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Partners In Business Spring 2009Partners In Business Spring 2009
May 19, 2009Hawk Hollow Golf Club
Bath, Michigan
Welcome!Welcome!
Jeff Dorr
Manager – Stakeholder Relations
3
AgendaAgenda
Introduction Jeff Dorr, Manager Stakeholder Relations
Smart Grid Jon Jipping, Chief Operating Officer
Summer Readiness Elizabeth Howell, VP Operations
Break
PHEV Gery Kissel, General Motors
Asset Management Steven Stout, Director Asset Management
Lunch
Legislative Update Nina Plaushin, Director, Federal &Legislative Affairs
Regulatory Update Tanya Paslawski, Director, Regulatory Strategy
Golf
4
Suddenly, knowing a lot about the U.S. power grid became sexy at cocktail parties.Suddenly, knowing a lot about the U.S. power grid became sexy at cocktail parties.
5
Project timing and overviewsProject timing and overviews
While the following slides identify general timetables for line and substation construction projects, several factors could impact the company’s ability to complete projects according to those timetables.
Those factors include, but are not limited to, regulatory approvals, access to construction resources, availability of materials, and even weather.
The dates and schedules identified in these slides represent our best estimates for projects to be initiated and completed, but please understand that many factors could alter those schedules.
Jon Jipping
Chief Operating Officer
ITC
Smart Grid at ITCSmart Grid at ITC
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The Smart Grid DefinedThe Smart Grid Defined
IEEE: “The term ‘Smart Grid’represents a vision for a digital upgrade of distribution and transmission grids both to optimize current operations and to open up new markets for alternative energy production.”
Wikipedia: “A Smart Grid delivers electricity from suppliers to consumers using digital technology to save energy, reduce cost, and increase reliability.”
FERC: “Grid advancements will apply digital technologies to the grid and enable real-time coordination of information…”
DOE: “A smarter grid applies technologies, tools, and techniques available now to bring knowledge to power – knowledge capable of making the grid work far more efficiently…”
GE: “The Smart Grid is in essence the marriage of information technology and process-automation technology with our existing electrical networks.”
Common themes:EfficiencyDemand responseConsumer savingsReduced emissions
TechnologyTwo-way communicationAdvanced sensorsDistributed computing
ReliabilityInterconnectivityRenewable integrationDistributed generation
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The Smart Grid Defined (Cont’d)The Smart Grid Defined (Cont’d)
The convergence between electrical and new “intelligence”infrastructure
Two-way flow of information strengthens reliability and resource management
Data, control, and automation providing increased efficiencies, responsiveness, flexibility and resiliency
Time-based decisions and transactions between energy suppliers, buyers and markets
Convergence
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The Smart Grid PromiseThe Smart Grid Promise
*Source: Department of Energy: “The Smart Grid – An Intro”
Vision of a Future with a Smart Grid
Descriptions of the Smart Grid paint a grand picture of the future*
EfficientEfficient
AccommodatingAccommodating
MotivatingMotivating
OpportunisticOpportunistic
QualityQuality--focusedfocused
ResilientResilient
““GreenGreen””
IntelligentIntelligent
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The Smart Grid Promise (Cont’d)The Smart Grid Promise (Cont’d)
Technology— Early stages of development or are not yet commercialized
Policy— FERC has issued a preliminary policy— States’ utility commissions will make the decisions about what is
appropriate at the retail level
Interconnectivity and standardization— Various devices and protocols are currently being developed
Rate recovery— FERC, state regulators, or both will determine the degree to which
investments in Smart Grid technologies are recoverable
Technology is not a panacea for an aging infrastructure— The real grid makes up the traditional infrastructure— Smart Grid is the application of advanced technologies that enhance the
operation of the real grid
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ITC Smart Grid StrategyITC Smart Grid Strategy
The ITC strategy is to continue to actively invest in new technology that:
Adds value for our investors and customers – ensure the business case makes sense—benefits outweigh costs and assets are used and useful
Improves reliability of our service – upgrade transmission assets with more effective monitoring and control technology
Retains flexibility for the future – retain maximum degrees of freedom—technologies employed are flexible enough to accommodate innovation over time
Enables a smarter future – deploy Smart Grid alternatives in transmission to serve as an enabler for generation and distribution Smart Grid applications
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Three fundamental areas that ITC views as aligned with Smart Grid for transmission:
1. Communications Network: a robust communication network is fundamental System uses a secure broadband logical network Outsourcing leverages the network and expertise of AT&T
2. Real-time Monitoring and Control: Intelligent devices enable enhanced real-time observation and rapid analysis and response to system disturbances Substation security enhancements Transmission asset health monitoring
3. Event Analysis: Enhanced monitoring and data analytics provide robust analysis of system events Advanced system fault monitoring GPS time-stamped data
Fundamental Areas for ImplementationFundamental Areas for Implementation
13
ITC Smart Grid TodayITC Smart Grid Today
ITC operates its widely distributed assets via a digital, private, broadband communication network
RTU
TMS
Engineering
OperationsControlRoom
SUBSTATION (typ.)NOVI HEADQUARTERS
AT&T Frame Relay Network /
AVPN
Eng’gServerFaultEvent
Recorder
Transformer
Asset Health Monitoring
System(i.e. T-Medic) Breaker
LocalNetwork
SCADAData
Signals
Eng’gDataSignals
ControlSignal
GPS TimeSynch Data
ControlSignal
Eng’gDataSignal
IntelligentRelayDevice
Relay Trip Signal
14
Communications NetworkCommunications Network
Communication Upgrades— Communications were previously provided over a variety of technologies
including dedicated analog phone lines Low speed, non-networked point-to-point lines with limited bandwidth Very expensive, some circuits costing thousands of dollars per month
— ITC adopted an IP based network running on frame relay technology Network and Communication Features
— AT&T is one of the world’s largest providers of IP-based communications services, with an extensive portfolio including Virtual Private Network (VPN) and Voice over IP (VoIP)
— AT&T frame relay network is based on proven technology and meets all ITC requirements for speed, bandwidth, reliability and security
— Open-industry protocols and standards provide the fundamental building blocks for interoperability
Cybersecurity— Network bandwidth and reliability enable cyber and physical security features
at substations that were not possible previously
15
Network Features and CybersecurityNetwork Features and Cybersecurity•
Network provides redundancy with no single point of failure
Uses off-the-shelf hardware that can be scaled or upgraded as technological advances are made
OCRTMS
RouterMARS
Novi SONET Ring
AT&T
FRAME RELAY NETWORK / AVPN
Substation(typical)
Router
RTU
OCRTMS
RouterMARS
Substation(typical)
RTU
Ann Arbor SONET Ring
Conceptualization of layers of security on
ITC data traffic
Cybersecurity is achieved at the ends (data are prioritized and encrypted prior to entering the AT&T network)
State-of-the-art Cisco technology is employed to centrally monitor substations, providing detection and mitigation of cyber-threats
16
Real-Time Monitoring and ControlReal-Time Monitoring and Control
Real-Time Monitoring and Control— A system based on information technology to monitor and control
equipment in the field from a central location Grid Intelligence
— Data provided in real time to the Control Room, enabling operators to see what is happening on the grid
— Applications provide graphical representations of system conditions— Analysis programs constantly search for potential overloads and
voltage issues Critical Equipment Monitoring
— Intelligent electronic devices (IEDs) are capable of self-diagnosis— Data on the status (i.e., temperature, oil analysis, etc.) of key pieces
of equipment are provided in real time— Analysis programs process the data points to identify where trending
changes and anomalies in the data may indicate problems
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Grid IntelligenceGrid IntelligenceField intelligence enhances system operations ITC’s remote terminal units (RTUs) and
intelligent electronic devices (IEDs) provide SCADA data to the Transmission Management System (TMS)
Dynamic displays provide regional visualization Displays have been configured to provide TSCs
with information related to system integrity with regard to established operating limits
Advanced tools help mitigate instability and secure system integrity State Estimator
— Approximates system status— Runs once per minute – leading in the
industry Contingency Analysis
— Tests system integrity by simulating failure of individual grid components
— Provides results of contingencies and their impact, in order of severity for both voltage and thermal limits
These analytical tools alert TSCs to system instabilities that might otherwise go unobserved
18
Critical Equipment MonitoringCritical Equipment Monitoring
Relays and other IEDs are utilized in the field— Allow intelligence to be
distributed beyond the Control Room
— Able to self diagnose their condition and report, virtually eliminating the need for field calibration and inspection
Transformer Monitoring (T-Medic) provides protection for transformers by analyzing system conditions and sending alerts to ITC— Dissolved gas in oil analysis— Full range of temperature
monitoring— Monitoring of fans and pumps
Intelligent electronic devices make it possible to take preventive measures based on changes in key indicators
19
Event Analysis – Introduction Event Analysis – Introduction
Digital support for event analysis— In the past, engineers needed to dial in to relays and fault
recorders to attempt to piece together what happened Dial up access was not always reliable Modems were not secure The lack of time stamp made sequencing events difficult
— Devices in the substations now have IP addresses and are accessible via the secure frame relay system
— Microprocessor relays with digital fault recording capabilities— ITC deployed GPS clocks in its substations
Analytics capability— In order to realize the full benefits of ITC’s Smart Grid
investments, the organization’s analytics capabilities needed to evolve
20
Digital Support for Event AnalysisDigital Support for Event AnalysisGPS data received simultaneously by substations, allowing accurate time stamping and synchronization of data
RTU
TMS
Engineering
OperationsControlRoom
SUBSTATION (typ.)NOVI HEADQUARTERS
AT&T Frame Relay Network /
AVPN
Eng’gServer
FaultEvent
Recorder
Transformer
Asset Health Monitoring
System(i.e. T-Medic) Breaker
LocalNetwork
SCADAData
Signals
Eng’gDataSignals
ControlSignal
GPS TimeSynch Data
ControlSignal
Eng’gDataSignal
IntelligentRelayDevice
Relay Trip Signal
21
Analytics CapabilityAnalytics Capability
The use of Smart Grid technologies requires skill sets not traditionally found in electric utilities— An understanding of telecom networks— The ability to use advanced data analysis tools
These capabilities enable ITC to— Accurately and reliably collect data— Make decisions quickly and with confidence— Send the right people with the right tools to the right location
Smart Grid technologies have implications for the work force— Understand the complex analysis tools and networks that have
evolved— Opportunity to attract and retain new engineering graduates
interested in the advanced applications— Focus on cyber security, common protocols and interconnectivity
across systems
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In SummaryIn Summary
ITC (and the transmission system) have been early adopters of what now are components of Smart Grid
ITC’s Smart Grid investments have focused on improving reliability
ITC’s strategy leveraged both the capability of the communications network and a strategic view of the types of datarequired to improve operation and analysis of the system
ITC will continue to upgrade the transmission system with appropriate Smart Grid technologies as their value to the operation of the grid is proven
There is a place for Smart Grid concepts, but it will not replace Real Grid
Questions?Questions?
Summer ReadinessSummer Readiness
Elizabeth HowellVice President – Operations
ITC
25
History of Cooling Degree DaysHistory of Cooling Degree Days
0
200
400
600
800
1,000
1,200
1969 1972 1975 1978 1981 1984 1987 1990 1993 1996 1999 2002 2005 2008
Year
CDD
Normal 736
21
14
27
37
18
33
2326
11
20
39
34
29
38
15
25
36
19
64
32
24
1
40
1612
5
22
35
7
9
28
13
3
30 31
2
17
8
10
Year's rank is above the barMedian
20th
26
Effect of TemperatureEffect of Temperature
0%
20%
40%
60%
80%
100%
0 20 40 60 80 100
Average Hourly Temperature (Deg F)
Peak
Dem
and
(MW
)
A Winter MonthA Summer MonthA Shoulder Month
27
Average Hourly Temps On Monthly PeaksAverage Hourly Temps On Monthly Peaks
9
25
39
707372
75
60
27
74
-3
34
60
76
80
878584
7974
3335 35
-10
0
10
20
30
40
50
60
70
80
90
100
Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Month
Ave
rage
Hou
rly
Tem
pera
ture
(Deg
F)
28
2009 Weather Forecast2009 Weather Forecast
50
60
70
80
90
100
2002
2003
2004
2005
2006
2007
2008
2009
?
Deg
rees
Anticipating a near or slightly warmer than “normal” summer —Slightly warmer than last year—Below normal precipitation/humidity—Hottest in mid-July
Average Mean Temp on Peak DayAverage Mean Temp on Peak Day
29
2009 Load Forecast2009 Load Forecast
9,50010,00010,50011,00011,50012,00012,50013,000
Jun Jul Aug
MW
2004 2005 2006 2007 2008
7,000
7,500
8,000
8,500
9,000
9,500
10,000
Jun Jul Aug
MW
ITCT Peak LoadITCT Peak Load METC Peak LoadMETC Peak Load
2008 summer peak loads were lower than the prior years
Based on weather and economic forecasts, expecting— lower loads this summer for ITCT— similar to slightly lower loads for METC
30
Summer Assessment SummarySummer Assessment Summary
ITCTransmission and METC Transmission Systems—During normal and single contingency operations, no
transmission element is anticipated to be loaded above its normal or emergency ratings respectively.
—During normal and single contingency operations, no transmission buses are anticipated to be below their normal or contingent minimum voltage limit.
Not anticipating any problems meeting the needs of load serving entities in Michigan for summer purchases that must be transported into and/or across the ITCT and METC systems to meet summer 2009 demand.
31
Projects - ITCTransmissionProjects - ITCTransmission
Axle Substation – 120kV Bus and Breaker Additions
Leppek – New 120kV Substation
Hood – New 120kV SubstationMarysville - Substation
Decommission
Hood
Leppek
AxleMarysville
32
Projects - METCProjects - METC
Murphy – New 345kV Substation
Orr Road – New 138kV Substation
Tallmadge – Addition of 3rd
345/138 kV Transformer
Keystone-Clearwater 138kV Line Rebuild
Bard Road, Croton and Orr Road – 138kV Capacitors
METC-CE Interconnection – Ten New 138kV / Distribution Substation Connections
33
METC Project MapMETC Project Map
Murphy & Orr Rd
Tallmadge
Bard Rd
Croton
34
Michigan - Ontario InterconnectionMichigan - Ontario Interconnection
The B3N transformer is being replaced by two (in series) phase angle regulating transformers.
First transformer is on-site, second is scheduled to arrive this summer. In-service date expected in late fall.
Once operational, the interconnection flow can be optimally controlled to equal schedule.
With PARs on 3 of 4 interconnections, it will not be possible to achieve the goal of flow equal to schedule, particularly when external transactions cause heavy flow conditions.
35
Operational ChallengesOperational Challenges
Michigan Northern Loop—Various 345kV critical contingencies will have heightened
awareness—Should one of these contingencies occur, MISO will dispatch the
Northern area peakers. METC can turn on capacitors in the area.—Should METC system loads get very high, MISO may need to
dispatch the Michigan Northern area peakers pre-contingency.
Thumb Area— Various 345kV and 120kV critical contingencies will have
heightened awareness—Should one of these contingencies occur, MISO will dispatch the
Thumb area peakers. ITCTransmission can turn on capacitors in the area.
36
Operational ChallengesOperational Challenges
37
Operational ChallengesOperational Challenges
Storm Season— Responding to equipment damage or operations resulting from
severe weather
38
Summer PreparationsSummer Preparations
Summer readiness equipment inspections
— Stations, transformers, capacitors
— Aerial inspection of lines
39
Summer PreparationsSummer Preparations
Vegetation management
— Implementing standards in the field
— Resolving ‘hot spots’ before summer load period
40
Summer PreparationsSummer Preparations
Conservative maintenance policy—ITC restricts maintenance and construction work on
power plant mats and on critical transmission assets during high load.
—On critical days, all non-emergency work will be stopped.
Emergency procedures—Updating Michigan Reliability Group procedures to
correspond to MISO’s annual revision.—MISO now the Balancing Authority, MECS still the
Local BA—Drills will take place in early June
41
Summer PreparationsSummer Preparations
Operation Engineering summer assessment presentation to all ITC system operators will be completed in May.
Neighboring utility meeting, hosted by First Energy, is scheduled for May.
Participated in the RFC 2009 Summer Assessment and Eastern Interconnection Reliability Assessment Group (ERAG) 2009 Summer Assessment. Both reports should be available at the end of May.
Questions?Questions?
43
BreakBreak
RPS and Energy Optimization Consultant Uncle Fester Adams
44
ITC Partners in BusinessBath, MI --- 19 May 2009
“Plugging In: GM’s Chevy Volt… and Utility Industry Collaboration”
Gery KisselHybrid Energy Storage Systems
Steven Stout
Director Asset Management
ITC
Asset ManagementAsset Management
74
Asset Management at ITCAsset Management at ITC
The Maintenance Program — Preventative maintenance— Reactive Maintenance
Technology and Tools— Maintenance Management Systems— Advanced Reliability Technologies
75
The Maintenance ProgramThe Maintenance Program
ITC’s preventative maintenance program is a blended system of time-based and reliability-centered maintenance (RCM)
Time Based Maintenance – Traditional maintenance based on time intervals (i.e. changing your oil in your car every 3000 miles)
Reliability Centered Maintenance (RCM) – A maintenance strategy to address dominant causes of equipment failure emphasizing the use of Predictive Maintenance (PdM) techniques. (i.e. getting your car dashboard to tell you what you need to repair)
— Application of advanced real-time diagnostic monitoring on key equipment (transformers, breakers, relays, gas insulated switchgear systems, underground lines, etc.)
— Analysis of collected maintenance data (transformer oil dissolved gases, bushing power factor, etc.)
76
The Maintenance ProgramThe Maintenance Program
Ensures maintenance is completed on a timely basis in order to detect problems before they affect system reliability
History and experience are used to “fine tune” the maintenance and testing performed— Annual/Semi-annual programs— Substation Maintenance— Line Maintenance
The Maintenance Plan must be
completed 100%
77
Preventative MaintenancePreventative Maintenance
The “foundation” of the Maintenance plan
Composed of inspections and scheduled maintenance to detect problems before system performance is affected
Substation, Line and other diagnostic inspections are the first line of defense— Substation inspection frequencies range based on the type of
station – larger 345kV stations are inspected more frequently than smaller 120kV stations
— Lines are flown twice a year with Field Supervisors and vegetation personnel to detect any imminent threats
— Infrared inspections occur annually for all stations and include a scan of all ITC equipment
78
ITCTransmission Preventative Maintenance - Key Maintenance Tasks in The PlanITCTransmission Preventative Maintenance - Key Maintenance Tasks in The Plan
PM Activity # of Assets Frequency (Years)
Breaker Inspections (120KV) (Oil) 304 10
Breaker Inspections (120KV) (Gas) 296 8
Breaker Inspections (345/230 kV) 163 8
Bus Inspections 496 10
Relay Periodic Inspections 2172 10
Relay Calibration 2170 5
Battery System Inspections 97 1
Transformer Dissolved Gas Analysis 59 0.5
Tower Inspections 10023 10
Tower Painting 10023 15
Infrared Inspections – Substation 163 1
Veg. Management –Clearing/Mowing Annual Plan 1
Veg. Management – Herbicide Annual Plan 1
Substation Live Line Washing 156 Variable
Manhole Inspections Pipe Type Cable 326 5
Manhole Inspections XLPE Cable 56 2
79
METC Preventative Maintenance - Key Maintenance Tasks in The PlanMETC Preventative Maintenance - Key Maintenance Tasks in The Plan
PM Activity # of Assets Frequency (Years)
Breaker Inspections (138KV) (Oil) 239 10
Breaker Inspections (138KV) (Gas) 174 8
Breaker Inspections (345 kV) 146 8
Bus Inspections 242 10
Relay Periodic Inspections 1701 10
Relay Calibration 1701 5
Battery System Inspections 70 1
Transformer Dissolved Gas Analysis 32 0.5
Tower Inspections 15000 10
Tower Painting 15000 15
Infrared Inspections – Substation 97 1
Veg. Management –Clearing/Mowing Annual Plan 1
Veg. Management – Herbicide Annual Plan 1
80
A Plan is Just A PlanA Plan is Just A Plan
Transformer failure
Tower collapse - due to compromised structure (missing or fractured bolts and/or members)
81
Our Focus is on ExecutionOur Focus is on Execution
Execute the preventative maintenance program 100%
82
Maintenance Management ToolsMaintenance Management Tools
ABB Advise Asset Sentry
— Centralized repository for all major station assets— Remotely managed database platform and is easy for ITC to
manage— Access requires only a web browser and simple for the field to
manage and use— Used for maintenance activities including PM routes, field O&M
exception generation and tracking, field test records, device configuration settings and as an OCR tool for reacting to systemdisturbance events (i.e. line faults)
— Exceptions and routes generate Work Orders in WMS system
83
Maintenance Routes (Time based)Maintenance Routes (Time based)
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Field Trouble ExceptionField Trouble Exception
85
Line Fault ExceptionLine Fault Exception
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Focus on System ReliabilityFocus on System Reliability
ITC records and investigates all unplanned line and substation outages on the transmission system
When an unplanned event occurs on the transmission system, certain procedures are followed to record the outage, investigate the cause of the outage and take corrective actions to prevent the outage from happening again
The data collected is used to meet reporting obligations to the North American Electric Reliability Corporation and Reliability First Corporation. In addition, the data is also submitted to SGS Statistical Services, who conducts a benchmarking study to gauge ITC’s performance relative to its peers
87
Maintenance Replacement ProgramMaintenance Replacement Program
Analysis of maintenance inspections and outages and helps drive new initiatives and programs to better prevent future problems
Identify high maintenance equipment and/or high reliability impact exposure
Identifying end-of-life equipment for replacement— Breakers— Surge arrester — Insulator & bushing — Potential device — GIS station equipment
88
Maintenance ReplacementsMaintenance Replacements
89
NERC ComplianceNERC Compliance
NERC (North America Electric Reliability Corporation) is a self-regulatory organization, subject to oversight by the U.S. Federal Energy Regulatory Commission and governmental authorities in Canada
As of June 18, 2007, the U.S. Federal Energy Regulatory Commission (FERC) granted NERC the legal authority to enforce reliability standards with all U.S. users, owners, and operators of the bulk power system, and made compliance with those standards mandatory and enforceable
Fines for lack of compliance can be substantial (up to $1 Million per day per incident until the violation is corrected)
90
Some Key NERC Standards impacting ITC’s maintenance programSome Key NERC Standards impacting ITC’s maintenance program
PRC-004-1 Analysis and Mitigation of Transmission and Generation Protection System Misoperations - Ensure all transmission and generation Protection System Misoperations affecting the reliability of the Bulk Electric System (BES) are analyzed and mitigated.
PRC-005-1 Transmission and Generation Protection System Maintenance and Testing - To ensure all transmission and generation Protection Systems affecting the reliability of the Bulk Electric System (BES) are maintained and tested.
PRC-008-0 Implementation and Documentation of Underfrequency Load Shedding Equipment Maintenance Program - Provide last resort system preservation measures by implementing an Under Frequency Load Shedding (UFLS) program.
PRC-011-0 Undervoltage Load Shedding System Maintenance and Testing - Provide system preservation measures in an attempt to prevent system voltage collapse or voltage instability by implementing an Undervoltage Load Shedding (UVLS) program.
PRC-015-0 Special Protection System Data and Documentation - To ensure that all Special Protection Systems (SPS) are properly designed, meet performance requirements, and are coordinated with other protection systems. To ensure that maintenance and testing programs are developed and misoperations are analyzed and corrected.
PRC-016-0 Special Protection System Misoperations - To ensure that all Special Protection Systems (SPS) are properly designed, meet performance requirements, and are coordinated with other protection systems. To ensure that maintenance and testing programs aredeveloped and misoperations are analyzed and corrected.
PRC-017-0 Special Protection System Maintenance and Testing - To ensure that all Special Protection Systems (SPS) are properly designed, meet performance requirements, and are coordinated with other protection systems. To ensure that maintenance and testing programs are developed and misoperations are analyzed and corrected.
PRC-018-1 Disturbance Monitoring Equipment Installation and Data Reporting - Ensure that Disturbance Monitoring Equipment (DME) is installed and that Disturbance data is reported in accordance with regional requirements to facilitate analyses of events.
FAC-003-1 Transmission Vegetation Management Program - To improve the reliability of the electric transmission systems by preventing outages from vegetation located on transmission rights-of-way (ROW) and minimizing outages from vegetation located adjacent to ROW, maintaining clearances between transmission lines and vegetation on and along transmission ROW, and reporting vegetation relatedoutages of the transmission systems to the respective Regional Reliability Organizations (RRO) and the North American Electric Reliability Council (NERC).
91
NERC NERC
ITC is an advocate of enforced national reliability standards
NERC standards are an integral part of our maintenance plan
PRC-005 (Protective Relay Maintenance) and FAC-003 (Vegetation Management) have the largest impact on the maintenance program
FAC-003 mandates vegetation management of our approximately 8300 circuit miles
PRC-005 mandates test programs for protective relay maintenance. ITC has a 5/10 year program for over 3500 transmission relay schemes which includes over 13,000 individual transmission relays
92
Maintenance Technology AdvancesMaintenance Technology Advances
ITC has implemented systems to improve the remote transparency of the health of our electrical system assets
Spot failure trends
Perform remote engineering data analysis
93
Better Asset Management Better Asset Management
Apply new proven technologies to make a smarter electrical grid.
Improve response time to component or system failure before further problems develop
Get the right people to the problem first
Use advanced field test equipment utilizing electronic data capture and analysis
94
106 miles of HPGF (High Pressure Gas Filled) underground cable systems is installed in and around Detroit
They are pressurized with nitrogen and are reliable systems (approaching 100 years of service)
ITC Transmission upgraded to remote nitrogen pressure monitoring in 2006 which replaced old paper chart recorders
Remote monitoring allows the actual pressure levels to be read real-time as opposed to on-site maintenance inspections
Additionally, data is archived in an electronic warehouse for analysis of history with accurate time stamped data
Asset Monitoring Improvements Example 1Asset Monitoring Improvements Example 1
95
Asset Monitoring Improvements Example 1- cont.Asset Monitoring Improvements Example 1- cont.
ITC had a Dig-in of Evergreen-Northwest 120-kV Cable in 2007
Noticed pressure drop online and reviewed pressure history which revealed sudden, but steady pressure loss
Excavation of pipe at fresh concrete revealed attempt to install a water saddle valve
EVRGN 1N.HC NWEST CABLE GAS PRESS.AV
PSIGNWEST .EVRGN I .AV
AMPSWAREN 1T.XFMR201 AMBIENT TEMP .AV
degC
EVERGREEN-NORTHWEST 9/10/2007 12:00:00 AM
8/21/07 8/23/07 8/25/07 8/27/07 8/29/07 8/31/07 9/2/07 9/4/07 9/6/07 9/8/07
205
210
215
220
225
200
230
0
800
-30
40
19.983
295.27
214.92
96
Asset Monitoring ImprovementsExample 2Asset Monitoring ImprovementsExample 2
Online Transformer Monitoring Systems to analyze the “health”of the transformer
97
Asset Monitoring ImprovementsExample 2 – cont.Asset Monitoring ImprovementsExample 2 – cont.
ITC has already avoided one potentially catastrophic failure utilizing this transformer monitoring system
Replacement transformer can be $4-5 M replacement cost. This system pays for itself quickly with a small number of avoided failures
Lead time for our size of transformers is 1-1/2 to 2 years
98
Best Maintenance PracticesBest Maintenance Practices
ITC is active in the industry to refine practices and to lead others in their development by participating in a number of organizations
Doble Client – Organization devoted to optimizing system asset performance
ITOPS – International transmission benchmarking
SGS Transmission Reliability Benchmarking - Annual reliability studies
Edison Electric Institute – Transmission Working Groups
NERC Standards Development Teams – Relay Maintenance and System Disturbance Monitoring
99
Present and Future ChallengesPresent and Future Challenges
Continuous improvement of maintenance programs to address continually aging equipment
Getting the backlog of older problematic equipment replaced quickly. i.e. we can’t get it all done at once due to shutdown limitations, budget, manpower, etc.
Increasingly stringent mandatory maintenance standards by NERC and maintaining fully auditable documentation.
Cyber and physical security access control requirements
100
SummarySummary
“Get the maintenance program completed 100%”
Questions?Questions?
LunchLunch
Nina Plaushin
Director, Federal and Legislative Affairs
ITC
Federal and State Legislative UpdateFederal and State Legislative Update
104
Status of Transmission LegislationStatus of Transmission Legislation
Transmission “just a part of the picture”Democratic leaders (especially in House) want to address transmission upgrades, nationwide renewable energy standards (RES), and climate change together in one large bill. While others (including Sen. Bingaman) want to deal with transmission alone, the “omnibus energy bill” approach appears likely to win out.
Several bills - which one will win out?Currently, three major bills (sponsored by Congressional leaders) control the debate. Two (the lead House bill, and Sen. Reid’s bill in the Senate) couple transmission with RES and climate change, but moderate Democrats’ opposition may prevent those measures from succeeding. Only time will tell which proposal wins the day, if any.
What’s the timeline?Democratic leadership and the White House have said they want to pass major energy legislation (including transmission) by the end of 2009. Committee activity is expected to be completed by the end of May. Most of the bills would not require any interconnection-wide plans to be developed for a year after enactment.
105
Key Issues for ITCKey Issues for ITC
Planning for National Transmission ProjectsITC supports using existing planning processes and structures to assist in development of an interconnection-wide planning process. In order to plan for remote resources that are distant from load, the existing planning footprints are inadequate. The process must be open, transparent, and mandatory. All transmission owners must participate in the process.
Siting AuthorityITC believes that the states are best situated to determine where transmission facilities should be located. However, for large, multi-state projects, designed to meet national energy and environmental goals, the determination of whether such projects are needed should be a federal decision.
Cost AllocationThe cost associated with extra high-voltage projects with broad regional benefits should be spread as broadly as possible, preferably interconnection-wide. Feeder lines that bring renewable resources into the EHV overlay should also be broadly allocated.
106
Key Legislation – Waxman-MarkeyKey Legislation – Waxman-Markey
Lead House Bill – American Clean Energy and Security Act (Waxman-Markey)
Planning: FERC would adopt transmission planning principles within a year— Principles must take into account “all significant demand-side and supply-side
options”— Regional planning entities must submit plans to FERC within 18 months of release— FERC must review for Waxman-Markey compliance; resolve any disputes— But – no authority for a meaningful interconnection-wide planning process
Siting: Waxman-Markey does not address siting or certification
Costs: Waxman-Markey does not address cost allocation or funding
Takeaway – The bill does very little to promote transmission development, ITC is advocating amendments to the bill and focusing on the Senate that deals more comprehensively with transmission reforms
Blue Dog Democrats (moderates) have expressed desire to amp up transmission requirements when House Energy & Commerce Committee considers amendments
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Key Legislation – Reid Bill (S. 539)Key Legislation – Reid Bill (S. 539)
Senate Bill #1 – Clean Renewable Energy and Economic Development Act (Reid bill, S. 539)
Planning: Designated regional planners to design interconnection-wide plans— FERC-designated entities must adopt interconnection-wide green transmission grid
project plans within one year of FERC designation— FERC does not have approval or review authority over regional plans, but can enforce
default plans on states that do not participate in their interconnection-wide plan
Siting: FERC can issue siting permits after consultation with states— FERC still serves as backstop authority; developers can only go to FERC for
certificate if they fail “to make reasonable progress” in siting facility under state/regional plan
Costs: Regional planners to design allocation method; FERC approval required— States and/or planning entities can collect “prudently-incurred” costs— Funds collected in surcharge on load serving entities not greater than $80mil/yr
Takeaway – ITC supports many elements of the bill. But, ITC does not believe that regional entities will be able to resolve the cost allocation impasse – as has been the case to date.
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Key Legislation – Bingaman DraftKey Legislation – Bingaman Draft
Senate Bill #2 – Senate Energy and Natural Resources Draft (Bingaman Draft)
Planning: FERC and regional entities to share authority for developing plans— FERC must coordinate development of interconnection-wide plans that promote policy
goals, to be published in a rule within one year of enactment— FERC can defer planning to interconnection-wide entity, but FERC must review and
approve regional plans and can modify once submitted— FERC may enforce default plans on interconnections if no regional entity develops plan
Siting: FERC to receive boosted backstop authority for high priority projects— States have one year from time regional proposal is filed to site high priority projects— FERC automatically obtains jurisdiction to site if states fail to complete siting within a
year
Costs: FERC to establish allocation methods by rule— Methods must be “just and reasonable,” but no further detail in draft— FERC may allocate costs across a region if found beneficial for region by FERC
Takeaway – ITC supports the most recent Bingaman draft, but feels it should be more explicit as to FERC’s role in integrating regional plans and Congress should provide more guidance to FERC for the cost allocation rulemaking
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Other Legislation Other Legislation
National Energy Security Act of 2009 (Dorgan Bill, S. 774)— Addresses transmission in coordination with RES and increased domestic oil
production— Requires FERC review and approval of interconnection-wide plans developed by
designated regional authorities; plan must be updated every two years— FERC has primary and exclusive citing authority for extra high voltage line projects— Regional entities will set cost allocation plans (with FERC approval)
SMART Energy Act of 2009 (Nelson bill, S. 807)— FERC has exclusive jurisdiction over planning, permitting, siting and construction
decisions necessary for national transmission projects— FERC must submit plans to Congress within one year, then begin work within 18
months— FERC receives backstop siting authority for all secondary connections— Transmission project sponsors can collect payment and recover costs of incremental
transmission capacity for renewable electricity sources if plan is approved by FERC
Takeaway – ITC’s position is most closely reflected in the Dorgan bill.
Questions?Questions?
Federal Regulatory UpdateFederal Regulatory Update
Tanya Paslawski
Director – Regulatory Strategy
ITC
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FERC rejected MISO’s Proposed “Market Coordination Services” under Module F part III of the Tariff. — This proposal suggested these services be offered to non RTO
members as “A Trial Membership to MISO.”
The ITC Companies filed jointly with AEP in protest of the cross border economic project cost allocation methodology proposed by MISO and PJM. — On May 8th FERC responded with a Deficiency Letter
The ITC Companies, along with Great River Energy and Xcel Energy, filed a Schedule 26 true up methodology. This mechanism allows for a true up by project, by independent pricing zones.
AEP has filed a petition for review of FERC’s rehearing decision on the rate design for the PJM/MISO region with the 7th Court of Appeals. — The ITC Companies filed a plain vanilla intervention.
Regulatory UpdateRegulatory Update
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FERC dismissed IP&L’s Section 206 complaint against ITC Midwest.
FERC approved all of the requested incentives (abandoned plant, CWIP in rate base, regulatory asset, ROE adders, and hypothetical capital structure) for the Green Power Express Project. The requested formula rate and protocols are set for hearing.
New Midwest ISO Members— MidAmerican Energy— Muscatine Power & Water
The 2008 Attachment O true up for ITC Transmission and METC will be posted to Oasis June 1st, 2009.
Regulatory UpdateRegulatory Update
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Green Power ExpressGreen Power Express
Population Centers
Green Power Express
Potential Future Collector System
• 3,000 miles 765 kV
• 10-12 GW transfer capacity to support approximately 20 GW of new wind generation
• Crosses 7 states, 20 utility service territories, 2 RTOsand non RTO areas
• Expected cost of $10-12 billion
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Timing of Filing - Why GPE Now?Timing of Filing - Why GPE Now?
Over a year of internal study prior to filing
— Submitted to MTEP for analysis and study in compliance with Order 890
— Discussions with developers and stakeholders ongoing
Initiated by federal policy discussions
— Private capital is available for major transmission investment
Financial disclosure and competitive considerations
Regional planning initiatives (UMTDI, RGOS, JCSP, CARP/RECB)
— ITC supports these efforts
— Timing concerns
— Studies do not build transmission
State of current project evaluation and cost allocation criteria
— Not conducive to regional project to move renewable sources
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Facilitates the movement of large amounts of high efficiency wind throughout the footprint
Reduces carbon emissions by approximately 37 million metric tons annually, equivalent to seven to ten 600 MW coal plants or nine to twelve million automobiles
Largely resolves Midwest ISO generation interconnection queue issues for region
Efficient use of land
Addresses concerns with system congestion as wind comes online
Increases electric reliability
Green Power Express Benefits Green Power Express Benefits
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765 kV provides greatest capacity increases with least land consumption— One 765 kV facility can carry as
much power as six 345 kV lines— Reduced right-of-way lowers cost as
well as impacts to consumers and environment
Supports competitive markets, reliability, and renewable energy development
Power carried greater distances and facilitates renewable resources market
“On-ramps” and “off-ramps” provide for easy generation connections and future transmission integration
Why 765kV instead of 345kV?Why 765kV instead of 345kV?
VS
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DC is a good technology for certain applications, namely point to point without off ramps— GPE has a number of pick-up and drop-off points
for power along the path DC does not allow for easy redirection of power in the
case of a line outage— Could make system vulnerable from a reliability
standpoint if used as a first step— May require a significant system below
DC overlays may be required in the Eastern Interconnect once a robust backbone system exists to accommodate renewable development
Why Not DC for GPE?Why Not DC for GPE?
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Recognition of State/Federal Rules and Contractual Rights
Underlying system planning— ITC will work with incumbent to
address local planning concerns and submit jointly to RTO as appropriate
— Determine appropriate location of substations based on local knowledge and input
— Strong backbone for local utility to build on to support local needs and future development
Local Siting Issues— Local color on approaches to siting,
including location
Partnership Structure— Must be developed in a way that
maintains independence
Affected Utility RoleAffected Utility Role
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FERC Order on GPE – April 10, 2009FERC Order on GPE – April 10, 2009
Approved the following incentives as in line with the project risks:
— Regulatory asset Approved effective April 11, 2009 and January 1 each year for subsequent year Future 205 filing required to show prudence and reasonableness before collection in rates
— CWIP Compliance filing for authorization to include in rates required at least 60 days prior to
requested effective date
— Abandoned plant Must file future 205 to show costs are just and reasonable and obtain approval for the cost
allocation method that will be applied
— Hypothetical capital structure
60 percent equity and 40 percent debt until any portion of the project is placed in service
ROE - approved total ROE of 12.38%, which includes 100 points for independence, 10 points for scope of project, and 50 points for RTO participation which is effective when entity becomes an RTO member and places project under RTO operational control
Formula rate and protocols – set for hearing and subject of ongoing settlement discussions
Requires informational filings with FERC on any changes in partnership structure as development occurs to ensure independence is maintained
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Lack of Federal Policy Direction— Federal RPS— CO2 Policy— FERC role in siting
Planning Processes— Regional approaches (UMTDI,
RGOS, JCSP)— Timing— RTO metrics
Cost Allocation— RECBTF— CARP/OMS— Current Structures
What Else Has to be Addressed? What Else Has to be Addressed?
Questions?Questions?
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Jeff Dorr
ITC Holdings
Manager, Stakeholder Relations
248.946.3482 office
248.660.7109 cell
Dave Nagy
ITC Holdings
Account Manager, Stakeholder Relations
248.946.3480 office
248.881.9208
Contact informationContact information
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THANK YOU !!!!!!!!! THANK YOU !!!!!!!!!
1. For electronic copies of ITC presentations please visit the Partners in Business tab found on our web-site at:
www.itctransco.com
2. Please take the time to respond to the evaluation for today's Partners in Business meeting. We will be sending the form via e-mail by tomorrow. We use your feed back for future meetings and continuous improvement efforts.
3. Drive home safely
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GOLF TIMEGOLF TIME
