suskie Senior Vice President and General Counsel Southwest Power Pool RARTF Secretary

Minutes No. 3



August 18, 2011

Crowne Plaza Hotel, Dallas, TX

• Summary of Current Action Items •

1. Provide list of forecasted Highway Byway projects that may require RARTF review.

2. Provide analysis of B/C ratios for existing upgrade portfolios. 3. Provide a history of B/C ratio calculation assumptions and key issues.

4. Provide a list of SPP zonal load ratio shares and net plant carrying charges.

5. Provide a definition of “roughly commensurate” and “reasonableness review.”

6. Begin the transition from “RARTF White Paper” to “RARTF Recommendation.”

• Summary of Action Items from Prior Meetings •

1. At the face to face meeting in Dallas in August, conduct a cost and benefit tutorial including descriptions of models, parameters, assumptions, data review, applications as applied to asset recovery.

2. Also at the first face to face meeting, Staff should present a draft of the RARTF Whitepaper discussing analytical methods of determining deficiency thresholds and potential remedies.

3. Expand/provide a “methods” definition to include the process of determining costs and benefits. 4. Begin to define the threshold of a “deficiency” in zonal benefits versus allocated costs.

5. Begin to develop remedies to deficiencies that exceed threshold limits.

6. Target the first face to face meeting date of August 5th, 2011, noon through August 6th, 2011

noon. Provide all necessary meeting arrangements. Also target August 18th and 19th, 2011 for an additional teleconference in August.

7. Establish monthly meetings in September, October, and November, 2011. Develop a matrix of possible dates for Task Force Member input.

8. Include ratification of the RARTF Charter at the first face to face meeting in Dallas on August 4 and 5th, 2011.

RARTF Agenda

Conference Call

August 18th @ 1:30 pm

1. CALL TO ORDER

2. PRELIMINARY MATTERS a. Declaration of a Quorum b. Announcement of Participants c. Approval of August 4-5 minutes

3. Discussion a. Review of Action Items (See Aug. 4-5 Minutes) .............................................................. Paul Suskie b. Review of Draft Transition from Staff White Paper to RARTF Recommendation ........ Paul Suskie c. Call for Stakeholder Feedback on Staff White Paper .................................................................... All d. Call for Stakeholder Proposals for RARTF ...................................................................................... All

4. SCHEDULING OF NEXT REGULAR MEETING, SPECIAL MEETINGS OR EVENT

a. September 22-23, 2011 ................................................................................................... Dallas, Texas 5. ANNOUNCEMENTS & ADJOURNMENT

Minutes No. 2



August 4th and 5th, 2011 Crowne Plaza Hotel, Dallas, TX

• M I N U T E S •

Agenda Items 1 and 2 – Call to Order, Preliminary Matters

SPP Chair Michael Siedschlag called the meeting to order at 12:00 pm on August 4th with the declaration of a Quorum. The following attendees were present: Task Force Members: Michael Siedschlag, Chair Richard Ross, Vice-Chair, American Electric Power Thomas Wright, KCC Butch Reeves, APSC Bary Warren, Empire District Electric Co. Phil Crissup, OG&E Harry Skilton, SPP Director Paul Suskie, SPP Staff Secretary Attendees: Pat Mosier, APSC Todd Fridley, KCPL Bruce Cude, SPS Bernie Liu, SPS Phyllis Bernard, SPP Board of Directors Doug Collins, OPPD Tom DeBaun, KCC Michael C. Moffet, SUNC Jim Krajecki, Customized Energy Solutions Adam McKinnie, MO PSC Charles Locke, KCPL Rich Kosch, LES Mike Proctor, SPP RSC Charles Cates, SPP Staff Dan Jones, SPP Staff Phone Participants: Jim Bell, KCC Tim Trexel, NRB Bill Leung, NRB Sam Loudenslager, APSC Gerald Dever, SPS Jim Palmer Dan Lenihan Elaina Larsen

Minutes No. 2

RARTF’s June 24, 2011 Minutes were approved. Agenda Item 3 – Presentations

a. Benefit/Cost Ratio Primer

A presentation was given by SPP Staff Members Paul Suskie, Charles Cates, and Dan Jones on calculating and modeling costs and benefits. Overviews were given on the SPP transmission planning methods, regional and zonal details, and upgrades approved to date. A hypothetical RTO (H-RTO) was also presented. Using the H-RTO as a model, Staff illustrated annual costs and benefits attributed to zones from new upgrades. Benefit/Cost ratios were calculated using the H-RTO model, details of zonal differences were explored and discussed. Analogies were drawn between the H-RTO and the SPP RTO.

b. PowerWorld Review

A simplified PowerWorld model was reviewed with each state in the SPP RTO give a single bus and power was shown flowing between the states.

c. Annual Transmission Revenue Requirement (ATRR)

Phil Crissup provided and Paul Suskie gave a presentation on “ATRR: What is it? Why it matters, and How is it Calculated?” The presentation illustrated the effect of depreciation, the importance and components of Net Plant Carrying Charge, and, ultimately, how costs are assigned and recovered by zone.

d. Staff White Paper on Analytical Methods for Unintended Consequence Review

Paul Suskie presented the White Paper outlining OATT requirements, Staff research, and recommendations on regional allocation “reasonableness review”. The group recommended changing the term “unintended consequence review” to “reasonableness review” to better match the OATT. Additionally, a discussion about the use of legal standards from the 7th Circuit in the PJM cost allocation appeal as well as FERC Order 1000. Details of a wide range of benefit metrics were reviewed. A proposal was given on tiered and staged approaches to B/C ratio calculations with possible threshold values:

Harry Skilton, SPP Director, requested pro forma studies to test the concepts. The team also recommended that “Seams” agreements be added to the possible remedy list.

Minutes No. 2

The Staff White Paper also presented a draft RARTF schedule:

e. Review of RARTF Charter

Paul Suskie reviewed the RARTF Charter. No official vote was required or taken. No changes noted or suggested.

f. Call for Stakeholder proposals were made to augment or modify the Staff White Paper. Paul Suskie noted that the White Paper can be transformed into the RARTF’s official proposal.

5. SCHEDULING OF NEXT REGULAR MEETING, SPECIAL MEETINGS OR EVENTS

a. Conference Call...............................................................August 18, 2011, 1:30pm C.S.T.

b. Next Face to Face Meeting………..September 22 and 23, 2011 in Dallas, TX

6. ADJOURNMENT Chairman Siedschlag adjourned the meeting at 12:00pm on Friday, August 5th, 2011. Respectfully Submitted, Paul Suskie Senior Vice President and General Counsel Southwest Power Pool RARTF Secretary

Minutes No. 2



August 4th and 5th, 2011

Crowne Plaza Hotel, Dallas, TX

• Summary of New Action Items •

1. Provide the RARTF a list of Highway/Byway projects (NTC and without NTCs)

2. Provide the RARTF a list of historical B/C ratios for SPP projects

3. Provide the RARTF a list of SPP zonal load ratio shares

4. Provide the RARTF net plant carrying charges for SPP members

5. Begin to define “roughly commensurate”

6. Transition from “unintended consequences review” to the “reasonableness review”

7. Begin the transition from “RARTF Staff White Paper” to “RARTF Recommendation”

8. Notify SPP Stakeholders of the Call for proposals and/or changes to the Staff Whitepaper.

• Summary of Action Items from June 24th, 2011 Meeting •

1. At the face to face meeting in Dallas in August, conduct a cost and benefit tutorial including descriptions of models, parameters, assumptions, data review, applications as applied to asset recovery.

2. Also at the first face to face meeting, Staff should present a draft of the RARTF Whitepaper discussing analytical methods of determining deficiency thresholds and potential remedies.

3. Expand/provide a “methods” definition to include the process of determining costs and benefits. 4. Begin to define the threshold of a “deficiency” in zonal benefits versus allocated costs.

5. Begin to develop remedies to deficiencies that exceed threshold limits.

6. Target the first face to face meeting date of August 5th, 2011, noon through August 6th, 2011

noon. Provide all necessary meeting arrangements. Also target August 18th and 19th, 2011 for an additional teleconference in August.

7. Establish monthly meetings in September, October, and November, 2011. Develop a matrix of possible dates for Task Force Member input.

8. Include ratification of the RARTF Charter at the first face to face meeting in Dallas on August 4 and 5th, 2011.

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Regional Allocation Review Task Force White Paper

In approving the Highway/Byway cost allocation methodology for the Southwest Power Pool, Inc. (SPP) Regional Transmission Organization (RTO), the Federal Energy Regulatory Commission (FERC) also approved a requirement that SPP conduct a review of the “reasonableness of the regional allocation methodology and factors (X% and Y%) and the zonal allocation methodology at least once every three years.”1 This review is required to “determine the cost allocation impacts of the Base Plan Upgrades with Notifications to Construct issued after June 19, 2010 to each pricing Zone within the SPP Region.”2 Thus, the purpose of this analysis is to measure the “cost allocation impacts” of SPP’s Highway/Byway methodology by zones. The review is hereinafter referred to as the SPP Highway/Byway has been often referred to by SPP Stakeholders as the “ReasonablenessUnintended Consequences Review.”

SPP’s Open Access Transmission Tariff (OATT) specifically requires that “the Markets and Operations Policy Committee [MOPC] and Regional State Committee [RSC] will define the analytical methods to be used” in conducting the Reasonableness Runintended consequences review.3 As a result, SPP’s stakeholder process created a Regional Allocation Review Task Force (RARTF) to develop the “analytical methods” used for the review.

Per its mandate under the RARTF Charter, In order to assist the RARTF and SPP stakeholders, the RARTF SPP staff has prepared this White Paper which includes its recommendation as to how to define as a beginning point to facilitate the process of defining the “analytical methods” to be used in the Reasonable Unintended Consequences Rreview.

1.1 Overview of SPP Tariff Requirements

Attachment J, Section III.D to the SPP OATT establishes a four‐step process for the Runintended consequenceseasonableness R review. These steps are:

Step 1: One year prior to each three‐year planning cycle (starting in 2013) the Markets and Operations Policy Committee and Regional State Committee will define the analytical methods to be used to report under this Section III.D and suggest adjustments to the Regional State Committee and Board of Directors on any imbalanced zonal cost allocation in the SPP footprint.4

Step 2: For each review conducted in accordance with Section III.D.1, the Transmission Provider shall determine the cost allocation impacts of the Base Plan Upgrades with Notifications to Construct issued after June 19, 2010 to each pricing Zone within the SPP Region. The Transmission Provider in collaboration with the Regional State Committee shall determine the cost allocation impacts utilizing the analysis specified in Section III.e of Attachment O and the results produced by the analytical methods defined pursuant to Section III.D.4(i) of this Attachment J.5

Step 3: The Transmission Provider shall review the results of the cost allocation analysis with SPP’s Regional Tariff Working Group, Markets and Operations Policy Committee, and the Regional State 1 Attachment J, Section III.D.1 of SPP’s OATT. 2 Attachment J, Section III.D.2 of SPP’s OATT. 3 Attachment J, Section III.D.4(i) of SPP’s OATT. 4 Id. 5 Attachment J, Section III.D.2 of SPP’s OATT.

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Committee. The Transmission Provider shall publish the results of the cost allocation impact analysis and any corresponding presentations on the SPP website.6

Step 4: The Transmission Provider shall request the Regional State Committee provide its recommendations, if any, to adjust or change the costs allocated under this Attachment J if the results of the analysis show an imbalanced cost allocation in one or more Zones.7

1.2 Cost Allocation Challenges for Transmission Upgrades

The allocation of costs for public projects with significant and widespread public benefits is very challenging and difficult. This is particularly true for electric transmission projects as has been stated by the FERC:

Determining the costs and benefits of adding transmission infrastructure to the grid is a complex process, particularly for projects that affect multiple systems and therefore may have multiple beneficiaries. At the same time, the expansion of regional power markets and the increasing adoption of renewable energy requirements have led to a growing need for transmission projects that cross multiple utility and RTO systems. There are few rate structures in place today that provide the allocation and recovery of costs for these intersystem projects, creating significant risk for developers that they will have no identified group of customers from which to recover the cost of their investment.8

The difficulties of implementing cost allocation methods for transmission projects are evident with the many challenges to, and critics of, the policies that are actually adopted.9 Because of the many challenges associated with regional transmission cost allocation and its accompanying critics, it is critical that SPP’s Reasonableness Runintended consequences review be based upon reasonable, sound, and defensible methods.

2.1 SPP Staff Research for this White Paper

In preparation of and research for this White Paper, SPP staff embarked on research to gather information that will be helpful to SPP Stakeholders in developing analytical methods to review both the cost and the benefits of SPP transmission projects. Hence, SPP staff researched how transmission costs are allocated in the various regions of the United States and the various ways that benefits are calculated for transmission projects. A summary of SPP staff’s research is provided below to help the RARTF and SPP Stakeholders with begin the process of defining the analytical methods to be used for SPP’s Reasonableness RUnintended Consequence Review. From the research of SPP staff below,

6 Attachment J, Section III.D.3 of SPP’s OATT. 7 Attachment J, Section III.D.4 of SPP’s OATT. 8 Transmission Planning Processes Under Order No. 890, Notice of Request for Comments at 5, Docket No. AD09‐8‐000 (Oct. 8, 2009). 9 See, Illinois Commerce Commission v. FERC, 576 F.3d 470 (7th Cir. 2009) and Senator Corker (TN‐R) Senate Bill 400: A bill to amend the Federal Power Act to ensure that rates and charges for electric energy are assessed in proportion to measurable reliability or economic benefit, and for other purposes.

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Stakeholders can better gauge both the difficulty of allocating cost of transmission projects and gain a better understanding of the number of methods available for use in measuring the benefits of transmission projects. The RARTF SPP staff believes that this information can help the RARTF and SPP Stakeholders to develop sound analytical methods to determine the impacts (or unintended consequences) of SPP’s Highway/Byway cost allocation methodology that are reasonable, sound, and defensible.

2.2 Transmission Cost Allocation Methods in the United States and SPP

The difficulties of transmission cost allocation are demonstrated by the wide variety of methods used in the various regions of the United States. This difficulty is further demonstrated by the inability of most regions to adopt transmission cost allocation methodologies for regional overlay projects. This is effectively illustrated in Figure 1, below, which presents a summary of our Nation’s various transmission cost allocation methods, as prepared by the Brattle Group.

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0Copyright © 2011 The Brattle Group, Inc.

Summary of Current Cost Allocation Methodologies

RTO/Region

General Tariff Methodology Reliability “Economic” Projects

Renewables Regional/Overlay Projects

CAISO PS 100% ≥200kV; otherwise LP or M GI and location-constrained

resource tariff (Tehachapi)

Not specifically discussed, but 100% PS of all network facilities

ERCOT PS or MCREZ (100% PS) Not specifically discussed,

but 100% PS of all network facilities

SPP Before 6/19/10: 33% PS+67% LP w/ Beneficiary AnalysisAfter 6/19/10: 100% PS ≥300kV; 33% PS+67% LP >100kV to <300kV; 100% LP ≤100kV

GI; Highway/Byway PS treatment

Highway/Byway PS treatment

Southeast LP (utility specific tariffs) n/a n/a (GI only) n/a

ISO-NE PS 100% ≥115kV; otherwise LP or M

too narrowly defined

n/a (GI only) n/a

PJM PS sharing 100% ≥500kV; otherwise LP allocation (beneficiary pays) or M


n/a (GI only) n/a

MISO PS sharing 20% ≥345kV; rest LP allocation (beneficiary pays) or M; MVP approach


Multi Value Project (“MVP”) PS treatment

MVP PS treatment

PJM-MISO Sharing of reliability project based on net flows/beneficiaries


n/a n/a

NYISO LP allocation (based on beneficiary pays) or M


n/a (GI only) n/a

WECC (non-CA)

LP; often with cost allocation based on co-ownership

(differs across WECC subregions)

GI (e.g., BPA open season); under discussion in WREZ

n/a – under discussion in WREZ

LP = License Plate Tariffs; PS = Postage Stamp Tariffs or Postage Stamp Allocation; M = Merchant Lines; GI = Generation Interconnection Tariffs; = workable approach; n/a = workable approach not yet available

Figure 1. Cost Allocation Methodologies of Regions of the United States10

Similar to how the different regions of the United States have developed a variety of cost allocation methodologies, so has SPP. Since SPP’s recognition as an RTO and the establishment of the RSC,11 the SPP Region has developed and implemented differing transmission cost allocations in an evolutionary manner through the RSC. These methods are summarized below in Figure 2.

10 Reprinted with permission by The Brattle Group, Inc.: Delphine Hou and Johannes P. Pfeifenberger, "Financing Transmission Expansion: The Impact of Cost Allocation," presented to EUCI, March 8‐9, 2011. (Slide 9 updated July 2011). 11 Through SPP’s governance structure, the SPP RSC has been delegated authority to establish cost allocations that the SPP Board of Directors must file at FERC as a Section 205 filing of under the Federal Power Act.

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Figure 2. SPP Cost Allocation Methods

The most recent method established by the RSC and approved by FERC is the Highway/Byway cost allocation methodology. The Highway/Byway method assigns 100% of all 300+ kV transmission upgrades’ Annual Transmission Revenue Requirement (ATRR) to the SPP zones on a regional basis using the Load Ratio Share (LRS), as a percentage of the whole of regional loads, of each zone multiplied by the total ATRR of the new upgrade. New upgrades with a voltage rating between 100 kV and 300 kV are allocated 33% to all zones in the region on a LRS basis and 67% to the host zone’s Transmission Customers (TCs). New upgrades under 100 kV are allocated 100% to the TCs of the host zone.

Figure 3. Highway/Byway Cost Allocation Overview

The ATRRs assigned to the zones are collected from their respective TCs using the previous year’s 12 month Coincident Peak LRS.

Cost allocation of new construction is the focus of Attachment J to the SPP OATT. The recovery of the ATRR is through Schedule 11 of the OATT and booked by each zone in Attachment H of the OATT.

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2.3 Methods of Measuring Transmission Upgrade Benefits

Just as SPP staff’s research found that a number of transmission cost allocation methods are used in the United States, staff’s research has found that a number of methods can be used to determine the amount of benefits transmission projects provide to society.

Based upon this research, the RARTF SPP staff recommends that the benefits to be assessedment review for the Reasonableness RUnintendeeview d Consequences should not be limited to a single methodology. Instead, the RARTFstaff recommends that in order to study a broader scope and a breadth of benefits in the region, multiple methodologies should be used. Staff believes that a very narrow focus on only one benefit type over a very narrow timeframe, does not provide a large enough sample size to reasonably determine the impact of SPP’s Highway/Bywayif Unintended Consequences truly exist. Additionally, because different benefits are valued differently by various people and segments of society; the RARTFstaff believes that in order to provide for a reasonable, fair, and acceptable review of the Highway/Byway numerous methods should be used in this review as opposed to a single narrowly‐ focused method. This White Paper outlines the RARTF’s staff’s recommendations.

As illustrated below in Figure 4, a number benefits can gained from transmission projects.

Figure 4. Benefits of a Robust Transmission System

SPP staff’s research has found that a number of benefits exist that can be measured under a benefit to cost analysis. Although the RARTF SPP staff does not recommend using all of these benefits for the Unintended Consequence Review, they are included below for educational purposes.

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Adjusted Production Cost

Adjusted Production Cost (APC) has quickly become the “standard” that utilities are employing to measure the benefit of transmission expansion. APC is a measure of the impact on production cost savings by Locational Marginal Price (LMP), taking into account purchases and sales of energy between areas of the transmission grid. APC is determined using a production cost modeling tool that accounts for 8,760 hourly commitment and dispatch profiles for one simulation year. Nodal analysis from the production cost model is aggregated on a zonal basis.

APC captures the monetary cost associated with fuel prices, run times, grid congestion, ramp rates, energy purchases, energy sales, and other factors that are directly related to energy production by generating resources in the SPP footprint.

References to an APC‐based B/C (Adjusted Production Cost‐based Benefit‐to‐Cost ratio) refer to the reduction in APC due to a project divided by the cost of that project.

Meeting State and Utility Goals and Standards

This metric links a transmission project to meeting the goals and standards set forth by the utilities and states that are in a study analysis. Simply put – does a transmission project or portfolio positively contribute to the success of an entity in meeting its stated goals or standards. Traditionally, utilities have looked at standards or goals for renewable energy, but this metric could be extended to plans such as Demand Side Management, Energy Efficiency and SMART grid initiatives.

Improvements in Reliability (value of improving the ability to keep the lights on)

This metric has three distinct components:

• Value of delaying or eliminating the need for previously approved reliability projects: This component monetizes (quantifies) the reliability benefit as the avoided cost (or additional cost) in dollars of delaying, canceling, or accelerating previously approved reliability projects.

• Value of improved Available Transfer Capabilities (ATCs) of the SPP grid: This component provides a non‐monetized (qualitative) assessment of the added flexibility for the potential redirection of power flows within SPP made possible by ATC increases. The challenge in defining this metric is the development of a meaningful weighting structure of ATC defined for multiple combinations of points of receipt and points of delivery.

• Value of providing a backstop to a catastrophic event: This component provides a qualitative assessment of improved grid reliability and its ability to withstand the impact of catastrophic events. This component requires the assessment of catastrophic events and the determination of their probability.

Enable Efficient Location of New Generation Capacity

This metric is a quantitative measure of the ability of a transmission project or portfolio to provide for efficient location of new generation capacity. For wind resources, SPP measured distance from the transmission hubs to high wind resource zones. SPP has not yet determined a methodology to use for conventional generation.

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Reduced Losses

Transmission expansion has an impact on total system losses. This metric serves as a first step in calculating Positive Impact on Capacity required for losses (shown below) and gives a qualitative measure for evaluating the relationship between a reduction in losses and the monetary and physical savings from reduced capacity and capital costs.

Increased Effective Capacity Factor

This metric is a measure of the value of adding transmission to reduce congestion on curtailed resources. The capacity factor may change due to a reduction in congestion.

Ability to Reduce Cost of Capacity

This metric captures the value from reducing the cost of capacity. This metric is an opportunity to capture value which is not currently being captured. SPP does not currently utilize this metric, and it will require additional tools to calculate which are not currently being used by SPP.

Positive Impact on Capacity Required for Losses

This metric captures a value for the generation capacity that may no longer be required due to a reduction in losses. Due to a lower amount of losses on the system, there is a lower need for generation capacity to support system loses, improving capacity margins.

Levelization of Locational Marginal Price (LMP)

This metric provides a qualitative indicator of the impact an alternate transmission topology could make on regional generation owners’ ability to compete on equal grounds. In the absence of congestion and losses on the system, any generator has the potential to serve any load, and there will be a single system price in each hour. A transmission system with no constraints and low losses makes the electricity market more competitive, as it provides an equal opportunity to all generators with similar costs to compete for loads.

In such transmission systems, the market for new entry will also be more competitive. An increase in congestion and losses places generators at certain locations at a disadvantage relative to other similar‐cost generators, making the market less competitive. This metric measures the levelization of LMPs for each transmission topology using the standard deviation of LMPs across locations for the SPP footprint. All else being equal, a decrease in the value of this metric indicates an improvement in the competitiveness of the SPP market.

Improved access to economical resources participating in SPP markets

This metric provides a qualitative measure of competitiveness across the SPP footprint. It analyzes a generating unit’s ability to compete within its own technology type. Capacity‐weighted LMPs are calculated for generating plants of different technology types on an hourly basis, and then averaged across 25% of the largest hourly standard deviations.

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Change in operating reserves

This metric provides a measure for the impact on operating reserves due to transmission expansion. Calculation of this metric requires a capacity expansion model which SPP does not currently license. This metric could provide an opportunity to capture value from reducing operating reserves.

Transmission Loading Relief (TLR) Reduction ‐ Enabling Market Solutions

This metric has been utilized in the past to determine the impact on TLR Reduction for transmission expansion plans; however, with the implementation of the Day Ahead market in SPP, the need for Transmission Loading Relief calls between SPP Balancing Authorities will be eliminated. Congestion will be managed by economic security constrained unit commitment and dispatch.

Improvements to Import/Export Limits

This metric quantifies the change in ATC that corresponds to an alternative topology in the Cost‐Effective Plan. Three categories of ATC changes are of interest and addressed by this metric:

• From major generation centers within SPP to key delivery points on the boundary of SPP. This category relates to export capability improvements.

• From key external receipt points at the boundary of SPP to load centers within SPP. This category relates to import capability improvements.

• From key external receipt points at the boundary of SPP to key delivery points on the boundary of SPP. This category relates to improvements in the ability of SPP to accommodate wheel‐through transactions.

Improved economic market dynamics not measured in the security constrained economic dispatch model

This metric quantifies the impacts on market dynamics that are not captured in a traditional production cost tool. This metric has not been calculated by SPP; however, it should be evaluated for use in future assessments as there is the potential to calculate value not currently being captured by other metrics.

Improved economic market dynamics measured in the nodal security constrained economic dispatch model

This metric measures the impacts on market dynamics as seen in production cost analysis. However, because this metric requires calculating the generation loading distribution factor for every hour, SPP has not yet been able to calculate this metric. Future assessments should evaluate this metric to capture additional value.

Reduction in market price volatility

This metric measures the reduction of market price volatility for transmission expansion projects. This metric requires using a stochastic model which SPP does not currently have the ability to process. Future assessments should reevaluate this metric to determine a calculation method which could be used to capture reductions in market price volatility.

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Reduction of emission rates and values

If an alternative topology results in a lower fossil fuel burn (or less coal‐intensive generation), then SO2, NOX, CO2, and Hg emissions would be lower with the alternative topology in place. APC captured the cost savings associated with reduced SO2, NOX, and CO2 emissions because the allowance prices for these pollutants were inputs to the production cost model simulations. However, since mercury is not a pollutant subject to an allowance price, changes in coal generation and the corresponding changes in mercury emissions are not currently captured.

This metric addresses that analytical deficiency and quantifies the changes in mercury emissions. This metric also quantifies the changes in SO2, NOX, and CO2 emissions so that they may be represented as stand‐alone values, separate from APC.

Transmission corridor utilization

Transmission expansion plans that effectively utilize existing right‐of‐way (ROW) and have topology that largely avoids environmentally sensitive areas are preferable to those that do not, all else being equal.

The metric is comprised of two sub‐metrics. The first sub‐metric measures the proportion of transmission expansion plan costs that do not effectively utilize existing ROW. The second sub‐metric measures the proportion of transmission expansion plan costs that traverse environmentally sensitive areas.

Ability to reduce cycling of base load units

This metric evaluates the benefit derived from reducing cycling of large base load generating plants. For purposes of this metric, a cycle occurs each time a unit’s output crosses or reaches the average output, then recedes below this average minus a tolerance during any start‐up to shut‐down period. A transmission project that reduces the total number of cycles for a base load unit would reduce maintenance costs and prolong the unit’s life span.

If SPP had data on the relationship between the number of cycles and operations and maintenance cost, or had a dollar value associated with excessive versus normal or ideal cycling, this metric could be monetized to determine a value to generators from reduced cycling.

Generation resource diversity

Transmission topology that results in a more diverse generation capacity expansion plan would add benefit because the power system could respond more flexibly to relative fuel price changes.

This is a semi‐quantitative metric based on generation mix (energy basis) from the production cost model simulation. For a given future, this metric is a comparison of the generation mixes (energy basis) from the cost‐effective topology and an alternative topology. Both the annual generation mix and the fuel‐on‐the‐margin mix are considered. Of particular interest is whether gas‐fired generation approaches or exceeds a specific percentage of the generation mix, because the level and volatility of gas prices is typically relatively high compared to the level and volatility of coal and nuclear fuel prices.

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Excessive dependence on gas‐fired generation ‐ to the detriment of a more balanced dispatch of gas, oil, coal, and nuclear energy ‐ exposes ratepayers to greater fuel price risk.

Ability to serve unexpected new load

This metric measures the ability of an alternative transmission topology to serve new load at levels that are different from those considered in APC. The metric tests two types of load changes: an overall incremental load in proportion to load forecast used in the development of each future and load shifts between major load centers.

Part of overall EHV Overlay Plan

This metric serves as an indicator to determine how a project fits in with the overall EHV Overlay Plan. If a project keeps appearing across multiple studies, it is a strong candidate for future development. This metric applies value for projects that fit in well with the overall goals of EHV expansion for a region.

3.1 SPP StaffRARTF Recommendations For the Reasonsableness Unintended Consequences Review

Based upon research, stakeholder input and extensive discussionexperience, the RARTF SPP staff recommends that the Reasonableness RUnintended Consequences review contain two components. First, a three‐tiered analytical methodology evaluating different benefits will be considered. Second, the review should be conducted looking at transmission projects in stages.

3.2 SPP StaffRARTF Recommendation: Three Tiered Benefit Analysis Approach

Because both a too conservative approach and a too broad approach to analyzing benefits of transmission projects can be problematic, the RARTF SPP staff proposes using a three‐tiered approach that utilizes three perspectives for transmission benefit assessment. As described below, these methods include a type of method with conservative benefits, moderate benefits, and broad benefits. These methodologies are incremental and contemplate benefits from the prior tier, i.e., the moderate approach considers all benefits from the conservative approach, plus additional value metrics. The three recommended methodologies are discussed below.

Conservative Approach

The first tiered approach is the conservative approach.12 This approach consists of using the following metrics:

• Dispatch Savings, • Loss Reductions, • Avoided Projects, • Applicable Environmental Impacts, • Reduction in Required Operating Reserves, and

12 See Attachment O, Section III.8.e to the SPP OATT.

Comment [p1]: To be further reviewed by the RARTF.


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• Interconnection Improvements.

The APC metric is an industry‐accepted, well‐utilized analysis technique often used to determine the benefits of a transmission construction project from a generation cost perspective. This metrics captures the following items: dispatch savings, energy loss reduction and interconnection improvements. This technique looks at the cost a zone must pay for electric power before and after a transmission upgrade is constructed. This is accomplished by looking at the cost a zone will pay to generate its own electric power, plus the cost of any purchase power required, and subtracts off the revenue from any power sales that are being generated. This is the APC for that zone. This is shown mathematically below.

Adj Prod Cost = Production Cost ‐ Revenue from Sales + Cost of Purchases

Where:

Revenues from Sales = MW Export x Zonal LMPGen Weighted

and

Cost of Purchases = MW Import x Zonal LMPLoad Weighted

The APC metric provides a measurement of the impact of a project under an Energy Market. Since SPP is moving towards implementation of an Energy Market by 2014, this will provides an indication of how these transmission projects may perform in that market.

Value of delaying or eliminating the need for previously approved reliability projects: This metric monetizes (quantifies) the reliability benefit as the avoided cost (or additional cost) in dollars of delaying, canceling, or accelerating previously approved reliability projects.

Additionally, metrics will need to be determined to capture the impact on operating reserves and environmental impacts and interconnection improvements.

Moderate Approach

• The second tiered approach is the moderate approach. This approach consists of using the methodology from the conservative approach, but adds the following benefit metrics: Meeting State and Utility Goals and Standards,

• Positive Impact on Capacity Required for Losses, and • Improvements in Reliability.

This approach takes a broader look at the benefits for the footprint. It takes into consideration value of the improvements to reliability for the projects in construction, the impact of the losses from a capacity perspective, as well as the value of meeting state and utility goals.

Many states and utilities have mandated renewable portfolio standards or set renewable goals. These standards provide a positive impact to society by lowering the overall emissions of traditional fossil fuel plants. In order to help meet these renewable targets or goals, SPP provides its members a transmission

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planning function. These transmission planning tools enable the members to meet their goals or targets in the future.

An objective of transmission development is to meet the goals and standards of a state or utility. These goals can range from NERC Reliability Standards to a renewable portfolio goal/target for a state. The objective of this metric is to determine if a set of transmission projects is enabling a state or utility to meet its stated goals and/or targets. This metric will use engineering analysis to determine if a set of projects will allow or assist an entity in meeting its overall goals and standards.

The positive impact on capacity required for losses evaluates the reduction in expenditure for generation expansion due to loss requirements for the construction of transmission. This metric will capture the value for the generation capacity that may no longer be required due to a reduction in losses and capacity margin. Due to reduced losses on the system, there is less need for generation capacity to support system losses.

The last metric considered for the moderate approach is the improvements to reliability, which has two components:

• Value of improved ATCs of the SPP grid: This metric provides a non‐monetized (qualitative) assessment of the added flexibility for the potential redirection of power flows within SPP made possible by ATC increases. The challenge in defining this metric is the development of a meaningful weighting structure of ATC defined for multiple combinations of points of receipt and points of delivery.

• Value of providing a backstop to a catastrophic event: This metric provides a qualitative assessment of improved grid reliability and its ability to withstand the impact of catastrophic events electrically expressed as multiple contingencies. This metric requires the assessment of catastrophic events and the determination of their probability.

Broad Approach

The final tiered approach is the broad approach. This approach consists of using the methodology from the moderate approach, but adds to it the metric of Societal Benefit.

Traditional methods of transmission benefit assessment do not take into account factors that are outside the realm of a utilities business. For any construction project, there are benefits to society and the local economy that go beyond the primary purpose of the construction project. These benefits include, but are not limited to, the following:

• Overall economic output during construction, • Overall jobs impact during construction, • Additional earnings related to construction jobs impact, • Overall economic output during operation, • Overall jobs impact during operation, • Additional earnings related to operation jobs impact, and • Tax benefits to the state.

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3.3 SPP StaffRARTF Recommends Analyzing Transmission Projects in 4 Stages

Per SPP’s OATT, the first Unintended ConsequencesReasonableness Review analysis will begin in 2013. At that point in time, there will be a few transmission projects in service with NTCs issued under the Highway/Byway cost allocation method.13 Because of the limitation of the number of projects in service at the time of the 2013 Unintended ConsequenceReasonableness Review and due to the long‐term nature of transmission facility investments, it will be important to evaluate how Unintended benefits and cost impacts Consequences occur over a longer timeframe than just the current year. For example, if an inequity Unintended Consequences exist for a zone in 2013, but transmission projects are due to come into service in 2014 that will remedy an an inequityunintended consequences disparity, then it may not be appropriate to enact certain remedies in the short‐term due to the sequenced nature of transmission projects as they are placed in service.

The RARTFSPP staff recommends that the Unintended Reasonableness Review Consequence analysis be conducted on transmission projects at varying stages in time over a 40‐year timeframe. 14 The RARTFStaff’s recommendation is that the analysis be conducted in four stages: (1) projects in‐service at the time of the study, (2) projects projected to be in‐service in 6 years, (3) projects projected to be in service in 10 years; and (4) projects projected to be in service in 20 years. The 6, 10, and 20‐year stages mirror SPP’s planning timelines defined in SPP’s OATT.

The first stage of analysis will consider the impacts of transmission construction in service at the time of the study. In this analysis only Highway/Byway transmission projects that are in service at the current time will be considered. This stage will determine the immediate impact to the zones in the region for transmission charges to date.

The second stage will consider the impacts of transmission construction projects in the short‐term. In this analysis, any Highway/Byway transmission project in the approved ITP Near‐Term with an in service date within the next 6 years will be considered.

The third stage will consider the impacts of transmission construction projects over a mid‐term period. In this analysis, any Highway/Byway transmission project in the approved ITP10 with an in service date within the next 10 years will be considered.

The fourth stage will consider the impacts of transmission construction projects over a long‐term period. In this analysis, any Highway/Byway transmission project in the approved ITP20 with an in service date within the next 20 years will be considered.

It is important to note that these recommended stages of analysis are only snapshots in time in which projects are evaluated. As to the timeframe for evaluating each stage, a 40‐year impact will be calculated. For example, for the first stage, considering only projects in service at the time of the

13 INSERT DATA ON EXPECTED PROJECTS IN SERVICE. 14 Section II.8.e to Attachment O of the SPP OATT requires SPP to use a financial modeling time frame of 40 years (with the last 20 years provided by a terminal value).


Formatted: Highlight



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analysis, those projects would still be considered for a 40‐year horizon. The same rule applies to each additional stage.15

3.4 Unintended ConsequencesRemedy Threshold

Per the its Charter, request of the RARTF, SPP staff recommends that a n Unintended Consequences threshold be established to determine when a remedy is warranted based upon th results of a Highway/Byway Reasonableness Review. This threshold will defines when a zonal mitigation is n Unintended Consequences determination will triggered zonal mitigation. If a zone is determined to be below this threshold, mitigation may be necessary to prevent undue unintended consequences.

It is recommended that the threshold utilized as a part of a Reasonableness Review for the Unintended Consequences take a broad look at the overall benefits for each of the recommended stages and metric methods considered for the analysis. In other words, the threshold will apply to the 40‐year analysis of the four stages of transmission projects using the three‐tiers of assessed benefits.

The RARTF SPP staff recommends that an initial threshold be set at a .8 B/C ratio for the conservative‐tiered analysis, and .9 B/C ratio for the moderate‐tiered analysis, and a 1.0 B/C ratio for the broad‐tiered analysis. These ratios will be applied to each of the tiered approaches over the four proposed stages, that is to say, each tier will be summed up from the current year through year 20. This number will be averaged for each tier to represent a final value. This value will be compared to the threshold index chosen for each tier and given a pass/fail result. If a zone passes the analysis for a minimum of two‐thirds of the categories, then it is determined to have no zonal mitigation is neededunintended consequences. The chart below shows how the RARTF staff proposes that the threshold will work.

Figure 5. RARTF Analytic Approaches with Proposed Threshold Values

15 Id.


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3.5 Proposed Unintended Consequences Mitigation Zonal Mitigation

If the results for a zone following an Reasonableness Review are below the an Unintended Consequences threshold in Section 3.4, mitigation may be implemented to reduce negative zonal impacts. The RARTF SPP staff recommends that, in addition to the current authority of the RSC on Cost Allocation issues, the following mitigation techniques may be used to alleviate unintended consequences:

• Acceleration of already planned upgrades required to bring benefits to a deficient zone earlier to offset unreasonable unintended consequences of other upgrades; • Issuance of NTCs for selected new upgrades required to bring benefits to a deficient zone to offset unreasonableintended consequences of other upgrades; and • Zonal Transfers (similar to Balanced Portfolio Transfers) to offset costs or a lack of benefits to a zone to offset unreasonable intended consequences.

3.6 Proposed Reasonableness Unintended Consequences Review Timeline

The RARTF SPP staff proposes the following Action Plan to conduct the Reasonableness Unintended Consequences Review.

Figure 6. RARTF Proposed Action Plan

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