Southwest Power Pool REGIONAL ALLOCATION REVIEW TASK … · Minutes No. 1 Southwest Power Pool...

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Minutes No. 2 Southwest Power Pool REGIONAL ALLOCATION REVIEW TASK FORCE MEETING August 4 th and 5 th , 2011 Crowne Plaza Hotel, Dallas, TX • MINUTES • 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 4 th 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

Transcript of Southwest Power Pool REGIONAL ALLOCATION REVIEW TASK … · Minutes No. 1 Southwest Power Pool...

Page 1: Southwest Power Pool REGIONAL ALLOCATION REVIEW TASK … · Minutes No. 1 Southwest Power Pool RARTF MEETING Friday, June 24, 2011 (10:00 AM - 12:00 PM) Teleconference: 877-932-5833

Minutes No. 2

Southwest Power Pool

REGIONAL ALLOCATION REVIEW TASK FORCE MEETING

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

Page 2: Southwest Power Pool REGIONAL ALLOCATION REVIEW TASK … · Minutes No. 1 Southwest Power Pool RARTF MEETING Friday, June 24, 2011 (10:00 AM - 12:00 PM) Teleconference: 877-932-5833

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.

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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

Page 4: Southwest Power Pool REGIONAL ALLOCATION REVIEW TASK … · Minutes No. 1 Southwest Power Pool RARTF MEETING Friday, June 24, 2011 (10:00 AM - 12:00 PM) Teleconference: 877-932-5833

Minutes No. 2

Southwest Power Pool

REGIONAL ALLOCATION REVIEW TASK FORCE MEETING

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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RARTF Agenda

August 4 (12:00 p.m. – 5:00 p.m.)

& August 5 (8:00 a.m. – 12:00 p.m.)

Crowne Plaza Downtown, Dallas, Texas.

1. CALL TO ORDER

2. PRELIMINARY MATTERS a. Declaration of a Quorum b. Announcement of Participants c. Approval of June 24, 2011 minutes

3. PRESENTATIONS a. Modeling Cost Benefits 101 ...................................................................................... SPP Staff b. Review of RARTF Charter ................................................................................... Bill Dowling c. SPP Staff White Paper/Straw Proposal for RARTF ........................................... Paul Suskie d. RARTF & Stakeholder Feedback to Staff White Paper/Straw Proposal .......................... All e. Call for Stakeholder Proposals for RARTF ............................................ Michael Siedschlag

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

a. Potential Dates for 2nd Meeting ......................................................................... August 2011 5. ANNOUNCEMENTS & ADJOURNMENT

Page 6: Southwest Power Pool REGIONAL ALLOCATION REVIEW TASK … · Minutes No. 1 Southwest Power Pool RARTF MEETING Friday, June 24, 2011 (10:00 AM - 12:00 PM) Teleconference: 877-932-5833

Minutes No. 1

Southwest Power Pool

RARTF MEETING

Friday, June 24, 2011 (10:00 AM - 12:00 PM) Teleconference: 877-932-5833

Passcode: 157403

• Summary of Action Items •

1. At the face to face meeting, Staff will conduct a cost and benefit tutorial (101) on how cost are

allocated and a description of how benefits are calculated.

2. Staff should present a draft of a RARTF Whitepaper proposing analytical methods to be used to determine impacts on zones of both cost and benefits. This should also include: * Provide “methods” to include the process of determining costs and benefits. * How to determine deficiency thresholds.

* Develop remedies for deficiencies that exceed threshold limits.

3. Include review of the RARTF Charter at the first face to face meeting.

4. Hold the first face-to-face meeting August 4th, 2011 (Noon-5:00 pm) and August 5th, 2011 (8:00-Noon). SPP Staff to provide all necessary meeting arrangements. Also target August 18th and 19th, 2011 for an additional teleconference in August.

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

Page 7: Southwest Power Pool REGIONAL ALLOCATION REVIEW TASK … · Minutes No. 1 Southwest Power Pool RARTF MEETING Friday, June 24, 2011 (10:00 AM - 12:00 PM) Teleconference: 877-932-5833

Minutes No. 1

Southwest Power Pool

RARTF MEETING

Friday, June 24, 2011 (10:00 AM - 12:00 PM) Teleconference: 877-932-5833

Pass code: 157403

• 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 10:00 am with the declaration of a Quorum. Role was called and the following attendees were confirmed: 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 Skelton, SPP Director Paul Suskie, SPP Staff Secretary Teleconference Participants: Kip Fox, AEP Thomas Hestermann, Sunflower Bernard Lui, Xcel Michael Moffet, Sunflower Elaina Larsen, KCC John Krafski, NE PRB Pat Smith, KCC Andrew Schulte, KCC Dan Jones, SPP Staff Agenda Item 3 - Welcome

Welcome and initial thoughts were given by Chairman Siedschlag. Bary Warren, EDE, expressed optimism towards a solution that will be built through consensus.

Harry Skelton, SPP Director, asked specifically for a tutorial describing the mechanics of cost and benefit analysis including models, parameters, assumptions, data, market impact and applications in utility recovery. Paul Suskie said the tutorial will be given at the first face to face meeting in Dallas in early August.

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Minutes No. 1

Agenda Item 4 – Business Meeting

a. Overview of Attachment J, Section III.D Review ..................................................... Paul Suskie

Paul Suskie gave a presentation on the specific Tariff section requiring a review of the Regional Cost Allocation at least every three years which has lead to the formation of the RARTF. Additionally Suskie discussed issues related to what thresholds could require remedies and what possible remedies could exist. An overview of RARTF transparency through the use of email exploders and open meetings was also discussed.

b. Proposed Schedule for RARTF.................................................................... Michael Siedschlag

The need for monthly face to face meetings in September, October, and November was discussed.

a. SPP Staff Straw Agenda Proposal for July RARTF Meeting ………………….…….Paul Suskie

Key Items:

• Presentation of Cost and Benefit analysis tutorial • Presentation of a Draft-Whitepaper on Analytical Methods of determining Costs, Benefits,

Deficiencies with potential Thresholds, and potential Remedies • Ratification of the RARTF Charter

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

b. Potential Dates for 1st Meeting..............................July 21 or 22 or August 1 or 2 (DFW Hyatt)

August 4th starting at noon and ending August 5th at noon were determined to be the best dates for the RARTF first face to face meeting in Dallas. 6. ADJOURNMENT Chairman Siedschlag adjourned the meeting at 11:05 a.m. Respectfully Submitted, Paul Suskie Senior Vice President and General Counsel Southwest Power Pool RARTF Secretary

Page 9: Southwest Power Pool REGIONAL ALLOCATION REVIEW TASK … · Minutes No. 1 Southwest Power Pool RARTF MEETING Friday, June 24, 2011 (10:00 AM - 12:00 PM) Teleconference: 877-932-5833

8/3/2011

1

Benefit/Cost Ratio Primer101 101

for the

Regional Allocation Review Task Force

1

August 4, 2011

SPP PLANNING AND COST ALLOCATION OVERVIEW

2

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2

Transmission = 10% Retail Electricity Rates 

3

Transmission enables optimal use of our region’s diverse generating resources, including coal, natural gas, hydroelectric, nuclear, and wind energy

How does SPP decide what and where transmission is needed?

• Generation Interconnection Studies

D t i t i i d d d t– Determines transmission upgrades needed to connect new generation to electric grid

• Aggregate Transmission Service Studies

– Determines transmission upgrades needed to transmit energy from new generation to loadto load

– Shares costs of studies and new transmission

• Specific transmission studies

• Integrated Transmission Planning process4

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3

Why do we need more transmission?

5

• In the past, built least‐cost transmission to meet local needs

• Today, proactively building “superhighways” to benefit region

Finding Balance

         More

SPP Today

Minimum for Reliable 

nvestm

ent                               

Expand Transmission

More Transmission 

Needed

Delivery to Customers

6Less                  Amount of Transmission                     More

Less                          In

Customer Energy Cost

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What is congestion?

• Congestion or “bottlenecks” happen when you can’t get energy to customers along a certain path

– Desired electricity flows exceed physical capability

• Congestion caused by:

– Lack of transmission, often due to load growth

– Line and generator maintenance outages

– Unplanned outages such as storms or trees on lines

7

– Too much generation pushed to grid in a particular location

– Preferred energy source located far from customers

• Results in inability to use least‐cost electricity to meet demand

500 kV

Congestion prevents access to lower‐cost generation

345 kV

230 kV

161 kV138 kV

115 kV69 kV

88 8

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Congestion’s Impact on Wholesale Market  Prices

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What is Integrated Transmission Planning?

• Goal: Design transmission backbone to connect load to the most reasonable generation alternatives

S h i d i– Strengthen ties to Eastern and Western Interconnections

– Improve connections between SPP’s east and west regions

• Horizons: 20, 10, and 4 year – 40 years

• Focus: Regional, integrated with local

• Resulting in: Comprehensive list of needed projects for SPP region over next 20 yearsregion over next 20 years

– With 40 year financial/economic analysis

• Underlying Value: Reliability and Economics are inseparable

10

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Integrated Transmission PlanningConceptual

• Increasing Refinement

• Reducing Uncertainty

• Narrowing Focus

ITP20

ITP10

Near Term

11

Implementation

Integrated Transmission Planning Process

• Reliability Analysis

– Annual Near‐Term plan

– Identifies potential problems and needed upgrades

– Coordinates with ITP10, ITP20, Aggregate and Generation Interconnection study processes

• Economics and Reliability AnalysisAnalyzes transmission system for 10 year horizon

12

‐ Analyzes transmission system for 10‐year horizon‐ Establishes timing of ITP20 projects

‐Develops 345 kV+ backbone for 20‐year horizon‐Studies broad range of possible futures

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Transmission planners consider:• What parts of grid need strengthening to “keep the lights on”?

– Redundancies necessary to account for a line being out

• Where is current and future generation located?

• Where are electricity consumers located?

• Where on the grid do we frequently see congestion (more traffic than roads can accommodate)?

• Will laws mandating more renewable energy or a carbon tax impact traffic?

• How do coal/gas prices impact traffic?

– People will use more coal if gas prices rise, and vice versa

• How do regional temperatures impact traffic?

– If temperature  differs across region, one area may need more energy 

13

Generation = 60% Retail Electricity Rates

Without transmission, we can’t deliver this capital-intensive generation to where it’s needed across region

14

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• Sponsored: Project owner builds and receives credit for use of transmission lines

Who pays for these transmission projects?

• Directly‐assigned: Project owner builds and recovers cost through retail rates

• Highway/Byway: Most SPP projects paid for under this methodology

Voltage Region Pays Local Zone Pays

1515

300 kV and above 100% 0%above 100 kV and below 300 kV 33% 67%

100 kV and below 0% 100%

Projects Constructed 2005‐2010

16

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Projects with Notifications to Construct

17

Balanced Portfolio

1818

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Priority Projects

19

2010 Plan for 2030

20

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POWER WORLD DEMONSTRATION

21

BENEFIT ANALYSIS BACKGROUND

22

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Background: Cost Allocation ‐ H/B 101

2323

Background: Adjusted Production Cost

• Adjusted Production Costs (APC):

– Industry accepted metric tied to generation costsy p g

– Based on a Day Ahead Market:  Locational Marginal Price (LMPs)

– Measures benefit on an hourly basis, over a year’s simulation

– Adjusted means that the simulation takes into account jthe purchase and sale of economic energy

– Price nodes are aggregated by zone

24

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Background: APC Formulation

APC = Production Cost – Revenue from Sales + Cost of Purchases

Where

Revenue from Sales= MW Export x Zonal LMP gen weighted

And

C t f P h MW I t Z l LMPCost of Purchases = MW Import x Zonal LMP load weighted

25

Background: Input Assumptions• Fuel Price Forecasts

– Coal, Gas, Oil, Uranium

• Generating Unit Parameters

– Operating Characteristics

– Ramp Rates

– Availability:  Forced Outages, Maintenance Schedules

– Wind Profiles

• Load Forecasts:  Peak Demand, Energy Profiles

• Hurdle Rates Between Utilities & Regions

• Transmission Topology

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Background: Benefits, Outputs

• APC captures the effects of:

– Fuel Prices

– Run Times

– Congestion

– Ramp Rates

– Energy Purchases

– Energy Sales

– Emission Costs (Environmental)

27

Background: Benefits, Benchmarking

• Benchmarking uses planning data to compare to historical operations

• This is an important step to build confidence in model results

• It’s important to note:  since historical data is an imbalance market, and planning is on a day ahead market, results should not match exactly

• Instead, benchmarking represents a “sanity test” to validate a model

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Generation by Unit Category in SPPCoal and combined cycle gas generation sources provide 79% of the total generation in the simulation. Historically, according to the EIA, these sources provided 77%. The gas prices between 2010 and the simulation warrant this difference.

29

Hydro Generation by Month

30

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Operating & Spinning Reserve

31

Generator Maintenance Outages

• Graph of capacity outaged by time period

• Correlates with GADS data

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• PROMOD® simulations do not take transmission 

Transmission Line & Transformer Outages

maintenance into account

• This is an everyday operational concern

• Take Away:  Results from PROMOD may demonstrate lower benefit than may be actual

33

Average LMP by Area

• The average LMP of each area trends well with the results of the EIS market in 2008, 2009, and 2010

34

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ITP10 Load at PeakExpectedDemand @ PeakAug 3rd, 5pm2022

35

Serving Kansas City

36

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Current Goals & Standards

Wind Energy

37 TWh for Future 1

10%2020

52 TWh for Future 2

Other Renewable Energy

2 TWh for both futures

Approximate RES %

20%2020

15%2021

15%2015

20%2020

14% in Future 1

20% in Future 2

37

5,880 MW by 2015

Future 1 CongestionNumber of Flowgates 

Binding

48 flowgates

Avg. Shadow Price

Average Shadow Price ($/MWh)

$0.5 ‐ $2

4.19 $/MWh

_____________

Hours with Congestion

7,563

$0.5 $

$2 ‐ $8

$8 ‐ $15

$15 ‐ $30

$30 ‐ $45

Red indicates % of binding hours at 

flowgate

Highest Prices in Hours

July 13th 1500July 13th 1600July 13th 1700

38

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20

Benefits/Cost (B/C) Ratio Computation

• Benefits are determined on a zone by zone basis for a year

• This benefit is compared to the allocated costs by each zone

• This gives a B/C ratio

• A B/C ratio of 1.0 means that a project just pays for itselftse

39

HYPOTHETICAL RTO EXAMPLE

40

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Intro: Hypothetical RTO (H‐RTO)

• RTO B/C 101 at the request of the RARTF is designed to provide background for RARTF to better understanding /B/C Ratios

• RTO B/C 101 uses a Hypothetical RTO (H‐RTO)

• H‐RTO has Five Zones, “A” thru “E”

• H‐RTO has 2 sets of transmission upgrades:  

Portfolio I (2011 13 @ $107 5M)– Portfolio I (2011‐13 @ $107.5M)  

– Portfolio 2 (2014‐16 @ $92.5M)

41

H‐RTO Considerations

Cost Allocation Methodology:

• H‐RTO has the same Cost Allocation Method as SPP (Highway/Byway)

• H‐RTO load share ration for each zone is computed the same as SPP – CP 12

Benefit Approach:

• H RTO uses 2 approaches to calculating B/C Ratios• H‐RTO uses 2 approaches to calculating B/C Ratios

– Adjusted Production Cost (APC) B/C

– Societal B/C

42

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H‐RTO: CHARACTERISTICS AND FACTS 

43

H‐RTO Foot Print

Zone A Zone B

44

Zone C Zone D Zone E

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H‐RTO Foot Print ‐ Overview

• Zone A and Zone B in the west are high renewable zones with 

Zone C

Zone A

low cost power

• These zones wish to move renewable energy to the east

45

H‐RTO Foot Print ‐ Overview

• Zones B, D & E are higher cost zones with a desire to import renewable energy

Zone D

Zone E

Zone B

46

D

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H‐RTO Foot Print ‐ Overview

Zone B

Congestion

Zone C

Zone A

Zone D Zone E

Zone B

47

• Congestion exists between the western and the eastern zones

• This congestion limits the import of desired energy

Load Ratio Share

Hypothetical RTO – Load Ratio Share (12CP)

A B

A, 41.7%C, 16.7%

D, 13.3%E, 3.3%

A

B

C

Zone

C D E

B, 25.0%

D

E

48

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Hypothetical RTO – Characteristics by Zone

49

H‐RTO PORTFOLIO 1 PROJECTS: 2011‐13

50

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H‐RTO Portfolio 1 Projects

A1 A2

Zone C

Zone A

Zone E

Zone B

51

Zone C Zone D Zone E

E1

H‐RTO: Portfolio I (2011‐2013) 

52

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Portfolio 1: First Year Cost Allocated by Zones

53

Portfolio 1: C/A by Zone to 2051

54

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Portfolio 1: APC Benefits Zones (2013)

1.6

Zone Costs APC B/CZone A 7,337,396$            9,000,000$                    1.2Zone B 4,402,438$            6,000,000$                    1.4Zone C 2,934,958$            2,900,000$                    1.0Zone D 2,347,967$            1,700,000$                    0.7

0.6

0.8

1.0

1.2

1.4 Zone E 727,242$               50,000$                          0.117,750,000$         19,650,000$                  1.11          

55

0.0

0.2

0.4

Zone A Zone B Zone C Zone D Zone E

$40,000,000 

$45,000,000 

Portfolio 1: APC + Societal Benefit (2013)

Zone Est. Benefit APC + Societal B/CZone A 8,000,000$            17,000,000$                  2.3Zone B 4,000,000$            10,000,000$                  2.3Zone C 1,000,000$            3,900,000$                    1.3

$15 000 000

$20,000,000 

$25,000,000 

$30,000,000 

$35,000,000 

APC Benefit

Societal Benefit

Zone D 3,500,000$            5,200,000$                    2.2Zone E 600,000$               650,000$                       0.9

17,100,000$         36,750,000$                  2.1

$‐

$5,000,000 

$10,000,000 

$15,000,000 

Zone A Zone B Zone C Zone D Zone E

56

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Portfolio 1: Benefits to 2051

$50,000,000

$60,000,000

P1:  APC Benefit Over Time

$20,000,000

$30,000,000

$40,000,000

57

$0

$10,000,000

Zone A Zone B Zone C Zone D Zone E

Portfolio 1: 40 Year Benefits vs Costs

$140,000,000 

P1:  40 Year Benefit vs Costs (APC Only)

$40 000 000

$60,000,000 

$80,000,000 

$100,000,000 

$120,000,000 Benefits

Costs

58

$‐

$20,000,000 

$40,000,000 

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H‐RTO PORTFOLIO 2 PROJECTS: 2014‐16

59

H‐RTO Portfolio 2 Projects

B1

B2

Zone C

Zone A

Zone E

Zone B

60

Zone C Zone D Zone E

C1 D1

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HRTO: Portfolio 2 (2014‐2016) 

61

Portfolio 2: Cost Allocated by Zones

62

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Portfolio 2: C/A by Zone to 2051

63

ALL PORTFOLIO PROJECTS: 2011‐16PORTFOLIO 1 & 2 COMBINED

64

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All Portfolio Projects

A1 A2 B1

B2

Zone C

Zone A

Zone E

Zone B

65

Zone C Zone D Zone EC1

D1E1

H‐RTO: All Portfolios (2011‐2016) 

66

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All Projects: By Zone (H/B)

67

All Projects: Cost Allocation by Zones

68

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All Portfolio: C/A by Zone to 2051

69

Portfolio 1 & 2: APC Benefits Zones (2016)*

1.4

1.6 Zone Costs APC B/CZone A 12,492,292$         17,000,000$                   1.4Zone B 8,148,625$            12,000,000$                   1.5Zone C 4,996,917$            3,000,000$                     0.6Zone D 3,997,533$            4,100,000$                     1.0Zone E 1 139 633$ 100 000$ 0 1

0.6

0.8

1.0

1.2

Zone E 1,139,633$            100,000$                        0.130,775,000$         36,200,000$                   1.18          

70*Note: Portfolio 2 is incremental to Portfolio 1, i.e. both Portfolios together account for the benefit shown

0.0

0.2

0.4

Zone A Zone B Zone C Zone D Zone E

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$40,000,000 

$45,000,000 

Portfolio 1 & 2: APC + Societal Benefits (2016) *

Zone Est. Benefit APC + Societal B/CZone A 12,000,000$         29,000,000$                   2.3Zone B 7,000,000$            19,000,000$                   2.3Zone C 3,000,000$            6,000,000$                     1.2

$ $

$15,000,000 

$20,000,000 

$25,000,000 

$30,000,000 

$35,000,000 

APC Benefit

Societal Benefit

Zone D 4,200,000$            8,300,000$                     2.1Zone E 700,000$               800,000$                        0.7

26,900,000$         63,100,000$                   2.3

$‐

$5,000,000 

$10,000,000 

Zone A Zone B Zone C Zone D Zone E

71*Note: Portfolio 2 is incremental to Portfolio 1, i.e. both Portfolios together account for the benefit shown

Portfolio 1 & 2: Total Benefit to 2051

$60,000,000

P1&2: APC Benefit Over Time

$20,000,000

$30,000,000

$40,000,000

$50,000,000

72

$0

$10,000,000

Zone A Zone B Zone C Zone D Zone E

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Portfolio 1 & 2: 40 Year Benefits vs Costs

$140,000,000 

P1 & 2 : 40 Year Benefit vs Costs (APC Only)

$40,000,000 

$60,000,000 

$80,000,000 

$100,000,000 

$120,000,000  Benefits

Costs

73

$‐

$20,000,000 

Who is “losing”?

Zone APC + Societal APC + SocietalZone E 0.07                       0.89                      0.09 0.70                     Zone C 0.99 1.33 0.60 1.20

2013 2016

• Zone E is still a “loser” after even societal benefits are added to the equation

• Zone C and D are “losers” at points in time

• Zones A and B are always “winners” 

Zone D 0.72 2.21 1.03 2.08

y

74

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What about remedies??

• Possible Remedies:

– Revenue Transfers

– Advance Projects/Staging Timing

– New Projects (Portfolio 3?)

75

Contact Information

• Paul Suskie, Sr. Vice President & General Counsel

[email protected] @ pp g

501‐688‐2535

• Charles Cates PE, Lead Engineer

[email protected]

501‐614‐3351

• Dan Jones PE, Lead Engineer

[email protected]

501‐688‐1717

76

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1

Annual Transmission Revenue Requirement

ATRR: What is it, Why it Matters and H i it l l t d?How is it calculated?

Annual Transmission Revenue Requirement

• What is it?

• Why it matters.

• How is it calculated.

• A Simple Example.

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2

ATRR: What is It?

• The Annual Transmission Revenue Requirement (ATRR) is the amount of Revenue that the(ATRR) is the amount of Revenue that the Transmission Owner receives from SPP for RECOVERY OF its expenses (Cost of Debt, O&M, Depreciation, Taxes) for the project andEARNINGS ON the project (Return On Equity).

• ATRR set in a Section 205 filing with the FERC for gjurisdictional utilities or in a rate filing a state commission.– By either a ‘Stated Rate’ or ‘Formula Rate’

ATRR: Why it MattersYear 0

ATRRn= Net Plant * Net Plant Carrying Charge (NPCC) of Transmission Owner building Project)(NPCC) of Transmission Owner building Project) until Project is fully depreciated

Example: Year 0Net Plant = $100 million ProjectNPCC = 16%D i ti $0Depreciation = $0Life = 40 years

ATRR0 = $100M * 16% = $16M

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3

ATRR: Why it MattersYear 1

ATRRn= Net Plant * Net Plant Carrying Charge (NPCC) of Transmission Owner building Project)(NPCC) of Transmission Owner building Project)

Example: Year 1

Net Plant = $100M Project

NPCC = 16%

Depreciation = $2 5MDepreciation = $2.5M

Life = 40 years

ATRR1 = $97.5M * 16% = $15.6M

ATRR: Why it MattersYear 2

ATRRn= Net Plant * Net Plant Carrying Charge (NPCC) f T i i O b ildi(NPCC) of Transmission Owner building Project)

Example: Year 2

Net Plant = $100M Project

NPCC 16%NPCC = 16%

Depreciation = $2.5M

ATRR2 = $95.0M * 16% = $15.2M

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4

ATRR: How is it calculated?

ATRRn= Net Plant * Net Plant Carrying Charge (NPCC) f T i i O b ildi P j t(NPCC) of Transmission Owner building Project

n = 1, 40 (or other depreciable life of Asset

Net Plant = Cost of Project – Accumulated Depreciation

Net Plant Carrying Charge = Weighted Average Cost of Capital + O&M + Taxes + Depreciation

ATRR: How is it calculated?

• Net Plant Carrying Charge = Weighted Average C t f C it l O&M T D i tiCost of Capital + O&M + Taxes + Depreciation

• Weighted Average Cost of Capital (WACC) = Cost of Debt * Debt/Equity ratio + Return On Equity (ROE) * (1 – Debt/Equity ratio)

In Example:In Example:

• WACC = 8%*(.5) + 11%*(.5) = 9.5%

• NPCC = 9.5% + 4% + 2% + 2.5% = 16%

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5

ATRR: Effect of Depreciation Over Time

$16.00 

$18.00 

$6.00 

$8.00 

$10.00 

$12.00 

$14.00 

Depreciation

ATRR

$‐

$2.00 

$4.00 

1 4 7 10 13 16 19 22 25 28 31 34 37 40

Effect on Net Plant over time due to Accumulated Depreciation

$120.00 

$40.00 

$60.00 

$80.00 

$100.00 

Net Plant

Accumulated Depreciation

$‐

$20.00 

1 4 7 10 13 16 19 22 25 28 31 34 37 40

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6

Annual Transmission Revenue Requirement

ATRR: What is it, Why it Matters and H i it l l t d?How is it calculated?

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8/4/2011

1

SPP Staff White Paper on Analytical Methods for 

i d dUnintended Consequence ReviewRARTF Meeting

August 4‐5, 2011Dallas, TexasDallas, Texas

Paul [email protected] 501.688.2535

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2

SPP Staff White Paper for RARTF.

SPP Staff White Paper is divided into 3 Sections

• Section 1 – Contains an overview of SPP Tariff Requirement

• Section 2 – Contains SPP Staff’s research

• Section 3 – Contains SPP Staff’s recommendations 

3

SPP Staff White Section 1

• Section 1.1 ‐ Overview of SPP Tariff Requirements

• Section 1.2 ‐ Cost Allocation Challenges for Transmission Upgrades 

4

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3

SPP Staff White Section 2.

• Section 2.1 ‐ SPP Staff Research for this White Paper

• Section 2.2 ‐ Transmission Cost Allocation Methods in the United States and SPP

• Section 2 3 ‐Methods of Measuring Transmission Upgrade• Section 2.3 ‐Methods of Measuring Transmission Upgrade Benefits 

5

SPP Staff White Section 3. 

• Section 3.1 ‐ SPP Staff Recommendations For Unintended Consequences Review 

• Section 3.2 ‐ SPP Staff Recommendation: Three ‐Tiered Benefit Analysis Approach

• Section 3.3 ‐ SPP Staff Recommends Analyzing Transmission Projects in 4 Stages 

• Section 3.4 ‐ Unintended Consequences Threshold 

• Section 3.5 ‐ Proposed Unintended Consequences Mitigation 

• Section 3.6 ‐ Proposed Unintended Consequences Review Timeline 

6

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4

Section 1.1 – SPP Tariff Requirements

• 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 C i d d f iCommittee and Board of Directors on any imbalanced zonal cost allocation in the SPP footprint.

7

Section 1.1 – SPP Tariff Requirements

• 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 allocationCommittee 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.

8

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5

Section 1.1 – SPP Tariff Requirements

• 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 Committee.  The Transmission Provider shall publish the results of the cost allocation impact analysis and any corresponding presentations on the SPP website Attachment J Section III D 3 ofthe SPP website. Attachment J, Section III.D.3 of SPP’s OATT.

9

Section 1.1 – SPP Tariff Requirements

• 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.

10

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Section 1.2 – Cost Allocation Challenges“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 developersintersystem projects, creating significant risk for developers that they will have no identified group of customers from which to recover the cost of their investment.”

FERC Transmission Planning Processes Under Order No. 890, Notice of Request for Comments at 5, Docket No. AD09‐8‐000 (Oct. 8, 2009). 11

Section 2.2 – Cost Allocation Methodologies

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Section 2.2 – SPP Cost Allocation Methods

13

Section 2.3 – Methods of Measuring Benefits

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• Adjusted Production Cost

• Meeting State and Utility Goals and Standards

• Improvements in Reliability

• Transmission Loading Relief (TLR) Reduction ‐ Enabling Market Solutions 

• Improvements to Import/Export Limits

• Improved economic market dynamics not 

Section 2.3 – Methods of Measuring Benefits

p o e e ts e ab ty

• Enable Efficient Location of New Generation Capacity 

• Reduced Losses 

• Increased Effective Capacity Factor 

• Ability to Reduce Cost of Capacity

• Positive Impact on Capacity Required for Losses

p o ed eco o c a et dy a cs otmeasured in the security constrained economic dispatch model 

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

• Reduction in market price volatility 

• Reduction of emission rates and values Losses 

• Levelization of Locational Marginal Price  

• Improved access to economical resources participating in SPP markets 

• Change in operating reserves 

• Transmission corridor utilization 

• Ability to reduce cycling of base load units 

• Generation resource diversity 

• Part of overall EHV Overlay Plan 

• Ability to serve unexpected new load 

15

Section 3.1 – SPP Staff REcommendation

• Based upon research and experience SPP staffBased upon research and experience, SPP staff recommends that the Unintended 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.

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Section 3.2 – Recommendation: 3‐Tiered Approach

• Because both a too conservative approach and a too broad approach to analyzing benefits of transmission 

j b bl i SPP ff iprojects can be problematic, 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 

l b fi f h i i i hcontemplate 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.

17

Section 3.2 – 1st Conservative Approach

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

– Dispatch Savings,

– Loss Reductions,

– Avoided Projects,

Applicable Environmental Impacts– Applicable Environmental Impacts,

– Reduction in Required Operating Reserves, and

– Interconnection Improvements.

* Note: The proposed conservative approach comes directly from Attachment O, Section III.8.e to the SPP OATT. 18

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Section 3.2 – 1st Conservative Approach

• 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

19

Section 3.2 – 2nd 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.

20

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Section 3.2 – 2nd Moderate Approach

• Value of improved ATCs of the SPP grid:  This metric provides a non‐monetized (qualitative) assessment of the added fl ibilit f th t ti l di ti f fl ithiflexibility 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 d l f d dmetric 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.  

21

Section 3.2 – 3rd Broad Approach

• This approach consists of using the methodology from the moderate approach, but adds to it the metric of Societal B fit Th b fit i l d b t t li it d t thBenefit . . . 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,

O ll i t t d i ti– 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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Section 3.3 – Analyzing Projects in 4 Stages 

• SPP staff recommends that the Unintended Consequence analysis be conducted on transmission projects at varying t i ti 40 ti f St ff’stages in time over a 40‐year timeframe. Staff’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(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. 

23

Section 3.4 – Unintended Consequences Threshold 

• Per the request of the RARTF, SPP staff recommends that an Unintended Consequences threshold be established.  This th h ld ill d fi h U i t d d Cthreshold will define when an Unintended Consequences determination will trigger 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 for the Unintended Consequences take a broad look at the overall b f f h f h d d dbenefits 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. 

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Section 3.4 – Unintended Consequences Threshold 

• 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 f th d t ti d l i d 1 0 B/C ti f thfor 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/failthreshold 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 unintended consequences.  The chart below shows how staff proposes that the threshold will work.

25

Section 3.4 – Unintended Consequences Threshold 

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Section 3.4 – Unintended Consequences Mitigation• If the results for a zone are below an Unintended Consequences 

threshold, mitigation may be implemented to reduce negative zonal impacts.  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 unintended consequences of other upgrades;

27

– Issuance of NTCs for selected new upgrades required to bring benefits to a deficient zone to offset unintended 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 unintended consequences.

Section 3.5 – Proposed Timeline 

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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 has been often referred to by SPP Stakeholders as the “Unintended 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  unintended  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. 

In  order  to  assist  the  RARTF  and  SPP  stakeholders,  SPP  staff  has  prepared  this White  Paper  as  a beginning  point  to  facilitate  the  process  of  defining  the  “analytical  methods”  to  be  used  in  the Unintended Consequences review.   

1.1 Overview of SPP Tariff Requirements 

Attachment  J,  Section  III.D  to  the  SPP  OATT  establishes  a  four‐step  process  for  the  unintended consequences 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 unintended 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 begin the process of defining the analytical methods to be used for SPP’s Unintended Consequence Review.  From the research of SPP staff below, Stakeholders can better gauge both  the difficulty of  allocating  cost of  transmission projects  and  gain  a better understanding of  the 

                                                            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. 

2  

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number  of methods  available  for  use  in measuring  the  benefits  of  transmission  projects.    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. 

   

3  

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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

too narrowly defined

n/a (GI only) n/a

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

too narrowly defined

Multi Value Project (“MVP”) PS treatment

MVP PS treatment

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

too narrowly defined

n/a n/a

NYISO LP allocation (based on beneficiary pays) or M

too narrowly defined

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, SPP staff recommends that the benefit assessment review for the Unintended Consequences should not be limited to a single methodology.  Instead, staff 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 if Unintended Consequences truly exist.  Additionally, because different benefits are valued differently by various  people and segments of society;  staff  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 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 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 Staff Recommendations For Unintended Consequences Review  

Based upon research and experience, SPP staff recommends that the Unintended 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 Staff 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, 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 • Interconnection Improvements. 

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

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

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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 Staff Recommends Analyzing Transmission Projects in 4 Stages  

Per SPP’s OATT, the  first Unintended Consequences 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.   Because of  the  limitation of  the number of projects  in  service at  the  time of  the 2013  Unintended  Consequence  Review  and  due  to  the  long‐term  nature  of  transmission  facility investments,  it  will  be  important  to  evaluate  how  Unintended  Consequences  occur  over  a  longer timeframe  than  just  the  current  year.    For  example,  if Unintended  Consequences  exist  in  2013,  but transmission  projects  are  due  to  come  into  service  in  2014  that  will  remedy  an  unintended 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.   

SPP  staff  recommends  that  the  Unintended  Consequence  analysis  be  conducted  on  transmission projects  at  varying  stages  in  time over  a  40‐year  timeframe.  13      Staff’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 analysis, those projects would still be considered for a 40‐year horizon.   The same rule applies to each additional stage.14 

 

                                                            13 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).  14 Id.  

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3.4 Unintended Consequences Threshold  

Per  the  request of  the RARTF, SPP staff  recommends  that an Unintended Consequences  threshold be established.   This  threshold will define when an Unintended Consequences determination will  trigger 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 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.  

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 unintended consequences.   The chart below shows how staff proposes that the threshold will work. 

 

Figure 5.  RARTF Analytic Approaches with Proposed Threshold Values 

3.5 Proposed Unintended Consequences Mitigation  

If  the  results  for  a  zone  are  below  an  Unintended  Consequences  threshold,  mitigation  may  be implemented to reduce negative zonal  impacts.   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: 

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• Acceleration of already planned upgrades required to bring benefits to a deficient zone earlier to offset unintended consequences of other upgrades; • Issuance of NTCs  for  selected new upgrades  required  to bring benefits  to a deficient  zone  to offset unintended 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 unintended consequences. 

3.6 Proposed Unintended Consequences Review Timeline  

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

 

Figure 6.  RARTF Proposed Action Plan 

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Southwest Power Pool ‐ Regional Allocation Review Task Force  Charter 

June 9, 2011    

PURPOSE 

The Regional Allocation Review Task Force (RARTF) is responsible for defining “the analytical methods to be used” to “review the reasonableness of the regional allocation methodology and factors (X% and Y%) and the zonal allocation methodology.”  The analytical method shall be designed 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.”  (Reference the Southwest Power Pool Open Access Transmission Tariff, Attachment J, Section III.D.)  The analytical methodology will form a basis for the RSC to consider improvements, if any, to the long term cumulative equity of cost allocation and benefits for members resulting from SPP’s Integrated Transmission Planning process.   After establishing proposed “analytical methods to be used” to “review the reasonableness” of the regional and zonal allocation methodology, the RARTF shall prepare and present a report to the Market and Operations Policy Committee (MOPC) and the Regional State Committee (RSC) for approval.  As stated in Attachment J to the SPP Tariff, SPP Staff will use the approved “analytical methods” to perform a review to “determine the cost allocation impacts of the Base Plan Upgrades with NTCs issued after June 19, 2010 to each pricing zone within the SPP Region.”  Further, after SPP Staff completes its determination of the cost allocation impacts and possible solutions, Staff shall publish the results on the SPP website and present the results to the Regional Tariff Working Group (RTWG), Cost Allocation Working Group (CAWG), MOPC, the RSC, and the SPP Board of Directors per Section III.D.3  of Attachment J to the SPP Tariff.    REPRESENTATION 

The RARTF will be a seven (7) member joint task force made up of representatives of the RSC and SPP Members and a member of the Board of Directors.  Three (3) task force members shall be composed of members of the RSC and three (3) members shall be SPP Members.  A RSC member shall serve as Chair and a SPP member shall serve as Vice‐Chair.  The RSC and SPP Members representatives shall be appointed by the RSC President and MOPC Chairman and shall represent diverse members.  Selection of such representatives shall consider, among other factors, geography, member type and expertise.  The seventh member of the RARTF will be appointed by the SPP Board of Directors.    Members of the RARTF shall have experience and knowledge in one or more of the following areas: 

• Economics, economic modeling , modeling for simulation analysis, and/or cost of service determinations 

• SPP Transmission Tariffs and Rates • Cost allocation in general, and SPP regional cost allocation practices in particular • Retail cost allocation recovery and rate payer impact for SPP members • Quantitative methods for decision analysis 

  

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DURATION 

The RARTF will be a temporary task force.  It is anticipated that its work will be completed by December 20, 2011, though the task force will continue its work until it is completed.  Meetings 

All meetings of the RARTF, whether in person or telephonic, shall be open to participation by all stakeholders in SPP, and advance notice of such meetings shall be provided  via the SPP website. Meeting materials including discussion topics, handouts and other meeting information will be posted via the SPP website as early as possible.  The task force may engage other SPP stakeholders and consultants (as deemed necessary by the RARTF) to participate in discussions related to particular topics, though this will not make such stakeholders voting members of the task force.  Stakeholders with proposals or alternative ideas shall be allowed to present their proposals or alternatives to the task force.    SPP Staff Support 

The SPP Staff shall have at least one individual in attendance for all meetings of the RARTF to serve as a Staff Liaison and Secretary for the task force who will be responsible for keeping and issuing minutes for the RARTF meetings.  Other members of the SPP Staff may be requested to assist in particular endeavors of the task force.  REPORTING 

The RARTF will provide status reports to the RSC and the MOPC at least on a quarterly basis at the regularly scheduled meetings.  The task force may make additional status reports to the CAWG, RSC and MOPC as it deems necessary.   

The RARTF will make final recommendations to the MOPC and the RSC regarding the analytical methods to be used to review the reasonableness of the regional allocation methodology for the approval of both the MOPC and RSC.  In addition to developing the analytical methods to be used in the analysis, the RARTF will provide SPP Staff guidance as to the Task Force’s expectation for the threshold for an unreasonable impact or cumulative inequity.  The RARTF shall prepare and issue the report by December 20, 2011. 

COST ALLOCATION IMPACT ASSESSMENT BASED ON APPROVED ANALYTICAL METHODS 

Upon the approval of the RARTF’s report by the MOPC and RSC, SPP staff, “in collaboration with the RSC” shall determine the cost allocation impacts and possible solutions utilizing the RARTF approved analytical methods.  SPP Staff shall report the cost allocation impacts and possible solutions by July 1, 2013.  Proposed solutions may include, but are not limited to, adjustments to the Highway/Byway, transfer payments, approval of projects in specific zones, etc.  After SPP Staff completes its determination of the cost allocation impacts and possible solutions, Staff shall publish the results on the SPP website and present the results to the RTWG, CAWG, MOPC the RSC, and the Board of Directors per Section III.D.3  of Attachment J to the SPP Tariff.    After receiving the Staff report on cost allocation impacts and possible solutions the RSC will consider issuance of recommendations.  Upon any recommendation from the RSC, the necessary filing with the FERC will be made by SPP in accordance with SPP Bylaws and Section III.D.5 of Attachment J to the SPP Tariff.   

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KEY DELIVERABLES OF THE TASK FORCE  The RARTF scope of work and key deliverables include the following:  

1. Development of and recommendation for a methodology to be used to determine the current and cumulative long‐term equity/inequity of the currently effective cost allocation for transmission construction/upgrade projects on each SPP Pricing Zone and/or Balancing Authority.  

2. Develop a recommendation regarding a threshold for determining an unreasonable impact or cumulative inequity on an SPP Pricing Zone or Balancing Authority. 

3. Develop a list of possible solutions for SPP staff to study for any unreasonable impacts or cumulative inequities on an SPP Pricing Zone or Balancing Authority.   

4. Final report containing such recommendations to be prepared and issued by December 20, 2011.