2015 Value Proposition
Stakeholder Review Meeting
January 21, 2016
The 2015 Value Proposition study shows that MISO provides between
$2.1 and $3.1 billion in annual economic benefits to its region
What is the MISO Value Proposition?
•
•
•
The Value Proposition study is a
quantification of value provided by
MISO to the region, including the entire
set of MISO market participants and
their customers
This value is provided through improved
grid reliability and increased efficiencies
in the use of generation resources
enabled by MISO market operations
The Value Proposition incorporates
benefits from the integration of the
South region in December 2013
What the MISO Value Proposition is NOT
•
The Value Proposition study does not
calculate savings received by individual
market participants as a result of MISO
membership
•
The Value Proposition study does not
calculate the value for any individual
market sector or state
•
The study does not capture the
complete value of MISO. For simplicity,
all benefits with minimal value are
excluded. Qualitative benefits, such as
price and data transparency, planning
coordination and seams management,
are also excluded as these are difficult
to quantify.
1
The MISO 2015 Value Proposition
Benefit by Value Driver
(in $ millions)
$75-$149
($267)
$213-$263
$2,101$3,069
$1,289$1,950
$91-$117
$316-$377
$140-$154
$67-$74
$32-$35
$145-$217
1
2
3
4
5
6
7
8
9
10
Improved
Reliability
Dispatch
of Energy
Regulation
Spinning
Reserves
Wind
Integration
Compliance
Footprint
Diversity
Generator
Availability
Improvement
Demand
Response
MISO Cost
Structure
Market – Commitment and Dispatch
Generation Investment Deferral
2
Total Net
Benefits
The MISO 2015 Value Proposition – South Region
Benefit by Value Driver
(in $ millions)
$559-$753
$16-$31
($57)
$653-$897
$54-$60
$14-$16
$8-$9
$21-$27
$38-$58
1
2
3
4
5
6
7
8
Improved
Reliability
Dispatch
of Energy
Regulation
Spinning
Reserves
Compliance
Footprint
Diversity
Demand
Response
MISO Cost
Structure
Market – Commitment and Dispatch
Total Net
Benefits
Generation Investment
Deferral
3
MISO exceeds industry standards to improve reliability
System
Monitoring and
Visualization
1
Improved
Reliability
Industry Standard Practice
MISO Practice
• Real-time monitoring using SCADA on a local area
basis
• Regional view/monitoring of the power system including:
– A State Estimator - runs every 60 seconds
– Contingency analysis of over 12,000 contingencies every
four minutes
– 24-hour shift engineer coverage responsible for
maintaining security application performance
• Use of standard vendor-supplied displays
• Operator interface of standard monitor display
screen augmented with static map board
• Ad-hoc and off-line voltage security analysis review
• Custom tools/displays for increased situational awareness
• Four control centers with large video wallboards displaying
real-time data reflecting the state of the electric grid and realtime market results
• Real-time Voltage Stability Analysis Tool (VSAT) and
Transmission Security Assessment Tool (TSAT) allow
comprehensive analyses of system operating conditions for
predicting and preventing voltage insecurity
Congestion
Management
Backup
Capabilities
• Performed using NERC Transmission Loading
Relief (TLR) process or internally developed
operating procedure based on congestion
management system
• Transmission congestion management via five-minute
security constrained economic dispatch based on least-cost
analysis, results in faster and more efficient solutions
• 30 – 60 minute response time
• Look Ahead Commitment Tool models near-real-time
conditions to better utilize resource capabilities and provide
unit commitments, de-commitments and online extension
recommendations for congestion management
• Offline and/or scaled down backup facility
• 24 x 7 staffed back-up control center
• Significant time to bring backup facility after a
failover or failback
• Testing of failover process performed annually
• On-line back-up facility with full coverage of power system
and market applications
• Critical applications require less than 10 minutes for failover
or failback.
• Monthly testing of failover process for critical applications
4
MISO exceeds industry standards, allowing enhanced
reliability in the footprint
Industry Standard Practice
Operator
Training
Performance
Monitoring
1
Improved
Reliability
MISO Practice
• Classroom training only
• Training methods include extensive use of full-dispatch
training simulator
• Train to meet minimum NERC requirements
• Training exceeds NERC requirements
• Five-person rotation (no training rotation)
• Six-person rotation at key operator positions allow for a
training week during each cycle
• Offline power system restoration procedure review
• Annual, regional “live” power system restoration drill,
involving dozens of members
• Post-event performance review
• Daily review of operational performance including:
– Extensive review of established operational metrics
– Monthly tracking of improvements
– Frequent near-term performance feedback to operators
and support personnel
– Routine review of upcoming operational events
• Post-event operator call review
• Standardized operator call review process incorporating
established metrics that score calls for each operator on a
routine basis
• Feedback provided to each operator
Procedure
Updates
• Procedures updates ad-hoc, as-needed
• All control room procedures reviewed annually
• Conduct routine drills with member participation for capacity
emergency and abnormal procedures
• Annual Emergency Operating Procedures workshop with
members and adjacent reliability coordinators
• Summer and Winter readiness workshops
5
Transmission System Availability Index used to evaluate
value of improved reliability
Reliability
Benefit
Improved
1 Improved
Reliability
Reliability
=
Transmission System Availability Index (TSAI)
x
MISO Load
• Measured in MWh
x
through
estimates or by contractual relationship1
Cost
of Outage
• Measured in cost per MWh
• RTO TSAI less Non-RTO TSAI
• TSAI measured as a percent
6
Outage data shows RTO’s serve load more reliably…
Transmission System
Availability Index (TSAI)1,3
Improved
1 Improved
Reliability
Reliability
TSAI Formulas
Sum of MWh Load Interrupted
99.9947%
TSAI =
1-
Sum of MWh Load Interrupted
+
Sum of MWh Load Served
99.9920%
1
∑ # of
99.9897%
disturbances
Non-RTO
RTO
Duration (hrs) X
Disturbance Size (MW) X
Load Loss Recovery Factor2 (0.67)
MISO
1Disturbances
with outages exceeding 1,000,000 customers and/or outage durations longer than one week were excluded from the analysis as it was assumed those characteristics fit the
profile of a distribution-level disturbance
2The Load Loss Recovery Factor is used to account for the progressive recovery of load during an outage
3Data collected from: (a) NERC, 2000-2007 & 2009 disturbance data, (b) U.S. Energy Information Administration, 2000-2015 disturbance data, (c) U.S. Energy Information Administration,
EIA-826 Database from July 2014 – June 2015, and (d) 2014 FERC Form 714s for individual ISO/RTOs
7
…providing annual benefits of $145 and $217 million
Reliability Benefit
Low Estimate
Transmission System
Availability Index (TSAI)
X
MISO Load1
X
Cost of Outage2
=
Reliability Benefit
($ in Mils.)
1
Improved
Reliability
Reliability Benefit
High Estimate
RTO
Non-RTO
99.992041%
99.989715%
RTO
Non-RTO
99.992041%
99.989715%
Difference
0.002325%
Difference
0.002325%
646,251,181 MWh
646,251,181 MWh
$9,647 per MWh
$14,470 per MWh
$145
$217
1MISO
load from Oct 2014 to Sep 2015 was used to approximate MISO's 2015 load. Information obtained from FERC Form 714 data and public MISO market reports.
“The Economic Cost of the Blackout.” The ICF paper defined a cost of outage range to be $7,440 to $11,160 per MWh. This range is supported by survey-based studies that estimate
an electric consumer’s (i.e. residential, commercial, industrial, and others) willingness-to-pay to avoid such outages. The cost of outage was adjusted from 2003 dollars to 2015 dollars using
Actual CPI from the Bureau of Labor Statistics.
2ICF,
8
MISO commits and dispatches generation more efficiently
than a decentralized market
2
Dispatch of
Energy
Historical Perspective
Before MISO, the region operated as a decentralized, bilateral market. Transmission operations and
bilateral power transactions were characterized by physical transmission constraints managed with
mechanisms that limited transmission utilization, high transaction costs, low market transparency,
pancaked transmission rates, decentralized unit commitment and dispatch.
What changed with MISO?
MISO’s real-time and day-ahead energy markets use security
constrained unit commitment and centralized economic dispatch to
optimize the use of all resources within the region based on bids and
offers provided by Market Participants.
Utility
Utility
MISO
Utility
Utility
The day-ahead market is a forward financial market for energy. Its
clearing process produces a set of financially binding schedules
according to which sellers are financially responsible to deliver and
purchasers are financially responsible to buy energy at defined
locations. The day-ahead market process is based upon a unit
commitment model that minimizes total production costs over 24 hours.
The primary purpose of the day-ahead market is to clear and schedule
sufficient supply to satisfy cleared day-ahead demand, using the most
economical generation resources. The real-time market dispatches
generation resources to meet actual demand rather than bid demand.
Real-time dispatch is also based on economics and dynamic
management of congestion.
9
Improved commitment and dispatch provide between $140
and $154 million in annual benefits
Assumptions / Inputs
2
Dispatch of
Energy
Calculation Methodology
• Modeled based on MISO Commercial and Network Model
• Analysis performed in PROMOD®
• Without MISO market analysis
– Transmission system utilization was de-rated by 10%
– Hurdle rates between control areas: Dispatch hurdle
rate in the North/Central region is $3. For the South
region, Entergy dispatch hurdle rate is $8. SMEPA
and CLECO dispatch hurdle rate is $6. Commitment
hurdle rate is $10 for the full MISO footprint.
• With MISO market analysis
– Improved transmission system utilization by 10%
– Hurdle rates between control areas were eliminated
– 1,000 MW contract path capacity limit between MISO
North/Central and South regions modeled with a
hurdle rate of $10 to allow transactions that are
economic at that level
This benefit is modeled using the industry standard
technique called production cost modeling. Independent
firms consistently find that a market, such as MISO’s, with
central commitment and dispatch of generation for a large
region is more cost-efficient versus the same generation
portfolio divided into sub-regions for commitment and
dispatch.
Low Estimate ($ in Mils.)
$140
High Estimate ($ in Mils.)
$154
10
The Ancillary Service Market reduces regulation
requirements and improved commitment/dispatch efficiency
3
Regulation
Historical Perspective
Prior to the launch of MISO’s Regulation Market, each Balancing Authority (BA) maintained regulation within
its area. This often resulted in the BAs within MISO’s footprint working “against” each other – some
regulating up while others were regulating down.
What changed with MISO?
With MISO’s Regulation Market, significantly less regulation is required within the MISO footprint. This is
due to one centralized footprint regulation target rather than multiple non-coordinated targets across the
footprint.
The Regulation Market also changed the pricing mechanism for regulation by moving from tariff pricing to
market pricing. This pricing change is not included in the Value Proposition as it is not a true economic
benefit. However, the impact of market pricing is reported in MISO’s monthly market operations report.
11
Regulation-related improvements result in $67 to $74
million in annual benefits
Assumptions / Inputs
Pre-ASM average
regulation1
Regulation reduction
Production cost savings
per MW 3
Regulation
Calculation Methodology
1,559 MW
Post-ASM average
regulation2
3
396 MW
1,163 MW
$57,692 – Low case
$63,764 – High case
• Capacity from low cost generation units previously held
to meet regulation requirements is available for energy
dispatch. This component is valued using production
cost analysis.
• Calculation is based on the difference between pre-ASM
and post-ASM regulation multiplied by the production
cost savings per MW.
Low Estimate ($ in Mils.)
$67
High Estimate ($ in Mils.)
$74
1Pre-ASM
MISO average regulation (MW) from 4/1/2005 to 12/31/2008 and adjusted for membership changes
average regulation (MW) from October 2014 to September 2015
3Based on MISO production cost modeling using PROMOD® software
2Post-ASM
12
Ancillary Service Market also reduces spinning reserve
requirements and improves efficiency
4
Spinning
Reserves
Historical Perspective
Pre-Contingency Reserve Sharing Group (CRSG)
Each Balancing Authority (BA) determined their spinning reserve requirement based on their individual (or
Reserve Sharing Group) standards.
Post-CRSG/Pre-Ancillary Services Market (ASM)
Each BA determined their spinning reserve requirement based on the CRSG standards.
Post-ASM
MISO determines their spinning reserve requirement based on CRSG requirements.
What changed with MISO?
Starting with the formation of the CRSG and continuing with the
Spinning Reserve Market, the total spinning reserve
requirement has been significantly reduced. Reduced
requirement frees up low cost capacity to meet energy market
needs.
Spinning Reserve
MISO
The Spinning Reserve Market also changed the pricing
mechanism for spinning reserve by moving from tariff pricing to
market pricing. This pricing change is not included in the Value
Proposition as it is not a true economic benefit. However, the
impact of market pricing is reported in MISO’s monthly market
operations report.
13
Spin-related improvements provide annual benefits of
$32 and $35 million
Assumptions / Inputs
Pre-ASM average spinning
reserves requirement1
Spinning
Regulation
Reserves
Calculation Methodology
1,482 MW
Post-ASM average
spinning reserves
requirement2
935 MW
Spinning reserves
requirement reduction
547 MW
Production cost savings
per MW 3
3
4
$57,692 – Low case
$63,764 – High case
• The reduced requirements for spinning reserves frees
up low cost generation units (where spinning reserves
were previously held) to serve the energy needs of the
region. This component is valued using production cost
analysis.
• Calculation is based on difference between pre-ASM
and post-ASM spinning reserves multiplied by the
production cost savings per MW
Low Estimate ($ in Mils.)
$32
High Estimate ($ in Mils.)
$35
12006
Spinning Reserves (based on reserve requirement of 2,635 MW multiplied by 45%) adjusted for membership changes
weighted average spinning reserve requirement (MW) from October 2014 to September 2015
3Based on MISO production cost modeling using PROMOD® software
2Monthly
14
MISO’s regional planning allows more economical
placement of wind resources in the North/Central region1
5
Wind
Integration
North/Central Only
Combination design of
wind generation build-out
Local design of wind
generation build-out
ILLUSTRATIVE
Local Design = Renewable energy
requirements and goals met with resources
within the same state as the load
1The
Combination Design = Renewable energy
requirements and goals met with local resources
combined with regional resources in high ranking
renewable energy zones
wind integration benefit is based on work done for the Regional Generation Outlet Study II and includes the MISO North/Central footprint only.
15
The economic benefit of optimizing wind into MISO’s
footprint is $316 to $377 million in annual benefits
5
3
Wind
Regulation
Integration
North/Central Only
Assumptions / Inputs
Calculation Methodology
2010 to 2015
Wind turbine build
Local – without MISO1
Combination – with MISO2
Cumulative wind savings
Wind turbine cost midpoint3 (in millions)
Local – without MISO
Combination – with MISO
Difference
Cost/MW 4
Transmission Cost Offset5
8,002 MW
7,215 MW
787 MW
$58,883
$50,899
$7,984
$2,237,000–Low estimate
$2,796,000–High estimate
• An annual revenue requirement is used to calculate an
annualized avoided-cost benefit. The annual revenue
requirement is estimated based on an annual charge
rate that includes rate of return, property tax rate,
insurance cost rate, fixed O&M, and depreciation.
EGEAS software calculates the annual charge rate.
• Calculation does NOT include production cost savings
related to wind generation or congestion relief from
transmission upgrades.
$20,159,383
Low Estimate ($ in Mils.)
$316
High Estimate ($ in Mils.)
$377
1Wind
build out without MISO for 2010 to 2015 was calculated based on the results of the Regional Generation Outlet Study II (RGOS II). RGOS II was modified to include the MISO North/Central
footprint only. RGOS II results (modified for the MISO footprint) showed that wind turbines required to meet renewable energy mandates may be reduced by approximately 11% through the combination
design siting methodology. The 11% additional wind under the local design was applied to the actual wind added in MISO's footprint to calculate the wind build out in the region without MISO.
2Registered wind added to MISO footprint from 1/1/2010 to 9/30/2015
3Wind turbine costs shown reflect midpoint of low and high fixed charges for entire book life (25 years) of turbine
4High and low estimate of the initial book value of a 1 MW onshore wind turbine generator. Estimates calculated using EGEAS software. Book/tax life = 25/15 years.
5Transmission capital costs of $115M added each year beginning in 2015 through 2027 to recognize the transmission costs required to incorporate new wind resources. Transmission cost offset
incorporates annual revenue requirement as provided in tariff Attachment O. Requirement assumes 40 year straight-line depreciation.
16
MISO adds quantitative and qualitative value by
performing compliance activities on behalf of members
Before MISO
Standards
Development
• Utilities were varied in their approach to standards
engagement. Many were “standards takers,” relying
on the good judgment of others to develop standards.
This worked well in a voluntary compliance
environment.
6
Compliance
With MISO
• By collaborating and participating in standards creation,
MISO and members can better manage ultimate
compliance responsibilities
• MISO engages in drafting teams at NERC, NAESB and
other organizations to actively manage the scope of
standards development and limit the number of changes
required of MISO and stakeholders
• MISO’s collaborative efforts lighten the workload on all
members for input and control of the process
NERC
Compliance
• Many parties in the MISO region were responsible for
managing NERC compliance:
– 3 Reliability Coordinators
– 20+ Interchange Authorities
– 20+ Transmission Service Providers
– 20+ Balancing Authorities (BA)
– Several Planning Authorities
– Individual Reserve Sharing Administration
• With MISO as central balancing authority, many
compliance responsibilities have consolidated and
member responsibilities have decreased:
– 1 Reliability Coordinator – MISO
– 1 Interchange Authority – MISO
– 1 Transmission Service Provider – MISO
– Significantly fewer BA Compliance Requirements –
LBAs
– Fewer Planning Authorities
– Single Reserve Sharing Administrator – MISO
– Centralization of some Transmission Operator
Requirements – MISO
• Allows members to avoid or reduce compliance-dedicated
staff
Tariff
Compliance
• Each utility managed the compliance of their
individual tariffs and their separate OASIS functions
• Under MISO, tariff compliance is consolidated, saving time
and money for our members
17
Compliance activities performed on behalf of members for
Transmission Asset Management (TAM) and Operations
TAM Compliance
Tariff, Order 890 and Order 1000
• MISO supports member long-term planning and
compliance per our FERC-approved Tariff. Tariff
compliance efforts focus on the following:
–
–
–
–
Long Term Expansion Planning
– Resource Adequacy
Generator Interconnection
– Loss of Load Expectation
Transmission Service Requests
– FERC 715 Market Rates Filing
System Support Resource Studies
• MISO’s planning process ensures that the regional
planning process is open, transparent, coordinated,
includes both reliability and economic considerations
as well as equitable cost sharing of expansion costs.
• 50 MISO member Transmission Owners (TOs) in
2015; 41 have signed MISO’s Order 890, as listed in
Attachment FF-4
NERC
• MISO, as NERC Planning Authority, reduces
compliance staff needs of members, by performing
required compliance activities, such as the following:
– Long Term Expansion Planning
– Seasonal Assessments, including transmission, generation and
resource adequacy
6
Compliance
Operations Compliance
• Operations ensures compliance with approximately
1,856 Tariff and 660 NERC requirements per
MISO’s multiple roles:
–
–
–
–
Reliability Coordinator
Balancing Authority
Transmission Service Provider
Interchange Authority
• To ensure compliance with these requirements,
Operations manages the following activities:
– Internal and external audits
– Annual self-certification
– New and revised standard readiness
– Event reviews
• Operations helps members coordinate and
communicate efficiently via the following efforts:
– Emergency Operating Procedures (EOP) Coordination and
Workshops
– Balancing Authority Task Team
– Balancing Area Reliability-Based Control Field Trials
• Operations also fulfills attestation requests to
support member need to demonstrate compliance.
MISO manages approximately 4,000 requirements
18
MISO’s compliance activities provide between $91 and
$117 million in annual benefits
Assumptions / Inputs
Full-time
equivalents
(FTEs)
savings1
Hourly rates
Regulation
Compliance
Calculation Methodology
• Transmission Asset Management
− Tariff Compliance:
4.9 - 8.6
− Order 890 Compliance:
6.0 - 9.8
− NERC Compliance:
6.0 - 6.8
• Operations Compliance:
Affected
members2
6
3
33.0
Large-size members: 2 - 4
Medium-size members : 9 - 11
Small-size members: 21 - 27
• The full-time equivalents (FTEs) savings were based on
internal MISO analysis
• The compliance benefit was calculated by multiplying
the estimated FTEs needed to perform each compliance
activity, the affected members, and the labor rate per
hour.
Internal rate: $66/hr
(70% - 90% of hours)
External rate: $100-178/hr
(10% - 30% of hours)
Low Estimate ($ in Mils.)
$91
High Estimate ($ in Mils.)
$117
1Full-time equivalents (FTEs) for large-size members based on internal MISO analysis. Medium-size members estimated to save 1/3 of a large-size member's FTEs. Small-size members estimated
to save 1/6 of a large-size member's FTEs.
2Members were divided into large, medium, and small based on their electric sales (in MWh). Members with sales above 50 million MWhs are classified as large. Medium-size members have
electric sales between 10 million and 50 million MWhs. Small-size members have electric sales below 10 million MWhs. MISO members with multiple operating utilities were counted as one
member because it was assumed their service company operated a majority of their compliance functions.
19
MISO’s large footprint allows lower planning reserve
margins for Local Resource Zones
High Temperatures on July 28, 2015
MISO Monthly Peak of 120 GW
Footprint
7 Footprint
Diversity
Diversity
Planning Reserve Margins
without MISO
18.83%
with MISO
14.30%
Load Diversity Explained
The high temperature map illustrates
that the peak for each Load Serving
Entity (LSE) does not occur at the
same time.
Prior to MISO, individual LSEs
maintained reserves based on their
monthly peak load forecasts. Due to
MISO’s broad and diverse footprint,
LSEs now maintain reserves based on
their load at the time of the MISO
system-wide peak. This creates
significant savings.
20
MISO’s footprint diversity defers need for 12,582 MW
of additional capacity
7
Footprint
Diversity
180,000
160,000
158,1081
12,582
145,5263
140,000
25,054
18,207
MWs
120,000
100,000
Non-Coincident
Peak
Coincident
Peak
133,0542
127,3194
145,526
2015 Required Capacity
without MISO
2015 Required Capacity
with MISO
2015 Capacity Savings
with MISO
80,000
60,000
40,000
20,000
0
1Estimated “without MISO” 2015 Local Reliability Requirement (installed capacity basis) based on an average of the Local Resource Zones local reliability requirements; assumes 3,156 MW of
import capability of firm external purchases (per 2015 LOLE study)
2Forecasted 2015 non-coincident peak provided to MISO by LSE's in accordance with Module E-1 for the 2015-2016 Resource Adequacy Planning Year
32015 forecasted MISO coincident peak utilized in the 2015 Planning Resource Adequacy auction and adjusted for the Planning Reserve Margin (PRM) [127,319 MW] X (1 + PRM%[14.3%]).
4Forecasted 2015 MISO coincident peak utilized to determine the Resource Adequacy requirement in the 2015 Planning Resource Auction
21
MISO’s footprint diversity annual benefits are between
$1,289 and $1,950 million
Assumptions / Inputs
14.30%
2015 planning reserve margin
without MISO2
17.08% - 18.83%
155,780 MW 158,108 MW
2015 required capacity with
MISO4
145,526 MW
Capital investment avoided,
2015
10,254 MW –
12,582 MW
Cost/MW 5
Footprint
Regulation
Diversity
Calculation Methodology
2015 planning reserve margin1
2015 required capacity
without MISO3
7
3
$758,914 - $948,642
• Regional rather than localized use of the electrical
system allows more efficient and effective operation of
generation assets while reducing the planning reserve
margin needed for reliability.
• An annual revenue requirement is used to calculate an
annualized avoided-cost benefit. The annual revenue
requirement is estimated based on an annual charge
rate that includes rate of return, property tax rate,
insurance cost rate, fixed O&M, and depreciation.
EGEAS software calculates the annual charge rate.
Low Estimate ($ in Mils.)
$1,289
High Estimate ($ in Mils.)
$1,950
12015
MISO required planning reserve margin from the 2015 LOLE study.
estimate uses the average of the LRZs local reliability requirement per unit of load (ICAP%) prepared as part of MISO's Planning Year 2015 LOLE Study and assumes each LRZ has import
capability of firm purchases (total 3,156 MW) and level of non-firm external support (total 2,331 MW). High estimate uses the same method but assumes no non-firm external support is available.
32015 forecasted without MISO non-coincident peak load adjusted for the 2015 required planning reserve margin without MISO. Low estimate: [133,054 MW] X (1 + PRM w/o MISO[17.08%]).
High estimate: [133,054 MW] X (1 + PRM w/o MISO[18.83%]).
42015 forecasted MISO coincident peak utilized in the 2015 Resource Adequacy auction adjusted for the Planning Reserve Margin [127,319 MW] X (1 + PRM%[14.3%])
5 High and low estimate of the initial book value of a 1 MW combustion turbine generator. Estimates calculated using EGEAS software. Book/tax life = 30/15 years.
2Low
22
MISO delayed need for 1,694 MW of new capacity with
generation availability improvement of 1.54%
8
Generator
Availability
Improvement
North/Central Only
Generator Availability – All Units1
2015 With and Without MISO
Comparison
Reserves
Reserves
Reserves
Reserves
2015 Required Capacity 2015 Required Capacity
at pre-MISO Generator
with MISO Generator
Availability
Availability
2015 Capacity
Savings with MISO
1The
generator availability improvement is calculated using Generator Availability Data System (GADS) data from 2000 to 2014. The equivalent availability factor (EAF) metric is used which is a
measure of the actual maximum capability of a unit to generate electricity relative to the theoretically possible amount.
22015 required capacity with MISO adjusted for the planning reserve margin [110,000] multiplied by (1 + generator availability improvement % [1.54%])
3Forecasted 2015 MISO coincident peak, for MISO North and Central Zones, per Planning Year 2015/2016 Loss of Load Expectation study and as utilized to calculate the Resource Adequacy
requirement for the 2015 Resource Adequacy auction. The South region was not included due to insufficient annual generator availability data history.
42015 forecasted MISO coincident peak used to determine the Resource Adequacy requirement utilized in the 2015 Planning Resource auction [96,238 MW] X (1 + PRM%[14.3%])
23
The delay in capacity construction results in an annual
benefit of between $213 to $263 million
8
3
Generator
Availability
Regulation
Improvement
North/Central Only
Assumptions / Inputs
Calculation Methodology
2015 planning reserve
margin1
14.3%
Generator availability
improvement2
1.54%
2015 required MW capacity
at pre-MISO generator
availability3
111,694 MW
2015 required MW capacity
with MISO generator
availability improvement4
110,000 MW
Capital investment avoided,
2015
1,694 MW
Cost/MW 5
• Competitive wholesale power markets incentivize
generation owners to improve power plant availability
and forced outage rates, reducing need for new
generation capacity construction
• An annual revenue requirement is used to calculate
annualized avoided-cost benefit. The annual revenue
requirement is estimated based on an annual charge
rate that includes rate of return, property tax rate,
insurance cost rate, fixed O&M and depreciation.
EGEAS software calculates the annual charge rate.
$758,914–Low estimate
$948,642–High estimate
Low Estimate ($ in Mils.)
$213
High Estimate ($ in Mils.)
$263
1MISO's
Planning Year 2015 LOLE Study Report
generator availability improvement is calculated using Generator Availability Data System (GADS) data from 2000 to 2014. The equivalent availability factor (EAF) metric is used which is a
measure of the actual maximum capability of a unit to generate electricity relative to the theoretically possible amount.
32015 required capacity with MISO adjusted for the Planning Reserve Margin [110,000 MW] multiplied by (1 + generator availability improvement [1.54%])
42015 forecasted MISO coincident peak used to determine the Resource Adequacy requirement utilized in the 2015 Planning Resource auction [96,238 MW] X (1 + PRM%[14.3%])
5High and low estimate of the initial book value of a 1 MW combustion turbine generator. Estimates calculated using EGEAS software. Book/tax life = 30/15 years.
2The
24
Demand Response defers additional generation investment
Without MISO vs. 2015 Total Committed
Demand Response in MISO (MW)
5,9382
9
Demand
Response
MISO advances Demand Response
• MISO’s transparent price information aids market
participants in making investment decisions related
to existing and new load reducing resources
• MISO recognizes and compensates four types of
demand response:
– Demand Response Resource Type I (Energy /
Capacity)
– Demand Response Resource Type II (Energy /
Capacity)
– Demand Response as a Load Modifying Resource
(Capacity)
– Emergency Demand Response (Energy during
Emergencies)
3,4681
Without MISO
12009
2From
2015
Fixed Resource Adequacy Plan Demand Response in Zones 1-7 (2,858MW) plus the 2013/14 Transitional Planning Resource Auction (TPRA) results for Zones 8-9 (610MW)
the 2015/2016 Planning Resource Auction: Fixed Resource Adequacy Plan Demand Response plus cleared Demand Response [3,969 MW + 1,969 MW]
25
Demand Response (DR) growth results in annual
benefits of $75 to $149 million
Assumptions / Inputs
Without MISO to 2015
Incremental Committed
DR in MISO1
% of incremental DR
assumed facilitated by
MISO2
Capacity deferred due to
incremental DR facilitated
by MISO
Cost/MW 3
9
3
Demand
Regulation
Response
Calculation Methodology
2,470 MW
25% - 40%
617 MW – 988 MW
An annual revenue requirement is used to calculate an
annualized avoided-cost benefit for the capacity deferred
due to MISO-facilitated incremental Demand Response.
The annual revenue requirement is estimated based on
an annual charge rate that includes rate of return,
property tax rate, insurance cost rate, fixed O&M, and
depreciation. EGEAS software calculates the annual
charge rate.
$758,914–Low estimate
$948,642–High estimate
Low Estimate ($ in Mils.)
$75
High Estimate ($ in Mils.)
$149
12015 Demand Response committed in MISO [5,938 MW] less total Demand Response without MISO [3,468 MW]. The 2015 Demand Response committed in MISO is from the 2015/2016
Planning Resource Auction: Fixed Resource Adequacy Plan Demand Response plus cleared Demand Response [3,969 MW + 1,969 MW]. The without MISO demand response is the sum of
the historical 2009 Fixed Resource Adequacy Plan Demand Response in Zones 1-7 (2,858MW) and the 2013/14 Transitional Planning Resource Auction (TPRA) Results for Zones 8-9
(610MW).
2Based on internal MISO analysis, percentages reflect incremental Demand Response that would not exist unless enabled by MISO's market.
3High and low estimate of the initial book value of a 1 MW combustion turbine generator. Estimates calculated using EGEAS software. Book/tax life = 30/15 years.
26
MISO costs are a small fraction of total benefits
10
Cost
Structure
MISO Operating Costs1
($ in Mils.)
Cost Recovery
Category
2015
Schedule 10
$124
Schedule 16
$14
Schedule 17
$126
Schedule 31
$3
Total Operating Cost
$267
1MISO
Schedule 10, 16, 17 & 31 Budget for 2015
Note: MISO's administrative and operating costs encompass material costs incurred by its members. Additional cost impacts (both increases and decreases) are incurred. However, these
costs are not material compared to overall MISO value.
27
The MISO 2015 Value Proposition
Benefit by Value Driver
(in $ millions)
$75-$149
($267)
$213-$263
$2,101$3,069
$1,289$1,950
$91-$117
$316-$377
$140-$154
$67-$74
$32-$35
$145-$217
1
2
3
4
5
6
7
8
9
10
Improved
Reliability
Dispatch
of Energy
Regulation
Spinning
Reserves
Wind
Integration
Compliance
Footprint
Diversity
Generator
Availability
Improvement
Demand
Response
MISO Cost
Structure
Market – Commitment and Dispatch
Generation Investment Deferral
28
Total Net
Benefits
The MISO 2015 Value Proposition – Qualitative Benefits
1
Price/Informational
Transparency
2
Planning
Coordination
3
Seams
Management
29
Price and data transparency in the MISO market
provides a host of benefits
Before MISO
1
Price/Informational
Transparency
With MISO
Efficiency
• Bilateral markets lacked price and data transparency,
leaving participants searching for which plants are
operating at what cost
• Every market participant can see pricing and information,
increasing market efficiencies
Investment
• Bilateral markets provided insufficient price signals
which resulted in inefficient investment and placement
of generation resources and transmission
infrastructure
• MISO’s energy market price signals provide investors in
generation assets the underlying data required to develop
forecasts for future wholesale prices. Price forecasts, in
turn, provide the necessary basis for market driven
investments
Reliability
• Bilateral markets achieved reliability based on
contractual rights and industry standards with little
thought to economic impacts
• MISO enhances reliability by informing all market
participants of grid conditions and market operations
through the public posting of electricity prices and other
key system information
• Prices in the MISO energy market reflect real-time system
conditions, high market prices indicating where more
generation is needed and lower market prices signifying
the reverse
30
MISO’s transmission planning process is focused on
minimizing total cost of delivered power to consumers
Before MISO
2
Planning
Coordination
With MISO
Transmission
Expansion
Planning
Model
• Reliability-based model
– Focused primarily on grid reliability
– Typically considers a short time horizon
– Seeks to minimize transmission build
•Value-based model
– Focused on value while maintaining reliability
– Reflects appropriate time scales
– Seeks to identify transmission infrastructure that
maximizes value
– Identifies the comprehensive value (reliability,
economic, and policy) of projects
Planning Scale
and Efficiency
• Local view
– Objective of expansion is to address local
needs
– 26 individual entities optimizing the system
within their area
•Regional view
– Objective of expansion is to address aggregate
regional needs consistent with value-based plans
in addition to meeting local needs
– Offers opportunities to find efficiencies across
multiple Transmission Owners
Cost Allocation
• Free rider issues caused by a lack of alignment
between transmission cost and the causers and
beneficiaries
• MISO helps facilitate the cost allocation of transmission to
minimize free rider issues
• MISO regional cost allocation matches costs roughly
commensurate with beneficiaries
31
MISO adds value by managing the seams around its
footprint
3
Seams
Management
Before MISO
With MISO
• In order to avoid congestion, a utility or balancing
authority (BA) had seams agreements with each
neighbor to monitor flowgates when selling
transmission service. Lacking such agreements,
service was sold ignoring neighbors’ flowgates
with Transmission Loading Relief (TLR)—the only
effective congestion management process. If firm
service was sold, curtailment had implications to
the owner of the firm service, and made the
service unavailable when needed.
• Seams agreements between MISO and its neighbors
eliminate the need for individual agreements between
utilities or BAs
Market Flows
& Allocations
• A utility or BA served its own interests by
classifying all of its generation to load flows as
firm so the flows would not be curtailed. This
would cause parallel flow issues for neighboring
BAs in that firm flow curtailment using TLR had
wide ranging implications. This required the utility
or BA experiencing congestion to redispatch
without compensation in order to manage parallel
flow impacts from others.
• The seams agreements between MISO, PJM and
SPP provide flowgate allocations between the seams
parties that limit the amount of firm market flows.
This requires the parties to the seams agreement to
classify some of their respective market flows as nonfirm so they can be curtailed using TLR. Having each
market classify some of its market flows as non-firm
means these flows are then subject to curtailment
using TLR along with other non-firm usages.
Market-toMarket
Process
• When congestion occurred within the MISO region or
PJM’s footprint, the IDC assigned tag curtailments
and/or market flow relief obligations to the flows. Prior
to having a market-to-market process, utilities in the
MISO and PJM regions would bind their own
flowgates based on the relief obligation from the IDC
without regard to the cost of re-dispatch in order to
meet the relief obligation.
• Under the market-to-market process, MISO and
neighboring markets both bind a coordinated flowgate in
order to dispatch the most cost effective generation to
manage congestion. After-the-fact settlement is used to
compensate for assistance provided by the other market.
By both markets binding on a constraint located in one
market, the proper price signal is sent to both markets,
helping achieve price convergence at the border.
Interchange
Transactions
• These agreements reduce the likelihood of parallel
flows causing overload on flowgates and the need for
TLRs to manage congestion, except when
unexpected events occur
32
Future benefit - The Multi Value Project Portfolio will create $13.1 - $49.6
billion in net benefits
Benefit by Value Driver
$2,192$2,523
(20 to 40 year present values, in 2014 $ million)
$17,363$59,576
$946$2,746
$327$1,223
$21,451$66,816
$8,303$17,192
$291$1,079
$0
Increased Market
Efficiency
6
Deferred Generation
Investment
Other Capital Benefits
Net Benefits
5
Total Costs
(Sum of Annual
Revenue
Requirements)
4
Total Benefits
Future
Transmission
Investment
3
Wind Turbine
Investment
2
Transmission
Line Losses
Operating
Reserves
1
Planning
Reserve
Margin
Congestion &
Fuel Savings
$13,148$49,623
* Value is the average of the Low and Historical
Demand and Energy Business as Usual Futures
33