Entergy reports second quarter 2013 earnings

Submitted by tim on Mon, 07/29/2013 - 23:01

Entergy Corporation (NYSE: ETR) of New Orleans on July 30, 2013 reported second quarter 2013 as-reported earnings of $163.7 million, or 92 cents per share, compared to $365.0 million, or $2.06 per share, for second quarter 2012. On an operational basis, Entergy’s second quarter 2013 earnings were $179.7 million, or $1.01 per share, compared with $374.6 million, or $2.11 per share, in second quarter 2012. Entergy owns the Vermont Yankee nuclear power plant in Vernon.

Table 1: Consolidated Earnings ‘Reconciliation of GAAP to Non-GAAP Measures

Second Quarter and Year-to-Date 2013 vs. 2012

(Per share in U.S. $)

Second Quarter

Year-to-Date

2013

2012

Change

2013

2012

Change

As-Reported Earnings

0.92

2.06

(1.14)

1.82

1.20

0.62

Less Special Items

(0.09)

(0.05)

(0.04)

(0.13)

(1.36)

1.23

Operational Earnings

1.01

2.11

(1.10)

1.95

2.56

(0.61)

Weather Impact

(0.02)

0.08

(0.10)

(0.12)

(0.09)

(0.03)

Operational Earnings Highlights for Second Quarter 2013

Utility earnings were lower driven largely by substantially higher income tax expense as well as higher non-fuel operation and maintenance expense and depreciation expense, partially offset by higher net revenue.

Entergy Wholesale Commodities earnings decreased due primarily to lower net revenue and higher decommissioning expense, partially offset by lower income tax expense.

Parent & Other results declined due to an increase in income tax expense on Parent & Other activities.

The company continued to make progress on its seven strategic imperatives, designed to create sustainable value for all stakeholders, including improving financial performance and reducing uncompensated risks going forward. One of those imperatives is to optimize the organization through human capital management. HCM, a months-long effort, will position Entergy to provide optimal service to all stakeholders while creating real, sustainable savings. As part of this initiative, the company completed the comprehensive redesign of the organization, which will result in approximately 800 positions being eliminated. Total savings from HCM are estimated in the range of approximately $200 million to $250 million by 2016.

‘Difficult decisions like job reductions are sometimes the very tough outcome of making long-term, fundamental improvements in the way a company works,’said Leo Denault, Entergy’s chairman and chief executive officer. ‘The redesign process has been comprehensive, thoughtful and focused squarely on being fair to our employees throughout the process and being responsive to the needs of our customers, our employees, our communities and our owners."

Entergy’s business highlights also included the following:

Customers ranked the Utility operating companies as the top five in the nation for proactive outage communications, as determined by JD Power and Associates.

The Utility operating companies offered enhanced rate mitigation to address concerns raised in the transaction approval process for the spin-merge of the transmission business with ITC.

EGSL signed an agreement to supply up to 200 megawatts to Sempra Energy’s proposed Cameron LNG liquefaction project.

In response to a request for proposals, Entergy submitted a bid to NYPA to provide 1,375 megawatts from IPEC beginning in 2016.

A teleconference will be held at 10 a.m. CT on Tuesday, July 30, 2013, to discuss Entergy’s second quarter 2013 earnings announcement and may be accessed by dialing (719) 457-2080, confirmation code 4532989, no more than 15 minutes prior to the start of the call. The call and presentation slides can also be accessed via Entergy’s website at www.entergy.com . A replay of the teleconference will be available by telephone and on Entergy’s website at www.entergy.com as soon as practical after the transcript is filed with the SEC due to filing requirements associated with the proposed spin-off and merger of Entergy’s transmission business with ITC. The telephone replay will be available through Aug. 7, 2013, by dialing (719) 457-0820, confirmation code 4532989.

Consolidated Results

Consolidated Earnings

Table 2 provides a comparative summary of consolidated earnings per share for second quarter 2013 versus 2012, including a reconciliation of GAAP as-reported earnings to non-GAAP operational earnings. A detailed discussion of the factors driving quarterly results at each business segment follows.

Table 2: Consolidated Earnings ‘Reconciliation of GAAP to Non-GAAP Measures
Second Quarter and Year-to-Date 2013 vs. 2012 (see Appendix F for definitions of certain measures)

(Per share in U.S. $)

Second Quarter

Year-to-Date

2013

2012

Change

2013

2012

Change

As-Reported

Utility

1.10

1.72

(0.62)

1.79

2.07

(0.28)

Entergy Wholesale Commodities

0.06

0.40

(0.34)

0.52

(0.59)

1.11

Parent & Other

(0.24)

(0.06)

(0.18)

(0.49)

(0.28)

(0.21)

Consolidated As-Reported Earnings

0.92

2.06

(1.14)

1.82

1.20

0.62

Less Special Items

Utility

(0.08)

(0.05)

(0.03)

(0.12)

(0.09)

(0.03)

Entergy Wholesale Commodities

(0.01)

(1.26)

1.25

Parent & Other

(0.01)

0.01

Consolidated Special Items

(0.09)

(0.05)

(0.04)

(0.13)

(1.36)

1.23

Operational

Utility

1.18

1.77

(0.59)

1.91

2.16

(0.25)

Entergy Wholesale Commodities

0.07

0.40

(0.33)

0.53

0.67

(0.14)

Parent & Other

(0.24)

(0.06)

(0.18)

(0.49)

(0.27)

(0.22)

Consolidated Operational Earnings

1.01

2.11

(1.10)

1.95

2.56

(0.61)

Weather Impact

(0.02)

0.08

(0.10)

(0.12)

(0.09)

(0.03)

Detailed earnings variance analyses are included in Appendix B-1 and Appendix B-2 to this release. In addition, Appendix B-3 provides details of special items shown in Table 2 above.

Consolidated Operating Cash Flow

Entergy’s operating cash flow in second quarter 2013 was $572 million compared to $587 million in second quarter 2012. The overall quarterly decrease was due primarily to higher income tax payments and non-capital spending related to ANO recovery from the March 31 industrial accident. Partially offsetting was the receipt of proceeds from the DOE resulting from litigation regarding storage of spent nuclear fuel in second quarter 2013 and a second quarter 2012 regulatory refund to a wholesale customer associated with rough production cost equalization.

Variations in cash flow from net revenue also contributed; EWC net revenue declined while Utility net revenue increased. In addition, intercompany income tax payments contributed to the line of business variances, but were largely offsetting between the segments.

Table 3 provides the components of operating cash flow contributed by each business with current quarter and year-to-date comparisons.

Table 3: Consolidated Operating Cash Flow

Second Quarter and Year-to-Date 2013 vs. 2012

(U.S. $ in millions)

Second Quarter

Year-to-Date

2013

2012

Change

2013

2012

Change

Utility

493

(481)

381

976

(595)

Entergy Wholesale Commodities

127

(47)

315

291

Parent & Other

480

(33)

513

420

(79)

499

Total Operating Cash Flow

572

587

(15)

1,116

1,188

(72)

II.

Utility

In second quarter 2013, Utility earnings were $1.10 per share on an as-reported basis and $1.18 per share on an operational basis, compared to as-reported earnings per share of $1.72 and operational earnings per share of $1.77 in second quarter 2012. The quarter-over-quarter decrease in Utility was due largely to significantly higher income tax expense. The prior period results reflected an agreement reached with the IRS regarding storm cost financings in Louisiana, which reduced second quarter 2012 income tax expense. The net income effect was partially offset by a regulatory charge for customer sharing of the benefits of the IRS agreement, which reduced net revenue in 2012.

Utility net revenue was higher than a year ago. The second quarter 2012 regulatory charge noted above was a factor. Pricing adjustments also contributed to the net revenue increase. Current year net revenue reflects regulatory actions from placing major generation investments in service. A portion of the net revenue increase was for recovery of costs below the net revenue line, including depreciation, taxes other than income taxes and non-fuel operation and maintenance expenses.

Partially offsetting net revenue increases was lower sales volume, including the effects of weather. Weather was below normal in second quarter 2013 compared to the warmer-than-normal temperatures experienced one year ago. On a weather-adjusted basis, billed retail sales declined (2.0) percent.

Retail electric sales in billed gigawatt-hours by customer segment are summarized in Table 4. Current quarter sales reflect the following:

Residential sales in second quarter 2013, on a weather-adjusted basis, decreased (3.6) percent compared to second quarter 2012.

Commercial and governmental sales, on a weather-adjusted basis, decreased (2.4) percent quarter over quarter.

Industrial sales in the second quarter decreased (0.5) percent compared to the same quarter of 2012.

A few factors contributed to these quarter-over-quarter decreases. Residential and commercial declines were partially due to fewer billing days. Energy efficiency and demand side management efforts, which were expected, and sluggish economic growth also contributed. Industrial sales were down principally due to lower results in the small- to mid-sized segments in Louisiana, Arkansas and Mississippi.

Second quarter 2013 results also reflected higher non-fuel operation and maintenance expense and higher depreciation expense. As noted above, a portion of the expense increases were associated with plant acquisitions and regulatory actions that were offset in net revenue.

Table 4 provides a comparative summary of Utility operational performance measures.

Table 4: Utility Operational Performance Measures

Second Quarter and Year-to-Date 2013 vs. 2012 (see Appendix F for definitions of certain measures)

Second Quarter

Year-to-Date

2013

2012

% Change

% Weather Adjusted

2013

2012

% Change

% Weather Adjusted

GWh billed

Residential

7,377

7,940

(7.1%)

(3.6%)

15,721

15,700

0.1%

(1.3%)

Commercial and governmental

7,267

7,753

(6.3%)

(2.4%)

14,272

14,745

(3.2%)

(1.0%)

Industrial

10,357

10,408

(0.5%)

20,225

20,366

(0.7%)

Total Retail Sales

25,001

26,101

(4.2%)

(2.0%)

50,218

50,811

(1.2%)

(1.0%)

Wholesale

590

836

(29.4%)

1,219

1,568

(22.3%)

Total Sales

25,591

26,937

(5.0%)

51,437

52,379

(1.8%)

Non-fuel O&M expense per MWh (a)

$23.44

$19.94

17.5%

$22.22

$20.01

11.0%

Number of retail customers

Residential

2,395,491

2,383,057

0.5%

Commercial and governmental

358,709

356,324

0.7%

Industrial

44,041

46,771

(5.8%)

Total Retail Customers

2,798,241

2,786,152

0.4%

(a)

Second quarter and year-to-date 2012 and 2013 exclude the special item associated with the proposed spin-merge of the transmission business; second quarter and year-to-date 2013 exclude the special item for HCM implementation expenses.

Appendix C provides information on selected pending local and federal regulatory cases.

III.

Entergy Wholesale Commodities

EWC operational adjusted EBITDA was $61 million in the second quarter of 2013, compared to $127 million in the same period a year ago, as shown in Table 5.

Table 5: Entergy Wholesale Commodities Operational Adjusted EBITDA ‘Reconciliation of GAAP to Non-GAAP Measures

Second Quarter and Year-to-Date 2013 vs. 2012 (see Appendix F for definitions of certain measures)

($ in millions)

Second Quarter

Year-to-Date

2013

2012

Change

2013

2012

Change

Net income

(59)

(105)

199

Add back: interest expense

(1)

(4)

Add back: income tax expense

(15)

(62)

(44)

Add back: depreciation and amortization

100

Subtract: interest and investment income

(5)

(7)

Add back: decommissioning expense

(17)

Adjusted EBITDA

127

(68)

253

(84)

337

Add back: special item for HCM implementation expenses

Add back: special item for asset impairment

356

(356)

Operational adjusted EBITDA

127

(66)

255

272

(17)

The EWC operational adjusted EBITDA decrease was due largely to a decline in period-over-period net revenue, driven by lower volume and a lower overall realized price for EWC’s nuclear fleet. Nuclear production declined due to higher refueling and unplanned outage days. Realized price for EWC’s nuclear fleet declined (4.7) percent quarter over quarter due primarily to lower energy pricing, partially offset by higher capacity pricing. Energy pricing for the current quarter averaged approximately $42 per megawatt hour, down from approximately $45 per megawatt hour in the prior period. Average capacity prices for the Northeast nuclear plants increased quarter over quarter, to approximately $3.6 per kilowatt-month in the current period from approximately $2.1 per kilowatt-month.

EWC earnings per share for second quarter 2013 were $0.06 on an as-reported basis and $0.07 on an operational basis, compared to the second quarter 2012 earnings of $0.40 per share on both an as-reported and an operational basis. The decrease in operational earnings was partially attributable to the operational adjusted EBITDA drivers noted above. Higher decommissioning expense also contributed. In the second quarter of 2012, a decommissioning liability adjustment, due primarily to an updated decommissioning cost study, reduced decommissioning expense. These decreases were partially offset by lower income tax expense.

Table 6 provides a comparative summary of EWC operational performance measures.

Table 6: Entergy Wholesale Commodities Operational Performance Measures

Second Quarter and Year-to-Date 2013 vs. 2012 (see Appendix F for definitions of certain measures)

Second Quarter

Year-to-Date

2013

2012

% Change

2013

2012

% Change

Owned capacity (MW)

6,612

GWh billed

11,172

11,674

(4.3%)

21,559

22,955

(6.1%)

Net revenue ($ millions)

383

444

(13.7%)

876

895

(2.1%)

Average realized revenue per MWh

$47.36

$48.27

(1.9%)

$52.80

$48.77

8.3%

Non-fuel O&M expense per MWh (b)

$25.69

$24.07

6.7%

$25.46

$24.00

6.1%

EWC Nuclear Fleet

Capacity factor

82%

85%

(3.5%)

82%

87%

(5.7%)

GWh billed

9,789

10,426

(6.1%)

19,035

20,264

(6.1%)

Average realized revenue per MWh

$46.40

$48.67

(4.7%)

$51.95

$49.47

5.0%

Production cost per MWh

$29.16

$26.61

9.6%

$27.54

$26.22

5.0%

Refueling outage days

Indian Point 2

Indian Point 3

Palisades

Pilgrim

Vermont Yankee

(b)

Second quarter and year-to-date 2013 exclude the special item for HCM implementation expenses; year-to-date 2012 excludes the effect of the special item for impairment of the Vermont Yankee assets.

Table 7 provides information on current forward capacity and generation contracts for EWC’s fleet, as well as total revenue projections based on market prices as of June 30, 2013. EWC uses a combination of forward physical and financial contracts, including swaps, collars, put and/or call options, to manage forward commodity price risk. Certain hedge volumes have price downside and upside relative to market price movements. The contracted minimum, current expected value and sensitivities are provided to show potential variations. Although the sensitivities reflect the minimum, they may not reflect the total maximum upside potential from higher market prices. Information contained in Table 7 represents projections at a point in time and will vary over time based on numerous factors, such as future market prices, contracting activities and generation.

Table 7: Entergy Wholesale Commodities Capacity and Generation

Third Quarter 2013 through 2017 (see Appendix F for definitions of certain measures)

(based on market prices as of June 30, 2013) (c)

Balance of 2013

2014

2015

2016

2017

EWC Nuclear Portfolio

Energy

Planned TWh of generation (d)

Percent of planned generation under contract

Unit-contingent

40%

21%

12%

14%

12%

Unit-contingent with availability guarantees

20%

16%

13%

Firm LD

23%

60%

14%

Offsetting positions

(20%)

Total

83%

77%

39%

27%

25%

Average revenue per MWh on contracted volumes

Minimum

$45

$44

$45

$50

$51

Expected based on current market prices

$46

$48

$50

$52

Sensitivity: -/+ $10 per MWh market price change

$45 - $48

$44 - $49

$45 - $53

$50 - $53

$51 - $55

Capacity

Planned net MW in operation

5,011

Percent of capacity sold forward

Bundled capacity and energy contracts

16%

Capacity contracts

42%

19%

12%

18%

Total

58%

35%

28%

34%

25%

Average revenue under contract per kW per month
(applies to capacity contracts only)

$2.8

$2.4

$3.2

Total Nuclear Energy and Capacity Revenues

Expected sold and market total revenue per MWh

$49

$47

$48

$49

Sensitivity: -/+ $10 per MWh market price change

$47 - $53

$44 - $52

$40 - $54

$41 - $56

$42 - $57

EWC Non-Nuclear Portfolio

Energy

Planned TWh of generation

Percent of planned generation under contract

Cost-based contracts

31%

32%

36%

33%

Firm LD

Total

37%

38%

43%

40%

39%

Capacity

Planned net MW in operation

1,052

977

Percent of capacity sold forward

Cost-based contracts

24%

26%

Bundled capacity and energy contracts

Capacity contracts

52%

50%

51%

49%

21%

Total

84%

82%

83%

81%

55%

Total Non-Nuclear Net Revenue

Expected portfolio net revenue in $ millions

$48

$90

$86

$107

$108

(c)

Assumes uninterrupted normal operation at all plants in all years. NRC license renewal applications are in process for both Indian Point units; current license expirations are 9/28/13 for Indian Point 2 and 12/12/15 for Indian Point 3.

(d)

Reflects moving the next Palisades refueling outage to early 2014 from fall 2013 due to the impact of the extended outage in second quarter 2013. Palisades is on an 18-month refueling cycle.

IV.

Parent & Other

Parent & Other reported a loss of $(0.24) per share on an as-reported and an operational basis in the current quarter, compared to a second quarter 2012 as-reported and operational loss of $(0.06) per share. The decline was due to an increase in income tax expense on Parent & Other activities. Second quarter 2012 benefited from a favorable federal appeals court decision affirming Entergy’s entitlement to claim foreign tax credits for the U.K. Windfall Tax.

2013 Earnings Guidance

Entergy affirmed its 2013 operational earnings guidance range of $4.60 to $5.40 per share. The 2013 operational earnings guidance is detailed in Table 8. Year-over-year changes are shown as point estimates and are applied to 2012 operational earnings to compute the 2013 guidance midpoint. Drivers for the 2013 operational earnings guidance range are listed separately. Because there is a range of possible outcomes associated with each earnings driver, a range is applied to the guidance midpoint to produce Entergy’s guidance range.

Table 8: 2013 Earnings Per Share Operational Guidance

(Per share in U.S. $) ‘Prepared November 2012 (e)

Segment

Description of Drivers

2012
Earnings per
Share

Expected
Change

2013
Guidance
Midpoint

2013
Guidance
Range

Utility

2012 Operational Earnings per Share

5.51

Adjustment to normalize weather

0.09

Increased net revenue due to absence of second quarter 2012 regulatory charge

0.57

Increased net revenue due to retail sales growth and rate actions

1.25

Increased non-fuel operation and maintenance expense

(0.40)

Increased taxes other than income taxes

(0.10)

Increased depreciation expense

(0.35)

Decreased other income

(0.05)

Increased interest and other charges

(0.10)

Higher effective income tax rate

(1.85)

Other

0.13

Subtotal

5.51

(0.81)

4.70

Entergy Wholesale Commodities

2012 Operational Earnings per Share

1.49

Decreased net revenue due primarily to lower pricing on nuclear assets

(0.40)

Increased non-fuel operation and maintenance expense

(0.15)

Increased decommissioning expense

(0.15)

Increased depreciation expense

(0.10)

Lower effective income tax rate

0.10

Other

0.01

Subtotal

1.49

(0.69)

0.80

Parent & Other

2012 Operational Earnings per Share

(0.77)

Increased Parent interest expense

(0.05)

Lower income tax expense

0.30

Other

0.02

Subtotal

(0.77)

0.27

(0.50)

Consolidated Operational

2013 Operational Earnings per Share Guidance Range

6.23

(1.23)

5.00

4.60 ‘5.40

(e)

Originally prepared November 2012 and updated February 2013 to reflect 2012 final results.

Key assumptions supporting 2013 operational earnings guidance are as follows:

Utility

Normal weather

Increased net revenue due to the absence of the second quarter 2012 regulatory charge

Retail sales growth of around 1.25 percent on a weather-adjusted basis

Increased net revenue from rate actions, including those associated with the Waterford 3 steam generator replacement project, a full year of the Grand Gulf extended power uprate and the Hinds and Hot Spring acquisitions, which are partially offset by increases in non-fuel operation and maintenance expense, depreciation expense and taxes other than income taxes

Increased non-fuel operation and maintenance expense due to plant acquisitions and other general expense increases

Increased taxes other than income taxes resulting largely from new plant acquisitions as well as increased franchise taxes

Increased depreciation expense associated with capital spending at the Utility and the new depreciation rates established in the ETI rate case in July 2012

Decreased other income due primarily to lower allowance for equity funds used during construction as significant projects moved into service (Waterford 3 steam generator, Grand Gulf extended power uprate)

Increased interest expense due primarily to a higher level of debt outstanding

Higher effective income tax rate in 2013, due largely to the net effect of items recorded in 2012

Entergy Wholesale Commodities

EWC drivers represent expected variances at the segment level for 2013

46 TWh of output for the total fleet, reflecting an approximate 92 percent nuclear capacity factor compared to an 89 percent nuclear capacity factor in 2012; 2013 includes approximately 30- to 35-day scheduled refueling outages at Indian Point 3, Pilgrim and Vermont Yankee in Spring 2013 and Palisades in Fall 2013 (outage days vary depending on the scope of the outage); as of second quarter 2013, the Palisades Fall 2013 refueling outage has been rescheduled to early 2014

Assumes full year operations for all nuclear plants

$47/MWh average total energy and capacity revenues for EWC-nuclear fleet based on published market prices at the end of September 2012

$45/MWh average revenue per MWh on contracted energy volumes, representing 84 percent of planned generation (prepared November 2012)

$43/MWh average market price on 16 percent unsold energy volumes (prepared November 2012); as of the end of June 2013, average market energy price for 2013 unsold volumes was approximately $47.5/MWh

$2.3/kW-month average capacity revenue under contract on 28 percent capacity (excludes bundled capacity contracts, which are priced within the contracted energy volumes above) (prepared November 2012)

$1.8/kW-month average capacity price on 56 percent unsold capacity (prepared November 2012); as of the end of June 2013, average market capacity price for 2013 unsold volumes was approximately $3.9/kW-month

$77 million non-nuclear portfolio net revenue based on prices at the end of September 2012

Nuclear fuel expense around $6.5/MWh for 2013 compared to approximately $5.9/MWh for 2012

Decreased purchased power expense reflected in net revenue

Non-fuel operation and maintenance expense, including nuclear refueling outage expenses, around $24.3/MWh reflecting increases in refueling outage amortization for Vermont Yankee following a reduction in 2012 due to the asset impairment, general expense increases and higher costs at RISEC due to higher maintenance outage costs

Increased decommissioning expense due to the absence of a reduction in the asset retirement obligation resulting from updated decommissioning cost studies completed in the second quarter 2012, which reduced decommissioning expense in the prior year period

Increased depreciation expense on nuclear assets due to higher depreciable plant balances as well as declining useful life of nuclear assets; also contributing was the absence of the third quarter 2012 DOE litigation awards for Indian Point 2 which resulted in a reversal of previously recorded depreciation expense

Lower effective income tax rate in 2013

Parent & Other

Higher Parent interest expense due largely to higher average debt outstanding

Lower income tax expense on Parent & Other activities

Other

2013 average fully diluted shares outstanding of approximately 177 million

Overall effective income tax rate of 34 percent in 2013, the timing and segment of which may ultimately vary

Pension discount rate of 5.1 percent; the final average pension discount rate is 4.36 percent

Earnings guidance for 2013 should be considered in association with earnings sensitivities as shown in Table 9. These sensitivities illustrate the estimated change in operational earnings per share resulting from changes in various revenue and expense drivers. Traditionally, the most significant variables for earnings drivers are retail sales for the Utility and energy prices for EWC. In addition, the operational earnings guidance range for 2013 takes into consideration a number of regulatory initiatives (rate actions on investments) underway across the Utility jurisdictions at the time guidance was initiated.

Estimated annual impacts shown in Table 9 are intended to be indicative rather than precise guidance.

Table 9: 2013 Earnings Sensitivities

(Per share in U.S. $) ‘Prepared November 2012

Variable

2013 Guidance Assumption

Description of Change

Estimated
Annual Impact

Utility

Retail sales growth
Residential
Commercial / Governmental
Industrial

Around 1.25% retail sales growth on a weather adjusted basis

1% change in Residential MWh sold
1% change in Comm / Govt MWh sold
1% change in Industrial MWh sold

- / + 0.05
- / + 0.04
- / + 0.02

Rate base

Growing rate base

$100 million change in rate base

- / + 0.03

Return on equity

Authorized regulatory ROEs

1% change in allowed ROE

- / + 0.41

Non-fuel operation and maintenance expense

Increased due to plant acquisitions and general expenses

1% change in expense

+ / - 0.08

Entergy Wholesale Commodities (f)

Nuclear capacity factor

92% capacity factor

1% change in capacity factor

- / + 0.06

EWC revenue

$47/MWh nuclear revenue;
$77M non-nuclear net revenue

$10/MWh market price change

- 0.25 / + 0.49

Total non-fuel operation and maintenance expense

$24.3/MWh non-fuel operation and maintenance expense

1% change in expense

+ / - 0.04

Nuclear Outage (lost revenue only)

92% capacity factor, including refueling outages for four EWC nuclear units

1,000 MW plant for 10 days at average portfolio energy price of $45/MWh for contracted volumes and $43/MWh for unsold volumes in 2013 (assuming no resupply option exercise)

- 0.03 / n/a

Consolidated

Interest expense

Higher debt outstanding balances

1% change in interest rate on $1 billion debt

+ / - 0.03

Pension and other postretirement costs (expense portion only)

Discount rate of 5.1%

0.25% change

- / + 0.07

Effective income tax rate

34% effective income tax rate

1% change in overall effective income tax rate

+ / - 0.08

(f)

Assumes uninterrupted normal operation at all nuclear plants.

VI.

Long-term Financial Outlook

Entergy believes it offers a long-term, competitive utility investment opportunity combined with a valuable option represented by a unique, clean, non-utility generation business located in attractive power markets. Table 10 summarizes the current five-year financial outlook for 2010 through 2014. Entergy also noted that the five-year financial outlook does not reflect the effects of the proposed spin-merge of the transmission business discussed in Appendix A.

Table 10: Long-term Financial Outlook (see Appendix F for definitions of certain measures)

As of July 2013

Category

Long-term Outlook

Assumption

Earnings

Utility net income

Around 6 percent compound annual net income growth rate over the 2010 ‘2014 horizon (2009 base year).

Entergy Wholesale Commodities results

Revenue projections through 2014 will experience volatility due to commodity market activities ‘one of the most important fundamental drivers for this business. At current sold and forward prices with its existing asset portfolio and contracts, EWC is expected to deliver declining adjusted EBITDA for the period through 2014 compared to 2010. However, EWC offers a valuable long-term option from the potential positive effects of economic growth (driving increased load, market heat rates, capacity prices and natural gas prices), aging and unprofitable unit retirements (driving market heat rate expansion and capacity price increases), rationalization of supply and growth of demand in natural gas markets, and impacts from environmental legislation.

Corporate results

Results will vary depending upon factors including future effective income tax and interest rates and the amount / timing of share repurchases, if any.

Capital Deployment

A balanced capital investment / return program

Entergy continues to see value-added investment opportunities at the Utility that benefit customers, as well as an investment outlook at EWC that supports continued safe, secure and reliable operations and opportunistic investments. Entergy aspires to fund this capital program without issuing traditional common equity, while maintaining a competitive capital return program. Given the company’s financial profile with a mix of utility and non-utility businesses, both common stock dividends and share repurchases will be considered in establishing return of capital policies. Over the five-year period from 2010 ‘2014 under the current long-term business outlook, capital deployment through dividends and share repurchases is projected to total around $4 billion. The amount of share repurchases may vary as a result of material changes in business results, capital spending or new investment opportunities.

Credit Quality

Strong liquidity.

Solid credit metrics that support ready access to capital on reasonable terms.

VII.

Appendices

Seven appendices are presented in this section as follows:

Appendix A includes information on Entergy’s plan to spin off the Utility transmission business and merge that business with a subsidiary of ITC.

Appendix B includes earnings per share variance analysis and detail on special items that relate to the current quarter and year-to-date results.

Appendix C provides information on selected pending local and federal Utility regulatory cases and events.

Appendix D provides financial metrics for both current and historical periods. In addition, historical financial and operating performance metrics are included for the trailing eight quarters.

Appendix E provides a summary of planned capital expenditures for 2013 through 2015.

Appendix F provides definitions of the operational performance measures, GAAP and non-GAAP financial measures and abbreviations or acronyms that are used in this release.

Appendix G provides a reconciliation of GAAP to non-GAAP financial measures used in this release.

Spin-Merge of Transmission Business

In December 2011, the Entergy and ITC boards of directors approved a definitive agreement under which Entergy will spin off and then merge its electric transmission business with a subsidiary of ITC. The transaction is targeted to close in 2013 and is subject to the satisfaction of certain closing conditions including retail regulatory approvals. Key transaction approvals from ITC shareholders, FERC and the NRC, as well as a private letter ruling from the IRS confirming the tax-free nature of the transaction structure were received in second quarter 2013. Approvals by the Utility operating companies’retail regulators and the Missouri PSC remain pending. After careful consideration of the input from parties in the retail regulatory proceedings, the Utility operating companies and ITC have proposed a rate mitigation plan.

Appendix A provides a summary of certain pending activities and events.

Appendix A: Regulatory Summary Table for Spin-Merge of Transmission Business
(see Appendix F for definitions of certain abbreviations or acronyms)

Proceeding

Pending Activities / Events

Retail Regulators

Recent Activity: To address concerns raised by stakeholders in the retail regulatory proceedings regarding increased customer costs, the Utility operating companies and ITC proposed a rate mitigation plan. Under the plan, the Utility operating companies and ITC have offered an initial five-year period of wholesale rate discounts and retail bill credits as follows:
· EAI customers: $127.5 million

· EGSL and ELL customers: $101.8 million

· EMI customers: $70.8 million

· ENOI customer: $20.0 million

· ETI customers: $67.0 million

Following the first five years after closing of the transaction, the economic and performance benefits of ITC’s ownership will be measured and verified by an independent auditor to determine if they offset the ownership cost increase resulting from ITC’s weighted average cost of capital. If the benefits do exceed such costs, rate mitigation will cease. If they do not, wholesale rate discounts and retail bill credits will continue until they do.

In addition, the Utility operating companies have offered additional retail bill credits to address the effects of moving to a forward test year:
· EAI customers: $6.9 million

· EGSL and ELL customers: $12.6 million

· EMI customers: $6.7 million

· ENOI customer: $0.4 million

· ETI customers: $13.1 million

Lastly, ETI customers will also experience net avoided costs of $10.0 million due to the effects of eliminating transmission cost allocation under the Entergy System Agreement. EGSL and ELL customers will also experience net avoided costs of $16.3 million due to the effects of both eliminating transmission cost allocation under the Entergy System Agreement and moving to MISO’s transmission pricing zone structure.
The total rate mitigation funds for existing Utility operating companies’customers, wholesale and retail, is $413.4 million plus $39.7 million to address the effects of moving to a forward test year.
Hearings were completed in the PUCT, Missouri PSC and LPSC proceedings in May, June and July, respectively. The ALJs in the PUCT proceeding issued a proposal for decision on July 9, 2013 recommending against approval of the proposed transaction, but noting that if the PUCT approves the transaction, certain conditions should be imposed on ITC and ETI. The proposal for decision did not consider the revised rate mitigation plan proposal outlined above.
Next Steps: An interlocutory appeal is pending at the LPSC with respect to the ALJ’s ruling regarding excluding from evidence the rate mitigation plan proposal outlined above. At the conclusion of the LPSC hearing, the ALJ established a post-hearing procedural schedule that indicates LPSC consideration at the Oct. 16, 2013 B&E meeting instead of the Sept. 18, 2013 meeting in the original schedule. ELL, EGSL and ITC plan to request at the July 31, 2013 B&E meeting that the original consideration date be preserved.
The PUCT is expected to consider ETI’s and ITC’s application at the Aug. 9, 2013 Open Meeting. The jurisdictional deadline for a decision in Texas is Aug. 18, 2013.
The APSC revised the procedural schedule and established additional testimony deadlines. Staff and intervenor supplemental testimony is due Aug. 15, 2013. EAI’s and ITC’s supplemental rebuttal testimony is due Aug. 23, 2013. The deadline for settlement is Aug. 28, 2013. A hearing is scheduled to begin Sept. 4, 2013.
In the MPSC proceeding, a paper hearing is scheduled in August 2013. Rejoinder testimony is due Aug. 12, 2013 in the CCNO proceeding and a hearing is scheduled to commence on Aug. 27, 2013. A decision from the Missouri PSC is pending.

Federal Energy Regulatory Commission

Sections 203, 205 and 305(a) Filings Recent Activity: On June 20, 2013, FERC issued an order approving the Utility operating companies’and ITC’s Sept. 24, 2012 joint application related to the proposed transaction, subject to the outcome of a hearing or settlement judge procedures on certain rate issues and transaction-related agreements. The hearing is held in abeyance for settlement procedures. The first settlement conference took place in mid-July.
Next Steps: The parties will continue discussions toward reaching settlement of the rate and agreement issues that remain pending. The transaction can close, subject to refund, with these issues pending.

Section 204 Filings Recent Activity: On May 16, 2013, FERC approved Entergy’s applications seeking authorization related to certain debt financings necessary to effectuate the ITC transaction and ITC’s application seeking authorizations related to certain post-closing financings.

Appendix A: Regulatory Summary Table for Spin-Merge of Transmission Business (continued)

(see Appendix F for definitions of certain abbreviations or acronyms)

Proceeding

Pending Activities / Events

Internal Revenue Service

Recent Activity: On May 31, 2013, the IRS issued a private letter ruling that certain requirements for the tax-free treatment of the distribution of TransCo have been met.

Nuclear Regulatory Commission

Recent Activity: On May 3, 2013, the NRC approved the license transfer requests and amendments as part of the steps to complete the transaction.

Securities and Exchange Commission

Recent Activity: Entergy filed the Mid South TransCo registration statement on July 24, 2013. The registration statement reflects Entergy’s intent to pursue a combination partial split-off and spin-off prior to the merger of the transmission business with ITC. In a split-off, Entergy shareholders will be offered the opportunity to exchange their Entergy common stock for TransCo common units at a to be determined exchange ratio (as described in the registration statement), subject to an upper limit on the exchange ratio. The terms of the exchange offer (including the number of TransCo units to be offered in the exchange offer, the discount to ITC’s stock price and the upper limit) will be determined immediately prior to the launch of the exchange offer and announced pursuant to a press release. Entergy also retains the option to contribute up to 4.999 percent of ITC shares at closing of the transmission business merger into an exchange trust to offer to exchange for Entergy common stock up to six months after close.
Next Steps: The SEC has 30 days from the filing of the Mid South TransCo registration statement to review and provide comments to Entergy.

Hart-Scott-Rodino Notification

Recent Activity: On Dec. 14, 2012, Entergy and ITC each filed a premerger notification under the HSR Act. The 30-day waiting period required under the HSR Act expired on Jan. 14, 2013.

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 was declared effective by the SEC on Feb. 25, 2013. ITC is also expected to file a post-effective amendment to the above registration statement. ITC shareholders are urged to read the prospectus included in the ITC registration statement (and the post-effective amendment to the ITC registration statement, when available) and any other relevant documents because they contain important information about TransCo and the proposed transactions. In addition, on July 24, 2013, TransCo filed a registration statement on Form S-4/S-1 (Registration No. 333-190094) with the SEC registering the offer and sale of TransCo common units to be issued to Entergy shareholders in connection with the proposed transactions. This registration statement includes a prospectus of TransCo related to the proposed transactions. Entergy will file a tender offer statement on Schedule TO with the SEC related to the exchange of shares of Entergy common stock for the TransCo common units. Entergy shareholders are urged to read the prospectuses included in the ITC registration statement (and the post-effective amendment to the ITC registration statement, when available), the Transco registration statement, the tender offer statement on Schedule TO (when available) and any other relevant documents because they contain important information about ITC, TransCo and the proposed transactions. The registration statements, prospectuses, tender offer statement 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.

Variance Analysis and Special Items

Appendix B-1 and Appendix B-2 provide details of second quarter and year-to-date 2013 versus 2012 as-reported and operational earnings variance analysis for Utility, Entergy Wholesale Commodities, Parent & Other and Consolidated.

Appendix B-1: As-Reported and Operational Earnings Per Share Variance Analysis

Second Quarter 2013 vs. 2012

(Per share in U.S. $, sorted in consolidated operational column, most to least favorable)

Utility

Entergy Wholesale Commodities

Parent & Other

Consolidated

As-
Reported

Opera-
tional

As-
Reported

Opera-
tional

As-
Reported

Opera-
tional

As-
Reported

Opera-
tional

2012 earnings

1.72

1.77

0.40

(0.06)

2.06

2.11

Net revenue

0.76

(g)

(0.21)

(h)

0.01

0.56

Preferred dividend requirements

0.01

Other income (deductions) - other

0.01

(0.01)

Taxes other than income taxes

(0.02)

Nuclear refueling outage expense

(0.02)

(0.01)

(0.03)

Interest expense and other charges

(0.03)

(0.01)

(0.04)

Depreciation / amortization expense

(0.07)

(i)

(0.01)

(0.08)

Decommissioning expense

(0.17)

(j)

(0.17)

Other operation & maintenance expense

(0.24)

(0.21)

(k)

(0.01)

(0.26)

(0.22)

Income taxes - other

(1.01)

(l)

0.08

(m)

(0.18)

(n)

(1.11)

2013 earnings

1.10

1.18

0.06

0.07

(0.24)

0.92

1.01

Appendix B-2: As-Reported and Operational Earnings Per Share Variance Analysis

Year-to-Date 2013 vs. 2012

(Per share in U.S. $, sorted in consolidated operational column, most to least favorable)

Utility

Entergy Wholesale Commodities

Parent & Other

Consolidated

As-
Reported

Opera-
tional

As-
Reported

Opera-
tional

As-
Reported

Opera-
tional

As-
Reported

Opera-
t ional

2012 earnings

2.07

2.16

(0.59)

0.67

(0.28)

(0.27)

1.20

2.56

Net revenue

1.17

(g)

(0.07)

(h)

0.01

1.11

Asset impairment

1.26

(o)

1.26

Nuclear refueling outage expense

(0.03)

0.01

(0.02)

Other income (deductions) - other

(0.03)

(0.01)

(0.04)

Interest expense and other charges

(0.06)

(p)

0.02

(0.03)

(0.07)

Taxes other than income taxes

(0.06)

(q)

(0.01)

(0.07)

Depreciation / amortization expense

(0.15)

(i)

(0.15)

Decommissioning expense

(0.17)

(j)

(0.17)

Other operation & maintenance expense

(0.34)

(0.31)

(k)

(0.01)

(0.02)

(0.36)

(0.33)

Income taxes - other

(0.78)

(l)

0.09

(m)

(0.18)

(n)

(0.87)

2013 earnings

1.79

1.91

0.52

0.53

(0.49)

1.82

1.95

(g)

The current quarter and year-to-date increases reflect a regulatory charge recorded in the second quarter of last year which was associated with the agreement to share income tax benefits resulting from an IRS agreement [discussed in (l) below]. Pricing factors also contributed to the increases. Net revenue reflected the net effect of pricing adjustments from regulatory actions, primarily from placing the Grand Gulf extended power uprate, Waterford 3 steam generator replacement and the Hinds and Hot Spring power plant acquisitions in service. The ETI 2012 rate case order and the EAI energy efficiency rider also contributed. A portion of the net revenue increases was for recovery of costs below the net revenue line including non-fuel operation and maintenance expense, depreciation expense and taxes other than income taxes. These increases were partially offset by lower retail sales volume.

Utility Net Revenue Variance Analysis
2013 vs. 2012 ($ EPS)

Second Quarter

Year-to-Date

Weather

(0.10)

(0.03)

Sales growth / pricing

0.29

0.60

Regulatory agreement

0.57

Other

0.03

Total

0.76

1.17

(h)

The current quarter decrease was due to several factors. Nuclear generation declined due to an increase in refueling and unplanned outage days. Realized price for EWC’s nuclear business also declined, driven by lower energy pricing which was partially offset by higher capacity pricing. Unfavorable effects of lower power prices on electricity derivative instruments that are not designated as hedges also contributed. The year-to-date decrease was largely due to an increase in refueling and unplanned outage days as well as the effects of lower power prices on electricity derivative instruments that are not designated as hedges. The year-to-date decrease was partially offset by higher nuclear energy and capacity pricing.

(i)

The current quarter and year-to-date decreases were due primarily to additions to plant in service, including the Grand Gulf extended power uprate, the Waterford 3 steam generator replacement and the Hinds and Hot Spring power plant acquisitions. Higher depreciation rates at ETI resulting from the 2012 rate case order also contributed.

(j)

Decreases in the current quarter and year-to-date periods reflected reductions in the asset retirement obligation recorded in the second quarter of the prior year, which factored in, among other things, an updated decommissioning cost study for the Pilgrim Nuclear Power Station, and reduced decommissioning expense.

(k)

The current quarter and year-to-date decreases were attributable to several factors, including increased spending on fossil plant outages; higher nuclear spending, including costs related to the generator stator accident at ANO and higher compensation and benefits costs (largely post-employment benefits). Higher fossil plant spending associated with the Hinds and Hot Spring power plant acquisitions and higher energy efficiency costs at EAI, which are offset in net revenue as discussed in (g) above, also contributed. The as-reported decreases included an increase in expenses incurred in connection with the planned spin-merge of the transmission business compared to 2012 and HCM implementation expenses in second quarter 2013.

(l)

The current quarter and year-to-date decreases were due primarily to an item recorded in the prior year. Second quarter 2012 included a decrease in income tax expense resulting from an agreement reached with the IRS associated with certain storm costs financings in Louisiana. The year-to-date decrease was partially offset by the first quarter 2012 write off of an EGSL regulatory asset for income taxes to align the regulatory treatment of income taxes associated with certain items (primarily pension expense) and the financial accounting treatment of those taxes.

(m)

Increases in the current quarter and year-to-date were due primarily to a state income tax benefit of approximately $17 million recorded in the second quarter 2013.

(n)

The current quarter and year-to-date decreases were due largely to an item recorded in the prior year - a favorable decision received in June 2012 from the U.S. Court of Appeals for the Fifth Circuit affirming Entergy’s entitlement to claim foreign tax credits for the U.K. Windfall Tax.

(o)

The year-to-date as-reported increase was due to an item recorded in the prior year. In first quarter 2012, an impairment charge was recorded to write down the carrying values of Vermont Yankee and related assets to their fair value, in accordance with GAAP.

(p)

The year-to-date decrease was due primarily to higher debt balances as well as lower allowance for funds used during construction due to completion of several major projects in mid- to late-2012.

(q)

The year-to-date decrease was due primarily to an increase in ad valorem taxes resulting from 2013 higher assessments as well as an increase in local franchise taxes resulting from higher residential and commercial revenues compared to the prior year.

Appendix B-3 lists special items by business with quarter-to-quarter and year-to-year comparisons. Amounts are shown on both an earnings per share basis and a net income basis. Special items are those events that are not routine. Special items are included in as-reported earnings per share consistent with GAAP, but are excluded from operational earnings per share. As a result, operational earnings per share is considered a non-GAAP measure.

Appendix B-3: Special Items (shown as positive / (negative) impact on earnings)

Second Quarter and Year-to-Date 2013 vs. 2012

(Per share in U.S. $)

Second Quarter

Year-to-Date

2013

2012

Change

2013

2012

Change

Utility

Transmission business spin-merge expenses

(0.07)

(0.05)

(0.02)

(0.11)

(0.09)

(0.02)

HCM implementation expenses

(0.01)

Total Utility

(0.08)

(0.05)

(0.03)

(0.12)

(0.09)

(0.03)

Entergy Wholesale Commodities

Vermont Yankee asset impairment

(1.26)

1.26

HCM implementation expenses

(0.01)

Total Entergy Wholesale Commodities

(0.01)

(1.26)

1.25

Parent & Other

Transmission business spin-merge expenses

(0.01)

0.01

Total Special Items

(0.09)

(0.05)

(0.04)

(0.13)

(1.36)

1.23

(U.S. $ in millions)

Second Quarter

Year-to-Date

2013

2012

Change

2013

2012

Change

Utility

Transmission business spin-merge expenses

(12.2)

(9.9)

(2.3)

(18.4)

(15.7)

(2.7)

HCM implementation expenses

(2.7)

Total Utility

(14.9)

(9.9)

(5.0)

(21.1)

(15.7)

(5.4)

Entergy Wholesale Commodities

Vermont Yankee asset impairment

(223.5)

223.5

HCM implementation expenses

(1.1)

Total Entergy Wholesale Commodities

(1.1)

(223.5)

222.4

Parent & Other

Transmission business spin-merge expenses

0.3

(0.3)

(1.0)

1.0

Total Special Items

(16.0)

(9.6)

(6.4)

(22.2)

(240.2)

218.0

Regulatory Summary

Appendix C provides a summary of selected regulatory cases and events that are pending.

Appendix C: Regulatory Summary (see Appendix F for definitions of certain abbreviations or acronyms)

Company

Pending Cases / Events

Retail Regulation

Entergy Arkansas
Authorized ROE: 10.2%
Last Filed Rate Base: see next column

Rate Case Recent Activity / Next Steps: Discovery is in progress. Staff and intervenor direct testimony is due Aug. 2, 2013. Hearings are scheduled to begin Oct. 22, 2013. New rates are expected to become effective January 2014.
Rate Case Background: On March 1, 2013, EAI filed a rate case reflecting a requested ROE of 10.4 percent and based on a test year period ending Dec. 31, 2012 with known and measurable changes through Dec. 31, 2013. In the primary scenario assuming only the transition to MISO, EAI is requesting a rate increase of $174 million based on rate base of $5.0 billion. The alternate scenario, which assumes completion of the spin-merge of the transmission business with ITC, reflects a $218 million rate increase request based on rate base of $4.3 billion. Both scenarios propose a capacity cost recovery rider and a rider to recover costs associated with MISO and ITC (if the ITC transaction is completed).

Entergy Gulf States Louisiana
Authorized ROE Range:
9.9% - 11.4% (electric)
9.45% - 10.45% (gas)
Last Filed Rate Base: see next column for electric
$0.05 billion (gas) filed 1/13 based on 9/30/12 test yr

Rate Case Recent Activity / Next Steps: Discovery is in progress. EGSL and ELL are seeking LPSC review of an ALJ ruling denying a motion to consolidate the ELL and EGSL rate cases. As part of the filing, EGSL and ELL requested a 60-day delay in the procedural schedule. The matter is on the agenda for the July 31, 2013 B&E meeting. On July 26, 2013, the ALJ granted an intervenor motion to temporarily suspend the current testimony deadlines pending the appeal decision. New rates are expected to become effective in April 2014.
Rate Case Background: On Feb. 15, 2013, EGSL filed an electric rate case reflecting a requested ROE of 10.4 percent and based on a test year period ending June 30, 2012 with known and measurable changes through Dec. 31, 2013. In the scenario that assumes that both the MISO transition and the proposed spin-merge of the transmission business with ITC are completed, EGSL is requesting a rate increase of $28 million based on rate base of $2.1 billion. The alternate scenario, which assumes only the transition to MISO, reflects a $24 million rate increase request based on rate base of $2.7 billion. Both scenarios propose a new transmission rider, continuation of the capacity rider and a new three-year FRP for 2013 - 2015 test years. The proposed FRP reflects a bandwidth of +/- 75 basis points and 60 percent / 40 percent sharing between customers and the company.
Other Recent Activity: On May 21, 2013, the LPSC approved an uncontested settlement resolving the LPSC’s review of the authorized ROE for EGSL’s gas operations. The settlement extends EGSL’s current Gas Rate Stabilization Plan for an additional three-year term with a revised ROE midpoint of 9.95 percent and a bandwidth of +/- 50 basis points.

Entergy Louisiana
Authorized ROE Range:
9.45% - 11.05%
Last Filed Rate Base: see next column

LPSC Rate Case Recent Activity / Next Steps: Discovery is in progress. EGSL and ELL are seeking LPSC review of an ALJ ruling denying a motion to consolidate the ELL and EGSL rate cases. As part of the filing, EGSL and ELL requested a 60-day delay in the procedural schedule. The matter is on the agenda for the July 31, 2013 B&E meeting. On July 26, 2013, the ALJ granted an intervenor motion to temporarily suspend the current testimony deadlines pending the appeal decision. New rates are expected to become effective in April 2014.
LPSC Rate Case Background: On Feb. 15, 2013, ELL filed a rate case reflecting a requested ROE of 10.4 percent and based on a test year period ending June 30, 2012 with known and measurable changes through Dec. 31, 2013. In the scenario that assumes that both the MISO transition and the proposed spin-merge of the transmission business with ITC are completed, ELL is requesting a rate increase of $168 million based on rate base of $3.8 billion. The alternate scenario, which assumes only the transition to MISO, reflects a $144 million rate increase request based on rate base of $4.5 billion. Both scenarios propose a new transmission rider, continuation of the capacity rider and a new three-year FRP for 2013 - 2015 test years. The proposed FRP reflects a bandwidth of +/- 75 basis points and 60 percent / 40 percent sharing between customers and the company.
Other Recent Activity: Discovery is in progress in ELL’s rate case for its Algiers territory, which is regulated by the CCNO. ELL is requesting a rate increase of $13 million (phased in over three years), including a 10.4 percent ROE and an FRP mechanism identical to the ELL request. Advisors direct testimony is due Nov. 11, 2013. Hearings are scheduled for April 2014. New rates are expected to become effective in second quarter 2014.

Entergy Mississippi
Authorized ROE Range:
9.76% - 11.83%
(per 4/13 revised FRP filing)
Last Filed Rate Base: $1.7 billion filed 4/13 based on 12/31/12 test yr

Recent Activity: On April 30, 2013, EMI filed its revised evaluation report for the 2012 test year. The revised filing reflected a 7.91 percent earned ROE, which was below the bandwidth of 9.76 to 11.83 percent. The calculated 10.8 percent FRP midpoint ROE included the benefit of a 0.74 percent performance incentive. On June 6, 2013, EMI and Staff filed a stipulation resolving EMI’s 2012 test year FRP. Without agreeing to any specific disallowances, the stipulation provides for a $22.3 million rate increase, which equates to an 8.96 percent earned ROE. MPSC consideration of the stipulation is pending.
Background: EMI’s FRP includes an annual redetermination of the benchmark ROE based on a formula tied to interest rates and equity risk premiums, with an adjustment based upon performance ratings. Returns inside the bandwidth result in no change in rates while returns outside the bandwidth reset rates prospectively to or within the bandwidth depending on performance, subject to a 4 percent revenue limit. The annual filing occurs each March with rates effective each June (if no hearing) or July (if hearing). EMI’s FRP does not have an expiration date.

Entergy New Orleans
Authorized ROE Range:
10.7% - 11.5% (electric)
10.25% - 11.25% (gas)
Last Filed Rate Base: $0.3 billion (electric) and $0.09 billion (gas) filed 5/12 based on 12/31/11 test yr

Recent Activity: The CCNO revised the procedural schedule to resolve the remaining disputed items in the 2011 test year FRP. The hearing is now scheduled in August 2013. ENOI is also in discussions with the CCNO Advisors and intervenors regarding a possible settlement of the 2011 test year FRP and possible extension of the FRP, which would require CCNO approval. ENOI currently plans to file a base rate case in 2014, based on a 2013 test year. The rate case filing was a condition in CCNO’s approval of a PPA for ENOI’s 20 percent participation in ELL’s Ninemile 6 CCGT under construction.
Background: A three-year FRP beginning with the 2009 test year was adopted in April 2009. Key provisions include an 11.1 percent electric ROE with a +/- 40 basis points bandwidth and a 10.75 percent gas ROE with a +/- 50 basis points bandwidth. Earnings outside the bandwidth reset to the midpoint ROE. Rates change on a prospective basis depending on whether ENOI is over- or under-earning. The FRP also includes a recovery mechanism for CCNO-approved capacity additions plus provisions for extraordinary cost changes and force majeure.
In October 2012, ENOI implemented, subject to refund pending resolution of remaining disputed items, rate changes reflected in its revised evaluation report for the 2011 test year FRP. The ROEs reflected in the revised report were 9.57 percent earned ROE for electric (which is below the bandwidth, resulting in a $4.9 million electric base revenue increase) and a 10.83 percent earned ROE for gas (which is within the bandwidth, resulting in no change in gas base rates).

Appendix C: Regulatory Summary (continued) (see Appendix F for definitions of certain abbreviations or acronyms)

Company

Pending Cases / Events

Retail Regulation

Entergy Texas
Authorized ROE: 9.8%
Last Filed Rate Base:
$1.7 billion filed 11/11 based on 6/30/11 adjusted test yr

Recent Activity: At the May 9, 2013 open meeting, the PUCT approved a Purchased Power Capacity Rider. In June 2013, ETI withdrew its application seeking special circumstances recovery of prior capacity costs, without prejudice to seek in future proceedings. ETI currently plans to file a rate case in third quarter 2013.
Background: ETI implemented a $27.7 million overall retail rate increase effective July 2012 pursuant to a final PUCT order authorizing an allowed ROE of 9.8 percent. On Nov. 28, 2012 and Jan. 11, 2013, ETI filed appeals of the PUCT final order and order on rehearing, respectively, in Travis County district court. The appeals remain pending.

Wholesale Regulation

System Energy Resources, Inc.
ROE and last calculated rate base: see next column

Recent Activity: None.
Background: 10.94 percent ROE approved by July 2001 FERC order.
Last Calculated Rate Base: $1.5 billion for June 30, 2013 monthly cost of service.

Transmission, Proposal to Join MISO and System Agreement
Authorized ROE:
11.0% (r)
Last Filed OATT Rate Base:
$2.5 billion (s) filed 5/13 based on 12/31/12 test year

Proposal to Join MISO Recent Activity: On June 18, 2013, a hearing was held on EAI’s filing seeking confirmation from the Missouri PSC that it has no jurisdiction over EAI's proposal to join MISO or, in the alternative, requesting the Missouri PSC find that EAI joining MISO is not detrimental to the public interest in Missouri. A Missouri PSC decision is pending. The Utility operating companies continue to target joining MISO in December 2013.
Background: Between June 2012 and April 2013, the LPSC, PUCT, APSC, CCNO and MPSC each issued orders approving, subject to certain conditions, the Utility operating companies’requests for MISO membership.

System Agreement Recent Activity: A hearing was held in May 2013 in the FERC proceeding regarding calculations for re-pricing wholesale opportunity sales of energy by EAI to third parties for the period 2000 through 2009. An initial decision is expected in August 2013.
Background: On June 21, 2012, FERC issued an order relating to an LPSC complaint involving Entergy’s accounting for wholesale opportunity sales of energy by EAI to third parties during the period 2000 through 2009. The order found that, although the sales at issue were permitted under the System Agreement and were made and priced in good faith, the after-the-fact accounting methodology used to determine the cost of the energy used to supply the sales was inconsistent with the System Agreement. The Utility operating companies’request for rehearing remains pending.
The June 2012 FERC decision established further hearing procedures to determine the calculations. In September and October 2012, the Utility operating companies submitted testimony that included a proposed illustrative re-run of intra-system bills for 2003, 2004 and 2006 (the three years with the highest volume of opportunity sales) consistent with the directives in FERC’s order. The proposed illustrative re-run of intra-system bills shows that the potential cost for EAI would be up to $12 million for those three years, and the potential benefit would be significantly less than that for each of the other Utility operating companies; effects to other System Agreement pricing schedules may offset these costs and benefits. On Dec. 21, 2012, the LPSC filed testimony concluding that EAI should refund approximately $75 million to the other Utility operating companies for those three years. On Feb. 1, 2013, FERC Staff and certain intervenors filed testimony in the proceeding taking positions on the opposing calculations proposed by the LPSC and the Utility operating companies. In April 2013, the Utility operating companies filed rebuttal testimony, including a revised illustrative rerun of the intra-system bills for the three years. The revised calculation resulted in an increase in the potential cost for EAI over those three years of $2.3 million compared to prior submissions. No payments will be made or received by the Utility operating companies until a decision is issued by FERC in this phase of the proceeding.

(r)

Applies to sales made under Entergy’s FERC OATT.

(s)

Reflects transmission rate base in Entergy’s FERC OATT filing, which is also included in the rate base figures for each of the Utility operating companies shown above.

Financial and Historical Performance Measures

Appendix D-1 provides comparative financial performance measures for the current quarter. Appendix D-2 provides historical financial performance measures and operating performance metrics for the trailing eight quarters. Financial performance measures in both tables include those calculated and presented in accordance with GAAP, as well as those that are considered non-GAAP measures.

As-reported measures are computed in accordance with GAAP as they include all components of net income, including special items. Operational measures are non-GAAP measures as they are calculated using operational net income, which excludes the impact of special items. A reconciliation of operational measures to as-reported measures is provided in Appendix G.

Appendix D-1: GAAP and Non-GAAP Financial Performance Measures

Second Quarter 2013 vs. 2012 (see Appendix F for definitions of certain measures)

For 12 months ending June 30

2013

2012

Change

GAAP Measures

Return on average invested capital ‘as-reported

5.9%

6.2%

(0.3%)

Return on average common equity ‘as-reported

10.5%

11.3%

(0.8%)

Cash flow interest coverage

5.8

7.2

(1.4)

Book value per share

$52.03

$50.96

$1.07

End of period shares outstanding (millions)

178.2

177.2

1.0

Non-GAAP Measures

Return on average invested capital ‘operational

6.1%

7.4%

(1.3%)

Return on average common equity ‘operational

10.9%

14.2%

(3.3%)

As of June 30 ($ in millions)

2013

2012

Change

GAAP Measures

Cash and cash equivalents

311

283

Revolver capacity

3,819

2,762

1,057

Commercial paper outstanding

947

Total debt

13,747

12,533

1,214

Securitization debt

927

1,020

(93)

Debt to capital ratio

59.0%

57.4%

1.6%

Off-balance sheet liabilities:

Debt of joint ventures ‘Entergy’s share

(3)

Leases ‘Entergy’s share

505

508

(3)

Total off-balance sheet liabilities

594

600

(6)

Non-GAAP Measures

Debt to capital ratio, excluding securitization debt

57.3%

55.3%

2.0%

Gross liquidity

4,130

3,045

1,085

Net debt to net capital ratio, excluding securitization debt

56.7%

54.7%

2.0%

Net debt to net capital ratio including off-balance sheet liabilities, excluding securitization debt

57.8%

56.0%

1.8%

Appendix D -2: Historical Performance Measures (see Appendix F for definitions of certain measures)

3Q11

4Q11

1Q12

2Q12

3Q12

4Q12

1Q13

2Q13

13YTD

12YTD

Financial

EPS ‘as-reported ($)

3.53

0.87

(0.86)

2.06

1.89

1.66

0.90

0.92

1.82

1.20

Less ‘special items ($)

(0.07)

(1.30)

(0.05)

(0.06)

(0.04)

(0.09)

(0.13)

(1.36)

EPS ‘operational ($)

3.53

0.94

0.44

2.11

1.95

1.72

0.94

1.01

1.95

2.56

Trailing twelve months

ROIC ‘as-reported (%)

8.2

8.0

6.0

6.2

4.8

5.5

6.9

5.9

ROIC ‘operational (%)

8.2

8.0

7.2

7.4

6.0

6.6

7.0

6.1

ROE ‘as-reported (%)

16.1

15.4

10.8

11.3

7.8

9.3

12.8

10.5

ROE ‘operational (%)

16.1

15.6

13.6

14.2

10.7

12.2

13.2

10.9

Cash flow interest coverage

6.6

7.1

7.5

7.2

6.8

6.1

5.9

5.8

Debt to capital ratio (%)

57.3

57.9

57.4

57.7

58.7

59.0

Debt to capital ratio, excluding securitization debt (%)

55.1

55.0

55.7

55.3

55.7

56.9

57.3

Net debt to net capital ratio, excluding securitization debt (%)

52.8

53.5

54.2

54.7

54.1

55.8

56.3

56.7

Utility

GWh billed

Residential

12,376

7,274

7,760

7,940

11,605

7,360

8,344

7,377

15,721

15,700

Commercial & Governmental

9,344

7,270

6,992

7,753

9,101

7,313

7,005

7,267

14,272

14,745

Industrial

11,024

10,130

9,958

10,408

10,748

10,067

9,868

10,357

20,225

20,366

Wholesale

1,038

1,090

732

836

833

798

630

590

1,219

1,568

Non-fuel O&M expense per MWh (t)

$14.93

$21.99

$20.08

$19.94

$16.66

$22.19

$21.02

$23.44

$22.22

$20.01

Entergy Wholesale Commodities

Owned Capacity in MW

6,016

6,599

6,612

GWh billed

11,255

11,121

11,281

11,674

12,002

11,221

10,387

11,172

21,559

22,955

Net revenue ($ millions)

542

504

452

444

495

463

493

383

876

895

Operational adjusted EBITDA
($ millions)

241

193

144

127

185

161

194

255

272

Avg realized revenue per MWh

$56.02

$52.48

$49.29

$48.27

$51.88

$50.56

$58.66

$47.36

$52.80

$48.77

Non-fuel O&M expense per MWh (t)

$23.71

$24.61

$23.93

$24.07

$23.15

$23.52

$25.22

$25.69

$25.46

$24.00

EWC Nuclear Operational Measures

Capacity factor (%)

GWh billed

10,645

10,367

9,838

10,426

10,480

10,298

9,246

9,789

19,035

20,264

Avg realized revenue per MWh

$56.07

$53.00

$50.32

$48.67

$52.27

$49.88

$57.82

$46.40

$51.95

$49.47

Production cost per MWh

$24.92

$25.92

$25.85

$26.61

$26.14

$26.18

$25.94

$29.16

$27.54

$26.22

(t)

Excludes effect of special items: the proposed spin-merge of the transmission business at Utility (2012 and 2013 quarterly and year-to-date periods), HCM implementation expenses (second quarter and year-to-date 2013) at Utility and EWC and the impairment of the Vermont Yankee plant at EWC (first quarter and year-to-date 2012).

Planned Capital Expenditures

The capital plan for 2013 through 2015 anticipates $6.7 billion for investment, including $3.3 billion of maintenance capital, as shown in Appendix E. EWC planned maintenance capital includes capital investment for non-nuclear plants, which can vary from year to year depending on planned maintenance and generation and other technical milestones.

The $3.4 billion in other capital commitments is for specific investments and initiatives such as:

Utility : the Utility’s portfolio transformation investment of $0.5 billion for ELL’s Ninemile 6 new CCGT project, approximately $0.3 billion for environmental compliance projects (included in generation) and transmission other capital of approximately $0.7 billion. Total transmission investment, including maintenance capital, is approximately $1.4 billion including spending to support the Utility’s plan to join the MISO RTO in December 2013.

Entergy Wholesale Commodities : other capital commitments reflect significant projects required to continue the operation of the current generation fleet including dry cask storage, nuclear license renewal efforts, component replacement and identified repairs across the nuclear fleet, NYPA value sharing (including the last payment to be made in January 2015 for 2014 generation) and potential wedgewire screens at the Indian Point site.

Estimated capital expenditures are subject to periodic review and modification, and actual spending may vary based on a number of factors. The capital plan described in Appendix E does not include significant capital for potential projects to satisfy NRC post-Fukushima requirements. The current preliminary cost estimate for post-Fukushima requirements is approximately $265 million for the Utility, including approximately $230 million in capital and approximately $35 million in one-time operation and maintenance expenses, and approximately $345 million for Entergy Wholesale Commodities, including approximately $290 million in capital and approximately $55 million in one-time operation and maintenance expenses. These costs are expected to be incurred over the 2012 through 2018 time period, and do not include any amounts for filtered vents, for which the NRC initiated a rulemaking in first quarter 2013, or any future NRC requirements (e.g., Tier 2 and 3 activities). The capital plan also does not reflect the expected delay in spending associated with potential wedgewire screens at the Indian Point site.

The capital plan also does not reflect the effects of the proposed spin-off and merger of the transmission business with ITC discussed in Appendix A.

Appendix E: 2013 ‘2015 Capital Expenditure Plan

($ in millions) ‘ Prepared February 2013

2013

2014

2015

Total

Maintenance capital

Utility

Generation

133

127

135

395

Transmission

253

229

202

684

Distribution

504

494

489

1,487

Other

107

105

309

Utility Total

987

957

931

2,875

Entergy Wholesale Commodities

108

131

176

415

Maintenance capital subtotal

1,095

1,088

1,107

3,290

Other capital commitments

Utility

Generation

716

415

392

1,523

Transmission

162

240

303

705

Distribution

Other

272

Utility Total

1,015

764

803

2,582

Entergy Wholesale Commodities

257

242

281

780

Other capital commitments subtotal

1,272

1,006

1,084

3,362

Total Planned Capital Expenditures

2,367

2,094

2,191

6,652

Definitions

Appendix F provides definitions of certain operational performance measures, as well as GAAP and non-GAAP financial measures, all of which are referenced in this release. Non-GAAP measures are included in this release to provide metrics that remove the effect of financial events that are not routine, from commonly used financial metrics.

Appendix F: Definitions of Operational Performance Measures, GAAP and Non-GAAP Financial Measures and Abbreviations or Acronyms

Utility Operational Performance Measures

GWh billed

Total number of GWh billed to all retail and wholesale customers

Non-fuel O&M expense per MWh

Operation, maintenance and refueling expenses per MWh of billed sales, excluding fuel, fuel-related expenses and purchased power

Number of retail customers

Number of customers at end of period

Entergy Wholesale Commodities Operational Performance Measures

Net revenue

Operating revenue less fuel, fuel related expenses and purchased power

Owned capacity

Installed capacity owned and operated by EWC, including investments in wind generation accounted for under the equity method of accounting; EWC acquired RISEC, a 583 MW natural gas-fired combined-cycle generating plant, on Dec. 20, 2011

GWh billed

Total number of GWh billed to customers, excluding investments in wind generation accounted for under the equity method of accounting

Average realized revenue per MWh

As-reported revenue per MWh billed, excluding revenue from the amortization of the Palisades below-market PPA and/or investments in wind generation accounted for under the equity method of accounting

Non-fuel O&M expense per MWh

Operation, maintenance and refueling expenses per MWh billed, excluding fuel, fuel-related expenses and purchased power and investments in wind generation accounted for under the equity method of accounting

Capacity factor

Normalized percentage of the period that the nuclear plants generate power

Production cost per MWh

Fuel and non-fuel operation and maintenance expenses according to accounting standards that directly relate to the production of electricity per MWh (based on net generation)

Refueling outage days

Number of days lost for scheduled refueling outage during the period

Planned TWh of generation

Amount of output expected to be generated by EWC resources considering plant operating characteristics, outage schedules and expected market conditions which impact dispatch, assuming uninterrupted normal operations at all plants and timely renewal of plant operating licenses; non-nuclear also includes purchases from affiliated and non-affiliated counterparties under long-term contracts and excludes energy and capacity from EWC’s wind investment accounted for under the equity method of accounting and Ritchie

Percent of planned generation under contract

Percent of planned generation output sold or purchased forward under contracts, forward physical contracts, forward financial contracts or options that mitigate price uncertainty (consistent with assumptions used in earnings guidance) that may or may not require regulatory approval or approval of transmission rights

Unit-contingent

Transaction under which power is supplied from a specific generation asset; if the asset is not operating, seller is generally not liable to buyer for any damages

Unit-contingent with availability guarantees

Transaction under which power is supplied from a specific generation asset; if the asset is not operating, seller is generally not liable to buyer for any damages, unless the actual availability over a specified period of time is below an availability threshold specified in the contract

Firm LD

Transaction that requires receipt or delivery of energy at a specified delivery point (usually at a market hub not associated with a specific asset) or settles financially on notional quantities; if a party fails to deliver or receive energy, defaulting party must compensate the other party as specified in the contract; a portion of which may be capped through the use of risk management products

Offsetting positions

Transactions for the purchase of energy, generally to offset a Firm LD transaction

Cost-based contracts

Contracts priced in accordance with cost-based rates, a ratemaking concept used for the design and development of rate schedules to ensure that the filed rate schedules recover only the cost of providing the service; these contracts are on owned non-utility resources located within Entergy’s utility service territory, which do not operate under market-based rate authority

Planned net MW in operation

Amount of installed capacity to generate power and/or sell capacity; non-nuclear also includes purchases from affiliated and non-affiliated counterparties under long-term contracts and excludes energy and capacity from EWC’s wind investment accounted for under the equity method of accounting and Ritchie

Percent of capacity sold forward

Percent of planned qualified capacity sold to mitigate price uncertainty under physical or financial transactions

Bundled capacity and energy contracts

A contract for the sale of installed capacity and related energy, priced per megawatt-hour sold

Capacity contracts

A contract for the sale of the installed capacity product in regional markets managed by ISO New England and the New York Independent System Operator

Appendix F: Definitions of Operational Performance Measures, GAAP and Non-GAAP Financial Measures and Abbreviations or Acronyms (continued)

Entergy Wholesale Commodities Operational Performance Measures (continued)

Average revenue per MWh on contracted volumes

Revenue on a per unit basis at which generation output reflected in contracts is expected to be sold to third parties (including offsetting positions) at the minimum contract prices and at forward market prices at a point in time, given existing contract or option exercise prices based on expected dispatch or capacity, excluding the revenue associated with the amortization of the below-market PPA for Palisades; revenue will fluctuate due to factors including market price changes affecting revenue received on puts, collars and call options, positive or negative basis differentials, option premiums and market prices at the time of option expiration, costs to convert firm LD to unit-contingent and other risk management cost; also, excludes payments owed under the value sharing agreements, if any

Average revenue under contract per kW per month (applies to capacity contracts only)

Revenue on a per unit basis at which capacity is expected to be sold to third parties, given existing contract prices and/or auction awards

Expected sold and market total revenue per MWh

Total energy and capacity revenue on a per unit basis at which total planned generation output and capacity is expected to be sold given contract terms and market prices at a point in time, including estimates for market price changes affecting revenue received on puts, collars and call options, positive or negative basis differentials, option premiums and market prices at time of option expiration, costs to convert Firm LD to unit-contingent and other risk management cost, excluding the revenue associated with the amortization of the below market power purchase agreement for Palisades; also excludes payments owed under value sharing agreements, if any

Financial Measures ‘GAAP

Return on average invested capital ‘as-reported

12-months rolling net income attributable to Entergy Corporation (Net Income) adjusted to include preferred dividends and tax-effected interest expense divided by average invested capital

Return on average common equity ‘as-reported

12-months rolling Net Income divided by average common equity

Cash flow interest coverage

12-months cash flow from operating activities plus 12-months rolling interest paid, divided by interest expense

Book value per share

Common equity divided by end of period shares outstanding

Revolver capacity

Amount of undrawn capacity remaining on corporate and subsidiary revolvers

Total debt

Sum of short-term and long-term debt, notes payable and commercial paper and capital leases on the balance sheet less non-recourse debt, if any

Debt of joint ventures - Entergy’s share

Debt issued by business joint ventures at EWC

Leases - Entergy’s share

Operating leases held by subsidiaries capitalized at implicit interest rate

Debt to capital ratio

Total debt divided by total capitalization

Securitization debt

Debt associated with securitization bonds issued to recover storm costs from hurricanes Rita, Ike and Gustav at ETI; the 2009 ice storm at EAI and investment recovery of costs associated with the cancelled Little Gypsy repowering project at ELL

Financial Measures ‘Non-GAAP

Operational earnings

As-reported Net Income adjusted to exclude the impact of special items

Adjusted EBITDA

Earnings before interest, income taxes, depreciation and amortization and interest and investment income excluding decommissioning expense and other than temporary impairment losses on decommissioning trust fund assets

Operational adjusted EBITDA

Adjusted EBITDA excluding effects of special items

Return on average invested capital ‘operational

12-months rolling operational Net Income adjusted to include preferred dividends and tax-effected interest expense divided by average invested capital

Return on average common equity ‘operational

12-months rolling operational Net Income divided by average common equity

Gross liquidity

Sum of cash and revolver capacity

Debt to capital ratio, excluding securitization debt

Total debt divided by total capitalization, excluding securitization debt

Net debt to net capital ratio, excluding securitization debt

Total debt less cash and cash equivalents divided by total capitalization less cash and cash equivalents, excluding securitization debt

Net debt to net capital ratio, including off-balance sheet liabilities, excluding securitization debt

Sum of total debt and off-balance sheet debt less cash and cash equivalents divided by sum of total capitalization and off-balance sheet debt less cash and cash equivalents, excluding securitization debt

Appendix F: Definitions of Operational Performance Measures, GAAP and Non-GAAP Financial Measures and Abbreviations or Acronyms (continued)

Abbreviations or Acronyms

ALJ

Administrative Law Judge

ANO

Arkansas Nuclear One nuclear power plant

APSC

Arkansas Public Service Commission

B&E

LPSC Business and Executive session

CCGT

Combined cycle gas turbine power plant

CCNO

Council of the City of New Orleans

Central time

DOE

U.S. Department of Energy

EAI

Entergy Arkansas, Inc.

EGSL

Entergy Gulf States Louisiana, L.L.C.

ELL

Entergy Louisiana, LLC

EMI

Entergy Mississippi, Inc.

ENOI

Entergy New Orleans, Inc.

ETI

Entergy Texas, Inc.

EWC

Entergy Wholesale Commodities

FERC

Federal Energy Regulatory Commission

FRP

Formula rate plan

GAAP

Generally accepted accounting principles

HCM

Human Capital Management strategic imperative

HSR

Hart-Scott-Rodino Antitrust Improvements Act

ICAP

Installed capacity

IPEC

Indian Point Energy Center

IRS

Internal Revenue Service

ISO

Independent system operator

ITC

ITC Holdings Corp.

LNG

Liquefied natural gas

LPSC

Louisiana Public Service Commission

MISO

Midcontinent Independent System Operator, Inc.

MPSC

Mississippi Public Service Commission

NRC

Nuclear Regulatory Commission

NYISO

New York Independent System Operator

NYPA

New York Power Authority

OATT

FERC-jurisdictional Open Access Transmission Tariff

PPA

Power purchase agreement

PSC

Public Service Commission

PUCT

Public Utility Commission of Texas

RISEC

Rhode Island State Energy Center

ROE

Return on equity

ROIC

Return on invested capital

RTO

Regional transmission organization

SEC

U.S. Securities and Exchange Commission

SERI

System Energy Resources, Inc., whose principal assets consists of ownership interest and leasehold interest in Grand Gulf Nuclear Station

TransCo

Mid South TransCo LLC, a wholly owned subsidiary of Entergy Corp. that will become the holding company for Entergy’s transmission business prior to the close of the merger with ITC

GAAP to Non-GAAP Reconciliations

Appendix G-1, Appendix G-2 and Appendix G-3 provide reconciliations of various non-GAAP financial measures disclosed in this release to their most comparable GAAP measure.

Appendix G-1: Reconciliation of GAAP to Non-GAAP Financial Measures ‘Return on Equity, Return on Invested Capital Metrics

($ in millions)

3Q11

4Q11

1Q12

2Q12

3Q12

4Q12

1Q13

2Q13

As-reported net income-rolling 12 months (A)

1,421

1,346

946

996

705

847

1,160

958

Preferred dividends

Tax effected interest expense

320

316

322

329

342

350

356

363

As-reported net income, rolling 12 months including preferred dividends and tax effected interest expense (B)

1,761

1,683

1,289

1,346

1,069

1,219

1,538

1,342

Special items in prior quarters

(7)

(13)

(244)

(253)

(251)

(31)

(28)

Special items in current quarter

Asset impairment

(224)

Transmission spin-merge

(13)

(7)

(9)

(11)

(6)

(12)

HCM expenses

(4)

Total special items (C)

(7)

(13)

(244)

(253)

(264)

(262)

(37)

(44)

Operational earnings, rolling 12 months including preferred dividends and tax effected interest expense (B-C)

1,768

1,696

1,533

1,599

1,333

1,481

1,575

1,386

Operational earnings, rolling 12 months (A-C)

1,428

1,359

1,190

1,249

969

1,109

1,197

1,002

Average invested capital (D)

21,509

21,126

21,339

21,556

22,065

22,290

22,389

22,573

Average common equity (E)

8,849

8,729

8,725

8,814

9,078

9,079

9,064

9,152

ROIC ‘as-reported % (B/D)

8.2

8.0

6.0

6.2

4.8

5.5

6.9

5.9

ROIC ‘operational % ((B-C)/D)

8.2

8.0

7.2

7.4

6.0

6.6

7.0

6.1

ROE ‘as-reported % (A/E)

16.1

15.4

10.8

11.3

7.8

9.3

12.8

10.5

ROE ‘operational % ((A-C)/E)

16.1

15.6

13.6

14.2

10.7

12.2

13.2

10.9

Appendix G-2: Reconciliation of GAAP to Non-GAAP Financial Measures ‘Credit and Liquidity Metrics

($ in millions)

3Q11

4Q11

1Q12

2Q12

3Q12

4Q12

1Q13

2Q13

Total debt (A)

12,452

12,387

12,619

12,533

12,931

13,473

13,471

13,747

Less securitization debt (B)

1,086

1,071

1,049

1,020

1,003

973

952

927

Total debt, excluding securitization debt (C)

11,366

11,316

11,570

11,513

11,928

12,500

12,519

12,820

Less cash and cash equivalents (D)

987

694

685

283

750

533

263

311

Net debt, excluding securitization debt (E)

10,379

10,622

10,885

11,230

11,178

11,967

12,256

12,509

Total capitalization (F)

21,728

21,629

21,813

21,844

22,402

22,951

22,965

23,302

Less securitization debt (B)

1,086

1,071

1,049

1,020

1,003

973

952

927

Total capitalization, excluding securitization debt (G)

20,642

20,558

20,764

20,824

21,399

21,978

22,013

22,375

Less cash and cash equivalents (D)

987

694

685

283

750

533

263

311

Net capital, excluding securitization debt (H)

19,655

19,864

20,079

20,541

20,649

21,445

21,750

22,064

Debt to capital ratio % (A/F)

57.3

57.9

57.4

57.7

58.7

59.0

Debt to capital ratio, excluding securitization debt % (C/G)

55.1

55.0

55.7

55.3

55.7

56.9

57.3

Net debt to net capital ratio, excluding securitization debt % (E/H)

52.8

53.5

54.2

54.7

54.1

55.8

56.3

56.7

Off-balance sheet liabilities (I)

645

604

601

600

599

595

594

Net debt to net capital ratio including off-balance sheet liabilities, excluding securitization debt % ((E+I)/(H+I))

54.3

54.8

55.5

56.0

55.4

57.0

57.5

57.8

Revolver capacity (J)

2,116

2,001

2,825

2,762

2,917

3,462

3,542

3,819

Gross liquidity (D+J)

3,103

2,695

3,510

3,045

3,667

3,995

3,805

4,130

Appendix G-3: Reconciliation of GAAP to Non-GAAP Financial Measures ‘Entergy Wholesale Commodities Operational Adjusted EBITDA

($ in millions)

3Q11

4Q11

1Q12

2Q12

3Q12

4Q12

1Q13

2Q13

Net income

122

156

(176)

Add back: interest expense

Add back: income tax expense

(92)

(15)

Add back: depreciation and amortization

Subtract: interest and investment income

Add back: decommissioning expense

(4)

(17)

Adjusted EBITDA

241

193

(212)

127

185

161

194

Add back: special item for asset impairment

356

‘

Add back: special item for HCM implementation expenses

‘

Operational adjusted EBITDA

241

193

144

127

185

161

194