MISO example:How do other regions do it?

WPTF Roundtable, Seattle November 14, 2019

1

MISO & neighboring U.S. electric grid operators

MISO Control Centers: Eagan, Indianapolis (HQ), Little Rock

MISO 15 states + Manitoba

42 million customers

$30 billion/yr market

> 6,600 generation units with 175,000 MW capacity

72,000 miles of high voltage transmission lines

> 180 member utilities

> 460 market participants

2

What does MISO do?

• Conduct day-ahead and real-time energy and operating reserves markets

• Manage least cost economic dispatch of generation units

• Monitor and schedule energy transfers on the high voltage transmission system

MISO’s Vision: Be the most reliable, value-creating RTO

Efficient Wholesale Market Management & Operations to Ensure Reliability

Comprehensive Regional Transmission Planning

• Long-range transmission planning • New generator interconnection and retirement• Transmission studies, e.g., Renewable Integration Impact Assessment (RIIA)

ImprovedReliability /Compliance

More EfficientUse of Existing

Assets

Reduced Needfor Additional

Assets

Cost Structure Total NetBenefits

$391

$362

$3,094

($304)

$3,543

3

Annual Benefits

$23,281 million

2018 Benefit by Value Driver($ millions)

MISO Value Proposition: $3.5 billion in benefits annually, and over $23 billion since 2009

RTO/ISO cost structures are largely fixed; implying economies of scale

4

ISO NENY ISO

CAISO

ERCOTSPP

MISOPJM

0.0

0.2

0.4

0.6

0.8

1.0

1.2

0 200 400 600 800 1000

Administrative Charges vs. Load Served

Terawatt hours per year, 2018

Dol

lars

per

meg

awat

t hou

r 1

1 Administrative charge is based on tariff revenues divided by load terawatt yours, published rates may be on a different basis.

Resource adequacy, markets, and transmission planning functions are inter-dependent and synergistic

5

Markets• Real time• Day ahead• FTRs, A/S, etc.• Market operations• Settlements

• Price signals(new build)

• Outage data• Capacity

accreditation (e.g., ELCC)

Resource Adequacy

Transmission Planning

• Economic planning• Reliability planning• Other… (“MVP”s, RIIA)• GI queue/retirement• Cost allocation

• Price signals (congestion to be resolved)

• Market solutions for transmission challenges

• Fleet change• Sub-regional import/

export limitations• Inter-regional transfers

• Annual Planning Resource Auction (PRA)

• OMS-MISO Survey• Resource Availability

and Need (RAN)

FERC and IMM cover multiple

functions

6

Resource Adequacy traditionally refers to the ability to meet the highest expected level of electricity consumption (i.e., peak demand)

MISO partners with state regulators and utilities to ensure sufficient electric generating resources are available to supply end-use customers

Load serving entities (e.g., utilities) must meet their load forecast plus a reserve margin which is established by MISO through the following: Owned resources Controlled/contracted resources Participation in MISO’s voluntary

capacity auction (i.e., Planning Resource Auction – PRA)

Ensuring resource adequacy is the responsibility of the states, in conjunction with their load serving entities; MISO processes must support these state objectives

7

The Independent Market Monitor (IMM) reviews the auction results for physical and economic withholding

Multiple options exist for Load-Serving Entities to demonstrate Resource Adequacy:

• Submit a Fixed Resource Adequacy Plan (FRAP)• Utilize bilateral contracts with another resource owner• Participate in the Planning Resource Auction (PRA)

Inputs

• Local Clearing Requirement (LCR) = capacity required from within each zone

• MISO-wide reserve margin requirements, which can be shared among the Zones, and Zones may import capacity to meet this requirement above LCR

• Capacity Import/Export Limits (CIL/CEL) = Zonal transmission limitations

• Sub-Regional contractual limitations such as between MISO’s South and Central/North Regions

Outputs

• Commitment of capacity to the MISO region, including performance obligations

• Capacity price (ACP = Auction Clearing Price) for each Zone

• ACP price drives the settlements process• Load pays the Auction Clearing Price for

the Zone in which it is physically located• Cleared capacity is paid the Auction

Clearing Price for the Zone where it is physically located

MISO’s Resource Adequacy construct combines regional and local criteria to achieve a least-cost solution for the region

OMS-MISO Survey: Future reserve margins demonstrate uncertainty around potential retirements and new resources

8

2.5

2.30.8

1.9 1.3

0.3

0.7

1.4

4.8 5.5

2020 2021 2022 2023 2024

Projected Regional Capacity Position in Installed Capacity in GW (and % Reserves)

Potential New Capacity Potentially Unavailable Resources Committed Capacity Projections

5.8 (21.4%)

4.0 (20.0%)

1.2 (17.7%)

-1.3 (15.8%)-2.3 (15.0%)

3.0 (19.2%)1.1 (17.7%)

3.4 (19.5%)

6.8 (22.2%)6.7 (22.1%)

3.63.2

Planning Reserve Margin “PRM” =

21 GW(16.8%)

OMS-MISO Survey also breaks down the ‘local clearing requirements’ and capacity balance by sub-region

9

-

5

10

15

20

25

30

2020 Local Resource Adequacy (Installed Capacity GW)

Committed Capacity Potential Capacity

Behind the Meter Generation Demand Response

Local Clearing Requirement

MN, MT, ND, SD, West WI

AR LA and TX

-

5

10

15

20

25

30

2024 Local Resource Adequacy (Installed Capacity GW)

Committed Capacity Potential CapacityBehind the Meter Generation Demand ResponseLocal Clearing Requirement

Potential Capacity includes both new generation and potential retirements

Load Modifying Resources include Demand Response (DR) and Behind the Meter Generation (BTMG)

IAEast WI and

Upper MI

IL MO IN and KY

Lower MI

MS LA and TX

MSARLower MI

IN and KY

MOILIAEast WI and

Upper MI

MN, MT, ND, SD, West WI

The transmission planning process ensures local/short-term needs are integrated with regional longer-term requirements

10

Policy Assessment

Local Planning

Regional Planning

Resource Planning

Evaluate interconnection and retirement requests; identify upgrades necessary to integrate new resources

MISO Value-Based

Planning Approach

Long-term regional planning based on future scenarios

Validate needs for plans identified by the member Transmission Owners; seek

efficiencies by combining plans, if possible; evaluate system against reliability standards

Analyze the impacts of changes in state or federal

policy; determine the transmission required to

support the policies

Transmission investment in MISO is trending up, but generally not for new ‘backbone’ transmission

11

'03 '05 '06 '07 '08 '09 '10 '11 '12 '13 '14 '15 '16 '17 '18 '19

MISO Transmission Expansion Plan (MTEP) Approved Investment by Year and Project Category (in billions)

Targeted Market Efficiency Project

Transmission Access Projects

Market Efficiency (Congestion)

Transmission Delivery Service

Generator Interconnection

Multi-Value Projects (MVP)

Baseline Reliability

Other *$3.8

$3.3

* Other = Projects based on local Transmission Owner identified needs including reliability, economics, equipment age and condition, environmental, etc.

$1.1$0.7

$1.2

$2.6

$0.4$0.9 $1.2

$7.3

$1.4 $1.4

$2.4 $2.6 $2.8 $2.9

(Proposed)

Primary project types:Total: $37 billion

12

Questions ?

Brian Tulloh – Executive Director, External Affairs (North Region)651-632-8408214-316-9846 (mobile)btulloh@misoenergy.org

Contact:

[pull up pages if needed]

13

Extra slides

Regional Transmission Organizations (RTOs) were formed to operate the transmission grid on a regional basis, removing transactional barriers across utility and state boundaries…

Before MISO, the footprint consisted of dozens of balancing authorities acting independently

14

With MISO, the footprint is operated as one large network and one balancing authority (with 37 local balancing areas)

MDU

3 GW52 projects

3 GW18 projects

52 GW356 projects

23 GW128 projects

8 GW22

projects

2 GW7 projects

MISO’s Current Generator InterconnectionQueue (currently active projects)

Storage Hybrid SolarWind Gas Other

Total:91 GW

583 projects

Renewables account for over 85% of MISO’s current active generator interconnection request ‘queue’

1515

2.42.23.6

7.62.9

3.52.5

13.6 22.1

28.2

2.7

14.5

17.614.8

5.5

0

5

10

15

20

25

30

35

40

45

50

2016 2017 2018 2019

Gen

erat

ion

Cap

acity

(GW

)

WindHybridSolarGasStorageOther

21

44

40 41

120projects

255projects

239projects

301 projects

Projects entering MISO’s Generator Interconnection Queue over the past 4 yrs

16.7%14.2% 14.8% 14.3% 15.2% 15.8% 17.1% 16.8%

2012 2013 2014 2015 2016 2017 2018 2019

27.4% 28.1%

18.6% 18.0% 18.2% 18.8%

Actual Reserve Margin

Planning Reserve Margin (PRM)Req’mt

19.1% 19.3%

Reserve margins are adequate but have tightened since 2013; our neighbors tend to have excess capacity

16

MISO Historical Reserve Margins 2019 Reserve Margin by RTO*

* Source: NERC Long-Term Reliability Assessment publications for anticipated reserve marginsNote: 2008 MISO is an estimate based on portions of MRO, RFC-MISO, and SERC data. Note: 2008 PJM is RFC-PJM.

19.3%

29.0%

31.8%30.7%

24.8%

22.4%

8.5%

MISO PJM SPP ISO-NE NYISO CAISO ERCOT

17

…a generation fleet which has shifted, with the pace accelerating toward more renewables and conventional unit retirement

Accelerated Fleet Change

2005

2033: Future Planning Scenarios

76%

7%

13%

4%

Distributed & Emerging

Technology

47%

27%

16%

2%8%

2018

Nuclear

Coal

Gas

Wind

Solar

OtherDemandSide Mgmt

30%

32%8%

4%4%

9%

13%

30%

16%11%

3%4%

7%

29%

Total MISO Generation Mix (% of MWh)

9

27

59

3

3

MISO Total Interconnection Queue

RAN is the most timely and significant near-term strategic initiative while continuing to evaluate several key issues

18

101 GW

* More aggressive utility de-carbonization goals and proposed policy changes in Illinois, Minnesota and Wisconsin may further accelerate renewables penetration

The picture can't be displayed.

Portfolio Change (energy mix %)(Based on utility and state announcements)

Longer-term Issues to Further Evaluate:

• Ensuring sufficient attributes to meet requirements every hour

• Aligning broad regional and local reliability requirements

• Sequencing and aligning enhancements to not only address near-term issues but also provide an effective progression of changes over time

76%48%

29% 24%

13%

16%

9% 9%

7%26%

29% 29%

7%30% 35%

4% 3% 4% 4%

0%

20%

40%

60%

80%

100%

2005 2018 2030 2030 +Policy*

Coal Nuclear Gas Wind/Solar Other

19

Going forward, Resource Availability and Need (RAN) guiding principles will help ensure reliability for a transforming grid…

20

1) Reliability Needs and Requirements: Reliability criteria must reflect required attributes in all horizons – “all hours matter”

2) Reliability Contribution: Members are responsible for meeting reliability criteria with resources that will be accredited based upon the resource’s ability to deliver those attributes

3) Alignment with Markets and Infrastructure: Market prices must be reflective of underlying system conditions and resources must be appropriately incentivized for the attributes they provide; infrastructure should enable efficient utilization of resources

Guiding Principles

The RAN initiative includes efforts to address both near-and long-term reliability

21

Resource Accreditation:

• Match with availability

• Deliverability improvements

Resource Adequacy Construct:

• Reflect risks throughout year

• PRA reliability value reflected in auction results

Market Incentives:

• Prices reflect operating conditions

• Incentivize needed system attributes

Next Focus Continued improvement in

availability and flexibility

In Flight Continued refinements for

2020 Planning Resource Auction (PRA), progress on

market-based solution

Progress, To Date Improve resource transparency

and performance for spring 2019 and subsequent planning

year

Load Modifying Resources (LMRs):

• Create transparency and better align LMR obligations with other resources

Outage Coordination:

• Improve forward-looking transparency for stakeholders and MISO

• Increase early outage notification and flexibility during emergencies

PRA Inputs:

• Improve PRA inputs, focus on LMR

• Create rules outlining reasonable expectations for availability or replacement during the planning year

Visibility:

• Multi-day Operating Margin forecast

Resource accreditation will deliver enhancements that align planning actions with obligations

22

Improving the expectation of generators’ availability, considering historical unit performance (outage frequency, duration, and timing), required reliability attributes and deliverability of capacity to load

What is it?

Tightness in operating margins extends outside summer, increased occurrences of emergency operations, a changing generation fleet and increased reliance on load modifying and intermittent resources

What are the drivers?

Incentivize required system attributes to be available when needed and gain improved visibility into actual resource availability

Why is it important?

• Historical Performance - Software Development, Implementation: Q4 2020

• Deliverability - Software Development, Implementation: Q3 2020

• Other attributes - Software Development, Implementation: Q4 2021

Forward Plan

Pricing will need to evolve to reflect the needs of a changing resource mix

23

Pricing will need to incent reliability attributes – reflecting both system conditions and availability of attributes (e.g., out-of-market actions, demand response deployments, value of lost load (VOLL) and the loss of load probability)

What is it?

Price formation has been a primary instrument to foster competitive markets - delivers reliable and cost effective outcomes, especially during emergency events [continued theme in IMM recommendations]

What are the drivers?

Prices should appropriately reflect the availability of necessary attributes in all system conditions including during emergency declarations

Why is it important?

• Revise VOLL and additional pricing parameters. Develop methodology and Stakeholder engagement Q2 2020

• Emergency and Scarcity Pricing – Prioritize initiative with Integrated Roadmap and evaluate Q3–Q4 2019

Forward Plan

Our planning process follows established Guiding Principles to ensure reliability, support policy requirements, and enable a competitive market to benefit all customers

24

• Make the benefits of an economically efficient electricity market available to customers by identifying transmission projects which provide access to electricity at the lowest total electric system cost

• Develop a transmission plan that meets all applicable NERC and Transmission Owner planning criteria and safeguards local and regional reliability through identification of transmission projects to meet those needs

• Support state and federal energy policy requirements by planning for access to a changing resource mix

• Provide an appropriate cost allocation mechanism that ensures that costs of transmission projects are allocated in a manner roughly commensurate with the projected benefits of those projects

• Analyze system scenarios and make the results available to state and federal energy policy makers and other stakeholders to provide context to inform regarding choices

• Coordinate planning processes with neighbors and work to eliminate barriers to reliable and efficient operationsG

uidi

ng P

rinci

ples

for P

lann

ing

The 2011 MVP portfolio is nearing completion

25

MVP Project Status April 2019

MISO’s Evolution

26

MISO’s Value Proposition

27

MISO’s Governance Structure

28