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

For further information:

Paula Waters, VP, Investor Relations

Phone 504/576-4380, Fax 504/576-2897

pwater1@entergy.com

INVESTOR NEWS

 Exhibit 99.1

January 31, 2012

ENTERGY REPORTS FOURTH QUARTER EARNINGS

NEW ORLEANS –   Entergy Corporation (NYSE: ETR) reported fourth quarter 2011 earnings of $0.87 per share on an as-reported basis and $0.94 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 2011 vs. 2010
(Per share in U.S. $)
	Fourth Quarter			Year-to-Date
	2011	2010	Change	2011	2010	Change
As-Reported Earnings	0.87	1.26	(0.39)	7.55	6.66	0.89
Less Special Items	(0.07)	(0.04)	(0.03)	(0.07)	(0.44)	0.37
Operational Earnings	0.94	1.30	(0.36)	7.62	7.10	0.52
Weather Impact	(0.05)	0.06	(0.11)	0.52	0.62	(0.10)

Operational Earnings Highlights for Fourth Quarter 2011

·   Utility results were higher due primarily to lower income tax expense.

·   Entergy Wholesale Commodities earnings increased due to a lower effective income tax rate and lower decommissioning expense, partially offset by the absence of a 2010 gain on a sale of a plant and lower net revenue.

·   Parent & Other results declined due primarily to higher income tax expense.

“Our objective of establishing sound public policy that creates greater energy independence, environmental cleanliness and economic growth was advanced by recent events,” said J. Wayne Leonard, Entergy’s chairman and chief executive officer.  “Approximately four months after the trial of the Entergy lawsuit against the state of Vermont, the court struck down statutory provisions passed by the Vermont Legislature in an effort to shut down the Vermont Yankee nuclear plant on radiological safety grounds, ruling that the effort was preempted by federal law.  We’re pleased with the decision issued after a thorough review of the facts and the law, as outlined in the meticulous 102-page decision.  The ruling is good news for VY’s approximately 600 employees, the nuclear industry, the environment, and New England residents and industries that depend on VY’s clean, affordable, reliable power.

"For the Utility, we announced an agreement to spin off and merge the Utility’s electric transmission business into ITC Holdings Corp., an independent transmission company.  Closing is targeted in 2013."

Entergy’s business highlights also include the following:

·   In the Utility’s effort to join the Midwest Independent System Operator regional transmission organization, change of control filings were submitted in Arkansas, Louisiana, Mississippi and New Orleans.

·   Entergy Texas filed a rate case requesting a $112 million rate increase and a 10.6 percent return on equity.

·   The Louisiana Public Service Commission approved one-year extensions for Entergy Louisiana’s and Entergy Gulf States Louisiana’s formula rate plans.

·   Entergy Wholesale Commodities successfully completed its acquisition of the Rhode Island State Energy Center, a 583-megawatt combined-cycle gas turbine facility.

	Table of Contents	Page
I.	Consolidated Results	2
II.	Utility	3
III.	Entergy Wholesale Commodities	4
IV.	Parent & Other	6
V.	2012 Earnings Guidance	6
VI.	Long-term Financial Outlook	9
VII.	Appendices	11
	A.  Spin-Merge of Transmission Business	12
	B.  Variance Analysis and Special Items	13
	C.  Regulatory Summary	16
	D. Financial and Historical Performance Measures	20
	E.  Planned Capital Expenditures	22
	F.  Definitions	23
	G.  GAAP to Non-GAAP Reconciliations	25
VIII.	Financial Statements	28

Entergy will host a teleconference to discuss this release at 10 a.m. CT on Tuesday, January 31, 2012, with access by telephone, (719) 457-2080, confirmation code 6779942.  The call and presentation slides can also be accessed via Entergy’s website at www.entergy.com.  A replay of the teleconference will be available through February 7, 2012, by dialing (719) 457-0820, confirmation code 6779942.  The replay will also be available on Entergy’s website at www.entergy.com.

I.   Consolidated Results

Consolidated Earnings

Table 2 provides a comparative summary of consolidated earnings per share for fourth quarter and year-to-date 2011 versus 2010, including a reconciliation of GAAP as-reported earnings to non-GAAP operational earnings.  The fourth quarter 2011 earnings decline was due to lower earnings at Parent & Other, partially offset by higher results at Utility and Entergy Wholesale Commodities.  A detailed discussion of the factors driving quarter and full year results at each business segment follows.

Table 2: Consolidated Earnings – Reconciliation of GAAP to Non-GAAP Measures Fourth Quarter and Year-to-Date 2011 vs. 2010 (see Appendix Ffor definitions of certain measures)
(Per share in U.S. $)
	Fourth Quarter			Year-to-Date
	2011	2010	Change	2011	2010	Change
As-Reported
Utility	0.96	0.63	0.33	6.20	4.33	1.87
Entergy Wholesale Commodities	0.97	0.83	0.14	2.74	2.59	0.15
Parent & Other	(1.06)	(0.20)	(0.86)	(1.39)	(0.26)	(1.13)
Consolidated As-Reported Earnings	0.87	1.26	(0.39)	7.55	6.66	0.89
Less Special Items
Utility	-	-	-	-	-	-
Entergy Wholesale Commodities	-	(0.04)	0.04	-	(0.54)	0.54
Parent & Other	(0.07)	-	(0.07)	(0.07)	0.10	(0.17)
Consolidated Special Items	(0.07)	(0.04)	(0.03)	(0.07)	(0.44)	0.37
Operational
Utility	0.96	0.63	0.33	6.20	4.33	1.87
Entergy Wholesale Commodities	0.97	0.87	0.10	2.74	3.13	(0.39)
Parent & Other	(0.99)	(0.20)	(0.79)	(1.32)	(0.36)	(0.96)
Consolidated Operational Earnings	0.94	1.30	(0.36)	7.62	7.10	0.52
Weather Impact	(0.05)	0.06	(0.11)	0.52	0.62	(0.10)

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 2011 was $999 million compared to $761 million in fourth quarter 2010.  Intercompany tax payments contributed to line of business variances, but were offsetting between the segments.  The overall quarterly increase was due primarily to lower pension payments and lower working capital requirements.

For the year 2011, Entergy’s operating cash flow was $3,129 million versus $3,926 million last year.  The overall decrease for the year was due primarily to:

·   Absence of the receipt of $703 million of proceeds associated with storm-related debt issuances for hurricanes Gustav and Ike in 2010, and

·   Lower EWC net revenues.

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 2011 vs. 2010
(U.S. $ in millions)
	Fourth Quarter			Year-to-Date
	2011	2010	Change	2011	2010	Change
Utility	610	523	87	2,100	2,942	(842)
Entergy Wholesale Commodities	18	(36)	54	756	630	126
Parent & Other	371	274	97	273	354	(81)
Total Net Cash Flow Provided by Operating Activities	999	761	238	3,129	3,926	(797)

II.   Utility

In fourth quarter 2011, Utility as-reported and operational earnings were $0.96 per share compared to $0.63 per share on the same bases in fourth quarter 2010.  The increase in Utility fourth quarter 2011 earnings was largely due to lower income tax expense.  After excluding the effect of a fourth quarter 2010 regulatory item that was offset in other income, net revenue was not a significant driver quarter over quarter.  Weather was mild in the current quarter compared to cooler-than-normal weather last year.  The negative weather effect was essentially offset by other price and volume variances.

Electricity usage, in gigawatt-hour sales by customer segment, is included in Table 4.  Current quarter sales reflect the following:

·   Residential sales in fourth quarter 2011, on a weather-adjusted basis, decreased (0.4) percent compared to fourth quarter 2010.

·   Commercial and governmental sales, on a weather-adjusted basis, decreased (0.9) percent quarter over quarter.

·   Industrial sales in the fourth quarter increased 2.5 percent compared to the same quarter of 2010.

Overall retail sales growth, on a weather-adjusted basis, was 0.6 percent in the fourth quarter of this year, driven by continued growth in the industrial sector.  Industrial sales growth of 2.5 percent was largely due to expansions.

For the year 2011, the Utility earned $6.20 per share on as-reported and operational bases, compared to $4.33 in 2010.  Earnings in 2011 reflect a tax settlement with the Internal Revenue Service that resulted in a significant decrease in income tax expense.  The majority of the income tax expense effect from the IRS settlement was recorded at the Utility; there was also some effect at the other business segments.  A portion of the Utility tax benefit from the IRS settlement will be shared with Entergy Louisiana customers, consistent with the settlement approved by the Louisiana Public Service Commission (LPSC) in October 2011.  As a result, the decrease in Utility income tax expense was partially offset by a decrease in net revenue attributed to the regulatory charge recorded to reflect the customer sharing arrangement.

Excluding the regulatory charge, net revenue was higher than the prior year.  The increase was largely due to the net effect of rate adjustments at Entergy Arkansas, Entergy Texas, Entergy Louisiana and Entergy New Orleans.  Despite significant effects of weather in 2011, the weather effect declined compared to last year.  Higher weather-adjusted retail sales volume was also reflected in net revenue.  Accretion from Entergy’s share repurchase programs and lower interest expense also contributed to the earnings increase.  These benefits were partially offset by higher depreciation and amortization expense.

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

Table 4:  Utility Operational Performance Measures (see Appendix Ffor definitions of measures)
Fourth Quarter and Year-to-Date 2011 vs. 2010
	Fourth Quarter				Year-to-Date
	2011	2010	% Change	% Weather Adjusted	2011	2010	% Change	% Weather Adjusted
GWh billed
Residential	7,274	7,750	(6.1)%	(0.4)%	36,684	37,465	(2.1)%	0.2%
Commercial and governmental	7,270	7,504	(3.1)%	(0.9)%	31,194	31,294	(0.3)%	(0.2)%
Industrial	10,130	9,880	2.5%	2.5%	40,810	38,751	5.3%	5.3%
Total Retail Sales	24,674	25,134	(1.8)%	0.6%	108,688	107,510	1.1%	2.0%
Wholesale	1,090	1,021	6.8%		4,111	4,372	(6.0)%
Total Sales	25,764	26,155	(1.5)%		112,799	111,882	0.8%
O&M expense per MWh	$21.99	$21.18	3.8%		$18.22	$18.39	(0.9)%
Number of retail customers
Residential					2,362,444	2,349,900	0.5%
Commercial and governmental					353,163	351,740	0.4%
Industrial					41,173	41,383	(0.5)%

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

III.   Entergy Wholesale Commodities

Entergy Wholesale Commodities earned $0.97 per share on as-reported and operational bases in fourth quarter 2011, compared to as-reported earnings of $0.83 per share and operational earnings of $0.87 per share in fourth quarter 2010.  The quarter-over-quarter increase in operational earnings was driven by a lower effective income tax rate.  Also contributing to the higher results was a reduction in the decommissioning liability, which reduced decommissioning expense, to reflect an updated decommissioning study finalized in the fourth quarter of 2011.  Partially offsetting these positive items was the absence of the gain on sale of EWC’s remaining ownership interest in the Harrison County power plant on December 31, 2010, and lower net revenue.  EWC’s net revenue declined due primarily to lower pricing associated with the nuclear fleet.  For the quarter, the average realized revenue per megawatt hour for the nuclear fleet was almost (10) percent lower than the same quarter last year.  Providing a partial offset in net revenue was an increase in nuclear generation due to fewer planned and unplanned outages.  The Vermont Yankee nuclear plant had 25 refueling days in the current quarter compared to 43 refueling days at two plants in fourth quarter 2010.

For the year 2011, Entergy Wholesale Commodities earned $2.74 per share on as-reported and operational bases, compared to as-reported earnings of $2.59 per share and operational earnings of $3.13 per share in 2010.  The decrease in Entergy Wholesale Commodities operational earnings was driven by lower net revenue.  EWC’s net revenue declined due primarily to lower pricing associated with the nuclear fleet; the average realized revenue per megawatt hour was down more than seven percent compared to a year ago.  Providing a partial offset in net revenue was an increase in nuclear generation.  The merchant nuclear fleet realized a 93 percent capacity factor in 2011 compared to 90 percent in 2010, with fewer planned and unplanned outages.  The absence of a gain on sale of a plant noted above, lower other income, and higher depreciation and amortization expense also contributed to the earnings decline.  Partially offsetting these items was the previously discussed fourth quarter 2011 reduction in the decommissioning liability, a lower effective income tax rate, lower operation and maintenance expense, and accretion from Entergy’s share repurchase programs.

Table 5provides a comparative summary of Entergy Wholesale Commodities operational performance measures.

Table 5:  Entergy Wholesale Commodities Operational Performance Measures
Fourth Quarter and Year-to-Date 2011 vs. 2010 (see Appendix Ffor definitions of measures)
	Fourth Quarter			Year-to-Date
	2011	2010	% Change	2011	2010	% Change
Owned Capacity	6,599	6,351	3.9%	6,599	6,351	3.9%
GWh billed	11,065	10,320	7.2%	43,520	42,682	2.0%
Average realized revenue per MWh	$52.74	$58.16	(9.3)%	$54.48	$59.04	(7.7)%
Non-fuel O&M expense / purchased power per MWh (a)	$25.37	$26.74	(5.1)%	$25.62	$26.76	(4.3)%
EWC Nuclear Fleet
Capacity factor	93%	86%	8.1%	93%	90%	3.3%
GWh billed	10,367	9,644	7.5%	40,918	39,655	3.2%
Average realized revenue per MWh	$53.00	$58.80	(9.9)%	$54.73	$59.16	(7.5)%
Production cost per MWh (a)	$25.92	$25.23	2.7%	$25.21	$25.27	(0.2)%
Refueling outage days:
FitzPatrick	-	17		-	35
Indian Point 2	-	-		-	33
Indian Point 3	-	-		30	-
Palisades	-	26		-	26
Pilgrim	-	-		25	-
Vermont Yankee	25	-		25	29

(a) Fourth quarter and year-to-date periods in 2010 exclude the effect of the special item for non-utility nuclear spin-off expenses.

Table 6 provides capacity and generation sold forward projections for Entergy Wholesale Commodities’ nuclear fleet.

Table 6:  Entergy Wholesale Commodities Nuclear Capacity and Generation Projected Sold Forward
2012 through 2016 (see Appendix Ffor definitions of measures)
	2012	2013	2014	2015	2016
Energy
Planned TWh of generation (b)	41	40	41	41	40
Percent of planned generation sold forward
Unit-contingent	61%	38%	14%	12%	12%
Unit-contingent with availability guarantees	16%	19%	15%	13%	13%
Firm LD	24%	24%	10%	-%	-%
Offsetting positions	(13)%	-%	-%	-%	-%
Total energy sold forward	88%	81%	39%	25%	25%
Average revenue under contract per MWh (c)	$49	$45 - 50	$49 - 54	$49 - 57	$50 - 59
Capacity
Planned net MW in operation (b)	4,998	4,998	4,998	4,998	4,998
Percent of capacity sold forward
Bundled capacity and energy contracts	18%	16%	16%	16%	16%
Capacity contracts	39%	26%	25%	11%	-%
Total capacity sold forward	57%	42%	41%	27%	16%
Average revenue under contract per kW per month   (applies to capacity contracts only)	$2.4	$3.2	$3.1	$2.9	$-
Blended Capacity and Energy Recap (based on revenues)
Percent of planned energy and capacity sold forward	90%	80%	43%	27%	26%
Average revenue under contract per MWh (c)	$51	$47	$51	$52	$52

(b)  Assumes successful license renewal and uninterrupted normal operation at all plants.  NRC license renewal applications are in process for three units (with current license expirations noted parenthetically): Pilgrim (6/8/2012), Indian Point 2 (9/28/2013), and Indian Point 3 (12/12/2015).

(c)  Average revenue under contract may fluctuate due to factors including positive or negative basis differentials, option premiums and market prices at time of option expiration, costs to convert Firm LD to unit-contingent and other risk management costs.  Also, average revenue under contract excludes payments owed under the value sharing agreement with the New York Power Authority.

IV.   Parent & Other

Parent & Other reported a loss of $(1.06) per share on an as-reported basis and $(0.99) per share on an operational basis in fourth quarter 2011, compared to a loss of $(0.20) per share on as-reported and operational bases in the fourth quarter of last year.  The decrease in operational earnings was due primarily to an increase in income tax expense, driven partially by income tax reserve adjustments.

For the year 2011, Parent & Other reported a loss of $(1.39) per share on an as-reported basis and $(1.32) per share on an operational basis.  This compares to an as-reported loss of $(0.26) per share and an operational loss of $(0.36) per share in 2010.  Higher income tax expense was the primary factor in the year-on-year operational decrease.

V.   2012 Earnings Guidance

Entergy affirmed previously issued operational earnings guidance for 2012 to be in the range of $5.40 to $6.20 per share.  Previously issued as-reported earnings guidance of $5.40 to $6.20 per share for 2012 does not reflect any potential future expenses for the special item to be recorded in connection with the proposed spin-merge of Entergy’s transmission business.  As-reported earnings guidance will be updated to reflect this special item as actual costs are incurred throughout 2012.  Year-over-year changes are shown as point estimates and are applied to 2011 earnings to compute the 2012 guidance midpoint.  Drivers for the 2012 guidance range are listed separately.  Because there is a range of possible outcomes associated with each earnings driver, a range is applied to the guidance midpoint to produce Entergy’s guidance range.  The 2012 earnings guidance is detailed in Table 7below.

Table 7:  2012 Earnings Per Share Guidance – As-Reported and Operational
(Per share in U.S. $) – Prepared November 2011 (d)
Segment	Description of Drivers	2011 Earnings per Share	Expected Change	2012 Guidance Midpoint	2012 Guidance Range
Utility	2011 Operational Earnings per Share	6.20
	Adjustment to normalize weather		(0.52)
	Increased net revenue due to absence of sharing 2011 tax benefit with Entergy Louisiana customers		1.11
	Increased net revenue due to sales growth and rate actions		0.85
	Increased non-fuel operation and maintenance expense		(0.05)
	Increased other operating expenses		(0.10)
	Increased depreciation expense		(0.20)
	Increased interest and other charges		(0.10)
	Higher effective income tax rate		(2.49)
	Other		0.10
	Subtotal	6.20	(1.40)	4.80
Entergy Wholesale Commodities	2011 Operational Earnings per Share	2.74
	Decreased net revenue from nuclear assets due primarily to lower pricing		(0.60)
	Increased non-fuel operation and maintenance expense for nuclear operations		(0.05)
	Increased other operating expenses for nuclear operations		(0.05)
	Decommissioning liability reduction in 2011		(0.12)
	Increased depreciation expense on nuclear assets		(0.05)
	Increased after-tax operating income for EWC non-nuclear operations, including RISEC acquisition		0.10
	Increased interest and dividend income		0.05
	Higher effective income tax rate		(0.17)
	Other		(0.05)
	Subtotal	2.74	(0.94)	1.80
Parent & Other	2011 Operational Earnings per Share	(1.32)
	Increased Parent non-fuel operation and maintenance expense		(0.05)
	Increased Parent interest expense		(0.15)
	Lower income tax expense		0.74
	Other		(0.02)
	Subtotal	(1.32)	0.52	(0.80)
Consolidated Operational	2012 Operational Earnings per Share Guidance Range	7.62	(1.82)	5.80	5.40 – 6.20
Consolidated As-Reported	2011 As-Reported Earnings per Share	7.55
	Changes detailed above		(1.82)
	2011 special items for expenses associated with proposed spin-merge of Entergy’s transmission business		0.07
	2012 As-Reported Earnings per Share Guidance Range	7.55	(1.75)	(e)	(e)

(d)  Originally prepared November 2011 and updated January 2012 to reflect 2011 final results.

(e)  Previously issued as-reported earnings guidance of $5.40 to $6.20 per share for 2012 does not reflect any potential future expenses for the special item noted above in connection with the proposed spin-merge of Entergy’s transmission business.  As-reported earnings guidance will be updated to reflect this special item as actual costs are incurred throughout 2012.

Key assumptions supporting 2012 earnings guidance are as follows:

Utility

·   Normal weather

·   Retail sales growth of around 1.6 percent on a weather-adjusted basis, including the effects of industrial expansion and cogen loss

·   Increased revenue from rate actions

·   Increased net revenue due to the absence of the third quarter 2011 regulatory charge to reflect an agreement to share a portion of tax benefits with Entergy Louisiana customers that resulted from an IRS tax settlement

·   Increased non-fuel operation and maintenance expense due to plant acquisitions and general expense increases (including lower expense associated with employee stock options, which is offset in Parent & Other)

·   Increased depreciation expense associated with capital spending at the Utility

·   Increased other operating expense due primarily to higher taxes other than income taxes, resulting largely from new plant acquisitions as well as expiration of property tax exemptions

·   Increased interest expense due to higher debt outstanding

·   Higher effective income tax rate in 2012, due largely to the absence of the August 2011 IRS settlement, a portion of which was partially offset in net revenue as noted above

·   Other primarily driven by the effect of 2011 share repurchases

Entergy Wholesale Commodities

·   41 TWh of total output for the non-utility nuclear fleet, reflecting an approximate 93 percent capacity factor, including 30-day scheduled refueling outages at Indian Point 2 and Palisades in Spring 2012 and FitzPatrick in Fall 2012

·   Assumes full year operations for Vermont Yankee and Pilgrim

·   89 percent of energy sold under existing contracts at the time 2012 guidance was initiated and 11 percent sold into the spot market for EWC-nuclear fleet

·   $49/MWh average energy contract price and $46/MWh average unsold energy price based on published market prices at the end of September 2011 for EWC-nuclear fleet (average energy price for unsold volume based on prices as of late January 2012 is around $35/MWh)

·   50 percent of capacity sold under existing contracts (including 32 percent sold as capacity contracts and 18 percent sold bundled with energy) for EWC-nuclear fleet at the time 2012 guidance was initiated

·   $2.8/kW-month average sold capacity contract price and $0.5/kW-month average unsold capacity price based on published market prices at the end of September 2011 for EWC-nuclear fleet (average capacity price for unsold volume based on prices as of December 2011 is approximately $0.75/kW-month)

·   Palisades PPA revenue amortization of $17 million in 2012, down from $43 million in 2011

·   Increased nuclear fuel expense reflected in net revenue

·   Non-fuel operation and maintenance expense for nuclear operations, including refueling outage expense and purchased power, around $25.5/MWh reflecting general expense increases

·   Absence of reduction in the asset retirement obligation resulting from an updated decommissioning study, which reduced decommissioning expense, completed in the fourth quarter 2011

·   Increased other operating expense due to higher decommissioning expense (excluding the fourth quarter 2011 adjustment noted above) and higher taxes other than income taxes for nuclear operations

·   Increased depreciation expense on nuclear assets due to higher depreciable plant balances as well as declining useful life of nuclear assets

·   Improved year-over-year operating income for the balance of EWC’s business, including the assumed Rhode Island State Energy Center (RISEC) acquisition by year-end 2011 and market prices at the end of September 2011

·   Higher effective income tax rate in 2012

Parent & Other

·   Increased Parent non-fuel operation and maintenance expense due primarily to the offset of lower intercompany employee stock option expense at Utility

·   Higher Parent interest expense due to the refinancing of low-cost debt (current credit facility expires August 2012)

·   Lower income tax expense in 2012

Share Repurchase Program

·   2012 average fully diluted shares outstanding of approximately 177 million; does not assume any repurchases under the $500 million share repurchase authority, $350 million of which remained as of December 31, 2011

Other

·   Overall effective income tax rate of 34 percent in 2012

·   Pension discount rate of 5.6 percent  (the final average pension discount rate is 5.1 percent)

Earnings guidance for 2012 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 and energy prices for Entergy Wholesale Commodities.  The broader earnings guidance range for 2012 also takes into consideration the following:

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

·   Potential outcomes for projected pension plan discount rate (guidance assumes 5.6 percent, the final average pension discount rate is 5.1 percent)

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

Table 8:  2012 Earnings Sensitivities
(Per share in U.S. $) – Prepared November 2011
Variable	2012 Guidance Assumption	Description of Change	Estimated Annual Impact (f)
Utility
Sales growth   Residential   Commercial / Governmental   Industrial	Around 1.6% 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	- / + 0.37
Entergy Wholesale Commodities (g)
Capacity factor	93% capacity factor	1% change in capacity factor	- / + 0.06
Energy revenues	89% energy sold at $49/MWh in 2012; 11% unsold at $46/MWh in 2012	$10/MWh market price change	- 0.16 / + 0.20
Non-fuel operation and maintenance expense	$25.5/MWh non-fuel operation and maintenance expense/purchased power	$1/MWh change	+ / - 0.14
Outage (lost revenue only)	93% capacity factor, including refueling outages for three non-utility nuclear units	1,000 MW plant for 10 days at average portfolio energy price of $49/MWh for sold and $46/MWh for unsold volumes in 2012	- 0.03 / n/a

(f)  Based on 2011 average fully diluted shares outstanding of approximately 178 million.

(g) Based on Entergy Wholesale Commodities’ nuclear portfolio.  Assumes successful license renewal and uninterrupted normal operation at all plants.

VI.   Long-term Financial Outlook

Entergy believes it offers a long-term, competitive utility investment opportunity combined with a valuable option represented by a unique, clean, non-utility generation business located in attractive power markets.

Table 9 summarizes the current long-term financial outlook for 2010 through 2014, which does not reflect the effects of the proposed spin-merge of the transmission business discussed in Appendix A.

Table 9:  Long-term Financial Outlook
Prepared November 2011
Category	Long-term Outlook	Assumption
Earnings	Utility net income	6 to 8 percent compound annual net income growth rate over the 2010 – 2014 horizon (2009 base year).
	Entergy Wholesale Commodities results	Revenue projections through 2014 will experience increased volatility due to commodity market activities – one of the most important fundamental drivers for this business.  At current sold and forward prices with its existing asset portfolio and in-the-money hedges that will roll off in the coming few years, EWC is expected to deliver declining adjusted EBITDA for the period through 2014 compared to 2010.  However, Entergy Wholesale Commodities offers a valuable long-term option from the potential positive effects of ongoing economic growth (driving increased load, market heat rates, capacity prices and natural gas prices), aging and unprofitable unit retirements (driving market heat rate expansion and capacity price increases), new environmental legislation and/or enforcement of additional environmental regulation.
	Corporate results	Results will vary depending upon factors including future effective income tax and interest rates and the amount / timing of share repurchases.
Capital Deployment	A balanced capital investment / return program	Entergy continues to see value-added investment opportunities at the Utility in the coming years, as well as an investment outlook at Entergy Wholesale Commodities that supports continued safe, secure and reliable operations and opportunistic investments.  Entergy aspires to fund this capital program without issuing traditional common equity, while maintaining a competitive capital return program.  Given the company’s financial profile with a mix of utility and non-utility businesses, return of capital is expected to be provided similar to the past through a combination of common stock dividends and share repurchases.  Absent other attractive investment opportunities, capital deployment through dividends and share repurchases could total as much as $4 – $5 billion from 2010 – 2014 under the current long-term business outlook.  The amount of share repurchases may vary as a result of material changes in business results, capital spending or new investment opportunities.
Credit Quality		Strong liquidity.
		Solid credit metrics that support ready access to capital on reasonable terms.

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

Table 10:  2014 Financial Sensitivities – Illustrative
Long-term Outlook	Assumption	Drivers	Estimated Annual Impact
Utility			(Per share in U.S. $) (h)
Earnings growth	6 – 8% compound annual net income growth rate from 2010 through 2014 (2009 base)	1% retail sales growth $100 million/year investment in service 1% change in allowed ROE 1% change in non-fuel operation and maintenance expense $100 million change in debt	- / + 0.14 - / + 0.03 - / + 0.45 + / - 0.07 + / - 0.02
Entergy Wholesale Commodities			(Adjusted EBITDA in U.S. $; millions) (i)
Adjusted EBITDA	Decline in adjusted EBITDA at current sold and forward power prices compared to 2010, plus option value	+0 – 1,500 Btu/kWh heat rate expansion +$0 – 4/kW-mo capacity price - / + $0 – 1/MMBtu change in Henry Hub natural gas price $1/MWh EBITDA expense	Up to 190 Up to 150 Down to 260 / Up to 290 +/- 40
Corporate			(Per share in U.S. $) (h)
Balanced capital investment  / return / credit quality		1% change in interest rate on $1 billion debt 1% change in overall effective income tax rate $500 million share repurchase (share accretion effect only)	+ / - 0.03 + / - 0.09 + 0.20 – 0.25

(h)  Based on estimated 2012 average fully diluted shares outstanding of approximately 177 million.

(i)  Based on Entergy Wholesale Commodities’ nuclear portfolio.  Assumes successful license renewal and uninterrupted normal operation at all plants.

VII.   Appendices

Seven appendices are presented in this section as follows:

·   Appendix A includes information on Entergy’s plan to spin off the Utility transmission business and merge that business into ITC Holdings Corp.

·   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-Merge of Transmission Business

Appendix A provides information on Entergy’s plans to spin off its transmission business and merge that business into a subsidiary of ITC Holdings Corp.

On December 5, 2011, Entergy and ITC announced plans to spin off Entergy’s electric transmission business and merge that transmission business into a subsidiary of ITC.  Below are transaction details and other information on the proposed transaction.

System Overview

Entergy’s electric transmission business consists of approximately 15,700 miles of interconnected transmission lines at voltages of 69kV and above and associated substations across its utility service territory in the Mid-South.  Following the completion of the transaction, ITC will become one of the largest electric transmission companies in the U.S., with over 30,000 miles of transmission lines, spanning from the Great Lakes to the Gulf Coast.

Transaction Overview

Entergy and ITC Boards of Directors approved a definitive agreement under which Entergy will spin off and then merge its electric transmission business into a subsidiary of ITC.  Terms of the transaction agreements include:

·   Entergy will spin off its electric transmission business, or “Transco,” to Entergy’s shareholders in the form of a tax-free spin-off.

·   After the spin-off, the newly formed Transco will merge into a newly-created merger subsidiary of ITC.

·   Prior to the merger, ITC expects to effectuate a $700 million recapitalization, currently anticipated to take the form of a one-time special dividend to its shareholders.

·   The merger will result in Entergy shareholders receiving 50.1 percent of the shares of pro forma ITC in exchange for their shares of Transco; existing ITC shareholders will own the remaining 49.9 percent of the combined company.

Entergy expects to receive gross cash proceeds of $1.775 billion from indebtedness that will be incurred in connection with the transaction, and this indebtedness will be assumed by ITC at the close of the merger.  Entergy expects to utilize most of the cash proceeds to retire debt associated with the transmission business at its utility operating companies and the balance for debt reduction at the parent, Entergy Corporation.

Closing Conditions and Approvals

The transaction is subject to the satisfaction of customary closing conditions, including, among others, receipt of regulatory approvals, including FERC and Entergy’s retail regulators; expiration of the applicable waiting period under the Hart-Scott-Rodino Act; and receipt of an IRS private letter ruling substantially to the effect that certain requirements for the tax-free treatment of the spin-off are met and an opinion from outside counsel that the spin-off and merger will be treated as tax-free reorganizations for U.S. federal income tax purposes.  Approval of ITC’s shareholders is also required.

Implications for Entergy’s Utility’s Proposal to Join MISO Regional Transmission Organization

Completing the Midwest Independent System Operator (MISO) and Transco proposals on parallel paths will require careful planning and execution.  Entergy believes that the decision to join MISO should be separate and apart from a decision regarding the ownership and operation of its transmission system.  The company plans to continue moving forward in its pursuit of membership in MISO and Entergy Arkansas post-System Agreement operations as expeditiously as possible.

Expected Close

Completion of the transaction is expected in 2013 subject to the satisfaction of certain closing conditions, including the required approvals discussed above.

B.   Variance Analysis and Special Items

Appendix B-1 and Appendix B-2 provide details of fourth quarter and year-to-date 2011 vs. 2010 as-reported and operational earnings variance analysis for Utility, Entergy Wholesale Commodities, Parent & Other, and Consolidated.

Appendix B-1: As-Reported and Operational Earnings Per Share Variance Analysis
Fourth Quarter 2011 vs. 2010
(Per share in U.S. $, sorted in consolidated operational column, most to least favorable)
	Utility			Entergy Wholesale Commodities			Parent & Other			Consolidated
	As-Reported	Opera- tional		As-Reported	Opera- tional		As- Reported	Opera- tional		As- Reported	Opera- tional
2010 earnings	0.63	0.63		0.83	0.87		(0.20)	(0.20)		1.26	1.30
Decommissioning exp.	-	-		0.11	0.11	(j)	-	-		0.11	0.11
Interest exp. and other charges	0.02	0.02		-	-		0.01	0.01		0.03	0.03
Share repurchase effect	0.02	0.02		0.02	0.02		(0.02)	(0.02)		0.02	0.02
Taxes other than income taxes	0.02	0.02		(0.01)	(0.01)		-	-		0.01	0.01
Net revenue	0.09	0.09	(k)	(0.09)	(0.09)	(l)	-	-		-	-
Depreciation / amortization exp.	(0.02)	(0.02)		(0.01)	(0.01)		-	-		(0.03)	(0.03)
Other income (deductions) - other	(0.05)	(0.05)	(m)	(0.01)	(0.01)		(0.01)	(0.01)		(0.07)	(0.07)
Other operation and maintenance exp.	(0.04)	(0.04)		-	(0.04)		(0.10)	(0.03)	(n)	(0.14)	(0.11)
Gain on sale of investment	-	-		(0.18)	(0.18)	(o)	0.03	0.03		(0.15)	(0.15)
Income taxes – other	0.29	0.29	(p)	0.31	0.31	(q)	(0.77)	(0.77)	(r)	(0.17)	(0.17)
2011 earnings	0.96	0.96		0.97	0.97		(1.06)	(0.99)		0.87	0.94

Appendix B-2: As-Reported and Operational Earnings Per Share Variance Analysis
Year-to-Date Fourth Quarter 2011 vs. 2010
(Per share in U.S. $, sorted in consolidated operational column, most to least favorable)
	Utility			Entergy Wholesale Commodities			Parent & Other			Consolidated
	As-Reported	Opera- tional		As-Reported	Opera- tional		As- Reported	Opera- tional		As- Reported	Opera- tional
2010 earnings	4.33	4.33		2.59	3.13		(0.26)	(0.36)		6.66	7.10
Income taxes – other	2.38	2.38	(p)	0.17	0.17	(q)	(0.83)	(0.73)	(r)	1.72	1.82
Share repurchase effect	0.31	0.31	(s)	0.14	0.14	(s)	(0.07)	(0.07)	(s)	0.38	0.38
Decommissioning exp.	(0.02)	(0.02)		0.09	0.09	(j)	-	-		0.07	0.07
Interest exp. and other charges	0.12	0.12	(t)	0.17	0.03	(u)	(0.09)	(0.09)	(v)	0.20	0.06
Nuclear refueling outage expense	0.01	0.01		(0.01)	(0.01)		-	-		-	-
Taxes other than income taxes	-	-		(0.01)	(0.01)		-	-		(0.01)	(0.01)
Other operation and maintenance exp.	(0.01)	(0.01)		0.46	0.07	(w)	(0.15)	(0.08)	(n)	0.30	(0.02)
Depreciation / amortization exp.	(0.05)	(0.05)	(x)	(0.05)	(0.06)	(y)	-	-		(0.10)	(0.11)
Other income (deductions) – other	0.02	0.02		(0.13)	(0.13)	(z)	(0.03)	(0.03)		(0.14)	(0.14)
Gain on sale of investment	-	-		(0.17)	(0.17)	(o)	0.03	0.03		(0.14)	(0.14)
Net revenue	(0.89)	(0.89)	(k)	(0.51)	(0.51)	(l)	0.01	0.01		(1.39)	(1.39)
2011 earnings	6.20	6.20		2.74	2.74		(1.39)	(1.32)		7.55	7.62

(j) The current quarter and year-to-date increase is due primarily to a reduction in the asset retirement obligation, which reduced decommissioning expense, as a result of an updated decommissioning study at Vermont Yankee completed in fourth quarter 2011.

Utility Net Revenue Variance Analysis 2011 vs. 2010 ($ EPS)
	Fourth Quarter	Year-to-Date
Weather	(0.11)	(0.10)
Sales growth / pricing	0.12	0.30
Regulatory agreement (3Q11)	-	(1.06)
Decommissioning Trust investment gain offset (4Q10)	0.08	0.08
Other	-	(0.11)
Total	0.09	(0.89)

(k) The increase in the current quarter is due primarily to the absence of an offset of other income associated with decommissioning trust investments in fourth quarter 2010 described in (m) below, as well as favorable sales growth / pricing (including in the unbilled period).  Partially offsetting was mild weather in the current quarter compared to cooler-than-normal weather in fourth quarter 2010.  The year-to-date decrease is due primarily to a regulatory charge resulting from a settlement approved by the LPSC to share with Entergy Louisiana customers a portion of tax benefits from a settlement with the IRS.  The year-to-date variance also reflects the net effect of pricing adjustments resulting from rate actions in Arkansas, Louisiana, New Orleans and Texas as well as higher sales growth.  While significant for 2011, the weather effect was negative compared to 2010.

(l) The current quarter and year-to-date decrease is due primarily to lower energy and capacity pricing on the EWC nuclear fleet, partially offset by fewer nuclear refueling and unplanned outages.  Higher fuel expenses, primarily at the nuclear plants, and the absence of net revenue from the Harrison plant, which was sold at the end of the fourth quarter 2010, also contributed.

(m) The decrease in the current quarter is due primarily to the absence of a decommissioning trust investment gain recorded in the fourth quarter of last year, which was offset in Utility net revenue.

(n) The current-quarter and year-to-date as-reported decrease is due primarily to expenses incurred in connection with the planned spin-merge of the transmission business announced in December 2011.  The year-to-date operational and as-reported decreases also reflect the offset of lower intercompany employee stock option expense at Utility.

(o) The current quarter and year-to-date decrease is due to the absence of a gain recorded on the fourth quarter 2010 sale of the remaining ownership interest in the Harrison County plant.

(p) The current quarter and year-to-date increase is due to the favorable effect of consolidated income tax adjustments, which net to zero on a consolidated basis, and favorable income tax adjustments, both recorded in fourth quarter 2011.  The year-to-date change also reflects the absence of a prior year unfavorable consolidated income tax adjustments recorded in the third quarter.  Also contributing to the year-to-date increase was the IRS tax settlement executed in the third quarter of this year.  Partially offsetting in both periods was the absence of a fourth quarter 2010 favorable income tax adjustments due to revised accruals which were based on completion of the 2009 tax return in 2010.  The year to date effect is also partially offset by the absence of a Louisiana state income tax benefit related to Act 55 storm cost financing recognized in the third quarter of last year.

(q) The current quarter increase is due to the favorable effect of consolidated income tax adjustments, which net to zero on a consolidated basis, recorded in fourth quarter 2011.  Also contributing in the current quarter and year-to-date periods was the absence of a portion of Entergy Nuclear Power Marketing (ENPM) income tax expense in fourth quarter 2011, now being recorded at Parent & Other due to an ownership restructuring.  The absence of a charge resulting from a change in tax law associated with federal healthcare legislation enacted in 2010 also contributed to the year-to-date increase.  Partially offsetting in the year-to-date period was the absence of favorable consolidated income tax adjustments recorded in the third quarter 2010 and changes in Michigan tax law stemming from legislation enacted in May 2011.

(r) The current quarter decrease is due primarily to the unfavorable effect of consolidated income tax adjustments (offset at Utility and Entergy Wholesale Commodities) and unfavorable income tax reserve adjustments on uncertain tax positions, both recorded in fourth quarter 2011.  Also contributing was the portion of Entergy Nuclear Power Marketing income tax expense now being recorded at Parent & Other, described in (q) above.  In addition, the year-to-date decrease reflects the absence of a prior year favorable Tax Court ruling addressing a foreign tax credit computation allowing the reversal of a previously-established tax reserve on the issue.  Partially offsetting these decreases was the reversal of a tax reserve recorded in the second quarter of this year.  The as-reported year-to-date decrease also reflects the absence of income tax benefits recorded in connection with the non-utility nuclear spin-off unwind in 2010.

(s) The year-to-date changes reflect accretion from Entergy’s share repurchase programs.

(t) The increase in the year-to-date period is due primarily to favorable debt refinancing and the absence of interest recorded on a fuel audit refund in the third quarter of 2010.  A revision in the treatment of funds received for transmission interconnection projects, accepted by the Federal Energy Regulatory Commission, also contributed to the increase.

(u) The as-reported year-to-date increase is due to the absence of the first quarter 2010 charge for the balance of fees recorded for the cancellation of a credit facility in connection with the non-utility nuclear spin-off unwind.

(v) The decrease year-to-date is due primarily to higher interest rates on $1 billion of Parent notes issued in September 2010.  Elimination of lower affiliated interest expense also contributed.

(w) The year-to-date increase is due primarily to the absence of operation and maintenance expenses from the Harrison County plant, which was sold in the fourth quarter of 2010.  Lower compensation and benefit expenses, lower spending on tritium remediation, and the absence of a write off of capitalized engineering costs associated with a potential uprate project recorded in the prior year, also contributed.  The absence of non-utility nuclear spin-off expenses contributed to the as-reported increase.

(x) The year-to-date decrease reflects higher depreciable plant balances.

(y) The decrease year-to-date reflects higher depreciable plant balances as well as the declining useful life of nuclear assets.

(z) The year-to-date decrease is due primarily to lower affiliate interest income (offset at Parent & Other) and lower realized gains on decommissioning trust investments.

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 not 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 2011 vs. 2010
(Per share in U.S. $)
	Fourth Quarter			Year-to-Date
	2011	2010	Change	2011	2010	Change
Utility
None	-	-	-	-	-	-
Entergy Wholesale Commodities
Non-utility nuclear spin-off expenses	-	(0.04)	0.04	-	(0.54)	0.54
Parent & Other
Non-utility nuclear spin-off expenses	-	-	-	-	0.10	(0.10)
Transmission business spin-merge expenses	(0.07)	-	(0.07)	(0.07)	-	(0.07)
Total Parent & Other	(0.07)	-	(0.07)	(0.07)	0.10	(0.17)
Total Special Items	(0.07)	(0.04)	(0.03)	(0.07)	(0.44)	0.37
(U.S. $ in millions)
	Fourth Quarter			Year-to-Date
	2011	2010	Change	2011	2010	Change
Utility
None	-	-	-	-	-	-
Entergy Wholesale Commodities
Non-utility nuclear spin-off expenses	-	(6.7)	6.7	-	(100.7)	100.7
Parent & Other
Non-utility nuclear spin-off expenses	-	-	-	-	18.5	(18.5)
Transmission business spin-merge expenses	(13.0)	-	(13.0)	(13.0)	-	(13.0)
Total Parent & Other	(13.0)	-	(13.0)	(13.0)	18.5	(31.5)
Total Special Items	(13.0)	(6.7)	(6.3)	(13.0)	(82.2)	69.2

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: 10.2% Last Filed Rate Base: $4.0 billion filed 6/10  based on 6/30/09 test yr, with known and measurable changes through 6/30/10	Rate Case Recent Activity:  None. Background:  EAI implemented a $63.7 million rate increase in July 2010 pursuant to the settlement approved by the Arkansas Public Service Commission (APSC) in June 2010, which authorized a 10.2 percent allowed return on equity (ROE).
	Hot Spring Acquisition Recent Activity:  On January 19, 2012, the APSC issued an order on the Joint Stipulation and Settlement filed by EAI, the APSC General Staff, and the Arkansas Attorney General on January 13, 2012.  Because the transmission upgrades costs remain uncertain pending the results of ongoing Facilities Studies, the order suspended the procedural schedule and cancelled the hearing scheduled for January 24, 2012.  The APSC directed EAI to file the study results when available (expected by early April 2012) and for a procedural schedule to be proposed by the parties thereafter. ��Under the settlement, the parties agreed that the acquisition costs may be recovered through a capacity acquisition rider and agreed that the level of the ROE reflected in the rider would be submitted to the APSC for resolution.  The APSC Staff recommended the ROE for the rider be set at 9.7 percent.  Assuming timely regulatory approvals and the satisfaction of all other closing conditions, closing is expected to occur in mid-2012. Background:  On April 29, 2011, EAI announced that it signed an asset purchase agreement to acquire the Hot Spring Energy Facility, a 620 MW natural gas-fired combined-cycle turbine plant located in Hot Spring County, Arkansas, from KGen Hot Spring LLC, a subsidiary of KGen Power Corporation.  The total expected cost is $277 million (or $447/kW) including the purchase price of approximately $253 million (or $408/kW) and planned plant upgrades, transaction costs, and contingencies and excluding transmission upgrades.  On July 15, 2011, EAI filed an application with the APSC seeking approval of the Hot Spring acquisition and rider recovery concurrent with closing of the acquisition.  On July 21, 2011, the transaction was reported to the U.S. Department of Justice and the Federal Trade Commission to satisfy the requirements of the Hart-Scott-Rodino Antitrust Improvements Act.  On August 31, 2011, EAI and KGen filed an application seeking FERC approval of the Hot Spring acquisition under Section 203 of the Federal Power Act.
Entergy Gulf States Louisiana Authorized ROE Range: 9.9% - 11.4% (electric) 10.0% - 11.0% (gas) Last Filed Rate Base: $2.4 billion (electric) filed 5/11 based on 12/31/10 test yr $0.05 billion (gas) filed 4/11 based on 9/30/10 test yr	Formula Rate Plan Recent Activity:  At its November 9, 2011 Business and Executive (B&E) session, the Louisiana Public Service Commission (LPSC) approved a one-year extension of EGSL’s current formula rate plan (FRP).  The FRP filing for the 2011 test year will be made in May 2012.  In addition, assuming the LPSC has not declined to certify the change-of-control to MISO on or before May 1, 2012, EGSL is required to file a full rate case by January 2013.  If the LPSC has declined the certification by May 1, 2012, then the rate case must be filed in September 2012. Background:  At its October 2009 B&E session, the LPSC approved an uncontested settlement which, among other things, extended the FRP regulatory process for an additional three years.  The new FRP, adopted for the 2008-2010 test years, retained the 10.65 percent ROE midpoint with a +/- 75 basis point bandwidth and a recovery mechanism for LPSC-approved capacity additions.  Earnings outside the bandwidth are allocated prospectively, 60 percent to customers and 40 percent to EGSL.  As part of the settlement, all parties also committed to work together to attempt to develop a transmission rider for EGSL.  In response to a depreciation rate complaint filed at FERC by the LPSC, EGSL presented in its 2009 test year FRP filing two ancillary FRP filing proposals based on a new depreciation study that increased depreciation rates and related FRP revenues by either $45.3 million (assuming a 40 year River Bend life) or $24.4 million (60 year life).  The depreciation matter raised by the ancillary filing and the transmission rider remain outstanding.  At its October 12, 2011 B&E session, the LPSC accepted the joint EGSL / LPSC Staff report reflecting resolution of the 2010 test year FRP filing.  The filing reflected an 11.11 percent earned ROE which was within the earnings bandwidth resulting in no cost of service rate change.  The filing also reflected a $(22.8) million decrease outside of the FRP sharing mechanism for capacity costs.
Entergy Louisiana Authorized ROE Range: 9.45% - 11.05% Last Filed Rate Base: $3.2 billion filed 5/11 based on 12/31/10 test yr	Formula Rate Plan Recent Activity: At its November 9, 2011 B&E session, the LPSC approved a one-year extension of ELL’s current FRP.  The FRP filing for the 2011 test year will be made in May 2012.  As part of the one-year extension, if the Waterford 3 replacement steam generator (RSG) project is completed by March 31, 2013, ELL shall be permitted to include in rates the revenue requirement associated with the project upon completion.  Inclusion of the revenue requirement shall be on a subject-to-refund basis pending proceedings by the LPSC to review the prudence of costs related to project construction.  For the rate-effective period of the 2011 test year prior to the project’s completion, earnings above certain levels will be recorded as a regulatory liability used to offset the Waterford 3 RSG project’s revenue requirement.  Beginning in September 2012 (the normal FRP rate change date) and ending the earlier of (1) when the project is closed to plant or (2) January 1, 2013, earnings in excess of the upper band (11.05 percent) shall be recognized by recording a regulatory liability.  After January 1, 2013, earnings in excess of 10.25 percent shall be recognized by recording a regulatory liability.  Upon the project’s completion, earnings above 10.25 percent shall be used to offset the project’s revenue requirement.  The total regulatory liability shall be amortized to the project’s revenue requirement over the first twelve months of operation.  These rates are anticipated to remain in effect until ELL’s next full rate case is resolved.  In addition, assuming the LPSC has not declined to certify the change-of-control to MISO on or before May 1, 2012, ELL is required to file a full rate case by January 2013.  If the LPSC has declined the certification by May 1, 2012, then the rate case must be filed in September 2012. Background:  At its October 2009 B&E session, the LPSC approved an uncontested settlement which, among other things, extended the FRP regulatory process for an additional three years.  The new FRP, adopted for the 2008-2010 test years, retained the 10.25 percent ROE midpoint with a +/- 80 basis point bandwidth and a recovery mechanism for LPSC-approved capacity additions.  Earnings outside the bandwidth are allocated prospectively, 60 percent to customers and 40 percent to ELL.  As part of the settlement, all parties also committed to work together to attempt to develop a transmission rider for ELL.  In response to a depreciation rate complaint filed at FERC by the LPSC, ELL presented in its 2009 test year FRP filing two ancillary FRP filing proposals based on a new depreciation study that increased depreciation rates and related FRP revenues by either $96.4 million (assuming a 40 year Waterford 3 life) or $40.5 million (60 year life).  The depreciation matter raised by the ancillary filing and the transmission rider remain outstanding.  At its October 12, 2011 B&E session, the LPSC accepted the joint ELL / LPSC Staff report reflecting resolution of the 2010 test year FRP filing.  The filing reflected an 11.08 percent earned ROE which was within the earnings bandwidth tolerance resulting in no cost of service rate change.  Capacity costs were essentially unchanged.

Appendix C: Regulatory Summary Table (continued)
Company	Pending Cases / Events
Retail Regulation
Entergy Louisiana (continued)	Waterford 3 Steam Generator Replacement Recent Activity:  On October 31, 2011, ELL filed its Quarterly Monitoring Report indicating that the Waterford 3 replacement steam generator (RSG) project continues to meet revised cost estimates and the revised schedule for installation in Fall 2012.  On December 19, 2011, ELL filed its Amended and Supplemental Application for Certain Cost Recovery, which will establish the revenue requirement for the project that will be placed into rates, subject to refund pending a review of the prudence of the project costs, upon the commercial operation of the project.  See also, ELL - Formula Rate Plan Recent Activity. Background: On June 26, 2008, ELL petitioned the LPSC to replace two steam generators, the reactor vessel closure head, and control drive mechanisms.  On November 12, 2008, the LPSC approved the stipulated settlement, finding that the decision to undertake this project at an estimated cost of $511 million was prudent and the timing concurrent with the 2011 outage was reasonable.  On December 17, 2010, ELL notified the LPSC that Westinghouse advised that the Waterford 3 RSGs would not be completed and delivered in time to maintain the then current project schedule for installation during the Spring 2011 refueling outage.  On June 15, 2011, ELL filed a Special Monitoring Report to reflect the updated cost and schedule associated with the project.  The installation schedule was revised from the Spring 2011 refueling outage to the Fall 2012 refueling outage.  Additional funding of approximately $176 million is required, bringing the revised replacement project total to approximately $687 million.  Extensive inspections of the steam generators during the Spring 2011 refueling outage confirmed that Waterford 3 can operate safely for another full cycle before the replacement of the steam generator.
	Ninemile 6 Certification Recent Activity:  On November 22, 2011, the LPSC Staff filed testimony generally supporting the construction of the Ninemile 6 project but recommending a lower project contingency level.  The LPSC Staff took issue with various aspects of ELL’s proposed Regulatory Approval Plan.  One intervenor, Calpine, filed testimony suggesting that certification should be denied; no other intervenors filed testimony.  On January 11, 2012, ELL filed rebuttal testimony providing further support for the contingency level and the proposed Regulatory Approval Plan.  The matter is set for hearing in late February 2012.  Assuming regulatory approvals are obtained, the targeted date to issue full notice to proceed with construction of the Ninemile 6 project is in May 2012.  On January 24, 2012, the Utility Committee of the Council of the City of New Orleans (CCNO) approved the participation by Entergy New Orleans, Inc. (ENOI) in a life-of-unit agreement to purchase 20 percent of the capacity and energy output of the Ninemile 6 project and to place the item on the CCNO’s February 2, 2012 Consent Agenda. Background:  The Ninemile 6 project is a proposed 550 MW combined-cycle gas turbine facility with commercial operation anticipated by the summer of 2015.  The resource has been allocated 55 percent to ELL, 25 percent to EGSL, and 20 percent to ENOI.  On June 21, 2011, ELL filed an application with the LPSC seeking approval to construct the Ninemile 6 CCGT and for EGSL to purchase up to 35 percent of the capacity and energy under a life-of-unit power purchase agreement.  As reflected in the filing, the current estimated construction cost is approximately $721 million.  ENOI submitted an application to the CCNO on July 8, 2011 seeking approval of its participation in the Ninemile 6 project through a life-of-unit power purchase agreement of capacity and energy.  If CCNO does not approve the power purchase agreement in a timely manner then ELL and EGSL propose an allocation of 65 percent to ELL and 35 percent to EGSL.  The project air permit was issued by the Louisiana Department of Environmental Quality on August 16, 2011.
Entergy Mississippi Authorized ROE Range: 10.54% - 12.72% (per FRP filing) Last Filed Rate Base:  $1.6 billion filed 3/11 based on 12/31/10 test yr	Formula Rate Plan Recent Activity:  On November 10, 2011, the Mississippi Public Service Commission (MPSC) approved a Joint Stipulation reached between EMI and the MPSC Staff regarding the 2010 test year.  Without addressing any of the issues identified by the Staff, the agreement noted that the sum of any disputed amounts do not move EMI outside the “Range of No Change;” therefore, there is no change in rates. Background:  On March 4, 2010, the MPSC approved modifications to EMI’s FRP that (1) aligned EMI’s FRP more closely with the FRPs of the other regulated gas and electric utilities in Mississippi; (2) provided the opportunity to reset the ROE and bandwidth based upon performance ratings; (3) rescored the performance adjustment factors; (4) increased the percent of revenues limit to a 4 percent limit, with any adjustment over 2 percent requiring a hearing; and (5) directed EMI to phase-out the summer / winter rate differential in residential rates over two years.  On March 15, 2011, EMI filed its second evaluation report under its new FRP for the 2010 test year.  The filing reflected a 10.65 percent earned ROE which was within the bandwidth resulting in no change in rates.  The calculated 11.63 percent FRP midpoint ROE includes the benefit of a 0.79 percent performance incentive.  On June 23, 2011, EMI filed a Depreciation Study, requesting that new rates become effective with the next base rate change.
	Hinds Acquisition Recent Activity:  The hearing on the certification proceeding is scheduled for February 16, 2012.  A schedule is being developed for the cost recovery proceeding.  Facilities Studies are ongoing to determine transmission upgrades costs associated with the plant, with results expected by early March 2012.  Assuming timely regulatory approvals and the satisfaction of all other closing conditions, closing is expected to occur in mid-2012. Background: On April 29, 2011, EMI announced that it signed an asset purchase agreement to acquire the Hinds Energy Facility, a 450 MW (summer rating) natural gas-fired combined-cycle turbine plant located in Jackson, Mississippi, from KGen Hinds, LLC, a subsidiary of KGen Power Corporation.  The total expected cost is $246 million (or $547/kW) including the purchase price of approximately $206 million (or $458/kW) and planned plant upgrades, transaction costs, and contingencies and excluding transmission upgrades.  On July 15, 2011, EMI filed an application with the MPSC seeking certification of the Hinds acquisition and rider recovery concurrent with closing of the acquisition.  On July 21, 2011, the transaction was reported to the U.S. Department of Justice and the Federal Trade Commission to satisfy the requirements of the Hart-Scott-Rodino Antitrust Improvements Act.  On August 31, 2011, EMI and KGen filed an application seeking FERC approval of the Hinds acquisition under Section 203 of the Federal Power Act.

Appendix C: Regulatory Summary Table (continued)
Company	Pending Cases / Events
Retail Regulation
Entergy New Orleans Authorized ROE Range: 10.7% - 11.5% (electric) 10.25% - 11.25% (gas) Last Filed Rate Base: $0.3 billion (electric),  $0.09 billion (gas) filed 5/11 based on 12/31/10 test yr	Formula Rate Plan 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 percent electric ROE with a +/- 40 basis points bandwidth and a 10.75 percent gas ROE with a +/- 50 basis points bandwidth.  Earnings outside the bandwidth reset to the midpoint ROE, with rates changing on a prospective basis depending on whether ENOI is over or under-earning.  The FRP also includes a recovery mechanism for CCNO-approved capacity additions plus provisions for extraordinary cost changes and force majeure.  The FRP may be extended by the mutual agreement of ENOI and the CCNO.  The settlement also implemented energy conservation and demand side management programs.  On September 22, 2011, the CCNO approved the Agreement in Principle reached between ENOI and the CCNO Advisors resolving ENOI’s 2010 test year FRP.  The agreement decreased electric rates by approximately $(13.1) million and gas rates by approximately $(1.6) million effective October 2011.  In addition, the agreement permitted ENOI to recover $2.5 million of System Agreement-related costs through ENOI’s Fuel Adjustment’s over / under collection mechanism.  The CCNO Advisors recommended that ENOI’s request to increase the electric and gas storm reserve rider in order to meet the original target of $75 million in the storm fund by the year 2017 be considered separately.
Entergy Texas Authorized ROE: 10.125% Last Filed Rate Base: $1.7 billion filed 11/11 based on 6/30/11 adjusted test yr	Rate Case Recent Activity:  On November 28, 2011, ETI filed its rate case requesting a $111.8 million base rate increase and a 10.6 percent ROE based on an adjusted twelve-month test year ending June 30, 2011.  As part of the filing, ETI proposed a Purchased Power Recovery (PPR) rider.  The parties have agreed to a procedural schedule that contemplates a final decision by July 30, 2012, with ultimate rates relating back to June 30, 2012.  On January 12, 2012, the Public Utility Commission of Texas (PUCT) voted to not address the PPR rider in the current rate case; however, the PUCT voted to set a baseline in this rate case that would be applicable if a PPR rider is approved in the open rulemaking project docket. Background:  Pursuant to settlement of its 2009 rate case, ETI implemented a $17.5 million interim rate increase beginning on May 1, 2010, and the balance of the total $59 million base rate increase for usage on and after August 15, 2010.  Other key elements of the settlement included an additional $9 million rate increase implemented for bills rendered on and after May 2, 2011 and a 10.125 percent allowed ROE.
	Other Regulatory Activity:  No action has been taken by the PUCT on the rulemaking with respect to a purchased power capacity rider.  On November 1, 2011, pursuant to a PUCT directive, parties submitted a list of issues to be resolved in the competitive generation service (CGS) tariff proposal.  On December 15, 2011, the PUCT established a procedural schedule to reach resolution on the issues. Background:  On March 10, 2011, the PUCT opened a rulemaking to review recovery of purchased power capacity costs.  The parties provided comments in June 2011 and the PUCT Staff subsequently held a technical conference.  The CGS tariff was proposed by ETI as required in state legislation initially enacted in 2005 and modified in 2009.  Parties have been negotiating a settlement of the CGS tariff proposal since it was severed from ETI’s last rate case proceeding in December 2010.  On September 29, 2011, the PUCT denied a motion seeking rejection of the CGS tariff proposal.
System Energy Resources, Inc. Authorized ROE:  10.94% Last Calculated Rate Base: $1.1 billion for 12/31/11 monthly cost of service	Recent Activity:  None. Background:  10.94 percent ROE approved by July 2001 FERC order. Grand Gulf Uprate:  Work continues on the approximate 178 MW uprate, which remains targeted for completion in 2012.  SERI owns or leases 90 percent of the plant.  After performing more detailed project design, engineering, analysis and major materials purchases, SERI’s current updated estimate of the total capital investment to be made in the course of the implementation of the Grand Gulf uprate project is approximately $734 million, including South Mississippi Electric Power Association’s 10 percent share.  As in the original estimate, this estimate includes spending on certain major equipment refurbishment and replacement that would have been required over the normal course of the plant’s life even if the uprate were not done.  The purpose of performing this major equipment refurbishment and replacement in connection with the uprate is to avoid additional plant outages and construction costs in the future while improving plant reliability.  The investment estimate may be revised in the future as SERI evaluates the progress of the project.  On November 30, 2009, the MPSC issued a Certificate of Public Convenience and Necessity for implementation of the uprate.  The license amendment application was submitted to the NRC on September 8, 2010.  Following an acceptance review period, the NRC formally accepted the submittal for review on December 22, 2010.  The NRC review of the project is ongoing.  In December 2011, SERI received new Requests for Additional Information (RAIs) from the NRC relating to the General Electric-Hitachi steam dryer that is being installed as part of the uprate project.  SERI is preparing responses to these RAIs and will seek to minimize potential cost effects or delay, if any, to the Grand Gulf uprate implementation schedule.

Appendix C: Regulatory Summary Table (continued)
Company	Pending Cases / Events
Wholesale Regulation
Transmission, Proposal to Join MISO and System Agreement Authorized ROE:  11.0% (aa) Last Filed OATT Rate Base:               $2.2 billion (bb) filed 5/11 based on 12/31/10 test year	Proposal to Join MISO Recent Activity:  The target implementation date for joining MISO is December 2013.  On October 31, 2011, EGSL and ELL submitted their joint change of control filing to the LPSC.  EAI, EMI, and ENOI submitted their change of control filings to their respective regulators on November 28, 2011, December 2, 2011, and November 14, 2011, respectively.  Because of a PUCT requirement to issue an order within 180 days of a filing, ETI plans to monitor other operating companies for further progress on their change of control filings before submitting its filing.  The APSC and LPSC have established procedural schedules with hearings scheduled in May and early June, and potential decisions shortly thereafter.  Decisions in the other jurisdictions are expected by the third quarter of 2012.  A tentative procedural schedule has been set for CCNO review, which provides for hearings in mid-May.  FERC filings related to integrating the Utility operating companies into MISO are targeted for Summer 2012.  ESI has initiated an Alternative Dispute Resolution process before the FERC in order to seek consensus from the retail regulators regarding amendments to the System Agreement that may be required as a result of the transfer of functional control of the Utility operating companies’ transmission assets to MISO. Background:  In November 2006, the Utility operating companies installed SPP as their ICT with an initial term of four years unless Entergy filed and FERC approved an extension beyond that four-year period.  The Utility operating companies did not transfer control of the transmission system but rather vested the ICT with responsibility, among others, for granting or denying transmission service, administering the OASIS node, developing a base plan for the transmission system that is used to determine whether costs of transmission upgrades should be rolled into transmission rates or directly assigned to customers requesting or causing the upgrade to be built, serving as reliability coordinator for the transmission system, and overseeing the weekly procurement process.  On November 16, 2010, FERC issued an order accepting the Utility operating companies’ proposal to extend the ICT arrangement with SPP by an additional term of two years, providing time for analysis of longer-term structures. On December 16, 2010, FERC issued an order thatgranted the Entergy Regional State Committee (E-RSC) additional authority over transmission planning and cost allocation.  Specifically, the E-RSC has been given authority, upon unanimous vote of all members, to direct the Utility operating companies to make a filing to propose changes to the way costs for future transmission upgrades are allocated under the Open Access Transmission Tariff (OATT) and to add specific projects to the Entergy Construction Plan.  The E-RSC, comprised of one representative from each of the Utility operating company retail regulators, was formed in 2009 to consider several of the issues related to the Entergy transmission system. On May 12, 2011, the Utility operating companies submitted detailed analysis to their respective retail regulators supporting their conclusion that joining MISO will provide meaningful long-term benefits for customers.  The proposal to join MISO also addresses the exit of Entergy Arkansas and Entergy Mississippi from the System Agreement.
	System Agreement Recent Activity:  On December 19, 2011, Entergy made a compliance filing in response to FERC’s October 20, 2011 order accelerating the implementation of the bandwidth remedy to June 1, 2005 from January 1, 2006.  Pursuant to the calculation provided in the compliance filing, EAI made a combined payment of $156 million to EGSL, EMI, ENOI, and ETI for the seven-month period of June 1, 2005 through December 31, 2005.  EAI has an existing rider approved by the APSC that provides for recovery of costs resulting from the FERC 2005 orders and any subsequent modifications of those orders.  On January 9, 2012, the APSC and LPSC filed protests to the compliance filing.  On January 13, 2012, the Court of Appeals for the DC Circuit held oral argument of the LPSC and CCNO appeals relating to FERC’s acceptance of EAI’s and EMI’s notices to withdraw from the System Agreement. Background:  The System Agreement case addresses the allocation of production costs among the Utility operating companies.  In 2005, FERC issued orders that require each Utility operating company’s production costs to be within        +/- 11 percent of System average production costs and set 2007 as the first possible year of payments among the Utility operating companies, based on calendar year 2006 actual production costs.  Upon appeal, the DC Circuit remanded to FERC to reconsider its conclusion that it did not have the authority to order refunds and to also reconsider its decision to delay implementation of the bandwidth remedy. On October 20, 2011, FERC issued an order addressing the DC Circuit’s directive that FERC reconsider two issues in the original bandwidth proceeding.  On the first issue, FERC concluded that it would not require refunds for the 20-month period from September 13, 2001 through May 2, 2003.  On the second issue, the FERC order concluded that the prospective bandwidth remedy should begin on June 1, 2005 (the date of its initial order in the proceeding), rather than on January 1, 2006 as it had previously ordered. Since 2007, bandwidth filings have required payments from EAI to various other Utility operating companies totaling approximately $1.2 billion.  FERC set each of the 2007 through 2011 bandwidth filings for hearing following protests from retail regulatory commissions and / or third parties.  Requests for rehearing and clarification of a final FERC order in the 2007 bandwidth proceeding were filed.  All other bandwidth proceedings remain outstanding. On November 19, 2009, FERC accepted EAI’s and EMI’s notices to withdraw from the System Agreement effective December 2013 and November 2015, respectively.�� On February 1, 2011, FERC denied the LPSC and CCNO’s request for rehearing of this order.  The LPSC and CCNO subsequently appealed this decision to the United States Court of Appeals for the DC Circuit.

(aa)  Applies to sales made under Entergy’s FERC-jurisdictional OATT.

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

D.   Financial and Historical Performance Measures

Appendix D-1 provides comparative financial performance measures for the current quarter.  Appendix D-2 provides historical financial performance measures and operating performance metrics for the trailing eight quarters.  Financial performance measures in both tables include those calculated and presented in accordance with 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 2011 vs. 2010 (see Appendix Ffor definitions of certain measures)
For 12 months ending December 31	2011	2010	Change
GAAP Measures
Return on average invested capital – as-reported	8.0%	7.8%	0.2%
Return on average common equity – as-reported	15.4%	14.6%	0.8%
Net margin – as-reported	12.0%	10.9%	1.1%
Cash flow interest coverage	7.1	7.8	(0.7)
Book value per share	$50.81	$47.53	$3.28
End of period shares outstanding (millions)	176.4	178.7	(2.3)
Non-GAAP Measures
Return on average invested capital – operational	8.0%	8.2%	(0.2)%
Return on average common equity – operational	15.6%	15.6%	-
Net margin – operational	12.1%	11.6%	0.5%
As of December 31 ($ in millions)	2011	2010	Change
GAAP Measures
Cash and cash equivalents	694	1,294	(600)
Revolver capacity	2,001	2,354	(353)
Total debt	12,387	11,816	571
Securitization debt	1,071	931	140
Debt to capital ratio	57.3%	57.3%	-
Off-balance sheet liabilities:
Debt of joint ventures  – Entergy’s share	96	107	(11)
Leases – Entergy’s share	508	546	(38)
Total off-balance sheet liabilities	604	653	(49)
Non-GAAP Measures
Debt to capital ratio, excluding securitization debt	55.0%	55.3%	(0.3)%
Total gross liquidity	2,695	3,648	(953)
Net debt to net capital ratio, excluding securitization debt	53.5%	52.1%	1.4%
Net debt to net capital ratio including off-balance sheet liabilities, excluding securitization debt	54.8%	53.8%	1.0%

Appendix D-2: Historical Performance Measures (see Appendix F for definitions of measures)
			1Q10	2Q10	3Q10	4Q10	1Q11	2Q11	3Q11	4Q11	10YTD	11YTD
Financial
		EPS – as-reported ($)	1.12	1.65	2.62	1.26	1.38	1.76	3.53	0.87	6.66	7.55
		Less – special items ($)	(0.21)	(0.06)	(0.14)	(0.04)	-  -	-  -	-  -	(0.07)	(0.44)	(0.07)
		EPS – operational ($)	1.33	1.71	2.76	1.30	1.38	1.76	3.53	0.94	7.10	7.62
	Trailing twelve months
		ROIC – as-reported (%)	7.6	8.1	8.2	7.8	7.7	7.7	8.2	8.0
		ROIC – operational (%)	8.0	8.5	8.7	8.2	7.9	7.9	8.2	8.0
		ROE – as-reported (%)	13.8	14.8	15.5	14.6	14.8	14.8	16.1	15.4
		ROE – operational (%)	14.9	15.8	16.6	15.6	15.3	15.2	16.1	15.6
		Cash flow interest coverage	6.3	6.6	8.0	7.8	7.8	7.6	6.6	7.1
		Debt to capital ratio (%)	57.0	56.6	57.5	57.3	57.6	58.1	57.3	57.3
		Debt to capital ratio, excluding securitization debt (%)	55.2	54.8	55.6	55.3	55.7	56.3	55.1	55.0
		Net debt to net capital ratio, excluding securitization debt (%)	51.3	51.6	50.9	52.1	54.0	55.1	52.8	53.5
Utility
		GWh billed
		Residential	9,645	7,705	12,365	7,750	9,042	7,993	12,376	7,274	37,465	36,684
		Commercial & Governmental	7,064	7,384	9,341	7,504	7,032	7,548	9,344	7,270	31,294	31,194
		Industrial	8,733	9,862	10,276	9,880	9,516	10,140	11,024	10,130	38,751	40,810
		Wholesale	1,317	971	1,063	1,021	947	1,036	1,038	1,090	4,372	4,111
		O&M expense per MWh	$17.29	$19.21	$16.41	$21.18	$17.89	$19.09	$14.93	$21.99	$18.39	$18.22
		Reliability – trailing twelve months
		SAIFI	1.7	1.8	1.8	1.7	1.7	1.7	1.7	1.6
		SAIDI	213	206	197	187	188	201	213	208
Entergy Wholesale Commodities
		Owned Capacity	6,351	6,351	6,351	6,351	6,016	6,016	6,016	6,599	6,351	6,599
		GWh billed	11,128	10,498	10,736	10,320	10,519	10,652	11,284	11,065	42,682	43,520
		Avg. realized revenue per MWh	$58.31	$58.15	$61.51	$58.16	$56.98	$52.32	$55.87	$52.74	$59.04	$54.48
		Non-fuel O&M expense / purchased power per MWh (cc)	$23.90	$26.93	$29.59	$26.74	$24.95	$26.87	$25.32	$25.37	$26.76	$25.62
		EWC Nuclear Operational Measures
		Capacity factor (%)	94	90	91	86	91	91	98	93	90	93
		GWh billed	10,255	9,868	9,888	9,644	9,913	9,993	10,645	10,367	39,655	40,918
		Avg. realized revenue per MWh	$58.72	$57.69	$61.41	$58.80	$57.46	$52.38	$56.07	$53.00	$59.16	$54.73
		Production cost per MWh (cc)	$23.70	$24.40	$27.79	$25.23	$24.01	$25.96	$24.92	$25.92	$25.27	$25.21

(cc)  2010 excludes the effects of the non-utility nuclear spin-off expenses special item at Entergy Wholesale Commodities.

E.   Planned Capital Expenditures

The capital plan for 2012 through 2014 anticipates $7.1 billion for investment, including $3.2 billion of maintenance capital, as shown in Appendix E.  The remaining $3.9 billion is for specific investments and other initiatives such as:

·   Utility:  the Utility’s portfolio transformation strategy including the 620 MW Hot Spring and 450 MW Hinds power plant acquisitions (including planned plant upgrades, transaction costs, and contingencies), an approximate 178 MW uprate project at the Grand Gulf nuclear plant, and Entergy Louisiana’s Ninemile 6 new CCGT project; the steam generator replacement at Entergy Louisiana’s Waterford 3 nuclear unit; transmission upgrades and spending to support the Utility’s plan to join the MISO RTO by December 2013.  Generation capital commitments include minimal investment for environmental compliance projects.

·   Entergy Wholesale Commodities: dry cask storage, nuclear license renewal efforts, component replacement and identified repairs across the fleet, NYPA value sharing, the Indian Point Independent Safety Evaluation, and wedgewire screens at the Indian Point site.

Appendix E:  2012 – 2014 Planned Capital Expenditures
($ in millions) – Prepared January 2012
	2012	2013	2014	Total
Maintenance capital
Utility
Generation	128	129	131	388
Transmission	282	273	255	810
Distribution	433	485	496	1,414
Other	91	89	103	283
Utility Total	934	976	985	2,895
Entergy Wholesale Commodities	90	120	107	317
Maintenance capital subtotal	1,024	1,096	1,092	3,212
Other capital commitments
Utility
Generation	1,428	583	358	2,369
Transmission	170	128	264	562
Distribution	17	11	11	39
Other	45	47	35	127
Utility Total	1,660	769	668	3,097
Entergy Wholesale Commodities	259	241	291	791
Other capital commitments subtotal	1,919	1,010	959	3,888
Total Planned Capital Expenditures	2,943	2,106	2,051	7,100

F.   Definitions

Appendix Fprovides 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
O&M expense per MWh	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 retail customers	Number of customers at end of period
Entergy Wholesale Commodities
Owned capacity	Installed capacity owned and operated by Entergy Wholesale Commodities, including investments in wind generation accounted for under the equity method of accounting; EWC’s 335 MW ownership position in the Harrison County power plant was sold on December 31, 2010; EWC acquired the Rhode Island State Energy Center, a 583 MW natural gas-fired combined-cycle generating plant, on December 20, 2011
GWh billed	Total number of GWh billed to customers, excluding investments in wind generation accounted for under the equity method of accounting
Average realized revenue per MWh	As-reported revenue per MWh billed for Entergy Wholesale Commodities, excluding revenue from the amortization of the Palisades below-market PPA and investments in wind generation accounted for under the equity method of accounting
Non-fuel O&M expense / purchased power per MWh	Operation, maintenance and refueling expenses and purchased power per MWh billed, excluding fuel and investments in wind generation accounted for under the equity method of accounting
Entergy Wholesale Commodities - Nuclear
Capacity factor	Normalized percentage of the period that the nuclear plants generate power
GWh billed	Total number of GWh billed to all customers
Average realized revenue per MWh	As-reported revenue per MWh billed for Entergy Wholesale Commodities’ nuclear business, excluding revenue from the amortization of the Palisades below-market PPA
Production cost per MWh	Fuel and non-fuel operation and maintenance expenses according to accounting standards that directly relate to the production of electricity per MWh (based on net generation)
Refueling outage days	Number of days lost for scheduled refueling outage during the period
Planned TWh of generation	Amount of output expected to be generated by Entergy Wholesale Commodities nuclear units considering plant operating characteristics, outage schedules, and expected market conditions which impact dispatch, assuming timely renewal of plant operating licenses and uninterrupted normal operations at all plants
Percent of planned generation sold forward	Percent of planned generation output sold or purchased forward under contracts, forward physical contracts, forward financial contracts or options that mitigate price uncertainty (consistent with assumptions used in earnings guidance) that may or may not require regulatory approval
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
Offsetting positions	Transactions for the purchase of energy, generally to offset a Firm LD transaction
Planned net MW in operation	Amount of capacity to be available to generate power and/or sell capacity considering uprates planned to be completed during the year
Percent of capacity sold forward	Percent of planned qualified capacity sold to mitigate price uncertainty under physical or financial transactions
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 revenue under contract per MWh or per kW per month	Revenue on a per unit basis at which generation output, capacity, or combination of both is expected to be sold to third parties (including offsetting positions), given existing contract or option exercise prices based on expected dispatch or capacity, excluding the revenue associated with the amortization of the below-market Power Purchase Agreement for Palisades.  Revenue may fluctuate due to factors including positive or negative basis differentials, option premiums and market prices at time of option expiration, costs to convert Firm LD to unit-contingent and other risk management cost.

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 not 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 business joint ventures at Entergy Wholesale Commodities
Leases (Entergy’s share)	Operating leases held by subsidiaries capitalized at implicit interest rate
Debt to capital ratio	Gross debt divided by total capitalization
Securitization debt	Debt associated with securitization bonds issued to recover storm costs from hurricanes Rita, Ike and Gustav at Entergy Texas; the 2009 ice storm at Entergy Arkansas; and investment recovery of costs associated with the cancelled Little Gypsy repowering project at Entergy Louisiana
Financial Measures – Non-GAAP
Operational earnings	As-reported Net Income adjusted to exclude the impact of special items
Adjusted EBITDA	Earnings before interest, income taxes, depreciation and amortization, and interest and investment income excluding decommissioning expense, other than temporary impairment losses on decommissioning trust fund assets, and special items
Return on average invested capital – operational	12-months rolling operational Net Income adjusted to include preferred dividends and tax-effected interest expense divided by average invested capital
Return on average common equity – operational	12-months rolling operational Net Income divided by average common equity
Net margin – operational	12-months rolling operational Net Income divided by 12 months rolling revenue
Total gross liquidity	Sum of cash and revolver capacity
Debt to capital ratio, excluding securitization debt	Gross debt divided by total capitalization, excluding securitization debt
Net debt to net capital ratio, excluding securitization debt	Gross debt less cash and cash equivalents divided by total capitalization less cash and cash equivalents, excluding securitization debt
Net debt to net capital ratio, including off-balance sheet liabilities, excluding securitization debt	Sum of 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, excluding securitization debt

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)
	1Q10	2Q10	3Q10	4Q10	1Q11	2Q11	3Q11	4Q11
As-reported Net Income-rolling 12 months (A)	1,210	1,298	1,336	1,250	1,285	1,285	1,421	1,346
Preferred dividends	20	20	20	20	20	20	20	21
Tax effected interest expense	372	368	358	354	327	320	320	316
As-reported Net Income, rolling 12 months including preferred dividends and tax effected interest expense (B)	1,602	1,686	1,714	1,624	1,632	1,625	1,761	1,683
Special items in prior quarters	(53)	(76)	(71)	(75)	(42)	(32)	(7)	-
Special items in current quarter
Transmission spin-merge	-	-	-	-	-	-	-	(13)
Nuclear spin-off expenses	(40)	(10)	(25)	(7)	-	-	-	-
Total special items (C)	(94)	(87)	(96)	(82)	(42)	(32)	(7)	(13)
Operational earnings, rolling 12 months including preferred dividends and tax effected interest expense (B-C)	1,696	1,773	1,810	1,706	1,674	1,657	1,768	1,696
Operational earnings, rolling 12 months (A-C)	1,304	1,385	1,432	1,332	1,327	1,317	1,428	1,359
Average invested capital (D)	21,149	20,761	20,802	20,781	21,093	21,101	21,509	21,126
Average common equity (E)	8,745	8,769	8,608	8,555	8,698	8,684	8,849	8,729
Operating revenues (F)	10,716	11,058	11,453	11,488	11,269	11,210	11,273	11,229
ROIC – as-reported % (B/D)	7.6	8.1	8.2	7.8	7.7	7.7	8.2	8.0
ROIC – operational % ((B-C)/D)	8.0	8.5	8.7	8.2	7.9	7.9	8.2	8.0
ROE – as-reported % (A/E)	13.8	14.8	15.5	14.6	14.8	14.8	16.1	15.4
ROE – operational % ((A-C)/E)	14.9	15.8	16.6	15.6	15.3	15.2	16.1	15.6
Net margin – as-reported % (A/F)	11.3	11.7	11.7	10.9	11.4	11.5	12.6	12.0
Net margin – operational % ((A-C)/F)	12.2	12.5	12.5	11.6	11.8	11.8	12.7	12.1

Appendix G-2: Reconciliation of GAAP to Non-GAAP Financial Measures – Credit and Liquidity Metrics
($ in millions)
	1Q10	2Q10	3Q10	4Q10	1Q11	2Q11	3Q11	4Q11
Gross debt (A)	12,152	11,853	12,247	11,816	12,018	12,360	12,452	12,387
Less securitization debt (B)	838	829	940	931	910	896	1,086	1,071
Gross debt, excluding securitization  debt (C)	11,314	11,024	11,307	10,885	11,108	11,464	11,366	11,316
Less cash and cash equivalents (D)	1,657	1,336	1,931	1,294	726	530	987	694
Net debt, excluding securitization debt (E)	9,657	9,688	9,376	9,591	10,382	10,934	10,379	10,622
Total capitalization (F)	21,322	20,935	21,290	20,623	20,864	21,268	21,728	21,629
Less securitization debt (B)	838	829	940	931	910	896	1,086	1,071
Total capitalization, excluding securitization debt (G)	20,484	20,106	20,350	19,692	19,954	20,372	20,642	20,558
Less cash and cash equivalents (D)	1,657	1,336	1,931	1,294	726	530	987	694
Net capital, excluding securitization debt (H)	18,827	18,770	18,419	18,398	19,228	19,842	19,655	19,864
Debt to capital ratio % (A/F)	57.0	56.6	57.5	57.3	57.6	58.1	57.3	57.3
Debt to capital ratio, excluding securitization debt % (C/G)	55.2	54.8	55.6	55.3	55.7	56.3	55.1	55.0
Net debt to net capital ratio, excluding securitization debt % (E/H)	51.3	51.6	50.9	52.1	54.0	55.1	52.8	53.5
Off-balance sheet liabilities (I)	644	641	638	653	650	647	645	604
Net debt to net capital ratio including off-balance sheet liabilities, excluding securitization debt % ((E+I)/(H+I))	52.9	53.2	52.5	53.8	55.5	56.5	54.3	54.8
Revolver capacity (J)	1,417	1,338	2,216	2,354	2,258	1,993	2,116	2,001
Gross liquidity (D+J)	3,074	2,674	4,147	3,648	2,984	2,523	3,103	2,695

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

Additional investor information can be accessed online at

www.entergy.com/investor_relations

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

In this news release, and from time to time, Entergy makes certain “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995. Except to the extent required by the federal securities laws, Entergy undertakes no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events, or otherwise.

Forward-looking statements involve a number of risks and uncertainties. There are factors that could cause actual results to differ materially from those expressed or implied in the forward-looking statements, including (a) those factors discussed in: (i) Entergy’s Form 10-K for the year ended December 31, 2010; (ii) Entergy’s Form 10-Q for the quarters ended March 31, 2011, June 30, 2011 and September 30, 2011; and (iii) Entergy’s other reports and filings made under the Securities Exchange Act of 1934; (b) uncertainties associated with rate proceedings, formula rate plans and other cost recovery mechanisms; (c) uncertainties associated with efforts to remediate the effects of major storms and recover related restoration costs; (d) nuclear plant relicensing, operating and regulatory risks, including any changes resulting from the nuclear crisis in Japan following its catastrophic earthquake and tsunami; (e) legislative and regulatory actions and risks and uncertainties associated with claims or litigation by or against Entergy and its subsidiaries; (f) conditions in commodity and capital markets during the periods covered by the forward-looking statements, in addition to other factors described elsewhere in this release and subsequent securities filings, and (g) risks inherent in the proposed spin-off and subsequent merger of Entergy’s electric transmission business into a subsidiary of ITC Holdings Corp. Entergy cannot provide any assurances that the spin-off and merger transaction will be completed and cannot give any assurance as to the terms on which such transaction will be consummated. The spin-off and merger transaction is subject to certain conditions precedent, including regulatory approvals and approval by ITC Holdings Corp. shareholders.

VIII.   Financial Statements

Entergy Corporation
Consolidating Balance Sheet
December 31, 2011
(Dollars in thousands)
(Unaudited)
	Utility			Entergy Wholesale Commodities			Parent & Other			Consolidated
ASSETS
CURRENT ASSETS
Cash and cash equivalents:
Cash	$	77,711		$	3,754		$	3		$	81,468
Temporary cash investments		281,921			318,633			12,416			612,970
Total cash and cash equivalents		359,632			322,387			12,419			694,438
Securitization recovery trust account		50,304			-			-			50,304
Notes receivable		-			1,083,918			(1,083,918	)		-
Accounts receivable:
Customer		403,321			165,237			-			568,558
Allowance for doubtful accounts		(30,827	)		(332	)		-			(31,159	)
Associated companies		42,847			99,162			(142,009	)		-
Other		151,956			13,376			854			166,186
Accrued unbilled revenues		297,265			1,018			-			298,283
Total accounts receivable		864,562			278,461			(141,155	)		1,001,868
Deferred fuel costs		209,776			-			-			209,776
Accumulated deferred income taxes		141,804			4,655			(136,603	)		9,856
Fuel inventory - at average cost		196,246			5,886			-			202,132
Materials and supplies - at average cost		559,230			335,526			-			894,756
Deferred nuclear refueling outage costs		103,788			127,243			-			231,031
System agreement cost equalization		24,370			-			-			24,370
Prepaid taxes		-			79,165			(79,165	)		-
Prepayments and other		67,285			222,049			2,408			291,742
TOTAL		2,576,997			2,459,290			(1,426,014	)		3,610,273
OTHER PROPERTY AND INVESTMENTS
Investment in affiliates - at equity		1,147,271			44,764			(1,147,159	)		44,876
Decommissioning trust funds		1,639,951			2,148,080			-			3,788,031
Non-utility property - at cost (less accumulated depreciation)		174,029			71,888			14,519			260,436
Other		374,379			12,044			30,000			416,423
TOTAL		3,335,630			2,276,776			(1,102,640	)		4,509,766
PROPERTY, PLANT, AND EQUIPMENT
Electric		34,487,985			4,894,128			3,411			39,385,524
Property under capital lease		809,449			-			-			809,449
Natural gas		343,111			439			-			343,550
Construction work in progress		1,420,163			358,902			658			1,779,723
Nuclear fuel		801,972			744,195			-			1,546,167
TOTAL PROPERTY, PLANT AND EQUIPMENT		37,862,680			5,997,664			4,069			43,864,413
Less - accumulated depreciation and amortization		17,238,272			1,016,507			349			18,255,128
PROPERTY, PLANT AND EQUIPMENT - NET		20,624,408			4,981,157			3,720			25,609,285
DEFERRED DEBITS AND OTHER ASSETS
Regulatory assets:
Regulatory asset for income taxes - net		799,006			-			-			799,006
Other regulatory assets		4,636,871			-			-			4,636,871
Deferred fuel costs		172,202			-			-			172,202
Goodwill		374,099			3,073			-			377,172
Accumulated deferred income taxes		4,313			9,232			5,458			19,003
Other		198,593			803,552			(46,454	)		955,691
TOTAL		6,185,084			815,857			(40,996	)		6,959,945
					-
TOTAL ASSETS	$	32,722,119		$	10,533,080		$	(2,565,930	)	$	40,689,269
*Totals may not foot due to rounding.

Entergy Corporation
Consolidating Balance Sheet
December 31, 2011
(Dollars in thousands)
(Unaudited)
	Utility			Entergy Wholesale Commodities		Parent & Other			Consolidated
LIABILITIES AND SHAREHOLDERS' EQUITY
CURRENT LIABILITIES
Currently maturing long-term debt	$	245,472		$	27,261	$	1,920,000		$	2,192,733
Notes payable and commercial paper:
Associated companies		-			138,862		(138,862	)		-
Other		108,331			-		-			108,331
Account payable:
Associated companies		14,839			36,878		(51,717	)		-
Other		787,516			280,663		917			1,069,096
Customer deposits		351,741			-		-			351,741
Taxes accrued		569,641			-		(291,406	)		278,235
Accumulated deferred income taxes		54,592			42,613		2,724			99,929
Interest accrued		169,710			490		13,312			183,512
Deferred fuel costs		255,839			-		-			255,839
Obligations under capital leases		3,631			-		-			3,631
Pension and other postretirement liabilities		37,858			6,173		-			44,031
System agreement cost equalization		67,660			-		-			67,660
Other		114,083			158,277		11,171			283,531
TOTAL		2,780,913			691,217		1,466,139			4,938,269
NON-CURRENT LIABILITIES
Accumulated deferred income taxes and taxes accrued		6,680,438			824,393		591,621			8,096,452
Accumulated deferred investment tax credits		284,747			-		-			284,747
Obligations under capital leases		38,421			-		-			38,421
Other regulatory liabilities		737,403			-		(9,210	)		728,193
Decommissioning and retirement cost liabilities		1,803,665			1,492,905		-			3,296,570
Accumulated provisions		379,331			1,849		4,332			385,512
Pension and other postretirement liabilities		2,463,493			670,164		-			3,133,657
Long-term debt		8,936,342			107,744		999,627			10,043,713
Other		651,919			639,552		(789,517	)		501,954
TOTAL		21,975,759			3,736,607		796,853			26,509,219
Subsidiaries' preferred stock without sinking fund		186,510			55,399		(55,398	)		186,511
EQUITY
Common Shareholders' Equity:
Common stock, $.01 par value, authorized 500,000,000 shares;
issued 254,752,788 shares in 2011		2,161,268			327,937		(2,486,657	)		2,548
Paid-in capital		2,416,634			1,499,406		1,444,642			5,360,682
Retained earnings		3,417,829			4,118,292		1,910,839			9,446,960
Accumulated other comprehensive income (loss)		(190,794	)		104,222		(81,880	)		(168,452	)
Less - treasury stock, at cost (78,396,988 shares in 2011)		120,000			-		5,560,468			5,680,468
Total common shareholders' equity		7,684,937			6,049,857		(4,773,524	)		8,961,270
Subsidiaries' preferred stock without sinking fund		94,000			-		-			94,000
TOTAL		7,778,937			6,049,857		(4,773,524	)		9,055,270
TOTAL LIABILITIES AND EQUITY	$	32,722,119		$	10,533,080	$	(2,565,930	)	$	40,689,269
*Totals may not foot due to rounding.

Entergy Corporation
Consolidating Balance Sheet
December 31, 2010
(Dollars in thousands)
(Unaudited)
	Utility			Entergy Wholesale Commodities			Parent & Other			Consolidated
ASSETS
CURRENT ASSETS
Cash and cash equivalents:
Cash	$	70,182		$	5,249		$	859		$	76,290
Temporary cash investments		751,403			448,541			18,238			1,218,182
Total cash and cash equivalents		821,585			453,790			19,097			1,294,472
Securitization recovery trust account		43,044			-			-			43,044
Notes receivable		-			1,065,356			(1,065,356	)		-
Accounts receivable:
Customer		385,383			217,413			-			602,796
Allowance for doubtful accounts		(31,575	)		(202	)		-			(31,777	)
Associated companies		20,214			66,807			(87,021	)		-
Other		150,369			10,893			400			161,662
Accrued unbilled revenues		302,787			114			-			302,901
Total accounts receivable		827,178			295,025			(86,621	)		1,035,582
Deferred fuel costs		64,659			-			-			64,659
Accumulated deferred income taxes		8,472			-			-			8,472
Fuel inventory - at average cost		205,258			2,262			-			207,520
Materials and supplies - at average cost		548,758			318,150			-			866,908
Deferred nuclear refueling outage costs		64,463			153,960			-			218,423
System agreement cost equalization		52,160			-			-			52,160
Prepaid taxes		190,349			111,919			(461	)		301,807
Prepayments and other		64,127			174,854			7,055			246,036
TOTAL		2,890,053			2,575,316			(1,126,286	)		4,339,083
OTHER PROPERTY AND INVESTMENTS
Investment in affiliates - at equity		1,147,271			291,453			(1,398,027	)		40,697
Decommissioning trust funds		1,542,832			2,052,884			-			3,595,716
Non-utility property - at cost (less accumulated depreciation)		166,671			72,869			18,307			257,847
Other		364,937			11,009			30,000			405,946
TOTAL		3,221,711			2,428,215			(1,349,720	)		4,300,206
PROPERTY, PLANT, AND EQUIPMENT
Electric		33,007,394			4,142,255			3,412			37,153,061
Property under capital lease		800,078			-			-			800,078
Natural gas		330,168			440			-			330,608
Construction work in progress		1,300,207			360,689			664			1,661,560
Nuclear fuel		760,140			617,822			-			1,377,962
TOTAL PROPERTY, PLANT AND EQUIPMENT		36,197,987			5,121,206			4,076			41,323,269
Less - accumulated depreciation and amortization		16,669,910			804,695			309			17,474,914
PROPERTY, PLANT AND EQUIPMENT - NET		19,528,077			4,316,511			3,767			23,848,355
DEFERRED DEBITS AND OTHER ASSETS
Regulatory assets:
Regulatory asset for income taxes - net		845,725			-			-			845,725
Other regulatory assets		3,838,237			-			-			3,838,237
Deferred fuel costs		172,202			-			-			172,202
Goodwill		374,099			3,073			-			377,172
Accumulated deferred income taxes		4,310			8,450			41,763			54,523
Other		205,826			771,252			(67,305	)		909,773
TOTAL		5,440,399			782,775			(25,542	)		6,197,632
					-
TOTAL ASSETS	$	31,080,240		$	10,102,817		$	(2,497,781	)	$	38,685,276
*Totals may not foot due to rounding.

Entergy Corporation
Consolidating Balance Sheet
December 31, 2010
(Dollars in thousands)
(Unaudited)
	Utility			Entergy Wholesale Commodities		Parent & Other			Consolidated
LIABILITIES AND SHAREHOLDERS' EQUITY
CURRENT LIABILITIES
Currently maturing long-term debt	$	184,291		$	29,257	$	86,000		$	299,548
Notes payable and commercial paper:
Associated companies		-			144,497		(144,497	)		-
Other		154,135			-		-			154,135
Account payable:
Associated companies		9,696			13,420		(23,116	)		-
Other		878,584			300,235		2,280			1,181,099
Customer deposits		335,058			-		-			335,058
Taxes accrued		-			-		-			-
Accumulated deferred income taxes		(8,062	)		49,522		7,847			49,307
Interest accrued		201,799			669		15,217			217,685
Deferred fuel costs		166,409			-		-			166,409
Obligations under capital leases		3,388			-		-			3,388
Pension and other postretirement liabilities		34,283			5,579		-			39,862
System agreement cost equalization		52,160			-		-			52,160
Other		78,689			193,497		5,412			277,598
TOTAL		2,090,430			736,676		(50,857	)		2,776,249
NON-CURRENT LIABILITIES
Accumulated deferred income taxes and taxes accrued		7,514,297			924,485		134,864			8,573,646
Accumulated deferred investment tax credits		292,330			-		-			292,330
Obligations under capital leases		42,078			-		-			42,078
Other regulatory liabilities		539,026			-		-			539,026
Decommissioning and retirement cost liabilities		1,728,469			1,420,010		-			3,148,479
Accumulated provisions		388,081			2,595		4,574			395,250
Pension and other postretirement liabilities		1,700,368			474,996		-			2,175,364
Long-term debt		8,553,358			132,143		2,631,656			11,317,157
Other		712,060			696,049		(789,550	)		618,559
TOTAL		21,470,067			3,650,278		1,981,544			27,101,889
Subsidiaries' preferred stock without sinking fund		186,510			85,985		(55,757	)		216,738
EQUITY
Common Shareholders' Equity:
Common stock, $.01 par value, authorized 500,000,000 shares;
issued 254,752,788 shares in 2010		2,161,268			398,987		(2,557,707	)		2,548
Paid-in capital		2,416,633			1,566,166		1,384,675			5,367,474
Retained earnings		2,889,317			3,594,952		2,205,132			8,689,401
Accumulated other comprehensive income (loss)		(107,985	)		69,773		-			(38,212	)
Less - treasury stock, at cost (76,006,920 shares in 2010)		120,000			-		5,404,811			5,524,811
Total common shareholders' equity		7,239,233			5,629,878		(4,372,711	)		8,496,400
Subsidiaries' preferred stock without sinking fund		94,000			-		-			94,000
TOTAL		7,333,233			5,629,878		(4,372,711	)		8,590,400
TOTAL LIABILITIES AND EQUITY	$	31,080,240		$	10,102,817	$	(2,497,781	)	$	38,685,276
*Totals may not foot due to rounding.

Entergy Corporation
Consolidating Balance Sheet
December 31, 2011 vs December 31, 2010
(Dollars in thousands)
(Unaudited)
	Utility			Entergy Wholesale Commodities			Parent & Other			Consolidated
ASSETS
CURRENT ASSETS
Cash and cash equivalents:
Cash	$	7,529		$	(1,495	)	$	(856	)	$	5,178
Temporary cash investments		(469,482	)		(129,908	)		(5,822	)		(605,212	)
Total cash and cash equivalents		(461,953	)		(131,403	)		(6,678	)		(600,034	)
Securitization recovery trust account		7,260			-			-			7,260
Notes receivable		-			18,562			(18,562	)		-
Accounts receivable:
Customer		17,938			(52,176	)		-			(34,238	)
Allowance for doubtful accounts		748			(130	)		-			618
Associated companies		22,633			32,355			(54,988	)		-
Other		1,587			2,483			454			4,524
Accrued unbilled revenues		(5,522	)		904			-			(4,618	)
Total accounts receivable		37,384			(16,564	)		(54,534	)		(33,714	)
Deferred fuel costs		145,117			-			-			145,117
Accumulated deferred income taxes		133,332			4,655			(136,603	)		1,384
Fuel inventory - at average cost		(9,012	)		3,624			-			(5,388	)
Materials and supplies - at average cost		10,472			17,376			-			27,848
Deferred nuclear refueling outage costs		39,325			(26,717	)		-			12,608
System agreement cost equalization		(27,790	)		-			-			(27,790	)
Prepaid taxes		(190,349	)		(32,754	)		(78,704	)		(301,807	)
Prepayments and other		3,158			47,195			(4,647	)		45,706
TOTAL		(313,056	)		(116,026	)		(299,728	)		(728,810	)
OTHER PROPERTY AND INVESTMENTS
Investment in affiliates - at equity		-			(246,689	)		250,868			4,179
Decommissioning trust funds		97,119			95,196			-			192,315
Non-utility property - at cost (less accumulated depreciation)		7,358			(981	)		(3,788	)		2,589
Other		9,442			1,035			-			10,477
TOTAL		113,919			(151,439	)		247,080			209,560
PROPERTY, PLANT, AND EQUIPMENT
Electric		1,480,591			751,873			(1	)		2,232,463
Property under capital lease		9,371			-			-			9,371
Natural gas		12,943			(1	)		-			12,942
Construction work in progress		119,956			(1,787	)		(6	)		118,163
Nuclear fuel		41,832			126,373			-			168,205
TOTAL PROPERTY, PLANT AND EQUIPMENT		1,664,693			876,458			(7	)		2,541,144
Less - accumulated depreciation and amortization		568,362			211,812			40			780,214
PROPERTY, PLANT AND EQUIPMENT - NET		1,096,331			664,646			(47	)		1,760,930
DEFERRED DEBITS AND OTHER ASSETS
Regulatory assets:
Regulatory asset for income taxes - net		(46,719	)		-			-			(46,719	)
Other regulatory assets		798,634			-			-			798,634
Deferred fuel costs		-			-			-			-
Goodwill		-			-			-			-
Accumulated deferred income taxes		3			782			(36,305	)		(35,520	)
Other		(7,233	)		32,300			20,851			45,918
TOTAL		744,685			33,082			(15,454	)		762,313
TOTAL ASSETS	$	1,641,879		$	430,263		$	(68,149	)	$	2,003,993
*Totals may not foot due to rounding.

Entergy Corporation
Consolidating Balance Sheet
December 31, 2011 vs December 31, 2010
(Dollars in thousands)
(Unaudited)
	Utility			Entergy Wholesale Commodities			Parent & Other			Consolidated
LIABILITIES AND SHAREHOLDERS' EQUITY
CURRENT LIABILITIES
Currently maturing long-term debt	$	61,181		$	(1,996	)	$	1,834,000		$	1,893,185
Notes payable and commercial paper:
Associated companies		-			(5,635	)		5,635			-
Other		(45,804	)		-			-			(45,804	)
Account payable:
Associated companies		5,143			23,458			(28,601	)		-
Other		(91,068	)		(19,572	)		(1,363	)		(112,003	)
Customer deposits		16,683			-			-			16,683
Taxes accrued		569,641			-			(291,406	)		278,235
Accumulated deferred income taxes		62,654			(6,909	)		(5,123	)		50,622
Interest accrued		(32,089	)		(179	)		(1,905	)		(34,173	)
Deferred fuel costs		89,430			-			-			89,430
Obligations under capital leases		243			-			-			243
Pension and other postretirement liabilities		3,575			594			-			4,169
System agreement cost equalization		15,500			-			-			15,500
Other		35,394			(35,220	)		5,759			5,933
TOTAL		690,483			(45,459	)		1,516,996			2,162,020
NON-CURRENT LIABILITIES
Accumulated deferred income taxes and taxes accrued		(833,859	)		(100,092	)		456,757			(477,194	)
Accumulated deferred investment tax credits		(7,583	)		-			-			(7,583	)
Obligations under capital leases		(3,657	)		-			-			(3,657	)
Other regulatory liabilities		198,377			-			(9,210	)		189,167
Decommissioning and retirement cost liabilities		75,196			72,895			-			148,091
Accumulated provisions		(8,750	)		(746	)		(242	)		(9,738	)
Pension and other postretirement liabilities		763,125			195,168			-			958,293
Long-term debt		382,984			(24,399	)		(1,632,029	)		(1,273,444	)
Other		(60,141	)		(56,497	)		33			(116,605	)
TOTAL		505,692			86,329			(1,184,691	)		(592,670	)
Subsidiaries' preferred stock without sinking fund		-			(30,586	)		359			(30,227	)
EQUITY
Common Shareholders' Equity:
Common stock, $.01 par value, authorized 500,000,000 shares;
issued 254,752,788 shares in 2011 and in 2010		-			(71,050	)		71,050			-
Paid-in capital		1			(66,760	)		59,967			(6,792	)
Retained earnings		528,512			523,340			(294,293	)		757,559
Accumulated other comprehensive income (loss)		(82,809	)		34,449			(81,880	)		(130,240	)
Less - treasury stock, at cost		-			-			155,657			155,657
Total common shareholders' equity		445,704			419,979			(400,813	)		464,870
Subsidiaries' preferred stock without sinking fund		-			-			-			-
TOTAL		445,704			419,979			(400,813	)		464,870
TOTAL LIABILITIES AND EQUITY	$	1,641,879		$	430,263		$	(68,149	)	$	2,003,993
*Totals may not foot due to rounding.

Entergy Corporation
Consolidating Income Statement
Three Months Ended December 31, 2011
(Dollars in thousands)
(Unaudited)
	Utility			Entergy Wholesale Commodities			Parent & Other			Consolidated
OPERATING REVENUES
Electric	$	1,862,737		$	-		$	(757	)	$	1,861,980
Natural gas		39,366			-			-			39,366
Competitive businesses		-			594,334			(6,648	)		587,686
Total		1,902,103			594,334			(7,405	)		2,489,032
OPERATING EXPENSES
Operating and Maintenance:
Fuel, fuel related expenses, and gas purchased for resale		489,166			82,845			(304	)		571,707
Purchased power		278,926			7,116			(10,255	)		275,787
Nuclear refueling outage expenses		26,568			37,533			-			64,101
Other operation and maintenance		539,871			236,089			14,733			790,692
Decommissioning		27,776			(4,411	)		-			23,366
Taxes other than income taxes		101,388			27,748			398			129,533
Depreciation and amortization		241,774			46,534			1,223			289,531
Other regulatory charges (credits) - net		1,620			-			-			1,620
Total		1,707,089			433,454			5,795			2,146,337
Gain on sale of business		-			-			-			-
OPERATING INCOME		195,014			160,880			(13,200	)		342,695
OTHER INCOME (DEDUCTIONS)
Allowance for equity funds used during construction		24,747			-			-			24,747
Interest and investment income		37,318			38,901			(43,131	)		33,088
Other than temporary impairment losses		-			-			-			-
Miscellaneous - net		(8,122	)		(9,522	)		(1,129	)		(18,773	)
Total		53,943			29,379			(44,260	)		39,062
INTEREST EXPENSE
Interest expense		128,698			5,933			7,405			142,036
Allowance for borrowed funds used during construction		(10,496	)		-			-			(10,496	)
Total		118,202			5,933			7,405			131,540
INCOME BEFORE INCOME TAXES		130,755			184,326			(64,865	)		250,217
Income taxes		(43,257	)		12,121			121,326			90,190
CONSOLIDATED NET INCOME		174,012			172,205			(186,191	)		160,027
Preferred dividend requirements of subsidiaries		4,332			1,196			358			5,887
NET INCOME ATTRIBUTABLE TO ENTERGY CORPORATION	$	169,680		$	171,009		$	(186,549	)	$	154,140
EARNINGS PER AVERAGE COMMON SHARE:
BASIC	$	0.96		$	0.97		$	(1.06	)	$	0.87
DILUTED	$	0.96		$	0.97		$	(1.06	)	$	0.87
AVERAGE NUMBER OF COMMON SHARES OUTSTANDING:
BASIC											176,161,769
DILUTED											177,082,570
*Totals may not foot due to rounding.

Entergy Corporation
Consolidating Income Statement
Three Months Ended December 31, 2010
(Dollars in thousands)
(Unaudited)
	Utility			Entergy Wholesale Commodities			Parent & Other			Consolidated
OPERATING REVENUES
Electric	$	1,881,436		$	-		$	(591	)	$	1,880,845
Natural gas		43,232			-			-			43,232
Competitive businesses		-			611,763			(2,736	)		609,027
Total		1,924,668			611,763			(3,327	)		2,533,104
OPERATING EXPENSES
Operating and Maintenance:
Fuel, fuel related expenses, and gas purchased for resale		510,804			68,989			(288	)		579,505
Purchased power		278,786			10,925			(6,351	)		283,361
Nuclear refueling outage expenses		26,710			38,017			-			64,728
Other operation and maintenance		527,152			237,297			(6,428	)		758,020
Decommissioning		26,716			27,598			-			54,313
Taxes other than income taxes		108,415			25,548			(262	)		133,702
Depreciation and amortization		236,624			42,673			1,205			280,502
Other regulatory charges (credits) - net		29,366			-			-			29,366
Total		1,744,573			451,047			(12,124	)		2,183,497
Gain on sale of business		-			44,173			-			44,173
OPERATING INCOME		180,095			204,889			8,797			393,780
OTHER INCOME (DEDUCTIONS)
Allowance for equity funds used during construction		13,391			-			-			13,391
Interest and investment income		63,591			38,551			(39,811	)		62,331
Other than temporary impairment losses		-			(123	)		-			(123	)
Miscellaneous - net		(8,800	)		(4,992	)		(2,281	)		(16,073	)
Total		68,182			33,436			(42,092	)		59,526
INTEREST EXPENSE
Interest expense		130,729			4,689			11,275			146,692
Allowance for borrowed funds used during construction		(7,705	)		-			-			(7,705	)
Total		123,024			4,689			11,275			138,987
INCOME BEFORE INCOME TAXES		125,253			233,636			(44,570	)		314,319
Income taxes		6,620			83,033			(8,641	)		81,012
CONSOLIDATED NET INCOME		118,633			150,603			(35,929	)		233,307
Preferred dividend requirements of subsidiaries		4,332			683			-			5,015
NET INCOME ATTRIBUTABLE TO ENTERGY CORPORATION	$	114,301		$	149,920		$	(35,929	)	$	228,292
EARNINGS PER AVERAGE COMMON SHARE:
BASIC	$	0.63		$	0.84		$	(0.20	)	$	1.27
DILUTED	$	0.63		$	0.83		$	(0.20	)	$	1.26
AVERAGE NUMBER OF COMMON SHARES OUTSTANDING:
BASIC											180,199,914
DILUTED											181,577,475
*Totals may not foot due to rounding.

Entergy Corporation
Consolidating Income Statement
Three Months Ended December 31, 2011 vs. 2010
(Dollars in thousands)
(Unaudited)
	Utility			Entergy Wholesale Commodities			Parent & Other			Consolidated
OPERATING REVENUES
Electric	$	(18,699	)	$	-		$	(166	)	$	(18,865	)
Natural gas		(3,866	)		-			-			(3,866	)
Competitive businesses		-			(17,429	)		(3,912	)		(21,341	)
Total		(22,565	)		(17,429	)		(4,078	)		(44,072	)
OPERATING EXPENSES
Operating and Maintenance:
Fuel, fuel related expenses, and gas purchased for resale		(21,638	)		13,856			(16	)		(7,798	)
Purchased power		140			(3,809	)		(3,904	)		(7,574	)
Nuclear refueling outage expenses		(142	)		(484	)		-			(627	)
Other operation and maintenance		12,719			(1,208	)		21,161			32,672
Decommissioning		1,060			(32,009	)		-			(30,947	)
Taxes other than income taxes		(7,027	)		2,200			660			(4,169	)
Depreciation and amortization		5,150			3,861			18			9,029
Other regulatory charges (credits )- net		(27,746	)		-			-			(27,746	)
Total		(37,484	)		(17,593	)		17,919			(37,160	)
Gain on sale of business		-			(44,173	)		-			(44,173	)
OPERATING INCOME		14,919			(44,009	)		(21,997	)		(51,085	)
OTHER INCOME (DEDUCTIONS)
Allowance for equity funds used during construction		11,356			-			-			11,356
Interest and investment income		(26,273	)		350			(3,320	)		(29,243	)
Other than temporary impairment losses		-			123			-			123
Miscellaneous - net		678			(4,530	)		1,152			(2,700	)
Total		(14,239	)		(4,057	)		(2,168	)		(20,464	)
INTEREST EXPENSE
Interest expense		(2,031	)		1,244			(3,870	)		(4,656	)
Allowance for borrowed funds used during construction		(2,791	)		-			-			(2,791	)
Total		(4,822	)		1,244			(3,870	)		(7,447	)
INCOME BEFORE INCOME TAXES		5,502			(49,310	)		(20,295	)		(64,102	)
Income taxes		(49,877	)		(70,912	)		129,967			9,178
CONSOLIDATED NET INCOME		55,379			21,602			(150,262	)		(73,280	)
Preferred dividend requirements of subsidiaries		-			513			358			872
NET INCOME ATTRIBUTABLE TO ENTERGY CORPORATION	$	55,379		$	21,089		$	(150,620	)	$	(74,152	)
EARNINGS PER AVERAGE COMMON SHARE:
BASIC	$	0.33		$	0.13		$	(0.86	)	$	(0.40	)
DILUTED	$	0.33		$	0.14		$	(0.86	)	$	(0.39	)
*Totals may not foot due to rounding.

Entergy Corporation
Consolidating Income Statement
Year to Date December 31, 2011
(Dollars in thousands)
(Unaudited)
	Utility				Entergy Wholesale Commodities			Parent & Other			Consolidated
OPERATING REVENUES
Electric	$	8,676,009			$	-		$	(2,492	)	$	8,673,517
Natural gas		165,819				-			-			165,819
Competitive businesses		-				2,413,773			(24,036	)		2,389,737
Total		8,841,828				2,413,773			(26,528	)		11,229,073
OPERATING EXPENSES
Operating and Maintenance:
Fuel, fuel related expenses, and gas purchased for resale		2,183,559				309,917			(762	)		2,492,714
Purchased power		1,548,276				58,971			(42,280	)		1,564,967
Nuclear refueling outage expenses		105,000				150,617			-			255,618
Other operation and maintenance		1,950,567				905,453			11,739			2,867,758
Decommissioning		109,144				81,450			-			190,595
Taxes other than income taxes		431,619				102,961			1,446			536,026
Depreciation and amortization		918,453				179,188			4,561			1,102,202
Other regulatory charges (credits) - net		205,959				-			-			205,959
Total		7,452,577				1,788,557			(25,296	)		9,215,839
Gain on sale of business		-				-			-			-
OPERATING INCOME		1,389,251				625,216			(1,232	)		2,013,234
OTHER INCOME (DEDUCTIONS)
Allowance for equity funds used during construction		84,305				-			-			84,305
Interest and investment income		158,737				136,492			(166,095	)		129,134
Other than temporary impairment losses		-				(140	)		-			(140	)
Miscellaneous - net		(25,377	)			(23,637	)		(10,257	)		(59,271	)
Total		217,665				112,715			(176,352	)		154,028
INTEREST EXPENSE
Interest expense		493,632				20,634			37,255			551,521
Allowance for borrowed funds used during construction		(37,893	)			-			-			(37,894	)
Total		455,739				20,634			37,255			513,627
INCOME BEFORE INCOME TAXES		1,151,177				717,297			(214,839	)		1,653,635
Income taxes		27,311				225,456			33,496			286,263
CONSOLIDATED NET INCOME		1,123,866				491,841			(248,335	)		1,367,372
Preferred dividend requirements of subsidiaries		17,329				3,245			359			20,933
NET INCOME ATTRIBUTABLE TO ENTERGY CORPORATION	$	1,106,537			$	488,596		$	(248,694	)	$	1,346,439
EARNINGS PER AVERAGE COMMON SHARE:
BASIC	$	6.24			$	2.75		$	(1.40	)	$	7.59
DILUTED	$	6.20			$	2.74		$	(1.39	)	$	7.55
AVERAGE NUMBER OF COMMON SHARES OUTSTANDING:
BASIC												177,430,208
DILUTED												178,370,695
*Totals may not foot due to rounding.				��

Entergy Corporation
Consolidating Income Statement
Year to Date December 31, 2010
(Dollars in thousands)
(Unaudited)
	Utility			Entergy Wholesale Commodities			Parent & Other			Consolidated
OPERATING REVENUES
Electric	$	8,743,674		$	-		$	(3,037	)	$	8,740,637
Natural gas		197,658			-			-			197,658
Competitive businesses		-			2,566,156			(16,874	)		2,549,282
Total		8,941,332			2,566,156			(19,911	)		11,487,577
OPERATING EXPENSES
Operating and Maintenance:
Fuel, fuel related expenses, and gas purchased for resale		2,217,265			302,860			(1,544	)		2,518,582
Purchased power		1,628,166			62,513			(31,262	)		1,659,416
Nuclear refueling outage expenses		108,199			147,924			-			256,123
Other operation and maintenance		1,948,892			1,047,041			(26,531	)		2,969,402
Decommissioning		104,258			107,478			-			211,736
Taxes other than income taxes		431,371			101,878			1,049			534,299
Depreciation and amortization		902,127			163,180			4,588			1,069,894
Other regulatory charges (credits) - net		44,921			-			-			44,921
Total		7,385,199			1,932,874			(53,700	)		9,264,373
Gain on sale of business		-			44,173			-			44,173
OPERATING INCOME		1,556,133			677,455			33,789			2,267,377
OTHER INCOME (DEDUCTIONS)
Allowance for equity funds used during construction		59,381			-			-			59,381
Interest and investment income		182,493			171,158			(168,196	)		185,455
Other than temporary impairment losses		-			(1,378	)		-			(1,378	)
Miscellaneous - net		(20,821	)		(17,347	)		(9,956	)		(48,124	)
Total		221,053			152,433			(178,152	)		195,334
INTEREST EXPENSE
Interest expense		528,220			71,817			10,109			610,146
Allowance for borrowed funds used during construction		(34,979	)		-			-			(34,979	)
Total		493,241			71,817			10,109			575,167
INCOME BEFORE INCOME TAXES		1,283,945			758,071			(154,472	)		1,887,544
Income taxes		454,227			268,649			(105,637	)		617,239
CONSOLIDATED NET INCOME		829,718			489,422			(48,835	)		1,270,305
Preferred dividend requirements of subsidiaries		17,331			2,732			-			20,063
NET INCOME ATTRIBUTABLE TO ENTERGY CORPORATION	$	812,387		$	486,690		$	(48,835	)	$	1,250,242
EARNINGS PER AVERAGE COMMON SHARE:
BASIC	$	4.37		$	2.61		$	(0.26	)	$	6.72
DILUTED	$	4.33		$	2.59		$	(0.26	)	$	6.66
AVERAGE NUMBER OF COMMON SHARES OUTSTANDING:
BASIC											186,010,452
DILUTED											187,814,235
*Totals may not foot due to rounding.

Entergy Corporation
Consolidating Income Statement
Year to Date December 31, 2011 vs. 2010
(Dollars in thousands)
(Unaudited)
	Utility			Entergy Wholesale Commodities			Parent & Other			Consolidated
OPERATING REVENUES
Electric	$	(67,665	)	$	-		$	545		$	(67,120	)
Natural gas		(31,839	)		-			-			(31,839	)
Competitive businesses		-			(152,383	)		(7,162	)		(159,545	)
Total		(99,504	)		(152,383	)		(6,617	)		(258,504	)
OPERATING EXPENSES
Operating and Maintenance:
Fuel, fuel related expenses, and gas purchased for resale		(33,706	)		7,057			782			(25,868	)
Purchased power		(79,890	)		(3,542	)		(11,018	)		(94,449	)
Nuclear refueling outage expenses		(3,199	)		2,693			-			(505	)
Other operation and maintenance		1,675			(141,588	)		38,270			(101,644	)
Decommissioning		4,886			(26,028	)		-			(21,141	)
Taxes other than income taxes		248			1,083			397			1,727
Depreciation and amortization		16,326			16,008			(27	)		32,308
Other regulatory charges (credits )- net		161,038			-			-			161,038
Total		67,378			(144,317	)		28,404			(48,534	)
Gain on sale of business		-			(44,173	)		-			(44,173	)
OPERATING INCOME		(166,882	)		(52,239	)		(35,021	)		(254,143	)
OTHER INCOME (DEDUCTIONS)
Allowance for equity funds used during construction		24,924			-			-			24,924
Interest and investment income		(23,756	)		(34,666	)		2,101			(56,321	)
Other than temporary impairment losses		-			1,238			-			1,238
Miscellaneous - net		(4,556	)		(6,290	)		(301	)		(11,147	)
Total		(3,388	)		(39,718	)		1,800			(41,306	)
INTEREST EXPENSE
Interest expense		(34,588	)		(51,183	)		27,146			(58,625	)
Allowance for borrowed funds used during construction		(2,914	)		-			-			(2,915	)
Total		(37,502	)		(51,183	)		27,146			(61,540	)
INCOME BEFORE INCOME TAXES		(132,768	)		(40,774	)		(60,367	)		(233,909	)
Income taxes		(426,916	)		(43,193	)		139,133			(330,976	)
CONSOLIDATED NET INCOME		294,148			2,419			(199,500	)		97,067
Preferred dividend requirements of subsidiaries		(2	)		513			359			870
NET INCOME ATTRIBUTABLE TO ENTERGY CORPORATION	$	294,150		$	1,906		$	(199,859	)	$	96,197
EARNINGS PER AVERAGE COMMON SHARE:
BASIC	$	1.87		$	0.14		$	(1.14	)	$	0.87
DILUTED	$	1.87		$	0.15		$	(1.13	)	$	0.89
*Totals may not foot due to rounding.

Entergy Corporation
Consolidated Cash Flow Statement
Three Months Ended December 31, 2011 vs. 2010
(Dollars in thousands)
(Unaudited)
	2011			2010			Variance
OPERATING ACTIVITIES
Consolidated net income	$	160,027		$	233,307		$	(73,280	)
Adjustments to reconcile consolidated net income to net cash flow
provided by operating activities:
Depreciation, amortization, and decommissioning, including nuclear fuel amortization		429,725			445,788			(16,063	)
Deferred income taxes, investment tax credits, and non-current taxes accrued		(274,050	)		194,628			(468,678	)
Gain on sale of business		-			(44,173	)		44,173
Changes in assets and liabilities:
Receivables		241,615			143,686			97,929
Fuel inventory		(7,284	)		(13,993	)		6,709
Accounts payable		106,909			172,287			(65,378	)
Prepaid taxes and taxes accrued		334,800			(162,186	)		496,986
Interest accrued		19,135			28,633			(9,498	)
Deferred fuel		63,795			74,564			(10,769	)
Other working capital accounts		73,194			1,958			71,236
Provisions for estimated losses		(6,478	)		6,322			(12,800	)
Other regulatory assets		(923,991	)		(143,552	)		(780,439	)
Pensions and other postretirement liabilities		1,238,151			61,576			1,176,575
Other assets and liabilities		(456,487	)		(237,853	)		(218,634	)
Net cash flow provided by operating activities		999,061			760,992			238,069
INVESTING ACTIVITIES
Construction/capital expenditures		(579,359	)		(563,578	)		(15,781	)
Allowance for equity funds used during construction		25,156			13,391			11,765
Nuclear fuel purchases		(166,075	)		(91,931	)		(74,144	)
Payment for purchase of assets and businesses		(346,547	)		-			(346,547	)
Proceeds from sale of assets and businesses		-			218,496			(218,496	)
Changes in securitization account		(6,817	)		(6,763	)		(54	)
Payments to storm reserve escrow account		(1,382	)		(1,713	)		331
Decrease (increase) in other investments		49,070			(92,740	)		141,810
Proceeds from nuclear decommissioning trust fund sales		307,257			632,375			(325,118	)
Investment in nuclear decommissioning trust funds		(332,653	)		(687,016	)		354,363
Net cash flow used in investing activities		(1,051,350	)		(579,479	)		(471,871	)
FINANCING ACTIVITIES
Proceeds from the issuance of:
Long-term debt		1,455,247			1,598,470			(143,223	)
Common stock and treasury stock		13,296			5,400			7,896
Retirement of long-term debt		(1,489,971	)		(2,064,200	)		574,229
Repurchase of common stock		-			(212,952	)		212,952
Redemption of subsidiary common and preferred stock		(30,308	)		-			(30,308	)
Changes in credit borrowings - net		(36,537	)		10,420			(46,957	)
Dividends paid:
Common stock		(146,315	)		(150,171	)		3,856
Preferred stock		(5,887	)		(5,015	)		(872	)
Net cash flow used in financing activities		(240,475	)		(818,048	)		577,573
Effect of exchange rates on cash and cash equivalents		62			88			(26	)
Net increase (decrease) in cash and cash equivalents		(292,702	)		(636,447	)		343,745
Cash and cash equivalents at beginning of period		987,140			1,930,919			(943,779	)
Cash and cash equivalents at end of period	$	694,438		$	1,294,472		$	(600,034	)
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
Cash paid (received) during the period for:
Interest - net of amount capitalized	$	118,746		$	133,880		$	(15,134	)
Income taxes	$	(2,031	)	$	(820	)	$	(1,211	)

Entergy Corporation
Consolidated Cash Flow Statement
Year to Date December 31, 2011 vs. 2010
(Dollars in thousands)
(Unaudited)
	2011			2010			Variance
OPERATING ACTIVITIES
Consolidated net income	$	1,367,372		$	1,270,305		$	97,067
Adjustments to reconcile consolidated net income to net cash flow
provided by operating activities:
Depreciation, amortization, and decommissioning, including nuclear fuel amortization		1,745,455			1,705,331			40,124
Deferred income taxes, investment tax credits, and non-current taxes accrued		(280,029	)		718,987			(999,016	)
Gain on sale of business		-			(44,173	)		44,173
Changes in assets and liabilities:
Receivables		28,091			(99,640	)		127,731
Fuel inventory		5,393			(10,665	)		16,058
Accounts payable		(131,970	)		216,635			(348,605	)
Prepaid taxes and taxes accrued		580,042			(116,988	)		697,030
Interest accrued		(34,172	)		17,651			(51,823	)
Deferred fuel		(55,686	)		8,909			(64,595	)
Other working capital accounts		41,875			(160,326	)		202,201
Provisions for estimated losses		(11,086	)		265,284			(276,370	)
Other regulatory assets		(673,244	)		339,408			(1,012,652	)
Pensions and other postretirement liabilities		962,461			(80,844	)		1,043,305
Other assets and liabilities		(415,685	)		(103,793	)		(311,892	)
Net cash flow provided by operating activities		3,128,817			3,926,081			(797,264	)
INVESTING ACTIVITIES
Construction/capital expenditures		(2,040,027	)		(1,974,286	)		(65,741	)
Allowance for equity funds used during construction		86,252			59,381			26,871
Nuclear fuel purchases		(641,493	)		(407,711	)		(233,782	)
Payment for purchase of plant		(646,137	)		-			(646,137	)
Proceeds from sale of assets and businesses		6,531			228,171			(221,640	)
Insurance proceeds received for property damages		-			7,894			(7,894	)
Changes in securitization account		(7,260	)		(29,945	)		22,685
NYPA value sharing payment		(72,000	)		(72,000	)		-
Payments to storm reserve escrow account		(6,425	)		(296,614	)		290,189
Receipts from storm reserve escrow account		-			9,925			(9,925	)
Decrease (increase) in other investments		(11,623	)		24,956			(36,579	)
Proceeds from nuclear decommissioning trust fund sales		1,360,346			2,606,383			(1,246,037	)
Investment in nuclear decommissioning trust funds		(1,475,017	)		(2,730,377	)		1,255,360
Net cash flow used in investing activities		(3,446,853	)		(2,574,223	)		(872,630	)
FINANCING ACTIVITIES
Proceeds from the issuance of:
Long-term debt		2,990,881			3,870,694			(879,813	)
Common stock and treasury stock		46,185			51,163			(4,978	)
Retirement of long-term debt		(2,437,372	)		(4,178,127	)		1,740,755
Repurchase of common stock		(234,632	)		(878,576	)		643,944
Redemption of subsidiary common and preferred stock		(30,308	)		-			(30,308	)
Changes in credit borrowings - net		(6,501	)		(8,512	)		2,011
Dividends paid:
Common stock		(589,605	)		(603,854	)		14,249
Preferred stock		(20,933	)		(20,063	)		(870	)
Net cash flow used in financing activities		(282,285	)		(1,767,275	)		1,484,990
Effect of exchange rates on cash and cash equivalents		287			338			(51	)
Net increase (decrease) in cash and cash equivalents		(600,034	)		(415,079	)		(184,955	)
Cash and cash equivalents at beginning of period		1,294,472			1,709,551			(415,079	)
Cash and cash equivalents at end of period	$	694,438		$	1,294,472		$	(600,034	)
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
Cash paid (received) during the period for:
Interest - net of amount capitalized	$	532,271		$	534,004		$	(1,733	)
Income taxes	$	(2,042	)	$	32,144		$	(34,186	)