425
0
ITC, ELL & EGSL
ITC, ELL & EGSL
Technical Conference
Technical Conference
March 6, 2013
Filed by Entergy Corporation Pursuant to Rule 425
Under the Securities Act of 1933
Subject Company: Entergy Corporation
Commission File No. 001-11299
Transmission Business


1
1
Entergy Forward-Looking Information
Entergy Forward-Looking Information
In this communication, and from time to time, Entergy makes certain “forward-looking statements” within the meaning of
the Private Securities Litigation Reform Act of 1995. Except to the extent required by the federal securities laws, Entergy
undertakes no obligation to publicly update or revise any forward-looking statements, whether as a result of new
information, future events, or otherwise. Forward-looking statements involve a number of risks and uncertainties. There
are factors that could cause actual results to differ materially from those expressed or implied in the forward-looking
statements, including (i) those factors discussed in Entergy’s most recent Annual Report on Form 10-K , any subsequent 
Quarterly Reports on Form 10-Q , and other filings made by Entergy with the Securities and Exchange Commission (the
“SEC”); (ii) the following transactional factors (in addition to others described elsewhere in this communication, in the
proxy statement/prospectus included in the registration statement on Form S-4 that was filed by ITC Holdings Corp. 
(“ITC”) with the SEC in connection with the proposed transactions) involving risks inherent in the contemplated 
transaction, including: (1) failure to obtain ITC shareholder approval, (2) failure of Entergy and its shareholders to
recognize the expected benefits of the transaction, (3) failure to obtain regulatory approvals necessary to consummate
the transaction or to obtain regulatory approvals on favorable terms, (4) the ability of Entergy, Mid South TransCo LLC
(“TransCo”) and ITC to obtain the required financings, (5) delays in consummating the transaction or the failure to
consummate the transaction, (6) exceeding the expected costs of the transaction, and (7) the failure to receive an IRS
ruling approving the tax-free status of the transaction; (iii) legislative and regulatory actions; and (iv) conditions of the
capital markets during the periods covered by the forward-looking statements. The transaction is subject to certain
conditions precedent, including regulatory approvals, approval of ITC’s shareholders and the availability of financing.
Entergy cannot provide any assurance that the transaction or any of the proposed transactions related thereto will be
completed, nor can it give assurances as to the terms on which such transactions will be consummated.


2
2
ITC Forward-Looking Information
ITC Forward-Looking Information
This document and the exhibits hereto contain certain statements that describe ITC management’s beliefs concerning future
business conditions and prospects, growth opportunities and the outlook for ITC’s business, including ITC’s business and the electric
transmission industry based upon information currently available. Such statements are “forward-looking” statements within the
meaning of the Private Securities Litigation Reform Act of 1995. Wherever possible, ITC has identified these forward-looking
statements by words such as “anticipates”, “believes”, “intends”, “estimates”, “expects”, “projects” and similar phrases. These
forward-looking statements are based upon assumptions ITC management believes are reasonable. Such forward-looking
statements are subject to risks and uncertainties which could cause ITC’s actual results, performance and achievements to differ
materially from those expressed in, or implied by, these statements, including, among other things, (a) the risks and uncertainties
disclosed in ITC’s most recent Annual Report on Form 10-K and any subsequent Quarterly Reports on Form 10-Q filed with the SEC
from time to time and (b) the following transactional factors (in addition to others described elsewhere in this document, in the proxy
statement/prospectus included in the registration statement on Form S-4 that was filed by ITC with the SEC in connection with the
proposed transactions): (i) risks inherent in the contemplated transaction, including: (A) failure to obtain approval by the Company’s
shareholders; (B) failure to obtain regulatory approvals necessary to consummate the transaction or to obtain regulatory approvals
on favorable terms; (C) the ability to obtain the required financings; (D) delays in consummating the transaction or the failure to
consummate the transactions; and (E) exceeding the expected costs of the transactions; (ii) legislative and regulatory actions, and 
(iii) conditions of the capital markets during the periods covered by the forward-looking statements.
Because ITC’s forward-looking statements are based on estimates and assumptions that are subject to significant business,
economic and competitive uncertainties, many of which are beyond ITC’s control or are subject to change, actual results could be
materially different and any or all of ITC’s forward-looking statements may turn out to be wrong. They speak only as of the date made
and can be affected by assumptions ITC might make or by known or unknown risks and uncertainties. Many factors mentioned in this
document and the exhibits hereto and in ITC’s annual and quarterly reports will be important in determining future results.
Consequently, ITC cannot assure you that ITC’s expectations or forecasts expressed in such forward-looking statements will be
achieved. Actual future results may vary materially.  Except as required by law, ITC undertakes no obligation to publicly update any
of ITC’s forward-looking or other statements, whether as a result of new information, future events, or otherwise.
The transaction is subject to certain conditions precedent, including regulatory approvals, approval of ITC’s shareholders and the
availability of financing. ITC cannot provide any assurance that the proposed transactions related thereto will be completed, nor can 
it give assurances as to the terms on which such transactions will be consummated.


3
3
Additional Information and Where to Find It
Additional Information and Where to Find It
ITC filed a registration statement on Form S-4 (Registration No. 333-184073) with the SEC registering the offer and
sale of shares of ITC common stock to be issued to Entergy shareholders in connection with the proposed
transactions. This registration statement includes a proxy statement of ITC that also constitutes a prospectus of ITC.
This
registration
statement
was
declared
effective
by
the
SEC
on
February
25,
2013.
ITC
mailed
the
proxy
statement/prospectus to its shareholders on or about February 28, 2013.  ITC shareholders are urged to read the
proxy statement/prospectus included in the ITC registration statement and any other relevant documents because
they contain important information about TransCo and the proposed transactions.  In addition, TransCo will file a
registration statement with the SEC registering the offer and sale of TransCo common units to be issued to Entergy
shareholders in connection with the proposed transactions. Entergy shareholders are urged to read the proxy
statement/prospectus included in the ITC registration statement and the prospectus to be included in the TransCo
registration statement (when available) and any other relevant documents, because they contain important information
about ITC, TransCo and the proposed transactions.
The proxy statement/prospectus, prospectus and other documents relating to the proposed transactions (when they
are available) can be obtained free of charge from the SEC’s website at www.sec.gov. The documents, when
available,
can
also
be
obtained
free
of
charge
from
Entergy
upon
written
request
to
Entergy
Corporation,
Investor
Relations, P.O. Box 61000 New Orleans, LA 70161 or by calling Entergy’s Investor Relations information line at
1-888-
ENTERGY (368-3749), or from ITC upon written request to ITC Holdings Corp., Investor Relations, 27175
Energy Way, Novi, MI 48377 or by calling 248-946-3000.
This communication is not a solicitation of a proxy from any security holder of ITC. However, Entergy, ITC and certain
of
their
respective
directors
and
executive
officers
and
certain
other
members
of
management
and
employees
may
be
deemed to be participants in the solicitation of proxies from shareholders of ITC in connection with the proposed
transaction under the rules of the SEC. Information about the directors and executive officers of Entergy, may be
found in its 2012 Annual Report on Form 10-K filed with the SEC on February 27, 2013, and its definitive proxy
statement relating to its 2012 Annual Meeting of Shareholders filed with the SEC on March 23, 2012.  Information
about the directors and executive officers of ITC may be found in its 2012 Annual Report on Form 10-K filed with the
SEC on March 1, 2013, and its definitive proxy statement relating to its 2012 Annual Meeting of Shareholders filed
with the SEC on April 12, 2012.


4
4
Agenda
Agenda
Morning
Session
(10:00
am
12:30
pm)
Welcome
&
Logistics
10:00
10:15
Montelaro, Blair, Freese
Vision
for
Industry
Future
10:15
11:15
Welch, May
Why is this transformation necessary?
Why this structure?
Why with ITC?
Why now?
Rationale
for
Transaction
-
11:15
12:30
Independence
Welch
Operational
Excellence
Jipping,
Riley
Storm Response
Regional
Planning
Vitez
IPL
Transaction
Experience
&
Results
Jipping
Local Presence
&
Engagement
w/Retail
Regulators
Jipping
Financial
Flexibility
and
Growth
Lewis
Financial
Strength
of
ITC
Bready
Afternoon
Session
(1:00
pm
4:00
pm)
Rate
Effects
1:00
2:30
Bready, Dingle, Lewis
ELL/EGSL Retail Customer Rate Effects
Rate Construct
Forward Test Year
Bill Effects
Any Potential Impacts on ELL/EGSL
Generation/Distribution Business 
Wholesale Rate Effects Post-MISO
Break –
2:30 –
2:45
Transaction Structure & ELL/EGSL Specific
Implications
2:45
3:45
Bready, Lewis
Wrap
Up
3:45
4:00
Fontan, Freese
03/06/13
ITC, ELL & EGSL Technical Conference
ELL/EGSL
Credit
Ratings
Impacts
Securitization
Transaction
Impact
on
ADIT
Liability
Transaction
Structure


5
5
Significant capital requirements to continue modernizing the grid best handled by
an independent company who can better manage the transmission portion of
capital spend
Affords the EOCs financial flexibility to manage the necessary investment in G&D
Independent ownership and operation of Entergy Transmission System (ETS)
extracts the greatest benefits in an RTO with a Day 2 market
Consistent with efforts towards independent transmission operation and ownership
Nation's first, largest, & only publicly-traded independent transmission company
A proven track record of best-in-class performance, improving reliability for ETS
Extensive
experience
with
MISO
and
committed
to
facilitating
the
MISO
Day
2
Market
Inter-RTO experience applicable to ETS's seams with SPP and other regions
Financially sound with strong investment grade credit ratings & access to capital
Opportunities for greater economies and efficiencies
Final step in over a decade of work to pursue best management structure for ETS
Eliminates perception of bias in transmission system planning and operations
Comparable
sizes
of
ITC's
and
the
EOCs’
(Entergy
Operating
Companies)
transmission businesses allows for a tax efficient transaction not necessarily
available in future
The right
transaction...
...with the
right
partner...
at the right
time
This transaction creates the right model
for the benefit of our customers...now and into the future
ITC Transaction is the Right Transaction
ITC Transaction is the Right Transaction
with the Right Partner at the Right Time
with the Right Partner at the Right Time


6
6
6
U.S. Transmission Grid –
U.S. Transmission Grid –
Historically Fragmented and Inefficient
Historically Fragmented and Inefficient
Historically, transmission
infrastructure development in
the U.S. primarily
focused on connecting load
and resources within
balancing authority areas,
with little interregional or
national perspective
In contrast,…
U.S. Electric Power Transmission Grid
More than 211,000 high voltage transmission
line miles
Operated by ~130 balancing authority areas
(ownership is even more fragmented)
Source: FEMA, NERC


7
7


8
8
Introduction
Industry Evolution
ITC’s Business Model
ITC’s Proven Track Record
Benefits Beyond MISO
Commitment to Louisiana & Communities we serve
Transaction Value for Louisiana
Strategic Overview
Strategic Overview
ITC
ITC


9
9
Agenda
Agenda
Morning
Session
(10:00
am
12:30
pm)
Welcome
&
Logistics
10:00
10:15
Montelaro, Blair, Freese
Vision
for
Industry
Future
10:15
11:15
Welch, May
Why is this transformation necessary?
Why this structure?
Why with ITC?
Why now?
Rationale
for
Transaction
-
11:15
12:30
Independence
Welch
Operational
Excellence
Jipping,
Riley
Storm Response
Regional
Planning
Vitez
IPL
Transaction
Experience
&
Results
Jipping
Local
Presence
&
Engagement
w/Retail
Regulators
Jipping
Financial
Flexibility
and
Growth
Lewis
Financial
Strength
of
ITC
Bready
Afternoon
Session
(1:00
pm
4:00
pm)
Rate
Effects
1:00
2:30
Bready, Dingle, Lewis
ELL/EGSL Retail Customer Rate Effects
Rate Construct
Forward Test Year
Bill Effects
Any Potential Impacts on ELL/EGSL
Generation/Distribution Business 
Wholesale Rate Effects Post-MISO
Break –
2:30 –
2:45
Transaction Structure & ELL/EGSL Specific
Implications
2:45
3:45
Bready, Lewis
Wrap
Up
3:45
4:00
Fontan, Freese
03/06/13
ITC, ELL & EGSL Technical Conference
ELL/EGSL
Credit
Ratings
Impacts
Securitization
Transaction
Impact
on
ADIT
Liability
Transaction
Structure


10
10
Transaction Rationale:
Transaction Rationale:
In the Public Interest
In the Public Interest
Independent model
Proven independent business model for owning and operating transmission systems
Independence from all buyers and sellers of electric energy allows ITC to plan
improvements to the electric transmission grid for the broadest public benefit
Singular focus
Transaction
results
in
two
companies
that
are
more
specialized
and
focused
ITC
on transmission and Entergy on generation and distribution
Operational excellence, cost efficiency, customer focus
Wholesale markets and a regional planning view
Transaction
facilitates
infrastructure
investment
and
fosters
competition
activities
that enhance wholesale electricity markets
Structural separation of the transmission business from generation and distribution
businesses encourages greater participation in the transmission planning process and
disclosure of information by third parties
Independent model aligns with national policy objectives
Financial strength and flexibility
Transaction will yield separate companies with strong balance sheets and greater
capability
to
finance
the
infrastructure
investment
requirements
today
and
in
the
future


11
11
Independent Model
Independent Model
Benefits of ITC Independent
Transmission Model
Transparency
Operational
Excellence
Reliability
Infrastructure
Investment
High Credit
Quality
Public Policy
Alignment
Facilitate Generator
Interconnection
Customer
Focus
11


12
12
Data from the SGS Study benchmarking study can be used to
quantify the resulting improved reliability
Operational Excellence:
Operational Excellence:
Quantitative Value of Reliability
Quantitative Value of Reliability
The calculation is based on data for the two largest load serving entities in Michigan from 2010 and 2011, with major storms excluded.  The ITCT
and METC data reflect a three year average SAIDI from the SGS Study, given that performance changes year over year.
Compared to the performance of the median utility in the SGS Study,
this
amounts
to
a
value
of
about
$153
million
per
year
delivered
by
ITC’s Michigan utilities
The U.S. Department of Energy’s Office
of Electricity Delivery and Energy
Reliability has developed a tool to
estimate interruption costs and the
benefits associated with reliability
improvements
A one minute improvement in System
Average Interruption Duration Index
(SAIDI)
for
ITCTransmission
and
METC
results in one year savings of $7.7M


13
Utilize standard equipment when possible to drive greater
efficiencies (e.g. breaker replacement completed in two versus
six weeks)
Utilize equipment with track record of longer life, resulting in
lower maintenance and replacement costs
Engage in strategic alliances to ensure that needed equipment is
available to meet project timelines
Purchasing power leads to better pricing when buying large
volume of transmission equipment
Cost Efficiencies
Cost Efficiencies
Standardization and Specialization
Standardization and Specialization
Ability to attract and retain
personnel with high levels of
interest and expertise in electric
transmission avoids turnover and
training costs (important when
facing near-term shortage of
skilled workers)
13


14
14
Customer Focus
Customer Focus
Dedicated Stakeholder Relations group for all stakeholders,
providing advocacy and issue resolution at ITC
Stakeholders include investor-owned, municipal and cooperative utilities,
independent power producers and retail load of large industrial and commercial
retail customers connected at transmission level voltages
Proactively meet with stakeholders to identify stakeholder issues
and resolve any concerns through one-on-one meetings and semi-
annual
“Partners
in
Business”
meetings
Energy policy, legislative and regulatory matters
Capital project, transmission planning and preventive maintenance
Operations preparedness for summer peak load and storm events
Transmission rates
Storm restoration
Planned outages to eliminate or
minimize any potential risk and costs to
industrial processes
Unplanned outages regarding cause,
estimated duration, and future prevention
14
Timely customer communication


15
Storm Response –
Storm Response –
Utilizing Best Practices
Utilizing Best Practices
ETR System Incident
Commander (SIC)
ITC System Incident
Commander (SIC)
System Section
Chiefs
System Planning
Section Chief
System Resource
Section
System Logistics
Section
Restoration
Prioritization Branch
Director
ITC Section
Chiefs
Entergy Liaison
Coord.
(New position)
ITC Technical/Management
employee assigned to
ETR System Command
Center in Jackson, MS
ITC employee
ETR employee
Functional Incident
Commanders
(ex. Fossil, EOC,   
Nuclear, Gas)
Storm response organization will be modified to ensure
close coordination and interaction between Entergy and ITC
ELL/EGSL
Customer
Customer
ITC Planning
Section
ITC Logistics
Section
ITC Resource
Section
Transmission Prioritization
Resource Coordination
Logistics Coordination
15


16
16
16
Fosters Regional Planning
Fosters Regional Planning
ITC has track record of planning its transmission systems to:
Address local, state, and regional reliability needs
Increase the economic efficiency of the overall grid
Respond to transmission needs identified in state and regional processes
When deficiencies are identified on the transmission system, such as
inadequate capacity to meet load under certain contingency conditions,
ITC plans, develops and constructs transmission projects to address
such deficiencies
ITC is committed to planning its transmission system in an open and
transparent manner; ITC has its own processes that supplement the
already open and transparent processes used by MISO
Transaction enhances customer benefits beyond what could be achieved
through the Entergy Operating Companies’
proposed MISO membership
ITC has proven it has the expertise, resources, and capital not only to
plan but also to construct needed investment
ITC’s regional approach to transmission planning will enhance
deliverability of generation throughout the region to provide a more
economic source of energy for customers


17
17
17
IPL Transaction Experience & Results
IPL Transaction Experience & Results
ITC has invested approximately $1.1 billion to improve the ITC
Midwest transmission system since acquisition of IPL assets
Projects needed to upgrade and improve existing lines and substations,
construct new lines to serve load growth and improve reliability, resolve
system constraints and provide interconnection for new load and generation
Major activities:
Built 26 new substations
Completed 32 major substation upgrades/expansions
Built nearly 26 miles of new line
Rebuilt nearly 400 miles of existing lines
Added four and replaced three major transformers
Key Project:  Salem-Hazleton
81-mile,
345
kV
line
connecting
Dubuque
and
Buchanan
Counties in eastern Iowa
Regional planning had long identified as needed to
resolve system constraints and reduce energy costs.
Expected completion: 2013
ITC Midwest reduced sustained outages from those experienced in 2008 (the last year
IPL operated and maintained the system) by 50% in 2009, 24% in 2010, and 58% in 2011


18
18
ITC Midsouth
ITC Midsouth
Regulatory and External Affairs Organization
Regulatory and External Affairs Organization
ITC
Chief Business Officer
ITC
Midsouth
Director,
Regulatory
Affairs
ITC Midsouth
Director,
State Gov’t
Affairs
ITC Midsouth
Director,
Local Gov’t
& Comm.
Affairs
ITC Midsouth
Director,
Stakeholder
Relations
An ITC executive (VP and BU Head)
will be responsible for the following
ITC Midsouth functions:
Regulatory Affairs
State Government Affairs
Local Government and
Community Affairs
Stakeholder Relations
ITC Midsouth staff will be located
throughout the Entergy footprint to
perform these functions
Regulatory Affairs Managers
will be located in each state
capital
Managers and other support
staff will be geographically
dispersed to cover the other
functions
These employees and functions will
report  to ITC’s Chief Business
Officer
Louisiana
Arkansas
Mississippi
Texas
ITC Midsouth
VP and Business Unit Head
Louisiana
Arkansas
Mississippi
Texas
Louisiana
Arkansas
Mississippi
Texas
Louisiana
Arkansas
Mississippi
Texas


19
19
ETR Utilities’
ETR Utilities’
Capital Needs
Capital Needs
Could Total ~$12B-16B  Over 2012-2018
Could Total ~$12B-16B  Over 2012-2018
Actual and Forecast Entergy Utilities
Investment
($B)
0
5
10
15
20
1999-2004
2005-2011
2012-2018
Average
2
= $1.8B -
$2.3B
Total = $12.3B -
$15.9B
Average
1
= $1.4B -
$1.7B
Total = $9.7B -
$11.7B
Average
1
= $1.1B
Total = $6.5B
???
Effect of EPA rules?
Aging infrastructure?
1. Range
based
on
actuals
plus
storm
capital.
2.
Range
based
on
projections
of
ETR
Utilities’
base
capital
plan
plus
potential
spend
3.
Potential
spend
related to potential economic development projects,  potential new generation investment, potential environmental spend, and potential  new storm
spend.
Potential storm spend for forward looking period is an estimate based on annual average spend over 2005-10 to illustrate potential of capital
requirements
of
event
risks.
Potential
spend
is
not
included
in
base
capital
plan
Note: ETR Utilities includes EAI, ELL, EGSL, EMI, ETI, ENO, SERI, ESI,
EOI, SFI; EOCs include EAI, ELL, EGSL, EMI, ETI, and ENO
Actual excluding storms (Transmission and Non-Transmission)
Potential spend
Past storm spend
Base case –
conservative (Transmission and Non-Transmission)
EOCs Transmission
EOC
Transmission
EOC
Transmission
19
3


20
20
20
ELL Total Capital Needs Could Total
ELL Total Capital Needs Could Total
~$3.1B -
~$3.1B -
$4.6B Over 2012-2018
$4.6B Over 2012-2018
Actual and Forecast Capital Investment
for ELL ($B)
1999-2004
2005-2011
2012-2018
2.5
5
0
Actual excluding storms (Transmission and Non-Transmission)
Potential spend
Past storm spend
Base case –
conservative (Transmission and Non-Transmission)
Average
2
= $445M -
$664M
Total = $3.1B -
$4.6B
Average
1
= $406M -
$505M
Total = $2.8B -
$3.5B
Average
1
= $208M
Total = $1.2B
???
Effect of EPA rules?
Aging infrastructure?
1. Range based on actuals plus storm capital.  2. Range based on
projections of ELL's base capital plan plus potential spend 3. Potential spend
related to potential economic development projects,  potential new generation investment, potential environmental spend, and potential  new storm
spend.
Potential storm spend for forward looking period is an estimate based on annual average spend over 2005-10 to illustrate potential of
capital requirements of event risks.  Potential spend is not included in base capital plan.
Transmission
Transmission
Transmission
3


21
21
21
EGSL Total Capital Needs Could Total
EGSL Total Capital Needs Could Total
~$1.5B -
~$1.5B -
$2.0B Over 2012-2018
$2.0B Over 2012-2018
Actual and Forecast Capital Investment
for EGSL ($B)
1999-2004
2005-2011
2012-2018
1
2
0
Average
2
=
$218M
-
$280M
Total = $1.5B -
$2.0B
Average
1
=
$192M
-
$225M
Total = $1.3B -
$1.6B
Average
1
=
$153M
Total = $0.9B
???
Effect of EPA rules?
Aging infrastructure?
1.
Range
based
on
actuals
plus
storm
capital.
2.
Range
based
on
projections
of
EGSL’s
base
capital
plan
plus
potential
spend
3.
Potential
spend
related to potential economic development projects,  potential new generation investment, potential environmental spend, and potential  new storm
spend.
Potential storm spend for forward looking period is an estimate based on annual average spend over 2005-10 to illustrate potential of
capital requirements of event risks.  Potential spend is not included in base capital plan.
Actual excluding storms (Transmission and Non-Transmission)
Potential
spend
Past storm spend
Base case –
conservative (Transmission and Non-Transmission)
Transmission
Transmission
Transmission
3


22
22
22
Note: Historical data excludes storm capital, as there is no capital associated with future storms in base capital plan projections. 
Numbers presented are only for EOCs (EAI, EGSL, ELL, EMI, ETI, ENO) and excludes SERI/ESI
EOCs’
EOCs’
Transmission Capital
Transmission Capital
Could Total ~$3.6B Over 2012-2018
Could Total ~$3.6B Over 2012-2018
Average = $254M
Total = $1.8B
Average= $511M
Total = $3.6B
Actual and Forecast Transmission Investment for EOCs
($B)
2005-2011
1999-2004
2012-2018
0
2
1
4
3
Projected base case capital
plan as of August 2012
Actual
Average= $200M
Total = $1.2B
Transmission Capital Spending for EOCs Could Increase
Over 100% in the Next Seven Years


23
23
23
ELL Transmission Capital
ELL Transmission Capital
Could Total  ~$650M Over 2012-2018
Could Total  ~$650M Over 2012-2018
Average = $74M
Total = $521M
Average= $93M
Total = $652M
Actual and Forecast Transmission Investment for ELL
($M)
750
1999-2004
2005-2011
2012-2018
0
375
Average= $35M
Total = $209M
Transmission Capital Spending for ELL Could Increase
Approximately 25% in the Next Seven Years
Projected base case capital
plan as of August 2012
Actual
Note: Historical data excludes storm capital, as there is no capital associated with future storms in base capital plan projections.


24
24
24
EGSL Transmission Capital
EGSL Transmission Capital
Could Total  ~$545M Over 2012-2018
Could Total  ~$545M Over 2012-2018
Average = $56M
Total = $392M
Average= $78M
Total = $545M
Actual and Forecast Transmission Investment for EGSL
($M)
600
1999-2004
2005-2011
2012-2018
0
300
Average= $75M
Total = $450M
Transmission Capital Spending for EGSL Could Increase
Approximately 39% in the Next Seven Years
Projected base case capital
plan as of August 2012
Actual
Note: Historical data excludes storm capital, as there is no capital associated with future storms in base capital plan projections.


25
25
25
ELL Transmission CapX as Multiple of Depreciation
ELL Transmission CapX as Multiple of Depreciation
Nearly Twice as High as Non-Transmission
Nearly Twice as High as Non-Transmission
ELL Average CapX as Multiple of
Depreciation (2012-18 Average)
For ELL,
Transmission
Constitutes ~31% of
Capital in Excess of
Depreciation, despite
being 12% of rate
base
2.4
4
3
2
1
0
1.6
Transmission
Non-
Transmission
Note: Based on figures filed in testimony at LPSC


26
26
26
EGSL Transmission CapX as Multiple of Depreciation
EGSL Transmission CapX as Multiple of Depreciation
More Than Three Times as High as Non-Transmission
More Than Three Times as High as Non-Transmission
EGSL Average CapX as Multiple of
Depreciation (2012-18 Average)
For EGSL,
Transmission
Constitutes ~89% of
Capital in Excess of
Depreciation, despite
being 14% of rate
base
3.5
4
3
2
1
0
1.1
Transmission
Non-
Transmission
Note: Based on figures filed in testimony at LPSC


27
27
27
Benefits from Financial Flexibility for Entergy
Benefits from Financial Flexibility for Entergy
Transmission-Related Cash
Capital Requirements Go Away
Utility Operating Cash Flow Minus
Cash Construction Expenditures
2014E –
2018E ($M)
Utility Debt Obligations
2018E ($M)
Stronger Utility Balance Sheet Improves Ability
to Invest in Generation and Distribution
Status Quo
With ITC
Transaction
Status Quo
With ITC
Transaction
6,000
2,000
0
4,000
2,000
0
6,000
4,000
8,000
10,000
4,716
5,580
Note: As detailed in direct testimony, Transaction has two separate effects on remaining entity's cash flow:
OCF: EOCs no longer earn on transmission rate base spun-off (negative effect on cash flow)
Cash Construction Expenditures: transmission related cash capital requirements go away (positive effect on cash flow for EOCs)
Net
effect
on
EOCs
is
positive
as
transmission
Cash
Construction
Expenditures
over
2014-2018
is
higher
than
transmission
OCF
18%
$2,755M


28
28
28
Benefits from Financial Flexibility for ELL
Benefits from Financial Flexibility for ELL
Transmission-Related Cash
Capital Requirements Go Away
ELL Operating Cash Flow Minus
Cash Construction Expenditures
2014E –
2018E ($M)
ELL Debt Obligations
2018E ($M)
Stronger Balance Sheet Improves Ability
to Invest in Generation and Distribution
Status Quo
With ITC
Transaction
Status Quo
With ITC
Transaction
2,000
1,000
0
500
1,500
2,500
3,000
2,000
1,000
0
2,093
2,164
Note: As detailed in direct testimony, Transaction has two separate effects on remaining entity's cash flow:
OCF: EOCs no longer earn on transmission rate base spun-off (negative effect on cash flow)
Cash Construction Expenditures: transmission related cash capital requirements go away (positive effect on cash flow for EOCs)
Net
effect
on
EOCs
is
positive
as
transmission
Cash
Construction
Expenditures
over
2014-2018
is
higher
than
transmission
OCF
3%
$576M


29
29
29
Benefits from Financial Flexibility for EGSL
Benefits from Financial Flexibility for EGSL
Transmission-Related Cash
Capital Requirements Go Away
EGSL Operating Cash Flow Minus
Cash Construction Expenditures
2014E –
2018E ($M)
EGSL Debt Obligations
2018E ($M)
Stronger Balance Sheet Improves Ability
to Invest in Generation and Distribution
Status Quo
With ITC
Transaction
Status Quo
With ITC
Transaction
1,500
1,000
500
0
2,000
1,000
0
500
1,500
1,011
1,113
Note: As detailed in direct testimony, Transaction has two separate effects on remaining entity's cash flow:
OCF: EOCs no longer earn on transmission rate base spun-off (negative effect on cash flow)
Cash Construction Expenditures: transmission related cash capital requirements go away (positive effect on cash flow for EOCs)
Net
effect
on
EOCs
is
positive
as
transmission
Cash
Construction
Expenditures
over
2014-2018
is
higher
than
transmission
OCF
10%
$359M


30
30
Financial Strength and Flexibility
Financial Strength and Flexibility
Transaction offers the financial strength of ITC and improves that of ELL and
EGSL to support the escalating capital investment requirements facing the
electric industry
ITC has a singular focus with no internal competition or competing priorities for
capital or other resources; provides a stronger, separate balance sheet to support
the transmission capital requirements
ITC better positioned to efficiently capitalize the significant and sustained level of
transmission investment required in the Entergy region, including Louisiana
Post-close, ELL and EGSL would be better positioned to attract capital separately
to finance needed investments in generation and distribution at lower costs and to
manage future uncertainty regarding event risk (e.g., new regulatory requirements
or major storms)
ITC’s MISO operating companies are deemed to be of higher credit quality
than ELL and EGSL, as well as most vertically-integrated utilities
Enables consistent and predictable access to cost-effective capital, even during
challenging economic times; supports enhanced liquidity
Given significant and sustained level of transmission capital investment
requirements, as well as unforeseen needs, credit quality and access to capital are
paramount


31
31
31
Credit Quality Enhancement Overview
Credit Quality Enhancement Overview
Debt Cost Savings
Debt Cost Savings
Expect new ITC operating companies to have ratings equivalent to
that of
ITC’s existing MISO operating companies
Merger between Entergy’s Transmission Business and ITC is expected to
lead to material interest expense savings, which will benefit Entergy’s
customers
Reflected in both the initial capitalization of the new ITC operating companies,
including ITC Louisiana, as well as future debt financings to fund transmission
investment requirements
Aggregate debt financing cost savings estimated in the range of $24 million to $27
million in 2014 (first full year of ownership) for the new ITC operating companies
Over a five-year period (2014-2018), estimate debt financing cost savings for the
new
ITC
operating
companies
in
a
range
of
approximately
$125
million
to
$156
million (in nominal dollars)
FERC rate construct utilized by ITC’s operating companies viewed favorably by the
rating agencies and investors, which supports lower debt financing costs
ITC is seeking FERC rate construct for its new operating companies as part of this
transaction
Results in lower borrowing costs of approximately 45 bps to 205 bps relative to the
status quo EOCs, depending on market conditions


32
32
Agenda
Agenda
Morning
Session
(10:00
am
12:30
pm)
Welcome
&
Logistics
10:00
10:15
Montelaro, Blair, Freese
Vision
for
Industry
Future
10:15
11:15
Welch, May
Why is this transformation necessary?
Why this structure?
Why with ITC?
Why now?
Rationale
for
Transaction
-
11:15
12:30
Independence
Welch
Operational
Excellence
Jipping,
Riley
Storm Response
Regional
Planning
Vitez
IPL
Transaction
Experience
&
Results
Jipping
Local Presence
&
Engagement
w/Retail
Regulators
Jipping
Financial
Flexibility
and
Growth
Lewis
Financial
Strength
of
ITC
Bready
Afternoon
Session
(1:00
pm
4:00
pm)
Rate
Effects
1:00
2:30
Bready, Dingle, Lewis
ELL/EGSL Retail Customer Rate Effects
Rate Construct
Forward Test Year
Bill Effects
Any Potential Impacts on ELL/EGSL
Generation/Distribution Business 
Wholesale Rate Effects Post-MISO
Break
2:30
2:45
Transaction Structure & ELL/EGSL Specific
Implications
2:45
3:45
Bready, Lewis
Wrap
Up
3:45
4:00
Fontan, Freese
03/06/13
ITC, ELL & EGSL Technical Conference
Transaction
Structure
Transaction
Impact
on
ADIT
Liability
Securitization
ELL/EGSL
Credit
Ratings
Impacts


33
33
33
Significant variability in average residential bills –
Significant variability in average residential bills –
yearly variation between $2 and $26 over 2001-2011
yearly variation between $2 and $26 over 2001-2011
Henry Hub
Gas Index
($/mmBtu)
2.7
3.1
5.4
5.9
8.3
6.5
6.9
9.0
3.8
4.4
4.0
2006
80.97
72.57
2002
100
2001
50
10
2004
2005
5
2011
150
ELL
Avg.
Monthly
Residential
Bill
1,000
kWh
($)
78.99
0
0
2008
84.12
95.93
99.55
96.83
93.70
2003
Henry Hub Gas Index
($/mmBtu)
2009
92.70
15
2010
2007
83.35
109.77
Henry Hub Gas Index
ELL Avg. Monthly Residential Bill-
1,000 kWh($)
Illustrative
Note: Residential bills are the average of the Typical Monthly Bills in that year for a residential customer using 1,000 kWh, excluding taxes.
Source: Entergy Regulatory Services, Typical Bill Report
(-24%)
-26.43
+2.23
(+2%)
-13%
13% reduction in customer
bills since 2008


34
34
34
Significant variability in average residential bills –
Significant variability in average residential bills –
yearly variation between $1 and $27 over 2001-2011
yearly variation between $1 and $27 over 2001-2011
Henry Hub Gas Index
($/mmBtu)
EGSL
Avg.
Monthly
Residential
Bill
1,000
kWh
($)
Henry Hub Gas Index
EGSL Avg. Monthly Residential Bill-
1,000 kWh ($)
Illustrative
14% reduction in customer
bills since 2008
Note: Residential bills are the average of the Typical Monthly Bills in that year for a residential customer using 1,000 kWh, excluding taxes.
Source: Entergy Regulatory Services, Typical Bill Report
50
10
2009
108.24
101.47
2011
0
108.99
101.34
87.16
80.95
2008
2010
75.12
2007
82.35
89.25
2006
2005
150
2004
5
2003
2002
100
2001
0
15
Henry Hub
Gas Index
($/mmBtu)
2.7
3.1
5.4
5.9
8.3
6.5
6.9
9.0
3.8
4.4
4.0
-14%
-26.64
(-24%)
-0.37
(0%)
93.55
93.91


35
35
35
Transmission Constitutes a Small Portion
Transmission Constitutes a Small Portion
of a Typical Louisiana Customer's Total Bill
of a Typical Louisiana Customer's Total Bill
3.7%
Transmission
Non-Transmission
96.3%
Typical
ELL
Customer
Bill
Typical EGSL Customer Bill
6.4%
Transmission
Non-Transmission
93.6%
Note: Average of January 2011 –
December 2011 typical bills for a residential customer using 1,000 kWh per month; non-transmission portion
of
monthly
bill
includes
fuel
and
portions
of
the
fixed
customer
charge
and
energy
charge
allocated
to
generation
and
distribution
functions,
as
well as the inclusion of various riders.


36
36
Transition from current retail rate construct to FERC-regulated rate construct
expected for ITC
Analysis assumes MISO base ROE for new ITC operating companies
(12.38%) and capital structure currently utilized by ITC operating companies
(60% equity/40% debt)
Benefits
of
credit
quality
improvement
resulting
from
transition
to
FERC-
regulated rate construct partially offset impacts
Rate Impacts Split into Rate Construct, Rate Timing,
Rate Impacts Split into Rate Construct, Rate Timing,
and Other Effects for Retail Customers
and Other Effects for Retail Customers
Rate
Construct
Effects
Rate Timing
Effects
Forward Test Year: Eliminates regulatory lag in recovery of capital
investments
One-time impact of conversion to forward test year
Reflects amounts that would have been collected in future years
Schedule MSS-2 construct eliminated post-Transaction
Current
estimation
reflects
effect
of
paying
load
ratio
share
of
Transmission
cost factoring in zonal investment (single LA zone) and retail share of
Transmission investments
Other
Effects
36


37
37
Over the long term,
customer bill effects 
expected to be mitigated
by...
Enhanced Financial
Flexibility
Operational Excellence
Independent and
transparent ITC model
Regional Planning
0
~0.52
0.5%
20
ELL
Residential
Bill
1,000
kWh
($)
120
100
80
60
40
Illustrative Bill
if ITC owns
T assets –
~96.45
2014
~(0.19)
2014
~0.71
Illustrative Bill
if ETR owns
T assets –
status quo
95.93
ELL Typical Residential Customer Bill
ELL Typical Residential Customer Bill
Expected
Expected
to
to
Increase
Increase
0.5%
0.5%
Expected
Expected
Mitigation by Customer Benefits
Mitigation by Customer Benefits
Note:
Contents exclude estimated
one-time 2014 rate timing
effect of $0.64 due to
conversion to forward test
year –
reflects amount that
would have been collected
in future years
Note:
$95.93
is
the
average
of
the
2011
Typical
Monthly
Bill
for
a
residential
customer
using
1,000
kWh,
excluding
taxes.
Calculation
is
indicative of the rate effects of the spin-merge transaction and is not meant to project an actual future customer bill. Illustration does not
include rate timing effects such as adoption of forward test year.
Illustrative
37
WACC
Effects
Net
Other
Effects
post-transaction


38
38
38
93.55
EGSL
Residential
Bill
1,000
kWh
($)
120
100
80
60
40
20
0
~1.20
1.3%
Illustrative Bill
if ITC owns
T assets –
~94.75
2014
~0.38
2014
~0.82
Illustrative Bill
if ETR owns
T assets –
status quo
EGSL Typical Residential Customer Bill
EGSL Typical Residential Customer Bill
Expected
Expected
to
to
Increase
Increase
1.3%
1.3%
Expected
Expected
Mitigation by Customer Benefits
Mitigation by Customer Benefits
Over the long term,
customer bill effects 
expected to be mitigated
by...
Enhanced Financial
Flexibility
Operational Excellence
Independent and
transparent ITC model
Regional Planning
Note:
Contents exclude estimated
one-time 2014 rate timing
effect of $0.63 due to
conversion to forward test
year –
reflects amount that
would have been collected
in future years
Note:
$93.55
is
the
average
of
the
2011
Typical
Monthly
Bill
for
a
residential
customer
using
1,000
kWh,
excluding
taxes.
Calculation
is
indicative of the rate effects of the spin-merge transaction and is not meant to project an actual future customer bill. Illustration does not
include rate timing effects such as adoption of forward test year.
Illustrative
Net Other Effects
WACC Effects
post-transaction


39
39
39
Modest
Modest
Bill
Bill
Effects
Effects
of
of
0.4
0.4
1.4%
1.4%
on
on
Select
Select
Commercial
Commercial
and
and
Industrial
Industrial
Classes
Classes
Expected
Expected
Mitigation by Customer Benefits
Mitigation by Customer Benefits
Note: Calculation indicative and illustrative of the rate effects of the spin-merge transaction and is not meant to project an actual future
customer
bill.
Contents
exclude
estimated
one-time
2014
rate
timing
effect
due
to
conversion
to
forward
test
year
reflects
amount
that
would
have been collected in future years. Based on August 2011 typical customer bill.
2014 Transaction  Bill Effects
Selected
Retail Class
Retail Class
Description
Typical
Bill
WACC
Effects
Net
Other
Effects
Total
Effect
%
Change
ELL
SGS
50 kW, 35% Load Factor
$1,237.15
7.46
(1.99)
5.48
0.4%
LGS
300 kW, 55% Load Factor
$8,823.83
80.51
(21.44)
59.07
0.7%
EGSL
SGS
1,500 kWh
$167.61
1.26
0.58
1.84
1.1%
GS
25 kW, 30% Load Factor, Summer
$488.23
4.73
2.17
6.90
1.4%
Illustrative


40
EGSL
$93.55
ELL
$95.93
EGSL
$93.55
Sensitivity of Residential Rate Effects
Sensitivity of Residential Rate Effects
to Variations in Spend
to Variations in Spend
ELL
$95.93
+ $0.11
O&M
Spend
+ $0.12
+ $0.04
Capital
Expenditure
Spend
+ $0.04
Typical Monthly
Residential Bill
Sensitivity to
10% Increase
in Spend
$0.52
$1.20
$0.52
$1.20
Total
Transaction
Bill Effect
Typical Monthly
Residential Bill
Sensitivity to
10% Increase
in Spend
Total
Transaction
Bill Effect
-
$0.11
-
$0.12
-
$0.04
-
$0.04
Sensitivity to
10% Decrease
in Spend
Sensitivity to
10% Decrease
in Spend
1. Typical
ELL
bill
of
$95.93,
typical
EGSL
bill
of
$93.55
reflect
the
average
of
the
2011
Typical
Monthly
Bills
for
residential
customer
using
1,000 kWh, excluding taxes. Note: Calculation is indicative and illustrative of the rate effects of the spin-merge transaction and is not meant to
project an actual future customer bill.
40
1
1


41
41
ELL and EGSL face long-term generation supply
ELL and EGSL face long-term generation supply
needs driving significant capital requirements
needs driving significant capital requirements
Load growth and replacement of aging
capacity are anticipated to drive
generation capacity shortages
By 2021, EGSL is expected to be short 1.3GW in generation
capacity
By 2031, ELL and EGSL are expected to be short 2.7 GW and
2.3 GW, respectively
Even after Ninemile 6 enters service, additional generation
investment  required in Amite South and WOTAB
Aging generation needs to be replaced
Average age of the generating fleet  in Amite South is 42 years
By 2020, additional resources needed in Amite South about
every 5 years
Local generation resources needed
Unit life extension is not the long-term fix
Sustainability spending  ($180/kW to $250/kW) could extend the
useful life but such spending can only delay but not eliminate
the need to replace older generation
Resource needs for ELL
and EGSL could range
from $2.4B to $6.1B
over the 20 year
planning period –
this range reflects
uncertainty regarding
load growth, cost of new
capacity, and ability to
maintain sustainability
strategy 
1.2012$,
under
the
assumption
that
all
of
the
resource
needs
are
self-built,
gas-fired
CTs
and
CCGTs.
1
1


42
42
ITC transaction enables ELL and EGSL to
ITC transaction enables ELL and EGSL to
better meet generation capital needs
better meet generation capital needs
Transaction strengthens balance sheets for ELL and EGSL by reducing
debt and improving cash positions, which would allow ELL and EGSL –
jointly
or
separately
to
fund
more
resource
acquisitions
at
a
lower
cost
Transaction allows the EOCs to shed transmission-business-related cash
capital requirements and negative cash flows
With its higher credit quality and singular focus on transmission, ITC can
efficiently build new transmission that keeps pace with the ELL and EGSL's
expected future generation needs
ITC's independent business model and regional view of planning can
facilitate infrastructure investments and foster increased competition in
wholesale
electricity
markets
activities
which
will
increase
resource
options to address generation needs of ELL and EGSL customers
ELL and EGSL will have
increased capability to
finance Generation
investments
ITC can build
Transmission to
complement Generation
needs and create access
to resource options for
ELL & EGSL


43
43
Change in How Wholesale Rates are Determined Due to
Change in How Wholesale Rates are Determined Due to
Adoption of MISO's 12 CP Demand Methodology
Adoption of MISO's 12 CP Demand Methodology
Note:
Amount
paid
remains
the
same
because
the
customer
consumes
the
same
amount
of
transmission
service
in
both
methodologies.
The
methodology affects the units of measuring rates and the units of measuring consumption but the amount paid is same and is reflective of services
consumed
In both methodologies aggregate amount paid by customer consuming a certain
amount
of
Transmission
service
will
remain
the
same
43
Current  ETR OATT
ETR OATT with 12 CP
2014 Transmission Net Revenue Requirement
2014 Transmission Net Revenue Requirement
Same Revenue Requirement numerator
Same Revenue Requirement numerator
Same Revenue Requirement numerator
Same Revenue Requirement numerator
Single annual peak demand x 12 months
Aggregated 12 coincident peaks (CP) demand
over year
Single highest peak in a month x 12 months
Sum of peak demands in each month of year
Higher demand denominator
Lower demand denominator
$ 1.85 / kWm
$ 2.43 / kWm


44
44
Wholesale Rate Effects Reduced
Wholesale Rate Effects Reduced
for Louisiana Customers Post-Transition to MISO
for Louisiana Customers Post-Transition to MISO
Note:
Calculation
indicative
and
illustrative
is
not
meant
to
project
an
actual
future
customer
bill.
Estimates
are
preliminary
and
draft
prior
to
rate
filings
in first quarter of 2013
Wholesale rate
effects estimation
does not factor
in any production
costs savings and
other benefits to
be achieved
through transition
to MISO RTO
Rates
have
been
estimated
using
12
CP
methodology
used
under
MISO
Attachment
O.
Current
ETR
OATT
methodology
uses
a
single
annual
peak
rather
than
12
CP.
Change
in
methodology
does
not
imply
a
change
in
Revenue
Requirements
hence
customers do not pay different amounts under 12 CP employed by MISO vs. single annual peak employed by ETR. The
equivalent number to $2.43 /kWm under 12 CP would be a $1.85 /kWm under single annual peak. The per unit estimation may
be different but the amount paid by the customer is the same.
Illustrative
*
*
*
Includes estimated one-time rate
effect of ~$0.21 due to conversion to
forward
test
year
reflects
amounts
that would have been collected in
future years
Estimated 2014 Wholesale Transmission Rate Effects
***using 12 CP methodology***
($/kWm)
2.5
2.0
1.5
1.0
0.5
0.0
Estimated 2014 WS rates post
transition to MISO with 4
Transmission
Pricing
Zones
2.36
Estimated Net Rate Effect
of adopting default MISO
ROE and implementing 4
Transmission
Pricing
Zones
(0.07)
Estimated 2014 WS rates paid
under ETR OATT under One
Transmission Pricing Zone
2.43


45
45
45
Transaction-Related Filings Pending Before the
Transaction-Related Filings Pending Before the
Federal Energy Regulatory Commission
Federal Energy Regulatory Commission
Joint ITC/Entergy Corp/ESI/EOCs filing:
EC12-145-000
Transaction approval (FPA 203)
ER12-2681-000
Formula rate and related agreements approval (FPA 205)
EL12-107-000
Declaratory Order regarding dividend payments from capital
accounts (FPA 305)
ER12-2682-000
MISO
filing:
Module
B-1,
Interim
provisions
for
integration
of
the
transmission assets into MISO if Transaction closes before full
Entergy-MISO integration
ER12-2683-000
ESI
filing
on
behalf
of
EOCs:
Ancillary
services
tariff
(to
cover
potential period before MISO provision)
ER12-2693-000
ESI
filing
on
behalf
of
EOCs:
Amends
the
Entergy
System
Agreement to delete MSS-2 upon closing of the Transaction
ES13-5-000
ITC
filing:
Authorization
for
financing
(FPA
204)
ES13-6-000
ESI
filing
on
behalf
of
the
Wires
Subs:
Authorization
for    
financing
(FPA 204)
ES11-40-002
EOCs
filing:
Authorization
for
financing
(FPA
204)
1Q2013, ELL, EGSL, and the other EOCs will file MISO Attachment O formula rate
at the FERC to be effective in the event the ITC transaction is not consummated


46
46
46
2014 Rate Effect from ITC Transaction for
2014 Rate Effect from ITC Transaction for
Typical Louisiana Wholesale Customer –
Typical Louisiana Wholesale Customer –
Expected Mitigation by Customer Benefits
Expected Mitigation by Customer Benefits
Note:
Includes estimated one-
time rate effect of ~$0.21
due to conversion to
forward test year –
reflects
amounts that would have
been collected in future
years; excludes offsetting
depreciation study impact
of ~$0.12
Estimated LAU Wholesale Transmission Rate Effects
($/kWm)
(1)
Customer bill effects 
expected to be
mitigated by...
Operational Excellence –
Reliability, System
Performance, etc.
3
1
Credit Quality Impacts
0
(0.08)
0.14
Estimated ETR
Ownership in MISO *
2.36
2.41
2
Net Effect of
~$0.06 or 2.5%
ITC Ownership
4
Expected FERC Construct
Effects
* Reflects ETR transition into MISO including establishment of four transmission pricing zones
and 12.38% ROE
(1) Does not apply to GFA customers
Illustrative
Rate Construct
Effects from FERC
Regulated Model
Independent and 
Transparent ITC Model
Enhanced Financial   
Flexibility
 
   Regional Planning


47
47
Agenda
Agenda
Morning
Session
(10:00
am
12:30
pm)
Welcome
&
Logistics
10:00
10:15
Montelaro, Blair, Freese
Vision
for
Industry
Future
10:15
11:15
Welch, May
Why is this transformation necessary?
Why this structure?
Why with ITC?
Why now?
Rationale
for
Transaction
-
11:15
12:30
Independence
Welch
Operational
Excellence
Jipping,
Riley
Storm Response
Regional
Planning
Vitez
IPL
Transaction
Experience
&
Results
Jipping
Local Presence
&
Engagement
w/Retail
Regulators
Jipping
Financial
Flexibility
and
Growth
Lewis
Financial
Strength
of
ITC
Bready
Afternoon Session (1:00 pm –
4:00 pm)
Rate
Effects
1:00
2:30
Bready, Dingle, Lewis
ELL/EGSL Retail Customer Rate Effects
Rate Construct
Forward Test Year
Bill Effects
Any Potential Impacts on ELL/EGSL
Generation/Distribution Business 
Wholesale Rate Effects Post-MISO
Break –
2:30 –
2:45
Transaction Structure & ELL/EGSL Specific
Implications –
2:45 –
3:45
Bready, Lewis
Wrap Up –
3:45 –
4:00
Fontan, Freese
03/06/13
ITC, ELL & EGSL Technical Conference
ELL/EGSL
Credit
Ratings
Impacts
Securitization
Transaction
Impact
on
ADIT
Liability
Transaction
Structure


48
Transaction Overview
Transaction Overview
Entergy
Shareholders
Transmission
Business
$1,775M of new
debt will be raised
~$1.2B of the new
debt will be raised
at the transmission
operating companies
~$575M will be
raised directly by
Entergy and will be
subject to a debt-
for-debt exchange
with debt issued by
MidSouth TransCo
Mid South
TransCo
TransCo
OpCos
(Six)
Entergy will create
and distribute
shares of Mid South
TransCo to Entergy
shareholders
(Mid South TransCo
will own all of
Entergy’s
transmission
operating
companies upon
separation)
Immediately
prior to the
merger, ITC will
distribute $700M
to existing
shareholders,
funded by new
debt at ITC
Holdings
(Required to
align ITC’s
equity value with
that of the
Entergy
Transmission
Business)
ITC
Shareholders
Entergy
Shareholders
Mid South
TransCo
TransCo
OpCos
(Six)
Entergy
Shareholders
ITC
Shareholders
Merger Sub
Mid South TransCo will immediately merge
with ITC Merger Sub and will become a
wholly-owned subsidiary of ITC; Entergy
shareholders will receive 50.1% ownership in
the combined company
1
2
3
4
48


Post Spin-Merge
Post Spin-Merge
Transaction Structure
Transaction Structure
100%
Entergy
Shareholders
Mid South
TransCo LLC
OpCos
ITC
Shareholders
ITC
OpCos
49.9%
Note: Chart represents ownership structure immediately upon closing of the transaction.
49


50
50
50
$1.775B of Debt Proceeds Used to Retire Preferred
$1.775B of Debt Proceeds Used to Retire Preferred
and Pay Down Debt in Proportion to Transmission Assets
and Pay Down Debt in Proportion to Transmission Assets
The allocations for ELL and EGSL were
estimated in order to:
Retire all Preferred at each Operating
Company
Target a post-transaction weighted
average cost of capital (WACC) that is
substantially unchanged from the pre-
transaction WACC
EOC
Amount ($M)
EAI
502
EGSL
263
ELL
413
EMI
290
ENO
22
ETI
284
Total
1,775
The amount of debt proceeds allocated to
each EOC is an estimate based on a forecast
The final amounts allocated to each EOC
may vary to the extent forecast assumptions
differ from the circumstances that exist at
the time of closing. 
Source: Fourth Set of Data Requests of Marathon Petroleum Company, 4-17a and 4-22b


51
51
51
Comparable
equity
values
of
ITC
and
the
Entergy
Operating
Companies’
combined
T-business at this point
in time support execution of a Reverse Morris Trust
transaction structure where T-business is spun-off to existing ETR shareholders and
merged with ITC
Through
the
Reverse
Morris
Trust
Transaction
structure,
ELL
and
EGSL
will
not
incur
a
tax
liability
Under a taxable transaction, the tax basis of ELL and EGSL’s transmission assets
would
be
reset
and
Accumulated
Deferred
Income
Taxes
(“ADIT”)
would
be
re-
measured,
resulting
in
lower
balances
of
ADIT
and
higher
transmission
rate
base
Because ADIT ultimately lowers T-rates in cost of service ratemaking, re-measuring
ADIT would otherwise result in higher T-rates in a taxable transaction, all other
things being equal
As
a
result
of
the
RMT
transaction
structure,
ELL
and
EGSL’s
transmission
assets
will
have
the
same
tax
basis
post-transaction
as
they
had
prior
to
the
Transaction
Accordingly,
the
negative
rate
effects
for
customers
that
otherwise
would
have
resulted
from
a
change
in
tax
basis
under
a
taxable
transaction
are
avoided
RMT Structure Avoids Re-Measurement of ADIT Preserving
Tax Basis for ELL and EGSL and Protecting Customers
from Negative Rate Effects of a Taxable Transaction


52
52
Securitized Transmission Assets
Securitized Transmission Assets
Current Process:
Securitized
transmission
assets
are
carried
at
zero
book
value
by
EOCs
Recovery
of
these
securitized
transmission
assets
is
through
direct
charges
to
only
the
EOC’s
retail
customers
in
retail
rates
Adjustments
to
Entergy
OATT
(D17.1)
provides
for
recovery
of
System-wide
transmission
securitization
costs
from
wholesale
transmission
customers
Revenue
collected
from
these
adjustments
is
credited
by
the
EOC’s
in
retail
rates
so
retail
customers
only
pay
for
their
portion
of
these
securitized
transmission
assets
Post Spin/Merge:
Securitized
transmission
assets
transferred
to
ITC
at
zero
book
value
Recovery
of
these
securitized
transmission
assets
continues
through
direct
charges
to
only
the
EOC’s
retail
customers
in
retail
rates
New
Schedules
are
needed
in
MISO’s
tariff
to
provide
for
recovery
of
securitization
costs
from
wholesale
transmission
customers
(not
including
the
EOCs)
in
the
appropriate
TPZ
All
revenue
collected
by
MISO
for
these
new
schedules
will
be
remitted
to
the
EOCs
directly
for
crediting
in
retail
rates
so
retail
customers
only
pay
for
their
portion
of
these
securitized
transmission
assets


53
53
53
Louisiana Credit Metrics are Expected to be Maintained
Louisiana Credit Metrics are Expected to be Maintained
or Improved Through the Transaction
or Improved Through the Transaction
Direct Testimony of Expert Witness Dr. Michael Tennican
“…will reduce the Operating Companies' total debt and total capitalization...”
“...will eliminate substantial capital expenditures for transmission…”
“...will significantly reduce the Operating Companies' debt financing needs...”
"...should help support  the current bond ratings of the Operating
Companies...”
“...should reduce the interest costs that might have to be borne by Operating
Company customers...”
"...should not impair and may improve the Companies' current investment
grade credit ratings..."
"...should preserve access to debt capital on reasonable terms even in difficult
market conditions..."
Any potential credit ratings improvement for ELL or EGSL could result in
savings for Louisiana customers through lower cost of debt
1. Testimony of Dr. Michael Tennican before the LPSC, Docket U-32538


54
54
EEI Data:  54% of Utilities Ended at a
EEI Data:  54% of Utilities Ended at a
Lower Credit Grade in 2011 Compared to 2001
Lower Credit Grade in 2011 Compared to 2001
Cumulative % of Companies at Lower/Higher Rating
in 2011 Compared to 2001
54
Downgrades
No changes
Total
100
19
27
Upgrades
Source: EEI 2011 Q3 Credit Ratings Charts


55
55
55
Utility Bond Yields by
Credit Rating vs. Treasury
Bills (Ten-Year Average
Spreads)
-16
A2
155
Baa3
400
200
0
-25
-37
-149
129
Baa1
Baa2
171
208
Ba2
357
bps
Transaction Protects ELL and EGSL from
Transaction Protects ELL and EGSL from
Negative Impact to Credit Ratings
Negative Impact to Credit Ratings
Estimates are hypothetical forecasts to illustrate effect on cost of debt and
benefits to customers  –
exact values will depend on market conditions
Current ELL
and EGSL
credit ratings
at Baa2
Transaction
protects ELL from
credit downgrade
risk; one-notch
hypothetical
downgrade could
increase cost of
debt by 37 bps
Transaction
protects ELL from
credit downgrade
which could cost
customers
~$9.9M
in additional
interest costs
from 2014-2018
Transaction
protects EGSL from
credit downgrade
risk; one-notch
hypothetical
downgrade could
increase cost of
debt by 37 bps
Transaction
protects EGSL from
credit downgrade
which could cost
customers
~$4.1M
in additional
interest costs
from 2014-2018
Source: Bloomberg Fair Value 10-year credit ratings for utilities.
Illustrative


56
56
Agenda
Agenda
Morning Session (10:00 am –
12:30 pm)
Welcome & Logistics –
10:00 –
10:15
Montelaro, Blair, Freese
Vision
for
Industry
Future
10:15
11:15
Welch, May
Why is this transformation necessary?
Why this structure?
Why with ITC?
Why now?
Rationale
for
Transaction
-
11:15
12:30
Independence
Welch
Operational
Excellence
Jipping,
Riley
Storm Response
Regional
Planning
Vitez
IPL
Transaction
Experience
&
Results
Jipping
Local Presence
Financial
Flexibility
and
Growth
Lewis
Financial
Strength
of
ITC
Bready
Afternoon Session (1:00 pm –
4:00 pm)
Rate
Effects
1:00
2:30
Bready, Dingle, Lewis
ELL/EGSL Retail Customer Rate Effects
Rate Construct
Forward Test Year
Bill Effects
Any Potential Impacts on ELL/EGSL
Generation/Distribution Business 
Wholesale Rate Effects Post-MISO
Break –
2:30 –
2:45
Transaction Structure & ELL/EGSL Specific
Implications –
2:45 –
3:45
Bready, Lewis
Wrap Up –
3:45 –
4:00
Fontan, Freese
03/06/13
ITC, ELL & EGSL Technical Conference
Transaction Structure
Transaction Impact on ADIT Liability
Securitization
ELL/EGSL Credit Ratings Impacts
& Engagement
w/Retail
Regulators
Jipping