SPC Materials 20160114

Southwest Power Pool, Inc.
STRATEGIC PLANNING COMMITTEE MEETING
Thursday, January 14, 2016
8:00 AM – 3 PM
Sheraton Oklahoma City, Oklahoma City, Oklahoma
• AGENDA •
1.
Call to Order and Administrative Items ................................................................................................... Mike Wise
2.
Review of Past Action Items .......................................................................................................... Michael Desselle
3.
MOPC Update ................................................................................................................................ Noman Williams
4.
CMTF Update .................................................................................................................................. Tom Hesterman
5.
TPITF Update ...................................................................................................................................... Brian Gedrich
6.
SPCTF CPP Update ................................................................................................................................... Mike Wise
7.
Task Force Creation ........................................................................................................ Jay Caspary/Lanny Nickell
8.
SPP Strategic Plan Status Report ................................................................................................... Michael Desselle
9.
2015 SPC Org Group Survey/Self-Assessment............................................................................... Michael Desselle
10. Summary of Action Items .............................................................................................................. Michael Desselle
11. Discussion of Future Meetings ...................................................................................................... Michael Desselle
May 5-6, 2016 Retreat
TBA
July 14, 2016
Rapid City
October 13, 2016
SPP Corporate Center
Executive Session
1 of 72
Strategic Planning Committee
October 15, 2015
Meeting No. 90
Southwest Power Pool
STRATEGIC PLANNING COMMITTEE MEETING
Thursday, October 15, 2015
SPP Corporate Office, Little Rock, Arkansas
•
M INUT E S
•
Agenda Item 1 – Call to Order and Administrative Items
Mike Wise (GSEC) called the meeting to order at 8:00 AM. Members present included: Jake Langthorn
(OGE); Venita McCellon-Allen (AEP); Mike Deggendorf by phone (KCPL): Jim Eckelberger (Director),
Harry Skilton (Director); Phyllis Bernard (Director); Les Evans (KEPCO); Rob Janssen (Dogwood); Dennis
Florom (LES); and Bill Grant (Xcel). SPP Staff included Michael Desselle, Carl Monroe, Nick Brown, Paul
Suskie, Mike Ross, Dustin Smith, Lanny Nickell, Antoine Lucas, Jay Caspary, and Sam Loudenslager.
Other guests participated in person or via phone (Attendance – Attachment 1 and 2). Harry Skilton
moved and Phyllis Bernard seconded adoption of the July 16, 2015 and August 20, 2015 teleconference
meeting minutes (Meeting Minutes – Attachment 3) which passed without opposition.
Agenda Item 2 – Review of Past Action Items
Michael Desselle provided a review of past action items, including the e-mail vote results for the SPCTF –
Clean Power Plan (CPP) scope document.
Agenda Item 3 – MOPC Update
Paul Malone (NPPD and MOPC Vice-Chair) provided an informational update following the MOPC
meeting. Paul reported that the MOPC: approved the 2017 ITP10 futures; approved moving forward on
the Enhanced Combined Cycle Project; discussed the proposed enhanced market metrics; was updated
on the SPP/MISO dispute settlement and began discussions on revenue distribution; and, acknowledged
the successful integration into the SPP Market on October 1st for the Integrated Systems of WAPA, Basin
and Heartland (IS).
Agenda Item 4 – New Member Update
Carl Monroe provided status reports on the Integrated Systems integration and also the NWPP EIM
developments.
Agenda Item 5 – LP&L Strategic Implications
Mike Wise informed the Committee about a recent news release that Lubbock Power and Light had
announced an intention to join ERCOT grid in 2019. Mike noted that this could have strategic
implications for SPP and introduced the subject to identify the strategic matters for consideration by the
Committee. Bill Grant noted that it is premature to determine that Lubbock is leaving SPP and that the
strategic issue for consideration is whether the Withdrawal fees developed and filed at FERC in a recent
docket are appropriate for the circumstances similar to Lubbock’s. Mike Deggendorf agreed and further
clarified that the issue is one of the appropriate regional funding for committed transmission facilities.
Staff also discussed existing transmission expansion cost controls.
Agenda Item 6 – Possible Expansion of the SPC
Michael Desselle noted that with the recent addition of the IS, a question had been raised regarding the
representation for the expanded states in the SPC. He noted that Staff raised the issue to the Corporate
Governance Committee and was directed to bring the issue before the SPC to develop a recommend
course of action. Michael recited the SPP Bylaws provision that defines the SPC composition (Bylaws
Section 6.2 – Attachment 4). Committee members discussed the process for filling vacancies, ensuring
diversity of representation and the history of other recent SPP member additions. Following discussions
and clarifications, Rob Janssen moved to recommend to the CGC that the Bylaws be modified to
2 of 72
Strategic Planning Committee
October 15, 2015
Meeting No. 90
accommodate 1 additional Transmission Owning Member and 1 additional Transmission Using Member.
Les Evans seconded the motion and it passed unanimously.
Agenda Item 7 – Clean Power Plan (CPP) Update
Lanny Nickell presented a recap of the SPCTF-CPP initial meeting. Lanny noted that the Task Force has
suggested some minor modifications to the scope: particularly to ensure coordination with other Working
Groups and to reflect the number of Task Force members (Revised Redline SPCTF-CPP – Attachment
5). Following discussions about the selection of task force members and redundant language which is
already in the Bylaws with respect to limited attendance, Phyllis Bernard moved adoption of the amended
scope seconded by Bill Grant which was approved without opposition (Amended SPCTF-CPP Scope –
Attachment 6). Lanny also provided an update on other subsequent CPP activities.
Agenda Item 8 – MOPC Task Force Updates
Transmission Process Improvement Task Force (TPITF)
Brian Gedrich presented the TPITF update on the efforts to develop recommendations that will produce
regional transmission planning process improvements (TPITF presentation – Attachment 7). While noting
an initial goal to have recommendation to the MOPC, SPC and Board in January 2016, Brian indicated
that the deadline may slip to insure that the group “gets it right”. Brian addressed concerns expressed
about the Near-term study implications for reliability and Mike Wise and Jim Eckelberger concurred that
the shift in the timeline to April was appropriate to ensure the right solutions for consideration by the
Board. Phyllis Bernard thanked the joint Task Force for the efforts to date.
Capacity Margin Task Force (CMTF)
Tom Hesterman presented an update of the CMTF’s activity to address the potential for changes in SPP’s
capacity margin (CMTF Update – Attachment 8). Tom highlighted that the Task Force working with SPP
staff has performed a Loss-of-Load-Expectation (LOLE) reserve margin study, a deliverability study, a
Planning Reserve Assurance Policy, a Load Responsible Entity whitepaper and other related study
activities. Tom described each of the initiatives and responded to questions and critiques regarding each.
Tom noted in response to Mike Wise’s question regarding scheduled deliverables that 3 items would be
ready for Board consideration in January (Reserve Margin/LOLE; Deliverability, and the Planning
Reserve Assurance Policy).
Behind the Meter Distributed Generation Tariff Discussion Item
Dennis Reed reported on the status of the “behind-the-meter-generation” review efforts of the Regional
Tariff Working Group (RTWG) (Report of the RTWG – Attachment 9).
Agenda Item 9 - Joint Finance Committee/SPC Meeting Report
Mike Wise and Michael Desselle reported on the inaugural meeting of the Finance Committee held in
conjunction with the SPC to determine the linkage between the Strategic Plan and the Staff-developed
Operating Plan which will shape the 2016 budget (Strategic to Operating Plan Linkage – Attachment 10)
and (Operating Plan Strategic Input presentation – Attachment 11).
Agenda Item 10 - Strategic Plan Status
Michael Desselle reviewed the status of SPP Strategic Plan Initiatives (Strategic Plan Metric – Attachment
12).
Agenda Item 9 – Summary of Action Items
Action Items are:
•
Finalize and post SPCTF-CPP scope document consistent with SPC direction.
3 of 72
Strategic Planning Committee
October 15, 2015
Meeting No. 90
Agenda Item 10 – Discussion of Future Meetings
Michael Desselle discussed future meetings and the Committee decided on the dates for the annual SPC
Retreat.
The next regularly schedule SPC meeting is January 14 in Oklahoma City.
Executive Session
The Committee then met in Executive Session.
Respectfully Submitted,
Michael Desselle
Secretary
4 of 72
Capacity Margin Task Force (CMTF) Status Update
SPC Presentation
January 14, 2016
5 of 72
Outline
•
Background
•
Load Responsible Entity
•
Planning Reserve Margin (PRM) Requirement
•
Planning Reserve Assurance Policy
•
Deliverability Study
•
Next Steps
6 of 72
2
BACKGROUND
7 of 72
3
CMTF Establishment •
•
SPP Realized Need to Re‐Evaluate Resource Adequacy
–
SPP became the Balancing Authority in March 2014
–
Issues raised with existing SPP Criteria language
–
Expanding footprint and operational changes
–
Significant transmission expansion in place
–
Capacity margin requirement unchanged since 1998
Activity
–
Need first introduced at April 2014 MOPC meeting
–
Survey questions sent out to MOPC for initial feedback
–
Formation of Capacity Margin Task Force approved in July 2014
–
Priority given to 4 primary areas of policy development
–
Load Responsible Entity (LRE) definition approved in July 2015
8 of 72
4
MOPC Responses to Survey Questions* 1. Should Capacity Margin requirement apply to all load serving entities operating
within the electrical boundaries of the SPP Balancing Authority?
[20 responses] 100% Yes, 0% No
2. Should we use Coincident Peak loads to calculate each entity's Capacity Margin?
[20 responses] 75% Yes, 20% No, 5 % Undecided
3. Penalties for non‐compliance?
[18 responses] 67% Yes, 11% No, 22% Undecided
4. Any issues with IRP state laws?
[17 responses] 65% No, 24% Yes, 11% Undecided
5. Should fuel supply and transportation firmness be documented?
[19 responses] 42% Yes, 16% No, 32% Undecided, 10% Unrelated
6. Can anything other than firm transmission be used to demonstrate deliverability?
[18 responses] 33% Yes, 22% No, 45% Undecided
*From survey performed in first half of 2014.
9 of 72
5
MOPC Responses to Survey Questions* 7. Which SPP Working Group should own the Capacity Margin process?
[18 responses] 31% GWG, 31% ORWG, 10% TWG, 28% Other
8. Do plants need to be available more than a certain percentage of the year?
[18 responses] 28% Yes, 16% No, 56% Undecided
9. How do we factor in environmental limits?
[19 responses] (Multiple types of responses)
Note: Several other questions were sent out in a subsequent survey that are not shown here due to low response rate.
*From survey performed in first half of 2014.
10 of 72
6
CMTF Policy Proposals
11 of 72
7
CMTF Balance Goals
Reliability
Economics
12 of 72
8
LOAD RESPONSIBLE ENTITY
13 of 72
9
Background
•
•
Addressing MOPC survey question concerning the
entity responsible for the Capacity Margin
requirement
Load Responsible Entity (“LRE”) definition
–
•
Any entity that is: (i) an Asset Owner with load asset(s) registered
in the Integrated Marketplace, where such load asset(s) is within
the metered boundary of the SPP Balancing Authority Area; or (ii) a
Transmission Customer or Network Customer with an obligation to
serve retail utility load requirements, where such load is
interconnected with the Transmission System but not included
within the metered boundary of the SPP Balancing Authority Area;
or (iii) an entity to which an Asset Owner, Transmission Customer,
or Network Customer has delegated obligations under Attachment
AS by mutual agreement.
LRE whitepaper approved by MOPC (July 2015)
14 of 72
10
LRE Next Steps
•
The Process Improvement Tariff Task Force (PITTF) is
currently working on language for the LRE
implementation
•
Alternative LRE proposals, by member companies, are
being discussed at the PITTF
•
–
Market Participant
–
Transmission Customer
The proposed language will be reviewed by the CMTF
before going to the RTWG
15 of 72
11
PRM REQUIREMENT
16 of 72
12
History of SPP Capacity Margin
•
SPP Criteria section 4.1.9 states, “Each Load Serving
Member’s Minimum Required Capacity Margin shall be
twelve percent. If a Load Serving Member’s System
Capacity for a Capacity Year is comprised of at least
seventy‐five percent hydro‐based generation, then such
Load Serving Member’s Minimum Required Capacity
Margin for that Capacity Year shall be nine percent”
•
The MOPC predecessor approved lowering the
capacity margin requirement level from 15% to 12%,
effective October 1, 1998.
17 of 72
13
Resource Adequacy Terminology
•
Resource adequacy for planning purposes is generally expressed
in terms of capacity margin or reserve margin
•
Reserve margin requirements are intended to ensure sufficient
capacity is planned and available to meet forecasted demand
•
SPP has expressed its requirements as “Capacity Margin” while
NERC and other regions typically use “Reserve Margin”
–
–
•
%
%
CMTF will be recommending to move to Reserve Margin
terminology and calculation
–
Consistent with industry usage
–
12% Capacity Margin = 13.6% Reserve Margin
18 of 72
14
Regional PRM Requirements
19 of 72
15
A11
LOLE Defined
•
Loss‐of‐load expectation (LOLE) is the expected number of
days or hours per year, that an entity doesn’t have enough
capacity to meet the firm load.
•
A Loss of Load Expectation (LOLE) analysis is typically
performed to determine the amount of capacity that needs
to be in place to meet the desired reliability target,
commonly expressed as an expected value, or LOLE of 0.1
days/year or 1 day in 10 years (“1 in 10”)
20 of 72
16
LOLE data inputs – Key Drivers
• Transmission topology
• Thermal / Variable Generation
data
Load
Capacity
• Wind shapes
• Transactions (Imports / Exports)
Uncertainty
• Load uncertainty and area load
shapes
LOLE
21 of 72
17
A12
Reserve Margin LOLE Study Scope Results
Reserve Margin Loss of Load Expectation Study Results
2016 LOLE Results
1.727
2017 LOLE Results
2020 LOLE Results
SPP Criteria
0.92
0.453
0.458 0.454
0.367
0.267
0.189 0.145
0.184 0.153
0.01
7.53%
8.70%
9.89%
22 of 72
11.11%
20
CMTF, ORWG, and GWG Concerns
• Load variability and
volatility
• Wind variability and
volatility
• Resource availability and
outage time‐frame
• Transmission monitored
• Ramp rate capabilities
• Frequency response
23 of 72
21
CMTF Stance
• Reserve Margin can be reduced without reliability impact
• CMTF straw poll results from December 3rd meeting
Reserve
Margin (%)
Votes For
Votes Against
Total Votes
Abstentions
Percentage of
votes For
reserve margin
13.0%
20
1
21
1
95.2%
12.5%
16
3
19
3
84.2%
12.0%
13
6
19
3
68.4%
11.5%
8
12
20
2
40.0%
24 of 72
22
Optimal Planning Reserves
25 of 72
23
PRM Reduction Savings
Inputs
Current Reserve Margin
Reduced Reserve Margin
13.6%
12.0%
Net CONE (CT)
$109.6
($/kW‐yr)
This CONE reflects an annual 2.5% inflation based on 2015 for 2025
Results
2025 Summer Peak Load
2025 Reduced Capacity Savings*
40‐yr Reduced capacity Cost Savings (2025 $)
2015 Reduced Capacity Savings*
40‐yr Reduced capacity Cost Savings (2015 $)
62,890 $110.27
$1,724.56
$86.14
$1,347.22
MW
$M
$M
$M
$M
Reducing reserve margin requirement from 13.6% to 12.0% results in approximately 1,000 MW of capacity reduction
*Uses 8% discount rate
26 of 72
24
Impacts of adjusting SPP Reserve Margin
• Minimal increased risk of loss of load based upon current
approved scope
Reserve Margin (%)
13.6 %
12.0 %
Study Year
2017
2017
LOLE Results (Days per 10 years)
0.023 0.068
Reserve Margin (%)
13.6 %
12.0 %
Study Year
2020
2020
LOLE Results (Days per 10 years)
0.030
0.040
LOLE in one day equivalence
1 Day per 444 years
1 Day per 146 years
LOLE in one day equivalence
1 Day per 333 years
1 Day per 250 years
• SPP Criteria is 1 day in ten years
27 of 72
25
PLANNING RESERVE ASSURANCE POLICY
28 of 72
26
Current Enforcement
•
Potential revocation of membership
•
Potential imposition of NERC reliability standard
penalty provisions in SPP’s Attachment AP, if violation
occurs
Shortfalls of Current Enforcement
• Too Extreme/Inadequate
• Occurs too late to assure adequate levels
of PRM are maintained
• Payments are either not anticipated or
would not compensate entities that have
excess PRM above SPP’s requirement
29 of 72
27
CMTF Proposed Assurance Guidelines
1.
• Assurance Mechanism would utilize payments to
provide compensation from LREs who are short on
capacity to those in the SPP region who are long on
capacity
2.
• LRE’s compliance would be established in advance of
the monitored peak season(s) by SPP Staff based on
weather normalized load and accredited capacity
data provided by each LRE
• Staff will independently review the data to ensure
accuracy and compliance with SPP’s PRM calculation requirements
30 of 72
28
CMTF Proposed Assurance Guidelines
3.
• Prior to the start of the peak season(s), each LRE that is
short on capacity has the option to make any
appropriate arrangements under the terms of the SPP
Criteria, including entering into a bilateral contract for
capacity or demand response from any GO or demand
response provider, including another LRE, that is long on
capacity in the SPP region
4.
• If an LRE’s reserve margin is not compliant with the SPP
Criteria prior to the start of the monitored peak
season(s) then that LRE will make a PRM deficiency
payment
31 of 72
29
PRM Deficiency Payment Guidelines
•
The amount of the PRM deficiency payment is
based on the Cost of New Entry (CONE) for new
generation in SPP
•
Referencing the most recent EIA report on
Updated Capital Cost Estimates for Utility Scale
Electricity Generation Plants, SPP will annually
determine the CONE value based on an
appropriate natural gas peaking technology
•
The CONE value only reflects costs and will not
include the anticipated net revenue from the sale
of capacity, Energy or Ancillary Services
32 of 72
30
PRM Deficiency Payment Guidelines
•
The CONE multiplier provides increasing incentives
consistent with the potential for reduced reliability
in the SPP region
•
The CONE multiplier mechanism reflects the
increased reliability value of capacity as PRMs
diminish in the SPP region
•
The total PRM deficiency payment made by an LRE
for the annually monitored peak season(s) should
cover the annual capital and fixed operating costs
33 of 72
31
PRM Deficiency Payment Guidelines
•
LREs who are found to be deficient in meeting
their PRM obligation determined by this assurance
policy are subject to the deficiency payment
•
The LRE is responsible to make a deficiency
payment for the necessary reserves to raise their
reserves to the SPP PRM requirement
•
The deficiency payment will be made to SPP, and
SPP will initially distribute payments to all the LREs
who have surplus reserves above the SPP PRM
34 of 72
32
Planning Reserve Margin Timeline
35 of 72
33
DELIVERABILITY STUDY
36 of 72
34
Deliverability Background
•
•
•
Current SPP Planning Criteria 4.1.3 requires firm
transmission service be obtained for load and capacity
obligations
Recognizing the operation of the Integrated Marketplace,
performance of SPP’s planning studies, and expected
adoption of PRAP, the firm transmission service
requirement for PRM capacity can be eliminated without
degrading reliability
CMTF voted to approve the Deliverability Study whitepaper on
November 30, 2015
37 of 72
35
Deliverability Concepts
•
Each Load Responsibility Entity (LRE) must report
capacity committed to supply its load and PRM
obligations to SPP
•
Firm transmission service must exist to support
delivery of capacity to an LRE’s load obligations
•
LREs may use firm transmission service or contractual
arrangement with generating capacity that has been
deemed deliverable through the deliverability study
for their reserve margin obligations
•
SPP will use a ITPNT CBA model to determine
deliverability capacity amounts and ensure
deliverability through transmission expansion
38 of 72
36
Determining Deliverability Amounts
•
•
•
SPP will identify the summer dispatch found in
planning models used in the most recent ITPNT –
establishes initial dispatch for each generator
The initial assumption is that any resource generating
in the CBA model is automatically deliverable to the
SPP BA for the initial dispatched output
SPP will assess ability to increase dispatch, one plant
at a time, to serve SPP BA load – establishes
incremental deliverability amount that when added to
initial dispatch creates the total plant deliverability
amount
•
Incremental deliverability amount is based on FCITC
limit
39 of 72
37
Process Flow
Annual Deliverability Study performed
SPP calculates PRM for LRE Planning Reserve Assurance
Deliverability Study results provided to Generator Owners (GOs)
GOs determine available capacity and contract with LREs
LREs report capacity and load amounts to SPP
40 of 72
38
Deliverability Study Example
100% Deliverable to SPP BA
LRE
“A”
PLANT “A”
500 MW
LRE
“B”
LRE
“C”
50% Deliverable to SPP BA
PLANT “B”
500 MW
SPP Balancing Authority
41 of 72
39
Capacity Deliverability and Availability Example
42 of 72
40
Deliverability Study Benefits
•
Provides alternative means of demonstrating
compliance with planning reserve margin obligations
•
Relies on transmission planning assumptions to
ensure consistency between generation usage for
reserve margin and transmission system availability
43 of 72
41
Deliverability Study Timeline
44 of 72
42
CMTF NEXT STEPS
45 of 72
43
NEXT STEPS
•
•
•
•
LRE tariff language being drafted by PITTF
Workshop planned for January 12 prior to MOPC
PRM Requirement, PRAP, and Deliverability policies to
be presented for approvals in April
Distributed Energy Resource policy and other capacity
accreditation Policies to be developed
46 of 72
44
Transmission Planning
Improvement
Task Force (TPITF)
Brian Gedrich - Chair
SPC
January 14, 2016
47 of 72
TPITF Scope
• Evaluate and propose recommendations on:
– The methodologies and modeling practices used in the
studies
– Utilization of data to ensure consistency in the planning
process
– The appropriateness of the planning cycle and
assessments
• Recommendations will be presented to MOPC, SPC, and
Board in April 2016
48 of 72
2
Key Issues Identified
• A three-year planning cycle is not timely
• Stakeholder process approvals and model development
are bottlenecks and can limit the frequency of the
planning process
• Duplication and variance of modeling in planning
processes and studies create inefficiencies and add
additional time
• Real-time operations data not always considered in the
planning process
• The ITP20 is resource intensive and provides primarily
strategic value and not actionable results
49 of 72
3
TPITF Consensus Items
• 18-month planning cycle
• Common planning model
• Holistic planning process
• Standardized scope
50 of 72
4
18-Month Planning Cycle
• Reduce the ITP planning cycle from 36 to 18 months
• Next Steps:
– Collaborate with applicable working groups to identify
potential issues and solutions to confirm feasibility
51 of 72
Common Planning Model
• Build a common base model for all planning processes
• Next Steps:
– Determine minimum planning model requirements
 Coincident vs. Non-Coincident Peak Load
 Consideration of Firm Transmission Rights
 Renewable Resource Forecast
 Consistency between compliance and planning assumptions
– Collaborate with applicable working groups to identify
potential issues and solutions to confirm feasibility
 TPITF strawman proposal that will provide a framework around
which working groups can focus their discussion on the
development of reliability and economic model sets for the
consolidated ITP process
52 of 72
6
Holistic Planning Process
• Combine the ITPNT, ITP10, and TPL processes into one
10-year study
• Next Steps:
– Conduct economic assessment for full planning horizon
– Include TPL compliance needs in ITP needs assessment
– Develop formal process to evaluate operational issues
53 of 72
7
Standardized Scope
• Standardize traditional scope items
• Next Steps:
– Identify ITP scope items that can be standardized
– Develop process for reviewing and approving
assumption document items
– Evaluate Revision Request (RR) process to track changes
to ITP Manual planning approaches and methods
– Collaborate with applicable working groups to identify
potential issues and solutions to confirm feasibility
54 of 72
8
Next Steps
• Model development strawman to the TWG for
consideration
• Final recommendations in April 2016
– Identify appropriate Working Group(s)
55 of 72
9
Questions?
56 of 72
10
Mass-based and Rate-based
Comparison
December 21, 2015
57 of 72
Deleted: December 9, 2015
Southwest Power Pool, Inc.
Name of Current Section (Optional)
Revision History
Date or Version
Number
Author
Change Description
11/24/2015
Sam Ellis
Initial draft
12/9/2015
Sam Ellis
Incorporated feedback
from CPPTF, et al
12/21/2015
Sam Ellis
Further feedback from
CPPTF
Comments
Report
Name
1
58 of 72
Southwest Power Pool, Inc.
Name of Current Section (Optional)
One of the goals of the Clean Power Plan Task Force of the Strategic Planning Committee
(“CPPTF”) is to perform a qualitative assessment of rate-based and mass-based approaches. The
CPPTF has had qualitative discussions on the relative advantages and disadvantages of mass-based
and rate-based approaches (which are summarized below) and, in doing so, has concluded that the
amount of flexibility afforded by compliance plans ultimately plays a larger role in regional
reliability and cost effectiveness than whether a mass-based or rate-based approach is utilized.
Determining supply of allowances and credits
Using the proposed mass-based methodology, the total number of available allowances is known at
the beginning of each compliance period. Because the supply of allowances is known in advance,
there is arguably greater economic certainty that can be attached to trading of allowances,
particularly in forward markets, which could facilitate greater market liquidity in the long-run.
Price-certainty related to allowances enhances market participants’ ability to understand production
costs and formulate accurate market offers, which facilitates efficient market dispatch based on
offers that reflect more definitive cost information.
Since the total allowances are pre-determined based on projections, one potential disadvantage of the
mass-based approach is that states experiencing higher load growth than anticipated may find the
mass-based caps more burdensome than rate-based compliance.
Under the proposed rate-based approach, certain types of resources generate emissions rate credits
throughout the compliance period that can be applied to other resources in order to bring each
resource’s overall emissions rate below a required target (pounds of CO 2 per MWh of output). Since
the generation of credits is not known in advance, forward markets may be inflated to reflect
additional risk premiums associated with the uncertainty of how many credits will be available in
future periods. However, additional credits can be generated based on demand, and so there may be
less long-term economic scarcity impact associated with a rate-based approach since the supply of
credits is not fixed.
An additional complicating factor in the rate-based approach is that there is potential that credits
submitted for compliance may not be valid, and the risk of its validity lies with the resource owner
who submitted the credits to demonstrate compliance. The uncertainty, along with measures (such as
third party verification services) that might be used to offset this risk, could increase the expense of
compliance under a rate-based approach.
Monitoring, verification and tracking
The proposed mass-based approach is more similar to existing EPA compliance programs, such as
ARP SO 2 trading program, NO X Budget Trading Program, CAIR, and CSAPR. The EPA states that
most generation resources already have the monitoring in place to track emissions against a mass-
Report
Name
2
59 of 72
Deleted: that
Southwest Power Pool, Inc.
Name of Current Section (Optional)
based approach. Hence, compliance with a mass-based plan may be easier, and, therefore, arguably,
measurement and verification under a mass-based plan may be less expensive.
Under a rate-based approach, new monitoring and tracking mechanisms might be necessary,
resulting in more expense and effort than would be required under a mass-based approach. Also, the
EPA states that any liability for the validity of an emissions rate credit is associated with the
resource owner who submits the credit as part of its compliance, so trading credits may be more
risky than trading allowances. Energy efficiency credits are more difficult to verify than credits
generated from more direct methods, such as from renewable energy sources.
Issues with allocation
Under a mass-based approach, there are different ways allowances can be allocated to resource
owners. The allocation plans ultimately lie with entities responsible for developing the compliance
plans. Although SPP has no position on particular allocation methods, there are two issues that are
worth noting in terms of their potential impact to SPP’s functions that relate to the proposed
benchmarks for allocations under the mass based FIP proposal and the treatment of infrequently used
resources.
The first issue relates to the allocation method proposed in the federal plan. In its proposed massbased plan, the EPA proposes to allocate allowances to resource owners based on historical
generation (MWh) levels. Alternative approaches could also be considered, such as an allocation
based on the emissions rates of the individual resources. Differing approaches will result in different
costs between owners of resources with higher and lower levels of carbon emissions. These different
costs have the potential to alter regional dispatch of the units.
Second, the EPA also plans to consider resources that haven’t produced energy for a period of time
to be retired, and the allowances associated with those generation resources that are considered
retired will be reallocated. This provides resource owners with the incentive to keep potentially
inefficient resources from retirement in order to retain the allowances associated with them and, as a
result, may undermine market efficiency in the long run.
States may propose allocation methods of allowances, either as part of a federal plan or as part of a
state plan. The process for each state’s determination of the best method of allocation could become
contentious.
In a rate-based plan, resources are assigned a target emissions rate and can meet that rate either by
reducing CO 2 emissions or applying rate credits to bring its overall rate below the assigned target.
Hence, the rate-based approach avoids much of the allocation contention that the mass-based
approach could entail. Some resources, such as certain coal plants, will have to procure credits
generated from other resources to comply since they cannot lower their emissions rate below their
assigned cap.
Report
Name
3
60 of 72
Commented [DF1]: This sentence didn’t quite read right. Make
sure I changed it to what was intended.
Deleted: rather than
Deleted: This could
Deleted: shifts
Deleted: retired
Southwest Power Pool, Inc.
Leakage under mass-based plans
Name of Current Section (Optional)
Under rate-based plans, the EPA has no concerns about shifting generation to resources not subject
to the requirements of 111(d), known as “leakage”. Under a mass-based plan, however, the EPA has
concerns with incentives to shift energy production to generation not subject to the requirements of
111(d). The EPA requires states to address such leakage in their plans, and they have proposed
establishing a set-aside in the federal plan to reduce incentives for leakages to occur. Based on
interactions with states and various stakeholders, leakage is one of the more contentious concepts in
the mass-based plan, with some asserting that the EPA has no authority to require mitigation of
potential leakage.
The way in which leakages are addressed may have an impact on the supply (and, as a result, cost)
of allowances. In some cases, it may be possible to demonstrate that leakage would not occur under
a state plan, to the extent that a state’s integrated resource planning processes are informative and
dependable. The EPA has encouraged states to expand their compliance plans to include resources
not subject to 111(d) as a way to demonstrate leakage would not occur, which would lead to more
restrictive output for a larger portion of resources, which decreases supply of allowances overall.
Commented [SE2]: Lauren requests we state plainly that ratebased plans don’t have leakage issues
Deleted: “
Deleted: ”
Deleted: Also for states that operate in organized energy markets,
there may be additional challenges for states to demonstrate that
leakage would not occur.
Reliability Implications
As discussed earlier, the mass-based portion of the federal plan proposes reallocating allowances
(eventually) for retired resources. This provides some incentive for resource owners to keep
inefficient resources available at some minimum level in order to provide credits. Over time, the
fleet of resources, particularly in certain constrained areas, may become less responsive and,
therefore, less effective in helping resolve reliability issues.
Although both approaches provide incentives to construct renewables, the proposed federal ratebased plan allows newer low-carbon resources (such as renewables) to generate rate credits while
existing ones cannot. Thus, rate-based plans may have more incentive to add renewables than massbased plans since, under a mass-based plan, any low-carbon resource generation contributes toward
reducing the number of allowances required, when it replaces higher CO 2 generation. Since most
renewables in SPP’s system are not synchronized generation, the challenges with associated
planning and reliability coordination will increase as asynchronous generation is added to the
system.
Deleted: Conversely, the proposed rate-based federal approach
may provide some incentives for high-CO2 producing resources to
retire sooner than they might under a mass-based approach. The
resulting shift in generation could result in more new construction as
well as shifts in existing generation, which would require additional
transmission expansion in order to reliably operate the system with
changes in power flows. ¶
Deleted: either
Deleted: s
Commented [DF4]: If I am understanding what you are trying to
say here.
Deleted: associated
Report
Name
4
61 of 72
SPP Assessment of EPA’s
Proposed Federal Plan
December 21, 2015
62 of 72
Deleted: December 9, 2015
Southwest Power Pool, Inc.
Name of Current Section (Optional)
Revision History
Date or Version
Number
Author
Change Description
11/24/2015
Sam Ellis
Initial draft
12/4/2015
Sam Ellis
Feedback from CPPTF
12/9/2015
Sam Ellis
Document title change
12/21/2015
Sam Ellis
CPPTF and other
feedback
Comments
Report
Name
1
63 of 72
Southwest Power Pool, Inc.
Name of Current Section (Optional)
One of the goals of the Clean Power Plan Task Force of the Strategic Planning Committee
(“CPPTF”) is to perform a qualitative assessment of the EPA’s proposed federal implementation
plan (“FIP”) for consideration in any comments SPP may file on the proposed FIP. These issues
were identified based on discussions with staff, the CPPTF, and other stakeholders, and they focus
on revisions to the FIP that would mitigate the CPP impact on electric system reliability in cases
where the FIP is implemented in a state(s).
The EPA should have a consolidated review process for proposed State
and Federal Plans
SPP proposes that the FIP accommodate and encourage coordinated reviews of compliance plans
(state and federal) to mitigate the impact the CPP may have on regional planning and operation of
the electric grid. The regional system operators for the relevant regions in the country should
perform these analyses, because they are in the best position to understand the impacts on grid
planning and operations.
Many regions of the country (organized markets and vertically integrated entities) operate the
electric grid on a regional basis. In those regions, the CPP compliance plans for states will impact
grid management by changing the capacity portfolio available to system operators that plan and
operate the grid. Individual state compliance with the CPP without consideration of the collective
impact of all relevant state compliance plans will likely result in greater impact to the system
operator functions (transmission planning, operations and markets). This, in turn, will impact
electric system reliability and economic benefits to the states in the regions. Conversely, concurrent
review of proposed state compliance plans (SIPs and/or FIPs) will facilitate CPP compliance in a
manner that mitigates the impact to regional grid operations and planning, which then mitigates the
impact to the electric system reliability and economic benefits that inure to the states and their
customers.
With respect to the SPP region in particular, states rely on a mix of generation resources from within
and outside of their state to provide electricity. In order to fully assess the reliability impacts that the
actions of one state may have on another, a consolidated review of all plans should be performed
before any of the plans have been submitted for final EPA approval. As noted above, this review
should be conducted by SPP, the RTO for the region that performs the relevant planning and
operational functions for the grid in the SPP region.
The EPA should establish timelines for issuance and review of FIPs that are conducive to supporting
a consolidated review that include both FIPs and state plans. An overall review of both state and
federal plans in context would allow transmission planning authorities to present more optimal
solutions to address any identified reliability concerns.
Report
Name
2
64 of 72
Deleted: in the SPP region
Southwest Power Pool, Inc.
Name of Current Section (Optional)
The EPA should consult planning authorities and reliability
coordinators in developing federal plans
The EPA should work with impacted system operators in developing a federal plan for a specific
state prior to submitting the plan for comments. This coordination should align with the requirement
in the CPP that states consider electric system reliability in the development of their SIPs. This
review of the FIP should also, to the maximum extent possible, be coordinated with other state plans
to mitigate the collective impact to regional grid management (discussed in more detail in above
section). Consideration of FIP impact on a coordinated basis will mitigate the potential negative
impacts from disconnects between plans. For example, EPA may need to consider plans from other
states in the surrounding region before determining whether a mass-based or rate-based approach is
best for a given state.
Also, system operator analysis will facilitate effective and efficient scoping any established
reliability-based allowance pools by facilitating the development of a thorough record and basis for
the allocation of such set-asides based on the analysis of the impacted system operators.
Furthermore, mitigating reliability concerns (must-run resources, voltage stability, load pockets, etc.)
may be addressed with a combination of flexible time-based actions (e.g., borrowing from future
periods) in the federal plan and planning actions developed by the planning authority.
Deleted: appropriate
Deleted: if EPA provides for any reliability set-asides in a federal
plan,
Deleted: of such set asides
Identifying and mitigating reliability issues are the responsibility of the relevant system operators
and planners, and in the development/application of any FIP, EPA should coordinate with those
entities to develop a FIP that mitigates potential and actual impacts to electric system reliability.
Both federal and state plans should require a reliability safety valve
As contemplated, the reliability safety valve (“RSV”) is to be used for an “unforeseeable . . .
extraordinary, unanticipated, potentially catastrophic event.” Although the proposed rules for federal
plans are expected to contain market-based flexibility, the RSV should be available in a federal plan
for extreme, unforeseen events that require immediate action. The market-based flexibility that is
proposed in a federal plan may not be effective to deal with these events if surrounding state plans
are not compatible with the federal plan imposed on a state in the same region.
Even if the plans are compatible/coordinated issues may arise that require the use of an RSV to
mitigate the impact to grid reliability. SPP recognizes that the approach in the CPP and the FIP rule
provide flexibility that can mitigate the potential impact to grid reliability. However, even if the
most beneficial, coordinated regional compliance approaches are implemented, situations can arise
where a unit is needed for grid reliability and the flexibility under approved plans is not adequate to
allow that unit to operate without resulting in a violation of CPP compliance. This is because the
grid is extremely complex and sensitive to the particularities of each respective region. For example,
the loss of a line or generator may result in the need to operate one or more generators to address
local issues. In unanticipated cases like this there may not be adequate time for market mechanisms
available in CPP compliance plans to enable those units to run without violating the rules. In these
circumstances an RSV would be needed to coordinate grid reliability with CPP compliance.
Report
Name
3
65 of 72
Deleted: s
Southwest Power Pool, Inc.
Name of Current Section (Optional)
SPP believes the RSV approach in the CPP is most likely suitable for inclusion in the FIP. SPP
looks forward to working with EPA to ensure an appropriate RSV is included in the FIP to provide
the insurance needed to mitigate unanticipated events that cannot be addressed via more structural
forward looking reliability reviews.
Since RSVs are intended for the catastrophic and unforeseen circumstances, there should be a
provision to deploy the RSV whenever such action is warranted by a justifiable reliability situation,
regardless of whether an RSV had been utilized previously.
FIPs should include an incremental reliability allowance reserve
For states coming under a federal plan, the EPA should provide a reserve for reliability-based
deployment of resources. These allowances would be incremental to market allowances, and would
be allocated to resources required to run for reliability purposes where the operation of such
resources would result in non-compliance with CPP obligations.
The allocation of the reliability allowances would be subject to appropriate reliability analyses and
determinations. The process for identifying, justifying and resolving the reliability issue(s) would be
similar to the RSV process adopted in the CPP. Unlike the RSV rules related to SIPs, the use of the
allowances would not be subject to offsetting prospective reductions if the resource is required to run
beyond 90 days.
The justification for the proposal is based on equity principles and differences between what EPA
requires in state plans versus what it has proposed in its FIP rules—the SIP has several reliability
review processes, whereas the FIP has none. Therefore, there is less opportunity to proactively
identify and address reliability issues under the FIP.
Regional precedent should be considered in formulating a federal
plan
The EPA should defer consideration of a blanket mass-based or rate-based approach for FIPs until it
is apparent whether there is a predominant regional preference for a particular approach.
Furthermore, if a state has expressed a particular approach in a plan that was rejected by the EPA,
the EPA should give consideration to that state’s preferences in formulating a FIP for that state.
Given that different areas of the country rely on different fuel sources and have varying capacity for
installation of renewable energy (such as wind or solar), there may be strong indications that a ratebased plan might be more appropriate than a mass-based plan, or vice versa. This issue should be
addressed in the coordinated reviews during FIP development that were discussed earlier in this
document.
Resource owners should continue to retain allowances for retired
resources under the proposed mass-based plan
Under the proposed mass-based plan, allowances associated with retired resources are reallocated to
provide incentives for additional renewable energy. This approach could have a detrimental impact
to market efficiency, particularly for states that are served by multiple system operators. As
resources retire, it is possible allowances, and their associated economic benefit, would shift to
Report
Name
4
66 of 72
Deleted: of
Commented [DF2]: I don’t think this last part is necessary, but I
may be missing something.
Deleted: , if the surrounding states have already indicated a
predominate approach in their plans
Southwest Power Pool, Inc.
Name of Current Section (Optional)
markets associated with different system operators. This could result in a significant cost shift
between utilities in states operating within multiple regions as well as between the regions
themselves. To mitigate this problem, resource owners should be allowed to retain the allowances
for retired resources under the federal plan.
Formatted: Heading 2
Report
Name
5
67 of 72
SPP Advanced Technology Steering Committee (ATSC)
Purpose
Organizational Group Scope Statement
January 4, 2016 DRAFT
The SPP Advanced Technology Steering Committee (ATSC) is being created under the Strategic
Planning Committee (SPC) to drive technology transfer and deployment within the SPP footprint for
the benefit of SPP members. The duties of the ATSC are to: (a) provide input into SPP research,
development and demonstration priorities and projects; (b) share best practices with respect to
research pilots, technology deployments and other activities which need to be considered for
broader application across the SPP footprint, (c) if necessary, propose amendments to SPP
governing documents to facilitate necessary changes related to research, development and
demonstration projects.
The ATSC may also be responsible for tasks assigned from the Strategic Planning Committee (SPC) on an
as-needed basis in order to leverage the ATSC member expertise.
Scope of Activities – ATSC:
In carrying out its purpose, the ATSC will:
1. Provide input into SPP research, development and demonstration priorities and projects
including:
a. Phasor Measurement Units and Synchrophasor Data/Tools,
b. Demand Response,
c. Energy Storage,
d. Distributed Energy Resources, and
e. Smart Grid.
2. Share best practices with respect to research pilots, technology deployments and other
activities which need to be considered for broader application across the SPP footprint.
3. Propose modifications, if necessary, to SPP governing documents to facilitate necessary changes
related to research, development and demonstration projects.
4. Perform studies, reviews and/or tasks that may be assigned by the SPC.
Representation
The ATSC shall be comprised of a balanced representation from the SPP sectors with no more than 11
total members. A Chair will be appointed by the SPC.
Duration
68 of 72
The ATSC will exist indefinitely at the discretion of the SPC. The ATSC shall meet at least quarterly on
dates to be determined after consultation with the committee members. SPP shall facilitate such
meetings and shall give reasonable written notice thereof to all Parties.
Reporting
The ATSC reports to the Strategic Planning Committee (SPC).
69 of 72
Strategic Planning Committee
Number of members
Number of responses
Response rate
Overall effectiveness score
Lowest score
Highest score
Question
2015
2014
2013
2012
2011
2010
12
10
83%
4.5
12
8
67%
4.9
12
10
83%
4.2
12
11
92%
4.4
12
12
100%
4.3
12
11
92%
4.2
2014
Average score
2013
2012
2011
2010
2015
The agenda reflects the actions to be taken during the meeting.
Meeting materials are provided in a timely manner.
The information provided prior to the meeting is utilized during the meeting.
The information presented in meetings is clear.
Meeting minutes are an accurate reflection of the meeting.
Additional comments:
well organized and well run meetings
4.6
4.1
4.4
4.2
4.4
Membership represents the diversity of the SPP organization.
Membership has the necessary expertise and/or skills to accomplish its goals.
Members come prepared to meetings.
Members are committed to participate and accomplish the group's goals.
Members are supportive and respectful of the individual needs and differences of group members.
Additional comments:
4.5
4.5
4.8
4.8
4.8
4.7
4.4
4.5
4.5
4.3
4.5
4.4
4.5
4.5
4.5
4.6
4.2
4.4
n/a
4.7
4.6
4.1
4.2
n/a
4.4
4.5
4.5
4.2
4.3
4.5
4.6
4.8
4.4
4.8
4.9
4.3
4.3
4.2
4.6
4.6
4.7
4.7
4.3
4.7
4.7
4.5
4.7
4.3
4.7
4.7
4.2
4.6
4.3
4.3
4.6
4.5
4.6
4.3
4.4
4.2
4.9
4.8
4.9
4.9
4.5
4.3
4.5
4.5
4.6
4.3
4.5
4.6
4.8
4.7
4.5
4.6
4.6
4.6
4.7
4.5
4.5
4.6
4.3
4.5
4.4
4.5
4.5
4.3
4.5
4.8
5.0
4.9
4.9
4.5
4.7
4.7
4.6
4.6
4.8
4.8
4.6
4.6
4.7
4.6
4.7
4.5
4.6
4.6
4.6
-
Members are engaged during the meeting.
Decisions are identified and action is recommended.
Facilitation is sufficient to guide discussion.
Dissenting voices are heard.
I depart with a feeling that we have accomplished something.
Additional comments:
-
The chair seeks input, and organizational group members are able to influence key decisions and
plans.
The chair is supportive and respectful of the individual needs and differences of group members.
The chair keeps the group on task to achieve appropriate outcomes.
The chair ensures follow-through on questions and commitments.
Additional comments:
-
Please provide three or more recommendations for improvement of this particular group and/or SPP's overall organizational group structure.
improve the effectiveness of the annual planning retreat better definition of operational and industry trends and goals that need to be addressed with
strategic initiatives/programs in depth evaluation of performance on strategic initiatives build on the steps being taken to improve the alignment of
strategic initiatives and financial budget
Need to move public information from a wish to an achievement.
Need to figure out how to marshall the states to respond to the CPP.
Please provide three or more recommendations for improvement of this particular group and/or SPP's overall organizational group structure
group is very adept at initiating task forces to address difficult issues
SPC
27
70 of 72
SPP Organizational Group Self-Evaluation/Assessment
(August 2014 – July 2015)
GROUP NAME:
Strategic Planning Committee
CHARTER/SCOPE UPDATE: Attached Charter/Scope has been reviewed: Y
MEMBER ROSTER/ATTENDANCE:
Member
Company
-
# Present
# Absent
Cooperative (TU)
4
0
Investor Owned (TO)
9
0
Cooperative (TU)
9
9
0
0
*Florom, Dennis
Grant, Bill
Arkansas Electric
Cooperative
Director
Kansas City Power & Light
Company
Director
Kansas Electric Power
Cooperative
Lincoln Electric System
Xcel Energy
Municipal (TU)
Investor Owned (TO)
5
7
*Hanson, Jon
Omaha Public Power District
State Agency (TO)
2
Janssen, Rob
Dogwood
9
Langthorn, Jake
Oklahoma Gas and Electric
Company
American Electric Power
Independent Power
Producer (TU)
Investor Owned (TO)
0
2
(2 Proxies)
1
(1 Proxy)
0
Investor Owned (TO)
8
Cooperative (TU)
9
9
2
(2 Proxies)
1
(1 Proxy)
0
0
Staff Secretary
9
0
*Bittle, Ricky
Bernard, Phyllis
*Deggendorf, Michael
Eckelberger, Jim
Evans, Les
McCellon-Allen, Venita
Sector
N
Skilton, Harry
Wise, Michael (Chair)
Director
Golden Spread Electric
Cooperative
Desselle, Michael
SPP
*Only on Committee for part of the assessment period.
7
List the number of members represented in the following areas:
Transmission/Owners
Transmission/Users
Directors
4
4
3
Investor
Owned
Utility
Cooperative
Municipal
State
4
3
1
1
Sectors
Independent Power
Federal Producer/ Marketer
1
71 of 72
Alt Power/
Public Interest
Large
Retail
Small
Retail
AVERAGE OVERALL ATTENDANCE (INCLUDING NON-GROUP MEMBERS):
MEETINGS HELD TO DATE:
Live:
AVERAGE LENGTH OF MEETINGS:
5:26
NUMBER OF VOTES TAKEN:
19
5
38
Teleconference:
4
*MEETING COST(S):
$65,068.88
* Meeting costs include hotel expenses (room rental, A/V, food and beverage), estimate of teleconference expenses,
and Director fees for attendance.
MAJOR ACCOMPLISHMENTS/ISSUES ADDRESSED BY THE GROUP:
1.
2.
3.
4.
Oversight of the Proposed Clean Power Plan Analyses and Policy pronouncements
Finalized New Member Addition processes
Finalized Order 1000 Policies and transitioned Task Force to the MOPC CTPTF
Provided to ESWG guidance on ITP10 Futures
MAJOR PENDING ISSUES BEFORE THE GROUP:
1.
2.
3.
4.
Continued oversight of Clean Power Plan strategic and policy implications
Coordinated oversight of the Transmission Planning Process Improvement Efforts
Coordinated oversight of Capacity Margin Changes
Continued oversight of New Member additions
72 of 72