Edgar Filing: ENTERGY CORP /DE/

425

ITC/EAI

Technical Conference

December 17, 2012

Transmission Business

Filed

Entergy

Corporation

Pursuant

Rule

425

Under

the

Securities

Act

1933

Subject

Company:

Entergy

Corporation

Commission

File

No.

001-11299

Entergy Forward-Looking Information

this

communication,

and

from

time

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 Annual Report on Form 10-K for the year ended December 31, 2011, its Quarterly Reports on

Form

10-Q for the quarters ended March 31, 2012, June 30, 2012 and September 30, 2012, and other filings made by

Entergy with the Securities and Exchange Commission (the “SEC”); (ii) the following transactional factors (in

addition

others

described

elsewhere

this

communication,

the

preliminary

proxy

statement/prospectus

included in the registration statement on Form S-4 that ITC filed with the SEC on September 25, 2012 in

connection with the proposed transactions, and in subsequent securities filings) 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

consummating

the

transaction

the

failure

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.

ITC Forward-Looking Information

This document and the exhibits hereto contain certain statements that describe ITC Holdings Corp. (“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 annual report on Form 10-K and

ITC’s quarterly reports on Form 10-Q filed with the Securities and Exchange Commission (the “SEC”) from time to time and (b)

the following transactional factors (in addition to others described elsewhere in this document, in the preliminary proxy

statement/prospectus included in the registration statement on Form S-4 that ITC filed with the SEC on September 25, 2012 in

connection with the proposed transactions, and in subsequent filings with the SEC): (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.

Additional Information and Where to Find It

On September 25, 2012, ITC filed a registration statement on Form S-4 (Registration No. 333-184073) with the

SEC registering shares of ITC common stock to be issued to Entergy shareholders in connection with the

proposed

transactions,

but

this

registration

statement

has

not

become

effective.

This

registration

statement

includes a proxy statement of ITC that also constitutes a prospectus of ITC, and will be sent to ITC

shareholders.

In addition, Mid South TransCo LLC (TransCo) will file a registration statement with the SEC

registering 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 proxy statement/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. 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. The proxy

statement/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 2011 Annual Report on Form 10-K filed with the SEC on

February 28, 2012, 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 2011 Annual Report on Form 10-K filed with the SEC on February 22, 2012, and its definitive proxy

statement relating to its 2012 Annual Meeting of Shareholders filed with the SEC on April 12, 2012.

Agenda

Morning Session (9:30 am –

12:00 pm)

Welcome & Logistics

Vision for Industry Future

•

Strategic Overview By EAI and Entergy Corporation

•

Strategic Overview By ITC

Rate Effects

•

EAI Retail Customer Rate Effects

–

Rate Construct

–

Forward Test Year

–

Bill Effects

•

Any Potential Impacts on EAI

Generation/Distribution Business

•

Wholesale Rate Effects Post-MISO

•

Rate Effects for Co-Ops and Munis Currently

Taking Transmission Service from EAI

Afternoon Session (12:30 pm –

5:00 pm)

Rationale for Transaction

•

Independence

•

Operational Excellence

–

Storm Response

•

Regional Planning

•

IPL Transaction Experience & Results

•

Financial Flexibility and Growth

•

Financial Strength of ITC

Transaction Structure & EAI Specific Implications

Transaction Assets and Value

Wrap Up

•

Transaction Structure

•

Debt Issuance/Retirement of EAI Debt

•

Pre/Post Transaction Capital Structure

•

Transaction Impact on ADIT Liability

•

Other Tax Benefits

•

EAI Credit Ratings Impacts

•

Other Impacts for EAI

•

Entergy T-Asset & EAI T-Asset Value

•

Other Transaction Mechanics

•

Significant capital requirements to continue modernizing the grid best handled by

an independent operator who can better manage the transmission portion of

capital spend

•

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

•

Familiarity

with

MISO

and

committed

facilitating

the

MISO

Day

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 towards dispatching ETR owned resources

•

Comparable

sizes

ITC's

and

the

EOCs’

(Entergy

Operating

Companies)

transmission businesses allows for a tax efficient transaction not necessarily

available in future

ITC Transaction is the Right Transaction

with the Right Partner at the Right Time

The right

transaction...

...with the

right

partner...

at the right

time

U.S. Transmission Grid –

Historically Fragmented and Inefficient

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

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,…

•

Introduction

•

Industry Evolution

•

ITC’s Business Model

•

ITC’s Proven Track Record

•

Benefits Beyond MISO

•

Transaction Value for Arkansas

Strategic Overview

ITC

Agenda

Morning

Session

(9:30

–

12:00

pm)

Welcome & Logistics

Vision for Industry Future

•

Strategic Overview By EAI and Entergy Corporation

•

Strategic Overview By ITC

Rate Effects

•

EAI Retail Customer Rate Effects

–

Rate Construct

–

Forward Test Year

–

Bill Effects

•

Any Potential Impacts on EAI

Generation/Distribution Business

•

Wholesale Rate Effects Post-MISO

•

Rate Effects for Co-Ops and Munis Currently

Taking Transmission Service from EAI

Afternoon

Session

(12:30

–

5:00

pm)

Rationale for Transaction

•

Independence

•

Operational Excellence

–

Storm Response

•

Regional Planning

•

IPL Transaction Experience & Results

•

Financial Flexibility and Growth

•

Financial Strength of ITC

Transaction Structure & EAI Specific Implications

•

Transaction Structure

•

Debt Issuance/Retirement of EAI Debt

•

Pre/Post Transaction Capital Structure

•

Transaction Impact on ADIT Liability

•

Other Tax Benefits

•

EAI Credit Ratings Impacts

•

Other Impacts for EAI

Transaction Assets and Value

•

Entergy T-Asset & EAI T-Asset Value

•

Other Transaction Mechanics

Wrap Up

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.

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

Henry Hub Gas Index ($/mmBtu))

EAI Avg. Monthly Residential Bill-

1,000 kWh($)

150

100

-13%

2011

94.23

2010

97.78

2009

108.00

2008

97.81

2007

95.15

2006

98.17

2005

90.25

2004

73.15

2003

83.28

2002

87.65

2001

93.53

13% reduction in

customer bills since

2009

Henry Hub Gas Index

Significant Variability in Average Residential Bills –

Yearly Variation Between $3 and $17 Over 2001-2011

+17.10

(+23%)

(+3%)

+2.67

EAI

Avg.

Monthly

Residential

Bill

1,000

kWh($)

Typical EAI Customer Bill

4.3%

Transmission

Non-Transmission

95.7%

Transmission Constitutes a Small Portion

of a Typical EAI Customer's Total Bill

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.

•

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

credit

quality

improvement

resulting

from

transition

FERC-

regulated rate construct partially offset ROE and capital structure impacts

Rate Impacts Split into Rate Construct, Rate Timing,

and Other Effects for Retail Customers

Rate

Construct

Effects

Rate

Timing

Effects

•

Forward

Test

Year:

Eliminates

regulatory

lag

recovery

capital

investments

•

One time impact of conversion to forward test year

•

Reflects amounts that would have been collected in future years

•

Current

estimation

reflects

effect

paying

load

ratio

Transmission

cost factoring in zonal investment (single AR zone) and retail share of

Transmission investments

Other Effects

~1.22

1.3%

Illustrative Bill

if ITC owns

T assets –

post-

transaction

~95.45

2014

Net Other

Effects

~0.00

2014

WACC

Effects

~1.22

Illustrative

Bill if ETR

owns

T assets –

status quo

94.23

EAI

Residential

Bill

–

1,000

kWh

($)

110

100

Note:

$94.23

the

average

the

2011

Typical

Monthly

Bill

for

residential

customer

using

1,000

kWh,

excluding

taxes.

Calculation

indicative

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.

Note:

Contents exclude estimated

one-time 2014 rate timing

effect of $0.51 due to

conversion to forward test

year –

reflects amount that

would have been collected in

future years

EAI Typical Residential Customer Bill

Modest

Increase

2014

1.3%

–

Expected

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

Modest Effects of 1.2 –

1.5%

Select Commercial and Industrial Classes –

Expected Mitigation by Customer Benefits

2014 Transaction Bill Effects –

Retail

Selected

Retail

Classification

Retail Class

Description

Typical

Bill

WACC

Effects

Net

Other

Effects

Total

Effect

Change

EAI

SGS

25 kW, 25% Load Factor

$408.91

4.96

0.00

4.96

1.2%

LGS

250 kW, 55% Load Factor,

Summer

$7,241.79

110.32

0.00

110.32

1.5%

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

conversion

forward

test

year

–

reflects

amount

that

would

have been collected in future years. Based on August 2011 typical customer bill.

EAI

–

$94.23

Sensitivity of Rate Effects

to Variations in Spend

EAI

–

$94.23

+ $0.12

O&M

Spend

Typical

EAI

bill

$94.23

represents

the

average

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.

+ $0.04

Capital

Expenditure

Spend

Typical Monthly

Residential

Bill

Sensitivity to

10% Increase

in Spend

$1.22

Total

Transaction

Bill Effect

Typical Monthly

Residential

Bill

Sensitivity to

10% Increase

in Spend

Total

Transaction

Bill Effect

$0.12

$0.04

Sensitivity to

10% Decrease

in Spend

Sensitivity to

10% Decrease

in Spend

Change in How Wholesale Rates are Determined Due to

Adoption of MISO's 12 CP Demand Methodology

$ 1.85 / kWm

$ 2.43 / kWm

In both methodologies aggregate amount paid by customer consuming a certain

amount

Transmission

service

will

remain

the

same

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

Current ETR

OATT

2014 Transmission

Net Revenue Requirement

Single

annual peak demand x 12 months

ETR OATT with 12 CP

2014 Transmission

Net Revenue Requirement

Aggregated 12 coincident peaks (CP) demand

over

year

Same

Revenue Requirement numerator

Sum

of peak demands in each month of year

Same

Revenue Requirement numerator

Lower

demand

denominator

Same

Revenue Requirement numerator

Single highest

peak in a months x 12 months

Same

Revenue Requirement numerator

Higher demand denominator

Wholesale Rate Effects Reduced

for EAI Customers Post Transition to MISO

2.5

2.0

1.5

1.0

0.5

0.0

2.41

Estimated Net Rate Effect

of adopting default MISO

ROE and implementing 4

Transmission Pricing Zones

(0.02)

Estimated 2014 WS rates

paid under ETR OATT

under One Transmission

Pricing Zone

2.43

Estimated 2014 Wholesale Transmission Rate Effects

***using 12 CP methodology***

($/kWm)

Note: Calculation

indicative

and

illustrative

not

meant

project

actual

future

customer

bill.

Estimates

are

preliminary

and

draft

prior

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

Illustrative

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.

Estimated 2014 WS rates

post transition to MISO

with 4 Transmission

Pricing Zones

Transaction-Related Filings Pending Before the

Federal Energy Regulatory Commission

Joint ITC/Entergy Corp/ESI/EOCs filing:

Transaction approval (FPA 203)

Formula rate and related agreements approval (FPA 205)

Declaratory Order regarding dividend payments from capital

accounts (FPA 305)

ESI

filing

behalf

EOCs:

Ancillary

services

tariff

(to

cover

potential period before MISO provision)

ESI

filing

behalf

EOCs:

Amends

the

Entergy

System

Agreement to delete MSS-2 upon closing of the Transaction

ITC

filing:

Authorization

for

financing

(FPA

204)

ESI

filing

behalf

the

Wires

Subs:

Authorization

for

(FPA 204)

EOCs

filing:

Authorization

for

financing

(FPA

204)

1Q2013, EAI and other EOCs will file MISO Attachment O formula rate at the FERC

to be effective in the event the ITC transaction is not consummated

MISO

filing:

Module

B1,

Interim

provisions

for

integration

the

transmission assets into MISO if Transaction closes before full

Entergy-MISO integration

EC12-145-000

ER12-2681-000

EL12-107-000

ER12-2682-000

ER12-2683-000

ER12-2693-000

ES13-5-000

ES13-6-000

financing

ES11-40-002

financing

2014 Rate Effect from ITC Transaction for

Typical Arkansas Wholesale Customer –

Expected Mitigation by Customer Benefits

Note:

Excludes estimated one-

time rate effect of ~$0.16

due to conversion to

forward test year –

reflects

amounts that would have

been collected in future

years

* Reflects ETR transition into MISO including establishment of four transmission

pricing zones and 12.38% ROE

(1) Does not apply to GFA customers

Illustrative

Estimated EAI Wholesale Transmission Rate Effects

($/kWm)

(1)

Expected FERC Construct

Effects

$2.41

$2.61

-$0.08

$0.28

Net effect of

~$0.20 or ~8.1%

Customer bill effects

expected to be

mitigated by...

•

Operational Excellence

–

Reliability, System

Performance, etc.

•

Independent and

Transparent ITC Model

•

Enhanced Financial

Flexibility

•

Regional Planning

Agenda

Morning Session (9:30 am

–

12:00 pm)

Welcome & Logistics

Vision for Industry Future

•

Strategic Overview By EAI and Entergy Corporation

•

Strategic Overview By ITC

Rate Effects

•

EAI Retail Customer Rate Effects

–

Rate Construct

–

Forward Test Year

–

Bill Effects

•

Any Potential Impacts on EAI

Generation/Distribution Business

•

Wholesale Rate Effects Post-MISO

•

Rate Effects for Co-Ops and Munis Currently

Taking Transmission Service from EAI

Afternoon

Session

(12:30

–

5:00

pm)

Rationale for Transaction

•

Independence

•

Operational Excellence

–

Storm Response

•

Regional Planning

•

IPL Transaction Experience & Results

•

Financial Flexibility and Growth

•

Financial Strength of ITC

Transaction Structure & EAI Specific Implications

Transaction Assets and Value

Wrap Up

•

Transaction Structure

•

Debt Issuance/Retirement of EAI Debt

•

Pre/Post Transaction Capital Structure

•

Transaction Impact on ADIT Liability

•

Other Tax Benefits

•

EAI Credit Ratings Impacts

•

Other Impacts for EAI

•

Entergy T-Asset & EAI T-Asset Value

•

Other Transaction Mechanics

Transaction Rationale:

In the Public Interest

Independent model

•

Singular focus

•

Transaction

results

two

companies

that

are

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

finance

the

infrastructure

investment

requirements

today

and

the

future

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

Independent Model

Benefits of ITC Independent

Transmission Model

Operational

Excellence

Transparency

Infrastructure

Investment

High Credit

Quality

Public Policy

Alignment

Facilitate Generator

Interconnection

Customer

Focus

Reliability

•

Data from the SGS Study benchmarking study can be used to

quantify the resulting improved reliability

Operational Excellence:

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.

•

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

ITC

Transmission

and

METC

results in one year savings of $7.7M

•

Compared to the performance of the median utility in the SGS Study,

this

amounts

value

about

$153

million

per

year

delivered

ITC’s Michigan utilities

•

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

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)

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

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

•

Timely customer communication

–

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

Storm Response –

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

EAI

Customer

ITC Planning

Section

ITC Logistics

Section

ITC Resource

Section

Transmission Prioritization

Resource Coordination

Logistics Coordination

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’s transmission planners develop transmission system reinforce-

ments to address those deficiencies

•

ITC is committed to planning its transmission system in an open and

transparent manner. As such, ITC has its own processes that supple-

ment the already-robust 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

IPL Transaction Experience & Results

•

ITC has invested approximately $1.1 billion to improve the ITC

Midwest transmission system since acquisition of IPL assets

–

Primarily needed to upgrade and improve existing lines and substations,

construct new lines to serve load growth and improve reliability, 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

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

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

ETR Utilities’

Capital Needs

Could Total ~$13B-16B Over 2012-2018

Actual and Forecast Entergy Utilities Investment

($B)

1999-2004

2005-2011

2012-2018

Projected base capital plan as of August 2012

Past storm capital

Actual excluding storms

Potential spend

Average

= $1.9B -

$2.3B

Total = $13.0B -

$15.8B

Average

= $1.4B -

$1.7B

Total = $9.7B -

$11.7B

Average

= $1.1B

Total = $6.5B

???

Effect of EPA rules?

Aging infrastructure?

1. Range

based

actuals

plus

storm

capital.

Range

based

projections

ETR

Utilities’

base

capital

plan

plus

potential

spend

Potential

spend

potential

economic

development

projects,

potential

new

generation

investment,

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.

EAI Total Capital Needs Could Total

~$3.4B -

$3.7B Over 2012-2018

Actual and Forecast Capital Investment

for EAI ($B)

1999-2004

2005-2011

2012-2018

Actual excluding storms

Potential spend

Base case -

conservative

Past storm spend

Average

= $492M -

$523M

Total = $3.4B -

$3.7B

Average

= $316M -

$342M

Total = $2.2B -

$2.4B

Average

= $295M

Total = $1.8B

???

Effect of EPA rules?

Aging infrastructure?

1. Range based on actuals plus storm capital. 2. Range based on projections of EAI’s base capital plan plus potential spend 3. Potential spend

related to potential economic development projects, potential new generation investment, 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: 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’

Transmission Capital

Could Total ~$3.5B Over 2012-2018

Average = $254M

Total = $1.8B

Average= $502M

Total = $3.5B

Actual and Forecast Transmission Investment for EOCs

($B)

2005-2011

1999-2004

2012-2018

Projected base case capital

plan as of August 2012

Actual

Average= $200M

Total = $1.2B

Transmission Capital Spending for EOCs Could Increase

Nearly 100% in the Next Seven Years

Note: Historical data excludes storm capital, as there is no capital associated with future storms in base capital plan projections.

EAI Transmission Capital

Could Total ~$1B Over 2012-2018

Average = $61M

Total = $429M

Average= $137M

Total = $962M

Actual and Forecast Transmission Investment for EAI

($M)

1,000

400

1999-2004

2005-2011

800

2012-2018

200

600

Average= $53M

Total = $319M

Transmission Capital Spending for EAI Could Increase

Nearly 124% in the Next Seven Years

Projected base case capital

plan as of August 2012

Actual

EAI Transmission CapX as Multiple of Depreciation

More Than Twice as High as Non-Transmission

EAI Average CapX as Multiple of Depreciation

(2012-18 Average)

1.6

3.8

Transmission

Non-

Transmission

For EAI,

Transmission

Constitutes ~43% of

Capital in Excess of

Depreciation, despite

being 17% of rate

base

Note: Based on figures filed in testimony at APSC

Benefits from

Financial Flexibility for Entergy

Utility Operating Cash Flow Minus

Cash Construction Expenditures

2014E –

2018E; $B

Status Quo

With ITC

Transaction

Utility Debt Obligations

2018E; $B

Status Quo

With ITC

Transaction

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

EOCs

positive

transmission

Cash

Construction

Expenditures

over

2014-2018

higher

than

transmission

OCF

Stronger Utility Balance Sheet Improves Ability

to Invest in Generation and Distribution

4.34

5.20

20%

$2.7B

Transmission-Related Cash

Capital Requirements Go

Away

Benefits from Financial Flexibility for EAI

Transmission-Related Cash

Capital Requirements Go

Away

EAI Operating Cash Flow Minus

Cash Construction Expenditures

2014E –

2018E; $M

Status Quo

With ITC

Transaction

EAI Debt Obligations

2018E; $M

Stronger Balance Sheet Improves Ability

to Invest in Generation and Distribution

Status Quo

With ITC

Transaction

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

EOCs

positive

transmission

Cash

Construction

Expenditures

over

2014-2018

higher

than

transmission

OCF

400

200

800

600

1,000

2,000

1,000

3,000

57%

$801M

Financial Strength and Flexibility

•

Transaction offers the financial strength of ITC and improves that of EAI 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 Arkansas

—

Post-close, EAI would be better positioned to attract capital separately to finance

needed

investments

generation

and

distribution

lower

costs

and

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 EAI, 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

Credit Quality Enhancement Overview

Debt Cost Savings

–

FERC rate construct utilized by ITC’s operating companies viewed favorably by the

rating agencies and investors, which supports lower funding costs

–

ITC is seeking FERC rate construct for its new operating companies as part of this

transaction

–

Results in lower borrowing costs of approximately 55 bps to 195 bps relative to the

status quo EOCs, depending on market conditions

–

Reflected in both the initial capitalization of the new ITC operating companies,

including ITC Arkansas, 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 cost savings for the new ITC

operating companies in a range of approximately $125 million to $156 million (in

nominal dollars)

•

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

Agenda

Morning

Session

(9:30

–

12:00

pm)

Welcome & Logistics

Vision for Industry Future

•

Strategic Overview By EAI and Entergy Corporation

•

Strategic Overview By ITC

Rate Effects

•

EAI Retail Customer Rate Effects

–

Rate Construct

–

Forward Test Year

–

Bill Effects

•

Any Potential Impacts on EAI

Generation/Distribution Business

•

Wholesale Rate Effects Post-MISO

•

Rate Effects for Co-Ops and Munis Currently

Taking Transmission Service from EAI

Afternoon

Session

(12:30

–

5:00

pm)

Rationale for Transaction

•

Independence

•

Operational Excellence

–

Storm Response

•

Regional Planning

•

IPL Transaction Experience & Results

•

Financial Flexibility and Growth

•

Financial Strength of ITC

Transaction Assets and Value

•

Entergy T-Asset & EAI T-Asset Value

•

Other Transaction Mechanics

Wrap Up

•

Transaction Structure

•

Debt Issuance/Retirement of EAI Debt

•

Pre/Post Transaction Capital Structure

•

Transaction Impact on ADIT Liability

•

Other Tax Benefits

•

EAI Credit Ratings Impacts

•

Other Impacts for EAI

Transaction Structure & EAI Specific Implications

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

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

OpCos

(Six)

Entergy

Shareholders

ITC

Shareholders

Merger Sub

ITC Merger Sub will then immediately merge

with the Mid South TransCo, and Entergy

shareholders will receive 50.1% ownership in

the combined company

Post Spin-Merge

Transaction Structure

100%

Entergy

Shareholders

Mid South

TransCo LLC

OpCos

ITC

Shareholders

ITC

OpCos

49.9%

$1.775B of Debt Proceeds Used to Retire Preferred

and Pay Down Debt in Proportion to Transmission Assets

For EAI, the amounts will be undertaken

to maintain the targeted capital structure

outlined in EAI’s last rate case, docket

09-084-U maintaining the Total Equity

Percentage at around 46% pre and post

transaction

For the remaining EOCs, the allocations

were estimated to target a post-

transaction WACC for each EOC that is

substantially unchanged from the pre-

transaction weighted average cost of

capital.

EOC

Amount ($M)

EAI

502

EGSL

263

ELL

413

EMI

290

ENO

ETI

284

Total

1,775

1.Based on May 2012 OATT filings 2. Based on August 2012 Projected Estimates for T-assets to be spin-merged at time of transaction

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.

EAI will Target to Maintain Capital Structure in Line with

APSC Rate-Making Guidelines Substantially the Same

Pre-

and Post-Transaction

APSC Staff Methodology

and Guidelines

Preferred treated as equity in capital structure

54% -

46% debt to equity ratio in capital structure

Preferred and Debt in proportion to Transmission assets for EAI will be

retired such that the 54% -

46% debt to equity ratio will be maintained

Pre-Transaction

% of Cap

Struct

Common

Equity

43%

Preferred

Debt

54%

Post-Transaction

% of Cap

Struct

Common

Equity

46%

Preferred

Debt

54%

46%

Other EOCs will retire debt and preferred in order to keep WACC approximately

the same pre-

and post-transaction

All EAI Credit Metrics are Expected

to Improve Through the Transaction

1. Testimony of Dr. Michael Tennican before the APSC, Docket 12-069-U

Direct Testimony of Expert Witness Dr. Michael Tennican

•

“…will

reduce

EAl’s

total

debt

and

total

capitalization...”

•

“...will

eliminate

substantial

capital

expenditures

for

transmission…”

•

“...will

reduce

EAl‘s

debt

financing

needs...”

•

“...will

strengthen

EAl’s

credit

metrics…”

•

should

help

retain

EAl’s

current

investment-grade

rating...”

•

“...should

reduce

the

interest

costs

that

would

have

borne

EAl’s

customers...”

•

“...should

facilitate

EAI's

access

debt

capital

even

difficult

market

conditions...”

“...all of the credit metrics used by both Moody’s and S&P are

enhanced by the Transaction...”

Any potential credit ratings improvement for EAI could result in

savings for EAI customers through lower cost of debt

EEI Data: 54% of Utilities Ended at a

Lower Credit Grade in 2011 Compared to 2001

Cumulative % of Companies at Lower/Higher Rating

in 2011 Compared to 2001

Downgrades

No changes

Total

100

Upgrades

Source: EEI 2011 Q3 Credit Ratings Charts

Transaction

protects EAI from

credit downgrade

which could cost

customers

in additional

interest costs

from 2014-2018

Utility Bond Yields by Credit

Rating vs. Treasury Bills

(Ten-Year Average Spreads)

-16

155

Baa3

400

200

-25

-37

-149

129

Baa1

Baa2

171

208

Ba2

357

bps

Transaction Protects EAI from

Negative Impact to Credit Ratings

Estimates are hypothetical forecasts to illustrate effect on cost of debt and

benefits

customers

–

exact

values

will

depend

market

conditions

Source: Bloomberg Fair Value 10-year credit ratings for utilities.

Current EAI

credit rating at

Baa2

Transaction

protects EAI from

credit downgrade

risk; one notch

hypothetical

downgrade could

increase cost of

debt by 37 bps

•

Comparable

equity

values

ITC

and

the

Entergy

Operating

Companies’

combined

T-business at this point

in time enable 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,

EAI

will

not

incur

tax

liability

•

Under a taxable transaction, the tax basis of EAI’s transmission assets would be

reset

and

Accumulated

Deferred

Income

Taxes

(“ADIT”)

would

re-measured,

resulting in lower balances of ADIT

•

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

•

result

the

RMT

transaction

structure,

EAI’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

change

tax

basis

under

taxable

transaction

are

avoided

RMT Transaction Structure Avoids Re-Measurement of

ADIT Preserving Tax Basis for EAI and Protecting Customers

from Negative Rate Effects of a Taxable Transaction

Morning Session (9:30 am –

12:00 pm)

Welcome & Logistics

Vision for Industry Future

Strategic Overview By EAI and Entergy Corporation

Strategic Overview By ITC

Rate Effects

EAI Retail Customer Rate Effects

Rate Construct

Forward Test Year

Bill Effects

Any Potential Impacts on EAI

Generation/Distribution Business

Wholesale Rate Effects Post-MISO

Rate Effects for Co-Ops and Munis Currently

Taking Transmission Service from EAI

Agenda

Afternoon Session (12:30 pm –

5:00 pm)

Rationale for Transaction

Independence

Operational Excellence

Storm Response

Regional Planning

IPL Transaction Experience & Results

Financial Flexibility and Growth

Financial Strength of ITC

Transaction Structure & EAI Specific Implications

Transaction Structure

Debt Issuance/Retirement of EAI Debt

Pre/Post Transaction Capital Structure

Transaction Impact on ADIT Liability

Other Tax Benefits

EAI Credit Ratings Impacts

Other Impacts for EAI

Transaction Assets and Value

Entergy T-Asset & EAI T-Asset Value

Other Transaction Mechanics

Wrap Up

Net Transmission Assets Being Transferred to ITC

(Estimated/Forecasted Values as of December 31, 2013)

EOC

$B *

EAI

0.8

EGSL

0.5

ETI

0.5

ELL

0.7

EMI

0.5

ENO

0.0

Total

3.2

The level of net assets at each

Entergy Operating Company is an

estimate based on a forecast.

Net asset estimates are based on the

Entergy Operating Company base

capital plan forecasts.

The final amounts at each Entergy

Operating Company may vary to the

extent forecast assumptions differ

from the circumstances that exist at

the time of closing.

Net Transmission Assets include net plant assets and liabilities

* Dollars rounded to billions

and may not add due to rounding

•

ITC’s financial advisors, JP Morgan and Barclays, as well as Entergy’s financial advisor, Goldman

Sachs, have each rendered fairness opinions regarding the value of the transaction

•

Ultimately,

the

assessment

whether

the

transaction

fair

was

based

relative

value

analysis

Other Transaction Considerations

Merger

Considerations

Transaction

Mechanics

Goodwill

Party

Valuation

•

ITC

stock

will

issued

Entergy

shareholders

exchange

for

their

the

Entergy

Transmission Business in a stock-for-stock merger

–

Sufficient shares issued for Entergy shareholders to own 50.1% of the combined business

•

ITC will also assume $1.775 billion of debt to be issued by Entergy Transmission Business

•

Immediately prior to close, ITC will effectuate a $700 million recapitalization to align ITC’s equity

value with that of Entergy’s Transmission Business

•

Post-recapitalization, the number of shares issued to Entergy shareholders will be determined by

the exchange ratio which can generally be calculated by multiplying (i) ~1.0x by (ii) the # of ITC

shares on an agreed upon date approximately 20 trading days prior to close

•

Goodwill will be calculated as the difference between the consideration transferred at closing and the

fair

value

net

assets

acquired

and

liabilities

assumed

•

not

possible

exactly

estimate

goodwill

closing

depends

the

following

variables:

–

ITC's stock price at closing

–

The exact # of shares to be issued to Entergy shareholders at closing

–

The fair value of the net assets acquired and liabilities assumed at closing

•

Irrespective

the

amount

goodwill

estimated

closing,

ITC

will

not

seek

recovery

any

goodwill

associated with the transaction

•

Customer rates will in no way be impacted by any goodwill associated with the transaction

* Please

refer

the

Merger

Agreement

dated

December

2011

for

additional

detail

Agenda

Morning

Session

(9:30

–

12:00

pm)

Welcome & Logistics

Vision for Industry Future

•

Strategic Overview By EAI and Entergy Corporation

•

Strategic Overview By ITC

Rate Effects

•

EAI Retail Customer Rate Effects

–

Rate Construct

–

Forward Test Year

–

Bill Effects

•

Any Potential Impacts on EAI

Generation/Distribution Business

•

Wholesale Rate Effects Post-MISO

•

Rate Effects for Co-Ops and Munis Currently

Taking Transmission Service from EAI

Afternoon

Session

(12:30

–

5:00

pm)

Rationale for Transaction

•

Independence

•

Operational Excellence

–

Storm Response

•

Regional Planning

•

IPL Transaction Experience & Results

•

Financial Flexibility and Growth

•

Financial Strength of ITC

Transaction Structure & EAI Specific Implications

Transaction Assets and Value

Wrap Up

•

Transaction Structure

•

Debt Issuance/Retirement of EAI Debt

•

Pre/Post Transaction Capital Structure

•

Transaction Impact on ADIT Liability

•

Other Tax Benefits

•

EAI Credit Ratings Impacts

•

Other Impacts for EAI

•

Entergy T-Asset & EAI T-Asset Value

•

Other Transaction Mechanics