Edgar Filing: ITC Holdings Corp.

Filed by ITC Holdings Corp. Pursuant to Rule 425 under the

Securities Act of 1933 and deemed filed pursuant

to Rule 14a-12 under the Securities Exchange Act of 1934

Subject Company: ITC Holdings Corp.

Commission File No. 001-32576

ITC/EMI Technical Conference March 7, 2013 Transmission Business

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. .

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.

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.

Agenda 03/07/13 ITC/EMI Technical Conference Transaction Structure & EMI Specific Implications – 11:00 – 12:30 Bready, Lewis Transaction Structure EMI credit impact & debt issuance/retirement Pre/Post Transaction Capital Structure Transaction Impact on ADIT Liability EMI Credit Ratings Impacts Lunch– 12:30 – 1:15 Afternoon Session (1:15 pm – 4:00 pm) Rate Effects 1:15 – 3:15 Bready, Lewis EMI Retail Customer Rate Effects Rate Construct Forward Test Year Bill Effects Any Potential Impacts on EMI Generation/Distribution Business Wholesale Rate Effects Post-MISO Wrap Up – 3:15 – 4:00 Grenfell Morning Session (8:00 am – 12:30 pm) Welcome & Logistics – 8:00 – 8:15 Fisackerly, Whitelocke Transformation Vision – 8:15 – 9:15 Welch, Bunting, Fisackerly Why is this transformation necessary? Why this structure? Why with ITC? Why now? Why for EMI? Rationale for Transaction - 9:15 – 11:00 Independence Welch Operational Excellence Jipping, Riley Storm Response Regional Planning Vitez IPL Transaction Experience & Results Jipping Local Presence & Engagement w/Retail Regulators Jipping Break – 15 mins Financial Flexibility and Growth Lewis Financial Strength of ITC Bready

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 with the Right Partner at the Right Time

U.S. Transmission Grid – 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 Europe, Australia, etc established independent transmission ownership and operation as the cornerstone of market reform 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 kV 115 138 161 230 345 500

“you may well expect to see an ultimate industry structure whereby the electric grid is separated, heavily regulated, treated as a natural monopoly” --J. Wayne Leonard, presentation to DOE (1996) “Mr. Leonard also said he wants to sell [Entergy’s] transmission system if it could be folded into a ‘transmission company,’ one genre of a company that is being considered in a restructured electric industry.” --The Wall Street Journal (1998) “A transmission organization that’s incentivized to maximize access will promote competitive markets and create the greatest value for consumers of electric power.” --J. Wayne Leonard, World Energy (1999) “Since 1998, Entergy has supported and pursued the establishment of an independent entity to operate the Entergy transmission system.” --J. Wayne Leonard, Letter to FERC Commissioners (2004)

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 ITC

Transaction Rationale: 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

Data from the SGS Study benchmarking study can be used to quantify the resulting improved reliability 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 to a value of about $153 million per year delivered by ITC’s Michigan utilities 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.

Operational Excellence: Improving Reliability of Acquired Systems Fewer outages: According to the SGS Statistical Services' Transmission Reliability Benchmarking Study, ITC Transmission and METC now perform with the best 10% of companies for number of sustained outages per circuit. As ITC's most recently acquired system, ITC Midwest improvement programs have had less time to be effective. However, performance showed continued improvement in 2011. Number of Sustained Outages per Circuit, All Voltages, 2011 0.6 0.4 0.2 0.0 Lower is better ITC Transmission METC Region Peers ITC Midwest improvement Third Quartile Second Quartile Top Quartile Top Decile

Operational Excellence: Improving Reliability of Acquired Systems Shorter outages: According to the SGS Study, average circuit outage duration for all three ITC operating companies is less than the Region and Peer Group. Transmission circuit outages do not equate to end-use customer outages in most cases, except for ITC Midwest.

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 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 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 EMI Customer 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 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

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

ITC Midsouth 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 Mississippi Arkansas Louisiana Texas ITC Midsouth VP and Business Unit Head Mississippi Arkansas Louisiana Texas Mississippi Arkansas Louisiana Texas Mississippi Arkansas Louisianan Texas

ETR Utilities’ Capital Needs Could Total ~$13B-16B Over 2012-2018 Actual and Forecast Entergy Utilities Investment ($B) EEI has estimated that prospective EPA rules could increase total capex by 30% 0 5 10 15 20 1999-2004 2005-2011 2012-2018 Average2 = $1.9B - $2.3B Total = $13.0B - $15.8B Average1 = $1.4B - $1.7B Total = $9.7B - $11.7B Average1 = $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, 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 spend3 Past storm spend Base case – conservative (Transmission and Non-Transmission) EOC Transmission EOC Transmission EOC Transmission

EMI Total Capital Needs Could Total ~$1.5B – $1.6B Over 2012-2018 Actual and Forecast Capital Investment for EMI ($B) EEI has estimated that prospective EPA rules could increase total capex by 30% 0.5 1.5 0 2012-2018 2005-2011 1999-2004 2 1 Average2 = $213M - $232M Total = $1.5B - $1.6B Average1 = $164M - $177M Total = $1.2B - $1.2B Average1 = $148M Total = $0.9B Actual excluding storms (Transmission and Non-Transmission) Past storm spend Potential spend3 ??? Effect of EPA rules? Aging infrastructure? 1. Range based on actuals plus storm capital. 2. Range based on projections of EMI’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. Transmission Transmission Transmission Base case – conservative (Transmission and Non-Transmission)

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 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 Nearly 100% in the Next Seven Years

EMI Transmission Capital Could Total ~$0.5B Over 2012-2018 Average= $68M Total = $474M Actual and Forecast Transmission Investment for EMI ($M) 200 0 2012-2018 2005-2011 1999-2004 400 100 300 500 Average= $36M Total = $216M Projected base case capital plan as of August 2012 Transmission Capital Spending for EMI Could Increase Nearly 83% in the Next Seven Years Actual Average = $37M Total = $259M Note: Historical data excludes storm capital, as there is no capital associated with future storms in base capital plan projections.

EMI Transmission CapX as Multiple of Depreciation Nearly Twice as High as Non-Transmission EMI Average CapX as Multiple of Depreciation (2012-18 Average) For EMI, Transmission Constitutes ~47% of Capital in Excess of Depreciation, despite being 22% of rate base 3.0 4 3 2 1 0 1.6 Transmission Non-Transmission Note: Based on figures filed in testimony at MPSC

Benefits from Financial Flexibility for Entergy Transmission-Related Cash Capital Requirements Go Away Utility Operating Cash Flow Minus Cash Construction Expenditures 2014E – 2018E; $B Status Quo With ITC Transaction 20% Utility Debt Obligations 2018E; $B Stronger Utility Balance Sheet Improves Ability to Invest in Generation and Distribution Status Quo With ITC Transaction $2.7B 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

Benefits from Financial Flexibility for EMI Transmission-Related Cash Capital Requirements Go Away EMI Operating Cash Flow Minus Cash Construction Expenditures 2014E – 2018E ($M) EMI Debt Obligations 2018E ($M) Stronger Balance Sheet Improves Ability to Invest in Generation and Distribution Status Quo With ITC Transaction $353M Status Quo With ITC Transaction 0 100 200 300 400 12% 1,000 0 500 1,500 298 334 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

Financial Strength and Flexibility Transaction offers the financial strength of ITC and improves that of EMI 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 Mississippi Post-close, EMI 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 EMI, 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 Expect new ITC operating companies to have ratings equivalent to that of ITC’s existing MISO operating companies 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 Op Co and market conditions 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 Mississippi, 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)

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 Dividend / share repurchase Cash from financing Internal separation ITC Stock Merge 1 2 3 4

Post Spin-Merge Transaction Structure 100% Entergy Shareholders Mid South TransCo LLC OpCos ITC Shareholders ITC OpCos 50.1% 49.9% Note: Chart represents ownership structure immediately upon closing of the transaction.

$1.775B of Debt Proceeds Used to Retire Preferred and Pay Down Debt in Proportion to Transmission Assets The allocation for EMI was estimated in order to: Retire all Preferred at each Operating Company Target a post-transaction weighted average cost of capital (WACC) that is substantially unchanged from the pre-transaction WACC EOC Amount ($M)1 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.

EMI Credit Metrics are Expected to be Maintained 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 reduce EMl‘s needs for debt financing...” "...should not affect EMl’s current investment-grade rating...” “...should help preserve or possibly enhance Entergy's S&P rating...” “...should preserve EMI's access to debt capital on reasonable terms even in difficult market conditions...” Any potential credit ratings improvement for EMI could result in savings for Mississippi customers through lower cost of debt 1. Testimony of Dr. Michael Tennican before the MPSC, Docket 12-UA-358

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 54 Downgrades No changes Total 100 19 27 Upgrades Source: EEI 2011 Q3 Credit Ratings Charts

Transaction Protects EMI from Negative Impact to Credit Ratings Current EMI credit rating at Baa3 Transaction protects EMI from credit downgrade risk; one notch hypothetical downgrade could increase cost of debt by 75 bps Transaction protects EMI from credit downgrade which could cost customers ~$4.4M in additional interest costs from 2014-2018 Estimates are hypothetical forecasts to illustrate effect on cost of debt and benefits to customers – exact values will depend on market conditions Source: Bloomberg Fair Value 10-year credit ratings for utilities. 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 Illustrative

Comparable equity values of 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, EMI will not incur a tax liability Under a taxable transaction, the tax basis of EMI’s transmission assets would be reset and Accumulated Deferred Income Taxes (“ADIT”) would be 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 As a result of the RMT transaction structure, EMI’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 Transaction Structure Avoids Re-Measurement of ADIT Preserving Tax Basis for EMI and Protecting Customers from Negative Rate Effects of a Taxable Transaction

Significant variability in average residential bills – yearly variation between $1 and $18 over 2001-2011 Henry Hub Gas Index ($/mmBtu) 2.7 3.1 5.4 5.9 8.3 6.5 6.9 9.0 3.8 4.4 4.0 Henry Hub Gas Index ($/mmBtu) 15 10 5 0 EMI Avg. Monthly Residential Bill – 1,000 kWh ($) 150 100 50 0 +18.14 (+22%) +1.47 (+2%) 2011 91.28 2010 89.81 2009 92.18 2008 99.44 2007 96.30 2006 111.07 2005 98.93 2004 80.78 2003 85.28 2002 77.37 2001 83.46 18% reduction in customer bills since 2006 EMI Avg. Monthly Residential Bill- 1,000 kWh($) Henry Hub Gas Index -18% 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 Illustrative

Transmission Constitutes a Small Portion of a Typical Mississippi Customer's Total Bill 6.6% Transmission Non-Transmission 93.4% Typical EMI Customer 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 of credit quality improvement resulting from transition to FERC-regulated rate construct partially offset 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 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 MS zone) and retail share of Transmission investments Other Effects

Over the long term, customer bill effects expected to be mitigated by... Enhanced Financial Flexibility Operational Excellence Independent and transparent ITC model Regional Planning 120 EMI Residential Bill – 1,000 kWh ($) 80 100 60 40 20 0 ~0.66 0.7% Illustrative Bill if ITC owns T assets – post-transaction ~91.94 2014 WACC Effects ~0.66 Illustrative Bill if ETR owns T assets – status quo 91.28 EMI Typical Residential Customer Bill Expected to Increase 0.7% – Expected Mitigation by Customer Benefits Note: Contents exclude estimated one-time 2014 rate timing effects of $0.73 due to conversion to forward test year – reflects amount that would have been collected in future years – and of $0.93 due to accelerated elimination of MSS-2 for EMI Note: $91.28 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

Modest Bill Effect of 0.7% on Selected Commercial and Industrial Class – Expected 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. Illustration does not include effect of $5.45 due to accelerated elimination of MSS-2 for EMI or rate timing effect of $4.32 due to adoption of forward test year. 2014 Transaction Bill Effects Selected Retail Class Retail Class Description Typical Bill WACC Effects Total Effect % Change EMI GS 25 kW, 30% Load Factor $548.50 3.86 3.86 0.7% Illustrative

EMI – $91.28 Sensitivity of Residential Rate Effects to Variations in Spend EMI – $91.28 + $0.11 O&M Spend + $0.03 Capital Expenditure Spend Typical Monthly Residential Bill 1 Sensitivity to 10% Increase in Spend $0.66 $0.66 Total Transaction Bill Effect Typical Monthly Residential Bill 1 Sensitivity to 10% Increase in Spend Total Transaction Bill Effect - $0.11 - $0.03 Sensitivity to 10% Decrease in Spend Sensitivity to 10% Decrease in Spend 1. Typical EMI bill of $91.28 reflects 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.

Change in How Wholesale Rates are Determined Due to Adoption of MISO's 12 CP Demand Methodology A B 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

Wholesale Rates for EMI Customers Increase Post-Transition to MISO Estimated 2014 WS rates post transition to MISO with 4 Transmission Pricing Zones 3.65 Estimated Net Rate Effect of adopting default MISO ROE and implementing 4 Transmission Pricing Zones 1.22 Estimated 2014 WS rates paid under ETR OATT under One Transmission Pricing Zone 2.43 3 4 Estimated 2014 Wholesale Transmission Rate Effects ***using 12 CP methodology*** ($/kWm) 2 1 0 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 ~$0.30 due to conversion to forward test year – reflects amounts that would have been collected in future years * * *

Transaction-Related Filings Pending Before the 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 financing ESI filing on behalf of the Wires Subs: Authorization for financing (FPA 204) ES11-40-002 EOCs filing: Authorization for financing (FPA 204) 1Q2013, EMI 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

2014 Rate Effect from ITC Transaction for Typical Mississippi Wholesale Customer – Expected Mitigation by... Customer Benefits Note: Includes estimated one-time rate effect of ~$0.30 due to conversion to forward test year – reflects amounts that would have been collected in future years; excludes offsetting depreciation study impact of ~$0.15 Estimated EMI Wholesale Transmission Rate Effects ($/kWm) (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 3.75 ITC Ownership (0.13) Credit Quality Impacts 4 Net Effect of ~$0.10 or 2.7% 0 2 3 1 Rate Construct Effects from FERC Regulated Model 0.23 Estimated ETR Ownership in MISO * 3.65 5 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