Partners in Business Meeting Meeting Kick-Off Mike Dabney Manager, - - PowerPoint PPT Presentation

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Meeting Kick-Off

Mike Dabney – Manager, Stakeholder Relations

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2018 Fall ITC Midwest Partners in Business Meeting

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Safe Harbor Language and Legal Disclosure

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Photo Release and Waiver

By participating in this ITC event or activity, you authorize ITC Holdings Corp., its subsidiaries and affiliates (hereinafter “ITC”) and its employees, agents and representatives acting on behalf of ITC, to use your name, voice, photograph, image and/or video (collectively referred to as your likeness) in any manner and media, worldwide in perpetuity, without compensation. All such photographs and recordings will be the sole property of ITC. Your participation further releases and discharges ITC from any and all claims and demands that may arise out of, or in connection with, the use of your likeness. Thank you for your cooperation!

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Today’s Facility and Meeting Accommodations

• Sign in on meeting registration sheet/ticket drawing
• Refreshments
• Lunch
• Restrooms/facility review
• ITC Midwest website: http://www.itc-holdings.com/op/itc-midwest
• MISO OASIS website: www.oasis.oati.com
• Relax, enjoy and ask questions
• Introductions

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Today’s Agenda

Meeting Kick-off: Mike Dabney - Manager Stakeholder Relations Welcome & Update:

Krista Tanner - President ITC Midwest Linda Apsey - President/CEO ITC Holdings Inc.

State Regulatory Update:

Tim Tessier - Manager Regulatory

What’s the Value of Transmission:

Tom Petersen - Director Public Affairs

Reliability Update:

Dan Daavettila - Senior Operations Planning Engineer

IPL: Transmission Value in Action

Scott Hamlin - Senior Transmission Specialist

Lunch Formula Rate Review:

Zach Paquette - Manager Rates

Projects Overview:

Jeff Eddy - Manager Planning Dan Barr - Supervisor Planning Robert Walter - Supervisor Planning

Project Management Update:

Marlon Vogt - Project Manager Aaron Curtis - Project Manager

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Krista Tanner – President, ITC Midwest Linda Apsey – President/CEO ITC Holdings Inc.

Welcome

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State Regulatory Update

Tim Tessier – Manager, Regulatory Strategy

CLICK TO EDIT MASTER TITLE STYLE Franchising to Support 34.5-69 kV Rebuilds and Conversions Transmission line franchises granted

• Over 125 franchises have been acquired, including MVPs,

69 kV, 161 kV and 345 kV lines

• 7 new franchises for 34.5-69 kV rebuilds in last year

Transmission line franchises still needed

• 17 new franchises to meet 2021 rebuild completion goal
• 10 projects currently in regulatory process
• Public information meetings for 2 projects later this year

CLICK TO EDIT MASTER TITLE STYLE Regulatory Progress on Cardinal-Hickory Creek (MVP-5) Project Franchising initiated in Iowa

• Public meetings held in March 2018
• Franchise application filed with Iowa Utilities Board in May

2018

• Project also under regulatory review by the Public Service

Commission of Wisconsin and federal agencies

• Working through regulatory review process with goal to have

franchise granted by second quarter 2020 Landowner negotiations ongoing

• Over halfway through land acquisition process
• Voluntary easements have been secured for 53% of

proposed route

CLICK TO EDIT MASTER TITLE STYLE Alliant Energy’s Duane Arnold Docket On July 27, 2019, Alliant Energy announced agreement to discontinue purchasing power from Duane Arnold Energy Center

• Filed request with Iowa Utilities Board to create regulatory

asset to collect buyout payment

• Sought approval to collect buyout payment through energy

adjustment clause ITC Midwest actively involved in docket

• Filed intervention and participating in hearing process
• Focus is ensuring that there are no adverse effects on the

regional transmission system and ensuring that the record is accurate regarding the necessary transmission upgrades and the costs and timing of those upgrades.

CLICK TO EDIT MASTER TITLE STYLE Improvements to Public Information Meetings Majority of transmission line projects require public information meeting

• Content hadn’t changed much over last 10 years
• Changes were needed to respond to landowner feedback

Goals of updates to meeting format

• Improve landowner information to facilitate project discussion

and understanding

• Explain project, process, impacts and roles in simpler terms
• Provide additional information that will help educate

landowners to be better prepared for every step of the project

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Questions?

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The Value of Transmission

Tom Petersen – Director, Public Affairs

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Agenda

• The value of

transmission:

• Reliability
• Resiliency
• Accommodating

generation changes

• Congestion reduction
• Market efficiency/

Economic impact

• How you see it

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Agenda

• The value of

transmission:

• Reliability
• Resiliency
• Accommodating

generation changes

• Congestion reduction
• Market efficiency/

Economic impact

• How you see it

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System History

• In 2007, State of Iowa looking to address:
• Pending generation changes
• Critical need to update 34.5 kV system
• Declining reliability
• ITC committed to investments to:
• Support state policy objectives
• Accelerate timeline to convert 34.5 kV system
• Respond to growing customer demands for reliability;

position system to support economic growth and development

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Flexible, Accessible Grid Needed

• Legacy transmission system

isn’t designed to meet current and future needs and demands

• Investments in transmission

grid are needed and prudent to improve reliability and reduce customer outages

• ITC Midwest tasked with

meeting the needs of the changing transmission environment

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Critical Issues – 34.5 kV Rebuild

ITC Midwest system had a significant amount of antiquated 34.5 kV lines

• Aged system, past its useful life
• Radial, versus network system
• No lightning protection

Rebuild to a networked 69 kV system

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34.5 kV Rebuilds

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34.5 kV to 69 kV rebuild miles to date by year:

Year 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 Miles 17 8 22 65 61 72 83 33 17 22 Cumulative Miles 17 26 47 112 173 245 328 361 377 400 Remaining 635 627 606 541 480 408 325 292 275 253

Note: All values rounded to nearest mile.

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34.5 kV Rebuilds

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• Annual 34.5 kV miles to be rebuilt to meet the 2021

rebuild deadline, while coordinating with stakeholders

Year 2018 2019 2020 2021 Miles 81 88 61 23 Cumulative Miles 481 568 630 653 Remaining 172 84 23

Note: Mileage is estimate with higher numbers in early years, anticipating realignment of work due to potential delays (e.g., routing, easement, and franchising process).

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Critical Issues – ITC Grid Improvement

Work Completed Across Service Territory

Upgrades to existing lines:

• Rebuilding infrastructure
• Rebuilding, converting

34.5kV to 69kV

• Networking previously

radial lines

• Increased reliability and

value for end-use customers through focused maintenance program

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Critical Issues – Reliability Improvements

• Focused capital investment
• Outstanding maintenance

practices

• Comprehensive system

planning and upgrades

• Frequent, cross-functional

review of system operations for improvement opportunities

ITC Midwest has reduced system outages by more than 50% since 2008

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ITC Value | System Reliability

What ICF studied: Improvement in system performance attributed to ITC’s capital investment and maintenance practices. Outage below 100kV has a direct customer effect. Customer benefit: These projects saved customers $98 million between 2008 and 2014 alone.

“Electric power outages and blackouts cost the nation about $80 billion annually.” – Berkeley Lab/U.S. Department of Energy

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Why Transmission Matters

• In 2009, Louis Dreyfus Ethanol plant in

Grand Junction, Iowa, went on line

• This new plant was connected to the

system on an old 34.5 kV line, without lightning protection/static line.

• ITC near that time rebuilt the Grand

Junction to Paton line to 69 kV standards, and dramatically reduced the number of

• utages.

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Agenda

• The value of

transmission:

• Reliability
• Resiliency
• Accommodating

generation changes

• Congestion reduction
• Market efficiency/

Economic impact

• How you see it

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Resilience

• Defining it as bouncing

back from service impact

• Limited quantification
• Outage duration

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Why Transmission Matters

• When an E-3 tornado drove through

central Marshalltown July 19, the storm tore down 37 poles on the main 34.5kV line through town

• Structures built when Lyndon Johnson

was president

• Recognizing the variability of wind and

storms, noteworthy that just half a mile away, similar voltage line rebuilt in 2014 suffered no impacts

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Agenda

• The value of

transmission:

• Reliability
• Resiliency
• Accommodating

generation changes

• Congestion reduction
• Market efficiency/

Economic impact

• How you see it

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Critical Issues – Changing Generation

Coal 86%

Nuclear 10% Hydroelectric 3% Natural Gas 1%

2017 1990

Source: Energy Information Administration: Net Generation by State by Type of Producer by Energy Source

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Coal 44%

Hydroelectric 2% Natural Gas 8% Nuclear 9% Other 0%

Wind 37%

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Critical Issues – Generation Retirements

Neal 1-2 496 MW Council Bluffs 1-2 131 MW Sutherland 2 38 MW Riverside 3-5 141 MW DBQ 1-3-4-5 129 MW Nelson Dewey 1-2 200 MW Lansing 2-3 50 MW 6th St. 2-4-7-8 68 MW Agency 1-2-3-4 70 MW ML Kapp 1 19 MW Stoneman 40 MW Sutherland 1-3 109 MW

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Critical Issues – Generation Additions

Short-term/Already announced:

• MidAmerican announced Wind

XI, planned $3.6B investment, 2,000 MW of new wind projects

• Alliant Energy announced

planned $1B investment, up to 500 MW of new wind projects

• Dozens of additional

developers proposing hundreds

• f megawatts of new wind

projects

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Transmission Upgrades for MGS

Major Upgrades

• Line relocations at the Marshalltown

sub

• Rebuild the Newton-Prairie City 69kV

line to current 69kV standards – 5.55 miles

• Jasper-Aurora Heights – 4 miles
• Blairstown-Marshalltown uprate –

structure replacements

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Project 3:

• Joint ITC/MidAmerican Energy Company (MEC) Project
• ~145 miles in Iowa, ~70 in Minnesota

Project 4:

• Joint ITC/MEC Project
• ~190 miles in Iowa

Project 5:

• Joint ITC/ATC/DPC Project
• Preferred route ~102 miles in Iowa, Wisconsin
• Status: Ongoing regulatory process; targeted in-service 2023

Project 7:

• Joint ITC/MEC/Ameren Missouri Project
• ~90 miles in Iowa, Missouri
• Status: Under construction; targeted in-service 2019

Multi-Value Projects

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Critical Issues – Accommodating Generation

MVPs and other 345 kV lines built or under construction since 2010 support connection of renewables.

“Wind farm development has followed as these lines have been approved and

• built. At the end of the day,

that’s the point.”

• Nathaniel Baer, Iowa

Environmental Council, in Midwest Energy News

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Why Transmission Matters

• The Dubuque Power Plant powered Dubuque for

more than 80 years, with plants at this site for more than 100 years

• December 2014, Alliant announced plant

conversion to natural gas, before closing it in 2016

• Closings planned for three other plants in

Cassville, Wisconsin, and Clinton, Iowa

• To address the issues, ITC:
• built Dubuque 8th Street-Salem 161 kV line,
• constructed the Hickory Creek substation,
• rebuilt the Hickory Creek-Lore line
• moved ahead with plans for the Cardinal-

Hickory Creek MVP

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Agenda

• The value of

transmission:

• Reliability
• Resiliency
• Accommodating

generation changes

• Congestion reduction
• Market efficiency/

Economic impact

• How you see it

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Market Analysis & Congestion Evaluation (MACE)

• Causes of unexpected congestion
• Forced outages of transmission facilities
• Facility derates (NERC alert, field inspection, etc.)
• Unexpected generation patterns (higher or lower wind output, forced

generation outages, etc.)

• Program to help ITC monitor & minimize congestion in our footprints
• Improve transmission system utilization
• Reduce financial impact of outages on customers
• Provides a relative benchmark for unhedged congestion

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Congestion Cost Trend

$0 $20,000,000 $40,000,000 $60,000,000 $80,000,000 $100,000,000 $120,000,000 $140,000,000 $160,000,000 $180,000,000 2012 Cumulative Total 2013 Cumulative Total 2014 Cumulative Total 2015 Cumulative Total 2016 Cumulative Total 2017 Cumulative Total

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Agenda

• The value of

transmission:

• Reliability
• Resiliency
• Accommodating

generation changes

• Congestion reduction
• Market efficiency/

Economic impact

• How you see it

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ITC’s Grid Investment | Singular Focus

Singular Focus

• System investment and drive value to customers
• Frequent and proactive customer engagement

Forward Looking

• Respond to needs of today while planning for the

future needs and policy goals

Interconnections

• Expand access to competitive energy markets
• Actively and collaboratively engage customers

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ITC Value | Market Efficiency

Project Name ITC Case Non-ITC Case Hazleton - Salem 345 kV line with a 2nd Salem 345/161 kV 448 MVA transformer. Yes No Quad Cities-Rock Creek-Salem 345 kV line Yes Yes Rock Creek 345/161 kV transformer Yes Yes Heron Lake-Lakefield 161kV line rebuild Yes No Arnold-Vinton-Dysart-Washburn 161kV Reconductor Yes No

What ICF studied: Two system models were developed, an ITC case and non-ITC case. The non-ITC case excluded project were only constructed due to ITC’s approach to transmission investment Modeled the Adjusted Production Cost (APC)

• f each scenario

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ITC Value | Market Efficiency

Customer benefit: ITC’s recently constructed transmission projects saved customers in the MISO region $714 million between 2010 and 2015 alone in reduced energy production costs due to decreased system congestion, according to the ICF study.

• Savings to Midwest customers: $172 million

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ITC Value | Aggregated Results

All Systems ~$1.4 Billion: Benefits accruing to all customers in all regions where ITC operates, resulting from ITC philosophy on system investment ITC Midwest ~$610 Million: Benefits accruing directly to ITCMW customers from ITC investment philosophy Not Studied

• Benefits accrued from ITC’s approach to planned
• utages congestion management
• Benefits accrued from reduced outage on

the EHV transmission system

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ITC Value | Economic Multiplier

• Investing in infrastructure has an

economic multiplier effect

• Materials purchased
• Services purchased
• Employment
• Example impacts for ITC Midwest:
• $953M investment through 2013

generated $1.4B multiplier

• Property tax payments in excess of

$30M

• Wind generation impacts of more than

$2B

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Why Transmission Matters – Economic Impact

• Jackson County, Minnesota, experienced its peak

population in 1940. Today, the population is 41% below what it was then

• Jackson County is one of the most active wind farm

counties in Minnesota: 12 wind farms with combined nameplate capacity of 346 megawatts.

• 2009: County received less than 5% of general

fund revenues from wind tax

• 2017: County received $1.9 million (16% of

general fund revenues),

• 2018: County is slated to receive $2.2 million

(20% of budgeted general fund revenues)

(Source: Moody’s: Wind Farms Bring Windfalls, May 2018)

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How you see it

• Value is in the eye of the

beholder

• We will continue working with

stakeholders to define the value of these investments in tangible terms

• Important to hear your

perspective

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Questions?

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System Performance

Dan Daavettila – Senior Engineer, Operational Planning

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Reliability Definitions

• Planned Outage: A non-automatic
• utage with advance notice for planned

activities that may be deferred

• Forced Outage: A non-automatic
• utage for the purpose of avoiding

emergency that cannot be deferred

• Automatic Outage: An outage that

results from the automatic operation of a switching device, causing an element to change from an In-Service State to a not In-Service State

• Momentary Outage: An automatic
• utage with an outage duration of less

than one minute

• Sustained Outage: An automatic
• utage with an outage duration of a

minute or greater

• External Outage: An outage with a

cause that is external to, and outside the control of, the transmission system

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Reliability Benchmarking

• ITC benchmarks performance

against a broad group of peers

• ITC targets top quartile performance

for outages per circuit per year

• 2017 benchmarking group:

100 kV and above

• 85 companies
• 18,408 circuits
• 74% of US and Canadian circuit miles

Below 100 kV

• 41 companies
• 6,398 total circuits

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Performance

Lower is better

ITCT, METC, and ITCM all achieved top quartile performance in 2017

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Performance

Lower is better

The ITCM 69 kV system achieved top quartile performance in 2017

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How Does Benchmarking Drive Performance?

Double circuit design standard review process

• 161kV double circuit design flashover study shows

an expected 2.79 lightning related outages per hundred miles per year using standard insulators

Is this acceptable?

• Benchmarking defines the target performance –

0.524 lightning outages per hundred miles per year

Redesign for target performance

• Upgrading to larger insulators results in a cost

effective improvement in system performance

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Historical Outage Performance

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Outage Response

Fault Study

• The relay group reviews the event and provides details and location

Investigation or line patrol

• Above 100 kV: All outages are investigated and a root cause identified
• Less than 100 kV: All sustained outages, repeated momentary outages,

and poor performing circuit outages are investigated for a root cause Human Performance

• Events with a human performance factor are reviewed through the Event

Free Performance Program

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Operational Excellence

Representatives

• Asset Management
• Engineering
• Operations
• Planning
• Design
• Stakeholder Relations
• Human Performance

Results

• Operational Awareness
• Identify Root Causes
• Identify Outage Trends
• Focused Investment
• Process Improvement
• Outage Reduction

Outage Response And Review

ITC Operations Committee

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Operational Excellence

Operations Committee Analysis

 Review of the previous month’s outages

• Did we adequately investigate the outage cause?
• Do we agree on the root causes?
• Have we had issues on this line/area historically?
• What is the specific design/construction of the circuit?
• Did the equipment operate as designed?

 Apply lessons learned

• Is the underlying problem present elsewhere?
• Develop a corrective action plan

 Follow through

• Review and follow up on outstanding corrective action plans

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Reliability Focused Investment

Maintenance  Poor performing circuits are prioritized for maintenance related activities Capital Investment  Circuit outage data feeds into Planning’s circuit rankings  Capital improvement projects are proposed for all worst-ranking circuits

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ITCM 69 kV Sustained Outage Breakdown

Percentage of total outages by initiating cause 2013-2017 (5 year avg.)

SYSTEM-PROT 2% VEGETATION 3% LIGHTNING 3% UNKNOWN 4% HUMAN 4%EQUIPMENT 5% OTHER 8% LINES 12% EXTERNAL 22% WEATHER 37%

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Historical Comparison – Outage Cause

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Benchmark Comparison by Outage Cause

0.02 0.04 0.06 0.08 0.1 0.12 0.14 0.16

69 kV Sustained Outages per Circuit - 5 Year Avg.

ITCM Q3 Q2 Q1

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ITCM 100 kV+ Sustained Outage Breakdown

Percentage of total outages by initiating cause 2013-2017 (5 year avg.)

VEGETATION 2% SYSTEM-PROT 2% LIGHTNING 4% UNKNOWN 6% OTHER 6% EQUIPMENT 8% HUMAN 10% EXTERNAL 14% LINES 17% WEATHER 31%

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Historical Comparison by Outage Cause

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Benchmark Comparison by Outage Cause

0.01 0.02 0.03 0.04 0.05 0.06 0.07 0.08

100 kV+ Sustained Outages per Circuit - 5 Year Avg.

ITCM Q3 Q2 Q1

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Impact and Risk Management

Determine high impact work  Work that places significant load or generation at risk  Outages that cause significant voltage problems Identify unintended outcomes  Switching risks including tripping or operating breakers  Adjacent equipment  Faults/operations of significant lines Managing risk  System reconfiguration or redispatch  Patrolling important lines, reviewing and addressing known issues  Awareness internally and externally Approval from operational planning and the control room

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Questions?

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ITC MIDWEST 2019 Projected Rate Presentation Zach Paquette – Manager, Rates

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Agenda

• Discuss the 2019 Projected Formula Rate posting
• Walk through the timeline and calculation of the Projected 2019

Revenue Requirement

• Discuss key drivers of the Projected Rates
• Describe the next steps for Stakeholders

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Contents of the 2019 Projected Rate Posting

On August 31, 2018, ITCMW posted the 2019 projected rates package

• n the MISO and OASIS

websites. Documents included in the postings:

• Workable populated Att. O Rate

Template

• Underlying work papers
• Attachments GG and MM with related

True-Ups

• Schedule 1 Expense Projected Rates
• Accounting disclosures

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Formula Rate Protocol Cycle

Protocols Open Review Process Rate Posting Timeline April April Informational* Filing (Mar 15) Prior year True-Up (Jun 1) Projected Rate for Next year (Sep 1) Informational Exchange Period (Jun 1 – Dec 1) Informal Challenge Due (Jan 31) Formal Challenge Due (Apr 15) July January FERC Form 1 (Apr 18) October Projected Rate year (Jan 1 – Dec 31)

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ITC MIDWEST 2019 Attachment O – Projected Formula Rate

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Steps to Derive the Projected 2019 Net Revenue Requirement

2019 Projected Rate Base $ 2,723,218,884 Weighted Average Cost of Capital 8.62%

Step 1

Allowed Return $ 234,871,627 Operating Expenses + Income Taxes $ 235,860,861

Step 2

Gross Revenue Requirement $ 470,732,488 Revenue Credits and Offsets $ 131,669,492

Step 3

Projected 2019 Revenue Requirement $ 339,062,996 2017 True-Up (Over) Recovery $ (860,096)

Step 4

Projected 2019 Net Revenue Requirement $ 338,202,900

Step 5

*Totals may not reconcile due to rounding

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ITC Midwest’s 2019 Network Rate is $9.596/kW-Mo.

*Totals may not reconcile due to rounding

Key Drivers

($ millions) $28M Higher Revenue Offsets

Higher MM (MVPs #4 and #7)

$332M Higher Plant in Service

MVP Projects #4 & #7 projected to go in service in 2019 | 34.5kV to 69kV Conversion Phase 1

$13M Higher Taxes

Higher Rate Base (Income Taxes) | Higher Plant in Service (Property related TOIT)

$4M Higher Depreciation & Amortization Expense

Higher Plant in Service

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Disclosures

• In March 2017, the Financial Accounting Standards Board issued guidance (Accounting Standards

Update No. 2017-07, Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost) on the presentation of net periodic pension cost and net periodic postretirement benefit cost for U.S. GAAP reporting purposes. Among other changes that did not affect the stand-alone FERC accounting and reporting for ITC Midwest, the new guidance allows

• nly the service cost component of net benefit cost to be eligible for capitalization; previously, the
• verall net benefit cost was eligible for capitalization. ITC Midwest adopted the guidance effective

January 1, 2018. Upon adoption and as permitted by FERC Docket No. AI18-1-000, we elected to change our capitalization policy for FERC accounting and reporting purposes to align with the capitalization accounting changes required for U.S. GAAP as a result of this guidance.

• The impacts in 2019 projected rates of this accounting change is estimated to be a $0.1 million

increase in capital assets, a $0.1 million decrease in G&A expense, and $0.1 million overall decrease in 2019 projected net revenue requirement.

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Questions?

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ITC Midwest

Appendix

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ITC Midwest’s Projected Rate Increased by $0.483/kW-Mo.

Description 2019 Projected 2018 Projected Increase/ (Decrease) % Variance Projected Gross Plant in Service $3,628,665,870 $3,296,062,190 $331,603,680 Accumulated Depreciation 472,428,570 471,478,800 949,770 Deferred Income Taxes (476,614,228) (436,430,887) (40,183,341) M&S/Prepayment/CWC 43,595,812 45,532,493 (1,936,681) Rate Base $2,723,218,884 $2,433,684,996 $289,533,888 12% Return on Rate Base $234,871,627 $208,621,262 $26,250,365 13% O&M Expenses $34,517,333 $32,932,996 $1,584,337 A&G Expenses 40,931,609 40,262,946 668,663 Depreciation Expense 63,656,976 60,100,000 3,556,976 Income Taxes 77,216,673 69,304,256 7,912,417 ADIT Deferral & Taxes Other Than Income Taxes 19,538,270 14,789,000 4,749,270 Total Operating Expenses $235,860,861 $217,389,198 $18,471,663 8% Credits/Offsets (Sch. 26, 26A, PTP, rents) $131,669,492 $103,940,768 $27,728,724 True-Up Adjustments (860,096) (1,635,309) 775,213 Projected Net Revenue Requirement* 338,202,900 320,434,383 17,768,517 Projected Network Load (based on 12 CP, kW) 2,937,034 2,930,212 6,822 Projected Rate ($/kW-Mo) $9.596 $9.113 $0.483 5%

*Totals may not reconcile due to rounding

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Overview of Planned Capital Additions

• The development of the annual Rate Base begins with a forecast of planned

capital additions.

• The ITC Midwest Planned Capital Addition slides identify expected line,

substation, and other construction projects as they are currently known.

• The projects identified represent our best estimates for projects to be initiated

and completed.

• Note that many factors such as regulatory approvals, construction resources,

availability of materials, weather and other unforeseen events, could alter projections and schedules.

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Major Planned Transfers to Plant in Service

Project Name Projected Amount for the 13 Months Ended December 31, 2019 MVP #4 - Winco to Hazleton 345 kV line $ 158,459,514 34.5 kV to 69 kV Conversion Phase 1 109,517,005 MVP #7 – Zachary - Ottumwa 345 kV 34,397,654 Cedar Rapids - North Liberty Area 18,082,310 Communication Addition Program 8,778,429

• N. Burlington to N. Burlington Tap

7,666,096 OH-UG NRUC/Reliability 7,126,896 Fairbank-Oelwein 69 kV Rebuild 5,694,233 Saling (Corydon) 69 kV Breaker Substation Rebuild 4,953,006 Kneedler (Mt. Ayr) 69 kV Breaker Substation Rebuild 4,467,672 Substation NRUC/Reliability 2,434,995

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Step 1: Calculation of ITC Midwest’s Rate Base

Rate Base Items 2019 Projected Amount 2018 Projected Amount Increase/(Decrease) % Variance Gross Plant in Service $3,628,665,870 $3,296,062,190 $322,603,680

• Accumulated Depreciation

472,428,570 471,478,800 949,770 Net Plant in Service* $3,156,237,300 $2,824,583,390 $331,653,910 12% + Deferred Income Taxes $(476,614,228) $(436,430,887) $(40,183,341) + Materials & Supplies 30,646,250 33,756,000 (3,109,750) + Land Held for Future Use

• + Prepayments

3,518,444 2,627,000 891,444 + Working Capital 9,431,118 9,149,493 281,625 = Total Rate Base* $2,723,218,884 $2,433,684,996 $289,553,888 12%

*Totals may not reconcile due to rounding

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Cost of Capital Weight Cost 2019 Projected WACC 2018 Projected WACC Increase/(Decrease) Equity 60% 11.32% 6.79% 6.79% Debt 40% 4.58% 1.83% 1.78% Rate of Return* 8.62% 8.57% Allowed Return 2019 Projected Amount 2018 Projected Amount Increase/(Decrease) % Variance Rate Base $2,723,218,884 $2,433,684,996 x Return (above) 8.62% 8.57% = Allowed Return* $234,871,627 $208,621,262 $26,250,365 13%

*Totals may not reconcile due to rounding

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Step 4 & 5: Operating Expenses & Total Gross Revenue Requirement

Operating Expense + Income Taxes 2019 Projected Amount 2018 Projected Amount Increase/(Decrease) % Variance Operation & Maintenance Expenses $34,517,333 $32,932,996 1,584,337 Administrative & General Expenses 40,931,609 40,262,946 668,663 Depreciation Expense 63,656,976 60,100,000 3,556,976 Taxes Other Than Income Taxes 19,538,270 14,789,000 4,749,270 Income Taxes 77,216,673 69,304,256 7,912,417 Total Operating Expenses + Income Taxes* $235,860,861 $217,389,198 $18,471,663 8% Projected Gross Revenue Requirement 2019 Projected Amount 2019 Projected Allowed Return (from previous slide) $234,871,627 + Projected Operating Expenses + Income Taxes (above) 235,860,861 2019 Projected Gross Revenue Requirement before Revenue Credits & Offsets* $470,732,488

*Totals may not reconcile due to rounding

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Gross Revenue Requirement & Revenue Credits & Offsets 2019 Projected Amount 2018 Projected Amount Increase/(Decrease) % Variance Gross Revenue Requirement before Revenue Credits & Offsets $470,732,488 $426,010,460 $44,722,028 Less: Attachment GG Revenue Requirement (Sch. 26) 21,459,998 21,934,993 (474,995) Less: Attachment MM Revenue Requirement (Sch. 26A) 94,216,225 65,676,228 28,539,997 Less: Point-to-Point/Other Transmission Service Revenues 13,936,404 14,145,427 (209,023) Less: Rental Revenues 2,056,865 2,184,120 (127,255) Total Revenue Credits & Offsets* $131,669,492 $103,940,768 $27,728,724 27% Total 2019 Projected Revenue Requirement after Revenue Credits & Offsets* $339,062,996 $322,069,692 $16,993,304 5%

*Totals may not reconcile due to rounding

CLICK TO EDIT MASTER TITLE STYLE Step 7: Net Revenue Requirement after 2017 True-Up

Net Revenue Requirement 2019 Projected Revenue Requirement after Revenue Credits & Offsets

$339,062,996

+ 2017 True-up Adjustment under/(over) Recovery

(860,096)

2019 Projected Net Revenue Requirement (including 2017 True-up Adjustment)

$338,202,900

*Totals may not reconcile due to rounding

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85

Questions?

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86

New Projects Submitted to MTEP 2018 Jeff Eddy – Manager, Planning

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Summary

19 new projects submitted for MTEP19 category “A” approval

• 4 related to 34/69 conversion project (2022-2026)
• 3 age and/or condition projects (2020-2022)
• 1 asset management “blanket” budget (2022)
• 1 small customer interconnection “blanket” budget(2022)
• 9 customer interconnection projects (2019-2022)
• 1 system capacity projects

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Age and/or Condition

New London 69kV Tap Rebuild

• Portion of the Burlington North –

Mediapolis 69kV circuit

• 10.6 miles long tap
• Long spans, no shield wire
• Other portions of this circuit being

rebuilt

• MISO Project 15004

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Age and/or Condition

Huntwoods-Sawyer 69kV Rebuild

• Portion of the Huntwoods – Sawyer

69kV circuit

• Reroute due to difficult terrain
• Rotting poles with no access
• MISO Project 15024

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Age and/or Condition

Dysart-Traer 161kV Rebuild

• 15.6 miles
• Design of line coupled with SD

conductor results in on-going performance/maintenance issues.

• MISO Project #15455

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Customer Connections

Ottumwa Heights

• 161/24 kV distribution substation
• Two transformers
• 161kV ring bus
• MISO Project 15449

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Customer Connections – 34/69 Conversion Related

Clarence South Substation

• MISO Project 15453

Anamosa White Fawn

• MISO Project 15452

Walford Terry

• MISO Project 15454

Solon Big Grove

• MISO Project 15484

Toledo Central

• MISO Project 15466

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Customer Connections

Asbury 161kV Breaker Additions

• Dubuque, Iowa
• Two transformers
• MISO Project 15485

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Customer Connections

South Grandview 161kV Breaker Additions

• Dubuque, Iowa
• Two transformers
• MISO Project 15486

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Customer Connections

Beaver Rock Terminal Addition

• Comanche, Iowa
• Add 69kV terminal to existing sub
• CIPCO to construct new 69kV line
• MISO Project 15450

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2019 – 2021 Planning Projects (non-conversion)

Jeff Eddy – Manager, Planning

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Northeast Iowa

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Eastern Iowa

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Eastern Iowa – Projects Overview

Van Allen 69-12kV Substation

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Southern Iowa

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Southern Iowa – Projects Overview

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Southern Iowa – Projects Overview

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Southeast Iowa

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Northern Iowa / Southern Minnesota

104

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Northern Iowa / Southern Minnesota – Projects Overview

Walters 161kV Substation Expansion And 161kV Circuit

• 7 mile 161kV line
• Install a 100MVA transformer at the

Walters Substations

• MISO Project #13888
• Eliminates several voltage violations

and increases operational flexibility in the Albert Lea area

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Cedar Rapids Area

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Cedar Rapids Area – Projects Overview

Williamsburg Area - Existing Williamsburg Projects

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Cedar Rapids Area – Projects Overview

South Loop

• Joint project with CIPCO
• Additional 69kV infrastructure included
• Eliminates several voltage violations

and provides load serving capability in the fast growing I-380 corridor

CLICK TO EDIT MASTER TITLE STYLE Multi-Value Projects (MVP’s), Market Efficiency Projects (MEP)

4

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Questions?

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111

Generator Interconnection Update

Dan Barr – Supervisor, Planning

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Generation Connected to Date

• ITC Midwest has connected 28

projects representing approximately 3,740 MW of new generation since 2008

• ITCM Peak Load – 3,724 MW
• Wind now accounts for

approximately 45% of the generating capacity connected to ITC Midwest

WIND - 45% NAT GAS - 22% COAL - 19% NUCLEAR - 7% FOSSIL/OIL - 6% OTHER - <1%

2018 Generation Mix

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10 Year View of Generation Changes

• Roughly $7B has been invested in

new generation sources connected to ITC Midwest

• Generator additions and generation

retirements account for a net change

• f roughly 4.7 GW in generation

sources since 2007 2007 Generation Mix

COAL-46% GAS-17% WIND-16% NUCLEAR-12% OIL-10%

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Interconnection Projects Under Construction

114

Project J449 – Mitchell County, IA 345 kV

• 200 MW wind-powered project
• Interconnecting to existing

generator terminal at Mitchell Co

• September 2018 in service date

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Interconnection Projects Under Construction

115 4

Project J041 – Wellsburg, IA 161 kV

• 90 MW - wind-powered project
• Expansion of existing project

H021

• October 2018 in service date

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Interconnection Projects Under Construction

Project J416 – New 345 kV station on Killdeer-Blackhawk 345 kV

• 200 MW – Wind-powered
• New “Quinn” 345 kV switching

station to be constructed near Hampton, IA

• ITCM to build & own a ~8 miles-

long 345 kV gen-tie line for IP&L

• July 2019 in service date requested

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Project J407 – Glenworth, MN 161 kV

• 200 MW wind-powered project
• Add terminal to 161 kV ring

bus

• Replace 100 MVA, 161/69 kV

transformer with 150 MVA unit

• August 2020 in service date

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Pending ITCM Interconnections

118 4

Generator Interconnection Agreements Underway

• J514: 65/30 MW – Combined Cycle Increase at Marshalltown
• Structure replacements on Marshalltown-Blairstown-Prairie Ck 115 kV
• J495: 200 MW – Wind powered interconnection to Ledyard-Colby 345 kV
• New 345 kV switching station
• J523: 50 MW – Solar powered interconnection to Adams 161 kV
• New 161 kV terminal at Adams
• J504: 50 MW – Solar powered interconnection to Arnold 161 kV
• New 161 kV terminal at DAEC

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Pending ITCM Facilities Upgrades

119 4

Facilities Construction Agreements Underway

• J475: 200 MW - Wind powered interconnection to

Montezuma 345 kV

• Rebuild approx. 9.5 mi Poweshiek – Irvine 161 kV line
• J498.J499/J500: 1,080 MW (collectively) wind-powered

interconnections to MEC 345 kV system

• Replace structures on Poweshiek-Reasoner 161 kV

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MISO Queue Status

120

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MISO Queue Update – Studies Underway

August 2016 West Definitive Planning Phase Study

• Phase 1 evaluation completed
• $3.2B in upgrades identified for the 28 projects and approx. 5,650

MW – all wind

• Phase 2 to Kickoff October 15th

February 2017 West DPP Study

• Approx. 27 projects and 3,400 MW of new generation
• Phase 1 study kickoff October 15th
• 3,200 MW – Wind; 220 MW – Solar; ~20 MW – Battery Storage

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Generation Changes - Summary

• Queue churn to continue – too many MW chasing too few PPAs
• Existing capacity of MVPs cannot accommodate queue
• Upgrading the transmission system based on individual queue cycles

is not ideal, long-term system planning

• Generation retirements continue - Arnold retirement expected in

2020

• First glance – Approved MTEP projects should reduce the

likelihood of necessary system upgrades for Arnold retirement

• Morgan Valley-Beverly 345 kV; Fairfax-Liberty-Hills 161 kV

and other upgrades have increased system reliability/flexibility

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123

Questions?

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124

34.5 kV to 69 kV Update

Robert Walter – Supervisor, Planning

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Value of 34.5 to 69 kV Rebuilds

Rebuild outdated 34.5 kV lines to 69 kV standards

• 34.5 kV lines are in poor physical condition and do not provide lightning

protection

• Most 34.5 kV lines have small conductor which limits system voltage and

loading capabilities during planned and unplanned outages

Rebuilt lines use a larger size conductor and provide lightning protection

• Larger conductor provides additional capacity for loading and reduces line

voltage drop

• Rebuilt lines have a shield wire which provides lightning protection

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Value of 34.5 to 69 kV Conversion

Convert radial 34.5 kV lines to networked 69 kV operation

• Converting to 69 kV increases capacity on a line and helps provide ability to serve

future load growth

• Networked 69 kV operation provides a system that is better able to maintain

voltage while providing alternate paths for the power to flow during planned and unplanned outages

Conversion allows retirement of lines not rebuilt as part of 69 kV plans for an area

• Most of the lines were 34.5 kV system ties which are not needed with the

networked 69 kV system topology

• Retiring lines not rebuilt to 69 kV standards reduces area lightning exposure

CLICK TO EDIT MASTER TITLE STYLE Iowa Utilities Board Commitment for Rebuilds and Conversions

ITC Midwest made a commitment to the Iowa Utilities Board for rebuilding and converting the 34.5 kV system

• 14-year time frame for rebuilding the 34.5 kV lines that

will be converted to 69 kV operation in the future

• Line rebuilds to be completed by the end of 2021
• 22-year time frame for converting the system to 69 kV
• peration
• Conversions to be completed by the end of 2029

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34.5 kV Rebuild and Conversion Progress

128 4

481 miles to be rebuilt by the end of 2018

• 74% of rebuilds completed
• 653 total miles of rebuilds required

21 new 69 kV circuits completed by the end of 2018

• Includes ITC and CIPCO conversions
• Out of 149 34.5 kV circuits/65 new networked

69 kV circuits

• For every 2.25 34.5 kV circuits, there will be 1

new networked 69 kV circuit

• 32% of total conversions completed

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Future Planned Rebuilds and Conversions

129 4

Planned Rebuilds

• Approximately 64 miles per year for the

next 3 years to complete rebuilds by end of 2021 obligation

Planned Conversions

• 4 new 69 kV circuits planned for 2019
• 3 new 69 kV circuits planned for 2020
• 37 new 69 kV circuits to be completed

between 2021 and 2029

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34.5 kV System Reliability

• ITC Planning and Asset Management have regular discussions to

determine level of maintenance required on assets planned for rebuild or retirement

• ITC considers stakeholder impacts when scheduling rebuild and

conversion projects

• Impacts are typically operational or financial
• Overall 34.5 kV breaker operations continue to trend downward
• Breaker operations include both momentary and sustained
• utages

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34.5 kV System Reliability

131 4

700 800 900 1000 1100 1200 1300 1400 1500 1600 1700 1800 1900 2000 2100 2200

34.5 kV Total 3-Year Rolling Operations (All Circuits Combined)

34.5 kV Total 3-Year Rolling Operations (All Circuits Combined)

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34.5 kV Study Areas

132 4

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34.5 to 69 kV Study and Coordination Process

• All study work has been completed and plans continue to be refined

based on stakeholder feedback and stakeholder plans for each study area

• ITC Midwest has submitted all planned rebuilds and conversions to the

MISO MTEP study process

• Additional submissions to MTEP based on plan updates may still be

required

• Project schedule coordination is an ongoing process and project

schedules continue to be updated to support stakeholder needs

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Vinton – Hazleton Area

134

All rebuilds and conversions in study area have been completed

• 75 miles rebuilt
• 3 new 69 kV circuits created

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Cedar Rapids Area

135 4

• 17.5 miles rebuilt, 11.5 miles remaining
• 60% rebuilds completed
• 4 new 69 kV circuits completed, 3 remaining
• 57% conversions completed

Future projects:

• 9th Ave – Oak Hill Rebuild (new line segment)
• PCI – Oak Hill Conversion
• Oak Hill – Marion Rebuild
• Emerald Isle – Beverly Conversion

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Eastern Iowa Area

136 4

• 110 miles rebuilt, 41 miles remaining
• 73% rebuilds completed
• 7 new 69 kV circuits completed, 9 remaining
• 44% conversions completed

Future projects:

• Wyoming – Rome REC – Stanwood Rebuild
• Radio – Anamosa – Amber Conversion
• Dixon – Fulton Rebuild
• Jones County – Maquoketa Conversion

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Toledo – Belle Plaine – Williamsburg Area

137 4

• 65 miles rebuilt, 56 miles remaining
• 54% rebuilds completed
• 1 new 69 kV circuit completed, 14 remaining
• 6% conversions completed

Future projects:

• Toledo Diesel – Tama East Rebuild
• Kalona South – Iowa Junction Rebuild
• Fletcher – LeGrand Rebuild
• Traer – Dysart Rebuild

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Grand Junction – Ames – Marshalltown Area

138 4

• 124 miles rebuilt, 9 miles remaining
• 93% rebuilds completed
• 5 new 69 kV circuits completed, 10 remaining
• 33% conversions completed

Future projects:

• Boone Quartz – Valley REC tap – Ogden Muni

rebuild

• Doud – Ridgeport new line
• Fletcher – Marshalltown North – East Nevada

Conversion

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Anita - Grand Junction

139 4

• 39 miles rebuilt, 77 miles remaining
• 34% rebuilds completed
• 1 new 69 kV circuit completed, 8 remaining
• 11% conversions completed

Future projects:

• Guthrie – White Pole Rd – Redfield – Panora

Conversion

• Perry – Bagley Rebuild
• Guthrie – Railway Conversion
• Bagley – Scranton Rebuild

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Northwest Iowa Area

140 4

• ITC’s plans in the Northwest Iowa

area are highly dependent on IPL and Corn Belt’s plans

• Current plans provided to ITC from

IPL indicate IPL will be moving their load onto Corn Belt’s existing 69 kV system in the area

• ITC will need to retire 138 miles of

ITC 34.5 kV lines in Northwest Iowa Area

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Fairfield Area

141 4

• ITC’s plans in the Fairfield area are

dependent on IPL’s plans

• Current plans provided to ITC from IPL

indicate IPL will be purchasing the existing 34.5 kV line to be used as a distribution line to serve the area load

• ITC works with local distribution

companies to reuse facilities such as existing poles and/or entire line sections to help control costs for customers

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142

Questions?

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ITC Midwest Project Management Updates

Marlon Vogt – Project Manager Aaron Curtis – Project Manager

Project Processes & Challenges

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Standard Project Schedule Templates

144

• Substations and transmission
• Consistent and comprehensive
• Developed with stakeholder

buy-in

• Regulatory
• Real Estate/Rights-of-way
• Permitting
• Design
• Construction

Schedule Discipline

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Line Routing

145

• Iowa Utilities Board Requirements
• Near or parallel to roads, railroads, or along

division lines of land

• Minimize land use interference
• Residences and environmentally sensitive areas
• Avoidance areas
• Existing lines/easements/

franchises

Multiple Options and Factors

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Regulatory and Rights-of-Way

146 146

• Easement acquisition
• Public Information Meetings
• Objections and condemnation

Risks to Losing Schedule Control

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Underbuild Coordination

147

• Several underbuild owners
• Separate easements
• Full easements vs. overhang vs.

public ROW

• Schedule and design coordination

An Important Potential Constraint

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Vegetation

148

50% Outage Reduction

• Root cause of most outages
• FERC/NERC Regulatory Rules
• Integrated approach
• Danger trees

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Terrain

149

• Access
• Construction
• Future operation

and maintenance

• Flood plains

When the Going Gets Tough….the Tough Get Going

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Weather

150

Limited Control…

• Crew response time
• Emergency preparation

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Unexpected Field Conditions

151

Control What We Can Control

• Artesian sand layer

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Questions?

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Thank You!

We thank you for participating in today’s Partners in Business Meeting. For a copy of today’s presentations, you may visit our website at www.itctransco.com. Click on ITC Midwest, then click on Learn More About Partners in Business. You can also access them on MISO’s OASIS website at http://www.oatioasis.com/woa/docs/ITCM/. We appreciate your continued feedback so that we may deliver value in our communications with you. Mike Dabney Keith Eyler mdabney@itctransco.com keyler@itctransco.com www.itctransco.com