Securities registered pursuant to Section 12(b) of the Act:

Registrant	Title of Class	Name of Each Exchange on Which Registered
Entergy Corporation	Common Stock, $0.01 Par Value – 176,620,417   shares outstanding at January 31, 2012	New York Stock Exchange, Inc. Chicago Stock Exchange, Inc.
Entergy Arkansas, Inc.	Mortgage Bonds, 5.75% Series due November 2040	New York Stock Exchange, Inc.
Entergy Louisiana, LLC	Mortgage Bonds, 6.0% Series due March 2040	New York Stock Exchange, Inc.
	Mortgage Bonds, 5.875% Series due June 2041	New York Stock Exchange, Inc.
Entergy Mississippi, Inc.	Mortgage Bonds, 6.0% Series due November 2032	New York Stock Exchange, Inc.
	Mortgage Bonds, 6.20% Series due April 2040	New York Stock Exchange, Inc.
	Mortgage Bonds, 6.0% Series due May 2051	New York Stock Exchange, Inc.
Entergy Texas, Inc.	Mortgage Bonds, 7.875% Series due June 2039	New York Stock Exchange, Inc.

Securities registered pursuant to Section 12(g) of the Act:

Registrant	Title of Class
Entergy Arkansas, Inc.	Preferred Stock, Cumulative, $100 Par Value Preferred Stock, Cumulative, $0.01 Par Value
Entergy Gulf States Louisiana, L.L.C.	Common Membership Interests
Entergy Mississippi, Inc.	Preferred Stock, Cumulative, $100 Par Value
Entergy New Orleans, Inc.	Preferred Stock, Cumulative, $100 Par Value
Entergy Texas, Inc.	Common Stock, no par value

Indicate by check mark if the registrants are well-known seasoned issuers, as defined in Rule 405 of the Securities Act.

	Yes		No
Entergy Corporation	Ö
Entergy Arkansas, Inc.			Ö
Entergy Gulf States Louisiana, L.L.C.			Ö
Entergy Louisiana, LLC	Ö
Entergy Mississippi, Inc.			Ö
Entergy New Orleans, Inc.			Ö
Entergy Texas, Inc.			Ö
System Energy Resources, Inc.			Ö

	Yes		No
Entergy Corporation			Ö
Entergy Arkansas, Inc.			Ö
Entergy Gulf States Louisiana, L.L.C.			Ö
Entergy Louisiana, LLC			Ö
Entergy Mississippi, Inc.			Ö
Entergy New Orleans, Inc.			Ö
Entergy Texas, Inc.			Ö
System Energy Resources, Inc.			Ö

	Large accelerated filer		Accelerated filer		Non-accelerated filer		Smaller reporting company
Entergy Corporation	Ö
Entergy Arkansas, Inc.					Ö
Entergy Gulf States Louisiana, L.L.C.					Ö
Entergy Louisiana, LLC					Ö
Entergy Mississippi, Inc.					Ö
Entergy New Orleans, Inc.					Ö
Entergy Texas, Inc.					Ö
System Energy Resources, Inc.					Ö

DEFINITIONS

Certain abbreviations or acronyms used in the text and notes are defined below:

Abbreviation or Acronym	Term
AFUDC	Allowance for Funds Used During Construction
ALJ	Administrative Law Judge
ANO 1 and 2	Units 1 and 2 of Arkansas Nuclear One (nuclear), owned by Entergy Arkansas
APSC	Arkansas Public Service Commission
ASU	Accounting Standards Update issued by the FASB
Board	Board of Directors of Entergy Corporation
Cajun	Cajun Electric Power Cooperative, Inc.
bundled energy and 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
capacity factor	Actual plant output divided by maximum potential plant output for the period
City Council or Council	Council of the City of New Orleans, Louisiana
DOE	United States Department of Energy
D. C. Circuit	U.S. Court of Appeals for the District of Columbia
Entergy	Entergy Corporation and its direct and indirect subsidiaries
Entergy Corporation	Entergy Corporation, a Delaware corporation
Entergy Gulf States, Inc.	Predecessor company for financial reporting purposes to Entergy Gulf States Louisiana that included the assets and business operations of both Entergy Gulf States Louisiana and Entergy Texas
Entergy Gulf States Louisiana	Entergy Gulf States Louisiana, L.L.C., a company formally created as part of the jurisdictional separation of Entergy Gulf States, Inc. and the successor company to Entergy Gulf States, Inc. for financial reporting purposes.  The term is also used to refer to the Louisiana jurisdictional business of Entergy Gulf States, Inc., as the context requires.
Entergy-Koch	A joint venture equally owned by subsidiaries of Entergy and Koch Industries, Inc.  Entergy-Koch’s pipeline and trading businesses were sold in 2004.
Entergy Texas	Entergy Texas, Inc., a company formally created as part of the jurisdictional separation of Entergy Gulf States, Inc.  The term is also used to refer to the Texas jurisdictional business of Entergy Gulf States, Inc., as the context requires.
Entergy Wholesale Commodities (EWC)	Entergy’s non-utility business segment primarily comprised of the ownership and operation of six nuclear power plants, the ownership of interests in non-nuclear power plants, and the sale of the electric power produced by those plants to wholesale customers
EPA	United States Environmental Protection Agency
ERCOT	Electric Reliability Council of Texas
FASB	Financial Accounting Standards Board
FERC	Federal Energy Regulatory Commission
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, the defaulting party must compensate the other party as specified in the contract
FitzPatrick	James A. FitzPatrick Nuclear Power Plant (nuclear), owned by an Entergy subsidiary in the Entergy Wholesale Commodities business segment
Grand Gulf	Unit No. 1 of Grand Gulf Nuclear Station (nuclear), 90% owned or leased by System Energy
GWh	Gigawatt-hour(s), which equals one million kilowatt-hours

 

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DEFINITIONS (Continued)

Abbreviation or Acronym		Term
Independence		Independence Steam Electric Station (coal), owned 16% by Entergy Arkansas, 25% by Entergy Mississippi, and 7% by Entergy Power
Indian Point 2		Unit 2 of Indian Point Energy Center (nuclear), owned by an Entergy subsidiary in the Entergy Wholesale Commodities business segment
Indian Point 3		Unit 3 of Indian Point Energy Center (nuclear), owned by an Entergy subsidiary in the Entergy Wholesale Commodities business segment
IRS		Internal Revenue Service
ISO		Independent System Operator
kV		Kilovolt
kW		Kilowatt, which equals one thousand watts
kWh		Kilowatt-hour(s)
LDEQ		Louisiana Department of Environmental Quality
LPSC		Louisiana Public Service Commission
Mcf		1,000 cubic feet of gas
MISO		Midwest Independent Transmission System Operator, Inc., a regional transmission organization
MMBtu		One million British Thermal Units
MPSC		Mississippi Public Service Commission
MW		Megawatt(s), which equals one thousand kilowatt(s)
MWh		Megawatt-hour(s)
Nelson Unit 6		Unit No. 6 (coal) of the Nelson Steam Electric Generating Station, 70% of which is co-owned by Entergy Gulf States Louisiana (57.5%) and Entergy Texas (42.5%), and 10.9% of which is owned by an Entergy subsidiary in the Entergy Wholesale Commodities business segment
Net debt ratio		Gross debt less cash and cash equivalents divided by total capitalization less cash and cash equivalents
Net MW in operation		Installed capacity owned and operated
NRC		Nuclear Regulatory Commission
NYPA		New York Power Authority
OASIS		Open Access Same Time Information Systems
Offsetting positions		Transactions for the purchase of energy, generally to offset a firm LD transaction
Palisades		Palisades Power Plant (nuclear), owned by an Entergy subsidiary in the Entergy Wholesale Commodities business segment
percent of capacity sold forward		Percent of planned qualified capacity sold to mitigate price uncertainty under physical or financial transactions
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 that may or may not require regulatory approval
Pilgrim		Pilgrim Nuclear Power Station (nuclear), owned by an Entergy subsidiary in the Entergy Wholesale Commodities business segment
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
PPA		Purchased power agreement or power purchase agreement
PRP		Potentially responsible party (a person or entity that may be responsible for remediation of environmental contamination)
PUCT		Public Utility Commission of Texas
Registrant Subsidiaries		Entergy Arkansas, Inc., Entergy Gulf States Louisiana, L.L.C., Entergy Louisiana, LLC, Entergy Mississippi, Inc., Entergy New Orleans, Inc., Entergy Texas, Inc., and System Energy Resources, Inc.

 

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DEFINITIONS (Concluded)

Abbreviation or Acronym	Term
Ritchie Unit 2	Unit 2 of the R.E. Ritchie Steam Electric Generating Station (gas/oil)
River Bend	River Bend Station (nuclear), owned by Entergy Gulf States Louisiana
RTO	Regional transmission organization
SEC	Securities and Exchange Commission
SMEPA	South Mississippi Electric Power Association, which owns a 10% interest in Grand Gulf
System Agreement	Agreement, effective January 1, 1983, as modified, among the Utility operating companies relating to the sharing of generating capacity and other power resources
System Energy	System Energy Resources, Inc.
System Fuels	System Fuels, Inc.
TWh	Terawatt-hour(s), which equals one billion kilowatt-hours
UK	United Kingdom of Great Britain and Northern Ireland
unit-contingent	Transaction under which power is supplied from a specific generation asset; if the asset is not operating, the seller is generally not liable to the buyer for any damages
Unit Power Sales Agreement	Agreement, dated as of June 10, 1982, as amended and approved by FERC, among Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and System Energy, relating to the sale of capacity and energy from System Energy’s share of Grand Gulf
Utility	Entergy’s business segment that generates, transmits, distributes, and sells electric power, with a small amount of natural gas distribution
Utility operating companies	Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas
Vermont Yankee	Vermont Yankee Nuclear Power Station (nuclear), owned by an Entergy subsidiary in the Entergy Wholesale Commodities business segment
Waterford 3	Unit No. 3 (nuclear) of the Waterford Steam Electric Station, 100% owned or leased by Entergy Louisiana
weather-adjusted usage	Electric usage excluding the effects of deviations from normal weather
White Bluff	White Bluff Steam Electric Generating Station, 57% owned by Entergy Arkansas

 

 

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ENTERGY CORPORATION AND SUBSIDIARIES

MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS

Entergy operates primarily through two business segments: Utility and Entergy Wholesale Commodities.

·

The Utility business segment includes the generation, transmission, distribution, and sale of electric power in portions of Arkansas, Mississippi, Texas, and Louisiana, including the City of New Orleans; and operates a small natural gas distribution business.  As discussed in more detail in “Plan to Spin Off the Utility’s Transmission Business,” in December 2011, Entergy entered into an agreement to spin off its transmission business and merge it with a newly-formed subsidiary of ITC Holdings Corp.

·

The Entergy Wholesale Commodities business segment includes the ownership and operation of six nuclear power plants located in the northern United States and the sale of the electric power produced by those plants to wholesale customers.  This business also provides services to other nuclear power plant owners.  Entergy Wholesale Commodities also owns interests in non-nuclear power plants that sell the electric power produced by those plants to wholesale customers.

Following are the percentages of Entergy’s consolidated revenues and net income generated by its operating segments and the percentage of total assets held by them:

		% of Revenue						% of Net Income						% of Total Assets
Segment		2011		2010		2009		2011		2010		2009		2011		2010		2009
Utility		79		78		75		82		65		57		80		80		80
Entergy Wholesale Commodities		21		22		25		36		39		51		26		26		30
Parent & Other		-		-		-		(18)		(4)		(8)		(6)		(6)		(10)

 

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Table of Contents

Entergy Corporation and Subsidiaries

Management's Financial Discussion and Analysis

Results of Operations

2011 Compared to 2010

Following are income statement variances for Utility, Entergy Wholesale Commodities, Parent & Other, and Entergy comparing 2011 to 2010 showing how much the line item increased or (decreased) in comparison to the prior period:

		Utility		Entergy Wholesale Commodities		Parent & Other		Entergy
		(In Thousands)
2010 Consolidated Net Income (Loss)		$829,719		$489,422		($48,836)		$1,270,305
Net revenue (operating revenue less fuel expense, purchased power, and other regulatory charges/credits)		(146,947)		(155,898)		3,620		(299,225)
Other operation and maintenance expenses		1,674		(141,588)		38,270		(101,644)
Taxes other than income taxes		248		1,083		396		1,727
Depreciation and amortization		16,326		16,008		(26)		32,308
Gain on sale of business		-		(44,173)		-		(44,173)
Other income		(3,388)		(39,717)		1,799		(41,306)
Interest expense		(37,502)		(51,183)		27,145		(61,540)
Other		1,688		(23,334)		-		(21,646)
Income taxes (benefit)		(426,916)		(43,193)		139,133		(330,976)
2011 Consolidated Net Income (Loss)		$1,123,866		$491,841		($248,335)		$1,367,372

Refer to “ SELECTED FINANCIAL DATA - FIVE-YEAR COMPARISON OF ENTERGY CORPORATION AND SUBSIDIARIES ” which accompanies Entergy Corporation’s financial statements in this report for further information with respect to operating statistics.

Net income for Utility in 2011 was significantly affected by a settlement with the IRS related to the mark-to-market income tax treatment of power purchase contracts, which resulted in a reduction in income tax expense.  The net income effect was partially offset by a regulatory charge, which reduced net revenue, because a portion of the benefits will be shared with customers.  See Notes 3 and 8 to the financial statements for additional discussion of the settlement and benefit sharing.

 

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Entergy Corporation and Subsidiaries

Management's Financial Discussion and Analysis

Net Revenue

Utility

Following is an analysis of the change in net revenue comparing 2011 to 2010.

		Amount
		(In Millions)
2010 net revenue		$5,051
Mark-to-market tax settlement sharing		(196)
Purchased power capacity		(21)
Net wholesale revenue		(14)
Volume/weather		13
ANO decommissioning trust		24
Retail electric price		49
Other		(2)
2011 net revenue		$4,904

The mark-to-market tax settlement sharing variance results from a regulatory charge because a portion of the benefits of a settlement with the IRS related to the mark-to-market income tax treatment of power purchase contracts will be shared with customers, slightly offset by the amortization of a portion of that charge beginning in October 2011.  See Notes 3 and 8 to the financial statements for additional discussion of the settlement and benefit sharing.

The purchased power capacity variance is primarily due to price increases for ongoing purchased power capacity and additional capacity purchases.

The net wholesale revenue variance is primarily due to lower margins on co-owner contracts and higher wholesale energy costs.

The volume/weather variance is primarily due to an increase of 2,061 GWh in weather-adjusted usage across all sectors.  Weather-adjusted residential retail sales growth reflected an increase in the number of customers.  Industrial sales growth has continued since the beginning of 2010.  Entergy’s service territory has benefited from the national manufacturing economy and exports, as well as industrial facility expansions.  Increases have been offset to some extent by declines in the paper, wood products, and pipeline segments.  The increase was also partially offset by the effect of less favorable weather on residential sales.

The ANO decommissioning trust variance is primarily related to the deferral of investment gains from the ANO 1 and 2 decommissioning trust in 2010 in accordance with regulatory treatment.  The gains resulted in an increase in interest and investment income in 2010 and a corresponding increase in regulatory charges with no effect on net income.

The retail electric price variance is primarily due to:

·	rate actions at Entergy Texas, including a base rate increase effective August 2010 and an additional increase beginning May 2011;

·	a formula rate plan increase at Entergy Louisiana effective May 2011; and

·	a base rate increase at Entergy Arkansas effective July 2010.

These were partially offset by formula rate plan decreases at Entergy New Orleans effective October 2010 and October 2011.  See Note 2 to the financial statements for further discussion of these proceedings.

 

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Entergy Corporation and Subsidiaries

Management's Financial Discussion and Analysis

Entergy Wholesale Commodities

Following is an analysis of the change in net revenue comparing 2011 to 2010.

		Amount
		(In Millions)
2010 net revenue		$2,200
Realized price changes		(159)
Fuel expenses		(30)
Harrison County		(27)
Volume		60
2011 net revenue		$2,044

As shown in the table above, net revenue for Entergy Wholesale Commodities decreased by $156 million, or 7%, in 2011 compared to 2010 primarily due to:

·	lower pricing in its contracts to sell power;

·	higher fuel expenses, primarily at the nuclear plants; and

·	the absence of the Harrison County plant, which was sold in December 2010.

These factors were partially offset by higher volume resulting from fewer planned and unplanned outage days in 2011 compared to the same period in 2010.

Following are key performance measures for Entergy Wholesale Commodities for 2011 and 2010:

		2011		2010
Owned capacity		6,599		6,351
GWh billed		43,520		42,682
Average realized price per MWh		$54.48		$59.04
Entergy Wholesale Commodities Nuclear Fleet
Capacity factor		93%		90%
GWh billed		40,918		39,655
Average realized revenue per MWh		$54.73		$59.16
Refueling Outage Days:
FitzPatrick		-		35
Indian Point 2		-		33
Indian Point 3		30		-
Palisades		-		26
Pilgrim		25		-
Vermont Yankee		25		29

Realized Revenue per MWh for Entergy Wholesale Commodities Nuclear Plants

The recent economic downturn and negative trends in the energy commodity markets have resulted in lower natural gas prices and therefore lower market prices for electricity in the New York and New England power regions, which is where five of the six Entergy Wholesale Commodities nuclear power plants are located.  Entergy Wholesale Commodities’ nuclear business experienced a decrease in realized price per MWh to $54.73 in 2011 from $59.16 in 2010, and is likely to experience a decrease again in 2012 because, as shown in the contracted sale of energy table in “Market and Credit Risk Sensitive Instruments,” Entergy Wholesale Commodities has sold forward 88% of its planned nuclear energy output for 2012 for an average contracted energy price of $49 per MWh.  In addition, Entergy Wholesale Commodities has sold forward 81% of its planned energy output for 2013 for an average contracted energy price range of $45-50 per MWh.

 

 

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Entergy Corporation and Subsidiaries

Management's Financial Discussion and Analysis

Other Income Statement Items

Utility

Other operation and maintenance expenses increased from $1,949 million for 2010 to $1,951 million for 2011 primarily due to:

·	an increase of $17 million in nuclear expenses primarily due to higher labor costs, including higher contract labor;

·	an increase of $15 million in contract costs due to the transition and implementation of joining the MISO RTO;

·	an increase of $9 million in legal expenses primarily resulting from an increase in legal and regulatory activity increasing the use of outside legal services;

·	an increase of $8 million in fossil-fueled generation expenses primarily due to the addition of Acadia Unit 2 in April 2011; and

·	several individually insignificant items.

These increases were substantially offset by:

·

a decrease of $29 million in compensation and benefits costs primarily resulting from an increase in the accrual for incentive-based compensation in 2010 and a decrease in stock option expense.  The decrease in stock option expense is offset by credits recorded by the parent company, Entergy Corporation;

·

the deferral in 2011 of $13.4 million of 2010 Michoud plant maintenance costs pursuant to the settlement of Entergy New Orleans’ 2010 test year formula rate plan filing approved by the City Council in September 2011.  See Note 2 to the financial statements for further discussion of the 2010 test year formula rate plan filing and settlement;

·	the amortization of $11 million of Entergy Texas rate case expenses in 2010.  See Note 2 to the financial statements for further discussion of the Entergy Texas rate case settlement; and

·	a decrease of $10 million in operating expenses due to the sale of surplus oil inventory in 2011.

Depreciation and amortization expense increased primarily due to an increase in plant in service, partially offset by a decrease in depreciation rates at Entergy Arkansas as a result of the rate case settlement agreement approved by the APSC in June 2010.

Interest expense decreased primarily due to:

·	the refinancing of long-term debt at lower interest rates by certain of the Utility operating companies;

·	a revision caused by FERC’s acceptance of a change in the treatment of funds received from independent power producers for transmission interconnection projects; and

·	interest expense accrued in 2010 related to the expected result of the LPSC Staff audit of Entergy Gulf States Louisiana’s fuel adjustment clause for the period 1995 through 2004.

 

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Entergy Corporation and Subsidiaries

Management's Financial Discussion and Analysis

Entergy Wholesale Commodities

Other operation and maintenance expenses decreased from $1,047 million for 2010 to $905 million for 2011 primarily due to:

·	the write-off of $64 million of capital costs in 2010, primarily for software that would not be utilized, and $16 million of additional costs incurred in 2010 in connection with Entergy’s decision to unwind the infrastructure created for the planned spin-off of its non-utility nuclear business;

·	a decrease of $30 million due to the absence of expenses from the Harrison County plant, which was sold in December 2010;

·	a decrease in compensation and benefits costs resulting from an increase of $19 million in the accrual for incentive-based compensation in 2010;

·	a decrease of $12 million in spending on tritium remediation work; and

·	the write-off of $10 million of capitalized engineering costs in 2010 associated with a potential uprate project.

The gain on sale resulted from the sale in 2010 of Entergy’s ownership interest in the Harrison County Power Project 550 MW combined-cycle plant to two Texas electric cooperatives that owned a minority share of the plant.  Entergy sold its 61 percent share of the plant for $219 million and realized a pre-tax gain of $44.2 million on the sale.

Depreciation and amortization expense increased primarily due to an increase in plant in service and declining useful life of nuclear assets.

Other income decreased primarily due to a decrease in interest income earned on loans to the parent company, Entergy Corporation, and a decrease of $13 million in realized earnings on decommissioning trust fund investments.

Interest expense decreased primarily due to the write-off of $39 million of debt financing costs in 2010, primarily incurred for a $1.2 billion credit facility that will not be used, in connection with Entergy’s decision to unwind the infrastructure created for the planned spin-off of its non-utility nuclear business.

Other expenses decreased primarily due to a credit to decommissioning expense of $34.1 million in 2011 resulting from a reduction in the decommissioning liability for a plant as a result of a revised decommissioning cost study obtained to comply with a state regulatory requirement.  See “ Critical Accounting Estimates – Nuclear Decommissioning Costs ” below for further discussion of accounting for asset retirement obligations.

Parent & Other

Other operation and maintenance expenses increased primarily due to lower intercompany stock option credits recorded by the parent company, Entergy Corporation, and an increase of $13 million related to the planned spin-off and merger of Entergy’s transmission business.  See “ Plan to Spin Off  the Utility’s Transmission Business ” below for further discussion.

Interest expense increased primarily due to $1 billion of Entergy Corporation senior notes issued in September 2010, with the proceeds used to pay down borrowings outstanding on Entergy Corporation’s revolving credit facility that were at a lower interest rate.

 

 

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Entergy Corporation and Subsidiaries

Management's Financial Discussion and Analysis

Income Taxes

The effective income tax rate for 2011 was 17.3%.  The difference in the effective income tax rate versus the statutory rate of 35% in 2011 was primarily due to a settlement with the IRS related to the mark-to-market income tax treatment of power purchase contracts, which resulted in a reduction in income tax expense of $422 million.  See Note 3 to the financial statements herein for further discussion of the settlement.

 

The effective income tax rate for 2010 was 32.7%.  The difference in the effective income tax rate versus the statutory rate of 35% in 2010 was primarily due to:

·

a favorable Tax Court decision holding that the U.K. Windfall Tax may be used as a credit for purposes of computing the U.S. foreign tax credit, which allowed Entergy to reverse a provision for uncertain tax positions of $43 million, included in Parent and Other, on the issue.  See Note 3 to the financial statements for further discussion of this tax litigation;

·	a $19 million tax benefit recorded in connection with Entergy’s decision to unwind the infrastructure created for the planned spin-off of its non-utility nuclear business; and

·	the recognition of a $14 million Louisiana state income tax benefit related to storm cost financing.

Partially offsetting the decreased effective income tax rate was a charge of $16 million resulting from a change in tax law associated with the recently enacted federal healthcare legislation, as discussed below in “ Critical Accounting Estimates ” and state income taxes and certain book and tax differences for Utility plant items.

See Note 3 to the financial statements for a reconciliation of the federal statutory rate of 35.0% to the effective income tax rates, and for additional discussion regarding income taxes.

2010 Compared to 2009

Following are income statement variances for Utility, Entergy Wholesale Commodities, Parent & Other, and Entergy comparing 2010 to 2009 showing how much the line item increased or (decreased) in comparison to the prior period:

		Utility		Entergy Wholesale Commodities		Parent & Other		Entergy
		(In Thousands)
2009 Consolidated Net Income (Loss)		$708,905		$641,094		($98,949)		$1,251,050
Net revenue (operating revenue less fuel expense, purchased power, and other regulatory charges/credits)		357,211		(163,518)		8,622		202,315
Other operation and maintenance expenses		112,384		124,758		(18,550)		218,592
Taxes other than income taxes		28,872		2,717		(1,149)		30,440
Depreciation and amortization		(24,112)		11,413		(182)		(12,881)
Gain on sale of business		-		44,173		-		44,173
Other income		(14,915)		66,222		(25,681)		25,626
Interest expense		31,035		(6,461)		(19,851)		4,723
Other		7,758		19,728		-		27,486
Income taxes		65,545		(53,606)		(27,440)		(15,501)
2010 Consolidated Net Income (Loss)		$829,719		$489,422		($48,836)		$1,270,305

 

 

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Entergy Corporation and Subsidiaries

Management's Financial Discussion and Analysis

Refer to “ SELECTED FINANCIAL DATA - FIVE-YEAR COMPARISON OF ENTERGY CORPORATION AND SUBSIDIARIES ” which accompanies Entergy Corporation’s financial statements in this report for further information with respect to operating statistics.

In November 2007 the Board approved a plan to pursue a separation of Entergy’s non-utility nuclear business from Entergy through a spin-off of the business to Entergy shareholders.  In April 2010, Entergy announced that it planned to unwind the business infrastructure associated with the proposed spin-off transaction.  As a result of the plan to unwind the business infrastructure, Entergy recorded expenses in 2010 for the write-off of certain capitalized costs incurred in connection with the planned spin-off transaction.  These costs are discussed in more detail below and throughout this section.

 

Net Revenue

Utility

Following is an analysis of the change in net revenue comparing 2010 to 2009.

		Amount
		(In Millions)
2009 net revenue		$4,694
Volume/weather		231
Retail electric price		137
Provision for regulatory proceedings		26
Rough production cost equalization		19
ANO decommissioning trust		(24)
Fuel recovery		(44)
Other		12
2010 net revenue		$5,051

The volume/weather variance is primarily due to an increase of 8,362 GWh, or 8%, in billed electricity usage in all retail sectors, including the effect on the residential sector of colder weather in the first quarter 2010 compared to 2009 and warmer weather in the second and third quarters 2010 compared to 2009.  The industrial sector reflected strong sales growth on continuing signs of economic recovery.  The improvement in this sector was primarily driven by inventory restocking and strong exports with the chemicals, refining, and miscellaneous manufacturing sectors leading the improvement.

The retail electric price variance is primarily due to:

·	increases in the formula rate plan riders at Entergy Gulf States Louisiana effective November 2009, January 2010,  and September 2010, at Entergy Louisiana effective November 2009, and at Entergy Mississippi effective July 2009;

·	a base rate increase at Entergy Arkansas effective July 2010;

·	rate actions at Entergy Texas, including base rate increases effective in May and August 2010;

·	a formula rate plan provision of $16.6 million recorded in the third quarter 2009 for refunds that were made to customers in accordance with settlements approved by the LPSC; and

·	the recovery in 2009 by Entergy Arkansas of 2008 extraordinary storm costs, as approved by the APSC, which ceased in January 2010.  The recovery of storm costs is offset in other operation and maintenance expenses.

See Note 2 to the financial statements for further discussion of the proceedings referred to above.

 

 

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Entergy Corporation and Subsidiaries

Management's Financial Discussion and Analysis

The provision for regulatory proceedings variance is primarily due to provisions recorded in 2009 at Entergy Arkansas.  See Note 2 to the financial statements for a discussion of regulatory proceedings affecting Entergy Arkansas.

The rough production cost equalization variance is due to an additional $18.6 million allocation recorded in the second quarter of 2009 for 2007 rough production cost equalization receipts ordered by the PUCT to Texas retail customers over what was originally allocated to Entergy Texas prior to the jurisdictional separation of Entergy Gulf States, Inc. into Entergy Gulf States Louisiana and Entergy Texas, effective December 2007, as discussed in Note 2 to the financial statements.

 

The ANO decommissioning trust variance is primarily related to the deferral of investment gains from the ANO 1 and 2 decommissioning trust in 2010 in accordance with regulatory treatment.  The gains resulted in an increase in interest and investment income in 2010 and a corresponding increase in regulatory charges with no effect on net income.

The fuel recovery variance resulted primarily from an adjustment to deferred fuel costs in the fourth quarter 2009 relating to unrecovered nuclear fuel costs incurred since January 2008 that will now be recovered after a revision to the fuel adjustment clause methodology.

Entergy Wholesale Commodities

Following is an analysis of the change in net revenue comparing 2010 to 2009.

		Amount
		(In Millions)
2009 net revenue		$2,364
Nuclear realized price changes		(96)
Nuclear volume		(60)
Other		(8)
2010 net revenue		$2,200

As shown in the table above, net revenue for Entergy Wholesale Commodities decreased by $164 million, or 7%, in 2010 compared to 2009 primarily due to results from its nuclear operations.  The net revenue decrease was primarily due to lower pricing in its contracts to sell nuclear power and lower nuclear volume resulting from more planned and unplanned outage days in 2010.  Included in net revenue is $46 million and $53 million of amortization of the Palisades purchased power agreement in 2010 and 2009, respectively, which is non-cash revenue and is discussed in Note 15 to the financial statements.  Following are key performance measures for Entergy Wholesale Commodities’ nuclear plants for 2010 and 2009:

		2010		2009
Net MW in operation at December 31		4,998		4,998
Average realized revenue per MWh		$59.16		$61.07
GWh billed		39,655		40,981
Capacity factor		90%		93%
Refueling Outage Days:
FitzPatrick		35		-
Indian Point 2		33		-
Indian Point 3		-		36
Palisades		26		41
Pilgrim		-		31
Vermont Yankee		29		-

 

 

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Overall, including its non-nuclear plants, Entergy Wholesale Commodities billed 42,682 GWh in 2010 and 43,969 GWh in 2009, with average realized revenue per MWh of $59.04 in 2010 and $60.46 in 2009.

 

Other Income Statement Items

Utility

Other operation and maintenance expenses increased from $1,837 million for 2009 to $1,949 million for 2010 primarily due to:

·

an increase of $70 million in compensation and benefits costs, resulting from decreasing discount rates, the amortization of benefit trust asset losses, and an increase in the accrual for incentive-based compensation.  See “ Critical Accounting Estimates - Qualified Pension and Other Postretirement Benefits” below and also Note 11 to the financial statements for further discussion of benefits costs;

·	an increase of $25 million in fossil-fueled generation expenses resulting from higher outage costs in 2010 primarily because the scope of the outages was greater than in 2009;

·	an increase of $17 million in transmission and distribution expenses resulting from increased vegetation contract work;

·	an increase of $13 million in nuclear expenses primarily due to higher nuclear labor and contract costs;

·	an increase of $12.5 million due to the capitalization in 2009 of Ouachita Plant service charges previously expensed; and

·	an increase of $11 million due to the amortization of Entergy Texas rate case expenses.  See Note 2 to the financial statements for further discussion of the Entergy Texas rate case settlement.

The increase was partially offset by:

·	a decrease of $19.4 million due to 2008 storm costs at Entergy Arkansas which were deferred per an APSC order and were recovered through revenues in 2009;

·	a decrease of $16 million due to higher write-offs of uncollectible customer accounts in 2009; and

·	charges of $14 million in 2009 due to the Hurricane Ike and Hurricane Gustav storm cost recovery settlement agreement, as discussed further in Note 2 to the financial statements.

Other income decreased primarily due to:

·	a decrease of $50 million in carrying charges on storm restoration costs because of the completion of financing or securitization of the costs, as discussed further in Note 2 to the financial statements; and

·	a gain of $16 million recorded in 2009 on the sale of undeveloped real estate by Entergy Louisiana Properties, LLC.

The decrease was partially offset by:

·	an increase of $24 million due to investment gains from the ANO 1 and 2 decommissioning trust, as discussed above;

·	an increase of $14 million resulting from higher earnings on decommissioning trust funds; and

·

an increase of distributions of $13 million earned by Entergy Louisiana and $7 million earned by Entergy Gulf States Louisiana on investments in preferred membership interests of Entergy Holdings Company.  The distributions on preferred membership interests are eliminated in consolidation and have no effect on net income because the investment is in another Entergy subsidiary.  See Note 2 to the financial statements for discussion of these investments in preferred membership interests.

 

 

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Interest expense increased primarily due to an increase in long-term debt outstanding resulting from net debt issuances by certain of the Utility operating companies in the second half of 2009 and in 2010.  See Notes 4 and 5 to the financial statements for details of long-term debt outstanding.

 

Depreciation and amortization expenses decreased primarily due to a decrease in depreciation rates at Entergy Arkansas as a result of the rate case settlement agreement approved by the APSC in June 2010.

Entergy Wholesale Commodities

Other operation and maintenance expenses increased from $922 million for 2009 to $1,047 million for 2010 primarily due to:

·	the write-off of $64 million of capital costs, primarily for software that will not be utilized, and $16 million of additional costs incurred in connection with Entergy’s decision to unwind the infrastructure created for the planned spin-off  of its non-utility nuclear business;

·

an increase of $36 million in compensation and benefits costs, resulting from decreasing discount rates, the amortization of benefit trust asset losses, and an increase in the accrual for incentive-based compensation.  See “ Critical Accounting Estimates - Qualified Pension and Other Postretirement Benefits” below and also Note 11 to the financial statements for further discussion of benefits costs;

·	spending of $15 million related to tritium remediation work at the Vermont Yankee site; and

·	the write-off of $10 million of capitalized engineering costs associated with a potential uprate project.

The gain on sale resulted from the sale of Entergy’s ownership interest in the Harrison County Power Project 550 MW combined-cycle plant to two Texas electric cooperatives that owned a minority share of the plant.  Entergy sold its 61 percent share of the plant for $219 million and realized a pre-tax gain of $44.2 million on the sale.

Other income increased primarily due to $86 million in charges in 2009 resulting from the recognition of impairments that are not considered temporary of certain equity securities held in Entergy Wholesale Commodities’ decommissioning trust funds, partially offset by a decrease of $28 million in realized earnings on the decommissioning trust funds.

Interest expense decreased primarily due to a decrease in fees paid to Entergy Corporation for providing collateral in the form of guarantees in connection with some of the Entergy Wholesale Commodities agreements to sell power.  The guarantee fees paid are intercompany transactions and are eliminated in consolidation.  The decrease was substantially offset by the write-off of $39 million of debt financing costs, primarily incurred for a $1.2 billion credit facility that will not be used, in connection with Entergy’s decision to unwind the infrastructure created for the planned spin-off of its non-utility nuclear business.

Parent & Other

Other income decreased primarily due to increases in the distributions paid of $13 million to Entergy Louisiana and $7 million to Entergy Gulf States Louisiana on investments in preferred membership interests of Entergy Holdings Company, as discussed above.

Interest expense decreased primarily due to lower borrowings, including the redemption of $267 million of notes payable in December 2009, as well as lower interest rates on borrowings under Entergy Corporation’s revolving credit facility.

 

 

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Management's Financial Discussion and Analysis

Income Taxes

The effective income tax rate for 2010 was 32.7%.  The difference in the effective income tax rate versus the statutory rate of 35% in 2010 was primarily due to:

·

a favorable Tax Court decision holding that the U.K. Windfall Tax may be used as a credit for purposes of computing the U.S. foreign tax credit, which allowed Entergy to reverse a provision for uncertain tax positions of $43 million, included in Parent and Other, on the issue.  See Note 3 to the financial statements for further discussion of this tax litigation;

·	a $19 million tax benefit recorded in connection with Entergy’s decision to unwind the infrastructure created for the planned spin-off of its non-utility nuclear business; and

·	the recognition of a $14 million Louisiana state income tax benefit related to storm cost financing.

Partially offsetting the decreased effective income tax rate was a charge of $16 million resulting from a change in tax law associated with the recently enacted federal healthcare legislation, as discussed below in “ Critical Accounting Estimates ” and state income taxes and certain book and tax differences for Utility plant items.

The effective income tax rate for 2009 was 33.6%.  The difference in the effective income tax rate versus the federal statutory rate of 35% in 2009 was primarily due to:

·	recognition of a capital loss of $73.1 million resulting from the sale of preferred stock of an Entergy Wholesale Commodities subsidiary to a third party;

·	reduction of a valuation allowance of $24.3 million on state loss carryovers;

·	reduction of a valuation allowance of $16.2 million on a federal capital loss carryover;

·	reduction of the provision for uncertain tax positions of $15.2 million resulting from settlements and agreements with taxing authorities;

·	adjustment to state income taxes of $13.8 million for Entergy Wholesale Commodities to reflect the effect of a change in the methodology of computing Massachusetts state income taxes as required by that state’s taxing authority; and

·	additional deferred tax benefit of approximately $8 million associated with writedowns on nuclear decommissioning qualified trust securities.

These reductions were partially offset by increases related to book and tax differences for utility plant items and state income taxes at the Utility operating companies.

See Note 3 to the financial statements for a reconciliation of the federal statutory rate of 35.0% to the effective income tax rates, and for additional discussion regarding income taxes.

Plan to Spin Off the Utility’s Transmission Business

On December 5, 2011, Entergy announced that it would spin off its transmission business and merge it with a newly formed subsidiary of ITC Holdings Corp. (ITC).  In order to effect the spin-off and merger, Entergy entered into (i) a Merger Agreement with Mid South TransCo LLC, a newly formed, wholly owned subsidiary of Entergy (TransCo); ITC; and Ibis Transaction Subsidiary LLC (Merger Sub), a newly formed, wholly-owned subsidiary of ITC; and (ii) a Separation Agreement with TransCo, ITC, each of the Utility operating companies, and Entergy Services, Inc.  These agreements, which have been approved by the Boards of Directors of Entergy and ITC, provide for the separation of Entergy’s transmission business (the “Transmission Business”), the distribution to Entergy’s stockholders of all of the common units of TransCo, a holding company subsidiary formed to hold the Transmission Business, and the merger of Merger Sub with and into TransCo, with TransCo continuing as the surviving entity in the Merger (the Merger), following which each common unit of TransCo will be converted into the right to receive one fully paid and nonassessable share of ITC common stock.  Both the Distribution (as defined below) and the Merger are expected to qualify as tax-free transactions.

 

 

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Management's Financial Discussion and Analysis

Pursuant to the Merger Agreement, and subject to the terms and conditions set forth therein, Entergy will distribute the TransCo common units to its shareholders.  At Entergy’s election, it may distribute the TransCo common units by means of a pro rata dividend in a spin-off or pursuant to an exchange offer in a split-off, or a combination of a spin-off and a split-off (the Distribution).  In connection with 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 of record as of a record date prior to the Merger, which will be determined by the board of directors of ITC at a later date (the Special Dividend).  Entergy’s shareholders who become shareholders of ITC as a result of the Merger will not receive the Special Dividend.  Pursuant to the Merger Agreement, and subject to the terms and conditions set forth therein, immediately after the consummation of the Separation (as defined below), the consummation of the Financings (as defined below), the payment of the Special Dividend and the consummation of the Distribution, Merger Sub will merge with and into TransCo, with TransCo continuing as the surviving entity, and Entergy shareholders who hold common units of TransCo will have those units exchanged for ITC common stock on a one-for-one basis.  Consummation of the transactions contemplated by the Separation Agreement and the Merger Agreement is expected to result in Entergy’s shareholders holding at least 50.1% of ITC’s common stock and existing ITC shareholders holding no more than 49.9% of ITC’s common stock immediately after the Merger.

The Merger Agreement contains certain customary representations and warranties.  The Merger Agreement may be terminated: (i) by mutual consent of Entergy and ITC, (ii) by either Entergy or ITC if the Merger has not been completed by June 30, 2013, subject to an up to six month extension by either Entergy or ITC in certain circumstances, (iii) by either Entergy or ITC if the transactions are enjoined or otherwise prohibited by applicable law, (iv) by Entergy, on the one hand, or ITC, on the other hand, upon a material breach of the Merger Agreement by the other party that has not been cured by the cure period specified in the Merger Agreement, (v) by either Entergy or ITC if ITC’s shareholders fail to approve the ITC shareholder proposals, (vi) by Entergy if the ITC Board of Directors withdraws or changes its recommendation of the ITC shareholder proposals in a manner adverse to Entergy, (vii) by Entergy if ITC willfully breaches in any material respect its non-solicitation covenant and the breach has not been cured by the cure period specified in the Merger Agreement, (viii) by Entergy if there is a law or order that enjoins the transactions or imposes a burdensome condition on Entergy, (ix) by either Entergy or ITC if there is a law or order that enjoins the transactions or imposes a burdensome condition on ITC, (x) by ITC, prior to ITC shareholder approval, to enter into a transaction for a superior proposal, provided that ITC complies with its notice and other obligations in the non-solicitation provision and pays Entergy the termination fee concurrently with termination or (xi) by ITC if Entergy takes certain actions with respect to the migration of the Transmission Business to a regional transmission organization if such actions could reasonably be expected to have certain adverse effects on TransCo or ITC after the Merger. In the event that (i) ITC terminates the Merger Agreement to accept a superior acquisition proposal, (ii) Entergy terminates the Merger Agreement because the ITC Board of Directors has withdrawn its recommendation of the ITC shareholder proposals, approves or recommends another acquisition proposal, fails to reaffirm its recommendation or materially breaches the non-solicitation provisions, (iii) either of the parties terminates the Merger Agreement because the approval of ITC’s shareholders is not obtained or (iv) Entergy terminates because of ITC’s uncured willful breach of the Merger Agreement, and in the case of clauses (iii) and (iv) an ITC takeover transaction was publicly announced and not withdrawn prior to termination and within 12 months of termination ITC agrees to or consummates a takeover transaction, then ITC must pay Entergy a $113,570,800 termination fee.

Consummation of the Merger is subject to the satisfaction of customary closing conditions for a transaction such as the Merger, including, among others, (i) consummation of the Separation, the Distribution, the Financings and the Special Dividend, (ii) the approval of the ITC shareholder proposals by the shareholders of ITC, (iii) the authorization for listing on the New York Stock Exchange of ITC common stock to be issued in the Merger, (iv) the receipt by Entergy of regulatory approvals necessary to become a member of an acceptable regional transmission organization, (v) the receipt of regulatory approvals necessary to consummate the transaction and the expiration of the applicable waiting period under the Hart-Scott-Rodino Act, and no such regulatory approvals impose a burdensome condition on ITC or Entergy, (vi) the absence of a material adverse effect on the Transmission Business or ITC, (vii) the receipt by Entergy of a solvency opinion and (viii) the receipt of a private letter ruling from the IRS substantially to the effect that certain requirements for the tax-free treatment of the distribution of TransCo are met and an opinion

 

 

 

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that the Distribution and the Merger will be treated as tax-free reorganizations for U.S. federal income tax purposes. The Merger and the other transactions contemplated by the Merger Agreement and the Separation Agreement are planned for completion in 2013.

 

Pursuant to the Separation Agreement, and subject to the terms and conditions set forth therein, Entergy will engage in a series of preliminary restructuring transactions that result in the transfer to TransCo’s subsidiaries of the assets relating to the Transmission Business (the Separation).  TransCo and its subsidiaries will consummate certain financing transactions (the TransCo Financing) totaling approximately $1.775 billion pursuant to which (i) TransCo’s subsidiaries will borrow through a one-year term funded bridge facility and (ii) TransCo will issue senior securities of TransCo to Entergy (the TransCo Securities).  Neither Entergy nor the Utility operating companies will guarantee or otherwise be liable for the payment of the TransCo Securities.  Entergy will issue new debt or enter into agreements under which certain unrelated creditors will agree to purchase existing corporate debt of Entergy, which will be exchangeable into the TransCo Securities at closing (the Exchangeable Debt Financing).  In addition, prior to the closing TransCo may obtain a working capital revolving credit facility in a principal amount agreed to by Entergy and ITC (such financing, together with the TransCo Financing and the Exchangeable Debt Financing, the Financings).

Under the terms of the Separation Agreement, concurrently with the TransCo Financing, each Utility operating company will contribute its respective transmission assets to a subsidiary that will become a TransCo subsidiary in the Separation in exchange for the equity interest in that subsidiary and the net proceeds received by that subsidiary from the one-year funded bridge facility described above.  Each Utility operating company will distribute the equity interests in the subsidiaries holding the transmission assets to Entergy, which will then contribute such interests to TransCo.  The Utility operating companies intend to apply all or a portion of the amounts received by them from the subsidiaries to the prepayment or redemption of outstanding preferred and debt securities, with the goal, following completion of the Separation, of maintaining their capitalization balanced between equity and debt generally consistent with the balance of their capitalization prior to the Separation.  Although the aggregate amount and particular series of preferred and debt securities of each Utility operating company to be redeemed as well as the redemption dates are uncertain at this time and are expected to remain subject to change, each Utility operating company currently anticipates that all of its outstanding preferred securities, if any, will be redeemed or otherwise retired prior to the Separation and that debt securities in the following approximate aggregate amounts will be redeemed prior to or following the Separation: $.51 billion for Entergy Arkansas, $.27 billion for Entergy Gulf States Louisiana, $.38 billion for Entergy Louisiana, $.29 billion for Entergy Mississippi, $.01 billion for Entergy New Orleans, and $.30 billion for Entergy Texas.  Entergy and the Utility operating companies may, subject to certain conditions, modify or supplement the manner in which the Separation is consummated.  As of December 31, 2011, net transmission plant in service, which does not include transmission-related construction work in progress or general or intangible plant, for the Utility operating companies was $.94 billion for Entergy Arkansas, $.50 billion for Entergy Gulf States Louisiana, $.71 billion for Entergy Louisiana, $.51 billion for Entergy Mississippi, $.02 billion for Entergy New Orleans, and $.62 billion for Entergy Texas.  Consummation of the Separation is subject to the satisfaction of the conditions applicable to Entergy and ITC contained in the Separation Agreement and the Merger Agreement, including that the sum of the principal amount of TransCo Securities issued to Entergy and the principal amount of the bridge facility entered into by TransCo’s subsidiaries is at least $1.775 billion.

Entergy Wholesale Commodities Authorizations to Operate Its Nuclear Power Plants

The NRC operating license for Palisades expires in 2031 and for FitzPatrick expires in 2034.  The NRC operating license for Vermont Yankee was to expire in March 2012.  In March 2011 the NRC renewed Vermont Yankee’s operating license for an additional 20 years, as a result of which the license now expires in 2032.  For additional discussion regarding the continued operation of the Vermont Yankee plant, see “ Impairment of Long-Lived Assets ” in Note 1 to the financial statements.

 

The NRC operating license for Pilgrim expires in June 2012, for Indian Point 2 expires in September 2013, and for Indian Point 3 expires in December 2015, and NRC license renewal applications are in process for these plants.  Under federal law, nuclear power plants may continue to operate beyond their license expiration dates while their renewal applications are pending NRC approval.  Various parties have expressed opposition to renewal of the

 

 

 

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licenses.  With respect to the Pilgrim license renewal, the Atomic Safety and Licensing Board (ASLB) of the NRC, after issuing an order denying a new hearing request, terminated its proceeding on Pilgrim’s license renewal application.  With the ASLB process concluded the proceeding, including appeals of certain ASLB decisions, is now before the NRC.

In April 2007, Entergy submitted an application to the NRC to renew the operating licenses for Indian Point 2 and 3 for an additional 20 years.  The ASLB has admitted 21 contentions raised by the State of New York or other parties, which were combined into 16 discrete issues.  Two of the issues have been resolved, leaving 14 issues that are currently subject to ASLB hearings.  In July 2011, the ASLB granted the State of New York’s motion for summary disposition of an admitted contention challenging the adequacy of a section of Indian Point’s environmental analysis as incorporated in the FSEIS (discussed below).  That section provided cost estimates for Severe Accident Mitigation Alternatives (SAMAs), which are hardware and procedural changes that could be implemented to mitigate estimated impacts of off-site radiological releases in case of a hypothesized severe accident.  In addition to finding that the SAMA cost analysis was insufficient, the ASLB directed the NRC staff to explain why cost-beneficial SAMAs should not be required to be implemented.  Entergy appealed the ASLB’s decision to the NRC and the NRC staff supported Entergy’s appeal, while the State of New York opposed it.  In December 2011 the NRC denied Entergy’s appeal as premature, stating that the appeal could be renewed at the conclusion of the ASLB proceedings.

 In November 2011 the ASLB issued an order establishing deadlines for the submission of several rounds of testimony on most of the contentions pending before the ASLB and for the filing of motions to limit or exclude testimony.  Initial hearings before the ASLB on the contentions for which testimony is submitted are expected to begin by the end of 2012.  Filing deadlines for testimony on certain admitted contentions remain to be set by the ASLB.

The NRC staff currently is also performing its technical and environmental reviews of the application.  The NRC staff issued a Final Safety Evaluation Report (FSER) in August 2009, a supplement to the FSER in August 2011, and a Final Supplemental Environmental Impact Statement (FSEIS) in December 2010.  The NRC staff has stated its intent to file a supplemental FSEIS in May 2012.  The New York State Department of Environmental Conservation has taken the position that Indian Point must obtain a new state-issued Clean Water Act Section 401 water quality certification as part of the license renewal process.  In addition, the consistency of Indian Point’s operations with New York State’s coastal management policies must be resolved as required by the Coastal Zone Management Act.  Entergy Wholesale Commodities’ efforts to obtain these certifications and determinations continue in 2012.

The hearing process is an integral component of the NRC’s regulatory framework, and evidentiary hearings on license renewal applications are not uncommon.  Entergy intends to participate fully in the hearing process as permitted by the NRC’s hearing rules.  As noted in Entergy’s responses to the various intervenor filings, Entergy believes the contentions proposed by the intervenors are unsupported and without merit.  Entergy will continue to work with the NRC staff as it completes its technical and environmental reviews of the license renewal application.

 

 

 

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Liquidity and Capital Resources

This section discusses Entergy’s capital structure, capital spending plans and other uses of capital, sources of capital, and the cash flow activity presented in the cash flow statement.

 

Capital Structure

Entergy’s capitalization is balanced between equity and debt, as shown in the following table.

		2011		2010
Debt to capital		57.3%		57.3%
Effect of excluding securitization bonds		(2.3)%		(2.0)%
Debt to capital, excluding securitization bonds (1)		55.0%		55.3%
Effect of subtracting cash		(1.5)%		(3.2)%
Net debt to net capital, excluding securitization bonds (1)		53.5%		52.1%

(1)	Calculation excludes the Arkansas, Louisiana, and Texas securitization bonds, which are non-recourse to Entergy Arkansas, Entergy Louisiana, and Entergy Texas, respectively.

Net debt consists of debt less cash and cash equivalents.  Debt consists of notes payable, capital lease obligations, and long-term debt, including the currently maturing portion.  Capital consists of debt, common shareholders’ equity, and subsidiaries’ preferred stock without sinking fund.  Net capital consists of capital less cash and cash equivalents.  Entergy uses the net debt to net capital ratio and the ratios excluding securitization bonds in analyzing its financial condition and believes they provide useful information to its investors and creditors in evaluating Entergy’s financial condition.

Long-term debt, including the currently maturing portion, makes up substantially all of Entergy’s total debt outstanding.  Following are Entergy’s long-term debt principal maturities and estimated interest payments as of December 31, 2011.  To estimate future interest payments for variable rate debt, Entergy used the rate as of December 31, 2011.  The amounts below include payments on the Entergy Louisiana and System Energy sale-leaseback transactions, which are included in long-term debt on the balance sheet.

Long-term debt maturities and estimated interest payments		2012		2013		2014		2015-2016		after 2016
		(In Millions)
Utility		$721		$1,197		$614		$1,524		$10,872
Entergy Wholesale Commodities		24		15		16		21		59
Parent and Other		1,972		43		43		610		535
Total		$2,717		$1,255		$673		$2,155		$11,466

Note 5 to the financial statements provides more detail concerning long-term debt outstanding.

Entergy Corporation has in place a credit facility that has a borrowing capacity of approximately $3.5 billion and expires in August 2012, which Entergy intends to renew before expiration.  Because the facility is now within one year of its expiration date, borrowings outstanding on the facility are classified as currently maturing long-term debt on the balance sheet.  Entergy Corporation also has the ability to issue letters of credit against the total borrowing capacity of the credit facility.  The facility fee is currently 0.125% of the commitment amount.  Facility fees and interest rates on loans under the credit facility can fluctuate depending on the senior unsecured debt ratings of Entergy Corporation.  The weighted average interest rate for the year ended December 31, 2011 was 0.745% on the drawn portion of the facility.

 

 

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As of December 31, 2011, amounts outstanding and capacity available under the $3.5 billion credit facility are:

 

Capacity		Borrowings		Letters of Credit		Capacity Available
(In Millions)
$3,451		$1,920		$28		$1,503

 

A covenant in Entergy Corporation’s credit facility requires Entergy to maintain a consolidated debt ratio of 65% or less of its total capitalization.  The calculation of this debt ratio under Entergy Corporation’s credit facility is different than the calculation of the debt to capital ratio above.  Entergy is currently in compliance with the covenant.  If Entergy fails to meet this ratio, or if Entergy or one of the Utility operating companies (except Entergy New Orleans) defaults on other indebtedness or is in bankruptcy or insolvency proceedings, an acceleration of the Entergy Corporation credit facility’s maturity date may occur.

Capital lease obligations are a minimal part of Entergy’s overall capital structure, and are discussed in Note 10 to the financial statements.  Following are Entergy’s payment obligations under those leases:

	2012		2013		2014		2015-2016		after 2016
	(In Millions)
Capital lease payments	$7		$6		$5		$9		$38

Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, and Entergy Texas each had credit facilities available as of December 31, 2011 as follows:

Company		Expiration Date		Amount of Facility		Interest Rate (a)		Amount Drawn as of Dec. 31, 2011
Entergy Arkansas		April 2012		$78 million (b)		3.25%		-
Entergy Gulf States Louisiana		August 2012		$100 million (c)		0.71%		-
Entergy Louisiana		August 2012		$200 million (d)		0.67%		$50 million
Entergy Mississippi		May 2012		$35 million (e)		2.05%		-
Entergy Mississippi		May 2012		$25 million (e)		2.05%		-
Entergy Mississippi		May 2012		$10 million (e)		2.05%		-
Entergy Texas		August 2012		$100 million (f)		0.77%		-

(a)	The interest rate is the weighted average interest rate as of December 31, 2011 applied, or that would be applied, to outstanding borrowings under the facility.
(b)	The credit facility requires Entergy Arkansas to maintain a debt ratio of 65% or less of its total capitalization.  Borrowings under the Entergy Arkansas credit facility may be secured by a security interest in its accounts receivable.
(c)	The credit facility allows Entergy Gulf States Louisiana to issue letters of credit against the borrowing capacity of the facility.  As of December 31, 2011, no letters of credit were outstanding.  The credit facility requires Entergy Gulf States Louisiana to maintain a consolidated debt ratio of 65% or less of its total capitalization.
(d)	The credit facility allows Entergy Louisiana to issue letters of credit against the borrowing capacity of the facility.  As of December 31, 2011, no letters of credit were outstanding.  The credit facility requires Entergy Louisiana to maintain a consolidated debt ratio of 65% or less of its total capitalization.
(e)	Borrowings under the Entergy Mississippi credit facilities may be secured by a security interest in its accounts receivable.  Entergy Mississippi is required to maintain a consolidated debt ratio of 65% or less of its total capitalization.

 

 

 

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(f)

The credit facility allows Entergy Texas to issue letters of credit against the borrowing capacity of the facility.  As of December 31, 2011, no letters of credit were outstanding.  The credit facility requires Entergy Texas to maintain a consolidated debt ratio of 65% or less of its total capitalization.  Pursuant to the terms of the credit agreement, securitization bonds are excluded from debt and capitalization in calculating the debt ratio.

 

Operating Lease Obligations and Guarantees of Unconsolidated Obligations

Entergy has a minimal amount of operating lease obligations and guarantees in support of unconsolidated obligations.  Entergy’s guarantees in support of unconsolidated obligations are not likely to have a material effect on Entergy’s financial condition, results of operations, or cash flows.  Following are Entergy’s payment obligations as of December 31, 2011 on non-cancelable operating leases with a term over one year:

	2012		2013		2014		2015-2016		after 2016
	(In Millions)
Operating lease payments	$85		$78		$79		$100		$166

The operating leases are discussed in Note 10 to the financial statements.

Summary of Contractual Obligations of Consolidated Entities

Contractual Obligations		2012		2013-2014		2015-2016		after 2016		Total
		(In Millions)
Long-term debt (1)		$2,717		$1,928		$2,155		$11,466		$18,266
Capital lease payments (2)		$7		$11		$9		$38		$65
Operating leases (2)		$85		$157		$100		$166		$508
Purchase obligations (3)		$1,803		$2,604		$1,654		$5,199		$11,260

(1)	Includes estimated interest payments.  Long-term debt is discussed in Note 5 to the financial statements.
(2)	Lease obligations are discussed in Note 10 to the financial statements.
(3)	Purchase obligations represent the minimum purchase obligation or cancellation charge for contractual obligations to purchase goods or services.  Almost all of the total are fuel and purchased power obligations.

In addition to the contractual obligations, Entergy currently expects to contribute approximately $162.9 million to its pension plans and approximately $80.4 million to other postretirement plans in 2012, although the required pension contributions will not be known with more certainty until the January 1, 2012 valuations are completed by April 1, 2012.  Entergy’s preliminary estimates of 2012 funding requirements indicate that the contributions will not exceed historical levels of pension contributions.

Also in addition to the contractual obligations, Entergy has $812 million of unrecognized tax benefits and interest net of unused tax attributes for which the timing of payments beyond 12 months cannot be reasonably estimated due to uncertainties in the timing of effective settlement of tax positions.  See Note 3 to the financial statements for additional information regarding unrecognized tax benefits.

Capital Funds Agreement

Pursuant to an agreement with certain creditors, Entergy Corporation has agreed to supply System Energy with sufficient capital to:

·	maintain System Energy’s equity capital at a minimum of 35% of its total capitalization (excluding short-term debt);

·	permit the continued commercial operation of Grand Gulf;

·	pay in full all System Energy indebtedness for borrowed money when due; and

·	enable System Energy to make payments on specific System Energy debt, under supplements to the agreement assigning System Energy’s rights in the agreement as security for the specific debt.

 

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Capital Expenditure Plans and Other Uses of Capital

Following are the amounts of Entergy’s planned construction and other capital investments by operating segment for 2012 through 2014:

Planned construction and capital investments			2012		2013		2014
			(In Millions)
Maintenance Capital:
	Utility:
	Generation		$128		$129		$131
	Transmission		282		273		255
	Distribution		433		485		496
	Other		91		89		103
	Total		934		976		985
	Entergy Wholesale Commodities		90		120		107
			1,024		1,096		1,092
Capital Commitments:
	Utility:
	Generation		$1,428		$583		$358
	Transmission		170		128		264
	Distribution		17		11		11
	Other		45		47		35
	Total		1,660		769		668
	Entergy Wholesale Commodities		259		241		291
			1,919		1,010		959
Total			$2,943		$2,106		$2,051

Maintenance Capital refers to amounts Entergy plans to spend on routine capital projects that are necessary to support reliability of its service, equipment, or systems and to support normal customer growth.

Capital Commitments refers to non-routine capital investments for which Entergy is either contractually obligated, has Board approval, or otherwise expects to make to satisfy regulatory or legal requirements.  Amounts reflected in this category include the following:

·	The currently planned construction or purchase of additional generation supply sources within the Utility’s service territory through the Utility’s portfolio transformation strategy, including three resources identified in the Summer 2009 Request for Proposal that are discussed below.

·	Entergy Louisiana’s Waterford 3 steam generators replacement project, which is discussed below.

·

System Energy’s planned approximate 178 MW uprate of the Grand Gulf nuclear plant.  On November 30, 2009, the MPSC issued a Certificate of Public Convenience and Necessity for implementation of the uprate.  A license amendment application was submitted to the NRC in September 2010.  After performing more detailed project design, engineering, analysis and major materials purchases, System Energy’s current estimate of the total capital investment to be made in the course of the implementation of the Grand Gulf uprate project is approximately $754 million, including SMEPA’s share.  The 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 System Energy evaluates the progress of the project, including the costs required to install instrumentation in the steam dryer in response to recent guidance from the NRC staff obtained during the review process for certain Requests for Additional Information (RAIs) issued by the NRC in December 2011.  The NRC’s review of the project is ongoing.  System   Energy is responding to the recent RAIs and will seek to minimize potential cost effects or delay, if any, to the Grand Gulf uprate implementation schedule.

 

 

 

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·	Transmission upgrades and spending to support the Utility’s plan to join the MISO RTO by December 2013.

·	Spending to comply with current and anticipated North American Electric Reliability Corporation transmission planning requirements.

·	Entergy Wholesale Commodities investments associated with specific investments such as dry cask storage, nuclear license renewal, component replacement and identified repairs, spending in response to the Indian Point Safety Evaluation, NYPA value sharing, and wedgewire screens at Indian Point.

·

A minimal amount of environmental compliance spending, although Entergy continues to review potential environmental spending needs and financing alternatives for any such spending, and future spending estimates could change based on the results of this continuing analysis and the implementation of new environmental laws and regulations.

The Utility’s owned generating capacity remains short of customer demand, and its supply plan initiative will continue to seek to transform its generation portfolio with new or repowered generation resources.  Opportunities resulting from the supply plan initiative, including new projects or the exploration of alternative financing sources, could result in increases or decreases in the capital expenditure estimates given above.  Estimated capital expenditures are also subject to periodic review and modification and may vary based on the ongoing effects of business restructuring, regulatory constraints and requirements, environmental regulations, business opportunities, market volatility, economic trends, changes in project plans, and the ability to access capital.

Summer 2009 Long-Term Request for Proposal

The 2012-2014 capital expenditure estimate includes the construction or purchase of three resources identified in the Summer 2009 Long-Term Request for Proposal:  a self-build option at Entergy Louisiana’s Ninemile site and agreements by two of the Utility operating companies to acquire the 620 MW Hot Spring Energy Facility and the 450 MW Hinds Energy Facility.

Ninemile Point Unit 6 Self-Build Project

In June 2011, Entergy Louisiana filed with the LPSC an application seeking certification that the public necessity and convenience would be served by Entergy Louisiana’s construction of a combined-cycle gas turbine generating facility (Ninemile 6) at its existing Ninemile Point electric generating station.  Ninemile 6 will be a nominally-sized 550 MW unit that is estimated to cost approximately $721 million to construct, excluding interconnection and transmission upgrades.  Entergy Gulf States Louisiana joined in the application, seeking certification of its purchase under a life-of-unit power purchase agreement of up to 35% of the capacity and energy generated by Ninemile 6.  The Ninemile 6 capacity and energy is proposed to be allocated 55% to Entergy Louisiana, 25% to Entergy Gulf States Louisiana, and 20% to Entergy New Orleans.  In February 2012 the City Council passed a resolution authorizing Entergy New Orleans to purchase 20% of the Ninemile 6 energy and capacity.  If approvals are obtained from the LPSC and other permitting agencies, Ninemile 6 construction is expected to begin in 2012, and the unit is expected to commence commercial operation by mid-2015.  The ALJ has established a schedule for the LPSC proceeding that includes February 27 - March 7, 2012, hearing dates.

Hot Spring Energy Facility Purchase Agreement

In April 2011, Entergy Arkansas 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 a subsidiary of KGen Power Corporation.  The purchase price is expected to be approximately $253 million.  Entergy Arkansas also expects to invest in various plant upgrades at the facility after closing and expects the total cost of the acquisition, including plant upgrades, transaction costs, and contingencies, to be approximately $277 million.  A new transmission service request has been submitted to the ICT to determine if investments for

 

 

 

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supplemental upgrades in the Entergy transmission system are needed to make energy from the Hot Spring Energy Facility deliverable to Entergy Arkansas for the period after Entergy Arkansas exits the System Agreement.  The initial results of the service request were received in January 2012 and indicate that available transfer capability does not exist with existing transmission facilities and that upgrades are required.  The studies do not provide a final and definitive indication of what those upgrades would be.  Entergy Arkansas has submitted transmission service requests for facilities studies which, when performed by the ICT, will provide more detailed estimates of the transmission upgrades and the associated costs required to obtain network service for the Hot Spring plant.  Accordingly there are still uncertainties that must be resolved.  The purchase is contingent upon, among other things, obtaining necessary approvals, including full cost recovery, from various federal and state regulatory and permitting agencies.  These include regulatory approvals from the APSC and the FERC, as well as clearance under the Hart-Scott-Rodino anti-trust law.  In February 2012 the FERC issued an order approving the acquisition.  Closing is expected to occur in mid-2012.

In July 2011, Entergy Arkansas filed its application with the APSC requesting approval of the acquisition and full cost recovery.  I n January 2012, Entergy Arkansas, the APSC General Staff, and the Arkansas Attorney General filed a Motion to Suspend the Procedural Schedule and Joint Stipulation and Settlement for consideration by the APSC.  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 return on equity reflected in the rider would be submitted to the APSC for resolution.  Because the transmission upgrade costs remain uncertain, the parties requested that the APSC suspend the procedural schedule and cancel the hearing scheduled for January 24, 2012, pending resolution of the transmission costs.  The APSC issued an order accepting the settlement as part of the record and directing E ntergy Arkansas to file the transmission studies when available and directing the parties to propose a procedural schedule to address the results of those studies.

Hinds Energy Facility Purchase Agreement

In April 2011, Entergy Mississippi announced that it has signed an asset purchase agreement to acquire the Hinds Energy Facility, a 450 MW natural gas-fired combined-cycle turbine plant located in Jackson, Mississippi, from a subsidiary of KGen Power Corporation.  The purchase price is expected to be approximately $206 million.  Entergy Mississippi also expects to invest in various plant upgrades at the facility after closing and expects the total cost of the acquisition to be approximately $246 million.  A new transmission service request has been submitted to determine if investments for supplemental upgrades in the Entergy transmission system are needed to make the Hinds Energy Facility deliverable to Entergy Mississippi for the period after Entergy Mississippi exits the System Agreement.  Facilities studies are ongoing to determine transmission upgrades costs associated with the plant, with results expected by early March 2012.  The purchase is contingent upon, among other things, obtaining necessary approvals, including full cost recovery, from various federal and state regulatory and permitting agencies.  These include regulatory approvals from the MPSC and the FERC, as well as clearance under the Hart-Scott-Rodino anti-trust law.   In February 2012 the FERC issued an order approving the acquisition.   Closing is expected to occur in mid-2012.  In July 2011, Entergy Mississippi filed with the MPSC requesting approval of the acquisition and full cost recovery.  A hearing on the request for a certificate of public convenience and necessity is scheduled for February 28, 2012.  A hearing on Entergy Mississippi’s proposed cost recovery has not been scheduled.

Waterford 3 Steam Generator Replacement Project

Entergy Louisiana planned to replace the Waterford 3 steam generators, along with the reactor vessel closure head and control element drive mechanisms, in the spring 2011.  Replacement of these components is common to pressurized water reactors throughout the nuclear industry.  In December 2010, Entergy Louisiana advised the LPSC that the replacement generators would not be completed and delivered by the manufacturer in time to install them during the spring 2011 refueling outage.  During the final steps in the manufacturing process, the manufacturer discovered separation of stainless steel cladding from the carbon steel base metal in the channel head of both

 

 

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replacement steam generators (RSGs), in areas beneath and adjacent to the divider plate.  As a result of this damage, the manufacturer was unable to meet the contractual delivery deadlines, and the RSGs were not installed in the spring 2011.  Entergy Louisiana worked with the manufacturer to fully develop and evaluate repair options, and expects the replacement steam generators to be delivered in time for the Fall 2012 refueling outage.  Extensive inspections of the existing steam generators at Waterford 3 in cooperation with the manufacturer were completed in April 2011.  The review of data obtained during these inspections supports the conclusion that Waterford 3 can operate safely for another full cycle before the replacement of the existing steam generators.  Entergy Louisiana has formally reported its findings to the NRC.  At this time, a requirement to perform a mid-cycle outage for further inspections in order to allow the plant to continue operation until its Fall 2012 refueling outage is not anticipated.  Entergy Louisiana currently expects the cost of the project, including carrying costs, to be approximately $687 million, assuming the replacement occurs during the Fall 2012 refueling outage.

In June 2008, Entergy Louisiana filed with the LPSC for approval of the replacement project, including full cost recovery.  Following discovery and the filing of testimony by the LPSC staff and an intervenor, the parties entered into a stipulated settlement of the proceeding.  The LPSC unanimously approved the settlement in November 2008.  The settlement resolved the following issues: 1) the accelerated degradation of the steam generators is not the result of any imprudence on the part of Entergy Louisiana; 2) the decision to undertake the replacement project at the then-estimated cost of $511 million is in the public interest, is prudent, and would serve the public convenience and necessity; 3) the scope of the replacement project is in the public interest; 4) undertaking the replacement project at the target installation date during the 2011 refueling outage is in the public interest; and 5) the jurisdictional costs determined to be prudent in a future prudence review are eligible for cost recovery, either in an extension or renewal of the formula rate plan or in a full base rate case including necessary pro forma adjustments.  Upon completion of the replacement project, the LPSC will undertake a prudence review with regard to the following aspects of the replacement project: 1) project management; 2) cost controls; 3) success in achieving stated objectives; 4) the costs of the replacement project; and 5) the outage length and replacement power costs.

In November 2011 the LPSC approved a one-year extension of Entergy Louisiana’s current formula rate plan.  The next formula rate plan filing, for the 2011 test year, will be made in May 2012 and will include a separate identification of any operating and maintenance expense savings that are expected to occur once the Waterford 3 steam generator replacement project is complete.  Pursuant to the LPSC decision, from September 2012 through December 2012 earnings above an 11.05% return on common equity (based on the 2011 test year) would be accrued and used to offset the Waterford 3 replacement steam generator revenue requirement for the first twelve months that the unit is in rates.  If the project is not in service by January 1, 2013, earnings above a 10.25% return on common equity (based on the 2011 test year) for the period January 1, 2013 through the date that the project is placed in service will be accrued and used to offset the incremental revenue requirement for the first twelve months that the unit is in rates.  Upon the in-service date of the replacement steam generators, rates will increase, subject to refund following any prudence review, by the full revenue requirement associated with the replacement steam generators, less (i) the previously accrued excess earnings from September 2012 until the in-service date and (ii) any earnings above a 10.25% return on common equity (based on the 2011 test year) for the period following the in-service date, provided that the excess earnings accrued prior to the in-service date shall only offset the revenue requirement for the first year of operation of the replacement steam generators.  These rates are anticipated to remain in effect until Entergy Louisiana’s next full rate case is resolved.  Entergy Louisiana currently anticipates filing a full rate case by January 2013.

Dividends and Stock Repurchases

Declarations of dividends on Entergy’s common stock are made at the discretion of the Board.  Among other things, the Board evaluates the level of Entergy’s common stock dividends based upon Entergy’s earnings, financial strength, and future investment opportunities.  At its January 2012 meeting, the Board declared a dividend of $0.83 per share, which is the same quarterly dividend per share that Entergy has paid since the second quarter 2010.  The prior quarterly dividend per share was $0.75.  Entergy paid $590 million in 2011, $604 million in 2010, and $577 million in 2009 in cash dividends on its common stock.

 

 

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In accordance with Entergy’s stock-based compensation plan, Entergy periodically grants stock options to key employees, which may be exercised to obtain shares of Entergy’s common stock.  According to the plan, these shares can be newly issued shares, treasury stock, or shares purchased on the open market.  Entergy’s management has been authorized by the Board to repurchase on the open market shares up to an amount sufficient to fund the exercise of grants under the plan.

In addition to the authority to fund grant exercises, in January 2007 the Board approved a program under which Entergy was authorized to repurchase up to $1.5 billion of its common stock.  In January 2008, the Board authorized an incremental $500 million share repurchase program to enable Entergy to consider opportunistic purchases in response to equity market conditions.  Entergy completed both the $1.5 billion and $500 million programs in the third quarter 2009.  In October 2009 the Board granted authority for an additional $750 million share repurchase program which was completed in the fourth quarter 2010.  In October 2010 the Board granted authority for an additional $500 million share repurchase program.  As of December 31, 2011, $350 million of authority remains under the $500 million share repurchase program.  The amount of repurchases may vary as a result of material changes in business results or capital spending or new investment opportunities, or if limitations in the credit markets continue for a prolonged period.

Sources of Capital

Entergy’s sources to meet its capital requirements and to fund potential investments include:

·	internally generated funds;

·	cash on hand ($694 million as of December 31, 2011);

·	securities issuances;

·	bank financing under new or existing facilities; and

·	sales of assets.

Circumstances such as weather patterns, fuel and purchased power price fluctuations, and unanticipated expenses, including unscheduled plant outages and storms, could affect the timing and level of internally generated funds in the future.

Provisions within the Articles of Incorporation or pertinent indentures and various other agreements relating to the long-term debt and preferred stock of certain of Entergy Corporation’s subsidiaries could restrict the payment of cash dividends or other distributions on their common and preferred stock.  As of December 31, 2011, under provisions in their mortgage indentures, Entergy Arkansas and Entergy Mississippi had restricted retained earnings unavailable for distribution to Entergy Corporation of $394.9 million and $68.5 million, respectively.  All debt and common and preferred equity issuances by the Registrant Subsidiaries require prior regulatory approval and their preferred equity and debt issuances are also subject to issuance tests set forth in corporate charters, bond indentures, and other agreements.  Entergy believes that the Registrant Subsidiaries have sufficient capacity under these tests to meet foreseeable capital needs.

The FERC has jurisdiction over securities issuances by the Utility operating companies and System Energy (except securities with maturities longer than one year issued by Entergy Arkansas and Entergy New Orleans, which are subject to the jurisdiction of the APSC and the City Council, respectively).  No regulatory approvals are necessary for Entergy Corporation to issue securities.  The current FERC-authorized short-term borrowing limits are effective through October 31, 2013.  Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy Texas, and System Energy have obtained long-term financing authorizations from the FERC that extend through July 2013.  Entergy Arkansas has obtained long-term financing authorization from the APSC that extends through December 2012.  Entergy New Orleans has obtained long-term financing authorization from the City Council that extends through July 2012.  In addition to borrowings from commercial banks, the FERC short-term borrowing orders authorize the Registrant Subsidiaries to continue as participants in the Entergy System money pool.  The money pool is an

 

 

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intercompany borrowing arrangement designed to reduce Entergy’s subsidiaries’ dependence on external short-term borrowings.  Borrowings from the money pool and external short-term borrowings combined may not exceed the FERC-authorized limits.  See Notes 4 and 5 to the financial statements for further discussion of Entergy’s borrowing limits, authorizations, and amounts outstanding.

In January 2012, Entergy Corporation issued $500 million of 4.70% senior notes due January 2017.  Entergy Corporation used the proceeds to repay borrowings under its $3.5 billion credit facility.

In January 2012, Entergy Louisiana issued $250 million of 1.875% Series first mortgage bonds due December 2014.  Entergy Louisiana used the proceeds to repay short-term borrowings under the Entergy System money pool.

Hurricane Gustav and Hurricane Ike

In September 2008, Hurricane Gustav and Hurricane Ike caused catastrophic damage to portions of Entergy's service territories in Louisiana and Texas, and to a lesser extent in Arkansas and Mississippi.  The storms resulted in widespread power outages, significant damage to distribution, transmission, and generation infrastructure, and the loss of sales during the power outages.  In September 2009, Entergy Gulf States Louisiana and Entergy Louisiana and the Louisiana Utilities Restoration Corporation (LURC), an instrumentality of the State of Louisiana, filed with the LPSC an application requesting that the LPSC grant financing orders authorizing the financing of Entergy Gulf States Louisiana’s and Entergy Louisiana’s   storm costs, storm reserves, and issuance costs pursuant to Act 55 of the Louisiana Regular Session of 2007 (Act 55 financings).  In July 2010 the Louisiana Local Government Environmental Facilities and Community Development Authority (LCDA) issued $468.9 million in bonds under Act 55.  From the $462.4 million of bond proceeds loaned by the LCDA to the LURC, the LURC deposited $200 million in a restricted escrow account as a storm damage reserve for Entergy Louisiana and transferred $262.4 million directly to Entergy Louisiana.  In July 2010 the LCDA issued another $244.1 million in bonds under Act 55.  From the $240.3 million of bond proceeds loaned by the LCDA to the LURC, the LURC deposited $90 million in a restricted escrow account as a storm damage reserve for Entergy Gulf States Louisiana and transferred $150.3 million directly to Entergy Gulf States Louisiana.  Entergy, Entergy Gulf States Louisiana, and Entergy Louisiana do not report the bonds on their balance sheets because the bonds are the obligation of the LCDA, and there is no recourse against Entergy, Entergy Gulf States Louisiana or Entergy Louisiana in the event of a bond default.  See Note 2 to the financial statements for additional discussion of the Act 55 financings.

In November 2009, Entergy Texas Restoration Funding, LLC (Entergy Texas Restoration Funding), a company wholly-owned and consolidated by Entergy Texas, issued $545.9 million of senior secured transition bonds (securitization bonds) to finance Entergy Texas Hurricane Ike and Hurricane Gustav restoration costs.  See Note 2 to the financial statements for a discussion of the proceeding approving the issuance of the securitization bonds and see Note 5 to the financial statements for a discussion of the terms of the securitization bonds.

In the third quarter 2009, Entergy settled with its insurer on its Hurricane Ike claim and Entergy Texas received $75.5 million in proceeds (Entergy received a total of $76.5 million).

Entergy Arkansas January 2009 Ice Storm

In January 2009, a severe ice storm caused significant damage to Entergy Arkansas’s transmission and distribution lines, equipment, poles, and other facilities.  A law was enacted in April 2009 in Arkansas that authorizes securitization of storm damage restoration costs.  In June 2010, the APSC issued a financing order authorizing the issuance of storm cost recovery bonds, including carrying costs of $11.5 million and $4.6 million of up-front financing costs.  In August 2010, Entergy Arkansas Restoration Funding, LLC, a company wholly-owned and consolidated by Entergy Arkansas, issued $124.1 million of storm cost recovery bonds.  See Note 5 to the financial statements for additional discussion of the issuance of the storm cost recovery bonds.

 

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Entergy Louisiana Securitization Bonds – Little Gypsy

In August 2011, the LPSC issued a financing order authorizing the issuance of bonds to recover Entergy Louisiana’s investment recovery costs associated with the cancelled Little Gypsy repowering project.  In September 2011, Entergy Louisiana Investment Recovery Funding I, L.L.C., a company wholly-owned and consolidated by Entergy Louisiana, issued $207.2 million of senior secured investment recovery bonds.  The bonds have an interest rate of 2.04% and an expected maturity date of June 2021.  See Note 5 to the financial statements for additional discussion of the issuance of the investment recovery bonds.

Cash Flow Activity

As shown in Entergy’s Statements of Cash Flows, cash flows for the years ended December 31, 2011, 2010, and 2009 were as follows:

			2011		2010		2009
			(In Millions)
Cash and cash equivalents at beginning of period			$1,295		$1,710		$1,920
Cash flow provided by (used in):
	Operating activities		3,128		3,926		2,933
	Investing activities		(3,447)		(2,574)		(2,094)
	Financing activities		(282)		(1,767)		(1,048)
Effect of exchange rates on cash and cash equivalents			-		-		(1)
	Net decrease in cash and cash equivalents		(601)		(415)		(210)
Cash and cash equivalents at end of period			$694		$1,295		$1,710

Operating Cash Flow Activity

2011 Compared to 2010

Entergy's cash flow provided by operating activities decreased by $797 million in 2011 compared to 2010 primarily due to the receipt in July 2010 of $703 million from the Louisiana Utilities Restoration Corporation as a result of the Louisiana Act 55 storm cost financings for Hurricane Gustav and Hurricane Ike.  The Act 55 storm cost financings are discussed in Note 2 to the financial statements.  The decrease in Entergy Wholesale Commodities net revenue that is discussed above also contributed to the decrease in operating cash flow.

2010 Compared to 2009

Entergy’s cash flow provided by operating activities increased $993 million in 2010 compared to 2009 primarily due to the receipt in July 2010 of $703 million from the Louisiana Utilities Restoration Corporation as a result of the Louisiana Act 55 storm cost financings, as noted in the preceding paragraph.  In addition, the absence of the Hurricane Gustav, Hurricane Ike, and Arkansas ice storm restoration spending that occurred in 2009 also contributed to the increase.  These factors were partially offset by an increase of $323 million in pension contributions at Utility and Entergy Wholesale Commodities and a decrease in net revenue at Entergy Wholesale Commodities.  See “ Critical Accounting Estimates - Qualified Pension and Other Postretirement Benefits” below and also Note 11 to the financial statements for further discussion of pension funding.

 

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Investing Activities

2011 Compared to 2010

Net cash used in investing activities increased $873 million in 2011 compared to 2010 primarily due to the following activity:

·

the purchase of the Acadia Power Plant by Entergy Louisiana for approximately $300 million in April 2011, the purchase of the Rhode Island State Energy Center for approximately $346 million by an Entergy Wholesale Commodities subsidiary in December 2011, and the sale of an Entergy Wholesale Commodities subsidiary’s ownership interest in the Harrison County Power Project for proceeds of $219 million in 2010.  These transactions are described in more detail in Note 15 to the financial statements;

·	an increase in nuclear fuel purchases because of variations from year to year in the timing and pricing of fuel reload requirements, material and services deliveries, and the timing of cash payments during the nuclear fuel cycle; and

·

a slight increase in construction expenditures, including spending resulting from April 2011 storms that caused damage to transmission and distribution lines, equipment, poles, and other facilities, primarily in Arkansas.  The capital cost of repairing that damage was approximately $55 million.  Entergy’s construction spending plans for 2012 through 2014 are discussed in “Management’s Financial Discussion and Analysis - Capital Expenditure Plans and Other Uses of Capital .”

These increases were offset by the investment in 2010 of a total of $290 million in Entergy Gulf States Louisiana’s and Entergy Louisiana’s storm reserve escrow accounts as a result of their Act 55 storm cost financings, which are discussed in Note 2 to the financial statements.

2010 Compared to 2009

Net cash used in investing activities increased $480 million in 2010 compared to 2009 primarily due to the following activity:

·

an increase in net uses of cash for nuclear fuel purchases, which was caused by the consolidation of the nuclear fuel company variable interest entities that is discussed in Note 18 to the financial statements.  With the consolidation of the nuclear fuel company variable interest entities, their purchases of nuclear fuel from Entergy are now eliminated in consolidation, whereas before 2010 they were a source of investing cash flows;

·	the investment of a total of $290 million in Entergy Gulf States Louisiana’s and Entergy Louisiana’s storm reserve escrow accounts as a result of their Act 55 storm cost financings, which are discussed in Note 2 to the financial statements;

·	an increase in construction expenditures, primarily in the Entergy Wholesale Commodities business, as decreases for the Utility resulting from Hurricane Gustav, Hurricane Ike, and Arkansas ice storm restoration spending in 2009 were offset by spending on various projects; and

·	the sale of an Entergy Wholesale Commodities subsidiary’s ownership interest in the Harrison County Power Project for proceeds of $219 million in 2010.  The sale is described in more detail in Note 15 to the financial statements.

Financing Activities

2011 Compared to 2010

Net cash used in financing activities decreased $1,485 million in 2011 compared to 2010 primarily because long-term debt activity provided approximately $554 million of cash in 2011 and used approximately $307 million of cash in 2010.  The most significant long-term debt activity in 2011 included the issuance of $207 million of securitization bonds by a subsidiary of Entergy Louisiana, the issuance of $200 million of first mortgage bonds by Entergy

 

 

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Louisiana, and Entergy Corporation increasing the borrowings outstanding on its 5-year credit facility by $288 million.  For the details of Entergy’s long-term debt outstanding on December 31, 2011 and 2010 see Note 5 to the financial statements herein.  In addition to the long-term debt activity, Entergy Corporation repurchased $236 million of its common stock in 2011 and repurchased $879 million of its common stock in 2010.  Entergy’s stock repurchases are discussed further in the “ Capital Expenditure Plans and Other Uses of Capital - Dividends and Stock Repurchases” section above.

2010 Compared to 2009

Net cash used in financing activities increased $719 million in 2010 compared to 2009 primarily because long-term debt activity used approximately $307 million of cash in 2010 and provided approximately $160 million of cash in 2009.  The most significant net use for long-term debt activity was by Entergy Corporation, which reduced its 5-year credit facility balance by $934 million and repaid a total of $275 million of notes and bank term loans, while issuing $1 billion of notes in 2010.  For the details of Entergy’s long-term debt outstanding see Note 5 to the financial statements herein.  In addition, Entergy Corporation repurchased $879 million of its common stock in 2010 and repurchased $613 million of its common stock in 2009.  Entergy’s stock repurchases are discussed further in the “ Capital Expenditure Plans and Other Uses of Capital - Dividends and Stock Repurchases” section above.

Rate, Cost-recovery, and Other Regulation

State and Local Rate Regulation and Fuel-Cost Recovery

The rates that the Utility operating companies and System Energy charge for their services significantly influence Entergy’s financial position, results of operations, and liquidity.  These companies are regulated and the rates charged to their customers are determined in regulatory proceedings.  Governmental agencies, including the APSC, the City Council, the LPSC, the MPSC, the PUCT, and the FERC, are primarily responsible for approval of the rates charged to customers.  Following is a summary of the Utility operating companies’ authorized returns on common equity and current retail base rates .  The Utility operating companies’ base rate, fuel and purchased power cost recovery, and storm cost recovery proceedings are discussed in Note 2 to the financial statements.

Company		Authorized Return on Common Equity
Entergy Arkansas		10.2%		-   Current retail base rates implemented in the July 2010 billing cycle pursuant to a settlement approved by the APSC.
Entergy Gulf States Louisiana		9.9%-11.4% Electric; 10.0%-11.0% Gas		-   Current retail electric base rates implemented based on Entergy Gulf States Louisiana's 2010 test year formula rate plan filing approved by the LPSC. -   Current retail gas base rates reflect the rate stabilization plan filing for the 2010 test year ended September 2010.
Entergy Louisiana		9.45%- 11.05%		-   Current retail base rates based on Entergy Louisiana's 2010 test year formula rate plan filing approved by the LPSC.
Entergy Mississippi		10.54%- 12.72%		-   Current retail base rates reflect Entergy Mississippi's latest formula rate plan filing, based on the 2010 test year, and a stipulation approved by the MPSC.

 

 

 

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Company		Authorized Return on Common Equity
Entergy New Orleans		10.7% - 11.5% Electric; 10.25% - 11.25% Gas		-   Current retail base rates reflect Entergy New Orleans's 2010 test year formula rate plan filing and a settlement approved by the City Council.
Entergy Texas		10.125%		-   Current retail base rates reflect Entergy Texas's 2009 base rate case filing and a settlement approved by the PUCT.

Federal Regulation

Independent Coordinator of Transmission

In 2000, the FERC issued an order encouraging utilities to voluntarily place their transmission facilities under the control of independent RTOs (regional transmission organizations).  Delays in implementing the FERC RTO order occurred due to a variety of reasons, including the fact that utility companies, other stakeholders, and federal and state regulators have had to work to resolve various issues related to the establishment of such RTOs.  In November 2006, the Utility operating companies installed the Southwest Power Pool (SPP), a regional transmission organization, as their Independent Coordinator of Transmission (ICT).  The installation does not transfer control of Entergy’s transmission system to the ICT, but rather vests with the ICT responsibility for:

·	granting or denying transmission service on the Utility operating companies’ transmission system.

·	administering the Utility operating companies’ OASIS node for purposes of processing and evaluating transmission service requests and ensuring compliance with the Utility operating companies’ obligation to post transmission-related information.

·

developing a base plan for the Utility operating companies’ transmission system that will result in the ICT making the determination on whether costs of transmission upgrades should be rolled into the Utility operating companies’ transmission rates or directly assigned to the customer requesting or causing an upgrade to be constructed.  This should result in a transmission pricing structure that ensures that the Utility operating companies’ retail native load customers are required to pay for only those upgrades necessary to reliably and economically serve their needs.

·	serving as the reliability coordinator for the Entergy transmission system.

·	overseeing the operation of the weekly procurement process (WPP).

·

evaluating interconnection-related investments already made on the Entergy System for purposes of determining the future allocation of the uncredited portion of these investments, pursuant to a detailed methodology.  The ICT agreement also clarifies the rights that customers receive when they fund a supplemental upgrade.

The FERC, in conjunction with the APSC, the LPSC, the MPSC, the PUCT, and the City Council, hosted a conference on June 24, 2009, to discuss the ICT arrangement and transmission access on the Entergy transmission system.  During the conference, several issues were raised by regulators and market participants, including the adequacy of the Utility operating companies’ capital investment in the transmission system, the Utility operating companies’ compliance with the existing North American Electric Reliability Corporation (NERC) reliability planning standards, the availability of transmission service across the system, and whether the Utility operating companies could have purchased lower cost power from merchant generators located on the transmission system rather than running their older generating facilities.  On July 20, 2009, the Utility operating companies filed comments with the FERC responding to the issues raised during the conference.  The comments explain that: 1) the Utility operating companies believe that the ICT arrangement has fulfilled its objectives; 2) the Utility operating companies’ transmission

 

 

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planning practices comply with laws and regulations regarding the planning and operation of the transmission system; and 3) these planning practices have resulted in a system that meets applicable reliability standards and is sufficiently robust to allow the Utility operating companies both to substantially increase the amount of transmission service available to third parties and to make significant amounts of economic purchases from the wholesale market for the benefit of the Utility operating companies’ retail customers.   The Utility operating companies also explain that, as with other transmission systems, there are certain times during which congestion occurs on the Utility operating companies’ transmission system that limits the ability of the Utility operating companies as well as other parties to fully utilize the generating resources that have been granted transmission service.  Additionally, the Utility operating companies commit in their response to exploring and working on potential reforms or alternatives for the ICT arrangement that could take effect following the initial term.  The Utility operating companies’ comments also recognize that NERC is in the process of amending certain of its transmission reliability planning standards and that the amended standards, if approved by the FERC, will result in more stringent transmission planning criteria being applicable in the future.  The FERC may also make other changes to transmission reliability standards.  These changes to the reliability standards would result in increased capital expenditures by the Utility operating companies.

The Entergy Regional State Committee (E-RSC), which is comprised of representatives from all of the Utility operating companies' retail regulators, has been formed to consider several of these issues related to Entergy's transmission system.  Among other things, the E-RSC in concert with the FERC conducted a cost/benefit analysis comparing the ICT arrangement to other transmission proposals, including participation in a regional transmission organization.

In September 2010, as modified in October 2010, the Utility operating companies filed a request for a two-year interim extension, with certain modifications, of the ICT arrangement, which was scheduled to expire on November 17, 2010.  In November 2010 the 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.  In addition, in December 2010 the FERC issued an order that granted the E-RSC additional authority over transmission upgrades and cost allocation.

System Agreement

The FERC regulates wholesale rates (including Entergy Utility intrasystem energy allocations pursuant to the System Agreement) and interstate transmission of electricity, as well as rates for System Energy’s sales of capacity and energy from Grand Gulf to Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans pursuant to the Unit Power Sales Agreement.  The Utility operating companies historically have engaged in the coordinated planning, construction, and operation of generating and bulk transmission facilities under the terms of the System Agreement, which is a rate schedule that has been approved by the FERC.  Certain of the Utility operating companies’ retail regulators and other parties are pursuing litigation involving the System Agreement at the FERC.  The proceedings include challenges to the allocation of costs as defined by the System Agreement and allegations of imprudence by the Utility operating companies in their execution of their obligations under the System Agreement.  See Note 2 to the financial statements for discussions of this litigation.

Entergy Arkansas and Entergy Mississippi Notices of Termination of System Agreement Participation

Citing its concerns that the benefits of its continued participation in the current form of the System Agreement have been seriously eroded, in December 2005, Entergy Arkansas submitted its notice that it will terminate its participation in the current System Agreement effective ninety-six ( 96) months from the date of the notice or such earlier date as authorized by the FERC.

In October 2007 the MPSC issued a letter confirming its belief that Entergy Mississippi should exit the System Agreement in light of the recent developments involving the System Agreement.  In November 2007, Entergy Mississippi provided its written notice to terminate its participation in the System Agreement effective ninety-six (96) months from the date of the notice or such earlier date as authorized by the FERC.

 

 

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On February 2, 2009, Entergy Arkansas and Entergy Mississippi filed with the FERC their notices of cancellation to terminate their participation in the Entergy System Agreement, effective December 18, 2013 and November 7, 2015, respectively.  While the FERC had indicated previously that the notices should be filed 18 months prior to Entergy Arkansas’s termination (approximately mid-2012), the filing explains that resolving this issue now, rather than later, is important to ensure that informed long-term resource planning decisions can be made during the years leading up to Entergy Arkansas’s withdrawal and that all of the Utility operating companies are properly positioned to continue to operate reliably following Entergy Arkansas’s and, eventually, Entergy Mississippi’s, departure from the System Agreement.

In November 2009 the FERC accepted the notices of cancellation and determined that Entergy Arkansas and Entergy Mississippi are permitted to withdraw from the System Agreement following the 96 month notice period without payment of a fee or the requirement to otherwise compensate the remaining Utility operating companies as a result of withdrawal.  In February 2011 the FERC denied the LPSC’s and the City Council’s rehearing requests.  The LPSC has appealed the FERC’s decision to the U.S. Court of Appeals for the District of Columbia and oral argument was held January 13, 2012.

Arkansas Public Service Commission System Agreement Investigation

The APSC had previously commenced an investigation, in 2004, into whether Entergy Arkansas’s continued participation in the System Agreement is in the best interests of its customers.  In February 2010 the APSC issued a show cause order opening an investigation regarding the prudence of Entergy Arkansas’s entering a successor pooling agreement with the other Entergy Utility operating companies, as opposed to becoming a standalone entity upon exit from the System Agreement in December 2013, and whether Entergy Arkansas, as a standalone utility, should join the SPP RTO.  The APSC subsequently added evaluation of Entergy Arkansas joining the Midwest Independent Transmission System Operator (MISO) RTO on a standalone basis as an alternative to be considered.  In August 2010, the APSC directed Entergy Arkansas and all parties to compare five strategic options at the same time as follows: (1) Entergy Arkansas Self-Provide; (2) Entergy Arkansas with 3rd party coordination agreements; (3) Successor Arrangements; (4) Entergy Arkansas as a standalone member of SPP RTO; and (5) Entergy Arkansas as a standalone member of the MISO RTO.

LPSC and City Council Action Related to the Entergy Arkansas and Entergy Mississippi Notices of Termination

In light of the notices of Entergy Arkansas and Entergy Mississippi to terminate participation in the current System Agreement, in January 2008 the LPSC unanimously voted to direct the LPSC Staff to begin evaluating the potential for a successor arrangement.  The New Orleans City Council opened a docket to gather information on progress towards a successor arrangement.  The LPSC subsequently passed a resolution stating that it cannot evaluate successor arrangements without having certainty about System Agreement exit obligations.

Entergy’s Proposal to Join the MISO RTO

On April 25, 2011, Entergy announced that each of the Utility operating companies propose joining the MISO RTO, which is expected to provide long-term benefits for the customers of each of the Utility operating companies.  MISO is a regional transmission organization that operates in 12 U.S. states (Illinois, Indiana, Iowa, Kentucky, Michigan, Minnesota, Missouri, Montana, North Dakota, Ohio, South Dakota, and Wisconsin) and also in Canada.  The Utility operating companies provided analysis in May 2011 to their retail regulators supporting this decision.  The APSC received additional information from Entergy, MISO, and other parties and held an evidentiary hearing in September 2011.  The APSC issued an order in the proceeding in October 2011 finding that it is prudent for Entergy Arkansas to join an RTO but deferred a decision on Entergy Arkansas’s plan to join the MISO RTO until Entergy Arkansas files an application to transfer control of its transmission assets to the MISO RTO.

 

 

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Entergy’s May 2011 filings estimate that the transition and implementation costs of joining the MISO RTO could be up to $105 million if all of the Utility operating companies join the MISO RTO, most of which will be spent in late 2012 and 2013.  Maintaining the viability of the alternatives of Entergy Arkansas joining the MISO RTO alone or standing alone within an ICT arrangement is expected to result in an additional cost of approximately $35 million, for a total estimated cost of up to $140 million.  This amount could increase with extended litigation in various regulatory proceedings.  It is expected that costs will be incurred to obtain regulatory approvals, to revise or implement commercial and legal agreements, to integrate transmission and generation facilities, to develop back-office accounting and settlement systems, and to build out communications infrastructure.

In the fourth quarter 2011, Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans filed applications with their local regulators concerning their proposal to join the MISO RTO and transfer control of each company’s transmission assets to the MISO RTO.  Entergy Texas expects to submit its filing in 2012.  The applications to join the MISO RTO seek a finding that membership in the MISO RTO is in the public interest.  Becoming a member of the MISO RTO will not affect the ownership by the Utility operating companies of their generation and transmission facilities or the responsibility for maintaining those facilities.  Once the Utility operating companies are fully integrated as members, however, the MISO RTO will assume control of transmission planning and congestion management and, through its Day 2 market, the commitment and dispatch of generation that is bid into the MISO RTO’s markets.  The APSC, the LPSC, and the MPSC have established procedural schedules with hearings scheduled in May/June 2012.  The FERC filings related to integrating the Utility operating companies into the MISO RTO are planned for late 2012 or early 2013.  The target implementation date for joining the MISO RTO is December 2013.

Entergy believes that the decision to join the MISO RTO should be evaluated separately from and independent of the decision regarding the ownership of Entergy’s transmission system, and Entergy plans to pursue the MISO RTO proposal and the planned spin-off and merger of the transmission business on parallel regulatory paths.  In December 2011, however, the LPSC ALJ in the MISO RTO proceeding ordered Entergy Gulf States Louisiana and Entergy Louisiana to file testimony regarding the impact of the proposed spin-off and merger of Entergy’s transmission business on the application to join the MISO RTO.  Entergy Gulf States Louisiana and Entergy Louisiana complied with this order, but also filed a notice of objection and reservation of rights in response to the order, stating that the testimony, as well as related discovery and other proceedings, are not relevant to the decision to join the MISO RTO.  In the APSC proceeding regarding the MISO RTO proposal, in February 2012 the APSC ordered the parties to consider to what extent, if any, the proposed spin-off and merger of Entergy’s transmission business might affect Entergy Arkansas’s membership in an RTO or otherwise affect the proceeding.  The next round of testimony in the APSC proceeding is scheduled for March 2012.

In June 2011, MISO filed with the FERC a request for a transitional waiver of provisions of its open access transmission, energy, and operating reserve markets tariff regarding allocation of transmission network upgrade costs, in order to establish a transition for the integration of the Utility operating companies.  Several parties intervened in the proceeding, including Entergy, the APSC, the LPSC, and the City Council, and some of the parties also filed comments or protests.  In September 2011 the FERC issued an order denying on procedural grounds MISO’s request, further advising MISO that submitting modified tariff sheets is the appropriate method for implementing the transition that MISO seeks for the Utility operating companies.  The FERC did not address the merits of any transition arrangements that may be appropriate to integrate the Utility operating companies into the MISO RTO.  MISO worked with its stakeholders to prepare the appropriate changes to its tariff and filed the proposed tariff changes with the FERC in November 2011.  Numerous entities filed interventions and protests to MISO’s filing.  On January 25, 2012, the FERC sent a letter to MISO requesting additional information relating to MISO’s proposed tariff changes.

Notice to SERC Reliability Corporation Regarding Reliability Standards and FERC Investigation

Entergy has notified the SERC Reliability Corporation (SERC) of potential violations of certain North American Electric Reliability Corporation (NERC) reliability standards, including certain Critical Infrastructure Protection, Facilities Design, Connection and Maintenance, and System Protection and Control standards.  Entergy is working with the SERC to provide information concerning these potential violations.  In addition, FERC’s Division of Investigations is conducting an investigation of certain issues relating to the Utility operating companies compliance with certain Reliability Standards related to protective system maintenance, facility ratings and modeling, training, and communications.  The Energy Policy Act of 2005 provides authority to impose civil penalties for violations of the Federal Power Act and FERC regulations.

 

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U.S. Department of Justice Investigation

In September 2010, Entergy was notified that the U.S. Department of Justice had commenced a civil investigation of competitive issues concerning certain generation procurement, dispatch, and transmission system practices and policies of the Utility operating companies.  The investigation is ongoing.

Market and Credit Risk Sensitive Instruments

Market risk is the risk of changes in the value of commodity and financial instruments, or in future net income or cash flows, in response to changing market conditions.  Entergy holds commodity and financial instruments that are exposed to the following significant market risks:

·	The commodity price risk associated with the sale of electricity by the Entergy Wholesale Commodities business.

·	The interest rate and equity price risk associated with Entergy’s investments in pension and other postretirement benefit trust funds.  See Note 11 to the financial statements for details regarding Entergy’s pension and other postretirement benefit trust funds.

·	The interest rate and equity price risk associated with Entergy’s investments in nuclear plant decommissioning trust funds, particularly in the Entergy Wholesale Commodities business.  See Note 17 to the financial statements for details regarding Entergy’s decommissioning trust funds.

·

The interest rate risk associated with changes in interest rates as a result of Entergy’s issuances of debt.  Entergy manages its interest rate exposure by monitoring current interest rates and its debt outstanding in relation to total capitalization.  See Notes 4 and 5 to the financial statements for the details of Entergy’s debt outstanding.

The Utility business has limited exposure to the effects of market risk because it operates primarily under cost-based rate regulation.  To the extent approved by their retail rate regulators, the Utility operating companies hedge the exposure to natural gas price volatility of their fuel and gas purchased for resale costs, which are recovered from customers.

Entergy’s commodity and financial instruments are exposed to credit risk.  Credit risk is the risk of loss from nonperformance by suppliers, customers, or financial counterparties to a contract or agreement.  Entergy is also exposed to a potential demand on liquidity due to credit support requirements within its supply or sales agreements.

Commodity Price Risk

Power Generation

As a wholesale generator, Entergy Wholesale Commodities core business is selling energy, measured in MWh, to its customers.  Entergy Wholesale Commodities enters into forward contracts with its customers and sells energy in the day ahead or spot markets.  In addition to selling the energy produced by its plants, Entergy Wholesale Commodities sells unforced capacity, which allows load-serving entities to meet specified reserve and related requirements placed on them by the ISOs in their respective areas.  Entergy Wholesale Commodities’ forward fixed price power contracts consist of contracts to sell energy only, contracts to sell capacity only, and bundled contracts in which it sells both capacity and energy.  While the terminology and payment mechanics vary in these contracts, each of these types of contracts requires Entergy Wholesale Commodities to deliver MWh of energy, make capacity available, or both.   The following is a summary as of December 31, 2011 of the amount of Entergy Wholesale Commodities’ nuclear power plants’ planned energy output that is sold forward under physical or financial contracts:

 

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Energy
		2012		2013		2014		2015		2016
Percent of planned generation sold forward:
Unit-contingent		61%		38%		14%		12%		12%
Unit-contingent with guarantee of availability (1)		16%		19%		15%		13%		13%
Firm LD		24%		24%		10%		-%		-%
Offsetting positions		(13)%		-%		-%		-%		-%
Total energy sold forward		88%		81%		39%		25%		25%
Planned generation (TWh) (2) (3)		41		40		41		41		40
Average revenue under contract per MWh (4)		$49		$45-50		$49-54		$49-57		$50-59

Capacity
		2012		2013		2014		2015		2016
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%
Planned net MW in operation (3)		4,998		4,998		4,998		4,998		4,998
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)
% of planned generation and capacity sold forward		90%		80%		43%		27%		26%
Average revenue under contract per MWh (4)		$51		$47		$51		$52		$52

(1)	A sale of power on a unit-contingent basis coupled with a guarantee of availability provides for the payment to the power purchaser of contract damages, if incurred, in the event the seller fails to deliver power as a result of the failure of the specified generation unit to generate power at or above a specified availability threshold.  All of Entergy’s outstanding guarantees of availability provide for dollar limits on Entergy’s maximum liability under such guarantees.
(2)	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.
(3)	Assumes NRC license renewal for plants whose current licenses expire within five years and the continued operation of all six plants.  NRC license renewal applications are in process for three units, as follows (with current license expirations in parentheses): Pilgrim (June 2012), Indian Point 2 (September 2013), and Indian Point 3 (December 2015).  For a discussion regarding the continued operation of the Vermont Yankee plant, see “ Impairment of Long-Lived Assets ” in Note 1 to the financial statements.
(4)	Revenue on a per unit basis at which generation output, capacity, or a 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 PPA 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 costs.  Also, average revenue under contract excludes payments owed under the value sharing agreement with NYPA.

 

 

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Entergy estimates that a $10 per MWh change in the annual average energy price in the markets in which the Entergy Wholesale Commodities nuclear business sells power, based on the respective year-end market conditions, planned generation volumes, and hedged positions, would have a corresponding effect on pre-tax net income of $48 million in 2012 and would have had a corresponding effect on pre-tax net income of $17 million in 2011.

 

Entergy’s purchase of the FitzPatrick and Indian Point 3 plants from NYPA included value sharing agreements with NYPA.  In October 2007, NYPA and the subsidiaries that own the FitzPatrick and Indian Point 3 plants amended and restated the value sharing agreements to clarify and amend certain provisions of the original terms.  Under the amended value sharing agreements, the Entergy subsidiaries agreed to make annual payments to NYPA based on the generation output of the Indian Point 3 and FitzPatrick plants from January 2007 through December 2014.  Entergy subsidiaries will pay NYPA $6.59 per MWh for power sold from Indian Point 3, up to an annual cap of $48 million, and $3.91 per MWh for power sold from FitzPatrick, up to an annual cap of $24 million.  The annual payment for each year’s output is due by January 15 of the following year.  Entergy will record the liability for payments to NYPA as power is generated and sold by Indian Point 3 and FitzPatrick.  In 2011, 2010, and 2009, Entergy Wholesale Commodities recorded a $72 million liability for generation during each of those years.  An amount equal to the liability was recorded each year to the plant asset account as contingent purchase price consideration for the plants.  This amount will be depreciated over the expected remaining useful life of the plants.

Some of the agreements to sell the power produced by Entergy Wholesale Commodities’ power plants contain provisions that require an Entergy subsidiary to provide collateral to secure its obligations under the agreements.  The Entergy subsidiary is required to provide collateral based upon the difference between the current market and contracted power prices in the regions where Entergy Wholesale Commodities sells power.  The primary form of collateral to satisfy these requirements is an Entergy Corporation guaranty.  Cash and letters of credit are also acceptable forms of collateral.  At December 31, 2011, based on power prices at that time, Entergy had liquidity exposure of $133 million under the guarantees in place supporting Entergy Wholesale Commodities transactions, $20 million of guarantees that support letters of credit, and $6 million of posted cash collateral to the ISOs.  As of December 31, 2011, the liquidity exposure associated with Entergy Wholesale Commodities assurance requirements would increase by $132 million for a $1 per MMBtu increase in gas prices in both the short-and long-term markets.  In the event of a decrease in Entergy Corporation’s credit rating to below investment grade, based on power prices as of December 31, 2011, Entergy would have been required to provide approximately $44 million of additional cash or letters of credit under some of the agreements.

As of December 31, 2011, substantially all of the counterparties or their guarantors for 100% of the planned energy output under contract for Entergy Wholesale Commodities nuclear plants through 2016 have public investment grade credit ratings.

Nuclear Matters

After the nuclear incident in Japan resulting from the March 2011 earthquake and tsunami, the NRC established a task force to conduct a review of processes and regulations relating to nuclear facilities in the United States.  The task force issued a near term (90-day) report in July 2011 that has made recommendations, which are currently being evaluated by the NRC.  It is anticipated that the NRC will issue certain orders and requests for information to nuclear plant licensees by the end of the first quarter 2012 that will begin to implement the task force’s recommendations.  These orders may require U.S. nuclear operators, including Entergy, to undertake plant modifications or perform additional analyses that could, among other things, result in increased costs and capital requirements associated with operating Entergy’s nuclear plants.

Critical Accounting Estimates

The preparation of Entergy’s financial statements in conformity with generally accepted accounting principles requires management to apply appropriate accounting policies and to make estimates and judgments that can have a significant effect on reported financial position, results of operations, and cash flows.  Management has identified the following accounting policies and estimates as critical because they are based on assumptions and

 

 

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measurements that involve a high degree of uncertainty, and the potential for future changes in these assumptions and measurements could produce estimates that would have a material effect on the presentation of Entergy’s financial position, results of operations, or cash flows.

Nuclear Decommissioning Costs

Entergy subsidiaries own nuclear generation facilities in both its Utility and Entergy Wholesale Commodities business units.  Regulations require Entergy subsidiaries to decommission the nuclear power plants after each facility is taken out of service, and money is collected and deposited in trust funds during the facilities’ operating lives in order to provide for this obligation.  Entergy conducts periodic decommissioning cost studies to estimate the costs that will be incurred to decommission the facilities.  The following key assumptions have a significant effect on these estimates:

·

Cost Escalation Factors - Entergy’s current decommissioning cost studies include an assumption that decommissioning costs will escalate over present cost levels by annual factors ranging from approximately 2.5% to 3.5%.  A 50 basis point change in this assumption could change the ultimate cost of decommissioning a facility by as much as an approximate average of 20% to 25%.  To the extent that a high probability of license renewal is assumed, a change in the estimated inflation or cost escalation rate has a larger effect on the undiscounted cash flows because the rate of inflation is factored into the calculation for a longer period of time.

·

Timing - In projecting decommissioning costs, two assumptions must be made to estimate the timing of plant decommissioning.  First, the date of the plant’s retirement must be estimated.  A high probability that the plant’s license will be renewed and operate for some time beyond the original license term has currently been assumed for purposes of calculating the decommissioning liability for a number of Entergy’s nuclear units.  Second, an assumption must be made whether decommissioning will begin immediately upon plant retirement, or whether the plant will be held in SAFSTOR status for later decommissioning, as permitted by applicable regulations.  SAFSTOR is decommissioning a facility by placing it in a safe stable condition that is maintained until it is subsequently decontaminated and dismantled to levels that permit license termination, normally within 60 years from permanent cessation of operations.  While the effect of these assumptions cannot be determined with precision, a change of assumption of either the probability of license renewal or use of a SAFSTOR period can possibly change the present value of these obligations.  Future revisions to appropriately reflect changes needed to the estimate of decommissioning costs will affect net income, only to the extent that the estimate of any reduction in the liability exceeds the amount of the undepreciated asset retirement cost at the date of the revision, for unregulated portions of Entergy’s business.  Any increases in the liability recorded due to such changes are capitalized and depreciated over the asset’s remaining economic life.

·

Spent Fuel Disposal - Federal law requires the DOE to provide for the permanent storage of spent nuclear fuel, and legislation has been passed by Congress to develop a repository at Yucca Mountain, Nevada. However, funding for the Yucca Mountain repository was almost completely eliminated from the federal budget for the current and prior years, and hearings on the facility’s NRC license have been suspended indefinitely. The DOE has not yet begun accepting spent nuclear fuel and is in non-compliance with federal law.  The DOE continues to delay meeting its obligation and Entergy is continuing to pursue damages claims against the DOE for its failure to provide timely spent fuel storage.  Until a federal site is available, however, nuclear plant operators must provide for interim spent fuel storage on the nuclear plant site, which can require the construction and maintenance of dry cask storage sites or other facilities.  The costs of developing and maintaining these facilities can have a significant effect (as much as an average of 20% to 30% of estimated decommissioning costs).  Entergy’s decommissioning studies may include cost estimates for spent fuel storage.  However, these estimates could change in the future based on the timing of the opening of an appropriate facility designated by the federal government to receive spent nuclear fuel.

·

Technology and Regulation - Over the past several years, more practical experience with the actual decommissioning of facilities has been gained and that experience has been incorporated into Entergy’s current decommissioning cost estimates.  However, given the long duration of decommissioning projects, additional experience, including technological advancements in decommissioning, could occur and affect current cost estimates.  If regulations regarding nuclear decommissioning were to change, this could have a potentially significant effect on cost estimates.  The effect of these potential changes is not presently determinable.

 

 

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·

Interest Rates - The estimated decommissioning costs that form the basis for the decommissioning liability recorded on the balance sheet are discounted to present values using a credit-adjusted risk-free rate. When the decommissioning cost estimate is significantly changed requiring a revision to the decommissioning liability and the change results in an increase in cash flows, that increase is discounted using a current credit-adjusted risk-free rate.  Under accounting rules, if the revision in estimate results in a decrease in estimated cash flows, that decrease is discounted using the previous credit-adjusted risk-free rate.  Therefore, to the extent that one of the factors noted above changes resulting in a significant increase in estimated cash flows, current interest rates will affect the calculation of the present value of the additional decommissioning liability.

           In the first quarter 2011, System Energy recorded a revision to its estimated decommissioning cost liability for Grand Gulf as a result of a revised decommissioning cost study.  The revised estimate resulted in a $38.9 million reduction in its decommissioning liability, along with a corresponding reduction in the related regulatory asset.

           In the fourth quarter 2011, Entergy Wholesale Commodities recorded a reduction of $34.1 million in its decommissioning cost liability for a plant as a result of a revised decommissioning cost study obtained to comply with a state regulatory requirement.  The revised cost study resulted in a change in the undiscounted cash flows and a credit to decommissioning expense of $34.1 million ($21 million net-of-tax) was recorded, reflecting the excess of the reduction in the liability over the amount of undepreciated assets.

Unbilled Revenue

As discussed in Note 1 to the financial statements, Entergy records an estimate of the revenues earned for energy delivered since the latest customer billing.  Each month the estimated unbilled revenue amounts are recorded as revenue and a receivable, and the prior month’s estimate is reversed.  The difference between the estimate of the unbilled receivable at the beginning of the period and the end of the period is the amount of unbilled revenue recognized during the period.  The estimate recorded is primarily based upon an estimate of customer usage during the unbilled period and the billed price to customers in that month.  Therefore, revenue recognized may be affected by the estimated price and usage at the beginning and end of each period, in addition to changes in certain components of the calculation.

Impairment of Long-lived Assets and Trust Fund Investments

Entergy has significant investments in long-lived assets in all of its segments, and Entergy evaluates these assets against the market economics and under the accounting rules for impairment whenever there are indications that impairments may exist.  This evaluation involves a significant degree of estimation and uncertainty.  In the Utility business, portions of River Bend are not included in rate base, which could reduce the revenue that would otherwise be recovered for the applicable portions of its generation.  In the Entergy Wholesale Commodities business, Entergy’s investments in merchant nuclear generation assets are subject to impairment if adverse market conditions arise, if a unit ceases operation, or for certain units if their operating licenses are not renewed.  Entergy’s investments in merchant non-nuclear generation assets are subject to impairment if adverse market conditions arise or if a unit ceases operation.

In order to determine if Entergy should recognize an impairment of a long-lived asset that is to be held and used, accounting standards require that the sum of the expected undiscounted future cash flows from the asset be compared to the asset’s carrying value.  The carrying value of the asset includes any capitalized asset retirement cost associated with the recording of an additional decommissioning liability, therefore changes in assumptions that affect the decommissioning liability can increase or decrease the carrying value of the asset subject to impairment.  If the expected undiscounted future cash flows exceed the carrying value, no impairment is recorded; if such cash flows are less than the carrying value, Entergy is required to record an impairment charge to write the asset down to its fair value.  If an asset is held for sale, an impairment is required to be recognized if the fair value (less costs to sell) of the asset is less than its carrying value.

 

 

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These estimates are based on a number of key assumptions, including:

·

Future power and fuel prices - Electricity and gas prices have been very volatile in recent years, and this volatility is expected to continue.  This volatility necessarily increases the imprecision inherent in the long-term forecasts of commodity prices that are a key determinant of estimated future cash flows.

·

Market value of generation assets - Valuing assets held for sale requires estimating the current market value of generation assets.  While market transactions provide evidence for this valuation, the market for such assets is volatile and the value of individual assets is impacted by factors unique to those assets.

·	Future operating costs - Entergy assumes relatively minor annual increases in operating costs.  Technological or regulatory changes that have a significant impact on operations could cause a significant change in these assumptions.

·	Timing -   Entergy currently assumes, for a number of its nuclear units, that the plant’s license will be renewed.  A change in that assumption could have a significant effect on the expected future cash flows and result in a significant effect on operations.

For additional discussion regarding the continued operation of the Vermont Yankee plant, see “ Impairment of Long-Lived Assets ” in Note 1 to the financial statements.

Effective January 1, 2009, Entergy adopted an accounting pronouncement providing guidance regarding recognition and presentation of other-than-temporary impairments related to investments in debt securities.  The assessment of whether an investment in a debt security has suffered an other-than-temporary impairment is based on whether Entergy has the intent to sell or more likely than not will be required to sell the debt security before recovery of its amortized costs.  Further, if Entergy does not expect to recover the entire amortized cost basis of the debt security, an other-than-temporary-impairment is considered to have occurred and it is measured by the present value of cash flows expected to be collected less the amortized cost basis (credit loss).  For debt securities held as of January 1, 2009 for which an other-than-temporary impairment had previously been recognized but for which assessment under the new guidance indicates this impairment is temporary, Entergy recorded an adjustment to its opening balance of retained earnings of $11.3 million ($6.4 million net-of-tax).  Entergy did not have any material other than temporary impairments relating to credit losses on debt securities in 2011, 2010, or 2009.  The assessment of whether an investment in an equity security has suffered an other than temporary impairment continues to be based on a number of factors including, first, whether Entergy has the ability and intent to hold the investment to recover its value, the duration and severity of any losses, and, then, whether it is expected that the investment will recover its value within a reasonable period of time.  Entergy’s trusts are managed by third parties who operate in accordance with agreements that define investment guidelines and place restrictions on the purchases and sales of investments.  As discussed in Note 1 to the financial statements, unrealized losses that are not considered temporarily impaired are recorded in earnings for Entergy Wholesale Commodities.  Entergy Wholesale Commodities recorded charges to other income of $0.1 million in 2011, $1 million in 2010, and $86 million in 2009 resulting from the recognition of impairments of certain securities held in its decommissioning trust funds that are not considered temporary.  Additional impairments could be recorded in 2012 to the extent that then current market conditions change the evaluation of recoverability of unrealized losses.  

Qualified Pension and Other Postretirement Benefits

Entergy sponsors qualified, defined benefit pension plans which cover substantially all employees.  Additionally, Entergy currently provides postretirement health care and life insurance benefits for substantially all employees who reach retirement age and meet certain eligibility requirements while still working for Entergy.  Entergy’s reported costs of providing these benefits, as described in Note 11 to the financial statements, are impacted by numerous factors including the provisions of the plans, changing employee demographics, and various actuarial calculations, assumptions, and accounting mechanisms.  Because of the complexity of these calculations, the long-term nature of these obligations, and the importance of the assumptions utilized, Entergy’s estimate of these costs is a critical accounting estimate for the Utility and Entergy Wholesale Commodities segments.

 

 

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Assumptions

Key actuarial assumptions utilized in determining these costs include:

·	Discount rates used in determining future benefit obligations;

·	Projected health care cost trend rates;

·	Expected long-term rate of return on plan assets;

·	Rate of increase in future compensation levels;

·	Retirement rates; and

·	Mortality rates.

Entergy reviews the first four assumptions listed above on an annual basis and adjusts them as necessary.  The falling interest rate environment and volatility in the financial equity markets have impacted Entergy’s funding and reported costs for these benefits.  In addition, these trends have caused Entergy to make a number of adjustments to its assumptions.

           The retirement and mortality rate assumptions are reviewed every three to five years as part of an actuarial study that compares these assumptions to the actual experience of the pension and other postretirement plans.  The 2011 actuarial study reviewed plan experience from 2007 through 2010.  As a result of the 2011 actuarial study, changes were made to reflect the expectation that participants have longer life expectancies and different retirement patterns than previously assumed.  These changes are reflected in the December 31, 2011 financial disclosures and are a significant factor in the increase in 2012 pension and other postretirement costs compared to the 2011 costs.

In selecting an assumed discount rate to calculate benefit obligations, Entergy reviews market yields on high-quality corporate debt and matches these rates with Entergy’s projected stream of benefit payments.  Based on recent market trends, the discount rates used to calculate its qualified pension benefit obligation decreased from a range of 5.6% to 5.7% for its specific pension plans in 2010 to a range of 5.1% to 5.2% in 2011.  The discount rate used to calculate its other postretirement benefit obligation also decreased from 5.5% in 2010 to 5.1% in 2011.

Entergy reviews actual recent cost trends and projected future trends in establishing health care cost trend rates.  Based on this review, Entergy’s assumed health care cost trend rate assumption used in measuring the December 31, 2011 accumulated postretirement benefit obligation and 2012 postretirement cost was 7.75% for pre-65 retirees and 7.5% for post-65 retirees for 2012, gradually decreasing each successive year until it reaches 4.75% in 2022 and beyond for both pre-65 and post-65 retirees.  Entergy’s health care cost trend rate assumption used in measuring the December 31, 2010 accumulated postretirement benefit obligation and 2011 postretirement cost was 8.5% for pre-65 retirees and 8.0% for post-65 retirees for 2011, gradually decreasing each successive year, until it reaches a 4.75% annual increase in health care costs in 2019 for pre-65 retirees and 4.75% in 2018 and beyond for post-65 retirees.

The assumed rate of increase in future compensation levels used to calculate 2011 and 2010 benefit obligations was 4.23%.

In determining its expected long-term rate of return on plan assets used in the calculation of benefit plan costs, Entergy reviews past performance, current and expected future asset allocations, and capital market assumptions of its investment consultant and investment managers.

Since 2003, Entergy has targeted an asset allocation for its qualified pension plan assets of roughly 65% equity securities and 35% fixed-income securities.  Entergy completed and adopted an optimization study in 2011 for the pension assets which recommended that the target asset allocation adjust dynamically over time, based on the funded status of the plan, from its current to its ultimate allocation of 45% equity, 55% fixed income.  The ultimate asset allocation is expected to be attained when the plan is 105% funded.

 

 

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The current target allocations for Entergy’s non-taxable postretirement benefit assets are 55% equity securities and 45% fixed-income securities and, for its taxable other postretirement benefit assets, 35% equity securities and 65% fixed-income securities.  Entergy also completed and adopted an optimization study in 2011 for the postretirement benefit trust assets that recommends both the taxable and the non-taxable assets move to 65% equity securities and 35% fixed-income securities.  Entergy plans to adjust the postretirement asset allocation during 2012.

Entergy’s expected long term rate of return on qualified pension assets used to calculate 2011, 2010 and 2009 qualified pension costs was 8.5% and will be 8.5% for 2012.  Entergy’s expected long term rate of return on non-taxable other postretirement assets used to calculate other postretirement costs was 7.75% for 2011 and 2010, 8.5% for 2009 and will be 8.5% for 2012.  For Entergy’s taxable postretirement assets, the expected long term rate of return was 5.5% for 2011 and 2010, 6% for 2009 and will be 6.5% in 2012.

Cost Sensitivity

The following chart reflects the sensitivity of qualified pension cost and qualified pension projected benefit obligation to changes in certain actuarial assumptions (dollars in thousands):

Actuarial Assumption		Change in Assumption		Impact on 2011 Qualified Pension Cost		Impact on Qualified Projected Benefit Obligation
		Increase/(Decrease)
Discount rate		(0.25%)		$17,145		$188,246
Rate of return on plan assets		(0.25%)		$8,863		-
Rate of increase in compensation		0.25%		$7,503		$41,227

The following chart reflects the sensitivity of postretirement benefit cost and accumulated postretirement benefit obligation to changes in certain actuarial assumptions (dollars in thousands):

Actuarial Assumption		Change in Assumption		Impact on 2011 Postretirement Benefit Cost		Impact on Accumulated Postretirement Benefit Obligation
		Increase/(Decrease)
Health care cost trend		0.25%		$8,900		$52,730
Discount rate		(0.25%)		$6,622		$62,316

Each fluctuation above assumes that the other components of the calculation are held constant.

 

Accounting Mechanisms

Accounting standards require an employer to recognize in its balance sheet the funded status of its benefit plans.  Refer to Note 11 to the financial statements for a further discussion of Entergy’s funded status.

In accordance with pension accounting standards, Entergy utilizes a number of accounting mechanisms that reduce the volatility of reported pension costs.  Differences between actuarial assumptions and actual plan results are deferred and are amortized into expense only when the accumulated differences exceed 10% of the greater of the projected benefit obligation or the market-related value of plan assets.  If necessary, the excess is amortized over the average remaining service period of active employees.

 

 

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Entergy calculates the expected return on pension and other postretirement benefit plan assets by multiplying the long-term expected rate of return on assets by the market-related value (MRV) of plan assets.  Entergy determines the MRV of pension plan assets by calculating a value that uses a 20-quarter phase-in of the difference between actual and expected returns.  For other postretirement benefit plan assets Entergy uses fair value when determining MRV.

Costs and Funding

In 2011, Entergy’s total qualified pension cost was $154 million.  Entergy anticipates 2012 qualified pension cost to be $264 million.  Pension funding was approximately $400 million for 2011.  Entergy’s contributions to the pension trust are currently estimated to be approximately $163 million in 2012, although the required pension contributions will not be known with more certainty until the January 1, 2012 valuations are completed by April 1, 2012.  Entergy’s preliminary estimates of 2012 funding requirements indicate that the contributions will not exceed historical levels of pension contributions.

Minimum required funding calculations as determined under Pension Protection Act guidance are performed annually as of January 1 of each year and are based on measurements of the assets and funding liabilities as measured at that date.  Any excess of the funding liability over the calculated fair market value of assets results in a funding shortfall which, under the Pension Protection Act, must be funded over a seven-year rolling period.  The Pension Protection Act also imposes certain plan limitations if the funded percentage, which is based on a calculated fair market values of assets divided by funding liabilities, does not meet certain thresholds. For funding purposes, asset gains and losses are smoothed in to the calculated fair market value of assets and the funding liability is based upon a weighted average 24-month corporate bond rate published by the U.S. Treasury; therefore, periodic changes in asset returns and interest rates can affect funding shortfalls and future cash contributions.

Total postretirement health care and life insurance benefit costs for Entergy in 2011 were $114.7 million, including $33 million in savings due to the estimated effect of future Medicare Part D subsidies.  Entergy expects 2012 postretirement health care and life insurance benefit costs to be $138.4 million.  This includes a projected $31.2 million in savings due to the estimated effect of future Medicare Part D subsidies.  Entergy contributed $76.1 million to its postretirement plans in 2011.  Entergy’s current estimate of contributions to its other postretirement plans is approximately $80.4 million in 2012.

Federal Healthcare Legislation

The Patient Protection and Affordable Care Act (PPACA) became federal law on March 23, 2010, and, on March 30, 2010, the Health Care and Education Reconciliation Act of 2010 became federal law and amended certain provisions of the PPACA.  These new federal laws change the law governing employer-sponsored group health plans, like Entergy's plans, and include, among other things, the following significant provisions:

·	A 40% excise tax on per capita medical benefit costs that exceed certain thresholds;

·	Change in coverage limits for dependents; and

·	Elimination of lifetime caps.

 

The total impact of PPACA is not yet determinable because technical guidance regarding application must still be issued.  Additionally, ongoing litigation and discussions are in progress regarding the constitutionality of and the potential repeal of health care reform, although whether that occurs and what parts of health care reform would be invalidated or repealed is not yet known.  Entergy will continue to monitor these developments to determine the possible impact on Entergy as a result of PPACA.  Entergy is participating in the programs currently provided for under PPACA, such as the early retiree reinsurance program, which has provided for some limited reimbursements of certain claims for early retirees aged 55 to 64 who are not yet eligible for Medicare.

One provision of the new law that is effective in 2013 eliminates the federal income tax deduction for prescription drug expenses of Medicare beneficiaries for which the plan sponsor also receives the retiree drug subsidy under Part D.  Entergy receives subsidy payments under the Medicare Part D plan and therefore in the first quarter 2010 recorded a reduction to the deferred tax asset related to the unfunded other postretirement benefit obligation.  The offset was recorded in 2010 as a $16 million charge to income tax expense or, for the Utility, including each Registrant Subsidiary, as a regulatory asset.

 

 

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Other Contingencies

As a company with multi-state domestic utility operations and a history of international investments, Entergy is subject to a number of federal, state, and international laws and regulations and other factors and conditions in the areas in which it operates, which potentially subject it to environmental, litigation, and other risks.  Entergy periodically evaluates its exposure for such risks and records a reserve for those matters which are considered probable and estimable in accordance with generally accepted accounting principles.

Environmental

Entergy must comply with environmental laws and regulations applicable to the handling and disposal of hazardous waste.  Under these various laws and regulations, Entergy could incur substantial costs to restore properties consistent with the various standards.  Entergy conducts studies to determine the extent of any required remediation and has recorded reserves based upon its evaluation of the likelihood of loss and expected dollar amount for each issue.  Additional sites could be identified which require environmental remediation for which Entergy could be liable.  The amounts of environmental reserves recorded can be significantly affected by the following external events or conditions:

·	Changes to existing state or federal regulation by governmental authorities having jurisdiction over air quality, water quality, control of toxic substances and hazardous and solid wastes, and other environmental matters.

·	The identification of additional sites or the filing of other complaints in which Entergy may be asserted to be a potentially responsible party.

·	The resolution or progression of existing matters through the court system or resolution by the EPA.

Litigation

Entergy is regularly named as a defendant in a number of lawsuits involving employment, customers, and injuries and damages issues, among other matters.  Entergy periodically reviews the cases in which it has been named as defendant and assesses the likelihood of loss in each case as probable, reasonably estimable, or remote and records reserves for cases which have a probable likelihood of loss and can be estimated.  Given the environment in which Entergy operates, and the unpredictable nature of many of the cases in which Entergy is named as a defendant, the ultimate outcome of the litigation to which Entergy is exposed has the potential to materially affect the results of operations of Entergy or Registrant Subsidiaries.

 

Uncertain Tax Positions

Entergy’s operations, including acquisitions and divestitures, require Entergy to evaluate risks such as the potential tax effects of a transaction, or warranties made in connection with such a transaction.  Entergy believes that it has adequately assessed and provided for these types of risks, where applicable.  Any provisions recorded for these types of issues, however, could be significantly affected by events such as claims made by third parties under warranties, additional transactions contemplated by Entergy, or completion of reviews of the tax treatment of certain transactions or issues by taxing authorities.

New Accounting Pronouncements

The accounting standard-setting process, including projects between the FASB and the International Accounting Standards Board (IASB) to converge U.S. GAAP and International Financial Reporting Standards, is ongoing and the FASB and the IASB are each currently working on several projects that have not yet resulted in final pronouncements.  Final pronouncements that result from these projects could have a material effect on Entergy’s future net income, financial position, or cash flows.

 

 

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In May 2011 the FASB issued ASU No. 2011-4, “Fair Value Measurement (Topic 820): Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRSs,” which states that the ASU explains how to measure fair value.  The ASU states that:  1) the amendments in the ASU result in common fair value measurement and disclosure requirements in U.S. GAAP and International Financial Reporting Standards; 2) consequently, the amendments change the wording used to describe many of the requirements in U.S. GAAP for measuring fair value and for disclosing information about fair value measurements; 3) for many of the requirements, the FASB does not intend for the ASU to result in a change in the application of the requirements of current U.S. GAAP; 4) some of the amendments clarify the FASB’s intent about the application of existing fair value measurement requirements; and 5) other amendments change a particular principle or requirement for measuring fair value or for disclosing information about fair value measurements.  ASU No. 2011-4 is effective for Entergy for the first quarter 2012.  Entergy does not expect ASU No. 2011-4 to affect materially its results of operations, financial position, or cash flows.

In September 2011 the FASB issued ASU No. 2011-8, “Intangibles – Goodwill and Other (Topic 350): Testing Goodwill for Impairment.”  The amendments permit an entity to first assess qualitative factors to determine whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount as a basis for determining whether it is necessary to perform a quantitative goodwill impairment assessment.  ASU No. 2011-8 is effective for Entergy for the first quarter 2012.  ASU No. 2011-8 will have no effect on Entergy’s results of operations, financial position, or cash flows.

 

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ENTERGY CORPORATION AND SUBSIDIARIES

REPORT OF MANAGEMENT

Management of Entergy Corporation and its subsidiaries has prepared and is responsible for the financial statements and related financial information included in this document.  To meet this responsibility, management establishes and maintains a system of internal controls over financial reporting designed to provide reasonable assurance regarding the preparation and fair presentation of financial statements in accordance with generally accepted accounting principles.  This system includes communication through written policies and procedures, an employee Code of Entegrity, and an organizational structure that provides for appropriate division of responsibility and training of personnel.  This system is also tested by a comprehensive internal audit program.

Entergy management assesses the effectiveness of Entergy’s internal control over financial reporting on an annual basis.  In making this assessment, management uses the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control - Integrated Framework.  Management acknowledges, however, that all internal control systems, no matter how well designed, have inherent limitations and can provide only reasonable assurance with respect to financial statement preparation and presentation.

Entergy Corporation and the Registrant Subsidiaries’ independent registered public accounting firm, Deloitte & Touche LLP, has issued an attestation report on the effectiveness of Entergy’s internal control over financial reporting as of December 31, 2011, which is included herein on pages 400 through 407.

In addition, the Audit Committee of the Board of Directors, composed solely of independent Directors, meets with the independent auditors, internal auditors, management, and internal accountants periodically to discuss internal controls, and auditing and financial reporting matters.  The Audit Committee appoints the independent auditors annually, seeks shareholder ratification of the appointment, and reviews with the independent auditors the scope and results of the audit effort.  The Audit Committee also meets periodically with the independent auditors and the chief internal auditor without management present, providing free access to the Audit Committee.

Based on management’s assessment of internal controls using the COSO criteria, management believes that Entergy and each of the Registrant Subsidiaries maintained effective internal control over financial reporting as of December 31, 2011.  Management further believes that this assessment, combined with the policies and procedures noted above, provides reasonable assurance that Entergy’s and each of the Registrant Subsidiaries’ financial statements are fairly and accurately presented in accordance with generally accepted accounting principles.

J. WAYNE LEONARD Chairman of the Board and Chief Executive Officer of Entergy Corporation	LEO P. DENAULT Executive Vice President and Chief Financial Officer of Entergy Corporation
HUGH T. MCDONALD Chairman of the Board, President, and Chief Executive Officer of Entergy Arkansas, Inc.	WILLIAM M. MOHL Chairman of the Board, President, and Chief Executive Officer of Entergy Gulf States Louisiana, L.L.C. and Entergy Louisiana, LLC
HALEY R. FISACKERLY Chairman of the Board, President, and Chief Executive Officer of Entergy Mississippi, Inc.	CHARLES L. RICE, JR. Chairman of the Board, President and Chief Executive Officer of Entergy New Orleans, Inc.
JOSEPH F. DOMINO Chairman of the Board, President, and Chief Executive Officer of Entergy Texas, Inc.	JOHN T. HERRON Chairman, President, and Chief Executive Officer of System Energy Resources, Inc.
THEODORE H. BUNTING, JR. Senior Vice President and Chief Accounting Officer (and acting principal financial officer) of Entergy Arkansas, Inc., Entergy Gulf States Louisiana, L.L.C., Entergy Louisiana, LLC, Entergy Mississippi, Inc., Entergy New Orleans, Inc., and Entergy Texas, Inc.	WANDA C. CURRY Vice President and Chief Financial Officer of System Energy Resources, Inc.