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

Exhibit 99.1

For further information:

Michele Lopiccolo, VP, Investor Relations

Phone 504/576-4879, Fax 504/576-2897

      mlopicc@entergy.com

INVESTOR NEWS

February 2, 2010

ENTERGY REPORTS FOURTH QUARTER EARNINGS

NEW ORLEANS – Entergy Corporation reported fourth quarter 2009 earnings of $1.64 per share on an as-reported basis and $1.75 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
Fourth Quarter and Year-to-Date 2009 vs. 2008
(Per share in U.S. $)
	Fourth Quarter			Year-to-Date
	2009	2008	Change	2009	2008	Change
As-Reported Earnings	1.64	0.89	0.75	6.30	6.20	0.10
Less Special Items	(0.11)	(0.10)	(0.01)	(0.37)	(0.31)	(0.06)
Operational Earnings	1.75	0.99	0.76	6.67	6.51	0.16
Weather Impact	(0.01)	(0.03)	0.02	(0.01)	(0.02)	0.01

Operational Earnings Highlights for Fourth Quarter 2009

·   Utility, Parent & Other’s results were higher due to lower income tax expense, lower non-fuel operation and maintenance expense and higher net revenue.

·   Entergy Nuclear’s earnings decreased as a result of higher income tax and non-fuel operation and maintenance expenses, partially offset by higher net revenue and other income.

·   Entergy’s Non-Nuclear Wholesale Assets’ results improved due to lower income tax expense.

“Both our utility and non-utility nuclear businesses delivered strong operational performance during a period of extraordinary global economic and financial uncertainty,” said J. Wayne Leonard, Entergy’s chairman and chief executive officer.  “Looking ahead, signs of an improving economic environment, our market-based point-of-view, adherence to our disciplined risk management and the strength of our cash position provide a foundation that supports our strategic, operational and financial goals.”

Entergy’s business highlights include the following:

·   Entergy Texas completed storm recovery for Hurricane Ike in November when it executed $545.9 million of securitization financing.  Also, a stipulation agreement was reached with the Louisiana Public Service Commission Staff in the storm proceedings in Louisiana.

·   Entergy Texas made a new rate case filing at the Public Utility Commission of Texas at the end of December

·   The Nuclear Regulatory Commission agreed to extend the expiration date for the spin-off approval to August 1, 2010.

Entergy will host a teleconference to discuss this release at 10:00 a.m. CT on Tuesday, February 2, 2010, with access by telephone, 719-457-2080, confirmation code 6584600.  The call and presentation slides can also be accessed via Entergy’s Web site at www.entergy.com.  A replay of the teleconference will be available through February 9, 2010 by dialing 719-457-0820, confirmation code 6584600.  The replay will also be available on Entergy’s Web site at www.entergy.com.

I.   Consolidated Results

Consolidated Earnings

Table 2 provides a comparative summary of consolidated earnings per share for fourth quarter 2009 versus 2008, including a reconciliation of GAAP as-reported earnings to non-GAAP operational earnings.  Utility, Parent & Other’s earnings increased quarter-over-quarter due primarily to lower income tax expense, as well as lower non-fuel operation and maintenance expense primarily resulting from the absence of regulatory charges associated with rate proceedings at Entergy Arkansas in 2008.  Entergy Nuclear’s fourth quarter 2009 earnings were lower than last year as a result of an increase in income tax and operation and maintenance expenses.  Higher net revenue from the non-utility nuclear fleet, driven by both higher pricing and production, and higher other income provided a partial offset to the lower results in the current quarter.  Entergy’s Non-Nuclear Wholesale Assets business reported improved earnings due primarily to a reduction in income tax expense.

Table 2: Consolidated Earnings – Reconciliation of GAAP to Non-GAAP Measures Fourth Quarter and Year-to-Date 2009 vs. 2008 (see Appendix F for definitions of certain measures)
(Per share in U.S. $)
	Fourth Quarter			Year-to-Date
	2009	2008	Change	2009	2008	Change
As-Reported
Utility, Parent & Other	0.56	(0.38)	0.94	2.88	2.22	0.66
Entergy Nuclear	0.89	1.14	(0.25)	3.22	3.97	(0.75)
Non-Nuclear Wholesale Assets	0.19	0.13	0.06	0.20	0.01	0.19
Consolidated As-Reported Earnings	1.64	0.89	0.75	6.30	6.20	0.10
Less Special Items
Utility, Parent & Other	(0.05)	(0.05)	-	(0.14)	(0.21)	0.07
Entergy Nuclear	(0.06)	(0.04)	(0.02)	(0.23)	(0.10)	(0.13)
Non-Nuclear Wholesale Assets	-	(0.01)	0.01	-	-	-
Consolidated Special Items	(0.11)	(0.10)	(0.01)	(0.37)	(0.31)	(0.06)
Operational
Utility, Parent & Other	0.61	(0.33)	0.94	3.02	2.43	0.59
Entergy Nuclear	0.95	1.18	(0.23)	3.45	4.07	(0.62)
Non-Nuclear Wholesale Assets	0.19	0.14	0.05	0.20	0.01	0.19
Consolidated Operational Earnings	1.75	0.99	0.76	6.67	6.51	0.16
Weather Impact	(0.01)	(0.03)	0.02	(0.01)	(0.02)	0.01

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

Consolidated Net Cash Flow Provided by Operating Activities

Entergy’s net cash flow provided by operating activities in fourth quarter 2009 was $924 million compared to $632 million in fourth quarter 2008.  A fourth quarter intercompany transaction that nets to zero on a consolidated basis resulted in significant offsetting variances at Utility, Parent & Other and Entergy Nuclear.  Pursuant to Entergy’s intercompany tax allocation agreement, Entergy Nuclear received $1.3 billion in cash payments from Utility, Parent & Other.

The overall quarterly increase was due primarily to:

·   a favorable variance from hurricanes Gustav and Ike with net effects reducing operating cash flow in 2008 by $444 million as a result of costs for system repairs and lower revenues due to customer outages

·   higher net revenue and lower operation and maintenance costs (excluding storm effects) of $76 million at the Utility

·   higher net revenues of $59 million at Entergy Nuclear

·   a decrease in refueling outage costs of $32 million at Entergy Nuclear

·   lower working capital requirements of $69 million at Entergy Nuclear

Partially offsetting was:

·   a decrease in net deferred fuel recovery of $481 million at the Utility

For the year 2009, Entergy’s operating cash flow was $2,933 million versus $3,324 million last year.  Payments under the intercompany tax allocation agreement noted above resulted in significant offsetting variances at Utility, Parent & Other and Entergy Nuclear.

The overall decrease for the year was due primarily to:

·   the absence of $954 million in securitization proceeds received in 2008 at Entergy Gulf States Louisiana and Entergy Louisiana for hurricanes Katrina and Rita

·   an increase in refueling outage costs and spin-off dis-synergies totaling $79 million at Entergy Nuclear

Partially offsetting items include:

·   a net decrease in the effects of major storm activity (i.e., the 2008 hurricanes and 2009 ice storm in Arkansas) and receipt of associated insurance proceeds totaling $91 million

·   an increase in net deferred fuel recovery of $111 million at the Utility

·   lower working capital requirements of $108 million at the Utility

·   a decrease of $155 million in pension funding at the Utility and Entergy Nuclear

·   an overall net decrease in tax payments of $94 million

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

Table 3:  Consolidated Net Cash Flow Provided by Operating Activities
Fourth Quarter and Year-to-Date 2009 vs. 2008
(U.S. $ in millions)
	Fourth Quarter			Year-to-Date
	2009	2008	Change	2009	2008	Change
Utility, Parent & Other	(837)	272	(1,109)	462	2,051	(1,589)
Entergy Nuclear	1,725	285	1,440	2,434	1,255	1,179
Non-Nuclear Wholesale Assets	36	75	(39)	37	18	19
Total Net Cash Flow Provided by Operating Activities	924	632	292	2,933	3,324	(391)

II.   Utility, Parent & Other Results

In fourth quarter 2009, Utility, Parent & Other’s as-reported earnings were $0.56 per share compared to a loss of $(0.38) per share in fourth quarter 2008.  On an operational basis, fourth quarter 2009 earnings for Utility, Parent & Other were $0.61 per share versus a loss of $(0.33) per share in the same quarter last year.  Operational earnings for Utility, Parent & Other in fourth quarter 2009 reflect lower income tax expense associated with the net effect of annual consolidated income tax adjustments across the Entergy companies.  A favorable tax reserve adjustment also contributed following issuance by the Louisiana Department of Revenue of a private letter ruling related to securitization of Katrina and Rita storm costs.  In addition, the absence of regulatory charges associated with rate proceedings at Entergy Arkansas in 2008 was the primary driver of lower non-fuel operation and maintenance expense, as well as a contributor to the lower income tax expense compared to fourth quarter 2008.  Also contributing to the earnings improvement versus the same quarter last year was higher net revenue.

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

·   Residential sales in fourth quarter 2009, on a weather-adjusted basis, increased 4.6 percent compared to fourth quarter 2008.

·   Commercial and governmental sales, on a weather-adjusted basis, increased 3.0 percent year over year.

·   Industrial sales in the fourth quarter increased 7.1 percent compared to the same quarter of 2008.

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 fourth quarter 2009 was driven by the large industrial customer group, particularly in chemicals and refining.  Small and mid-sized industrial customers are slowly showing signs of recovery from the recession, but their usage continued to be negatively affected in the current quarter.  Also, a portion of the quarter-over-quarter increase in sales for all customer classes was the result of the absence of outages for the September 2008 hurricanes, most notably in the industrial segment. Industrial customers are typically billed at the beginning of the month, and as such these outages for hurricanes Gustav and Ike were reflected in October sales.  Near normal weather versus warmer-than-normal weather in fourth quarter 2008 also provided a modest increase in sales volume.

For the year 2009, Utility, Parent and Other earned $2.88 per share on an as-reported earnings basis, compared to $2.22 per share in 2008.  Operational earnings in 2009 were $3.02 per share compared to $2.43 per share in 2008.  The increase in operational earnings in 2009 was driven by higher Utility net revenue with the absence of hurricanes Gustav and Ike in 2008 contributing.  Another factor in the improved results at Utility, Parent & Other was lower operation and maintenance expense, due primarily to the absence of Entergy Arkansas regulatory charges noted above.  Also contributing to the earnings improvement was a lower overall effective tax rate for Utility, Parent & Other in 2009 versus 2008.  Partially offsetting these items was an increase in depreciation and amortization expense in the current year due to increased plant in service.

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

Table 4:  Utility Operational Performance Measures
Fourth Quarter and Year-to-Date 2009 vs. 2008 (see Appendix F for definitions of measures)
	Fourth Quarter				Year-to-Date
	2009	2008	% Change	% Weather Adjusted	2009	2008	% Change	% Weather Adjusted
GWh billed
Residential	7,421	6,992	6.1%	4.6%	33,626	33,047	1.8%	1.5%
Commercial and governmental	7,240	6,992	3.5%	3.0%	29,884	29,719	0.6%	0.5%
Industrial	9,235	8,626	7.1%	7.1%	35,638	37,843	(5.8)%	(5.8)%
Total Retail Sales	23,896	22,610	5.7%	5.0%	99,148	100,609	(1.5)%	(1.5)%
Wholesale	998	1,240	(19.5)%		4,862	5,401	(10.0)%
Total Sales	24,894	23,850	4.4%		104,010	106,010	(1.9)%
O&M expense per MWh	$20.18	$23.95	(15.7)%		$18.67	$18.48	1.0%
Number of retail customers
Residential					2,331,433	2,304,324	1.2%
Commercial and governmental					346,925	342,152	1.4%
Industrial					40,757	42,148	(3.3)%

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

III.   Competitive Businesses Results

Entergy’s competitive businesses include Entergy Nuclear and Non-Nuclear Wholesale Assets.

Entergy Nuclear

Entergy Nuclear earned $0.89 per share on an as-reported basis in fourth quarter 2009, compared to as-reported earnings of $1.14 per share in fourth quarter 2008.  On an operational basis, fourth quarter 2009 Entergy Nuclear earnings were $0.95 per share versus $1.18 per share in the last quarter of the prior year.  Entergy Nuclear’s operational earnings decreased as a result of higher income tax expense in the current quarter due primarily to the net effect of the annual consolidated tax adjustments.  Also contributing to the lower results was higher operation and maintenance expense during the quarter due to the absence of refueling outages in the quarter and associated deferral of costs.  Partially offsetting these items was higher net revenue as a result of higher generation due to 32 fewer refueling outage days in the current quarter and increased pricing.  Higher other income associated with decommissioning trusts also provided an offset to decreased earnings.  A smaller impairment recognized on Entergy Nuclear’s decommissioning trust funds in the current period contributed to higher other income, as well as higher earnings realized on decommissioning trust investments in 2009.

For the year 2009, Entergy Nuclear earned $3.22 per share on an as-reported basis and $3.45 per share on an operational basis.  This compares to as-reported earnings of $3.97 per share and operational earnings of $4.07 per share at Entergy Nuclear in the prior year.  The decline in Entergy Nuclear’s operational earnings in 2009 was due primarily to a higher effective income tax rate as well as an increase in operation and maintenance expense.  Impairments on Entergy Nuclear’s decommissioning trust funds in 2009 exceeded amounts recognized in 2008, and were partially offset by higher realized earnings on decommissioning trust investments, also reflected in other income.

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

Table 5:  Entergy Nuclear Operational Performance Measures
Fourth Quarter and Year-to-Date 2009 vs. 2008 (see Appendix F for definitions of measures)
	Fourth Quarter			Year-to-Date
	2009	2008	% Change	2009	2008	% Change
Net MW in operation	4,998	4,998	-%	4,998	4,998	-%
Average realized price per MWh	$59.43	$56.69	5%	$61.07	$59.51	3%
Production cost per MWh	$23.20	$22.77	2%	$23.26	$21.88	6%
Non-fuel O&M expense/purchased power per MWh (a)	$23.60	$23.06	2%	$23.30	$21.95	6%
GWh billed	11,052	10,489	5%	40,981	41,710	(2)%
Capacity factor	99%	94%	5%	93%	95%	(2)%
Refueling outage days:
FitzPatrick	-	10		-	26
Indian Point 2	-	-		-	26
Indian Point 3	-	-		36	-
Palisades	-	-		41	-
Pilgrim	-	-		31	-
Vermont Yankee	-	22		-	22

(a) Fourth quarter and year-to-date 2009 exclude the effect of the special item for non-utility nuclear spin-off dis-synergies.

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

Table 6:  Entergy Nuclear’s Capacity and Generation Projected Sold Forward
2010 through 2014 (see Appendix F for definitions of measures)
	2010	2011	2012	2013	2014
Energy
Planned TWh of generation	40	41	41	40	41
Percent of planned generation sold forward (b)
Unit-contingent	53%	54%	18%	12%	14%
Unit-contingent with availability guarantees	35%	17%	13%	6%	3%
Firm LD	-%	3%	-%	-%	-%
Total Energy Sold Forward	88%	74%	31%	18%	17%
Average contract price per MWh (c)	$57	$56	$56	$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	26%	25%	18%	16%	16%
Capacity contracts	42%	26%	30%	13%	-%
Total Capacity Sold Forward	68%	51%	48%	29%	16%
Average capacity contract price per kW per month	$3.0	$3.6	$3.0	$2.6	-
Blended Capacity and Energy Recap (based on revenues)
Percent of planned energy and capacity sold forward	87%	73%	33%	16%	13%
Average contract revenue per MWh (c)	$59	$58	$60	$53	$50

(b) 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.

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

Non-Nuclear Wholesale Assets

Entergy’s Non-Nuclear Wholesale Assets’ fourth quarter earnings were $0.19 per share in 2009 compared to as-reported earnings of $0.13 per share and operational earnings of $0.14 per share in the same quarter a year ago.  Income tax benefits were the primary drivers in both quarters.  The current quarter reflects a tax benefit recognized on a capital loss associated with the sale of stock of a merchant fossil generation subsidiary to a third party.  In the fourth quarter 2008, a closing agreement was reached with the Internal Revenue Service allowing a capital loss.  As a result, a provision for tax uncertainties that existed on this item was reversed.

For the year 2009, Entergy’s Non-Nuclear Wholesale Assets business earned $0.20 per share compared to earnings of $0.01 per share in 2008.  As-reported and operational results were the same in both periods.  The earnings increase in 2009 was driven by a decrease in income tax expense due to the fourth quarter 2009 benefit noted above, plus a second quarter decrease in valuation allowance on loss carryovers.  Quarterly income tax effects in 2008 were largely offsetting.

IV.   Other Financial Performance Highlights

Earnings Guidance

Entergy is affirming 2010 earnings guidance in the range of $6.15 to $6.95 per share on an as-reported basis, assuming a business as usual operation for the full year.  Operational earnings per share guidance ranges from $6.40 to $7.20 per share and excludes $(0.25) per share of projected dis-synergies associated with the spin-off of Entergy’s non-utility nuclear business and plans to enter into a nuclear services joint venture.  Guidance for 2010 does not incorporate a special item for expenses anticipated in connection with outside services provided to pursue the spin-off.  The level of these charges in 2010 will vary depending upon resolution of the spin-off.  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.  Beginning in 2010, Entergy will combine the Non-Nuclear Wholesale Assets’ results with Utility, Parent & Other’s for earnings release purposes.  The segments in 2010 guidance have been adjusted to align with the revised presentation format.  The 2010 earnings guidance is detailed in Table 7 below.

Table 7:  2010 Earnings Per Share Guidance – As-Reported and Operational
Business as Usual Basis
(Per share in U.S. $) – Prepared October 2009 (d)
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 Utility, Parent & Other		0.14
	2010 As-Reported Earnings per Share Guidance Range	6.30	0.25	6.55	6.15 – 6.95

(d)  Updated February 2010 to reflect 2009 final results.

Key assumptions supporting 2010 business as usual 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

·   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 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

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 assumes 6.75%)

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

Table 8:  2010 Earnings Sensitivities Business as Usual Basis
(Per share in U.S. $) – Prepared October 2009
Variable	2010 Guidance Assumption	Description of Change	Estimated Annual Impact (e)
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

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

V.   Appendices

Seven appendices are presented in this section as follows:

·   Appendix A includes information on Entergy’s plan to separate the non-utility nuclear business from Entergy’s regulated utility business through a tax-free spin-off of the non-utility nuclear business.

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

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

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

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

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

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

A.   Spin-off of Non-Utility Nuclear Business

Appendix A provides information on Entergy’s planned spin-off of its non-utility nuclear business.

Appendix A: Spin-off of Non-Utility Nuclear Business

The announced spin-off of Entergy’s non-utility nuclear business will establish a new independent, publicly traded company, Enexus Energy Corporation.  In addition, Entergy and Enexus intend to enter into a nuclear services joint venture, with equal ownership, with the joint venture being named EquaGen LLC.  The state regulatory decisions and financing continue as the critical path items in finalizing the spin-off transaction.  The transactions are subject to various approvals, outlined in the table below.  Final terms of the transactions and spin-off completion are subject to the approval of the Entergy Board of Directors.

Proceeding	Pending Regulatory Approvals – Spin-Off of Non-Utility Nuclear Business
Nuclear Regulatory Commission	The Nuclear Regulatory Commission (NRC) initially approved Entergy Nuclear Operations, Inc.’s (ENO) application on July 28, 2008 with the approval effective for a period of one year. Additional extensions of the approval have been granted with the current extension in effect through August 1, 2010.
Vermont Public Service Board	Request:  In January 2008, Entergy Nuclear Vermont Yankee, L.L.C. (EVY) and ENO requested approval from the Vermont Public Service Board (VPSB) for spin-off transaction and other actions required to effect the transaction. Recent Activity:  In an official statement issued on January 27, 2010, Vermont Governor Douglasdirected Commissioner O’Brien to request a stay from any further action by the VPSB on the Enexus spin-off.  This direction came in reaction to recent events at Vermont Yankee regarding conflicting information provided about piping systems carrying radioactivity prompted by tritium discovery.  A comprehensive internal investigation, conducted by an independent counsel, is now underway to not only resolve the known inconsistencies but to seek out and find any and all discrepancies or less than clear information supplied in this process and correct the record. Next Steps:  Action by the VPSB on the request for approval of the transaction following resolution of the stay. Other Background:  Under Vermont law, approval requires a finding that actions promote the general good of the state.  In October 2009, a Memorandum of Understanding (MOU) was filed with the VPSB outlining an agreement reached with the Vermont Department of Public Service, which if approved by the VPSB, would result in approval of the spin-off transaction in Vermont.  The decision on the MOU as submitted was pending before the VPSB prior to the governor’s direction to request a stay in the proceeding.
New York Public Service Commission	Request:  In January 2008, Entergy Nuclear FitzPatrick, L.L.C. (ENFP), Entergy Nuclear Indian Point 2 and 3, L.L.C. (ENIP2 & 3), ENO and corporate affiliate Enexus filed a petition with the New York Public Service Commission (NYPSC) requesting approval for the spin-off transaction and other actions required to effect the transaction. Recent Activity:  Various filings were made throughout the fourth quarter and into January in accordance with the procedures and schedule ordered by the Administrative Law Judges (ALJs) assigned to the proceeding. Next Steps:  The ALJs are expected to submit a report to the NYPSC.  While a definitive date for the submittal of such report is not known, it is expected that the ALJs will do so on a schedule that would permit the NYPSC to consider approval of the transaction at its next scheduled meeting on February 11, 2010. Other Background:  Entergy’s most recent filing on January 14, 2010 once again presented facts that demonstrate its position that Enexus will be at least as capable as Entergy of continuing the safe, secure, and reliable operation of its nuclear facilities in New York.  Other parties to the proceeding continue to oppose the transaction on various grounds.
Federal Energy Regulatory Commission	FERC approved the ENO application on June 12, 2008.  In August 2009, Entergy supplied additional data to FERC given the enhancements to the transaction and an amended order approving the transaction was received from FERC on September 11, 2009.
Securities and Exchange Commission	Request / Recent Activity:   A fifth amendment to the Form 10 was filed on November 20, 2009. Next Steps:  Final amendments will be filed, following which the SEC is expected to ultimately declare the Form 10 effective shortly before the spin-off is consummated. Other Background:  Pursuant to Section 12 of the 34 Exchange Act, a Form 10 information statement is required to be filed to register securities with the SEC.  The Form 10 is subject to review and comments by the SEC staff and will need to be declared effective prior to the distribution.  The Form 10 was initially filed in May 2008.

B.   Variance Analysis and Special Items

Appendix B-1 and Appendix B-2 provide details of fourth quarter and year-to-date 2009 vs. 2008 as-reported and operational earnings variance analysis for “Utility, Parent & Other,” “Competitive Businesses,” and “Consolidated.”

Appendix B-1: As-Reported and Operational Earnings Per Share Variance Analysis
Fourth Quarter 2009 vs. 2008
(Per share in U.S. $, sorted in consolidated as-reported column, most to least favorable)
	Utility, Parent & Other			Competitive Businesses			Consolidated
	As-Reported	Opera- tional		As-Reported	Opera- tional		As- Reported	Opera-tional
2008 earnings	(0.38)	(0.33)		1.27	1.32		0.89	0.99
Net revenue	0.14	0.14	(f)	0.20	0.20	(g)	0.34	0.34
Other operation & maintenance expense	0.30	0.25	(h)	(0.12)	(0.08)	(i)	0.18	0.17
Income taxes – other	0.56	0.56	(j)	(0.41)	(0.41)	(k)	0.15	0.15
Other income (deductions)	(0.04)	(0.04)		0.11	0.11	(l)	0.07	0.07
Interest and other charges	0.05	0.05	(m)	-	0.02		0.05	0.07
Taxes other than income taxes	0.01	0.01		-	-		0.01	0.01
Nuclear refueling outage expense	(0.01)	(0.01)		(0.01)	(0.01)		(0.02)	(0.02)
Depreciation/amortization expense	(0.02)	(0.02)		(0.01)	(0.01)		(0.03)	(0.03)
Prior year effect of the unsuccessful Equity Units remarketing	(0.05)	-	(n)	0.05	-	(n)	-	-
2009 earnings	0.56	0.61		1.08	1.14		1.64	1.75

Appendix B-2: As-Reported and Operational Earnings Per Share Variance Analysis
Year-to-Date Fourth Quarter 2009 vs. 2008
(Per share in U.S. $, sorted in consolidated as-reported column, most to least favorable)
	Utility, Parent & Other			Competitive Businesses			Consolidated
	As-Reported	Opera- tional		As-Reported	Opera- tional		As- Reported	Opera- tional
2008 earnings	2.22	2.43		3.98	4.08		6.20	6.51
Net revenue	0.33	0.33	(f)	(0.03)	(0.03)		0.30	0.30
Interest and other charges	0.05	0.05	(m)	0.09	0.16	(o)	0.14	0.21
Taxes other than income taxes	0.01	0.01		(0.03)	(0.03)		(0.02)	(0.02)
Decommissioning expense	(0.01)	(0.01)		(0.02)	(0.02)		(0.03)	(0.03)
Other operation & maintenance expense	0.25	0.11	(h)	(0.28)	(0.13)	(i)	(0.03)	(0.02)
Income taxes – other	0.22	0.22	(j)	(0.27)	(0.27)	(k)	(0.05)	(0.05)
Nuclear refueling outage expense	(0.04)	(0.04)		(0.02)	(0.02)		(0.06)	(0.06)
Other income (deductions)	0.04	0.04		(0.06)	(0.06)	(l)	(0.02)	(0.02)
Depreciation/amortization expense	(0.12)	(0.12)	(p)	(0.04)	(0.03)		(0.16)	(0.15)
Prior year effect of the unsuccessful Equity Units remarketing	(0.07)	-	(n)	0.10	-	(n)	0.03	-
2009 earnings	2.88	3.02		3.42	3.65		6.30	6.67

Utility Net Revenue Variance Analysis 2009 vs. 2008 ($ EPS)
Fourth Quarter		Year-to-Date
Weather	0.02	Weather	0.01
Sales growth/ pricing	0.07	Sales growth/ pricing	0.26
Other	0.05	Other	0.06
Total	0.14	Total	0.33

(f) Quarter and year-to-date variances were driven primarily by Utility Operating Company rate actions in Texas, Louisiana, Mississippi and Arkansas (capacity acquisition rider).  An increase in volume also benefited both periods, with the year-to-date improvement mainly as a result of the absence of two hurricanes in 2008 that materially lowered usage. In addition, fourth quarter net revenue reflected a regulatory charge resulting from a FERC order related to an Entergy Arkansas wholesale contract offset by a positive adjustment for changes in the deferred fuel methodology related to 2008 and 2009 periods at Entergy Gulf States Louisiana.

(g) The increase in the quarter is due to higher revenues at Entergy Nuclear from higher production due to fewer scheduled refueling outage days and higher pricing.  Partially offsetting was lower revenue amortization associated with the below-market PPA at Palisades.

(h) The quarter and year-to-date variances were due primarily to the absence of regulatory charges at Entergy Arkansas in fourth quarter 2008.  Partially offsetting on a year-to-date basis was higher nuclear spending, increased customer write-offs, settlement of storm-related costs and the absence of 2008 storm-related restoration cost deferrals.

(i) The increases in the quarter and year-to-date were due primarily to spin-off dis-synergies, higher nuclear spending as a result of higher non-labor costs and higher nuclear labor, in part due to the absence of refueling outages in fourth quarter 2009 and the associated deferral of costs.  Higher spending at Non-Nuclear Wholesale Assets also contributed to both the quarter and year-to-date variances.

(j) The quarter and year-to-date variances were due primarily to the net effect of fourth quarter consolidated income tax adjustments, the absence of tax flow through items associated with Entergy Arkansas proceedings in fourth quarter 2008, and a favorable tax reserve adjustment related to a fourth quarter 2009 Louisiana Department of Revenue private letter ruling.  Also contributing to the year-to-date increase were decreases in valuation allowances on capital loss carryforwards offset by the absence of a tax benefit on the liquidation of Entergy Power Generation in third quarter 2008.

(k) The quarter and year-to-date variances were driven by the net effect of consolidated income tax adjustments.  In addition, at Non-Nuclear Wholesale assets a tax benefit was recognized on a capital loss in fourth quarter 2009, while 2008 fourth quarter results reflected the reversal of a provision for tax uncertainties given a closing agreement reached with the IRS.   Also affecting the year-to-date period was the absence of 2008 benefits from a change in Massachusetts state tax law at Entergy Nuclear and the redemption of an investment at Non-Nuclear Wholesale Assets, as well as reductions in valuation allowances on capital loss carryforwards.

(l) The increase in the quarter was driven by higher realized earnings on decommissioning trust investments and a smaller decommissioning impairment in the current quarter.  The decrease year-to-date is due primarily to impairments associated with decommissioning trust fund investments for the year exceeding similar impairments in 2008, partially offset by higher realized earnings on decommissioning trust investments.

(m) The lower interest expense in the quarter and year-to-date is due primarily to lower Parent company borrowings and debt redemptions and lower affiliate interest expense, partially offset by higher net borrowings at the Utility.  Higher rates on Utility borrowings also provided a partial offset in the year-to-date period.

(n) The quarter and year-to-date variances reflect the effects of the unsuccessful remarketing of the Equity Units in February 2009 on 2008 results, which resulted in a reduction in Parent company interest expense associated with the note component of the Equity Units (for EPS calculation purposes only) offset by the dilutive effect of the Entergy common stock projected to be issued in accordance with the purchase contract component of the Equity Units.  This was classified as a special item in 2008, and as such only affected as-reported results.

(o) The variance in the year-to-date period was due primarily to lower intercompany interest charges which are eliminated in consolidation and have no effect on consolidated results.  The corresponding reduction in intercompany other income (deductions) at Utility, Parent & Other was offset by carrying charges on storm costs for hurricanes Gustav and Ike in Texas and Louisiana and a gain recorded on a land sale.

(p) The increase is due primarily to increased plant in service at the Utility.

Appendix B-3 lists special items by business with quarter-to-quarter and year-to-date 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 B-3:  Special Items (shown as positive / (negative) impact on earnings)
Fourth Quarter and Year-to-Date 2009 vs. 2008
(Per share in U.S. $)
	Fourth Quarter			Year-to-Date
	2009	2008	Change	2009	2008	Change
Utility, Parent & Other
Non-utility nuclear spin-off expenses	(0.05)	(0.10)	0.05	(0.14)	(0.28)	0.14
Dilution effect – unsuccessful remarketing	-	0.05	(0.05)	-	0.07	(0.07)
Total Utility, Parent & Other	(0.05)	(0.05)	-	(0.14)	(0.21)	0.07
Competitive Businesses
Entergy Nuclear
Non-utility nuclear spin-off dis-synergies	(0.06)	-	(0.06)	(0.23)	-	(0.23)
Dilution effect – unsuccessful remarketing	-	(0.04)	0.04	-	(0.10)	0.10
Non-Nuclear Wholesale Assets
Dilution effect – unsuccessful remarketing	-	(0.01)	0.01	-	-	-
Total Competitive Businesses	(0.06)	(0.05)	(0.01)	(0.23)	(0.10)	(0.13)
Total Special Items	(0.11)	(0.10)	(0.01)	(0.37)	(0.31)	(0.06)
(U.S. $ in millions)
	Fourth Quarter			Year-to-Date
	2009	2008	Change	2009	2008	Change
Utility, Parent & Other
Non-utility nuclear spin-off expenses	(9.1)	(20.0)	10.9	(27.0)	(55.4)	28.4
Dilution effect – unsuccessful remarketing	-	-	-	-	-	-
Total Utility, Parent & Other	(9.1)	(20.0)	10.9	(27.0)	(55.4)	28.4
Competitive Businesses
Entergy Nuclear
Non-utility nuclear spin-off dis-synergies	(12.0)	-	(12.0)	(44.0)	-	(44.0)
Dilution effect – unsuccessful remarketing	-	-	-	-	-	-
Non-Nuclear Wholesale Assets
Dilution effect – unsuccessful remarketing	-	-	-	-	-	-
Total Competitive Businesses	(12.0)	-	(12.0)	(44.0)	-	(44.0)
Total Special Items	(21.1)	(20.0)	(1.1)	(71.0)	(55.4)	(15.6)

C.   Regulatory Summary

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

Appendix C: 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	Recent activity:  Rate case discovery is ongoing as APSC Staff and Intervenors prepare to file direct testimony on February 26, 2010. 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 Formula Rate Plan (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 purchase or construction / acquisition of new transmission or generating facilities.  Finally, the proposed FRP includes an energy efficiency-related mechanism.  Hearings are scheduled to begin 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:  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 as EAI’s analysis demonstrates retail customers will benefit from lower costs using securitization.  EAI will remove the associated revenue requirement from its rate case should the APSC approve securitization. Background:  In January 2009, EAI was struck by a severe ice storm with the current restoration cost estimate approximating $123 million, including $11.7 million in carrying costs, at the lower end of the $120 to $140 million range.  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 is scheduled on 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.  The ice storm restoration costs would be removed from the cost-of-service in the pending rate case if the APSC approves EAI’s request to securitize the ice storm costs.  EAI is also seeking an increase in the annual storm damage accrual from $14.4 million to $22.3 million in its rate case.
	White Bluff Environmental Controls Project:  In December, the APSC suspended the procedural schedule following letters submitted by the United States Environmental Protection Agency (U.S. EPA) and the U.S. Department of Agriculture (U.S. DA) to the Arkansas Department of Environmental Quality (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.  On January 22, 2010, the Arkansas Pollution Control and Ecology (PC&E) Commission adopted a procedural schedule to conduct a public hearing in response to Sierra Club’s petition regarding the variance request with the expectation that the variance could be considered at the PC&E Commission’s March 26, 2010 meeting.  EAI will address cost recovery issues for limited spending to date in the early stages of the project at such time when there is more certainty regarding the project disposition. Background:  On March 27, 2009, EAI petitioned the APSC to undertake the Environmental Controls project that will install 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 are required to meet more stringent SO2 and NOx limits by 2013 in order to comply with the ADEQ State Implementation Plan regulations implementing the U.S. EPA’s Regional Haze Rule.  To continue operating, White Bluff must install pollution control technology.  EAI conducted economic analysis comparing the Environmental Controls project to other supply options for capacity and energy and concluded the project is the lowest reasonable cost alternative under a wide range of assumptions. EAI had intended to recover costs pursuant to Act 310 through an interim rate schedule to be amended approximately every six months to capture ongoing costs.  Act 310 permits utilities to recover costs associated with government-mandated expenditures and investments required for the protection of public health, safety and the environment through a surcharge outside the normal rate case process.  The interim surcharge was to be effective until implementation of new rate schedules in connection with the next general rate filing of a utility.  EAI and the White Bluff plant co-owners filed supplemental testimony in the proceeding in early July, with the co-owners generally indicating that the plant represents a reliable, low cost base load capacity resource even after considering the cost of installing scrubbers.  The procedural schedule called for hearings in March 2010, which will not occur due to the suspension of the procedural schedule.
Entergy Gulf States Louisiana Authorized ROE Range:  9.9% - 11.4% (electric) Last Filed Rate Base: $2.1 billion (electric) Filed 10/09 based on 12/31/08 test yr	Recent activity: In November 2009, EGSL made its $3.7 million refund and implemented its $44.3 million rate increase pursuant to the settlement approved by the LPSC in October.  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, 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. Background:  At its October 2009 Business and Executive Session, the LPSC approved an uncontested settlement resolving the 2007 test year FRP filing and 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 the one-time rate reset noted previously 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
Appendix C: Regulatory Summary Table (continued)
Company	Pending Cases / Events
Retail Regulation
Entergy Gulf States Louisiana (continued)	effect coincident with the November 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 a schedule to be set that provides for the LPSC to address this matter at its March 2010 Business and Executive session.  Finally, the settlement included a $3.7 million refund commencing with the November billing cycle for the 2007 test year FRP filing.
	Storm Cost Recovery:  On December 30, 2009, EGSL entered into a black box stipulation agreement with the LPSC Staff that, if approved, provides for total recoverable costs of nearly $234 million (greater than 98 percent of EGSL’s request) and permits replenishing EGSL’s storm reserve in the amount of $90 million when Act 55 securitization is accomplished.  Storm costs will be deemed prudent and recoverable and will not be tried (at least between the Staff and EGSL) at the hearings scheduled to take place in March 2010.  Intervenors are required to state their position regarding the stipulation by February 15, 2010. 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 securitization 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) securitization.  EGSL expects significant potential financing savings from pursuing Act 55 alternative securitization and plans to guarantee customer savings, consistent with results achieved from the same approach used for hurricanes Katrina and Rita recovery. The procedural schedule established concludes with hearings in March 2010.
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	Recent activity: In November 2009, ELL made its $12.9 million refund and implemented its $2.5 million rate increase pursuant to the settlement approved by the LPSC in October.  In addition, in December, 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. Background:  At its October 2009 Business and Executive Session, the LPSC approved an uncontested settlement resolving the 2006 and 2007 test year FRP filings and 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 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 ELL with a schedule to be set that provides for the LPSC to address this matter at its March 2010 Business and Executive session.  Finally, the settlement included a $12.9 million refund commencing with the November billing cycle for the 2006 and 2007 test year FRP filings.
	Storm Cost Recovery:  On December 30, 2009, ELL entered into a black box stipulation agreement with the LPSC Staff that, if approved, provides for total recoverable costs of approximately $394 million (greater than 98 percent of ELL’s request) and permits replenishing ELL’s storm reserve in the amount of $200 million when Act 55 securitization is accomplished.  Storm costs will be deemed prudent and recoverable and will not be tried (at least between the Staff and ELL) at the hearings scheduled to take place in March 2010.  Intervenors are required to state their position regarding the stipulation by February 15, 2010. 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 securitization 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) securitization.  ELL expects significant potential financing savings from pursuing Act 55 alternative securitization and plans to guarantee customer savings, consistent with results achieved from the same approach used for hurricanes Katrina and Rita recovery. The procedural schedule established concludes with hearings in March 2010.
	Acadia Unit 2 Acquisition:  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.  A procedural schedule is expected to be established by the LPSC on February 2, 2010. Background:  ELL signed a purchase and sale agreement to acquire the 580MW Unit 2 of the Acadia Energy Center for $300 million ($517/kW).  ELL proposes to acquire 100 percent of Acadia Unit 2 and a 50 percent 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 late 2010 or early 2011.  ELL has also entered into a power purchase agreement for 100 percent of the output of Acadia Unit that will commence on May 1, 2010 and is set to expire at the closing of the acquisition transaction.  A procedural schedule to approve the power purchase agreement provides for hearings in February if the approval is contested, and EGSL is seeking LPSC approval of this agreement in April.

Appendix C: Regulatory Summary Table (continued)
Company	Pending Cases/Events
Retail Regulation
Entergy Louisiana (continued)	Little Gypsy Repowering:  On October 27, 2009, ELL filed an application and testimony 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, 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.  Hearings are scheduled for October 2010. Background:  On November 8, 2007, the LPSC voted unanimously to approve ELL’s request to repower the 538 MW Little Gypsy unit to utilize CFB technology relying on a dual-fuel approach (petroleum coke and coal), an action that could reduce Louisiana customers’ dependence on natural gas.  The approval was subject to a number of conditions, including the development and approval of a construction monitoring plan.  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) as a result of a federal court decision in February 2008 unrelated to the project.  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 February 2009, the Louisiana Department of Environmental Quality issued the new air permit.  On March 11, 2009, the LPSC issued an order directing ELL to temporarily suspend the Little Gypsy Repowering 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.  This action was based upon a number of factors including the recent decline in natural gas prices, as well as environmental concerns, the unknown costs of carbon legislation and changes in the capital / financial markets.  On April 1, 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.  The filing indicated approximately $160 million of spending through February 28, 2009 and estimated approximately $300 million of total costs if the project is cancelled.  ELL had obtained all major environmental permits required to begin construction.  A longer-term delay places these permits at risk and may adversely affect the project’s economics and technological feasibility in the event the project is re-initiated.  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.  The quarterly monitoring plan was suspended indefinitely, with ELL instead working cooperatively with the LPSC Staff keeping them informed of activities associated with suspending the project and terminating current contracts related to the project.  On or before, December 15, 2011, ELL was required to report to the LPSC and its Staff whether or not it intends to re-initiate the project, including a detailed discussion of the basis for the decision.  ELL also dismissed its proceeding to recover cash earnings on Construction Work in Progress (CWIP) for the Little Gypsy project.
Entergy Mississippi Authorized ROE Range:  11.91% - 14.42% Last Filed Rate Base: $1.5 billion Filed 3/09 based on 12/31/08 test year	Recent activity:  EMI continues to pursue proposed modifications to its FRP.  The MPSC approved a similar plan for another Mississippi regulated electric utility company in fourth quarter 2009. Background:  EMI has been operating under a FRP last approved in December 2002.  The FRP allows the company’s earned ROE to increase or decrease within a bandwidth with no change in rates.  Earnings outside the bandwidth are allocated 50% to customers and 50% to the company, but on a prospective basis only.  The plan also provides 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.  As a result, EMI filed a voluntary motion to dismiss its Mississippi Supreme Court appeal of the 2007 FRP.  On September 18, 2009, EMI filed proposed modifications to its FRP rider.  EMI is proposing changes to better achieve the goal of an FRP by providing a reasonable opportunity to earn its allowed return.  The proposed modifications also more closely align EMI’s FRP with the FRPs of the other regulated gas and electric utilities in Mississippi, which would allow for a more uniform and streamlined review process.  Key changes include (1) resetting EMI’s return to the middle of the FRP bandwidth each year and eliminating the 50 / 50 sharing in the current plan, (2) replacing the current rate change limit of two percent of revenues subject to a $14.5 million revenue adjustment cap, with a proposed limit of four percent of revenues, (3) implementing a projected test year for the annual filing and subsequent look-back for the prior year, and (4) modifying the performance measurement process.
	Fuel Recovery/Attorney General Complaint:  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.  The financial portion of the fuel audit undertaken at the request of the MPSC performed by Horne Group LLP (Horne) 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. In November 2009, the MPSC also engaged another firm, McFadden Consulting Group, Inc., to review processes and practices related to fuel and purchased energy. 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 fuel adjustment clause 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.

Appendix C: Regulatory Summary Table (continued)
Company	Pending Cases/Events
Retail Regulation
Entergy Mississippi (continued)	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 fuel adjustment clause by an independent audit firm which was undertaken by Horne, as previously described.
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	Recent activity:  None. 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 City Council of New Orleans approved the Energy Smart Resolution.  Energy Smart is the energy efficiency program that was filed pursuant to ENOI’s April 2009 rate case settlement.
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:  In November, a procedural schedule was established in the Power Cost Recovery Factor (PCRF) proceeding with hearings scheduled for February.  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.  A prehearing conference is scheduled for February 3, 2010.  Entergy Texas is negotiating with parties to develop a procedural schedule that will provide a Commission decision before the end of 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 wholesale baseload (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 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.
	Storm Cost Recovery:  On November 6, 2009, ETI closed its securitization financing.  Entergy Texas Restoration Funding, LLC issued $545.9 million in securitization bonds; $540.6 million for system restoration costs, including adjusted carrying costs of $44.2 million, plus $5.3 million of up-front qualified costs.  Securitization proceeds were net of an estimated $70 million for projected insurance proceeds, subject to true-up, for which ETI received $75.5 million in the third quarter of 2009 following resolution of the Hurricane Ike claim. Background:  On April 16, 2009, Governor Perry signed Senate Bill (SB) 769 enacting evergreen securitization legislation for recovery of system restoration costs.  ETI initiated its storm recovery proceeding on April 21, 2009 seeking recovery of system restoration costs, and authorization to recover in a financing proceeding to be subsequently filed, carrying costs on the approved system restoration costs at ETI’s WACC.  ETI initiated its financing order request on July 16, 2009.  On August 5, 2009, ETI reached an unopposed “black box” settlement agreement in the storm cost recovery proceeding and later that month reached a unanimous settlement in its financing order docket, both of which were subsequently approved by the PUCT.

Appendix C: Regulatory Summary Table (continued)
Company/ Proceeding	Pending Cases/Events
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:  On November 19, 2009, FERC accepted notices of cancellation and determined EAI and EMI are permitted 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.  With the certainty provided by the FERC order, Entergy is again moving forward with further development of successor arrangements.  Efforts will be pursued in parallel with evaluation by the Entergy Regional State Committee (E-RSC) of the Southwest Power Pool Regional Transmission Organization (SPP RTO) and modified Independent Coordinator of Transmission (ICT) alternatives.  EAI also continues to evaluate systems, facilities and resources necessary to operate the generation fleet on a stand alone basis.  The LPSC and CCNO have requested rehearing of the FERC’s decision. On December 17, 2009, FERC set a paper hearing for the appropriateness of refunds resulting from changes in the treatment of interruptible load in the allocation of capacity costs by the Operating Companies.  FERC also deferred further action until resolution of the paper hearing on the question of whether it provided sufficient rationale for not ordering refunds, and whether it impermissibly delayed implementation of the bandwidth remedy. On January 11, 2010, FERC issued its decision in the first bandwidth proceeding, both affirming and overturning certain ALJ rulings.  FERC’s conclusion related to a 1999 wholesale contract with AmerenUE did not permit EAI to recover a portion of its bandwidth payment from AmerenUE, resulting in EAI recording a regulatory charge during fourth quarter 2009.  The Operating Companies continue to review the decision and expect to file a request for rehearing / clarification on certain issues.  On that date, FERC also issued a decision affirming the ALJ’s ruling that certain revisions to the bandwidth formula proposed by ESI on behalf of the Operating Companies in March of 2007 were just and reasonable. Background:  The System Agreement case addresses the allocation of production costs among the utility Operating Companies.  In June 2005, the FERC issued its decision and established a bandwidth of +/- 11% to reallocate production costs and ordered that this approach be applied prospectively.  In December 2005, FERC established, among other things, that 1) the bandwidth would be applied to calendar year 2006 actual production costs and 2) 2007 would be the first possible year of payments among Entergy’s Operating Companies.  The orders were appealed and 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.  Oral arguments were held on May 8, 2009 on the LPSC’s DC Circuit appeal of FERC Orders approving the Operating Companies compliance filing implementing the bandwidth remedy.  On July 6, 2009, the DC Circuit denied the LPSC’s appeal. The Entergy Operating Companies submitted bandwidth filings for the calendar years 2006 through 2008 production costs.  The calendar year 2008 filing indicates a payment from EAI in the amount of $390 million collectively to EGSL, ETI, ELL and EMI.  On September 23, 2008, the ALJ issued a decision regarding the initial bandwidth proceeding related to calendar year 2006 production costs, that concluded that, with one exception, the Operating Company calculation was appropriate and that the Operating Companies' production costs were prudently incurred. The one exception would require the Operating Companies to calculate nuclear depreciation / decommissioning for each facility based on the NRC license life.  On September 19, 2008, FERC also issued an order on rehearing in the proceeding involving the exclusion of interruptible loads from certain System Agreement calculations that concluded that FERC had authority to order refunds and that refunds were appropriate.  The APSC and the Operating Companies appealed the FERC's orders to the DC Circuit. On September 10, 2009, the ALJ issued its initial decision regarding the 2007 production cost bandwidth filing that concluded, with two exceptions, the Operating Company calculation was appropriate and the production costs were prudently incurred.  The two exceptions related to depreciation expense for which new studies are needed and accumulated deferred income tax related to the Waterford 3 sale-leaseback that should not have been excluded from the bandwidth calculation.  Parties have since filed briefs on exceptions to the ALJ decision with the FERC.  In addition, the FERC set the 2008 production cost bandwidth filing for hearing in April 2010. 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 in December 2005 and November 2007, respectively, and on February 2, 2009 filed with the FERC their notices of cancellation of their respective System Agreement rate schedules, effective December 2013 and November 2015, respectively.  EAI and EMI requested FERC issue a decision on the notices of cancellation.  The Operating Companies are considering a Successor Arrangement for the System Agreement.  Further progress on a proposed framework for a Successor Arrangement to the System Agreement could be stalled until FERC resolves EAI’s and EMI’s notices of cancellation filing made February 2, 2009.  Given EAI must take action well before its termination date to prepare to act as a stand-alone utility in the event successor arrangements are not implemented, EAI reported the results of a related study to the APSC in September 2009.  Total estimated cost to establish the systems and staff the organizations to perform the necessary functions for a stand-alone EAI operation are estimated at approximately $23 million, including $18 million to establish generation-related functionality and $5 million to modify the transmission system.  Incremental costs for ongoing staffing and systems costs are estimated at approximately $8 million.  Cost and implementation schedule estimates will continue to be re-evaluated and refined as additional, more detailed analysis is completed.  EAI expects it will take approximately two years to implement stand-alone operations for EAI.

Appendix C: Regulatory Summary Table (continued)
Company/ Proceeding	Pending Cases/Events
Wholesale Regulation
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:  Representatives from all of the Entergy Operating Company retail regulators formed the E-RSC to consider several of the issues related to the Entergy transmission system and conducted a preliminary meeting on October 12, 2009.  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 newly formed E-RSC.  The Utility Operating Companies expect that the E-RSC will rely heavily on the cost-benefit analysis that is being jointly sponsored by the E-RSC and FERC that will compare the current ICT arrangement to joining SPP.  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 propose modifications to the cost allocation policy for transmission upgrades and the ability to add projects to the Operating Companies’ transmission construction plan.  Given the timing required to complete this work, an extension of the ICT for some period will likely be required under either scenario being considered.  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. 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 ICT 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 including a determination on whether costs of transmission upgrades should be rolled into transmission rates or directly assigned to customers requesting or causing the upgrade, serving as reliability coordinator the transmission system and overseeing the WPP.

(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.

D.   Financial Performance Measures and Historical Performance Measures

Appendix D-1 provides comparative financial performance measures for the current quarter.  Appendix D-2 provides historical financial performance measures and operating performance metrics for the trailing eight quarters. Financial performance measures in both tables include those calculated and presented in accordance with 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 G.

Appendix D-1:  GAAP and Non-GAAP Financial Performance Measures
Fourth Quarter 2009 vs. 2008 (see Appendix F for definitions of certain measures)
For 12 months ending December 31	2009	2008	Change
GAAP Measures
Return on average invested capital – as-reported	7.7%	8.1%	(0.4)%
Return on average common equity – as-reported	14.9%	15.4%	(0.5)%
Net margin – as-reported	11.5%	9.3%	2.2%
Cash flow interest coverage	6.1	6.5	(0.4)
Book value per share	$45.54	$42.07	$3.47
End of period shares outstanding (millions)	189.1	189.4	(0.3)
Non-GAAP Measures
Return on average invested capital – operational	8.1%	8.4%	(0.3)%
Return on average common equity – operational	15.7%	16.1%	(0.4)%
Net margin – operational	12.1%	9.7%	2.4%
As of December 31 ($ in millions)	2009	2008	Change
GAAP Measures
Cash and cash equivalents	1,710	1,920	(210)
Revolver capacity	1,464	645	819
Total debt	12,014	12,279	(265)
Debt to capital ratio	57.4%	59.7%	(2.3)%
Off-balance sheet liabilities:
Debt of joint ventures  – Entergy’s share	116	125	(9)
Leases – Entergy’s share	530	449	81
Total off-balance sheet liabilities	646	574	72
Non-GAAP Measures
Total gross liquidity	3,174	2,565	609
Net debt to net capital ratio	53.6%	55.6%	(2.0)%
Net debt ratio including off-balance sheet liabilities	55.1%	56.9%	(1.8)%

Appendix D-2: Historical Performance Measures (see Appendix F for definitions of measures)
			1Q08	2Q08	3Q08	4Q08		1Q09		2Q09		3Q09	4Q09	08YTD	09YTD
Financial
		EPS – as-reported ($)	1.56	1.37	2.41		0.89		1.20	1.14	2.32		1.64	6.20	6.30
		Less – special items ($)	0.00	(0.09)	(0.09)		(0.10)		(0.09)	(0.09)	(0.08)		(0.11)	(0.31)	(0.37)
		EPS – operational ($)	1.56	1.46	2.50		0.99		1.29	1.23	2.40		1.75	6.51	6.67
	Trailing Twelve Months
		ROIC – as-reported (%)	8.8	8.6	8.1		8.1		7.6	7.5	7.1		7.7
		ROIC – operational (%)	9.0	8.8	8.4		8.4		8.0	7.8	7.5		8.1
		ROE – as-reported (%)	15.9	16.3	15.6		15.4		14.1	13.7	13.2		14.9
		ROE – operational (%)	16.3	17.0	16.4		16.1		15.0	14.6	14.1		15.7
		Cash flow interest coverage	4.9	5.0	7.0		6.5		6.5	6.7	5.5		6.1
		Debt to capital ratio (%)	58.6	60.7	60.4		59.7		57.4	55.9	56.7		57.4
		Net debt/net capital ratio (%)	56.5	58.3	54.9		55.6		53.4	53.0	54.2		53.6
Utility
		GWh billed
		Residential	8,011	7,372	10,671		6,992		7,893	7,100	11,213		7,421	33,047	33,626
		Commercial & Gov’t	6,807	7,275	8,646		6,992		6,756	7,095	8,794		7,240	29,719	29,884
		Industrial	9,377	9,730	10,110		8,626		8,139	8,790	9,473		9,235	37,843	35,638
		Wholesale	1,290	1,440	1,431		1,240		1,387	1,313	1,164		998	5,401	4,862
		O&M expense/MWh	$17.26	$19.48	$14.43		$23.95		$18.51	$20.96	$15.77		$20.18	$18.48	$18.67
		Reliability
		SAIFI	1.9	1.9	1.9		1.9		1.8	1.7	1.7		1.8	1.9	1.8
		SAIDI	191	215	227		216		208	194	203		210	216	210
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	$61.47	$58.22	$61.59		$56.69		$63.84	$59.22	$61.70		$59.43	$59.51	$61.07
		Production cost/MWh (s)	$19.98	$23.11	$21.77		$22.77		$23.14	$24.30	$22.57		$23.20	$21.88	$23.26
		Non-fuel O&M expense/ purchased power per MWh (s)	$20.20	$23.42	$21.19		$23.06		$22.44	$25.33	$22.11		$23.60	$21.95	$23.30
		GWh billed	10,760	10,145	10,316		10,489		10,074	8,980	10,876		11,052	41,710	40,981
		Capacity factor (%)	97	92	95		94		92	81	100		99	95	93

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

E.   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 E.  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 could ultimately be delayed pending the outcome of the variance request from the October 2013 compliance date as discussed more fully in Appendix E.

·   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 E:  2010 – 2012 Planned Capital Expenditures
($ in millions) – Prepared February 2010
	2010	2011	2012	Total
Maintenance capital
Utility, 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, 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

F.   Definitions

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

Appendix F:  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 PPA 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 Power Purchase Agreement
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 F:  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 Non-Nuclear Wholesale Assets business joint ventures
Leases (Entergy’s share)	Operating leases held by subsidiaries capitalized at implicit interest rate
Debt to capital	Gross debt divided by total capitalization
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
Net debt to net capital	Gross debt less cash and cash equivalents divided by total capitalization less cash and cash equivalents
Net debt including off-balance sheet liabilities	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

G.   GAAP to Non-GAAP Reconciliations

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

Appendix G-1: Reconciliation of GAAP to Non-GAAP Financial Measures – Return on Equity, Return on Invested Capital and Net Margin Metrics
($ in millions)
	1Q08	2Q08	3Q08	4Q08	1Q09	2Q09	3Q09	4Q09
As-reported Net Income-rolling 12 months (A)	1,231	1,235	1,244	1,221	1,147	1,103	1,088	1,231
Preferred dividends	24	23	21	20	20	20	20	20
Tax effected interest expense	396	390	375	374	366	368	361	351
As-reported Net Income, rolling 12 months including preferred dividends and tax effected interest expense (B)	1,651	1,648	1,640	1,615	1,533	1,491	1,469	1,602
Special items in prior quarters	(32)	(32)	(50)	(35)	(55)	(54)	(54)	(49)
Special items in current quarter
Nuclear spin-off costs		(18)	(17)	(20)	(17)	(17)	(15)	(21)
Total special items (C)	(32)	(50)	(67)	(55)	(72)	(71)	(69)	(71)
Operational earnings, rolling 12 months including preferred dividends and tax effected interest expense (B-C)	1,683	1,698	1,707	1,670	1,605	1,562	1,538	1,673
Operational earnings, rolling 12 months (A-C)	1,263	1,285	1,311	1,276	1,219	1,174	1,157	1,302
Average invested capital (D)	18,790	19,244	20,236	19,927	20,126	19,995	20,629	20,748
Average common equity (E)	7,756	7,555	7,973	7,915	8,152	8,045	8,230	8,290
Operating revenues (F)	11,655	12,150	12,825	13,094	13,018	12,275	11,248	10,746
ROIC – as-reported % (B/D)	8.8	8.6	8.1	8.1	7.6	7.5	7.1	7.7
ROIC – operational % ((B-C)/D)	9.0	8.8	8.4	8.4	8.0	7.8	7.5	8.1
ROE – as-reported % (A/E)	15.9	16.3	15.6	15.4	14.1	13.7	13.2	14.9
ROE – operational % ((A-C)/E)	16.3	17.0	16.4	16.1	15.0	14.6	14.1	15.7
Net margin – as-reported % (A/F)	10.6	10.2	9.7	9.3	8.8	9.0	9.7	11.5
Net margin – operational % ((A-C)/F)	10.8	10.6	10.2	9.7	9.4	9.6	10.3	12.1

Appendix G-2: Reconciliation of GAAP to Non-GAAP Financial Measures – Credit and Liquidity Metrics
($ in millions)
	1Q08	2Q08	3Q08	4Q08	1Q09	2Q09	3Q09	4Q09
Gross debt (A)	11,292	11,768	12,656	12,279	12,034	11,510	11,522	12,014
Less cash and cash equivalents (B)	916	1,086	2,556	1,920	1,803	1,281	1,131	1,710
Net debt (C)	10,376	10,682	10,100	10,359	10,231	10,229	10,391	10,304
Total capitalization (D)	19,276	19,401	20,944	20,557	20,975	20,588	20,315	20,939
Less cash and cash equivalents (B)	916	1,086	2,556	1,920	1,803	1,281	1,131	1,710
Net capital (E)	18,360	18,315	18,388	18,637	19,172	19,307	19,184	19,229
Debt to capital ratio % (A/D)	58.6	60.7	60.4	59.7	57.4	55.9	56.7	57.4
Net debt to net capital ratio % (C/E)	56.5	58.3	54.9	55.6	53.4	53.0	54.2	53.6
Off-balance sheet liabilities (F)	642	638	637	574	573	569	567	646
Net debt to net capital ratio including off-balance sheet liabilities % ((C+F)/(E+F))	58.0	59.7	56.4	56.9	54.7	54.3	55.5	55.1
Revolver capacity (G)	1,503	826	374	645	725	1,585	1,647	1,464
Gross liquidity (B+G)	2,419	1,912	2,930	2,565	2,528	2,866	2,778	3,174

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

**********************************************************************************************************************

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 (i) Entergy’s Form 10-K for the year ended December 31, 2008, (ii) Entergy’s Form 10-Q for the quarters ended March 31, June 30 and September 30, 2009, and (iii) Entergy’s other reports and filings made under the Securities Exchange Act of 1934, (b) the uncertainties associated with efforts to remediate the effects of Hurricanes Gustav and Ike and the January 2009 Arkansas ice storm and recovery of costs associated with restoration, and (c) the following transactional factors (in addition to others described elsewhere in this news release and in subsequent securities filings): (i) risks inherent in the contemplated spin-off, joint venture and related transactions (including the level of debt to be incurred by Enexus Energy Corporation and the terms and costs related thereto), (ii) legislative and regulatory actions, and (iii) conditions of the capital markets during the periods covered by the forward-looking statements.  Entergy cannot provide any assurances that the spin-off or any of the proposed transactions related thereto will be completed, nor can it give assurances as to the terms on which such transactions will be consummated.  The transaction is subject to certain conditions precedent, including regulatory approvals and the final approval by the Board of Directors of Entergy.

VI.   Financial Statements

Entergy Corporation
Consolidating Balance Sheet
December 31, 2009
(Dollars in thousands)
(Unaudited)
	U.S. Utilities/ Parent & Other			Competitive Businesses			Eliminations			Consolidated
ASSETS
CURRENT ASSETS
Cash and cash equivalents:
Cash	$	82,155		$	3,706		$	-		$	85,861
Temporary cash investments		1,208,025			415,665			-			1,623,690
Total cash and cash equivalents		1,290,180			419,371			-			1,709,551
Securitization recovery trust account		13,098			-			-			13,098
Notes receivable		203,916			1,760,420			(1,964,336	)		-
Accounts receivable:
Customer		331,936			221,756			-			553,692
Allowance for doubtful accounts		(27,428	)		(203	)		-			(27,631	)
Associated companies		25,381			117,483			(142,864	)		-
Other		137,968			14,335			-			152,303
Accrued unbilled revenues		302,463			-			-			302,463
Total accounts receivable		770,320			353,371			(142,864	)		980,827
Deferred fuel costs		126,798			-			-			126,798
Accumulated deferred income taxes		-			-			-			-
Fuel inventory - at average cost		194,827			2,028			-			196,855
Materials and supplies - at average cost		526,543			299,159			-			825,702
Deferred nuclear refueling outage costs		106,428			118,862			-			225,290
System agreement cost equalization		70,000			-			-			70,000
Prepayments and other		79,084			417,960			(111,004	)		386,040
TOTAL		3,381,194			3,371,171			(2,218,204	)		4,534,161
OTHER PROPERTY AND INVESTMENTS
Investment in affiliates - at equity		6,871,604			1,042,565			(7,874,589	)		39,580
Decommissioning trust funds		1,325,863			1,885,320			-			3,211,183
Non-utility property - at cost (less accumulated depreciation)		239,956			7,708			-			247,664
Other		110,645			9,628			-			120,273
TOTAL		8,548,068			2,945,221			(7,874,589	)		3,618,700
PROPERTY, PLANT, AND EQUIPMENT
Electric		32,446,351			3,897,421			-			36,343,772
Property under capital lease		783,096			-			-			783,096
Natural gas		314,256			-			-			314,256
Construction work in progress		1,133,823			413,496			-			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		35,424,364			4,831,427			-			40,255,791
Less - accumulated depreciation and amortization		16,159,041			707,348			-			16,866,389
PROPERTY, PLANT AND EQUIPMENT - NET		19,265,323			4,124,079			-			23,389,402
DEFERRED DEBITS AND OTHER ASSETS
Regulatory assets:
SFAS 109 regulatory asset - 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
Other		649,258			873,457			(516,409	)		1,006,306
TOTAL		5,462,213			876,530			(516,409	)		5,822,334
					-
TOTAL ASSETS	$	36,656,798		$	11,317,001		$	(10,609,202	)	$	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/ Parent & Other			Competitive Businesses			Eliminations			Consolidated
LIABILITIES AND SHAREHOLDERS' EQUITY
CURRENT LIABILITIES
Currently maturing long-term debt	$	681,016		$	30,941		$	-		$	711,957
Notes payable:
Associated companies		1,964,336			-			(1,964,336	)		-
Other		30,031			-			-			30,031
Account payable:
Associated companies		130,229			10,612			(140,841	)		-
Other		753,362			244,866			-			998,228
Customer deposits		323,092			250			-			323,342
Taxes accrued		107,944			-			(107,944	)		-
Accumulated deferred income taxes		48,584			-			-			48,584
Interest accrued		191,375			908			-			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		54,279			163,983			(3,060	)		215,202
TOTAL		4,953,499			456,679			(2,216,181	)		3,193,997
NON-CURRENT LIABILITIES
Accumulated deferred income taxes and taxes accrued		4,609,839			2,812,480			-			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		1,618,845			1,320,694			-			2,939,539
Accumulated provisions		132,225			9,090			-			141,315
Pension and other postretirement liabilities		1,771,350			469,689			-			2,241,039
Long-term debt		10,549,181			156,557			-			10,705,738
Other		451,438			786,443			(526,547	)		711,334
TOTAL		20,217,491			5,554,953			(526,547	)		25,245,897
Subsidiaries' preferred stock without sinking fund		186,510			82,953			(52,120	)		217,343
EQUITY
Common Shareholders' Equity:
Common stock, $.01 par value, authorized 500,000,000 shares;
issued 254,752,788 shares in 2009		2,163,815			982,040			(3,143,307	)		2,548
Paid-in capital		8,915,541			1,882,103			(5,427,602	)		5,370,042
Retained earnings		5,103,166			2,316,101			623,855			8,043,122
Accumulated other comprehensive income (loss)		(130,057	)		54,872			-			(75,185	)
Less - treasury stock, at cost (65,634,580 shares in 2009)		4,847,167			12,700			(132,700	)		4,727,167
Total common shareholders' equity		11,205,298			5,222,416			(7,814,354	)		8,613,360
Subsidiaries' preferred stock without sinking fund		94,000			-			-			94,000
TOTAL		11,299,298			5,222,416			(7,814,354	)		8,707,360
TOTAL LIABILITIES AND EQUITY	$	36,656,798		$	11,317,001		$	(10,609,202	)	$	37,364,597
*Totals may not foot due to rounding.

Entergy Corporation
Consolidating Balance Sheet
December 31, 2008
(Dollars in thousands)
(Unaudited)
	U.S. Utilities/ Parent & Other			Competitive Businesses			Eliminations			Consolidated
ASSETS
CURRENT ASSETS
Cash and cash equivalents:
Cash	$	110,203		$	5,673		$	-		$	115,876
Temporary cash investments		1,355,498			449,117			-			1,804,615
Total cash and cash equivalents		1,465,701			454,790			-			1,920,491
Securitization recovery trust account		12,062			-			-			12,062
Notes receivable		99,330			1,333,123			(1,432,453	)		-
Accounts receivable:
Customer		523,348			210,856			-			734,204
Allowance for doubtful accounts		(25,610	)		-			-			(25,610	)
Associated companies		139,912			84,341			(224,253	)		-
Other		179,207			27,420			-			206,627
Accrued unbilled revenues		282,914			-			-			282,914
Total accounts receivable		1,099,771			322,617			(224,253	)		1,198,135
Deferred fuel costs		167,092			-			-			167,092
Accumulated deferred income taxes		7,307			-			-			7,307
Fuel inventory - at average cost		213,313			2,832			-			216,145
Materials and supplies - at average cost		505,720			270,450			-			776,170
Deferred nuclear refueling outage costs		106,514			115,289			-			221,803
System agreement cost equalization		394,000			-			-			394,000
Prepayments and other		106,044			144,200			(3,060	)		247,184
TOTAL		4,176,854			2,643,301			(1,659,766	)		5,160,389
OTHER PROPERTY AND INVESTMENTS
Investment in affiliates - at equity		7,354,792			(296,465	)		(6,992,080	)		66,247
Decommissioning trust funds		1,143,391			1,688,852			-			2,832,243
Non-utility property - at cost (less accumulated depreciation)		226,333			4,782			-			231,115
Other		103,308			10,019			(5,388	)		107,939
TOTAL		8,827,824			1,407,188			(6,997,468	)		3,237,544
PROPERTY, PLANT, AND EQUIPMENT
Electric		30,878,491			3,616,915			-			34,495,406
Property under capital lease		745,504			-			-			745,504
Natural gas		303,769			-			-			303,769
Construction work in progress		1,458,181			254,580			-			1,712,761
Nuclear fuel under capital lease		465,374			-			-			465,374
Nuclear fuel		130,675			506,138			-			636,813
TOTAL PROPERTY, PLANT AND EQUIPMENT		33,981,994			4,377,633			-			38,359,627
Less - accumulated depreciation and amortization		15,365,659			564,854			-			15,930,513
PROPERTY, PLANT AND EQUIPMENT - NET		18,616,335			3,812,779			-			22,429,114
DEFERRED DEBITS AND OTHER ASSETS
Regulatory assets:
SFAS 109 regulatory asset - net		581,719			-			-			581,719
Other regulatory assets		3,615,104			-			-			3,615,104
Deferred fuel costs		168,122			-			-			168,122
Goodwill		374,099			3,073			-			377,172
Other		744,499			868,454			(565,299	)		1,047,654
TOTAL		5,483,543			871,527			(565,299	)		5,789,771
					-
TOTAL ASSETS	$	37,104,556		$	8,734,795		$	(9,222,533	)	$	36,616,818
*Totals may not foot due to rounding.
Entergy Corporation
Consolidating Balance Sheet
December 31, 2008
(Dollars in thousands)
(Unaudited)
	U.S. Utilities/ Parent & Other			Competitive Businesses			Eliminations			Consolidated
LIABILITIES AND SHAREHOLDERS' EQUITY
CURRENT LIABILITIES
Currently maturing long-term debt	$	514,911		$	29,549		$	-		$	544,460
Notes payable:
Associated companies		1,341,198			91,255			(1,432,453	)		-
Other		55,034			-			-			55,034
Account payable:
Associated companies		97,530			126,413			(223,943	)		-
Other		1,222,415			253,330			-			1,475,745
Customer deposits		302,303			-			-			302,303
Taxes accrued		175,920			(100,710	)		-			75,210
Accumulated deferred income taxes		-			-			-			-
Interest accrued		185,778			1,532			-			187,310
Deferred fuel costs		183,539			-			-			183,539
Obligations under capital leases		162,393			-			-			162,393
Pension and other postretirement liabilities		41,653			4,635			-			46,288
System agreement cost equalization		460,315			-			-			460,315
Other		146,808			129,549			(3,060	)		273,297
TOTAL		4,889,797			535,553			(1,659,456	)		3,765,894
NON-CURRENT LIABILITIES
Accumulated deferred income taxes and taxes accrued		5,718,488			847,282			-			6,565,770
Accumulated deferred investment tax credits		325,570			-			-			325,570
Obligations under capital leases		343,093			-			-			343,093
Other regulatory liabilities		280,643			-			-			280,643
Decommissioning and retirement cost liabilities		1,447,659			1,229,836			-			2,677,495
Accumulated provisions		136,449			11,003			-			147,452
Pension and other postretirement liabilities		1,731,824			446,169			-			2,177,993
Long-term debt		10,991,204			188,473			(5,388	)		11,174,289
Other		735,252			720,223			(574,477	)		880,998
TOTAL		21,710,182			3,442,986			(579,865	)		24,573,303
Subsidiaries' preferred stock without sinking fund		186,511			82,280			(51,762	)		217,029
EQUITY
Common Shareholders' Equity:
Common stock, $.01 par value, authorized 500,000,000 shares;
issued 248,174,087 shares in 2008		2,163,749			911,494			(3,072,761	)		2,482
Paid-in capital		6,979,623			2,138,165			(4,248,485	)		4,869,303
Retained earnings		5,494,812			1,631,437			256,470			7,382,719
Accumulated other comprehensive income (loss)		(118,904	)		5,580			626			(112,698	)
Less - treasury stock, at cost (58,815,518 shares in 2008)		4,295,214			12,700			(132,700	)		4,175,214
Total common shareholders' equity		10,224,066			4,673,976			(6,931,450	)		7,966,592
Subsidiaries' preferred stock without sinking fund		94,000			-			-			94,000
TOTAL		10,318,066			4,673,976			(6,931,450	)		8,060,592
TOTAL LIABILITIES AND EQUITY	$	37,104,556		$	8,734,795		$	(9,222,533	)	$	36,616,818
*Totals may not foot due to rounding.

Entergy Corporation
Consolidating Balance Sheet
December 31, 2009 vs December 31, 2008
(Dollars in thousands)
(Unaudited)
	U.S. Utilities/ Parent & Other			Competitive Businesses			Eliminations			Consolidated
ASSETS
CURRENT ASSETS
Cash and cash equivalents:
Cash	$	(28,048	)	$	(1,967	)	$	-		$	(30,015	)
Temporary cash investments		(147,473	)		(33,452	)		-			(180,925	)
Total cash and cash equivalents		(175,521	)		(35,419	)		-			(210,940	)
Securitization recovery trust account		1,036			-			-			1,036
Notes receivable		104,586			427,297			(531,883	)		-
Accounts receivable:
Customer		(191,412	)		10,900			-			(180,512	)
Allowance for doubtful accounts		(1,818	)		(203	)		-			(2,021	)
Associated companies		(114,531	)		33,142			81,389			-
Other		(41,239	)		(13,085	)		-			(54,324	)
Accrued unbilled revenues		19,549			-			-			19,549
Total accounts receivable		(329,451	)		30,754			81,389			(217,308	)
Deferred fuel costs		(40,294	)		-			-			(40,294	)
Accumulated deferred income taxes		(7,307	)		-			-			(7,307	)
Fuel inventory - at average cost		(18,486	)		(804	)		-			(19,290	)
Materials and supplies - at average cost		20,823			28,709			-			49,532
Deferred nuclear refueling outage costs		(86	)		3,573			-			3,487
System agreement cost equalization		(324,000	)		-			-			(324,000	)
Prepayments and other		(26,960	)		273,760			(107,944	)		138,856
TOTAL		(795,660	)		727,870			(558,438	)		(626,228	)
OTHER PROPERTY AND INVESTMENTS
Investment in affiliates - at equity		(483,188	)		1,339,030			(882,509	)		(26,667	)
Decommissioning trust funds		182,472			196,468			-			378,940
Non-utility property - at cost (less accumulated depreciation)		13,623			2,926			-			16,549
Other		7,337			(391	)		5,388			12,334
TOTAL		(279,756	)		1,538,033			(877,121	)		381,156
PROPERTY, PLANT, AND EQUIPMENT
Electric		1,567,860			280,506			-			1,848,366
Property under capital lease		37,592			-			-			37,592
Natural gas		10,487			-			-			10,487
Construction work in progress		(324,358	)		158,916			-			(165,442	)
Nuclear fuel under capital lease		62,147			-			-			62,147
Nuclear fuel		88,642			14,372			-			103,014
TOTAL PROPERTY, PLANT AND EQUIPMENT		1,442,370			453,794			-			1,896,164
Less - accumulated depreciation and amortization		793,382			142,494			-			935,876
PROPERTY, PLANT AND EQUIPMENT - NET		648,988			311,300			-			960,288
DEFERRED DEBITS AND OTHER ASSETS
Regulatory assets:
SFAS 109 regulatory asset - net		37,781			-			-			37,781
Other regulatory assets		32,050			-			-			32,050
Deferred fuel costs		4,080			-			-			4,080
Goodwill		-			-			-			-
Other		(95,241	)		5,003			48,890			(41,348	)
TOTAL		(21,330	)		5,003			48,890			32,563
TOTAL ASSETS	$	(447,758	)	$	2,582,206		$	(1,386,669	)	$	747,779
*Totals may not foot due to rounding.
Entergy Corporation
Consolidating Balance Sheet
December 31, 2009 vs December 31, 2008
(Dollars in thousands)
(Unaudited)
	U.S. Utilities/ Parent & Other			Competitive Businesses			Eliminations			Consolidated
LIABILITIES AND SHAREHOLDERS' EQUITY
CURRENT LIABILITIES
Currently maturing long-term debt	$	166,105		$	1,392		$	-		$	167,497
Notes payable:
Associated companies		623,138			(91,255	)		(531,883	)		-
Other		(25,003	)		-			-			(25,003	)
Account payable:
Associated companies		32,699			(115,801	)		83,102			-
Other		(469,053	)		(8,464	)		-			(477,517	)
Customer deposits		20,789			250			-			21,039
Taxes accrued		(67,976	)		100,710			(107,944	)		(75,210	)
Accumulated deferred income taxes		48,584			-			-			48,584
Interest accrued		5,597			(624	)		-			4,973
Deferred fuel costs		36,100			-			-			36,100
Obligations under capital leases		50,103			-			-			50,103
Pension and other postretirement liabilities		8,259			484			-			8,743
System agreement cost equalization		(273,111	)		-			-			(273,111	)
Other		(92,529	)		34,434			-			(58,095	)
TOTAL		63,702			(78,874	)		(556,725	)		(571,897	)
NON-CURRENT LIABILITIES
Accumulated deferred income taxes and taxes accrued		(1,108,649	)		1,965,198			-			856,549
Accumulated deferred investment tax credits		(17,175	)		-			-			(17,175	)
Obligations under capital leases		11,140			-			-			11,140
Other regulatory liabilities		141,342			-			-			141,342
Decommissioning and retirement cost liabilities		171,186			90,858			-			262,044
Accumulated provisions		(4,224	)		(1,913	)		-			(6,137	)
Pension and other postretirement liabilities		39,526			23,520			-			63,046
Long-term debt		(442,023	)		(31,916	)		5,388			(468,551	)
Other		(283,814	)		66,220			47,930			(169,664	)
TOTAL		(1,492,691	)		2,111,967			53,318			672,594
Subsidiaries' preferred stock without sinking fund		(1	)		673			(358	)		314
EQUITY
Common Shareholders' Equity:
Common stock, $.01 par value, authorized 500,000,000 shares;
issued 254,772,087 shares in 2009 and 248,174,087 shares in 2008		66			70,546			(70,546	)		66
Paid-in capital		1,935,918			(256,062	)		(1,179,117	)		500,739
Retained earnings		(391,646	)		684,664			367,385			660,403
Accumulated other comprehensive income (loss)		(11,153	)		49,292			(626	)		37,513
Less - treasury stock, at cost		551,953			-			-			551,953
Total common shareholders' equity		981,232			548,440			(882,904	)		646,768
Subsidiaries' preferred stock without sinking fund		-			-			-			-
TOTAL		981,232			548,440			(882,904	)		646,768
TOTAL LIABILITIES AND EQUITY	$	(447,758	)	$	2,582,206		$	(1,386,669	)	$	747,779
*Totals may not foot due to rounding.

Entergy Corporation
Consolidating Income Statement
Three Months Ended December 31, 2009
(Dollars in thousands)
(Unaudited)
	U.S. Utilities/ Parent & Other			Competitive Businesses			Eliminations			Consolidated
OPERATING REVENUES
Electric	$	1,739,732		$	-		$	(539	)	$	1,739,193
Natural gas		45,298			-			-			45,298
Competitive businesses		7,088			712,442			(5,368	)		714,163
Total		1,792,118			712,442			(5,907	)		2,498,654
OPERATING EXPENSES
Operating and Maintenance:
Fuel, fuel related expenses, and gas purchased for resale		305,730			77,662			(1,253	)		382,139
Purchased power		353,774			11,543			(4,596	)		360,721
Nuclear refueling outage expenses		27,654			35,202			-			62,856
Other operation and maintenance		471,376			258,144			(172	)		729,348
Decommissioning		25,272			25,672			-			50,945
Taxes other than income taxes		93,750			24,461			-			118,211
Depreciation and amortization		244,970			38,623			-			283,592
Other regulatory charges (credits) - net		7,643			-			-			7,643
Total		1,530,169			471,307			(6,021	)		1,995,455
OPERATING INCOME		261,949			241,135			114			503,199
OTHER INCOME (DEDUCTIONS)
Allowance for equity funds used during construction		12,046			-			-			12,046
Interest and dividend income		26,176			70,334			(29,859	)		66,651
Other than temporary impairment losses		-			(703	)		-			(703	)
Equity in earnings (loss) of unconsolidated equity affiliates		(3,433	)		(3,916	)		-			(7,350	)
Miscellaneous - net		(6,843	)		(5,176	)		(114	)		(12,133	)
Total		27,946			60,539			(29,973	)		58,511
INTEREST AND OTHER CHARGES
Interest on long-term debt		134,835			2,627			-			137,462
Other interest - net		35,868			7,548			(29,859	)		13,557
Allowance for borrowed funds used during construction		(6,688	)		-			-			(6,688	)
Total		164,015			10,175			(29,859	)		144,331
INCOME BEFORE INCOME TAXES		125,880			291,499			-			417,379
Income taxes		14,502			84,137			-			98,639
CONSOLIDATED NET INCOME		111,378			207,362			-			318,740
Preferred dividend requirements of subsidiaries		4,332			633			-			4,965
NET INCOME ATTRIBUTABLE TO ENTERGY CORPORATION	$	107,046		$	206,729		$	-		$	313,775
EARNINGS PER AVERAGE COMMON SHARE:
BASIC	$	0.57		$	1.09					$	1.66
DILUTED	$	0.56		$	1.08					$	1.64
AVERAGE NUMBER OF COMMON SHARES OUTSTANDING:
BASIC											188,996,969
DILUTED											191,255,405
*Totals may not foot due to rounding.

Entergy Corporation
Consolidating Income Statement
Three Months Ended December 31, 2008
(Dollars in thousands)
(Unaudited)
	U.S. Utilities/ Parent & Other			Competitive Businesses			Eliminations			Consolidated
OPERATING REVENUES
Electric	$	2,294,707		$	-		$	(997	)	$	2,293,710
Natural gas		56,495			-			-			56,495
Competitive businesses		6,736			647,696			(3,770	)		650,662
Total		2,357,938			647,696			(4,767	)		3,000,867
OPERATING EXPENSES
Operating and Maintenance:
Fuel, fuel related expenses, and gas purchased for resale		964,747			75,520			-			1,040,267
Purchased power		352,695			10,275			(4,738	)		358,232
Nuclear refueling outage expenses		23,622			32,960			-			56,582
Other operation and maintenance		565,774			218,565			(143	)		784,196
Decommissioning		24,597			24,485			-			49,082
Taxes other than income taxes		97,355			24,265			-			121,620
Depreciation and amortization		238,947			35,296			-			274,243
Other regulatory charges (credits) - net		(40,088	)		-			-			(40,088	)
Total		2,227,649			421,366			(4,881	)		2,644,134
OPERATING INCOME		130,289			226,330			114			356,733
OTHER INCOME (DEDUCTIONS)
Allowance for equity funds used during construction		15,740			-			-			15,740
Interest and dividend income		40,607			46,995			(33,003	)		54,599
Other than temporary impairment losses		-			(14,463	)		-			(14,463	)
Equity in earnings (loss) of unconsolidated equity affiliates		48			(9,689	)		-			(9,641	)
Miscellaneous - net		(13,238	)		4,024			(114	)		(9,328	)
Total		43,157			26,867			(33,117	)		36,907
INTEREST AND OTHER CHARGES
Interest on long-term debt		129,155			(49	)		-			129,106
Other interest - net		58,889			13,607			(33,003	)		39,493
Allowance for borrowed funds used during construction		(9,274	)		-			-			(9,274	)
Total		178,770			13,558			(33,003	)		159,325
INCOME BEFORE INCOME TAXES		(5,324	)		239,639			-			234,315
Income taxes		72,959			(14,215	)		-			58,744
CONSOLIDATED NET INCOME		(78,283	)		253,854			-			175,571
Preferred dividend requirements of subsidiaries		4,332			665			-			4,997
NET INCOME ATTRIBUTABLE TO ENTERGY CORPORATION	$	(82,615	)	$	253,189		$	-		$	170,574
EARNINGS PER AVERAGE COMMON SHARE:
BASIC	$	(0.44	)	$	1.34					$	0.90
DILUTED	$	(0.38	)	$	1.27					$	0.89
AVERAGE NUMBER OF COMMON SHARES OUTSTANDING:
BASIC											189,379,904
DILUTED											198,257,675
*Totals may not foot due to rounding.

Entergy Corporation
Consolidating Income Statement
Three Months Ended December 31, 2009 vs. 2008
(Dollars in thousands)
(Unaudited)
	U.S. Utilities/ Parent & Other			Competitive Businesses			Eliminations			Consolidated
OPERATING REVENUES
Electric	$	(554,975	)	$	-		$	458		$	(554,517	)
Natural gas		(11,197	)		-			-			(11,197	)
Competitive businesses		352			64,746			(1,598	)		63,501
Total		(565,820	)		64,746			(1,140	)		(502,213	)
OPERATING EXPENSES
Operating and Maintenance:
Fuel, fuel related expenses, and gas purchased for resale		(659,017	)		2,142			(1,253	)		(658,128	)
Purchased power		1,079			1,268			142			2,489
Nuclear refueling outage expenses		4,032			2,242			-			6,274
Other operation and maintenance		(94,398	)		39,579			(29	)		(54,848	)
Decommissioning		675			1,187			-			1,863
Taxes other than income taxes		(3,605	)		196			-			(3,409	)
Depreciation and amortization		6,023			3,327			-			9,349
Other regulatory charges (credits )- net		47,731			-			-			47,731
Total		(697,480	)		49,941			(1,140	)		(648,679	)
OPERATING INCOME		131,660			14,805			-			146,466
OTHER INCOME (DEDUCTIONS)
Allowance for equity funds used during construction		(3,694	)		-			-			(3,694	)
Interest and dividend income		(14,431	)		23,339			3,144			12,052
Other than temporary impairment losses		-			13,760			-			13,760
Equity in earnings (loss) of unconsolidated equity affiliates		(3,481	)		5,773			-			2,291
Miscellaneous - net		6,395			(9,200	)		-			(2,805	)
Total		(15,211	)		33,672			3,144			21,604
INTEREST AND OTHER CHARGES
Interest on long-term debt		5,680			2,676			-			8,356
Other interest - net		(23,021	)		(6,059	)		3,144			(25,936	)
Allowance for borrowed funds used during construction		2,586			-			-			2,586
Total		(14,755	)		(3,383	)		3,144			(14,994	)
INCOME BEFORE INCOME TAXES		131,204			51,860			-			183,064
Income taxes		(58,457	)		98,352			-			39,895
CONSOLIDATED NET INCOME		189,661			(46,492	)		-			143,169
Preferred dividend requirements of subsidiaries		-			(32	)		-			(32	)
NET INCOME ATTRIBUTABLE TO ENTERGY CORPORATION	$	189,661		$	(46,460	)	$	-		$	143,201
EARNINGS PER AVERAGE COMMON SHARE:
BASIC	$	1.01		$	(0.25	)				$	0.76
DILUTED	$	0.94		$	(0.19	)				$	0.75
*Totals may not foot due to rounding.

Entergy Corporation
Consolidating Income Statement
Year to Date December 31, 2009
(Dollars in thousands)
(Unaudited)
	U.S. Utilities/ Parent & Other			Competitive Businesses			Eliminations			Consolidated
OPERATING REVENUES
Electric	$	7,883,140		$	-		$	(3,124	)	$	7,880,016
Natural gas		172,213			-			-			172,213
Competitive businesses		29,953			2,686,806			(23,338	)		2,693,421
Total		8,085,306			2,686,806			(26,462	)		10,745,650
OPERATING EXPENSES
Operating and Maintenance:
Fuel, fuel related expenses, and gas purchased for resale		2,026,893			284,191			(1,253	)		2,309,831
Purchased power		1,356,418			62,586			(23,801	)		1,395,203
Nuclear refueling outage expenses		105,016			136,293			-			241,310
Other operation and maintenance		1,851,090			901,585			(1,864	)		2,750,810
Decommissioning		99,683			99,380			-			199,063
Taxes other than income taxes		403,957			99,903			-			503,859
Depreciation and amortization		933,758			149,017			-			1,082,775
Other regulatory charges (credits) - net		(21,727	)		-			-			(21,727	)
Total		6,755,088			1,732,955			(26,918	)		8,461,124
OPERATING INCOME		1,330,218			953,851			456			2,284,526
OTHER INCOME (DEDUCTIONS)
Allowance for equity funds used during construction		59,545			-			-			59,545
Interest and dividend income		153,400			211,805			(128,577	)		236,628
Other than temporary impairment losses		-			(86,069	)		-			(86,069	)
Equity in earnings (loss) of unconsolidated equity affiliates		(3,327	)		(4,466	)		-			(7,793	)
Miscellaneous - net		(11,998	)		(20,149	)		(456	)		(32,603	)
Total		197,620			101,121			(129,033	)		169,708
INTEREST AND OTHER CHARGES
Interest on long-term debt		511,451			9,265			-			520,716
Other interest - net		162,370			49,170			(128,577	)		82,963
Allowance for borrowed funds used during construction		(33,235	)		-			-			(33,235	)
Total		640,586			58,435			(128,577	)		570,444
INCOME BEFORE INCOME TAXES		887,252			996,537			-			1,883,790
Income taxes		308,552			324,187			-			632,740
CONSOLIDATED NET INCOME		578,700			672,350			-			1,251,050
Preferred dividend requirements of subsidiaries		17,329			2,629			-			19,958
NET INCOME ATTRIBUTABLE TO ENTERGY CORPORATION	$	561,371		$	669,721		$	-		$	1,231,092
EARNINGS PER AVERAGE COMMON SHARE:
BASIC	$	2.91		$	3.48					$	6.39
DILUTED	$	2.88		$	3.42					$	6.30
AVERAGE NUMBER OF COMMON SHARES OUTSTANDING:
BASIC											192,772,032
DILUTED											195,838,068
*Totals may not foot due to rounding.

Entergy Corporation
Consolidating Income Statement
Year to Date December 31, 2008
(Dollars in thousands)
(Unaudited)
	U.S. Utilities/ Parent & Other			Competitive Businesses			Eliminations			Consolidated
OPERATING REVENUES
Electric	$	10,076,774		$	-		$	(3,614	)	$	10,073,160
Natural gas		241,856			-			-			241,856
Competitive businesses		29,011			2,771,082			(21,353	)		2,778,740
Total		10,347,641			2,771,082			(24,967	)		13,093,756
OPERATING EXPENSES
Operating and Maintenance:
Fuel, fuel related expenses, and gas purchased for resale		3,212,404			365,360			-			3,577,764
Purchased power		2,457,741			57,008			(23,549	)		2,491,200
Nuclear refueling outage expenses		92,221			129,538			-			221,759
Other operation and maintenance		1,929,781			814,855			(1,874	)		2,742,762
Decommissioning		95,821			93,588			-			189,409
Taxes other than income taxes		405,677			91,275			-			496,952
Depreciation and amortization		896,632			134,228			-			1,030,860
Other regulatory charges (credits) - net		59,883			-			-			59,883
Total		9,150,160			1,685,852			(25,423	)		10,810,589
OPERATING INCOME		1,197,481			1,085,230			456			2,283,167
OTHER INCOME (DEDUCTIONS)
Allowance for equity funds used during construction		44,523			-			-			44,523
Interest and dividend income		156,293			154,688			(113,109	)		197,872
Other than temporary impairment losses		-			(49,656	)		-			(49,656	)
Equity in earnings (loss) of unconsolidated equity affiliates		(2,161	)		(9,523	)		-			(11,684	)
Miscellaneous - net		(14,048	)		2,736			(456	)		(11,768	)
Total		184,607			98,245			(113,565	)		169,287
INTEREST AND OTHER CHARGES
Interest on long-term debt		499,679			1,219			-			500,898
Other interest - net		176,375			70,024			(113,109	)		133,290
Allowance for borrowed funds used during construction		(25,267	)		-			-			(25,267	)
Total		650,787			71,243			(113,109	)		608,921
INCOME BEFORE INCOME TAXES		731,301			1,112,232			-			1,843,533
Income taxes		291,994			311,004			-			602,998
CONSOLIDATED NET INCOME		439,307			801,228			-			1,240,535
Preferred dividend requirements of subsidiaries		17,307			2,662			-			19,969
NET INCOME ATTRIBUTABLE TO ENTERGY CORPORATION	$	422,000		$	798,566		$	-		$	1,220,566
EARNINGS PER AVERAGE COMMON SHARE:
BASIC	$	2.21		$	4.18					$	6.39
DILUTED	$	2.22		$	3.98					$	6.20
AVERAGE NUMBER OF COMMON SHARES OUTSTANDING:
BASIC											190,925,613
DILUTED											201,011,588
*Totals may not foot due to rounding.

Entergy Corporation
Consolidating Income Statement
Year to Date December 31, 2009 vs. 2008
(Dollars in thousands)
(Unaudited)
	U.S. Utilities/ Parent & Other			Competitive Businesses			Eliminations			Consolidated
OPERATING REVENUES
Electric	$	(2,193,634	)	$	-		$	490		$	(2,193,144	)
Natural gas		(69,643	)		-			-			(69,643	)
Competitive businesses		942			(84,276	)		(1,985	)		(85,319	)
Total		(2,262,335	)		(84,276	)		(1,495	)		(2,348,106	)
OPERATING EXPENSES
Operating and Maintenance:
Fuel, fuel related expenses, and gas purchased for resale		(1,185,511	)		(81,169	)		(1,253	)		(1,267,933	)
Purchased power		(1,101,323	)		5,578			(252	)		(1,095,997	)
Nuclear refueling outage expenses		12,795			6,755			-			19,551
Other operation and maintenance		(78,691	)		86,730			10			8,048
Decommissioning		3,862			5,792			-			9,654
Taxes other than income taxes		(1,720	)		8,628			-			6,907
Depreciation and amortization		37,126			14,789			-			51,915
Other regulatory charges (credits )- net		(81,610	)		-			-			(81,610	)
Total		(2,395,072	)		47,103			(1,495	)		(2,349,465	)
OPERATING INCOME		132,737			(131,379	)		-			1,359
OTHER INCOME (DEDUCTIONS)
Allowance for equity funds used during construction		15,022			-			-			15,022
Interest and dividend income		(2,893	)		57,117			(15,468	)		38,756
Other than temporary impairment losses		-			(36,413	)		-			(36,413	)
Equity in earnings (loss) of unconsolidated equity affiliates		(1,166	)		5,057			-			3,891
Miscellaneous - net		2,050			(22,885	)		-			(20,835	)
Total		13,013			2,876			(15,468	)		421
INTEREST AND OTHER CHARGES
Interest on long-term debt		11,772			8,046			-			19,818
Other interest - net		(14,005	)		(20,854	)		(15,468	)		(50,327	)
Allowance for borrowed funds used during construction		(7,968	)		-			-			(7,968	)
Total		(10,201	)		(12,808	)		(15,468	)		(38,477	)
INCOME BEFORE INCOME TAXES		155,951			(115,695	)		-			40,257
Income taxes		16,558			13,183			-			29,742
CONSOLIDATED NET INCOME		139,393			(128,878	)		-			10,515
Preferred dividend requirements of subsidiaries		21			(33	)		-			(11	)
NET INCOME ATTRIBUTABLE TO ENTERGY CORPORATION	$	139,372		$	(128,845	)	$	-		$	10,526
EARNINGS PER AVERAGE COMMON SHARE:
BASIC	$	0.70		$	(0.70	)					-
DILUTED	$	0.66		$	(0.56	)				$	0.10
*Totals may not foot due to rounding.

Entergy Corporation
Consolidated Cash Flow Statement
Three Months Ended December 31, 2009 vs. 2008
(Dollars in thousands)
(Unaudited)
	2009			2008			Variance
OPERATING ACTIVITIES
Consolidated net income	$	318,740		$	175,572		$	143,168
Adjustments to reconcile consolidated net income to net cash flow
provided by operating activities:
Reserve for regulatory adjustments		572			(6,424	)		6,996
Other regulatory charges (credits) - net		7,643			(40,087	)		47,730
Depreciation, amortization, and decommissioning		334,537			323,324			11,213
Deferred income taxes, investment tax credits, and non-current taxes accrued		355,854			(227,756	)		583,610
Equity in earnings (loss) of unconsolidated equity affiliates - net of dividends		7,350			9,642			(2,292	)
Changes in working capital:
Receivables		101,588			344,002			(242,414	)
Fuel inventory		9,461			12,320			(2,859	)
Accounts payable		175,335			(149,890	)		325,225
Taxes accrued		(122,141	)		75,210			(197,351	)
Interest accrued		17,150			7,500			9,650
Deferred fuel		(123,797	)		357,118			(480,915	)
Other working capital accounts		(110,539	)		16,045			(126,584	)
Provision for estimated losses and reserves		(1,704	)		(218,372	)		216,668
Changes in other regulatory assets		(82,610	)		(1,265,836	)		1,183,226
Changes in pensions and other postretirement liabilities		124,503			1,049,839			(925,336	)
Other		(88,115	)		169,307			(257,422	)
Net cash flow provided by operating activities		923,827			631,514			292,313
INVESTING ACTIVITIES
Construction/capital expenditures		(588,405	)		(756,598	)		168,193
Allowance for equity funds used during construction		12,046			15,741			(3,695	)
Nuclear fuel purchases		(233,753	)		(96,345	)		(137,408	)
Proceeds from sale/leaseback of nuclear fuel		87,291			46,650			40,641
Proceeds from sale of assets and businesses		500			-			500
Insurance proceeds received for property damages		20,846			(6	)		20,852
Changes in transition charge account		7,323			9,362			(2,039	)
Decrease (increase) in other investments		69,849			155,143			(85,294	)
Proceeds from nuclear decommissioning trust fund sales		837,153			423,517			413,636
Investment in nuclear decommissioning trust funds		(859,583	)		(444,893	)		(414,690	)
Net cash flow used in investing activities		(646,733	)		(647,429	)		696
FINANCING ACTIVITIES
Proceeds from the issuance of:
Long-term debt		1,221,972			23,511			1,198,461
Common stock and treasury stock		10,983			(1,066	)		12,049
Retirement of long-term debt		(758,437	)		(482,688	)		(275,749	)
Repurchase of common stock		-			(44,272	)		44,272
Changes in credit line borrowings - net		(25,000	)		30,000			(55,000	)
Dividends paid:
Common stock		(141,778	)		(142,013	)		235
Preferred stock		(4,965	)		(4,997	)		32
Net cash flow provided by (used in) financing activities		302,775			(621,525	)		924,300
Effect of exchange rates on cash and cash equivalents		(1,098	)		2,043			(3,141	)
Net increase (decrease) in cash and cash equivalents		578,771			(635,397	)		1,214,168
Cash and cash equivalents at beginning of period		1,130,780			2,555,888			(1,425,108	)
Cash and cash equivalents at end of period	$	1,709,551		$	1,920,491		$	(210,940	)
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
Cash paid (received) during the period for:
Interest - net of amount capitalized	$	126,073		$	156,497		$	(30,424	)
Income taxes	$	24,142		$	9,281		$	14,861

Entergy Corporation
Consolidated Cash Flow Statement
Year to Date December 31, 2009 vs. 2008
(Dollars in thousands)
(Unaudited)
	2009			2008			Variance
OPERATING ACTIVITIES
Consolidated net income	$	1,251,050		$	1,240,535		$	10,515
Adjustments to reconcile consolidated net income to net cash flow
provided by operating activities:
Reserve for regulatory adjustments		(508	)		(8,285	)		7,777
Other regulatory charges (credits) - net		(21,727	)		59,883			(81,610	)
Depreciation, amortization, and decommissioning		1,281,838			1,220,269			61,569
Deferred income taxes, investment tax credits, and non-current taxes accrued		868,649			333,948			534,701
Equity in earnings (loss) of unconsolidated equity affiliates - net of dividends		7,793			11,684			(3,891	)
Changes in working capital:
Receivables		116,444			78,653			37,791
Fuel inventory		19,291			(7,561	)		26,852
Accounts payable		(14,251	)		(23,225	)		8,974
Taxes accrued		(75,210	)		75,210			(150,420	)
Interest accrued		4,974			(652	)		5,626
Deferred fuel		72,314			(38,500	)		110,814
Other working capital accounts		(228,210	)		(72,372	)		(155,838	)
Provision for estimated losses and reserves		(12,030	)		12,462			(24,492	)
Changes in other regulatory assets		(415,157	)		(324,211	)		(90,946	)
Changes in pensions and other postretirement liabilities		71,789			828,160			(756,371	)
Other		6,109			(61,670	)		67,779
Net cash flow provided by operating activities		2,933,158			3,324,328			(391,170	)
INVESTING ACTIVITIES
Construction/capital expenditures		(1,931,245	)		(2,212,255	)		281,010
Allowance for equity funds used during construction		59,545			44,523			15,022
Nuclear fuel purchases		(525,474	)		(423,951	)		(101,523	)
Proceeds from sale/leaseback of nuclear fuel		284,997			297,097			(12,100	)
Proceeds from sale of assets and businesses		39,554			30,725			8,829
Payment for purchase of plant		-			(266,823	)		266,823
Insurance proceeds received for property damages		53,760			130,114			(76,354	)
Changes in transition charge account		(1,036	)		7,211			(8,247	)
NYPA value sharing payment		(72,000	)		(72,000	)		-
Decrease (increase) in other investments		94,154			(72,833	)		166,987
Proceeds from nuclear decommissioning trust fund sales		2,570,523			1,652,277			918,246
Investment in nuclear decommissioning trust funds		(2,667,172	)		(1,704,181	)		(962,991	)
Net cash flow used in investing activities		(2,094,394	)		(2,590,096	)		495,702
FINANCING ACTIVITIES
Proceeds from the issuance of:
Long-term debt		2,003,469			3,456,695			(1,453,226	)
Common stock and treasury stock		28,198			34,775			(6,577	)
Retirement of long-term debt		(1,843,169	)		(2,486,806	)		643,637
Repurchase of common stock		(613,125	)		(512,351	)		(100,774	)
Redemption of preferred stock		(1,847	)		-			(1,847	)
Changes in credit line borrowings - net		(25,000	)		30,000			(55,000	)
Dividends paid:
Common stock		(576,956	)		(573,045	)		(3,911	)
Preferred stock		(19,958	)		(20,025	)		67
Net cash flow used in financing activities		(1,048,388	)		(70,757	)		(977,631	)
Effect of exchange rates on cash and cash equivalents		(1,316	)		3,288			(4,604	)
Net increase (decrease) in cash and cash equivalents		(210,940	)		666,763			(877,703	)
Cash and cash equivalents at beginning of period		1,920,491			1,253,728			666,763
Cash and cash equivalents at end of period	$	1,709,551		$	1,920,491		$	(210,940	)
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
Cash paid (received) during the period for:
Interest - net of amount capitalized	$	568,417		$	612,288		$	(43,871	)
Income taxes	$	43,057		$	137,234		$	(94,177	)
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