Entergy (ETR) 8-K Entergy Reports First Quarter Earnings

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Michele Lopiccolo, VP, Investor Relations

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      mlopicc@entergy.com

INVESTOR NEWS

Exhibit 99.1

April 29, 2010

ENTERGY REPORTS FIRST QUARTER EARNINGS

NEW ORLEANS –  Entergy Corporation (NYSE: ETR) reported first quarter 2010 earnings of $1.12 per share on an as-reported basis and $1.33 per share on an operational basis, as shown in Table 1 below.  A more detailed discussion of quarterly results begins on page 2 of this release.

Table 1:  Consolidated Earnings – Reconciliation of GAAP to Non-GAAP Measures
First Quarter 2010 vs. 2009
(Per share in U.S. $)
	First Quarter
	2010	2009	Change
As-Reported Earnings	1.12	1.20	(0.08)
Less Special Items	(0.21)	(0.09)	(0.12)
Operational Earnings	1.33	1.29	0.04
Weather Impact	0.17	(0.02)	0.19

Operational Earnings Highlights for First Quarter 2010

·   Utility’s results were higher due to higher net revenue driven by increased sales volumes across all customer classes, including the effect of significantly colder-than-normal weather.

·   Entergy Nuclear’s earnings decreased as a result of lower net revenue resulting primarily from lower pricing,  higher non-fuel operation and maintenance expense and a higher effective income tax rate.

·   Parent & Other’s results were higher due primarily to lower interest expense.

“Results for the quarter reflect an improving economy and its positive effects on our utility business, and the continuing volatility in commodity markets and its effect on our non-utility nuclear business,” said J. Wayne Leonard, Entergy’s chairman and chief executive officer.  “Looking forward, we will remain focused on managing cash flows and operating within our risk capacity and stakeholders’ risk tolerance.  We continue to believe our strategies drive long-term success and sustainability.”

Entergy’s business highlights include the following:

·   The Mississippi Public Service Commission approved revisions to Entergy Mississippi’s formula rate plan positioning the company to timely recover its business investments and bolstering its ability to provide safe, affordable and reliable power to its customers.

·   Entergy Texas achieved a unanimous settlement for an interim $17.5 million rate increase effective May 1, 2010.   The settlement also calls for a final rate case order to be issued November 1, 2010, with permanent rates to be effective relating back to service rendered on / after September 13, 2010.

·   Entergy was awarded the Edison Electric Institute Emergency Recovery Award for the 12th consecutive year for its work restoring power following a destructive ice storm in Arkansas last year.  Entergy is the only company to be honored every year since inception of the EEI awards in 1998.

Entergy will host a teleconference to discuss this release at 10 a.m. CT on Thursday, April 29, 2010, with access by telephone, 719-457-2080, confirmation code 3884569.  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 through May 6, 2010 by dialing 719-457-0820, confirmation code 3884569.  The replay will also be available on Entergy’s website at www.entergy.com.

I.   Consolidated Results

Consolidated Earnings

Table 2 provides a comparative summary of consolidated earnings per share for first quarter 2010 versus 2009, including a reconciliation of GAAP as-reported earnings to non-GAAP operational earnings.  Utility’s earnings increased quarter-over-quarter as a result of higher net revenue due primarily to increased sales volumes across all customer classes, including significantly colder-than-normal weather.  The effect of this increase was partially offset by higher non-fuel operation and maintenance expense and higher interest expense.  Entergy Nuclear’s first quarter 2010 earnings were lower than last year as a result of lower net revenue due primarily to lower pricing.  Also contributing to the lower results at Entergy Nuclear were increases in non-fuel operation and maintenance expense and a higher effective income tax rate.  Partially offsetting was higher other income from decommissioning trusts.  Parent and Other’s results improved in the current period compared to a year ago due primarily to lower interest expense.  Beginning with first quarter 2010, Parent & Other includes the results from the non-nuclear wholesale assets business.

Table 2: Consolidated Earnings – Reconciliation of GAAP to Non-GAAP Measures First Quarter 2010 vs. 2009 (see Appendix E for definitions of certain measures)
(Per share in U.S. $)
	First Quarter
	2010	2009	Change
As-Reported
Utility	0.73	0.56	0.17
Entergy Nuclear	0.49	0.91	(0.42)
Parent & Other	(0.10)	(0.27)	0.17
Consolidated As-Reported Earnings	1.12	1.20	(0.08)
Less Special Items
Utility	-	-	-
Entergy Nuclear	(0.29)	(0.04)	(0.25)
Parent & Other	0.08	(0.05)	0.13
Consolidated Special Items	(0.21)	(0.09)	(0.12)
Operational
Utility	0.73	0.56	0.17
Entergy Nuclear	0.78	0.95	(0.17)
Parent & Other	(0.18)	(0.22)	0.04
Consolidated Operational Earnings	1.33	1.29	0.04
Weather Impact	0.17	(0.02)	0.19

Detailed earnings variance analysis is included in Appendix A-1 to this release.  In addition, Appendix A-2 provides details of special items shown in Table 2 above.

Consolidated Net Cash Flow Provided by Operating Activities

Entergy’s net cash flow provided by operating activities in first quarter 2010 was $674 million compared to $375 million in first quarter 2009.  The overall quarterly increase was due primarily to:

·   the absence of hurricane and ice storm restoration spending of $314 million, which affected cash flow during first quarter 2009

·   higher net revenue at the Utility resulting from increased sales

Partially offsetting was:

·   a decrease in net deferred fuel recovery of $275 million at the Utility

Table 3 provides the components of net cash flow provided by operating activities contributed by each business with quarterly comparisons.

Table 3:  Consolidated Net Cash Flow Provided by Operating Activities
First Quarter 2010 vs. 2009
(U.S. $ in millions)
	First Quarter
	2010	2009	Change
Utility	416	151	265
Entergy Nuclear	306	254	52
Parent & Other	(48)	(30)	(18)
Total Net Cash Flow Provided by Operating Activities	674	375	299

II.   Utility

In first quarter 2010, Utility’s as-reported and operational earnings were $0.73 per share compared to $0.56 per share on the same bases in first quarter 2009.  Earnings for the Utility in the current quarter reflect higher net revenue due to increased sales across all customer classes and rate adjustments at Entergy Gulf States Louisiana, Entergy Louisiana and Entergy Mississippi under their formula rate plans.  Significantly colder-than-normal weather was a key contributor to the increase in sales volume.  Partially offsetting was higher non-fuel operation and maintenance expense resulting primarily from higher pension and benefits expense, as well as the absence of a nuclear insurance premium refund typically received from Nuclear Electric Insurance Limited included in first quarter results.  In addition, higher interest expense associated with additional debt issuances served as another partial offset to the positive effect of higher net revenue during the quarter.

Electricity usage, in gigawatt-hour sales by customer segment, is included in Table4.  Current quarter sales reflect the following:

·   Residential sales in first quarter 2010, on a weather-adjusted basis, increased 3.9 percent compared to first quarter 2009.

·   Commercial and governmental sales, on a weather-adjusted basis, increased 3.2 percent year over year.

·   Industrial sales in the first quarter increased 7.3 percent compared to the same quarter of 2009.

Residential, commercial and industrial classes reflected sales growth as a result of increasing economic activity in Entergy’s service territory. The improvement in industrial sales in first quarter 2010 was driven by economic recovery that had a positive effect particularly in the chemicals, pulp and paper and primary metals sectors partially offset by a decline in refining due to maintenance outages.  Small and mid-sized industrial customers began to also show signs of recovery as they benefited from global industrial expansion.  As noted above, colder-than-normal weather provided a significant increase in sales volume.

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

Table 4:  Utility Operational Performance Measures
First Quarter 2010 vs. 2009 (see Appendix E for definitions of measures)
	First Quarter
	2010	2009	% Change	% Weather Adjusted
GWh billed
Residential	9,645	7,893	22.2%	3.9%
Commercial and governmental	7,064	6,756	4.6%	3.2%
Industrial	8,733	8,139	7.3%	7.3%
Total Retail Sales	25,442	22,788	11.7%	4.9%
Wholesale	1,317	1,387	(5.0)%
Total Sales	26,759	24,175	10.7%
O&M expense per MWh	$17.29	$18.51	(6.6)%
Number of retail customers
Residential	2,348,838	2,321,488	1.2%
Commercial and governmental	348,414	343,871	1.3%
Industrial	38,782	38,892	(0.3)%

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

III.   Entergy Nuclear

Entergy Nuclear earned $0.49 per share on an as-reported basis in first quarter 2010, compared to as-reported earnings of $0.91 per share in first quarter 2009.  On an operational basis, first quarter 2010 Entergy Nuclear earnings were $0.78 per share versus $0.95 per share in the first quarter of the prior year.  Entergy Nuclear’s operational earnings decreased as a result of lower net revenue due primarily to lower pricing.  Contributing to the decrease in earnings were higher non-fuel operation and maintenance expense due primarily to tritium remediation work at the Vermont Yankee site, higher pension and benefits expense, refueling amortization expense, and insurance expense.  A higher effective income tax rate also contributed to the decrease in results this quarter driven primarily by the change in tax laws associated with recently enacted federal health care legislation.  Higher other income associated with decommissioning trusts provided an offset to decreased earnings.

Table 5 provides a comparative summary of Entergy Nuclear’s operational performance measures.

Table 5:  Entergy Nuclear Operational Performance Measures
First Quarter 2010 vs. 2009 (see Appendix E for definitions of measures)
	First Quarter
	2010	2009	% Change
Net MW in operation	4,998	4,998	-%
Average realized price per MWh	$58.72	$63.84	-8%
Production cost per MWh (a)	$23.70	$23.14	2%
Non-fuel O&M expense/purchased power per MWh(a)	$23.63	$22.44	5%
GWh billed	10,255	10,074	2%
Capacity factor	94%	92%	2%
Refueling outage days:
Indian Point 2 (b)	22	-
Indian Point 3	-	21
Palisades	-	9

(a)  First quarter 2009 and 2010 exclude the effect of the special item for non-utility nuclear spin-off expenses.

(b)  Table reflects the duration of refueling outages that occurred in first quarter 2010. For the Indian Point 2 plant, approximately 11 refueling outage days occurred in second quarter 2010.

Table 6 provides capacity and generation sold forward projections for Entergy Nuclear.

Table 6:  Entergy Nuclear’s Capacity and Generation Projected Sold Forward
Second Quarter 2010 through 2014 (see Appendix E for definitions of measures)
	Balance of 2010	2011	2012	2013	2014
Energy
Planned TWh of generation	30	41	41	40	41
Percent of planned generation sold forward (c)
Unit-contingent	54%	63%	31%	12%	14%
Unit-contingent with availability guarantees	37%	17%	14%	6%	3%
Firm LD	-%	2%	2%	-%	-%
Total Energy Sold Forward	91%	82%	47%	18%	17%
Average contract price per MWh (d)	$57	$55	$55	$50	$50
Capacity
Planned net MW in operation	4,998	4,998	4,998	4,998	4,998
Percent of capacity sold forward
Bundled capacity and energy contracts	27%	25%	18%	16%	16%
Capacity contracts	46%	26%	30%	13%	-%
Total Capacity Sold Forward	73%	51%	48%	29%	16%
Average capacity contract price per kW per month	$3.1	$3.6	$3.0	$2.6	-
Blended Capacity and Energy Recap (based on revenues)
Percent of planned energy and capacity sold forward	92%	84%	51%	18%	15%
Average contract revenue per MWh (d)	$59	$57	$57	$53	$50

(c)  A portion of EN’s total planned generation sold forward through March 2012 is associated with the Vermont Yankee contract, for which pricing may be adjusted.

(d)  Average contract prices exclude payments that may be owed under the value sharing agreement with the New York Power Authority.

IV.   Parent & Other

Parent & Other reported a loss of $(0.10) per share on an as-reported basis in first quarter 2010 compared to an as-reported loss of $(0.27) per share in first quarter 2009.  On an operational basis, Parent & Other reported a loss of $(0.18) per share in the current quarter and a loss of $(0.22) per share in first quarter 2009.  Lower interest expense due to lower borrowings, including Parent debt redemptions, was the primary factor that resulted in the change in results at Parent & Other for the quarter.

V.   Other Financial Performance Highlights

Earnings Guidance

On April 15, 2010, Entergy revised its 2010 as-reported earnings guidance to a range of $5.95 to $6.80 per share from $6.15 to $6.95 per share to reflect the potential charge in connection with the previously announced business unwind of the internal organizations created for Enexus and EquaGen.  This charge will be classified as a special item in 2010.  The total potential charge estimated at $0.40 to $0.45 per share includes previously identified special items for spin-off dis-synergies and expenses for outside services provided to pursue the spin-off, for which $0.25 per share had already been reflected in as-reported earnings guidance.  Entergy has initiated efforts to eliminate spin-off dis-synergies as soon as possible during 2010.

On an operational basis, Entergy affirmed its earnings per share guidance range of $6.40 to $7.20, which was based on the current business structure and excluded the special items described above.  Year-over-year changes are shown as point estimates and are applied to 2009 earnings to compute the 2010 guidance midpoint.  Drivers for the 2010 operational guidance range are listed separately.  Because there is a range of possible outcomes associated with each earnings driver, a range is applied to the calculated guidance midpoints to produce Entergy’s guidance ranges for as-reported and operational earnings.  The 2010 earnings guidance is detailed in Table 7 below.

Table 7:  2010 Earnings Per Share Guidance – As-Reported and Operational
(Per share in U.S. $) – Prepared October 2009; As-Reported Updated April 2010 (e)
Segment	Description of Drivers	2009 Earnings per Share	Expected Change	2010 Guidance Midpoint	2010 Guidance Range
Utility,  Parent,          & Other (includes Non-Nuclear Wholesale Assets)	2009 Operational Earnings per Share	3.22
	Adjustment to normalize weather		0.01
	Increased net revenue due to sales growth and rate actions		0.65
	Increased non-fuel operation and maintenance expense		(0.05)
	Increased depreciation expense		(0.08)
	Decreased other income		(0.15)
	Increased interest expense		(0.05)
	Non-nuclear wholesale assets contribution		(0.20)
	Accretion / other		0.20
	Subtotal	3.22	0.33	3.55
Entergy Nuclear	2009 Operational Earnings per Share	3.45
	Decreased net revenue due to lower pricing and volume		(0.15)
	Increased non-fuel operation and maintenance expense		(0.20)
	Increased depreciation expense		(0.05)
	Increased other income		0.20
	Accretion / other		-
	Subtotal	3.45	(0.20)	3.25
Consolidated Operational	2010 Operational Earnings per Share	6.67	0.13	6.80	6.40 – 7.20
Consolidated As-Reported	2009 As-Reported Earnings per Share
	Changes detailed above		0.13
	2010 Entergy Nuclear spin-off dis-synergies		(0.25)
	2009 Entergy Nuclear spin-off dis-synergies		0.23
	2009 Non-utility nuclear spin-off expenses for outside services at Parent & Other		0.14
	2010 As-Reported Earnings per Share Guidance Range	6.30	0.25	6.55	6.15 – 6.95
	Incremental special items related to the spin-off in connection with the business unwind		(0.15) – (0.20)
	Revised 2010 As-Reported Earnings per Share Guidance Range	6.30	0.05 – 0.10	6.35 – 6.40	5.95 – 6.80

(e)  Updated February 2010 to reflect 2009 final results and in April 2010 to reflect the special item for the total potential charge for the business unwind of Enexus and EquaGen.

Key assumptions supporting 2010 earnings guidance are as follows:

Utility, Parent & Other

·   Normal weather

·   Retail sales growth of around 4.5% on a weather adjusted basis; around 3% on a normalized basis excluding the effects of industrial expansion

·   Increased revenue associated with rate actions, including storm securitization which is offset by increased interest expense as noted below

·   Increased non-fuel operation and maintenance expense resulting from compensation and benefits expense and increased refueling outage amortization, largely offset by lower customer write-offs and the absence of 2009 storm related items

·   Increased depreciation associated with capital spending at the Utility

·   Decreased other income due to lower carrying charges and the absence of the 2009 gain on sale of land at the Utility

·   Increased interest expense associated with increased debt outstanding at the Utility, including storm securitization, partially offset by lower debt outstanding at the Parent

·   Break-even operations targeted for the non-nuclear wholesale assets business

·   Accretion / other is primarily driven by the effect of share repurchases in both 2009 and 2010

Entergy Nuclear

·   40 TWh of total output, reflecting an approximate 92 percent capacity factor, including 30 day refueling outages at Indian Point 2 and Vermont Yankee in Spring 2010 and FitzPatrick and Palisades in Fall 2010

·   88 percent of energy sold under existing contracts; 12 percent sold into the spot market

·   $57/MWh average energy contract price; $56/MWh average unsold energy price based on published market prices at the end of September 2009 (market prices have since declined with 2010 now averaging near $40 per MWh)

·   Palisades PPA revenue amortization of $46 million in 2010, down from $53 million in 2009

·   Non-fuel operation and maintenance expense, including refueling outage expense and purchased power, around $25/MWh resulting from increased compensation and benefits expense, higher NRC fees and increased refueling outage amortization

·   Increased depreciation associated with capital spending

·   Increased other income due primarily to the absence of 2009 decommissioning trust other than temporary impairments; earnings guidance does not incorporate assumptions for other than temporary impairments as financial market outcomes are outside of Entergy Nuclear’s control and difficult to predict

·   Offsetting effects of accretion / other are primarily driven by the effect of share repurchases in both 2009 and 2010, largely offset by a higher effective income tax rate in 2010

Share Repurchase Program

·   2010 average fully diluted shares outstanding of approximately 187 million (including effects of share repurchases in both 2009 and 2010)

Effective Income Tax Rate

·   2010 assumes an overall effective income tax rate of 36 percent

Revised 2010 As-Reported Earnings Guidance Range

·   In connection with the business unwind of the internal organizations for Enexus Energy Corporation and EquaGen LLC, the estimated range of a total potential charge of $0.40 to $0.45 per share reflects the write-off of capitalized costs incurred to date and certain other costs in accordance with generally accepted accounting principles.  This charge will be reported as a special item.  The range for this charge also includes the previously identified special items for spin-off dis-synergies and expenses for outside services provided to pursue the spin-off in 2010.

Earnings guidance for 2010 should be considered in association with earnings sensitivities as shown in Table 8.  These sensitivities illustrate the estimated change in operational earnings resulting from changes in various revenue and expense drivers.  Traditionally, the most significant variables for earnings drivers are utility sales for Utility, Parent & Other and energy prices for Entergy Nuclear.  The broader earnings guidance range for 2010 also takes into consideration the following:

·   A number of regulatory initiatives (rate actions) underway across the Utility jurisdictions

·   Timing flexibility for executing the share repurchase program across the year (guidance assumes execution on a ratable basis)

·   Potential outcomes for projected pension plan discount rate (guidance assumed 6.75%; actual is 6.1 – 6.3%)

Estimated annual impacts shown in Table 8 are intended to be indicative rather than precise guidance.

Table 8:  2010 Earnings Sensitivities
(Per share in U.S. $) – Prepared October 2009
Variable	2010 Guidance Assumption	Description of Change	Estimated Annual Impact (f)
Utility, Parent & Other
Sales growth   Residential   Commercial / Governmental   Industrial	Around 4.5% total 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	- / + 0.33
Entergy Nuclear
Capacity factor	92% capacity factor	1% change in capacity factor	- / + 0.07
Energy price	12% energy unsold at $56/MWh in 2010	$10/MWh change for unsold energy	- / + 0.15
Non-fuel operation and maintenance expense	$25/MWh non-fuel operation and maintenance expense/purchased power	$1/MWh change	+ / - 0.13
Outage (lost revenue only)	92% capacity factor, including refueling outages for four northeast units	1,000 MW plant for 10 days at average portfolio energy price of $57/MWh for sold and $56/MWh for unsold volumes in 2010	- 0.04 / n/a

(f)  Based on 2009 average fully diluted shares outstanding of approximately 196 million.

VI.   Long-term Financial Outlook

Overarching Financial Aspiration

Entergy continues to aspire to deliver superior value to owners as measured by total shareholder return.  The company believes top-quartile total shareholder returns are achieved by:

·   Operating the business with the highest expectations and standards,

·   Executing on earnings growth opportunities while managing commodity and other business risks,

·   Delivering returns at or above the risk-adjusted cost of capital for each initiative, project, business, etc.,

·   Maintaining credit quality and flexibility,

·   Deploying capital in a disciplined manner, whether for new investments, share repurchases, dividends or debt retirements, and

·   Being disciplined as either a buyer or a seller consistent with the market or Entergy’s proprietary point-of-view.

Long-term Financial Outlook

Over the next five years, Entergy believes it offers a competitive utility investment opportunity combined with a valuable option represented by a unique, clean, non-utility nuclear generation business located in attractive power markets.  Table 9 summarizes the current long-term financial outlook.

Table 9:  Long-term Financial Outlook
Prepared April 2010
Category	Long-term Outlook	Assumption
Earnings	Utility net income	5 to 6 percent compound annual net income growth rate over the 2010 – 2014 horizon (2009 base year).
	Entergy Nuclear results	Revenue projections over the next five years are expected to routinely fluctuate based on commodity markets – one of the most important fundamental drivers for this business.  While current forward power prices would show a decline in the long-term financial outlook for this business compared to 2010, Entergy Nuclear offers a valuable option taking into consideration the contango forward curve and the potential positive effects of an economic rebound (on market heat rates, capacity markets and natural gas prices), new legislation and / or regulation over the longer term.
	Corporate results	Results will vary depending upon factors including future effective income tax and interest rates, the amount of share repurchases and the ability to achieve the targeted break-even financial result for the non-nuclear wholesale assets business.
Capital Deployment	A balanced capital investment / return program	Entergy continues to see productive investment opportunities at the Utility in the coming years, as well as an investment outlook at Entergy Nuclear 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, return of capital is expected to be provided similar to the past through a combination of common stock dividends and share repurchases.  Absent other attractive investment opportunities, capital deployment through dividends and share repurchases could total as much as $5 billion over the next five years under the current long-term business outlook. The amount of share repurchases may vary as a result of material changes in business results or capital spending or new investment opportunities.
Credit Quality		Strong liquidity.
		Solid credit metrics that support ready access to capital on reasonable terms.

The long-term financial outlook should be considered in association with 2014 financial sensitivities as shown in Table 10.  These sensitivities illustrate the estimated change in earnings or Adjusted EBITDA resulting from changes in business drivers.  Estimated impacts shown in Table 10 are intended to be illustrative.

Table 10:  2014 Financial Sensitivities – Illustrative
Prepared April 2010
Long-term Outlook	Assumption	Drivers	Estimated Annual Impact
Utility			(Per share in U.S. $) (g)
Earnings growth	5 – 6% compound annual net income growth rate from 2010 through 2014 (2009 base)	1% retail sales growth $100 million/year investment in service 1% change in allowed ROE 1% change in non-fuel operation and maintenance expense $100 million change in debt	- / + 0.13 - / + 0.03 - / + 0.44 + / - 0.07 + / - 0.02
Entergy Nuclear			(Adjusted EBITDA in U.S. $; millions) (h)
Adjusted EBITDA	Decline in Adjusted EBITDA at current forward power prices compared to 2010, plus option value	+0 – 1,500 Btu/kWh heat rate expansion +$0 – 30/ton CO2 +$0 – 4/kW-mo. capacity price - / + $0 – 2/MMBtu change in gas price	Up to 300 Up to 500 Up to 200 Down / Up to 600
Corporate			(Per share in U.S. $) (g)
Balanced capital investment  / return / credit quality		1% change in interest rate on $1 billion debt 1% change in overall effective tax rate $500 million share repurchase	+ / - 0.03 + / - 0.10 + 0.20 – 0.25
(g) Based on estimated 2010 average fully diluted shares outstanding of approximately 187 million. (h) Adjusted EBITDA, a non-GAAP financial measure, is defined as earnings before interest, income taxes, depreciation and amortization and interest and dividend income, excluding decommissioning expense and other than temporary impairment losses on decommissioning trust fund assets.

VII.   Appendices

Six appendices are presented in this section as follows:

·   Appendix A includes earnings per share variance analysis and detail on special items that relate to the current quarter results.

·   Appendix Bprovides information on selected pending local and federal regulatory cases.

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

·   Appendix D provides a summary of planned capital expenditures for the next three years.

·   Appendix E provides definitions of the operational performance measures and GAAP and non-GAAP financial measures that are used in this release.

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

A.    Variance Analysis and Special Items

Appendix A-1 provides details of first quarter 2010 vs. 2009 as-reported and operational earnings variance analysis for “Utility,” “Entergy Nuclear,” “Parent & Other,” and “Consolidated.”

Appendix A-1: As-Reported and Operational Earnings Per Share Variance Analysis
First Quarter 2010 vs. 2009
(Per share in U.S. $, sorted in consolidated as-reported column, most to least favorable)
	Utility			Entergy Nuclear			Parent & Other			Consolidated
	As-Reported	Opera- tional		As-Reported	Opera-tional		As- Reported	Opera-tional		As- Reported	Opera-tional
2009 earnings	0.56	0.56		0.91	0.95		(0.27)	(0.22)		1.20	1.29
Net revenue	0.29	0.29	(i)	(0.15)	(0.15)	(j)	0.01	0.01		0.15	0.15
Other than temporary impairment losses	-	-		0.05	0.05	(k)	-	-		0.05	0.05
Share repurchase effect	0.02	0.02		0.02	0.02		-	-		0.04	0.04
Other income (deductions)	(0.02)	(0.02)		0.05	0.05	(l)	-	-		0.03	0.03
Interest and other charges	(0.05)	(0.05)	(m)	(0.10)	0.03		0.05	0.05	(n)	(0.10)	0.03
Taxes other than income taxes	(0.01)	(0.01)		0.01	0.01		-	-		-	-
Decommissioning expense	-	-		(0.01)	(0.01)		-	-		(0.01)	(0.01)
Depreciation/ amortization expense	(0.02)	(0.02)		(0.01)	-		-	-		(0.03)	(0.02)
Nuclear refueling outage expense	(0.01)	(0.01)		(0.01)	(0.01)		-	-		(0.02)	(0.02)
Other operation & maintenance expense	(0.04)	(0.04)		(0.15)	(0.04)		0.01	(0.02)		(0.18)	(0.10)
Income taxes – other	0.01	0.01		(0.12)	(0.12)	(o)	0.10	-		(0.01)	(0.11)
2010 earnings	0.73	0.73		0.49	0.78		(0.10)	(0.18)		1.12	1.33

Utility Net Revenue Variance Analysis 2010 vs. 2009 ($ EPS)
First Quarter
Weather	0.19
Sales growth/ pricing	0.08
Other	0.02
Total	0.29

(i) The increase is due primarily to colder-than-normal weather during the current period.  Also, higher pricing resulting from adjustments to the formula rate plans for Entergy Gulf States Louisiana, Entergy Louisiana and Entergy Mississippi, as well as an increase in weather-adjusted sales across all customer classes and jurisdictions, increased revenues during the period.

(j) The decrease is due primarily to lower revenues at Entergy Nuclear in the current period resulting from lower pricing.

(k) The increase is due to the absence in the current period of impairments recorded in first quarter 2009 associated with decommissioning trust fund investments.

(l) The increase is due primarily to higher earnings resulting from sales of securities held in decommissioning trust investments.

(m) The decrease is due to higher interest expense on increased debt borrowings.

(n) The increase is due primarily to lower interest expense on lower parent borrowings including parent debt redemptions.

(o) The decrease is due primarily to the change in tax law associated with recently enacted federal health care legislation.

Appendix A-2 lists special items by business with quarter-to-quarter comparisons.  Amounts are shown on both earnings per share and net income bases.  Special items are those events that are less routine, are related to prior periods, or are related to discontinued businesses.  Special items are included in as-reported earnings per share consistent with generally accepted accounting principles (GAAP), but are excluded from operational earnings per share.  As a result, operational earnings per share is considered a non-GAAP measure.

Appendix A-2:  Special Items (shown as positive / (negative) impact on earnings)
First Quarter 2010 vs. 2009
(Per share in U.S. $)
	First Quarter
	2010	2009	Change
Utility
None	-	-	-
Entergy Nuclear
Non-utility nuclear spin-off expenses (p)	(0.29)	(0.04)	(0.25)
Parent & Other
Non-utility nuclear spin-off expenses (p)	0.08	(0.05)	0.13
Total Special Items	(0.21)	(0.09)	(0.12)
(U.S. $ in millions)
	First Quarter
	2010	2009	Change
Utility
None	-	-	-
Entergy Nuclear
Non-utility nuclear spin-off expenses (p)	(54.3)	(6.6)	(47.7)
Parent & Other
Non-utility nuclear spin-off expenses (p)	14.4	(10.6)	25.0
Total Special Items	(39.9)	(17.2)	(22.7)

(p)  Includes spin-off dis-synergies and previously contracted expenses for outside services to pursue the spin-off in both periods and the charge in connection with the business unwind in 2010.

B.   Regulatory Summary

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

Appendix B: Regulatory Summary Table
Company	Pending Cases / Events
Retail Regulation
Entergy Arkansas Authorized ROE:  9.9% Last Filed Rate Base: $4.1 billion Filed 9/09 based on 6/30/09 test year, with known and measurable changes through 6/30/10	Rate Case Recent Activity:  All testimony has been filed.Current APSC Staff position proposes a $49 million revenue requirement increase reflecting a 10.1% ROE and $10 million for the 2009 ice storm.  In the event a Formula Rate Plan (FRP) is adopted, Staff recommends a further ROE reduction to 9.6%.  EAI reduced its request to $168 million reflecting a lower ROE at 10.65% and the reduction to remove the revenue requirement associated with ice storm recovery from its case as discussed below.  Also, on February 11, 2010, the APSC requested comments from parties in the rate case on various issues raised related to transmission cost recovery mechanisms.  On March 3, 2010, EAI filed supplemental testimony regarding transmission costs and investments and potential recovery through a transmission rider or the proposed FRP. Background:  On September 4, 2009, EAI filed a rate case requesting a $223.2 million increase reflecting an 11.5% ROE based on a June 30, 2009 test year with known and measurable changes through June 30, 2010.  The filing also includes a proposed FRP.  Key provisions include a +/- 25 basis point bandwidth, with earnings outside the bandwidth reset to the 11.5% midpoint ROE and rates changing on a prospective basis depending on whether EAI is over or under-earning.  The proposed FRP also includes a recovery mechanism that provides timely recovery for APSC-approved expense for additional capacity purchases or construction / acquisition of new transmission or generating facilities.  Finally, the proposed FRP includes an energy efficiency-related mechanism.  Hearings are scheduled to begin in May 2010, with an effective date for new rates of July 2010.  EAIimplemented its last base rate change, a $5.1 million rate reduction, on August 29, 2007.
	Storm Cost Recovery Recent Activity:  The Administrative Law Judge approved the establishment of EAI’s storm cost reserve account on April 16, 2010using the annual amount of $14.449 million previously established.  Hearings are scheduled in the securitization docket for April 29, 2010, and an APSC order is due no later than June 15, 2010.  Since EAI’s analysis demonstrated that retail customers will benefit from lower costs using securitization versus conventional utility financing, EAI conditionally removed ice storm recovery from the pending rate case filing in its rebuttal testimony filed on March 24, 2010, pending authorization by the APSC to securitize these costs. Background:  EAI incurred approximately $123 million in estimated restoration costs resulting from the severe ice storm that struck in January 2009.  Considering the magnitude of the statewide storm damages, the Arkansas legislature passed legislation authorizing storm reserve accounting in March 2009, followed by the enactment of storm securitization legislation in April.  Both pieces of legislation are effective for storms occurring on or after January 1, 2009.  At the end of March 2009, EAI filed a petition with the APSC to establish storm reserve accounting pursuant to the legislation for which a hearing was scheduled for March 9, 2010.  In the interim, the APSC approved on March 6, 2009 EAI’s application for an accounting order authorizing the deferral of the operation and maintenance cost portion of the ice storm restoration costs pending their recovery.  As part of EAI’s September 4, 2009 rate case filing, EAI included the 2009 ice storm restoration costs in cost-of-service, indicating the ice storm restoration costs would be removed from the pending rate case if the APSC approved EAI’s request to securitize the ice storm costs.  On February 1, 2010, EAI requested a financing order to issue approximately $127.5 million in storm recovery bonds which included carrying costs of $11.7 million and $4.6 million of up-front financing costs to pay for ice storm restoration.
	White Bluff Environmental Controls Project Recent Activity:  On February 26, 2010, the APSC approved EAI’s request to withdraw its Act 310 application.  On March 26, 2010, the Arkansas Pollution Control and Ecology Commission voted to grant EAI’s variance request from the state’s 2013 compliance date and tie the date to a compliance requirement within five years of the United States Environmental Protection Agency’s (U.S. EPA) approval of the state’s implementation plan. Background:  In March 2009, EAI petitioned the APSC to undertake a project that would have installed scrubbers and low NOx burners at the co-owned White Bluff coal plant at an expected total cost of approximately $1.0 billion, and EAI’s share at $631 million, with estimates revised downward in October 2009 to $780 million, with EAI’s revised share at $465 million.  White Bluff Units 1 and 2 had been required to meet more stringent SO2 and NOx limits by 2013 in order to comply with the Arkansas Department of Environmental Quality (ADEQ) State Implementation Plan regulations implementing the U.S. EPA’s Regional Haze Rule.  EAI conducted economic analysis comparing the project to other supply options and concluded the project was the lowest reasonable cost alternative. EAI had intended to recover the project costs pursuant to Act 310 through an interim rate schedule to be amended periodically.  In December, the APSC suspended the procedural schedule following letters submitted by the U.S. EPA and the U.S. Department of Agriculture to the ADEQ regarding concerns about issuing draft air permits for the SO2 scrubbers and NOx controls.  Later that month, EAI and other interested parties requested a variance from the state’s 2013 compliance date and suspended all work on the project.  EAI also filed a notice of withdrawal of its Act 310 filing and refunded limited collections received to date in January.
	Show Cause Order Regarding System Agreement / Future Operation and Control of EAI’s Generation and Transmission Assets Recent Activity:  In March, EAI filed testimony and participated in a hearing in response to the APSC Show Cause proceeding initiated in February 2010.  Another hearing is scheduled to take place in May 2010 following the filing of additional testimony ordered by the APSC. Background:  On February 11, 2010, the APSC issued a Show Cause order opening an inquiry to conduct an investigation, with the intent to render its decision by the end of 2010, regarding the prudence of EAI entering a successor Entergy System Agreement, as opposed to becoming a stand-alone entity upon exit from the System Agreement in December 2013, and whether EAI, as a stand-alone utility should join the Southwest Power Pool Regional Transmission Organization (SPP RTO) (the APSC subsequently added participation as a member in the Midwest ISO as an alternative to be evaluated).  As a parallel matter, the APSC will also monitor whether Entergy will make any meaningful enhancements to its Independent Coordinator of Transmission (ICT) arrangement in 2010 with filings at FERC.  EAI noted in its testimony

Appendix B: Regulatory Summary Table (continued)
Company	Pending Cases / Events
Retail Regulation
Entergy Arkansas (continued)	that it is not reasonable to complete a comprehensive evaluation of strategic options by the end of 2010 and that forcing a decision would place parties in the untenable position of making critical decisions based on insufficient information.  EAI outlined three options for post-System Agreement operation of its electrical system: EAI Self Provide –  as a stand-alone company for resource planning; EAI plus new Coordination Agreements with Third Parties – EAI self provides or contracts some functions, but also enters into one or more coordinating and / or pooling agreements with third parties, such as SPP RTO; and Successor Arrangements – EAI plans for its own generation resources but enters into a new generation agreement with other Entergy operating companies under a successor agreement that benefits all, but avoids the litigation previously experienced.  EAI’s plan is expected to lead to a decision regarding critical path issues in late 2011; however, EAI anticipates several transition plan elements will move forward in 2010 and require ongoing dialogue.  In an attempt to reach understanding of complex issues, EAI proposes to hold a series of five technical conferences in the coming months targeting specific subject matter.  The initial technical conference is scheduled for May 5, 2010.
Entergy Gulf States Louisiana Authorized ROE Range:  9.9% - 11.4% (electric) Last Filed Rate Base: $2.2 billion (electric) Filed 12/09 based on 12/31/08 test year	Formula Rate Plan Recent Activity:  Discovery continues on 2008 test year filing.  EGSL will make its 2009 test year filing by May 31, 2010. Background:  At its October 2009 Business and Executive Session, the LPSC approved an uncontested settlement extending the FRP regulatory process for an additional three years.  The new FRP was adopted for the 2008-2010 test years and retains the 10.65% ROE midpoint with a +/- 75 basis point bandwidth and a recovery mechanism for Commission-approved capacity additions.  Earnings outside the bandwidth are allocated prospectively, 60% to customers and 40% to the company.  As part of the settlement, EGSL implemented a one-time rate reset to achieve its 10.65% midpoint ROE for the 2008 test year filing, which was filed October 21, 2009.  This filing reflected an 8.64% earned ROE and total rate increase of $44.3 million, including a $36.9 million cost of service adjustment, plus $7.4 million net for increased capacity costs and a base rate reclassification.  New rates took effect coincident with the November 2009 billing cycle and are subject to review and final approval by the LPSC.  All parties also committed to work together to attempt to develop a transmission rider for EGSL with the latest schedule anticipating the LPSC could address this matter at its May 2010 Business and Executive session.  In January, EGSL implemented a further $23.9 million rate increase pursuant to the special rate implementation filing made in December, primarily for incremental capacity costs approved by the LPSC.  In addition, in December 2009, EGSL filed a joint application seeking LPSC approval for a $9.7 million revenue requirement to provide supplemental funding for the decommissioning trust maintained for the LPSC-regulated 70% share of River Bend, in response to the NRC notification of a projected shortfall of decommissioning funding assurance.  Currently, EGSL has no funding in retail rates for decommissioning.
	Storm Cost Recovery Recent Activity:  At its April 21, 2010 Business and Executive Session, the LPSC approved uncontested stipulated settlements resolving all issues in Phase I (level of storm cost recovery, level of recovery for storm reserves and the allocation of the revenue requirements associated with those amounts among retail customers) and Phases II and III (issuance of system restoration bonds, the structure of the proposed financings and non-shareholder capital contributions, system restoration charges and storm cost offset riders). Background:  In lieu of seeking interim recovery, on October 9, 2008, EGSL accessed $85 million of storm reserves funded by securitized debt proceeds.  On October 15, 2008, the LPSC approved EGSL’s request to defer and accrue carrying cost on unrecovered storm expenditures during the period the company seeks regulatory recovery.  The approval was without prejudice to the ultimate resolution of the total amount of prudently incurred storm cost or final carrying cost rate.  New financing legislation was not needed, as existing legislation extends to Gustav and Ike.  EGSL initiated its storm recovery proceeding for hurricanes Gustav and Ike on May 11, 2009.  EGSL also sought to replenish its storm reserve in the amount of $90 million.  On September 29, 2009, EGSL filed its first and second supplemental and amending joint applications in the storm proceeding requesting that the LPSC approve and authorize alternative (Act 55) financing.  EGSL expects significant potential financing savings from pursuing Act 55 alternative financing and plans to guarantee customer savings, consistent with the approach used for hurricanes Katrina and Rita.  On December 30, 2009, EGSL entered into a black box stipulation agreement with the LPSC Staff that provided for total recoverable costs of nearly $234 million (greater than 98% of EGSL’s request) and permitted replenishing EGSL’s storm reserve in the amount of $90 million when Act 55 financing is accomplished.
Entergy Louisiana Authorized ROE Range:  9.45% - 11.05% Last Filed Rate Base: $2.9 billion Filed 10/09 based on 12/31/08 test year	Formula Rate Plan Recent Activity: At its April 21, 2010 Business and Executive Session, the LPSC accepted the joint LPSC Staff / ELL report indicating agreement to implement a prospective reduction in ELL’s rates of $144.4 thousand beginning with the May 2010 billing cycle and to refund $72.2 thousand plus judicial interest through the fuel adjustment clause.  Further, ELL will move the recovery of approximately $12.5 million of capacity costs associated with EAI’s Wholesale Baseload Capacity Resource from fuel adjustment clause recovery to base rate recovery.  ELL will make its 2009 test year filing by May 15, 2010. Background: At its October 2009 Business and Executive Session, the LPSC approved an uncontested settlement extending the FRP regulatory process for an additional three years.  The new FRP was adopted for the 2008-2010 test years and retains the 10.25% ROE midpoint with a +/- 80 basis point bandwidth and a recovery mechanism for Commission-approved capacity additions.  Earnings outside the bandwidth are allocated prospectively, 60% to customers and 40% to the company.  As part of the settlement, ELL implemented the one-time rate reset noted previously to achieve its 10.25% midpoint ROE for the 2008 test year filing, which was filed October 21, 2009.  This filing reflected a 9.35% earned ROE and total rate increase of $2.5 million, including a $16.3 million cost of service adjustment, less a $13.8 million net reduction for decreased capacity costs and a base rate reclassification. New rates took effect coincident with the November 2009 billing cycle and were subject to review and final approval by the LPSC.  All parties also committed to work together to attempt to develop a transmission rider for ELL with latest schedule anticipating the LPSC could address this matter at its May 2010 Business and Executive session.  In addition, in December 2009, ELL filed a joint application seeking LPSC approval for a $10.3 million revenue requirement to provide supplemental funding for the decommissioning trust maintained for the LPSC-jurisdictional portion of Waterford 3, in response to the NRC notification of a projected shortfall of decommissioning funding assurance.  Currently, ELL has $2.2 million in retail rates for decommissioning.

Appendix B: Regulatory Summary Table (continued)
Company	Pending Cases/Events
Retail Regulation
Entergy Louisiana (continued)	Storm Cost Recovery Recent Activity:  At its April 21, 2010 Business and Executive Session, the LPSC approved uncontested stipulated settlements resolving all issues in Phase I (level of storm cost recovery, level of recovery for storm reserves and the allocation of the revenue requirements associated with those amounts among retail customers) and Phases II and III (issuance of system restoration bonds, the structure of the proposed financings and non-shareholder capital contributions, system restoration charges and storm cost offset riders). Background:  In lieu of seeking interim recovery, on October 9, 2008, ELL accessed $134 million of storm reserves funded by securitized debt proceeds.  On October 15, 2008, the LPSC approved ELL’s request to defer and accrue carrying cost on unrecovered storm expenditures during the period the company seeks regulatory recovery.  The approval was without prejudice to the ultimate resolution of the total amount of prudently incurred storm cost or final carrying cost rate.  New financing legislation was not needed, as existing legislation extends to Gustav and Ike.  ELL initiated its storm recovery proceeding for hurricanes Gustav and Ike on May 11, 2009.  ELL also sought to replenish its storm reserve in the amount of $200 million.  On September 29, 2009, ELL filed its first and second supplemental and amending joint applications in the storm proceeding requesting that the LPSC approve and authorize alternative (Act 55) financing.  ELL expects significant potential financing savings from pursuing Act 55 alternative financing and plans to guarantee customer savings, consistent with approach used for hurricanes Katrina and Rita.  On December 30, 2009, ELL entered into a black box stipulation agreement with the LPSC Staff that provided for total recoverable costs of approximately $394 million (greater than 98% of ELL’s request) and permitted replenishing ELL’s storm reserve in the amount of $200 million when Act 55 financing is accomplished.
	Acadia Unit 2 Acquisition Recent Activity:  Hearings are scheduled to begin in September 2010 pursuant to the procedural schedule established February 9, 2010.  Consideration of the application at the January 2011 LPSC Business and Executive Session would accommodate a closing by the March 31, 2011 deadline triggering certain price increases.  The Hart-Scott-Rodino Antitrust Improvements Act filing was made in March 2010.  On April 9, 2010, the LPSC approved ELL and EGSL’s uncontested request concerning the limited-term Interim Tolling Agreement (ITA) associated with the Acadia acquisition.  The ITA, originally scheduled to begin on May 1, 2010, is now anticipated to begin on June 1, 2010 to allow the companies time to appropriately address various regulatory considerations. Background:  ELL signed a purchase and sale agreement to acquire the 580 MW Unit 2 of the Acadia Energy Center for $300 million ($517/kW).  ELL proposes to acquire 100% of Acadia Unit 2 and a 50% ownership interest in the facility’s common assets.  Cleco Power will serve as operator for the entire facility.  ELL has committed to sell one third of the output to Entergy Gulf States Louisiana in accordance with terms and conditions detailed under the existing System Agreement.  The purchase is contingent upon, among other things, obtaining necessary approvals, including full cost recovery, from various federal and state regulatory and permitting agencies and the filing of notification under Hart-Scott-Rodino antitrust law.  Closing is expected to occur in early 2011.  ELL has also entered into an Interim Tolling Agreement (ITA) to purchase the capacity and energy output of Acadia Unit 2.  The ITA, originally scheduled to begin on May 1, 2010, is now anticipated to begin on June 1, 2010 to allow the companies time to appropriately address various regulatory considerations.  On January 29, 2010, ELL initiated its Section 203 filing at FERC seeking authorization to acquire Power Block Two of the Acadia Energy Center from Acadia Power Partners, LLC.
	Little Gypsy Repowering Recent Activity:  Discovery continues, and hearings are scheduled for October 2010. Background:  In November 2007, the LPSC voted unanimously, subject to conditions, to approve ELL’s request to repower the 538 MW Little Gypsy unit to utilize CFB technology.  The order also included a recovery provision for prudently incurred costs in the event circumstances changed materially.  The project later experienced a delay resulting from the need to conduct additional environmental analysis (Maximum Achievable Control Technology application).  The additional analysis estimated construction could commence by mid-year 2009 leading to a targeted in service date by mid-year 2013 and resulting in a project cost estimate increase to $1.76 billion.  In March 2009, the LPSC issued an order directing ELL to temporarily suspend the project and file a report with the LPSC on the economic viability of the project and develop a recommendation regarding whether to delay the project for an extended time.  In April 2009, ELL recommended to the LPSC that it continue the temporary project suspension and make a filing with the LPSC seeking a longer-term suspension (three years or more) of the project.  In May 2009, the LPSC unanimously accepted ELL’s recommendation and issued an order finding that ELL’s decision to place the Little Gypsy project in longer-term suspension of 3 years or more was in the public interest and prudent, without prejudice to issues of prudence of timing of decisions, project management, whether ELL may recover project costs from retail customers and the manner of that recovery and whether the project should be canceled or abandoned as opposed to merely suspended.  ELL dismissed its proceeding to recover cash earnings on Construction Work in Progress (CWIP) for the Little Gypsy project.  In October 2009, ELL filed seeking LPSC authorization to cancel the Little Gypsy Unit 3 repowering project allowing ELL to cancel permits, eliminating the requirement to monitor the project for potential restart.  This approach requires starting over should the decision be made to engage in a similar future project.  In addition, ELL sought to recover cost incurred on a levelized five-year recovery basis to be trued up.  In the event ELL’s costs exceed the authorized amount, ELL proposed that it be required to justify any additional recovery.  Pursuant to the procedural schedule, in January 2010, ELL filed an updated cost estimate of nearly $215 million, including nearly $193 million of costs incurred through December 31, 2009 and $22 million of net cancellation / project termination costs including AFUDC through March 2011.

Appendix B: Regulatory Summary Table (continued)
Company	Pending Cases/Events
Retail Regulation
Entergy Mississippi Authorized ROE Range:  10.79% - 13.05% (subject to review / approval) Last Filed Rate Base: $1.5 billion Filed 3/10 based on 12/31/09 test year	Formula Rate Plan Recent Activity:  On March 4, 2010, the MPSC approved modifications to EMI’s FRP that (1) aligns EMI’s FRP more closely with the FRPs of the other regulated gas and electric utilities in Mississippi, (2) resets the ROE and bandwidth based upon performance ratings, (3) rescores the performance adjustment factors, (4) eliminates the current $14.5 million revenue adjustment limit and changes the 2% of revenues limit to a 4% limit, with any adjustment over 2% requiring a hearing, and (5) directs EMI to phase-out the summer / winter rate differential in residential rates over two years.  On March 15, 2010, EMI filed its first evaluation report under its new FRP for the 2009 test year.  The filing reflected a 10.66% earned ROE and total rate increase of $11.8 million.  The calculated 11.92% FRP midpoint ROE includes the benefit of a 0.76% performance incentive.  The FRP calls for new rates to be implemented in the June 2010 billing cycle, subject to review and final approval by the MPSC. Background:  EMI had been operating under a FRP last approved in December 2002.  The FRP allowed the company’s earned ROE to increase or decrease within a bandwidth with no change in rates.  Earnings outside the bandwidth were allocated 50% to customers and 50% to the company, but on a prospective basis only.  The plan also provided for performance incentives that can increase or decrease the benchmark ROE by as much as 100 basis points.  On June 30, 2009, the MPSC approved EMI’s 2008 FRP adjustment increase of $14.5 million effective July 1, 2009.
	Fuel Recovery / Attorney General Complaint Recent Activity:  The MPSC continues to investigate issues associated with EMI fuel costs and claims raised by the Mississippi Attorney General (AG) going back some 30 years.  On March 9, 2010, the MPSC established a Fuel Adjustment Clause (FAC) rulemaking to consider various issues, including an analysis of the advantages / disadvantages of using monthly, quarterly, semi-annual or annual FACs.  A proposed rule is expected to be issued by May 20, 2010.  On March 30, 2010, McFadden Consulting Group, Inc. presented their report on the management review of EMI’s fuel practices and procedures for the two year period October 2007 through September 2009.  In the report, McFadden indicated that the fuel and purchased power costs for Mississippi are reasonable and at the lowest cost possible given the operations and design of the Entergy system. Background:  The Commission has been reviewing state utilities’ practices and procedures, most notably related to fuel recovery.  EMI understands the MPSC’s need to obtain more information about past Commission actions, system tariffs, and issues including fuel purchases, fuel costs and power generation needs, and will continue to work with the Commission to inform, respond to questions and develop alternative policies on tariffs if they are found to be in the best interests of customers and fairly balanced with other stakeholder rights. In addition, the AG issued civil investigative demands directed at EMI and other Entergy companies related to EMI’s FAC and other matters.  The AG voluntarily dismissed this proceeding, and instead filed a complaint in state court in December 2008 against EMI and other Entergy companies alleging, among other things, violations of Mississippi statutes, fraud, and breach of good faith and fair dealing, and requesting an accounting and restitution.  The litigation is wide ranging and relates to tariffs and procedures under which EMI obtains power in the wholesale market to meet electricity demand.  EMI believes the complaint is unfounded, and should be resolved in the appropriate regulatory forum.  On December 29, 2008, the affected Entergy companies filed to remove the AG’s suit to U.S. District Court where it is currently pending, and additionally answered the complaint and filed a counter-claim for injunctive and other relief based upon the Mississippi Public Utilities Act and the Federal Power Act.  The AG has filed a pleading seeking to remand the case to state court. On February 10, 2009, an independent audit report commissioned by the MPSC to review fuel recovery was released.  The report indicated that many of EMI’s fuel procurement and adjustment practices are sound and in the customers’ best interest.  On June 30, 2009, the MPSC issued an order authorizing an audit of EMI’s FAC by an independent audit firm.  The financial portion of the fuel audit undertaken at the request of the MPSC performed by Horne Group LLP for the years ended September 30, 2008 and 2009 does not recommend that any costs be disallowed for recovery.  The January 2010 report did suggest that some costs (less than one percent of the $1.66 billion in fuel and purchased energy during the period) may have been more reasonably charged to customers through base rates rather than through fuel charges, but the report did not suggest that customers should not have paid for those costs.  At the January 2010 MPSC open / public meeting, the Mississippi Public Utilities Staff stated that costs identified by Horne as excludable were indeed properly recoverable in EMI’s FAC.
Entergy New Orleans Authorized ROE Range: 10.7% - 11.5% (electric) 10.25% - 11.25% (gas) Last Filed Rate Base: $0.3 billion (electric) $0.1 billion (gas) Filed 7/08 based on 12/31/07 test year	Formula Rate Plan Recent activity:  None.  ENOI will make its 2009 test year filing by May 31, 2010. Background:  A new three year FRP beginning with the 2009 test year was adopted in ENOI’s rate case settled in April 2009.  Key provisions include an 11.1% electric ROE and a +/- 40 basis point bandwidth and a 10.75% gas ROE with a +/- 50 basis point bandwidth.  Earnings outside the bandwidth reset to the midpoint ROE, with rates changing on a prospective basis depending on whether ENOI is over or under-earning.  The FRP also includes a recovery mechanism for Council-approved capacity additions, plus provisions for extraordinary cost changes and force majeure.  The FRP may be extended by the mutual agreement of ENOI and the City Council of New Orleans (CCNO).  The settlement also implemented energy conservation and demand programs.  Effective June 1, 2009, pursuant to its April rate case settlement, ENOI implemented a total electric bill reduction of $35.3 million, including conversion of the $10.6 million voluntary recovery credit to a permanent reduction and complete realignment of Grand Gulf recovery from fuel to base rates, and a $4.95 million gas rate increase. On September 17, 2009, the CCNO approved the Energy Smart Resolution.  Energy Smart is the energy efficiency program that was filed pursuant to ENOI’s April 2009 rate case settlement.

Appendix B: Regulatory Summary Table (continued)
Company/ Proceeding	Pending Cases/Events
Retail Regulation
Entergy Texas Authorized ROE:  10.0% Last Filed Rate Base: $1.6 billion Filed 12/09 based on 6/30/09 adjusted test year	Recent activity:  On February 18, 2010, the Administrative Law Judge issued an order approving a unanimous settlement on interim rates and the procedural schedule reached on February 11, 2010 with the parties in the rate case.  The settlement calls for an interim rate increase of $17.5 million to begin on May 1, 2010 and the withdrawal of the Purchased Power Recovery Factor (PCRF) docket pertaining to the Arkansas wholesale baseload (WBL) capacity.  The procedural schedule calls for hearings in July 2010, with a final order to be issued November 1, 2010 and permanent rates to be effective relating back to service rendered on / after September 13, 2010. Background:  ETI implemented a $46.7 million base rate increase pursuant to its black box rate case settlement effective January 28, 2009, for usage beginning December 19, 2008.  ETI is in need of baseload resources, and EAI recently elected to offer its WBL capacity to the Entergy system as a three-year cost based deal beginning January 1, 2010.  ETI projects that the purchase can save customers in the range of $9.5 to $16.0 million over three years.  Given expected savings, on September 18, 2009, ETI had requested a cost recovery mechanism to recover the annual capacity costs of approximately $26 million through the PCRF until such time as the costs are reflected in rates after a general rate case or the transaction expires, whichever occurs first.  On December 30, 2009, ETI filed a rate case requesting a $198.7 million increase reflecting an 11.5% ROE based on an adjusted June 30, 2009 test year.  The filing includes a proposed cost of service adjustment (COSA) rider with a three year term beginning with the 2010 calendar test year.  Key provisions include a +/- 15 basis point bandwidth, with earnings outside the bandwidth reset to the bottom or top of the band and rates changing prospectively depending upon whether ETI is over or under-earning.  The annual change in revenue requirement is limited to a percentage change in Consumer Price Index for urban areas, and the FRP includes a provision for extraordinary events greater than $10 million per year which would be considered separately.  The filing also proposes a purchased power recovery rider, a competitive generation service tariff and will establish test year baseline values to be used in the transmission cost recovery factor rider authorized for use by ETI in the 2009 legislative session.  Finally, the rate case included a $2.8 million revenue requirement to provide supplemental funding for the decommissioning trust maintained for the 70% share of River Bend for which Texas retail customers have responsibility, in response to the NRC notification of a projected shortfall of decommissioning funding assurance.
Wholesale Regulation
System Energy Resources, Inc.	Recent activity:  None. Background:  10.94% ROE approved by July 2001 FERC order. Last Filed Rate Base: $1.2 billion filed 12/31/09 in monthly cost of service filing
System Agreement	Recent activity:  The Operating Companies continue to meet with Staffs and / or advisors of retail regulatory commissions to discuss a proposed framework for Successor Arrangements to the current System Agreement, which is being pursued in parallel with evaluation by the Entergy Regional State Committee (E-RSC) of the SPP RTO and modified Independent Coordinator of Transmission (ICT) alternatives.  In early April, Entergy Corporation and the Entergy Operating Companies determined in connection with their decision-making process that it is appropriate to agree and commit that no Entergy Operating Company will enter voluntarily into successor arrangements with the other Entergy Operating Companies if its retail regulator finds successor arrangements are not in the public interest. Paper hearings concluded in February 2010 in the interruptible / curtailable case on the appropriateness of refunds resulting from changes in the treatment of interruptible load in the allocation of costs among the Operating Companies under the System Agreement.  Resolution of this proceeding is expected to have implications regarding the question of whether FERC provided sufficient rationale for not ordering refunds in the System Agreement case; this issue as well as  whether FERC impermissibly delayed implementation of the bandwidth remedy are also pending before the FERC. On a preliminary basis, the 2010 rough production cost equalization payment by EAI, based on calendar year 2009 production costs, was estimated at $70 million to be paid collectively to EGSL, ELL and ENOI.  This payment reflects a reduction of approximately $320 million versus calendar year 2008 production costs, due primarily to lower natural gas prices. The actual payments / receipts will not be calculated until the Operating Companies' FERC Form 1s have been filed. On April 16, 2010, the LPSC made a filing at the FERC alleging that Entergy violated the System Agreement by permitting EAI to make non-requirements sales to non-affiliated third parties rather than making such energy available to the other utility Operating Companies’ customers.  The LPSC filing also stated these non-requirements sales caused harm to the Operating Companies’ customers of $144.4 million over the period 2000-2009, and these customers should be compensated for this harm by Entergy’s shareholders.  The Utility operating companies believe the LPSC’s allegations are without merit and are scheduled to file rebuttal testimony May 25. Background:  The System Agreement case addresses the allocation of production costs among the Utility Operating Companies.  In 2005, the FERC issued orders that require each Operating Company’s production costs to be within + / - 11% of System average production costs and set 2007 as the first possible year of payments among Entergy’s Operating Companies, based on calendar year 2006 actual production costs.  Upon appeal, the DC Circuit remanded to the FERC for reconsideration of the FERC's conclusion it did not have the authority to order refunds and the decision to delay the implementation of the bandwidth remedy.  The remand is pending at FERC. Bandwidth filings for the calendar years 2006 through 2008 production costs required payments from EAI to various other Operating Companies of approximately $252 million, $252 million and $390 million for test years 2006, 2007 and 2008 respectively.  FERC set each of these bandwidth filings for hearing following protests from retail regulatory commissions and / or third parties.  A final order in the bandwidth proceeding related to 2006 calendar year production costs has been issued by the FERC, and requests for rehearing and clarification have been filed.  Bandwidth proceedings based on 2007 and 2008 calendar year production costs remain outstanding. The System Agreement has been and continues to be the subject of ongoing litigation.  As a result, EAI and EMI submitted their eight year notices to withdraw from the System Agreement effective December 2013 and November 2015, respectively.  On November 19, 2009, FERC accepted notices of cancellation and determined EAI and EMI are permitted

Appendix B: Regulatory Summary Table (continued)
Company/ Proceeding	Pending Cases/Events
Wholesale Regulation
System Agreement (continued)	to withdraw from the System Agreement following the 96 month notice period without payment of a fee or being required to otherwise compensate the remaining Entergy Operating Companies as a result of withdrawal.  FERC stated it expected Entergy and all interested parties to move forward and develop details of all needed successor arrangements and encouraged Entergy to file its Section 205 filing for post 2013 arrangements as soon as possible.  The LPSC and CCNO have requested rehearing of the FERC’s decision. EAI continues to evaluate alternatives, including stand-alone operation  of its generation facilities, EAI participating as a member of the SPP RTO or Midwest ISO and potential Successor Arrangements.
Independent Coordinator of Transmission Authorized ROE:  11.0%(q) Last Filed Rate Base: $2.1 billion (r) Filed 5/09 based on 12/31/08 test year	Recent activity:  The E-RSC is generally conducting meetings monthly and in March 2010 selected the consulting firm ESPY Energy Solutions to assist in their evaluations.  In March 2010, FERC also selected Charles Rivers & Associates to perform the cost-benefit analysis associated with the current ICT versus SPP RTO evaluation. Background:  In November 2006, the Utility Operating Companies installed SPP as their ICT with an initial term of four years unless Entergy files and the FERC approves an extension beyond that four year period.  The Operating Companies did not transfer control of the transmission system but rather vested the ICT with responsibility, among others, for granting or denying transmission service, administering the OASIS node, developing a base plan for the transmission system that is used to determine whether costs of transmission upgrades should be rolled into transmission rates or directly assigned to customers requesting or causing the upgrade to be built, serving as reliability coordinator the transmission system and overseeing the WPP. In its November 17, 2009 FERC filing, in anticipation of the expiration of the initial term of the ICT, a process was proposed for the evaluation of modifications to, or the replacement of, the current ICT and Weekly Procurement Process (WPP) arrangements.  The process will facilitate review by the FERC, Entergy’s retail regulators, and interested stakeholders of two primary alternatives; 1) the adoption of certain modifications to the current ICT arrangements, or 2) a transition to membership in the SPP RTO.  A critical factor in the Operating Companies’ proposal will be the opinion and recommendation of the E-RSC formed in the Fall of 2009, including one representative from each of the Entergy Operating Company retail regulators, to consider several of the issues related to the Entergy transmission system.  The Utility Operating Companies expect that the E-RSC will reflect in its evaluation process the cost-benefit analysis that is being jointly sponsored by the E-RSC and FERC that will compare the current ICT arrangement to joining the SPP RTO.  The target date for completion of the cost-benefit analysis is third quarter 2010. In addition, the E-RSC is currently considering potential modifications to the ICT arrangement, including, among others, providing the E-RSC with authority (upon a unanimous vote) to (1) require the Entergy Operating Companies to file with the FERC proposed modifications to the cost allocation policy for transmission upgrades and (2) add projects to the Operating Companies’ transmission construction plan.  It is anticipated certain potential modifications to the ICT will be implemented in November 2010, with other potential modifications being considered if the ICT is ultimately determined to be the appropriate longer term option.  If the SPP RTO is ultimately deemed the preferred alternative, SPP has indicated the implementation process may take at least 12-18 months after a decision is made. While alternatives are being explored, Entergy has already taken the voluntary step to more closely align its transmission planning criteria with the anticipated modifications to the NERC planning standards.  Entergy believes that the current ICT arrangements have produced benefits, and, if modified as a result of this process, can continue to benefit customers and competition.  The SPP RTO alternative also has the potential to produce benefits.  The progress of cost-benefit analysis will be closely monitored, including its treatment of the costs associated with any socialization of transmission upgrades constructed to integrate wind development.

(q)  Applies to sales made under Entergy’s FERC jurisdictional Open Access Transmission Tariff.

(r)  Reflects transmission rate base in Entergy’s FERC OATT filing, for which such amounts are also reflected in the rate base figures for each of the Operating Companies shown above.

C.   Financial Performance Measures and Historical Performance Measures

Appendix C-1 provides comparative financial performance measures for the current quarter.  Appendix C-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 generally accepted accounting principles (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 F.

Appendix C-1:  GAAP and Non-GAAP Financial Performance Measures
First Quarter 2010 vs. 2009 (see Appendix E for definitions of certain measures)
For 12 months ending March 31	2010	2009	Change
GAAP Measures
Return on average invested capital – as-reported	7.6%	7.6%	-
Return on average common equity – as-reported	13.8%	14.1%	(0.3%)
Net margin – as-reported	11.3%	8.8%	2.5%
Cash flow interest coverage	6.3	6.5	(0.2)
Book value per share	$46.81	$44.02	$2.79
End of period shares outstanding (millions)	189.3	196.1	(6.8)
Non-GAAP Measures
Return on average invested capital – operational	8.0%	8.0%	-
Return on average common equity – operational	14.9%	15.0%	(0.1%)
Net margin – operational	12.2%	9.4%	2.8%
As of March 31 ($ in millions)	2010	2009	Change
GAAP Measures
Cash and cash equivalents	1,657	1,803	(146)
Revolver capacity	1,417	725	692
Total debt	12,152	12,034	118
Securitization debt	838	310	528
Debt to capital ratio	57.0%	57.4%	(0.4%)
Off-balance sheet liabilities:
Debt of joint ventures  – Entergy’s share	114	124	(10)
Leases – Entergy’s share	530	449	81
Total off-balance sheet liabilities	644	573	71
Non-GAAP Measures
Debt to capital ratio, excluding securitization debt	55.2%	56.7%	(1.5%)
Total gross liquidity	3,074	2,528	546
Net debt to net capital ratio, excluding securitization debt	51.3%	52.6%	(1.3%)
Net debt ratio including off-balance sheet liabilities, excluding securitization debt	52.9%	54.0%	(1.1%)

Appendix C-2: Historical Performance Measures (see Appendix E for definitions of measures)
				2Q08	3Q08	4Q08	1Q09		2Q09		3Q09		4Q09	1Q10	09YTD	10YTD
Financial
		EPS – as-reported ($)		1.37	2.41	0.89		1.20		1.14	2.32	1.64		1.12	1.20	1.12
		Less – special items ($)		(0.09)	(0.09)	(0.10)		(0.09)		(0.09)	(0.08)	(0.11)		(0.21)	(0.09)	(0.21)
		EPS – operational ($)		1.46	2.50	0.99		1.29		1.23	2.40	1.75		1.33	1.29	1.33
	Trailing Twelve Months
		ROIC – as-reported (%)		8.6	8.1	8.1		7.6		7.5	7.1	7.7		7.6	7.6	7.6
		ROIC – operational (%)		8.8	8.4	8.4		8.0		7.8	7.5	8.1		8.0	8.0	8.0
		ROE – as-reported (%)		16.3	15.6	15.4		14.1		13.7	13.2	14.9		13.8	14.1	13.8
		ROE – operational (%)		17.0	16.4	16.1		15.0		14.6	14.1	15.7		14.9	15.0	14.9
		Cash flow interest coverage		5.0	7.0	6.5		6.5		6.7	5.5	6.1		6.3	6.5	6.3
		Debt to capital ratio (%)		60.7	60.4	59.7		57.4		55.9	56.7	57.4		57.0	57.4	57.0
		Debt to capital ratio, excluding securitization debt (%)		60.0	59.8	59.1		56.7		55.3	56.1	55.6		55.2	56.7	55.2
		Net debt to net capital ratio, excluding securitization debt (%)		57.6	54.1	54.8		52.6		52.2	53.4	51.5		51.3	52.6	51.3
Utility
		GWh billed
		Residential	7,372		10,671	6,992		7,893		7,100	11,213	7,421		9,645	7,893	9,645
		Commercial & Gov’t	7,275		8,646	6,992		6,756		7,095	8,794	7,240		7,064	6,756	7,064
		Industrial	9,730		10,110	8,626		8,139		8,790	9,473	9,235		8,733	8,139	8,733
		Wholesale	1,440		1,431	1,240		1,387		1,313	1,164	998		1,317	1,387	1,317
		O&M expense/MWh	$19.48		$14.43	$23.95		$18.51		$20.96	$15.77	$20.18		$17.29	$18.51	$17.29
		Reliability
		SAIFI	1.9		1.9	1.9		1.8		1.7	1.7	1.8		1.7	1.8	1.7
		SAIDI	215		227	216		208		194	203	210		213	208	213
Nuclear
		Net MW in operation	4,998		4,998	4,998		4,998		4,998	4,998	4,998		4,998	4,998	4,998
		Avg. realized price per MWh	$58.22		$61.59	$56.69		$63.84		$59.22	$61.70	$59.43		$58.72	$63.84	$58.72
		Production cost/MWh (s)	$23.11		$21.77	$22.77		$23.14		$24.30	$22.57	$23.20		$23.70	$23.14	$23.70
		Non-fuel O&M expense/ purchased power per MWh (s)	$23.42		$21.19	$23.06		$22.44		$25.33	$22.11	$23.60		$23.63	$22.44	$23.63
		GWh billed	10,145		10,316	10,489		10,074		8,980	10,876	11,052		10,255	10,074	10,255
		Capacity factor (%)	92		95	94		92		81	100	99		94	92	94

(s) 2009 and 2010 excludes the effect of the non-utility nuclear spin-off expenses special item at Entergy Nuclear.

D.   Planned Capital Expenditures

The capital plan for 2010 through 2012 anticipates $7.1 billion for investment, including $2.8 billion of maintenance capital, as shown in Appendix D.  The remaining $4.3 billion is for specific investments (as well as other initiatives) such as:

·   Utility:  the Utility’s portfolio transformation strategy including the 580 MW Acadia Unit 2 purchase for $300 million, or $517/kW, pending regulatory approval and assuming closing by March 31, 2011, with a total expected cost of $329 million (or $567/kW) including planned plant upgrades, transaction costs, and contingencies (but excluding transmission upgrades); the steam generator replacement at Entergy Louisiana’s Waterford 3 nuclear unit; an approximate 178 MW uprate project at Grand Gulf; transmission upgrades and spending to comply with revised NERC Transmission Planning rules and NRC security requirements.  The three year capital plan also includes $420 million for the installation of scrubbers and low NOx burners at White Bluff which was delayed upon approval of a variance from the October 2013 compliance date by the Arkansas Pollution Control and Ecology Commission as discussed more fully in Appendix B.

·   Entergy Nuclear:  dry cask storage, nuclear license renewal efforts, component replacement across the fleet, NYPA value sharing, the Indian Point Independent Safety Evaluation and spending to comply with revised NRC security requirements.

Appendix D:  2010 – 2012 Planned Capital Expenditures
($ in millions) – Prepared February 2010
	2010	2011	2012	Total
Maintenance capital
Utility and Parent & Other (including non-nuclear wholesale assets)	785	790	830	2,405
Entergy Nuclear	92	140	123	355
Subtotal	877	930	953	2,760
Other capital commitments
Utility and Parent & Other      (including non-nuclear wholesale assets)	991	1,578	926	3,495
Entergy Nuclear	349	220	219	788
Subtotal	1,340	1,798	1,145	4,283
Total Planned Capital Expenditures	2,217	2,728	2,098	7,043
Storm Capital	35	13	13	61
Total Planned Capital Expenditures Including Storm Capital	2,252	2,741	2,111	7,104

E.   Definitions

Appendix E provides definitions of certain operational performance measures, as well as GAAP and non-GAAP financial measures, all of which are referenced in this release.

Appendix E:  Definitions of Operational Performance Measures and GAAP and Non-GAAP Financial Measures
Utility
GWh billed	Total number of GWh billed to all retail and wholesale customers
Operation & maintenance expense	Operation, maintenance and refueling expenses per MWh of billed sales, excluding fuel
SAIFI	System average interruption frequency index; average number per customer per year, excluding the impact of major storm activity
SAIDI	System average interruption duration index; average minutes per customer per year, excluding the impact of major storm activity
Number of customers	Number of customers at end of period
Competitive Businesses
Planned TWh of generation	Amount of output expected to be generated by Entergy Nuclear for nuclear units considering plant operating characteristics, outage schedules, and expected market conditions which impact dispatch, assuming timely renewal of plant operating licenses
Percent of planned generation sold   forward	Percent of planned generation output sold forward under contracts, forward physical contracts, forward financial contracts or options (consistent with assumptions used in earnings guidance) that may or may not require regulatory approval
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
Planned net MW in operation	Amount of capacity to be available to generate power considering uprates planned to be completed within the calendar year
Bundled energy & capacity contract	A contract for the sale of installed capacity and related energy, priced per megawatt-hour sold
Capacity contract	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
Average contract price per MWh or per kW per month	Price at which generation output and / or capacity is expected to be sold to third parties, given existing contract or option exercise prices based on expected dispatch or capacity, excluding the revenue associated with the amortization of the below-market Power Purchase Agreement for Palisades
Average contract revenue per MWh	Price at which the combination of generation output and capacity are expected to be sold to third parties, given existing contract or option exercise prices based on expected dispatch, excluding the revenue associated with the amortization of the below-market PPA for Palisades
Entergy Nuclear
Net MW in operation	Installed capacity owned and operated by Entergy Nuclear
Average realized price per MWh	As-reported revenue per MWh billed for all non-utility nuclear operations, excluding revenue from the amortization of the Palisades below-market PPA
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
Non-fuel O&M expense/purchased power per MWh	Operation, maintenance and refueling expenses and purchased power per MWh billed, excluding fuel
GWh billed	Total number of GWh billed to all customers
Capacity factor	Normalized percentage of the period that the plants generate power
Refueling outage duration	Number of days lost for scheduled refueling outage during the period

Financial measures defined in the below table include measures prepared in accordance with generally accepted accounting principles, (GAAP), as well as non-GAAP measures.  Non-GAAP measures are included in this release in order to provide metrics that remove the effect of less routine financial impacts from commonly used financial metrics.

Appendix E:  Definitions of Operational Performance Measures and GAAP and Non-GAAP Financial Measures (continued)
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
Net margin – as-reported	12-months rolling Net Income divided by 12 months rolling revenue
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, capital leases, and preferred stock with sinking fund on the balance sheet less non-recourse debt, if any
Debt of joint ventures (Entergy’s share)	Debt issued by business joint ventures at non-nuclear wholesale assets
Leases (Entergy’s share)	Operating leases held by subsidiaries capitalized at implicit interest rate
Debt to capital	Gross debt divided by total capitalization
Securitization debt	Debt associated with securitization bonds issued to recover storm costs from hurricanes Rita, Ike and Gustav at Entergy Texas
Financial Measures – Non-GAAP
Operational earnings	As-reported Net Income applicable to common stock adjusted to exclude the impact 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
Net margin – operational	12-months rolling operational Net Income divided by 12 months rolling revenue
Total gross liquidity	Sum of cash and revolver capacity
Debt to capital, excluding securitization debt	Gross debt divided by total capitalization, excluding securitization debt
Net debt to net capital, excluding securitization debt	Gross debt less cash and cash equivalents divided by total capitalization less cash and cash equivalents, excluding securitization debt
Net debt including off-balance sheet liabilities, excluding securitization debt	Sum of gross 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; both gross debt and total capitalization are also adjusted to exclude securitization debt

F.   GAAP to Non-GAAP Reconciliations

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

Appendix F-1: Reconciliation of GAAP to Non-GAAP Financial Measures – Return on Equity, Return on Invested Capital and Net Margin Metrics
($ in millions)
	2Q08	3Q08	4Q08	1Q09	2Q09	3Q09	4Q09	1Q10
As-reported Net Income-rolling 12 months (A)	1,235	1,244	1,221	1,147	1,103	1,088	1,231	1,210
Preferred dividends	23	21	20	20	20	20	20	20
Tax effected interest expense	390	375	374	366	368	361	351	372
As-reported Net Income, rolling 12 months including preferred dividends and tax effected interest expense (B)	1,648	1,640	1,615	1,533	1,491	1,469	1,602	1,602
Special items in prior quarters	(32)	(50)	(35)	(55)	(54)	(54)	(49)	(53)
Special items in current quarter
Nuclear spin-off expenses	(18)	(17)	(20)	(17)	(17)	(15)	(21)	(40)
Total special items (C)	(50)	(67)	(55)	(72)	(71)	(69)	(71)	(94)
Operational earnings, rolling 12 months including preferred dividends and tax effected interest expense (B-C)	1,698	1,707	1,670	1,605	1,562	1,538	1,673	1,696
Operational earnings, rolling 12 months (A-C)	1,285	1,311	1,276	1,219	1,174	1,157	1,302	1,304
Average invested capital (D)	19,244	20,236	19,927	20,126	19,995	20,629	20,748	21,149
Average common equity (E)	7,555	7,973	7,915	8,152	8,045	8,230	8,290	8,745
Operating revenues (F)	12,150	12,825	13,094	13,018	12,275	11,248	10,746	10,716
ROIC – as-reported % (B/D)	8.6	8.1	8.1	7.6	7.5	7.1	7.7	7.6
ROIC – operational % ((B-C)/D)	8.8	8.4	8.4	8.0	7.8	7.5	8.1	8.0
ROE – as-reported % (A/E)	16.3	15.6	15.4	14.1	13.7	13.2	14.9	13.8
ROE – operational % ((A-C)/E)	17.0	16.4	16.1	15.0	14.6	14.1	15.7	14.9
Net margin – as-reported % (A/F)	10.2	9.7	9.3	8.8	9.0	9.7	11.5	11.3
Net margin – operational % ((A-C)/F)	10.6	10.2	9.7	9.4	9.6	10.3	12.1	12.2

Appendix F-2: Reconciliation of GAAP to Non-GAAP Financial Measures – Credit and Liquidity Metrics
($ in millions)
	2Q08	3Q08	4Q08	1Q09	2Q09	3Q09	4Q09	1Q10
Gross debt (A)	11,768	12,656	12,279	12,034	11,510	11,522	12,014	12,152
Less securitization debt (B)	318	318	310	310	301	301	838	838
Gross debt, excluding securitization  debt (C)	11,450	12,338	11,969	11,724	11,209	11,221	11,176	11,314
Less cash and cash equivalents (D)	1,086	2,556	1,920	1,803	1,281	1,131	1,710	1,657
Net debt, excluding securitization debt (E)	10,364	9,782	10,049	9,921	9,928	10,090	9,466	9,657
Total capitalization (F)	19,401	20,944	20,557	20,975	20,588	20,315	20,939	21,322
Less securitization debt (B)	318	318	310	310	301	301	838	838
Total capitalization, excluding securitization debt (G)	19,083	20,626	20,247	20,665	20,287	20,014	20,101	20,484
Less cash and cash equivalents (D)	1,086	2,556	1,920	1,803	1,281	1,131	1,710	1,657
Net capital, excluding securitization debt (H)	17,997	18,070	18,327	18,862	19,006	18,883	18,391	18,827
Debt to capital ratio % (A/F)	60.7	60.4	59.7	57.4	55.9	56.7	57.4	57.0
Debt to capital ratio, excluding securitization debt % (C/G)	60.0	59.8	59.1	56.7	55.3	56.1	55.6	55.2
Net debt to net capital ratio, excluding securitization debt % (E/H)	57.6	54.1	54.8	52.6	52.2	53.4	51.5	51.3
Off-balance sheet liabilities (I)	638	637	574	573	569	567	646	644
Net debt to net capital ratio including off-balance sheet liabilities, excluding securitization debt % ((E+I)/(H+I))	59.0	55.7	56.2	54.0	53.6	54.8	53.1	52.9
Revolver capacity (J)	826	374	645	725	1,585	1,647	1,464	1,417
Gross liquidity (D+J)	1,912	2,930	2,565	2,528	2,866	2,778	3,174	3,074

Entergy Corporation’s common stock is listed on the New York and Chicago exchanges under the symbol “ETR”.

Additional investor information can be accessed on-line at

www.entergy.com/investor_relations

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In this news release, and from time to time, Entergy Corporation 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          (a) those factors discussed in Entergy’s Form 10-K for the year ended December 31, 2009, and Entergy’s other reports and filings made under the Securities Exchange Act of 1934, (b) uncertainties associated with rate proceedings, formula rate plans and other cost recovery mechanisms, (c) uncertainties associated with efforts to remediate the effects of major storms and recover related restoration costs, (d) nuclear operating and regulatory risks, and (e) legislative and regulatory actions, and conditions in commodity and capital markets during the periods covered by the forward-looking statements, in addition to other factors described elsewhere in this release and in subsequent securities filings.

VIII.   Financial Statements

Entergy Corporation
Consolidating Balance Sheet
March 31, 2010
(Dollars in thousands)
(Unaudited)
	U.S. Utilities			Entergy Nuclear		Parent & Other			Consolidated
ASSETS
CURRENT ASSETS
Cash and cash equivalents:
Cash	$	70,339		$	1,171	$	3,936		$	75,446
Temporary cash investments		968,572			558,764		54,252			1,581,588
Total cash and cash equivalents		1,038,911			559,935		58,188			1,657,034
Securitization recovery trust account		35,037			-		-			35,037
Notes receivable		-			1,137,023		(1,137,023	)		-
Accounts receivable:
Customer		406,039			164,618		-			570,657
Allowance for doubtful accounts		(28,230	)		-		(202	)		(28,432	)
Associated companies		25,150			43,695		(68,845	)		-
Other		127,921			-		16,195			144,116
Accrued unbilled revenues		250,480			-		177			250,657
Total accounts receivable		781,360			208,313		(52,675	)		936,998
Deferred fuel costs		24,678			-		-			24,678
Accumulated deferred income taxes		27,221			1,403		(4,469	)		24,155
Fuel inventory - at average cost		200,654			528		1,997			203,179
Materials and supplies - at average cost		531,347			300,348		2,020			833,715
Deferred nuclear refueling outage costs		92,034			122,121		-			214,155
System agreement cost equalization		70,000			-		-			70,000
Prepayments and other		221,200			302,010		210,459			733,669
TOTAL		3,022,442			2,631,681		(921,503	)		4,732,620
OTHER PROPERTY AND INVESTMENTS
Investment in affiliates - at equity		734,578			1,330,589		(2,025,516	)		39,651
Decommissioning trust funds		1,388,755			1,941,926		-			3,330,681
Non-utility property - at cost (less accumulated depreciation)		158,499			5,972		82,825			247,296
Other		70,067			6,100		35,173			111,340
TOTAL		2,351,899			3,284,587		(1,907,518	)		3,728,968
PROPERTY, PLANT, AND EQUIPMENT
Electric		32,580,678			3,555,991		371,491			36,508,160
Property under capital lease		782,722			-		-			782,722
Natural gas		315,697			-		439			316,136
Construction work in progress		1,213,053			451,291		3,376			1,667,720
Nuclear fuel under capital lease		-			-		-			-
Nuclear fuel		729,229			511,216		-			1,240,445
TOTAL PROPERTY, PLANT AND EQUIPMENT		35,621,379			4,518,498		375,306			40,515,183
Less - accumulated depreciation and amortization		16,243,939			581,809		150,440			16,976,188
PROPERTY, PLANT AND EQUIPMENT - NET		19,377,440			3,936,689		224,866			23,538,995
DEFERRED DEBITS AND OTHER ASSETS
Regulatory assets:
Regulatory asset for income taxes - net		625,391			-		-			625,391
Other regulatory assets		3,738,435			-		-			3,738,435
Deferred fuel costs		172,202			-		-			172,202
Goodwill		374,099			3,073		-			377,172
Accumulated deferred income taxes		8,592			-		65,436			74,028
Other		270,015			883,187		(31,611	)		1,121,591
TOTAL		5,188,734			886,260		33,825			6,108,819
					-
TOTAL ASSETS	$	29,940,515		$	10,739,217	$	(2,570,330	)	$	38,109,402
*Totals may not foot due to rounding.

Entergy Corporation
Consolidating Balance Sheet
March 31, 2010
(Dollars in thousands)
(Unaudited)
	U.S. Utilities			Entergy Nuclear		Parent & Other			Consolidated
LIABILITIES AND SHAREHOLDERS' EQUITY
CURRENT LIABILITIES
Currently maturing long-term debt	$	411,002		$	28,412	$	361,000		$	800,414
Notes payable:
Associated companies		5,388			-		(5,388	)		-
Other		175,498			-		-			175,498
Account payable:
Associated companies		17,724			5,851		(23,575	)		-
Other		631,717			235,294		10,082			877,093
Customer deposits		325,859			-		-			325,859
Taxes accrued		244,009			947,167		(1,191,176	)		-
Accumulated deferred income taxes		7,100			-		-			7,100
Interest accrued		152,398			1,811		7,134			161,343
Deferred fuel costs		118,483			-		-			118,483
Obligations under capital leases		2,395			-		-			2,395
Pension and other postretirement liabilities		50,433			5,277		-			55,710
System agreement cost equalization		187,314			-		-			187,314
Other		146,548			200,275		1,749			348,572
TOTAL		2,475,868			1,424,087		(840,174	)		3,059,781
NON-CURRENT LIABILITIES
Accumulated deferred income taxes and taxes accrued		6,528,558			1,975,191		(597,388	)		7,906,361
Accumulated deferred investment tax credits		304,132			-		-			304,132
Obligations under capital leases		36,620			-		-			36,620
Other regulatory liabilities		534,523			-		-			534,523
Decommissioning and retirement cost liabilities		1,645,578			1,343,760		1,266			2,990,604
Accumulated provisions		85,813			2,501		4,593			92,907
Pension and other postretirement liabilities		1,743,979			455,497		-			2,199,476
Long-term debt		8,565,934			157,131		2,413,669			11,136,734
Other		735,668			301,185		(359,389	)		677,464
TOTAL		20,180,805			4,235,265		1,462,751			25,878,821
Subsidiaries' preferred stock without sinking fund		186,510			-		30,211			216,721
EQUITY
Common Shareholders' Equity:
Common stock, $.01 par value, authorized 500,000,000 shares;
issued 254,752,788 shares in 2010		2,161,268			774,274		(2,932,994	)		2,548
Paid-in capital		2,416,633			1,027,064		1,929,727			5,373,424
Retained earnings		2,673,668			3,059,278		2,382,064			8,115,010
Accumulated other comprehensive income (loss)		(128,237	)		219,249		(5,620	)		85,392
Less - treasury stock, at cost (65,483,672 shares in 2010)		120,000			-		4,596,295			4,716,295
Total common shareholders' equity		7,003,332			5,079,865		(3,223,118	)		8,860,079
Subsidiaries' preferred stock without sinking fund		94,000			-		-			94,000
TOTAL		7,097,332			5,079,865		(3,223,118	)		8,954,079
TOTAL LIABILITIES AND EQUITY	$	29,940,515		$	10,739,217	$	(2,570,330	)	$	38,109,402
*Totals may not foot due to rounding.

Entergy Corporation
Consolidating Balance Sheet
December 31, 2009
(Dollars in thousands)
(Unaudited)
	U.S. Utilities			Entergy Nuclear		Parent & Other			Consolidated
ASSETS
CURRENT ASSETS
Cash and cash equivalents:
Cash	$	81,255		$	1,187	$	3,419		$	85,861
Temporary cash investments		1,158,014			392,088		73,588			1,623,690
Total cash and cash equivalents		1,239,269			393,275		77,007			1,709,551
Securitization recovery trust account		13,098			-		-			13,098
Notes receivable		-			1,132,023		(1,132,023	)		-
Accounts receivable:
Customer		331,936			221,756		-			553,692
Allowance for doubtful accounts		(27,428	)		-		(203	)		(27,631	)
Associated companies		27,783			28,940		(56,723	)		-
Other		135,307			-		16,996			152,303
Accrued unbilled revenues		302,293			-		170			302,463
Total accounts receivable		769,891			250,696		(39,760	)		980,827
Deferred fuel costs		126,798			-		-			126,798
Accumulated deferred income taxes		-			-		-			-
Fuel inventory - at average cost		194,826			529		1,500			196,855
Materials and supplies - at average cost		526,543			297,132		2,027			825,702
Deferred nuclear refueling outage costs		106,428			118,862		-			225,290
System agreement cost equalization		70,000			-		-			70,000
Prepayments and other		68,406			432,968		(115,334	)		386,040
TOTAL		3,115,259			2,625,485		(1,206,583	)		4,534,161
OTHER PROPERTY AND INVESTMENTS
Investment in affiliates - at equity		734,578			1,330,589		(2,025,587	)		39,580
Decommissioning trust funds		1,325,863			1,885,320		-			3,211,183
Non-utility property - at cost (less accumulated depreciation)		156,333			6,038		85,293			247,664
Other		77,418			7,730		35,125			120,273
TOTAL		2,294,192			3,229,677		(1,905,169	)		3,618,700
PROPERTY, PLANT, AND EQUIPMENT
Electric		32,426,732			3,540,860		376,180			36,343,772
Property under capital lease		783,096			-		-			783,096
Natural gas		313,817			-		439			314,256
Construction work in progress		1,134,194			411,523		1,602			1,547,319
Nuclear fuel under capital lease		527,521			-		-			527,521
Nuclear fuel		219,317			520,510		-			739,827
TOTAL PROPERTY, PLANT AND EQUIPMENT		35,404,677			4,472,893		378,221			40,255,791
Less - accumulated depreciation and amortization		16,150,763			561,698		153,928			16,866,389
PROPERTY, PLANT AND EQUIPMENT - NET		19,253,914			3,911,195		224,293			23,389,402
DEFERRED DEBITS AND OTHER ASSETS
Regulatory assets:
Regulatory asset for income taxes - net		619,500			-		-			619,500
Other regulatory assets		3,647,154			-		-			3,647,154
Deferred fuel costs		172,202			-		-			172,202
Goodwill		374,099			3,073		-			377,172
Accumulated deferred income taxes		-			-		-			-
Other		231,156			821,382		(46,232	)		1,006,306
TOTAL		5,044,111			824,455		(46,232	)		5,822,334
					-
TOTAL ASSETS	$	29,707,476		$	10,590,812	$	(2,933,691	)	$	37,364,597
*Totals may not foot due to rounding.

Entergy Corporation
Consolidating Balance Sheet
December 31, 2009
(Dollars in thousands)
(Unaudited)
	U.S. Utilities			Entergy Nuclear		Parent & Other			Consolidated
LIABILITIES AND SHAREHOLDERS' EQUITY
CURRENT LIABILITIES
Currently maturing long-term debt	$	406,016		$	30,941	$	275,000		$	711,957
Notes payable:
Associated companies		207,161			-		(207,161	)		-
Other		30,031			-		-			30,031
Account payable:
Associated companies		6,920			7,543		(14,463	)		-
Other		758,886			231,119		8,223			998,228
Customer deposits		323,092			250		-			323,342
Taxes accrued		12,742			-		(12,742	)		-
Accumulated deferred income taxes		41,125			-		7,459			48,584
Interest accrued		187,154			908		4,221			192,283
Deferred fuel costs		219,639			-		-			219,639
Obligations under capital leases		212,496			-		-			212,496
Pension and other postretirement liabilities		49,912			5,119		-			55,031
System agreement cost equalization		187,204			-		-			187,204
Other		48,643			163,328		3,231			215,202
TOTAL		2,691,021			439,208		63,768			3,193,997
NON-CURRENT LIABILITIES
Accumulated deferred income taxes and taxes accrued		6,506,974			3,052,967		(2,137,622	)		7,422,319
Accumulated deferred investment tax credits		308,395			-		-			308,395
Obligations under capital leases		354,233			-		-			354,233
Other regulatory liabilities		421,985			-		-			421,985
Decommissioning and retirement cost liabilities		1,618,844			1,319,450		1,245			2,939,539
Accumulated provisions		127,634			9,090		4,591			141,315
Pension and other postretirement liabilities		1,771,351			469,688		-			2,241,039
Long-term debt		7,897,032			156,556		2,652,150			10,705,738
Other		750,024			317,661		(356,351	)		711,334
TOTAL		19,756,472			5,325,412		164,013			25,245,897
Subsidiaries' preferred stock without sinking fund		186,510			-		30,833			217,343
EQUITY
Common Shareholders' Equity:
Common stock, $.01 par value, authorized 500,000,000 shares;
issued 254,752,788 shares in 2009		2,161,268			774,274		(2,932,994	)		2,548
Paid-in capital		2,416,633			1,027,164		1,926,245			5,370,042
Retained earnings		2,651,629			2,965,052		2,426,441			8,043,122
Accumulated other comprehensive income (loss)		(130,057	)		59,702		(4,830	)		(75,185	)
Less - treasury stock, at cost (65,634,580 shares in 2009)		120,000			-		4,607,167			4,727,167
Total common shareholders' equity		6,979,473			4,826,192		(3,192,305	)		8,613,360
Subsidiaries' preferred stock without sinking fund		94,000			-		-			94,000
TOTAL		7,073,473			4,826,192		(3,192,305	)		8,707,360
TOTAL LIABILITIES AND EQUITY	$	29,707,476		$	10,590,812	$	(2,933,691	)	$	37,364,597
*Totals may not foot due to rounding.

Entergy Corporation
Consolidating Balance Sheet
March 31, 2010 vs December 31, 2009
(Dollars in thousands)
(Unaudited)
	U.S. Utilities			Entergy Nuclear			Parent & Other			Consolidated
ASSETS
CURRENT ASSETS
Cash and cash equivalents:
Cash	$	(10,916	)	$	(16	)	$	517		$	(10,415	)
Temporary cash investments		(189,442	)		166,676			(19,336	)		(42,102	)
Total cash and cash equivalents		(200,358	)		166,660			(18,819	)		(52,517	)
Securitization recovery trust account		21,939			-			-			21,939
Notes receivable		-			5,000			(5,000	)		-
Accounts receivable:
Customer		74,103			(57,138	)		-			16,965
Allowance for doubtful accounts		(802	)		-			1			(801	)
Associated companies		(2,633	)		14,755			(12,122	)		-
Other		(7,386	)		-			(801	)		(8,187	)
Accrued unbilled revenues		(51,813	)		-			7			(51,806	)
Total accounts receivable		11,469			(42,383	)		(12,915	)		(43,829	)
Deferred fuel costs		(102,120	)		-			-			(102,120	)
Accumulated deferred income taxes		27,221			1,403			(4,469	)		24,155
Fuel inventory - at average cost		5,828			(1	)		497			6,324
Materials and supplies - at average cost		4,804			3,216			(7	)		8,013
Deferred nuclear refueling outage costs		(14,394	)		3,259			-			(11,135	)
System agreement cost equalization		-			-			-			-
Prepayments and other		152,794			(130,958	)		325,793			347,629
TOTAL		(92,817	)		6,196			285,080			198,459
OTHER PROPERTY AND INVESTMENTS
Investment in affiliates - at equity		-			-			71			71
Decommissioning trust funds		62,892			56,606			-			119,498
Non-utility property - at cost (less accumulated depreciation)		2,166			(66	)		(2,468	)		(368	)
Other		(7,351	)		(1,630	)		48			(8,933	)
TOTAL		57,707			54,910			(2,349	)		110,268
PROPERTY, PLANT, AND EQUIPMENT
Electric		153,946			15,131			(4,689	)		164,388
Property under capital lease		(374	)		-			-			(374	)
Natural gas		1,880			-			-			1,880
Construction work in progress		78,859			39,768			1,774			120,401
Nuclear fuel under capital lease		(527,521	)		-			-			(527,521	)
Nuclear fuel		509,912			(9,294	)		-			500,618
TOTAL PROPERTY, PLANT AND EQUIPMENT		216,702			45,605			(2,915	)		259,392
Less - accumulated depreciation and amortization		93,176			20,111			(3,488	)		109,799
PROPERTY, PLANT AND EQUIPMENT - NET		123,526			25,494			573			149,593
DEFERRED DEBITS AND OTHER ASSETS
Regulatory assets:
Regulatory asset for income taxes - net		5,891			-			-			5,891
Other regulatory assets		91,281			-			-			91,281
Deferred fuel costs		-			-			-			-
Goodwill		-			-			-			-
Accumulated deferred income taxes		8,592			-			65,436			74,028
Other		38,859			61,805			14,621			115,285
TOTAL		144,623			61,805			80,057			286,485
TOTAL ASSETS	$	233,039		$	148,405		$	363,361		$	744,805
*Totals may not foot due to rounding.

Entergy Corporation
Consolidating Balance Sheet
March 31, 2010 vs December 31, 2009
(Dollars in thousands)
(Unaudited)
	U.S. Utilities			Entergy Nuclear			Parent & Other			Consolidated
LIABILITIES AND SHAREHOLDERS' EQUITY
CURRENT LIABILITIES
Currently maturing long-term debt	$	4,986		$	(2,529	)	$	86,000		$	88,457
Notes payable:
Associated companies		(201,773	)		-			201,773			-
Other		145,467			-			-			145,467
Account payable:
Associated companies		10,804			(1,692	)		(9,112	)		-
Other		(127,169	)		4,175			1,859			(121,135	)
Customer deposits		2,767			(250	)		-			2,517
Taxes accrued		231,267			947,167			(1,178,434	)		-
Accumulated deferred income taxes		(34,025	)		-			(7,459	)		(41,484	)
Interest accrued		(34,756	)		903			2,913			(30,940	)
Deferred fuel costs		(101,156	)		-			-			(101,156	)
Obligations under capital leases		(210,101	)		-			-			(210,101	)
Pension and other postretirement liabilities		521			158			-			679
System agreement cost equalization		110			-			-			110
Other		97,905			36,947			(1,482	)		133,370
TOTAL		(215,153	)		984,879			(903,942	)		(134,216	)
NON-CURRENT LIABILITIES
Accumulated deferred income taxes and taxes accrued		21,584			(1,077,776	)		1,540,234			484,042
Accumulated deferred investment tax credits		(4,263	)		-			-			(4,263	)
Obligations under capital leases		(317,613	)		-			-			(317,613	)
Other regulatory liabilities		112,538			-			-			112,538
Decommissioning and retirement cost liabilities		26,734			24,310			21			51,065
Accumulated provisions		(41,821	)		(6,589	)		2			(48,408	)
Pension and other postretirement liabilities		(27,372	)		(14,191	)		-			(41,563	)
Long-term debt		668,902			575			(238,481	)		430,996
Other		(14,356	)		(16,476	)		(3,038	)		(33,870	)
TOTAL		424,333			(1,090,147	)		1,298,738			632,924
Subsidiaries' preferred stock without sinking fund		-			-			(622	)		(622	)
EQUITY
Common Shareholders' Equity:
Common stock, $.01 par value, authorized 500,000,000 shares;
issued 254,752,788 shares in 2010 and in 2009		-			-			-			-
Paid-in capital		-			(100	)		3,482			3,382
Retained earnings		22,039			94,226			(44,377	)		71,888
Accumulated other comprehensive income (loss)		1,820			159,547			(790	)		160,577
Less - treasury stock, at cost		-			-			(10,872	)		(10,872	)
Total common shareholders' equity		23,859			253,673			(30,813	)		246,719
Subsidiaries' preferred stock without sinking fund		-			-			-			-
TOTAL		23,859			253,673			(30,813	)		246,719
TOTAL LIABILITIES AND EQUITY	$	233,039		$	148,405		$	363,361		$	744,805
*Totals may not foot due to rounding.

Entergy Corporation
Consolidating Income Statement
Three Months Ended March 31, 2010
(Dollars in thousands)
(Unaudited)
	U.S. Utilities			Entergy Nuclear			Parent & Other			Consolidated
OPERATING REVENUES
Electric	$	2,007,802		$	-		$	(871	)	$	2,006,931
Natural gas		96,027			-			-			96,027
Competitive businesses		-			613,776			42,613			656,389
Total		2,103,829			613,776			41,742			2,759,347
OPERATING EXPENSES
Operating and Maintenance:
Fuel, fuel related expenses, and gas purchased for resale		478,055			55,111			25,502			558,668
Purchased power		467,895			3,906			3,102			474,903
Nuclear refueling outage expenses		27,600			34,689			-			62,289
Other operation and maintenance		435,168			246,664			20,657			702,489
Decommissioning		25,420			26,134			22			51,576
Taxes other than income taxes		109,830			24,122			1,460			135,412
Depreciation and amortization		227,547			37,690			3,967			269,204
Other regulatory charges (credits) - net		28,092			-			-			28,092
Total		1,799,607			428,316			54,710			2,282,633
OPERATING INCOME		304,222			185,460			(12,968	)		476,714
OTHER INCOME (DEDUCTIONS)
Allowance for equity funds used during construction		13,296			-			-			13,296
Interest and dividend income		37,828			42,985			(32,604	)		48,209
Other than temporary impairment losses		-			-			-			-
Miscellaneous - net		(995	)		(1,708	)		2,181			(522	)
Total		50,129			41,277			(30,423	)		60,983
INTEREST AND OTHER CHARGES
Interest on long-term debt		122,615			38,767			5,550			166,932
Other interest - net		6,797			7,539			(2,069	)		12,267
Allowance for borrowed funds used during construction		(8,001	)		-			-			(8,001	)
Total		121,411			46,306			3,481			171,198
INCOME BEFORE INCOME TAXES		232,940			180,431			(46,872	)		366,499
Income taxes		89,970			86,205			(28,490	)		147,685
CONSOLIDATED NET INCOME		142,970			94,226			(18,382	)		218,814
Preferred dividend requirements of subsidiaries		4,332			-			683			5,015
NET INCOME ATTRIBUTABLE TO ENTERGY CORPORATION	$	138,638		$	94,226		$	(19,065	)	$	213,799
EARNINGS PER AVERAGE COMMON SHARE:
BASIC	$	0.73		$	0.50		$	(0.10	)	$	1.13
DILUTED	$	0.73		$	0.49		$	(0.10	)	$	1.12
AVERAGE NUMBER OF COMMON SHARES OUTSTANDING:
BASIC											189,202,684
DILUTED											191,283,703
*Totals may not foot due to rounding.

Entergy Corporation
Consolidating Income Statement
Three Months Ended March 31, 2009
(Dollars in thousands)
(Unaudited)
	U.S. Utilities			Entergy Nuclear			Parent & Other			Consolidated
OPERATING REVENUES
Electric	$	2,028,156		$	-		$	(1,240	)	$	2,026,916
Natural gas		74,049			-			-			74,049
Competitive businesses		-			656,187			31,960			688,147
Total		2,102,205			656,187			30,720			2,789,112
OPERATING EXPENSES
Operating and Maintenance:
Fuel, fuel related expenses, and gas purchased for resale		778,401			51,466			16,465			846,332
Purchased power		316,532			1,835			4,888			323,255
Nuclear refueling outage expenses		25,090			31,689			-			56,779
Other operation and maintenance		422,316			199,960			22,426			644,702
Decommissioning		25,037			23,686			19			48,742
Taxes other than income taxes		106,403			26,259			1,735			134,397
Depreciation and amortization		220,360			33,639			3,853			257,852
Other regulatory charges (credits) - net		(29,474	)		-			-			(29,474	)
Total		1,864,665			368,534			49,386			2,282,585
OPERATING INCOME		237,540			287,653			(18,666	)		506,527
OTHER INCOME (DEDUCTIONS)
Allowance for equity funds used during construction		16,947			-			-			16,947
Interest and dividend income		43,106			29,308			(26,027	)		46,387
Other than temporary impairment losses		-			(15,737	)		-			(15,737	)
Miscellaneous - net		(2,722	)		(5,058	)		(5,519	)		(13,299	)
Total		57,331			8,513			(31,546	)		34,298
INTEREST AND OTHER CHARGES
Interest on long-term debt		109,709			2,125			16,131			127,965
Other interest - net		5,543			11,082			2,668			19,293
Allowance for borrowed funds used during construction		(9,812	)		-			-			(9,812	)
Total		105,440			13,207			18,799			137,446
INCOME BEFORE INCOME TAXES		189,431			282,959			(69,011	)		403,379
Income taxes		73,463			102,077			(12,494	)		163,046
CONSOLIDATED NET INCOME		115,968			180,882			(56,517	)		240,333
Preferred dividend requirements of subsidiaries		4,332			-			666			4,998
NET INCOME ATTRIBUTABLE TO ENTERGY CORPORATION	$	111,636		$	180,882		$	(57,183	)	$	235,335
EARNINGS PER AVERAGE COMMON SHARE:
BASIC	$	0.58		$	0.94		$	(0.30	)	$	1.22
DILUTED	$	0.56		$	0.91		$	(0.27	)	$	1.20
AVERAGE NUMBER OF COMMON SHARES OUTSTANDING:
BASIC											192,593,601
DILUTED											198,058,002
*Totals may not foot due to rounding.

Entergy Corporation
Consolidating Income Statement
Three Months Ended March 31, 2010 vs. 2009
(Dollars in thousands)
(Unaudited)
	U.S. Utilities			Entergy Nuclear			Parent & Other			Consolidated
OPERATING REVENUES
Electric	$	(20,354	)	$	-		$	369		$	(19,985	)
Natural gas		21,978			-			-			21,978
Competitive businesses		-			(42,411	)		10,653			(31,758	)
Total		1,624			(42,411	)		11,022			(29,765	)
OPERATING EXPENSES
Operating and Maintenance:
Fuel, fuel related expenses, and gas purchased for resale		(300,346	)		3,645			9,037			(287,664	)
Purchased power		151,363			2,071			(1,786	)		151,648
Nuclear refueling outage expenses		2,510			3,000			-			5,510
Other operation and maintenance		12,852			46,704			(1,769	)		57,787
Decommissioning		383			2,448			3			2,834
Taxes other than income taxes		3,427			(2,137	)		(275	)		1,015
Depreciation and amortization		7,187			4,051			114			11,352
Other regulatory charges (credits )- net		57,566			-			-			57,566
Total		(65,058	)		59,782			5,324			48
OPERATING INCOME		66,682			(102,193	)		5,698			(29,813	)
OTHER INCOME (DEDUCTIONS)
Allowance for equity funds used during construction		(3,651	)		-			-			(3,651	)
Interest and dividend income		(5,278	)		13,677			(6,577	)		1,822
Other than temporary impairment losses		-			15,737			-			15,737
Miscellaneous - net		1,727			3,350			7,700			12,777
Total		(7,202	)		32,764			1,123			26,685
INTEREST AND OTHER CHARGES
Interest on long-term debt		12,906			36,642			(10,581	)		38,967
Other interest - net		1,254			(3,543	)		(4,737	)		(7,026	)
Allowance for borrowed funds used during construction		1,811			-			-			1,811
Total		15,971			33,099			(15,318	)		33,752
INCOME BEFORE INCOME TAXES		43,509			(102,528	)		22,139			(36,880	)
Income taxes		16,507			(15,872	)		(15,996	)		(15,361	)
CONSOLIDATED NET INCOME		27,002			(86,656	)		38,135			(21,519	)
Preferred dividend requirements of subsidiaries		-			-			17			17
NET INCOME ATTRIBUTABLE TO ENTERGY CORPORATION	$	27,002		$	(86,656	)	$	38,118		$	(21,536	)
EARNINGS PER AVERAGE COMMON SHARE:
BASIC	$	0.15		$	(0.44	)	$	0.20		$	(0.09	)
DILUTED	$	0.17		$	(0.42	)	$	0.17		$	(0.08	)
*Totals may not foot due to rounding.

Entergy Corporation
Consolidating Income Statement
Twelve Months Ended March 31, 2010
(Dollars in thousands)
(Unaudited)
	U.S. Utilities			Entergy Nuclear			Parent & Other			Consolidated
OPERATING REVENUES
Electric	$	7,862,785		$	-		$	(2,755	)	$	7,860,030
Natural gas		194,190			-			-			194,190
Competitive businesses		-			2,512,842			148,822			2,661,664
Total		8,056,975			2,512,842			146,067			10,715,884
OPERATING EXPENSES
Operating and Maintenance:
Fuel, fuel related expenses, and gas purchased for resale		1,726,547			219,665			75,955			2,022,167
Purchased power		1,507,780			17,711			21,360			1,546,851
Nuclear refueling outage expenses		107,526			139,294			-			246,820
Other operation and maintenance		1,849,360			895,624			63,615			2,808,599
Decommissioning		100,067			101,747			83			201,897
Taxes other than income taxes		405,926			93,928			5,020			504,874
Depreciation and amortization		933,426			145,498			15,202			1,094,126
Other regulatory charges (credits) - net		35,838			-			-			35,838
Total		6,666,470			1,613,467			181,235			8,461,172
OPERATING INCOME		1,390,505			899,375			(35,168	)		2,254,712
OTHER INCOME (DEDUCTIONS)
Allowance for equity funds used during construction		55,894			-			-			55,894
Interest and dividend income		175,227			183,741			(120,488	)		238,480
Other than temporary impairment losses		-			(70,363	)		-			(70,363	)
Miscellaneous - net		(2,355	)		(16,011	)		(9,252	)		(27,618	)
Total		228,766			97,367			(129,740	)		196,393
INTEREST AND OTHER CHARGES
Interest on long-term debt		476,394			45,908			37,381			559,683
Other interest - net		33,206			43,075			(345	)		75,936
Allowance for borrowed funds used during construction		(31,424	)		-			-			(31,424	)
Total		478,176			88,983			37,036			604,195
INCOME BEFORE INCOME TAXES		1,141,095			907,759			(201,944	)		1,846,910
Income taxes		405,188			363,394			(151,203	)		617,379
CONSOLIDATED NET INCOME		735,907			544,365			(50,741	)		1,229,531
Preferred dividend requirements of subsidiaries		17,329			-			2,647			19,976
NET INCOME ATTRIBUTABLE TO ENTERGY CORPORATION	$	718,578		$	544,365		$	(53,388	)	$	1,209,555
EARNINGS PER AVERAGE COMMON SHARE:
BASIC	$	3.76		$	2.84		$	(0.28	)	$	6.32
DILUTED	$	3.72		$	2.81		$	(0.28	)	$	6.25
AVERAGE NUMBER OF COMMON SHARES OUTSTANDING:
BASIC											191,411,500
DILUTED											193,604,305
*Totals may not foot due to rounding.

Entergy Corporation
Consolidating Income Statement
Twelve Months Ended March 31, 2009
(Dollars in thousands)
(Unaudited)
	U.S. Utilities			Entergy Nuclear			Parent & Other			Consolidated
OPERATING REVENUES
Electric	$	10,057,996		$	-		$	(4,147	)	$	10,053,849
Natural gas		226,511			-			-			226,511
Competitive businesses		-			2,534,080			203,695			2,737,775
Total		10,284,507			2,534,080			199,548			13,018,135
OPERATING EXPENSES
Operating and Maintenance:
Fuel, fuel related expenses, and gas purchased for resale		3,536,222			211,239			136,135			3,883,596
Purchased power		2,162,423			10,939			20,451			2,193,813
Nuclear refueling outage expenses		97,974			129,305			-			227,279
Other operation and maintenance		1,868,816			791,301			116,079			2,776,196
Decommissioning		97,533			94,545			77			192,155
Taxes other than income taxes		423,764			93,766			5,249			522,779
Depreciation and amortization		898,458			129,582			15,687			1,043,727
Other regulatory charges (credits) - net		(4,871	)		-			-			(4,871	)
Total		9,080,319			1,460,677			293,678			10,834,674
OPERATING INCOME		1,204,188			1,073,403			(94,130	)		2,183,461
OTHER INCOME (DEDUCTIONS)
Allowance for equity funds used during construction		52,183			-			-			52,183
Interest and dividend income		139,984			110,225			(63,886	)		186,323
Other than temporary impairment losses		-			(61,736	)		-			(61,736	)
Miscellaneous - net		(5,467	)		(15,052	)		(3,746	)		(24,265	)
Total		186,700			33,437			(67,632	)		152,505
INTEREST AND OTHER CHARGES
Interest on long-term debt		427,352			3,270			75,098			505,720
Other interest - net		33,364			50,895			35,788			120,047
Allowance for borrowed funds used during construction		(29,962	)		-			-			(29,962	)
Total		430,754			54,165			110,886			595,805
INCOME BEFORE INCOME TAXES		960,134			1,052,675			(272,648	)		1,740,161
Income taxes		360,501			296,211			(83,672	)		573,040
CONSOLIDATED NET INCOME		599,633			756,464			(188,976	)		1,167,121
Preferred dividend requirements of subsidiaries		17,307			-			2,662			19,969
NET INCOME ATTRIBUTABLE TO ENTERGY CORPORATION	$	582,326		$	756,464		$	(191,638	)	$	1,147,152
EARNINGS PER AVERAGE COMMON SHARE:
BASIC	$	3.06		$	3.97		$	(1.00	)	$	6.03
DILUTED	$	2.91		$	3.79		$	(0.85	)	$	5.85
AVERAGE NUMBER OF COMMON SHARES OUTSTANDING:
BASIC											190,387,963
DILUTED											199,681,692
*Totals may not foot due to rounding.

Entergy Corporation
Consolidating Income Statement
Twelve Months Ended March 31, 2010 vs. 2009
(Dollars in thousands)
(Unaudited)
	U.S. Utilities			Entergy Nuclear			Parent & Other			Consolidated
OPERATING REVENUES
Electric	$	(2,195,211	)	$	-		$	1,392		$	(2,193,819	)
Natural gas		(32,321	)		-			-			(32,321	)
Competitive businesses		-			(21,238	)		(54,873	)		(76,111	)
Total		(2,227,532	)		(21,238	)		(53,481	)		(2,302,251	)
OPERATING EXPENSES
Operating and Maintenance:
Fuel, fuel related expenses, and gas purchased for resale		(1,809,675	)		8,426			(60,180	)		(1,861,429	)
Purchased power		(654,643	)		6,772			909			(646,962	)
Nuclear refueling outage expenses		9,552			9,989			-			19,541
Other operation and maintenance		(19,456	)		104,323			(52,464	)		32,403
Decommissioning		2,534			7,202			6			9,742
Taxes other than income taxes		(17,838	)		162			(229	)		(17,905	)
Depreciation and amortization		34,968			15,916			(485	)		50,399
Other regulatory charges (credits )- net		40,709			-			-			40,709
Total		(2,413,849	)		152,790			(112,443	)		(2,373,502	)
OPERATING INCOME		186,317			(174,028	)		58,962			71,251
OTHER INCOME (DEDUCTIONS)
Allowance for equity funds used during construction		3,711			-			-			3,711
Interest and dividend income		35,243			73,516			(56,602	)		52,157
Other than temporary impairment losses		-			(8,627	)		-			(8,627	)
Miscellaneous - net		3,112			(959	)		(5,506	)		(3,353	)
Total		42,066			63,930			(62,108	)		43,888
INTEREST AND OTHER CHARGES
Interest on long-term debt		49,042			42,638			(37,717	)		53,963
Other interest - net		(158	)		(7,820	)		(36,133	)		(44,111	)
Allowance for borrowed funds used during construction		(1,462	)		-			-			(1,462	)
Total		47,422			34,818			(73,850	)		8,390
INCOME BEFORE INCOME TAXES		180,961			(144,916	)		70,704			106,749
Income taxes		44,687			67,183			(67,531	)		44,339
CONSOLIDATED NET INCOME		136,274			(212,099	)		138,235			62,410
Preferred dividend requirements of subsidiaries		21			-			(15	)		7
NET INCOME ATTRIBUTABLE TO ENTERGY CORPORATION	$	136,253		$	(212,099	)	$	138,250		$	62,403
EARNINGS PER AVERAGE COMMON SHARE:
BASIC	$	0.70		$	(1.13	)	$	0.72		$	0.29
DILUTED	$	0.81		$	(0.98	)	$	0.57		$	0.40
*Totals may not foot due to rounding.

Entergy Corporation
Consolidated Cash Flow Statement
Three Months Ended March 31, 2010 vs. 2009
(Dollars in thousands)
(Unaudited)
	2010			2009			Variance
OPERATING ACTIVITIES
Consolidated net income	$	218,814		$	240,333		$	(21,519	)
Adjustments to reconcile consolidated net income to net cash flow
provided by operating activities:
Reserve for regulatory adjustments		438			1,210			(772	)
Other regulatory charges (credits) - net		28,092			(29,474	)		57,566
Depreciation, amortization, and decommissioning, including nuclear fuel amortization		423,432			348,444			74,988
Deferred income taxes, investment tax credits, and non-current taxes accrued		133,533			155,029			(21,496	)
Changes in working capital:
Receivables		43,830			102,428			(58,598	)
Fuel inventory		(6,324	)		(17,631	)		11,307
Accounts payable		(79,250	)		(134,008	)		54,758
Taxes accrued		-			(12,784	)		12,784
Interest accrued		(36,676	)		(37,413	)		737
Deferred fuel		964			275,508			(274,544	)
Other working capital accounts		19,527			(120,505	)		140,032
Provision for estimated losses and reserves		(35,870	)		1,281			(37,151	)
Changes in other regulatory assets		(66,248	)		(447,882	)		381,634
Changes in pensions and other postretirement liabilities		(40,884	)		(29,158	)		(11,726	)
Other		70,887			79,241			(8,354	)
Net cash flow provided by operating activities		674,265			374,619			299,646
INVESTING ACTIVITIES
Construction/capital expenditures		(447,476	)		(455,737	)		8,261
Allowance for equity funds used during construction		13,296			16,947			(3,651	)
Nuclear fuel purchases		(65,336	)		(118,890	)		53,554
Proceeds from sale/leaseback of nuclear fuel		-			11,040			(11,040	)
Proceeds from sale of assets and businesses		9,675			-			9,675
Changes in transition charge account		(21,940	)		(7,831	)		(14,109	)
NYPA value sharing payment		(72,000	)		(72,000	)		-
Decrease (increase) in other investments		96,416			7,339			89,077
Proceeds from nuclear decommissioning trust fund sales		770,781			583,166			187,615
Investment in nuclear decommissioning trust funds		(798,864	)		(610,836	)		(188,028	)
Net cash flow used in investing activities		(515,448	)		(646,802	)		131,354
FINANCING ACTIVITIES
Proceeds from the issuance of:
Long-term debt		42,545			489,987			(447,442	)
Common stock and treasury stock		6,078			927			5,151
Retirement of long-term debt		(100,289	)		(215,023	)		114,734
Changes in credit line borrowings - net		(13,368	)		25,000			(38,368	)
Dividends paid:
Common stock		(141,892	)		(142,085	)		193
Preferred stock		(5,015	)		(4,998	)		(17	)
Net cash flow provided by (used in) financing activities		(211,941	)		153,808			(365,749	)
Effect of exchange rates on cash and cash equivalents		607			842			(235	)
Net increase (decrease) in cash and cash equivalents		(52,517	)		(117,533	)		65,016
Cash and cash equivalents at beginning of period		1,709,551			1,920,491			(210,940	)
Cash and cash equivalents at end of period	$	1,657,034		$	1,802,958		$	(145,924	)
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
Cash paid (received) during the period for:
Interest - net of amount capitalized	$	171,145		$	176,892		$	(5,747	)
Income taxes	$	(1,385	)	$	(15,139	)	$	13,754
Noncash financing activities:
Long-term debt retired (equity unit notes)		-		$	(500,000	)	$	500,000
Common stock issued in settlement of equity unit purchase contracts		-		$	500,000		$	(500,000	)
Proceeds from long-term debt issued for the purpose
of refunding prior long-term debt	$	150,000			-		$	150,000

Entergy Corporation
Consolidated Cash Flow Statement
Twelve Months Ended March 31, 2010 vs. 2009
(Dollars in thousands)
(Unaudited)
	2010			2009			Variance
OPERATING ACTIVITIES
Consolidated net income	$	1,229,531		$	1,167,121		$	62,410
Adjustments to reconcile consolidated net income to net cash flow
provided by operating activities:
Reserve for regulatory adjustments		(1,280	)		(4,166	)		2,886
Other regulatory charges (credits) - net		35,839			(4,871	)		40,710
Depreciation, amortization, and decommissioning, including nuclear fuel amortization		1,533,849			1,407,975			125,874
Deferred income taxes, investment tax credits, and non-current taxes accrued		843,188			390,993			452,195
Changes in working capital:
Receivables		57,846			190,455			(132,609	)
Fuel inventory		30,598			(2,527	)		33,125
Accounts payable		40,507			(166,755	)		207,262
Taxes accrued		(62,426	)		62,426			(124,852	)
Interest accrued		5,711			(3,827	)		9,538
Deferred fuel		(202,230	)		432,658			(634,888	)
Other working capital accounts		(88,178	)		(11,476	)		(76,702	)
Provision for estimated losses and reserves		(49,181	)		9,709			(58,890	)
Changes in other regulatory assets		(33,523	)		(812,662	)		779,139
Changes in pensions and other postretirement liabilities		60,063			816,713			(756,650	)
Other		(167,510	)		(220,989	)		53,479
Net cash flow provided by operating activities		3,232,804			3,250,777			(17,973	)
INVESTING ACTIVITIES
Construction/capital expenditures		(1,922,984	)		(2,294,675	)		371,691
Allowance for equity funds used during construction		55,894			52,184			3,710
Nuclear fuel purchases		(471,920	)		(372,460	)		(99,460	)
Proceeds from sale/leaseback of nuclear fuel		273,957			195,437			78,520
Proceeds from sale of assets and businesses		49,229			30,725			18,504
Payment for purchase of plant		-			(210,414	)		210,414
Insurance proceeds received for property damages		53,760			130,114			(76,354	)
Changes in transition charge account		(15,145	)		7,732			(22,877	)
NYPA value sharing payment		(72,000	)		(72,000	)		-
Decrease (increase) in other investments		183,231			(73,468	)		256,699
Proceeds from nuclear decommissioning trust fund sales		2,758,138			1,977,725			780,413
Investment in nuclear decommissioning trust funds		(2,855,200	)		(2,020,177	)		(835,023	)
Net cash flow used in investing activities		(1,963,040	)		(2,649,277	)		686,237
FINANCING ACTIVITIES
Proceeds from the issuance of:
Long-term debt		1,556,027			3,401,682			(1,845,655	)
Common stock and treasury stock		33,349			31,032			2,317
Retirement of long-term debt		(1,728,435	)		(2,263,602	)		535,167
Repurchase of common stock		(613,125	)		(354,169	)		(258,956	)
Redemption of preferred stock		(1,847	)		-			(1,847	)
Changes in credit line borrowings - net		(63,368	)		55,000			(118,368	)
Dividends paid:
Common stock		(576,763	)		(570,551	)		(6,212	)
Preferred stock		(19,975	)		(17,753	)		(2,222	)
Net cash flow provided by (used in) financing activities		(1,414,137	)		281,639			(1,695,776	)
Effect of exchange rates on cash and cash equivalents		(1,551	)		4,113			(5,664	)
Net increase (decrease) in cash and cash equivalents		(145,924	)		887,252			(1,033,176	)
Cash and cash equivalents at beginning of period		1,802,958			915,706			887,252
Cash and cash equivalents at end of period	$	1,657,034		$	1,802,958		$	(145,924	)
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
Cash paid (received) during the period for:
Interest - net of amount capitalized	$	562,670		$	605,393		$	(42,723	)
Income taxes	$	56,811		$	119,938		$	(63,127	)
Noncash financing activities:
Long-term debt retired (equity unit notes)		-		$	(500,000	)	$	500,000
Common stock issued in settlement of equity unit purchase contracts		-		$	500,000		$	(500,000	)
Proceeds from long-term debt issued for the purpose
of refunding prior long-term debt	$	150,000			-		$	150,000