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
Minutes No. 2
RARTF’s June 24, 2011 Minutes were approved. Agenda Item 3 – Presentations
a. Benefit/Cost Ratio Primer
A presentation was given by SPP Staff Members Paul Suskie, Charles Cates, and Dan Jones on calculating and modeling costs and benefits. Overviews were given on the SPP transmission planning methods, regional and zonal details, and upgrades approved to date. A hypothetical RTO (H-RTO) was also presented. Using the H-RTO as a model, Staff illustrated annual costs and benefits attributed to zones from new upgrades. Benefit/Cost ratios were calculated using the H-RTO model, details of zonal differences were explored and discussed. Analogies were drawn between the H-RTO and the SPP RTO.
b. PowerWorld Review
A simplified PowerWorld model was reviewed with each state in the SPP RTO give a single bus and power was shown flowing between the states.
c. Annual Transmission Revenue Requirement (ATRR)
Phil Crissup provided and Paul Suskie gave a presentation on “ATRR: What is it? Why it matters, and How is it Calculated?” The presentation illustrated the effect of depreciation, the importance and components of Net Plant Carrying Charge, and, ultimately, how costs are assigned and recovered by zone.
d. Staff White Paper on Analytical Methods for Unintended Consequence Review
Paul Suskie presented the White Paper outlining OATT requirements, Staff research, and recommendations on regional allocation “reasonableness review”. The group recommended changing the term “unintended consequence review” to “reasonableness review” to better match the OATT. Additionally, a discussion about the use of legal standards from the 7th Circuit in the PJM cost allocation appeal as well as FERC Order 1000. Details of a wide range of benefit metrics were reviewed. A proposal was given on tiered and staged approaches to B/C ratio calculations with possible threshold values:
Harry Skilton, SPP Director, requested pro forma studies to test the concepts. The team also recommended that “Seams” agreements be added to the possible remedy list.
Minutes No. 2
The Staff White Paper also presented a draft RARTF schedule:
e. Review of RARTF Charter
Paul Suskie reviewed the RARTF Charter. No official vote was required or taken. No changes noted or suggested.
f. Call for Stakeholder proposals were made to augment or modify the Staff White Paper. Paul Suskie noted that the White Paper can be transformed into the RARTF’s official proposal.
5. SCHEDULING OF NEXT REGULAR MEETING, SPECIAL MEETINGS OR EVENTS
a. Conference Call...............................................................August 18, 2011, 1:30pm C.S.T.
b. Next Face to Face Meeting………..September 22 and 23, 2011 in Dallas, TX
6. ADJOURNMENT Chairman Siedschlag adjourned the meeting at 12:00pm on Friday, August 5th, 2011. Respectfully Submitted, Paul Suskie Senior Vice President and General Counsel Southwest Power Pool RARTF Secretary
Minutes No. 2
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.
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
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.
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.
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
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
8/3/2011
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
8/3/2011
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
8/3/2011
4
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
8/3/2011
5
Congestion’s Impact on Wholesale Market Prices
9
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
8/3/2011
6
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
8/3/2011
7
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
8/3/2011
8
• 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
8/3/2011
9
Projects with Notifications to Construct
17
Balanced Portfolio
1818
8/3/2011
10
Priority Projects
19
2010 Plan for 2030
20
8/3/2011
11
POWER WORLD DEMONSTRATION
21
BENEFIT ANALYSIS BACKGROUND
22
8/3/2011
12
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
8/3/2011
13
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
26
8/3/2011
14
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
28
8/3/2011
15
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
8/3/2011
16
Operating & Spinning Reserve
31
Generator Maintenance Outages
• Graph of capacity outaged by time period
• Correlates with GADS data
32
8/3/2011
17
• 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
8/3/2011
18
ITP10 Load at PeakExpectedDemand @ PeakAug 3rd, 5pm2022
35
Serving Kansas City
36
8/3/2011
19
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
8/3/2011
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
8/3/2011
21
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 @ $92.5M)
41
H‐RTO Considerations
Cost Allocation Methodology:
• H‐RTO has the same Cost Allocation Method as SPP (Highway/Byway)
• H‐RTO load share ration for each zone is computed the same as SPP – CP 12
Benefit Approach:
• H RTO uses 2 approaches to calculating B/C Ratios• H‐RTO uses 2 approaches to calculating B/C Ratios
– Adjusted Production Cost (APC) B/C
– Societal B/C
42
8/3/2011
22
H‐RTO: CHARACTERISTICS AND FACTS
43
H‐RTO Foot Print
Zone A Zone B
44
Zone C Zone D Zone E
8/3/2011
23
H‐RTO Foot Print ‐ Overview
• Zone A and Zone B in the west are high renewable zones with
Zone C
Zone A
low cost power
• These zones wish to move renewable energy to the east
45
H‐RTO Foot Print ‐ Overview
• Zones B, D & E are higher cost zones with a desire to import renewable energy
Zone D
Zone E
Zone B
46
D
8/3/2011
24
H‐RTO Foot Print ‐ Overview
Zone B
Congestion
Zone C
Zone A
Zone D Zone E
Zone B
47
• Congestion exists between the western and the eastern zones
• This congestion limits the import of desired energy
Load Ratio Share
Hypothetical RTO – Load Ratio Share (12CP)
A B
A, 41.7%C, 16.7%
D, 13.3%E, 3.3%
A
B
C
Zone
C D E
B, 25.0%
D
E
48
8/3/2011
25
Hypothetical RTO – Characteristics by Zone
49
H‐RTO PORTFOLIO 1 PROJECTS: 2011‐13
50
8/3/2011
26
H‐RTO Portfolio 1 Projects
A1 A2
Zone C
Zone A
Zone E
Zone B
51
Zone C Zone D Zone E
E1
H‐RTO: Portfolio I (2011‐2013)
52
8/3/2011
27
Portfolio 1: First Year Cost Allocated by Zones
53
Portfolio 1: C/A by Zone to 2051
54
8/3/2011
28
Portfolio 1: APC Benefits Zones (2013)
1.6
Zone Costs APC B/CZone A 7,337,396$ 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
8/3/2011
29
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
$40,000,000
8/3/2011
30
H‐RTO PORTFOLIO 2 PROJECTS: 2014‐16
59
H‐RTO Portfolio 2 Projects
B1
B2
Zone C
Zone A
Zone E
Zone B
60
Zone C Zone D Zone E
C1 D1
8/3/2011
31
HRTO: Portfolio 2 (2014‐2016)
61
Portfolio 2: Cost Allocated by Zones
62
8/3/2011
32
Portfolio 2: C/A by Zone to 2051
63
ALL PORTFOLIO PROJECTS: 2011‐16PORTFOLIO 1 & 2 COMBINED
64
8/3/2011
33
All Portfolio Projects
A1 A2 B1
B2
Zone C
Zone A
Zone E
Zone B
65
Zone C Zone D Zone EC1
D1E1
H‐RTO: All Portfolios (2011‐2016)
66
8/3/2011
34
All Projects: By Zone (H/B)
67
All Projects: Cost Allocation by Zones
68
8/3/2011
35
All Portfolio: C/A by Zone to 2051
69
Portfolio 1 & 2: APC Benefits Zones (2016)*
1.4
1.6 Zone Costs APC B/CZone A 12,492,292$ 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
8/3/2011
36
$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
8/3/2011
37
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
8/3/2011
38
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
501‐614‐3351
• Dan Jones PE, Lead Engineer
501‐688‐1717
76
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.
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
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
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%
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
6
Annual Transmission Revenue Requirement
ATRR: What is it, Why it Matters and H i it l l t d?How is it calculated?
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
8/4/2011
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
8/4/2011
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
8/4/2011
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
8/4/2011
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
8/4/2011
6
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
12
8/4/2011
7
Section 2.2 – SPP Cost Allocation Methods
13
Section 2.3 – Methods of Measuring Benefits
14
8/4/2011
8
• 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.
16
8/4/2011
9
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
8/4/2011
10
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
8/4/2011
11
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.
22
8/4/2011
12
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.
24
8/4/2011
13
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
26
8/4/2011
14
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
28
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.
1
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
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
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.
4
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.
5
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.
6
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.
7
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.
8
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.
9
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.
10
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.
11
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.
12
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.
13
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.
14
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:
15
• 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
16
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
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.
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.
Top Related