Indicate by check mark whether the registrants are shell companies (as defined in Rule 12b-2 of the Act.) Yes o No þ

System Energy Resources meets the requirements set forth in General Instruction I(1) of Form 10-K and is therefore filing this Form 10-K with reduced disclosure as allowed in General Instruction I(2). System Energy Resources is reducing its disclosure by not including Part III, Items 10 through 13 in its Form 10-K.

The aggregate market value of Entergy Corporation Common Stock, $0.01 Par Value, held by non-affiliates as of the end of the second quarter of ~~2013,~~2014, was ~~$12.4~~$14.7 billion based on the reported last sale price of ~~$69.68~~$82.09 per share for such stock on the New York Stock Exchange on June ~~28, 2013.~~30, 2014. Entergy Corporation is the sole holder of the common stock of Entergy Arkansas, Inc., Entergy Mississippi, Inc., Entergy New Orleans, Inc., Entergy Texas, Inc., and System Energy Resources, Inc. Entergy Corporation is the sole holder of the common stock of Entergy Louisiana Holdings, Inc., which is the sole holder of the common membership interests in Entergy Louisiana, LLC. Entergy Corporation is the sole holder of the common stock of EGS Holdings, Inc., which is the sole holder of the common membership interests in Entergy Gulf States Louisiana, L.L.C.

Portions of the Proxy Statement of Entergy Corporation to be filed in connection with its Annual Meeting of Stockholders, to be held May ~~2, 2014,~~8, 2015, are incorporated by reference into Part III hereof.

In this combined report and from time to time, Entergy Corporation and the Registrant Subsidiaries each makes statements as a registrant concerning its expectations, beliefs, plans, objectives, goals, strategies, and future events or performance. Such statements are “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995. Words such as “may,” “will,” “could,” “project,” “believe,” “anticipate,” “intend,” “expect,” “estimate,” “continue,” “potential,” “plan,” “predict,” “forecast,” and other similar words or expressions are intended to identify forward-looking statements but are not the only means to identify these statements. Although each of these registrants believes that these forward-looking statements and the underlying assumptions are reasonable, it cannot provide assurance that they will prove correct. Any forward-looking statement is based on information current as of the date of this combined report and speaks only as of the date on which such statement is made. Except to the extent required by the federal securities laws, these registrants undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events, or otherwise.

Forward-looking statements involve a number of risks and uncertainties. There are factors that could cause actual results to differ materially from those expressed or implied in the forward-looking statements, including (a) those factors discussed or incorporated by reference in Item 1A. Risk Factors, (b) those factors discussed or incorporated by reference in Management’s Financial Discussion and Analysis, and (c) the following factors (in addition to others described elsewhere in this combined report and in subsequent securities filings):

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

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

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.

Following are income statement variances for Utility, Entergy Wholesale Commodities, Parent & Other, and Entergy comparing ~~2013~~2014 to ~~2012~~2013 showing how much the line item increased or (decreased) in comparison to the prior period.

Results of operations for 2014 include $154 million ($100 million after-tax) of charges related to Vermont Yankee primarily resulting from the effects of an updated decommissioning cost study completed in the third quarter 2014 along with reassessment of the assumptions regarding the timing of decommissioning cash flows and severance and employee retention costs. See Note 1 to the financial statements for further discussion of the charges. Results of operations for 2014 also include the $56.2 million ($36.7 million after-tax) write-off in 2014 of Entergy Mississippi’s regulatory asset associated with new nuclear generation development costs as a result of a joint stipulation entered into with the Mississippi Public Utilities Staff, subsequently approved by the MPSC, in which Entergy Mississippi agreed not to pursue recovery of the costs deferred by an MPSC order in the new nuclear generation docket. See Note 2 to the financial statements for further discussion of the new nuclear generation development costs and the joint stipulation.

As discussed in more detail in Note 1 to the financial statements, results of operations for 2013 include ~~$321.5~~$322 million ($~~202.2~~202 million after-tax) ~~in 2013 and $355.5 million ($223.5 million after-tax) in 2012~~ of impairment and other related charges to write down the carrying value of Vermont Yankee and related assets to their fair values. Also, net income for Utility in 2012 was significantly affected by a settlement with the IRS related to the income tax treatment of the Louisiana Act 55 financing of the Hurricane Katrina and Hurricane Rita storm costs, which resulted in a reduction in income tax expense. The net income effect was partially offset by a regulatory charge, which reduced net revenue in 2012, associated with the storm costs settlement to reflect the obligation to customers with respect to the settlement. See Note 3 to the financial statements for additional discussion of the tax settlement.

Following is an analysis of the change in net revenue comparing ~~2013~~2014 to ~~2012.~~2013.

The retail electric price variance is primarily due to:

The ~~Louisiana Act 55 financing savings~~asset retirement obligation ~~variance results from~~affects net revenue because Entergy records a regulatory ~~charge recorded~~debit or credit for the difference between asset retirement obligation-related expenses and trust earnings plus asset retirement obligation-related costs collected in revenue. The variance is primarily caused by increases in regulatory credits because of decreases in decommissioning trust earnings and increases in depreciation and accretion expenses and increases in regulatory credits to realign the asset retirement obligation regulatory assets with regulatory treatment.

The volume/weather variance is primarily due to an increase of 3,129 GWh, or 3%, in billed electricity usage primarily due to an increase in sales to industrial customers and the effect of more favorable weather on residential sales. The increase in industrial sales was primarily due to expansions, recovery of a major refining customer from an unplanned outage in 2013, and continued moderate growth in the second quarter 2012 because Entergy Gulf States Louisiana and Entergy Louisiana agreed to share with customers the savings from an IRS settlement related to the uncertain tax position regarding the Hurricane Katrina and Hurricane Rita Louisiana Act 55 financing. See Note 3 to the financial statements for additional discussion of the tax settlement. manufacturing sector.

The ~~Grand Gulf recovery variance is primarily due to increased recovery of higher costs resulting from the Grand Gulf uprate.~~

The ~~decommissioning trusts~~net wholesale variance is primarily due to a wholesale customer contract termination in December 2013 and lower ~~regulatory credits resulting from higher realized income~~margins on ~~decommissioning trust fund investments. There is no effect on net income as the credits are offset by interest and investment income.~~co-owner contracts due to contract changes.

Following is an analysis of the change in net revenue comparing ~~2013~~2014 to ~~2012.~~2013.

As shown in the table above, net revenue for Entergy Wholesale Commodities ~~decreased~~increased by approximately ~~$52~~$422 million in ~~2013~~2014 primarily due to:

The effects of sustained low natural gas prices and power market structure challenges have resulted in lower market prices for electricity in the New York and New England power regions, which is where ~~five~~four of the ~~six~~five operating Entergy Wholesale Commodities nuclear power plants are located. A sixth plant, Vermont Yankee, ceased operations in December 2014. The Entergy Wholesale ~~Commodities’s~~Commodities nuclear business experienced ~~a decrease in~~an annual realized price per MWh toof $60.35 in 2014, $50.15 in 2013, ~~from~~and $50.29 in ~~2012~~2012. The increase in realized price in 2014 is primarily attributable to a significant increase in first quarter 2014 prices due to cold winter weather and ~~$54.73 in 2011. The~~northeastern U.S. gas pipeline infrastructure limitations. Prior to 2009 the annual realized price per MWh for Entergy Wholesale Commodities ~~reached~~generally increased each year, reaching a peak of $61.07 in 2009. As shown in the contracted sale of energy table in “Market and Credit Risk Sensitive Instruments,” Entergy Wholesale Commodities has sold forward ~~74%~~86% of its planned nuclear energy output for ~~2014~~2015 for an expected average contracted energy price of ~~$50~~$48 per MWh based on market prices at December 31, ~~2013.~~2014. In addition, Entergy Wholesale Commodities has sold forward 74% of its planned nuclear energy output for ~~2015~~2016 for an expected average contracted energy price of $49 per MWh based on market prices at December 31, ~~2013. These~~2014. The market price ~~trends present~~trend presents a challenging economic situation for the Entergy Wholesale Commodities plants. The challenge is greater for some of these plants based on a variety of factors such as their market for both energy and capacity, their size, their contracted positions, and the amount of investment required to continue to operate and maintain the safety and integrity of the ~~plants.~~plants, including the estimated asset retirement costs. If, in the future, economic conditions or regulatory activity no longer support the continued operation or recovery of the costs of a plant it could adversely affect Entergy’s results of operations through loss of revenue, impairment charges, increased depreciation rates, transitional costs, or accelerated decommissioning costs.

On August 27, 2013, Entergy announced its plan to close and decommission Vermont Yankee. ~~Vermont Yankee is expected to cease power production in the fourth quarter 2014 after its current fuel cycle.~~ This decision was approved by the Board in August 2013. The decision to shut down the plant was primarily due to sustained low natural gas and

Impairment of long-lived assets and nuclear decommissioning costs, and the factors that influence these items, are both discussed below in “Critical Accounting Estimates.” See also the discussion below in “Entergy Wholesale

Other operation and maintenance expenses increased from $2,264 million for 2013 to $2,276 million for 2014 primarily due to:

The asset write-off, impairment, and related charges variance is due to the $56.2 million ($36.7 million after-tax) write-off in 2014 of Entergy Mississippi’s regulatory asset associated with new nuclear generation development costs and a $16 million ($10.5 million after-tax) write-off recorded in 2014 because of the uncertainty associated with the resolution of the Waterford 3 replacement steam generator project prudence review. See Note 2 to the financial statements for further discussion of new nuclear generation development costs and the prudence review.

Interest expense increased primarily due to the lease renewal in December 2013 of the Grand Gulf sale leaseback and net debt issuances of first mortgage bonds in the first quarter 2014 and the second quarter 2013 by certain Utility operating companies. See Note 5 to the financial statements for more details of long-term debt. The increase was partially offset by an increase in the allowance for borrowed funds used during construction due to a higher construction work in progress balance in 2014, including the Ninemile Unit 6 self-build project.

Other expenses increased primarily due to increases in decommissioning expenses resulting from revisions to the estimated decommissioning cost liabilities as a result of revised decommissioning cost studies in the fourth quarter 2013 and the first quarter 2014, partially offset by a decrease in nuclear refueling outage costs that are being amortized over the estimated period to the next outage. See Note 9 to the financial statements for further discussion of the decommissioning cost revisions.

Other operation and maintenance expenses decreased from $1,048 million for 2013 to $1,023 million for 2014 primarily due to:

The asset write-off, impairments, and related charges variance is primarily due to $321.5 million ($202.2 million after-tax) in 2013 of impairment and other related charges primarily to write down the carrying value of Vermont Yankee and related assets to their fair values and $107.5 million ($69.8 million after-tax) in 2014 of impairment charges related to Vermont Yankee primarily resulting from the effects of an updated decommissioning cost study completed in the third quarter 2014. See Note 1 to the financial statements for further discussion of these impairment charges.

Depreciation and amortization expenses increased primarily due to a change effective in 2014 in the estimated average useful lives of plant in service as a result of a new depreciation study and an increase to depreciable plant balances.

The gain on sale of business resulted from the sale in November 2013 of Entergy Solutions District Energy, a business wholly-owned by Entergy in the Entergy Wholesale Commodities segment that owned and operated district energy assets servicing the business districts in Houston and New Orleans. Entergy sold Entergy Solutions District Energy for $140 million and realized a pre-tax gain of $44 million on the sale.

Other income decreased primarily due to lower realized gains on nuclear decommissioning trust fund investments.

Other expenses increased primarily due to an increase in nuclear refueling outage costs that are being amortized over the estimated period to the next outage and an increase in decommissioning expenses primarily due to revisions to the estimated decommissioning cost liability for Vermont Yankee recorded in the third and fourth quarters of 2013. See “Critical Accounting Estimates - Nuclear Decommissioning Costs” below for further discussion of nuclear decommissioning costs.

Other income decreased primarily due to the elimination of intersegment activity.

See Note 3 to the financial statements for a reconciliation of the federal statutory rate of 35% to the effective income tax rates, and for additional discussion regarding income taxes.

The effective income tax rate for 2014 was 38%. The difference in the effective income tax rate versus the statutory rate of 35% for 2014 was primarily due to state income taxes, certain book and tax differences related to utility plant items, and the provision for uncertain tax positions, partially offset by a deferred state income tax reduction related to a New York tax law change and book and tax differences related to the allowance for equity funds used during construction.

The effective income tax rate for 2013 was 23.6%. The difference in the effective income tax rate versus the statutory rate of 35% for 2013 was primarily related to (1) IRS settlements as discussed further in Note 3 to the financial statements; and (2) a tax benefit associated with the now-terminated plan to spin off and merge the Utility’s transmission business, because certain associated costs became deductible with the termination of the transaction.

Following are income statement variances for Utility, Entergy Wholesale Commodities, Parent & Other, and Entergy comparing 2013 to 2012 showing how much the line item increased or (decreased) in comparison to the prior period.

As discussed in more detail in Note 1 to the financial statements, results of operations include $322 million ($202 million after-tax) in 2013 and $356 million ($224 million after-tax) in 2012 of impairment and other related charges to write down the carrying value of Vermont Yankee and related assets to their fair values. Also, net income for Utility in 2012 was significantly affected by a settlement with the IRS related to the income tax treatment of the Louisiana Act 55 financing of the Hurricane Katrina and Hurricane Rita storm costs, which resulted in a reduction in income tax expense. The net income effect was partially offset by a regulatory charge, which reduced net revenue in 2012, associated with the storm costs settlement to reflect the obligation to customers with respect to the settlement. See Note 3 to the financial statements for additional discussion of the tax settlement.

Also, earnings were negatively affected in 2013 by expenses, including other operation and maintenance expenses and taxes other than income taxes, of approximately $110 million ($70 million after-tax), including approximately $85 million ($55 million after-tax) for Utility and $25 million ($15 million after-tax) for Entergy Wholesale Commodities, recorded in connection with a strategic imperative intended to optimize the organization through a process known as human capital management. In December 2013, Entergy deferred for future collection approximately $45 million ($30 million after-tax) of these costs in the Arkansas and Louisiana jurisdictions at the Utility, as approved by the APSC and the LPSC, respectively. See “Human Capital Management Strategic Imperative” below for further discussion.

Following is an analysis of the change in net revenue comparing 2013 to 2012.

The Louisiana Act 55 financing savings obligation variance results from a regulatory charge recorded in the second quarter 2012 because Entergy Gulf States Louisiana and Entergy Louisiana were required to share with customers the savings from the tax treatment related to the Hurricane Katrina and Hurricane Rita Louisiana Act 55 financing. See Note 3 to the financial statements for additional discussion of the tax treatment.

The Grand Gulf recovery variance is primarily due to increased recovery of higher costs resulting from the Grand Gulf uprate.

The volume/weather variance is primarily due to the effects of more favorable weather on residential sales and an increase in industrial sales primarily due to growth in the refining segment.

The fuel recovery variance is primarily due to:

The MISO deferral variance is primarily due to the deferral in April 2013, as approved by the APSC, of costs incurred from March 2010 through December 2012 related to the transition and implementation of joining the MISO RTO.

The asset retirement obligation affects net revenue because Entergy records a regulatory debit or credit for the difference between asset retirement obligation-related expenses and trust earnings plus asset retirement obligation-related costs collected in revenue. The variance is primarily caused by a decrease in regulatory credits resulting from higher realized income on decommissioning trust fund investments.

Following is an analysis of the change in net revenue comparing 2013 to 2012.

As shown in the table above, net revenue for Entergy Wholesale Commodities decreased by approximately $52 million in 2013 primarily due to:

Following are key performance measures for Entergy Wholesale Commodities for 2013 and 2012.

Other operation and maintenance expenses increased from $2,080 million for 2012 to $2,264 million for 2013 primarily due to:

Taxes other than income taxes increased primarily due to an increase in ad valorem taxes, primarily due to the Hot Spring and Hinds plant acquisitions in 2012, as well as an increase in local franchise taxes resulting from higher residential and commercial revenues as compared with prior year.

Depreciation and amortization expenses increased primarily due to additions to plant in service, including the Hot Spring and Hinds plant acquisitions in 2012 and the completion of the Waterford 3 steam generator replacement project and the Grand Gulf uprate project in 2012. Also contributing to the increase is an increase in depreciation rates as a result of the 2011 rate case order issued by the PUCT in September 2012.

Interest expense increased primarily due to net debt issuances in 2013 of $520 million by the Utility operating companies and System Energy and lower ~~AFUDC~~allowance for borrowed funds used during construction due to the completion of several major projects in 2012. ~~See Note 5 to the financial statements for more details of long-term debt.~~

Other operation and maintenance expenses increased from $958 million for 2012 to $1,048 million for 2013 primarily due to:

The asset impairment variance is primarily due to $321.5 million ($202.2 million after-tax) in 2013 and $355.5 million ($223.5 million after-tax) in 2012 of impairment and other related charges primarily to write down the carrying value of Vermont Yankee and related assets to their fair values. See Note 1 to the financial statements for further discussion of these charges.

Depreciation and amortization expenses increased primarily due to an adjustment in 2012 resulting from final court decisions in the Indian Point 2 and Vermont Yankee lawsuits against the U.S. Department of Energy related to

The gain on sale of business resulted from the sale in November 2013 of Entergy Solutions District Energy, a business wholly-owned by Entergy in the Entergy Wholesale Commodities segment that ~~owns~~owned and ~~operates~~operated district energy assets serving the business districts in Houston and New Orleans. Entergy sold Entergy Solutions District Energy for $140 million and realized a pre-tax gain of $44 million on the sale.

Other income increased primarily due to realized decommissioning trust gains that resulted from portfolio reallocations for the Indian Point 2 and ~~Palisades.~~Palisades decommissioning trust funds.

Other expenses increased primarily due to a credit to decommissioning expense of $49 million in the second quarter 2012 resulting from a reduction in the decommissioning cost liability for a plant as a result of a revised decommissioning cost study. See “Critical Accounting Estimates - Nuclear Decommissioning Costs” for further discussion of nuclear decommissioning costs.

Other operation and maintenance expenses increased primarily due to the elimination of intersegment activity.

See Note 3 to the financial statements for a reconciliation of the federal statutory rate of 35% to the effective income tax rates, and for additional discussion regarding income taxes.

The effective income tax rate for 2013 was 23.6%. The difference in the effective income tax rate versus the statutory rate of 35% for 2013 was primarily related to (1) IRS settlements as discussed further in Note 3 to the financial statements; and (2) a tax benefit associated with the ~~ITC transaction,~~now-terminated plan to spin off and merge the Utility’s transmission business, because certain associated costs became deductible with the termination of the transaction.

The effective income tax rate for 2012 was 3.4%. The difference in the effective income tax rate versus the statutory rate of 35% for 2012 was primarily related to (1) IRS settlements as discussed further in Note 3 to the financial statements; and (2) a unanimous court decision from the U.S. Court of Appeals for the Fifth Circuit affirming an earlier decision of the U.S. Tax Court holding that Entergy was entitled to claim a credit against its U.S. tax liability for the U.K. windfall tax that it paid. The decision necessitated that Entergy reverse the provision for the uncertain tax position related to that item.

~~In March 2011 and May 2012 the~~The NRC ~~renewed the~~ operating ~~licenses of Vermont Yankee and Pilgrim, respectively,~~license for ~~an additional 20 years, as a result of which each license now~~Palisades expires in ~~2032.~~2031, for Pilgrim expires in 2032, and for FitzPatrick expires in 2034. For additional discussion regarding the ~~planned~~ shutdown of the Vermont Yankee plant ~~by the end of~~in December 2014, see “Impairment of Long-Lived Assets” in Note 1 to the financial statements. ~~The NRC operating license for Palisades expires in 2031 and for FitzPatrick expires in 2034.~~

In April 2007, Entergy submitted to the NRC a joint application to renew the operating licenses for Indian Point 2 and Indian Point 3 for an additional 20 years. The original expiration date of the NRC operating license for Indian Point 2 was in September 2013 and the original expiration date of the NRC operating license for Indian Point 3 is in December 2015. ~~In April 2007, Entergy submitted the applications~~Authorization to ~~the NRC to renew the operating licenses~~operate Indian Point 2 rests, and for Indian Point ~~2 and~~ 3 ~~for an additional 20 years.~~will rest, on Entergy’s having timely filed a license renewal application that remains pending before the NRC. Indian Point ~~Unit~~ 2 has now entered its “period of extended operation” after expiration of the plant’s initial license term under “timely renewal,” which is a federal statutory rule of general applicability providing for extension of a license for which a renewal application has been timely filed with the licensing agency. ~~The~~ Indian Point 3 is expected to reach the same milestone, and to become subject to the same statutorily prescribed extension of its license ~~renewal application qualifies for timely renewal protection because it met NRC regulatory standards for timely filing.~~expiration date, in December 2015. The license

The scope of NRC license renewal applications is focused primarily on whether the licensee has in place aging management programs (detailed diagnostic analyses performed when and as prescribed) to ensure that passive systems, structures, and components (such as pipes and concrete and metal structures) can continue to perform their intended safety functions. Other aspects of nuclear plant operations (maintenance of active components like pumps and control systems, security, and emergency preparedness) are regulated by the NRC on an ongoing basis and, as such, are outside the scope of license renewal proceedings. The NRC also determines whether there are any environmental impacts that would affect license renewal.

Every application for renewal of a reactor operating license undergoes comprehensive NRC staff review to ensure the adequacy of the application and the aging management programs detailed in it. NRC staff’s conclusions following such review are set forth in a Final Safety Evaluation Report (FSER). Issuance of a renewed operating license is a “major federal action” under the National Environmental Policy Act, so NRC staff also are required to prepare an Environmental Impact Statement (EIS) regarding the proposed licensing action. The NRC has elected to address certain EIS issues on a generic basis via the rulemaking process. As a result, the EIS for a particular license renewal proceeding has two components: the Generic Environmental Impact Statement and a Final Supplemental Environmental Impact Statement (FSEIS) addressing site-specific EIS issues. Both the FSER and the FSEIS are subject to updating by NRC staff in an individual license renewal proceeding.

Where, as in the case of Indian Point, one or more intervenors proposes for admission contentions alleging errors and omissions in the applicant’s license renewal application or the NRC staff’s review of related safety and environmental issues, the NRC appoints an ASLB to determine whether the contentions satisfy threshold standards and, if so, to adjudicate such “admitted” contentions. Safety-related contentions address issues that will be or have been described in the FSER; environmental-related contentions address issues that will be or have been described in the FSEIS. Contentions may be proposed at any time before license issuance based on new and material information, subject to timeliness and admissibility standards. Final ASLB orders on admissibility or resolving contentions, whether after hearing or on summary disposition, are appealable to the NRC.

Various ~~parties~~governmental and private intervenors have ~~expressed~~sought and obtained party status to express opposition to renewal of the Indian Point 2 and Indian Point 3 licenses. The ASLB has admitted 16 consolidated contentions based on 21 contentions ~~raised~~originally proposed by the State of New York or other ~~parties, which were combined into 16 discrete issues.~~parties.

~~Three~~Four of the 16 ~~discrete issues~~admitted contentions have been resolved by the ASLB without hearing, two by means of ASLB-approved settlements, ~~and~~ a third by summary ~~disposition.~~disposition as described below, and a fourth by motion to dismiss as moot as described in the second paragraph below. 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 Final Supplemental Environmental Impact Statement (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~~premature. Entergy renewed its appeal in February 2014 in conjunction with the ~~appeal could be renewed at the conclusion~~filing of ~~the ASLB proceedings.~~Track 1 appeals, as discussed further below. In May 2013, Entergy filed an updated SAMA cost analysis with the NRC, and in July 2013 the ASLB granted ~~Entergy's~~Entergy’s motion for clarification that a future NRC staff filing would be the trigger for potential new or amended contentions on the SAMA update. ~~There is no deadline for the NRC staff filing on Entergy's updated SAMA cost analysis.~~

OfNine of the remaining ~~13 discrete issues, nine that~~admitted contentions were designated by the ASLB as “Track 1” and were subject to hearings over 12 days in October, November, and December 2012. In November 2013 the ASLB issued a decision on the nine Track 1 contentions. The ASLB resolved eight Track 1 contentions favorably to Entergy. ~~One~~No appeal was

Following the ASLB's November 2013 decision on Track 1 ~~decision were due in February 2014. The~~contentions, the State of New York and Clearwater each appealed the decision on a single contention (SAMA decontamination ~~times~~cost estimates for the State of New York and environmental justice for Clearwater), while Riverkeeper filed no appeals. Entergy and NRC staff both appealed the same three issues: (1) the ~~ASLB's~~ASLB’s decision on electrical transformers; (2) certain intermediate determinations in the ~~ASLB's~~ASLB’s overall favorable decision on environmental justice; and (3) the ~~ASLB's~~ASLB’s earlier decisions on SAMA cost estimates, thus renewing their appeals of that issue previously denied by the NRC as premature. Appeal (3) addressed a contention that was one of the four decided without hearing. The ~~ASLB's~~remaining appeals addressed contentions that were tried in Track 1 hearings.

In February 2015, the NRC granted petitions for review of two appeals for the purpose of obtaining additional information prior to making final disposition. The appeals for which the NRC requested answers to specified questions were New York State’s appeal on SAMA decontamination cost estimates and the appeal of Entergy and NRC staff on SAMA cost estimates. The NRC stated that the remaining appeals filed after the ASLB’s Track 1 decision ~~on issues not appealed is now final. NRC rules provide for two further rounds of filings after submission of appeals.~~would be resolved in the future. There is no deadline for the NRC ~~to resolve~~action on either group of appeals from the ASLB.

The remaining four ~~discrete issues have been~~admitted consolidated contentions were designated by the ASLB as “Track 2.” ~~Testimony~~In April 2014 the ASLB granted Entergy’s motion to dismiss as moot a contention by Riverkeeper alleging that the FSEIS failed to adequately address endangered species issues. At the same time, the ASLB denied a motion filed by Riverkeeper in August 2013 to amend its endangered species contention. These ASLB decisions were not appealed and are now final, making a total of nine of the original 16 admitted consolidated contentions that have been resolved favorably (or in the case of settlement, acceptably) to Entergy. Seven of the original 16 admitted consolidated contentions are on appeal (four total) or pending hearing on Track 2 ~~contentions has not been completed, and~~(three total).

While Track 2 hearings have not been ~~scheduled.~~scheduled, the procedural steps leading to such hearings have begun. Pursuant to ASLB procedural orders, New York State filed in February 2015 proposed revisions to two of the three admitted contentions designated as Track 2. Entergy and NRC staff will have an opportunity to oppose or to seek limitations on those contention revisions, after which the ASLB will decide whether to accept New York State’s proposed revisions to previously-admitted contentions. In addition, before Track 2 hearings are convened, the parties will have the opportunity to update and complete their testimony.

~~The~~Independent of the ASLB process, the NRC staff ~~is also continuing to perform~~has performed its technical and environmental reviews of the Indian Point 2 and Indian Point 3 license renewal ~~applications.~~application. The NRC staff issued ~~a Final Safety Evaluation Report (FSER)~~an FSER in August 2009, a supplement to the FSER in August 2011, aan FSEIS in December 2010, ~~and~~ a supplement to the FSEIS in June ~~2013. In addition, the NRC staff has stated its intent to issue~~2013, and, as noted above, a further supplement to the FSER ~~by mid-2014. The~~in November 2014. In November 2014 the NRC staff ~~is considering whether~~advised of its proposed schedule for issuance of a ~~second~~further FSEIS supplement to address new information received by NRC staff since preparation and publication of the previous FSEIS ~~is necessary.~~supplement in June 2013. The ~~second supplement~~proposed schedule identifies several milestones leading to the ~~FSER~~issuance of a new final FSEIS supplement in March 2016. The matters to be addressed in the new supplement include Entergy’s May 2013 submittal of updated cost information for SAMAs; Entergy’s February 2014 submittal of new aquatic impact information; the June 2013 revision by the NRC of its Generic Environmental Impact Statement relied upon in license renewal proceedings; and the ~~already-issued supplement to~~NRC’s Continued Storage Of Spent Nuclear Fuel rule, which was published in the ~~FSEIS are expected to affect testimony yet to be filed on Track 2 contentions.~~Federal Register in September 2014.

The hearing process is an integral component of the NRC’s regulatory framework, and evidentiary hearings on license renewal applications are not uncommon. Entergy is participating fully in the hearing and appeals processes as authorized by the NRC regulations. As noted in Entergy filings at the ASLB and the appellate levels, 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 Indian Point 2 and 3 license renewal

NYSDOS disputed the effectiveness of Entergy’s November 2014 notice withdrawing the consistency certification. In ~~January~~December 2014, Entergy and NYSDOS executed ~~another~~an agreement intended to preserve the parties’ respective positions on withdrawal. The agreement provides, among other things, that if NYSDOS is correct about withdrawal not being effective, the parties will be deemed to have agreed to a stay ~~agreement that further extends YSDOS's~~of NYSDOS’s deadline for decision on the 2012 consistency certification to ~~December 31, 2014. A basis for the further extension is a request by NYSDOS for supplemental information, to which~~ June 30, 2015.

In August 2013, Riverkeeper filed with the ASLB a proposed amended Endangered Species Act contention alleging that NRC Staff’s supplemental FSEIS issued in June 2013 did not adequately consider Riverkeeper comments or explain the effect of certain new information used to develop the supplemental FSEIS. Entergy and NRC Staff have filed answers in opposition. Riverkeeper’s proposed amended contention and Entergy’s motion to dismiss Riverkeeper’s original admitted contention on endangered species are pending before the ASLB.

Entergy Arkansas is ~~assessing~~pursuing its options for recovering damages that resulted from the stator drop, including its insurance coverage and legal action. Entergy is a member of Nuclear Electric Insurance Limited (NEIL), a mutual insurance company that provides property damage coverage to the members’ nuclear generating plants, including ANO. NEIL has notified Entergy that it believes that a $50 million course of construction sublimit applies to any loss associated with the lifting apparatus failure and stator drop at ANO. Entergy has responded that it disagrees with ~~NEIL's~~NEIL’s position and is evaluating its options for enforcing its rights under the policy. During 2014, Entergy Arkansas collected $50 million from NEIL and is pursuing additional recoveries due under the policy. On July 12, 2013, Entergy Arkansas filed a complaint in the Circuit Court in Pope County, Arkansas against the owner of the heavy-lifting apparatus that collapsed, an engineering firm, a ~~general~~ contractor, and certain individuals asserting claims of breach of contract, negligence, and gross negligence in connection with their responsibility for the stator drop.

Shortly after the stator incident, the NRC deployed an augmented inspection team to review the plant’s response. In July 2013 a second team of NRC inspectors visited ANO to evaluate certain items that were identified as requiring follow-up inspection to determine whether performance deficiencies existed. In March 2014 the ~~second quarter 2013, Entergy Arkansas recorded~~NRC issued an ~~insurance receivable of $50 million based~~inspection report on the ~~minimum amount~~follow-up inspection that discussed two preliminary findings, one that was preliminarily determined to be “red with high safety significance” for Unit 1 and one that was preliminarily determined to be “yellow with substantial safety significance” for Unit 2, with the NRC indicating further that these preliminary findings may warrant additional regulatory oversight. This report also noted that one additional item related to flood barrier effectiveness was still under review.

In May 2014 the NRC met with Entergy during a regulatory conference to discuss the preliminary red and yellow findings and Entergy’s response to the findings. During the regulatory conference, Entergy presented information on the facts and assumptions the NRC used to assess the potential findings. The NRC used the information provided by Entergy at the regulatory conference to finalize its decision regarding the inspection team’s findings. In a letter dated June 23, 2014, the NRC classified both findings as “yellow with substantial safety significance.” In an assessment follow-up letter for ANO dated July 29, 2014, the NRC stated that given the two yellow findings, it expects to receive from NEIL. This $50 million receivable offset approximately $35 million of capital spending, $13 million of operation and maintenance expense, and $2 million of incremental deferred refueling outage costs incurred fordetermined that the ~~recovery through December 31, 2013. As of December 31, 2013, Entergy Arkansas has incurred approximately $34 million~~performance at ANO is in capital spending, $9 million in operation and maintenance expense, and $1 million in incremental deferred refueling outage costs in excess of its recorded insurance receivable. In January 2014, Entergy Arkansas collected $20 millionthe “degraded cornerstone column,” or column 3, of the ~~$50 million receivable that it expects~~NRC’s reactor oversight process action matrix beginning the first quarter 2014. Corrective actions in response to ~~receive from NEIL.~~the NRC’s findings have been taken and remain ongoing at ANO. The NRC plans to conduct supplemental inspection activity to review the actions taken to address the yellow findings. Entergy will continue to interact with the NRC to address the NRC’s findings.

In September 2014 the NRC issued an inspection report on the flood barrier effectiveness issue that was still under review at the time of the March 2014 inspection report. While Entergy believes that the flood barrier issues that led to the finding have been addressed at ANO, NRC processes still required that the NRC assess the safety significance of the deficiencies. In its September 2014 inspection report, the NRC discussed a preliminary finding of “yellow with

The NRC’s January 2015 letter did not advise ANO of the additional level of oversight that will result from the yellow finding related to the flood barrier issue, and it stated that the NRC would inform ANO of this decision by separate correspondence. The yellow finding may result in ANO being placed into the “multiple/repetitive degraded cornerstone column” of the NRC’s reactor oversight process action matrix. Placement into this column would require significant additional NRC inspection activities at the ANO site, including a review of the site’s root cause evaluation associated with the flood barrier and stator issues, an assessment of the effectiveness of the site’s corrective action program, an additional design basis inspection, a safety culture assessment, and possibly other inspection activities consistent with the NRC’s Inspection Procedure. The additional NRC inspection activities at the site are expected to increase ANO’s operating costs.

Entergy engaged in a strategic imperative intended to optimize the organization through a process known as human capital management. In July 2013 management completed a comprehensive review of Entergy’s organization design and processes. This effort resulted in a new internal organization structure, which resulted in the elimination of approximately 800 employee positions. Entergy incurred approximately $110 million and approximately $20 million in costs in 2013 and 2014, respectively, associated with this phase of human capital management, primarily implementation costs, severance expenses, pension curtailment losses, special termination benefits expense, and corporate property, plant, and equipment impairments. In December 2013, Entergy deferred for future recovery approximately $45 million of these costs, as approved by the APSC and the LPSC. See Note 2 to the financial statements for details of the deferrals and Note 13 to the financial statements for details of the restructuring charges.

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.

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

Long-term debt, including the currently maturing portion, makes up most of Entergy’s total debt outstanding. Following are Entergy’s long-term debt principal maturities and estimated interest payments as of December 31, ~~2013.~~2014. To estimate future interest payments for variable rate debt, Entergy used the rate as of December 31, ~~2013.~~2014. 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.

Entergy Corporation has in place a credit facility that has a borrowing capacity of $3.5 billion and expires in March ~~2018.~~2019. Entergy Corporation has the ability to issue letters of credit against 50% of the total borrowing capacity of the facility. The commitment fee is currently 0.275% of the undrawn commitment amount. Commitment 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, ~~2013~~2014 was ~~1.96%~~1.93% on the drawn portion of the facility.

As of December 31, ~~2013,~~2014, amounts outstanding and capacity available under the $3.5 billion credit facility are:

~~In September 2012,~~ Entergy ~~implemented~~Corporation has a commercial paper program ~~and in July 2013 the Board increased the commercial paper~~with a Board-approved program limit of up to ~~$1.5~~$1.5 billion. ~~As of~~At December 31, ~~2013,~~2014, Entergy Corporation had ~~approximately $1,045~~$484 million of commercial paper outstanding. The weighted-average interest rate for the year ended December 31, ~~2013~~2014 was ~~0.84%~~0.88%.

Capital lease obligations are a minimal part of Entergy’s overall capital structure. Following are Entergy’s payment obligations under those leases.

Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas each had credit facilities available as of December 31, ~~2013~~2014 as follows:

~~In addition, Entergy Mississippi and Entergy New Orleans each entered into an uncommitted letter~~Each of credit facility as a means to post collateral to support its obligations related to MISO. As of December 31, 2013, a $21 million letter of credit was outstanding under Entergy Mississippi’s letter of credit facility and a $8.5 million letter of credit was outstanding under Entergy New Orleans’s letter of credit facility. As of December 31, 2013, the ~~letter of credit fee on outstanding letters of credit under the Entergy Mississippi and Entergy New Orleans letter of~~ credit facilities ~~was 1.50%.~~requires the Registrant Subsidiary borrower to maintain a debt ratio of 65% or less of its total capitalization. Each Registrant Subsidiary is in compliance with this covenant.

In addition, Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas each entered into one or more uncommitted standby letter of credit facilities as a means to post collateral to support its obligations related to MISO. Following is a summary of the uncommitted standby letter of credit facilities as of December 31, 2014:

In January 2015, Entergy Nuclear Vermont Yankee entered into a credit facility guaranteed by Entergy Corporation with a borrowing capacity of $60 million which expires in January 2018. Also in January 2015, Entergy Nuclear Vermont Yankee entered into an uncommitted credit facility guaranteed by Entergy Corporation with a borrowing capacity of $85 million which expires in January 2018. See Note 4 to the financial statements for additional discussion of the Vermont Yankee facilities.

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, ~~2013~~2014 on non-cancelable operating leases with a term over one year:

Also in addition to the contractual obligations, Entergy has ~~$193~~$441 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.

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

Following are the amounts of Entergy’s planned construction and other capital investments by operating segment for ~~2014~~2015 through ~~2016.~~2017.

Planned construction and capital investments refer 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, and includes spending for the nuclear and non-nuclear plants at Entergy Wholesale Commodities. In addition to routine capital projects, they also refer to amounts Entergy plans to spend on 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 include the following:

In December 2014, Entergy Arkansas, Entergy Gulf States Louisiana, and Entergy Texas entered into an asset purchase agreement to acquire the Union Power Station, a 1,980 MW (summer rating) power generation facility located near El Dorado, Arkansas, from Union Power Partners, L.P. The Union Power Station consists of four natural gas-fired, combined-cycle gas turbine power blocks, each rated at 495 MW (summer rating). Pursuant to the agreement, Entergy Gulf States Louisiana will acquire two of the power blocks and a 50% undivided ownership interest in certain assets related to the facility, and Entergy Arkansas and Entergy Texas will each acquire one power block and a 25% undivided ownership interest in such related assets. If Entergy Arkansas or Entergy Texas do not obtain approval for the purchase of their power blocks, Entergy Gulf States Louisiana will seek to purchase the power blocks not approved. The base purchase price is expected to be approximately $948 million (approximately $237 million for each power block) subject to adjustments. In addition, Entergy Gulf States Louisiana anticipates selling 20% of the capacity and energy associated with its two power blocks to Entergy New Orleans through a cost-based, life-of-unit power purchase agreement. The purchase is contingent upon, among other things, obtaining necessary approvals, including cost recovery, from various federal and state regulatory and permitting agencies. These include regulatory approvals from the APSC, LPSC, PUCT, and FERC, as well as clearance under the Hart-Scott-Rodino anti-trust law. In December 2014, Entergy Texas filed its application with the PUCT for approval of the acquisition. The PUCT has indicated that it will convene the hearing on the merits of this case in June 2015. Entergy Texas intends to file a rate application to seek cost recovery later in 2015. In January 2015, Entergy Gulf States Louisiana filed its application with the LPSC and Entergy Arkansas filed its application with the APSC, each for approval of the acquisition and cost recovery. Closing is targeted to occur in late-2015.

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~~is a nominally-sized ~~550~~560 MW unit that is ~~estimated~~expected to cost approximately ~~$721~~$655 million to construct when spending is complete, 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 25% of the capacity and energy generated by Ninemile 6. The

Under ~~the~~ terms approved by the LPSC, non-fuel costs may be recovered through Entergy Louisiana’s and Entergy Gulf States Louisiana’s formula rate plans beginning in the month after the unit is placed in service. In ~~November 2013,~~July 2014, Entergy Louisiana and Entergy Gulf States Louisiana filed ~~a joint application~~an unopposed stipulation with the LPSC ~~to certify the estimated~~that estimates a first year revenue requirement associated with Ninemile 6 ~~that will be placed into rates.~~and provides a mechanism to update the revenue requirement as the in-service date approaches, which was subsequently approved by the LPSC. In late December 2014, roughly contemporaneous with the unit’s placement in service, a final updated estimated revenue requirement of $51.1 million for Entergy Louisiana and $26.8 million for Entergy Gulf States Louisiana was filed. The December 2014 estimate forms the basis of rates implemented effective with the first billing cycle of January 2015. Under terms approved by the City Council, Entergy New ~~Orleans expects to initiate~~Orleans’s non-fuel costs associated with Ninemile 6 may be recovered through a ~~rate proceeding prior~~special rider for that purpose. The unit was placed in service in December 2014. Entergy Louisiana will submit project and cost information to the ~~expected in-service date.~~LPSC in mid-2015 to enable the LPSC to review the prudence of Entergy Louisiana’s management of the project.

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 ~~2014~~2015 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. Entergy paid $596 million in 2014, $593 million in 2013, and $589 million in 2012 ~~and $590 million in 2011~~ in cash dividends on its common stock.

In accordance with Entergy’s stock-based compensation plans, Entergy periodically grants stock options, restricted stock, performance units, and restricted unit awards to key employees, which may be exercised to obtain shares of Entergy’s common stock. According to the plans, 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 plans.

In addition to the authority to fund grant exercises, the Board has authorized share repurchase programs to enable opportunistic purchases in response to market conditions. In October 2010 the Board granted authority for a $500 million share repurchase program. As of December 31, ~~2013,~~2014, $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.

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

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, ~~2013,~~2014, under provisions

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, 2015. 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 October 2015. Entergy Arkansas has obtained long-term financing authorization from the APSC that extends through December 2015. Entergy New Orleans has obtained long-term financing authorization from the City Council that extends through July ~~2014.~~2016. Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, and System Energy each have obtained long-term financing authorizations from the FERC that extend through October 2015 for issuances by its nuclear fuel company variable interest entity. 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 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 short-term borrowing limits. See Notes 4 and 5 to the financial statements for further discussion of Entergy’s borrowing limits, authorizations, and amounts outstanding.

In August 2012, Hurricane Isaac caused extensive damage to portions of ~~Entergy's~~Entergy’s service area in Louisiana, and to a lesser extent in Mississippi and Arkansas. The storm resulted in widespread power outages, significant damage primarily to distribution infrastructure, and the loss of sales during the power outages.

In ~~August 2011~~July 2014, Entergy Gulf States Louisiana issued $110 million of 3.78% Series first mortgage bonds due April 2025 and used the ~~LPSC issued a financing order authorizing the issuance of bonds~~proceeds to ~~recover Entergy Louisiana’s investment recovery costs associated with the canceled Little Gypsy repowering project.~~re-establish and replenish its storm damage escrow reserves and for general corporate purposes. In ~~September 2011,~~July 2014, Entergy Louisiana ~~Investment Recovery Funding I, L.L.C.,~~issued $190 million of 3.78% Series first mortgage bonds due April 2025 and used the proceeds to re-establish and replenish its storm damage escrow reserves and for general corporate purposes.

In August 2014 the Louisiana Local Government Environmental Facilities and Community Development Authority (LCDA) issued $71 million in bonds under Act 55 of the Louisiana Legislature. From the $69 million of bond proceeds loaned by the LCDA to the LURC, the LURC deposited $3 million in a restricted escrow account as a storm damage reserve for Entergy Gulf States Louisiana and transferred $66 million directly to Entergy Gulf States Louisiana. Entergy Gulf States Louisiana used the $66 million received from the LURC to acquire 662,426.80 Class C preferred, non-voting, membership interest units of Entergy Holdings Company LLC, a company wholly-owned and consolidated by Entergy, that carry a 7.5% annual distribution rate. Distributions are payable quarterly commencing on September 15, 2014, and the membership interests have a liquidation price of $100 per unit. The preferred membership interests are callable at the option of Entergy Holdings Company LLC after ten years under the terms of the LLC agreement. The terms of the membership interests include certain financial covenants to which Entergy Holdings Company LLC is subject, including the requirement to maintain a net worth of at least $1.75 billion.

In August 2014 the LCDA issued another $243.85 million in bonds under Act 55 of the Louisiana ~~issued $207.2~~Legislature. From the $240 million of ~~senior secured investment recovery bonds.~~bond proceeds loaned by the LCDA to the LURC, the LURC deposited $13 million in a restricted escrow account as a storm damage reserve for Entergy Louisiana and transferred $227 million directly to Entergy Louisiana. Entergy Louisiana used the $227 million received from the LURC to acquire 2,272,725.89 Class C preferred, non-voting, membership interest units of Entergy Holdings Company LLC that carry a 7.5% annual distribution rate. Distributions are payable quarterly commencing on September 15, 2014, and the membership interests have a liquidation price of $100 per unit. The preferred membership interests are callable at the option of Entergy Holdings Company LLC after ten years under the terms of the LLC agreement. The terms of the membership interests include certain financial covenants to which Entergy Holdings Company LLC is subject, including the requirement to maintain a net worth of at least $1.75 billion.

Entergy, Entergy Gulf States Louisiana, and Entergy Louisiana do not report the bonds ~~have an interest rate~~on their balance sheets because the bonds are the obligation of ~~2.04%~~the LCDA and ~~an expected maturity date of June 2021. There~~there is no recourse toagainst Entergy, Entergy Gulf States Louisiana, or Entergy Louisiana in the event of a bond default. ~~See Note 5~~To service the bonds, Entergy Gulf States Louisiana and Entergy Louisiana collect a system restoration charge on behalf of the LURC, and remit the collections to the ~~financial statements~~bond indenture trustee. Entergy, Entergy Gulf States Louisiana, and Entergy Louisiana do not report the collections as revenue because they are merely acting as the billing and collection agents for ~~additional discussion of~~ the ~~issuance of the investment recovery bonds.~~state.

As shown in Entergy’s Statements of Cash Flows, cash flows for the years ended December 31, 2014, 2013, ~~2012,~~ and ~~2011~~2012 were as ~~follows.~~follows:

Net cash provided by operating activities increased by $701 million in 2014 primarily due to:

Net cash provided by operating activities increased by $249 million in 2013 ~~compared to 2012~~ primarily due to:

~~Entergy's net~~Net cash ~~provided~~used in investing activities increased by ~~operating activities decreased by $188~~$353 million in ~~2012 compared to 2011~~2014 primarily due to:

Net cash used in investing activities decreased by $1,038 million in 2013 ~~compared to 2012~~ primarily due to:

Net cash flow used in ~~investing~~financing activities ~~increased~~decreased by ~~$192~~$129 million in ~~2012~~2014 primarily due to:

Financing activities used $381 million in net cash in 2013 compared to providing $538 million in net cash in 2012 primarily due to:

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:

On December 19, 2013, the Utility operating companies successfully completed their planned integration into the MISO RTO. Integration into the MISO RTO was the culmination of efforts undertaken by the Utility operating companies consistent with FERC’s order, issued in 2000, encouraging utilities to voluntarily place their transmission facilities under the control of an independent regional transmission organization (RTO). Initially, these efforts led to the establishment of Southwest Power Pool (SPP), an RTO, in November 2006, as the Independent Coordinator of Transmission (ICT) for the Utility operating companies, with responsibility for certain transmission tariff functions, including granting or denying transmission service, administering OASIS, evaluating all transmission requests, and serving as the reliability coordinator. Also as part of these initial efforts, an Entergy Regional State Committee (E-RSC), comprised of one representative from each of the Utility operating companies’ retail regulators, was formed. In concert with the FERC, the E-RSC retained an independent entity to conduct a cost-benefit analysis comparing the option of continuing the ICT arrangement to proposals under which Entergy would join the SPP RTO or the MISO RTO. This analysis, completed in 2011, showed that joining the MISO RTO would be expected to provide the most benefits to the Utility operating companies’ customers of these options.

~~that Entergy Mississippi’s proposed transfer of functional control of its transmission facilities to MISO is in the public interest, subject to certain conditions.~~

In April 2014, Occidental filed a ~~protest~~complaint in federal district court for the Middle District of Louisiana against the LPSC and Entergy Louisiana that challenges the January 2014 order issued by the LPSC on grounds similar to those raised in the 2013 complaint and 2014 petition for enforcement that Occidental previously filed at the FERC. The district court complaint also seeks damages from Entergy Louisiana and a declaration from the district court that in pursuing the January 2014 order Entergy Louisiana breached an existing agreement with Occidental and an implied covenant of good faith and fair dealing. In January 2015 the district court granted Entergy Louisiana’s motion to stay the district court proceeding, pending a decision from the FERC relating to the ~~pleadings.~~MISO tariff and market rules that are underlying Occidental’s district court complaint. In January 2015, Occidental filed a motion for reconsideration in the district court and also filed a notice of appeal to the U.S. Fifth Circuit Court of Appeals. In February 2015 the district court denied the motion for reconsideration as moot, finding it lacked jurisdiction to consider the motion because Occidental had sought an appeal to the U.S. Fifth Circuit Court of Appeals.

In February 2013, Entergy Services, on behalf of the Utility operating companies, made a filing with the FERC requesting to adopt the standard Attachment O formula rate template used by transmission owners to establish transmission rates within MISO. The filing proposed four transmission pricing zones for the Utility operating companies, one for Entergy Arkansas, one for Entergy Mississippi, one for Entergy Texas, and one for Entergy Louisiana, Entergy Gulf States Louisiana, and Entergy New Orleans. In June 2013 the FERC issued an order accepting the use of four transmission pricing zones and set for hearing and settlement judge procedures those issues of material fact that FERC decided could not be resolved based on the existing record. Several parties, including the City Council, filed requests for rehearing of the June 2013 order. OnIn February ~~20,~~ 2014 the FERC issued an order addressing the rehearing requests. Among other things, the FERC denied rehearing and affirmed its prior decision allowing the four transmission pricing zones for the Utility operating companies in MISO. The FERC granted rehearing and set for hearing and settlement judge proceedings certain challenges of ~~MISO's~~MISO’s regional through and out rates. In March 2014 certain parties filed a request for rehearing of the FERC’s February 2014 order on issues related to MISO’s regional through and out rates. In February 2014 and April 2014 various parties appealed the FERC’s June 2013 and February 2014 orders to the U.S. Court of Appeals for the D.C. Circuit where the appeals have been consolidated for further proceedings.

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.

~~Citing its concerns that the benefits~~Consistent with their written notices of ~~its continued participation in the current form of the System Agreement have been seriously eroded,~~termination delivered 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 2012 the PUCT issued an order approving the transfer of operational control of Entergy Texas’s transmission facilities to MISO as in the public interest, subject to the terms and conditions in a non-unanimous settlement filed with the PUCT in August 2012, with several additional terms and conditions requested by the PUCT and agreed to by the settling parties. In particular, the settlement and the PUCT order required Entergy Texas, unless otherwise directed by the PUCT, to provide by October 31, 2013 its notice to exit the System Agreement, subject to certain conditions. In addition, the PUCT order requires Entergy Texas, as well as Entergy Corporation and Entergy Services, Inc., to exercise reasonable best efforts to engage the Utility operating companies and their retail regulators in searching for a consensual means, subject to FERC approval, of allowing Entergy Texas to exit the System Agreement prior to the end of the mandatory 96-month notice period.

In December 2012 the PUCT Staff filed a memo in the proceeding established by the PUCT to track compliance with its October 2012 order. In the memo, the PUCT Staff expressed concerns about the effect of Entergy Texas’s exit from the System Agreement on PPAs for gas and oil-fired generation units owned by Entergy Texas and Entergy Gulf States Louisiana that were entered into upon the December 2007 jurisdictional separation of Entergy Gulf States, Inc. and, further, expressed concerns about the implications of these issues as they relate to the continuing validity of the PUCT’s October 2012 order regarding MISO. Entergy Texas subsequently filed a position statement relating that Entergy Texas’s exit from the System Agreement would trigger the termination of the PPAs of concern to the PUCT Staff. Entergy Texas expressed its continuing commitment to work collaboratively with the PUCT Staff and other parties to address ongoing issues and challenges in implementing the PUCT order including any potential effect from termination of the PPAs. In January 2013, Entergy Texas filed an updated analysis assessing the effect on the benefits of MISO membership of terminating the particular PPAs addressed in Entergy Texas’s Statement of Position upon Entergy Texas’s exit from the System Agreement, and determined that termination of these PPAs did not adversely affect the benefits of the move to MISO once Entergy Texas exits the System Agreement. An independent consultant

In November 2012 the Utility operating companies filed amendments to the System Agreement with the FERC pursuant to section 205 of the Federal Power Act. The amendments consist primarily of the technical revisions needed to the System Agreement to (i) allocate certain charges and credits from the MISO settlement statements to the participating Utility operating companies; and (ii) address Entergy Arkansas’s withdrawal from the System Agreement. As noted in the filing, the Utility operating ~~companies~~companies’ integration into MISO and the revisions to the System Agreement are the main feature of the Utility operating companies’ future operating arrangements, including the successor arrangements with respect to the departure of Entergy Arkansas from the System Agreement. The LPSC, MPSC, PUCT, and City Council filed protests at the FERC regarding the amendments filed in November 2012 and other aspects of the Utility operating companies’ future operating arrangements, including requests that the continued viability of the System Agreement in MISO (among other issues) be set for hearing by the FERC. On March 12, 2013, the Utility operating companies filed an answer to the protests. The answer proposed, among other things, that: (1) the FERC allow the System Agreement revisions to go into effect as of December 19, 2013, without a hearing and for an initial two-year transition period; (2) no later than October 18, 2013, Entergy Services submit a filing pursuant to section 205 of the Federal Power Act that provides Entergy Texas’s notice of cancellation to terminate participation in the System Agreement and responds to the PUCT’s position that Entergy Texas be allowed to terminate its participation prior to the end of the mandatory 96-month notice period; and (3) at least six months prior to the end of the two-year transition period, Entergy Services submits an additional filing under section 205 of the Federal Power Act that addresses the allocation of MISO charges and credits among the Utility operating companies that remain in the System Agreement. On December 18, 2013, the FERC issued an order accepting the revisions filed in November 2012, subject to a further compliance filing and other conditions. The FERC set one issue for hearing involving a settlement with Union Pacific regarding certain coal delivery issues. Consistent with the decisions described above, Entergy ~~Arkansas's~~Arkansas’s participation in the System Agreement terminated effective December ~~19,~~18, 2013. In December 2014 a FERC ALJ issued an initial decision finding that Entergy Arkansas would realize benefits after December 18, 2013 from the 2008 settlement agreement between Entergy Services, Entergy Arkansas, and Union Pacific, related to certain coal delivery issues. The ALJ further found that all of the Utility operating companies should share in those benefits pursuant to the methodology proposed by the MPSC. The Utility operating companies and other parties to the proceeding have filed briefs on exceptions and/or briefs opposing exceptions with the FERC challenging various aspects of the December 2014 initial decision and the matter is pending before the FERC.

In keeping with the commitments made in ~~its~~their March 2013 answer to the protests and after a careful evaluation of the basis for and continued reasonableness of the ~~ninety-six month~~96-month System Agreement termination notice period, the Utility operating companies filed with the FERC on October 11, 2013 to amend the System Agreement changing the notice period for an operating company to terminate its participation in the System Agreement from ~~ninety-six~~96 months to ~~sixty~~60 months. The proposed amendment also clarifies that the revised notice period will apply to any written notice of termination

The LPSC, the City Council, and the PUCT protested the proposed amendment to shorten the notice period for an operating company to terminate its participation in the System Agreement from ~~ninety-six~~96 months to ~~sixty~~60 months. The City Council argued that Entergy has not adequately supported its proposal to shorten the notice period from ~~ninety-six~~96 months to ~~sixty~~60 months and asked the FERC to either reject the amendment or set it for hearing. The PUCT supported shortening of the notice period, but argued that ~~sixty~~60 months is not short enough and that the FERC should instead order Entergy to shorten the notice period to correspond to the time required for a Utility operating company to become operationally ready to participate in the MISO markets (but no longer than ~~thirty-six~~36 months). The LPSC argued that the ~~sixty-month~~60-month proposal was not justified and failed to make provision for the consequences that would flow from a company’s withdrawal from the System Agreement. The LPSC and the City Council both separately protested Entergy Texas’s termination notice.

In January 2014 the LPSC issued a directive that no later than February 15, 2014, Entergy Louisiana and Entergy Gulf States Louisiana each shall provide notice of their intention to terminate their participation in the System Agreement and shall make the necessary filings at the FERC of such notice. The LPSC further directed that Entergy Louisiana and Entergy Gulf States Louisiana and LPSC Staff continue utilizing their reasonable best efforts to achieve a consensual resolution permitting early termination of the System Agreement. On February 14, 2014, Entergy Louisiana and Entergy Gulf States Louisiana provided notice of their respective decisions to terminate their participation in the System Agreement and made a filing with the FERC seeking acceptance of the notice. In the FERC filing, Entergy Louisiana and Entergy Gulf States Louisiana requested an effective date of February 14, 2019 or such other effective date approved by the FERC for the termination. In March 2014 the City Council submitted comments to the FERC regarding the notices of termination. The City Council requested the FERC either to condition its acceptance of the notices on compliance with the prior 96-month notice termination period, or in the alternative, to consolidate the notice filings with the proceeding related to the Utility operating companies’ proposal to shorten the System Agreement’s termination notice period from 96 months to 60 months, and to set all of the proceedings for hearing. Also in March 2014, Entergy Louisiana and Entergy Gulf States Louisiana filed a response to the City Council’s comments requesting that the FERC accept the notices without hearing and with an effective date subject to and consistent with the notice period established by the FERC in the proceeding related to the Utility operating companies’ proposal to shorten the System Agreement’s termination notice period.

In December 2014 the FERC issued an order setting the proposed amendment changing the notice period from 96 months to 60 months for settlement judge and hearing procedures. The FERC’s order also conditionally accepted the notices of termination filed by Entergy Texas, Entergy Louisiana, and Entergy Gulf States Louisiana, to be effective as of the dates requested in those filings, subject to the outcome of the settlement judge procedures and hearing on the proposed amendment. Entergy Louisiana, Entergy Gulf States Louisiana, Entergy New Orleans, and Entergy Texas continue to explore with the LPSC staff, City Council advisors, and the PUCT staff the early termination of the System Agreement on a consensual basis.

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. In November 2012 the U.S. Department of Justice issued a press release in which the U.S. Department of Justice stated, among other things, that the civil investigation concerning certain generation procurement, dispatch, and transmission system practices and policies of the Utility operating companies would remain open. The release noted, however, the intention of each of the Utility operating companies

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.

Entergy’s commodity and financial instruments are also 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.

As a wholesale generator, Entergy Wholesale ~~Commodities's~~Commodities’ core business is selling energy, measured in MWh, to its customers. Entergy Wholesale Commodities enters into forward contracts with its customers and also 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’s~~Commodities’ forward physical 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. In addition to its forward physical power contracts, Entergy Wholesale Commodities also uses a combination of financial contracts, including swaps, collars, ~~put and/or call~~and options, to manage forward commodity price risk. Certain hedge volumes have price downside and upside relative to market price movement. The contracted minimum, expected value, and ~~sensitivity~~sensitivities are provided in the table below to show potential variations. The sensitivities may not reflect the total

Entergy estimates that a positive $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 income of ~~$240~~$107 million in ~~2014~~2015 and would have had a corresponding effect on pre-tax income of ~~$125~~$240 million in ~~2013.~~2014. A negative $10 per MWh change in the annual average energy price in the markets based on the respective year-end market conditions, planned generation volumes, and hedged positions, would have a corresponding effect on pre-tax income of ($~~91)~~73) million in ~~2014~~2015 and would have had a corresponding effect on pre-tax income of ($~~76)~~91) million in ~~2013.~~2014.

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

Some of the agreements to sell the power produced by Entergy Wholesale ~~Commodities~~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, ~~2013,~~2014, based on power prices at that time, Entergy had liquidity exposure of ~~$274~~$159 million under the guarantees in place supporting Entergy Wholesale Commodities transactions and ~~$104~~$5 million of posted cash collateral. As of December 31, 2013, the liquidity exposure associated with Entergy Wholesale Commodities assurance requirements, including return of previously posted collateral from counterparties, would increase by $123 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, ~~2013,~~2014, Entergy would have been required to provide approximately ~~$113~~$51 million of additional cash or letters of credit under some of the agreements. As of December 31, 2014, the liquidity exposure associated with Entergy Wholesale Commodities assurance requirements, including return of previously posted collateral from counterparties, would increase by $52 million for a $1 per MMBtu increase in gas prices in both the short-and long-term markets.

As of December 31, ~~2013,~~2014, substantially all of the counterparties or their guarantors for ~~100% of~~ the planned energy output under contract for Entergy Wholesale Commodities nuclear plants through ~~2017~~2018 have public investment grade credit ratings.

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 made initial recommendations, which were subsequently

In June 2012 the U.S. Court of Appeals for the D.C. Circuit vacated the NRC’s 2010 update to its Waste Confidence Decision, which had found generically that a permanent geologic repository to store spent nuclear fuel would be available when necessary and that spent nuclear fuel could be stored at nuclear reactor sites in the interim without significant environmental effects, and remanded the case for further proceedings. The court concluded that the NRC had not satisfied the requirements of the National Environmental Policy Act (NEPA) when it considered

The nuclear industry continues to address susceptibility to stress corrosion cracking of certain materials within the reactor coolant system. The issue is applicable at all nuclear units to varying degrees and is managed in accordance with industry standard practices and guidelines ~~which~~that include in-service examinations, replacements, and mitigation strategies. Developments in the industry or identification of issues at the nuclear units could require unanticipated remediation efforts that cannot be quantified in advance.

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 estimates as critical because they are based on assumptions and 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.

Entergy subsidiaries own nuclear generation facilities in both the Utility and Entergy Wholesale Commodities operating segments. Regulations require Entergy subsidiaries to decommission the nuclear power plants after each facility is taken out of service, and cash is 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.

In 2014, Entergy Arkansas recorded a revision to its estimated decommissioning cost liabilities for ANO 1 and ANO 2 as a result of a revised decommissioning cost study. The revised estimates resulted in a $47.6 million increase in the decommissioning cost liabilities, along with a corresponding increase in the related asset retirement cost assets that will be depreciated over the remaining lives of the units.

See Note 1 to the financial statements for further discussion of the shutdown of Vermont Yankee and the December 2013 settlement agreement involving Entergy and Vermont parties. In accordance with the settlement agreement, Entergy Vermont Yankee provided to the Vermont parties, in 2014, a site assessment study of the costs and tasks of radiological decommissioning, spent nuclear fuel management, and site restoration for Vermont Yankee. Entergy Vermont Yankee also filed its Post-Shutdown Decommissioning Activities Report (PSDAR) for Vermont Yankee with the NRC in December 2014. As part of the development of the site assessment study and PSDAR, Entergy obtained a revised decommissioning cost study in the third quarter 2014. The revised estimate, along with reassessment of the assumptions regarding the timing of decommissioning cash flows, resulted in a $101.6 million increase in the decommissioning cost liability and a corresponding impairment charge.

In the fourth quarter 2014, Entergy Gulf States Louisiana recorded a revision to its estimated decommissioning cost liability for River Bend as a result of a revised decommissioning cost study. The revised estimate resulted in a $20 million increase in the decommissioning cost liability, along with a corresponding increase in the related asset retirement cost asset that will be depreciated over the remaining useful life of the unit.

In the fourth quarter 2014, 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 $99.9 million increase in its decommissioning liability, along with a corresponding increase in the related asset retirement cost asset that will be depreciated over the remaining life of the unit.

In the first quarter 2013, Entergy Wholesale Commodities recorded a revision to its estimated decommissioning cost liability for a nuclear site as a result of a revised decommissioning cost study. The revised estimate resulted in a $46.6 million reduction in the decommissioning cost liability, along with a corresponding reduction in the related asset retirement cost asset.

In the third quarter 2013, Entergy Wholesale Commodities recorded a revision to its estimated decommissioning cost liability for Vermont Yankee as a result of a revised decommissioning cost study. The revised estimate resulted in a $58 million increase in the decommissioning cost liability, along with a corresponding increase in the related asset retirement cost asset. The increase in the estimated decommissioning cost liability resulted from the change in expectation regarding the timing of decommissioning cash flows due to the decision to cease operations of the plant. The asset retirement cost asset was included in the carrying value used to write down Vermont Yankee and related assets to their fair values in third quarter 2013. See Note 1 to the financial statements for further discussion of the resulting impairment charge recorded in third quarter 2013.

In the fourth quarter 2013, 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 $102.3 million increase in its decommissioning liability, along with a corresponding increase in the related asset retirement cost asset that will be depreciated over the remaining life of the unit.

In the fourth quarter 2013, Entergy Louisiana recorded a revision to its estimated decommissioning cost liability for Waterford 3 as a result of a revised decommissioning cost study. The revised estimate resulted in a $39.4 million increase in its decommissioning cost liability, along with a corresponding increase in the related asset retirement cost asset that will be depreciated over the remaining life of the unit.

In the fourth quarter 2013, Entergy Wholesale Commodities recorded a revision to its estimated decommissioning cost liability for Vermont Yankee. As a result of a settlement agreement regarding the remaining operation and decommissioning of Vermont Yankee, Entergy reassessed its assumptions regarding the timing of

In the second quarter 2012, Entergy Wholesale Commodities recorded a reduction of $60.6 million in the estimated decommissioning cost liability for a plant as a result of a revised decommissioning cost study. The revised estimate resulted in a credit to decommissioning expense of $49 million, reflecting the excess of the reduction in the liability over the amount of the undepreciated asset retirement costs asset.

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.

Entergy has significant investments in long-lived assets in both of its operating segments, and Entergy evaluates these assets against the market economics and under the accounting rules for impairment when there are indications that ~~impairments~~an impairment may exist. This evaluation involves a significant degree of estimation and uncertainty. In the Entergy Wholesale Commodities business, Entergy’s investments in merchant generation assets are subject to impairment if adverse market or regulatory conditions arise, particularly if it leads to a ~~unit plans~~decision for Entergy to ~~cease, or ceases, operation sooner~~operate a plant for a shorter period than previously expected; if there is a significant adverse change in the physical condition of a plant; if investment in a plant significantly exceeds expected levels; or for certain nuclear ~~units~~plants if their operating licenses are not renewed.

If an asset is considered held for use, and Entergy concludes that an impairment analysis has been triggered under the accounting standards, the sum of the expected undiscounted future cash flows from the asset are compared to the asset’s carrying value. The carrying value of the asset includes any capitalized asset retirement cost associated with the 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~~recorded. If the expected undiscounted future cash flows are less than the carrying value and the carrying value exceeds the fair value, Entergy is required to record an impairment charge to write the asset down to its fair value. If an asset is considered 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.

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

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

Entergy evaluates investment securities with unrealized losses at the end of each period to determine whether an other-than-temporary impairment has occurred. 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. 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). Entergy did not have any material other than temporary impairments relating to credit losses on debt securities in 2014, 2013, ~~2012,~~ or ~~2011.~~2012. The assessment of whether an investment in an equity security has suffered an other than temporary impairment is 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 on equity securities that are considered other-than-temporarily impaired are recorded in earnings for Entergy Wholesale Commodities. Entergy Wholesale Commodities did not record material charges to other income in 2014, 2013, ~~2012,~~ or ~~2011~~2012 resulting from the recognition of other-than-temporary impairment of equity securities held in its decommissioning trust funds.

Entergy sponsors qualified, defined benefit pension plans that 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.

In December 2013, Entergy announced that employees hired or rehired after June 30, 2014, will participate in a new cash balance defined benefit pension plan and will be eligible to receive an enhanced employer matching contribution under one of the Entergy defined contribution plans, rather than the current final average pay defined benefit pension plan and employer matching contribution. These changes are prospective and have no effect on the December 31, 2013 pension obligation. Additionally, at the same time, Entergy announced changes to its other postretirement benefits which include, among other things, elimination of other postretirement benefits for all non-bargaining employees hired or rehired after June 30, 2014 and for certain bargaining employees hired or rehired after June 30, 2014, or such later date provided for in their applicable collective bargaining agreement, and setting a dollar limit cap on ~~Entergy's~~Entergy’s contribution to retiree medical costs, effective 2019 for those non-bargaining employees who commence their Entergy retirement benefits on or after January 1, ~~2015.~~2015 and for certain bargaining employees who commence their Entergy retirement benefits on or after January 1, 2015 or such later date as provided for in their applicable collective bargaining agreement. In accordance with accounting standards, certain of the other postretirement benefit changes have been reflected in the December 31, 2013 other postretirement obligation. The changes affecting active bargaining unit employees ~~will be~~are being negotiated with their unions prior to implementation, where necessary, and to the extent required by law.

Entergy’s reported costs of providing these benefits, as described in Note 11 to the financial statements, are affected 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.

Key actuarial assumptions utilized in determining these costs include:

Entergy reviews the first four assumptions listed above on an annual basis and adjusts them as necessary. The falling interest rate environment over the past few years and volatility in the financial equity markets have affected 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~~2014 actuarial study reviewed plan experience from ~~2007~~2010 through ~~2010.~~2013. As a result of the ~~2011~~2014 actuarial study and the issuance of new mortality tables in October 2014 by the Society of Actuaries, changes were made to reflect ~~the expectation that participants have~~modified demographic pattern expectations as well as longer life ~~expectancies and different retirement patterns than previously assumed.~~expectancies. These changes are reflected in the December 31, ~~2013,~~2014 financial disclosures. Adoption of the new mortality assumptions for 2015 resulted in an increase at December 31, ~~2012~~2014 of $504.4 million in the qualified pension benefit obligation and ~~December 31, 2011 financial disclosures.~~$94.4 million in the accumulated postretirement obligation. The new mortality assumptions increased anticipated 2015 qualified pension cost by approximately $77.4 million and other postretirement cost by approximately $12.3 million. Pension funding guidelines, as established by the Employee Retirement Income Security Act of 1974, as amended and the Internal Revenue Code of 1986, as amended, are not expected to incorporate the October 2014 Society of Actuaries new mortality assumptions until after 2015, possibly 2016.

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 2014 qualified pension benefit obligation and 2015 qualified pension cost ranged from 4.03% to 4.40% for its specific pension plans (4.27% combined rate for all pension plans). The discount rates used to calculate its 2013 qualified pension benefit obligation and 2014 qualified pension cost ranged from 5.04% to 5.26% for its specific pension plans (5.14% combined rate for all pension plans). The discount rates used to calculate its 2012 qualified pension benefit obligation and 2013 qualified pension cost ranged from 4.31% to 4.50% for its specific pension plans (4.36% combined rate for all pension plans). The discount ~~rates~~rate used to calculate its ~~2011 qualified pension~~2014 other postretirement benefit obligation and ~~2012 qualified pension~~2015 other postretirement benefit cost ~~ranged from 5.1% to 5.2% for its specific pension plans (5.1% combined rate for all pension plans)~~was 4.23%. The discount rate used to calculate its 2013 other postretirement benefit obligation and 2014 other postretirement benefit cost was 5.05%~~.The~~. The discount rate used to calculate its 2012 other postretirement benefit obligation and 2013 other postretirement benefit cost was

Entergy reviews actual recent cost trends and projected future trends in establishing health care cost trend rates. Based on this review, Entergy’s health care cost trend rate assumption used in measuring the December 31, 2014 accumulated postretirement benefit obligation and 2015 postretirement cost was 7.10% for pre-65 retirees and 7.70% for post-65 retirees for 2014, gradually decreasing each successive year until it reaches 4.75% in 2023 and beyond for both pre-65 and post-65 retirees. Entergy’s assumed health care cost trend rate assumption used in measuring the December 31, 2013 accumulated postretirement benefit obligation and 2014 postretirement cost was 7.25% for pre-65 retirees and 7.00% for post-65 retirees for 2013, gradually decreasing each successive year until it reaches 4.75% in 2022 and beyond for both pre-65 and post-65 retirees. Entergy’s assumed health care cost trend rate assumption used in measuring ~~the December 31, 2012 accumulated postretirement benefit obligation and~~ 2013 postretirement cost was 7.50% for pre-65 retirees and 7.25% for post-65 retirees, ~~for 2013,~~ gradually decreasing each successive year until it reaches 4.75% in 2022 and beyond for both pre-65 and post-65 retirees. Entergy’s assumed

The assumed rate of increase in future compensation levels used to calculate ~~2013~~2014 and ~~2012~~2013 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 that recommended that the target asset allocation adjust dynamically over time, based on the funded status of the plan, from its current allocation to an ultimate allocation of 45% equity and 55% fixed income securities. The ultimate asset allocation is expected to be attained when the plan is 105% funded.

The current target allocations for both ~~Entergy's~~Entergy’s non-taxable postretirement benefit assets and its taxable other postretirement benefit assets are 65% equity securities and 35% fixed-income securities. This takes into account asset allocation adjustments that were made during 2012.

Entergy’s expected long term rate of return on qualified pension assets used to calculate 2014, 2013, ~~2012~~ and ~~2011~~2012 qualified pension costs was 8.5% and will be ~~8.5%~~8.25% for ~~2014.~~2015. Entergy’s expected long term rate of return on ~~non-taxable~~tax deferred other postretirement assets used to calculate other postretirement costs was 8.3% for 2014 and 8.5% for 2013 ~~2012,~~ and ~~2011, and~~2012. It will be ~~8.3%~~8.05% for ~~2014.~~2015. For Entergy’s taxable postretirement assets, the expected long term rate of return was 6.5% for 2014, 2013, and 2012, ~~5.5% for 2011,~~ and will be ~~6.5%~~6.25% in ~~2014.~~2015.

Accounting standards allow for the deferral of prior service costs/credits arising from plan amendments that attribute an increase or decrease in benefits to employee service in prior periods and deferral of gains and losses arising from the difference between actuarial estimates and actual experience. Prior service costs/credits and deferred gains and losses are then amortized into expense over future periods. Certain decisions, including workforce reductions and plan amendments, may significantly reduce the expense amortization period and result in immediate recognition of certain previously-deferred costs and gains/losses in the form of curtailment losses or gains. Similarly, payments made to settle benefit obligations can also result in recognition in the form of settlement losses or gains.

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).

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

Accounting standards require an employer to recognize in its balance sheet the funded status of its benefit plans. ~~Refer to~~See 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.

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.

In ~~2013,~~2014, Entergy’s total qualified pension cost was ~~$352~~$216.5 million, including a ~~$16.3 million curtailment charge and a $13.1~~$0.7 million special termination charge related to workforce downsizing. Entergy anticipates ~~2014~~2015 qualified pension cost to be ~~$215.7~~$320.7 million. ~~Entergy's~~Entergy’s pension funding was approximately ~~$163~~$399 million for ~~2013.~~2014. Entergy’s contributions to the pension trust are currently estimated to be approximately ~~$400~~$396.2 million in ~~2014,~~2015, although the required pension contributions will not be known with more certainty until the January 1, ~~2014~~2015 valuations are completed by April 1, ~~2014. The expected increase in pension contributions is primarily due to the phase out of pension funding relief under the Moving Ahead for Progress in the 21st Century Act (MAP-21).~~2015.

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 that, 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.

~~MAP-21~~Moving Ahead for Progress in the 21st Century Act (MAP-21) became federal law onin July 6, 2012. Under the law, the segment rates used to calculate funding liabilities must be within a corridor of the 25-year average of prior segment rates. The interest rate corridor applies to the determination of minimum funding requirements and benefit restrictions. The pension funding stabilization provisions will provide for a near-term reduction in minimum funding

The Highway and ~~it is likely that Entergy’s contributions to~~Transportation Funding Act (HATFA) became federal law in August 2014. HATFA’s pension provisions provided a five-year extension of the MAP-21 pension ~~trust will increase after 2013.~~funding stabilization.

Total postretirement health care and life insurance benefit costs for Entergy in ~~2013~~2014 were ~~$155.8 million, including a $12.7 million curtailment charge related to workforce downsizing.~~$50.1 million. Entergy expects ~~2014~~2015 postretirement health care and life insurance benefit costs to be ~~$50.1~~$66.2 million. Entergy contributed ~~$75.7~~$76.5 million to its postretirement plans in ~~2013.~~2014. Entergy’s current estimate of contributions to its other postretirement plans is approximately ~~$74.1~~$66.9 million in ~~2014.~~2015.

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~~Entergy has implemented the ~~law governing employer-sponsored group health plans, like Entergy's plans, and include, among other things,~~major provisions of the ~~following significant provisions.~~law.

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

As a company with multi-state utility operations, Entergy is subject to a number of federal and state 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.

Entergy must comply with environmental laws and regulations applicable to air emissions, water discharges, solid and hazardous waste, toxic substances, protected species, and other environmental matters. Under these various laws and regulations, Entergy could incur substantial costs to comply or address any impacts to the environment. Entergy conducts studies to determine the extent of any required remediation and has recorded liabilities based upon its evaluation of the likelihood of loss and expected dollar amount for each issue. Additional sites or issues could be identified which require environmental remediation or corrective action for which Entergy could be liable. The amounts of environmental liabilities recorded can be significantly affected by the following external events or conditions.

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 possible, or remote and records

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.

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.~~projects. Final pronouncements that result from these projects could have a material effect on Entergy’s future net income, financial position, or cash flows.

In April 2014 the FASB issued ASU No. 2014-08, “Presentation of Financial Statements (Topic 205) and Property Plant, and Equipment (Topic 360): Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity” which changes the requirements for reporting discontinued operations. The ASU states that a disposal of a component of an entity or a group of components of an entity is required to be reported in discontinued operations if the disposal represents a strategic shift that has or will have a major effect on an entity’s operations and financial results when the component of an entity or group of components of an entity meets the criteria to be classified as held for sale, is disposed of by sale, or is disposed of other than by sale. The amendments in this ASU also require additional disclosures about discontinued operations. ASU 2014-08 is effective for Entergy for the first quarter 2015. Entergy does not currently expect ASU 2014-08 to affect materially its results of operations, financial position, or cash flows.

In May 2014 the FASB issued ASU No. 2014-09, “Revenue from Contracts with Customers (Topic 606).” The ASU’s core principle is that “an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services.” The ASU details a five-step model that should be followed to achieve the core principle. ASU 2014-09 is effective for Entergy for the first quarter 2017. Entergy does not expect ASU 2014-09 to affect materially its results of operations, financial position, or cash flows.

In November 2014 the FASB issued ASU No. 2014-16, “Derivatives and Hedging (Topic 815): Determining Whether the Host Contract in a Hybrid Financial Instrument Issued in the Form of a Share Is More Akin to Debt or to Equity.” The ASU states that for hybrid financial instruments issued in the form of a share, an entity should determine the nature of the host contract by considering all stated and implied substantive terms and features of the hybrid financial instrument, weighing each term and feature on the basis of relevant facts and circumstances. ASU 2014-16 is effective for Entergy for the first quarter 2016. Entergy does not expect ASU 2014-16 to affect materially its results of operations, financial position, or cash flows.

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 design and 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. The ~~original 1992~~2013 COSO Framework was utilized for ~~management's~~management’s assessment. 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’~~Corporation’s independent registered public accounting firm, Deloitte & Touche LLP, has issued an attestation report on the effectiveness of ~~Entergy’s~~Entergy Corporation’s internal control over financial reporting as of December 31, ~~2013, which is included herein on pages 436 through 443.~~2014.

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 ~~original 1992~~2013 COSO criteria, management believes that Entergy and each of the Registrant Subsidiaries maintained effective internal control over financial reporting as of December 31, ~~2013.~~2014. 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.

The accompanying consolidated financial statements include the accounts of Entergy Corporation and its subsidiaries. As required by generally accepted accounting principles in the United States of America, all intercompany transactions have been eliminated in the consolidated financial statements. Entergy’s Registrant Subsidiaries (Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy) also include their separate financial statements in this Form 10-K. The Registrant Subsidiaries and many other Entergy subsidiaries maintain accounts in accordance with FERC and other regulatory guidelines.

In conformity with generally accepted accounting principles in the United States of America, the preparation of Entergy Corporation’s consolidated financial statements and the separate financial statements of the Registrant Subsidiaries requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, and expenses and the disclosure of contingent assets and liabilities. Adjustments to the reported amounts of assets and liabilities may be necessary in the future to the extent that future estimates or actual results are different from the estimates used.

Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, and Entergy Texas generate, transmit, and distribute electric power primarily to retail customers in Arkansas, Louisiana, Louisiana, Mississippi, and Texas, respectively. Entergy Gulf States Louisiana also distributes natural gas to retail customers in and around Baton Rouge, Louisiana. Entergy New Orleans sells both electric power and natural gas to retail customers in the City of New Orleans, except for Algiers, where Entergy Louisiana is the electric power supplier. The Entergy Wholesale Commodities segment derives almost all of its revenue from sales of electric power generated by plants owned by subsidiaries in that segment.

Entergy recognizes revenue from electric power and natural gas sales when power or gas is delivered to customers. To the extent that deliveries have occurred but a bill has not been issued, Entergy’s Utility operating companies accrue an estimate of the revenues for energy delivered since the latest billings. The Utility operating companies calculate the estimate based upon several factors including billings through the last billing cycle in a month, actual generation in the month, historical line loss factors, and prices in effect in Entergy’s Utility operating companies’ various jurisdictions. Changes are made to the inputs in the estimate as needed to reflect changes in billing practices. Each month the estimated unbilled revenue amounts are recorded as revenue and unbilled accounts receivable, and the prior month’s estimate is reversed. Therefore, changes in price and volume differences resulting from factors such as weather affect the calculation of unbilled revenues from one period to the next, and may result in variability in reported revenues from one period to the next as prior estimates are reversed and new estimates recorded.

Entergy records revenue from sales under rates implemented subject to refund less estimated amounts accrued for probable refunds when Entergy believes it is probable that revenues will be refunded to customers based upon the status of the rate proceeding as of the date the financial statements are prepared.

Entergy’s Utility operating companies’ rate schedules include either fuel adjustment clauses or fixed fuel factors, which allow either current recovery in billings to customers or deferral of fuel costs until the costs are billed to customers. Where the fuel component of revenues is billed based on a pre-determined fuel cost (fixed fuel factor),

In December 2013, Entergy joined MISO, a regional transmission organization that maintains functional control over the combined transmission systems of its members and manages one of the largest energy markets in the U.S. In the MISO market, Entergy offers its generation and bids its load into the market on an hourly basis. MISO settles these hourly offers and bids based on locational marginal prices, which is pricing for energy at a given location based on a market clearing price that takes into account physical limitations on the transmission system, generation, and demand throughout the MISO region. MISO evaluates the market participants’ energy offers and demand bids to economically and reliably dispatch the entire MISO system. Entergy ~~accounts for these~~nets purchases and sales within the MISO market on an hourly ~~offers~~basis and ~~bids, on a net basis,~~reports in operating revenues when in a net selling position and in operating expenses when in a net purchasing position.

Property, plant, and equipment is stated at original cost. Depreciation is computed on the straight-line basis at rates based on the applicable estimated service lives of the various classes of property. For the Registrant Subsidiaries, the original cost of plant retired or removed, less salvage, is charged to accumulated depreciation. Normal maintenance, repairs, and minor replacement costs are charged to operating expenses. Substantially all of the Registrant Subsidiaries’ plant is subject to mortgage liens.

Electric plant includes the portions of Grand Gulf and Waterford 3 that have been sold and leased back. For financial reporting purposes, these sale and leaseback arrangements are reflected as financing transactions.

Net property, plant, and equipment for Entergy (including property under capital lease and associated accumulated amortization) by business segment and functional category, as of December 31, ~~2013~~2014 and ~~2012~~,2013, is shown below:

Depreciation rates on average depreciable property for Entergy approximated ~~2.6%~~2.8% in ~~2013~~, ~~2.5%~~2014, 2.6% in ~~2012~~,2013, and ~~2.6%~~2.5% in ~~2011~~.2012. Included in these rates are the depreciation rates on average depreciable Utility property of 2.5% in ~~2013~~, ~~2.4%~~2014, 2.5% in ~~2012~~,2013, and ~~2.5%2011~~,2.4% 2012, and the depreciation rates on average depreciable Entergy Wholesale Commodities property of ~~4.1%~~5.5% in ~~2013~~, ~~3.5%~~2014, 4.1% in ~~2012~~,2013, and ~~3.9%~~3.5% in ~~2011~~.2012. The increase in 2014 for Entergy Wholesale Commodities resulted from implementation of a new depreciation study.

Entergy amortizes nuclear fuel using a units-of-production method. Nuclear fuel amortization is included in fuel expense in the income statements.

“Non-utility property - at cost (less accumulated depreciation)” for Entergy is reported net of accumulated depreciation of ~~$203.0~~$185.5 million and ~~$230.4~~$203 million as of December 31, ~~2013~~2014 and ~~2012~~,2013, respectively.

Construction expenditures included in accounts payable is ~~$166~~$209 million and ~~$267~~$166 million at December 31, ~~2013~~2014 and ~~2012~~,2013, respectively.

Net property, plant, and equipment for the Registrant Subsidiaries (including property under capital lease and associated accumulated amortization) by company and functional category, as of December 31, ~~2013~~2014 and ~~2012~~,2013, is shown below:

Depreciation rates on average depreciable property for the Registrant Subsidiaries are shown below:

Non-utility property - at cost (less accumulated depreciation) for Entergy Gulf States Louisiana is reported net of accumulated depreciation of ~~$146~~$151 million and ~~$142~~$146 million as of December 31, ~~2013~~2014 and ~~2012~~,2013, respectively. Non-utility property - at cost (less accumulated depreciation) for Entergy Louisiana is reported net of accumulated depreciation of ~~$3.0~~$3.2 million and ~~$2.8~~$3 million as of December 31, ~~2013~~2014 and ~~2012~~,2013, respectively. Non-utility property - at cost (less accumulated depreciation) for Entergy Mississippi is reported net of accumulated depreciation of $2.2 million and $2.1 million as of December 31, 2014 and 2013, respectively. Non-utility property - at cost (less accumulated depreciation) for Entergy Texas is reported net of accumulated depreciation of ~~$10.4~~$10.4 million and ~~$10.0~~$10.4 million as of December 31, ~~2013~~2014 and ~~2012~~,2013, respectively.

As of December 31, ~~2013~~,2014, construction expenditures included in accounts payable are ~~$61.9~~$37.3 million for Entergy Arkansas, ~~$13.1~~$23.4 million for Entergy Gulf States Louisiana, ~~$31.1~~$48 million for Entergy Louisiana, ~~$2.8~~$7.8 million for Entergy Mississippi, ~~$1.7~~$0.9 million for Entergy New Orleans, ~~$10.9~~$24.1 million for Entergy Texas, and ~~$6.7~~$7.7 million for System Energy. As of December 31, ~~2012~~,2013, construction expenditures included in accounts payable are ~~$56.3~~$61.9 million for Entergy Arkansas, ~~$9.7~~$13.1 million for Entergy Gulf States Louisiana, ~~$110.4~~$31.1 million for Entergy Louisiana, ~~$4.8~~$2.8 million for Entergy Mississippi, ~~$1.9~~$1.7 million for Entergy New Orleans, ~~$8.6~~$10.9 million for Entergy Texas, and ~~$13.5~~$6.7 million for System Energy.

Certain Entergy subsidiaries jointly own electric generating facilities with affiliates or third parties. The investments and expenses associated with these generating stations are recorded by the Entergy subsidiaries to the extent of their respective undivided ownership interests. As of December 31, ~~2013~~,2014, the subsidiaries’ investment and accumulated depreciation in each of these generating stations were as follows:

Nuclear refueling outage costs are deferred during the outage and amortized over the estimated period to the next outage because these refueling outage expenses are incurred to prepare the units to operate for the next operating cycle without having to be taken off line.

AFUDC represents the approximate net composite interest cost of borrowed funds and a reasonable return on the equity funds used for construction by the Registrant Subsidiaries. AFUDC increases both the plant balance and earnings and is realized in cash through depreciation provisions included in the rates charged to customers.

Entergy Corporation and the majority of its subsidiaries file a United States consolidated federal income tax return. Each tax-paying entity records income taxes as if it were a separate taxpayer and consolidating adjustments are allocated to the tax filing entities in accordance with Entergy’s intercompany income tax allocation agreement. Deferred income taxes are recorded for ~~all~~ temporary differences between the book and tax basis of assets and liabilities, and for certain losses and credits available for carryforward.

Deferred tax assets are reduced by a valuation allowance when, in the opinion of management, it is more likely than not that some portion of the deferred tax assets will not be realized. Deferred tax assets and liabilities are adjusted for the effects of changes in tax laws and rates in the period in which the tax or rate was enacted.

~~Investment~~The benefits of investment tax credits are deferred and amortized ~~based upon~~over the average useful life of the related property, as a reduction of income tax expense, for such credits associated with regulated operations in accordance with ratemaking treatment.

The following table presents Entergy’s basic and diluted earnings per share calculation included on the consolidated statements of income:

The calculation of diluted earnings per share excluded ~~8,866,542~~5,743,013 options outstanding at December 31, ~~2013~~, ~~7,164,319~~2014, 8,866,542 options outstanding at December 31, ~~2012~~,2013, and ~~5,712,604~~7,164,319 options outstanding at December 31, ~~2011~~2012 that

Entergy grants stock options, restricted stock, performance units, and restricted liability awards to key employees of the Entergy subsidiaries under its Equity Ownership Plans, which are shareholder-approved stock-based compensation plans. These plans are described more fully in Note 12 to the financial statements. The cost of the stock-based compensation is charged to income over the vesting period. Awards under Entergy’s plans generally vest over 3 years.

Entergy’s Utility operating companies and System Energy are rate-regulated enterprises whose rates meet three criteria specified in accounting standards. The Utility operating companies and System Energy have rates that (i) are approved by a body (its regulator) empowered to set rates that bind customers; (ii) are cost-based; and (iii) can be charged to and collected from customers. These criteria may also be applied to separable portions of a utility’s business, such as the generation or transmission functions, or to specific classes of customers. Because the Utility operating companies and System Energy meet these criteria, each of them capitalizes costs that would otherwise be charged to expense if the rate actions of its regulator make it probable that those costs will be recovered in future revenue. Such capitalized costs are reflected as regulatory assets in the accompanying financial statements. When an enterprise concludes that recovery of a regulatory asset is no longer probable, the regulatory asset must be removed from the entity’s balance sheet.

An enterprise that ceases to meet the three criteria for all or part of its operations should report that event in its financial statements. In general, the enterprise no longer meeting the criteria should eliminate from its balance sheet all regulatory assets and liabilities related to the applicable operations. Additionally, if it is determined that a regulated enterprise is no longer recovering all of its costs, it is possible that an impairment may exist that could require further write-offs of plant assets.

Entergy Gulf States Louisiana does not apply regulatory accounting standards to the Louisiana retail deregulated portion of River Bend, the 30% interest in River Bend formerly owned by Cajun, and its steam business, ~~where~~unless specific cost recovery is ~~not~~ provided for in tariff rates. The Louisiana retail deregulated portion of River Bend is operated under a deregulated asset plan representing a portion (approximately 15%) of River Bend plant costs, generation, revenues, and expenses established under a 1992 LPSC order. The plan allows Entergy Gulf States Louisiana to sell the electricity from the deregulated assets to Louisiana retail customers at 4.6 cents per kWh or off-system at higher prices, with certain provisions for sharing incremental revenue above 4.6 cents per kWh between customers and shareholders.

Accounting standards for income taxes provide that a regulatory asset or liability be recorded if it is probable that the currently determinable future increase or decrease in regulatory income tax expense will be recovered from or reimbursed to customers through future rates. The primary source of ~~Entergy's~~Entergy’s regulatory asset for income taxes is related to the ratemaking treatment of the tax effects of book depreciation for the equity component of AFUDC ~~equity~~ that has been capitalized to property, plant, and equipment but for which there is no corresponding tax basis. ~~AFUDC equity~~Equity-AFUDC is a component of property, plant, and equipment that is included in rate base when the plant is placed in service.

Entergy considers all unrestricted highly liquid debt instruments with an original ~~or remaining~~ maturity of three months or less at date of purchase to be cash equivalents.

The allowance for doubtful accounts reflects Entergy’s best estimate of losses on the accounts receivable balances. The allowance is based on accounts receivable agings, historical experience, and other currently available evidence. Utility operating company customer accounts receivable are written off consistent with approved regulatory requirements.

Entergy records decommissioning trust funds on the balance sheet at their fair value. Because of the ability of the Registrant Subsidiaries to recover decommissioning costs in rates and in accordance with the regulatory treatment for decommissioning trust funds, the Registrant Subsidiaries record an offsetting amount in other regulatory liabilities/assets tofor the unrealized gains/(losses) on investment securities. For the ~~portion of~~30% interest in River Bend ~~that is not rate-regulated,~~formerly owned by Cajun, Entergy Gulf States Louisiana has recorded an offsetting amount in other deferred credits tofor the unrealized gains/(losses). Decommissioning trust funds for Pilgrim, Indian Point 2, Vermont Yankee, and Palisades do not meet the criteria for regulatory accounting treatment. Accordingly, unrealized gains recorded on the assets in these trust funds are recognized in the accumulated other comprehensive income component of equity because these assets are classified as available for sale. Unrealized losses (where cost exceeds fair market value) on the assets in these trust funds are also recorded in the accumulated other comprehensive income component of equity unless the unrealized loss is other than temporary and therefore recorded in earnings. 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). The assessment of whether an investment in an equity security has suffered an other-than-temporary impairment is 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. See Note 17 to the financial statements for details on the decommissioning trust funds.

Entergy owns investments that are accounted for under the equity method of accounting because Entergy’s ownership level results in significant influence, but not control, over the investee and its operations. Entergy records its share of the investee's comprehensive earnings and losses in income and as an increase or ~~losses of the investee based on the change during the period in the estimated liquidation value of~~decrease to the investment ~~assuming that~~account. Any cash distributions are charged against the investee’s assets were to be liquidated at book value. In accordance with this method, earnings are allocated to owners or members based on what each partner would receive from its capital account if, hypothetically, liquidation were to occur at the balance sheet date and amounts distributed were based on recorded book values.investment account. Entergy discontinues the recognition of losses on equity investments when its share of losses equals or exceeds its carrying amount for an investee plus any advances made or commitments to provide additional financial support. See Note 14 to the financial statements for additional information regarding Entergy’s equity method investments.

The accounting standards for derivative instruments and hedging activities require that all derivatives be recognized at fair value on the balance sheet, either as assets or liabilities, unless they meet various exceptions including the normal purchase, normal sales criteria. The changes in the fair value of recognized derivatives are recorded each period in current earnings or other comprehensive income, depending on whether a derivative is designated as part of a hedge transaction and the type of hedge transaction. Due to regulatory treatment, an offsetting regulatory asset or liability is recorded for changes in fair value of recognized derivatives for the Registrant Subsidiaries.

Contracts for commodities that will be physically delivered in quantities expected to be used or sold in the ordinary course of business, including certain purchases and sales of power and fuel, meet the normal purchase, normal sales criteria and are not recognized on the balance sheet. Revenues and expenses from these contracts are reported on a gross basis in the appropriate revenue and expense categories as the commodities are received or delivered.

For other contracts for commodities in which Entergy is hedging the variability of cash flows related to a variable-rate asset, liability, or forecasted transactions that qualify as cash flow hedges, the changes in the fair value of such derivative instruments are reported in other comprehensive income. To qualify for hedge accounting, the relationship between the hedging instrument and the hedged item must be documented to include the risk management objective and strategy and, at inception and on an ongoing basis, the effectiveness of the hedge in offsetting the changes in the cash flows of the item being hedged. Gains or losses accumulated in other comprehensive income are reclassified to earnings in the periods when the underlying transactions actually occur. The ineffective portions of all hedges are recognized in current-period earnings. Changes in the fair value of derivative instruments that are not designated as cash flow hedges are recorded in current-period earnings on a mark-to-market basis.

Entergy has determined that contracts to purchase uranium do not meet the definition of a derivative under the accounting standards for derivative instruments because they do not provide for net settlement and the uranium markets are not sufficiently liquid to conclude that forward contracts are readily convertible to cash. If the uranium markets do become sufficiently liquid in the future and Entergy begins to account for uranium purchase contracts as derivative instruments, the fair value of these contracts would be accounted for consistent with Entergy’s other derivative instruments.

The estimated fair values of Entergy’s financial instruments and derivatives are determined using bid prices, market quotes, and financial modeling. Considerable judgment is required in developing the estimates of fair value. Therefore, estimates are not necessarily indicative of the amounts that Entergy could realize in a current market exchange. Gains or losses realized on financial instruments held by regulated businesses may be reflected in future rates and therefore do not accrue to the benefit or detriment of stockholders. Entergy considers the carrying amounts of most financial instruments classified as current assets and liabilities to be a reasonable estimate of their fair value because of the short maturity of these instruments. See Note 16 to the financial statements for further discussion of fair value.

Entergy periodically reviews long-lived assets held in all of its business segments whenever events or changes in circumstances indicate that recoverability of these assets is uncertain. Generally, the determination of recoverability is based on the undiscounted net cash flows expected to result from such operations and assets. Projected net cash flows depend on the future operating costs associated with the assets, the efficiency and availability of the assets and generating units, and the future market and price for energy over the remaining life of the assets.

Two nuclear power plants in the Entergy Wholesale Commodities business segment (Indian Point 2 and Indian Point 3) have ~~applications~~an application pending for renewed NRC licenses. Various parties have expressed opposition to renewal of the licenses. Under federal law, nuclear power plants may continue to operate beyond their original license expiration dates while their timely filed renewal applications are pending NRC approval. On September 28, 2013, Indian Point 2 reached the expiration date of its original NRC operating license and entered into the period of extended operation under the timely renewal rule. In December 2015, Indian Point 3 will reach the expiration date of its original NRC operations license and, similarly, will enter the period of extended operation under the timely renewal rule if its license is not renewed before then. If the NRC does not renew the operating license for either of these plants, the plant’s operating life could be shortened, reducing its projected net cash flows and potentially impairing its value as an asset.

In March 2011 the NRC renewed Vermont Yankee’s operating license for an additional 20 ~~years~~.years. The renewed operating license expires in March ~~2032~~.2032. Vermont Yankee ~~also is operating~~operated under a Certificate of Public Good from the State of Vermont that was scheduled to expire in March 2012, but ~~has~~had an ~~application~~amended petition pending before the Vermont Public Service Board (VPSB) for a renewed Certificate of Public ~~Good. In April 2011, Entergy Nuclear Vermont~~

In June 2013 the VPSB completed hearings on Entergy’s amended petition for a Certificate of Public Good to continuing operating Vermont Yankee. In August 2013, Entergy announced that it planned to close Vermont Yankee at the end of 2014 and that same day filed a second amended petition seeking authorization to operate the plant only until that date. In December 2013, Entergy and Vermont entered into a settlement agreement, with an accompanying memorandum of understanding that was filed with the VPSB, under which Vermont agreed to support Entergy’s request to operate Vermont Yankee until the end of 2014. The settlement agreement ~~provides~~provided for Entergy to make ~~$10~~$10 million in economic transition payments, $5 million in clean energy development support, and a transitional $5 million payment to Vermont. The settlement agreement also provided for Entergy ~~will also~~to set aside a new $25 million fund to ensure the Vermont Yankee site is restored after decommissioning. These terms ~~are~~were contingent upon the ~~VPSB’s issuance~~VPSB issuing by March 31, 2014 of a Certificate of Public Good authorizing Vermont Yankee’s operation through 2014, and otherwise conforming to the terms of the settlement agreement. The settlement agreement also ~~provides~~provided for the dismissal or discontinuation of other litigation between Entergy and ~~Vermont; in~~Vermont. On March 28, 2014, the ~~case~~VPSB approved the memorandum of ~~Entergy’s appeal of the VPSB’s March~~understanding and ~~November 2012 orders, such dismissal is contingent upon the VPSB’s issuance of such~~issued a Certificate of Public ~~Good. The~~Good authorizing Vermont Yankee to operate until December 31, 2014. In May 2014 the VPSB ~~has scheduled additional proceedings~~denied a motion that had been filed by one of the intervenors to amend its approval order. Pursuant to its commitment in the settlement agreement, Entergy Vermont Yankee provided to the Vermont parties in October 2014, a site assessment study of the costs and ~~further hearings on~~tasks of radiological decommissioning, spent nuclear fuel management, and site restoration of Vermont Yankee. Entergy Vermont Yankee also filed its Post-Shutdown Decommissioning Activities Report (PSDAR) for Vermont Yankee with the ~~memorandum of understanding.~~NRC in December 2014.

Because of the uncertainty regarding the continued operation of Vermont Yankee, Entergy tested the recoverability of the plant and related assets in each quarter since the first quarter ~~2010.~~2010 after a bill to approve the continued operation of Vermont Yankee was defeated in the Vermont legislature. Vermont law at that time required legislative approval of Vermont Yankee’s continued operation although that law was later invalidated by the U.S. federal courts as preempted by the Atomic Energy Act. The determination of recoverability is based on the probability-weighted undiscounted net cash flows expected to be generated by the plant

The estimate of fair value was based on the price that Entergy would expect to receive in a hypothetical sale of the Vermont Yankee plant and related assets to a market participant on March 31, 2012. In order to determine this price, Entergy used significant observable inputs, including quoted forward power and gas prices, where available. Significant unobservable inputs, such as projected long-term pre-tax operating margins (cash basis), and estimated weighted average costs of capital were also used in the estimation of fair value. In addition, Entergy made certain assumptions regarding future tax deductions associated with the plant and related assets. Based on the use of significant unobservable inputs, the fair value measurement for the entirety of the asset group, and for each type of asset within the asset group, is classified as Level 3 in the fair value hierarchy discussed in Note 16 to the financial statements.

The following table sets forth a description of significant unobservable inputs used in the valuation of the Vermont Yankee plant and related assets as of March 31, 2012:

On August 27, 2013, Entergy announced its plan to close and decommission Vermont ~~Yankee. Vermont~~ Yankee ~~is expected to cease power production in~~at the ~~fourth quarter 2014 after~~end of its ~~current~~ fuel ~~cycle.~~cycle at the end of 2014. This decision was approved by the Board in August 2013, although the exact date of shutdown was not determined. The decision to shut down the plant was primarily due to sustained low natural gas and wholesale energy prices, the high cost structure of the plant, and lack of a market structure that adequately compensates merchant nuclear plants for their environmental and fuel diversity benefits in the region in which the plant operates.

As a result of the decision to shut down the plant, Entergy recognized non-cash impairment and other related charges of ~~$291.5~~$291.5 million ($ ($183.7 million after-tax) during the third quarter 2013 to write down the carrying value of Vermont Yankee and related assets to their fair values. Entergy performed a fair value analysis based on the income approach, a discounted cash flow method, to determine the amount of impairment. The estimated fair value of the plant and related assets was ~~$62~~$62 million,, while the carrying value was ~~$349 million~~.$349 million. The carrying value of ~~$349~~$349 million ~~reflects~~ reflected the effect of a ~~$58~~$58 million increase in Vermont Yankee’s estimated decommissioning cost liability and the related asset retirement cost asset. The increase in the estimated decommissioning cost liability resulted from the change in expectation regarding the timing of decommissioning cash flows due to the decision to cease operations. Impairment and other related charges ~~are~~were recorded as a separate line item in Entergy’s consolidated statements of income for 2013 and this impairment charge is included within the results of the Entergy Wholesale Commodities segment.

The estimate of fair value was based on the price that Entergy would expect to receive in a hypothetical sale of the Vermont Yankee plant and related assets to a market participant. In order to determine this price, Entergy used

The following table sets forth a description of significant unobservable inputs used in the valuation of the Vermont Yankee plant and related assets as of July 31, 2013:

As a result of the settlement agreement entered into by Entergy and Vermont regarding the remaining operation and decommissioning of Vermont Yankee discussed above, Entergy reassessed its assumptions regarding the timing of decommissioning cash flows for Vermont Yankee. The reassessment resulted in a $27.2 million increase in the~~$27.2~~

In addition to the $101.6 million impairment charge in September 2014 and depreciation ofrecorded on the remaining plant balance ~~by the end of~~in 2014, Entergy ~~expects to record additional~~also recorded charges ~~through the end~~ of ~~2014 totaling approximately~~ ~~$50~~$45.8 million to ~~$55 million~~ related to severance and employee retention costs in 2014 relating to the shutdown of Vermont Yankee.

Vermont Yankee ceased operation in December 2014. In January 2015, Vermont Yankee completed the defueling of the reactor and submitted the certification of permanent cessation of operations and permanent removal of fuel from the reactor vessel to the NRC.

The River Bend AFUDC gross-up is a regulatory asset that represents the incremental difference imputed by the LPSC between the AFUDC actually recorded by Entergy Gulf States Louisiana on a net-of-tax basis during the construction of River Bend and what the AFUDC would have been on a pre-tax basis. The imputed amount was only calculated on that portion of River Bend that the LPSC allowed in rate base and is being amortized through August 2025.

The premiums and costs associated with reacquired debt of Entergy’s Utility operating companies and System Energy (except that portion allocable to the deregulated operations of Entergy Gulf States Louisiana) are included in regulatory assets and are being amortized over the life of the related new issuances, or over the life of the original debt issuance if the debt is not refinanced, in accordance with ratemaking treatment.

Governmental authorities assess taxes that are both imposed on and concurrent with a specific revenue-producing transaction between a seller and a customer, including, but not limited to, sales, use, value added, and some excise taxes. Entergy presents these taxes on a net basis, excluding them from revenues, unless required to report them differently by a regulatory authority.

Accounting standards regarding non-controlling interests and the classification and measurement of redeemable securities require the classification of preferred securities between liabilities and shareholders’ equity on the balance sheet if the holders of those securities have protective rights that allow them to gain control of the board of directors in certain circumstances. These rights would have the effect of giving the holders the ability to potentially redeem their securities, even if the likelihood of occurrence of these circumstances is considered remote. The Entergy Arkansas, Entergy Mississippi, and Entergy New Orleans articles of incorporation provide, generally, that the holders of each company’s preferred securities may elect a majority of the respective company’s board of directors if dividends are not paid for a year, until such time as the dividends in arrears are paid. Therefore, Entergy Arkansas, Entergy Mississippi, and Entergy New Orleans present their preferred securities outstanding between liabilities and shareholders’ equity on the balance sheet. Entergy Gulf States Louisiana and Entergy Louisiana, both organized as limited liability companies, have outstanding preferred securities with similar protective rights with respect to unpaid dividends, but provide for

The outstanding preferred securities of Entergy Arkansas, Entergy Mississippi, Entergy New Orleans, and Entergy Finance Holding (an Entergy Wholesale Commodities subsidiary), whose preferred holders also have protective rights, are similarly presented between liabilities and equity on Entergy’s consolidated balance sheets and the outstanding preferred securities of Entergy Gulf States Louisiana and Entergy Louisiana are presented within total equity in Entergy’s consolidated balance sheets. The preferred dividends or distributions paid by all subsidiaries are reflected for all periods presented outside of consolidated net income.

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.~~projects. Final pronouncements that result from these projects could have a material effect on Entergy’s future net income, financial position, or cash flows.

In April 2014 the FASB issued ASU No. 2014-08, “Presentation of Financial Statements (Topic 205) and Property Plant, and Equipment (Topic 360): Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity” which changes the requirements for reporting discontinued operations. The ASU states that a disposal of a component of an entity or a group of components of an entity is required to be reported in discontinued operations if the disposal represents a strategic shift that has or will have a major effect on an entity’s operations and financial results when the component of an entity or group of components of an entity meets the criteria to be classified as held for sale, is disposed of by sale, or is disposed of other than by sale. The amendments in this ASU also require additional disclosures about discontinued operations. ASU 2014-08 is effective for Entergy for the first quarter 2015. Entergy does not currently expect ASU 2014-08 to affect materially its results of operations, financial position, or cash flows.

In May 2014 the FASB issued ASU No. 2014-09, “Revenue from Contracts with Customers (Topic 606).” The ASU’s core principle is that “an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services.” The ASU details a five-step model that should be followed to achieve the core principle. ASU 2014-09 is effective for Entergy for the first quarter 2017. Entergy does not expect ASU 2014-09 to affect materially its results of operations, financial position, or cash flows.

In November 2014 the FASB issued ASU No. 2014-16, “Derivatives and Hedging (Topic 815): Determining Whether the Host Contract in a Hybrid Financial Instrument Issued in the Form of a Share Is More Akin to Debt or to Equity.” The ASU states that for hybrid financial instruments issued in the form of a share, an entity should determine the nature of the host contract by considering all stated and implied substantive terms and features of the hybrid financial instrument, weighing each term and feature on the basis of relevant facts and circumstances. ASU 2014-16 is effective for Entergy for the first quarter 2016. Entergy does not expect ASU 2014-16 to affect materially its results of operations, financial position, or cash flows.

~~Other Regulatory Assets~~

Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas are allowed to recover fuel and purchased power costs through fuel mechanisms included in electric and gas rates that are recorded as fuel cost recovery revenues. The difference between revenues collected and the current fuel and purchased power costs is generally recorded as “Deferred fuel costs” on the Utility operating companies’ financial statements. The table below shows the amount of deferred fuel costs as of December 31, ~~2013~~2014 and ~~2012~~2013 that Entergy expects to recover (or return to customers) through fuel mechanisms, subject to subsequent regulatory review.

Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas are allowed to recover fuel and purchased power costs through fuel mechanisms included in electric and gas rates that are recorded as fuel cost recovery revenues. The difference between revenues collected and the current fuel and purchased power costs is generally recorded as “Deferred fuel costs” on the Utility operating companies’ financial statements. The table below shows the amount of deferred fuel costs as of December 31, 2014 and 2013 that Entergy expects to recover (or return to customers) through fuel mechanisms, subject to subsequent regulatory review.

The APSC approved a production cost allocation rider for recovery from customers of the retail portion of the costs allocated to Entergy Arkansas as a result of the System Agreement proceedings, which are discussed in the “System Agreement Cost Equalization Proceedings” section below. These costs cause an increase in Entergy Arkansas’s deferred fuel cost balance because Entergy Arkansas pays the costs over seven months but collects them from customers over twelve months.

In May 2014, Entergy Arkansas filed its annual redetermination of the production cost allocation rider to recover the $3 million unrecovered retail balance as of December 31, 2013 and the $67.8 million System Agreement bandwidth remedy payment made in May 2014 as a result of the compliance filing pursuant to the FERC’s February 2014 orders related to the bandwidth payments/receipts for the June - December 2005 period. In June 2014 the APSC suspended the annual redetermination of the production cost allocation rider and scheduled a hearing in September 2014. Upon a joint motion of the parties, the APSC canceled the September 2014 hearing and in January 2015 the APSC issued an order approving Entergy Arkansas’s request for recovery of the $3 million under-recovered amount based on the true-up of the production cost allocation rider and the $67.8 million May 2014 System Agreement bandwidth remedy payment subject to refund with interest, with recovery of these payments concluding with the last billing cycle in December 2015. The APSC also found that Entergy Arkansas is entitled to carrying charges pursuant to the current terms of the production cost allocation rider. Entergy Arkansas made its compliance filing pursuant to the order in January 2015 and the APSC issued its approval order, also in January 2015. The redetermined rate went into effect the first billing cycle of February 2015.

Entergy Arkansas’s retail rates include an energy cost recovery rider to recover fuel and purchased energy costs in monthly customer bills. The rider utilizes the prior calendar-year energy costs and projected energy sales for the twelve-month period commencing on April 1 of each year to develop an energy cost rate, which is redetermined annually and includes a true-up adjustment reflecting the over- or under-recovery, including carrying charges, of the energy costs for the prior calendar year. The energy cost recovery rider tariff also allows an interim rate request depending upon the level of over- or under-recovery of fuel and purchased energy costs.

In October 2005 the APSC initiated an investigation into Entergy Arkansas’s interim energy cost recovery rate. The investigation focused on Entergy Arkansas’s 1) gas contracting, portfolio, and hedging practices; 2) wholesale purchases during the period; 3) management of the coal inventory at its coal generation plants; and 4) response to the contractual failure of the railroads to provide coal deliveries. In March 2006 the APSC extended its investigation to cover the costs included in Entergy Arkansas’s March 2006 annual energy cost rate filing, and a hearing was held in the APSC investigation in October 2006.

In January 2007 the APSC issued an order in its review of the energy cost rate. The APSC found that Entergy Arkansas failed to maintain an adequate coal inventory level going into the summer of 2005 and that Entergy Arkansas should be responsible for any incremental energy costs that resulted from two outages caused by employee and contractor error. The coal plant generation curtailments were caused by railroad delivery problems and Entergy Arkansas has since resolved litigation with the railroad regarding the delivery problems. The APSC staff was directed to perform an analysis with Entergy Arkansas’s assistance to determine the additional fuel and purchased energy costs associated with these findings and file the analysis within sixty days of the order. After a final determination of the costs is made by the APSC, Entergy Arkansas will be directed to refund that amount with interest to its customers as a credit on the energy cost recovery rider. Entergy Arkansas requested rehearing of the order.

In February 2010 the APSC denied Entergy Arkansas’s request for rehearing, and held a hearing in September 2010 to determine the amount of damages, if any, that should be assessed against Entergy Arkansas. A decision is pending. Entergy Arkansas expects the amount of damages, if any, to have an immaterial effect on its results of operations, financial position, or cash flows.

The APSC also established a separate docket to consider the resolved railroad litigation, and in February 2010 it established a procedural schedule that concluded with testimony through September 2010. The testimony has been filed, and the APSC will decide the case based on the record in the proceeding.

In January 2014, Entergy Arkansas filed a motion with the APSC relating to its redetermination of its energy cost rate to be filed in March 2014. In that motion, Entergy Arkansas requested that the APSC authorize Entergy Arkansas to exclude $65.9 million of deferred fuel and purchased energy costs incurred in 2013 from the redetermination of its 2014 energy cost rate. The $65.9 million is an estimate of the incremental fuel and replacement energy costs that Entergy Arkansas incurred as a result of the ANO stator incident. Entergy Arkansas requested that the APSC authorize Entergy Arkansas to retain that amount in its deferred fuel balance, with recovery to be reviewed in a later period after more information is available regarding various claims associated with the ANO stator incident. The APSC approved Entergy Arkansas’s request in February 2014. See the “ANO Damage, Outage, and NRC Reviews” section in Note 8 to the financial statements for further discussion of the ANO stator incident.

Entergy Gulf States Louisiana and Entergy Louisiana recover electric fuel and purchased power costs for the billing month based upon the level of such costs incurred two months prior to the billing month. Entergy Gulf States Louisiana’s purchased gas adjustments include estimates for the billing month adjusted by a surcharge or credit that arises from an annual reconciliation of fuel costs incurred with fuel cost revenues billed to customers, including carrying charges.

In April 2010 the LPSC authorized its staff to initiate an audit of Entergy Louisiana’s fuel adjustment clause filings. The audit includes a review of the reasonableness of charges flowed through the fuel adjustment clause by Entergy Louisiana for the period from 2005 through 2009. The LPSC Staff issued its audit report in January 2013. The LPSC staff recommended that Entergy Louisiana refund approximately $1.9 million, plus interest, to customers and realign the recovery of approximately $1 million from Entergy Louisiana’s fuel adjustment clause to base rates. The recommended refund was made by Entergy Louisiana in May 2013 in the form of a credit to customers through its fuel adjustment clause filing. Two parties intervened in the proceeding. A procedural schedule was established for the identification of issues by the intervenors and for Entergy Louisiana to submit comments regarding the LPSC Staff report and any issues raised by intervenors. One intervenor is seeking further proceedings regarding certain issues it raised in its comments on the LPSC Staff report. Entergy Louisiana has filed responses to both the LPSC Staff report and the issues raised by the intervenor. As required by the procedural schedule, a joint status report was submitted in October 2013 by the parties. A status conference was held in December 2013. Discovery is in progress, but a procedural schedule has not been established.

In December 2011 the LPSC authorized its staff to initiate another proceeding to audit the fuel adjustment clause filings of Entergy Gulf States Louisiana and its affiliates. The audit includes a review of the reasonableness of charges flowed by Entergy Gulf States Louisiana through its fuel adjustment clause for the period 2005 through 2009. Discovery is in progress, but a procedural schedule has not been established.

In July 2014 the LPSC authorized its staff to initiate an audit of Entergy Gulf States Louisiana’s fuel adjustment clause filings. The audit includes a review of the reasonableness of charges flowed by Entergy Gulf States Louisiana through its fuel adjustment clause for the period from 2010 through 2013. Discovery has yet to commence.

In July 2014 the LPSC authorized its staff to initiate an audit of Entergy Louisiana’s fuel adjustment clause filings. The audit includes a review of the reasonableness of charges flowed by Entergy Louisiana through its fuel adjustment clause for the period from 2010 through 2013. Discovery has yet to commence.

Entergy Mississippi’s rate schedules include an energy cost recovery rider that ~~effective January 1, 2013,~~ is adjusted annually to reflect accumulated over- or under-recoveries. Entergy Mississippi’s fuel cost recoveries are subject to annual audits conducted pursuant to the authority of the MPSC.

Entergy Mississippi had a deferred fuel balance of $60.4 million as of March 31, 2014. In May 2014, Entergy Mississippi filed for an interim adjustment under its energy cost recovery rider. The interim adjustment proposed a net energy cost factor designed to collect over a six-month period the under-recovered deferred fuel balance as of March 31, 2014 and also reflected a natural gas price of $4.50 per MMBtu. In May 2014, Entergy Mississippi and the Public Utilities Staff entered into a joint stipulation in which Entergy Mississippi agreed to a revised net energy cost factor that reflected the proposed interim adjustment with a reduction in costs recovered through the energy cost recovery rider associated with the suspension of the DOE nuclear waste storage fee. In June 2014 the MPSC approved the joint stipulation and allowed Entergy Mississippi’s interim adjustment. In November 2014, Entergy Mississippi filed its annual redetermination of the annual factor to be applied under the energy cost recovery rider. Due to lower gas prices and a lower deferred fuel balance, the redetermined annual factor was a decrease from the revised interim net energy cost factor. In January 2015 the MPSC approved the redetermined annual factor effective January 30, 2015.

The Mississippi attorney general filed a complaint in state court in December 2008 against Entergy Corporation, Entergy Mississippi, Entergy Services, and Entergy Power alleging, among other things, violations of Mississippi statutes, fraud, and breach of good faith and fair dealing, and requesting an accounting and restitution. The complaint is wide ranging and relates to tariffs and procedures under which Entergy Mississippi purchases power not generated in Mississippi to meet electricity demand. Entergy believes the complaint is unfounded. In December 2008 the

The defendant Entergy companies answered the complaint and filed a counterclaim for relief based upon the Mississippi Public Utilities Act and the Federal Power Act. In May 2009 the defendant Entergy companies filed a motion for judgment on the pleadings asserting grounds of federal preemption, the exclusive jurisdiction of the MPSC, and factual errors in the attorney general’s complaint. In September 2012 the District Court heard oral argument on Entergy’s motion for judgment on the pleadings. The District Court’s ruling on the motion for judgment on the pleadings is pending.

In January 2014 the U.S. Supreme Court issued a decision in which it held that cases brought by attorneys general as the sole plaintiff to enforce state laws were not subject to the federal law that allowed federal courts to hear those cases as “mass action” lawsuits. One day later the Attorney General renewed its motion to remand the Entergy case back to state court, citing the U.S. Supreme Court’s decision. The defendant Entergy companies have responded to that motion and the District Court held oral argument on the motion to remand in February 2014. Entergy also has asserted federal question jurisdiction as a basis for the district court having jurisdiction and also has pending the motion for judgment on the pleadings.

Entergy New Orleans’s electric rate schedules include a fuel adjustment tariff designed to reflect no more than targeted fuel and purchased power costs, adjusted by a surcharge or credit for deferred fuel expense arising from the monthly reconciliation of actual fuel and purchased power costs incurred with fuel cost revenues billed to customers, including carrying charges.

Entergy New Orleans’s gas rate schedules include a purchased gas adjustment to reflect estimated gas costs for the billing month, adjusted by a surcharge or credit similar to that included in the electric fuel adjustment clause, including carrying charges.

Entergy Texas’s rate schedules include a fixed fuel factor to recover fuel and purchased power costs, including interest, not recovered in base rates. Semi-annual revisions of the fixed fuel factor are made in March and September

In December 2010, Entergy Texas filed with the PUCT a request to refund fuel cost recovery over-collections through October 2010. Pursuant to a stipulation among the parties that was approved by the PUCT in March 2011, Entergy Texas refunded over-collections through November 2010 of approximately ~~$73 million, including interest through the refund period. The refund was made for most customers over a three-month period that began with the February 2011 billing cycle.~~

In October 2012, Entergy Texas filed with the PUCT a request to refund approximately ~~$78~~$78 million,, including interest, of fuel cost recovery over-collections through September 2012. Entergy Texas requested that the refund be implemented over a six-month period effective with the January 2013 billing month. Entergy Texas and the parties to the proceeding reached an agreement that Entergy Texas would refund ~~$84~~$84 million,, including interest and additional over-recoveries through October 2012, to most customers over a three-month period beginning January 2013. The PUCT approved the stipulation in January 2013. Entergy Texas completed this refund to customers in March 2013.

In July 2012, Entergy Texas filed with the PUCT an application to credit its customers approximately ~~$37.5~~$37.5 million,, including interest, resulting from the FERC’s October 2011 order in the System Agreement rough production cost equalization proceeding which is discussed below in “System Agreement Cost Equalization Proceedings.” In September 2012 the parties submitted a stipulation resolving the proceeding. The stipulation provided that most Entergy Texas customers would be credited over a four-month period beginning October 2012. The credits were initiated with the October 2012 billing month on an interim basis, and the PUCT subsequently approved the stipulation, also in October 2012.

In August 2014, Entergy Texas filed an application seeking PUCT approval to implement an interim fuel refund of approximately $24.6 million for over-collected fuel costs incurred during the months of November 2012 through April 2014. This refund resulted from (i) applying $48.6 million in bandwidth remedy payments that Entergy Texas received in May 2014 related to the June - December 2005 period to Entergy Texas’s $8.7 million under-recovered fuel balance as of April 30, 2014 and (ii) netting that fuel balance against the $15.3 million bandwidth remedy payment that Entergy Texas made related to calendar year 2013 production costs. Also in August 2014, Entergy Texas filed an unopposed motion for interim rates to implement these refunds for most customers over a two-month period commencing with September 2014. The PUCT issued its order approving the interim relief in August 2014 and Entergy Texas completed the refunds in October 2014. Parties intervened in this matter. All parties agreed that this case should be bifurcated such that the interim refunds would become final in a separate docket. The current docket would remain in place to potentially address additional rough production cost equalization-related matters that are not part of the interim refunds discussed above. In January 2015, Entergy Texas filed a request for this severance and final approval of the interim refund. Both applications are pending.

At the ~~PUCT's~~PUCT’s April 2013 open meeting, the PUCT Commissioners discussed their view that a purchased power capacity rider was good public policy. The PUCT issued an order in May 2013 adopting the rule allowing for a purchased power capacity rider, subject to an offsetting adjustment for load growth. The rule, as adopted, also includes a process for obtaining pre-approval by the PUCT of purchased power agreements. Entergy Texas has not exercised the option to recover its capacity costs under the new rider mechanism, ~~due to the pending base rate case filed with the PUCT in September 2013,~~ but will continue to evaluate the benefits of utilizing the new rider to recover future capacity costs.

In March 2013, Entergy Arkansas filed with the APSC for a general change in rates, charges, and tariffs. The filing assumed Entergy ~~Arkansas's~~Arkansas’s transition to MISO in December 2013, and requested a rate increase of ~~$174~~$174 million,, including ~~$49~~$49 million of revenue being transferred from collection in riders to base rates. The filing also proposed a new transmission rider and a capacity cost recovery rider. The filing requested a 10.4% return on common equity. In September 2013, Entergy Arkansas filed testimony reflecting an updated rate increase request of ~~$145~~$145 million,, with

On January 30, 2015, Entergy Arkansas filed with the APSC a notice of intent to file a rate case within 60 to 90 days.

~~In May 2011, Entergy Gulf States Louisiana made a special formula rate plan rate implementation filing with the LPSC that implemented effective with the May 2011 billing cycle a~~ ~~$5.1 million~~ rate decrease to reflect adjustments in accordance with a previous LPSC order relating to the acquisition of Unit 2 of the Acadia Energy Center by Entergy Louisiana. As a result of the closing of the acquisition and termination of the pre-acquisition power purchase agreement with Acadia, Entergy Gulf States Louisiana’s allocation of capacity related to this unit ended, resulting in a reduction in the additional capacity revenue requirement.

In connection with its decision to extend the formula rate plan to the 2011 test year, the LPSC required that a base rate case be filed by Entergy Gulf States Louisiana, and the required filing was made onin February ~~15,~~ 2013. The filing anticipated Entergy Gulf States ~~Louisiana's~~Louisiana’s integration into MISO. In the filing Entergy Gulf States Louisiana requested, among other relief:

Following a hearing before an ALJ and the ~~ALJ's~~ALJ’s issuance of a Report of Proceedings, in December 2013 the LPSC approved an unopposed settlement of the proceeding. Major terms of the settlement include approval of a ~~three-year~~three-year formula rate plan (effective for test years 2014-2016) modeled after the formula rate plan in effect for Entergy Gulf States Louisiana for 2011, including the following: (1) a midpoint return on equity of 9.95% plus or minus 80 basis points, with 60/60/40 sharing of earnings outside of the bandwidth; (2) recovery outside of the sharing mechanism for the non-fuel MISO-related costs, additional capacity revenue requirement, extraordinary items, such as the Ninemile 6 project, and certain special recovery items; (3) ~~three-year~~three-year amortization of costs to achieve savings associated with

Pursuant to the rate case settlement approved by the LPSC in December 2013, Entergy Gulf States Louisiana submitted a compliance filing in May 2014 reflecting the effects of the estimated MISO cost recovery mechanism revenue requirement and adjustment of the additional capacity mechanism. In November 2014, Entergy Gulf States Louisiana submitted an additional compliance filing updating the estimated MISO cost recovery mechanism for the most recent actual data. Based on this updated filing, a net increase of $5.8 million in formula rate plan revenue to be collected over nine months was implemented in December 2014. The compliance filings are subject to LPSC review in accordance with the review process set forth in Entergy Gulf States Louisiana’s formula rate plan.

In July 2014, Entergy Gulf States Louisiana and Entergy Louisiana filed an unopposed stipulation with the LPSC that estimated a first year revenue requirement associated with Ninemile 6 and provided a mechanism to update the revenue requirement as the in-service date approached, which was subsequently approved by the LPSC. In late December 2014, roughly contemporaneous with the unit's placement in service, a final updated estimated revenue requirement of $26.8 million for Entergy Gulf States Louisiana was filed. The December 2014 estimate forms the basis of rates implemented effective with the first billing cycle of January 2015.

~~In May 2011, Entergy Louisiana made a special formula rate plan rate implementation filing with the LPSC that implemented, effective with the May 2011 billing cycle, a~~ ~~$43.1 million~~ net rate increase to reflect adjustments in accordance with a previous LPSC order relating to the acquisition of Unit 2 of the Acadia Energy Center. The net rate increase represented the decrease in the additional capacity revenue requirement resulting from the termination of the power purchase agreement with Acadia and the increase in the revenue requirement resulting from the ownership of the Acadia facility. In August 2011, Entergy Louisiana made a filing to correct the May 2011 filing and decrease the rate by ~~$1.1 million~~.

With completion of the Waterford 3 replacement steam generator project, the LPSC is conducting a prudence review in connection with a filing made by Entergy Louisiana in April 2013 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 July 2014 the LPSC Staff filed testimony recommending potential project and replacement power cost disallowances of up to $71 million, citing a need for further explanation or documentation from Entergy Louisiana. An intervenor filed testimony recommending disallowance of $141 million of incremental project costs, claiming the steam generator fabricator was imprudent. Entergy Louisiana provided further documentation and explanation requested by the LPSC staff. An evidentiary hearing ~~is scheduled for November~~was held in December 2014. At the hearing the parties maintained the positions reflected in pre-filed testimony. A post-hearing briefing schedule has not been established. Entergy Louisiana believes that the replacement steam

In connection with its decision to extend the formula rate plan to the 2011 test year, the LPSC required that a base rate case be filed by Entergy Louisiana, and the required filing was made on February 15, 2013. The filing anticipated Entergy ~~Louisiana's~~Louisiana’s integration into MISO. In the filing Entergy Louisiana requested, among other relief:

Following a hearing before an ALJ and the ~~ALJ's~~ALJ’s issuance of a Report of Proceedings, in December 2013 the LPSC approved an unopposed settlement of the proceeding. The settlement provides for a ~~$10~~$10 million rate increase effective with the first billing cycle of December 2014. Major terms of the settlement include approval of a ~~three-year~~three-year formula rate plan (effective for test years 2014-2016) modeled after the formula rate plan in effect for Entergy Louisiana for 2011, including the following: (1) a midpoint return on equity of 9.95% plus or minus 80 basis points, with 60/60/40 sharing of earnings outside of the bandwidth; (2) recovery outside of the sharing mechanism for the non-fuel MISO-related costs, additional capacity revenue requirement, extraordinary items, such as the Ninemile 6 project, and certain special recovery items; (3) ~~three-year~~three-year amortization of costs to achieve savings associated with the human capital management ~~initiative,~~strategic imperative, with savings reflected as they are realized in subsequent years; (4) ~~eight-year~~eight-year amortization of costs incurred in connection with potential development of a new nuclear unit at River Bend, without carrying costs, beginning December 2014, provided, however, that amortization of these costs shall not result in a future rate increase; (5) recovery of non-fuel MISO-related costs and any changes to the additional capacity revenue requirement related to test year 2013 effective with the first billing cycle of December 2014; and (6) a cumulative ~~$30~~$30 million cap on cost of service increases over the ~~three-year~~three-year formula rate plan cycle, except for those items outside of the sharing mechanism. Existing depreciation rates will not change.

Pursuant to the rate case settlement approved by the LPSC in December 2013, Entergy Louisiana submitted a compliance filing in May 2014 reflecting the effects of the $10 million agreed-upon increase in formula rate plan revenue, the estimated MISO cost recovery mechanism revenue requirement, and the adjustment of the additional capacity mechanism. In November 2014, Entergy Louisiana submitted an additional compliance filing updating the estimated MISO cost recovery mechanism for the most recent actual data, as well as providing for a refund and prospective reduction in rates for the true-up of the estimated revenue requirement for the Waterford 3 replacement steam generator project. Based on this updated filing, a net increase of $41.6 million in formula rate plan revenue to be collected over nine months was implemented in December 2014. The compliance filings are subject to LPSC review in accordance with the review process set forth in Entergy Louisiana’s formula rate plan. Additionally, the adjustments of rates made related to the Waterford 3 replacement steam generator project included in the December 2014 compliance filing are subject to final true-up following completion of the LPSC’s determination regarding the prudence of the project.

In July 2014, Entergy Gulf States Louisiana and Entergy Louisiana filed an unopposed stipulation with the LPSC that estimated a first year revenue requirement associated with Ninemile 6 and provided a mechanism to update the revenue requirement as the in-service date approached, which was subsequently approved by the LPSC. In late December 2014, roughly contemporaneous with the unit's placement in service, a final updated estimated revenue requirement of $51.1 million for Entergy Louisiana was filed. The December 2014 estimate forms the basis of rates implemented effective with the first billing cycle of January 2015. Entergy Louisiana will submit project and cost information to the LPSC in mid-2015 to enable the LPSC to review the prudence of Entergy Louisiana’s management of the project.

In January ~~2014,~~2012, Entergy Gulf States Louisiana filed with the LPSC its gas rate stabilization plan for the test year ended September 30, ~~2013.~~2011. The filing showed an earned return on common equity of ~~5.47%~~10.48%, which ~~results in~~is within the earnings bandwidth of 10.5%, plus or minus fifty basis points. In April 2012 the LPSC Staff filed its findings, suggesting adjustments that produced an 11.54% earned return on common equity for the test year and a ~~$1.5~~$0.1 million rate ~~increase. The~~reduction. Entergy Gulf States Louisiana accepted the LPSC Staff’s recommendations, and the rate ~~increase, if approved, will be~~reduction was effective with the first billing cycle of ~~April 2014.~~

In January 2013, Entergy Gulf States Louisiana filed with the LPSC its gas rate stabilization plan for the test year ended September 30, 2012. The filing showed an earned return on common equity of 11.18%, which results in a ~~$43~~$43 thousand rate reduction. In March 2013 the LPSC Staff issued its proposed findings and recommended two adjustments. Entergy Gulf States Louisiana and the LPSC Staff reached agreement regarding the LPSC Staff’s proposed adjustments. As reflected in an unopposed joint report of proceedings filed by Entergy Gulf States Louisiana and the LPSC Staff in May 2013, Entergy Gulf States Louisiana accepted, with modification, the LPSC Staff’s proposed adjustment to property insurance expense and agreed to: (1) a ~~three-year~~three-year extension of the gas rate stabilization plan with a midpoint return on equity of 9.95%, with a first year midpoint reset; (2) dismissal of a docket initiated by the LPSC to evaluate the allowed return on equity for Entergy Gulf States Louisiana’s gas rate stabilization plan; and (3) presentation to the LPSC by November 2014 by Entergy Gulf States Louisiana and the LPSC Staff of their recommendation for implementation of an infrastructure rider to recover expenditures associated with strategic plant investment. The LPSC approved the agreement in May 2013.

In January ~~2012,~~2014, Entergy Gulf States Louisiana filed with the LPSC its gas rate stabilization plan for the test year ended September 30, ~~2011.~~2013. The filing showed an earned return on common equity of ~~10.48%~~5.47%, which ~~is within the earnings bandwidth of~~ ~~10.5%, plus or minus fifty basis points.~~results in a $1.5 million rate increase. In April ~~2012~~2014 the LPSC Staff ~~filed~~issued a report indicating “that Entergy Gulf States Louisiana has properly determined its ~~findings, suggesting adjustments that produced an~~ ~~11.54%~~ ~~earned return on common equity~~earnings for the test year ~~and a~~ ~~$0.1~~ended September 30, 2013.” The $1.5 million rate ~~reduction. Entergy Gulf States Louisiana accepted the LPSC Staff’s recommendations, and the rate reduction~~increase was implemented effective with the first billing cycle of ~~May 2012.~~April 2014.

In accordance with the settlement of Entergy Gulf States Louisiana’s gas rate stabilization plan for the test year ended September 30, 2012, in August 2014 Entergy Gulf States Louisiana submitted for consideration a proposal for implementation of an infrastructure rider to recover expenditures associated with strategic plant investment and relocation projects mandated by local governments. After review by the LPSC staff and inclusion of certain customer safeguards required by the LPSC staff, in December 2014, Entergy Gulf States Louisiana and the LPSC staff submitted a joint settlement for implementation of an accelerated gas pipe replacement program providing for the replacement of approximately 100 miles of pipe over the next ten years, as well as relocation of certain existing pipe resulting from local government-related infrastructure projects, and for a rider to recover the investment associated with these projects. The rider allows for recovery of approximately $65 million over ten years. The rider recovery will be adjusted on a quarterly basis to include actual investment incurred for the prior quarter and is subject to the following conditions, among others: a ten-year term; application of any earnings in excess of 10.45% as an offset to the revenue requirement of the infrastructure rider; adherence to a specified spending plan, within plus or minus 20 percent annually; annual filings comparing actual versus planned rider spending with actual spending and explanation of variances exceeding ten percent; and an annual true-up. The joint settlement was approved by the LPSC in January 2015. Implementation of the infrastructure rider will commence with bills rendered on and after the first billing cycle of April 2015.

In January ~~2011,~~2015, Entergy Gulf States Louisiana filed with the LPSC its gas rate stabilization plan for the test year ended September 30, ~~2010.~~2014. The filing showed an earned return on common equity of ~~8.84%~~ ~~and~~7.20%, which results in a ~~revenue deficiency of~~ ~~$0.3 million. In March 2011 the LPSC Staff filed its findings, suggesting an adjustment that produced an~~ ~~11.76%~~ ~~earned return on common equity for the test year and a~~ ~~$0.2 million~~$706 thousand rate ~~reduction. Entergy Gulf States Louisiana~~increase. The rate increase, if approved, will be implemented ~~the~~ ~~$0.2 million~~ ~~rate reduction~~ effective with the ~~May 2011~~first billing ~~cycle.~~cycle of April 2015.

In September 2009, Entergy Mississippi filed with the MPSC proposed modifications to its formula rate plan rider. In March 2010 the MPSC issued an order: (1) providing the opportunity for a reset of Entergy Mississippi’s return on common equity to a point within the formula rate plan bandwidth and eliminating the 50/50 sharing that had been in the plan, (2) modifying the performance measurement process, and (3) replacing the revenue change limit of two percent of revenues, which was subject to a ~~$14.5~~$14.5 million revenue adjustment cap, with a limit of four percent of revenues, although any adjustment above two percent requires a hearing before the MPSC. The MPSC did not approve Entergy Mississippi’s request to use a projected test year for its annual scheduled formula rate plan filing and, therefore, Entergy Mississippi continued to use a historical test year for its annual evaluation reports under the plan.

~~In March 2011, Entergy Mississippi submitted its formula rate plan 2010 test year filing. The filing shows an earned return on common equity of~~ ~~10.65%~~ for the test year, which is within the earnings bandwidth and results in no change in rates. In November 2011 the MPSC approved a joint stipulation between Entergy Mississippi and the Mississippi Public Utilities Staff that provides for no change in rates.

In March 2013, Entergy Mississippi submitted its formula rate plan filing for the 2012 test year. The filing requested a ~~$36.3~~$36.3 million revenue increase to reset Entergy ~~Mississippi's~~Mississippi’s return on common equity to 10.55%, which is a point within the formula rate plan bandwidth. In June 2013, Entergy Mississippi and the Mississippi Public Utilities

In June 2014, Entergy Mississippi filed its first general rate case before the MPSC in almost 12 years. The rate filing laid out Entergy Mississippi’s plans for improving reliability, modernizing the grid, maintaining its workforce, stabilizing rates, utilizing new technologies, and attracting new industry to its service territory. Entergy Mississippi requested a net increase in revenue of $49 million for bills rendered during calendar year 2015, including $30 million resulting from new depreciation rates to update the estimated service life of assets. In addition, the filing proposed, among other things: 1) realigning cost recovery of the Attala and Hinds power plant acquisitions from the power management rider to base rates; 2) including certain MISO-related revenues and expenses in the power management rider; 3) power management rider changes that reflect the changes in costs and revenues that will accompany Entergy Mississippi’s withdrawal from participation in the System Agreement; and 4) a formula rate plan forward test year to allow for known changes in expenses and revenues for the rate effective period. Entergy Mississippi proposed maintaining the current authorized return on common equity of 10.59%.

In October 2014, Entergy Mississippi and the Mississippi Public Utilities Staff entered into and filed joint stipulations that addressed the majority of issues in the proceeding. The stipulations provided for:

The following table presents changes in accumulated other comprehensive income (loss) for Entergy for the year ended December 31, 2013 by component:

The following table presents changes in accumulated other comprehensive income (loss) for Entergy Gulf States Louisiana and Entergy Louisiana for the year ended December 31, 2014:

The following table presents changes in accumulated other comprehensive ~~loss~~income (loss) for Entergy Gulf States Louisiana and Entergy Louisiana for the year ended December 31, 2013:

Total reclassifications out of accumulated other comprehensive income (loss) (AOCI) for Entergy for the year ended December 31, 2014 are as follows:

Total reclassifications out of accumulated other comprehensive income (loss) (AOCI) for Entergy for the year ended December 31, 2013 are as follows:

Total reclassifications out of accumulated other comprehensive ~~loss~~income (loss) (AOCI) for Entergy Gulf States Louisiana and Entergy Louisiana for the year ended December 31, 2014 are as follows:

Total reclassifications out of accumulated other comprehensive income (loss) (AOCI) for Entergy Gulf States Louisiana and Entergy Louisiana for the year ended December 31, 2013 are as follows:

Entergy and the Registrant Subsidiaries are involved in a number of legal, regulatory, and tax proceedings before various courts, regulatory commissions, and governmental agencies in the ordinary course of business. While management is unable to predict the outcome of such proceedings, management does not believe that the ultimate resolution of these matters will have a material effect on Entergy’s results of operations, cash flows, or financial condition. Entergy discusses regulatory proceedings in Note 2 to the financial statements and discusses tax proceedings in Note 3 to the financial statements.

Entergy Louisiana has an agreement extending through the year 2031 to purchase energy generated by a hydroelectric facility known as the Vidalia project. Entergy Louisiana made payments under the contract of approximately ~~$181.1~~$152.8 million in ~~2013~~, ~~$125.0~~2014, $181.1 million in ~~2012~~,2013, and ~~$185.6~~$125.0 million in ~~2011~~.2012. If the maximum percentage (~~94%~~(94%) of the energy is made available to Entergy Louisiana, current production projections would require estimated payments of approximately ~~$147.5~~$148.5 million in ~~2014~~,2015, and a total of ~~$2.19~~$2.06 billion for the years ~~2015~~2016 through 2031. Entergy Louisiana currently recovers the costs of the purchased energy through its fuel adjustment clause.

In an LPSC-approved settlement related to tax benefits from the tax treatment of the Vidalia contract, Entergy Louisiana agreed to credit rates by ~~$11~~$11 million each year for up to 10 years, beginning in October 2002. In addition, in accordance with an LPSC settlement, Entergy Louisiana credited rates in August 2007 by ~~$11.3~~$11.3 million (including interest) as a result of a settlement with the IRS of the 2001 tax treatment of the Vidalia contract. ~~As discussed in more detail in Note 3 to the financial statements, in~~In August 2011, Entergy agreed to a settlement with the IRS regarding the mark-to-market income tax treatment of various wholesale electric power purchase and sale ~~agreements,~~contracts, including the

On March 31, 2013, during a scheduled refueling outage at ANO 1, a contractor-owned and operated heavy-lifting apparatus collapsed while moving the generator stator out of the turbine building. The collapse resulted in the death of an ironworker and injuries to several other contract workers, caused ANO 2 to shut down, and damaged the ANO turbine building. The turbine building serves both ANO 1 and 2 and is a non-radiological area of the plant. ANO 2 reconnected to the grid on April 28, 2013 and ANO 1 reconnected to the grid on August 7, 2013. The total cost of assessment, restoration of off-site power, site restoration, debris removal, and replacement of damaged property and equipment was $~~94 million~~ ~~as of December 31, 2013.~~approximately $95 million. In addition, Entergy Arkansas incurred replacement power costs for ANO 2 power during its outage and incurred incremental replacement power costs for ANO 1 power because the outage extended beyond the originally-planned duration of the refueling outage. ~~Each~~In February 2014 the APSC approved Entergy Arkansas’s request to exclude from the calculation of ~~the Utility operating companies has recovery mechanisms in place designed to recover~~ its ~~prudently-incurred~~revised energy cost rate $65.9 million of deferred fuel and purchased ~~power costs.~~energy costs incurred in 2013 as a result of the ANO stator incident. The APSC authorized Entergy Arkansas to retain the $65.9 million in its deferred fuel balance with recovery to be reviewed in a later period after more information regarding various claims associated with the ANO stator incident is available.

Entergy Arkansas is ~~assessing~~pursuing its options for recovering damages that resulted from the stator drop, including its insurance coverage and legal action. Entergy is a member of Nuclear Electric Insurance Limited (NEIL), a mutual

Shortly after the stator incident, the NRC deployed an augmented inspection team to review the plant’s response. In July 2013 a second team of NRC inspectors visited ANO to evaluate certain items that were identified as requiring follow-up inspection to determine whether performance deficiencies existed. In March 2014 the ~~second quarter 2013, Entergy Arkansas recorded~~NRC issued an ~~insurance receivable of $50 million~~ ~~based~~inspection report on the ~~minimum amount~~follow-up inspection that discussed two preliminary findings, one that was preliminarily determined to be “red with high safety significance” for Unit 1 and one that was preliminarily determined to be “yellow with substantial safety significance” for Unit 2, with the NRC indicating further that these preliminary findings may warrant additional regulatory oversight. This report also noted that one additional item related to flood barrier effectiveness was still under review.

In May 2014 the NRC met with Entergy during a regulatory conference to discuss the preliminary red and yellow findings and Entergy’s response to the findings. During the regulatory conference, Entergy presented information on the facts and assumptions the NRC used to assess the potential findings. The NRC used the information provided by Entergy at the regulatory conference to finalize its decision regarding the inspection team’s findings. In a letter dated June 23, 2014, the NRC classified both findings as “yellow with substantial safety significance.” In an assessment follow-up letter for ANO dated July 29, 2014, the NRC stated that given the two yellow findings, it ~~expects~~determined that the performance at ANO is in the “degraded cornerstone column,” or column 3, of the NRC’s reactor oversight process action matrix beginning the first quarter 2014. Corrective actions in response to ~~receive from NEIL. This $50 million~~ ~~receivable offset approximately $35 million~~the NRC’s findings have been taken and remain ongoing at ANO. The NRC plans to conduct supplemental inspection activity to review the actions taken to address the yellow findings. Entergy will continue to interact with the NRC to address the NRC’s findings.

In September 2014 the NRC issued an inspection report on the flood barrier effectiveness issue that was still under review at the time of ~~capital spending, $13 million~~the March 2014 inspection report. While Entergy believes that the flood barrier issues that led to the finding have been addressed at ANO, NRC processes still required that the NRC assess the safety significance of ~~operation and maintenance expense, and $2 million~~the deficiencies. In its September 2014 inspection report, the NRC discussed a preliminary finding of ~~incremental deferred refueling outage costs incurred~~“yellow with substantial safety significance” for the ~~recovery through December 31, 2013. As~~Unit 1 and Unit 2 auxiliary and emergency diesel fuel storage buildings. The NRC indicated that these preliminary findings may warrant additional regulatory oversight. Entergy requested a public regulatory conference regarding the inspection, and the conference was held on October 28, 2014. During the regulatory conference, Entergy presented information related to the facts and assumptions used by the NRC in arriving at its preliminary finding of ~~December 31, 2013, Entergy Arkansas has incurred approximately $34 million~~ ~~in capital spending, $9 million~~ ~~in operation and maintenance expense, and $1 million~~ ~~in incremental deferred refueling outage costs in excess of its recorded insurance receivable.~~“yellow with substantial safety significance.” In January 2015 the NRC issued its final risk significance determination for the flood barrier violation originally cited in the September 2014 ~~Entergy Arkansas collected $20 million~~report. The NRC’s final risk significance determination was classified as “yellow with substantial safety significance.”

The NRC’s January 2015 letter did not advise ANO of the $~~50 million~~ ~~receivable~~additional level of oversight that will result from the yellow finding related to the flood barrier issue, and it ~~expects~~stated that the NRC would inform ANO of this decision by separate correspondence. The yellow finding may result in ANO being placed into the “multiple/repetitive degraded cornerstone column” of the NRC’s reactor oversight process action matrix. Placement into this column would require significant additional NRC inspection activities at the ANO site, including a review of the site’s root cause evaluation associated with the flood barrier and stator issues, an assessment of the effectiveness of the site’s corrective action program, an additional design basis inspection, a safety culture assessment, and possibly other inspection activities consistent with the NRC’s Inspection Procedure. The additional NRC inspection activities at the site are expected to ~~receive from NEIL.~~increase ANO’s operating costs.

On September 11, 2013, Entergy Mississippi’s Baxter Wilson (Unit 1) power plant experienced a significant unplanned outage event. Entergy Mississippi completed the repairs to the unit in December 2014. As of December 31, 2014, Entergy Mississippi incurred $22.3 million of capital spending and $26.6 million of operation and maintenance expenses to return the unit to service. The ~~cause~~damage was covered by Entergy Mississippi’s property insurance policy, subject to a $20 million deductible. As of December 31, 2014, Entergy Mississippi recorded an insurance receivable of $28.2 million for the amount expected to be received from its insurance policy, allocating $12.9 million of the ~~event is currently under investigation.~~expected insurance proceeds to capital spending and $15.3 million to operation and maintenance expenses. In June 2014, Entergy Mississippi ~~is still in~~filed a rate case with the ~~process of assessing the nature and extent~~MPSC, which includes recovery of the ~~damage~~costs associated with Baxter Wilson (Unit 1) repair activities, net of applicable insurance proceeds. In December 2014 the MPSC issued an order that provided for a deferral of $6 million in other operation and maintenance expenses associated with the Baxter Wilson outage and that the regulatory asset should accrue carrying costs, with amortization of the regulatory asset to occur over two years beginning in February 2015, and provided that the ~~unit.~~capital costs will be reflected in rate base. The ~~current estimate~~final accounting of costs to return the unit to service ~~is between $45 million~~and $~~60 million~~. This estimate may change as restorative activities occur. The costs necessary to return the plant to service are expected to continue to be incurred into the third quarter 2014. Entergy Mississippi believes that the damage is primarily covered by its property insurance policy, subject to a $~~20 million~~ ~~deductible.~~ In December 2013, Entergy Mississippi made a filing with the MPSC requesting approval for Entergy Mississippi to defer and accumulate the costs incurred in connection with Baxter Wilson repair activities, net of applicable insurance proceeds ~~with such costs to~~will be ~~recoverable~~addressed in ~~a manner to be determined by the MPSC. The MPSC has not acted on~~ Entergy ~~Mississippi's request.~~

The Price-Anderson Act requires that reactor licensees purchase insurance and participate in a secondary insurance pool that provides insurance coverage for the public in the event of a nuclear power plant accident. The costs of this insurance are borne by the nuclear power industry. Congress amended and renewed the Price-Anderson Act in 2005 for a term through 2025. The Price-Anderson Act requires nuclear power plants to show evidence of financial protection in the event of a nuclear accident. This protection must consist of two layers of coverage:

Currently, 104 nuclear reactors are participating in the Secondary Financial Protection program. The product of the maximum retrospective premium assessment to the nuclear power industry and the number of nuclear power reactors provides over ~~$13.2~~$13.2 billion in secondary layer insurance coverage to compensate the public in the event of a nuclear power reactor accident. The Price-Anderson Act provides that all potential liability for a nuclear accident is limited to the amounts of insurance coverage available under the primary and secondary layers.

Entergy Arkansas has two licensed reactors and Entergy Gulf States Louisiana, Entergy Louisiana, and System Energy each have one licensed reactor (~~10%~~(10% of Grand Gulf is owned by a non-affiliated company (SMEPA) that would share on a pro-rata basis in any retrospective premium assessment to System Energy under the Price-Anderson Act). The Entergy Wholesale Commodities segment includes the ownership, operation, and ~~operation~~decommissioning of~~six~~ nuclear power reactors and the ownership of the shutdown Indian Point 1 reactor and Big Rock Point facility.

Entergy’s nuclear owner/licensee subsidiaries are members of ~~Nuclear Electric Insurance Limited (NEIL),~~NEIL, a mutual insurance company that provides property damage coverage, including decontamination and premature decommissioning expense, to the members’ nuclear generating plants. Effective April 1, ~~2013,~~2014, Entergy was insured against such losses per the following structures:

Note: ANO 1 and 2 share in the primary and blanket excess layers with common policies because the policies are issued on a per site basis. ~~Also, flood~~Flood and earthquake coverage are excluded from the primary ~~layer, which provides the~~layer’s first ~~$500~~$500 million in coverage. Entergy currently purchases ~~primary layer~~ flood coverage ~~for~~at Waterford 3 and River ~~Bend.~~Bend for the primary layer’s first $500 million in coverage.

Note: ~~Big Rock Point has its own primary policy with no excess coverage. Also, flood~~Flood and earthquake coverage are excluded from the primary ~~layer, which provides the~~layer’s first ~~$500~~$500 million in coverage. Entergy currently purchases ~~primary layer~~ flood and earthquake coverage at Palisades for ~~Vermont Yankee, Palisades, and Big Rock Point.~~the primary layer’s first $500 million in coverage.

Note: The Indian Point Units share in the primary and excess layers with common policies because the policies are issued on a per site basis. ~~Also, flood~~Flood and earthquake coverage are excluded from the primary ~~layer, which provides the~~layer’s first ~~$500~~$500 million

Note: Flood and earthquake coverage are excluded from the primary layer’s first $500 million in coverage. Entergy currently purchases flood and earthquake coverage at Vermont Yankee for the primary layer’s first $500 million in coverage.

Note: Flood and earthquake coverage are excluded from the primary layer’s first $500 million in coverage. Entergy currently purchases flood and earthquake coverage at Big Rock Point for the primary layer’s first $500 million in coverage.

In addition, Waterford 3, Grand Gulf, and the Entergy Wholesale Commodities plants, with the exception of Vermont Yankee, are also covered under NEIL’s Accidental Outage Coverage program. Due to the shutdown of the Vermont Yankee Nuclear Power Plant in December 2014, and the required 12 week deductible waiting period for the accidental outage coverage to take effect, accidental outage coverage was removed effective October 1, 2014. This coverage provides certain fixed indemnities in the event of an unplanned outage that results from a covered NEIL primary property damage loss, subject to a deductible period. The payout for damage resulting from non-nuclear events is limited to a $~~327.6~~$327.6 million per occurrence sub-limit. The following summarizes this coverage effective ~~April~~October 1, ~~2013:~~2014:

Under the property damage and accidental outage insurance programs, all NEIL insured plants could be subject to assessments should losses exceed the accumulated funds available from NEIL. Effective April 1, ~~2013,~~2014, the maximum amounts of such possible assessments per occurrence were as follows:

Entergy maintains property insurance for its nuclear units in excess of the NRC’s minimum requirement of ~~$1.06~~$1.06 billion per site for nuclear power plant licensees. NRC regulations provide that the proceeds of this insurance must be used, first, to render the reactor safe and stable, and second, to complete decontamination operations. Only after proceeds are dedicated for such use and regulatory approval is secured would any remaining proceeds be made available for the benefit of plant owners or their creditors.

In the event that one or more acts of terrorism causes property damage under one or more or all nuclear insurance policies issued by NEIL (including, but not limited to, those described above) within 12 months from the date the first property damage occurs, the maximum recovery under all such nuclear insurance policies shall be an aggregate of ~~$3.24~~$3.24 billion plus the additional amounts recovered for such losses from reinsurance, indemnity, and any other sources

Entergy’s conventional property insurance program provides coverage of up to ~~$400~~$400 million on an Entergy system-wide basis for all operational perils (direct physical loss or damage due to machinery breakdown, electrical failure, fire, lightning, hail, or explosion) on an “each and every loss” basis; up to ~~$400~~$400 million in coverage for certain natural perils (direct physical loss or damage due to earthquake, tsunami, and flood) on an annual aggregate basis; up to ~~$125~~$125 million for certain other natural perils (direct physical loss or damage due to a named windstorm and associated storm surge) on an annual aggregate basis; and up to ~~$400~~$400 million in coverage for all other natural perils not previously stated (direct physical loss or damage due to a tornado, ice storm, or any other natural peril except named windstorm and associated storm surge, earthquake, tsunami, and flood) on an “each and every loss” basis. The conventional property insurance program provides up to ~~$50~~$50 million in coverage for the Entergy New Orleans gas distribution system on an “each and every loss” basis. This ~~$50~~$50 million limit is subject to: the ~~$400~~$400 million annual aggregate limit for the natural perils of earthquake, tsunami, and flood; the ~~$125~~$125 million annual aggregate limit for the natural perils of named windstorm and associated storm ~~surge; the~~ ~~$400 million~~ per occurrence limit for all other natural perils not previously stated, which includes tornado and ice storm, but excludes named windstorm and associated storm surge, earthquake, tsunami, and flood; and the ~~$400 million~~ ~~per occurrence limit for operational perils.~~surge. The coverage is subject to a ~~$40~~$40 million self-insured retention per occurrence for the natural perils of named windstorm and associated storm surge, earthquake, flood, and tsunami; and a ~~$20~~$20 million

Covered property generally includes power plants, substations, facilities, inventories, and gas distribution-related properties. Excluded property generally includes above-ground transmission and distribution lines, poles, and towers for substations valued at $5$5 million or less, coverage for named windstorm and associated storm surge is excluded. This coverage is in place for Entergy Corporation, the Registrant Subsidiaries, and certain other Entergy subsidiaries, including the owners of the nuclear power plants in the Entergy Wholesale Commodities segment. Entergy also purchases ~~$300~~$300 million in terrorism insurance coverage for its conventional property. The Terrorism Risk Insurance Reauthorization Act of 2007 created a government program that provides for up to ~~$100~~$100 billion in coverage in excess of existing coverage for a terrorist event. The Terrorism Risk Insurance Reauthorization Act of 2007 expired on December 31, 2014. However, The Terrorism Risk Insurance Reauthorization Act of 2015 was signed into law by the President of the United States on January 12, 2015 thereby extending the Terrorism Risk Insurance Act for six years until December 31, 2020.

In addition to the conventional property insurance program, Entergy has purchased additional coverage ($($20 million per occurrence) for some of its non-regulated, non-generation assets. This policy serves to buy-down the ~~$20~~$20 million deductible and is placed on a scheduled location basis. The applicable deductibles are ~~$100,000~~$100,000 to ~~$250,000~~,$250,000, except for properties that are damaged by flooding and properties whose values are greater than ~~$20 million~~;$20 million; these properties have a ~~$500,000~~$500,000 deductible. Four nuclear locations have a ~~$2.5~~$2.5 million deductible, which coincides with the nuclear property insurance deductible at each respective nuclear site.

Entergy New Orleans received insurance proceeds for future construction expenditures associated with rebuilding its gas system, and the October 2006 City Council resolution approving the settlement of Entergy New Orleans’s rate and storm-cost recovery filings requires Entergy New Orleans to record those proceeds in a designated sub-account of other deferred credits until the proceeds are spent on the rebuild project. This other deferred credit is shown as “Gas system rebuild insurance proceeds” on Entergy New Orleans’s balance sheet.

The Registrant Subsidiaries and other Entergy subsidiaries are responding to various lawsuits in both state and federal courts and to other labor-related proceedings filed by current and former employees, recognized bargaining

Numerous lawsuits have been filed in federal and state courts primarily in Texas and Louisiana, primarily by contractor employees who worked in the 1940-1980s timeframe, against Entergy Gulf States Louisiana and Entergy Texas, and to a lesser extent the other Utility operating companies, as premises owners of power plants, for damages caused by alleged exposure to asbestos. Many other defendants are named in these lawsuits as well. Currently, there are approximately 400 lawsuits involving approximately ~~5,000~~4,000 claimants. Management believes that adequate provisions have been established to cover any exposure. Additionally, negotiations continue with insurers to recover reimbursements. Management believes that loss exposure has been and will continue to be handled so that the ultimate resolution of these matters will not be material, in the aggregate, to the financial position, results of operation, or cash flows of the Utility operating companies.

System Energy has entered into agreements with Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans whereby they are obligated to purchase their respective entitlements of capacity and energy from System Energy’s interest in Grand Gulf, and to make payments that, together with other available funds, are adequate to cover System Energy’s operating expenses. System Energy would have to secure funds from other sources, including Entergy Corporation’s obligations under the Capital Funds Agreement, to cover any shortfalls from payments received from Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans under these agreements.

System Energy has agreed to sell all of its share of capacity and energy from Grand Gulf to Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans in accordance with specified percentages (Entergy ~~Arkansas-36%~~Arkansas-36%, Entergy ~~Louisiana-14%~~Louisiana-14%, Entergy ~~Mississippi-33%~~Mississippi-33%, and Entergy New ~~Orleans-17%~~Orleans-17%) as ordered by the FERC. Charges under this agreement are paid in consideration for the purchasing companies’ respective entitlement to receive capacity and energy and are payable irrespective of the quantity of energy delivered. The agreement will remain in effect until terminated by the parties and the termination is approved by the FERC, most likely upon Grand Gulf’s retirement from service. Monthly obligations are based on actual capacity and energy costs. The average monthly payments for ~~2013~~2014 under the agreement are approximately ~~$22.3~~$20.2 million for Entergy Arkansas, ~~$8.7~~$8.0 million for Entergy Louisiana, ~~$19.2~~$17.4 million for Entergy Mississippi, and ~~$10.8~~$9.8 million for Entergy New Orleans.

Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans are individually obligated to make payments or subordinated advances to System Energy in accordance with stated percentages (Entergy ~~Arkansas-17.1%~~Arkansas-17.1%, Entergy ~~Louisiana-26.9%~~Louisiana-26.9%, Entergy ~~Mississippi-31.3%~~Mississippi-31.3%, and Entergy New ~~Orleans-24.7%~~Orleans-24.7%) in amounts that, when added to amounts received under the Unit Power Sales Agreement or otherwise, are adequate to cover all of System Energy’s operating expenses as defined, including an amount sufficient to amortize the cost of Grand Gulf 2 over 27 years (See Reallocation Agreement terms below) and expenses incurred in connection with a permanent shutdown of Grand Gulf. System Energy has assigned its rights to payments and advances to certain creditors as security for certain obligations. Since commercial operation of Grand Gulf began, payments under the Unit Power Sales Agreement have exceeded the amounts payable under the Availability Agreement. Accordingly, no payments under the Availability Agreement have ever been required. If Entergy Arkansas or Entergy Mississippi fails to make its Unit Power Sales Agreement payments, and System Energy is unable to obtain funds from other sources, Entergy

System Energy, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans entered into the Reallocation Agreement relating to the sale of capacity and energy from Grand Gulf and the related costs, in which Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans agreed to assume all of Entergy Arkansas’s responsibilities and obligations with respect to Grand Gulf under the Availability Agreement. FERC’s decision allocating a portion of Grand Gulf capacity and energy to Entergy Arkansas supersedes the Reallocation Agreement as it relates to Grand Gulf. Responsibility for any Grand Gulf 2 amortization amounts has been individually allocated (Entergy ~~Louisiana-26.23%~~Louisiana-26.23%, Entergy ~~Mississippi-43.97%~~Mississippi-43.97%, and Entergy New ~~Orleans-29.80%~~Orleans-29.80%) under the terms of the Reallocation Agreement. However, the Reallocation Agreement does not affect Entergy Arkansas’s obligation to System Energy’s lenders under the assignments referred to in the preceding paragraph. Entergy Arkansas would be liable for its share of such amounts if Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans were unable to meet their contractual obligations. No payments of any amortization amounts will be required so long as amounts paid to System Energy under the Unit Power Sales Agreement, including other funds available to System Energy, exceed amounts required under the Availability Agreement, which is expected to be the case for the foreseeable future.

In December 1988, in two separate but substantially identical transactions, System Energy sold and leased back undivided ownership interests in Grand Gulf for the aggregate sum of ~~$500 million~~.$500 million. During the term of the leases, System Energy is required to maintain letters of credit for the equity investors to secure certain amounts payable to the equity investors under the transactions.

Under the provisions of the reimbursement agreement relating to the letters of credit, System Energy has agreed to a number of covenants regarding the maintenance of certain capitalization and fixed charge coverage ratios. System Energy agreed, during the term of the reimbursement agreement, to maintain a ratio of debt to total liabilities and equity less than or equal to 70%. In addition, System Energy must maintain, with respect to each fiscal quarter during the term of the reimbursement agreement, a ratio of adjusted net income to interest expense of at least 1.50 times earnings. As of December 31, ~~2013,~~2014, System Energy was in compliance with these covenants.

Accounting standards require companies to record liabilities for all legal obligations associated with the retirement of long-lived assets that result from the normal operation of the assets. For Entergy, substantially all of its asset retirement obligations consist of its liability for decommissioning its nuclear power plants. In addition, an insignificant amount of removal costs associated with non-nuclear power plants is also included in the decommissioning line item on the balance sheets.

These liabilities are recorded at their fair values (which are the present values of the estimated future cash outflows) in the period in which they are incurred, with an accompanying addition to the recorded cost of the long-lived asset. The asset retirement obligation is accreted each year through a charge to expense, to reflect the time value of money for this present value obligation. The accretion will continue through the completion of the asset retirement activity. The amounts added to the carrying amounts of the long-lived assets will be depreciated over the useful lives

In accordance with ratemaking treatment and as required by regulatory accounting standards, the depreciation provisions for the Registrant Subsidiaries include a component for removal costs that are not asset retirement obligations under accounting standards. In accordance with regulatory accounting principles, the Registrant Subsidiaries have recorded regulatory assets (liabilities) in the following amounts to reflect their estimates of the difference between estimated incurred removal costs and estimated removal costs recovered in rates:

The cumulative decommissioning and retirement cost liabilities and expenses recorded in 2014 by Entergy were as follows:

In 2014, Entergy Arkansas recorded a revision to its estimated decommissioning cost liabilities for ANO 1 and ANO 2 as a result of a revised decommissioning cost study. The revised estimates resulted in a $47.6 million increase in the decommissioning cost liabilities, along with a corresponding increase in the related asset retirement cost assets that will be depreciated over the remaining lives of the units.

See Note 1 to the financial statements for further discussion of the shutdown of Vermont Yankee and the December 2013 settlement agreement involving Entergy and Vermont parties. In accordance with the settlement agreement, Entergy Vermont Yankee provided to the Vermont parties, in 2014, a site assessment study of the costs and tasks of radiological decommissioning, spent nuclear fuel management, and site restoration for Vermont Yankee. Entergy Vermont Yankee also filed its Post-Shutdown Decommissioning Activities Report (PSDAR) for Vermont Yankee with the NRC in December 2014. As part of the development of the site assessment study and PSDAR, Entergy obtained a revised decommissioning cost study in the third quarter 2014. The revised estimate, along with reassessment of the assumptions regarding the timing of decommissioning cash flows, resulted in a $101.6 million increase in the decommissioning cost liability and a corresponding impairment charge.

In the fourth quarter 2014, Entergy Gulf States Louisiana recorded a revision to its estimated decommissioning cost liability for River Bend as a result of a revised decommissioning cost study. The revised estimate resulted in a $20 million increase in the decommissioning cost liability, along with a corresponding increase in the related asset retirement cost asset that will be depreciated over the remaining useful life of the unit.

In the fourth quarter 2014, 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 $99.9 million increase in its decommissioning liability, along with a corresponding increase in the related asset retirement cost asset that will be depreciated over the remaining life of the unit.

In the first quarter 2013, Entergy Wholesale Commodities recorded a revision to its estimated decommissioning cost liability for a nuclear site as a result of a revised decommissioning cost study. The revised estimate resulted in a ~~$46.6~~$46.6 million reduction in the decommissioning cost liability, along with a corresponding reduction in the related asset retirement cost asset.

In the third quarter 2013, Entergy Wholesale Commodities recorded a revision to its estimated decommissioning cost liability for Vermont Yankee as a result of a revised decommissioning cost study. The revised estimate resulted in a ~~$58~~$58 million increase in the decommissioning cost liability, along with a corresponding increase in the related asset retirement cost asset. The increase in the estimated decommissioning cost liability resulted from the change in expectation regarding the timing of decommissioning cash flows due to the decision to cease operations of the plant. The asset retirement cost asset was included in the carrying value used to write down Vermont Yankee and related

In the fourth quarter 2013, 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 ~~$102.3~~$102.3 million increase in its decommissioning liability, along with a corresponding increase in the related asset retirement cost asset that will be depreciated over the remaining life of the unit.

In the fourth quarter 2013, Entergy Louisiana recorded a revision to its estimated decommissioning cost liability for Waterford 3 as a result of a revised decommissioning cost study. The revised estimate resulted in a ~~$39.4~~$39.4 million increase in its decommissioning cost liability, along with a corresponding increase in the related asset retirement cost asset that will be depreciated over the remaining life of the unit.

In the fourth quarter 2013, Entergy Wholesale Commodities recorded a revision to its estimated decommissioning cost liability for Vermont Yankee. As a result of the settlement agreement regarding the remaining operation and decommissioning of Vermont Yankee, Entergy reassessed its assumptions regarding the timing of decommissioning cash flows. The reassessment resulted in a ~~$27.2~~$27.2 million increase in the decommissioning cost liability and a corresponding impairment charge, which will not result in future cash expenditures. See Note 1 to the financial statements for further discussion of the Vermont Yankee plant.

~~Assuming the end of Vermont Yankee operations in the fourth quarter 2014, the amount required to meet the NRC minimum for decommissioning financial assurance for license termination is~~ ~~$569.1 million. The Vermont Yankee decommissioning trust had a balance of approximately~~ ~~$612.1 million~~ ~~as of December 31, 2013, excluding the~~ ~~$40 million~~ guarantee by Entergy Corporation to satisfy NRC requirements following the 2009 review of financial assurance levels. Filings with the NRC for planned shutdown activities will determine whether any other financial assurance may be required.

InVermont Yankee submitted notification of permanent cessation of operations and permanent removal of fuel from the ~~fourth quarter~~reactor in January 2015 after final shutdown in December 2014. The PSDAR for Vermont Yankee, including a site specific cost estimate, was submitted to the NRC in December 2014. Vermont Yankee’s future certifications to satisfy the NRC’s financial assurance requirements will now be based on the site specific cost estimate, including the estimated cost of ~~2011,~~managing spent fuel, rather than the NRC minimum formula for estimating decommissioning costs. Entergy ~~Wholesale Commodities recorded a reduction~~expects that amounts available in Vermont Yankee’s decommissioning trust fund, including expected earnings, together with the credit facilities entered into in January 2015 that are expected to be repaid with recoveries from DOE litigation related to spent fuel storage, will be sufficient to cover expected costs of ~~$34.1 million~~ indecommissioning, spent fuel management costs, and site restoration. Filings with the ~~decommissioning cost liability~~NRC 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~~planned shutdown activities will determine whether any other financial assurance may be required and will specifically address funding for spent fuel management, which will be required until the ~~undiscounted cash flows and a credit to decommissioning expense of~~ ~~$34.1 million, reflecting the excess~~federal government takes possession of the ~~reduction in~~fuel and removes it from the ~~liability over the amount of undepreciated assets.~~site, per its current obligation.

For the Indian Point 3 and FitzPatrick plants purchased in 2000, NYPA retained the decommissioning trusts and the decommissioning liabilities. NYPA and Entergy subsidiaries executed decommissioning agreements, which specify their decommissioning obligations. NYPA has the ~~rights~~right to require the Entergy subsidiaries to assume each of the decommissioning liabilities provided that it assigns the corresponding decommissioning trust, up to a specified level, to the Entergy subsidiaries. If the decommissioning liabilities are retained by NYPA, the Entergy subsidiaries will perform the decommissioning of the plants at a price equal to the lesser of a pre-specified level or the amount in the decommissioning trusts. Entergy recorded an asset, which is ~~$572.6~~$599.9 million as of December 31, ~~2013~~,2014, representing its estimate of the present value of the difference between the stipulated contract amount for decommissioning the ~~plants less the decommissioning costs estimated in independent decommissioning cost studies. The asset is increased~~

Entergy maintains decommissioning trust funds that are committed to meeting its obligations for the costs of decommissioning the nuclear power plants. The fair values of the decommissioning trust funds and the related asset retirement obligation regulatory assets (liabilities) of Entergy as of December 31, ~~2013~~2014 are as follows:

Entergy maintains decommissioning trust funds that are committed to meeting its obligations for the costs of decommissioning the nuclear power plants. The fair values of the decommissioning trust funds and the related asset retirement obligation regulatory assets (liabilities) of Entergy as of December 31, ~~2012~~2013 are as follows:

As of December 31, ~~2013~~,2014, Entergy had capital leases and non-cancelable operating leases for equipment, buildings, vehicles, and fuel storage facilities with minimum lease payments as follows (excluding power purchase agreement operating leases, nuclear fuel leases and the Grand Gulf and Waterford 3 sale and leaseback ~~transactions) with minimum lease payments as follows:~~transactions, all of which are discussed elsewhere):

Total rental expenses for all leases (excluding power purchase agreement operating leases, nuclear fuel leases and the Grand Gulf and Waterford 3 sale and leaseback transactions) amounted to ~~$63.7~~$59 million in ~~2013~~, ~~$69.9~~2014, $63.7 million in ~~2012~~,2013, and ~~$75.3~~$69.9 million in ~~2011~~.2012.

As of December 31, ~~2013~~,2014 the Registrant Subsidiaries had a capital ~~leases~~lease and non-cancelable operating leases for equipment, buildings, vehicles, and fuel storage facilities with minimum lease payments as follows (excluding power purchase agreement operating leases, nuclear fuel leases and the Grand Gulf and Waterford 3 sale and leaseback ~~transactions) with minimum lease payments as follows:~~transactions, all of which are discussed elsewhere):

As of December 31, 2014, Entergy Texas had a power purchase agreement that is accounted for as an operating lease under the accounting standards. The lease payments are recovered in fuel expense in accordance with regulatory treatment. The minimum lease payments under the power purchase agreement are as follows:

In 1989, in three separate but substantially identical transactions, Entergy Louisiana sold and leased back undivided interests in Waterford 3 for the aggregate sum of ~~$353.6 million~~.$353.6 million. The leases expire in July 2017. At the end of the lease terms, Entergy Louisiana has the option to repurchase the leased interests in Waterford 3 at fair market value or to renew the leases for either fair market value or, under certain conditions, a fixed rate. In the event that Entergy Louisiana does not renew or purchase the interests, Entergy Louisiana would surrender such interests and their associated entitlement of Waterford 3’s capacity and energy.

Entergy Louisiana issued ~~$208.2~~$208.2 million of non-interest bearing first mortgage bonds as collateral for the equity portion of certain amounts payable under the leases.

Upon the occurrence of certain events, Entergy Louisiana may be obligated to assume the outstanding bonds used to finance the purchase of the interests in the unit and to pay an amount sufficient to withdraw from the lease transaction. Such events include lease events of default, events of loss, deemed loss events, or certain adverse “Financial Events.” “Financial Events” include, among other things, failure by Entergy Louisiana, following the expiration of any applicable grace or cure period, to maintain (i) total equity capital (including preferred membership interests) at least equal to 30% of adjusted capitalization, or (ii) a fixed charge coverage ratio of at least 1.50 computed on a rolling 12 month basis. As of December 31, ~~2013~~,2014, Entergy Louisiana was in compliance with these provisions.

In 1988, in two separate but substantially identical transactions, System Energy sold and leased back undivided ownership interests in Grand Gulf for the aggregate sum of ~~$500 million~~.$500 million. The initial term of the leases was to expire in July 2015. In December 2013, System Energy exercised its options to renew the leases for fair market value with a renewal term for one lease expiring in July 2018 and the renewal term of the other lease expiring in July 2036. At the end of the new lease renewal terms, System Energy has the option to repurchase the leased interests in Grand Gulf or renew the leases at fair market value. In the event that System Energy does not renew or purchase the interests, System Energy would surrender such interests and their associated entitlement of Grand Gulf’s capacity and energy.

System Energy is required to report the sale-leaseback as a financing transaction in its financial statements. For financial reporting purposes, System Energy expenses the interest portion of the lease obligation and the plant depreciation. However, operating revenues include the recovery of the lease payments because the transactions are accounted for as a sale and leaseback for ratemaking purposes. Consistent with a recommendation contained in a FERC audit report, System Energy initially recorded as a net regulatory asset the difference between the recovery of the lease payments and the amounts expensed for interest and depreciation and continues to record this difference as a regulatory asset or liability on an ongoing basis, resulting in a zero net balance for the regulatory asset at the end of the lease term. The amount was a net regulatory liability of ~~$61.6~~$62.9 million and ~~$27.8~~$61.6 million as of December 31, ~~2013~~2014 and ~~2012~~,2013, respectively.

~~149~~

Entergy has ~~seven~~nine qualified pension plans covering substantially all ~~employees:~~employees. The “Entergy Corporation Retirement Plan for Non-Bargaining Employees,” “Entergy Corporation Retirement Plan for Bargaining Employees,” “Entergy Corporation Retirement Plan II for Non-Bargaining Employees,” “Entergy Corporation Retirement Plan II for Bargaining Employees,” “Entergy Corporation Retirement Plan ~~III,” “Entergy Corporation Retirement Plan~~ IV for Non-Bargaining Employees,” and “Entergy Corporation Retirement Plan IV for Bargaining ~~Employees.”~~Employees” are non-contributory final average pay plans and provide pension benefits that are based on employees’ credited service and compensation during employment. The ~~Registrant Subsidiaries participate in two of these plans:~~ “Entergy Corporation Retirement Plan for Non-Bargaining Employees” and “Entergy Corporation Retirement Plan for Bargaining Employees.” Except for the Entergy Corporation Retirement Plan III, the pension plans are noncontributory and provideIII” is a final average pay plan that provides pension benefits that are based on employees’ credited service and compensation during the final years before ~~retirement. The Entergy Corporation Retirement Plan III~~retirement and includes a mandatory employee contribution of 3% of earnings during the first 10 years of plan participation, and allows voluntary contributions from 1% to 10% of earnings for a limited group of employees. Non-bargaining employees hired or rehired after June 30, 2014 participate in the “Entergy Corporation Cash Balance Plan for Non-Bargaining Employees.” Certain bargaining employees hired or rehired after June 30, 2014, or such later date provided for in their applicable collective bargaining agreements, participate in the “Entergy Corporation Cash Balance Plan for Bargaining Employees.” The Registrant Subsidiaries participate in these four plans: “Entergy Corporation Retirement Plan for Non-Bargaining Employees,” “Entergy Corporation Retirement Plan for Bargaining Employees,” “Entergy Corporation Cash Balance Plan for Non-Bargaining Employees,” and “Entergy Cash Balance Plan for Bargaining Employees.”

The assets of the seven final average pay qualified pension plans are held in a master trust established by Entergy and the assets of the two cash balance pension plans are held in a second master trust established by Entergy. Each pension plan has an undivided beneficial interest in each of the investment accounts ~~of the~~in its respective master trust that is maintained by a trustee. Use of the master ~~trust~~trusts permits the commingling of the trust assets of the pension plans of Entergy Corporation and its Registrant Subsidiaries for investment and administrative purposes. Although assets ~~are commingled~~ in the master ~~trust,~~trusts are commingled, the trustee maintains supporting records for the purpose of allocating the trust level equity in net earnings (loss) and the administrative expenses of the investment accounts in each trust to the various participating pension ~~plans.~~plans in that particular trust. The fair value of the ~~trust~~trusts’ assets is determined by the trustee and certain investment managers. ~~The~~For each trust, the trustee calculates a daily earnings factor, including realized and unrealized gains or losses, collected and accrued income, and administrative expenses, and allocates earnings to each plan in the master ~~trust~~trusts on a pro rata basis.

~~Further, within~~Within each pension plan, the record of each Registrant Subsidiary’s beneficial interest in the plan assets is maintained by the plan’s actuary and is updated quarterly. Assets for each Registrant Subsidiary are increased for investment income and contributions, and are decreased for benefit payments. A plan’s investment net income/~~(loss)~~loss (i.e. interest and dividends, realized and unrealized gains and losses and expenses) is allocated to the Registrant Subsidiaries participating in that plan based on the value of assets for each Registrant Subsidiary at the beginning of the quarter adjusted for contributions and benefit payments made during the quarter.

Entergy Corporation and its subsidiaries fund pension costs in accordance with contribution guidelines established by the Employee Retirement Income Security Act of 1974, as amended, and the Internal Revenue Code of 1986, as amended. The assets of the plans include common and preferred stocks, fixed-income securities, interest in a money market fund, and insurance contracts. The Registrant Subsidiaries’ pension costs are recovered from customers as a component of cost of service in each of their respective jurisdictions.

Entergy Corporation and its subsidiaries’ total 2014, 2013,, ~~2012~~, and ~~2011~~2012 qualified pension costs and amounts recognized as a regulatory asset and/or other comprehensive income, including amounts capitalized, included the following components:

The Registrant Subsidiaries’ total 2014, 2013,, ~~2012~~, and ~~2011~~2012 qualified pension costs and amounts recognized as a regulatory asset and/or other comprehensive income, including amounts capitalized, for their employees included the following components:

Entergy also currently ~~provides health care~~offers retiree medical, dental, vision, and life insurance benefits (other postretirement benefits) for eligible retired employees. ~~Substantially all employees~~Employees who commenced employment before July 1, 2014 and who satisfy certain eligibility requirements (including retiring from Entergy after a certain age and/or years of service with Entergy and immediately commencing their Entergy pension benefit), may become eligible for ~~these~~other postretirement benefits.

In December 2013, Entergy announced changes to its other postretirement benefits ~~if they reach~~which include, among other things, elimination of other postretirement benefits for all non-bargaining employees hired or rehired after June 30, 2014 and for certain bargaining employees hired or rehired after June 30, 2014, or such later date provided for in their applicable collective bargaining agreement, and setting a dollar limit cap on Entergy’s contribution to retiree medical costs, effective 2019 for those non-bargaining employees who commence their Entergy retirement ~~age~~benefits on or after

Entergy uses a December 31 measurement date for its postretirement benefit plans.

Effective January 1, 1993, Entergy adopted an accounting standard requiring a change from a cash method to an accrual method of accounting for postretirement benefits other than pensions. At January 1, 1993, the actuarially determined accumulated postretirement benefit obligation (APBO) earned by retirees and active employees was estimated to be approximately ~~$241.4~~$241.4 million for Entergy (other than the former Entergy Gulf States) and ~~$128~~$128 million for the former Entergy Gulf States (now split into Entergy Gulf States Louisiana and Entergy Texas). Such obligations were being amortized over a 20~~-year~~20-year period that began in 1993 and ended in 2012. For the most part, the Registrant Subsidiaries

Entergy Arkansas, Entergy Mississippi, Entergy New Orleans, and Entergy Texas have received regulatory approval to recover accrued other postretirement benefit costs through rates. Entergy Arkansas began recovery in 1998, pursuant to an APSC order. This order also allowed Entergy Arkansas to amortize a regulatory asset (representing the difference between other postretirement benefit costs and cash expenditures for other postretirement benefits incurred from 1993 through 1997) over a 15~~-year~~15-year period that began in January 1998 and ended in December 2012.

The LPSC ordered Entergy Gulf States Louisiana and Entergy Louisiana to continue the use of the pay-as-you-go method for ratemaking purposes for postretirement benefits other than pensions. However, the LPSC retains the flexibility to examine individual companies’ accounting for other postretirement benefits to determine if special exceptions to this order are warranted.

Pursuant to regulatory directives, Entergy Arkansas, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy contribute the other postretirement benefit costs collected in rates into external trusts. System Energy is funding, on behalf of Entergy Operations, other postretirement benefits associated with Grand Gulf.

Trust assets contributed by participating Registrant Subsidiaries are in bank-administered master trusts, established by Entergy Corporation and maintained by a trustee. Each participating Registrant Subsidiary holds a beneficial interest in the trusts’ assets. The assets in the master trusts are commingled for investment and administrative purposes. Although assets are commingled, supporting records are maintained for the purpose of allocating the beneficial interest in net earnings/(losses) and the administrative expenses of the investment accounts to the various participating plans and participating Registrant Subsidiaries. Beneficial interest in an investment account’s net income/(loss) is comprised of interest and dividends, realized and unrealized gains and losses, and expenses. Beneficial interest from these investments is allocated to the plans and participating Registrant Subsidiary based on their portion of net assets in the pooled accounts.

In December 2013, Entergy announced changes to its other postretirement benefits which include, among other things, elimination of other postretirement benefits for employees hired or rehired after June 30, 2014 and setting a dollar limit cap on Entergy's contribution to retiree medical costs, effective 2019 for those employees who commence their Entergy retirement benefits on or after January 1, 2015. In accordance with accounting standards, certain of the other postretirement benefit changes have been reflected in the December 31, 2013 other postretirement obligation. The changes affecting active bargaining unit employees will be negotiated with the unions prior to implementation, where necessary, and to the extent required by law.

Entergy Corporation’s and its subsidiaries’ total 2014, 2013,, ~~2012~~, and ~~2011~~2012 other postretirement benefit costs, including amounts capitalized and amounts recognized as a regulatory asset and/or other comprehensive income, included the following components:

Total 2014, 2013,, ~~2012~~, and ~~2011~~2012 other postretirement benefit costs of the Registrant Subsidiaries, including amounts capitalized and deferred, for their employees included the following components:

Entergy also sponsors non-qualified, non-contributory defined benefit pension plans that provide benefits to certain key employees. Entergy recognized net periodic pension cost related to these plans of ~~$54.5~~$32.4 million in ~~2013~~, ~~$26.5~~2014, $54.5 million in ~~2012~~,2013, and ~~$24.0~~$26.5 million in ~~2011~~.2012. In 2014, 2013,, ~~2012~~, and ~~2011~~2012 Entergy recognized ~~$33.0~~$15.1 million,, ~~$6.3~~ $33 million,, and ~~$4.6~~$6.3 million,, respectively in settlement charges related to the payment of lump sum benefits out of the plan that is included in the non-qualified pension plan cost above. The projected benefit obligation was ~~$154.3~~$151.8 million and ~~$199.3~~$154.3 million as of December 31, ~~2013~~2014 and ~~2012~~,2013, respectively. The accumulated benefit obligation was ~~$131.4~~$130.6 million and ~~$180.6~~$131.4 million as of December 31, ~~2013~~2014 and ~~2012~~,2013, respectively.

Entergy’s non-qualified, non-current pension liability at December 31, ~~2013~~2014 and ~~2012~~2013 was ~~$127.5~~$135.6 million and ~~$137.2~~$127.5 million,, respectively; and its current liability was ~~$26.8~~$16.2 million and ~~$62.1~~$26.8 million,, respectively. The unamortized ~~transition asset,~~ prior service cost and net loss are recognized in regulatory assets (~~$59.1~~($60.3 million at December 31, ~~2013~~2014 and ~~$81.2~~$59.1 million at December 31, ~~2012~~)2013) and accumulated other comprehensive income before taxes (~~$26.1~~($23.5 million at December 31, ~~2013~~2014 and ~~$32.5~~$26.1 million at December 31, ~~2012~~)2013).

The Registrant Subsidiaries (except System Energy) participate in Entergy’s non-qualified, non-contributory defined benefit pension plans that provide benefits to certain key employees. The net periodic pension cost for their employees for the non-qualified plans for 2014, 2013,, ~~2012~~, and ~~2011~~,2012, was as follows:

Included in the ~~2013~~2014 net periodic pension cost above are settlement charges of ~~$415~~$337 thousand and $16 thousand for Entergy Arkansas and Entergy Texas, respectively, related to the lump sum benefits paid out of the plan. Included in the 2013 net periodic pension cost above are settlement charges of $415 thousand for Entergy Texas related to the lump sum benefits paid out of the plan. Included in the 2012 net periodic pension cost above are settlement charges of ~~$38~~$38 thousand for Entergy Arkansas related to the lump sum benefits paid out of the plan. ~~Included in the~~ ~~2011~~ ~~net periodic pension cost above are settlement charges of~~ ~~$41 thousand~~ ~~for Entergy Arkansas related to the lump sum benefits paid out of the plan.~~

The projected benefit obligation for their employees for the non-qualified plans as of December 31, ~~2013~~2014 and ~~2012~~2013 was as follows:

The accumulated benefit obligation for their employees for the non-qualified plans as of December 31, ~~2013~~2014 and ~~2012~~2013 was as follows:

Entergy and the Registrant Subsidiaries reclassified the following costs out of accumulated other comprehensive income (before taxes and including amounts capitalized) as of December 31, 2014:

Entergy and the Registrant Subsidiaries reclassified the following costs out of accumulated other comprehensive income (before taxes and including amounts capitalized) as of December 31, 2013:

Accounting standards require an employer to recognize in its balance sheet the funded status of its benefit plans. This is measured as the difference between plan assets at fair value and the benefit obligation. Entergy uses a December 31 measurement date for its pension and other postretirement plans. Employers are to record previously unrecognized gains and losses, prior service costs, and any remaining transition asset or obligation (that resulted from adopting prior pension and other postretirement benefits accounting standards) as comprehensive income and/or as a regulatory asset reflective of the recovery mechanism for pension and other postretirement benefit costs in the Registrant Subsidiaries’ respective regulatory jurisdictions. For the portion of Entergy Gulf States Louisiana that is not regulated, the unrecognized prior service cost, gains and losses, and transition asset/obligation for its pension and other postretirement benefit obligations are recorded as other comprehensive income. Entergy Gulf States Louisiana and Entergy Louisiana recover other postretirement benefit costs on a ~~pay as you go~~pay-as-you-go basis and record the unrecognized prior service cost, gains and losses, and transition obligation for its other postretirement benefit obligation as other comprehensive income. Accounting standards also ~~requires~~require that changes in the funded status be recorded as other comprehensive income and/or a regulatory asset in the period in which the changes occur.

With regard to pension and other postretirement costs, 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~~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.

The Plan Administrator’s trust asset investment strategy is to invest the assets in a manner whereby long-term earnings on the assets (plus cash contributions) provide adequate funding for retiree benefit payments. The mix of assets is based on an optimization study that identifies asset allocation targets in order to achieve the maximum return for an acceptable level of risk, while minimizing the expected contributions and pension and postretirement expense.

In the optimization studies, the Plan Administrator formulates assumptions about characteristics, such as expected asset class investment returns, volatility (risk), and correlation coefficients among the various asset classes. The future market assumptions used in the optimization study are determined by examining historical market characteristics of the various asset classes and making adjustments to reflect future conditions expected to prevail over the study period. ~~Target~~

The target asset ~~allocations adjust~~allocation for pension adjusts dynamically based on the pension plans' funded status. The current targets are shown below. The expectation is that the allocation to fixed income securities will increase as the pension plans' funded status ~~of the pension plans.~~increases. The following ~~targets and~~ ranges were established to produce an acceptable, economically efficient plan to manage around the targets. The target asset allocation range below for pension shows the ranges within which the allocation may adjust based on funded status, with the expectation that the allocation to fixed income securities will increase as the pension funded status increases.

The target and range asset allocation for postretirement assets reflects changes made in 2012 as recommended in the latest optimization ~~study~~study.

Entergy’s qualified pension and postretirement weighted-average asset allocations by asset category at December 31, ~~2013~~2014 and ~~2012~~2013 and the target asset allocation and ranges are as follows:

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 some investment managers.

The expected long-term rate of return for the qualified pension plans’ assets is based primarily on the geometric average of the historical annual performance of a representative portfolio weighted by the target asset allocation defined in the table above, along with other indications of expected return on ~~current assets and expected return available for reinvestment.~~assets. The time period reflected is a long dated period spanning several decades.

The expected long-term rate of return for the non-taxable postretirement trust assets is determined using the same methodology described above for pension assets, but the asset allocation specific to the non-taxable postretirement assets is used.

For the taxable postretirement trust assets, the investment allocation includes tax-exempt fixed income securities. This asset allocation in combination with the same methodology employed to determine the expected return for other trust assets (as described above), with a modification to reflect applicable taxes, is used to produce the expected long-term rate of return for taxable postretirement trust assets.

Entergy’s investment guidelines mandate the avoidance of risk concentrations. Types of concentrations specified to be avoided include, but are not limited to, investment concentrations in a single entity, type of industry, foreign country, geographic area and individual security issuance. As of December 31, ~~2013~~2014, all investment managers and assets were materially in compliance with the approved investment guidelines, therefore there were no significant concentrations (defined as greater than 10 percent of plan assets) of risk in Entergy’s pension and other postretirement benefit plan assets.

Accounting standards provide the framework for measuring fair value. That framework provides a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (level 1 measurements) and the lowest priority to unobservable inputs (level 3 measurements).

Assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The following tables set forth by level within the fair value hierarchy, measured at fair value

The accumulated benefit obligation for Entergy’s qualified pension plans was ~~$5.2~~$6.6 billion and ~~$5.4~~$5.2 billion at December 31, ~~2013~~2014 and ~~2012~~,2013, respectively.

The qualified pension accumulated benefit obligation for each of the Registrant Subsidiaries for their employees as of December 31, ~~2013~~2014 and ~~2012~~2013 was as follows:

Based upon the assumptions used to measure Entergy’s qualified pension and other postretirement benefit obligations at December 31, ~~2013~~,2014, and including pension and other postretirement benefits attributable to estimated future employee service, Entergy expects that benefits to be paid and the Medicare Part D subsidies to be received over the next ten years for Entergy Corporation and its subsidiaries will be as follows:

Based upon the same assumptions, Entergy expects that benefits to be paid and the Medicare Part D subsidies to be received over the next ten years for the Registrant Subsidiaries for their employees will be as follows:

Entergy currently expects to contribute approximately ~~$400~~$396 million to its qualified pension plans and approximately ~~$74.1~~$66.9 million to other postretirement plans in ~~2014.~~2015. The expected ~~2014~~2015 pension and other postretirement plan contributions of the Registrant Subsidiaries for their employees are shown below. The required pension contributions will not be known with more certainty until the January 1, ~~2014~~2015 valuations are completed by April 1, ~~2014.~~2015.

The Registrant Subsidiaries expect to contribute approximately the following to the qualified pension and other postretirement plans for their employees in ~~2014:~~2015:

The significant actuarial assumptions used in determining the pension PBO and the other postretirement benefit APBO as of December 31, ~~2013~~,2014, and ~~2012~~2013 were as follows:

The ~~actuarially estimated effect~~significant actuarial assumptions used in determining the net periodic pension and other postretirement benefit costs for 2014, 2013, and 2012 were as follows:

Entergy’s other postretirement benefit transition obligations were amortized over 20 years ending in 2012.

With respect to mortality assumptions, Entergy used the RP-2014 Employee and Health Annuitant Tables, with a fully generational MP-2014 projection scale, in determining its December 31, 2014 pension plans’ PBOs and other postretirement benefit APBO. The mortality assumptions used in determining Entergy’s December 31, 2013 pension plans’ PBOs were the 1994 Group Annuity Mortality Table and RP 2000 Combined Health Mortality, with generational (using Scale AA) projected mortality improvement. The mortality assumption used in determining the December 31, 2013 other postretirement APBO was the 1994 Group Annuity Mortality Table, with generational (using Scale AA) projected mortality improvement.

A one percentage point change in the assumed health care cost trend rate for 2014 would have the following effects:

A one percentage point change in the ~~actual subsidies received~~assumed health care cost trend rate for 2014 would have the following effects for the Registrant Subsidiaries for their ~~employees was as follows:~~employees:

Entergy sponsors the Savings Plan of Entergy Corporation and Subsidiaries (System Savings Plan). The System Savings Plan is a defined contribution plan covering eligible employees of Entergy and certain of its subsidiaries. The participating employing Entergy subsidiary makes matching contributions ~~for all non-bargaining and certain bargaining employees~~ to the System Savings Plan for all eligible participating employees in an amount equal to either 70% or 100% of the participants’ basic contributions, up to 6% of their eligible earnings per pay period. The ~~70%~~ ~~match~~matching contribution is allocated to investments as directed by the employee.

Entergy also sponsors the Savings Plan of Entergy Corporation and Subsidiaries IV (established in March 2002), the Savings Plan of Entergy Corporation and Subsidiaries VI (established in April 2007), and the Savings Plan of Entergy Corporation and Subsidiaries VII (established in April 2007) to which matching contributions are also made. The plans are defined contribution plans that cover eligible employees, as defined by each plan, of Entergy and certain of its subsidiaries.

Entergy’s subsidiaries’ contributions to defined contribution plans collectively were ~~$44.5~~$43.3 million in ~~2013~~, ~~$43.7~~2014, $44.5 million in ~~2012~~,2013, and ~~$42.6~~$43.7 million in ~~2011~~.2012. The majority of the contributions were to the System Savings Plan.

~~180~~

Entergy grants stock options, restricted stock, performance units, and restricted unit awards to key employees of the Entergy subsidiaries under its Equity Ownership Plans which are shareholder-approved stock-based compensation

Stock options are granted at exercise prices that equal the closing market price of Entergy Corporation common stock on the date of grant. Generally, stock options granted will become exercisable in equal amounts on each of the first three anniversaries of the date of grant. Unless they are forfeited previously under the terms of the grant, options expire ten years after the date of the grant if they are not exercised.

The following table includes financial information for stock options for each of the years presented:

Entergy determines the fair value of the stock option grants by considering factors such as lack of marketability, stock retention requirements, and regulatory restrictions on exercisability in accordance with accounting standards. The stock option weighted-average assumptions used in determining the fair values are as follows:

A summary of stock option activity for the year ended December 31, ~~2013~~2014 and changes during the year are presented below:

~~182~~

Stock-based compensation cost related to non-vested stock options outstanding as of December 31, ~~2013~~2014 not yet recognized is approximately ~~$5.0~~$5.4 million and is expected to be recognized over a weighted-average period of ~~1.70~~1.7 years.

In January ~~2013~~2014 the Board approved and Entergy granted ~~361,700~~352,600 restricted stock awards under the 2011 Equity Ownership and Long-term Cash Incentive Plan. The restricted stock awards were made effective as of January ~~31, 2013~~30, 2014 and were valued at ~~$64.60~~$63.17 per share, which was the closing price of Entergy Corporation’s common stock on that date. One-third of the restricted stock awards will vest upon each anniversary of the grant date and are expensed

The following table includes financial information for restricted stock for each of the years presented:

Entergy grants long-term incentive awards earned under its stock benefit plans in the form of performance units, which are equal to the cash value of shares of Entergy Corporation common stock at the end of the performance period, which is the last trading day of the year. Performance units will pay out to the extent that the performance conditions are satisfied. In addition to the potential for equivalent share appreciation or depreciation, performance units will earn the cash equivalent of the dividends paid during the 3~~-year~~3-year performance period applicable to each plan. The costs of incentive awards are charged to income over the 3~~-year~~3-year period. Beginning with the 2012-2014 performance period, upon vesting, the performance units granted under the Long-Term Performance Unit Program will be settled in shares of Entergy common stock rather than cash. In January ~~2013~~2014 the Board approved and Entergy granted ~~201,474~~226,792 performance units under the 2011 Equity Ownership and Long-Term Cash Incentive Plan. The performance units were made effective as of January ~~31, 2013,~~30, 2014, and were valued at ~~$65.36~~$67.16 per share. Entergy considers factors, primarily market conditions, in determining the value of the performance units. Shares of the performance units have the same dividend and voting rights as other common stock, are considered issued and outstanding shares of Entergy upon vesting, and are expensed ratably over the 3~~-year~~3-year vesting period.

The following table includes financial information for the long-term performance units for each of the years presented:

Entergy grants restricted unit awards earned under its stock benefit plans in the form of stock units that are subject to time-based restrictions. The restricted units are equal to the cash value of shares of Entergy Corporation common stock at the time of vesting. The costs of restricted unit awards are charged to income over the restricted period, which varies from grant to grant. The average vesting period for restricted unit awards granted is 36 ~~months~~.months. As of December 31, ~~2013~~,2014, there were ~~85,335~~98,334 unvested restricted units that are expected to vest over an average period of 1721 months.

The following table includes financial information for restricted unit awards for each of the years presented:

Entergy’s reportable segments as of December 31, ~~2013~~2014 are Utility and Entergy Wholesale Commodities. Utility includes the generation, transmission, distribution, and sale of electric power in portions of Arkansas, Louisiana, Mississippi, and Texas, and natural gas utility service in portions of Louisiana. Entergy Wholesale Commodities includes the ownership, operation, and ~~operation~~decommissioning of~~six~~ nuclear power plants located in the northern United States and the sale of the electric power produced by ~~those~~its operating plants to wholesale customers. Entergy Wholesale Commodities also includes the ownership of interests in non-nuclear power plants that sell the electric power produced by those plants to wholesale customers. “All Other” includes the parent company, Entergy Corporation, and other business activity.

~~In the fourth quarter 2012, Entergy moved~~ ~~two~~ ~~subsidiaries from All Other to the Entergy Wholesale Commodities~~Entergy’s segment ~~to improve the alignment of certain intercompany items and income tax activity.~~ financial information is as follows:

Earnings were negatively affected by expenses in 2013 ~~by expenses~~ of approximately ~~$110~~$110 million ($ ($70 million after-tax), including approximately ~~$85~~$85 million ($ ($55 million after-tax) for Utility and ~~$25~~$25 million ($ ($15 million after-tax) for Entergy Wholesale Commodities, and expenses in 2014 of approximately $20 million ($12 million after-tax), including approximately $15 million ($9 million after-tax) for Utility and $5 million ($3 million after-tax) for Entergy Wholesale Commodities, recorded in connection with a strategic imperative intended to optimize the organization through a process known as human capital management. In July 2013 management completed a comprehensive review of Entergy’s organization design and processes. This effort resulted in a new internal organization structure, which resulted in the elimination of approximately 800 employee positions. The restructuring costs associated with this phase of human capital management included implementation costs, severance expenses, benefits-related costs, including pension curtailment losses and special termination benefits, and impairments of corporate property, plant, and equipment. The implementation costs, severance costs, and benefits-related costs are included in ~~"Other~~“Other operation and ~~maintenance"~~maintenance” in the consolidated income statements. The property, plant, and equipment impairments are included in ~~"Asset impairment~~“Asset write-offs, impairments, and related ~~charges"~~charges” in the consolidated income statements. Total restructuring charges ~~in 2013~~ were comprised of the following:

For the years ended December 31, 2014, 2013,, ~~2012~~, and ~~2011~~,2012, the amount of revenue Entergy derived from outside of the United States was insignificant. As of December 31, ~~2013~~2014 and ~~2012~~,2013, Entergy had no long-lived assets located outside of the United States.

Each of the Registrant Subsidiaries has one reportable segment, which is an integrated utility business, except for System Energy, which is an electricity generation business. Each of the Registrant Subsidiaries’ operations is managed on an integrated basis by that company because of the substantial effect of cost-based rates and regulatory oversight on the business process, cost structures, and operating results.

As of December 31, ~~2013~~,2014, Entergy owns investments in the following companies that it accounts for under the equity method of accounting:

Following is a reconciliation of Entergy’s investments in equity affiliates:

Entergy Gulf States Louisiana purchased approximately ~~$3.2~~$3.2 million, ~~$2.8~~ in 2013 and $2.8 million~~, and~~ ~~$41.1 million~~ in 2012 of electricity generated from Entergy’s share of RS ~~Cogen~~Cogen. Entergy Gulf States Louisiana made no purchases in ~~2013~~, ~~2012, and~~ ~~2011, respectively.~~2014 of electricity generated from Entergy’s share of RS Cogen. Entergy’s operating transactions with its other equity method investees were not significant in 2014, 2013,, ~~2012~~, or ~~2011~~.2012.

In November 2012, Entergy Arkansas purchased the Hot Spring Energy Facility, a 620 MW combined-cycle natural gas turbine unit located in Malvern, Arkansas, from KGen Hot Spring LLC for approximately ~~$253 million~~.$253 million. The FERC and the APSC approved the transaction.

In November 2012, Entergy Mississippi purchased the Hinds Energy Facility, a 450 MW combined-cycle natural gas turbine unit located in Jackson, Mississippi, from KGen Hinds LLC for approximately ~~$206 million~~.$206 million. The FERC and the MPSC approved the transaction.

Entergy’s purchase of the Palisades plant in 2007 included a unit-contingent, 15~~-year~~15-year purchased power agreement (PPA) with Consumers Energy for 100% of the plant’s output, excluding any future uprates. Prices under the PPA range from ~~$43.50~~/$43.50/MWh in 2007 to ~~$61.50~~/$61.50/MWh in 2022, and the average price under the PPA is ~~$51~~/$51/MWh. For the PPA, which was at below-market prices at the time of the acquisition, Entergy will amortize a liability to revenue over the life of the agreement. The amount that will be amortized each period is based upon the difference between the present value calculated at the date of acquisition of each year’s difference between revenue under the agreement and revenue based on estimated market prices. Amounts amortized to revenue were ~~$18~~$16 million in ~~2013~~, ~~$17~~2014, $18 million in ~~2012~~,2013, and ~~$43~~$17 million in ~~2011~~.2012. The amounts to be amortized to revenue for the next five years will be ~~$16~~$15 million in ~~2014~~, ~~$15~~2015, $13 million for ~~2015~~, ~~$13~~2016, $12 million for ~~2016~~, ~~$12~~2017, $8 million for ~~2017~~,2018, and $8$13 million for ~~2018~~.2019.

Entergy’s purchase of the FitzPatrick and Indian Point 3 plants from NYPA included value sharing agreements with NYPA. In October 2007, Entergy subsidiaries and NYPA amended and restated the value sharing agreements to clarify and amend certain provisions of the original terms. Under the amended value sharing agreements, Entergy subsidiaries ~~will make~~made 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~~paid NYPA ~~$6.59~~$6.59 per MWh for power sold from Indian Point 3, up to an annual cap of ~~$48~~$48 million,, and ~~$3.91~~$3.91 per MWh for power sold from FitzPatrick, up to an annual cap of ~~$24 million~~.$24 million. The annual payment for each year’s output iswas due by January 15 of the following year. Entergy ~~will record~~recorded the liability for payments to NYPA as power is generated and sold by Indian Point 3 and FitzPatrick. An amount equal to the liability ~~will be~~was recorded to the plant asset account as contingent purchase price consideration for the plants. In 2014, 2013,, ~~2012~~, and ~~2011~~,2012, Entergy Wholesale Commodities recorded approximately ~~$72~~$72 million as plant for generation during each of those years. This amount ~~will be~~was depreciated over the expected remaining useful life of the plants.

In November 2013, Entergy sold Entergy Solutions District Energy, a business wholly-owned by Entergy in the Entergy Wholesale Commodities segment that owns and operates district energy assets serving the business districts in Houston and New Orleans. Entergy sold Entergy Solutions District Energy for ~~$140~~$140 million and realized a pre-tax gain of ~~$44~~$44 million on the sale.

In the normal course of business, Entergy is exposed to a number of market risks. Market risk is the potential loss that Entergy may incur as a result of changes in the market or fair value of a particular ~~instrument~~commodity or ~~commodity.~~instrument. All financial and commodity-related instruments, including derivatives, are subject to market risk including commodity price risk, equity price, and interest rate risk. Entergy uses derivatives primarily to mitigate commodity price risk, particularly power price and fuel price risk.

The Utility 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 regulators, the Utility operating companies use derivative instruments to hedge the exposure to price volatility inherent in their purchased power, fuel, and gas purchased for resale costs that are recovered from customers.

As a wholesale generator, Entergy Wholesale ~~Commodities’s~~Commodities’ core business is selling energy, measured in MWh, to its customers. Entergy Wholesale Commodities enters into forward contracts with its customers and also sells energy and capacity in the day ahead or spot markets. In addition to its forward physical power contracts, Entergy Wholesale Commodities also uses a combination of financial contracts, including swaps, collars, ~~put and/or call~~and options, to mitigate ~~forward~~ commodity price risk. When the market price falls, the combination of instruments is expected to settle in gains ~~offsetting~~that offset lower revenue from generation, ~~and resulting~~which results in a more predictable cash flow.

Entergy’s exposure to market risk is determined by a number of factors, including the size, term, composition, and diversification of positions held, as well as market volatility and liquidity. For instruments such as options, the time period during which the option may be exercised and the relationship between the current market price of the underlying instrument and the option’s contractual strike or exercise price also affects the level of market risk. A significant factor influencing the overall level of market risk to which Entergy is exposed is its use of hedging techniques to mitigate such risk. Hedging instruments and volumes are chosen based on ability to mitigate risk associated with future energy and capacity prices; however, other considerations are factored into hedge product and volume decisions including corporate liquidity, corporate credit ratings, counterparty credit risk, hedging costs, firm settlement risk, and product availability in the marketplace. Entergy manages market risk by actively monitoring compliance with stated risk management policies as well as monitoring the effectiveness of its hedging policies and strategies. Entergy’s risk management policies limit the amount of total net exposure and rolling net exposure during the stated periods. These policies, including related risk limits, are regularly assessed to ensure their appropriateness given Entergy’s objectives.

Some derivative instruments are classified as cash flow hedges due to their financial settlement provisions while others are classified as normal purchase/normal sale transactions due to their physical settlement provisions. Normal purchase/normal sale risk management tools include power purchase and sales agreements, fuel purchase agreements, capacity contracts, and tolling agreements. Financially-settled cash flow hedges can include

Entergy enters into derivatives ~~only~~ to manage natural risks inherent in its physical or financial assets or liabilities. Electricity over-the-counter instruments that financially settle against day-ahead power pool prices are used to manage price exposure for Entergy Wholesale Commodities generation. The maximum length of time over which Entergy is currently hedging the variability in future cash flows with derivatives for forecasted power transactions at December 31, ~~2013~~2014 is approximately 3 years. Planned generation currently under contract from Entergy Wholesale Commodities nuclear power plants is ~~74%~~86% for ~~2014~~,2015, of which approximately 62% is sold under financial derivatives and the remainder under normal purchase/normal sale contracts. Total planned generation for ~~2014~~2015 is 3935 TWh.

Entergy may use standardized master netting agreements to help mitigate the credit risk of derivative instruments. These master agreements facilitate the netting of cash flows associated with a single counterparty and may include collateral requirements. Cash, letters of credit and parental/affiliate guarantees may be obtained as security from counterparties in order to mitigate credit risk. The collateral agreements require a counterparty to post cash or letters of credit in the event an exposure exceeds an established threshold. The threshold represents an unsecured credit limit, which may be supported by a parental/affiliate guaranty, as determined in accordance with Entergy’s credit policy. In addition, collateral agreements allow for termination and liquidation of all positions in the event of a failure or inability to post collateral.

Certain 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 when the current market prices exceed the contracted power prices. The primary form of collateral to satisfy these requirements is an Entergy Corporation guarantee. As of December 31, 2014, derivative contracts with 1 counterparty were in a liability position (approximately $1 million total). As of December 31, 2013, derivative contracts with 9 counterparties were in a liability position (approximately $187 million total). In addition to the corporate guarantee, $47 million in cash collateral was required to be posted. If the Entergy Corporation credit rating falls below investment grade, the effect of the corporate guarantee is typically ignored and Entergy would have to post collateral equal to the estimated outstanding liability under the contract at the applicable date.

Entergy manages fuel price volatility for its Louisiana jurisdictions (Entergy Gulf States Louisiana, Entergy Louisiana, and Entergy New Orleans) and Entergy Mississippi ~~primarily~~ through the purchase of short-term natural gas swaps that financially settle against NYMEX futures. These swaps are marked-to-market through fuel expense with offsetting regulatory assets or liabilities. All benefits or costs of the program are recorded in fuel costs. The notional volumes of these swaps are based on a portion of projected annual exposure to gas for electric generation and projected winter purchases for gas distribution at Entergy Gulf States Louisiana and Entergy New Orleans. The total volume of natural gas swaps outstanding as of December 31, ~~2013~~2014 is ~~27,480,000~~21,475,000 MMBtu for Entergy, including ~~10,340,000~~8,740,000 MMBtu for Entergy Gulf States Louisiana, ~~13,050,000~~8,810,000 MMBtu for Entergy Louisiana, ~~3,590,000~~3,230,000 MMBtu for Entergy Mississippi, and ~~500,000~~695,000 MMBtu for Entergy New Orleans. Credit support for these natural gas swaps is covered by master agreements that do not require collateralization based on mark-to-market value, but do carry adequate assurance language that may lead to collateralization requests.

~~In connection with joining~~During the second quarter 2014, Entergy participated in the annual FTR auction process for the MISO ~~Entergy received a direct allocation~~planning year of ~~FTRs in November 2013.~~June 1, 2014 through May 31, 2015. FTRs are derivative instruments which represent economic hedges of future congestion charges that will be incurred in serving Entergy’s customer load. They are not designated as hedging instruments. Entergy initially records FTRs at their estimated fair value and subsequently adjusts the carrying value to their estimated fair value at the end of each accounting period

The fair values of Entergy’s derivative instruments in the consolidated balance sheet as of December 31, ~~2013~~2014 are shown in the table below. Certain investments, including those not designated as hedging instruments, are subject to master netting ~~arrangements~~agreements and are presented in the balance sheet on a net basis in accordance with accounting guidance for derivatives and hedging.

The fair values of Entergy’s derivative instruments in the consolidated balance sheet as of December 31, ~~2012~~2013 are shown in the table below. Certain investments, including those not designated as hedging instruments, are subject to master netting ~~arrangements~~agreements and are presented in the balance sheet on a net basis in accordance with accounting guidance for derivatives and hedging.

The effect of Entergy’s derivative instruments designated as cash flow hedges on the consolidated income statements for the years ended December 31, 2014, 2013,, ~~2012~~, and ~~2011~~2012 are as follows:

Entergy may effectively liquidate a cash flow hedge instrument by entering into a contract offsetting the original hedge, and then de-designating the original hedge in this situation. Gains or losses accumulated in other comprehensive income prior to de-designation continue to be deferred in other comprehensive income until they are included in income as the original hedged transaction occurs. From the point of de-designation, the gains or losses on the original hedge

The effect of Entergy’s derivative instruments not designated as hedging instruments on the consolidated income statements for the years ended December 31, 2014, 2013,, ~~2012~~, and ~~2011~~2012 is as follows:

The fair values of the Registrant Subsidiaries’ derivative instruments not designated as hedging instruments on their balance sheets as of December 31, ~~2013~~2014 and ~~2012~~2013 are as follows:

The effects of the Registrant Subsidiaries’ derivative instruments not designated as hedging instruments on their income statements for the years ended December 31, 2014, 2013,, ~~2012~~, and ~~2011~~2012 are as follows:

The estimated fair values of Entergy’s financial instruments and derivatives are determined using historical prices, bid prices, market quotes, and financial modeling. Considerable judgment is required in developing the estimates of fair value. Therefore, estimates are not necessarily indicative of the amounts that Entergy could realize in a current market exchange. Gains or losses realized on financial instruments other than those instruments held by the Entergy Wholesale Commodities business are reflected in future rates and therefore do not affect net income. Entergy considers the carrying amounts of most financial instruments classified as current assets and liabilities to be a reasonable estimate of their fair value because of the short maturity of these instruments.

Accounting standards define fair value as an exit price, or the price that would be received to sell an asset or the amount that would be paid to transfer a liability in an orderly transaction between knowledgeable market participants at the date of measurement. Entergy and the Registrant Subsidiaries use assumptions or market input data that market participants would use in pricing assets or liabilities at fair value. The inputs can be readily observable, corroborated by market data, or generally unobservable. Entergy and the Registrant Subsidiaries endeavor to use the best available information to determine fair value.

Accounting standards establish a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy establishes the highest priority for unadjusted market quotes in an active market for the identical asset or liability and the lowest priority for unobservable inputs. The three levels of the fair value hierarchy are:

The values for power contract assets or liabilities are based on both observable inputs including public market prices and interest rates, and unobservable inputs such as implied volatilities, unit contingent discounts, expected basis differences, and credit adjusted counterparty interest rates. They are classified as Level 3 assets and liabilities. The

The amounts reflected as the fair value of electricity swaps are based on the estimated amount that the contracts are in-the-money at the balance sheet date (treated as an asset) or out-of-the-money at the balance sheet date (treated as a liability) and would equal the estimated amount receivable to or payable by Entergy if the contracts were settled at that date. These derivative contracts include cash flow hedges that swap fixed for floating cash flows for sales of the output from the Entergy Wholesale Commodities business. The fair values are based on the mark-to-market comparison between the fixed contract prices and the floating prices determined each period from quoted forward power market prices. The differences between the fixed price in the swap contract and these market-related prices multiplied by the volume specified in the contract and discounted at the counterparties’ credit adjusted risk free rate are recorded as derivative contract assets or liabilities. For contracts that have unit contingent terms, a further discount is applied based on the historical relationship between contract and market prices for similar contract terms.

The amounts reflected as the fair values of electricity options are valued based on a Black Scholes model, and are calculated at the end of each month for accounting purposes. Inputs to the valuation include end of day forward market prices for the period when the transactions will settle, implied volatilities based on market volatilities provided by a third party data aggregator, and US Treasury rates for a risk-free return rate. As described further below, prices and implied volatilities are reviewed and can be adjusted if it is determined that there is a better representation of fair value.

On a daily basis, Entergy Wholesale Commodities ~~calculated~~Risk Control group calculates the mark-to-market for ~~all derivative transactions.~~electricity swaps and options. Entergy Wholesale Commodities Risk Control ~~Group~~group also ~~validated~~validates forward market prices by comparing them to other sources of forward market prices ~~and/~~or to settlement prices of actual market transactions. Significant differences ~~were~~are analyzed and potentially adjusted based on these other sources of forward market prices ~~and/~~or settlement prices of actual market transactions. Implied volatilities used to value options ~~were~~are also validated using actual counterparty quotes for Entergy Wholesale Commodities transactions when available, and ~~used~~uses multiple sources of market implied volatilities. Moreover, on at least a monthly basis, the Office of Corporate Risk Oversight ~~confirmed~~confirms the mark-to-market calculations and ~~prepared~~prepares price scenarios and credit downgrade scenario analysis. The scenario analysis ~~was~~is communicated to senior management within Entergy and within Entergy Wholesale Commodities. Finally, for all proposed derivative transactions, an analysis ~~was~~is completed to assess the risk of adding the proposed derivative to Entergy Wholesale ~~Commodities’s~~Commodities’ portfolio. In particular, the credit and liquidity ~~and financial metrics impacts were~~effects are calculated for this analysis. This analysis ~~was~~is communicated to senior management within Entergy and Entergy Wholesale Commodities.

The values of FTRs are based on unobservable inputs, including estimates of future congestion costs in MISO between applicable ~~sink~~generation and ~~source~~load pricing nodes based on prices published by MISO. They are classified as Level 3 assets and liabilities. The valuations of these assets and liabilities are performed by the Entergy Wholesale Commodities Risk Control group for the unregulated business and by the System Planning and Operations Risk Control group for the Utility operating companies. Entergy’s Accounting Policy group reviews these valuations for reasonableness, with the assistance of others within the organization with knowledge of the various inputs and

The following tables set forth, by level within the fair value hierarchy, Entergy’s assets and liabilities that are accounted for at fair value on a recurring basis as of December 31, ~~2013~~2014 and December 31, ~~2012~~.2013. The assessment of the significance of a particular input to a fair value measurement requires judgment and may affect their placement within the fair value hierarchy levels.

The following table sets forth a reconciliation of changes in the net assets (liabilities) for the fair value of derivatives classified as Level 3 in the fair value hierarchy for the years ended December 31, 2014, 2013,, ~~2012~~, and ~~2011~~:

The following table sets forth a description of the types of transactions classified as Level 3 in the fair value hierarchy and significant unobservable inputs to each which cause that classification, as of December 31, ~~2013~~:2014:

The following table sets forth an analysis of each of the types of unobservable inputs impacting the fair value of items classified as Level 3 within the fair value hierarchy, and the sensitivity to changes to those inputs:

The following table sets forth, by level within the fair value hierarchy, the Registrant Subsidiaries’ assets that are accounted for at fair value on a recurring basis as of December 31, ~~2013~~2014 and December 31, ~~2012~~.2013. The assessment of the significance of a particular input to a fair value measurement requires judgment and may affect its placement within the fair value hierarchy levels.

The following table sets forth a reconciliation of changes in the net assets (liabilities) for the fair value of derivatives classified as Level 3 in the fair value hierarchy for the year ended December 31, ~~2013~~.2014.

The following table sets forth a reconciliation of changes in the net assets (liabilities) for the fair value of derivatives classified as Level 3 in the fair value hierarchy for the year ended December 31, 2013.

Entergy holds debt and equity securities, classified as available-for-sale, in nuclear decommissioning trust accounts. The NRC requires Entergy subsidiaries to maintain trusts to fund the costs of decommissioning ANO 1, ANO 2, River Bend, Waterford 3, Grand Gulf, Pilgrim, Indian Point 1 and 2, Vermont Yankee, and Palisades (NYPA currently retains the decommissioning trusts and liabilities for Indian Point 3 and FitzPatrick). The funds are invested primarily in equity securities, fixed-rate debt securities, and cash and cash equivalents.

Entergy records decommissioning trust funds on the balance sheet at their fair value. Because of the ability of the Registrant Subsidiaries to recover decommissioning costs in rates and in accordance with the regulatory treatment for decommissioning trust funds, the Registrant Subsidiaries have recorded an offsetting amount of unrealized gains/(losses) on investment securities in other regulatory liabilities/assets. For the ~~nonregulated portion of~~30% interest in River Bend formerly owned by Cajun, Entergy Gulf States Louisiana has recorded an offsetting amount of unrealized gains/(losses) in other deferred credits. Decommissioning trust funds for Pilgrim, Indian Point 1 and 2, Vermont Yankee, and Palisades do not meet the criteria for regulatory accounting treatment. Accordingly, unrealized gains recorded on the assets in these trust funds are recognized in the accumulated other comprehensive income component of shareholders’ equity because these assets are classified as available for sale. Unrealized losses (where cost exceeds fair market value) on the assets in these trust funds are also recorded in the accumulated other comprehensive income component of shareholders’ equity unless the unrealized loss is other than temporary and therefore recorded in earnings. Generally, Entergy records

The securities held as of December 31, ~~2013~~2014 and ~~2012~~2013 are summarized as follows:

The fair value and gross unrealized losses of available-for-sale equity and debt securities, summarized by investment type and length of time that the securities have been in a continuous loss position, are as follows as of December 31, ~~2013~~:2014:

The fair value and gross unrealized losses of available-for-sale equity and debt securities, summarized by investment type and length of time that the securities have been in a continuous loss position, are as follows as of December 31, ~~2012~~:2013:

The fair value of debt securities, summarized by contractual maturities, as of December 31, ~~2013~~2014 and ~~2012~~2013 are as follows:

During the years ended December 31, 2014, 2013,, ~~2012~~, and ~~2011~~,2012, proceeds from the dispositions of securities amounted to ~~$2,032~~$1,872 million,, ~~$2,074~~ $2,032 million,, and ~~$1,360~~$2,074 million,, respectively. During the years ended December 31, 2014, 2013,, ~~2012~~, and ~~2011~~,2012, gross gains of ~~$91~~$39 million,, ~~$39~~ $91 million,, and ~~$29~~$39 million,, respectively, and gross losses of ~~$11~~$8 million,, $7 $11 million,, and ~~$11~~$7 million,, respectively, were reclassified out of other comprehensive income into earnings.

Entergy Arkansas holds debt and equity securities, classified as available-for-sale, in nuclear decommissioning trust accounts. The securities held as of December 31, ~~2013~~2014 and ~~2012~~2013 are summarized as follows:

The fair value and gross unrealized losses of available-for-sale equity and debt securities, summarized by investment type and length of time that the securities have been in a continuous loss position, are as follows as of December 31, ~~2013~~:2014:

The fair value and gross unrealized losses of available-for-sale equity and debt securities, summarized by investment type and length of time that the securities have been in a continuous loss position, are as follows as of December 31, ~~2012~~:2013:

The fair value of debt securities, summarized by contractual maturities, as of December 31, ~~2013~~2014 and ~~2012~~2013 are as follows:

During the years ended December 31, 2014, 2013,, ~~2012~~, and ~~2011~~,2012, proceeds from the dispositions of securities amounted to ~~$266.4~~$181.5 million,, ~~$144.3~~ $266.4 million,, and ~~$125.4~~$144.3 million,, respectively. During the years ended December 31, 2014, 2013,, ~~2012~~, and ~~2011~~,2012, gross gains of ~~$16.8~~$8.7 million,, ~~$3.4~~ $16.8 million,, and ~~$3.9~~$3.4 million,, respectively, and gross losses of ~~$0.6~~$0.3 million,, ~~$0.1~~ $0.6 million,, and ~~$0.2~~$0.1 million,, respectively, were recorded in earnings.

Entergy Gulf States Louisiana holds debt and equity securities, classified as available-for-sale, in nuclear decommissioning trust accounts. The securities held as of December 31, ~~2013~~2014 and ~~2012~~2013 are summarized as follows:

The fair value and gross unrealized losses of available-for-sale equity and debt securities, summarized by investment type and length of time that the securities have been in a continuous loss position, are as follows as of December 31, ~~2013~~:2014:

The fair value and gross unrealized losses of available-for-sale equity and debt securities, summarized by investment type and length of time that the securities have been in a continuous loss position, are as follows as of December 31, ~~2012~~:2013:

During the years ended December 31, 2014, 2013,, ~~2012~~, and ~~2011~~,2012, proceeds from the dispositions of securities amounted to ~~$193.8~~$173.5 million,, ~~$131.0~~ $193.8 million,, and ~~$76.8~~$131.0 million,, respectively. During the years ended December 31, 2014, 2013,, ~~2012~~, and ~~2011~~,2012, gross gains of ~~$16.0~~$1.9 million,, ~~$6.7~~ $16.0 million,, and ~~$2.8~~$6.7 million,, respectively, and gross losses of ~~$0.1~~$0.3 million,, ~~$0.04~~ $0.1 million,, and ~~$0.5~~$0.04 million,, respectively, were recorded in earnings.

Entergy Louisiana holds debt and equity securities, classified as available-for-sale, in nuclear decommissioning trust accounts. The securities held as of December 31, ~~2013~~2014 and ~~2012~~2013 are summarized as follows:

The fair value and gross unrealized losses of available-for-sale equity and debt securities, summarized by investment type and length of time that the securities have been in a continuous loss position, are as follows as of December 31, ~~2013~~:

The fair value and gross unrealized losses of available-for-sale equity and debt securities, summarized by investment type and length of time that the securities have been in a continuous loss position, are as follows as of December 31, ~~2012~~:2013:

The fair value of debt securities, summarized by contractual maturities, as of December 31, ~~2013~~2014 and ~~2012~~2013 are as follows:

During the years ended December 31, 2014, 2013,, ~~2012~~, and ~~2011~~,2012, proceeds from the dispositions of securities amounted to ~~$109.9~~$43.2 million,, ~~$27.6~~ $109.9 million,, and ~~$19.9~~$27.6 million,, respectively. During the years ended December 31, 2014, 2013,, ~~2012~~, and ~~2011~~,2012, gross gains of ~~$6.0~~$0.3 million,, ~~$0.2~~ $6.0 million,, and ~~$0.3~~$0.2 million,, respectively, and gross losses of ~~$0.1~~$0.02 million,, ~~$0.04~~ $0.1 million,, and ~~$0.2~~$0.04 million,, respectively, were recorded in earnings.

System Energy holds debt and equity securities, classified as available-for-sale, in nuclear decommissioning trust accounts. The securities held as of December 31, ~~2013~~2014 and ~~2012~~2013 are summarized as follows:

The fair value and gross unrealized losses of available-for-sale equity and debt securities, summarized by investment type and length of time that the securities have been in a continuous loss position, are as follows as of December 31, ~~2013~~:2014:

The fair value and gross unrealized losses of available-for-sale equity and debt securities, summarized by investment type and length of time that the securities have been in a continuous loss position, are as follows as of December 31, ~~2012~~:2013:

The fair value of debt securities, summarized by contractual maturities, as of December 31, ~~2013~~2014 and ~~2012~~2013 are as follows:

During the years ended December 31, 2014, 2013,, ~~2012~~, and ~~2011~~,2012, proceeds from the dispositions of securities amounted to ~~$215.5~~$392.9 million,, ~~$349.4~~ $215.5 million,, and ~~$203.4~~$349.4 million,, respectively. During the years ended December 31, 2014, 2013,, ~~2012~~, and ~~2011~~,2012, gross gains of ~~$1.5~~$1.8 million,, ~~$3.6~~ $1.5 million,, and ~~$2.7~~$3.6 million,, respectively, and gross losses of ~~$1.3~~$0.9 million,, ~~$0.3~~ $1.3 million,, and ~~$1.2~~$0.3 million,, respectively, were recorded in earnings.

Entergy, Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, and System Energy evaluate unrealized losses at the end of each period to determine whether an other-than-temporary impairment has occurred. 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

Under applicable authoritative accounting guidance, a variable interest entity (VIE) is an entity that conducts a business or holds property that possesses any of the following characteristics: an insufficient amount of equity at risk to finance its activities, equity owners who do not have the power to direct the significant activities of the entity (or have voting rights that are disproportionate to their ownership interest), or where equity holders do not receive expected losses or returns. An entity may have an interest in a VIE through ownership or other contractual rights or obligations, and is required to consolidate a VIE if it is the VIE’s primary beneficiary. The primary beneficiary of a VIE is the entity that has the power to direct the activities of the VIE that most significantly affect the VIE’s economic performance, and has the obligation to absorb losses or has the right to residual returns that would potentially be significant to the entity.

Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, and System Energy consolidate the respective companies from which they lease nuclear fuel, usually in a sale and leaseback transaction. This is because Entergy directs the nuclear fuel companies with respect to nuclear fuel purchases, assists the nuclear fuel companies in obtaining financing, and, if financing cannot be arranged, the lessee (Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, or System Energy) is responsible to repurchase nuclear fuel to allow the nuclear fuel company (the VIE) to meet its obligations. During the term of the arrangements, none of the Entergy operating companies have been required to provide financial support apart from their scheduled lease payments. See Note 4 to the financial statements for details of the nuclear fuel companies’ credit facility and commercial paper borrowings and long-term debt that are reported by Entergy, Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, and System Energy. These amounts also represent Entergy’s and the respective Registrant Subsidiary’s maximum exposure to losses associated with their respective interests in the nuclear fuel companies.

Entergy Gulf States Reconstruction Funding I, LLC, and Entergy Texas Restoration Funding, LLC, companies wholly-owned and consolidated by Entergy Texas, are variable interest entities and Entergy Texas is the primary beneficiary. In June 2007, Entergy Gulf States Reconstruction Funding issued senior secured transition bonds (securitization bonds) to finance Entergy Texas’s Hurricane Rita reconstruction costs. In November 2009, Entergy Texas Restoration Funding issued senior secured transition bonds (securitization bonds) to finance Entergy Texas’s Hurricane Ike and Hurricane Gustav restoration costs. With the proceeds, the variable interest entities purchased from Entergy Texas the transition property, which is the right to recover from customers through a transition charge amounts sufficient to service the securitization bonds. The transition property is reflected as a regulatory asset on the consolidated Entergy Texas balance sheet. The creditors of Entergy Texas do not have recourse to the assets or revenues of the variable interest entities, including the transition property, and the creditors of the variable interest entities do not have recourse to the assets or revenues of Entergy Texas. Entergy Texas has no payment obligations to the variable interest entities except to remit transition charge collections. See Note 5 to the financial statements for additional details regarding the securitization bonds.

Entergy Arkansas Restoration Funding, LLC, a company wholly-owned and consolidated by Entergy Arkansas, is a variable interest entity and Entergy Arkansas is the primary beneficiary. In August 2010, Entergy Arkansas Restoration Funding issued storm cost recovery bonds to finance Entergy Arkansas’s January 2009 ice storm damage restoration costs. With the proceeds, Entergy Arkansas Restoration Funding purchased from Entergy Arkansas the storm recovery property, which is the right to recover from customers through a storm recovery charge amounts sufficient to service the securitization bonds. The storm recovery property is reflected as a regulatory asset on the consolidated Entergy Arkansas balance sheet. The creditors of Entergy Arkansas do not have recourse to the assets or revenues of Entergy Arkansas Restoration Funding, including the storm recovery property, and the creditors of Entergy Arkansas Restoration Funding do not have recourse to the assets or revenues of Entergy Arkansas. Entergy Arkansas has no payment obligations to Entergy Arkansas Restoration Funding except to remit storm recovery charge collections. See Note 5 to the financial statements for additional details regarding the storm cost recovery bonds.

Entergy Louisiana Investment Recovery Funding I, L.L.C., a company wholly-owned and consolidated by Entergy Louisiana, is a variable interest entity and Entergy Louisiana is the primary beneficiary.In September 2011, Entergy Louisiana Investment Recovery Funding issued investment recovery bonds to recover Entergy Louisiana’s investment recovery costs associated with the canceled Little Gypsy repowering project. With the proceeds, Entergy Louisiana Investment Recovery Funding purchased from Entergy Louisiana the investment recovery property, which is the right to recover from customers through an investment recovery charge amounts sufficient to service the bonds.The investment recovery property is reflected as a regulatory asset on the consolidated Entergy Louisiana balance sheet. The creditors of Entergy Louisiana do not have recourse to the assets or revenues of Entergy Louisiana Investment Recovery Funding, including the investment recovery property, and the creditors of Entergy Louisiana Investment Recovery Funding do not have recourse to the assets or revenues of Entergy Louisiana. Entergy Louisiana has no payment obligations to Entergy Louisiana Investment Recovery Funding except to remit investment recovery charge collections. See Note 5 to the financial statements for additional details regarding the investment recovery bonds.

Entergy Louisiana and System Energy are also considered to each hold a variable interest in the lessors from which they lease undivided interests in the Waterford 3 and Grand Gulf nuclear plants, respectively. Entergy Louisiana and System Energy are the lessees under these arrangements, which are described in more detail in Note 10 to the financial statements. Entergy Louisiana made payments on its lease, including interest, of ~~$26.3~~$31.0 million in ~~2013~~, ~~$39.1~~2014, $26.3 million in ~~2012~~,2013, and ~~$50.4~~$39.1 million in ~~2011~~.2012. System Energy made payments on its lease, including interest, of ~~$50.5~~$51.6 million in ~~2013~~, ~~$50.0~~2014, $50.5 million in ~~2012~~,2013, and ~~$49.4~~$50.0 million in ~~2011~~.2012. The lessors are banks acting in the capacity of owner trustee for the benefit of equity investors in the transactions pursuant to trust agreements entered solely for the purpose of facilitating the lease transactions. It is possible that Entergy Louisiana and System Energy may be considered as the primary beneficiary of the lessors, but Entergy is unable to apply the authoritative accounting guidance with respect to these VIEs because the lessors are not required to, and could not, provide the necessary financial information to consolidate the lessors. Because Entergy accounts for these leasing arrangements as capital financings, however, Entergy believes that consolidating the lessors would not materially affect the financial statements. In the unlikely event of default under a lease, remedies available to the lessor include payment by the lessee of the fair value of the undivided interest in the plant, payment of the present value of the basic rent payments, or payment of a predetermined casualty value. Entergy believes, however, that the obligations recorded on the balance sheets materially represent each company’s potential exposure to loss.

Entergy has also reviewed various lease arrangements, power purchase agreements, and other agreements in which it holds a variable interest. In these cases, Entergy has determined that it is not the primary beneficiary of the related VIE because it does not have the power to direct the activities of the VIE that most significantly affect the VIE’s economic performance, or it does not have the obligation to absorb losses or the right to residual returns that would potentially be significant to the entity, or both.

Each Registrant Subsidiary purchases electricity from or sells electricity to the other Registrant Subsidiaries, or both, under rate schedules filed with FERC. The Registrant Subsidiaries receive management, technical, advisory, operating, and administrative services from Entergy Services; and receive management, technical, and operating services from Entergy ~~Operations; and until the first quarter 2011 purchased fuel from System Fuels.~~Operations. These transactions are on an “at cost” basis. In addition, Entergy Power ~~sells~~sold electricity to Entergy Arkansas, Entergy Louisiana, and Entergy New ~~Orleans.~~Orleans prior to the expiration of the contract in 2013. RS Cogen sells electricity to Entergy Gulf States Louisiana.

As described in Note 1 to the financial statements, all of System Energy’s operating revenues consist of billings to Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans.

As described in Note 4 to the financial statements, the Registrant Subsidiaries participate in Entergy’s money pool and earn interest income from the money pool. Entergy Arkansas, Entergy Mississippi, and Entergy New Orleans also received interest income from System Fuels until the first quarter 2011, when System Fuels repaid each company’s investment in System Fuels. As described in Note 2 to the financial statements, Entergy Gulf States Louisiana and Entergy Louisiana receive preferred membership distributions from Entergy Holdings Company.

The tables below contain the various affiliate transactions of the Utility operating companies, System Energy, and other Entergy affiliates.

Operating results for the four quarters of ~~2013~~2014 and ~~2012~~2013 for Entergy Corporation and subsidiaries were:

As discussed in more detail in Note 1 to the financial statements, operating results for ~~2013~~2014 include $154 million ($100 million after-tax) of charges related to Vermont Yankee primarily resulting from the effects of an updated decommissioning cost study completed in the third quarter 2014 along with reassessment of assumptions regarding the timing of decommissioning cash flows and ~~2012~~severance and employee retention costs. Results of operations for 2014 also include the $56.2 million ($36.7 million after-tax) write-off of Entergy Mississippi’s regulatory asset associated with new nuclear generation development costs as a ~~$321.5~~result of a joint stipulation entered into with the Mississippi Public Utilities Staff, subsequently approved by the MPSC, in which Entergy Mississippi agreed not to pursue recovery of

Results of operations for 2013 include $322 million (~~$202.2~~ ($202 million after-tax) ~~and~~ ~~$355.5 million~~ (~~$223.5 million~~ ~~after-tax), respectively,~~ of impairment and other related charges primarily to write down the carrying value of Vermont Yankee and related assets to their fair values. See Note 1 to the financial statements for further discussion of the charges. Also, as discussed in more detail in Note 13 to the financial statements, operating results include approximately ~~$110~~$110 million ($ ($70 million after-tax) in costs in 2013 associated with the human capital management strategic ~~initiative,~~imperative, primarily implementation costs, severance expenses, pension curtailment losses, and special termination benefits expense. In December 2013, Entergy deferred for future recovery approximately ~~$45~~$45 million ($ ($30 million after-tax) of these costs in the Arkansas and Louisiana jurisdictions, as approved by the APSC and the LPSC, respectively.

Entergy is an integrated energy company engaged primarily in electric power production and retail electric distribution operations. Entergy owns and operates power plants with approximately 30,000 MW of aggregate electric generating capacity, including ~~over~~nearly 10,000 MW of nuclear-fueled capacity. Entergy’s Utility business delivers electricity to 2.8 million utility customers in Arkansas, Louisiana, Mississippi, and Texas. Entergy generated annual revenues of ~~$11.4~~$12.5 billion in ~~2013~~2014 and had approximately ~~14,000~~13,000 employees as of December 31, ~~2013.~~2014.

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

Entergy’s mission is to operate a world-class energy business that creates sustainable value for its owners, customers, employees, and communities. Entergy aspires to achieve top quartile total shareholder returns in a socially and environmentally responsible fashion by leveraging the scale and expertise inherent in its core utility and nuclear operations. Entergy’s current scope includes electricity generation, transmission, and distribution as well as natural gas distribution. Entergy focuses on operational excellence with an emphasis on safety, reliability, customer service, sustainability, cost efficiency, risk management, and engaged employees. Entergy also continually seeks opportunities to grow its utility business to benefit all stakeholders and to optimize its portfolio of assets in an ever-dynamic market through periodic buy, build, hold, or disposal decisions. To accomplish this, Entergy has established strategic imperatives for each business segment. For the Utility, the strategic imperative is to grow the business by leveraging the industrial expansion underway in the Gulf region of the United States, and for Entergy Wholesale Commodities, the strategic imperative is to manage the risk and preserve value in the business.

The Utility business segment includes six wholly-owned retail electric utility subsidiaries: Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas. These companies generate, transmit, distribute and sell electric power to retail and wholesale customers in Arkansas, Louisiana, Mississippi, and Texas. Entergy Gulf States Louisiana and Entergy New Orleans also provide natural gas utility services to customers in and around Baton Rouge, Louisiana, and New Orleans, Louisiana, respectively. Also included in the Utility is System Energy, a wholly-owned subsidiary of Entergy Corporation that owns or leases 90 percent of Grand Gulf. System Energy sells its power and capacity from Grand Gulf at wholesale to Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans. The six retail utility subsidiaries are each regulated by the FERC and by state utility commissions, or, in the case of Entergy New Orleans, the City Council. System Energy is regulated by the FERC because all of its transactions are at wholesale. The overall generation portfolio of the Utility, which relies heavily on natural gas and nuclear generation, is consistent with Entergy’s strong support for the environment.

As of December 31, ~~2013~~,2014, the Utility operating companies provided retail electric and gas service to customers in Arkansas, Louisiana, Mississippi, and Texas, as follows:

The electric energy sales of the Utility operating companies are subject to seasonal fluctuations, with the peak sales period normally occurring during the third quarter of each year. On August ~~8, 2013,~~22, 2014, Entergy reached a ~~2013~~2014 peak demand of ~~21,581~~20,472 MWh, compared to the ~~2012~~2013 peak of ~~21,866~~21,581 MWh recorded on ~~July 30, 2012.~~August 8, 2013. Selected electric energy sales data is shown in the table below:

The following table illustrates the Utility operating companies’ 2014 combined electric sales volume as a percentage of total electric sales volume, and 2014 combined electric revenues as a percentage of total 2014 electric revenue, each by customer class.

Entergy New Orleans and Entergy Gulf States Louisiana provide both electric power and natural gas to retail customers. Entergy New Orleans and Entergy Gulf States Louisiana sold ~~10,436,919~~11,296,179 and ~~6,816,023~~7,933,968 Mcf, respectively, of natural gas to retail customers in ~~2013.~~2014. In ~~2013,~~2014, 97% of Entergy Gulf States Louisiana’s operating revenue was derived from the electric utility business, and only 3% from the natural gas distribution business. For Entergy New Orleans, ~~85%~~84% of operating revenue was derived from the electric utility business and ~~15%~~16% from the natural gas distribution business in ~~2013.~~ 2014.

Following is data concerning Entergy New Orleans’s ~~2013~~2014 retail operating revenue sources.

Each Utility operating company regularly participates in retail rate proceedings. The status of material retail rate proceedings is described in Note 2 to the financial statements. Certain aspects of the Utility operating companies’ retail rate mechanisms are discussed below.

Entergy Arkansas’s rate schedules include an energy cost recovery rider to recover fuel and purchased energy costs in monthly bills. The rider utilizes prior calendar year energy costs and projected energy sales for the twelve-month period commencing on April 1 of each year to develop an energy cost rate, which is redetermined annually and includes a true-up adjustment reflecting the over-recovery or under-recovery, including carrying charges, of the energy cost for the prior calendar year. The energy cost recovery rider tariff also allows an interim rate request depending

See Note 2 to the financial statements for a discussion of proceedings regarding recovery of Entergy Arkansas’s storm restoration costs.

Entergy Gulf States Louisiana’s electric rates include a fuel adjustment clause designed to recover the cost of fuel and purchased power costs. The fuel adjustment clause contains a surcharge or credit for deferred fuel expense and related carrying charges arising from the monthly reconciliation of actual fuel costs incurred with fuel cost revenues billed to customers, including carrying charges. See Note 2 to the financial statements for a discussion of proceedings related to audits of Entergy Gulf States ~~Louisiana's~~Louisiana’s fuel adjustment clause filings.

To help stabilize electricity costs, Entergy Gulf States Louisiana received approval from the LPSC to hedge its exposure to natural gas price volatility through the use of financial instruments. Entergy Gulf States Louisiana hedges approximately one-third of the projected exposure to natural gas price changes for the gas used to serve its native electric load for all months of the year. The hedge quantity is reviewed on an annual basis.

Entergy Gulf States Louisiana’s gas rates include a purchased gas adjustment clause based on estimated gas costs for the billing month adjusted by a surcharge or credit that arises from an annual reconciliation of fuel costs incurred with fuel cost revenues billed to customers, including carrying charges.

To help stabilize retail gas costs, Entergy Gulf States Louisiana received approval from the LPSC to hedge its exposure to natural gas price volatility for its gas purchased for resale through the use of financial instruments. Entergy Gulf States Louisiana hedges approximately one-half of the projected natural gas volumes used to serve its natural gas customers for November through March. The hedge quantity is reviewed on an annual basis.

See Note 2 to the financial statements for a discussion of Entergy Gulf States Louisiana’s filings to recover storm-related costs.

See Note 2 to the financial statements for a discussion of Entergy Louisiana’s filings to recover storm-related costs.

Entergy Mississippi’s rate schedules include energy cost recovery riders to recover fuel and purchased energy costs. The energy cost rate for each calendar year is redetermined annually and includes a true-up adjustment reflecting the over-recovery or under-recovery of the energy costs as of the 12-month period ended September 30. Entergy Mississippi’s fuel cost recoveries are subject to annual audits conducted pursuant to the authority of the MPSC.

Power Management Rider

~~The~~In November 2005 the MPSC approved the purchase of the Attala power plant ~~in November 2005. In December 2005 the MPSC issued an order approving~~and recovery of the investment cost ~~recovery~~ through Entergy Mississippi’s power management rider. Entergy Mississippi ~~is allowed to recover~~recovered the annual ownership costs of the Attala plant through the power management rider until ~~it files a~~resolution of its general rate case. ~~The~~In 2012 the MPSC approved the purchase of the Hinds power plant ~~in February 2012. In August and October 2012, the MPSC issued orders approving~~recovery of the investment cost ~~recovery~~ through Entergy Mississippi’s power management rider. ~~The orders have the effect of allowing~~ Entergy Mississippi ~~to recover~~recovered the annual ownership costs of the Hinds plant ~~until it files a general rate case. Entergy Mississippi acquired the Hinds plant on November 30, 2012. Recovery of the Hinds plant costs~~ through the power management rider ~~commenced~~until resolution of its general rate case. See Note 2 to the financial statements for a discussion of Entergy Mississippi’s 2014 general rate case. Included in the rate changes and revenue adjustments effective with ~~January 2013 bills.~~February 2015 bills was the realignment of the annual ownership costs associated with the Attala plant and the Hinds plant from the power management rider to base rates.

To help stabilize electricity costs, Entergy Mississippi received approval from the MPSC to hedge its exposure to natural gas price volatility through the use of financial instruments. Entergy Mississippi hedges approximately one-third of the projected exposure to natural gas price changes for the gas used to serve its native electric load for all months of the year. The hedge quantity is reviewed on an annual basis.

Entergy Mississippi maintains a storm damage ~~reserve~~provision pursuant to orders of the MPSC and consistent with regulatory accounting requirements. Entergy ~~Mississippi's~~Mississippi’s storm damage provision is funded through its storm damage rider schedule. In two orders issued in July 2012, the MPSC temporarily increased Entergy Mississippi’s storm damage provision monthly accrual from $750,000 to ~~$2.0~~$2 million for bills rendered during the billing months of August 2012 through December 2012, and approved recovery of $14.9 million in prudently incurred storm costs to be amortized over five months, beginning with August 2012 bills. Beginning with January 2013 bills, the monthly accrual to the storm damage provision reverted back to $750,000. On July 1, 2013, Entergy Mississippi and the Mississippi Public Utilities Staff entered into a joint stipulation, in which both parties agreed that approximately $32 million in storm restoration costs incurred in 2011 and 2012 were prudently incurred and chargeable to storm damages, while approximately $700,000 in prudently incurred costs were more properly recoverable through the formula rate plan. Entergy Mississippi and the Mississippi Public Utilities Staff also agreed that the storm damage accrual should be increased from $750,000 per month to $1.75 million per month. In September 2013 the MPSC approved the joint stipulation with the increase in the storm damage accrual effective with October 2013 bills.

The MPSC has also ordered that Entergy Mississippi will annually submit its storm costs for audit.

Entergy New Orleans’s electric rate schedules include a fuel adjustment tariff designed to reflect no more than targeted fuel and purchased power costs, adjusted by a surcharge or credit for deferred fuel expense arising from the monthly reconciliation of actual fuel and purchased power costs incurred with fuel cost revenues billed to customers, including carrying charges.

Entergy New Orleans’s gas rate schedules include a purchased gas adjustment to reflect estimated gas costs for the billing month, adjusted by a surcharge or credit similar to that included in the electric fuel adjustment clause, including carrying charges. In October 2005 the City Council approved modification of the current gas cost collection mechanism effective November 2005 in order to address concerns regarding its fluctuations, particularly during the winter heating season. The modifications are intended to minimize fluctuations in gas rates during the winter months.

To help stabilize gas costs, Entergy New Orleans seeks approval annually from the City Council to continue implementation of its natural gas hedging program consistent with the City Council’s stated policy objectives. The program uses financial instruments to hedge exposure to volatility in the wholesale price of natural gas purchased to serve Entergy New Orleans gas customers. Entergy New Orleans hedges up to 25% of actual gas sales made during the winter months.

See Note 2 to the financial statements for a discussion of Entergy New Orleans’s efforts to recover storm-related costs.

Entergy Texas’s rate schedules include a fixed fuel factor to recover fuel and purchased power costs, including interest, that are not included in base rates. Semi-annual revisions of the fixed fuel factor are made in March and September based on the market price of natural gas and changes in fuel mix. The amounts collected under Entergy Texas’s fixed fuel factor and any interim surcharge or refund are subject to fuel reconciliation proceedings before the PUCT. The PUCT fuel cost ~~reviews~~proceedings are discussed in Note 2 to the financial statements.

In June 2009, a law was enacted in Texas that required Entergy Texas to cease all activities relating to Entergy Texas’s transition to competition. The law allows Entergy Texas to remain a part of the SERC Region, although it does not prevent Entergy Texas from joining another power region. The law provides that proceedings to certify a power region that Entergy Texas belongs to as a qualified power region can be initiated by the PUCT, or on motion by another party, when the conditions supporting such a proceeding exist. Under the law, the PUCT may not approve a transition to competition plan for Entergy Texas until the expiration of four years from the PUCT’s certification of Entergy Texas’s power region.

The law also contains provisions that allow Entergy Texas to take advantage of a cost recovery mechanism that permits annual filings for the recovery of reasonable and necessary expenditures for transmission infrastructure improvement and changes in wholesale transmission charges. This mechanism was previously available to other non-ERCOT Texas utility companies, but not to Entergy Texas.

In September 2011 the PUCT adopted a proposed rule implementing a Distribution Cost Recovery Factor to recover capital and capital-related costs related to distribution infrastructure. The Distribution Cost Recovery Factor

The law further amended already existing law that had required Entergy Texas to propose for PUCT approval a tariff to allow eligible customers the ability to contract for competitive generation. The amending language in the law provides, among other things, that: 1) the tariff shall not be implemented in a manner that harms the sustainability or competitiveness of manufacturers who choose not to participate in the tariff; 2) Entergy Texas shall “purchase competitive generation service, selected by the customer, and provide the generation at retail to the customer”; and 3) Entergy Texas shall provide and price transmission service and ancillary services under that tariff at a rate that is unbundled from its cost of service. The law directs that the PUCT may not issue an order on the tariff that is contrary to an applicable decision, rule, or policy statement of a federal regulatory agency having jurisdiction.

Entergy Texas and the other parties to the PUCT proceeding to determine the design of the competitive generation tariff were involved in negotiations throughout 2011 and 2012 with the objective of resolving as many disputed issues as possible regarding the tariff. The PUCT determined that unrecovered costs that could be recovered through the rider consist only of those costs necessary to implement and administer the competitive generation program and do not include lost revenues or embedded generation costs. The PUCT also ruled that the amount of customer load that may be included in the competitive generation service program is limited to 115 MW. After additional negotiations, and ultimately the scheduling of a hearing to resolve remaining contested issues, the PUCT issued the order approving the competitive generation service rider in July 2013. Entergy Texas filed for rehearing of the ~~PUCT's~~PUCT’s July 2013 order, which the PUCT denied. Entergy Texas has since filed its appeal of that PUCT order to the Travis County District ~~Courts, where this matter~~Court, which found in favor of the PUCT in an order issued in October 2014. In November 2014, Entergy Texas appealed the District Court’s order which moves the appeal to the Third Court of Appeals. The appeal remains pending.

Entergy Arkansas holds exclusive franchises to provide electric service in approximately ~~307~~308 incorporated cities and towns in Arkansas. These franchises are unlimited in duration and continue unless the municipalities purchase the utility property. In Arkansas franchises are considered to be contracts and, therefore, are terminable pursuant to the terms of the franchise agreement and applicable statutes.

Entergy Gulf States Louisiana holds non-exclusive franchises to provide electric service in approximately 5659 incorporated municipalities and the unincorporated areas of approximately 1822 parishes, and to provide gas service in the City of Baton Rouge and the unincorporated areas of two parishes. Most of Entergy Gulf States Louisiana’s franchises have a term of 60 years. Entergy Gulf States Louisiana’s current electric and gas franchises expire during 2015-2055.

Entergy Louisiana holds non-exclusive franchises to provide electric service in approximately ~~116~~117 incorporated Louisiana municipalities. Most of these franchises have 25-year terms. Entergy Louisiana also supplies electric service in approximately 4552 Louisiana parishes in which it holds non-exclusive franchises. Entergy Louisiana’s electric franchises expire during 2015-2039.

Entergy Mississippi has received from the MPSC certificates of public convenience and necessity to provide electric service to areas within 45 counties, including a number of municipalities, in western Mississippi. Under Mississippi statutory law, such certificates are exclusive. Entergy Mississippi may continue to serve in such municipalities upon payment of a statutory franchise fee, regardless of whether an original municipal franchise is still in existence.

Entergy New Orleans provides electric and gas service in the City of New Orleans pursuant to indeterminate permits set forth in city ordinances (except electric service in Algiers, which is provided by Entergy Louisiana). These ordinances contain a continuing option for the City of New Orleans to purchase Entergy New Orleans’s electric and gas utility properties.

Entergy Texas holds a certificate of convenience and necessity from the PUCT to provide electric service to areas within approximately 27 counties in eastern Texas, and holds non-exclusive franchises to provide electric service in approximately 68 incorporated municipalities. Entergy Texas ~~was~~ typically ~~granted 50-year franchises, but recently has been receiving~~obtains 25-year ~~franchises.~~franchise agreements as existing agreements expire. Entergy Texas’s electric franchises expire during ~~2014-2058.~~2016-2058.

The business of System Energy is limited to wholesale power sales. It has no distribution franchises.

The total capability of the generating stations owned and leased by the Utility operating companies and System Energy as of December 31, ~~2013~~,2014, is indicated below:

Summer peak load for the Utility has averaged 23,269 MW over the previous decade. The ~~Entergy System's~~Utility operating companies, in aggregate, are projected to have approximately 224 MW more than their minimum capacity requirements needed to meet MISO Resource Adequacy for 2015.

The Utility operating companies’ load and capacity projections are reviewed periodically to assess the need and timing for additional generating capacity and interconnections. These reviews consider existing and projected demand, and the availability and price of power, the location of new load, the economy, and the economy. Summer peak load in the Entergy System service territory has averaged 21,408 MW from 2003-2013. In the 2002 time period the Entergy System's long-term capacity resources, allowing for an adequate reserve margin, were approximately 3,000 MW less than the total capacity required for peak period demands. In this time period the Entergy System met its capacity shortages almost entirely through short-term power purchases in the wholesale spot market. In the fallage and condition of ~~2002 the Entergy System began a program to add new resources to its~~Entergy’s existing generation portfolio and began a process of issuing requests for proposals (RFP) to procure supply-side resources from sources other than the spot market to meet the unique regional needs of the Utility operating companies.infrastructure. The Entergy System has adopted a long-term resource strategy, the "Portfolio Transformation Strategy," that calls for the bulk of capacity needs to be met through long-term resources, whether owned or contracted. Over the past eleven years, the Portfolio Transformation has resulted in the addition of about 5,798 MW of new long-term resources. The Entergy Operating Companies, in aggregate, are projected to have approximately 580 MW more than their minimum capacity requirements needed to meet MISO Resource Adequacy for 2014. The Entergy System will rely upon MISO’s Day 2 market to economically purchase energy to minimize customer cost. Finally, the resource planning processes also consider the Entergy Arkansas exit from the System Agreement on December ~~19,~~18, 2013, and ~~both~~ Entergy ~~Mississippi's~~Mississippi’s (in November 2015), Entergy Texas’s, Entergy Louisiana’s, and Entergy ~~Texas’s~~Gulf States Louisiana’s notices of their future withdrawal from the System Agreement.

The Utility operating companies’ long-term resource strategy, the “Portfolio Transformation Strategy,” calls for the bulk of capacity needs to be met through long-term resources, whether owned or contracted. Over the past decade, the Portfolio Transformation Strategy has resulted in the addition of about 6,500 MW of new long-term resources. As MISO market participants, the Utility operating companies also participate in MISO’s Day Ahead and Real Time Energy and Ancillary Services markets to economically dispatch generation and purchase energy to serve customers reliably and at the lowest reasonable cost.

The Utility operating companies from time to time issue requests for proposals (RFP) to procure supply-side resources from sources other than the spot market to meet the unique regional needs of the Utility operating companies. The RFPs issued by the ~~Entergy System since the fall of 2002~~Utility operating companies have sought resources needed to meet near-term summer reliability requirements as well as longer-term requirements through a broad range of wholesale power products, including limited-term (1 to 3 years) and long-term contractual products and asset acquisitions. ~~Detailed evaluation processes have been developed to analyze submitted proposals, and, with the exception~~The RFP process resulted, among other things, in:

The RFP process has also resulted in the selection, or confirmation of the economic merits of, long-term purchased power agreements (PPAs), including, among others:

In December 2010 on behalf of Entergy Gulf States Louisiana and Entergy Louisiana, Entergy Services issued the 2010 RFP for Long-Term Renewable Energy Resources seeking up to 233 MW of renewable generation resources to meet the requirements of an LPSC general order issued on December 9, 2010. In September 2012, Entergy Gulf States Louisiana executed a 20-year contract for 28 MW, with the potential to purchase an additional 9 megawatts when available, from Rain CII Carbon ~~LLC's~~LLC’s pet coke calcining facility in Sulphur, Louisiana. The facility began commercial operation in May 2013. ~~LPSC certification of the contract was received in December 2012.~~ In March 2013, Entergy Gulf States Louisiana executed a 20-year contract for 8.5 MW from Agrilectric Power Partners, LP’s refurbished rice hull-fueled electric generation facility located in Lake Charles, Louisiana. ~~LPSC certification of the contract was received in July 2013.~~ In September 2013, Entergy Louisiana executed a 10-year contract with TX LFG Energy, LP, a wholly-owned subsidiary of Montauk Energy Holdings, LLC, to purchase approximately 3 MW from its landfill gas-fueled power generation facility located in Cleveland, ~~Texas and filed with the~~Texas. LPSC ~~an application seeking approval and cost recovery for the contract.~~certification of these three contracts has been received.

In ~~June 2011~~May 2014, Entergy Arkansas issued the 2014 Entergy Arkansas RFP for Long-Term, Supply-Side and Renewable Generation Resources. This RFP is seeking between 200 to 600 MW of capacity, capacity-related benefits, energy, other electric products, and environmental attributes from traditional resources (CT, CCTG or solid fuel) for deliveries beginning in 2017 and approximately 200 MW of the same products from renewable resources (wind, solar, biomass and hydro) for deliveries starting as early as 2015.

In September 2014, on behalf of ~~Entergy Arkansas, Entergy Services issued the 2011 RFP for Transition Plan Resources. The RFP sought up to 750 MW of flexible generation resources through~~ one or more ~~purchased power~~

The ~~above table does not include~~Utility operating companies have also made resource acquisitions ~~made~~ outside of the RFP process, including Entergy ~~Mississippi's~~Mississippi’s January 2006 acquisition of the 480 MW, combined-cycle, gas-fired Attala power plant; Entergy Gulf States ~~Louisiana's~~Louisiana’s March 2008 acquisition of the 322 MW, simple-cycle, gas-fired Calcasieu Generating Facility; and Entergy Louisiana’s April 2011 acquisition of the 580 MW, combined-cycle, gas-fired Acadia Energy Center Unit 2. The ~~above table~~Utility operating companies have also ~~does not reflect~~entered into various limited- and long-term contracts ~~that have been entered into~~ in recent years ~~by the Utility operating companies~~ as a result of bilateral negotiations.

In December 2014, Entergy Arkansas, Entergy Gulf States Louisiana, and Entergy Texas entered into an asset purchase agreement to acquire the Union Power Station, a 1,980 MW (summer rating) power generation facility located near El Dorado, Arkansas, from Union Power Partners, L.P. The Union Power Station consists of four natural gas-fired, combined-cycle gas turbine power blocks, each rated at 495 MW (summer rating). Pursuant to the agreement, Entergy Gulf States Louisiana will acquire two of the power blocks and a 50% undivided ownership interest in certain assets related to the facility, and Entergy Arkansas and Entergy Texas will each acquire one power block and a 25% undivided ownership interest in the related assets. If Entergy Arkansas or Entergy Texas do not obtain approval for the purchase of their power blocks, Entergy Gulf States Louisiana will seek to purchase the power blocks not approved. The base purchase price is expected to be approximately $948 million (approximately $237 million for each power block) subject to adjustments. In addition, Entergy Gulf States Louisiana anticipates selling 20% of the capacity and energy associated with its two power blocks to Entergy New Orleans through a cost-based, life-of-unit power purchase

The ~~Entergy System's~~Utility operating companies’ generating units are interconnected by a transmission system operating at various voltages up to 500 kV. These generating units consist primarily of steam-electric production facilities and are provided dispatch instructions by ~~the~~ MISO. ~~Entergy's~~Entergy’s Utility operating companies are MISO market participants and are interconnected with many neighboring utilities. ~~MISO’s primary purpose as~~MISO is an essential link in the safe, cost-effective delivery of electric power across all or parts of 15 U.S. states and the Canadian province of Manitoba. As a Regional Transmission Organization, ~~is to guarantee a safe, cost-effective delivery of electrical power and assure~~MISO assures consumers of unbiased regional grid management and open access to the transmission ~~facilities.~~facilities under MISO’s functional supervision. In addition, the Utility operating companies are members of the SERC Reliability ~~Corporation. The primary purpose of~~Corporation (SERC). SERC is ~~to ensure~~a nonprofit corporation responsible for promoting and improving the reliability, adequacy, and ~~adequacy~~critical infrastructure of the ~~electric~~ bulk power supply systems in ~~the southeast region~~all or portions of ~~the United States.~~ 16 central and southeastern states.SERC isserves as a ~~member of~~regional entity with delegated authority from the North American Electric Reliability ~~Corporation.~~Corporation (NERC) for the purpose of proposing and enforcing reliability standards within the SERC Region.

As of December 31, ~~2013~~,2014, Entergy New Orleans distributed and transported natural gas for distribution within Algiers and New Orleans, Louisiana, through approximately 2,500 miles of gas pipeline. As of December 31, ~~2013,~~2014, the gas properties of Entergy Gulf States Louisiana, which are located in and around Baton Rouge, Louisiana, were not material to Entergy Gulf States ~~Louisiana's~~Louisiana’s financial position.

The ~~Entergy System's~~Utility operating companies’ generating stations are generally located on properties owned in fee simple. Most of the substations and transmission and distribution lines are constructed on private property or public rights-of-way pursuant to easements, servitudes, or appropriate franchises. Some substation properties are owned in fee simple. The

Substantially all of the physical properties and assets owned by Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy are subject to the liens of mortgages securing bonds issued by those companies. The Lewis Creek generating station is owned by GSG&T, Inc., a subsidiary of Entergy Texas, and is not subject to its mortgage lien. Lewis Creek is leased to and operated by Entergy Texas.

The sources of generation and average fuel cost per kWh for the Utility operating companies and System Energy for the years ~~2011-2013~~2012-2014 were:

Actual ~~2013~~2014 and projected ~~2014~~2015 sources of generation for the Utility operating companies and System Energy, including certain power purchases from affiliates under life of unit power purchase agreements, including the Unit Power Sales Agreement, are:

The Utility operating companies have long-term firm and short-term interruptible gas contracts for both supply and transportation. Long-term firm contracts for power plants comprise less than 25% of the Utility operating ~~companies'~~companies’ total requirements. Short-term contracts and spot-market purchases satisfy additional gas requirements. Entergy Texas owns a gas storage facility that provides reliable and flexible natural gas service to certain generating stations.

Entergy Louisiana entered into a long-term natural gas supply contract beginning January 1, 2013, in which Entergy Louisiana purchases natural gas in annual amounts equal to approximately one-half of its projected annual fuel requirements for certain generating units.

Entergy Arkansas has committed to ~~six~~eight one- to three-year contracts that will supply approximately ~~90%~~87% of the total coal supply needs in ~~2014.~~2015. These contracts are staggered in term so that not all contracts have to be renewed the same year. The remaining ~~10%~~13% of total coal requirements will be satisfied by contracts with a term of less than one year. Based on continued improved Powder River Basin (PRB) coal deliveries by rail and the high cost of alternate sources and modes of transportation, no alternative coal consumption is expected at Entergy Arkansas during ~~2014.~~2015. Entergy Arkansas ~~has an existing railroad transportation contract~~is currently negotiating a new rail agreement that ~~is expected to~~will provide all of Entergy Arkansas’s coal transportation requirements ~~for 2014.~~through 2015. The current agreement is set to expire June 30, 2015.

Entergy Gulf States Louisiana has committed to four one- to three-year contracts that will supply approximately ~~90%~~79% of Nelson Unit 6 coal needs in ~~2014.~~2015. Additional PRB coal will be purchased through contracts with a term of less than one year to provide the remaining supply needs. For the same reasons as for Entergy Arkansas’s plants, no alternative coal consumption is expected at Nelson Unit 6 during ~~2014.~~2015. Coal will be transported to Nelson via an existing transportation agreement that is expected to provide all of Entergy Gulf States Louisiana’s rail transportation requirements for ~~2014.~~2015.

For the year ~~2013,~~2014, coal transportation delivery to Entergy ~~Arkansas~~Arkansas- and Entergy Gulf States ~~Louisiana operated~~Louisiana-operated coal-fired units met coal demand at the plants and it is expected that delivery times experienced in ~~2013~~2014 will continue to improve through ~~2014.~~2015. Both Entergy Arkansas and Entergy Gulf States Louisiana control a sufficient number of railcars to satisfy the rail transportation requirement.

The operator of Big Cajun 2 - Unit 3, Louisiana Generating, LLC, has advised Entergy Gulf States Louisiana and Entergy Texas that it has adequate rail car and barge capacity to meet the volumes of PRB coal requested for ~~2014.~~2015. Entergy Gulf States Louisiana’s and Entergy Texas’s coal nomination requests to Big Cajun 2 - Unit 3 are made on an annual basis.

The nuclear fuel cycle consists of the following:

The Registrant Subsidiaries that own nuclear plants (Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, and System Energy) are responsible through a shared regulated uranium pool for contracts to acquire nuclear material to be used in fueling ~~Entergy's~~Entergy’s Utility nuclear units. These companies own the materials and services in this shared regulated uranium pool on a pro rata fractional basis determined by the nuclear generation capability of each company. Any liabilities for obligations of the pooled contracts are on a several but not joint basis. The shared regulated uranium pool maintains inventories of nuclear materials during the various stages of processing. The Registrant Subsidiaries purchase enriched uranium hexafluoride for their nuclear plant reload requirements at the average inventory cost from the shared regulated uranium pool. Entergy Operations Inc. contracts separately for the fabrication of nuclear fuel as agent on behalf of each of the Registrant Subsidiaries that owns a nuclear plant. All contracts for the disposal of spent nuclear fuel are between the ~~Department of Energy (DOE)~~DOE and the owner of a nuclear power plant.

Based upon currently planned fuel cycles, the nuclear units in both the Utility and Entergy Wholesale Commodities segments have a diversified portfolio of contracts and inventory that provides substantially adequate nuclear fuel materials and conversion and enrichment services at what Entergy believes are reasonably predictable or fixed prices through most of ~~2014.~~2015. Entergy’s ability to purchase nuclear fuel at reasonably predictable prices, however, depends upon the performance reliability of uranium miners. There are a number of possible ~~alternate suppliers~~supply alternatives that may be accessed to mitigate any supplier performance failure, including potentially drawing upon Entergy’s inventory intended for later generation periods depending upon its risk management strategy at that time, although the pricing of any alternate uranium supply from the market will be dependent upon the market for uranium supply at that time. In addition, some nuclear fuel contracts are on a non-fixed price basis subject to prevailing prices at the time of delivery.

The effects of market price changes may be reduced and deferred by risk management strategies, such as negotiation of floor and ceiling amounts for long-term contracts, buying for inventory or entering into forward physical contracts at fixed prices when Entergy believes it is appropriate and useful. Entergy buys uranium from a diversified mix of sellers located in a diversified mix of countries, and from time to time purchases from nearly all qualified reliable major market participants worldwide that sell into the U.S.

Entergy’s ability to assure nuclear fuel supply also depends upon the performance reliability of conversion, enrichment, and fabrication services providers. There are fewer of these providers than for uranium. For conversion and enrichment services, like uranium, Entergy diversifies its supply by supplier and country and may take special measures as needed to ensure supply of enriched uranium for the reliable fabrication of nuclear fuel. For fabrication services, each plant is dependent upon the effective performance of the fabricator of that plant’s nuclear fuel, therefore, Entergy provides additional monitoring, inspection, and oversight for the fabrication process to assure reliability and quality.

Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, and System Energy each have made arrangements to lease nuclear fuel and related equipment and services. The lessors, which are consolidated in the financial statements of Entergy and the applicable Registrant Subsidiary, finance the acquisition and ownership of nuclear fuel through credit agreements and the issuance of notes. These ~~arrangements~~credit facilities are subject to periodic ~~renewal.~~renewal, and the notes are issued periodically, typically for terms between three and ten years.

Entergy New Orleans has several suppliers of natural gas. Its system is interconnected with three interstate and three intrastate pipelines. Entergy New Orleans has a ~~"no-notice"~~“no-notice” service gas purchase contract with Atmos Energy which guarantees Entergy New Orleans gas delivery at specific delivery points and at any volume within the minimum and maximum set forth in the contract amounts. The Atmos Energy gas supply is transported to Entergy New Orleans pursuant to a transportation service agreement with Gulf South Pipeline Co. This service is subject to FERC-approved rates. Entergy New Orleans also makes interruptible spot market purchases. In recent years, natural gas deliveries to Entergy New Orleans have been subject primarily to weather-related curtailments.

Entergy Gulf States Louisiana purchases natural gas for resale under a firm contract from Enbridge Marketing (U.S.) Inc. The gas is delivered through a combination of intrastate and interstate pipelines.

As a result of the implementation of FERC-mandated interstate pipeline restructuring in 1993, curtailments of interstate gas supply could occur if Entergy Gulf States Louisiana’s or Entergy New ~~Orleans's~~Orleans’s suppliers failed to perform their obligations to deliver gas under their supply agreements. Gulf South Pipeline Co. could curtail transportation capacity only in the event of pipeline system constraints.

State or local regulatory authorities, as described above, regulate the retail rates of the Utility operating companies. The FERC regulates wholesale rates (including intrasystem sales pursuant to the System Agreement) and

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. Under the terms of the System Agreement, generating capacity and other power resources are jointly operated by the Utility operating ~~companies.~~companies that are participating in the System Agreement. The System Agreement provides, among other things, that parties having generating reserves greater than their allocated share of reserves (long companies) shall receive payments from those parties having generating reserves that are less than their allocated share of reserves (short companies). Such payments are at amounts sufficient to cover certain of the long companies’ costs for intermediate and peaking oil/gas-fired generation, including operating expenses, fixed charges on debt, dividend requirements on preferred equity, and a fair rate of return on common equity investment. Under the System Agreement, the rates used to compensate long companies are based on costs associated with the long companies’ steam electric generating units fueled by oil or gas and having an annual average heat rate above 10,000 Btu/kWh. In addition, for all energy exchanged among the Utility operating companies under the System Agreement, the companies purchasing exchange energy are required to pay the cost of fuel consumed in generating such energy plus a charge to cover other associated costs. Entergy Arkansas terminated its participation in the System Agreement in December 2013. Entergy Mississippi will terminate its participation in the System Agreement in November 2015.

See “System Agreement” in Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for additional discussion of the System Agreement, including ~~Entergy Arkansas terminating its participation in December 2013 and~~ other Utility operating ~~companies'~~companies’ notices to terminate participation in the future. See Note 2 to the financial statements for discussion of legal proceedings at the FERC involving the System Agreement.

See “~~Entergy's~~Entergy’s Integration into the MISO Regional Transmission Organization” in the “Rate, Cost-recovery, and Other Regulation - Federal Regulation” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis.

System Energy recovers costs related to its interest in Grand Gulf through rates charged to Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans for capacity and energy under the Unit Power Sales Agreement (described below). In December 1995, System Energy commenced a rate proceeding at the FERC. In July 2001 the rate proceeding became final, with the FERC approving a prospective 10.94% return on equity. The FERC’s decision also affected other aspects of System Energy’s charges to the Utility operating companies that it supplies with

The Unit Power Sales Agreement allocates capacity, energy, and the related costs from System Energy’s ownership and leasehold interests in Grand Gulf to Entergy Arkansas (36%), Entergy Louisiana (14%), Entergy Mississippi (33%), and Entergy New Orleans (17%). Each of these companies is obligated to make payments to System Energy for its entitlement of capacity and energy on a full cost-of-service basis regardless of the quantity of energy

In the case of Entergy Arkansas and Entergy Louisiana, payments are also recovered through sales of electricity from their respective retained shares of Grand Gulf. Under a settlement agreement entered into with the APSC in 1985 and amended in 1988, Entergy Arkansas retains 22% of its 36% share of Grand Gulf-related costs and recovers the remaining 78% of its share in rates. In the event that Entergy Arkansas is not able to sell its retained share to third parties, it may sell such energy to its retail customers at a price equal to its avoided cost, which is currently less than Entergy Arkansas’s cost from its retained share. Entergy Arkansas has life-of-resources purchased power agreements with Entergy Louisiana and Entergy New Orleans that sell a portion of the output of Entergy Arkansas’s retained share of Grand Gulf to those companies, with the remainder of the retained share being sold to Entergy Mississippi through a separate life-of-resources purchased power agreement. In a series of LPSC orders, court decisions, and agreements from late 1985 to mid-1988, Entergy Louisiana was granted rate relief with respect to costs associated with Entergy Louisiana’s share of capacity and energy from Grand Gulf, subject to certain terms and conditions. Entergy Louisiana retains and does not recover from retail ratepayers 18% of its 14% share of the costs of Grand Gulf capacity and energy and recovers the remaining 82% of its share in rates. Entergy Louisiana is allowed to recover through the fuel adjustment clause at 4.6 cents per kWh for the energy related to its retained portion of these costs. Alternatively, Entergy Louisiana may sell such energy to non-affiliated parties at prices above the fuel adjustment clause recovery amount, subject to the LPSC’s approval. Entergy Arkansas also has a life-of-resources purchased power agreement with Entergy Mississippi to sell a portion of the output of Entergy ~~Arkansas's~~Arkansas’s non-retained share of Grand Gulf. Entergy Mississippi was granted rate relief for those purchases by the MPSC through its annual rate mechanism.

The Availability Agreement among System Energy and Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans was entered into in 1974 in connection with the financing by System Energy of Grand Gulf. The Availability Agreement provides that System Energy make available to Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans all capacity and energy available from System Energy’s share of Grand Gulf.

Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans also agreed severally to pay System Energy monthly for the right to receive capacity and energy from Grand Gulf in amounts that (when added to any amounts received by System Energy under the Unit Power Sales Agreement) would at least equal System Energy’s total operating expenses for Grand Gulf (including depreciation at a specified rate and expenses incurred in a permanent shutdown of Grand Gulf) and interest charges. The September 1989 write-off of System Energy’s investment in Grand Gulf 2, amounting to approximately $900 million, is being amortized for Availability Agreement purposes over 27 years.

The allocation percentages under the Availability Agreement are fixed as follows: Entergy Arkansas - 17.1%; Entergy Louisiana - 26.9%; Entergy Mississippi - 31.3%; and Entergy New Orleans - 24.7%. The allocation percentages

System Energy has assigned its rights to payments and advances from Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans under the Availability Agreement as security for its first mortgage bonds and reimbursement obligations to certain banks providing letters of credit in connection with the equity funding of the sale and leaseback transactions described in Note 10 to the financial statements under ~~“Sale~~“Sale and Leaseback Transactions - Grand Gulf Lease Obligations.” In these assignments, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans further agreed that, in the event they were prohibited by governmental action from making

Each of the assignment agreements relating to the Availability Agreement provides that Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans will make payments directly to System Energy. However, if there is an event of default, those payments must be made directly to the holders of indebtedness that are the beneficiaries of such assignment agreements. The payments must be made pro rata according to the amount of the respective obligations secured.

The obligations of Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans to make payments under the Availability Agreement are subject to the receipt and continued effectiveness of all necessary regulatory approvals. Sales of capacity and energy under the Availability Agreement would require that the Availability Agreement be submitted to the FERC for approval with respect to the terms of such sale. No such filing with the FERC has been made because sales of capacity and energy from Grand Gulf are being made pursuant to the Unit Power Sales Agreement. If, for any reason, sales of capacity and energy are made in the future pursuant to the Availability Agreement, the jurisdictional portions of the Availability Agreement would be submitted to the FERC for approval.

Since commercial operation of Grand Gulf began, payments under the Unit Power Sales Agreement to System Energy have exceeded the amounts payable under the Availability Agreement and, therefore, no payments under the Availability Agreement have ever been required. If Entergy Arkansas or Entergy Mississippi fails to make its Unit Power Sales Agreement payments, and System Energy is unable to obtain funds from other sources, Entergy Louisiana and Entergy New Orleans could become subject to claims or demands by System Energy or its creditors for payments or advances under the Availability Agreement (or the assignments thereof) equal to the difference between their required Unit Power Sales Agreement payments and their required Availability Agreement payments because their Availability Agreement obligations exceed their Unit Power Sales Agreement obligations.

The Availability Agreement may be terminated, amended, or modified by mutual agreement of the parties thereto, without further consent of any assignees or other creditors.

System Energy and Entergy Corporation have entered into the Capital Funds Agreement, whereby Entergy Corporation has agreed to supply System Energy with sufficient capital to (i) maintain System Energy’s equity capital at an amount equal to a minimum of 35% of its total capitalization (excluding short-term debt) and (ii) permit the continued commercial operation of Grand Gulf and pay in full all indebtedness for borrowed money of System Energy when due.

Entergy Corporation has entered into various supplements to the Capital Funds Agreement. System Energy has assigned its rights under such supplements as security for its first mortgage bonds and for reimbursement obligations to certain banks providing letters of credit in connection with the equity funding of the sale and leaseback transactions

The Capital Funds Agreement may be terminated, amended, or modified by mutual agreement of the parties thereto, upon obtaining the consent, if required, of those holders of System Energy’s indebtedness then outstanding who have received the assignments of the Capital Funds Agreement.

Entergy Services, a corporation wholly-owned by Entergy Corporation, provides management, administrative, accounting, legal, engineering, and other services primarily to the Utility operating companies, but also provides services to Entergy Wholesale Commodities. Entergy Operations is also wholly-owned by Entergy Corporation and provides nuclear management, operations and maintenance services under contract for ANO, River Bend, Waterford 3, and Grand Gulf, subject to the owner oversight of Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, and System Energy, respectively. Entergy Services and Entergy Operations provide their services to the Utility operating companies and System Energy on an “at cost” basis, pursuant to cost allocation methodologies for these service agreements that were approved by the FERC.

Effective December 31, 2007, Entergy Gulf States, Inc. completed a jurisdictional separation into two vertically integrated utility companies, one operating under the sole retail jurisdiction of the PUCT, Entergy Texas, and the other operating under the sole retail jurisdiction of the LPSC, Entergy Gulf States Louisiana. Entergy Texas now owns all Entergy Gulf States, Inc. distribution and transmission assets located in Texas, the gas-fired generating plants located in Texas, undivided 42.5% ownership shares of Entergy Gulf States, Inc.’s 70% ownership interest in Nelson 6 and 42% ownership interest in Big Cajun 2, Unit 3, which are coal-fired generating plants located in Louisiana, and other assets and contract rights to the extent related to utility operations in Texas. Entergy Gulf States Louisiana now owns all of the remaining assets that were owned by Entergy Gulf States, Inc. On a book value basis, approximately 58.1% of the Entergy Gulf States, Inc. assets were allocated to Entergy Gulf States Louisiana and approximately 41.9% were allocated to Entergy Texas.

Entergy Texas purchases from Entergy Gulf States Louisiana pursuant to a life-of-unit purchased power agreement ~~(PPA)~~ a 42.5% share of capacity and energy from the 70% of River Bend subject to retail regulation. Entergy Texas was allocated a share of River Bend’s nuclear and environmental liabilities that is identical to the share of the plant’s output purchased by Entergy Texas under the ~~PPA.~~purchased power agreement. Entergy Gulf States Louisiana purchases a 57.5% share of capacity and energy from the gas-fired generating plants owned by Entergy Texas, and Entergy Texas purchases a 42.5% share of capacity and energy from the gas-fired generating plants owned by Entergy Gulf States Louisiana. The ~~PPAs~~purchased power agreements associated with the gas-fired generating plants will terminate when the unit(s) is/are removed from Entergy System dispatch. The dispatch and operation of the generating plants did not change as a result of the jurisdictional separation. The LPSC staff has asserted that the ~~PPAs~~purchased power agreements would terminate if Entergy Texas and Entergy Gulf States Louisiana join MISO. Entergy Gulf States Louisiana filed testimony opposing that position. The LPSC stayed consideration of this issue until December 31, 2013. No further action has been taken regarding this matter. See additional discussion of the ~~PPAs~~purchased power agreements in the "“Federal Regulation - ~~Entergy's~~Entergy’s Integration Into the MISO Regional Transmission Organization” section in Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis.

See Note 2 to the financial statements for a discussion of the planned Entergy Louisiana and Entergy Gulf States Louisiana business combination.

The Registrant Subsidiaries’ ratios of earnings to fixed charges and ratios of earnings to combined fixed charges and preferred dividends or distributions pursuant to Item 503 of SEC Regulation S-K are as follows:

Entergy Wholesale Commodities includes the ownership, operation, and ~~operation~~decommissioning of ~~six~~ nuclear power plants, ~~five of which are~~ located in the ~~Northeast~~northern United States ~~with~~and the ~~sixth located in Michigan, and is primarily focused on selling~~sale of the electric power produced by ~~those~~its operating plants to wholesale customers. Entergy Wholesale Commodities revenues are primarily derived from sales of energy and generation capacity from these plants. 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.

On December 29, 2014, Entergy Wholesale Commodities Vermont Yankee plant was removed from the grid, after 42 years of operations. The decision to close and decommission Vermont Yankee was announced in August 2013, as a result of numerous issues including sustained low natural gas and wholesale energy prices, the high cost structure of the plant, and lack of a market structure that adequately compensates merchant nuclear plants for their environmental and fuel diversity benefits in the Northeast region.

Entergy Wholesale Commodities includes the ownership of the following nuclear power plants:

Entergy Wholesale Commodities also includes the ownership of two non-operating nuclear facilities, Big Rock Point in Michigan and Indian Point 1 in New York that were acquired when Entergy purchased the Palisades and Indian Point 2 nuclear plants, respectively. These facilities are in various stages of the decommissioning process.

In ~~March 2011 and May 2012~~April 2007, Entergy submitted to the NRC ~~renewed~~a joint application to renew the operating licenses ~~of Vermont Yankee~~for Indian Point 2 and ~~Pilgrim, respectively,~~Indian Point 3 for an additional 20 ~~years, as a result of which each license now expires in 2032. For additional discussion regarding the decision to cease operation of the Vermont Yankee plant in the fourth quarter 2014, see “Impairment of Long-Lived Assets” in Note 1 to the financial statements.~~

Entergy Wholesale Commodities includes the ownership, or interests in joint ventures that own, the following non-nuclear power plants:

The Pilgrim and Vermont Yankee and Rhode Island plants fall under the authority of the Independent System Operator (ISO) New England and the FitzPatrick and Indian Point plants fall under the authority of the New York Independent System Operator (NYISO). The Palisades plant falls under the authority of the MISO. The primary purpose of ISO New England, NYISO, and MISO is to direct the operations of the major generation and transmission facilities in their respective regions; ensure grid reliability; administer and monitor wholesale electricity markets; and plan for their respective region’s energy needs.

As a wholesale generator, Entergy Wholesale ~~Commodities's~~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’s~~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. See “Market and Credit Risk Sensitive Instruments” in Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for additional information regarding these contracts.

As part of the purchase of the Palisades plant in 2007, Entergy executed a 15-year PPA with the seller, Consumers Energy, for 100% of the plant’s output, excluding any future uprates. Under the purchased power agreement, Consumers Energy will receive the value of any new environmental credits for the first ten years of the agreement. Palisades and Consumers Energy will share on a 50/50 basis the value of any new environmental credits for years 11 through 15 of the agreement. The environmental credits are defined as benefits from a change in law that causes capability of the

Entergy Wholesale ~~Commodities's~~Commodities’ customers for the sale of both energy and capacity from its nuclear plants include retail power providers, utilities, electric power co-operatives, power trading organizations and other power generation companies. These customers include Consolidated Edison and Consumers Energy, companies from which Entergy purchased plants, and ISO New England, NYISO, and MISO. Substantially all of the counterparties or their guarantors for the planned energy output under contract for Entergy Wholesale Commodities nuclear plants have public investment grade credit ratings.

The ISO New England and NYISO markets are highly competitive. Entergy Wholesale Commodities has numerous competitors in New England and New York, including generation companies affiliated with regulated utilities, other independent power producers, municipal and co-operative generators, owners of co-generation plants and wholesale power marketers. Entergy Wholesale Commodities is an independent power producer, which means it generates power for sale to third parties at day ahead or spot market prices to the extent that the power is not sold under a fixed price contract. Municipal and co-operative generators also generate power but use most of it to deliver power to their municipal or co-operative power customers. Owners of co-generation plants produce power primarily for their own consumption. Wholesale power marketers do not own generation; rather they buy power from generators or other market participants and resell it to retail providers or other market participants. Competition in the New England and New York power markets is affected by, among other factors, the amount of generation and transmission capacity in these markets. MISO does not have a centralized clearing capacity market, but load serving entities do meet the majority of their capacity needs through bilateral contracts and self-supply with a smaller portion coming through voluntary MISO auctions. The majority of Palisades’s current output is contracted to Consumers Energy through 2022 and, therefore, Entergy Wholesale Commodities does not expect to be materially affected by competition in the MISO market in the near term.

Entergy Wholesale ~~Commodities's~~Commodities’ revenues and operating income are subject to fluctuations during the year due to seasonal factors, weather conditions, and contract pricing. Refueling outages are generally scheduled for the spring and the fall, and cause volumetric decreases during those seasons. When outdoor and cooling water temperatures are lower, generally during colder months, Entergy Wholesale Commodities nuclear power plants operate more efficiently, and consequently, generate more electricity. Many of Entergy Wholesale ~~Commodities’s~~Commodities’ contracts provide for shaped pricing over the course of the year. As a result of these factors, Entergy Wholesale ~~Commodities’s~~Commodities’ revenues are typically higher in the first and third quarters than in the second and fourth quarters.

See “Fuel Supply, - Nuclear Fuel” in the Utility portion of Part I, Item 1 for a discussion of the nuclear fuel cycle and markets. Entergy Nuclear Fuels Company, a wholly-owned subsidiary, is responsible for contracts to acquire nuclear materials, except for fuel fabrication, for Entergy Wholesale Commodities nuclear power plants, while Entergy Nuclear Operations, Inc. acts as the agent for the purchase of nuclear fuel assembly fabrication services. All contracts for the disposal of spent nuclear fuel are between the DOE and each of the nuclear power plants.

Entergy Nuclear Power Marketing, LLC (ENPM) was formed in 2005 to centralize the power marketing function for Entergy Wholesale Commodities nuclear plants. Upon its formation, ENPM entered into long-term power purchase agreements with the Entergy Wholesale Commodities subsidiaries that own nuclear power plants (generating

Entergy Nuclear, Inc. pursues service agreements with other nuclear power plant owners who seek the advantages of Entergy’s scale and expertise but do not necessarily want to sell their assets. Services provided by either Entergy Nuclear, Inc. or other Entergy Wholesale Commodities subsidiaries include engineering, operations and maintenance, fuel procurement, management and supervision, technical support and training, administrative support, and other managerial or technical services required to operate, maintain, and decommission nuclear electric power facilities. Entergy Nuclear, Inc. provided decommissioning services for the Maine Yankee nuclear power plant and continues to pursue opportunities for Entergy Wholesale Commodities with other nuclear plant owners through operating agreements.

Entergy Nuclear, Inc. also offers operating license renewal and life extension services to nuclear power plant owners. TLG Services, a subsidiary of Entergy Nuclear Inc., offers decommissioning, engineering, and related services to nuclear power plant owners. In April 2009, Entergy announced that it will team with energy firm ENERCON to offer nuclear development services ranging from plant relicensing to full-service, new plant deployment. ENERCON has experience in engineering, environmental, technical and management services.

In September 2003, Entergy agreed to provide plant operation support services for the 800 MW Cooper Nuclear Station located near Brownville, Nebraska. The original contract was to expire in 2014 corresponding to the original operating license life of the plant. In 2006 an Entergy subsidiary signed an agreement to provide license renewal services for the Cooper Nuclear Station. The Cooper Nuclear Station received its license renewal from the NRC onin November ~~29,~~ 2010. Entergy continues to provide implementation services for the renewed license. In 2010 an Entergy subsidiary signed an agreement to extend the management support services to Cooper Nuclear Station by 15 years, through January 2029.

The Federal Power Act provides the FERC the authority to regulate:

The Federal Power Act gives the FERC jurisdiction over the rates charged by System Energy for Grand Gulf capacity and energy provided to Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans and over some of the rates charged by Entergy Arkansas and Entergy Gulf States Louisiana. The FERC also regulates the provisions of the System Agreement, including the rates, and the provision of transmission service to wholesale market participants. The FERC also regulates the MISO RTO, an independent entity that maintains functional control over the combined transmission systems of its members and administers wholesale energy, capacity, and ancillary services markets for market participants in the MISO region, including the Utility operating companies. FERC

Entergy Arkansas holds a FERC license that expires in 2053 for two hydroelectric projects totaling 70 MW of capacity.

Entergy Arkansas is subject to regulation by the APSC, which includes the authority to:

Entergy Gulf States Louisiana’s electric and gas business and Entergy Louisiana are subject to regulation by the LPSC as to:

Entergy Louisiana is also subject to the jurisdiction of the City Council with respect to such matters within Algiers in Orleans Parish, although the precise scope of that jurisdiction differs from that of the LPSC.

Entergy Mississippi is subject to regulation by the MPSC as to the following:

Entergy Mississippi is also subject to regulation by the APSC as to the certificate of environmental compatibility and public need for the Independence Station, which is located in Arkansas.

Entergy New Orleans is subject to regulation by the City Council as to the following:

To the extent authorized by governing legislation, Entergy Texas is subject to the original jurisdiction of the municipal authorities of a number of incorporated cities in Texas with appellate jurisdiction over such matters residing in the PUCT. Entergy Texas is also subject to regulation by the PUCT as to:

Under the Atomic Energy Act of 1954 and the Energy Reorganization Act of 1974, the operation of nuclear plants is heavily regulated by the NRC, which has broad power to impose licensing and safety-related requirements. The NRC has broad authority to impose fines or shut down a unit, or both, depending upon its assessment of the severity of the situation, until compliance is achieved. Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, and System Energy, as owners of all or portions of ANO, River Bend, Waterford 3, and Grand Gulf, respectively, and Entergy Operations, as the licensee and operator of these units, are subject to the jurisdiction of the NRC. Entergy subsidiaries in the Entergy Wholesale Commodities segment are subject to the NRC’s jurisdiction as the owners and operator of Pilgrim, Indian Point Energy Center, FitzPatrick, Vermont Yankee, and Palisades. Substantial capital expenditures at Entergy’s nuclear plants because of revised safety requirements of the NRC could be required in the future.

Under the Nuclear Waste Policy Act of 1982, the DOE is required, for a specified fee, to construct storage facilities for, and to dispose of, all spent nuclear fuel and other high-level radioactive waste generated by domestic nuclear power reactors. Entergy’s nuclear owner/licensee subsidiaries ~~provide~~have been charged fees for the estimated future disposal costs of spent nuclear fuel in accordance with the Nuclear Waste Policy Act of 1982. The affected Entergy companies entered into contracts with the DOE, whereby the DOE is to furnish disposal services at a cost of one mill per net kWh generated and sold after April 7, 1983, plus a one-time fee for generation prior to that date. Entergy Arkansas is the only one of the Utility operating companies that generated electric power with nuclear fuel prior to that date and has a recorded

The permanent spent fuel repository in the U.S. has been legislated to be Yucca Mountain, Nevada. The DOE is required by law to proceed with the licensing (the DOE filed the license application in June 2008) and, after the license is granted by the NRC, proceed with the repository construction and commencement of receipt of spent fuel. Because the DOE has not begun accepting spent fuel, it is in non-compliance with the Nuclear Waste Policy Act of 1982 and has breached its spent fuel disposal contracts. The DOE continues to delay meeting its obligation. Moreover, the ~~Obama~~current Presidential administration has taken specific steps to discontinue the Yucca Mountain project and study a new spent fuel strategy. Such actions included a motion to the NRC to withdraw the license application with prejudice and the establishment of a commission to develop recommendations for alternative spent fuel storage solutions. In August 2013 the U.S. Court of Appeals for the D.C. Circuit ordered the NRC to continue with the Yucca Mountain license review, but only to the extent of funds previously appropriated by Congress for that purpose and not yet used. This amount of money is not expected to be sufficient to complete the review. The government has taken no effective action to date related to the recommendations of the appointed spent fuel study commission. Accordingly, large uncertainty remains regarding the time frame under which the DOE will begin to accept spent fuel from ~~Entergy's~~Entergy’s facilities for storage or disposal. As a result, continuing future expenditures will be required to increase spent fuel storage capacity at ~~Entergy's~~Entergy’s nuclear sites.

Following the current Presidential administration’s defunding of the Yucca Mountain spent fuel repository program, the National Association of Regulatory Utility Commissioners and others sued the government seeking cessation of collection of the one mill ~~fees mentioned above. On~~per net kWh generated and sold after April 7, 1983 fee. In November ~~19,~~ 2013 the D.C. Circuit Court of Appeals ordered the DOE to submit a proposal to Congress to reset the fee to zero until the DOE complies with the Nuclear Waste Policy Act or Congress enacts an alternative waste disposal plan. OnIn January 3, 2014 the DOE submitted the proposal to Congress under protest, ~~but on that same date,~~and also filed a petition for rehearing with the D.C. Circuit. ~~Unless~~The petition for rehearing was denied. The zero spent fuel fee went into effect prospectively in May 2014. Management cannot predict the potential timing or magnitude of future spent fuel fee ~~proposal is withdrawn or other contrary court or legislative action is taken, the proposal will become the new fee after a statutorily required waiting period.~~revisions that may occur.

As a result of the ~~DOE's~~DOE’s failure to begin disposal of spent nuclear fuel in 1998 pursuant to the Nuclear Waste Policy Act of 1982 and the spent fuel disposal contracts, ~~Entergy's~~Entergy’s nuclear owner/licensee subsidiaries have incurred and will continue to incur damages. In November 2003 these subsidiaries, except for the owner of Palisades, began litigation to recover the damages caused by the ~~DOE's~~DOE’s delay in performance. ~~In October 2007 the U.S. Court~~Through 2014, Entergy’s subsidiaries have won and collected on judgments in excess of ~~Federal Claims awarded $48.7~~$200 million ~~jointly to System Fuels and~~, including approximately $48 million collected by Entergy Arkansas in 2013, against the U.S. for damages ~~related to~~caused by the ~~DOE's~~DOE’s breach of ~~its obligations.~~the contract. First round or second round damages cases are in progress covering each of the nuclear plants owned by Entergy subsidiaries. In ~~a revised decision~~2014 trials were held in three additional cases (second round ANO case, second round Grand Gulf case, and first round Waterford 3 case) but judgments have not yet been issued in March 2010, the court awarded $9.7 million jointly to System Fuels, System Energy, and SMEPA. Also in March 2010, in two separate decisions, the court awarded $106.1 million to Entergy Nuclear Indian Point 2, and $4.2 million to Entergy Nuclear Generation Company (the ownerany of ~~Pilgrim). In September 2010 the court awarded $46.6 million to Entergy Nuclear Vermont Yankee. All of these decisions were appealed by the DOE to the U.S. Court of Appeals~~those cases. A second round case was filed for the Federal Circuit (Federal Circuit). In September 2011 the Federal Circuit affirmed most of the Entergy Nuclear Generation Company award for Pilgrim, but remanded to the trial court for recalculation of certain damages. In April 2012 the U.S. Court of Federal Claims entered a final judgment in the amount of approximately $4 million in the Pilgrim case, and Entergy received payment of that amount in April 2013. In January 2012 the Federal Circuit affirmed the System Fuels and Entergy Arkansas award in large part, and reversed the trial court’s denial of certain damages sought, but remanded to the trial court for recalculation of certain damages. In April 2013 the U.S. Court of Federal Claims issued a judgment in favor of Entergy Arkansas and against the DOE in the remanded spent fuel case for damages in the amount of $47.8 million and Entergy Arkansas received

Pending DOE acceptance and disposal of spent nuclear fuel, the owners of nuclear plants are providing their own spent fuel storage. Storage capability additions using dry casks began operations at Palisades in 1993, at ANO in 1996, at FitzPatrick in 2002, at River Bend in 2005, at Grand Gulf in 2006, at Indian Point and Vermont Yankee in 2008, ~~and~~ at Waterford 3 in ~~2011.~~2011, and at Pilgrim in 2015. These facilities will be expanded as needed. ~~Current on-site spent fuel storage capacity at Pilgrim is estimated to be sufficient until 2014, by which time dry cask storage facilities are planned to be placed into service at that unit.~~

Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Texas, and System Energy are entitled to recover from customers through electric rates the estimated decommissioning costs for ANO, the portion of River Bend subject to retail rate regulation, Waterford 3, and Grand Gulf, respectively. The collections are deposited in trust funds that can only be used for future decommissioning costs. Entergy periodically reviews and updates the estimated decommissioning costs to reflect inflation and changes in regulatory requirements and technology, and then makes applications to the regulatory authorities to reflect, in rates, the changes in projected decommissioning costs.

Following a review in 2009, Entergy concluded that there was a funding shortfall for Vermont Yankee of approximately $40 million, which it satisfied with a $40 million guarantee from Entergy Corporation that is still in ~~place. On~~place subject to a 120-day notice of cancellation sent to the NRC in December 2014. In July ~~28,~~ 2010 the LPSC approved increased decommissioning collections for Waterford 3 and the Louisiana regulated share of River Bend and onin December ~~13,~~ 2010 the PUCT approved increased decommissioning collections for the Texas share of River Bend to address previously identified funding shortfalls. Entergy currently believes its decommissioning funding will be sufficient for its nuclear plants subject to retail rate regulation, although decommissioning cost inflation and trust fund performance will ultimately determine the adequacy of the funding amounts. See Note 1 to the financial statements for further discussion of Vermont Yankee decommissioning costs.

For the Indian Point 3 and FitzPatrick plants purchased in 2000, NYPA retained the decommissioning trusts and the decommissioning liabilities. NYPA and Entergy subsidiaries executed decommissioning agreements, which specify their decommissioning obligations. NYPA has the ~~rights~~right to require the Entergy subsidiaries to assume each of the decommissioning liabilities provided that it assigns the corresponding decommissioning trust, up to a specified level, to the Entergy subsidiaries. If the decommissioning liabilities are retained by NYPA, the responsible Entergy

In March ~~2013, Entergy Operations and~~2014, Entergy Nuclear Operations made filings with the NRC reporting on decommissioning funding for certain of Entergy’s nuclear plants. Those reports all showed that decommissioning funding for ~~the~~those nuclear plants met the NRC’s financial assurance requirements.

Additional information with respect to Entergy’s decommissioning costs and decommissioning trust funds is found in Note 9 and Note 17 to the financial statements.

The Price-Anderson Act requires that reactor licensees purchase and maintain the maximum amount of nuclear liability insurance available and participate in an industry assessment program called Secondary Financial Protection in order to protect the public in the event of a nuclear power plant accident. The costs of this insurance are borne by the nuclear power industry. Congress amended and renewed the Price-Anderson Act in 2005 for a term through 2025. The Price-Anderson Act limits the contingent liability for a single nuclear incident to a maximum assessment of approximately $127.318 million per reactor (with 104 nuclear industry reactors currently participating). In the case of a nuclear event in which Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, System Energy, or an Entergy Wholesale Commodities company is liable, protection is afforded through a combination of private insurance and the Secondary Financial Protection program. In addition to this, insurance for property damage, costs of replacement power, and other risks relating to nuclear generating units is also purchased. The Price-Anderson Act and insurance applicable to the nuclear programs of Entergy are discussed in more detail in Note 8 to the financial statements.

Entergy’s facilities and operations are subject to regulation by various governmental authorities having jurisdiction over air quality, water quality, control of toxic substances and hazardous and solid wastes, and other environmental matters. Management believes that Entergy’s businesses are in substantial compliance with environmental regulations currently applicable to its facilities and operations. Because environmental regulations are subject to change, future compliance requirements and costs cannot be precisely estimated. Except to the extent discussed below, at this time compliance with federal, state, and local provisions regulating the discharge of materials into the environment, or otherwise protecting the environment, is incorporated into the routine cost structure of Entergy’s businesses and is not expected to have a material effect on their competitive position, results of operations, cash flows, or financial position.

The Clean Air Act and its amendments establish several programs that currently or in the future may affect Entergy’s fossil-fueled generation facilities and, to a ~~much~~ lesser extent, certain operations at nuclear and other facilities. Individual states also operate similar independent state programs or delegated federal programs that may include requirements more stringent than federal regulatory requirements. These programs include:

Following are the amounts of Entergy Arkansas’s existing debt and lease obligations (includes estimated interest payments) and other purchase obligations.

Also in addition to the contractual obligations, Entergy Arkansas has ~~$2.0~~$1.9 million of unrecognized tax benefits and interest net of unused tax attributes for which the timing of payments beyond 12 months cannot be reasonably

Entergy Texas requires capital resources for:

Following are the amounts of Entergy Texas’s planned construction and other capital investments.

Following are the amounts of Entergy Texas’s existing debt and lease obligations (includes estimated interest payments) and other purchase obligations.

Also in addition to the contractual obligations, Entergy Texas has ~~$12.8~~$17 million of unrecognized tax benefits and interest net of unused tax attributes and payments 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.

In addition to routine capital spending to maintain operations, the planned capital investment estimate for Entergy Texas ~~includes~~amounts associated with specific investments, ~~and initiatives~~ such as the Union Power Station acquisition discussed below; NRC post-Fukushima requirements; environmental compliance spending; transmission ~~spending~~projects to ~~support~~enhance reliability, reduce congestion, and enable economic ~~development projects, reliability,~~growth; resource planning; generation projects; system improvements; and new compliance projects. Entergy’s Utility 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. The estimatedother investments. Estimated capital expenditures are subject to periodic review and modification and may vary based on the ongoing effects of regulatory constraints and requirements, environmental compliance, business opportunities, market volatility, economic trends, business restructuring, changes in project plans,and the ability to access capital. Management provides more information on long-term debt in Note 5 to the financial statements.

As a wholly-owned subsidiary, Entergy Texas pays dividends to Entergy Corporation from its earnings at a percentage determined monthly.

In December 2014, Entergy Arkansas, Entergy Gulf States Louisiana, and Entergy Texas entered into an asset purchase agreement to acquire the Union Power Station, a 1,980 MW (summer rating) power generation facility located near El Dorado, Arkansas, from Union Power Partners, L.P. The Union Power Station consists of four natural gas fired, combined-cycle gas turbine power blocks, each rated at 495 MW (summer rating). Pursuant to the agreement, Entergy Gulf States Louisiana will acquire two of the power blocks and a 50% undivided ownership interest in certain assets related to the facility, and Entergy Arkansas and Entergy Texas will each acquire one power block and a 25% undivided ownership interest in such related assets. (If Entergy Arkansas or Entergy Texas do not obtain approval for the purchase of their power blocks, Entergy Gulf States Louisiana will seek to purchase the power blocks not approved.) The base purchase price is expected to be approximately $948 million (approximately $237 million for each power block) subject to adjustments. In addition, Entergy Gulf States Louisiana anticipates selling 20% of the capacity and energy associated with its two power blocks to Entergy New Orleans through a cost-based, life-of-unit power purchase

Entergy Texas’s sources to meet its capital requirements include:

Entergy Texas may refinance, redeem, or otherwise retire debt prior to maturity, to the extent market conditions and interest and dividend rates are favorable.

All debt and common and preferred stock issuances by Entergy Texas require prior regulatory approval. Debt issuances are also subject to issuance tests set forth in its bond ~~indentures~~indenture and other agreements. Entergy Texas has sufficient capacity under these tests to meet its foreseeable capital needs.

Entergy Texas’s receivables from the money pool were as follows as of December 31 for each of the following years.

Entergy Texas has a credit facility in the amount of $150 million scheduled to expire in March ~~2018.~~2019. The credit facility allows Entergy Texas to issue letters of credit against 50% of the borrowing capacity of the facility. As of December 31, ~~2013,~~2014, there were no borrowings and ~~$25~~$1.3 million of letters of credit outstanding under the facility. ~~See Note 4~~In addition, Entergy Texas entered into an uncommitted letter of credit facility in 2014 as a means to ~~the financial statements for additional discussion~~post collateral to support its obligations under MISO. As of ~~the~~December 31, 2014, a $24.5 million letter of credit was outstanding under Entergy Texas’s letter of credit facility.

Entergy Texas ~~has~~ obtained ~~short-term borrowing authorization~~authorizations from the FERC through October 2015 ~~from the FERC under which it may borrow~~for short-term borrowings not to exceed an aggregate amount of $200 million at any ~~one~~ time outstanding ~~$200 million in the aggregate.~~and long-term borrowings and security issuances. See Note 4 to the financial statements for further discussion of Entergy Texas’s short-term borrowing limits.

In May 2014, Entergy Texas ~~has also obtained an order from~~issued $135 million of 5.625% Series first mortgage bonds due June 2064. Entergy Texas used the ~~FERC authorizing long-term securities issuances through October 2015.~~proceeds to pay, prior to maturity, a portion of its $150 million of 7.875% Series first mortgage bonds due June 2039.

The rates that Entergy Texas charges for its services significantly influence its financial position, results of operations, and liquidity. Entergy Texas is regulated and the rates charged to its customers are determined in regulatory proceedings. The PUCT, a governmental agency, is primarily responsible for approval of the rates charged to customers.

In November 2011, Entergy Texas filed a rate case requesting a $112 million base rate increase reflecting a 10.6% return on common equity based on an adjusted June 2011 test year. The rate case also proposed a purchased power recovery rider. On January 12, 2012, the PUCT voted not to address the purchased power recovery rider in the current rate case, but the PUCT voted to set a baseline in the rate case proceeding that would be applicable if a purchased power capacity rider is approved in a separate proceeding. In April 2012 the PUCT Staff filed direct testimony recommending a base rate increase of $66 million and a 9.6% return on common equity. The PUCT Staff, however,

In September 2012 the PUCT issued an order approving a $28 million rate increase, effective July 2012. The order includes a finding that “a return on common equity (ROE) of 9.80 percent will allow [Entergy Texas] a reasonable opportunity to earn a reasonable return on invested capital.” The order also provides for increases in depreciation rates and the annual storm reserve accrual. The order also reduced Entergy Texas’s proposed purchased power capacity costs, stating that they are not known and measureable; reduced Entergy Texas’s regulatory assets associated with Hurricane Rita; excluded from rate recovery capitalized financially-based incentive compensation; included $1.6 million of MISO transition expense in base rates, and reduced Entergy’s Texas’s fuel reconciliation recovery by ~~$4.0~~$4 million because it disagreed with the line-loss factor used in the calculation. After considering the progress of the proceeding in light of the PUCT order, Entergy Texas recorded in the third quarter 2012 an approximate $24 million charge to recognize that assets associated with Hurricane Rita, financially-based incentive compensation, and fuel recovery are no longer probable of recovery. Entergy Texas continues to believe that it is entitled to recover these prudently incurred costs, however, and it filed a motion for rehearing regarding these and several other issues in the PUCT’s order on October 4, 2012. Several other parties have also filed motions for rehearing of the PUCT’s order. The PUCT subsequently denied rehearing of substantive issues. Several parties, including Entergy Texas, have appealed the PUCT’s order to the Travis County District Court. A hearing ~~is expected~~was held in ~~April~~July 2014. In October 2014 the Travis County District Court issued an order upholding the PUCT’s decision except as to the line-loss factor issue referenced above, which was found in favor of Entergy Texas. In November 2014, Entergy Texas appealed the Travis County District Court decision and the PUCT appealed the decision on the line-loss factor issue. Entergy Texas expects to file briefs during the first half of 2015.

In September 2013, Entergy Texas filed a rate case requesting a $38.6 million base rate increase reflecting a 10.4% return on common equity based on an adjusted test year ending March 31, 2013. The rate case also proposed (1) a rough production cost equalization adjustment rider recovering Entergy Texas’s payment to Entergy New Orleans to achieve rough production cost equalization based on calendar year 2012 production costs and (2) a rate case expense rider recovering the cost of the 2013 rate case and certain costs associated with previous rate cases. The rate case filing also ~~includes~~included a request to reconcile $0.9 billion of fuel and purchased power costs and fuel revenues covering the period July 2011 through March 2013. The fuel reconciliation also reflects special circumstances fuel cost recovery of approximately $22 million of purchased power capacity costs. ~~If approved, new rates could go into effect as early as April 2014.~~ In January 2014 the PUCT staff filed direct testimony recommending a retail rate reduction of $0.3 million and a 9.2% return on common equity. In ~~February~~March 2014, Entergy Texas filed an Agreed Motion for Interim Rates. The motion explained that the parties to this proceeding have agreed

In September 2014, Entergy Texas filed for a distribution cost recovery factor rider based on a law that was passed in 2011 allowing for the recovery of increases in capital costs associated with distribution plant. Entergy Texas requested collection of approximately $7 million annually from retail customers. The parties reached a unanimous settlement ~~discussions continue.~~authorizing recovery of $3.6 million annually commencing with usage on and after January 1, 2015. A State Office of Administrative Hearings ALJ issued an order in December 2014 authorizing this recovery on an interim basis and remanded the case to the PUCT. In February 2015 the PUCT entered a final order, making the settlement final and the interim rates permanent.

Entergy Texas’s rate schedules include a fixed fuel factor to recover fuel and purchased power costs, including interest, not recovered in base rates. Semi-annual revisions of the fixed fuel factor are made in March and September based on the market price of natural gas and changes in fuel mix. The amounts collected under Entergy Texas’s fixed fuel factor and any interim surcharge or refund are subject to fuel reconciliation proceedings before the PUCT.

In December 2010, Entergy Texas filed with the PUCT a request to refund fuel cost recovery over-collections through October 2010. Pursuant to a stipulation among the parties that was approved by the PUCT in March 2011, Entergy Texas refunded over-collections through November 2010 of approximately $73 million, including interest through the refund period. The refund was made for most customers over a three-month period that began with the February 2011 billing cycle.

In October 2012, Entergy Texas filed with the PUCT a request to refund approximately $78 million, including interest, of fuel cost recovery over-collections through September 2012. Entergy Texas requested that the refund be implemented over a six-month period effective with the January 2013 billing month. Entergy Texas and the parties to the proceeding reached an agreement that Entergy Texas would refund $84 million, including interest and additional over-recoveries through October 2012, to most customers over a three-month period beginning January 2013. The PUCT approved the stipulation in January 2013. Entergy Texas completed this refund to customers in March 2013.

In July 2012, Entergy Texas filed with the PUCT an application to credit its customers approximately $37.5 million, including interest, resulting from the FERC’s October 2011 order in the System Agreement rough production cost equalization proceeding. See Note 2 to the financial statements for a discussion of the FERC’s October 2011 order. In September 2012 the parties submitted a stipulation resolving the proceeding. The stipulation provided that most Entergy Texas customers would be credited over a four-month period beginning October 2012. The credits were initiated with the October 2012 billing month on an interim basis, and the PUCT subsequently approved the stipulation, also in October 2012.

In August 2014, Entergy Texas filed an application seeking PUCT approval to implement an interim fuel refund of approximately $24.6 million for over-collected fuel costs incurred during the months of November 2012 through April 2014. This refund resulted from (i) applying $48.6 million in bandwidth remedy payments that Entergy Texas

At the ~~PUCT's~~PUCT’s April 2013 open meeting, the PUCT Commissioners discussed their view that a purchased power capacity rider was good public policy. The PUCT issued an order in May 2013 adopting the rule allowing for a purchased power capacity rider, subject to an offsetting adjustment for load growth. The rule, as adopted, also includes a process for obtaining pre-approval by the PUCT of purchased power agreements. Entergy Texas has not exercised the option to recover its capacity costs under the new rider mechanism, ~~due to the pending base rate case filed with the PUCT in September 2013,~~ but will continue to evaluate the benefits of utilizing the new rider to recover future capacity costs.

See “~~Entergy's~~Entergy’s Integration Into the MISO Regional Transmission Organization,”, “System Agreement,”, and “U.S. Department of Justice Investigation” in the “Rate, Cost-recovery, and Other Regulation – Federal Regulation” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for a discussion of these topics.

See the "“Nuclear Matters"” section of Entergy Corporation and Subsidiaries ~~Management's~~Management’s Financial Discussion and Analysis for a discussion of nuclear matters.

Entergy Texas’s large industrial and commercial customers continually explore ways to reduce their energy costs. In particular, cogeneration is an option available to a portion of Entergy Texas’s industrial customer base. Entergy Texas responds by working with industrial and commercial customers and negotiating electric service contracts to provide, under existing rate schedules, competitive rates that match specific customer needs and load profiles. Entergy Texas actively participates in economic development, customer retention, and reclamation activities to increase industrial and commercial demand, from both new and existing customers. Entergy Texas does not currently expect additional significant losses to cogeneration because of the current economics of the electricity markets and Entergy Texas’s marketing efforts in retaining industrial customers.

Entergy Texas’s facilities and operations are subject to regulation by various governmental authorities having jurisdiction over air quality, water quality, control of toxic substances and hazardous and solid wastes, and other

The preparation of Entergy Texas’s financial statements in conformity with generally accepted accounting principles requires management to apply appropriate accounting policies and to make estimates and judgments that

As discussed in Note 1 to the financial statements, Entergy Texas 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 and fuel price fluctuations, in addition to changes in certain components of the calculation.

Entergy ~~sponsors~~Texas’s qualified ~~defined benefit~~ pension ~~plans which cover substantially all employees. Additionally, Entergy currently provides~~and other 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. See the “Qualified Pension and Other Postretirement Benefits” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries’ Management’s Financial Discussion and Analysis for further discussion. 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.

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

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

Total qualified pension cost for Entergy Texas in ~~2013~~2014 was ~~$16.2 million, including a $1.6 million curtailment charge and a $855 thousand special termination charge related to workforce downsizing.~~$8.5 million. Entergy Texas anticipates ~~2014~~2015 qualified pension cost to be ~~$8.5~~$12.1 million. Entergy Texas contributed ~~$6.9~~$17.1 million to its qualified pension plans in ~~2013~~2014 and estimates ~~2014~~2015 pension contributions to be approximately ~~$18.5 million;~~$17.2 million, although the required pension contributions will not be known with more certainty until the January 1, ~~2014~~2015 valuations are completed by April 1, ~~2014. The expected increase in pension contributions is primarily due to the phase out of pension funding relief under MAP-21.~~2015.

Total postretirement health care and life insurance benefit ~~costs~~income for Entergy Texas in ~~2013 were $5.1 million, including a $1.4 million curtailment charge related to workforce downsizing.~~2014 was $2.8 million. Entergy Texas expects ~~2014~~2015 postretirement health care and life insurance benefit income to approximate ~~$2.8~~$3.0 million. Entergy Texas contributed ~~$4.8~~$3.4 million to its other postretirement plans in ~~2013~~2014 and expects to contribute approximately ~~$4.6~~$3.2 million in ~~2014.~~2015.

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 2014 actuarial study reviewed plan experience from 2010 through 2013. As a result of the 2014 actuarial study and the issuance of new mortality tables in October 2014 by the Society of Actuaries, changes were made to reflect modified demographic pattern expectations as well as longer life expectancies. These changes are reflected in the December 31, 2014 financial disclosures. Adoption of the new mortality assumptions for 2015 resulted in an increase at December 31, 2014 of $30.8 million in the qualified pension benefit obligation and $8.2 million in the accumulated postretirement obligation. The new mortality assumptions increased anticipated 2015 qualified pension cost by approximately $4.3 million and other postretirement cost by approximately $1 million. Pension funding guidelines, as established by the Employee Retirement Income Security Act of 1974, as amended and the Internal Revenue Code of 1986, as amended, are not expected to incorporate the October 2014 Society of Actuaries new mortality assumptions until after 2015, possibly 2016.

See the “Qualified Pension and Other Postretirement Benefits - Federal Healthcare Legislation” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for a discussion of Federal Healthcare Legislation.

See “New Accounting Pronouncements” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis.

System Energy’s principal asset currently consists of an ownership interest and a leasehold interest in Grand Gulf. The capacity and energy from its 90% interest is sold under the Unit Power Sales Agreement to its only four customers, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans. System Energy’s operating revenues are derived from the allocation of the capacity, energy, and related costs associated with its 90% interest in Grand Gulf pursuant to the Unit Power Sales Agreement. Payments under the Unit Power Sales Agreement are System Energy’s only source of operating revenues.

Net income decreased $17.3 million primarily due to a higher effective income tax rate and lower operating revenues resulting from lower rate base as compared with the same period in the prior year, partially offset by higher other regulatory credits. System Energy records a regulatory debit or credit for the difference between asset retirement obligation-related expenses and trust earnings plus asset retirement obligation-related costs collected in revenue. The increase in regulatory credits for 2014 compared to 2013 is primarily caused by increases in depreciation and accretion expenses and regulatory credits recorded in 2014 to realign the asset retirement obligation regulatory asset with regulatory treatment.

Net income increased $1.8 million primarily due to higher operating income and a lower effective income tax rate, partially offset by lower other income. Operating income was higher because of higher rate base compared to 2012 resulting from capital spending at Grand Gulf, including the uprate project. The lower effective income tax rate was primarily due to the reversal of a portion of the provision for uncertain tax positions. Other income was lower due to AFUDC accrued on the Grand Gulf uprate project in 2012. Grand Gulf’s Spring 2012 refueling outage was completed in June 2012, and the majority of uprate-related capital improvements were completed during this outage.

The effective income tax rates for 2014, 2013, and 2012 ~~and 2011~~ were 46.4%, 37.7%, and 40.8%, ~~and 53.9%,~~ respectively. The income tax rate for 2011 is primarily due to an intercompany settle up for federal income taxes for years prior to 2008 which include an allocation of the tax benefit of Entergy Corporation’s expenses to the subsidiaries generating taxable income for the respective years. The effects of various tax positions settled with the IRS pertaining to the 2006/2007 audit require System Energy to pay back prior benefits of the Entergy Corporation’s expenses it received when the benefits were originally allocated based upon the tax return as filed. See Note 3 to the financial statements for a reconciliation of the federal statutory rate of ~~35.0%~~35% to the effective income tax rates.

Cash flows for the years ended December 31, 2014, 2013, ~~2012,~~ and ~~2011~~2012 were as ~~follows.~~follows:

Net cash flow provided by operating activities increased $148.6 million in 2014 primarily due to income tax refunds of $10.1 million in 2014 compared to income tax payments of $211.2 million in 2013. The increase was partially offset by spending on the Grand Gulf refueling outage in 2014 and an increase of $12.9 million in pension contributions in 2014. System Energy made income tax payments in 2013 in accordance with the Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement. The income tax payments in 2013 resulted primarily from the reversal of temporary differences for which System Energy had previously claimed a tax deduction. See “Critical Accounting Estimates”below and Note 11 to the financial statements for a discussion of qualified pension and other postretirement benefits funding.

Net cash provided by operating activities decreased $132.4 million in 2013 primarily due to income tax payments of $211.2 million in 2013, as discussed above, compared to income tax refunds of $56.8 million in 2012, partially offset by spending on the Grand Gulf refueling outage in 2012. System Energy ~~had~~received income tax ~~payments~~refunds in ~~2013~~2012 in accordance with the Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement. ~~The income tax payments resulted primarily from the reversal of temporary differences for which System Energy had previously claimed a tax deduction.~~ The income tax refunds of $56.8 million in 2012 resulted primarily from a decrease of previously estimated 2011 taxable income due to the recognition of additional bonus depreciation.

Net cash flow used in investing activities increased $107.1 million in 2014 primarily due to:

Decreases in System Energy’s receivable from the money pool are a source of cash flow and System Energy’s

Net cash used in investing activities decreased $405.8 million in 2013 primarily due to a decrease in construction expenditures resulting from spending on the uprate project at Grand Gulf completed during the refueling outage in 2012 and a decrease in nuclear fuel activity primarily due to the Grand Gulf refueling outage in 2012. The decrease was partially offset by money pool activity.

Decreases in System Energy’s receivable from the money pool are a source of cash flow, and System Energy’s receivable from the money pool decreased $17.7 million in 2013 compared to decreasing by $93.5 million in 2012. ~~The money pool is an inter-company borrowing arrangement designed to reduce the Utility subsidiaries’ need for external short-term borrowings.~~

Net cash used in ~~investing~~financing activities ~~increased $191.2~~decreased $11 million in ~~2012~~2014 primarily due to:

Net cash used in financing activities increased $128.4 million in 2013 primarily due to:

System Energy’s capitalization is balanced between equity and debt, as shown in the following table. The decrease in the debt to capital ratio for System Energy as of December 31, 2013 is primarily due to a decrease in long-term debt as a result of the redemption of $70 million of 6.29% Series F notes, as discussed above, and an increase in retained earnings.

Net debt consists of debt less cash and cash equivalents. Debt consists of short-term borrowings and long-term debt, including the currently maturing portion. Capital consists of debt and common equity. Net capital consists of

System Energy requires capital resources for:

Following are the amounts of System Energy’s planned construction and other capital investments.

Following are the amounts of System Energy’s existing debt and lease obligations (includes estimated interest payments) and other purchase obligations.

Also in addition to the contractual obligations, System Energy has ~~$39.9~~$95.1 million of unrecognized tax benefits and interest net of unused tax attributes and payments 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.

In addition to routine spending to maintain operations, the planned capital investment estimate includes specific investments and initiatives such as NRC post-Fukushima requirements and plant improvements.

As a wholly-owned subsidiary, System Energy dividends its earnings to Entergy Corporation at a percentage determined monthly. Currently, all of System Energy’s retained earnings are available for distribution.

System Energy’s sources to meet its capital requirements include:

System Energy may refinance, redeem, or otherwise retire debt prior to maturity, to the extent market conditions and interest and dividend rates are favorable.

All debt and common stock issuances by System Energy require prior regulatory approval. Debt issuances are also subject to issuance tests set forth in its bond indentures and other agreements. System Energy has sufficient capacity under these tests to meet its foreseeable capital needs.

System Energy’s receivables from the money pool were as follows as of December 31 for each of the following years.

The System Energy nuclear fuel company variable interest entity has a credit facility in the amount of $125 million scheduled to expire in June 2016. ~~No borrowings were~~As of December 31, 2014, $20.4 million was outstanding on the variable interest entity credit ~~facility as of December 31, 2013.~~facility. See Note 4 to the financial statements for additional discussion of the variable interest entity credit facilities.

System Energy ~~has~~ obtained ~~a short-term borrowing authorization~~authorizations from the FERC ~~under which it may borrow,~~ through October 2015 upfor the following:

System Energy owns and operates Grand Gulf. System Energy is, therefore, subject to the risks related to owning and operating a nuclear plant. These include risks from the use, storage, handling and disposal of high-level and low-level radioactive materials, regulatory requirement changes, including changes resulting from events at other plants, limitations on the amounts and types of insurance commercially available for losses in connection with nuclear operations, and technological and financial uncertainties related to decommissioning nuclear plants at the end of their licensed lives, including the sufficiency of funds in decommissioning trusts. In the event of an unanticipated early

The nuclear industry continues to address susceptibility to stress corrosion cracking of certain materials within the reactor coolant system. The issue is applicable to Grand Gulf and is managed in accordance with industry standard practices and guidelines which include in-service examinations, replacements, and mitigation strategies. Developments in the industry or identification of issues at the nuclear units could require unanticipated remediation efforts that cannot be quantified in advance.

The nuclear industry continues to address susceptibility to stress corrosion cracking of certain materials within the reactor coolant system. The issue is applicable to Grand Gulf and is managed in accordance with industry standard practices and guidelines that include in-service examinations, replacements, and mitigation strategies. Developments in the ~~effective date 30 days after publication.~~industry or identification of issues at the nuclear units could require unanticipated remediation efforts that cannot be quantified in advance.

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 made initial recommendations, which were subsequently refined and prioritized after input from stakeholders. The task force then issued a second report in September 2011. Based upon the task force’s recommendations, the NRC issued three orders effective on March 12, 2012. The three orders require U.S. nuclear operators to undertake plant modifications and perform additional analyses that will, among other things, result in increased operating and capital costs associated with operating nuclear plants. The NRC, with input from the industry, is continuing to determine the specific actions required by the orders. System Energy’s estimated capital expenditures for 2015 through 2017 for complying with the NRC orders are included in the planned construction and ~~an estimate~~other capital investments estimates given in “Liquidity and Capital Resources - Uses of ~~the full amount of the increased costs cannot be made at this time.~~Capital” above.

System Energy’s facilities and operations are subject to regulation by various governmental authorities having jurisdiction over air quality, water quality, control of toxic substances and hazardous and solid wastes, and other environmental matters. Management believes that System Energy is in substantial compliance with environmental regulations currently applicable to its facilities and operations. Because environmental regulations are subject to change, future compliance costs cannot be precisely estimated.

The preparation of System Energy’s financial statements in conformity with generally accepted accounting principles requires management to apply appropriate accounting policies and to make estimates and judgments that

See “Nuclear Decommissioning Costs” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for discussion of the estimates inherent in accounting for nuclear decommissioning costs.

In the fourth quarter 2014, 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 $99.9 million increase in its decommissioning liability, along with a corresponding increase in the related asset retirement cost asset that will be depreciated over the remaining life of the unit.

In the fourth quarter 2013, 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 ~~$102.3~~$102.3 million increase in its decommissioning liability, along with a corresponding increase in the related asset retirement cost ~~asset.~~asset that will be depreciated over the remaining life of the unit.

~~Entergy sponsors~~System Energy’s qualified ~~defined benefit~~ pension ~~plans which cover substantially all employees. Additionally, Entergy currently provides~~and other 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. See the “Qualified Pension and Other Postretirement Benefits” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for further discussion. 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.

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

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

Total qualified pension cost for System Energy in ~~2013~~2014 was ~~$13.7 million, including a $2 million special termination charge related to workforce downsizing.~~$12.2 million. System Energy anticipates ~~2014~~2015 qualified pension cost to be ~~$12.2~~$16.6 million. System Energy contributed ~~$8.3~~$21.2 million to its pension plans in ~~2013~~2014 and estimates ~~2014~~2015 pension contributions to be approximately ~~$12.2 million;~~$20.8 million, although the required pension contributions will not be known with more certainty until the January 1, ~~2014~~2015 valuations are completed by April 1, ~~2014. The expected increase in pension contributions is primarily due to the phase out of pension funding relief under MAP-21.~~2015.

Total postretirement health care and life insurance benefit costs for System Energy in ~~2013~~2014 were ~~$5.7 million, including a $760 thousand curtailment charge related to workforce downsizing.~~$561 thousand. System Energy expects ~~2014~~2015 postretirement health care and life insurance benefit costs to approximate ~~$561~~$481 thousand. System Energy contributed ~~$5.4 million~~$334 thousand to its other postretirement plans in ~~2013~~2014 and expects to contribute ~~$864~~$475 thousand in ~~2014.~~2015.

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 2014 actuarial study reviewed plan experience from 2010 through 2013. As a result of the 2014 actuarial study and the issuance of new mortality tables in October 2014 by the Society of Actuaries, changes were made to reflect modified demographic pattern expectations as well as longer life expectancies. These changes are reflected in the December 31, 2014 financial disclosures. Adoption of the new mortality assumptions for 2015 resulted in an increase at December 31, 2014 of $17.7 million in the qualified pension benefit obligation and $3.1 million in the accumulated postretirement obligation. The new mortality assumptions increasedanticipated 2015 qualified pension cost by approximately $2.7 million and other postretirement cost by approximately $0.4 million. Pension funding guidelines, as established by the Employee Retirement Income Security Act of 1974, as amended and the Internal Revenue Code of 1986, as amended, are not expected to incorporate the October 2014 Society of Actuaries new mortality assumptions until after 2015, possibly 2016.

See the “Qualified Pension and Other Postretirement Benefits - Federal Healthcare Legislation” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for a discussion of Federal Healthcare Legislation.

See “New Accounting Pronouncements” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis.

Information regarding the registrant’s properties is included in Part I. Item 1. - Business under the sections titled “Utility - Property and Other Generation Resources” and “Entergy Wholesale Commodities - Property” in this report.

Details of the registrant’s material environmental regulation and proceedings and other regulatory proceedings and litigation that are pending or those terminated in the fourth quarter of ~~2012~~2014 are discussed in Part I. Item 1. - Business under the sections titled “Retail Rate Regulation”, “Environmental Regulation”, and “Litigation” and "“Impairment of Long-Lived Assets"” in Note 1 to the financial statements in this report.

Not applicable.

Each officer of Entergy Corporation is elected yearly by the Board of Directors. Each ~~officer's~~officer’s age and title is provided as of December 31, ~~2013.~~2014.

The shares of Entergy Corporation’s common stock are listed on the New York Stock and Chicago Stock Exchanges under the ticker symbol ETR.

The high and low prices of Entergy Corporation’s common stock for each quarterly period in ~~2013~~2014 and ~~2012~~2013 were as follows:

Consecutive quarterly cash dividends on common stock were paid to stockholders of Entergy Corporation in ~~2013~~2014 and ~~2012.~~2013. Quarterly dividends of $0.83 per share were paid in ~~2013~~2014 and ~~2012.~~2013.

As of January 31, ~~2014,~~2015, there were ~~32,163~~30,762 stockholders of record of Entergy Corporation.

In accordance with Entergy’s stock-based compensation plans, Entergy periodically grants stock options to key employees, which may be exercised to obtain shares of Entergy’s common stock. According to the plans, 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 plans. In addition to this authority, the Board has authorized share repurchase programs to enable opportunistic purchases in response to market conditions. In October 2010 the Board granted authority for a $500 million share repurchase program. The amount of share repurchases under these programs may vary as a result of material changes in business results or capital spending or new investment opportunities. In addition, in the first quarter ~~2013,~~2014, Entergy withheld ~~62,841~~55,076 shares of its common stock at ~~$64.45~~$61.29 per share and 43,246 shares of its common stock at $63.03 per share to pay income taxes due upon vesting of restricted stock granted as part of its long-term incentive program.

There is no market for the common stock of Entergy Corporation’s wholly owned subsidiaries. Cash dividends on common stock paid by the Registrant Subsidiaries during ~~2013~~2014 and ~~2012,~~2013, were as follows:

Information with respect to restrictions that limit the ability of the Registrant Subsidiaries to pay dividends is presented in Note 7 to the financial statements.

Refer to “SELECTED FINANCIAL DATA - FIVE-YEAR COMPARISON OF ENTERGY CORPORATION AND SUBSIDIARIES, ENTERGY ARKANSAS, INC. AND SUBSIDIARIES, ENTERGY GULF STATES LOUISIANA, L.L.C., ENTERGY LOUISIANA, LLC, ENTERGY MISSISSIPPI, INC., ENTERGY NEW ORLEANS, INC., ENTERGY TEXAS,

Refer to “MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS OF ENTERGY CORPORATION AND SUBSIDIARIES, ENTERGY ARKANSAS, INC. AND SUBSIDIARIES, ENTERGY GULF STATES, LOUISIANA, L.L.C., ENTERGY LOUISIANA, LLC, ENTERGY MISSISSIPPI, INC., ENTERGY NEW ORLEANS, INC., ENTERGY TEXAS, INC. AND SUBSIDIARIES, and SYSTEM ENERGY RESOURCES, INC.”

Refer to “MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS OF ENTERGY CORPORATION AND SUBSIDIARIES - Market and Credit Risk Sensitive Instruments.”

Refer to “TABLE OF CONTENTS - Entergy Corporation, 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.”

No event that would be described in response to this item has occurred with respect to Entergy Corporation, Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, or System Energy.

As of December 31, ~~2013~~,2014, evaluations were performed under the supervision and with the participation of Entergy Corporation, Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy (individually “Registrant” and collectively the “Registrants”) management, including their respective Principal Executive Officers (PEO) and Principal Financial Officers (PFO). The evaluations assessed the effectiveness of the Registrants’ disclosure controls and procedures. Based on the evaluations, each PEO and PFO has concluded that, as to the Registrant or Registrants for which they serve as PEO or PFO, the Registrant’s or Registrants’ disclosure controls and procedures are effective to ensure that information required to be disclosed by each Registrant in reports that it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in Securities and Exchange Commission rules and forms; and that the Registrant’s or Registrants’ disclosure controls and procedures are also effective in reasonably assuring that such information is accumulated and communicated to the Registrant’s or Registrants’ management, including their respective PEOs and PFOs, as appropriate to allow timely decisions regarding required disclosure.

(Entergy Corporation, Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy)

The managements of Entergy Corporation, Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy (individually “Registrant” and collectively the “Registrants”) are responsible for establishing and maintaining adequate internal control over financial reporting for the Registrants. Each Registrant’s internal control system is designed to provide reasonable

All internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation.

Each Registrant’s management assessed the effectiveness of each Registrant’s internal control over financial reporting as of December 31, ~~2013~~.2014. In making this assessment, each Registrant’s management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control - Integrated Framework. The ~~original 1992~~2013 COSO Framework was utilized for ~~management's~~management’s assessment.

Based on each management’s assessment and the criteria set forth by the ~~original 1992~~2013 COSO Framework, each Registrant’s management believes that each Registrant maintained effective internal control over financial reporting as of December 31, ~~2013~~.2014.

The ~~Registrants’~~report of Deloitte & Touche LLP, Entergy Corporation’s independent registered public accounting firm, ~~has issued an attestation report on each Registrant’s~~regarding Entergy Corporation’s internal control over financial ~~reporting.~~reporting is included herein on page 529. The report of Deloitte & Touche LLP is not applicable to Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy because these Registrants are non-accelerated filers.

Under the supervision and with the participation of each Registrant’s management, including its respective PEO and PFO, each Registrant evaluated changes in internal control over financial reporting that occurred during the quarter ended December 31, ~~2013~~2014 and found no change that has materially affected, or is reasonably likely to materially affect, internal control over financial reporting.

Information required by this item concerning directors of Entergy Corporation is set forth under the heading “Item 1 – Election of Directors” contained in the Proxy Statement of Entergy Corporation, to be filed in connection with its Annual Meeting of Stockholders to be held May ~~2, 2014,~~8, 2015, and is incorporated herein by reference.

Each director and officer of the applicable Entergy company is elected yearly to serve by the unanimous consent of the sole stockholder with the exception of the directors and officers of Entergy Gulf States Louisiana, L.L.C. and Entergy Louisiana, LLC, who are elected yearly to serve by the unanimous consent of the sole common membership owners, EGS Holdings, Inc. and Entergy Louisiana Holdings, respectively. Entergy Corporation’s directors are elected annually at the annual meeting of shareholders. Entergy Corporation’s officers are elected at the annual organizational meeting of the Board of Directors.

Each of the Audit, Corporate Governance, and Personnel Committees of Entergy Corporation’s Board of Directors operates under a written charter. In addition, the full Board has adopted Corporate Governance Guidelines. Each charter and the guidelines are available through Entergy’s website (www.entergy.com) or upon written request.

The following directors are members of the Audit Committee of Entergy Corporation’s Board of Directors:

The Board of Directors has adopted a Code of Business Conduct and Ethics for Members of the Board of Directors. The code is available through Entergy’s website (www.entergy.com) or upon written request. The Board has also adopted a Code of Business Conduct and Ethics for Employees that includes Special Provision Relating to Principal Executive Officer and Senior Financial Officers. The Code of Business Conduct and Ethics for Employees is to be read in conjunction with Entergy’s omnibus code of integrity under which Entergy operates called the Code of Entegrity as well as system policies. All employees are required to abide by the Codes. Non-bargaining employees are required to acknowledge annually that they understand and abide by the Code of Entegrity. The Code of Business Conduct and Ethics for Employees and the Code of Entegrity are available through Entergy’s website (www.entergy.com) or upon written request.

The Corporate Governance Committee does not have any single method for identifying director candidates but will consider candidates suggested by a wide range of sources including director candidates recommended by Entergy ~~Corporation's~~Corporation’s shareholders. Shareholders wishing to recommend a candidate to the Corporate Governance Committee should do so by submitting the recommendation in writing to Entergy ~~Corporation's~~Corporation’s Secretary at 639 Loyola Avenue, P.O. Box 61000, New Orleans, LA 70161, and it will be forwarded to the Corporate Governance Committee members for their consideration. Any recommendation should include:

Once the Corporate Governance Committee receives the recommendation, it may request additional information from the candidate about the ~~candidate's~~candidate’s independence, qualifications, and other information that would assist the Corporate Governance Committee in evaluating the candidate, as well as certain information that must be disclosed about the candidate in the Proxy Statement, if nominated. The Corporate Governance Committee will apply the same standards in considering director candidates recommended by shareholders as it applies to other candidates.

Information called for by this item concerning the directors and officers of Entergy Corporation is set forth in the Proxy Statement of Entergy Corporation to be filed in connection with its Annual Meeting of Stockholders to be held on May ~~2, 2014,~~8, 2015, under the heading “Section 16(a) Beneficial Ownership Reporting Compliance”, which information is incorporated herein by reference.

Information concerning the directors and officers of Entergy Corporation is set forth in the Proxy Statement under the headings ~~"Compensation~~“Compensation Discussion and Analysis,~~" "Executive~~” “Executive Compensation Tables,~~" "Nominees~~” “Nominees for the Board of Directors,"” and ~~"Non-Employee~~“Non-Employee Director Compensation,"” all of which information is incorporated herein by reference.

In this section, the compensation earned by the following Named Executive Officers in ~~2013~~2014 is discussed. Each officer’s title is provided as of December 31, ~~2013.~~

Mr. Denault, Mr. ~~Forbes,~~Marsh, Ms. Mount, Mr. ~~Marsh, Mr. Mohl~~Savoff, and Mr. West serve as executive officers of Entergy Corporation. No additional compensation was paid in ~~2013~~2014 to Mr. Denault, Mr. Marsh, Ms. Mount, Mr. ~~Mohl~~Savoff, or Mr. West for their service as Named Executive Officers of Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas (the ~~"Subsidiaries"~~“Subsidiaries”). Ms. Mount is included in the Executive Compensation section of this Form 10-K because she served as the principal financial officer of the Subsidiaries for a portion of 2014.

Entergy ~~Corporation's~~Corporation’s executive compensation programs are based on a philosophy of pay-for-performance that is embodied in the design of ~~the~~its annual and long-term incentive plans. In keeping with this philosophy approximately 80% of the annual target compensation of Entergy Corporation’s Chief Executive Officer ~~(excluding non-qualified supplemental retirement income)~~ is “at risk,” with the substantial majority of this “at risk” compensation consisting of awards under the Executive Annual Incentive Plan (or Annual Incentive Plan) and the Long-Term Performance Unit Program, and the balance consisting of stock option and restricted stock awards.equity or performance-based compensation.

Pay outcomes for the Named Executive Officers during ~~2013~~2014 demonstrated the application of this ~~pay- for-performance~~pay-for-performance philosophy.

Awards under ~~the~~Entergy Corporation’s Annual Incentive Plan are tied to ~~operational~~its financial performance through the Entergy Achievement Multiplier, which is the performance metric used to determine the funding of awards under the plan. For ~~2013,~~2014, the Entergy Achievement Multiplier was determined based in equal part on ~~the~~Entergy Corporation’s success in achieving its operational earnings per share and operating cash flow goals. These goals were ~~set~~approved by the Personnel Committee at the beginning of the year based on Entergy Corporation’s financial plan and the Board’s overall goals for Entergy Corporation and were consistent with its published earnings guidance.

For ~~2013,~~2014, the Personnel Committee, based on the recommendation of the Finance Committee, determined that management exceeded its operational earnings per share goal of $5.00 per share by ~~$0.36~~$0.83 per share and ~~met~~exceeded its operational operating cash flow goal of ~~$3.25~~$3.43 billion ~~in each case based~~by approximately $517 million. Based on ~~operational earnings and operating cash flow, which excluded from as-reported results special items relating to~~the targets previously determined by the Committee, Entergy Corporation’s decision to close the Vermont Yankee Nuclear Power Station and a related settlement reached with the State of Vermont in 2013, the implementation of the human capital management strategic initiative, and Entergy Corporation’s proposed spin-merge transaction with ITC Holdings Corp. (the “ITC Transaction”). The Personnel Committee evaluated each of these adjustments to as-reported results and concluded that they were appropriate in light of management’s performance with respect to these matters and the Committee’s view that, in general, management’s performance for purposes of determining Annual Incentive Plan awards should be measured against operational financial results, since operational results form the basis for Entergy Corporation’s financial plan and guidance to investors and are the primary basis on which itsoutstanding financial performance ~~is evaluated by investors.~~

Under the Long-Term Performance Unit Program, a substantial portion of targeted executive officer pay is tied directly to ~~Entergy’s~~Entergy Corporation’s relative total shareholder return. Under this program, Entergy Corporation measures performance ~~is measured~~ over a three-year period by assessing ~~Entergy Corporation’s~~Entergy’s total shareholder return in relation to the total shareholder return of the companies included in the Philadelphia Utility Index, with payouts based solely on Entergy Corporation’s performance relative ~~performance. Performance is measured~~to the other companies in the index. Entergy Corporation measures performance based on relative total shareholder return because it encourages the executives to deliver superior shareholder value in relation to Entergy Corporation’s peers and rewards not just stock price appreciation, but also the ability to deliver significant dividends to ~~shareholders.~~shareholders, and takes into account market fluctuations in the utility sector.

~~Although~~ Entergy Corporation’s total shareholder return, which had substantially lagged the returns of its peer group in 2012, improved significantly in 2013 ~~both on an absolute basis~~ and, ~~in relation to its peers,~~for 2014, was near the top of the Philadelphia Utility Index. As a result, following a review by the Finance Committee and the Personnel Committee of Entergy Corporation’s total shareholder return ~~for~~in relation to the ~~2011 through 2013 performance period was~~total shareholder return of the companies in the ~~bottom~~Philadelphia Utility Index, the Personnel Committee determined that Entergy Corporation’s relative total shareholder return fell within the third quartile of the Philadelphia Utility Index ~~which resulted in a zero payout~~ for the 2012-2014 performance ~~units granted~~period, resulting in ~~2011 for all~~payouts of 64.64% of target. Such payouts were made 100% in shares of Entergy Corporation stock that are required to be held by the Named Executive Officers. This compares with a grant date target opportunity of $1,111,023 for Entergy Corporation’s Chief Executive Officer and grant date payout opportunities ranging from $243,224 to $544,393~~for~~executives until they satisfy the ~~other Named Executive Officers for this performance period.~~executive stock ownership guidelines.

Entergy Corporation’s executive compensation programs are based on a philosophy of pay-for-performance that is embodied in the design of ~~the~~its annual and long-term incentive plans. Entergy Corporation believes the executive pay programs described in this section and in the accompanying tables have played a material role in its ability to drive strong financial and operational results and to attract and retain a highly experienced and successful management team. The ~~annual incentive plan~~Annual Incentive Plan incentivizes and rewards the achievement of operational financial metrics that are deemed by the Personnel Committee to be consistent with the overall goals and strategic direction that the Board has ~~set. The~~approved for Entergy Corporation. Entergy Corporation’s long-term incentive programs further align the interests of its executives and ~~Entergy Corporation’s~~its shareholders by directly tying the value of the equity awards granted to executives under these programs to the performance of Entergy Corporation’s stock price and its total shareholder return. ~~Entergy Corporation believes the executive pay programs described in this section and in the accompanying tables have played a material role in the ability~~By incentivizing officers to ~~drive strong~~achieve important financial and operational ~~results~~objectives and ~~to attract~~create long-term shareholder value, these programs play a key role in creating sustainable value for the benefit of all of Entergy Corporation's stakeholders, including its owners, customers, employees, and ~~retain a highly experienced and successful management team.~~communities.

To develop a competitive compensation program, the Personnel Committee annually reviews compensation data from two sources:

The Committee uses published and private compensation survey data to develop marketplace compensation levels for the executive officers. The data, which isare compiled by Pay Governance, LLC, the Committee’s independent compensation consultant, ~~compares~~compare the current compensation opportunities provided to each of the executive officers against the compensation opportunities provided to executives holding similar positions at companies with corporate revenues similar to Entergy Corporation’s. For non-industry specific positions such as a chief financial officer, the Committee reviews general industry data for total cash compensation (base salary and annual incentive). since the market for talent is broader than the utility sector. For management positions that are industry-specific such as Group President, Utility Operations, the Committee reviews data from utility companies for total cash compensation. However, for long-term incentives, all positions are reviewed relative to utility market data. The survey

The Committee uses this survey data to develop compensation opportunities that are designed to deliver total target compensation at approximately the 50^th percentile of the surveyed companies. The survey data are the primary data used for purposes of ~~determining~~assessing target compensation. As a result, Mr. Denault, Entergy Corporation’s Chief Executive Officer, is compensated at a higher level than ~~Entergy Corporation’s~~the other Named Executive Officers, reflecting market practices that compensate chief executive officers at greater potential compensation levels with more ~~“pay at~~pay “at risk” than other named executive officers, due to the greater responsibilities and accountability required of a Chief Executive Officer. In most cases, the Committee considers its objectives to have been met if Entergy Corporation’s Chief Executive Officer and the eight (8) other executive officers ~~(including all of the Named Executive Officers)~~ who constitute what ~~is referred~~Entergy Corporation refers to as ~~the~~its Office of the Chief Executive each have a target compensation opportunity that falls within the range of 85% ~~- 115%~~-115% of the 50th percentile of the survey data. Promoted officers or officers who are new to their roles may be transitioned into the targeted market range over time. Actual compensation received by an individual officer may be above or below the targeted range based on an individual officer’s skills, performance, experience and responsibilities, corporate performance, and internal pay equity. For ~~2013,~~2014, the total target compensation of each of the Named Executive Officers fell within the targeted range except for three officers whose total target compensation fell below the targeted range and another officer whose total targeted compensation was set above the targeted range, based on the Committee’s assessment of his skills, performance, experience and responsibilities and internal pay equity.range.

Although the survey data described above isare the primary data used in determining compensation, the Committee reviews data derived from the proxy statements of companies included in the Philadelphia Utility Index as an additional point of comparison. The proxy data are used to compare the compensation levels of the Named Executive Officers with the compensation levels of the corresponding top five highest paid executive officers of the companies included in the Philadelphia Utility Index, as reported in their proxy statements, based on pay rank and without regard to roles and responsibilities, except with respect to the Chief Executive Officer and Chief Financial Officer, for whom comparable roles are used. The Personnel Committee uses this analysis to evaluate the overall reasonableness of the Entergy ~~Corporation's~~Corporation’s compensation programs. The following companies were included in the Philadelphia Utility Index at the time the proxy data ~~was~~from the 2014 filings of the Index were compiled:

The following table ~~lists~~summarizes the elements of target direct compensation ~~for~~granted or paid to the ~~2013~~executive officers under the 2014 executive compensation program. The program uses a mix of fixed and variable compensation elements and provides alignment with both

The Personnel Committee determines the base salaries for all of the Named Executive Officers who are members of the Office of the Chief Executive based on competitive compensation data, performance considerations, and advice provided by the Committee’s independent compensation consultant. For the other Named Executive Officers, their salaries are established by their immediate supervisors using the same criteria. The Committee also ~~uses~~considers internal pay equity; however, the Committee has not established any predetermined formula against which the base salary of one Named Executive Officer is measured against another officer or employee.

In ~~2013,~~2014, all of the Named Executive Officers received merit increases in their base salaries ~~in the range of 2.0~~ranging from 2 to ~~5.8 percent, except for Messrs. Denault, Marsh, Forbes, May and Mohl. These~~5 percent. The increases in base salary were made in light of current economic conditions and the projected growth in executive salaries in ~~2013~~2014 based on ~~general industry surveys obtained from human resources consulting firms,~~the market data previously discussed in this CD&A under “What Entergy Corporation Pays and Why - How Entergy Corporation Sets Target Pay,” as well as an internal pay equity comparison. The salary increases shown for Messrs. Denault, Forbes, Marsh, May and Mohl from 2012 to 2013 were determined in conjunction with their promotion to new positions assumed in 2013. The Committee determined the compensation levels for each of these officers using competitive compensation data provided by its independent compensation consultant. The Committee also considered their previous compensation levels and the compensation paid to their predecessors. In determining the 2013 base salaries, the Committee sought to position the compensation for each officer, other than Mr. Mohl and Mr. May, at below market levels with the intent of transitioning them to market-competitive levels over time. Mr. Mohl’s salary was established, in consultation with the independent compensation consultant, to reflect his unique responsibilities and accountability as President of the wholesale commodities business.

The following table sets forth the ~~2012~~2013 and ~~2013~~2014 base salaries for the Named Executive Officers. Changes in base salaries for 2014 were effective ~~either upon the date of the officers’ promotion or~~ in ~~April of the years shown, for those who received merit increases.~~April.

~~Performance-based~~Entergy Corporation includes performance-based incentives ~~are included~~ in the Named Executive Officers’ compensation packages because ~~Entergy Corporation~~it believes performance-based incentives encourage the Named Executive Officers to pursue objectives consistent with the overall goals and strategic direction that the Board has ~~set~~approved for Entergy Corporation. ~~Annual incentive plans are commonly used by companies in a variety of industry sectors to compensate their executive officers for achieving financial and operational goals.~~

Under the Annual Incentive Plan, Entergy Corporation uses a performance metric known as the Entergy Achievement Multiplier ~~is used~~ to determine the percentage of target annual plan opportunities that will be paid each year to each Named Executive Officer, subject to adjustment based on individual performance.

Target awards are set based on an executive officer’s position and executive management level within the Entergy organization. Executive management levels at Entergy range from Level 1 through Level 4. At December 31, ~~2013,~~2014, Mr. Denault held a Level 1 position, Messrs. ~~Forbes,~~ Marsh, ~~Mohl~~Savoff, and West held positions in Level 2, Ms. Mount and Mr. May held Level 3 positions and the remaining Named Executive Officers held positions in Level 4. Accordingly, their respective incentive targets differ one from another based on the external market data developed by the Committee’s independent compensation consultant and the other factors noted above.

Each year the Personnel Committee reviews the performance measures used to determine the Entergy Achievement Multiplier. In December 2013, the Personnel Committee decided to retain for 2014 the performance measures used for determining the 2013 Entergy Achievement Multiplier. These measures were operational earnings per share and operating cash flow, with each measure weighted equally. The Committee considered a variety of other potential measures, but determined that operational earnings per share and operating cash flow continued to be the

The Personnel Committee also engages in a rigorous process each year to establish the targets for the Annual Incentive Plan with a goal of establishing target achievement levels that are consistent with Entergy Corporation’s strategy and business objectives for the upcoming year, as reflected in its financial plan, and sufficient to drive results that represent a high level of achievement for Entergy Corporation, taking into consideration the applicable business environment and specific challenges facing it. These targets are approved based on a comprehensive review by the full Board of Entergy Corporation’s financial plan, including changes in commodity market conditions and other key drivers of anticipated changes in performance from the preceding year. The Committee further confirms that the targets it approves are aligned with the earnings guidance that will be communicated to the financial markets, which assures that the internal targets approved for purposes of Entergy Corporation’s incentive compensation plans are aligned with the external expectations set and communicated to its shareholders.

In December 2013, after full Board review of management’s 2014 financial plan for Entergy Corporation and engaging in the process discussed above, the Committee determined the Annual Incentive Plan targets to be used for purposes of determining annual bonuses for 2014. In keeping with its past practice, the Committee also determined that for purposes of measuring performance against such targets, the Committee would exclude the effect on as-reported results of activities related to special items that would be excluded in determining operational results, and the effect of any major storms that may occur during the year.

The following table shows the Annual Incentive Plan targets established by the Personnel Committee in December 2013, and 2014 results:

In January ~~2014,~~2015, the Finance and Personnel Committees reviewed Entergy Corporation’s financial results against the performance objectives reflected in the table above. Based on the Finance Committee’s recommendation, the Personnel Committee determined that ~~for 2013,~~ management exceeded its operational earnings per share goal of $5.00 per share by ~~$0.36~~$0.83 per share and ~~met~~exceeded its operational operating cash flow goal of ~~$3.25~~$3.43 billion ~~in each case based on operational earnings and operating cash flow, which~~by approximately $517 million. Operational results excluded from as-reported results special items recorded for (i) ~~an impairment and other~~ expenses associated with the ~~planned closure~~shutdown in December 2014 of the Vermont Yankee Nuclear Power Station and the related settlement agreement reached with the State of Vermont in ~~2013,~~2014, and (ii) expenses for the implementation of the ~~human capital management~~Human Capital Management strategic ~~initiative~~imperative in ~~2013, and (iii) costs associated with Entergy Corporation’s proposed spin-merge transaction~~2014. The exclusion of these items was consistent with the ~~ITC Transaction, offset by a related tax benefit. The adjustment~~Committee’s decision to ~~as-reported results~~approve the annual incentive plan targets for ~~costs associated with~~2014 on the ~~ITC Transaction had been identified as a special item at the time the goals were set, but the other special items had arisen during the year. The Committee evaluated each~~basis of these adjustments to as-reported results and concluded that they were appropriate in light of the Committee’s view that, in general, management’s performance for purposes of determining Annual Incentive Plan awards should be measured againstEntergy Corporation’s operational financial results, ~~since operational~~because such results form the basis for Entergy Corporation’s financial plan and guidance to investors and are the primary basis on which ~~Entergy Corporation’s~~its financial performance is evaluated by investors.

Based on the targets previously determined by the Committee, Entergy Corporation’s outstanding financial performance in 2014 exceeded the maximum target achievement approved by the Committee, and would have resulted

Based on the foregoing evaluation of management performance and the recommendation of the Finance Committee, the Personnel Committee certified an Entergy Achievement Multiplier of ~~136%~~195% for ~~2013, consistent with~~2014 for the strong financial results achieved by Entergy Corporation, despite the significant challenges posed in 2013, including continued low wholesale power prices and regulatory challenges and uncertainty related to Entergy Corporation’s wholesale nuclear plants. In reaching this decision, the Committee also took into account management's performance in relation to a number of strategic initiatives and decisions undertaken in 2013, including the successful integration of the transmission systems owned by Entergy Corporation’s utility operating companies into MISO, the decision to close the Vermont Yankee Nuclear Power Station and related settlement agreement with the State of Vermont, the development and implementation of the human capital management initiative, and management’s unsuccessful effort to complete the ITC Transaction. This compares with an Entergy Achievement Multiplier of 104% and a payout to members of the Office of the Chief Executive of 95% of target for 2012, when Entergy Corporation exceeded its earnings per share target by a smaller margin and fell short of its operating cash flow goal and the Personnel Committee reduced the awards paid to reflect management’s failure to meet the Committee’s expectations with respect to employee safety.

~~458~~

~~Table of Contents~~

The following table shows the Annual Incentive Plan ~~payments as a percentage of base salary for 2013, as well as the incentive awards paid~~payouts to each Named Executive Officer for ~~2013.~~2014.


Named Executive Officer	Base Salary	Target as Percentage of Base Salary	Payout as Percentage of Base Salary	2013 Annual Incentive Award	Base Salary	Target as Percentage of Base Salary	Payout as Percentage of Base Salary	2014 Annual Incentive Award
Leo P. Denault	$1,085,000	120%	163%	$1,770,720	$1,110,000	120%	234%	$2,597,400
Jeffrey D. Forbes	$550,000	70%	95%	$523,600
Haley R. Fisackerly					$302,934	40%	64%	$193,878
Andrew S. Marsh	$500,000	70%	95%	$476,000	$517,500	70%	137%	$706,388
Roderick K. West	$612,726	70%	95%	$583,315
Haley R. Fisackerly	$296,174	40%	48%	$142,368
Phillip R. May, Jr.	$330,000	60%	72%	$238,223	$338,250	60%	78%	$263,835
Hugh T. McDonald	$345,220	50%	56%	$191,562	$352,121	50%	65%	$228,879
William M. Mohl	$560,000	70%	95%	$533,120
Alyson M. Mount	$286,700	60%	86%	$245,000	$301,100	60%	108%	$325,188
Sallie T. Rainer	$291,000	40%	48%	$140,184	$298,275	40%	58%	$171,500
Charles L. Rice, Jr.	$257,144	40%	44%	$112,446	$262,275	40%	64%	$167,864
Mark T. Savoff					$644,896	70%	137%	$880,283
Roderick K. West					$628,044	70%	137%	$857,280

~~The~~Entergy Corporation’s goal for ~~the~~its long-term incentive compensation is to focus the executive officers on building shareholder value and to increase the executive officers’ ownership of Entergy ~~Corporation~~Corporation’s common ~~stock.~~stock in order to more closely align their interest with those of its shareholders. In ~~the~~its long-term incentive compensation ~~programs,~~program, Entergy Corporation uses a mix of performance units, restricted stock, and stock options. Performance units reward the Named Executive Officers on the basis of total shareholder return, which is a measure of stock price appreciation and dividend payments, in relation to the companies in the Philadelphia Utility Index. Restricted stock ties the executive officers’ long-term financial interest to the long-term financial interests of Entergy Corporation’s shareholders. Stock options provide a direct incentive to increase the ~~price~~value of Entergy Corporation’s common stock. In general, Entergy Corporation seeks to allocate the total value of long-term incentive compensation 60% to performance units and 40% to a combination of stock options and restricted stock, equally divided in value,

All of the performance units, shares of restricted stock, and stock options granted to the Named Executive Officers in ~~2013~~2014 were awarded under ~~the~~Entergy Corporation’s 2011 Equity Ownership ~~Plan. All equity awards granted under the equity ownership plans require~~Plan and Long-Term Cash

~~Performance~~Entergy Corporation issues performance unit awards ~~are issued~~ to the Named Executive Officers under ~~the~~its Long-Term Performance Unit Program. Each performance unit represents the value of one share of Entergy ~~Corporation~~Corporation’s common stock at the end of the three-year performance period, plus dividends accrued during the performance period. The Personnel Committee ~~sets~~approves payout opportunities for the program at the outset of each performance period, and the program is structured to reward Named Executive Officers only if performance goals ~~set~~approved by the Personnel Committee are met. The Personnel Committee has no discretion to make awards if minimum performance goals are not achieved.

~~Beginning with the 2012-2014 performance period, upon vesting, the~~The performance units granted under the Long-Term Performance Unit Program ~~will be settled in shares of Entergy Corporation common stock rather than cash. Accrued~~and accrued dividends on any shares earned during the performance period ~~will also be will be paid~~are settled in shares of Entergy ~~Corporation~~ common stock ~~at the end of the performance period if earned.~~rather than cash. All shares paid out under the Long-Term Performance Unit Program ~~will be~~are required to be retained by the officers until applicable executive stock ownership requirements are met. The form of payment was modified from a cash-settled award to a stock-settled award to align the method of payment with market practice and to encourage the executives to own shares of Entergy Corporation common stock.

The Long-Term Performance Unit Program specifies a minimum, target, and maximum achievement ~~level. Performance is measured~~level, the achievement of which will determine the number of performance units that may be earned by each participant. Entergy Corporation measures performance by assessing ~~Entergy’s~~Entergy Corporation’s total shareholder return relative to the total shareholder return of the companies in the Philadelphia Utility Index. The Personnel Committee identified the Philadelphia Utility Index as the appropriate industry peer group for ~~total shareholder return performance~~this purpose because the companies included in this index, in the aggregate, approximate Entergy Corporation in terms of business and scale. The Personnel Committee chose relative total shareholder return as a measure of performance because it reflects Entergy Corporation’s creation of shareholder value relative to other electric utilities over the performance period. It also takes into account dividends paid by the companies in this index and normalizes certain events that affect the industry as a whole. Minimum, target, and maximum performance levels are determined by reference to the ~~percentile~~ ranking of ~~Entergy’s~~Entergy Corporation’s total shareholder return against the total shareholder return of the companies in the Philadelphia Utility Index. The range of potential payouts under the program is shown below.

There is no payout for performance below the 25th percentile. Payouts between minimum and target and between target and maximum are calculated by interpolating between the bottom position of the third quartile and the median or between the median and the bottom position of the top quartile, respectively. For top quartile performance, a maximum payout of 200% of target is earned. At any given time, a participant in the Long-Term Performance Unit Program may be participating in up to three performance periods. Currently, participants are participating in the ~~2012-2014,~~2013-2015, the ~~2013-2015~~2014-2016, and the ~~2014-2016~~2015-2017 performance periods.

~~2013-2015~~ Performance Unit Program ~~Grants~~Grants.. Subject to achievement of the applicable performance levels, the Personnel Committee established the following target performance unit payout opportunities for each of the 2012-2014, 2013-2015, and 2014-2016 performance ~~period:~~

The following table sets forth the number of stock options and shares of restricted stock granted to each Named Executive Officer in ~~2013.~~2014. The exercise price for each option was ~~$64.60,~~$63.17, which was the closing price of Entergy’s common stock on the date of grant.

~~The Committee believes~~Effective July 1, 2014, the Pension Equalization Plan was amended to provide that ~~these plans have been an important part of the executive compensation programs because they have assisted~~employees who participate in Entergy Corporation’s new cash balance pension plan are not eligible to participate in the ~~recruitment of top talent~~Pension Equalization Plan. These employees instead will participate in a new cash balance restoration plan. In addition, the ~~competitive market,~~Pension Equalization Plan and all other non-qualified plans sponsored by Entergy Corporation were amended, as ~~these types~~necessary, to eliminate the grant of supplemental credited service to new executive officers under any of those plans. The plan amendments were authorized by the Personnel Committee after reviewing comparative market data to better align Entergy Corporation’s retirement plans ~~have typically been found historically in companies~~with emerging market practice. Also to better align with emerging market practice, effective July 1, 2014, the System Executive Retirement Plan and the Supplemental Retirement Plan of ~~similar size to~~ Entergy Corporation and in its industry. These plans serve a critically important role in the retention of senior executives, as benefits from these plans generally increase for each year that these executives remain employed by us. The plans thereby have encouraged the most senior executivesSubsidiaries were closed to ~~remain employed by us and continue their work on behalf of Entergy Corporation’s shareholders.~~ new participants.

See the ~~2013~~2014 Pension Benefits Table for additional information regarding the operation of the plans described under this caption.

The Named Executive Officers are eligible to participate in an Entergy Corporation-sponsored Savings Plan that covers a broad group of employees. The Savings Plan is a tax-qualified 401(k) retirement savings plan, wherein total combined before-tax and after-tax contributions may not exceed 30% of a participant’s base salary up to certain contribution limits defined by law. In addition, under the Savings Plan, the ~~participant’s~~ employer of Savings Plan participants, who participate in the final average pay defined benefit pension plan, matches an amount equal to seventy cents for each dollar contributed by participating employees, including the Named Executive Officers, with respect to the first six percent of their eligible earnings under the plan for that pay period. For employees hired or rehired on or after July 1, 2014 who are not eligible to participate in the final average pay defined benefit pension, but instead will participate in a new cash balance defined benefit pension plan, the Entergy System employer matching contribution will be one dollar for each dollar contributed by the employee with respect to the first six percent of the

The Named Executive Officers are eligible to defer up to 100% of their Annual Incentive Plan awards into either or both of the Entergy Corporation-sponsored Executive Deferred Compensation Plan and the ~~equity plan.~~2011 Equity Plan. In addition, they are eligible to defer up to 100% of their base salary into the Executive Deferred Compensation Plan. Entergy Corporation believes that providing this benefit is important as a retention and recruitment tool because many, if not all, of the companies with which ~~Entergy Corporation~~it competes for executive talent provide a similar arrangement to their senior executive officers. See the ~~2013~~2014 Non-qualified Deferred Compensation discussion for additional information regarding the operation of the Executive Deferred Compensation Plan.

The Named Executive Officers are eligible to participate in various health and welfare benefits available to a broad group of employees. These benefits include medical, dental, and vision coverage, life and accidental death and dismemberment insurance, business travel accident insurance, and long-term disability insurance. Eligibility, coverage levels, potential employee contributions, and other plan design features are the same for the Named Executive Officers as for the broad employee population.

All of the executive officers, including the Named Executive Officers, are eligible to participate in the Executive Disability Plan of Entergy Corporation and Subsidiaries. Individuals who elect to participate in this plan and become disabled under the terms of the plan are eligible for 65% of the difference between their base salary and $276,923 (i.e. the base salary that produces the maximum $15,000 monthly disability payment under ~~Entergy Corporation’s~~the general long-term disability plan).

Entergy Corporation provides the Named Executive Officers ~~are provided~~ with a limited number of perquisites and other personal benefits as part of providing a competitive executive compensation program and for employee retention. The Personnel Committee reviews all perquisites, including the personal use of corporate aircraft, on an annual basis. In ~~2013,~~2014, the Named Executive Officers were ~~offered:~~offered corporate aircraft usage, relocation assistance, annual physical exams, and event tickets. ~~Certain~~

The Committee believes that retention and transitional compensation arrangements are an important part of overall compensation. The Committee believes that these arrangements help to secure the continued employment and dedication of the Named Executive Officers, notwithstanding any concern that they might have at the time of a change in control regarding their own continued employment. In addition, the Committee believes that these arrangements are important as recruitment and retention devices, as all or nearly all of the companies with which Entergy Corporation competes for executive talent have similar arrangements in place for ~~their~~its senior employees.

To achieve these objectives, Entergy Corporation has established a System Executive Continuity Plan under which each of the Named Executive Officers is entitled to receive “change in control” payments and benefits if such

In certain cases, the Committee may approve the execution of a retention agreement with an individual executive officer. These decisions are made on a case by case basis to reflect specific retention needs or other factors, including market practice. If a retention agreement is entered into with an individual officer, the Committee considers the economic value associated with that agreement in making overall compensation decisions for that officer. Entergy Corporation has voluntarily adopted a policy that any employment or severance ~~arrangements~~agreements providing severance benefits in excess of 2.99 times the sum of an officer’s annual base salary and annual incentive award (other than the value of the vesting or payment of an outstanding equity-based award or the pro rata vesting or payment of an outstanding long-term incentive award) must be approved by Entergy Corporation’s shareholders.

~~During 2013,~~ Entergy Corporation ~~had~~has a retention ~~agreements~~agreement with Mr. ~~Denault and Mr. Mohl.~~Denault. In general, Mr. Denault’s retention agreement provides for severance payments and other benefits in the event of termination of employment other than for cause or on account of death or disability in lieu of those provided under ~~Entergy Corporation’s~~the System Executive Continuity Plan. As with any severance benefits paid under the System Executive Continuity Plan, Mr. Denault will not receive tax gross-up payments on any severance benefits he may receive under his agreement. Mr. Denault’s retention agreement was entered into in 2006 when he was Entergy Corporation’s Chief Financial Officer and was designed to reflect the competition for chief financial officer talent in the marketplace at that time and the Committee’s assessment of the critical role this position plays in executing Entergy Corporation’s long-term financial and other strategic objectives. Based on the market data provided by its former independent compensation consultant, the Committee believes the benefits and payment levels under Mr. Denault’s retention agreement are consistent with market practices.

For additional information regarding the System Executive Continuity Plan and Mr. Denault’s ~~and Mr. Mohl’s~~ retention ~~agreements~~agreement described above, see ~~“2013~~“2014 Potential Payments Upon Termination or ~~Change.~~Change in Control."

Entergy Corporation strives to ensure that its compensation philosophy and practices are in line with the best practices of companies in ~~its~~the utility industry as well as ~~Fortune 500 companies.~~other companies in the S&P 500. Some of these practices include the following:

Entergy Corporation has adopted ~~the Entergy Corporation Policy Regarding Recoupment of Certain Compensation. This~~a clawback policy that covers all individuals subject to Section 16 of the Exchange ~~Act.~~Act, including all of the members of the Office of the Chief Executive. Under the policy, the Committee will require reimbursement of incentives paid to these executive officers where:

The amount the Committee requires to be reimbursed is equal to the excess of the gross incentive payment made over the gross payment that would have been made if the original payment had been determined based on the restated financial results or correct calculation. Further, following a material restatement of ~~Entergy Corporation’s~~the financial statements, Entergy Corporation will seek to recover any compensation received by ~~Entergy Corporation’s~~its Chief Executive Officer and Chief Financial Officer that is required to be reimbursed under Section 304 of the Sarbanes-Oxley Act of 2002.

For many years, Entergy Corporation has had stock ownership guidelines for executives, including the Named Executive Officers. These guidelines are designed to align the executives’ long-term financial interests with those of shareholders. Annually, the Personnel Committee monitors the executive officers’ compliance with these guidelines.

Further, to ensure compliance with the guidelines, until an executive officer satisfies the stock ownership guidelines, the officer must retain:

Executive officers, including the Named Executive Officers, are required to receive the permission of Entergy Corporation’s General Counsel prior to entering into any transaction involving ~~company~~Entergy Corporation securities, including gifts, other than the exercise of employee stock options. Trading is generally permitted only during open trading windows occurring immediately following the release of earnings. Employees, who are subject to trading restrictions, including the Named Executive Officers, may enter into trading plans under Rule 10b5-1 of the Exchange Act, but these trading plans may be entered into only during an open trading window and must be approved by Entergy Corporation. The Named Executive Officer bears full responsibility if he or she violates ~~this~~company policy by permitting shares to be bought or sold without pre-approval or when trading is restricted.

Entergy Corporation also prohibits its directors and executive officers, including the Named Executive Officers, from pledging any Entergy ~~Corporation~~Corporation’s securities or entering into margin accounts involving Entergy ~~Corporation~~ securities. ~~Entergy Corporation~~It prohibits these transactions because of the potential that sales of Entergy ~~Corporation~~Corporation’s securities could occur outside trading periods and without the required approval of the General Counsel.

Entergy Corporation also has adopted an anti-hedging policy that prohibits officers, directors, and employees from entering into hedging or monetization transactions involving ~~Entergy Corporation’s~~its common stock. Prohibited transactions include,

The Personnel Committee has overall responsibility for approving the compensation program for the Named Executive Officers and makes all final compensation decisions regarding the Named Executive Officers. The Committee works with Entergy Corporation’s executive management to ensure that the compensation policies and practices are consistent with Entergy Corporation’s values and support the successful recruitment, development, and retention of executive talent so Entergy Corporation can achieve its business objectives ~~can be achieved~~ and optimize ~~Entergy Corporation’s~~its long-term financial returns. Each year, Entergy Corporation’s Senior Vice President, Human Resources and Chief Diversity Officer presents the proposed compensation model for the following year, including the compensation elements, mix of elements and measures for each element and consults with Entergy Corporation’s Chief Executive Officer on recommended compensation for senior executives. The Committee evaluates executive pay each year to ensure that the compensation policies and practices are consistent with Entergy Corporation’s philosophy. The Personnel Committee is responsible for, among its other duties, the following actions related to the Named Executive Officers:

The Personnel Committee solicits recommendations from Entergy Corporation’s Chief Executive Officer with respect to compensation decisions for the other Named Executive Officers. ~~Compensation decisions made by the Personnel Committee in early 2013 were based on the recommendations of Mr. Leonard, Entergy Corporation’s former Chief Executive Officer.~~

~~Mr. Denault~~Entergy Corporation’s Chief Executive Officer may attend meetings of the Personnel Committee only at the invitation of the chair of the Personnel Committee and cannot call a meeting of the Committee. ~~However,~~In addition, he is not in attendance at the portion of any meeting when the Committee approves the compensation to be paid to the Named Executive Officers. Since he is not a member of the Committee, he has no vote on matters submitted to the Committee. During ~~2013,~~2014, Mr. Denault attended 6 meetings of the Personnel Committee.

~~The~~Entergy Corporation’s Personnel Committee has the sole authority ~~from the Board of Directors~~ for the appointment, compensation, and oversight of its outside compensation consultant. In ~~2013, Entergy Corporation’s~~2014, the Personnel Committee retained

During ~~2013,~~2014, Pay Governance assisted the Committee with its responsibilities related to Entergy Corporation’s compensation programs for its executives. ~~Specifically, the~~The Committee directed Pay Governance to: (i) regularly attend meetings of the Committee; (ii) conduct studies of competitive compensation practices; (iii) identify market surveys and proxy peer ~~groups;~~group; (iv) review base salary, annual incentives, and long-term incentive compensation opportunities relative to competitive practices; and (v) develop conclusions and recommendations related to the executive compensation plan for consideration by the Committee. A senior consultant from Pay Governance attended all Personnel Committee meetings to which he was invited in ~~2013.~~2014.

To maintain the independence of the Personnel Committee’s compensation consultant, the Board has adopted a policy that any consultant (including its affiliates) retained by the Board of Directors or any Committee of the Board of Directors to provide advice or recommendations on the amount or form of executive and director compensation should not be retained by Entergy Corporation or any of its affiliates to provide other services in an aggregate amount that exceeds $120,000 in any year. In 2014, the Personnel Committee’s independent compensation consultant, Pay Governance LLC, did not provide any ~~other~~ services to Entergy Corporation other than its services to the Personnel Committee. Annually, the Committee reviews the relationship with its compensation consultant including services provided, quality of those services, and fees associated with services in ~~2013.~~its evaluation of the executive compensation consultant’s independence. The Committee also assesses Pay Governance’s independence under NYSE rules and has concluded that no conflict of interests exists that would prevent Pay Governance from independently advising the Personnel Committee.

Section 162(m) of the Code limits the tax deductibility by a publicly held corporation of compensation in excess of $1 million paid to ~~Entergy Corporation’s~~the Chief Executive Officer or any of its other Named Executive Officers who may be a Section 162(m) covered ~~employee,~~employees, unless that compensation is “performance-based compensation” within the meaning of Section 162(m). The Personnel Committee considers deductibility under Section 162(m) as it structures the compensation packages that are provided to its Named Executive Officers. Likewise, the Personnel Committee considers financial accounting consequences as it structures the compensation packages that are provided to the Named Executive Officers. However, the Personnel Committee and the Board believe that it is in ~~Entergy Corporation’s~~the best interest of Entergy Corporation that the Personnel Committee retains the flexibility and discretion to make compensation awards, whether or not deductible. This flexibility is necessary to foster achievement of performance goals established by the Personnel Committee, as well as other corporate goals that the Committee deems important to Entergy Corporation’s success, such as encouraging employee retention and rewarding achievement of key ~~Entergy Corporation’s~~ goals.

The Personnel Committee Report included in the Entergy Corporation Proxy Statement is incorporated by reference, but will not be deemed to be “filed” in this Annual Report on Form 10-K. None of the Subsidiaries has a compensation committee or other board committee performing equivalent functions. The board of directors of each of the Subsidiaries is comprised of individuals who are officers or employees of Entergy Corporation or one of the Subsidiaries. These boards do not make determinations regarding the compensation paid to executive officers of the Subsidiaries.

The following table summarizes the total compensation paid or earned by each of the Named Executive Officers for the fiscal ~~years~~year ended December 31, 2014, and to the extent required by SEC rules, for the fiscal years ended 2013 ~~2012,~~ and ~~2011.~~2012. For information on the principal positions held by each of the Named Executive Officers, see Item 10, “Directors and Executive Officers of the Registrants.” The compensation set forth in the table represents the aggregate compensation paid by all Entergy System companies. None of the Entergy System companies has entered into any employment agreements with any of the Named Executive Officers (other than the retention agreements described in ~~“Potential~~“2014 Potential Payments upon Termination or Change in Control”). For additional information regarding the material terms of the awards reported in the following tables, including a general description of the formula or criteria to be applied in determining the amounts payable, see “Compensation Discussion and Analysis.”

The amounts set forth in column (i) include perquisites and other personal benefits that Entergy Corporation provides to the Named Executive Officers as part of providing a competitive executive compensation program and for employee retention. In 2013, the Named Executive Officers were offered: corporate aircraft usage, relocation assistance, annual physical exams and event tickets. Certain of the Named Executive Officers, who are not members of the Office of the Chief Executive, were provided with club dues and tax gross up payments on some perquisites. The following perquisites and other compensation were provided by Entergy Corporation in ~~2013:~~2014.

For security and business reasons, Entergy Corporation permits its Chief Executive Officer to use its corporate aircraft for personal use at the expense of Entergy Corporation. The other Named Executive Officers may use the corporate aircraft for personal travel subject to the approval of Entergy Corporation’s Chief Executive Officer. The amounts included in column (i) for the personal use of corporate aircraft, reflect the incremental cost to Entergy Corporation for use of the corporate aircraft, determined on the basis of the variable operational costs of each flight, including fuel, maintenance, flight crew travel expense, catering, communications, and fees, including flight planning, ground handling, and landing permits.

The following table provides information concerning each exercise of stock options and each vesting of stock during ~~2013~~2014 for the Named Executive Officers.

The qualified retirement plan in which the Named Executive Officers participate is a funded, tax-qualified, noncontributory defined benefit pension plan that provides benefits to most of the non-bargaining unit employees of Entergy System Companies. All Named Executive Officers are participants in this plan. Benefits under the tax-qualified pension plan are calculated as an annuity payable at age 65 and generally equal to 1.5% of a ~~participant's~~participant’s Final Average Monthly Earnings (FAME) multiplied by years of service (not to exceed 40). ~~“Eligible Earnings”~~“Earnings” for purposes of calculating FAME generally includes the employee’s base salary and eligible annual incentive award and excludes all other bonuses. FAME is calculated using the ~~employee's~~employee’s average monthly Earnings for the 60 consecutive months in which the ~~employee's~~employee’s earnings were highest during the 120 month period immediately preceding the ~~employee's~~employee’s retirement and includes up to 5 annual bonuses paid during the 60 month period. Benefits under the tax-qualified plan are payable monthly after attainment of at least age 55 and after separation from an Entergy System company. The amount of annual earnings that may be considered in calculating benefits under the tax-qualified pension plan is limited by federal law. Participants are 100% vested in their benefit upon completing 5 years of vesting service or upon attainment of age 65 while an active employee participant in the plan. Contributions to the pension plan are made entirely by the Entergy ~~Corporation~~System employer and are paid into a trust fund from which the benefits of participants will be paid.

Normal retirement under the plan is age 65. Employees who terminate employment prior to age 55 may receive a reduced deferred vested retirement benefit commencing as early as age 55 that is based on the normal retirement benefit (reduced by 7% per year for the first 5 years commencement precedes age 65, and reduced by 6% for each additional year commencement precedes age 65). Employees who are at least age 55 with 10 years of vesting service upon termination of employment are entitled to a subsidized early retirement benefit beginning as early as age 55. The subsidized early retirement benefit is equal to the normal retirement benefit reduced by 2% per year for each year that early retirement precedes age 65.

Mr. ~~Forbes~~Denault, Mr. McDonald, and Mr. ~~McDonald~~Savoff are eligible for subsidized early retirement benefits.

The Named Executive Officers are eligible to participate in certain non-qualified retirement benefit plans that provide retirement income, including the Pension Equalization Plan and the System Executive Retirement Plan. Each of these plans is an unfunded non-qualified defined benefit pension plan that provides benefits to key management employees. In these plans, as described below, an executive is typically enrolled in one or more plans but only paid the amount due under the plan that provides the highest benefit. In general, upon disability, participants in the Pension Equalization Plan and the System Executive Retirement Plan remain eligible for continued service credits until the earlier of recovery, separation from service due to disability, or retirement eligibility. Generally, spouses of participants who die before commencement of benefits may be eligible for a portion of the participant’s accrued benefit.

All of the Named Executive Officers participate in both the Pension Equalization Plan and the System Executive Retirement Plan.

The System Executive Retirement Plan is a non-qualified supplemental retirement plan that provides for a single sum payment at age 65. Like the Pension Equalization Plan, the System Executive Retirement Plan is designed to provide for the payment to participants from ~~Entergy’s~~Entergy Corporation’s general assets of a single-sum cash distribution upon the participant’s separation from service. The single-sum benefit is generally equal to the actuarial present value of a specified percentage of the participant’s “Final Average Monthly Compensation” (which is generally 1/36th of the sum of the ~~participant's~~participant’s annual rate of base salary and Annual Incentive Plan award for the 3 highest years during the last 10 years preceding termination of employment), after first being reduced by the value of the participant’s tax-qualified ~~Pension Plan~~retirement plan benefit and typically any prior employer pension benefit available to the participant.

While the System Executive Retirement Plan has a replacement ratio schedule from one year of service to the maximum of 30 years of service, the table below offers a sample ratio at 20 and 30 years of service.

The Executive Deferred Compensation Plan, the 2007 Equity Ownership Plan and Long-Term Cash Incentive Plan, and the 2011 Equity Ownership Plan allow for the deferral of compensation for the Named Executive Officers. Entergy Corporation does not “match” amounts that are deferred by employees pursuant to the Executive Deferred Compensation Plan or the equity plans. With the exception of allowing for the deferral of federal and state taxes, Entergy Corporation provides no additional benefit to the Named Executive Officer for deferring any of the compensation received under these plans. Any increase in value of the deferred amounts results solely from the increase in value of the deemed investment options selected by the Named Executive Officer (phantom stock of Entergy Corporation or mutual funds available under the Savings Plan). As of December 31, ~~2013,~~2014, none of the Named Executive Officers had deferred compensation balances under the equity ownership plans or the Executive Deferred Compensation Plan.

As of December 31, ~~2013,~~2014, Mr. ~~Forbes~~Savoff and Mr. May had deferred account balances under a frozen Defined Contribution Restoration Plan. These amounts are deemed invested, as chosen by the participant, in certain T. Rowe Price investment funds that are also available to participants under the Savings Plan. Mr. Savoff and Mr. May have elected to receive the deferred account balances after they retire. The Defined Contribution Restoration Plan, until it was frozen in 2005, credited eligible employees’ deferral accounts with employer contributions to the extent contributions under the qualified savings plan in which the employee participated were subject to limitations imposed by the Internal Revenue Code.

Entergy Corporation has plans and other arrangements that provide compensation to a Named Executive Officer if his or her employment ~~is terminated~~terminates under specified conditions, including following a change in control of Entergy Corporation. In addition, Entergy Corporation has entered into ~~individual~~a retention ~~agreements~~agreement with Mr. Denault ~~and Mr. Mohl.~~



(Mark One)

X	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

	For the Fiscal Year Ended December 31, ~~2013~~2014
	OR
	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

	For the transition period from ____________ to ____________



Commission File Number	Registrant, State of Incorporation or Organization, Address of Principal Executive Offices, Telephone Number, and IRS Employer Identification No.	Commission File Number	Registrant, State of Incorporation or Organization, Address of Principal Executive Offices, Telephone Number, and IRS Employer Identification No.
1-11299	ENTERGY CORPORATION (a Delaware corporation) 639 Loyola Avenue New Orleans, Louisiana 70113 Telephone (504) 576-4000 72-1229752	1-31508	ENTERGY MISSISSIPPI, INC. (a Mississippi corporation) 308 East Pearl Street Jackson, Mississippi 39201 Telephone (601) 368-5000 64-0205830


1-10764	ENTERGY ARKANSAS, INC. (an Arkansas corporation) 425 West Capitol Avenue Little Rock, Arkansas 72201 Telephone (501) 377-4000 71-0005900	0-05807	ENTERGY NEW ORLEANS, INC. (a Louisiana corporation) 1600 Perdido Street New Orleans, Louisiana 70112 Telephone (504) 670-3700 72-0273040


0-20371	ENTERGY GULF STATES LOUISIANA, L.L.C. (a Louisiana limited liability company) ~~446 North Boulevard~~4809 Jefferson Highway ~~Baton Rouge,~~Jefferson, Louisiana ~~70802~~70121 Telephone ~~(800) 368-3749~~(504) 576-4000 74-0662730	1-34360	ENTERGY TEXAS, INC. (a Texas corporation) ~~350 Pine Street~~9425 Pinecroft ~~Beaumont, Texas 77701~~The Woodlands, TX 77380 Telephone (409) 981-2000 61-1435798


1-32718	ENTERGY LOUISIANA, LLC (a Texas limited liability company) ~~446 North Boulevard~~4809 Jefferson Highway ~~Baton Rouge,~~Jefferson, Louisiana ~~70802~~70121 Telephone ~~(800) 368-3749~~(504) 576-4000 75-3206126	1-09067	SYSTEM ENERGY RESOURCES, INC. (an Arkansas corporation) Echelon One 1340 Echelon Parkway Jackson, Mississippi 39213 Telephone (601) 368-5000 72-0752777



Registrant	Title of Class	Name of Each Exchange on Which Registered

Entergy Corporation	Common Stock, $0.01 Par Value – ~~178,563,836~~179,697,449 shares outstanding at January ~~31, 2014~~30, 2015	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.
	Mortgage Bonds, 4.90% Series due December 2052	New York Stock Exchange, Inc.
	Mortgage Bonds, 4.75% Series due June 2063	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.
	Mortgage Bonds, 5.25% Series due July 2052	New York Stock Exchange, Inc.
	Mortgage Bonds, 4.70% Series due June 2063	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 New Orleans, Inc.	Mortgage Bonds, 5.0% Series due December 2052	New York Stock Exchange, Inc.

Entergy Texas, Inc.	Mortgage Bonds, ~~7.875%~~5.625% Series due June ~~2039~~2064	New York Stock Exchange, Inc.



	Large accelerated filer	Accelerated filer	Non-accelerated filer	Smaller reporting company

Entergy Corporation	ü
Entergy Arkansas, Inc.			ü
Entergy Gulf States Louisiana, L.L.C.			ü
Entergy Louisiana, LLC			ü
Entergy Mississippi, Inc.			ü
Entergy New Orleans, Inc.			ü
Entergy Texas, Inc.			ü
System Energy Resources, Inc.			ü



	SEC Form 10-K Reference Number	Page Number

Forward-looking information		iv
Definitions		vi
Entergy Corporation and Subsidiaries
Management’s Financial Discussion and Analysis	Part II. Item 7.	1
Selected Financial Data - Five-Year Comparison	Part II. Item 6.	4752
Report of Independent Registered Public Accounting Firm		4953
Consolidated Income Statements For the Years Ended December 31, 2014, 2013, ~~2012,~~ and ~~2011~~2012	Part II. Item 8.	5054
Consolidated Statements of Comprehensive Income For the Years Ended December 31, 2014, 2013, ~~2012,~~ and ~~2011~~2012	Part II. Item 8.	5155
Consolidated Statements of Cash Flows For the Years Ended December 31, 2014, 2013, ~~2012,~~ and ~~2011~~2012	Part II. Item 8.	5256
Consolidated Balance Sheets, December 31, ~~2013~~2014 and ~~2012~~2013	Part II. Item 8.	5458
Consolidated Statements of Changes in Equity for the Years Ended December 31, 2014, 2013, ~~2012,~~ and ~~2011~~2012	Part II. Item 8.	5660
Notes to Financial Statements	Part II. Item 8.	5761
Entergy’s Business	Part I. Item 1.	~~218~~235
Utility	Part I. Item 1.	~~218~~235
Entergy Wholesale Commodities	Part I. Item 1.	~~236~~253
Regulation of Entergy’s Business	Part I. Item 1.	~~240~~257
Litigation		~~256~~272
Employees		~~257~~273
Availability of SEC filings and other information on Entergy’s website		~~257~~273
Risk Factors	Part I. Item 1A.	~~258~~274
Unresolved Staff Comments	Part I. Item 1B.	None
Entergy Arkansas, Inc. and Subsidiaries
Management’s Financial Discussion and Analysis	Part II. Item 7.	~~280~~296
Report of Independent Registered Public Accounting Firm		~~297~~315
Consolidated Income Statements For the Years Ended December 31, 2014, 2013, ~~2012,~~ and ~~2011~~2012	Part II. Item 8.	~~298~~316
Consolidated Statements of Cash Flows For the Years Ended December 31, 2014, 2013, ~~2012,~~ and ~~2011~~2012	Part II. Item 8.	~~299~~317
Consolidated Balance Sheets, December 31, ~~2013~~2014 and ~~2012~~2013	Part II. Item 8.	~~300~~318
Consolidated Statements of Changes in Common Equity for the Years Ended December 31, 2014, 2013, ~~2012,~~ and ~~2011~~2012	Part II. Item 8.	~~302~~320
Selected Financial Data - Five-Year Comparison	Part II. Item 6.	~~303~~321
Entergy Gulf States Louisiana, L.L.C.
Management’s Financial Discussion and Analysis	Part II. Item 7.	~~304~~322
Report of Independent Registered Public Accounting Firm		~~322~~342
Income Statements For the Years Ended December 31, 2014, 2013, ~~2012,~~ and ~~2011~~2012	Part II. Item 8.	~~323~~343
Statements of Comprehensive Income For the Years Ended December 31, 2014, 2013, ~~2012,~~ and ~~2011~~2012	Part II. Item 8.	~~324~~344
Statements of Cash Flows For the Years Ended December 31, 2014, 2013, ~~2012,~~ and ~~2011~~2012	Part II. Item 8.	~~325~~345
Balance Sheets, December 31, ~~2013~~2014 and ~~2012~~2013	Part II. Item 8.	~~326~~346



Statements of Changes in Equity for the Years Ended December 31, 2014, 2013, ~~2012,~~ and ~~2011~~2012	Part II. Item 8.	~~328~~348
Selected Financial Data - Five-Year Comparison	Part II. Item 6.	~~329~~349
Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis	Part II. Item 7.	~~330~~350
Report of Independent Registered Public Accounting Firm		~~348~~370
Consolidated Income Statements For the Years Ended December 31, 2014, 2013, ~~2012,~~ and ~~2011~~2012	Part II. Item 8.	~~349~~371
Consolidated Statements of Comprehensive Income For the Years Ended December 31, 2014, 2013, ~~2012,~~ and ~~2011~~2012	Part II. Item 8.	~~350~~372
Consolidated Statements of Cash Flows For the Years Ended December 31, 2014, 2013, ~~2012,~~ and ~~2011~~2012	Part II. Item 8.	~~351~~373
Consolidated Balance Sheets, December 31, ~~2013~~2014 and ~~2012~~2013	Part II. Item 8.	~~352~~374
Consolidated Statements of Changes in Equity for the Years Ended December 31, 2014, 2013, ~~2012,~~ and ~~2011~~2012	Part II. Item 8.	~~354~~376
Selected Financial Data - Five-Year Comparison	Part II. Item 6.	~~355~~377
Entergy Mississippi, Inc.
Management’s Financial Discussion and Analysis	Part II. Item 7.	~~356~~378
Report of Independent Registered Public Accounting Firm		~~369~~393
Income Statements For the Years Ended December 31, 2014, 2013, ~~2012,~~ and ~~2011~~2012	Part II. Item 8.	~~370~~394
Statements of Cash Flows For the Years Ended December 31, 2014, 2013, ~~2012,~~ and ~~2011~~2012	Part II. Item 8.	~~371~~395
Balance Sheets, December 31, ~~2013~~2014 and ~~2012~~2013	Part II. Item 8.	~~372~~396
Statements of Changes in Common Equity for the Years Ended December 31, 2014, 2013, ~~2012,~~ and ~~2011~~2012	Part II. Item 8.	~~374~~398
Selected Financial Data - Five-Year Comparison	Part II. Item 6.	~~375~~399
Entergy New Orleans, Inc.
Management’s Financial Discussion and Analysis	Part II. Item 7.	~~376~~400
Report of Independent Registered Public Accounting Firm		~~387~~411
Income Statements For the Years Ended December 31, 2014, 2013, ~~2012,~~ and ~~2011~~2012	Part II. Item 8.	~~388~~412
Statements of Cash Flows For the Years Ended December 31, 2014, 2013, ~~2012,~~ and ~~2011~~2012	Part II. Item 8.	~~389~~413
Balance Sheets, December 31, ~~2013~~2014 and ~~2012~~2013	Part II. Item 8.	~~390~~414
Statements of Changes in Common Equity for the Years Ended December 31, 2014, 2013, ~~2012,~~ and ~~2011~~2012	Part II. Item 8.	~~392~~416
Selected Financial Data - Five-Year Comparison	Part II. Item 6.	~~393~~417
Entergy Texas, Inc. and Subsidiaries
Management’s Financial Discussion and Analysis	Part II. Item 7.	~~394~~418
Report of Independent Registered Public Accounting Firm		~~407~~431
Consolidated Income Statements For the Years Ended December 31, 2014, 2013, ~~2012,~~ and ~~2011~~2012	Part II. Item 8.	~~408~~432
Consolidated Statements of Cash Flows For the Years Ended December 31, 2014, 2013, ~~2012,~~ and ~~2011~~2012	Part II. Item 8.	~~409~~433
Consolidated Balance Sheets, December 31, ~~2013~~2014 and ~~2012~~2013	Part II. Item 8.	~~410~~434
Consolidated Statements of Changes in Common Equity for the Years Ended December 31, 2014, 2013, ~~2012,~~ and ~~2011~~2012	Part II. Item 8.	~~412~~436
Selected Financial Data - Five-Year Comparison	Part II. Item 6.	~~413~~437
System Energy Resources, Inc.
Management’s Financial Discussion and Analysis	Part II. Item 7.	~~414~~438
Report of Independent Registered Public Accounting Firm		~~423~~447
Income Statements For the Years Ended December 31, 2014, 2013, ~~2012,~~ and ~~2011~~2012	Part II. Item 8.	~~424~~448
Statements of Cash Flows For the Years Ended December 31, 2014, 2013, ~~2012,~~ and ~~2011~~2012	Part II. Item 8.	~~425~~449



Balance Sheets, December 31, ~~2013~~2014 and ~~2012~~2013	Part II. Item 8.	~~426~~450
Statements of Changes in Common Equity for the Years Ended December 31, 2014, 2013, ~~2012,~~ and ~~2011~~2012	Part II. Item 8.	~~428~~452
Selected Financial Data - Five-Year Comparison	Part II. Item 6.	~~429~~453
Properties	Part I. Item 2.	~~430~~454
Legal Proceedings	Part I. Item 3.	~~430~~454
Mine Safety Disclosures	Part I. Item 4.	~~430~~454
Executive Officers of Entergy Corporation	Part I. and Part III. Item 10.	~~430~~454
Market for Registrants’ Common Equity and Related Stockholder Matters	Part II. Item 5.	~~432~~456
Selected Financial Data	Part II. Item 6.	~~433~~457
Management’s Discussion and Analysis of Financial Condition and Results of Operations	Part II. Item 7.	~~434~~458
Quantitative and Qualitative Disclosures About Market Risk	Part II. Item 7A.	~~434~~458
Financial Statements and Supplementary Data	Part II. Item 8.	~~434~~458
Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	Part II. Item 9.	~~434~~458
Controls and Procedures	Part II. Item 9A.	~~434~~458
Attestation Report of Registered Public Accounting Firm	Part II. Item 9A.	~~436~~460
Directors and Executive Officers of the Registrants	Part III. Item 10.	~~444~~461
Executive Compensation	Part III. Item 11.	~~451~~468
Security Ownership of Certain Beneficial Owners and Management	Part III. Item 12.	~~513~~510
Certain Relationships and Related Transactions and Director Independence	Part III. Item 13.	~~516~~515
Principal Accountant Fees and Services	Part III. Item 14.	~~518~~516
Exhibits and Financial Statement Schedules	Part IV. Item 15.	~~521~~519
Signatures		~~522~~520
Consents of Independent Registered Public Accounting Firm		~~530~~528
Report of Independent Registered Public Accounting Firm		~~531~~529
Index to Financial Statement Schedules		S-1
Exhibit Index		E-1



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
ASLB	Atomic Safety and Licensing Board, the board within the NRC that conducts hearings and performs other regulatory functions that the NRC authorizes
ASU	Accounting Standards Update issued by the FASB
Board	Board of Directors of Entergy Corporation
Cajun	Cajun Electric Power Cooperative, Inc.
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 Circuit
DOE	United States Department of Energy
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 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, operation, and ~~operation~~decommissioning of ~~six~~ nuclear power plants, the ownership of interests in non-nuclear power plants, and the sale of the electric power produced by ~~those~~its operating power 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
FitzPatrick	James A. FitzPatrick Nuclear Power Plant (nuclear), owned by an Entergy subsidiary in the Entergy Wholesale Commodities business segment
FTR	Financial transmission right
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
Independence	Independence Steam Electric Station (coal), owned 16% by Entergy Arkansas, 25% by Entergy Mississippi, and 7% by Entergy Power, LLC
Indian Point 2	Unit 2 of Indian Point Energy Center (nuclear), owned by an Entergy subsidiary in the Entergy Wholesale Commodities business segment



Abbreviation or Acronym	Term

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	Midcontinent Independent 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 to net capital 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
Palisades	Palisades Power Plant (nuclear), owned by an Entergy subsidiary in the Entergy Wholesale Commodities business segment
Pilgrim	Pilgrim Nuclear Power Station (nuclear), owned by an Entergy subsidiary in the Entergy Wholesale Commodities business segment
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.
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



Abbreviation or Acronym	Term

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~~resources. Entergy Arkansas terminated its participation in the System Agreement effective December 18, 2013.
System Energy	System Energy Resources, Inc.
System Fuels	System Fuels, Inc.
TWh	Terawatt-hour(s), which equals one billion kilowatt-hours
U.K.	United Kingdom of Great Britain and Northern Ireland
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, which ceased power production in December 2014
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


	% of Revenue			% of Net Income						% of Total Assets						% of Revenue			% of Net Income						% of Total Assets
Segment	2013	2012	2011	2013		2012		2011		2013		2012		2011		2014	2013	2012	2014		2013		2012		2014		2013		2012
Utility	80	78	79	116		110		82		82		82		80		78	80	78	88		116		110		82		82		82
Entergy Wholesale Commodities	20	22	21	6		5		36		22		22		24		22	20	22	31		6		5		22		22		22
Parent & Other	—	—	—	(22	)	(15	)	(18	)	(4	)	(4	)	(4	)	—	—	—	(19	)	(22	)	(15	)	(4	)	(4	)	(4	)


	Utility		Entergy Wholesale Commodities			Parent & Other			Entergy			Utility			Entergy Wholesale Commodities			Parent & Other			Entergy
	(In Thousands)											(In Thousands)
2012 Consolidated Net Income (Loss)		$960,322		$40,427			($132,386	)		$868,363
2013 Consolidated Net Income (Loss)													$846,215			$42,976			($158,619	)		$730,572

Net revenue (operating revenue less fuel expense, purchased power, and other regulatory charges/credits)	555,233		(51,509		)	7,136			510,860			210,893			422,147			(17,519		)	615,521
Other operation and maintenance	184,374		90,222			11,946			286,542			12,369			(25,043		)	(8,724		)	(21,398		)
Asset impairment and related charges	9,411		(26,188		)	2,790			(13,987		)
Asset write-off, impairments, and related charges												62,814			(221,809		)	(2,790		)	(161,785		)
Taxes other than income taxes	37,547		5,380			125			43,052			2,760			1,709			(213		)	4,256
Depreciation and amortization	76,850		39,824			(215		)	116,459			(2,019		)	60,053			(440		)	57,594
Gain on sale of business	—		43,569			—			43,569			—			(43,569		)	—			(43,569		)
Other income	6,378		29,624			2,268			38,270			1,795			(23,642		)	(13,272		)	(35,119		)
Interest expense	32,688		(1,577		)	3,642			34,753			22,556			323			591			23,470
Other expenses	18,271		50,274			—			68,545			7,696			33,699			—			41,395
Income taxes	316,577		(138,800		)	17,349			195,126			106,231			254,459			2,926			363,616
2013 Consolidated Net Income (Loss)		$846,215		$42,976			($158,619	)		$730,572
2014 Consolidated Net Income (Loss)													$846,496			$294,521			($180,760	)		$960,257



	Amount
	(In Millions)

~~2012~~2013 net revenue		$~~4,969~~5,524
Retail electric price	~~236~~135
~~Louisiana Act 55 financing savings~~Asset retirement obligation	~~165~~
~~Grand Gulf recovery~~	7556
Volume/weather	40
~~Fuel recovery~~	3536
MISO deferral	1216
~~Decommissioning trusts~~Net wholesale revenue	(2329		)
Other	15(3		)
~~2013~~2014 net revenue		$~~5,524~~5,735


~~(a)~~	~~The reduction in owned capacity is due to the retirement of the 544 MW Ritchie Unit 2 in November 2013.~~



	Amount
	(In Millions)

2012 net revenue		$4,969
Retail electric price	236
Louisiana Act 55 financing savings obligation	165
Grand Gulf recovery	75
Volume/weather	40
Fuel recovery	35
MISO deferral	12
Asset retirement obligation	(23		)
Other	15
2013 net revenue		$5,524



	~~Amount~~
	~~(In Millions)~~

~~2011 net revenue~~		~~$4,904~~
~~Mark-to-market tax settlement sharing~~	~~200~~
~~Retail electric price~~	81
~~Grand Gulf recovery~~	71
~~Net wholesale revenue~~	~~(28~~		)
~~Purchased power capacity~~	~~(29~~		)
~~Volume/weather~~	~~(80~~		)
~~Louisiana Act 55 financing savings obligation~~	~~(161~~		)
~~Other~~	11
~~2012 net revenue~~		~~$4,969~~



	~~Amount~~
	~~(In Millions)~~

~~2011 net revenue~~		~~$2,045~~
~~Nuclear realized price changes~~	~~(194~~		)
~~Nuclear volume~~	~~(33~~		)
~~Other~~	36
~~2012 net revenue~~		~~$1,854~~


Long-term debt maturities and estimated interest payments	2014		2015		2016		2017-2018		after 2018		2015		2016		2017		2018-2019		after 2019
	(In Millions)										(In Millions)
Utility		$942		$1,095		$754		$2,328		$12,240		$882		$746		$886		$2,070		$13,997
Entergy Wholesale Commodities	15		19		2		4		55		19		2		2		4		53
Parent and Other	72		616		51		808		489		624		60		537		757		466
Total		$1,029		$1,730		$807		$3,140		$12,784		$1,525		$808		$1,425		$2,831		$14,516



	2013	2012
Owned capacity (MW) (a)	6,068	6,612
GWh billed	45,127	46,178
Average realized price per MWh	$50.86	$50.02

Entergy Wholesale Commodities Nuclear Fleet
Capacity factor	89%	89%
GWh billed	40,167	41,042
Average realized revenue per MWh	$50.15	$50.29
Refueling Outage Days:
FitzPatrick	—	34
Indian Point 2	—	28
Indian Point 3	28	—
Palisades	—	34
Pilgrim	45	—
Vermont Yankee	27	—


(a)	The reduction in owned capacity is due to the retirement of the 544 MW Ritchie Unit 2 in November 2013.



	2012	2011
Owned capacity (MW)	6,612	6,599
GWh billed	46,178	43,497
Average realized price per MWh	$50.02	$54.50

Entergy Wholesale Commodities Nuclear Fleet
Capacity factor	89%	93%
GWh billed	41,042	40,918
Average realized revenue per MWh	$50.29	$54.73
Refueling Outage Days:
FitzPatrick	34	—
Indian Point 2	28	—
Indian Point 3	—	30
Palisades	34	—
Pilgrim	—	25
Vermont Yankee	—	25


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



Company	Expiration Date	Amount of Facility	Interest Rate (a)	Amount Drawn as of December 31, ~~2013~~2014
Entergy Arkansas	April ~~2014~~2015	$20 million (b)	~~1.75%~~1.67%	—
Entergy Arkansas	March ~~2018~~2019	$150 million (c)	1.67%	—
Entergy Gulf States Louisiana	March ~~2018~~2019	$150 million (d)	~~1.67%~~1.42%	—
Entergy Louisiana	March ~~2018~~2019	$200 million (e)	1.42%	—
Entergy Mississippi	May 2015	$10 million (f)	1.67%	—
Entergy Mississippi	May ~~2014~~2015	$3520 million (f)	~~1.92%~~1.67%	—
Entergy Mississippi	May ~~2014~~2015	$2035 million (f)	~~1.92%~~1.67%	—
Entergy Mississippi	May ~~2014~~2015	$37.5 million (f)	~~1.92%~~1.67%	—
Entergy New Orleans	November ~~2014~~2015	$25 million ~~(g)~~	~~1.64%~~1.92%	—
Entergy Texas	March ~~2018~~2019	$150 million ~~(h)~~(g)	~~1.92%~~1.67%	—


(a)	The interest rate is the rate as of December 31, ~~2013~~2014 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 this Entergy Arkansas credit facility may be secured by a security interest in its accounts ~~receivable.~~ receivable at Entergy Arkansas’s option.


(c)	The credit facility allows Entergy Arkansas to issue letters of credit against 50% of the borrowing capacity of the facility. As of December 31, ~~2013, $0.2~~ ~~million in~~2014, no letters of credit were outstanding. ~~The credit facility requires Entergy Arkansas to maintain a consolidated debt ratio of~~ ~~65%~~ ~~or less of its total capitalization.~~


(d)	The credit facility allows Entergy Gulf States Louisiana to issue letters of credit against 50% of the borrowing capacity of the facility. As of December 31, ~~2013~~, ~~$15.2 million~~ in2014, 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.~~


(e)	The credit facility allows Entergy Louisiana to issue letters of credit against 50% of the borrowing capacity of the facility. As of December 31, ~~2013~~, ~~$7.0~~ ~~million in~~2014, 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.~~


(f)	~~The credit facilities require Entergy Mississippi to maintain a debt ratio of~~ ~~65%~~ ~~or less of its total capitalization.~~ Borrowings under the Entergy Mississippi credit facilities may be secured by a security interest in its accounts ~~receivable.~~ receivable at Entergy Mississippi’s option.


(g)	~~The credit facility requires Entergy New Orleans to maintain a debt ratio of~~ ~~65%~~ ~~or less of its total capitalization.~~


~~(h)~~	The credit facility allows Entergy Texas to issue letters of credit against 50% of the borrowing capacity of the facility. As of December 31, ~~2013~~, ~~$25~~2014, $1.3 million in 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.~~



	Amount of		Letters of Credit Issued as of
Company	Uncommitted Facility	Letter of Credit Fee	December 31, 2014
Entergy Arkansas	$25 million	0.70%		$2.0	million
Entergy Gulf States Louisiana	$75 million	0.70%		$27.9	million
Entergy Louisiana	$50 million	0.70%		$4.7	million
Entergy Mississippi	$40 million	0.70%		$14.4	million
Entergy Mississippi	$40 million	1.50%		$—
Entergy New Orleans	$15 million	0.75%		$8.1	million
Entergy Texas	$50 million	0.70%		$24.5	million


Contractual Obligations	2014		2015-2016		2017-2018		after 2018		Total		2015		2016-2017		2018-2019		after 2019		Total
	(In Millions)										(In Millions)
Long-term debt (a)		$1,029		$2,537		$3,140		$12,784		$19,490		$1,525		$2,233		$2,831		$14,516		$21,105
Capital lease payments (b)		$5		$9		$8		$30		$52		$5		$8		$7		$28		$48
Operating leases (b)		$106		$155		$84		$111		$456
Operating leases (b) (c)												$90		$139		$97		$96		$422
Purchase obligations ~~(c)~~(d)		$1,738		$2,877		$2,379		$9,526		$16,520		$1,898		$2,738		$2,405		$5,821		$12,862


(a)	Includes estimated interest payments. Long-term debt is discussed in Note 5 to the financial statements.


(b)	Lease obligations are discussed in Note 10 to the financial statements.


(c)	Does not include power purchase agreements that are accounted for as leases that are included in purchase obligations.


(d)	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.



Company		Authorized Return on Common Equity

Entergy Arkansas		~~9.3%~~9.5%
Entergy Gulf States Louisiana		9.15%-10.75% Electric; 9.45%-10.45% Gas
Entergy Louisiana		9.15% - 10.75%
Entergy Mississippi		~~9.76% - 11.83%~~10.07%
Entergy New Orleans		10.7% - 11.5% Electric; 10.25% - 11.25% Gas
Entergy Texas		9.8%

Capacity (a)

Borrowings

Letters
of Credit

Capacity
Available

(In Millions)