Entergy Corporation (ETR, NYSE)
Industry: Utilities - Regulated Electric
Annual report, fiscal year 2015


ENERGY CORPORATION AND SUBSIDIARIES

2015 ANNUAL REPORT



## Entergy Corporation and Subsidiaries 2015

Entergy Corporation (NYSE: ETR) is an integrated energy company engaged primarily in electric power production and retail distribution operations. Entergy owns and operates power plants with approximately 30,000 megawatts of electric generating capacity, including nearly 10,000 megawatts of nuclear power. Entergy delivers electricity to 2.8 million utility customers in Arkansas, Louisiana, Mississippi and Texas. Entergy has annual revenues of approximately $11.5 billion and more than 13,000 employees.

Again this year, in addition to our Annual Report to Shareholders, Entergy is producing an online-only Integrated Report for 2015 that combines key elements previously presented in our annual report to shareholders and sustainability report. Producing one integrated report reinforces our belief that our stakeholders – owners, customers, employees and communities – are linked and that we must deliver sustainable value to all stakeholders in order to succeed.

We encourage you to visit our 2015 Integrated Report website. It presents an interactive version of our 2015 financial, environmental and social performance that includes videos, feature stories and other material.

The website can be found at integratedreport.energy.com.

## Contents

1 Letter To Our Stakeholders
5 Forward-Looking Information and Regulation G Compliance
8 Five-Year Summary of Selected Financial and Operating Data
9 Comparison of Five-Year Cumulative Return
10 Definitions
13 Management's Financial Discussion and Analysis
63 Report of Management
64 Report of Independent Registered Public Accounting Firm
66 Consolidated Statements of Operations
67 Consolidated Statements of Comprehensive Income (Loss)
68 Consolidated Statements of Cash Flows
70 Consolidated Balance Sheets
72 Consolidated Statements of Changes in Equity
73 Notes to Financial Statements
192 Board of Directors
193 Executive Officers
194 Investor Information



## Letter To Our Stakeholders:

At Entergy, we take a lot of pride in what we do. Powering life for our customers, owners, employees and communities is important work that holds tremendous opportunity. We are on a journey to capture that opportunity and create value for our stakeholders. Two years ago, we set a clear vision for our company: We Power Life; and a clear mission: create sustainable value for our customers, owners, employees and communities. In 2015, we made clear progress on numerous operational and regulatory priorities that are critical to creating sustainable value. Employees across our company pulled together as one team to achieve an aggressive to-do list and respond to multiple challenges. It was a terrific effort that demonstrates our commitment to aim high and act in the long-term interests of all our stakeholders.

Much of our work in 2015 was focused on building a foundation to become more predictable and deliver stable utility, parent and other earnings growth. Our ability to operate successfully as a company is predicated on delivering steady earnings and dividend growth and reducing risk. It is how we will continue to power life and create sustainable value for our stakeholders. We have developed strategies that will help us achieve this objective.

Our utility strategy includes aggressive investment plans to modernize our infrastructure and enhance reliability. We made significant progress in 2015 to meet our customers' long-term need for clean, reliable power at reasonable rates. In generation, we pursued approvals for the acquisition of Union Power Station and selected the self-build option for a new combined-cycle gas turbine unit in Louisiana. The Union Power Station acquisition successfully closed in early March 2016. We launched utility-scale solar projects to provide access to renewable energy sources to customers in Arkansas, Mississippi and New Orleans. In transmission and distribution, we invested in projects to improve reliability and resiliency, connect new customers and better handle flow patterns made possible by our move to the Midcontinent Independent System Operator, Inc., or MISO. We initiated one of the largest transmission projects in our history and are moving forward with steps toward the installation of smart meters to benefit our customers and lay the foundation for the next generation of grid technologies on our system. We will continue to work to be more agile and efficient so that we are positioned to meet the technological and other developments that are changing the utility industry.

To facilitate our ability to make these types of productive investments for our customers, we work to mitigate the impact on customer bills. Our average monthly bills are more than 20 to 25 percent below the national average, a significant advantage for our customers and communities. We completed our second year in MISO, a move that resulted in immediate benefits and will continue to have meaningful long-term benefits in lowering costs for our customers through participation in a broader market. We advanced efforts to support industrial growth in our region, which drives demand for power and helps us maintain favorable rates. We also strengthened our ability to access capital to make investments through progressive regulatory mechanisms, a stronger balance sheet and financial flexibility. Positive developments in 2015 include the passage of legislation in Arkansas, Texas and Mississippi that supports our ability to meet our customers' needs when and how they want us to; the combination of our two Louisiana companies into one utility to facilitate future investment; improved regulatory frameworks in Arkansas and Texas that are better aligned to facilitate future investments and the transfer of Algiers, Louisiana, assets to Entergy New Orleans, Inc. from Entergy Louisiana, LLC.

We took significant steps in 2015 to provide greater certainty around our Entergy Wholesale Commodities business and its ability to generate positive cash flows. EWC faces continued pressure – particularly in the Northeast – from low wholesale power prices, which further declined last year. We announced in the fourth quarter of 2015 difficult, but necessary, decisions to close two nuclear plants that are no longer financially viable – Pilgrim Nuclear Power Station in Massachusetts and James A. FitzPatrick Nuclear Power Plant in New York. These decisions affect more than 1,000 dedicated Entergy employees, as well as the communities that have been home to the plants' operations for more than 40 years. We are committed to supporting our employees and communicating openly and honestly with all stakeholders affected by these closures. We continue to focus on safe, secure, reliable operation of our remaining EWC nuclear assets. The three remaining nuclear units are financially viable at this time. Palisades Power Plant, a single-unit plant in Michigan, operates under a favorable power purchase agreement that expires in 2022. Indian Point Energy Center, a low-cost, two-unit plant in New York, is in an attractive market and expected to operate at least into the next decade as we work to secure license renewal from the Nuclear Regulatory Commission. We also have interests in several fossil and wind assets, and we continue to provide management services to the Nebraska Public Power District's Cooper Nuclear Station.



We strengthened the foundation for a safe work environment and a healthy, engaged organization. We continue to evaluate our approach to safety and make improvements to ensure our employees and contractors work safely and go home safely every day after work. We launched a new companywide system to track and report safety-related incidents, developed a new safety manual based on input from more than 600 field personnel and created a new team within the utility organization to drive consistency and focus. We also continue to emphasize throughout the organization the need and benefits of improving our organizational health. We are pushing culture change deeper in the organization and monitoring progress through regular employee surveys. Our emphasis is on working more effectively as a team across organizational boundaries to respond to challenges and achieve better outcomes.

We also continued to invest in the strong foundation we are building with our communities. Our efforts are directed toward education with an emphasis on workforce development. In 2015, we initiated a $5 million, five-year initiative to address workforce development issues and create competitive advantage in the communities we serve. In addition, we invested approximately $3 million with organizations such as Teach For America, STEM NOLA, Jobs for America’s Graduates and City Year to help ensure students, particularly in underserved communities, stay in school and graduate with the skills to achieve their goals.

We strengthened our leadership, refreshing our board of directors in 2015 and adding new members to our executive team. We welcomed three new board members in anticipation of the retirement of two valued members in 2016. By design, our board is diverse and balanced in terms of expertise and skills, gender and tenure. We believe this helps ensure ideas are critically evaluated from multiple perspectives. We also welcomed new members to our executive team. These seamless transitions are evidence of the strong and deep leadership team at Entergy plus our willingness to gain outside expertise where it is needed. At all levels of our organization, leaders are aligned to achieve our mission.

While much of our 2015 progress was focused on building a foundation for future growth, we also delivered solid results for the year. Our 2015 operational earnings per share grew nearly 3 percent over prior year. In 2015, our board of directors approved a 2.4 percent increase in our dividend, the first increase in more than five years. Our objective is a steady, predictable trajectory in our dividend payout going forward. Credit metrics remain strong across our operating companies. We focus on maintaining investment-grade ratings, which helps ensure we have access to the capital we need to invest in our business. Unfortunately, the progress we made in 2015 did not translate into returns for our shareholders. Our total shareholder return was -18.2 percent, which ranked in the fourth quartile of our peer group. However, following progress we made late in 2015, our total shareholder return improved to the top quartile for fourth quarter, which validates the momentum we see moving into 2016. A more complete list of our 2015 accomplishments follows. Suffice it to say, it was a busy year. Not only did our employees address the items on our to-do list, they also responded quickly and effectively to numerous challenges that arose during the year. Their commitment to doing what's right for our stakeholders is inspiring. And of course, we are already tackling an equally aggressive to-do list for 2016. We expect to build on the foundational accomplishments of 2015 with another year of clear progress. We are on a journey to power life and create sustainable value for our customers, owners, employees and communities. We have important work to do.



Leo P. Denault

Chairman of the Board and Chief Executive Officer
March 23, 2016
Our
Commitment to
Operational
Excellence
Operational
excellence is
integral to who we
are at Entergy. We
are committed to
maximizing the
value of our assets
for our customers,
owners,
employees and
communities
through industry-
leading operational
performance. We
did not meet this
commitment in
2015. Two of our
nuclear facilities –
Arkansas Nuclear
One in our utility
business and
Pilgrim Nuclear
Power Station in
EWC – were
placed by the NRC
in Column 4 of the
Reactor Oversight
Process Action
Matrix, which is
based on a scale
of 1 to 5. As a
result, both ANO
and Pilgrim are
currently under
additional NRC
oversight. As we
work through the
evaluation and
inspection
processes
associated with
returning these
plants to Column
1, we are
evaluating nuclear
operations across
our fleet from top
to bottom to
identify any
systemic issues.
We are
disappointed in our
performance and
committed to
strengthening a
culture of
operational
excellence
throughout our
organization.



## To Our Retiring Board Members:

## Thank You

Lead director Gary Edwards will retire from the Entergy board of directors upon reaching mandatory retirement age. A member of our board since 2005 and lead director since 2006, Gary helped guide Entergy during a transformative period, when electric utilities adapted to technological innovations, proposed regulatory changes and dramatic shifts in commodities markets. Gary leads with confidence, experience and a commitment to creating sustainable value for all stakeholders. His contributions have helped position Entergy to operate successfully as a company in the years ahead. Gary’s influence has been recognized inside and outside our company. In 2015, he was named by the National Association of Corporate Directors to the NACD Directorship 100, a list of the most influential people in the boardroom and corporate governance community who play a significant role in shaping the greater boardroom agenda. We thank Gary for his service to the board and Entergy, and for the lasting impact he has had on our company.

Board member Steve Wilkinson will retire from the Entergy board of directors upon reaching mandatory retirement age. Steve’s extensive public utilities, accounting and auditing expertise benefited our board and all of Entergy’s stakeholders. Steve served on the Entergy board since 2003 and as the audit committee chair since 2004. Previously, he was an audit partner with Arthur Andersen for almost 25 years until his retirement in 1998, serving as director of the firm’s North American utility practice. He has played a critical role in helping Entergy meet its objective of presenting information that is accurate, compliant and meaningful to users of financial statements, and provided valuable guidance to our management team. We thank Steve for his contributions to our board and our company.

## To Our Retiring Executive Team Members:

## Thank You

We thank our retiring executives for their many contributions to our company. Jeff Forbes retired as executive vice president and chief nuclear officer in early 2016 after serving more than 12 years in the Entergy nuclear organization. Jeff oversaw 11 nuclear units before moving into the role of chief nuclear officer and directed regional operations for our utility nuclear plants. Mark Savoff retired as executive vice president and chief operating officer following 12 years of service in operations at Entergy. He led the company’s transition to MISO, the construction of the Ninemile Point Unit 6 plant ahead of schedule and under budget, and the optimization of the utility fossil generation fleet. Hugh McDonald will retire as president and chief executive officer of Entergy Arkansas, Inc. in 2016, following a 34-year career with Entergy. Hugh’s vision and leadership have been instrumental in making the right decisions on many critical issues, and he has been a passionate voice for our Arkansas customers and employees.

## To Our New Executive Team Members:

## Welcome

We welcomed several new members to our executive team following retirements announced in 2015. Chris Bakken III will join our organization as executive vice president and chief nuclear officer in early 2016. He brings a unique combination of skills to our nuclear organization to help us perform at a sustained level of operational excellence. Paul Hinnenkamp, previously Entergy senior vice president, capital project management and technology, was named senior vice president and chief operating officer. Paul is responsible for supporting the utility’s growth strategy with safe and reliable operations and disciplined fiscal and project planning for our capital spending plans. Rick Riley, currently group vice president of customer service and operations for Entergy Arkansas, will become president and chief executive officer of Entergy Arkansas in 2016. In that role, he will be responsible for customer service, economic development and resource planning to meet the needs of Entergy Arkansas’ stakeholders.



## What Progress Looks Like at Entergy

- Dedicated Ninemile Point Unit 6 into service, the first utility plant Entergy has built in approximately 30 years

• Completed the Union Power Station acquisition

• Selected self-build option for St. Charles Power Station in Louisiana in a competitive bid process

• Issued request for proposals for long-term generation capacity in southeastern Louisiana

- Issued request for proposals for long-term generation capacity in the western region of our Texas service area

• Pursued utility-scale solar projects in Arkansas, Mississippi and New Orleans

• Announced Lake Charles transmission project and received required certification

• Secured approval for more than $700 million of transmission investments

• Advocated for favorable legislation in Arkansas, Mississippi and Texas

• Secured an improved framework and settlement of Entergy Arkansas rate case

- Combined Entergy Gulf States Louisiana, L.L.C. and Entergy Louisiana, LLC into one utility after receiving final approval

• Transferred Algiers, Louisiana, assets to Entergy New Orleans from Entergy Louisiana

- Utilized distribution cost recovery factor and transmission cost recovery factor mechanisms in filings by Entergy Texas, Inc.

• Received approvals to end the Entergy System Agreement

• Announced decision to close Pilgrim Nuclear Power Station

• Announced decision to close James A. FitzPatrick Nuclear Power Plant

• Sold Rhode Island State Energy Center

• Improved 2015 safety performance over prior year

• Implemented new workforce safety system, manual and team

• Launched $5 million, five-year initiative to support workforce development in our communities

• Improved organizational health scores

• Achieved nearly 3 percent growth in 2015 operational earnings per share over 2014

• Increased dividend by 2.4 percent, first increase in five years

• Added three members to our board of directors in anticipation of 2016 retirements



## Forward-Looking Information and Regulation G Compliance

In this report and from time to time, Entergy Corporation 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 Entergy 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 report and speaks only as of the date on which such statement is made. Except to the extent required by the federal securities laws, Entergy undertakes no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.

Forward-looking statements involve a number of risks and uncertainties. There are factors that could cause actual results to differ materially from those expressed or implied in the forward-looking statements, including (a) those factors discussed or incorporated by reference in Item 1A. Risk Factors contained in the Form 10-K for the year ended Dec. 31, 2015, (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 report and in subsequent securities filings):

- resolution of pending and future rate cases and negotiations, including various performance-based rate discussions, Entergy’s utility supply plan and recovery of fuel and purchased power costs;

- the termination of Entergy Arkansas’ participation in the System Agreement, which occurred in December 2013, the termination of Entergy Mississippi’s participation in the System Agreement, which occurred in November 2015, and the termination of Entergy Texas’, Entergy New Orleans’ and Entergy Louisiana’s participation in the System Agreement, which will occur on August 31, 2016, and will result in the termination of the System Agreement in its entirety pursuant to a settlement agreement approved by FERC in December 2015;

- regulatory and operating challenges and uncertainties and economic risks associated with the Utility operating companies’ move to MISO, which occurred in December 2013, including the effect of current or projected MISO market rules and market and system conditions in the MISO markets, the allocation of MISO system transmission upgrade costs, and the effect of planning decisions that MISO makes with respect to future transmission investments by the Utility operating companies;

- changes in utility regulation, including the beginning or end of retail and wholesale competition, the ability to recover net utility assets and other potential stranded costs, and the application of more stringent transmission reliability requirements or market power criteria by the FERC; changes in the regulation or regulatory oversight of Entergy’s nuclear generating facilities and nuclear materials and fuel, including with respect to the planned potential or actual shutdown of nuclear generating facilities owned or operated by Entergy Wholesale Commodities, and the effects of new or existing safety or environmental concerns regarding nuclear power plants and nuclear fuel;

- resolution of pending or future applications, and related regulatory proceedings and litigation, for license renewals or modifications or other authorizations required of nuclear generating facilities; and the effect of public and political opposition on these applications, regulatory proceedings and litigation;

- the performance of and deliverability of power from Entergy’s generation resources, including the capacity factors at its nuclear generating facilities;

- Entergy’s ability to develop and execute on a point of view regarding future prices of electricity, natural gas and other energy-related commodities;



## Forward-Looking Information and Regulation G Compliance

- prices for power generated by Entergy’s merchant generating facilities and the ability to hedge, meet credit support requirements for hedges, sell power forward or otherwise reduce the market price risk associated with those facilities, including the Entergy Wholesale Commodities nuclear plants;

- the prices and availability of fuel and power Entergy must purchase for its Utility customers, and Entergy’s ability to meet credit support requirements for fuel and power supply contracts;

- volatility and changes in markets for electricity, natural gas, uranium, emissions allowances and other energy-related commodities, and the effect of those changes on Entergy and its customers;

- changes in law resulting from federal or state energy legislation or legislation subjecting energy derivatives used in hedging and risk management transactions to governmental regulation;

- changes in environmental, tax and other laws and regulations, including requirements for reduced emissions of sulfur dioxide, nitrogen oxide, greenhouse gases, mercury, thermal energy and other regulated air and water emissions, and changes in costs of compliance with environmental and other laws and regulations;

- uncertainty regarding the establishment of interim or permanent sites for spent nuclear fuel and nuclear waste storage and disposal and the level of spent fuel and nuclear waste disposal fees charged by the U.S. government or other providers related to such sites;

- variations in weather and the occurrence of hurricanes and other storms and disasters, including uncertainties associated with efforts to remediate the effects of hurricanes, ice storms or other weather events and the recovery of costs associated with restoration, including accessing funded storm reserves, federal and local cost recovery mechanisms, securitization and insurance;

• effects of climate change;

- changes in the quality and availability of water supplies and the related regulation of water use and diversion;

• Entergy’s ability to manage its capital projects and operation and maintenance costs;

- Entergy’s ability to purchase and sell assets at attractive prices and on other attractive terms; the economic climate, and particularly economic conditions in Entergy’s Utility service area and the Northeast United States and events and circumstances that could influence economic conditions in those areas, including power prices, and the risk that anticipated load growth may not materialize;

• the effects of Entergy’s strategies to reduce tax payments;

- changes in the financial markets, particularly those affecting the availability of capital and Entergy’s ability to refinance existing debt, execute share repurchase programs and fund investments and acquisitions;

- actions of rating agencies, including changes in the ratings of debt and preferred stock, changes in general corporate ratings and changes in the rating agencies' ratings criteria;

• changes in inflation and interest rates;

• the effect of litigation and government investigations or proceedings;

• changes in technology, including with respect to new, developing or alternative sources of generation;



## Forward-Looking Information and Regulation G Compliance

- the effects of threatened or actual terrorism, cyberattacks or data security breaches, including increased security costs, accidents and war or a catastrophic event such as a nuclear accident or a natural gas pipeline explosion;

• Entergy’s ability to attract and retain talented management and directors;

• changes in accounting standards and corporate governance;

- declines in the market prices of marketable securities and resulting funding requirements and the effects on benefit costs for Entergy’s defined benefit pension and other postretirement benefit plans; future wage and employee benefit costs, including changes in discount rates and returns on benefit plan assets;

- changes in decommissioning trust fund values or earnings or in the timing of, requirements for, or cost to decommission nuclear plant sites;

- the implementation of the shutdown of Pilgrim and FitzPatrick and the related decommissioning of those plants and Vermont Yankee;

- the effectiveness of Entergy’s risk management policies and procedures and the ability and willingness of its counterparties to satisfy their financial and performance commitments;

• factors that could lead to impairment of long-lived assets and

- the ability to successfully complete merger, acquisition or divestiture plans, regulatory or other limitations imposed as a result of a merger, acquisition or divestiture and the success of the business following a merger, acquisition or divestiture.

## Regulation G

This report includes the non-GAAP financial measure of operational earnings per share. The reconciliation of this measure to the most directly comparable GAAP measures is below.

<table><tr><td>GAAP to Non-GAAP Reconciliation</td><td>2015</td><td>2014</td></tr><tr><td>Earnings (Loss) Per Share</td><td></td><td></td></tr><tr><td>(per share in dollars)</td><td></td><td></td></tr><tr><td>As-reported</td><td>(0.99)</td><td>5.22</td></tr><tr><td>Less special items:</td><td></td><td></td></tr><tr><td>HCM implementation expenses</td><td>—</td><td>(0.05)</td></tr><tr><td>Decisions to close Vermont Yankee, FitzPatrick and Pilgrim</td><td>(5.99)</td><td>(0.56)</td></tr><tr><td>Palisades asset impairment and related write-offs</td><td>(1.43)</td><td>—</td></tr><tr><td>Top Deer investment impairment</td><td>(0.13)</td><td>—</td></tr><tr><td>Gain on the sale of Rhode Island State Energy Center</td><td>0.56</td><td>—</td></tr><tr><td>Total special items</td><td>(6.99)</td><td>(0.61)</td></tr><tr><td>Operational</td><td>6.00</td><td>5.83</td></tr></table>



## Five-Year Summary of Selected Financial and Operating Data

<table><tr><td></td><td>2015</td><td>2014</td><td>2013</td><td>2012</td><td>2011</td></tr><tr><td>Selected Financial Data</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>(In Thousands, Except Percentages and Per Share Amounts)</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Operating revenues</td><td>$11,513,251</td><td>$12,494,921</td><td>$11,390,947</td><td>$10,302,079</td><td>$11,229,073</td></tr><tr><td>Net income (loss)</td><td>($156,734)</td><td>$960,257</td><td>$730,572</td><td>$868,363</td><td>$1,367,372</td></tr><tr><td>Earnings (loss) per share:</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Basic</td><td>($0.99)</td><td>$5.24</td><td>$3.99</td><td>$4.77</td><td>$7.59</td></tr><tr><td>Diluted</td><td>($0.99)</td><td>$5.22</td><td>$3.99</td><td>$4.76</td><td>$7.55</td></tr><tr><td>Dividends declared per share</td><td>$3.34</td><td>$3.32</td><td>$3.32</td><td>$3.32</td><td>$3.32</td></tr><tr><td>Return on common equity</td><td>(1.83)%</td><td>9.58 %</td><td>7.56 %</td><td>9.33 %</td><td>15.43 %</td></tr><tr><td>Book value per share, year-end</td><td>$51.89</td><td>$55.83</td><td>$54.00</td><td>$51.72</td><td>$50.81</td></tr><tr><td>Total assets</td><td>$44,647,681</td><td>$46,414,455</td><td>$43,290,290</td><td>$43,087,339</td><td>$40,597,676</td></tr><tr><td>Long-term obligations (a)</td><td>$13,456,742</td><td>$12,627,180</td><td>$12,265,971</td><td>$12,026,207</td><td>$10,164,622</td></tr><tr><td>Utility Electric Operating Revenues: (In Millions)</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Residential</td><td>$3,518</td><td>$3,555</td><td>$3,396</td><td>$3,022</td><td>$3,369</td></tr><tr><td>Commercial</td><td>2,516</td><td>2,553</td><td>2,415</td><td>2,174</td><td>2,333</td></tr><tr><td>Industrial</td><td>2,462</td><td>2,623</td><td>2,405</td><td>2,034</td><td>2,307</td></tr><tr><td>Governmental</td><td>223</td><td>227</td><td>218</td><td>198</td><td>205</td></tr><tr><td>Total retail</td><td>8,719</td><td>8,958</td><td>8,434</td><td>7,428</td><td>8,214</td></tr><tr><td>Sales for resale</td><td>249</td><td>330</td><td>210</td><td>179</td><td>216</td></tr><tr><td>Other</td><td>341</td><td>304</td><td>298</td><td>264</td><td>244</td></tr><tr><td>Total</td><td>$9,309</td><td>$9,592</td><td>$8,942</td><td>$7,871</td><td>$8,674</td></tr><tr><td>Utility Billed Electric Energy Sales: (GWh)</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Residential</td><td>36,068</td><td>35,932</td><td>35,169</td><td>34,664</td><td>36,684</td></tr><tr><td>Commercial</td><td>29,348</td><td>28,827</td><td>28,547</td><td>28,724</td><td>28,720</td></tr><tr><td>Industrial</td><td>44,382</td><td>43,723</td><td>41,653</td><td>41,181</td><td>40,810</td></tr><tr><td>Governmental</td><td>2,514</td><td>2,428</td><td>2,412</td><td>2,435</td><td>2,474</td></tr><tr><td>Total retail</td><td>112,312</td><td>110,910</td><td>107,781</td><td>107,004</td><td>108,688</td></tr><tr><td>Sales for resale</td><td>9,274</td><td>9,462</td><td>3,020</td><td>3,200</td><td>4,111</td></tr><tr><td>Total</td><td>121,586</td><td>120,372</td><td>110,801</td><td>110,204</td><td>112,799</td></tr><tr><td>Entergy Wholesale Commodities:</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Operating revenues (In Millions)</td><td>$2,062</td><td>$2,719</td><td>$2,313</td><td>$2,326</td><td>$2,414</td></tr><tr><td>Billed electric energy sales (In GWh)</td><td>39,745</td><td>44,424</td><td>45,127</td><td>46,178</td><td>43,497</td></tr></table>

(a) Includes long-term debt (excluding currently maturing debt), noncurrent capital lease obligations, and subsidiary preferred stock without sinking fund that is not presented as equity on the balance sheet.



## Comparison of Five-Year Cumulative Return

The following graph compares the performance of the common stock of Entergy Corporation with the Philadelphia Utility Index and the S&P 500 Index (each of which includes Entergy Corporation) for the last five years ended December 31.



<table><tr><td></td><td>2010</td><td>2011</td><td>2012</td><td>2013</td><td>2014</td><td>2015</td></tr><tr><td>ENTERGY CORPORATION</td><td>$100.00</td><td>$108.29</td><td>$99.23</td><td>$103.54</td><td>$149.88</td><td>$122.66</td></tr><tr><td>PHILADELPHIA UTILITY</td><td>$100.00</td><td>$119.24</td><td>$118.57</td><td>$131.59</td><td>$169.66</td><td>$159.05</td></tr><tr><td>S&amp;P 500 INDEX</td><td>$100.00</td><td>$102.11</td><td>$118.44</td><td>$156.78</td><td>$178.22</td><td>$180.67</td></tr></table>

Assumes $100 invested at the closing price on Dec. 31, 2010, in Entergy Corporation common stock, the Philadelphia Utility Index and the S&P 500 Index, and reinvestment of all dividends.

Source: Bloomberg



## DEFINITIONS

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

<table><tr><td>Abbreviation or Acronym</td><td>Term</td></tr><tr><td>AFUDC</td><td>Allowance for Funds Used During Construction</td></tr><tr><td>ALJ</td><td>Administrative Law Judge</td></tr><tr><td>ANO 1 and 2</td><td>Units 1 and 2 of Arkansas Nuclear One (nuclear), owned by Entergy Arkansas</td></tr><tr><td>APSC</td><td>Arkansas Public Service Commission</td></tr><tr><td>ASLB</td><td>Atomic Safety and Licensing Board, the board within the NRC that conducts hearings and performs other regulatory functions that the NRC authorizes</td></tr><tr><td>ASU</td><td>Accounting Standards Update issued by the FASB</td></tr><tr><td>Board</td><td>Board of Directors of Entergy Corporation</td></tr><tr><td>Cajun</td><td>Cajun Electric Power Cooperative, Inc.</td></tr><tr><td>capacity factor</td><td>Actual plant output divided by maximum potential plant output for the period</td></tr><tr><td>City Council or Council</td><td>Council of the City of New Orleans, Louisiana</td></tr><tr><td>D. C. Circuit</td><td>U.S. Court of Appeals for the District of Columbia Circuit</td></tr><tr><td>DOE</td><td>United States Department of Energy</td></tr><tr><td>Entergy</td><td>Entergy Corporation and its direct and indirect subsidiaries</td></tr><tr><td>Entergy Corporation</td><td>Entergy Corporation, a Delaware corporation</td></tr><tr><td>Entergy Gulf States, Inc.</td><td>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</td></tr><tr><td>Entergy Gulf States</td><td>Entergy Gulf States Louisiana, L.L.C., a Louisiana limited liability 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. Effective October 1, 2015, the business of Entergy Gulf States Louisiana was combined with Entergy Louisiana.</td></tr><tr><td>Entergy Louisiana</td><td>Entergy Louisiana, LLC, a Texas limited liability company formally created as part of the combination of Entergy Gulf States Louisiana and the company formerly known as Entergy Louisiana, LLC (Old Entergy Louisiana) into a single public utility company and the successor to Old Entergy Louisiana for financial reporting purposes.</td></tr><tr><td>Entergy Texas</td><td>Entergy Texas, Inc., a Texas corporation 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.</td></tr><tr><td>Entergy Wholesale Commodities (EWC)</td><td>Entergy&#x27;s non-utility business segment primarily comprised of the ownership, operation, and decommissioning of nuclear power plants, the ownership of interests in non-nuclear power plants, and the sale of the electric power produced by its operating power plants to wholesale customers</td></tr><tr><td>EPA</td><td>United States Environmental Protection Agency</td></tr><tr><td>ERCOT</td><td>Electric Reliability Council of Texas</td></tr><tr><td>FASB</td><td>Financial Accounting Standards Board</td></tr><tr><td>FERC</td><td>Federal Energy Regulatory Commission</td></tr><tr><td>FitzPatrick</td><td>James A. FitzPatrick Nuclear Power Plant (nuclear), owned by an Entergy subsidiary in the Entergy Wholesale Commodities business segment</td></tr><tr><td>FTR</td><td>Financial transmission right</td></tr><tr><td>Grand Gulf</td><td>Unit No. 1 of Grand Gulf Nuclear Station (nuclear), 90% owned or leased by System Energy</td></tr></table>



## DEFINITIONS (Continued)

<table><tr><td>GWh</td><td>Gigawatt-hour(s), which equals one million kilowatt-hours</td></tr><tr><td>Independence</td><td>Independence Steam Electric Station (coal), owned 16% by Entergy Arkansas, 25% by Entergy Mississippi, and 7% by Entergy Power, LLC</td></tr><tr><td>Indian Point 2</td><td>Unit 2 of Indian Point Energy Center (nuclear), owned by an Entergy subsidiary in the Entergy Wholesale Commodities business segment</td></tr><tr><td>Indian Point 3</td><td>Unit 3 of Indian Point Energy Center (nuclear), owned by an Entergy subsidiary in the Entergy Wholesale Commodities business segment</td></tr><tr><td>IRS</td><td>Internal Revenue Service</td></tr><tr><td>ISO</td><td>Independent System Operator</td></tr><tr><td>kV</td><td>Kilovolt</td></tr><tr><td>kW</td><td>Kilowatt, which equals one thousand watts</td></tr><tr><td>kWh</td><td>Kilowatt-hour(s)</td></tr><tr><td>LDEQ</td><td>Louisiana Department of Environmental Quality</td></tr><tr><td>LPSC</td><td>Louisiana Public Service Commission</td></tr><tr><td>Mcf</td><td>1,000 cubic feet of gas</td></tr><tr><td>MISO</td><td>Midcontinent Independent System Operator, Inc., a regional transmission organization</td></tr><tr><td>MMBtu</td><td>One million British Thermal Units</td></tr><tr><td>MPSC</td><td>Mississippi Public Service Commission</td></tr><tr><td>MW</td><td>Megawatt(s), which equals one thousand kilowatts</td></tr><tr><td>MWh</td><td>Megawatt-hour(s)</td></tr><tr><td>Nelson Unit 6</td><td>Unit No. 6 (coal) of the Nelson Steam Electric Generating Station, 70% of which is co-owned by Entergy 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</td></tr><tr><td>Net debt to net capital ratio</td><td>Gross debt less cash and cash equivalents divided by total capitalization less cash and cash equivalents</td></tr><tr><td>Net MW in operation</td><td>Installed capacity owned and operated</td></tr><tr><td>NRC</td><td>Nuclear Regulatory Commission</td></tr><tr><td>NYPA</td><td>New York Power Authority</td></tr><tr><td>Palisades</td><td>Palisades Nuclear Plant (nuclear), owned by an Entergy subsidiary in the Entergy Wholesale Commodities business segment</td></tr><tr><td>Parent &amp; Other</td><td>The portions of Entergy not included in the Utility or Entergy Wholesale Commodities segments, primarily consisting of the activities of the parent company, Entergy Corporation</td></tr><tr><td>Pilgrim</td><td>Pilgrim Nuclear Power Station (nuclear), owned by an Entergy subsidiary in the Entergy Wholesale Commodities business segment</td></tr><tr><td>PPA</td><td>Purchased power agreement or power purchase agreement</td></tr><tr><td>PRP</td><td>Potentially responsible party (a person or entity that may be responsible for remediation of environmental contamination)</td></tr><tr><td>PUCT</td><td>Public Utility Commission of Texas</td></tr><tr><td>Registrant Subsidiaries</td><td>Entergy Arkansas, Inc., Entergy Louisiana, LLC, Entergy Mississippi, Inc., Entergy New Orleans, Inc., Entergy Texas, Inc., and System Energy Resources, Inc.</td></tr></table>



## DEFINITIONS (Concluded)

<table><tr><td>Abbreviation or Acronym</td><td>Term</td></tr><tr><td>Ritchie Unit 2</td><td>Unit 2 of the R.E. Ritchie Steam Electric Generating Station (gas/oil)</td></tr><tr><td>River Bend</td><td>River Bend Station (nuclear), owned by Entergy Louisiana</td></tr><tr><td>RTO</td><td>Regional transmission organization</td></tr><tr><td>SEC</td><td>Securities and Exchange Commission</td></tr><tr><td>SMEPA</td><td>South Mississippi Electric Power Association, which owns a 10% interest in Grand Gulf</td></tr><tr><td>System Agreement</td><td>Agreement, effective January 1, 1983, as modified, among the Utility operating companies relating to the sharing of generating capacity and other power resources. Entergy Arkansas terminated its participation in the System Agreement effective December 18, 2013. Entergy Mississippi terminated its participation in the System Agreement effective November 7, 2015.</td></tr><tr><td>System Energy</td><td>System Energy Resources, Inc.</td></tr><tr><td>System Fuels</td><td>System Fuels, Inc.</td></tr><tr><td>TWh</td><td>Terawatt-hour(s), which equals one billion kilowatt-hours</td></tr><tr><td>Unit Power Sales Agreement</td><td>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&#x27;s share of Grand Gulf</td></tr><tr><td>Utility</td><td>Entergy&#x27;s business segment that generates, transmits, distributes, and sells electric power, with a small amount of natural gas distribution</td></tr><tr><td>Utility operating companies</td><td>Entergy Arkansas, Entergy Gulf States Louisiana (prior to the completion of the business combination with Entergy Louisiana), Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas</td></tr><tr><td>Vermont Yankee</td><td>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</td></tr><tr><td>Waterford 3</td><td>Unit No. 3 (nuclear) of the Waterford Steam Electric Station, 100% owned or leased by Entergy Louisiana</td></tr><tr><td>weather-adjusted usage</td><td>Electric usage excluding the effects of deviations from normal weather</td></tr><tr><td>White Bluff</td><td>White Bluff Steam Electric Generating Station, 57% owned by Entergy Arkansas</td></tr></table>



## MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS

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

- The Utility business segment includes the generation, transmission, distribution, and sale of electric power in portions of Arkansas, Mississippi, Texas, and Louisiana, including the City of New Orleans; and operation of a small natural gas distribution business.

- The Entergy Wholesale Commodities business segment includes the ownership, operation, and decommissioning of nuclear power plants located in the northern United States and the sale of the electric power produced by its operating plants to wholesale customers. On December 29, 2014, the Vermont Yankee plant ceased power production and entered its decommissioning phase. In October 2015, Entergy determined that it will close the Pilgrim plant no later than June 1, 2019 and the FitzPatrick plant at the end of its current fuel cycle, which is planned for January 27, 2017. Entergy Wholesale Commodities also provides services to other nuclear power plant owners and owns interests in non-nuclear power plants that sell the electric power produced by those plants to wholesale customers.

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

<table><tr><td rowspan="2">Segment</td><td colspan="3">% of Revenue</td><td colspan="3">% of Net Income (Loss)</td><td colspan="3">% of Total Assets</td></tr><tr><td>2015</td><td>2014</td><td>2013</td><td>2015</td><td>2014</td><td>2013</td><td>2015</td><td>2014</td><td>203</td></tr><tr><td>Utility</td><td>82</td><td>78</td><td>80</td><td>711</td><td>88</td><td>116</td><td>86</td><td>82</td><td>82</td></tr><tr><td>Entergy Wholesale Commodities</td><td>18</td><td>22</td><td>20</td><td>(680)</td><td>31</td><td>6</td><td>18</td><td>22</td><td>22</td></tr><tr><td>Parent &amp; Other</td><td>—</td><td>—</td><td>—</td><td>(131)</td><td>(19)</td><td>(22)</td><td>(4)</td><td>(4)</td><td>(4)</td></tr></table>

See Note 13 to the financial statements for further financial information regarding Entergy’s business segments.

Net income (loss) for 2015 includes $2,036 million ($1,317 million net-of-tax) of impairment and related charges to write down the carrying values of the Entergy Wholesale Commodities' FitzPatrick, Pilgrim, and Palisades plants and related assets to their fair values. See Note 1 to the financial statements for further discussion of the impairment and related charges.



## Results of Operations

## 2015 Compared to 2014

Following are income statement variances for Utility, Entergy Wholesale Commodities, Parent & Other, and Entergy comparing 2015 to 2014 showing how much the line item increased or (decreased) in comparison to the prior period.

<table><tr><td></td><td>Utility</td><td>Entergy Wholesale Commodities</td><td>Parent &amp; Other</td><td>Entergy</td></tr><tr><td></td><td></td><td colspan="3">(In Thousands)</td></tr><tr><td>2014 Consolidated Net Income (Loss)</td><td>$846,496</td><td>$294,521</td><td>($180,760)</td><td>$960,257</td></tr><tr><td>Net revenue (operating revenue less fuel expense, purchased power, and other regulatory charges/credits)</td><td>94,195</td><td>(558,060)</td><td>(1,885)</td><td>(465,750)</td></tr><tr><td>Other operation and maintenance</td><td>166,812</td><td>(123,645)</td><td>1,278</td><td>44,445</td></tr><tr><td>Asset write-offs, impairments, and related charges</td><td>(3,553)</td><td>1,928,707</td><td>—</td><td>1,925,154</td></tr><tr><td>Taxes other than income taxes</td><td>35,010</td><td>(20,196)</td><td>2</td><td>14,816</td></tr><tr><td>Depreciation and amortization</td><td>57,076</td><td>(36,892)</td><td>(1,546)</td><td>18,638</td></tr><tr><td>Gain on sale of business</td><td>—</td><td>154,037</td><td>—</td><td>154,037</td></tr><tr><td>Other income</td><td>(3,993)</td><td>(4,899)</td><td>(18,607)</td><td>(27,499)</td></tr><tr><td>Interest expense</td><td>11,403</td><td>10,142</td><td>(5,583)</td><td>15,962</td></tr><tr><td>Other expenses</td><td>10,821</td><td>(19,533)</td><td>—</td><td>(8,712)</td></tr><tr><td>Income taxes</td><td>(455,387)</td><td>(787,327)</td><td>10,190</td><td>(1,232,524)</td></tr><tr><td>2015 Consolidated Net Income (Loss)</td><td>$1,114,516</td><td>($1,065,657)</td><td>($205,593)</td><td>($156,734)</td></tr></table>

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

Results of operations for 2015 include $2,036 million ($1,317 million net-of-tax) of impairment and related charges to write down the carrying values of the FitzPatrick, Pilgrim, and Palisades plants and related assets to their fair values. See Note 1 to the financial statements for further discussion of the impairment and related charges. As a result of the Entergy Louisiana and Entergy Gulf States Louisiana business combination, results of operations for 2015 also include two items that occurred in October 2015: 1) a deferred tax asset and resulting net increase in tax basis of approximately $334 million and 2) a regulatory liability of $107 million ($66 million net-of-tax) as a result of customer credits to be realized by electric customers of Entergy Louisiana, consistent with the terms of an agreement with the LPSC. See Note 2 to the financial statements for further discussion of the business combination and customer credits. Results of operations for 2015 also include the sale in December 2015 of the 583 MW Rhode Island State Energy Center for a realized gain of $154 million ($100 million net-of-tax) on the sale and the $77 million ($47 million net-of-tax) write-off and regulatory charges to recognize that a portion of the assets associated with the Waterford 3 replacement steam generator project is no longer probable of recovery. See Note 2 to the financial statements for further discussion of the Waterford 3 write-off.

Results of operations for 2014 include $154 million ($100 million net-of-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 net-of-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.

## Net Revenue

## Utility

Following is an analysis of the change in net revenue comparing 2015 to 2014.

<table><tr><td></td><td>Amount (In Millions)</td></tr><tr><td>2014 net revenue</td><td>$5,735</td></tr><tr><td>Retail electric price</td><td>187</td></tr><tr><td>Volume/weather</td><td>95</td></tr><tr><td>Louisiana business combination customer credits</td><td>(107)</td></tr><tr><td>MISO deferral</td><td>(35)</td></tr><tr><td>Waterford 3 replacement steam generator provision</td><td>(32)</td></tr><tr><td>Other</td><td>(14)</td></tr><tr><td>2015 net revenue</td><td>$5,829</td></tr></table>

The retail electric price variance is primarily due to:

• formula rate plan increases at Entergy Louisiana, as approved by the LPSC, effective December 2014 and January 2015;

- an increase in energy efficiency rider revenue primarily due to increases in the energy efficiency rider at Entergy Arkansas, as approved by the APSC, effective July 2015 and July 2014, and new energy efficiency riders at Entergy Louisiana and Entergy Mississippi that began in the fourth quarter 2014. Energy efficiency revenues are largely offset by costs included in other operation and maintenance expenses and have a minimal effect on net income; and

- an annual net rate increase at Entergy Mississippi of $16 million, effective February 2015, as a result of the MPSC order in the June 2014 rate case.

See Note 2 to the financial statements for a discussion of rate and regulatory proceedings.

The volume/weather variance is primarily due to an increase of 1,402 GWh, or 1%, in billed electricity usage, including an increase in industrial usage and the effect of more favorable weather. The increase in industrial sales was primarily due to expansion in the chemicals industry and the addition of new customers, partially offset by decreased demand primarily due to extended maintenance outages for existing chemicals customers.

The Louisiana business combination customer credits variance is due to a regulatory liability of $107 million recorded by Entergy in October 2015 as a result of the Entergy Gulf States Louisiana and Entergy Louisiana business combination. Consistent with the terms of an agreement with the LPSC, electric customers of Entergy Louisiana will realize customer credits associated with the business combination; accordingly, in October 2015, Entergy recorded a regulatory liability of $107 million ($66 million net-of-tax). See Note 2 to the financial statements for further discussion of the business combination and customer credits.



The MISO deferral variance is primarily due to the deferral in 2014 of non-fuel MISO-related charges, as approved by the LPSC and the MPSC. The deferral of non-fuel MISO-related charges is partially offset in other operation and maintenance expenses. See Note 2 to the financial statements for further discussion of the recovery of non-fuel MISO-related charges.

The Waterford 3 replacement steam generator provision is due to a regulatory charge of approximately $32 million recorded in 2015 related to the uncertainty associated with the resolution of the Waterford 3 replacement steam generator project. See Note 2 to the financial statements for a discussion of the Waterford 3 replacement steam generator prudence review proceeding.

## Entergy Wholesale Commodities

Following is an analysis of the change in net revenue comparing 2015 to 2014.

<table><tr><td></td><td>Amount (In Millions)</td></tr><tr><td>2014 net revenue</td><td>$2,224</td></tr><tr><td>Nuclear realized price changes</td><td>(310)</td></tr><tr><td>Vermont Yankee shutdown in December 2014</td><td>(305)</td></tr><tr><td>Nuclear volume, excluding Vermont Yankee effect</td><td>20</td></tr><tr><td>Other</td><td>37</td></tr><tr><td>2015 net revenue</td><td>$1,666</td></tr></table>

As shown in the table above, net revenue for Entergy Wholesale Commodities decreased by approximately $558 million in 2015 primarily due to:

- lower realized wholesale energy prices, primarily due to significantly higher Northeast market power prices in 2014, and lower capacity prices in 2015; and

• a decrease in net revenue as a result of Vermont Yankee ceasing power production in December 2014.

The decrease was partially offset by higher volume in the Entergy Wholesale Commodities nuclear fleet, excluding Vermont Yankee, resulting from fewer refueling outage days in 2015 as compared to 2014, partially offset by more unplanned outage days in 2015 as compared to 2014.



Following are key performance measures for Entergy Wholesale Commodities for 2015 and 2014.

<table><tr><td></td><td>2015</td><td>2014</td></tr><tr><td>Owned capacity (MW) (a)</td><td>4,880</td><td>6,068</td></tr><tr><td>GWh billed</td><td>39,745</td><td>44,424</td></tr><tr><td>Average revenue per MWh</td><td>$51.88</td><td>$60.84</td></tr><tr><td>Entergy Wholesale Commodities Nuclear Fleet</td><td></td><td></td></tr><tr><td>Capacity factor</td><td>91%</td><td>91%</td></tr><tr><td>GWh billed</td><td>35,859</td><td>40,253</td></tr><tr><td>Average revenue per MWh</td><td>$51.49</td><td>$60.35</td></tr><tr><td>Refueling Outage Days:</td><td></td><td></td></tr><tr><td>FitzPatrick</td><td>—</td><td>44</td></tr><tr><td>Indian Point 2</td><td>—</td><td>24</td></tr><tr><td>Indian Point 3</td><td>23</td><td>—</td></tr><tr><td>Palisades</td><td>32</td><td>56</td></tr><tr><td>Pilgrim</td><td>34</td><td>—</td></tr></table>

(a) The reduction in owned capacity is due to the retirement of the 605 MW Vermont Yankee plant in December 2014 and the sale of the 583 MW Rhode Island State Energy Center in December 2015.

Realized Revenue per MWh for Entergy Wholesale Commodities Nuclear Plants

The effects of sustained low natural gas prices and power market structure challenges have resulted in lower market prices for electricity in the power regions where the Entergy Wholesale Commodities nuclear power plants are located. The Entergy Wholesale Commodities nuclear business experienced an annual realized price per MWh of $51.49 in 2015, $60.35 in 2014, and $50.15 in 2013. The decrease in realized price in 2015 is primarily attributable to a significant increase in first quarter 2014 prices due to cold winter weather and northeastern U.S. gas pipeline infrastructure limitations. Prior to 2010 the annual realized price per MWh for Entergy Wholesale Commodities 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 86% of its planned nuclear energy output for 2016 for an expected average contracted energy price of $46 per MWh based on market prices at December 31, 2015. In addition, Entergy Wholesale Commodities has sold forward 63% of its planned nuclear energy output for 2017 for an expected average contracted energy price of $46 per MWh based on market prices at December 31, 2015.

The market price trend presents a challenging economic situation for the Entergy Wholesale Commodities plants. The severity of the challenge varies for each of the 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, including the estimated asset retirement costs. In addition, currently the market design under which the plants operate does not adequately compensate merchant nuclear plants for their environmental and fuel diversity benefits in the region.

In October 2015, Entergy determined that it will close the Pilgrim and FitzPatrick plants. The decisions to shut down the plants were primarily due to the poor market conditions that have led to reduced revenues, the poor market design that fails to properly compensate nuclear generators for the benefits they provide, and increased operational costs. The Pilgrim plant will cease operations no later than June 1, 2019. FitzPatrick is expected to shut down at the end of its current fuel cycle, which is planned for January 27, 2017.

Entergy previously shut down Vermont Yankee in 2014, and, after the closures of Pilgrim and FitzPatrick, will have two remaining nuclear power generating facilities in operation in the Entergy Wholesale Commodities business,



Indian Point and Palisades. Unlike the three facilities that Entergy has decided to shut down, Indian Point is a multi-unit site with both Indian Point 2 and 3 in operation that sells power at NYISO Zone G, which is a key supply region for New York City. In addition, Indian Point 2 (1,028 MW) and 3 (1,041 MW) are significantly larger plants than Vermont Yankee (605 MW), Pilgrim (688 MW), or FitzPatrick (838 MW). The Indian Point plants, however, are currently involved, and face opposition, in extensive licensing proceedings, which are described in “Entergy Wholesale Commodities Authorizations to Operate Its Nuclear Power Plants.” Palisades (811 MW) is similar in size to FitzPatrick, is also a single-unit site, and the MISO market in which it operates has also experienced market price declines over the past few years. Most of the Palisades output, however, is sold under a 15-year power purchase agreement, entered at the plant’s acquisition in 2007, that expires in 2022. The power purchase agreement prices currently exceed market prices and escalate each year, up to $61.50/MWh in 2022.

In 2015, Entergy recorded impairment and other related charges to write down the carrying values of the FitzPatrick, Pilgrim, and Palisades plants and related assets to their fair values. See Note 1 to the financial statements for further discussion of the impairments of the value of FitzPatrick, Pilgrim, and Palisades. Impairment of long-lived assets and nuclear decommissioning costs, and the factors that influence these items, are both discussed in “Critical Accounting Estimates” below. If economic conditions or regulatory activity no longer support the continued operation of Indian Point or Palisades for their expected lives or no longer support the recovery of the costs of the plants it could adversely affect Entergy’s results of operations through loss of revenue, impairment charges, increased depreciation rates, transitional costs, or accelerated decommissioning costs.

Other Income Statement Items

## Utility

Other operation and maintenance expenses increased from $2,276 million for 2014 to $2,443 million for 2015 primarily due to:

- an increase of $59 million in nuclear generation expenses primarily due to an increase in regulatory compliance costs, higher labor costs, and an overall higher scope of work done in 2015. The increase in regulatory compliance costs is primarily related to additional NRC inspection activities in 2015 as a result of the NRC’s March 2015 decision to move ANO into the “multiple/repetitive degraded cornerstone column” of the NRC’s reactor oversight process action matrix. See “ANO Damage, Outage, and NRC Reviews” below for a discussion of the ANO stator incident and subsequent NRC reviews;

- an increase of $28 million in compensation and benefits costs primarily due to an increase in net periodic pension and other postretirement benefit costs as a result of lower discount rates and changes in retirement and mortality assumptions, partially offset by a decrease in the accrual for incentive-based compensation. See “Critical Accounting Estimates” below and Note 11 to the financial statements for further discussion of pension and other postretirement benefit costs;

- an increase of $27 million in energy efficiency costs, including the effects of true-ups to energy efficiency filings for fixed costs to be collected from customers. These costs are recovered through energy efficiency riders in certain jurisdictions and have a minimal effect on net income;

- an increase of $26 million in distribution expenses primarily due to higher vegetation maintenance and higher labor costs in 2015 as compared to 2014; and

- an increase of $24 million in transmission expenses primarily due to an increase in the amount of transmission costs allocated by MISO. The net income effect is partially offset by the method of recovery of these costs in certain jurisdictions. See Note 2 to the financial statements for further information on the recovery of these costs.

The increase was partially offset by a decrease of $23 million in storm damage accruals primarily at Entergy Mississippi. See Note 2 to the financial statements for a discussion of storm cost recovery.



The asset write-offs, impairments, and related charges variance is due to the following activity:

- the $45 million ($28 million net-of-tax) write-off in 2015 to recognize that a portion of the assets associated with the Waterford 3 replacement steam generator project is no longer probable of recovery and the $16 million ($11 million net-of-tax) write-off in 2014 due to the uncertainty at the time associated with the resolution of the Waterford 3 replacement steam generator project prudence review;

- the $23.5 million ($15.3 million net-of-tax) write-off in 2015 of the regulatory asset associated with the Spindletop gas storage facility as a result of the approval of the System Agreement termination settlement agreement; and

- the $56 million ($37 million net-of-tax) write-off in 2014 of Entergy Mississippi’s regulatory asset associated with new nuclear generation development costs.

See Note 2 to the financial statements for further discussion of the asset write-offs, impairments, and related charges.

Taxes other than income taxes increased primarily due to increases in ad valorem taxes, payroll taxes, and franchise taxes.

Depreciation and amortization expenses increased primarily due to additions to plant in service, including the Ninemile Unit 6 project, which was placed in service in December 2014, and higher depreciation rates at Entergy Mississippi effective February 2015, as approved by the MPSC.

Interest expense increased primarily due to net debt issuances in the fourth quarter 2014 by certain Utility operating companies including the issuance by Entergy Louisiana in November 2014 of $250 million of 4.95% Series first mortgage bonds due January 2045 and the issuance by Entergy Arkansas in December 2014 of $250 million of 4.95% Series first mortgage bonds due December 2044.

Other expenses increased primarily due to increases in decommissioning expenses in 2015 as a result of revised decommissioning cost studies in 2014 for Grand Gulf, ANO1, ANO2, and Waterford 3. See Note 9 to the financial statements for further discussion of the revised decommissioning cost studies.

## Entergy Wholesale Commodities

Other operation and maintenance expenses decreased from $1,023 million for 2014 to $899 million for 2015 primarily due to the shutdown of Vermont Yankee, which ceased power production in December 2014. The decrease was partially offset by an increase of $12 million in compensation and benefits costs primarily due to an increase in net periodic pension and other postretirement benefit costs as a result of lower discount rates and changes in retirement and mortality assumptions, partially offset by a decrease in the accrual for incentive-based compensation. See “Critical Accounting Estimates” below and Note 11 to the financial statements for further discussion of pension and other postretirement benefit costs.

The asset write-offs, impairments, and related charges variance is primarily due to $2,036 million ($1,317 million net-of-tax) in 2015 of impairment and related charges to write down the carrying values of the FitzPatrick, Pilgrim, and Palisades plants and related assets to their fair values, partially offset by $107 million ($69 million net-of-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 charges.

Taxes other than income taxes decreased primarily due to the shutdown of Vermont Yankee, which ceased power production in December 2014.



Depreciation and amortization expenses decreased primarily due to decreases in depreciable asset balances as a result of the shutdown of Vermont Yankee, which ceased power production in December 2014. See Note 1 to the financial statements for further discussion of impairment of long-lived assets.

The gain on sale of business resulted from the sale in December 2015 of the 583 MW Rhode Island State Energy Center in Johnston, Rhode Island, a business wholly-owned by Entergy in the Entergy Wholesale Commodities segment. Entergy sold Rhode Island State Energy Center for approximately $490 million and realized a pre-tax gain of $154 million on the sale.

Other income decreased primarily due to $37 million ($24 million net-of-tax) in 2015 of impairment and related charges resulting from the write-down of the carrying values of the generating assets of Entergy’s equity method investee Top Deer Wind Ventures, LLC to their fair values, partially offset by higher realized gains on decommissioning trust fund investments in 2015 as compared to 2014, including portfolio reallocations for the Vermont Yankee nuclear decommissioning trust funds.

Other expenses decreased primarily due to a decrease in nuclear refueling outage costs that are being amortized over the estimated period to the next outage as a result of the impairments and related charges in 2015 to write down the carrying values of the FitzPatrick and Pilgrim plants and related assets and the shutdown of Vermont Yankee, which ceased power production in December 2014. See Note 1 to the financial statements for further discussion of the impairment and related charges.

## Income Taxes

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 2015 was 80.4%. The difference in the effective income tax rate versus the statutory rate of 35% for 2015 was primarily due to the tax effects of the Louisiana business combination coupled with the loss before income taxes resulting from the nuclear plant impairments previously discussed. See Note 3 to the financial statements for further discussion of the tax effects of the Louisiana business combination and a reconciliation of the federal statutory rate of 35% to the effective income tax rate.

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.



## 2014 Compared to 2013

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

<table><tr><td></td><td>Utility</td><td>Entergy Wholesale Commodities</td><td>Parent &amp; Other</td><td>Entergy</td></tr><tr><td></td><td></td><td colspan="3">(In Thousands)</td></tr><tr><td>2013 Consolidated Net Income (Loss)</td><td>$846,215</td><td>$42,976</td><td>($158,619)</td><td>$730,572</td></tr><tr><td>Net revenue (operating revenue less fuel expense, purchased power, and other regulatory charges/credits)</td><td>210,893</td><td>422,147</td><td>(17,519)</td><td>615,521</td></tr><tr><td>Other operation and maintenance</td><td>12,369</td><td>(25,043)</td><td>(8,724)</td><td>(21,398)</td></tr><tr><td>Asset write-offs, impairments, and related charges</td><td>62,814</td><td>(221,809)</td><td>(2,790)</td><td>(161,785)</td></tr><tr><td>Taxes other than income taxes</td><td>2,760</td><td>1,709</td><td>(213)</td><td>4,256</td></tr><tr><td>Depreciation and amortization</td><td>(2,019)</td><td>60,053</td><td>(440)</td><td>57,594</td></tr><tr><td>Gain on sale of business</td><td>—</td><td>(43,569)</td><td>—</td><td>(43,569)</td></tr><tr><td>Other income</td><td>1,795</td><td>(23,642)</td><td>(13,272)</td><td>(35,119)</td></tr><tr><td>Interest expense</td><td>22,556</td><td>323</td><td>591</td><td>23,470</td></tr><tr><td>Other expenses</td><td>7,696</td><td>33,699</td><td>—</td><td>41,395</td></tr><tr><td>Income taxes</td><td>106,231</td><td>254,459</td><td>2,926</td><td>363,616</td></tr><tr><td>2014 Consolidated Net Income (Loss)</td><td>$846,496</td><td>$294,521</td><td>($180,760)</td><td>$960,257</td></tr></table>

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

Results of operations for 2014 include $154 million ($100 million net-of-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 net-of-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 $322 million ($202 million net-of-tax) of impairment and other related charges to write down the carrying value of Vermont Yankee and related assets to their fair values. 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 net-of-tax), including approximately $85 million ($55 million net-of-tax) for Utility and $25 million ($15 million net-of-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 net-of-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.



## Net Revenue

## Utility

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

<table><tr><td></td><td>Amount (In Millions)</td></tr><tr><td>2013 net revenue</td><td>$5,524</td></tr><tr><td>Retail electric price</td><td>135</td></tr><tr><td>Asset retirement obligation</td><td>56</td></tr><tr><td>Volume/weather</td><td>36</td></tr><tr><td>MISO deferral</td><td>16</td></tr><tr><td>Net wholesale revenue</td><td>(29)</td></tr><tr><td>Other</td><td>(3)</td></tr><tr><td>2014 net revenue</td><td>$5,735</td></tr></table>

The retail electric price variance is primarily due to:

- increases in the energy efficiency rider at Entergy Arkansas, as approved by the APSC, effective July 2013 and July 2014. Energy efficiency revenues are offset by costs included in other operation and maintenance expenses and have minimal effect on net income;

- the effect of the APSC’s order in Entergy Arkansas’s 2013 rate case, including an annual base rate increase effective January 2014 offset by a MISO rider to provide customers credits in rates for transmission revenue received through MISO;

• a formula rate plan increase at Entergy Mississippi, as approved by the MSPC, effective September 2013;

- an increase in Entergy Mississippi’s storm damage rider, as approved by the MPSC, effective October 2013. The increase in the storm damage rider is offset by other operation and maintenance expenses and has no effect on net income;

- an annual base rate increase at Entergy Texas, effective April 2014, as a result of the PUCT’s order in the September 2013 rate case; and

• a formula rate plan increase at Entergy Louisiana, as approved by the LPSC, effective December 2014.

See Note 2 to the financial statements for a discussion of rate proceedings.

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 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 manufacturing sector.

The MISO deferral variance is primarily due to the deferral in 2014 of the non-fuel MISO-related charges, as approved by the LPSC and the MPSC, partially offset by 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 deferral of non-fuel MISO-related charges is partially offset in other operation and maintenance expenses. See Note 2 to the financial statements for further discussion of the recovery of non-fuel MISO-related charges.

The net wholesale variance is primarily due to a wholesale customer contract termination in December 2013 and lower margins on co-owner contracts due to contract changes.

## Entergy Wholesale Commodities

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

<table><tr><td></td><td>Amount (In Millions)</td></tr><tr><td>2013 net revenue</td><td>$1,802</td></tr><tr><td>Nuclear realized price changes</td><td>393</td></tr><tr><td>Nuclear volume</td><td>37</td></tr><tr><td>Other</td><td>(8)</td></tr><tr><td>2014 net revenue</td><td>$2,224</td></tr></table>

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

- higher realized wholesale energy prices primarily due to increases in Northeast market power prices and higher capacity prices. Entergy Wholesale Commodities’ hedging strategies routinely include financial instruments that manage operational and liquidity risk. These positions, in addition to a larger-than-normal unhedged position in 2014 due to Vermont Yankee being in its final year of operation, allowed Entergy Wholesale Commodities to benefit from increases in Northeast market power prices; and

- higher volume in its nuclear fleet resulting from approximately 90 fewer unplanned outage days in 2014 compared to 2013, partially offset by a larger exercise of resupply options in 2013 compared to 2014 provided for in purchase power agreements where Entergy Wholesale Commodities may elect to supply power from another source when the plant is not running. Amounts related to the exercise of resupply options are included in the GWh billed in the table below.

Following are key performance measures for Entergy Wholesale Commodities for 2014 and 2013.

<table><tr><td></td><td>2014</td><td>2013</td></tr><tr><td>Owned capacity (MW)</td><td>6,068</td><td>6,068</td></tr><tr><td>GWh billed</td><td>44,424</td><td>45,127</td></tr><tr><td>Average revenue per MWh</td><td>$60.84</td><td>$50.86</td></tr><tr><td>Entergy Wholesale Commodities Nuclear Fleet</td><td></td><td></td></tr><tr><td>Capacity factor</td><td>91%</td><td>89%</td></tr><tr><td>GWh billed</td><td>40,253</td><td>40,167</td></tr><tr><td>Average revenue per MWh</td><td>$60.35</td><td>$50.15</td></tr><tr><td>Refueling Outage Days:</td><td></td><td></td></tr><tr><td>FitzPatrick</td><td>44</td><td>—</td></tr><tr><td>Indian Point 2</td><td>24</td><td>—</td></tr><tr><td>Indian Point 3</td><td>—</td><td>28</td></tr><tr><td>Palisades</td><td>56</td><td>—</td></tr><tr><td>Pilgrim</td><td>—</td><td>45</td></tr><tr><td>Vermont Yankee</td><td>—</td><td>27</td></tr></table>



## Other Income Statement Items

## Utility

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

- an increase of $53 million in nuclear generation expenses primarily due to higher material costs, higher contract labor costs, and higher NRC fees;

- an increase of $38 million in administration fees related to participation in the MISO RTO beginning December 2013. The net income effect is partially offset due to deferrals of these fees in certain jurisdictions. See Note 2 to the financial statements for further information on the deferrals;

- an increase of $29 million in energy efficiency costs. These costs are recovered through energy efficiency riders and have a minimal effect on net income;

- an increase of $24 million in storm damage accruals primarily at Entergy Arkansas effective January 2014, as approved by the APSC, and at Entergy Mississippi effective October 2013, as approved by the MPSC;

• an increase of $20 million in regulatory, consulting, and legal fees;

- an increase of $19 million in contract labor primarily due to higher infrastructure and application services and call center outsourcing;

• an increase of $11 million primarily due to higher vegetation maintenance;

- an increase of $7 million due to higher write-offs of uncollectible customer accounts in 2014 as compared to 2013;

- an increase of $7 million due to the amortization in 2014 of costs deferred in 2013 related to the transition and implementation of joining the MISO RTO; and

• several individually insignificant items.

## The increase was partially offset by:

- a decrease of $146 million in compensation and benefits costs primarily due to fewer employees, an increase in the discount rates used to determine net periodic pension and other postretirement benefit costs, other postretirement benefit plan design changes, and a settlement charge recognized in September 2013 related to the payment of lump sum benefits out of the non-qualified pension plan. See “Critical Accounting Estimates” below and Note 11 to the financial statements for further discussion of benefits costs;

- a decrease of $36 million resulting from costs incurred in 2013 related to the now-terminated plan to spin off and merge the Utility’s transmission business;

- a decrease of $9 million resulting from costs incurred in 2013 related to the generator stator incident at ANO, including an offset for insurance proceeds. See “ANO Damage, Outage, and NRC Reviews” below for further discussion of the incident;

- a net decrease of $8 million related to the human capital management strategic imperative in 2014 as compared to 2013 including a decrease of $60 million in implementation costs, severance costs, and curtailment and special termination benefits, the deferral in 2013 of $44 million of costs incurred, as approved by the APSC and LPSC, and partial amortization in 2014 of $8 million of costs that were deferred in 2013. See “Human Capital Management Strategic Imperative” below for further discussion; and

- a net decrease of $4 million related to Baxter Wilson (Unit 1) repairs. The increase in repair costs incurred in 2014 compared to the prior year were offset by expected insurance proceeds and the deferral of repair costs, as approved by the MPSC. See “Baxter Wilson Plant Event” in Note 8 to the financial statements for further discussion.

The asset write-offs, impairment, and related charges variance is due to the $56.2 million ($36.7 million net-of-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 net-of-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 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.

## Entergy Wholesale Commodities

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

- a decrease of $63 million in compensation and benefits costs primarily due to fewer employees, an increase in the discount rates used to determine net periodic pension and other postretirement benefit costs, other postretirement benefit plan design changes, and a settlement charge recognized in September 2013 related to the payment of lump sum benefits out of the non-qualified pension plan. See “Critical Accounting Estimates” below and Note 11 to the financial statements for further discussion of benefits costs;

- a decrease of $15 million due to the absence of expenses from Entergy Solutions District Energy, which was sold in November 2013; and

- a decrease of $13 million in implementation costs, severance costs, and curtailment and special termination benefits related to the human capital management strategic imperative in 2014 as compared to 2013. See “Human Capital Management Strategic Imperative” below for further discussion.

The decrease was partially offset by:

- an increase of $22 million incurred in 2014 as compared to 2013 related to the shutdown of Vermont Yankee including severance and retention costs. See “Impairment of Long-Lived Assets” in Note 1 to the financial statements for discussion regarding the shutdown of the Vermont Yankee plant in December 2014;

• an increase of $18 million primarily due to higher contract costs and higher NRC fees; and

• $18 million in transmission imbalance sales in 2013.

The asset write-offs, impairments, and related charges variance is primarily due to $321.5 million ($202.2 million net-of-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 net-of-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.

## Income Taxes

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 IRS settlements as discussed further in Note 3 to the financial statements and 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.

## Entergy Wholesale Commodities Authorizations to Operate Its Nuclear Power Plants

The NRC operating license for Palisades expires in 2031, for Pilgrim expires in 2032, and for FitzPatrick expires in 2034. For additional discussion regarding the shutdown of the Vermont Yankee plant in December 2014 and the planned shutdown of the FitzPatrick and Pilgrim plants, see “Impairment of Long-Lived Assets” in Note 1 to the financial statements.

## Indian Point NRC/ASLB Proceedings

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 dates of the NRC operating licenses for Indian Point 2 and Indian Point 3 were in September 2013 and December 2015, respectively. Authorization to operate Indian Point 2 and Indian Point 3 rests on Entergy’s having timely filed a license renewal application that remains pending before the NRC. Each of Indian Point 2 and Indian Point 3 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 license renewal application for Indian Point 2 and Indian Point 3 qualifies for timely renewal protection because it met NRC regulatory standards for timely filing.

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 governmental and private intervenors have 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 originally proposed by the State of New York or other parties.

Four of the 16 admitted contentions have been resolved by the ASLB without hearing, two by means of ASLB-approved settlements, a third by summary disposition as described below, and a fourth by motion to dismiss as moot as described 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 FSEIS as 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. Entergy renewed its appeal in February 2014 in conjunction with the filing of 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 motion for clarification that a future NRC staff filing would be the trigger for potential new or amended contentions on the SAMA update.

Nine of the remaining 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. No appeal was taken from the ASLB’s decision on six of those eight contentions, so they have been conclusively resolved in Entergy’s favor. The ASLB resolved one Track 1 contention favorably to New York State. That contention was based on a dispute over the characterization of certain electrical equipment as “active” or “passive.” The ASLB found in favor of the State of New York despite precedent supporting the characterization advocated by Entergy and NRC staff.

Following the ASLB’s November 2013 decision on Track 1 contentions, the State of New York and Clearwater each appealed the decision on a single contention (SAMA decontamination 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 decision on electrical transformers; (2) certain intermediate determinations in the ASLB’s overall favorable decision on environmental justice; and (3) the 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 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 would be resolved in the future.

In March 2015 the NRC resolved the remaining appeals from the ASLB’s Track 1 decisions in favor of Entergy and the NRC staff. Those appeals addressed electrical transformers and environmental justice. All filings in response to the NRC’s request for additional information on SAMA issues raised by the pending two SAMA-related appeals have been completed. There is no deadline for the NRC to act on the SAMA-related appeals.

The remaining four admitted consolidated contentions were designated by the ASLB as “Track 2.” 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 11 of the original 16 admitted consolidated contentions that have been resolved favorably (or in the case of settlement, acceptably) to Entergy. Five of the original 16 admitted consolidated contentions are on appeal (two total) or pending ASLB decision on Track 2 (three total).

Track 2 hearings on the three remaining Track 2 contentions, all of which relate to safety, were conducted by the ASLB in November 2015. The ASLB has scheduled the submission of proposed findings of fact and conclusions of law and a reply to other parties’ proposed findings and conclusions through late-March 2016. There is no deadline for the ASLB to issue a decision on Track 2 contentions. The disappointed party may appeal to the NRC and, ultimately, to the federal courts.

Independent of the ASLB process, the NRC staff has performed its technical and environmental reviews of the Indian Point 2 and Indian Point 3 license renewal application. The NRC staff issued an FSER in August 2009, a supplement to the FSER in August 2011, an FSEIS in December 2010, a supplement to the FSEIS in June 2013, and, as noted above, a further supplement to the FSER in November 2014. In November 2014 the NRC staff advised of its proposed schedule for issuance of a further FSEIS supplement to address new information received by NRC staff since preparation and publication of the previous FSEIS supplement in June 2013. 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 NRC’s Continued Storage Of Spent Nuclear Fuel rule, which was published in the Federal Register in September 2014. The NRC staff issued a draft of the new FSEIS supplement in December 2015. Under the updated schedule, the new final FSEIS supplement is expected to be issued in September 2016.

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 applications. See “Nuclear Matters” below for discussion of spent nuclear fuel storage issues and their potential effect on the timing of license renewals.



## Indian Point NYSDEC Water Quality Certification Proceedings

The New York State Department of Environmental Conservation (NYSDEC) has taken the position that Indian Point must obtain a new state-issued Clean Water Act Section 401 water quality certification as part of the license renewal process. Entergy submitted its application for a water quality certification to NYSDEC in April 2009, with a reservation of rights regarding the applicability of Section 401 in this case. After Entergy submitted certain additional information in response to NYSDEC requests for additional information, in February 2010 the NYSDEC staff determined that Entergy’s water quality certification application was complete. In April 2010 the NYSDEC staff issued a proposed notice of denial of Entergy’s water quality certification application (the Notice). NYSDEC staff’s Notice triggered an administrative adjudicatory hearing before NYSDEC ALJs on the proposed Notice. The NYSDEC staff decision does not restrict Indian Point operations, but the issuance of a certification is potentially required prior to NRC issuance of renewed unit licenses. In June 2011, Entergy filed notice with the NRC that NYSDEC, the agency that would issue or deny a water quality certification for the Indian Point license renewal process, had taken longer than one year to take final action on Entergy’s application for a water quality certification and, therefore, had waived its opportunity to require a certification under the provisions of Section 401 of the Clean Water Act. The NYSDEC has notified the NRC that it disagrees with Entergy’s position and does not believe that it has waived the right to require a certification. The NYSDEC ALJs overseeing the agency’s certification adjudicatory process stated in a ruling issued in July 2011 that while the waiver issue is pending before the NRC, the NYSDEC hearing process will continue on selected issues. The ALJs held a Legislative Hearing (agency public comment session) and an Issues Conference (pre-trial conference) in July 2010 and set certain issues for trial in October 2011. In 2014, hearings were held on NYSDEC’s proposed best technology available, closed cycle cooling. The NYSDEC staff also has proposed annual fish protection outages of 42, 62, or 92 days at both units or at one unit with closed cycle cooling at the other. The ALJs held a further legislative hearing and issues conference on this NYSDEC staff proposal in July 2014. In January 2015, Entergy wrote NYSDEC leadership requesting an explanation of the delay in release of the ruling following an ALJ’s on-record statement that the ALJ’s draft ruling was under “executive review.” In February 2015 the ALJs issued a ruling scheduling hearings on the outage proposals and other pending issues. In March 2015 the NYSDEC staff withdrew from consideration at trial before the ALJs its proposal for annual fish protection outages of 92 days. The NYSDEC staff and Riverkeeper continue to advance other annual outage proposals. The NYSDEC staff also withdrew from further consideration a $24 million annual interim payment that had been proposed as a condition of the draft water pollution control permit. Hearings on the outages proposal were held in September 2015, and post-hearing briefing on both the closed cycle cooling proposal and the outages proposal has been scheduled for May and July 2016.

The ALJs have issued no partial decisions on the several issues that have been the subject of hearing during the past four years and have not announced a schedule for doing so. After the completion of hearings on the merits, the ALJs will issue a recommended decision to the NYSDEC Commissioner’s designated delegate who will then issue the final agency decision. A party to the proceeding can appeal the final agency decision to state court.

## Indian Point Coastal Zone Management Act Proceedings

In addition, before the NRC may issue renewed operating licenses it must resolve its obligation to address the requirements of the Coastal Zone Management Act (CZMA). Most commonly, those requirements are met by the applicant’s demonstration that the activity authorized by the federal permit being sought is consistent with the host state’s federally-approved coastal management policies. Entergy has undertaken three independent initiatives to resolve CZMA issues: “grandfathering;” “previous review;” and a “consistency certification.”

First, Entergy filed with the New York State Department of State (NYSDOS) in November 2012 a petition for declaratory order that Indian Point is grandfathered under either of two criteria prescribed by the New York Coastal Management Program (NYCMP), which sets forth the state coastal policies applied in a CZMA consistency review. NYSDOS denied the motion by order dated January 2013. Entergy filed a petition for judicial review of NYSDOS’s decision with the New York State Supreme Court for Albany County in March 2013. The court denied Entergy’s appeal in December 2013. Entergy initiated an appeal to the Appellate Division of the New York State Supreme Court in January 2014. In December 2014 a five-judge panel of that court unanimously held that Indian Point is exempt from



CZMA consistency review by NYSDOS because it meets one of the two criteria for grandfathering established in the NYCMP. The court did not address the second criterion. Appeal to New York State’s highest court, the State Court of Appeals, was granted in June 2015 upon NYSDOS’s motion. Oral argument has not been scheduled.

Second, in July 2012, Entergy filed a supplement to the Indian Point license renewal applications currently pending before the NRC. The supplement states that, based on applicable federal law and in light of prior reviews by the State of New York, the NRC may issue the requested renewed operating licenses for Indian Point without the need for an additional consistency review by the State of New York under the CZMA. In July 2012, Entergy filed a motion for declaratory order with the ASLB seeking confirmation of its position that no further CZMA consistency determination is required before the NRC may issue renewed licenses. In April 2013 the State of New York and Riverkeeper filed answers opposing Entergy’s motion. The State of New York also filed a cross-motion for declaratory order seeking confirmation that Indian Point had not been previously reviewed, and that only NYSDOS could conduct a CZMA review for NRC license renewal purposes. In April 2013 the NRC Staff filed answers recommending the ASLB deny both Entergy’s and the State of New York’s motions for declaratory order. In June 2013 the ASLB denied Entergy’s and the State of New York’s motions, without prejudice, on the ground that consultation on the matter of previous review among the NRC, Entergy (as applicant), and the State of New York had not taken place, as the ASLB determined to be required. In December 2013, NRC staff initiated consultation under federal CZMA regulations by serving on NYSDOS written questions related to whether Indian Point had been previously reviewed. In May 2014 the NYSDOS responded to questions the NRC staff submitted in December 2013. In July 2014, Entergy submitted comments on NYSDOS’s responses and NYSDOS filed a reply to those comments. Further submissions to the NRC staff with respect to the previous review issue were made by Entergy in November 2014 and by NYSDOS in December 2014. The NRC staff advised the ASLB in February 2015 that it is reviewing the information it has received regarding previous review and will provide further information when available.

Third, in December 2012, Entergy filed with NYSDOS a consistency determination explaining why Indian Point satisfies all applicable NYCMP policies while noting that Entergy did not concede NYSDOS’s right to conduct a new CZMA review for Indian Point. In January 2013, NYSDOS notified Entergy that it deemed the consistency determination incomplete because it did not include the final version of a further supplement to the FSEIS that was targeted for subsequent issuance by NRC staff. In June 2013, NYSDOS notified Entergy that NYSDOS had received a copy of the final version of the FSEIS on June 20, 2013, and that NYSDOS’s review of the Indian Point consistency determination had begun that date. By a series of agreements, Entergy and NYSDOS agreed to extend NYSDOS’s deadline for concurring with or objecting to the Indian Point consistency certification to December 31, 2014. In November 2014, Entergy filed with the NRC and with NYSDOS a notice withdrawing the consistency certification. Entergy cited the NRC staff’s announcement two days earlier of its intent to issue in March 2016 a new FSEIS supplement addressing, among other things, new information concerning aquatic impacts. Entergy stated that unless the previous review or grandfathering issues were first and finally resolved in Entergy’s favor, Entergy intended to file a new consistency certification after the NRC issues the FSEIS supplement. That new consistency certification would initiate NYSDOS’s review process, would allow the FSEIS supplement to also be part of the record before NYSDOS, and, were NYSDOS to object to the new certification, would also be part of the record before the U.S. Secretary of Commerce on appeal.

NYSDOS disputed the effectiveness of Entergy’s November 2014 notice withdrawing the consistency certification. In December 2014, Entergy and NYSDOS executed 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 of NYSDOS’s deadline for decision on the 2012 consistency certification to June 30, 2015. That agreement was extended several times; upon expiration of the last extension, NYSDOS issued an objection on November 6, 2015. On November 10, 2015, Entergy filed with the National Oceanographic and Atmospheric Administration (NOAA), the agency within the U.S. Department of Commerce that has been delegated authority to act on CZMA appeals, a motion requesting a determination that Entergy’s November 2014 withdrawal notice was effective, and the objection therefore invalid, or, alternatively, an extension of the deadline for Entergy to file a notice of appeal and the consolidated record of proceedings which by law must be assembled by the federal licensing agency, here the NRC. On November 25, 2015, after receiving papers in



opposition from NYSDOS, NOAA issued a letter (1) deferring until after the New York Court of Appeals ruled on grandfathering the determination whether Entergy’s withdrawal notice was effective, and (2) extending until that time Entergy’s deadline for filing a notice of appeal and the consolidated record. In January 2016, Entergy filed suit in the U.S. District Court for the Northern District of New York challenging NYSDOS’s November 6, 2015 CZMA objection on federal preemption grounds. Entergy’s complaint requests a determination that the objection, which cites nuclear safety concerns, is preempted and thus invalid.

## ANO Damage, Outage, and NRC Reviews

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 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. In February 2014 the APSC approved Entergy Arkansas’s request to exclude from the calculation of its revised energy cost rate $65.9 million of deferred fuel and purchased 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 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 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. In July 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 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 NRC issued an inspection report on the 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 determined that the performance at ANO was 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 the NRC’s findings have been taken and remain ongoing at ANO.



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 substantial safety significance” for the 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 in October 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 “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 report. The NRC’s final risk significance determination was classified as “yellow with substantial safety significance.”

In March 2015 the NRC issued a letter notifying Entergy of its decision to move ANO into the “multiple/repetitive degraded cornerstone column” (Column 4) of the NRC’s Reactor Oversight Process Action Matrix. Placement into Column 4 requires 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. Entergy Arkansas incurred incremental costs of approximately $53 million in 2015 to prepare for the NRC inspection that began in early 2016. Excluding remediation and response costs that may result from the additional NRC inspection activities, Entergy Arkansas also expects to incur approximately $50 million in 2016 in support of NRC inspection activities and to implement Entergy Arkansas’s performance improvement initiatives developed in 2015. A much lesser amount of incremental expenses is expected to be ongoing annually after 2016.

## Entergy Louisiana and Entergy Gulf States Louisiana Business Combination

Entergy Louisiana and Entergy Gulf States Louisiana filed an application with the LPSC in September 2014 seeking authorization to undertake the transactions that would result in the combination of Entergy Louisiana and Entergy Gulf States Louisiana into a single public utility. In the application, Entergy Louisiana and Entergy Gulf States Louisiana identified potential benefits, including enhanced economic and customer diversity, enhanced geographic and supply diversity, and greater administrative efficiency. In the initial proceedings with the LPSC, Entergy Louisiana and Entergy Gulf States Louisiana estimated that the business combination could produce up to $128 million in measurable customer benefits during the first ten years following the transaction’s close including proposed guaranteed customer credits of $97 million in the first nine years. In April 2015 the LPSC staff and intervenors filed testimony in the LPSC business combination proceeding. The testimony recommended an extensive set of conditions that would be required in order to recommend that the LPSC find that the business combination was in the public interest. The LPSC staff’s primary concern appeared to be potential shifting in fuel costs between Entergy Louisiana and Entergy Gulf States Louisiana customers. In May 2015, Entergy Louisiana and Entergy Gulf States Louisiana filed rebuttal testimony. After the testimony was filed with the LPSC, the parties engaged in settlement discussions that ultimately led to the execution of an uncontested stipulated settlement (“stipulated settlement”), which was filed with the LPSC in July 2015. Through the stipulated settlement, the parties agreed to terms upon which to recommend that the LPSC find that the business combination was in the public interest. The stipulated settlement, which was either joined, or unopposed, by all parties to the LPSC proceeding, represents a compromise of stakeholder positions and was the result of an extensive period of analysis, discovery, and negotiation. The stipulated settlement provides $107 million in guaranteed customer benefits during the first nine years following the transaction’s close. Additionally, the combined company will honor the 2013 Entergy Louisiana and Entergy Gulf States Louisiana rate case settlements, including the commitments that (1) there will be no rate increase for legacy Entergy Gulf States Louisiana customers for the 2014 test year, and (2) through the 2016 test year formula rate plan, Entergy Louisiana (as a combined entity) will not raise rates by more than $30 million, net of the $10 million rate increase included in the Entergy Louisiana legacy formula rate plan. The stipulated settlement also describes the process for implementing a fuel-tracking mechanism that is designed to address potential effects arising from the shifting of fuel costs between legacy Entergy Louisiana and legacy Entergy Gulf States Louisiana customers as a result of the combination of those companies’ fuel adjustment clauses. Specifically, the fuel



tracker would reallocate such cost shifts as between legacy customers of the companies on an after-the-fact basis, and the calculation of the fuel tracker will be submitted annually in a compliance filing. The stipulated settlement also provides that Entergy Gulf States Louisiana and Entergy Louisiana are permitted to defer certain external costs that were incurred to achieve the business combination’s customer benefits. The deferred amount, which shall not exceed $25 million, will be subject to a prudence review and amortized over a 10-year period. In 2015 deferrals of $16 million for these external costs were recorded. A hearing on the stipulated settlement in the LPSC proceeding was held in July 2015. In August 2015 the LPSC approved the business combination.

In April 2015 the FERC approved applications requesting authorization for the business combination. In August 2015 the NRC approved the applications for the River Bend and Waterford 3 license transfers as part of the steps to complete the business combination.

On October 1, 2015, the businesses formerly conducted by Entergy Louisiana and Entergy Gulf States Louisiana were combined into a single public utility. With the completion of the business combination, Entergy Louisiana holds substantially all of the assets, and has assumed the liabilities, of Entergy Louisiana and Entergy Gulf States Louisiana. The effect of the business combination has been retrospectively applied to Entergy Louisiana’s financial statements that are presented in this report. See Note 2 to the financial statements for further discussion of the business combination and related customer credits.

## Human Capital Management Strategic Imperative

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.

## Liquidity and Capital Resources

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

## Capital Structure

Entergy’s capitalization is balanced between equity and debt, as shown in the following table. The increase in the debt to capital ratio for Entergy as of December 31, 2015 is primarily due to a decrease in retained earnings.

<table><tr><td></td><td>2015</td><td>2014</td></tr><tr><td>Debt to capital</td><td>59.1%</td><td>57.4%</td></tr><tr><td>Effect of excluding securitization bonds</td><td>(1.4%)</td><td>(1.4%)</td></tr><tr><td>Debt to capital, excluding securitization bonds (a)</td><td>57.7%</td><td>56.0%</td></tr><tr><td>Effect of subtracting cash</td><td>(2.7%)</td><td>(2.8%)</td></tr><tr><td>Net debt to net capital, excluding securitization bonds (a)</td><td>55.0%</td><td>53.2%</td></tr></table>

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



Net debt consists of debt less cash and cash equivalents. Debt consists of notes payable and commercial paper, capital lease obligations, and long-term debt, including the currently maturing portion. Capital consists of debt, common shareholders' equity, and subsidiaries' preferred stock without sinking fund. Net capital consists of capital less cash and cash equivalents. Entergy uses the debt to capital ratios excluding securitization bonds in analyzing its financial condition and believes they provide useful information to its investors and creditors in evaluating Entergy's financial condition because the securitization bonds are non-recourse to Entergy, as more fully described in Note 5 to the financial statements. Entergy also uses the net debt to net capital ratio excluding securitization bonds in analyzing its financial condition and believes it provides useful information to its investors and creditors in evaluating Entergy's financial condition because net debt indicates Entergy's outstanding debt position that could not be readily satisfied by cash and cash equivalents on hand.

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, 2015. To estimate future interest payments for variable rate debt, Entergy used the rate as of December 31, 2015. 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.

<table><tr><td>Long-term debt maturities and estimated interest payments</td><td>2016</td><td>2017</td><td>2018</td><td>2019-2020</td><td>after 2020</td></tr><tr><td></td><td colspan="5">(In Millions)</td></tr><tr><td>Utility</td><td>$743</td><td>$890</td><td>$1,308</td><td>$1,978</td><td>$13,410</td></tr><tr><td>Entergy Wholesale Commodities</td><td>3</td><td>2</td><td>13</td><td>2</td><td>26</td></tr><tr><td>Parent and Other</td><td>89</td><td>566</td><td>66</td><td>1,403</td><td>690</td></tr><tr><td>Total</td><td>$835</td><td>$1,458</td><td>$1,387</td><td>$3,383</td><td>$14,126</td></tr></table>

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

Entergy Corporation has in place a credit facility that has a borrowing capacity of $3.5 billion and expires in August 2020. 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, 2015 was 1.98% on the drawn portion of the facility.

As of December 31, 2015, amounts outstanding and capacity available under the $3.5 billion credit facility are:

<table><tr><td>Capacity (a)</td><td>Borrowings</td><td>Letters of Credit</td><td>Capacity Available</td></tr><tr><td>$3,500</td><td>$835</td><td>$9</td><td>$2,656</td></tr></table>

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

Entergy Corporation has a commercial paper program with a Board-approved program limit of up to $1.5 billion. At December 31, 2015, Entergy Corporation had $422 million of commercial paper outstanding. The weighted-average interest rate for the year ended December 31, 2015 was 0.90%.



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

<table><tr><td></td><td>2016</td><td>2017</td><td>2018</td><td>2019-2020</td><td>after 2020</td></tr><tr><td></td><td></td><td></td><td>(In Millions)</td><td></td><td></td></tr><tr><td>Capital lease payments</td><td>$5</td><td>$4</td><td>$4</td><td>$6</td><td>$25</td></tr></table>

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

Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas each had credit facilities available as of December 31, 2015 as follows:

<table><tr><td rowspan="2">Company</td><td rowspan="2">Expiration Date</td><td rowspan="2">Amount of Facility</td><td rowspan="2">Interest Rate (a)</td><td colspan="2">Amount Drawn as of December 31, 2015</td><td rowspan="2">Letters of Credit Outstanding as of December 31, 2015</td></tr><tr><td></td><td></td></tr><tr><td>Entergy Arkansas</td><td>April 2016</td><td>$20 million (b)</td><td>1.92%</td><td>—</td><td>—</td><td></td></tr><tr><td>Entergy Arkansas</td><td>August 2020</td><td>$150 million (c)</td><td>1.92%</td><td>—</td><td>—</td><td></td></tr><tr><td>Entergy Louisiana</td><td>August 2020</td><td>$350 million (d)</td><td>1.67%</td><td>—</td><td>$3.1 million</td><td></td></tr><tr><td>Entergy Mississippi</td><td>May 2016</td><td>$10 million (e)</td><td>1.92%</td><td>—</td><td>—</td><td></td></tr><tr><td>Entergy Mississippi</td><td>May 2016</td><td>$20 million (e)</td><td>1.92%</td><td>—</td><td>—</td><td></td></tr><tr><td>Entergy Mississippi</td><td>May 2016</td><td>$35 million (e)</td><td>1.92%</td><td>—</td><td>—</td><td></td></tr><tr><td>Entergy Mississippi</td><td>May 2016</td><td>$37.5 million (e)</td><td>1.92%</td><td>—</td><td>—</td><td></td></tr><tr><td>Entergy New Orleans</td><td>November 2018</td><td>$25 million</td><td>2.17%</td><td>—</td><td>—</td><td></td></tr><tr><td>Entergy Texas</td><td>August 2020</td><td>$150 million (f)</td><td>1.92%</td><td>—</td><td>$1.3 million</td><td></td></tr></table>

(a) The interest rate is the rate as of December 31, 2015 that would be applied to outstanding borrowings under the facility.

(b) Borrowings under this Entergy Arkansas credit facility may be secured by a security interest in its accounts 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.

(d) The credit facility allows Entergy Louisiana to issue letters of credit against 50% of the borrowing capacity of the facility.

(e) Borrowings under the Entergy Mississippi credit facilities may be secured by a security interest in its accounts receivable at Entergy Mississippi’s option.

(f) The credit facility allows Entergy Texas to issue letters of credit against 50% of the borrowing capacity of the facility.

Each of the credit facilities 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 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, 2015:

<table><tr><td>Company</td><td>Amount of Uncommitted Facility</td><td>Letter of Credit Fee</td><td>Letters of Credit Issued as of December 31, 2015</td></tr><tr><td>Entergy Arkansas</td><td>$25 million</td><td>0.70%</td><td>$1.0 million</td></tr><tr><td>Entergy Louisiana</td><td>$125 million</td><td>0.70%</td><td>$17.1 million</td></tr><tr><td>Entergy Mississippi</td><td>$40 million</td><td>0.70%</td><td>$6.0 million</td></tr><tr><td>Entergy New Orleans</td><td>$15 million</td><td>0.75%</td><td>$1.4 million</td></tr><tr><td>Entergy Texas</td><td>$50 million</td><td>0.70%</td><td>$9.4 million</td></tr></table>

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.

Operating Lease Obligations and Guarantees of Unconsolidated Obligations

Entergy has a minimal amount of operating lease obligations and guarantees in support of unconsolidated obligations. Entergy’s guarantees in support of unconsolidated obligations are not likely to have a material effect on Entergy’s financial condition, results of operations, or cash flows. Following are Entergy’s payment obligations as of December 31, 2015 on non-cancelable operating leases with a term over one year:

<table><tr><td></td><td>2016</td><td>2017</td><td>2018</td><td>2019-2020</td><td>after 2020</td></tr><tr><td></td><td></td><td></td><td>(In Millions)</td><td></td><td></td></tr><tr><td>Operating lease payments</td><td>$78</td><td>$64</td><td>$53</td><td>$84</td><td>$80</td></tr></table>

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

Summary of Contractual Obligations of Consolidated Entities

<table><tr><td>Contractual Obligations</td><td>2016</td><td>2017-2018</td><td>2019-2020</td><td>after 2020</td><td>Total</td></tr><tr><td></td><td></td><td></td><td>(In Millions)</td><td></td><td></td></tr><tr><td>Long-term debt (a)</td><td>$835</td><td>$2,845</td><td>$3,383</td><td>$14,126</td><td>$21,189</td></tr><tr><td>Capital lease payments (b)</td><td>$5</td><td>$8</td><td>$6</td><td>$25</td><td>$44</td></tr><tr><td>Operating leases (b) (c)</td><td>$78</td><td>$117</td><td>$84</td><td>$80</td><td>$359</td></tr><tr><td>Purchase obligations (d)</td><td>$1,584</td><td>$2,684</td><td>$1,803</td><td>$4,165</td><td>$10,236</td></tr></table>

(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.



In addition to the contractual obligations given above, Entergy currently expects to contribute approximately $387.5 million to its pension plans and approximately $52.8 million to other postretirement plans in 2016, although the 2016 required pension contributions will be known with more certainty when the January 1, 2016 valuations are completed, which is expected by April 1, 2016. See “Critical Accounting Estimates - Qualified Pension and Other Postretirement Benefits” below for a discussion of qualified pension and other postretirement benefits funding.

Also in addition to the contractual obligations, Entergy has $1,347 million of unrecognized tax benefits and interest net of unused tax attributes for which the timing of payments beyond 12 months cannot be reasonably estimated due to uncertainties in the timing of effective settlement of tax positions. See Note 3 to the financial statements for additional information regarding unrecognized tax benefits.

## Capital Funds Agreement

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

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

• permit the continued commercial operation of Grand Gulf;

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

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

## Capital Expenditure Plans and Other Uses of Capital

Following are the amounts of Entergy’s planned construction and other capital investments by operating segment for 2016 through 2018.

<table><tr><td rowspan="2">Planned construction and capital investments</td><td>2016</td><td>2017</td><td>2018</td></tr><tr><td colspan="3">(In Millions)</td></tr><tr><td>Utility:</td><td></td><td></td><td></td></tr><tr><td>Generation</td><td>$1,790</td><td>$1,155</td><td>$1,380</td></tr><tr><td>Transmission</td><td>715</td><td>850</td><td>725</td></tr><tr><td>Distribution</td><td>775</td><td>810</td><td>755</td></tr><tr><td>Other</td><td>270</td><td>200</td><td>185</td></tr><tr><td>Total</td><td>3,550</td><td>3,015</td><td>3,045</td></tr><tr><td>Entergy Wholesale Commodities</td><td>260</td><td>235</td><td>215</td></tr><tr><td>Total</td><td>$3,810</td><td>$3,250</td><td>$3,260</td></tr></table>

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:

- Potential resource planning investments, including the Union Power Station acquisition discussed below, and potential construction of additional generation.

- Entergy Wholesale Commodities investments associated with specific investments such as component replacements, software and security, dry cask storage, and nuclear license renewal.

• NRC post-Fukushima requirements for the Utility and Entergy Wholesale Commodities nuclear fleets.



• Transmission spending to enhance reliability, reduce congestion, and enable economic growth.

- Distribution spending to maintain reliability and improve service to customers, including initial investment to support smart meter deployment.

For the next several years, the Utility’s owned generating capacity is projected to be adequate to meet MISO reserve requirements; however, in the longer-term additional supply resources will be needed, and its supply plan initiative will continue to seek to transform its generation portfolio with new generation resources. Opportunities resulting from the supply plan initiative, including new projects or the exploration of alternative financing sources, could result in increases or decreases in the capital expenditure estimates given above. Estimated capital expenditures are also subject to periodic review and modification and may vary based on the ongoing effects of business restructuring, regulatory constraints and requirements, environmental regulations, business opportunities, market volatility, economic trends, changes in project plans, and the ability to access capital.

## St. Charles Power Station

In August 2015, Entergy Louisiana filed with the LPSC an application seeking certification that the public necessity and convenience would be served by the construction of the St. Charles Power Station, a nominal 980 megawatt combined-cycle generating unit, on land adjacent to the existing Little Gypsy plant in St. Charles Parish, Louisiana. Discovery has begun in the proceeding. Testimony has been filed by LPSC staff and intervenors, with LPSC staff concluding that the construction of the project serves the public convenience and necessity. Three intervenors contend that Entergy Louisiana has not established that construction of the project is in the public interest, claiming that the RFP excluded consideration of certain resources that could be more cost effective, that the RFP provided undue preference to the self-build option, and that a 30-year capacity commitment is not warranted by current supply conditions. The RFP independent monitor also filed testimony and a report affirming that the St. Charles Power Station was selected through an objective and fair RFP that showed no undue preference to any proposal. An evidentiary hearing is scheduled for April 2016 and, subject to regulatory approval by the LPSC, full notice to proceed is expected to be issued in Summer 2016. Commercial operation is estimated to occur by Summer 2019.

## Union Power Station Purchase Agreement

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 would 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 would each acquire one power block and a 25% undivided ownership interest in such related assets. The base purchase price is expected to be approximately $948 million (approximately $237 million for each power block) subject to adjustments. The purchase is contingent upon, among other things, obtaining necessary approvals, including cost recovery, from various federal and state regulatory and permitting agencies. Under the original terms of the asset purchase agreement, these included regulatory approvals from the APSC, LPSC, PUCT, and FERC, as well as clearance under the Hart-Scott-Rodino antitrust law.

In December 2014, Entergy Texas filed its application for Certificate of Convenience and Necessity (CCN) with the PUCT seeking one of the two necessary PUCT approvals of the acquisition. Based on the opposition to the acquisition of the power block, Entergy Texas determined it was appropriate to seek to dismiss the CCN filing. In July 2015, Entergy Texas withdrew its rate case and, together with other parties, filed a motion with the PUCT to dismiss Entergy Texas's CCN application. In July 2015, the PUCT granted the motion to dismiss the CCN case. The power block originally allocated to Entergy Texas will be acquired by Entergy New Orleans. The acquisition by Entergy New Orleans replaces the power purchase agreement with Entergy Gulf States Louisiana that the City Council approved in June 2015. In August 2015, Entergy New Orleans filed an application with the City Council seeking authorization to proceed with the acquisition of the power block and seeking approval of the recovery of the associated costs. In November 2015 the City Council issued written resolutions and an order approving an agreement in principle between



Entergy New Orleans and City Council advisors providing that the purchase of Power Block 1 and related assets by Entergy New Orleans is prudent and in the public interest.

In January 2015, Entergy Gulf States Louisiana filed its application with the LPSC for approval of the acquisition and cost recovery. Supplemental testimony was submitted in July 2015 explaining the reallocation of one of the power blocks to Entergy New Orleans and clarifying that Entergy Gulf States Louisiana would own 100% of the capacity and associated energy of two power blocks. In September 2015, Entergy Gulf States Louisiana agreed to settlement terms with all parties for Entergy Gulf States Louisiana’s purchase of the two power blocks. In October 2015 the LPSC voted unanimously to approve the uncontested settlement which finds, among other things, that acquisition of Power Blocks 3 and 4 is in the public interest and, therefore, prudent. The business combination of Entergy Gulf States Louisiana and Entergy Louisiana received regulatory approval and closed in October 2015 making Entergy Louisiana the named purchaser of Power Blocks 3 and 4 of the Union Power Station.

In January 2015, Entergy Arkansas filed its application with the APSC for approval of the acquisition and cost recovery. A hearing was held in September 2015. In November 2015 the APSC issued an order conditionally approving the acquisition and requesting that Entergy Arkansas file compliance testimony reporting on two minor conditions. In January 2016 the APSC issued an order finding that Entergy Arkansas’s December 2015 compliance filing was substantially compliant with its November 2015 order. If the transaction closes on or before March 24, 2016, recovery of the costs to acquire Power Block 2 of the Union Power Station will be through Entergy Arkansas’s new base rates that will commence with the first billing cycle of April 2016. If the transaction closes after that date, the parties have agreed to concurrent cost recovery through Entergy Arkansas’s capacity acquisition rider.

In February 2015, Entergy Arkansas, Entergy Gulf States Louisiana, and Entergy Texas filed a notification and report form pursuant to the Hart-Scott-Rodino Antitrust Improvements Act with the United States Department of Justice (DOJ) and Federal Trade Commission with respect to their planned acquisition of the Union Power Station. Union Power Partners, L.P. (UPP), the seller, also filed a notification and report form in February 2015.

In March 2015 the DOJ requested additional information and documentary material from each of the purchasing companies and UPP. Also in March 2015, UPP, Entergy Arkansas, Entergy Gulf States Louisiana, and Entergy Texas filed an application with the FERC requesting authorization for the transaction. In April 2015, Entergy Arkansas, Entergy Gulf States Louisiana, and Entergy Texas made a filing with the FERC for approval of their proposed accounting treatment of the amortization expenses relating to the acquisition adjustment. Filings were made with the FERC in September 2015 replacing Entergy Texas with Entergy New Orleans as an applicant in the filings and providing supplemental information. In the FERC proceeding requesting authorization for the transaction, in December 2015, UPP, Entergy Arkansas, Entergy Louisiana, as successor in interest to Entergy Gulf States Louisiana, and Entergy New Orleans filed their response to the FERC’s November 2015 request for additional information. The public comment period on the December 2015 filing expired in January 2016. No protests were filed. The LPSC, City Council, and APSC have filed submissions with the FERC urging the FERC to promptly consider and approve the transaction.

Closing of the purchase is expected to be completed promptly following the receipt of FERC approval.

## Dividends and Stock Repurchases

Declarations of dividends on Entergy’s common stock are made at the discretion of the Board. Among other things, the Board evaluates the level of Entergy’s common stock dividends based upon earnings per share from the Utility operating segment and the Parent and Other portion of the business, financial strength, and future investment opportunities. At its January 2016 meeting, the Board declared a dividend of $0.85 per share. Entergy paid $599 million in 2015, $596 million in 2014, and $593 million in 2013 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 stock 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, 2015, $350 million of authority remains under the $500 million share repurchase program. The amount of repurchases may vary as a result of material changes in business results or capital spending or new investment opportunities, or if limitations in the credit markets continue for a prolonged period.

## Sources of Capital

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

• internally generated funds;

• cash on hand ($1,351 million as of December 31, 2015);

• securities issuances;

• bank financing under new or existing facilities or commercial paper; and

• sales of assets.

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

Provisions within the Articles of Incorporation or pertinent indentures and various other agreements relating to the long-term debt and preferred stock of certain of Entergy Corporation’s subsidiaries could restrict the payment of cash dividends or other distributions on their common and preferred stock. As of December 31, 2015, under provisions in their mortgage indentures, Entergy Arkansas and Entergy Mississippi had restricted retained earnings unavailable for distribution to Entergy Corporation of $394.9 million and $68.5 million, respectively. All debt and common and preferred equity issuances by the Registrant Subsidiaries require prior regulatory approval and their preferred equity and debt issuances are also subject to issuance tests set forth in corporate charters, bond indentures, and other agreements. Entergy believes that the Registrant Subsidiaries have sufficient capacity under these tests to meet foreseeable capital needs.

The FERC has jurisdiction over securities issuances by the Utility operating companies and System Energy, except securities with maturities longer than one year issued by Entergy Arkansas and Entergy New Orleans, which are subject to the jurisdiction of the APSC and the City Council, respectively. No regulatory approvals are necessary for Entergy Corporation to issue securities. The current FERC-authorized short-term borrowing limits are effective through October 2017. Entergy Louisiana, Entergy Mississippi, Entergy Texas, and System Energy have obtained long-term financing authorizations from the FERC that extend through October 2017. Entergy Arkansas has obtained long-term financing authorization from the APSC that extends through December 2018. Entergy New Orleans has obtained long-term financing authorization from the City Council that extends through July 2016. Entergy Arkansas, Entergy Louisiana, and System Energy each have obtained long-term financing authorizations from the FERC that extend through October 2017 for issuances by its nuclear fuel company variable interest entity. In addition to borrowings from commercial banks, the Registrant Subsidiaries may also borrow from 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 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 January 2013, Entergy Louisiana drew $252 million from its funded storm reserve escrow accounts. In April 2013, Entergy Louisiana filed a joint application with the LPSC relating to Hurricane Isaac system restoration costs. Specifically, Entergy Louisiana requested that the LPSC determine the amount of such costs that were prudently incurred and are, thus, eligible for recovery from customers. Including carrying costs and additional storm escrow funds for prior storms, Entergy Louisiana requested an LPSC determination that $321.5 million in system restoration costs were prudently incurred. In May 2013, Entergy Louisiana and the Louisiana Utilities Restoration Corporation (LURC), an instrumentality of the State of Louisiana, filed with the LPSC an application requesting that the LPSC grant financing orders authorizing the financing of Entergy Louisiana’s storm costs, storm reserves, and issuance costs pursuant to Act 55 of the Louisiana Regular Session of 2007 (Louisiana Act 55). The LPSC Staff filed direct testimony in September 2013 concluding that Hurricane Isaac system restoration costs incurred by Entergy Louisiana were reasonable and prudent, subject to proposed minor adjustments which totaled approximately 1% of the company’s costs. Following an evidentiary hearing and recommendations by the ALJ, the LPSC voted in June 2014 to approve a series of orders which (i) quantify the amount of Hurricane Isaac system restoration costs prudently incurred ($290.8 million for Entergy Louisiana); (ii) determine the level of storm reserves to be re-established ($290 million for Entergy Louisiana); (iii) authorize Entergy Louisiana to utilize Louisiana Act 55 financing for Hurricane Isaac system restoration costs; and (iv) grant other requested relief associated with storm reserves and Act 55 financing of Hurricane Isaac system restoration costs. Entergy Louisiana committed to pass on to customers a minimum of $30.8 million of customer benefits through annual customer credits of approximately $6.2 million for five years. Approvals for the Act 55 financings were obtained from the Louisiana Utilities Restoration Corporation (LURC) and the Louisiana State Bond Commission.

In July 2014, Entergy Louisiana issued two series totaling $300 million of 3.78% Series first mortgage bonds due April 2025. Entergy Louisiana 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 $314.85 million in bonds under Act 55 of the Louisiana Legislature. From the $309 million of bond proceeds loaned by the LCDA to the LURC, the LURC deposited $16 million in a restricted escrow account as a storm damage reserve for Entergy Louisiana and transferred $293 million directly to Entergy Louisiana. Entergy Louisiana used the $293 million received from the LURC to acquire 2,935,152.69 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.

Entergy and Entergy Louisiana do not report the bonds on their balance sheets because the bonds are the obligation of the LCDA and there is no recourse against Entergy or Entergy Louisiana in the event of a bond default. To service the bonds, Entergy Louisiana collects a system restoration charge on behalf of the LURC, and remits the collections to the bond indenture trustee. Entergy and Entergy Louisiana do not report the collections as revenue because Entergy Louisiana is merely acting as the billing and collection agent for the state.

In May 2015, the City Council issued a financing order authorizing the issuance of securitization bonds to recover Entergy New Orleans’s Hurricane Isaac storm restoration costs of $31.8 million, including carrying costs, the costs of funding and replenishing the storm recovery reserve in the amount of $63.9 million, and approximately $3 million for estimated up-front financing costs associated with the securitization. See Note 5 to the financial statements for a discussion of the July 2015 issuance of the securitization bonds.



## Cash Flow Activity

As shown in Entergy’s Consolidated Statements of Cash Flows, cash flows for the years ended December 31, 2015, 2014, and 2013 were as follows:

<table><tr><td rowspan="2"></td><td>2015</td><td>2014</td><td>2013</td></tr><tr><td colspan="3">(In Millions)</td></tr><tr><td>Cash and cash equivalents at beginning of period</td><td>$1,422</td><td>$739</td><td>$533</td></tr><tr><td>Net cash provided by (used in):</td><td></td><td></td><td></td></tr><tr><td>Operating activities</td><td>3,291</td><td>3,890</td><td>3,189</td></tr><tr><td>Investing activities</td><td>(2,609)</td><td>(2,955)</td><td>(2,602)</td></tr><tr><td>Financing activities</td><td>(753)</td><td>(252)</td><td>(381)</td></tr><tr><td>Net increase (decrease) in cash and cash equivalents</td><td>(71)</td><td>683</td><td>206</td></tr><tr><td>Cash and cash equivalents at end of period</td><td>$1,351</td><td>$1,422</td><td>$739</td></tr></table>

## Operating Activities

## 2015 Compared to 2014

Net cash provided by operating activities decreased by $599 million in 2015 primarily due to:

• lower Entergy Wholesale Commodities net revenues in 2015 as compared to 2014, as discussed previously;

- proceeds of $310 million received from the Louisiana Utilities Restoration Corporation in August 2014 as a result of the Louisiana Act 55 storm cost financing. See Note 2 to the financial statements and “Hurricane Isaac” above for a discussion of the Act 55 storm cost financing;

- spending of $78 million in 2015 on activities related to the decommissioning of Vermont Yankee, which ceased power production in December 2014;

- an increase of $52 million in interest paid in 2015 primarily due to an increase in interest paid on the Grand Gulf sale-leaseback obligation. See Note 10 to the financial statements for details of the Grand Gulf sale-leaseback obligation;

- an increase in spending of $48 million in 2015 related to Vermont Yankee, including the severance and retention payments accrued in 2014 and defueling activities that took place after the plant ceased power production in December 2014; and

- an increase in income tax payments of $26 million primarily due to payments made in 2015 for the final settlement of amounts outstanding associated with the 2006-2007 IRS audit. See Note 3 to the financial statements for a discussion of the finalized tax and interest computations for the 2006-2007 IRS audit.

The decrease was partially offset by:

• an increase in the recovery of fuel costs in 2015;

• higher Utility net revenues in 2015 as compared to 2014, as discussed above; and

• a decrease of $46 million in storm spending in 2015 as compared to 2014.



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

- higher Entergy Wholesale Commodities and Utility net revenues in 2014 as compared to 2013, as discussed previously;

- proceeds of $310 million received from the LURC in August 2014 as a result of the Louisiana Act 55 storm cost financings. See Note 2 to the financial statements for a discussion of the Act 55 storm cost financings;

• $58 million margin deposits made by Entergy Wholesale Commodities in 2013;

- a decrease in income tax payments of $50 million in 2014 compared to 2013 primarily due to state income tax effects of the settlement of the 2004-2005 IRS audit paid in 2013; and

• approximately $25 million in spending in 2013 related to the generator stator incident at ANO, as discussed previously.

The increase was partially offset by:

- an increase of $236 million in pension contributions in 2014, partially offset by a decrease of $38 million in lump sum retirement payments out of the non-qualified pension plan in 2014 as compared to 2013. See “Critical Accounting Estimates” below and Note 11 to the financial statements for a discussion of qualified pension and other postretirement benefits funding;

- proceeds of $72 million received in 2013 from the U.S. Department of Energy resulting from litigation regarding the storage of spent nuclear fuel;

• an increase of $44 million in spending on nuclear refueling outages in 2014 as compared to 2013; and

• an increase of $25 million in storm restoration spending in 2014.

## Investing Activities

## 2015 Compared to 2014

Net cash flow used in investing activities decreased by $346 million in 2015 primarily due to:

- proceeds of approximately $490 million from the sale in December 2015 of Rhode Island State Energy Center. See Note 15 to the financial statements for further discussion of the sale;

- the deposit of a total of $64 million into Entergy New Orleans’s storm reserve escrow accounts in 2015 compared to the deposit of a total of $268 million into Entergy Louisiana’s storm reserve escrow accounts in 2014;

- $58 million in disbursements from the Vermont Yankee decommissioning trust funds to Entergy in 2015; and

- a decrease in nuclear fuel purchases due to variations from year to year in the timing and pricing of fuel reload requirements, material and services deliveries, and the timing of cash payments during the nuclear fuel cycle.

The decrease was partially offset by:

- an increase in construction expenditures primarily due to an overall higher scope of work on various projects in 2015 as compared to 2014 and compliance with NRC post-Fukushima requirements, partially offset by a decrease in storm restoration spending and a decrease in spending on the Ninemile Unit 6 project;

- a change in collateral deposit activity, reflected in the “Decrease (increase) in other investments” line on the Consolidated Statements of Cash Flows, as Entergy received net deposits of $47 million in 2014. Entergy Wholesale Commodities’ forward sales contracts are discussed in the “Market and Credit Risk Sensitive Instruments” section below; and

- a decrease of $16 million in insurance proceeds primarily due to $13 million received in 2015 related to the Baxter Wilson plant event and $12 million received in 2015 for property damages related to the generator stator



incident at ANO compared to $37 million received in 2014 for property damages related to the generator stator incident at ANO. See Note 8 to the financial statements for a discussion of the Baxter Wilson plant event and the ANO stator incident.

## 2014 Compared to 2013

Net cash used in investing activities increased by $353 million in 2014 primarily due to:

- the deposit of a total of $276 million into storm reserve escrow accounts in 2014, primarily by Entergy Louisiana. See “Hurricane Isaac” above for a discussion of storm reserve escrow account replenishments in 2014;

- the withdrawal of a total of $260 million from storm reserve escrow accounts in 2013, primarily by Entergy Louisiana, after Hurricane Isaac. See “Hurricane Isaac” above for discussion of storm reserve escrow account withdrawals;

• proceeds of $140 million from the sale in November 2013 of Entergy Solutions District Energy. See Note 15 to the financial statements for further discussion of the sale;

• proceeds of $21 million received in 2013 from the U.S. Department of Energy resulting from litigation regarding the storage of spent nuclear fuel; and

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

The increase was partially offset by:

- a decrease in construction expenditures, primarily in the Utility business, including a decrease in spending on the Ninemile 6 project and spending in 2013 on the generator stator incident at ANO, partially offset by an increase in storm restoration spending;

- a change in collateral deposit activity, reflected in the “Decrease (increase) in other investments” line on the Consolidated Statements of Cash Flows, as Entergy received net deposits of $47 million in 2014 and returned net deposits of $88 million in 2013. Entergy Wholesale Commodities’ forward sales contracts are discussed in the “Market and Credit Risk Sensitive Instruments” section below; and

- $37 million in insurance proceeds received in 2014 for property damages related to the generator stator incident at ANO, as discussed above.

## Financing Activities

## 2015 Compared to 2014

Net cash flow used in financing activities increased $501 million in 2015 primarily due to:

- long-term debt activity providing approximately $41 million of cash in 2015 compared to providing $777 million of cash in 2014. Included in the long-term debt activity is $140 million in 2015 and $440 million in 2014 for the repayment of borrowings on the Entergy Corporation long-term credit facility;

- a decrease of $171 million in treasury stock issuances in 2015 primarily due to a larger amount of previously repurchased Entergy Corporation stock issued in 2014 to satisfy stock option exercises;

- a net decrease of $154 million in 2015 in short-term borrowings by the nuclear fuel company variable interest entities; and

- the repurchase or redemption of $94 million of preferred membership interests in 2015. Entergy Louisiana redeemed its $100 million 6.95% Series preferred membership interests, of which $16 million was owned by Entergy Louisiana Holdings, an Entergy subsidiary, and repurchased its $10 million Series A 8.25% preferred membership interests as part of a multi-step process to effectuate the Entergy Louisiana and Entergy Gulf States Louisiana business combination. See Note 2 to the financial statements for a discussion of the business combination.



The increase was partially offset by:

- net repayments of $62 million of commercial paper in 2015 compared to net repayments of $561 million of commercial paper in 2014;

- the issuance of $110 million of preferred stock in 2015. See Note 6 to the financial statements for further discussion; and

• a decrease of $83 million of common stock repurchased in 2015 as compared to 2014.

## 2014 Compared to 2013

Net cash flow used in financing activities decreased by $129 million in 2014 primarily due to:

- long-term debt activity providing approximately $777 million of cash in 2014 compared to using $69 million of cash in 2013. The most significant long-term debt activity in 2014 included the net issuance of approximately $385 million of long-term debt at the Utility operating companies and System Energy and Entergy Corporation increasing borrowings outstanding on its long-term credit facility by $440 million in 2014;

• Entergy Corporation repaid $561 million of commercial paper in 2014 and issued $380 million in 2013;

- an increase of $112 million in 2014 compared to a decrease of $129 million in 2013 in short-term borrowings by the nuclear fuel company variable interest entities;

• the repurchase of $183 million of Entergy common stock in 2014; and

- an increase of $170 million in treasury stock issuances in 2014 primarily due to a larger amount of previously repurchased Entergy Corporation common stock issued in 2014 to satisfy stock option exercises.

For the details of Entergy’s commercial paper program and the nuclear fuel company variable interest entities’ short-term borrowings, see Note 4 to the financial statements. See Note 5 to the financial statements for details of long-term debt.

## Rate, Cost-recovery, and Other Regulation

## State and Local Rate Regulation and Fuel-Cost Recovery

The rates that the Utility operating companies and System Energy charge for their services significantly influence Entergy’s financial position, results of operations, and liquidity. These companies are regulated and the rates charged to their customers are determined in regulatory proceedings. Governmental agencies, including the APSC, the City Council, the LPSC, the MPSC, the PUCT, and the FERC, are primarily responsible for approval of the rates charged to customers. Following is a summary of the Utility operating companies’ authorized returns on common equity:

<table><tr><td>Company</td><td>Authorized Return on Common Equity</td></tr><tr><td>Entergy Arkansas</td><td>9.25%-10.25%</td></tr><tr><td>Entergy Louisiana</td><td>9.15%-10.75% Electric; 9.45%-10.45% Gas</td></tr><tr><td>Entergy Mississippi</td><td>10.07%</td></tr><tr><td>Entergy New Orleans</td><td>10.7% - 11.5% Electric; 10.25% - 11.25% Gas</td></tr><tr><td>Entergy Texas</td><td>9.8%</td></tr></table>

The Utility operating companies’ base rate, fuel and purchased power cost recovery, and storm cost recovery proceedings are discussed in Note 2 to the financial statements.



## Federal Regulation

## Entergy’s Integration Into the MISO Regional Transmission Organization

In April 2011, Entergy announced that each of the Utility operating companies proposed to join the MISO RTO, an RTO operating in several U.S. states and also in Canada. On December 19, 2013, the Utility operating companies completed their planned integration into the MISO RTO. Becoming a member of MISO does not affect the ownership by the Utility operating companies of their transmission facilities or the responsibility for maintaining those facilities. With the Utility operating companies fully integrated as members, however, MISO assumed control of transmission planning and congestion management and, through its Day 2 market, MISO provides schedules and pricing for the commitment and dispatch of generation that is offered into MISO’s markets, as well as pricing for load that bids into the market.

The Utility operating companies obtained from each of their retail regulators the public interest findings sought by the Utility operating companies in order to move forward with their plan to join MISO. Each of the retail regulators’ orders includes conditions, some of which entail compliance prospectively. See also “System Agreement - Utility Operating Company Notices of Termination of System Agreement Participation” below.

Beginning in 2011 the Utility operating companies and the MISO RTO began submitting various filings with the FERC that contained many of the rates, terms and conditions that would govern the Utility operating companies' integration into the MISO RTO. The Utility operating companies and the MISO RTO received the FERC orders necessary for those companies to integrate into the MISO RTO consistent with the approvals obtained from the Utility operating companies' retail regulators, although some proceedings remain pending at the FERC.

In January 2013, Occidental Chemical Corporation filed with the FERC a petition for declaratory judgment and complaint against MISO alleging that MISO’s proposed treatment of Qualifying Facilities (QFs) in the Entergy region is unduly discriminatory in violation of sections 205 and 206 of the Federal Power Act and violates the Public Utility Regulatory Policies Act (PURPA) and the FERC’s implementing regulations. In February 2014, Occidental also filed a petition for enforcement with the FERC against the LPSC. Occidental’s petition for enforcement alleges that the LPSC’s January 2014 order, which approved Entergy Louisiana’s application for modification of Entergy’s methodology for calculating avoided cost rates paid to QFs, is inconsistent with the requirements of PURPA and the FERC’s regulations implementing PURPA. In April 2014 the FERC issued a “Notice Of Intent Not To Act At This Time” with respect to Occidental’s petition for enforcement against the LPSC. The FERC concluded that Occidental’s petition for enforcement largely raises the same issues as those raised in the January 2013 complaint and petition for declaratory order that Occidental filed against MISO, and that the two proceedings should be addressed at the same time. The FERC reserved its ability to issue a further order or to take further action at a future date should it find that doing so is appropriate. In January 2016, in a separate proceeding, the FERC issued an order granting the Utility operating companies’ petition to terminate the requirement that they enter into new obligations or contracts with QFs with net capacity in excess of 20 MW, including Occidental’s Taft QF, effective October 2015. The FERC denied without prejudice the petition as it relates to Dow Chemical Company’s Plaquemine QF.

In April 2014, Occidental filed a 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 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 January 2016 the U.S. Fifth Circuit Court of Appeals vacated the district court’s stay order and remanded the case to the district court to enter a new order staying the proceedings for a period of 180 days to allow the FERC the opportunity to rule on the MISO tariff and market rules that are underlying Occidental’s district court complaint. If the FERC fails to act within that 180 day period, then the district court may extend the deadline if (1) good cause is shown regarding the lack of FERC action, and (2) the delay would not irreparably harm Occidental’s rights. The district court entered a new stay order in January 2016.

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-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. In February 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 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. In July 2015, as amended in August and October 2015, Entergy Services, on behalf of the Utility operating companies, filed a settlement at the FERC resolving all issues relating to the Utility operating companies’ Attachment O transmission rates in MISO except for challenges to MISO’s regional through and out rates. In October 2015 the presiding judge certified the settlement as contested to the FERC due to comments opposing the settlement filed by the same parties that have raised issues related to MISO’s through and out rates. The settlement is pending before the FERC.

In May 2015 several parties filed a complaint against MISO related to certain charges for transmission service provided by MISO to them when their point-to-point service under the Entergy open access transmission tariff was transitioned to the MISO tariff in December 2013. The complainants request that the FERC order refunds for alleged overcharges since December 2013, or alternatively that the FERC institute a proceeding under Section 206 of the Federal Power Act to address the legality of transmission applicable rates and establish a different fifteen-month refund period from the period established in the FERC’s February 2014 order. In June 2015, another party filed a similar complaint against MISO. MISO filed answers to both complaints asking the FERC to dismiss the complaints, and Entergy filed protests in support of MISO’s answers. Also in June 2015 the FERC issued an order denying rehearing of certain determinations in the February 2014 order regarding MISO’s regional through and out rates. In October 2015 the FERC issued an order denying the complaints filed in May and June 2015, finding that MISO did not violate its tariff and the justness and reasonableness of the rates referenced in the complaints are already being addressed in the proceeding initiated in February 2014, thus rendering the complaints duplicative. The proceeding initiated in February 2014 is being held in abeyance pending settlement discussions.

## System Agreement

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



imprudence by the Utility operating companies in their execution of their obligations under the System Agreement. See Note 2 to the financial statements for discussions of this litigation.

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. The LPSC, MPSC, PUCT, and City Council filed protests at the FERC regarding the amendments 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. In December 2013 the FERC issued an order accepting the revisions filed in November 2012, subject to a further compliance filing and other conditions. Entergy Services made the requisite compliance filing in February 2014 and the FERC accepted the compliance filing in November 2015. In the November 2015 order, the FERC required Entergy Services to file a refund report consisting of the results of the intra-system bill rerun from December 19, 2013 through November 30, 2015 calculating the use of an energy-based allocator to allocate losses, ancillary services charges and credits, and uplift charges and credits to load of each participating Utility operating company. The filing shows the following payments and receipts among the Utility operating companies:

<table><tr><td>Payments (Receipts)</td></tr><tr><td>(In Millions)</td></tr><tr><td>Entergy Louisiana ($6.3)</td></tr><tr><td>Entergy Mississippi $4</td></tr><tr><td>Entergy New Orleans $0.4</td></tr><tr><td>Entergy Texas $1.9</td></tr></table>

In the December 2013 order, 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 participation in the System Agreement terminated effective December 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.

## Utility Operating Company Notices of Termination of System Agreement Participation

Consistent with their written notices of termination delivered in December 2005 and November 2007, respectively, Entergy Arkansas and Entergy Mississippi filed with the FERC in February 2009 their notices of cancellation to terminate their participation in the System Agreement, effective December 18, 2013 and November 7, 2015, respectively. In November 2009 the FERC accepted the notices of cancellation and determined that Entergy Arkansas and Entergy Mississippi are permitted to withdraw from the System Agreement following the 96-month notice period without payment of a fee or the requirement to otherwise compensate the remaining Utility operating companies as a result of withdrawal. Appeals by the LPSC and the City Council were denied in 2012 and 2013. Effective December 18, 2013, Entergy Arkansas ceased participating in the System Agreement. Effective November 7, 2015, Entergy Mississippi ceased participating in the System Agreement.

In keeping with their prior commitments and after a careful evaluation of the basis for and continued reasonableness of the 96-month System Agreement termination notice period, the Utility operating companies filed with the FERC in October 2013 to amend the System Agreement changing the notice period for an operating company to



terminate its participation in the System Agreement from 96 months to 60 months. Subsequent to that filing, Entergy Texas and Entergy Louisiana separately provided notice to terminate their participation in the System Agreement.

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. In August 2015, Entergy Services filed a settlement in the FERC dockets addressing the notice period for exiting the System Agreement, including the pending notices of withdrawal filed by Entergy Louisiana and Entergy Texas. The settlement was expressly conditioned on obtaining the necessary FERC and state and local regulatory approvals. By November 2015, all necessary state and local regulatory approvals had been obtained, and in December 2015 the FERC issued an order approving the settlement.

Under the settlement, the System Agreement will terminate at the end of August 2016 as to all parties remaining as of that date. The purchase power agreements, referred to as the jurisdictional separation plan PPAs, between Entergy Texas and Entergy Gulf States Louisiana that were put in place for certain legacy gas units at the time of Entergy Gulf States's separation into Entergy Texas and Entergy Gulf States Louisiana will terminate, effective with System Agreement termination. Similarly, the PPA between Entergy Gulf States Louisiana and Entergy Texas for the Calcasieu unit also will terminate. Currently, the jurisdictional separation plan PPAs are the means by which Entergy Texas receives payment for its receivable associated with Entergy Louisiana's Spindletop gas storage facility regulatory asset. See Note 2 to the financial statements for discussion of the decision to write off the Spindletop regulatory asset.

The settlement also provides that Entergy New Orleans will be established as a separate transmission pricing zone in MISO effective with System Agreement termination, and that Entergy New Orleans will make payments to Entergy Louisiana in the amount of $2.2 million annually for a period of 15 years. Entergy New Orleans will obtain an option to participate in a portion of certain future Amite South CCGT resources that may be procured by Entergy Louisiana, subject to certain conditions and restrictions. If Entergy New Orleans acquires Power Block 1 of the Union Power Station and obtains full deliverability of the resource, this option will terminate. Entergy New Orleans will also pursue investment in certain new generating resources located in New Orleans.

## Market and Credit Risk Sensitive Instruments

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

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

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

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

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

The Utility 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 commodity and financial 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.



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.

## Commodity Price Risk

## Power Generation

As a wholesale generator, Entergy Wholesale Commodities’ core business is selling energy, measured in MWh, to its customers. Entergy Wholesale Commodities enters into forward contracts with its customers and 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’ 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, 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 sensitivities are provided in the table below to show potential variations. The sensitivities may not reflect the total maximum upside potential from higher market prices. The information contained in the following table represents projections at a point in time and will vary over time based on numerous factors, such as future market prices, contracting activities, and generation. Following is a summary of Entergy Wholesale Commodities’ current forward capacity and generation contracts as well as total revenue projections based on market prices as of December 31, 2015.



## Entergy Wholesale Commodities Nuclear Portfolio

<table><tr><td></td><td>2016</td><td>2017</td><td>2018</td><td>2019</td></tr><tr><td>Energy</td><td></td><td></td><td></td><td></td></tr><tr><td>Percent of planned generation under contract (a):</td><td></td><td></td><td></td><td></td></tr><tr><td>Unit-contingent (b)</td><td>65%</td><td>53%</td><td>21%</td><td>26%</td></tr><tr><td>Firm LD (c)</td><td>41%</td><td>10%</td><td>—%</td><td>—%</td></tr><tr><td>Offsetting positions (d)</td><td>(20%)</td><td>—%</td><td>—%</td><td>—%</td></tr><tr><td>Total</td><td>86%</td><td>63%</td><td>21%</td><td>26%</td></tr><tr><td>Planned generation (TWh) (e) (f)</td><td>36</td><td>28</td><td>29</td><td>26</td></tr><tr><td>Average revenue per MWh on contracted volumes:</td><td></td><td></td><td></td><td></td></tr><tr><td>Minimum</td><td>$45</td><td>$46</td><td>$56</td><td>$57</td></tr><tr><td>Expected based on market prices as of December 31, 2015</td><td>$46</td><td>$46</td><td>$56</td><td>$57</td></tr><tr><td>Sensitivity: -/+ $10 per MWh market price change</td><td>$45-$47</td><td>$46-$48</td><td>$56</td><td>$57</td></tr><tr><td>Capacity</td><td></td><td></td><td></td><td></td></tr><tr><td>Percent of capacity sold forward (g):</td><td></td><td></td><td></td><td></td></tr><tr><td>Bundled capacity and energy contracts (h)</td><td>17%</td><td>21%</td><td>22%</td><td>25%</td></tr><tr><td>Capacity contracts (i)</td><td>26%</td><td>19%</td><td>20%</td><td>9%</td></tr><tr><td>Total</td><td>43%</td><td>40%</td><td>42%</td><td>34%</td></tr><tr><td>Planned net MW in operation (f)</td><td>4,406</td><td>3,638</td><td>3,568</td><td>3,167</td></tr><tr><td>Average revenue under contract per kW per month(applies to capacity contracts only)</td><td>$3.3</td><td>$5.6</td><td>$9.4</td><td>$11.1</td></tr><tr><td>Total Nuclear Energy and Capacity Revenues</td><td></td><td></td><td></td><td></td></tr><tr><td>Expected sold and market total revenue per MWh</td><td>$48</td><td>$49</td><td>$49</td><td>$51</td></tr><tr><td>Sensitivity: -/+ $10 per MWh market price change</td><td>$46-$51</td><td>$45-$53</td><td>$42-$57</td><td>$43-$58</td></tr></table>

(a) Percent of planned generation output sold or purchased forward under contracts, forward physical contracts, forward financial contracts, or options that mitigate price uncertainty that may require regulatory approval or approval of transmission rights. Positions that are not classified as hedges are netted in the planned generation under contract.

(b) Transaction under which power is supplied from a specific generation asset; if the asset is not operating, the seller is generally not liable to buyer for any damages. Certain unit-contingent sales include a guarantee of availability. Availability guarantees provide for the payment to the power purchaser of contract damages, if incurred, in the event the seller fails to deliver power as a result of the failure of the specified generation unit to generate power at or above a specified availability threshold. All of Entergy’s outstanding guarantees of availability provide for dollar limits on Entergy’s maximum liability under such guarantees.

(c) Transaction that requires receipt or delivery of energy at a specified delivery point (usually at a market hub not associated with a specific asset) or settles financially on notional quantities; if a party fails to deliver or receive energy, defaulting party must compensate the other party as specified in the contract, a portion of which may be capped through the use of risk management products. This also includes option transactions that may expire without being exercised.

(d) Transactions for the purchase of energy, generally to offset a Firm LD transaction.

(e) Amount of output expected to be generated by Entergy Wholesale Commodities resources considering plant operating characteristics, outage schedules, and expected market conditions that affect dispatch.

(f) Assumes NRC license renewals for plants with NRC license renewal applications in process. Assumes shutdown of FitzPatrick at the end of January 2017, shutdown of Pilgrim June 1, 2019, and uninterrupted normal operation at remaining plants. NRC license renewal applications are in process for two units, as follows (with current license expirations in parentheses): Indian Point 2 (September 2013 and now operating under its period of extended operations while its application is pending) and Indian Point 3 (December 2015 and now operating



under its period of extended operations while its application is pending). For a discussion regarding the shutdown of the FitzPatrick and Pilgrim plants, see Note 1 to the financial statements. For a discussion regarding the license renewals for Indian Point 2 and Indian Point 3, see “Entergy Wholesale Commodities Authorizations to Operate Its Nuclear Power Plants” above.

(g) Percent of planned qualified capacity sold to mitigate price uncertainty under physical or financial transactions.

(h) A contract for the sale of installed capacity and related energy, priced per megawatt-hour sold.

(i) A contract for the sale of an installed capacity product in a regional market.

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 $99 million in 2016 and would have had a corresponding effect on pre-tax income of $107 million in 2015. 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 ($74) million in 2016 and would have had a corresponding effect on pre-tax income of ($73) million in 2015.

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

Some of the agreements to sell the power produced by Entergy Wholesale Commodities' power plants contain provisions that require an Entergy subsidiary to provide credit support to secure its obligations under the agreements. The Entergy subsidiary is required to provide credit support based upon the difference between the current market prices and contracted power prices in the regions where Entergy Wholesale Commodities sells power. The primary form of credit support to satisfy these requirements is an Entergy Corporation guaranty. Cash and letters of credit are also acceptable forms of credit support. At December 31, 2015, based on power prices at that time, Entergy had liquidity exposure of $142 million under the guarantees in place supporting Entergy Wholesale Commodities transactions and $14 million of posted cash collateral. In the event of a decrease in Entergy Corporation's credit rating to below investment grade, based on power prices as of December 31, 2015, Entergy would have been required to provide approximately $52 million of additional cash or letters of credit under some of the agreements. As of December 31, 2015, the liquidity exposure associated with Entergy Wholesale Commodities assurance requirements, including return of previously posted collateral from counterparties, would increase by $98 million for a $1 per MMBtu increase in gas prices in both the short-and long-term markets.

As of December 31, 2015, substantially all of the credit exposure associated with the planned energy output under contract for Entergy Wholesale Commodities nuclear plants through 2019 is with counterparties or their guarantors that have public investment grade credit ratings.

## Nuclear Matters

After the nuclear incident in Japan resulting from the March 2011 earthquake and tsunami, the NRC established a task force to conduct a review of processes and regulations relating to nuclear facilities in the United States. The task



force issued a near-term (90-day) report in July 2011 that 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 March 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. Entergy’s estimated capital expenditures for 2016 through 2018 for complying with the NRC orders are included in the planned construction and other capital investments estimates given in “Liquidity and Capital Resources - Capital Expenditure Plans and Other Uses of Capital” above.

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 environmental effects in reaching these conclusions. The Waste Confidence Decision has been relied upon by NRC license renewal applicants to address some of the issues that the NEPA requires the NRC to address before it issues a renewed license. Certain nuclear opponents filed requests with the NRC asking it to address the issues raised by the court’s decision in the license renewal proceedings for a number of nuclear plants including Grand Gulf and Indian Point 2 and 3. In August 2012 the NRC issued an order stating that it will not issue final licenses dependent upon the Waste Confidence Decision until the D.C. Circuit’s remand is addressed, but also stating that licensing reviews and proceedings should continue to move forward. In September 2014 the NRC published a new final Waste Confidence rule, named Continued Storage of Spent Nuclear Fuel, that for licensing purposes adopts non-site specific findings concerning the environmental impacts of the continued storage of spent nuclear fuel at reactor sites - for 60 years, 100 years and indefinitely - after the reactor’s licensed period of operations. The NRC also issued an order lifting its suspension of licensing proceedings after the final rule’s effective date in October 2014. After the final rule became effective, New York, Connecticut, and Vermont filed a challenge to the rule in the U.S. Court of Appeals. The final rule remains in effect while that challenge is pending unless the court orders otherwise.

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 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.

See “ANO Damage, Outage, and NRC Reviews” above and Note 8 to the financial statements for discussion of the NRC’s decision to move ANO into the “multiple/repetitive degraded cornerstone column” (Column 4) of the NRC’s Reactor Oversight Process Action Matrix, and the resulting significant additional NRC inspection activities at the ANO site.

See Note 8 to the financial statements for discussion of the NRC’s decision in September 2015 to place Pilgrim in Column 4 of its Reactor Oversight Process Action Matrix due to its finding of continuing weaknesses in Pilgrim’s corrective action program that contributed to repeated unscheduled shutdowns and equipment failures.

## Critical Accounting Estimates

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

## Nuclear Decommissioning Costs

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.

- Timing - In projecting decommissioning costs, two assumptions must be made to estimate the timing of plant decommissioning. First, the date of the plant’s retirement must be estimated for those plants that do not have an announced shutdown date. For certain nuclear plants for which the operating license has not been renewed yet, this estimate assumes a high probability that the plant’s license will be renewed. Second, an assumption must be made whether all decommissioning activity will proceed immediately upon plant retirement, or whether the plant will be placed in SAFSTOR status. SAFSTOR is decommissioning a facility by placing it in a safe, stable condition that is maintained until it is subsequently decontaminated and dismantled to levels that permit license termination, normally within 60 years from permanent cessation of operations. A change of assumption regarding either the probability of license renewal, the period of continued operation, or the use of a SAFSTOR period can change the present value of the asset retirement obligations.

- Cost Escalation Factors - Entergy’s current decommissioning cost studies include an assumption that decommissioning costs will escalate over present cost levels by factors ranging from approximately 2% to 3% annually. A 50-basis point change in this assumption could change the estimated present value of the decommissioning liabilities by approximately 8% to 15%. The timing assumption influences the significance of the effect of a change in the estimated inflation or cost escalation rate because the effect increases with the length of time assumed before decommissioning activity ends.

- Spent Fuel Disposal - Federal law requires the DOE to provide for the permanent storage of spent nuclear fuel, and legislation has been passed by Congress to develop a repository at Yucca Mountain, Nevada. The current Presidential administration, however, has defunded the Yucca Mountain project. The DOE has not yet begun accepting spent nuclear fuel and is in non-compliance with federal law. The DOE continues to delay meeting its obligation and Entergy’s nuclear plant owners are continuing to pursue damage claims against the DOE for its failure to provide timely spent fuel storage. Until a federal site is available, however, nuclear plant operators must provide for interim spent fuel storage on the nuclear plant site, which can require the construction and maintenance of dry cask storage sites or other facilities. The costs of developing and maintaining these facilities during the decommissioning period can have a significant effect (as much as an average of 20% to 30% of total estimated decommissioning costs). Entergy’s decommissioning studies include cost estimates for spent fuel storage. These estimates could change in the future, however, based on the timing of when the DOE begins to fulfill its obligation to receive and store spent nuclear fuel.

- Technology and Regulation - Over the past several years, more practical experience with the actual decommissioning of nuclear facilities has been gained and that experience has been incorporated into Entergy’s current decommissioning cost estimates. Given the long duration of decommissioning projects, additional experience, including technological advancements in decommissioning, could occur, however, and affect current cost estimates. In addition, if regulations regarding nuclear decommissioning were to change, this could significantly affect cost estimates.

- Interest Rates - The estimated decommissioning costs that are the basis for the recorded decommissioning liability are discounted to present value using a credit-adjusted risk-free rate. When the decommissioning liability is revised, increases in cash flows are discounted using the current credit-adjusted risk-free rate. Decreases in estimated cash flows are discounted using the credit-adjusted risk-free rate used previously in estimating the decommissioning liability that is being revised. Therefore, to the extent that a revised cost study results in an increase in estimated cash flows, a change in interest rates from the time of the previous cost estimate will affect the calculation of the present value of the revised decommissioning liability.



Revisions of estimated decommissioning costs that decrease the liability also result in a decrease in the asset retirement cost asset. For the non-rate-regulated portions of Entergy’s business, these reductions will immediately reduce operating expenses in the period of the revision if the reduction of the liability exceeds the amount of the undepreciated asset retirement cost asset at the date of the revision. Revisions of estimated decommissioning costs that increase the liability result in an increase in the asset retirement cost asset, which is then depreciated over the asset’s remaining economic life. For a plant in the non-rate-regulated portions of Entergy’s business for which the plant’s value is impaired, however, including a plant that is shutdown, or is nearing its shutdown date, the increase in the liability is likely to immediately increase operating expense in the period of the revision and not increase the asset retirement cost asset. See Note 1 to the financial statements for further discussion of impairment of long-lived assets and Note 9 to the financial statements for further discussion of decommissioning cost revisions.

## Unbilled Revenue

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

## Impairment of Long-lived Assets and Trust Fund Investments

Entergy has significant investments in long-lived assets in 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 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 decision or an expectation that Entergy will 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 previously-expected amounts; or, for Indian Point 2 and 3, if their operating licenses are not renewed.

If an asset is considered held for use, and Entergy concludes that events and circumstances are present indicating that an impairment analysis should be done 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 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.

The expected future cash flows are based on a number of key assumptions, including:

- Future power and fuel prices - Electricity and gas prices can be very volatile. This volatility increases the imprecision inherent in the long-term forecasts of commodity prices that are a key determinant of estimated future cash flows.

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



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

- Timing and the life of the asset - Entergy assumes an expected life of the asset and currently assumes, for some of its nuclear units, that the plant’s license will be renewed beyond its current expiration date. A change in the timing assumption could have a significant effect on the expected future cash flows and result in a significant effect on operations.

See “Impairment of Long-Lived Assets” in Note 1 to the financial statements for a discussion of the impairments of the Vermont Yankee, FitzPatrick, Pilgrim, and Palisades plants.

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 2015, 2014, or 2013. 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 2015, 2014, or 2013 resulting from the recognition of other-than-temporary impairment of equity securities held in its decommissioning trust funds.

## Qualified Pension and Other Postretirement Benefits

Entergy sponsors qualified, defined benefit pension plans that cover substantially all employees, including cash balance plans for employees whose most recent date of hire or rehire is after June 30, 2014 (or for certain eligible bargaining employees, such later date provided in their applicable collective bargaining agreements) and final average pay plans for substantially all employees whose more recent date of hire or rehire is before July 1, 2014. Additionally, Entergy currently provides postretirement health care and life insurance benefits for substantially all full-time employees whose most recent date of hire or rehire is before July 1, 2014 (and for certain eligible bargaining employees, such later date provided in their applicable collective bargaining agreements), and 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 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.

## Assumptions

Key actuarial assumptions utilized in determining these costs include:

• Discount rates used in determining future benefit obligations;

• Projected health care cost trend rates;

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



• Rate of increase in future compensation levels;

• Retirement rates; and

• Mortality rates.

Entergy reviews the first four assumptions listed above on an annual basis and adjusts them as necessary. The falling interest rate environment 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 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 resulted in an increase at December 31, 2014 of $504.4 million in the qualified pension benefit obligation and $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 uses a yield curve based on high-quality corporate debt. Based on recent market trends, the discount rates used to calculate its 2015 qualified pension benefit obligation ranged from 4.51% to 4.79% for its specific pension plans (4.67% combined rate for all pension plans). In 2016, Entergy refined its approach to estimating the service cost and interest cost components of qualified pension costs and other postretirement health care and life insurance costs, which had the effect of lowering qualified pension costs by $61.4 million. This refined approach discounts the individual expected cash flows underlying the service cost and interest cost using the applicable spot rates derived from the yield curve used to discount the cash flows used to measure the pension obligation. Historically, Entergy estimated these service and interest cost components utilizing a single weighted-average discount rate derived from the yield curve used to measure the benefit obligation at the beginning of the period. This is a change in accounting estimate and accordingly the effect will be reflected prospectively. The benefit obligations measured under this approach are unchanged. The spot rates used to determine the qualified pension service cost ranged from 4.52% to 5.08% (5.00% combined rate for all pension plans) and the interest cost ranged from 3.68% to 4.14% (3.90% combined for all pension plans), respectively. Under the prior approach, the rate for qualified pension service and interest costs would have been a weighted average rate of approximately 4.67%.

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 rate used to calculate the 2015 postretirement health care and life insurance benefit obligation was 4.60%. The 2016 postretirement health care and life insurance benefit service and interest cost, under the more refined discount rate calculation, was reduced by $14.6 million. The effective spot rates used to determine the postretirement health care and life insurance benefit service cost and interest costs were 4.92% and 3.78%, respectively. Under the prior approach, the rate would have been a weighted-average rate for other postretirement service and interest costs of approximately 4.60%.



The discount rate used to calculate its 2014 postretirement health care and life insurance benefit obligation and 2015 postretirement health care and life insurance benefit cost was 4.23%. The discount rate used to calculate its 2013 postretirement health care and life insurance benefit obligation and 2014 postretirement health care and life insurance benefit cost was 5.05%. The discount rate used to calculate its 2012 postretirement health care and life insurance benefit obligation and 2013 postretirement health care and life insurance benefit cost was 4.36%.

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, 2015 accumulated postretirement benefit obligation and 2016 postretirement cost was 6.75% for pre-65 retirees and 7.55% for post-65 retirees for 2015, gradually decreasing each successive year until it reaches 4.75% in 2024 and beyond for both pre-65 and post-65 retirees. 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 2013 postretirement cost was 7.50% for pre-65 retirees and 7.25% for post-65 retirees, gradually decreasing each successive year until it reaches 4.75% in 2022 and beyond for both pre-65 and post-65 retirees.

The assumed rate of increase in future compensation levels used to calculate 2015 and 2014 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 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 2015, 2014, and 2013 qualified pension costs was 8.25%, 8.5%, and 8.5%, respectively and will be 7.75% for 2016. Entergy’s expected long term rate of return on tax deferred other postretirement assets used to calculate other postretirement costs was 8.05%, 8.3%, and 8.5% in 2015, 2014, and 2013, respectively. It will be 7.75% for 2016. For Entergy’s taxable postretirement assets, the expected long term rate of return was 6.25% in 2015 and 6.5% in 2014 and 2013. It will be 6.00% in 2016.

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.



## Cost Sensitivity

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

<table><tr><td>Actuarial Assumption</td><td>Change in Assumption</td><td>Impact on 2015 Qualified Pension Cost</td><td>Impact on 2015 Qualified Projected Benefit Obligation</td></tr><tr><td>Discount rate</td><td>(0.25%)</td><td>Increase/(Decrease)</td><td>$228,185</td></tr><tr><td>Rate of return on plan assets</td><td>(0.25%)</td><td>$11,178</td><td>$—</td></tr><tr><td>Rate of increase in compensation</td><td>0.25%</td><td>$8,973</td><td>$35,458</td></tr></table>

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

<table><tr><td>Actuarial Assumption</td><td>Change in Assumption</td><td>Impact on 2015 Postretirement Benefit Cost</td><td>Impact on 2015 Accumulated Postretirement Benefit Obligation</td></tr><tr><td></td><td></td><td>Increase/(Decrease)</td><td></td></tr><tr><td>Discount rate</td><td>(0.25%)</td><td>$4,578</td><td>$50,925</td></tr><tr><td>Health care cost trend</td><td>0.25%</td><td>$7,450</td><td>$42,890</td></tr></table>

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

## Accounting Mechanisms

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

## Costs and Funding

In 2015, Entergy’s total qualified pension cost was $321.1 million, including a $0.4 million curtailment charge related to announced plant closures. Entergy anticipates 2016 qualified pension cost to be $211.8 million. Entergy’s pension funding was approximately $395.8 million for 2015. Entergy’s 2016-2018 contributions to the pension trust are currently estimated to be approximately $1.1 billion, including $387.5 million in 2016; although the 2016 required pension contributions will be known with more certainty when the January 1, 2016 valuations are completed, which is expected by April 1, 2016.



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 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.

Moving Ahead for Progress in the 21st Century Act (MAP-21) became federal law in July 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 requirements for single employer defined benefit plans in response to the historically low interest rates that existed when the law was enacted. The law did not reduce contribution requirements over the long term.

The Highway and Transportation Funding Act (HATFA) became federal law in August 2014. HATFA’s pension provisions provided a five-year extension of the MAP-21 pension funding stabilization.

Total postretirement health care and life insurance benefit costs for Entergy in 2015 were $66.2 million. Entergy expects 2016 postretirement health care and life insurance benefit costs to be $19.5 million. Entergy contributed $62.7 million to its postretirement plans in 2015. Entergy’s current estimate of 2016-2018 contributions to its other postretirement plans is approximately $148.6 million, including $52.8 million in 2016.

## Federal Healthcare Legislation

The Patient Protection and Affordable Care Act (PPACA) became federal law on March 23, 2010, and, on March 30, 2010, the Health Care and Education Reconciliation Act of 2010 became federal law and amended certain provisions of the PPACA. Entergy has implemented the major provisions of the law.

A 40% excise tax on per capita medical benefit costs that exceed certain thresholds is due to take effect beginning in 2018. There are still many technical issues, however, that have not been finalized. Entergy will continue to monitor these developments to determine the possible effect on Entergy.

## Other Contingencies

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.

## Environmental

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.

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

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

- The resolution or progression of existing matters through the court system or resolution by the EPA or relevant state or local authority.

## Litigation

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

## Uncertain Tax Positions

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

## New Accounting Pronouncements

The accounting standard-setting process, including projects between the FASB and the International Accounting Standards Board (IASB) to converge U.S. GAAP and International Financial Reporting Standards, is ongoing and the FASB and the IASB are each currently working on several projects. Final pronouncements that result from these projects could have a material effect on Entergy’s future net income, 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. In August 2015 the FASB issued ASU No. 2015-14, “Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date.” The ASU defers the effective date of ASU 2014-09 for all entities by one year. ASU 2014-09 is effective for Entergy for the first quarter 2018. 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.



In February 2015 the FASB issued ASU No. 2015-02, “Consolidation (Topic 810): Amendments to Consolidation Analysis” which changes the analysis that a reporting entity must perform to determine whether it should consolidate certain types of legal entities. The ASU affects (1) limited partnerships and similar legal entities, (2) evaluating fees paid to a decision maker or a service provider as a variable interest, (3) the effect of fee arrangements on the primary beneficiary determination, (4) the effect of related parties on the primary beneficiary determination, and (5) certain investment funds. ASU 2015-02 is effective for Entergy for the first quarter 2016. Entergy does not expect ASU 2015-02 to affect materially its results of operations, financial position, or cash flows.

In January 2016 the FASB issued ASU No. 2016-01 “Financial Instruments (Subtopic 825-10): Recognition and Measurement of Financial Assets and Financial Liabilities.” The ASU requires equity investments, excluding those accounted for under the equity method or resulting in consolidation of the investee, to be measured at fair value with changes recognized in net income. The ASU requires a qualitative assessment to identify impairments of equity investments without readily determinable fair value. ASU 2016-01 is effective for Entergy for the first quarter 2018. Entergy expects that ASU 2016-01 will affect its results of operations by requiring unrealized gains and losses on equity investments held by the nuclear decommissioning trust funds to be recorded in earnings rather than in other comprehensive income. In accordance with the regulatory treatment of the decommissioning trust funds of Entergy Arkansas, Entergy Louisiana, and System Energy, an offsetting amount of unrealized gains/losses will continue to be recorded in other regulatory liabilities/assets. Entergy is evaluating the ASU for other effects on the results of operations, financial position, and cash flows.



# ENTERGY CORPORATION AND SUBSIDIARIES
REPORT OF MANAGEMENT

Management of Entergy Corporation and its subsidiaries has prepared and is responsible for the financial statements and related financial information included in this document. To meet this responsibility, management establishes and maintains a system of internal controls over financial reporting designed to provide reasonable assurance regarding the preparation and fair presentation of financial statements in accordance with generally accepted accounting principles. This system includes communication through written policies and procedures, an employee Code of Integrity, 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 2013 COSO Framework was utilized for 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’s independent registered public accounting firm, Deloitte & Touche LLP, has issued an attestation report on the effectiveness of Entergy Corporation’s internal control over financial reporting as of December 31, 2015.

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 2013 COSO criteria, management believes that Entergy maintained effective internal control over financial reporting as of December 31, 2015. Management further believes that this assessment, combined with the policies and procedures noted above, provides reasonable assurance that Entergy’s financial statements are fairly and accurately presented in accordance with generally accepted accounting principles.

LEO P. DENAULT
Chairman of the Board and Chief Executive Officer of Entergy Corporation
ANDREW S. MARSH
Executive Vice President and Chief Financial Officer of Entergy Corporation



# REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders of Entergy Corporation and Subsidiaries
New Orleans, Louisiana

We have audited the accompanying consolidated balance sheets of Entergy Corporation and Subsidiaries (the “Corporation”) as of December 31, 2015 and 2014, and the related consolidated statements of operations, comprehensive income, cash flows, and changes in equity for each of the three years in the period ended December 31, 2015. These financial statements are the responsibility of the Corporation’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Entergy Corporation and Subsidiaries as of December 31, 2015 and 2014, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2015, in conformity with accounting principles generally accepted in the United States of America.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Corporation’s internal control over financial reporting as of December 31, 2015, based on the criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 25, 2016 expressed an unqualified opinion on the Corporation’s internal control over financial reporting.

/s/ DELOITTE & TOUCHE LLP

New Orleans, Louisiana
February 25, 2016



# REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders of Entergy Corporation and Subsidiaries
New Orleans, Louisiana

We have audited the internal control over financial reporting of Entergy Corporation and Subsidiaries (the “Corporation”) as of December 31, 2015, based on criteria established in Internal Control -Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Corporation’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in Item 9A, Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Corporation’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company’s internal control over financial reporting is a process designed by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and effected by the company’s board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, the Corporation maintained, in all material respects, effective internal control over financial reporting as of December 31, 2015, based on the criteria established in Internal Control -Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements of the Corporation as of and for the year ended December 31, 2015 and our report dated February 25, 2016 expressed an unqualified opinion on those consolidated financial statements.

/s/ DELOITTE & TOUCHE LLP



## ENTERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS

<table><tr><td rowspan="3"></td><td colspan="3">For the Years Ended December 31,</td></tr><tr><td>2015</td><td>2014</td><td>2013</td></tr><tr><td colspan="3">(In Thousands, Except Share Data)</td></tr><tr><td>OPERATING REVENUES</td><td></td><td></td><td></td></tr><tr><td>Electric</td><td>$9,308,678</td><td>$9,591,902</td><td>$8,942,360</td></tr><tr><td>Natural gas</td><td>142,746</td><td>181,794</td><td>154,353</td></tr><tr><td>Competitive businesses</td><td>2,061,827</td><td>2,721,225</td><td>2,294,234</td></tr><tr><td>TOTAL</td><td>11,513,251</td><td>12,494,921</td><td>11,390,947</td></tr><tr><td>OPERATING EXPENSES</td><td></td><td></td><td></td></tr><tr><td>Operation and Maintenance:</td><td></td><td></td><td></td></tr><tr><td>Fuel, fuel-related expenses, and gas purchased for resale</td><td>2,452,171</td><td>2,632,558</td><td>2,445,818</td></tr><tr><td>Purchased power</td><td>1,390,805</td><td>1,915,414</td><td>1,554,332</td></tr><tr><td>Nuclear refueling outage expenses</td><td>251,316</td><td>267,679</td><td>256,801</td></tr><tr><td>Other operation and maintenance</td><td>3,354,981</td><td>3,310,536</td><td>3,331,934</td></tr><tr><td>Asset write-offs, impairments, and related charges</td><td>2,104,906</td><td>179,752</td><td>341,537</td></tr><tr><td>Decommissioning</td><td>280,272</td><td>272,621</td><td>242,104</td></tr><tr><td>Taxes other than income taxes</td><td>619,422</td><td>604,606</td><td>600,350</td></tr><tr><td>Depreciation and amortization</td><td>1,337,276</td><td>1,318,638</td><td>1,261,044</td></tr><tr><td>Other regulatory charges (credits) - net</td><td>175,304</td><td>(13,772)</td><td>45,597</td></tr><tr><td>TOTAL</td><td>11,966,453</td><td>10,488,032</td><td>10,079,517</td></tr><tr><td>Gain on sale of asset / business</td><td>154,037</td><td>—</td><td>43,569</td></tr><tr><td>OPERATING INCOME (LOSS)</td><td>(299,165)</td><td>2,006,889</td><td>1,354,999</td></tr><tr><td>OTHER INCOME</td><td></td><td></td><td></td></tr><tr><td>Allowance for equity funds used during construction</td><td>51,908</td><td>64,802</td><td>66,053</td></tr><tr><td>Interest and investment income</td><td>187,062</td><td>147,686</td><td>199,300</td></tr><tr><td>Miscellaneous - net</td><td>(95,997)</td><td>(42,016)</td><td>(59,762)</td></tr><tr><td>TOTAL</td><td>142,973</td><td>170,472</td><td>205,591</td></tr><tr><td>INTEREST EXPENSE</td><td></td><td></td><td></td></tr><tr><td>Interest expense</td><td>670,096</td><td>661,083</td><td>629,537</td></tr><tr><td>Allowance for borrowed funds used during construction</td><td>(26,627)</td><td>(33,576)</td><td>(25,500)</td></tr><tr><td>TOTAL</td><td>643,469</td><td>627,507</td><td>604,037</td></tr><tr><td>INCOME (LOSS) BEFORE INCOME TAXES</td><td>(799,661)</td><td>1,549,854</td><td>956,553</td></tr><tr><td>Income taxes</td><td>(642,927)</td><td>589,597</td><td>225,981</td></tr><tr><td>CONSOLIDATED NET INCOME (LOSS)</td><td>(156,734)</td><td>960,257</td><td>730,572</td></tr><tr><td>Preferred dividend requirements of subsidiaries</td><td>19,828</td><td>19,536</td><td>18,670</td></tr><tr><td>NET INCOME (LOSS) ATTRIBUTABLE TO ENERGY CORPORATION</td><td>($176,562)</td><td>$940,721</td><td>$711,902</td></tr><tr><td>Earnings (loss) per average common share:</td><td></td><td></td><td></td></tr><tr><td>Basic</td><td>($0.99)</td><td>$5.24</td><td>$3.99</td></tr><tr><td>Diluted</td><td>($0.99)</td><td>$5.22</td><td>$3.99</td></tr><tr><td>Basic average number of common shares outstanding</td><td>179,176,356</td><td>179,506,151</td><td>178,211,192</td></tr><tr><td>Diluted average number of common shares outstanding</td><td>179,176,356</td><td>180,296,885</td><td>178,570,400</td></tr></table>

See Notes to Financial Statements.



## ENTERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

<table><tr><td rowspan="3"></td><td colspan="3">For the Years Ended December 31,</td></tr><tr><td>2015</td><td>2014</td><td>2013</td></tr><tr><td colspan="3">(In Thousands)</td></tr><tr><td>Net Income (Loss)</td><td>($156,734)</td><td>$960,257</td><td>$730,572</td></tr><tr><td>Other comprehensive income (loss)</td><td></td><td></td><td></td></tr><tr><td>Cash flow hedges net unrealized gain (loss)</td><td></td><td></td><td></td></tr><tr><td>(net of tax expense (benefit) of $3,752, $96,141, and ($87,940))</td><td>7,852</td><td>179,895</td><td>(161,682)</td></tr><tr><td>Pension and other postretirement liabilities</td><td></td><td></td><td></td></tr><tr><td>(net of tax expense (benefit) of $61,576, ($152,763), and $220,899)</td><td>103,185</td><td>(281,566)</td><td>302,489</td></tr><tr><td>Net unrealized investment gains (losses)</td><td></td><td></td><td></td></tr><tr><td>(net of tax expense (benefit) of ($45,904), $66,594, and $118,878)</td><td>(59,138)</td><td>89,439</td><td>122,709</td></tr><tr><td>Foreign currency translation</td><td></td><td></td><td></td></tr><tr><td>(net of tax expense (benefit) of ($345), ($404), and $131)</td><td>(641)</td><td>(751)</td><td>243</td></tr><tr><td>Other comprehensive income (loss)</td><td>51,258</td><td>(12,983)</td><td>263,759</td></tr><tr><td>Comprehensive Income (Loss)</td><td>(105,476)</td><td>947,274</td><td>994,331</td></tr><tr><td>Preferred dividend requirements of subsidiaries</td><td>19,828</td><td>19,536</td><td>18,670</td></tr><tr><td>Comprehensive Income (Loss) Attributable to Entergy Corporation</td><td>($125,304)</td><td>$927,738</td><td>$975,661</td></tr></table>

See Notes to Financial Statements.



## ENTERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS

<table><tr><td rowspan="3"></td><td colspan="3">For the Years Ended December 31,</td></tr><tr><td>2015</td><td>2014</td><td>2013</td></tr><tr><td colspan="3">(In Thousands)</td></tr><tr><td>OPERATING ACTIVITIES</td><td></td><td></td><td></td></tr><tr><td>Consolidated net income (loss)</td><td>($156,734)</td><td>$960,257</td><td>$730,572</td></tr><tr><td>Adjustments to reconcile consolidated net income (loss) to net cash flow provided by operating activities:</td><td></td><td></td><td></td></tr><tr><td>Depreciation, amortization, and decommissioning, including nuclear fuel amortization</td><td>2,117,236</td><td>2,127,892</td><td>2,012,076</td></tr><tr><td>Deferred income taxes, investment tax credits, and non-current taxes accrued</td><td>(820,350)</td><td>596,935</td><td>311,789</td></tr><tr><td>Asset write-offs, impairments, and related charges</td><td>2,104,906</td><td>123,527</td><td>341,537</td></tr><tr><td>Gain on sale of asset / business</td><td>(154,037)</td><td>—</td><td>(43,569)</td></tr><tr><td>Changes in working capital:</td><td></td><td></td><td></td></tr><tr><td>Receivables</td><td>38,152</td><td>98,493</td><td>(180,648)</td></tr><tr><td>Fuel inventory</td><td>(12,376)</td><td>3,524</td><td>4,873</td></tr><tr><td>Accounts payable</td><td>(135,211)</td><td>(12,996)</td><td>94,436</td></tr><tr><td>Prepaid taxes and taxes accrued</td><td>81,969</td><td>(62,985)</td><td>(142,626)</td></tr><tr><td>Interest accrued</td><td>(11,445)</td><td>25,013</td><td>(3,667)</td></tr><tr><td>Deferred fuel costs</td><td>298,725</td><td>(70,691)</td><td>(4,824)</td></tr><tr><td>Other working capital accounts</td><td>(113,701)</td><td>112,390</td><td>(66,330)</td></tr><tr><td>Changes in provisions for estimated losses</td><td>42,566</td><td>301,871</td><td>(248,205)</td></tr><tr><td>Changes in other regulatory assets</td><td>262,317</td><td>(1,061,537)</td><td>1,105,622</td></tr><tr><td>Changes in other regulatory liabilities</td><td>61,241</td><td>87,654</td><td>397,341</td></tr><tr><td>Changes in pensions and other postretirement liabilities</td><td>(446,418)</td><td>1,308,166</td><td>(1,433,663)</td></tr><tr><td>Other</td><td>134,344</td><td>(647,952)</td><td>314,505</td></tr><tr><td>Net cash flow provided by operating activities</td><td>3,291,184</td><td>3,889,561</td><td>3,189,219</td></tr><tr><td>INVESTING ACTIVITIES</td><td></td><td></td><td></td></tr><tr><td>Construction/capital expenditures</td><td>(2,500,860)</td><td>(2,119,191)</td><td>(2,287,593)</td></tr><tr><td>Allowance for equity funds used during construction</td><td>53,635</td><td>68,375</td><td>69,689</td></tr><tr><td>Nuclear fuel purchases</td><td>(493,604)</td><td>(537,548)</td><td>(517,825)</td></tr><tr><td>Payment for purchase of plant</td><td>—</td><td>—</td><td>(17,300)</td></tr><tr><td>Proceeds from sale of assets and businesses</td><td>487,406</td><td>10,100</td><td>147,922</td></tr><tr><td>Insurance proceeds received for property damages</td><td>24,399</td><td>40,670</td><td>—</td></tr><tr><td>Changes in securitization account</td><td>(5,806)</td><td>1,511</td><td>155</td></tr><tr><td>NYPA value sharing payment</td><td>(70,790)</td><td>(72,000)</td><td>(71,736)</td></tr><tr><td>Payments to storm reserve escrow account</td><td>(69,163)</td><td>(276,057)</td><td>(7,716)</td></tr><tr><td>Receipts from storm reserve escrow account</td><td>5,916</td><td>—</td><td>260,279</td></tr><tr><td>Decrease (increase) in other investments</td><td>571</td><td>46,983</td><td>(82,955)</td></tr><tr><td>Litigation proceeds for reimbursement of spent nuclear fuel storage costs</td><td>18,296</td><td>—</td><td>21,034</td></tr><tr><td>Proceeds from nuclear decommissioning trust fund sales</td><td>2,492,176</td><td>1,872,115</td><td>2,031,552</td></tr><tr><td>Investment in nuclear decommissioning trust funds</td><td>(2,550,958)</td><td>(1,989,446)</td><td>(2,147,099)</td></tr><tr><td>Net cash flow used in investing activities</td><td>(2,608,782)</td><td>(2,954,488)</td><td>(2,601,593)</td></tr></table>

See Notes to Financial Statements.



## ENTERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS

<table><tr><td rowspan="3"></td><td colspan="3">For the Years Ended December 31,</td></tr><tr><td>2015</td><td>2014</td><td>2013</td></tr><tr><td colspan="3">(In Thousands)</td></tr><tr><td>FINANCING ACTIVITIES</td><td></td><td></td><td></td></tr><tr><td>Proceeds from the issuance of:</td><td></td><td></td><td></td></tr><tr><td>Long-term debt</td><td>3,502,189</td><td>3,100,069</td><td>3,746,016</td></tr><tr><td>Preferred stock of subsidiary</td><td>107,426</td><td>—</td><td>24,249</td></tr><tr><td>Treasury stock</td><td>24,366</td><td>194,866</td><td>24,527</td></tr><tr><td>Retirement of long-term debt</td><td>(3,461,518)</td><td>(2,323,313)</td><td>(3,814,666)</td></tr><tr><td>Repurchase of common stock</td><td>(99,807)</td><td>(183,271)</td><td>—</td></tr><tr><td>Repurchase / redemptions of preferred stock</td><td>(94,285)</td><td>—</td><td>—</td></tr><tr><td>Changes in credit borrowings and commercial paper - net</td><td>(104,047)</td><td>(448,475)</td><td>250,889</td></tr><tr><td>Other</td><td>(9,136)</td><td>23,579</td><td>—</td></tr><tr><td>Dividends paid:</td><td></td><td></td><td></td></tr><tr><td>Common stock</td><td>(598,897)</td><td>(596,117)</td><td>(593,037)</td></tr><tr><td>Preferred stock</td><td>(19,758)</td><td>(19,511)</td><td>(18,802)</td></tr><tr><td>Net cash flow used in financing activities</td><td>(753,467)</td><td>(252,173)</td><td>(380,824)</td></tr><tr><td>Effect of exchange rates on cash and cash equivalents</td><td>—</td><td>—</td><td>(245)</td></tr><tr><td>Net increase (decrease) in cash and cash equivalents</td><td>(71,065)</td><td>682,900</td><td>206,557</td></tr><tr><td>Cash and cash equivalents at beginning of period</td><td>1,422,026</td><td>739,126</td><td>532,569</td></tr><tr><td>Cash and cash equivalents at end of period</td><td>$1,350,961</td><td>$1,422,026</td><td>$739,126</td></tr><tr><td>SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:</td><td></td><td></td><td></td></tr><tr><td>Cash paid during the period for:</td><td></td><td></td><td></td></tr><tr><td>Interest - net of amount capitalized</td><td>$663,630</td><td>$611,376</td><td>$570,212</td></tr><tr><td>Income taxes</td><td>$103,589</td><td>$77,799</td><td>$127,735</td></tr></table>

See Notes to Financial Statements.



## ENTERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
ASSETS

<table><tr><td rowspan="3"></td><td colspan="2">December 31,</td></tr><tr><td>2015</td><td>2014</td></tr><tr><td colspan="2">(In Thousands)</td></tr><tr><td>CURRENT ASSETS</td><td></td><td></td></tr><tr><td>Cash and cash equivalents:</td><td></td><td></td></tr><tr><td>Cash</td><td>$63,497</td><td>$131,327</td></tr><tr><td>Temporary cash investments</td><td>1,287,464</td><td>1,290,699</td></tr><tr><td>Total cash and cash equivalents</td><td>1,350,961</td><td>1,422,026</td></tr><tr><td>Accounts receivable:</td><td></td><td></td></tr><tr><td>Customer</td><td>608,491</td><td>596,917</td></tr><tr><td>Allowance for doubtful accounts</td><td>(39,895)</td><td>(35,663)</td></tr><tr><td>Other</td><td>178,364</td><td>220,342</td></tr><tr><td>Accrued unbilled revenues</td><td>321,940</td><td>321,659</td></tr><tr><td>Total accounts receivable</td><td>1,068,900</td><td>1,103,255</td></tr><tr><td>Deferred fuel costs</td><td>—</td><td>155,140</td></tr><tr><td>Accumulated deferred income taxes</td><td>—</td><td>27,783</td></tr><tr><td>Fuel inventory - at average cost</td><td>217,810</td><td>205,434</td></tr><tr><td>Materials and supplies - at average cost</td><td>873,357</td><td>918,584</td></tr><tr><td>Deferred nuclear refueling outage costs</td><td>211,512</td><td>214,188</td></tr><tr><td>Prepayments and other</td><td>344,872</td><td>343,223</td></tr><tr><td>TOTAL</td><td>4,067,412</td><td>4,389,633</td></tr><tr><td>OTHER PROPERTY AND INVESTMENTS</td><td></td><td></td></tr><tr><td>Investment in affiliates - at equity</td><td>4,341</td><td>36,234</td></tr><tr><td>Decommissioning trust funds</td><td>5,349,953</td><td>5,370,932</td></tr><tr><td>Non-utility property - at cost (less accumulated depreciation)</td><td>219,999</td><td>213,791</td></tr><tr><td>Other</td><td>468,704</td><td>405,169</td></tr><tr><td>TOTAL</td><td>6,042,997</td><td>6,026,126</td></tr><tr><td>PROPERTY, PLANT, AND EQUIPMENT</td><td></td><td></td></tr><tr><td>Electric</td><td>44,467,159</td><td>44,881,419</td></tr><tr><td>Property under capital lease</td><td>952,465</td><td>945,784</td></tr><tr><td>Natural gas</td><td>392,032</td><td>377,565</td></tr><tr><td>Construction work in progress</td><td>1,456,735</td><td>1,425,981</td></tr><tr><td>Nuclear fuel</td><td>1,345,422</td><td>1,542,055</td></tr><tr><td>TOTAL PROPERTY, PLANT AND EQUIPMENT</td><td>48,613,813</td><td>49,172,804</td></tr><tr><td>Less - accumulated depreciation and amortization</td><td>20,789,452</td><td>20,449,858</td></tr><tr><td>PROPERTY, PLANT AND EQUIPMENT - NET</td><td>27,824,361</td><td>28,722,946</td></tr><tr><td>DEFERRED DEBITS AND OTHER ASSETS</td><td></td><td></td></tr><tr><td>Regulatory assets:</td><td></td><td></td></tr><tr><td>Regulatory asset for income taxes - net</td><td>775,528</td><td>836,064</td></tr><tr><td>Other regulatory assets (includes securitization property of $714,044 as of December 31, 2015 and $724,839 as of December 31, 2014)</td><td>4,704,796</td><td>4,968,553</td></tr><tr><td>Deferred fuel costs</td><td>238,902</td><td>238,102</td></tr><tr><td>Goodwill</td><td>377,172</td><td>377,172</td></tr><tr><td>Accumulated deferred income taxes</td><td>54,903</td><td>48,351</td></tr><tr><td>Other</td><td>561,610</td><td>807,508</td></tr><tr><td>TOTAL</td><td>6,712,911</td><td>7,275,750</td></tr><tr><td>TOTAL ASSETS</td><td>$44,647,681</td><td>$46,414,455</td></tr></table>

See Notes to Financial Statements.



## ENTERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
LIABILITIES AND EQUITY

<table><tr><td rowspan="3"></td><td colspan="2">December 31,</td></tr><tr><td>2015</td><td>2014</td></tr><tr><td colspan="2">(In Thousands)</td></tr><tr><td>CURRENT LIABILITIES</td><td></td><td></td></tr><tr><td>Currently maturing long-term debt</td><td>$214,374</td><td>$899,375</td></tr><tr><td>Notes payable and commercial paper</td><td>494,348</td><td>598,407</td></tr><tr><td>Accounts payable</td><td>1,071,798</td><td>1,166,431</td></tr><tr><td>Customer deposits</td><td>419,407</td><td>412,166</td></tr><tr><td>Taxes accrued</td><td>210,077</td><td>128,108</td></tr><tr><td>Accumulated deferred income taxes</td><td>—</td><td>38,039</td></tr><tr><td>Interest accrued</td><td>194,565</td><td>206,010</td></tr><tr><td>Deferred fuel costs</td><td>235,986</td><td>91,602</td></tr><tr><td>Obligations under capital leases</td><td>2,709</td><td>2,508</td></tr><tr><td>Pension and other postretirement liabilities</td><td>62,513</td><td>57,994</td></tr><tr><td>Other</td><td>184,181</td><td>248,251</td></tr><tr><td>TOTAL</td><td>3,089,958</td><td>3,848,891</td></tr><tr><td>NON-CURRENT LIABILITIES</td><td></td><td></td></tr><tr><td>Accumulated deferred income taxes and taxes accrued</td><td>8,306,865</td><td>9,133,161</td></tr><tr><td>Accumulated deferred investment tax credits</td><td>234,300</td><td>247,521</td></tr><tr><td>Obligations under capital leases</td><td>27,001</td><td>29,710</td></tr><tr><td>Other regulatory liabilities</td><td>1,414,898</td><td>1,383,609</td></tr><tr><td>Decommissioning and asset retirement cost liabilities</td><td>4,790,187</td><td>4,458,296</td></tr><tr><td>Accumulated provisions</td><td>460,727</td><td>418,128</td></tr><tr><td>Pension and other postretirement liabilities</td><td>3,187,357</td><td>3,638,295</td></tr><tr><td>Long-term debt (includes securitization bonds of $774,696 as of December 31, 2015 and $776,817 as of December 31, 2014)</td><td>13,111,556</td><td>12,386,710</td></tr><tr><td>Other</td><td>449,856</td><td>557,649</td></tr><tr><td>TOTAL</td><td>31,982,747</td><td>32,253,079</td></tr><tr><td>Commitments and Contingencies</td><td></td><td></td></tr><tr><td>Subsidiaries&#x27; preferred stock without sinking fund</td><td>318,185</td><td>210,760</td></tr><tr><td>EQUITY</td><td></td><td></td></tr><tr><td>Common Shareholders&#x27; Equity:</td><td></td><td></td></tr><tr><td>Common stock, \(.01 par value, authorized 500,000,000 shares; issued 254,752,788 shares in 2015 and in 2014</td><td>2,548</td><td>2,548</td></tr><tr><td>Paid-in capital</td><td>5,403,758</td><td>5,375,353</td></tr><tr><td>Retained earnings</td><td>9,393,913</td><td>10,169,657</td></tr><tr><td>Accumulated other comprehensive income (loss)</td><td>8,951</td><td>(42,307)</td></tr><tr><td>Less - treasury stock, at cost (76,363,763 shares in 2015 and 75,512,079 shares in 2014)</td><td>5,552,379</td><td>5,497,526</td></tr><tr><td>Total common shareholders&#x27; equity</td><td>9,256,791</td><td>10,007,725</td></tr><tr><td>Subsidiaries&#x27; preferred stock without sinking fund</td><td>—</td><td>94,000</td></tr><tr><td>TOTAL</td><td>9,256,791</td><td>10,101,725</td></tr><tr><td>TOTAL LIABILITIES AND EQUITY</td><td>$44,647,681</td><td>$46,414,455</td></tr></table>

See Notes to Financial Statements.



## ENTERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
For the Years Ended December 31, 2015, 2014, and 2013

<table><tr><td rowspan="2"></td><td colspan="7">Common Shareholders&#x27; Equity</td></tr><tr><td>Subsidiaries&#x27; Preferred Stock</td><td>Common Stock</td><td>Treasury Stock</td><td>Paid-in Capital</td><td>Retained Earnings</td><td>Accumulated Other Comprehensive Income (Loss)</td><td>Total</td></tr><tr><td></td><td></td><td></td><td colspan="5">(In Thousands)</td></tr><tr><td>Balance at December 31, 2012</td><td>$94,000</td><td>$2,548</td><td>($5,574,819)</td><td>$5,357,852</td><td>$9,704,591</td><td>($293,083)</td><td>$9,291,089</td></tr><tr><td>Consolidated net income (a)</td><td>18,670</td><td>—</td><td>—</td><td>—</td><td>711,902</td><td>—</td><td>730,572</td></tr><tr><td>Other comprehensive income</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>263,759</td><td>263,759</td></tr><tr><td>Common stock issuances related to stock plans</td><td>—</td><td>—</td><td>40,877</td><td>10,279</td><td>—</td><td>—</td><td>51,156</td></tr><tr><td>Common stock dividends declared</td><td>—</td><td>—</td><td>—</td><td>—</td><td>(591,440)</td><td>—</td><td>(591,440)</td></tr><tr><td>Preferred dividend requirements of subsidiaries (a)</td><td>(18,670)</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>(18,670)</td></tr><tr><td>Balance at December 31, 2013</td><td>$94,000</td><td>$2,548</td><td>($5,533,942)</td><td>$5,368,131</td><td>$9,825,053</td><td>($29,324)</td><td>$9,726,466</td></tr><tr><td>Consolidated net income (a)</td><td>19,536</td><td>—</td><td>—</td><td>—</td><td>940,721</td><td>—</td><td>960,257</td></tr><tr><td>Other comprehensive loss</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>(12,983)</td><td>(12,983)</td></tr><tr><td>Common stock repurchases</td><td>—</td><td>—</td><td>(183,271)</td><td>—</td><td>—</td><td>—</td><td>(183,271)</td></tr><tr><td>Common stock issuances related to stock plans</td><td>—</td><td>—</td><td>219,687</td><td>7,222</td><td>—</td><td>—</td><td>226,909</td></tr><tr><td>Common stock dividends declared</td><td>—</td><td>—</td><td>—</td><td>—</td><td>(596,117)</td><td>—</td><td>(596,117)</td></tr><tr><td>Preferred dividend requirements of subsidiaries (a)</td><td>(19,536)</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>(19,536)</td></tr><tr><td>Balance at December 31, 2014</td><td>$94,000</td><td>$2,548</td><td>($5,497,526)</td><td>$5,375,353</td><td>$10,169,657</td><td>($42,307)</td><td>$10,101,725</td></tr><tr><td>Consolidated net income (loss) (a)</td><td>19,828</td><td>—</td><td>—</td><td>—</td><td>(176,562)</td><td>—</td><td>(156,734)</td></tr><tr><td>Other comprehensive income</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>51,258</td><td>51,258</td></tr><tr><td>Common stock repurchases</td><td>—</td><td>—</td><td>(99,807)</td><td>—</td><td>—</td><td>—</td><td>(99,807)</td></tr><tr><td>Preferred stock repurchases / redemptions</td><td>(94,000)</td><td>—</td><td>—</td><td>—</td><td>(285)</td><td>—</td><td>(94,285)</td></tr><tr><td>Common stock issuances related to stock plans</td><td>—</td><td>—</td><td>44,954</td><td>28,405</td><td>—</td><td>—</td><td>73,359</td></tr><tr><td>Common stock dividends declared</td><td>—</td><td>—</td><td>—</td><td>—</td><td>(598,897)</td><td>—</td><td>(598,897)</td></tr><tr><td>Preferred dividend requirements of subsidiaries (a)</td><td>(19,828)</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>(19,828)</td></tr><tr><td>Balance at December 31, 2015</td><td>$—</td><td>$2,548</td><td>($5,552,379)</td><td>$5,403,758</td><td>$9,393,913</td><td>$8,951</td><td>$9,256,791</td></tr></table>

See Notes to Financial Statements.

(a) Consolidated net income and preferred dividend requirements of subsidiaries for 2015, 2014, and 2013 include $14.9 million, $12.9 million, and $12 million, respectively, of preferred dividends on subsidiaries' preferred stock without sinking fund that is not presented as equity.



# ENTERGY CORPORATION AND SUBSIDIARIES

# NOTES TO FINANCIAL STATEMENTS

## NOTE 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

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. The Registrant Subsidiaries and many other Entergy subsidiaries also maintain accounts in accordance with FERC and other regulatory guidelines.

## Use of Estimates in the Preparation of Financial Statements

In conformity with generally accepted accounting principles in the United States of America, the preparation of Entergy Corporation’s consolidated financial statements 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.

## Revenues and Fuel Costs

Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy Texas generate, transmit, and distribute electric power primarily to retail customers in Arkansas, Louisiana, Mississippi, and Texas, respectively. Entergy 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, including Algiers. Prior to October 1, 2015, Entergy Louisiana was the electric power supplier for Algiers. 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), the fuel factor remains in effect until changed as part of a general rate case, fuel reconciliation, or fixed fuel factor filing. System Energy’s operating revenues are intended to recover from Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans operating expenses and capital costs attributable to Grand Gulf. The capital costs are computed by allowing a return on System Energy’s common equity funds allocable to its net investment in Grand Gulf, plus System Energy’s effective interest cost for its debt allocable to its investment in Grand Gulf.



## Accounting for MISO transactions

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 nets purchases and sales within the MISO market on an hourly basis and reports in operating revenues when in a net selling position and in operating expenses when in a net purchasing position.

## Property, Plant, and Equipment

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, 2015 and 2014, is shown below:

<table><tr><td>2015</td><td>Entergy</td><td>Utility</td><td>Entergy Wholesale Commodities</td><td>Parent &amp; Other</td></tr><tr><td></td><td colspan="4">(In Millions)</td></tr><tr><td>Production</td><td></td><td></td><td></td><td></td></tr><tr><td>Nuclear</td><td>$8,672</td><td>$6,606</td><td>$2,066</td><td>$—</td></tr><tr><td>Other</td><td>3,176</td><td>3,127</td><td>49</td><td>—</td></tr><tr><td>Transmission</td><td>4,431</td><td>4,408</td><td>23</td><td>—</td></tr><tr><td>Distribution</td><td>7,207</td><td>7,207</td><td>—</td><td>—</td></tr><tr><td>Other</td><td>1,536</td><td>1,422</td><td>111</td><td>3</td></tr><tr><td>Construction work in progress</td><td>1,457</td><td>1,327</td><td>130</td><td>—</td></tr><tr><td>Nuclear fuel</td><td>1,345</td><td>857</td><td>489</td><td>—</td></tr><tr><td>Property, plant, and equipment - net</td><td>$27,824</td><td>$24,954</td><td>$2,868</td><td>$3</td></tr></table>



<table><tr><td>2014</td><td>Entergy</td><td>Utility</td><td>Entergy Wholesale Commodities</td><td>Parent &amp; Other</td></tr><tr><td></td><td></td><td colspan="3">(In Millions)</td></tr><tr><td>Production</td><td></td><td></td><td></td><td></td></tr><tr><td>Nuclear</td><td>$9,639</td><td>$6,586</td><td>$3,053</td><td>$—</td></tr><tr><td>Other</td><td>3,425</td><td>3,067</td><td>358</td><td>—</td></tr><tr><td>Transmission</td><td>4,197</td><td>4,164</td><td>33</td><td>—</td></tr><tr><td>Distribution</td><td>6,973</td><td>6,973</td><td>—</td><td>—</td></tr><tr><td>Other</td><td>1,521</td><td>1,373</td><td>145</td><td>3</td></tr><tr><td>Construction work in progress</td><td>1,426</td><td>969</td><td>456</td><td>1</td></tr><tr><td>Nuclear fuel</td><td>1,542</td><td>840</td><td>702</td><td>—</td></tr><tr><td>Property, plant, and equipment - net</td><td>$28,723</td><td>$23,972</td><td>$4,747</td><td>$4</td></tr></table>

Depreciation rates on average depreciable property for Entergy approximated 2.9% in 2015, 2.8% in 2014, and 2.6% in 2013. Included in these rates are the depreciation rates on average depreciable Utility property of 2.7% in 2015, 2.5% in 2014, and 2.5% in 2013, and the depreciation rates on average depreciable Entergy Wholesale Commodities property of 5.4% in 2015, 5.5% in 2014, and 4.1% in 2013. 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 $163.8 million and $185.5 million as of December 31, 2015 and 2014, respectively.

Construction expenditures included in accounts payable is $234 million and $209 million at December 31, 2015 and 2014, respectively.

## Jointly-Owned Generating Stations

Certain Entergy subsidiaries jointly own electric generating facilities with affiliates or third parties. All parties are required to provide their own financing. The investments, fuel expenses, and other operation and maintenance 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, 2015, the subsidiaries' investment and accumulated depreciation in each of these generating stations were as follows:



<table><tr><td>Generating Stations</td><td>Fuel-Type</td><td>Total Megawatt Capability (a)</td><td>Ownership</td><td>Investment</td><td>Accumulated Depreciation</td></tr><tr><td>Utility business:</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Entergy Arkansas -</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td rowspan="2">Independence</td><td>Unit 1</td><td>Coal</td><td>839</td><td>31.50%</td><td>$134</td></tr><tr><td>Common Facilities</td><td>Coal</td><td></td><td>15.75%</td><td>$33</td></tr><tr><td>White Bluff</td><td>Units 1 and 2</td><td>Coal</td><td>1,637</td><td>57.00%</td><td>$520</td></tr><tr><td>Ouachita (b)</td><td>Common Facilities</td><td>Gas</td><td>489</td><td>66.67%</td><td>$170</td></tr><tr><td>Entergy Louisiana -</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Roy S. Nelson</td><td>Unit 6</td><td>Coal</td><td>537</td><td>40.25%</td><td>$274</td></tr><tr><td>Roy S. Nelson</td><td>Unit 6 Common Facilities</td><td>Coal</td><td></td><td>17.26%</td><td>$11</td></tr><tr><td>Big Cajun 2</td><td>Unit 3</td><td>Coal</td><td>594</td><td>24.15%</td><td>$151</td></tr><tr><td>Ouachita (b)</td><td>Common Facilities</td><td>Gas</td><td>243</td><td>33.33%</td><td>$87</td></tr><tr><td>Acadia</td><td>Common Facilities</td><td>Gas</td><td>551</td><td>50.00%</td><td>$19</td></tr><tr><td>Entergy Mississippi -</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Independence</td><td>Units 1 and 2 and Common Facilities</td><td>Coal</td><td>1,681</td><td>25.00%</td><td>$258</td></tr><tr><td>Entergy Texas -</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Roy S. Nelson</td><td>Unit 6</td><td>Coal</td><td>537</td><td>29.75%</td><td>$197</td></tr><tr><td>Roy S. Nelson</td><td>Unit 6 Common Facilities</td><td>Coal</td><td></td><td>12.75%</td><td>$6</td></tr><tr><td>Big Cajun 2</td><td>Unit 3</td><td>Coal</td><td>594</td><td>17.85%</td><td>$113</td></tr><tr><td>System Energy -</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Grand Gulf</td><td>Unit 1</td><td>Nuclear</td><td>1,409</td><td>90.00% (c)</td><td>$4,829</td></tr><tr><td>Entergy Wholesale Commodities:</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Independence</td><td>Unit 2</td><td>Coal</td><td>842</td><td>14.37%</td><td>$71</td></tr><tr><td>Independence</td><td>Common Facilities</td><td>Coal</td><td></td><td>7.18%</td><td>$16</td></tr><tr><td>Roy S. Nelson</td><td>Unit 6</td><td>Coal</td><td>537</td><td>10.90%</td><td>$111</td></tr><tr><td>Roy S. Nelson</td><td>Unit 6 Common Facilities</td><td>Coal</td><td></td><td>4.67%</td><td>$2</td></tr></table>

(a) “Total Megawatt Capability” is the dependable load carrying capability as demonstrated under actual operating conditions based on the primary fuel (assuming no curtailments) that each station was designed to utilize.

(b) Ouachita Units 1 and 2 are owned 100% by Entergy Arkansas and Ouachita Unit 3 is owned 100% by Entergy Louisiana. The investment and accumulated depreciation numbers above are only for the common facilities and not for the generating units.

(c) Includes a leasehold interest held by System Energy. System Energy’s Grand Gulf lease obligations are discussed in Note 10 to the financial statements.



## Nuclear Refueling Outage Costs

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.

## Allowance for Funds Used During Construction (AFUDC)

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.

## Income Taxes

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 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.

Effective December 31, 2015, Entergy prospectively adopted ASU 2015-17, which simplifies the presentation of deferred taxes. Beginning with the December 31, 2015 balances, all deferred taxes will be classified as non-current. Periods prior to December 31, 2015 were not retrospectively adjusted.

The benefits of investment tax credits are deferred and amortized 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.

## Earnings (Loss) per Share

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

For the Years Ended December 31,

<table><tr><td></td><td>2015</td><td colspan="2">2014</td><td colspan="2">2013</td></tr><tr><td></td><td colspan="5">(In Millions, Except Per Share Data)</td></tr><tr><td></td><td>$/share</td><td colspan="2">\)/share</td><td colspan="2">\(/share</td></tr><tr><td>Net income (loss) attributable to Entergy Corporation</td><td>($176.6)</td><td colspan="2">$940.7</td><td colspan="2">$711.9</td></tr><tr><td>Basic earnings (loss) per average common share</td><td>179.2</td><td>($0.99)</td><td>179.5</td><td>$5.24</td><td>178.2</td></tr><tr><td>Average dilutive effect of:</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Stock options</td><td>—</td><td>—</td><td>0.3</td><td>(0.01)</td><td>0.1</td></tr><tr><td>Other equity plans</td><td>—</td><td>—</td><td>0.5</td><td>(0.01)</td><td>0.3</td></tr><tr><td>Diluted earnings (loss) per average common shares</td><td>179.2</td><td>($0.99)</td><td>180.3</td><td>$5.22</td><td>178.6</td></tr></table>



The calculation of diluted earnings (loss) per share excluded 7,399,820 options outstanding at December 31, 2015, 5,743,013 options outstanding at December 31, 2014, and 8,866,542 options outstanding at December 31, 2013.

## Stock-based Compensation Plans

Entergy grants stock options, restricted stock, performance units, and restricted stock unit 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.

## Accounting for the Effects of Regulation

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 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, unless specific cost recovery is 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 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.

## Regulatory Asset for Income Taxes

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 regulatory asset for income taxes is related to the ratemaking treatment of the tax effects of book depreciation for the equity component of AFUDC that has been capitalized to property, plant, and equipment but for which there is no corresponding tax basis. Equity-AFUDC is a component of property, plant, and equipment that is included in rate base when the plant is placed in service.

## Cash and Cash Equivalents

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



## Allowance for Doubtful Accounts

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.

## Investments

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 for the unrealized gains/(losses) on investment securities. For the 30% interest in River Bend formerly owned by Cajun, Entergy Louisiana has recorded an offsetting amount in other deferred credits for the unrealized gains/(losses). 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. 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.

## Equity Method Investments

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 decrease to the investment account. Any cash distributions are charged against the 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.

## Derivative Financial Instruments and Commodity Derivatives

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 sale 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.

## Fair Values

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 held by regulated businesses may be 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. See Note 16 to the financial statements for further discussion of fair value.

## Impairment of Long-Lived Assets

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 and capacity 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 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. Indian Point 2 reached the expiration date of its original NRC operating license on September 28, 2013, and Indian Point 3 reached the expiration date of its original NRC operating license on December 12, 2015. Upon expiration of their operating licenses, each plant entered into a period of extended operation under the timely renewal rule. 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.

Entergy determined in October 2015 that it will close FitzPatrick at the end of its current fuel cycle, which is planned for January 27, 2017, because of poor market conditions that have led to reduced revenues, a poor market design that fails to properly compensate nuclear generators for the benefits they provide, and increased operational costs. This decision came after management’s extensive analysis of whether it was advisable economically to refuel the plant,



as scheduled, in the fall of 2016. Entergy also had discussions with the State of New York regarding the future of FitzPatrick. Because of the uncertainty regarding the refueling decision and its implications to the plant’s expected operating life, Entergy tested the recoverability of the plant and related assets as of September 30, 2015.

Entergy determined in October 2015 that it will close Pilgrim no later than June 1, 2019 because of poor market conditions that have led to reduced revenues, a poor market design that fails to properly compensate nuclear generators for the benefits they provide, and increased operational costs. The decision came after management’s extensive analysis of the economics and operating life of the plant following the NRC’s decision in September 2015 to place the plant in Column 4 of the Reactor Oversight Process Action Matrix. Because of the uncertainty regarding the plant’s operating life created by the NRC’s decision and management’s analysis of the plant, Entergy tested the recoverability of the plant and related assets as of September 30, 2015.

Due to the announced plant closures in October 2015, as well as the continued challenging market price trend, the high level of investment required to continue to operate the Entergy Wholesale Commodities plants, and the inadequate compensation provided to nuclear generators for their capacity benefits under the current market design, Entergy tested the recoverability of the plant and related assets of the two remaining operating nuclear power generating facilities in the Entergy Wholesale Commodities business, Palisades and Indian Point, in the fourth quarter 2015. For purposes of that evaluation, Entergy considered a number of factors associated with the facilities' continued operation, including the status of the associated NRC licenses, the status of state regulatory issues, existing power purchase agreements, and the supply region in which the nuclear facilities sell energy and capacity.

Under generally accepted accounting principles the determination of an asset’s recoverability is based on the probability-weighted undiscounted net cash flows expected to be generated by the plant and related assets. Projected net cash flows primarily depend on the status of the operations of the plant and pending legal and state regulatory matters, as well as projections of future revenues and costs over the estimated remaining life of the plant.

The tests for FitzPatrick and Pilgrim indicated that the probability-weighted undiscounted net cash flows did not exceed the carrying values of the plants and related assets as of September 30, 2015.

The test for Palisades indicated the probability-weighted undiscounted net cash flows did not exceed the carrying value of the plant and related assets as of December 31, 2015.

The test for Indian Point indicated that the probability-weighted undiscounted net cash flows exceeded the carrying value of the plant and related assets as of December 31, 2015. As such, the carrying value of Indian Point was not impaired as of December 31, 2015. As of December 31, 2015, the net carrying value of Indian Point, including nuclear fuel, is $2,360 million.

As a result of the impairment analyses, Entergy recognized non-cash impairment and other related charges of $1,642 million ($1,062 million net-of-tax) during the third quarter 2015 to write down the carrying values of the FitzPatrick and Pilgrim plants and related assets to their fair values. In the fourth quarter 2015, Entergy recognized non-cash impairment and other related charges of $396 million ($256 million net-of-tax) to write down the carrying value of the Palisades plant and related assets to their fair values, as well as additional charges related to the plant closure decisions at FitzPatrick and Pilgrim. Entergy performed fair value analyses based on the income approach, a discounted cash flow method, to determine the amount of impairment.

The estimated fair value of the FitzPatrick plant and related long-lived assets is $29 million, while the carrying value was $742 million, resulting in an impairment charge of $713 million. Materials and supplies were evaluated and written down by $48 million. In addition, FitzPatrick has a contract asset recorded for an agreement between Entergy subsidiaries and NYPA entered when Entergy subsidiaries purchased FitzPatrick from NYPA in 2000 and NYPA retained the decommissioning trusts and the decommissioning liabilities. NYPA has the right to require the Entergy subsidiaries to assume the decommissioning liability provided that it assigns the decommissioning trust, up to a specified level, to Entergy. If the decommissioning liabilities are retained by NYPA, the Entergy subsidiaries will perform the



decommissioning of the plant at a price equal to the lesser of a pre-specified level or the amount in the decommissioning trusts. The contract asset represents an estimate of the present value of the difference between the Entergy subsidiaries' stipulated contract amount for decommissioning the plants less the decommissioning costs estimated in independent decommissioning cost studies. See Note 9 for further discussion of the contract asset. Due to a change in expectation regarding the timing of decommissioning cash flows, the result was a write down of the contract asset from $335 million to $131 million, for a charge of $204 million. In summary, the impairment and related charges for FitzPatrick total $965 million ($624 million net-of-tax).

The estimated fair value of the Pilgrim plant and related long-lived assets is $65 million, while the carrying value was $718 million, resulting in an impairment charge of $653 million. Materials and supplies were evaluated and written down by $24 million. In summary, the total impairment loss and related charges for Pilgrim is $677 million ($438 million net-of-tax). The pre-impairment carrying value of $718 million includes the effect of a $134 million increase in Pilgrim’s estimated decommissioning cost liability and the related asset retirement cost asset. The increase in the estimated decommissioning cost liability primarily resulted from the change in expectation regarding the timing of decommissioning cash flows.

The estimated fair value of the Palisades plant and related long-lived assets is $463 million, while the carrying value was $859 million, resulting in an impairment charge of $396 million ($256 million net-of-tax). The pre-impairment carrying value of $859 million includes the effect of a $42 million increase in Palisades' estimated decommissioning cost liability and the related asset retirement cost asset. The increase in the estimated decommissioning cost liability primarily resulted from assessment of the estimated decommissioning cash flows that occurred in conjunction with the impairment analysis.

In August 2013, the Board approved a plan to close and decommission Vermont Yankee at the end of its fuel cycle at the end of 2014. 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 million ($183.7 million net-of-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 million, while the carrying value was $349 million. The carrying value of $349 million reflected the effect of a $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.

As a result of a settlement agreement entered into in 2013 by Entergy and Vermont regarding the remaining operation and decommissioning of Vermont Yankee, 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 decommissioning cost liability and a corresponding impairment charge, recorded in December 2013. 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, recorded in September 2014. Impairment charges are recorded as a separate line item in Entergy’s consolidated statements of income for 2014 and 2013, and this impairment charge is included within the results of the Entergy Wholesale Commodities segment.

The impairments and other related charges are recorded as a separate line item in Entergy’s consolidated statements of operations and are included within the results of the Entergy Wholesale Commodities segment. In addition to the impairments and other related charges, Entergy incurred $46 million in 2014 and $8 million in 2015, and expects



to incur additional charges from 2016 into mid-2019 estimated to be up to approximately $175 million for severance and employee retention costs relating to the decisions to shut down Vermont Yankee, FitzPatrick, and Pilgrim.

The estimates of fair value were based on the prices that Entergy would expect to receive in hypothetical sales of the FitzPatrick, Pilgrim, Palisades, and Vermont Yankee plants and related assets to a market participant. In order to determine these prices, 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 plants and related assets as well as the amount and timing of recoveries from future litigation with the DOE related to spent fuel storage costs. 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, are 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 FitzPatrick, Pilgrim, Palisades, and Vermont Yankee plants and related assets:

<table><tr><td>Significant Unobservable Inputs</td><td>Amount</td><td>Weighted Average</td></tr><tr><td>Weighted average cost of capital</td><td></td><td></td></tr><tr><td>FitzPatrick</td><td>7.5%</td><td>7.5%</td></tr><tr><td>Pilgrim (a)</td><td>7.5%-8.0%</td><td>7.9%</td></tr><tr><td>Palisades</td><td>7.5%</td><td>7.5%</td></tr><tr><td>Vermont Yankee</td><td>7.5%</td><td>7.5%</td></tr><tr><td>Long-term pre-tax operating margin (cash basis)</td><td></td><td></td></tr><tr><td>FitzPatrick</td><td>10.2%</td><td>10.2%</td></tr><tr><td>Pilgrim (a)</td><td>2.4%-10.6%</td><td>8.1%</td></tr><tr><td>Palisades (b)</td><td>30.8%</td><td>30.8%</td></tr><tr><td>Vermont Yankee</td><td>7.0%</td><td>7.0%</td></tr></table>

(a) The fair value of Pilgrim was based on the probability weighting of two potential scenarios.

(b) Most of the Palisades output is sold under a 15-year power purchase agreement, entered at the plant’s acquisition in 2007, that expires in 2022. The power purchase agreement prices currently exceed market prices and escalate each year, up to $61.50/MWh in 2022.

Entergy’s Accounting Policy group, which reports to the Chief Accounting Officer, was primarily responsible for determining the valuation of the FitzPatrick, Pilgrim, Palisades, and Vermont Yankee plants and related assets, in consultation with external advisors. Entergy’s Accounting Policy group obtained and reviewed information from other Entergy departments with expertise on the various inputs and assumptions that were necessary to calculate the fair values of the asset groups.

## River Bend AFUDC

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 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.



## Reacquired Debt

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 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.

## Debt Issuance Costs

In the fourth quarter 2015, Entergy adopted ASU No. 2015-03 “Interest-Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs” and ASU No. 2015-15 “Interest-Imputation of Interest (Subtopic 835-30): Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements.”

For all periods presented in this report, debt issuance costs related to a note are reported in the balance sheet as a reduction of the carrying value of the related debt, and debt issuance costs related to revolving credit facilities are reported in Other deferred debits separately from the amounts owed under such facility. Prior to adoption, Entergy reported both types of debt issuance costs in Other deferred debits. The change resulted in a reduction of both Other deferred debits and Long-term debt for all prior periods presented.

## Taxes Imposed on Revenue-Producing Transactions

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.

## Presentation of Preferred Stock without Sinking Fund

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 Louisiana, a limited liability company, had outstanding preferred securities with similar protective rights with respect to unpaid dividends, but provided for the election of board members that would not constitute a majority of the board; and its preferred securities were therefore classified as a component of members' equity. In September 2015, Entergy Louisiana redeemed or repurchased and canceled its preferred membership interests as part of a multi-step process to effectuate the Entergy Louisiana and Entergy Gulf States Louisiana business combination. See Note 2 to the financial statements for a discussion of the business combination.

The outstanding preferred securities of Entergy Arkansas, Entergy Mississippi, and Entergy New Orleans, and Entergy Utility Holding Company (a Utility subsidiary) 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 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.



## New Accounting Pronouncements

The accounting standard-setting process, including projects between the FASB and the International Accounting Standards Board (IASB) to converge U.S. GAAP and International Financial Reporting Standards, is ongoing and the FASB and the IASB are each currently working on several projects. Final pronouncements that result from these projects could have a material effect on Entergy’s future net income, 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. In August 2015, the FASB issued ASU No. 2015-14, “Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date” which deferred the effective date of ASU 2014-09 for all entities by one year. Accordingly, ASU 2014-09 is effective for Entergy for the first quarter 2018. 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.

In February 2015 the FASB issued ASU No. 2015-02, “Consolidation (Topic 810): Amendments to the Consolidation Analysis” which changes the analysis that a reporting entity must perform to determine whether it should consolidate certain types of legal entities. The ASU affects (1) limited partnerships and similar legal entities, (2) evaluating fees paid to a decision maker or a service provider as a variable interest, (3) the effect of fee arrangements on the primary beneficiary determination, (4) the effect of related parties on the primary beneficiary determination, and (5) certain investment funds. ASU 2015-02 is effective for Entergy for the first quarter 2016. Entergy does not expect ASU 2015-02 to affect materially its results of operations, financial position, or cash flows.

In January 2016 the FASB issued ASU No. 2016-01 “Financial Instruments (Subtopic 825-10): Recognition and Measurement of Financial Assets and Financial Liabilities.” The ASU requires equity investments, excluding those accounted for under the equity method or resulting in consolidation of the investee, to be measured at fair value with changes recognized in net income. The ASU requires a qualitative assessment to identify impairments of equity investments without readily determinable fair value. ASU 2016-01 is effective for Entergy for the first quarter 2018. Entergy expects that ASU 2016-01 will affect its results of operations by requiring unrealized gains and losses on equity investments held by the nuclear decommissioning trust funds to be recorded in earnings rather than in other comprehensive income. In accordance with the regulatory treatment of the decommissioning trust funds of Entergy Arkansas, Entergy Louisiana, and System Energy, an offsetting amount of unrealized gains/losses will continue to be recorded in other regulatory liabilities/assets. Entergy is evaluating the ASU for other effects on the results of operations, financial position, and cash flows.



## Entergy Louisiana Basis of Presentation

As discussed in more detail in Note 2 to the financial statements, on October 1, 2015, the businesses formerly conducted by Entergy Louisiana (Old Entergy Louisiana) and Entergy Gulf States Louisiana (Old Entergy Gulf States Louisiana) were combined into a single public utility. With the completion of the business combination, Entergy Louisiana holds substantially all of the assets, and has assumed the liabilities, of Old Entergy Louisiana and Old Entergy Gulf States Louisiana. The combination was accounted for as a transaction between entities under common control. The effect of the business combination has been retrospectively applied to Entergy Louisiana's financial statements that are presented in this report.

## Entergy New Orleans Basis of Presentation

On September 1, 2015, Entergy Louisiana transferred its Algiers assets to Entergy New Orleans for a purchase price of approximately $85 million, subject to closing adjustments. Entergy New Orleans paid Entergy Louisiana $59.6 million, including final true-ups, from available cash and issued a note payable to Entergy Louisiana in the amount of $25.5 million. Because the asset transfer was a transaction involving entities under common control, Entergy New Orleans recognized the assets and liabilities transferred to it at their carrying amounts in the accounts of Entergy Louisiana at the time of the asset transfer. The effect of the Algiers transfer has been retrospectively applied to Entergy New Orleans’s financial statements that are presented in this report.

## NOTE 2. RATE AND REGULATORY MATTERS

## Regulatory Assets and Regulatory Liabilities

Regulatory assets represent probable future revenues associated with costs that Entergy expects to recover from customers through the regulatory ratemaking process under which the Utility business operates. Regulatory liabilities represent probable future reductions in revenues associated with amounts that Entergy expects to benefit customers through the regulatory ratemaking process under which the Utility business operates. In addition to the regulatory assets and liabilities that are specifically disclosed on the face of the balance sheets, the tables below provide detail of “Other regulatory assets” and “Other regulatory liabilities” that are included on Entergy’s balance sheets as of December 31, 2015 and 2014:



## Other Regulatory Assets

Entergy

<table><tr><td></td><td>2015</td><td>2014</td></tr><tr><td></td><td colspan="2">(In Millions)</td></tr><tr><td>Pension &amp; postretirement costs (Note 11 - Qualified Pension Plans, Other Postretirement Benefits, and Non-Qualified Pension Plans) (a)</td><td>$2,574.9</td><td>$2,798.8</td></tr><tr><td>Storm damage costs, including hurricane costs - recovered through securitization and retail rates (Note 2 - Storm Cost Recovery Filings with Retail Regulators) (Note 5 - Entergy Arkansas Securitization Bonds)</td><td>717.8</td><td>736.2</td></tr><tr><td>Asset retirement obligation - recovery dependent upon timing of decommissioning of nuclear units or dismantlement of non-nuclear power plants (Note 9) (a)</td><td>589.1</td><td>513.8</td></tr><tr><td>Removal costs - recovered through depreciation rates (Note 9) (a)</td><td>273.3</td><td>245.1</td></tr><tr><td>Little Gypsy costs - recovered through securitization (Note 5 - Entergy Louisiana Securitization Bonds - Little Gypsy)</td><td>121.1</td><td>139.2</td></tr><tr><td>Unamortized loss on reacquired debt - recovered over term of debt</td><td>66.7</td><td>76.2</td></tr><tr><td>Transition to competition costs - recovered over a 15-year period through February 2021</td><td>57.4</td><td>66.2</td></tr><tr><td>New nuclear generation development costs (Note 2 - New Nuclear Generation Development Costs) (b)</td><td>51.1</td><td>58.4</td></tr><tr><td>MISO implementation costs - recovery through retail rate riders (Note 2 - Retail Rate Proceedings)</td><td>49.4</td><td>69.6</td></tr><tr><td>Retail rate deferrals - recovered through rate riders as rates are redetermined by retail regulators</td><td>32.2</td><td>54.7</td></tr><tr><td>Human capital management costs - recovery through retail rate mechanisms (Note 2 - Retail Rate Proceedings)</td><td>28.3</td><td>42.3</td></tr><tr><td>Other</td><td>143.5</td><td>168.1</td></tr><tr><td>Entergy Total</td><td>$4,704.8</td><td>$4,968.6</td></tr></table>

(a) Does not earn a return on investment, but is offset by related liabilities.

(b) Does not earn a return on investment.



## Other Regulatory Liabilities

Entergy

<table><tr><td></td><td>2015</td><td>2014</td></tr><tr><td></td><td colspan="2">(In Millions)</td></tr><tr><td>Unrealized gains on nuclear decommissioning trust funds (Note 17) (a)</td><td>$611.7</td><td>$656.7</td></tr><tr><td>Vidalia purchased power agreement (Note 8)</td><td>222.6</td><td>242.8</td></tr><tr><td>Louisiana Act 55 financing savings obligation (Note 2)</td><td>156.0</td><td>156.0</td></tr><tr><td>Business combination guaranteed customer benefits - returned to customers through retail rates and fuel rates beginning December 2015 through November 2024 (Note 2 - Entergy Louisiana and Entergy Gulf States Louisiana Business Combination)</td><td>105.2</td><td>—</td></tr><tr><td>Removal costs - returned to customers through depreciation rates (Note 9) (a)</td><td>68.3</td><td>82.7</td></tr><tr><td>Grand Gulf sale-leaseback - (Note 10 - Sale and Leaseback Transactions)</td><td>67.9</td><td>79.5</td></tr><tr><td>Entergy Mississippi&#x27;s accumulated accelerated Grand Gulf amortization - amortized and credited through the UPSA</td><td>46.4</td><td>53.6</td></tr><tr><td>Entergy Arkansas&#x27;s accumulated accelerated Grand Gulf amortization - will be returned to customers when approved by the APSC and FERC</td><td>44.4</td><td>44.4</td></tr><tr><td>Waterford 3 replacement steam generator provision (Note 2 - Retail Rate Proceedings)</td><td>31.7</td><td>—</td></tr><tr><td>Asset retirement obligation - will be returned to customers dependent upon timing of decommissioning (Note 9) (a)</td><td>28.2</td><td>27.7</td></tr><tr><td>Other</td><td>32.5</td><td>40.2</td></tr><tr><td>Entergy Total</td><td>$1,414.9</td><td>$1,383.6</td></tr></table>

(a) Offset by related asset.

## Fuel and purchased power cost recovery

Entergy Arkansas, 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, 2015 and 2014 that Entergy expects to recover (or return to customers) through fuel mechanisms, subject to subsequent regulatory review.

<table><tr><td></td><td>2015</td><td>2014</td></tr><tr><td></td><td colspan="2">(In Millions)</td></tr><tr><td>Entergy Arkansas (a)</td><td>$57.8</td><td>$209.2</td></tr><tr><td>Entergy Louisiana (b)</td><td>$102.9</td><td>$107.1</td></tr><tr><td>Entergy Mississippi</td><td>($107.8)</td><td>($2.2)</td></tr><tr><td>Entergy New Orleans (b)</td><td>($24.9)</td><td>($25.1)</td></tr><tr><td>Entergy Texas</td><td>($25.1)</td><td>$11.9</td></tr></table>

(a) 2015 and 2014 include respectively $66.7 million and $65.9 million for Entergy Arkansas of fuel, purchased power, and capacity costs, which do not currently earn a return on investment and whose recovery periods are indeterminate but are expected to be recovered over a period greater than twelve months.



(b) 2015 and 2014 include $168.1 million for Entergy Louisiana and $4.1 million for Entergy New Orleans of fuel, purchased power, and capacity costs, which do not currently earn a return on investment and whose recovery periods are indeterminate but are expected to be recovered over a period greater than twelve months.

## Entergy Arkansas

## Production Cost Allocation Rider

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.

In May 2015, Entergy Arkansas filed its annual redetermination of the production cost allocation rider, which included a $38 million payment made by Entergy Arkansas as a result of the FERC’s February 2014 order related to the comprehensive bandwidth recalculation for calendar year 2006, 2007, and 2008 production costs. The redetermined rate for the 2015 production cost allocation rider update was added to the redetermined rate from the 2014 production cost allocation rider update and the combined rate was effective with the first billing cycle of July 2015. This combined rate was effective through December 2015. The collection of the remainder of the redetermined rate for the 2015 production cost allocation rider update will continue through June 2016.

## Energy Cost Recovery Rider

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 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 was 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 that was 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 Louisiana

Entergy Louisiana recovers 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 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 has ceased and the parties are awaiting issuance of the audit report of the LPSC staff, 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 has ceased and the parties are awaiting issuance of the audit report of the LPSC staff, 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 commenced in July 2015.

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 commenced in July 2015.

## Entergy Mississippi

Entergy Mississippi’s rate schedules include an energy cost recovery rider that 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.

Entergy Mississippi had a deferred fuel over-recovery balance of $58.3 million as of May 31, 2015, along with an under-recovery balance of $12.3 million under the power management rider. Pursuant to those tariffs, in July 2015, Entergy Mississippi filed for interim adjustments under both the energy cost recovery rider and the power management rider to flow through to customers the approximately $46 million net over-recovery over a six-month period. In August 2015, the MPSC approved the interim adjustments effective with September 2015 bills. In November 2015, Entergy Mississippi filed its annual redetermination of the annual factor to be applied under the energy cost recovery rider. The calculation of the annual factor included a projected over-recovery balance of $48 million projected through January 31, 2016. In January 2016 the MPSC approved the redetermined annual factor effective February 1, 2016. The MPSC further ordered, however, that due to the significant change in natural gas price forecasts since Entergy Mississippi’s filing in November 2015 Entergy Mississippi shall file a revised fuel factor with the MPSC no later than February 1, 2016. In February 2016, Entergy Mississippi submitted a revised fuel factor reflecting a natural gas price of $2.45 per MMBtu.

## Mississippi Attorney General Complaint

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 defendant Entergy companies removed the Attorney General’s lawsuit to U.S. District Court in Jackson, Mississippi. The Mississippi attorney general moved to remand the matter to state court. In August 2012 the District Court issued an



opinion denying the Attorney General’s motion for remand, finding that the District Court has subject matter jurisdiction under the Class Action Fairness Act.

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.

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 considered “mass actions” under the Class Action Fairness Act, so as to establish federal subject matter jurisdiction. One day later the Attorney General renewed his motion to remand the Entergy case back to state court, citing the U.S. Supreme Court’s decision. The defendant Entergy companies responded to that motion reiterating the additional grounds asserted for federal question jurisdiction, and the District Court held oral argument on the renewed motion to remand in February 2014. In April 2015 the District Court entered an order denying the renewed motion to remand, holding that the District Court has federal question subject matter jurisdiction. The Attorney General appealed to the U.S. Fifth Circuit Court of Appeals the denial of the motion to remand. In July 2015 the Fifth Circuit issued an order denying the appeal, and the Attorney General subsequently filed a petition for rehearing of the request for interlocutory appeal, which was also denied. The case remains pending in federal district court, awaiting a ruling on the Entergy companies’ motion for judgment on the pleadings. In December 2015 the District Court ordered that the parties submit to the court undisputed and disputed facts that are material to the Entergy defendants’ motion for judgment on the pleadings, as well as supplemental briefs regarding the same. Those filings were made in January 2016.

## Entergy New Orleans

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

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 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 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, and all parties agreed that the proceeding should be bifurcated such that the proposed interim refund would become final in a separate proceeding, which refund was approved by the PUCT in March 2015. In July 2015 certain parties filed briefs in the open proceeding asserting that Entergy Texas should refund to retail customers an additional $10.9 million in bandwidth remedy payments Entergy Texas received related to calendar year 2006 production costs. In October 2015 an ALJ issued a proposal for decision recommending that the additional $10.9 million in bandwidth remedy payments be refunded to retail customers. In January 2016 the PUCT issued its order affirming the ALJ’s recommendation, and Entergy Texas filed a motion for rehearing of the PUCT’s decision, which the PUCT denied.

At the 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, but will continue to evaluate the benefits of utilizing the new rider to recover future capacity costs.

## Retail Rate Proceedings

## Filings with the APSC (Entergy Arkansas)

## Retail Rates

## 2013 Base Rate Filing

In March 2013, Entergy Arkansas filed with the APSC for a general change in rates, charges, and tariffs. The filing assumed Entergy Arkansas’s transition to MISO in December 2013, and requested a rate increase of $174 million, including $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 million, with no change to its requested return on common equity of 10.4%. Hearings in the proceeding began in October 2013, and in December 2013 the APSC issued an order. The order authorized a base rate increase of $81 million and included an authorized return on common equity of 9.3%. The order allowed Entergy Arkansas to amortize its human capital management costs over a three-and-a-half year period, but also ordered Entergy Arkansas to file a detailed report of the Arkansas-specific costs, savings and final payroll changes upon conclusion of the human capital management strategic imperative. The detailed report was subsequently filed in February 2015. The substance of the report was addressed in Entergy Arkansas’s 2015 base rate filing. New rates under the January 2014 order were implemented in the first billing cycle of March 2014 and were effective as of January 2014. Additionally, in January 2014, Entergy Arkansas filed a petition for rehearing or clarification of several aspects of the APSC’s order, including the 9.3% authorized return on common equity. In February 2014 the APSC granted Entergy Arkansas’s petition for the purpose of considering the



additional evidence identified by Entergy Arkansas. In August 2014 the APSC issued an order amending certain aspects of the original order, including providing for a 9.5% authorized return on common equity. Pursuant to the August 2014 order, revised rates were effective for all bills rendered after December 31, 2013 and were implemented in the first billing cycle of October 2014.

## 2015 Base Rate Filing

In April 2015, Entergy Arkansas filed with the APSC for a general change in rates, charges, and tariffs. The filing notified the APSC of Entergy Arkansas’s intent to implement a forward test year formula rate plan pursuant to Arkansas legislation passed in 2015, and requested a retail rate increase of $268.4 million, with a net increase in revenue of $167 million. The filing requested a 10.2% return on common equity. In May 2015 the APSC issued an order suspending the proposed rates and tariffs filed by Entergy Arkansas and establishing a procedural schedule to complete its investigation of Entergy Arkansas’s application. In September 2015, APSC staff and intervenors filed direct testimony, with the APSC staff recommending a revenue requirement of $217.9 million and a 9.65% return on common equity. Entergy Arkansas filed rebuttal testimony in October 2015. In December 2015, Entergy Arkansas, the APSC staff, and certain of the intervenors in the rate case filed with the APSC a joint motion for approval of a settlement of the case that proposes a retail rate increase of approximately $225 million with a net increase in revenue of approximately $133 million; an authorized return on common equity of 9.75%; and a formula rate plan tariff that provides a 50 basis point band around the 9.75% allowed return on common equity.

A hearing was held in January 2016. In February 2016 the APSC approved the settlement with one exception that would reduce the retail rate increase proposed in the settlement by $5 million. The parties were directed to inform the APSC by filing no later than February 26, 2016 whether they accept the APSC’s proposed settlement agreement modification or request a full hearing on the issues. Entergy Arkansas plans to make its first formula rate plan filing in July 2016 for rates effective with the first billing cycle of January 2017.

A significant portion of the rate increase is related to Entergy Arkansas’s acquisition of Union Power Station Power Block 2 for an expected base purchase price of $237 million, subject to adjustment. The acquisition is expected to be completed promptly following the receipt of FERC approval. If the acquisition closes on or before March 24, 2016, recovery of the costs to acquire Power Block 2 of the Union Power Station will be through Entergy Arkansas’s new base rates that will commence with the first billing cycle of April 2016. If the transaction closes after that date, the parties have agreed to concurrent cost recovery through Entergy Arkansas’s capacity acquisition rider.

## Filings with the LPSC (Entergy Louisiana)

## Retail Rates - Electric

## 2013 Rate Cases

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 in February 2013. The filing anticipated Entergy Gulf States Louisiana’s integration into MISO. In the filing Entergy Gulf States Louisiana requested, among other relief:

• authorization to increase the revenue it collects from customers by approximately $24 million;

• an authorized return on common equity of 10.4%;

• authorization to increase depreciation rates embedded in the proposed revenue requirement; and,

- authorization to implement a three-year formula rate plan with a midpoint return on common equity of 10.4%, plus or minus 75 basis points (the deadband), that would provide a means for the annual re-setting of rates (commencing with calendar year 2013 as its first test year), that would include a mechanism to recover incremental transmission revenue requirement on the basis of a forward-looking test year as compared to the initial base year of 2014 with an annual true-up, that would retain the primary aspects of the prior formula rate plan, including a 60% to customers/40% to Entergy Gulf States Louisiana sharing mechanism for earnings



outside the deadband, and a capacity rider mechanism that would permit recovery of incremental capacity additions approved by the LPSC.

Following a hearing before an ALJ and the 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 included approval of a 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 60/40 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 amortization of costs to achieve savings associated with the human capital management strategic imperative, with savings to be reflected as they are realized in subsequent years; (4) 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) no change in rates related to test year 2013, except with respect to recovery of the non-fuel MISO-related costs and any changes to the additional capacity revenue requirement; and (6) no increase in rates related to test year 2014, except for those items eligible for recovery outside of the earnings sharing mechanism. Existing depreciation rates will not change. Implementation of rate changes for items recoverable outside of the earnings sharing mechanism occurred in December 2014.

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 November 2011 the LPSC approved a one-year extension of Entergy Louisiana’s formula rate plan. In May 2012, Entergy Louisiana made its formula rate plan filing with the LPSC for the 2011 test year. The filing reflected a 9.63% earned return on common equity, which is within the earnings bandwidth and resulted in no cost of service rate change under the formula rate plan. The filing also reflected an $18.1 million rate increase for the incremental capacity rider. In August 2012, Entergy Louisiana submitted a revised filing that reflected an earned return on common equity of 10.38%, which is still within the earnings bandwidth, resulting in no cost of service rate change. The revised filing also indicated that an increase of $15.9 million should be reflected in the incremental capacity rider. The rate change was implemented, subject to refund, effective for bills rendered the first billing cycle of September 2012. Subsequently, in December 2012, Entergy Louisiana submitted a revised evaluation report that reflected two items: 1) a $17 million reduction for the first-year capacity charges for the purchase by Entergy Gulf States Louisiana from Entergy Louisiana of one-third of Acadia Unit 2 capacity and energy, and 2) an $88 million increase for the first-year retail revenue requirement associated with the Waterford 3 replacement steam generator project, which was in-service in December 2012. These rate changes were implemented, subject to refund, effective with the first billing cycle of January 2013. In April 2013, Entergy Louisiana and the LPSC staff filed a joint report resolving the 2011 test year formula rate plan and recovery related to the Grand Gulf uprate. This report was approved by the LPSC in April 2013.

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 integration into MISO. In the filing Entergy Louisiana requested, among other relief:

- authorization to increase the revenue it collects from customers by approximately $145 million (which does not take into account a revenue offset of approximately $2 million resulting from a proposed increase for those customers taking service under the Qualifying Facility Standby Service);

• an authorized return on common equity of 10.4%;

• authorization to increase depreciation rates embedded in the proposed revenue requirement; and



- authorization to implement a three-year formula rate plan with a midpoint return on common equity of 10.4%, plus or minus 75 basis points (the deadband), that would provide a means for the annual re-setting of rates (commencing with calendar year 2013 as its first test year), that would include a mechanism to recover incremental transmission revenue requirement on the basis of a forward-looking test year as compared to the initial base year of 2014 with an annual true-up, that would retain the primary aspects of the prior formula rate plan, including a 60% to customers/40% to Entergy Louisiana sharing mechanism for earnings outside the deadband, and a capacity rider mechanism that would permit recovery of incremental capacity additions approved by the LPSC.

Following a hearing before an ALJ and the ALJ’s issuance of a Report of Proceedings, in December 2013 the LPSC approved an unopposed settlement of the proceeding. The settlement provided for a $10 million rate increase effective with the first billing cycle of December 2014. Major terms of the settlement included approval of a 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 60/40 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 amortization of costs to achieve savings associated with the human capital management strategic imperative, with savings reflected as they are realized in subsequent years; (4) 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 million cap on cost of service increases over the 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. LPSC staff identified five issues, of which two remain. The remaining issues pertain to Entergy Louisiana’s method of collecting the agreed-upon $10 million increase and the level of recovery of investment related to the Grand Gulf uprate. No procedural schedule has been established, however, to address these remaining issues. The final issue raised by the LPSC staff pertains to the appropriate level of refunds related to the Waterford 3 replacement steam generator project. That issue will be resolved in connection with the Waterford 3 prudence review proceedings discussed below.

## Waterford 3 Replacement Steam Generator Project

Following the completion of the Waterford 3 replacement steam generator project, the LPSC undertook 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 was held in December 2014. At the hearing the parties maintained the positions reflected in pre-filed testimony. Entergy Louisiana believes that the replacement steam generator costs were prudently incurred and applicable legal principles support their recovery in rates. Nevertheless, Entergy Louisiana recorded a write-off of $16 million of Waterford 3's plant balance in December 2014 because of the uncertainty at the time associated with the resolution of the prudence review. In December 2015 the ALJ issued a proposed recommendation, which was subsequently finalized, concluding that Entergy Louisiana prudently managed the Waterford 3 replacement steam generator project, including the selection, use, and oversight of contractors, and could not reasonably have anticipated the damage to the steam generators. Nevertheless, the ALJ concluded that Entergy Louisiana was liable for the conduct of its contractor and subcontractor and, therefore, recommended a disallowance of $67 million in capital costs. Additionally, the ALJ concluded that Entergy Louisiana did not sufficiently justify the incurrence of $2 million in replacement power costs during the replacement outage. Although the ALJ's recommendation has yet to be considered by the LPSC, after considering the progress of the proceeding in light of the ALJ recommendation, Entergy Louisiana recorded in the fourth quarter 2015 approximately $77 million in charges, including a $45 million asset write-off and a $32 million regulatory charge, to reflect that a portion of the assets associated with the Waterford 3 replacement steam generator project is no longer probable of recovery. Entergy Louisiana maintains that the ALJ's recommendation contains significant factual and legal errors.

## Ninemile 6

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 and $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. In July 2015, Entergy Louisiana submitted to the LPSC a compliance filing including an estimate at completion, inclusive of interconnection costs and transmission upgrades, of approximately $648 million, or $76 million less than originally estimated, along with other project details and supporting evidence, to enable the LPSC to review the prudence of Entergy Louisiana's management of the project. A hearing is scheduled in March 2016.

## Union Power Station

In January 2015, Entergy Gulf States Louisiana filed its application with the LPSC for approval of the acquisition and cost recovery of two power blocks of the Union Power Station for an expected base purchase price of approximately $237 million per power block, subject to adjustments. In September 2015, Entergy Gulf States Louisiana agreed to settlement terms with all parties for Entergy Gulf States Louisiana’s purchase of the two power blocks. In October 2015 the LPSC voted unanimously to approve the uncontested settlement which finds, among other things, that acquisition of Power Blocks 3 and 4 is in the public interest and, therefore, prudent. The business combination of Entergy Gulf States Louisiana and Entergy Louisiana received regulatory approval and closed in October 2015 making Entergy Louisiana the named purchaser of Power Blocks 3 and 4 of the Union Power Station.

## Business Combination

In connection with the approval of the business combination of Entergy Gulf States Louisiana and Entergy Louisiana, the LPSC authorized the filing of a single, joint formula rate plan evaluation report for Entergy Gulf States Louisiana’s and Entergy Louisiana’s 2014 calendar year operations. The joint evaluation report was filed in September 2015 and reflects an earned return on common equity of 9.09%. As such, no adjustment to base formula rate plan revenue is required. The following adjustments are required under the formula rate plan, however: a decrease in the additional capacity mechanism for Entergy Louisiana of $17.8 million; an increase in the additional capacity mechanism for Entergy Gulf States Louisiana of $4.3 million; and a reduction of $5.5 million to the MISO cost recovery mechanism, to collect approximately $35.7 million on a combined-company basis. Under the order approving the



business combination, following completion of the prescribed review period, rates were implemented with the first billing cycle of December 2015, subject to refund. In November 2015, the LPSC staff filed objections, corrections, and comments identifying several issues for potential rate adjustments, including: preservation of previously-raised issues; the implementation of the $10 million increase in annual formula rate plan revenue over abbreviated rate-effective period; the level of adjustment to rates for the extended power uprate at System Energy, as well as asserting a general reservation of rights for further review of adjustments related to Ninemile 6 and the Waterford 3 provision for rate refund; change to gross plant, depreciation, and net plant components of rate base; regulatory debts and credits; adjustment for business combination expenses and the implementation of certain guaranteed customer credits. See “Entergy Louisiana and Entergy Gulf States Louisiana Business Combination” below for further discussion of the business combination.

## Retail Rates - Gas

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 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 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 2014, Entergy Gulf States Louisiana filed with the LPSC its gas rate stabilization plan for the test year ended September 30, 2013. The filing showed an earned return on common equity of 5.47%, which results in a $1.5 million rate increase. In April 2014 the LPSC staff issued a report indicating “that Entergy Gulf States Louisiana has properly determined its earnings for the test year ended September 30, 2013.” The $1.5 million rate increase was implemented effective with the first billing cycle of 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% annually; annual filings comparing actual versus planned rider spending with actual spending and explanation of variances exceeding 10%; and an annual true-up. The joint settlement was approved by the LPSC in January 2015. Implementation of the infrastructure rider commenced with bills rendered on and after the first billing cycle of April 2015.

In January 2015, Entergy Gulf States Louisiana filed with the LPSC its gas rate stabilization plan for the test year ended September 30, 2014. The filing showed an earned return on common equity of 7.20%, which resulted in a $706 thousand rate increase. In April 2015 the LPSC issued findings recommending two adjustments to Entergy Gulf States Louisiana’s as-filed results, and an additional recommendation that does not affect current year results. The LPSC



staff’s recommended adjustments increase the earned return on equity for the test year to 7.24%. Entergy Gulf States Louisiana accepted the LPSC staff’s recommendations and a revenue increase of $688 thousand was implemented with the first billing cycle of May 2015.

In January 2016, Entergy Louisiana filed with the LPSC its gas rate stabilization plan for the test year ended September 30, 2015. The filing showed an earned return on common equity of 10.22%, which is within the authorized bandwidth, therefore requiring no change in rates. Absent approval of an extension by the LPSC, test year 2015 is the final year under the current gas rate stabilization plan. In February 2016, however, Entergy Louisiana filed a motion requesting to extend the terms of the gas rate stabilization plan for an additional three-year term.

## Filings with the MPSC (Entergy Mississippi)

## Formula Rate Plan Filings

In March 2013, Entergy Mississippi submitted its formula rate plan filing for the 2012 test year. The filing requested a $36.3 million revenue increase to reset Entergy 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 Staff entered into a joint stipulation, in which both parties agreed that the MPSC should approve a $22.3 million rate increase for Entergy Mississippi which, with other adjustments reflected in the stipulation, would have the effect of resetting Entergy Mississippi’s return on common equity to 10.59% when adjusted for performance under the formula rate plan. In August 2013 the MPSC approved the joint stipulation between Entergy Mississippi and the Mississippi Public Utilities Staff authorizing the rate increase effective with September 2013 bills. Additionally, the MPSC authorized Entergy Mississippi to defer approximately $1.2 million in MISO-related implementation costs incurred in 2012 along with other MISO-related implementation costs incurred in 2013.

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:

- an approximate $16 million net increase in revenues, which reflected an agreed upon 10.07% return on common equity;

- revision of Entergy Mississippi’s formula rate plan by providing Entergy Mississippi with the ability to reflect known and measurable changes to historical rate base and certain expense amounts; resolving uncertainty around and obviating the need for an additional rate filing in connection with Entergy Mississippi’s withdrawal from participation in the System Agreement; updating depreciation rates; and moving costs associated with the Attala and Hinds generating plants from the power management rider to base rates;

• recovery of non-fuel MISO-related costs through a separate rider for that purpose;

- a deferral of $6 million in other operation and maintenance expenses associated with the Baxter Wilson outage and a determination that the regulatory asset should accrue carrying costs, with amortization of the regulatory asset over two years beginning in February 2015, and a provision that the capital costs will be reflected in rate base. See Note 8 to the financial statements for further discussion of the Baxter Wilson outage; and



- consolidation of the new nuclear generation development costs proceeding with the general rate case proceeding for hearing purposes and a determination that Entergy Mississippi would not further pursue, except as noted below, recovery of the costs that were approved for deferral by the MPSC in November 2011. The stipulations state, however, that, if Entergy Mississippi decides to move forward with nuclear development in Mississippi, it can at that time re-present for consideration by the MPSC only those costs directly associated with the existing early site permit (ESP), to the extent that the costs are verifiable and prudent and the ESP is still valid and relevant to any such option pursued. See “New Nuclear Generation Development Costs - Entergy Mississippi” below for further discussion of the new nuclear generation development costs proceeding and subsequent write-off in 2014 of the regulatory asset related to those costs.

In December 2014 the MPSC issued an order accepting the stipulations in their entirety and approving the revenue adjustments and rate changes effective with February 2015 bills.

## Filings with the City Council

## (Entergy Louisiana and Entergy New Orleans)

In March 2013, Entergy Louisiana filed a rate case for the Algiers area, which is in New Orleans and is regulated by the City Council. Entergy Louisiana requested a rate increase of $13 million over three years, including a 10.4% return on common equity and a formula rate plan mechanism identical to its LPSC request. In January 2014 the City Council Advisors filed direct testimony recommending a rate increase of $5.56 million over three years, including an 8.13% return on common equity. In June 2014 the City Council unanimously approved a settlement that includes the following:

• a $9.3 million base rate revenue increase to be phased in on a levelized basis over four years;

• recovery of an additional $853 thousand annually through a MISO recovery rider; and

- the adoption of a four-year formula rate plan requiring the filing of annual evaluation reports in May of each year, commencing May 2015, with resulting rates being implemented in October of each year. The formula rate plan includes a midpoint target authorized return on common equity of 9.95% with a +/- 40 basis point bandwidth.

The rate increase was effective with bills rendered on and after the first billing cycle of July 2014. Additional compliance filings were made with the Council in October 2014 for approval of the form of certain rate riders, including among others, a Ninemile 6 non-fuel cost recovery interim rider, allowing for contemporaneous recovery of capacity costs related to the commencement of commercial operation of the Ninemile 6 generating unit and a purchased power capacity cost recovery rider. The monthly Ninemile 6 cost recovery interim rider was implemented in December 2014 to initially collect $915 thousand from Entergy Louisiana customers in the Algiers area. See “Algiers Asset Transfer” below for discussion of the transfer from Entergy Louisiana to Entergy New Orleans of certain assets that serve Algiers customers.

## (Entergy New Orleans)

## Formula Rate Plan

In April 2009 the City Council approved a three-year formula rate plan for Entergy New Orleans, with terms including an 11.1% benchmark electric return on common equity (ROE) with a +/-40 basis point bandwidth and a 10.75% benchmark gas ROE with a +/-50 basis point bandwidth. Earnings outside the bandwidth reset to the midpoint benchmark ROE, with rates changing on a prospective basis depending on whether Entergy New Orleans was over- or under-earning. The formula rate plan also included a recovery mechanism for City Council-approved capacity additions, plus provisions for extraordinary cost changes and force majeure events.



In May 2012, Entergy New Orleans filed its electric and gas formula rate plan evaluation reports for the 2011 test year. Subsequent adjustments agreed upon with the City Council Advisors indicate a $4.9 million electric base revenue increase and a $0.05 million gas base revenue increase as necessary under the formula rate plan. As part of the original filing, Entergy New Orleans also requested to increase annual funding for its storm reserve by approximately $5.7 million for five years. On September 26, 2012, Entergy New Orleans made a filing with the City Council that implemented the $4.9 million electric formula rate plan rate increase and the $0.05 million gas formula rate plan rate increase. The new rates were effective with the first billing cycle in October 2012. In August 2013 the City Council unanimously approved a settlement of all issues in the formula rate plan proceeding. Pursuant to the terms of the settlement, Entergy New Orleans implemented an approximately $1.625 million net decrease to the electric rates that were in effect prior to the electric rate increase implemented in October 2012, with no change in gas rates. Entergy New Orleans refunded to customers approximately $6 million over the four-month period from September 2013 through December 2013 to make the electric rate decrease effective as of the first billing cycle of October 2012. Entergy New Orleans had previously recorded provisions for the majority of the refund to customers, but recorded an additional $1.1 million provision in second quarter 2013 as a result of the settlement. Entergy New Orleans’s formula rate plan ended with the 2011 test year and has not been extended.

See “Algiers Asset Transfer” below for discussion of the Algiers asset transfer. As a provision of the settlement agreement approved by the City Council in May 2015 providing for the Algiers asset transfer, it was agreed that, with limited exceptions, no action may be taken with respect to Entergy New Orleans’s base rates until rates are implemented from a base rate case that must be filed for its electric and gas operations in 2018. This provision eliminated the formula rate plan applicable to Algiers operations. The limited exceptions include continued implementation of the remaining two years of the four-year phased-in rate increase for its operations in the Algiers area and certain exceptional cost increases or decreases in its base revenue requirement. An additional provision of the settlement agreement allows for continued recovery of the revenue requirement associated with the capacity and energy from Ninemile 6 received by Entergy New Orleans under a power purchase agreement with Entergy Louisiana (Algiers PPA). The settlement authorizes Entergy New Orleans to recover the remaining revenue requirement related to the Algiers PPA through base rates charged to Algiers customers. The settlement also provided for continued implementation of the Algiers MISO recovery rider.

In addition to the Algiers PPA, Entergy New Orleans has a separate power purchase agreement with Entergy Louisiana for 20% of the capacity and energy of the Ninemile Unit 6 generating station (Ninemile PPA), which commenced operation in December 2014. Initially, recovery of the non-fuel costs associated with the Ninemile PPA was authorized through a special Ninemile 6 rider billed to only Entergy New Orleans customers outside of Algiers.

In August 2015, Entergy New Orleans filed an application with the City Council seeking authorization to proceed with the acquisition of Union Power Block 1, with an expected base purchase price of approximately $237 million, subject to adjustments, and seeking approval of the recovery of the associated costs. In November 2015 the City Council issued written resolutions and an order approving an agreement in principle between Entergy New Orleans and City Council advisors providing that the purchase of Union Power Block 1 and related assets by Entergy New Orleans is prudent and in the public interest. The City Council authorized expansion of the special Ninemile 6 rider, discussed above, to cover the non-fuel purchased power from Ninemile 6 as well as the revenue requirement associated with the acquisition of Union Power Block 1, upon closing of the transaction.

A 2008 rate case settlement included $3.1 million per year in electric rates to fund the Energy Smart energy efficiency programs. In September 2009 the City Council approved the energy efficiency programs filed by Entergy New Orleans. The rate settlement provides an incentive for Entergy New Orleans to meet or exceed energy savings targets set by the City Council and provides a mechanism for Entergy New Orleans to recover lost contribution to fixed costs associated with the energy savings generated from the energy efficiency programs. In October 2013 the City Council approved the extension of the current Energy Smart program through December 2014. The City Council approved the use of $3.5 million of rough production cost equalization funds for program costs. In addition, Entergy New Orleans will be allowed to recover its lost contribution to fixed costs and to earn an incentive for meeting program goals. In January 2015 the City Council approved extending the Energy Smart program through March 2015 and using



$1.2 million of rough production cost equalization funds to cover program costs for the extended period. Additionally, the City Council approved funding for the Energy Smart 2 programs from April 2015 through March 2017 using the remainder of the approximately $12.8 million of 2014 rough production cost equalization funds, and with any remaining costs being recovered through the fuel adjustment clause. This funding methodology was modified in November 2015 when the City Council directed Entergy New Orleans to use a combination of guaranteed customer savings related to a prior agreement with the City Council and rough production cost equalization funds to cover program costs prior to recovering any costs through the fuel adjustment clause.

## Filings with the PUCT and Texas Cities (Entergy Texas)

## Retail Rates

## 2011 Rate Case

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, subsequently filed a statement of position in the proceeding indicating that it was still evaluating the position it would ultimately take in the case regarding Entergy Texas's recovery of purchased power capacity costs and Entergy Texas's proposal to defer its MISO transition expenses. In April 2012, Entergy Texas filed rebuttal testimony indicating a revised request for a $105 million base rate increase. A hearing was held in late-April through early-May 2012.

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 measurable; 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 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 also filed motions for rehearing of the PUCT’s order. The PUCT subsequently denied rehearing of substantive issues. Several parties, including Entergy Texas, appealed various aspects of the PUCT’s order to the Travis County District Court. A hearing was held in 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 and other parties, including the PUCT, appealed the Travis County District Court decision to the Third Court of Appeals. Briefs were filed by the appealing and responding parties in the first half of 2015. Oral argument before the court panel was held in September 2015. The appeal is currently pending.

## 2013 Rate Case

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 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. 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 March 2014, Entergy Texas filed an Agreed Motion for Interim Rates. The motion explained that the parties to this proceeding have agreed that Entergy Texas should be allowed to implement new rates reflecting an $18.5 million base rate increase, effective for usage on and after April 1, 2014, as well as recovery of charges for rough production cost equalization and rate case expenses. In March 2014 the State Office of Administrative Hearings, the body assigned to hear the case, approved the motion. In April 2014, Entergy Texas filed a unanimous stipulation in this case. Among other things, the stipulation provides for an $18.5 million base rate increase, provides for recovery over three years of the calendar year 2012 rough production cost equalization charges and rate case expenses, and states a 9.8% return on common equity. In addition, the stipulation finalizes the fuel and purchased power reconciliation covering the period July 2011 through March 2013, with the parties stipulating an immaterial fuel disallowance. No special circumstances recovery of purchased power capacity costs was allowed. In April 2014 the State Office of Administrative Hearings remanded the case back to the PUCT for final processing. In May 2014 the PUCT approved the stipulation. No motions for rehearing were filed during the statutory rehearing period.

## 2015 Rate Case

In June 2015, Entergy Texas filed a rate case that included pro forma adjustments to reflect the proposed acquisition of Union Power Station Power Block 1, which is one of four units that comprise the Union Power Station near El Dorado, Arkansas. Previously in 2015 Entergy Texas made a filing with the PUCT requesting that it grant a certificate of convenience and necessity for the Union acquisition. In July 2015 the PUCT requested briefing on legal and policy issues related to, among other things, the propriety of rate recovery for the Union Power transaction given the uncertainty of the actual closing date of the transaction and the commencement of the rate year, as well as Entergy Texas’s requirement for acceptable rate treatment as a condition to closing the transaction. Also in July 2015, in connection with the requested briefing, the PUCT staff and certain parties filed briefs concluding that Entergy Texas should not be permitted recovery for the Union Power Station purchase in the rate case. Based on the opposition to the acquisition of the power block, Entergy Texas determined it was appropriate to seek to dismiss the certificate of convenience and necessity filing and withdraw the rate case. In July 2015, Entergy Texas filed its notice of withdrawal of its base rate case and the ALJs in the case dismissed the case from the dockets of the State Office of Administrative Hearings and the PUCT. In the third quarter 2015, Entergy Texas wrote off $4.7 million in rate case expenses and acquisition costs related to the proposed Union Power Station acquisition.

## Other Filings

In September 2014, Entergy Texas filed for a distribution cost recovery factor (DCRF) 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 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. In September 2015, Entergy Texas filed to amend its distribution cost recovery factor rider. Entergy Texas requested an increase in recovery under the rider of $6.5 million, for a total collection of $10.1 million annually from retail customers. In October 2015 intervenors and PUCT staff filed testimony opposing, in part, Entergy Texas’s request. In November 2015 Entergy Texas and the parties filed an unopposed settlement agreement and supporting documents. The settlement established an annual revenue requirement of $8.65 million for the amended DCRF rider, with the resulting rates effective for usage on and after January 1, 2016. The PUCT approved the settlement agreement in February 2016.



In September 2015, Entergy Texas filed for a transmission cost recovery factor (TCRF) rider requesting a $13 million increase, incremental to base rates. Testimony was filed in November 2015, with the PUCT staff and other parties proposing various disallowances that would reduce the requested increase. The largest remaining single disallowance is $3.4 million which would impose a load growth adjustment on Entergy Texas’s TCRF rider. A hearing on the merits was held in December 2015. A proposal for decision from the ALJ is expected in first quarter 2016.

## Entergy Louisiana and Entergy Gulf States Louisiana Business Combination

Entergy Louisiana and Entergy Gulf States Louisiana filed an application with the LPSC in September 2014 seeking authorization to undertake the transactions that would result in the combination of Entergy Louisiana and Entergy Gulf States Louisiana into a single public utility. In the application, Entergy Louisiana and Entergy Gulf States Louisiana identified potential benefits, including enhanced economic and customer diversity, enhanced geographic and supply diversity, and greater administrative efficiency. In the initial proceedings with the LPSC, Entergy Louisiana and Entergy Gulf States Louisiana estimated that the business combination could produce up to $128 million in measurable customer benefits during the first ten years following the transaction’s close including proposed guaranteed customer credits of $97 million in the first nine years. In April 2015 the LPSC staff and intervenors filed testimony in the LPSC business combination proceeding. The testimony recommended an extensive set of conditions that would be required in order to recommend that the LPSC find that the business combination was in the public interest. The LPSC staff’s primary concern appeared to be potential shifting in fuel costs between Entergy Louisiana and Entergy Gulf States Louisiana customers. In May 2015, Entergy Louisiana and Entergy Gulf States Louisiana filed rebuttal testimony. After the testimony was filed with the LPSC, the parties engaged in settlement discussions that ultimately led to the execution of an uncontested stipulated settlement (“stipulated settlement”), which was filed with the LPSC in July 2015. Through the stipulated settlement, the parties agreed to terms upon which to recommend that the LPSC find that the business combination was in the public interest. The stipulated settlement, which was either joined, or unopposed, by all parties to the LPSC proceeding, represents a compromise of stakeholder positions and was the result of an extensive period of analysis, discovery, and negotiation. The stipulated settlement provides $107 million in guaranteed customer benefits during the first nine years following the transaction’s close. Additionally, the combined company will honor the 2013 Entergy Louisiana and Entergy Gulf States Louisiana rate case settlements, including the commitments that (1) there will be no rate increase for legacy Entergy Gulf States Louisiana customers for the 2014 test year, and (2) through the 2016 test year formula rate plan, Entergy Louisiana (as a combined entity) will not raise rates by more than $30 million, net of the $10 million rate increase included in the Entergy Louisiana legacy formula rate plan. The stipulated settlement also describes the process for implementing a fuel-tracking mechanism that is designed to address potential effects arising from the shifting of fuel costs between legacy Entergy Louisiana and legacy Entergy Gulf States Louisiana customers as a result of the combination of those companies’ fuel adjustment clauses. Specifically, the fuel tracker would reallocate such cost shifts as between legacy customers of the companies on an after-the-fact basis, and the calculation of the fuel tracker will be submitted annually in a compliance filing. The stipulated settlement also provides that Entergy Gulf States Louisiana and Entergy Louisiana are permitted to defer certain external costs that were incurred to achieve the business combination’s customer benefits. The deferred amount, which shall not exceed $25 million, will be subject to a prudence review and amortized over a 10-year period. In 2015 deferrals of $16 million for these external costs were recorded. A hearing on the stipulated settlement in the LPSC proceeding was held in July 2015. In August 2015 the LPSC approved the business combination.

In April 2015 the FERC approved applications requesting authorization for the business combination. In August 2015 the NRC approved the applications for the River Bend and Waterford 3 license transfers as part of the steps to complete the business combination.

On October 1, 2015, the businesses formerly conducted by Entergy Louisiana and Entergy Gulf States Louisiana were combined into a single public utility. With the completion of the business combination, Entergy Louisiana holds substantially all of the assets, and has assumed the liabilities, of Entergy Louisiana and Entergy Gulf States Louisiana. The combination was accounted for as a transaction between entities under common control. The effect of the business combination has been retrospectively applied to Entergy Louisiana's financial statements that are presented in this report.



See Note 3 to the financial statements for further discussion of the customer credits resulting from the business combination.

## Algiers Asset Transfer (Entergy Louisiana and Entergy New Orleans)

In October 2014, Entergy Louisiana and Entergy New Orleans filed an application with the City Council seeking authorization to undertake a transaction that would result in the transfer from Entergy Louisiana to Entergy New Orleans of certain assets that supported the provision of service to Entergy Louisiana’s customers in Algiers. In April 2015 the FERC issued an order approving the Algiers assets transfer. In May 2015 the parties filed a settlement agreement authorizing the Algiers assets transfer and the settlement agreement was approved by a City Council resolution in May 2015. On September 1, 2015, Entergy Louisiana transferred its Algiers assets to Entergy New Orleans for a purchase price of approximately $85 million, subject to closing adjustments. Entergy New Orleans paid Entergy Louisiana $59.6 million, including final true-ups, from available cash and issued a note payable to Entergy Louisiana in the amount of $25.5 million. See Note 1 to the financial statements for a discussion of the accounting for the Algiers asset transfer and the basis of presentation for the Entergy New Orleans’s financial statements presented in this report.

## System Agreement Cost Equalization Proceedings

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.

In June 2005 the FERC issued a decision in System Agreement litigation that had been commenced by the LPSC, and essentially affirmed its decision in a December 2005 order on rehearing. The FERC decision concluded, among other things, that:

- The System Agreement no longer roughly equalizes total production costs among the Utility operating companies.

- In order to reach rough production cost equalization, the FERC imposed a bandwidth remedy by which each company’s total annual production costs will have to be within  \( \pm $ 11% of Entergy System average total annual production costs.

- In calculating the production costs for this purpose under the FERC’s order, output from the Vidalia hydroelectric power plant will not reflect the actual Vidalia price for the year but is priced at that year’s average price paid by Entergy Louisiana for the exchange of electric energy under Service Schedule MSS-3 of the System Agreement, thereby reducing the amount of Vidalia costs reflected in the comparison of the Utility operating companies’ total production costs.

- The remedy ordered by FERC in 2005 required no refunds and became effective based on calendar year 2006 production costs and the first reallocation payments were made in 2007.

The FERC’s decision reallocates total production costs of the Utility operating companies whose relative total production costs expressed as a percentage of Entergy System average production costs are outside an upper or lower bandwidth. Under the current circumstances, this will be accomplished by payments from Utility operating companies whose production costs are more than 11% below Entergy System average production costs to Utility operating companies whose production costs are more than the Entergy System average production cost, with payments going first to those Utility operating companies whose total production costs are farthest above the Entergy System average.

The financial consequences of the FERC’s decision are determined by the total production cost of each Utility operating company, which are affected by the mix of solid fuel and gas-fired generation available to each company and the costs of natural gas and purchased power. Entergy Louisiana, Entergy Texas, and Entergy Mississippi are more



dependent upon gas-fired generation sources than Entergy Arkansas or Entergy New Orleans. Of these, Entergy Arkansas is the least dependent upon gas-fired generation sources. Therefore, increases in natural gas prices generally increased the amount by which Entergy Arkansas’s total production costs were below the Entergy System average production costs.

The LPSC, APSC, MPSC, and the Arkansas Electric Energy Consumers appealed the FERC’s December 2005 decision to the United States Court of Appeals for the D.C. Circuit. Entergy and the City of New Orleans intervened in the various appeals. The D.C. Circuit issued its decision in April 2008. The D.C. Circuit concluded that the FERC’s orders had failed to adequately explain both its conclusion that it was prohibited from ordering refunds for the 20-month period from September 13, 2001 - May 2, 2003 and its determination to implement the bandwidth remedy commencing on January 1, 2006, rather than June 1, 2005. The D.C. Circuit remanded the case to the FERC for further proceedings on these issues.

In October 2011, the FERC issued an order addressing the D.C. Circuit remand on these two issues. On the first issue, the FERC concluded that it did have the authority to order refunds, but decided that it would exercise its equitable discretion and not require refunds for the 20-month period from September 13, 2001 - May 2, 2003. Because the ruling on refunds relied on findings in the interruptible load proceeding, which is discussed in a separate section below, the FERC concluded that the refund ruling will be held in abeyance pending the outcome of the rehearing requests in that proceeding. On the second issue, the FERC reversed its prior decision and ordered that the prospective bandwidth remedy begin on June 1, 2005 (the date of its initial order in the proceeding) rather than January 1, 2006, as it had previously ordered. Pursuant to the October 2011 order, Entergy was required to calculate the additional bandwidth payments for the period June - December 2005 utilizing the bandwidth formula tariff prescribed by the FERC that was filed in a December 2006 compliance filing and accepted by the FERC in an April 2007 order. As is the case with bandwidth remedy payments, these payments and receipts will ultimately be paid by Utility operating company customers to other Utility operating company customers. In March 2015, in light of the December 2014 decision by the D.C. Circuit in the interruptible load proceeding, Entergy filed with the FERC a motion to establish briefing schedule on refund issues and an initial brief addressing refund issues. The initial brief argued that the FERC, in response to the D.C. Circuit decision, should clarify its policy on refunds and find that refunds are not required in this proceeding. In October 2015 the FERC issued three orders related to the commencement of the remedy on June 1, 2005 and the inclusion of interest on the amount for the period June 1, 2005 through December 31, 2005. Specifically, the FERC rejected Entergy Services’s request for rehearing of its decision to include interest on the amount for the seven-month period. The FERC also rejected Entergy Services’s request for rehearing of the order rejecting the compliance filing with regard to the issue of interest. Finally, the FERC set for hearing and settlement procedures the 2014 compliance filing that included the bandwidth calculation for the seven months June 1, 2005 through December 31, 2005. In setting the compliance filing for hearing, the FERC rejected the APSC’s protest that Entergy Arkansas should not be subject to the filing because Entergy Arkansas would be making the payments during a period following its exit from the System Agreement. The hearing on the bandwidth calculation for the seven months June 1, 2005 through December 31, 2005 is scheduled to occur in July 2016.

In December 2011, Entergy filed with the FERC its compliance filing that provides the payments and receipts among the Utility operating companies pursuant to the FERC’s October 2011 order. The filing shows the following payments/receipts among the Utility operating companies:

<table><tr><td></td><td>Payments (Receipts)</td></tr><tr><td>Entergy Arkansas</td><td>$156</td></tr><tr><td>Entergy Louisiana</td><td>($75)</td></tr><tr><td>Entergy Mississippi</td><td>($33)</td></tr><tr><td>Entergy New Orleans</td><td>($5)</td></tr><tr><td>Entergy Texas</td><td>($43)</td></tr></table>



Entergy Arkansas made its payment in January 2012. In February 2012, Entergy Arkansas filed for an interim adjustment to its production cost allocation rider requesting that the $156 million payment be collected from customers over the 22-month period from March 2012 through December 2013. In March 2012 the APSC issued an order stating that the payment can be recovered from retail customers through the production cost allocation rider, subject to refund. The LPSC and the APSC have requested rehearing of the FERC’s October 2011 order. In December 2013 the LPSC filed a petition for a writ of mandamus at the United States Court of Appeals for the D.C. Circuit. In its petition, the LPSC requested that the D.C. Circuit issue an order compelling the FERC to issue a final order on pending rehearing requests. In January 2014 the D.C. Circuit denied the LPSC’s petition. The APSC, the LPSC, the PUCT, and other parties intervened in the December 2011 compliance filing proceeding, and the APSC and the LPSC also filed protests.

In February 2014 the FERC issued a rehearing order addressing its October 2011 order. The FERC denied the LPSC’s request for rehearing on the issues of whether the bandwidth remedy should be made effective earlier than June 1, 2005, and whether refunds should be ordered for the 20-month refund effective period. The FERC granted the LPSC’s rehearing request on the issue of interest on the bandwidth payments/receipts for the June - December 2005 period, requiring that interest be accrued from June 1, 2006 until the date those bandwidth payments/receipts are made. Also in February 2014 the FERC issued an order rejecting the December 2011 compliance filing that calculated the bandwidth payments/receipts for the June - December 2005 period. The FERC order required a new compliance filing that calculates the bandwidth payments/receipts for the June - December 2005 period based on monthly data for the seven individual months including interest pursuant to the February 2014 rehearing order. Entergy has sought rehearing of the February 2014 orders with respect to the FERC’s determinations regarding interest. In April 2014 the LPSC filed a petition for review of the FERC’s October 2011 and February 2014 orders with the U.S. Court of Appeals for the D.C. Circuit. The appeal is pending.

In April and May 2014, Entergy filed with the FERC an updated compliance filing that provides the payments and receipts among the Utility operating companies pursuant to the FERC’s February 2014 orders. The filing shows the following net payments and receipts, including interest, among the Utility operating companies:

<table><tr><td></td><td>Payments (Receipts)</td></tr><tr><td></td><td>(In Millions)</td></tr><tr><td>Entergy Arkansas</td><td>$68</td></tr><tr><td>Entergy Louisiana</td><td>($10)</td></tr><tr><td>Entergy Mississippi</td><td>($11)</td></tr><tr><td>Entergy New Orleans</td><td>$2</td></tr><tr><td>Entergy Texas</td><td>($49)</td></tr></table>

These payments were made in May 2014. The LPSC, City Council, and APSC have filed protests.



## Rough Production Cost Equalization Rates

Each May since 2007 Entergy has filed with the FERC the rates to implement the FERC’s orders in the System Agreement proceeding. These filings show the following payments/receipts among the Utility operating companies are necessary to achieve rough production cost equalization as defined by the FERC’s orders:

Payments (Receipts)

<table><tr><td></td><td>2007</td><td>2008</td><td>2009</td><td>2010</td><td>2011</td><td>2012</td><td>2013</td><td>2014</td></tr><tr><td></td><td colspan="8">(In Millions)</td></tr><tr><td>Entergy Arkansas</td><td>$252</td><td>$252</td><td>$390</td><td>$41</td><td>$77</td><td>$41</td><td>$—</td><td>$—</td></tr><tr><td>Entergy Louisiana</td><td>($211)</td><td>($160)</td><td>($247)</td><td>($22)</td><td>($12)</td><td>($41)</td><td>$—</td><td>$—</td></tr><tr><td>Entergy Mississippi</td><td>($41)</td><td>($20)</td><td>($24)</td><td>($19)</td><td>($40)</td><td>$—</td><td>$—</td><td>$—</td></tr><tr><td>Entergy New Orleans</td><td>$—</td><td>($7)</td><td>$—</td><td>$—</td><td>($25)</td><td>$—</td><td>($15)</td><td>($15)</td></tr><tr><td>Entergy Texas</td><td>($30)</td><td>($65)</td><td>($119)</td><td>$—</td><td>$—</td><td>$—</td><td>$15</td><td>$15</td></tr></table>

The Utility operating companies record, as necessary, accounts payable or accounts receivable to reflect the rough production cost equalization payments and receipts required to implement the FERC’s remedy. When accounts payable are recorded, a corresponding regulatory asset is recorded for the right to collect the payments from customers. When accounts receivable are recorded, a corresponding regulatory liability is recorded for the obligations to pass the receipts on to customers. As discussed below, no payments and receipts were required in 2015 to implement the FERC’s remedy based on calendar year 2014 production costs. Entergy Arkansas ceased participating in the System Agreement on December 18, 2013 and was not part of the calendar year 2013 or 2014 production costs calculations.

The APSC has approved a production cost allocation rider for recovery from customers of the retail portion of the costs allocated to Entergy Arkansas. Entergy Texas is recovering its 2013 rough production cost equalization payment over three years beginning April 2014. Entergy Texas included its 2014 rough production cost equalization payment as component of an interim fuel refund made in 2014. Management believes that any changes in the allocation of production costs resulting from the FERC’s decision and related retail proceedings should result in similar rate changes for retail customers, subject to specific circumstances that have caused trapped costs.

Comprehensive Bandwidth Recalculation for 2007, 2008, and 2009 Rate Filing Proceedings

In July 2014 the FERC issued four orders in connection with various Service Schedule MSS-3 rough production cost equalization formula compliance filings and rehearing requests. Specifically, the FERC accepted Entergy Services’ revised methodologies for calculating certain cost components of the formula and affirmed its prior ruling requiring interest on the true-up amounts. The FERC directed that a comprehensive recalculation of the formula be performed for the filing years 2007, 2008, and 2009 based on calendar years 2006, 2007, and 2008 production costs. In September 2014, Entergy filed with the FERC its compliance filing that provides the payments and receipts, including interest, among the Utility operating companies pursuant to the FERC’s orders for the 2007, 2008, and 2009 rate filing proceedings. The filing shows the following additional payments/receipts among the Utility operating companies:

<table><tr><td></td><td>Payments (Receipts)</td></tr><tr><td></td><td>(In Millions)</td></tr><tr><td>Entergy Arkansas</td><td>$38</td></tr><tr><td>Entergy Louisiana</td><td>($38)</td></tr><tr><td>Entergy Mississippi</td><td>$16</td></tr><tr><td>Entergy New Orleans</td><td>($1)</td></tr><tr><td>Entergy Texas</td><td>($15)</td></tr></table>

Entergy Arkansas and Entergy Mississippi made the payments in September and October 2014.



The FERC proceedings that resulted from rate filings made in 2007, 2008, and 2009 have been resolved by various orders issued by the FERC and appellate courts. See below for a discussion of rate filings since 2009 and the comprehensive recalculation filing directed by the FERC in the proceeding related to the 2010 rate filing.

## 2010 Rate Filing Based on Calendar Year 2009 Production Costs

In May 2010, Entergy filed with the FERC the 2010 rates in accordance with the FERC’s orders in the System Agreement proceeding, and supplemented the filing in September 2010. Several parties intervened in the proceeding at the FERC, including the LPSC and the City Council, which also filed protests. In July 2010 the FERC accepted Entergy’s proposed rates for filing, effective June 1, 2010, subject to refund, and set the proceeding for hearing and settlement procedures. Settlement procedures have been terminated, and the ALJ scheduled hearings to begin in March 2011. Subsequently, in January 2011 the ALJ issued an order directing the parties and FERC Staff to show cause why this proceeding should not be stayed pending the issuance of FERC decisions in the prior production cost proceedings currently before the FERC on review. In March 2011 the ALJ issued an order placing this proceeding in abeyance. In October 2013 the FERC issued an order granting clarification and denying rehearing with respect to its October 2011 rehearing order in this proceeding. The FERC clarified that in a bandwidth proceeding parties can challenge erroneous inputs, implementation errors, or prudence of cost inputs, but challenges to the bandwidth formula itself must be raised in a Federal Power Act section 206 complaint or section 205 filing. Subsequently in October 2013 the presiding ALJ lifted the stay order holding in abeyance the hearing previously ordered by the FERC and directing that the remaining issues proceed to a hearing on the merits. The hearing was held in March 2014 and the presiding ALJ issued an initial decision in September 2014. Briefs on exception were filed in October 2014. In December 2015 the FERC issued an order affirming the initial decision in part and rejecting the initial decision in part. Among other things, the December 2015 order directs Entergy Services to submit a compliance filing, the results of which may affect the rough production cost equalization filings made for the June - December 2005, 2006, 2007, and 2008 test periods. In January 2016 the LPSC, the APSC, and Entergy Services filed requests for rehearing of the FERC’s December 2015 order. In February 2016, Entergy Services submitted the compliance filing ordered in the December 2015 order. The result of the true-up payments and receipts for the recalculation of production costs resulted in the following payments/receipts among the Utility operating companies:

<table><tr><td></td><td>Payments (Receipts)</td></tr><tr><td></td><td>(In Millions)</td></tr><tr><td>Entergy Arkansas</td><td>$2</td></tr><tr><td>Entergy Louisiana</td><td>$6</td></tr><tr><td>Entergy Mississippi</td><td>($4)</td></tr><tr><td>Entergy New Orleans</td><td>($1)</td></tr><tr><td>Entergy Texas</td><td>($3)</td></tr></table>

## 2011 Rate Filing Based on Calendar Year 2010 Production Costs

In May 2011, Entergy filed with the FERC the 2011 rates in accordance with the FERC’s orders in the System Agreement proceeding. Several parties intervened in the proceeding at the FERC, including the LPSC, which also filed a protest. In July 2011 the FERC accepted Entergy’s proposed rates for filing, effective June 1, 2011, subject to refund, set the proceeding for hearing procedures, and then held those procedures in abeyance pending FERC decisions in the prior production cost proceedings currently before the FERC on review. In January 2014 the LPSC filed a petition for a writ of mandamus at the United States Court of Appeals for the Fifth Circuit. In its petition, the LPSC requested that the Fifth Circuit issue an order compelling the FERC to issue a final order in several proceedings related to the System Agreement, including the 2011 rate filing based on calendar year 2010 production costs and the 2012 and 2013 rate filings discussed below. In March 2014 the Fifth Circuit rejected the LPSC’s petition for a writ of mandamus. In December 2014 the FERC rescinded its earlier abeyance order and consolidated the 2011 rate filing with the 2012, 2013,



and 2014 rate filings for settlement and hearing procedures. See discussion below regarding the consolidated settlement and hearing procedures in connection with this proceeding.

## 2012 Rate Filing Based on Calendar Year 2011 Production Costs

In May 2012, Entergy filed with the FERC the 2012 rates in accordance with the FERC’s orders in the System Agreement proceeding. Several parties intervened in the proceeding at the FERC, including the LPSC, which also filed a protest. In August 2012 the FERC accepted Entergy’s proposed rates for filing, effective June 2012, subject to refund, set the proceeding for hearing procedures, and then held those procedures in abeyance pending FERC decisions in the prior production cost proceedings currently before the FERC on review. In December 2014 the FERC rescinded its earlier abeyance order and consolidated the 2012 rate filing with the 2011, 2013, and 2014 rate filings for settlement and hearing procedures. See discussion below regarding the consolidated settlement and hearing procedures in connection with this proceeding.

## 2013 Rate Filing Based on Calendar Year 2012 Production Costs

In May 2013, Entergy filed with the FERC the 2013 rates in accordance with the FERC’s orders in the System Agreement proceeding. Several parties intervened in the proceeding at the FERC, including the LPSC, which also filed a protest. The City Council intervened and filed comments related to including the outcome of a related FERC proceeding in the 2013 cost equalization calculation. In August 2013 the FERC issued an order accepting the 2013 rates, effective June 1, 2013, subject to refund, set the proceeding for hearing procedures, and then held those procedures in abeyance pending FERC decisions in the prior production cost proceedings currently before the FERC on review. In December 2014 the FERC rescinded its earlier abeyance order and consolidated the 2013 Rate Filing with the 2011, 2012, and 2014 Rate Filings for settlement and hearing procedures. See discussion below regarding the consolidated settlement and hearing procedures in connection with this proceeding.

## 2014 Rate Filing Based on Calendar Year 2013 Production Costs

In May 2014, Entergy filed with the FERC the 2014 rates in accordance with the FERC’s orders in the System Agreement proceeding. Several parties intervened in the proceeding at the FERC, including the LPSC, which also filed a protest. The City Council intervened and filed comments. In December 2014 the FERC issued an order accepting the 2014 rates, effective June 1, 2014, subject to refund, set the proceeding for hearing procedures, and consolidated the 2014 Rate Filing with the 2011, 2012, and 2013 Rate Filings for settlement and hearing procedures. See discussion below regarding the consolidated settlement and hearing procedures in connection with this proceeding.

## Consolidated 2011, 2012, 2013, and 2014 Rate Filing Proceedings

As discussed above, in December 2014 the FERC consolidated the 2011, 2012, 2013, and 2014 rate filings for settlement and hearing procedures. In May 2015, Entergy filed direct testimony in the consolidated rate filings and the LPSC filed direct testimony concerning its complaint proceeding that is consolidated with the rate filings, challenging certain components of the pending bandwidth calculations for prior years. In July 2015 the parties filed direct and answering testimony. Among other issues with the pending bandwidth calculations, the LPSC challenged the administration of the accounting for joint account sales of energy in the intra-system bill. In August and September 2015 the parties filed additional rounds of testimony in the consolidated hearing for the 2011, 2012, 2013, and 2014 rate filings. In October 2015 the LPSC withdrew its testimony challenging the accounting for joint account sales of energy. The hearings occurred in November 2015, and an initial decision from the ALJ is expected in July 2016.

## 2015 Rate Filing Based on Calendar Year 2014 Production Costs

In May 2015, Entergy filed with the FERC the 2015 rates in accordance with the FERC’s orders in the System Agreement proceeding. The filing showed that no payments and receipts were required in 2015 to implement the FERC’s remedy based on calendar year 2014 production costs. Several parties intervened in the proceeding and the



LPSC and City Council intervened and filed comments. In October 2015 the FERC accepted the 2015 rates for filing, suspended them for a nominal period, to become effective June 1, 2015, as requested, subject to refund, and set them for hearing and settlement judge procedures.

## Calendar Year 2015 Production Costs

Entergy preliminarily estimates that no payments and receipts are required in 2016 to implement the FERC’s remedy based on calendar year 2015 production costs. The actual payments/receipts for 2016, based on calendar year 2015 production costs, will not be calculated until the Utility operating companies’ 2015 FERC Form 1s have been filed. Once the calculation is completed, it will be filed at the FERC. The level of any payments and receipts is significantly affected by a number of factors, including, among others, weather, the price of alternative fuels, the operating characteristics of the Entergy System generating fleet, and multiple factors affecting the calculation of the non-fuel related revenue requirement components of the total production costs, such as plant investment. The calculation based on 2015 production costs will be the last rough production cost equalization filing submitted by the Utility operating companies because the System Agreement will terminate at the end of August 2016.

## Utility Operating Company Termination of System Agreement Participation

Entergy Arkansas and Entergy Mississippi ceased participating in the System Agreement effective December 18, 2013 and November 7, 2015, respectively. Entergy Louisiana, Entergy New Orleans, and Entergy Texas will terminate participation in the System Agreement on August 31, 2016, which will result in the termination of the System Agreement in its entirety pursuant to a settlement agreement approved by the FERC in December 2015.

In connection with the System Agreement termination settlement agreement, it was determined that the purchase power agreements, referred to as the jurisdictional separation plan PPAs, between Entergy Texas and Entergy Gulf States Louisiana that were put in place for certain legacy gas units at the time of Entergy Gulf States’s separation into Entergy Texas and Entergy Gulf States Louisiana will terminate effective with System Agreement termination. Similarly, the PPA between Entergy Gulf States Louisiana and Entergy Texas for the Calcasieu unit also will terminate. Currently, the jurisdictional separation plan PPAs are the means by which Entergy Texas receives payment for its receivable associated with Entergy Louisiana’s Spindletop gas storage facility regulatory asset. As a result of the System Agreement termination settlement agreement, effective with the termination date, Entergy Texas will no longer receive payments from Entergy Louisiana related to the Spindletop storage facility which resulted in a write-off recorded in 2015 by Entergy Texas of $23.5 million ($15.3 million net-of-tax).

## Interruptible Load Proceeding

In April 2007 the U.S. Court of Appeals for the D.C. Circuit issued its opinion in the LPSC’s appeal of the FERC’s March 2004 and April 2005 orders related to the treatment under the System Agreement of the Utility operating companies’ interruptible loads. In its opinion the D.C. Circuit concluded that the FERC (1) acted arbitrarily and capriciously by allowing the Utility operating companies to phase-in the effects of the elimination of the interruptible load over a 12-month period of time; (2) failed to adequately explain why refunds could not be ordered under Section 206(c) of the Federal Power Act; and (3) exercised appropriately its discretion to defer addressing the cost of sulfur dioxide allowances until a later time. The D.C. Circuit remanded the matter to the FERC for a more considered determination on the issue of refunds. The FERC issued its order on remand in September 2007, in which it directed Entergy to make a compliance filing removing all interruptible load from the computation of peak load responsibility commencing April 1, 2004 and to issue any necessary refunds to reflect this change. In addition, the order directed the Utility operating companies to make refunds for the period May 1995 through July 1996. In November 2007 the Utility operating companies filed a refund report describing the refunds to be issued pursuant to the FERC’s orders. The LPSC filed a protest to the refund report in December 2007, and the Utility operating companies filed an answer to the protest in January 2008. The refunds were made in October 2008 by the Utility operating companies that owed refunds to the Utility operating companies that were due a refund under the decision. The APSC and the Utility operating companies appealed the FERC decisions to the D.C. Circuit.



Following the filing of petitioners’ initial briefs, the FERC filed a motion requesting the D.C. Circuit hold the appeal of the FERC’s decisions ordering refunds in the interruptible load proceeding in abeyance and remand the record to the FERC. The D.C. Circuit granted the FERC’s unopposed motion in June 2009. In December 2009 the FERC established a paper hearing to determine whether the FERC had the authority and, if so, whether it would be appropriate to order refunds resulting from changes in the treatment of interruptible load in the allocation of capacity costs by the Utility operating companies. In August 2010 the FERC issued an order stating that it has the authority and refunds are appropriate. The APSC, MPSC, and Entergy requested rehearing of the FERC’s decision. In June 2011 the FERC issued an order granting rehearing in part and denying rehearing in part, in which the FERC determined to invoke its discretion to deny refunds. The FERC held that in this case where “the Entergy system as a whole collected the proper level of revenue, but, as was later established, incorrectly allocated peak load responsibility among the various Entergy operating companies….the Commission will apply here our usual practice in such cases, invoking our equitable discretion to not order refunds, notwithstanding our authority to do so.” The LPSC has requested rehearing of the FERC’s June 2011 decision. In July 2011 the refunds made in the fourth quarter 2009 described above were reversed. In October 2011 the FERC issued an “Order Establishing Paper Hearing” inviting parties that oppose refunds to file briefs within 30 days addressing the LPSC’s argument that FERC precedent supports refunds under the circumstances present in this proceeding. Parties that favor refunds were then invited to file reply briefs within 21 days of the date that the initial briefs are due. Briefs were submitted and the matter is pending.

In September 2010 the FERC had issued an order setting the refund report filed in the proceeding in November 2007 for hearing and settlement judge procedures. In May 2011, Entergy filed a settlement agreement that resolved all issues relating to the refund report set for hearing. In June 2011 the settlement judge certified the settlement as uncontested and the settlement agreement is currently pending before the FERC. In July 2011, Entergy filed an amended/corrected refund report and a motion to defer action on the settlement agreement until after the FERC rules on the LPSC’s rehearing request regarding the June 2011 decision denying refunds.

Prior to the FERC’s June 2011 order on rehearing, Entergy Arkansas filed an application in November 2010 with the APSC for recovery of the refund that it paid. The APSC denied Entergy Arkansas’s application, and also denied Entergy Arkansas’s petition for rehearing. If the FERC were to order Entergy Arkansas to pay refunds on rehearing in the interruptible load proceeding the APSC’s decision would trap FERC-approved costs at Entergy Arkansas with no regulatory-approved mechanism to recover them. In August 2011, Entergy Arkansas filed a complaint in the United States District Court for the Eastern District of Arkansas asking for a declaratory judgment that the rejection of Entergy Arkansas’s application by the APSC is preempted by the Federal Power Act. The APSC filed a motion to dismiss the complaint. In April 2012 the United States district court dismissed Entergy Arkansas’s complaint without prejudice stating that Entergy Arkansas’s claim is not ripe for adjudication and that Entergy Arkansas did not have standing to bring suit at this time.

In March 2013 the FERC issued an order denying the LPSC’s request for rehearing of the FERC’s June 2011 order wherein the FERC concluded it would exercise its discretion and not order refunds in the interruptible load proceeding. Based on its review of the LPSC’s request for rehearing and the briefs filed as part of the paper hearing established in October 2011, the FERC affirmed its earlier ruling and declined to order refunds under the circumstances of the case. In May 2013 the LPSC filed a petition for review with the U.S. Court of Appeals for the D.C. Circuit seeking review of FERC prior orders in the Interruptible Load Proceeding that concluded that the FERC would exercise its discretion and not order refunds in the proceeding. Oral argument was held on the appeal in the D.C. Circuit in September 2014. In December 2014 the D.C. Circuit issued an order on the LPSC’s appeal and remanded the case back to the FERC. The D.C. Circuit rejected the LPSC’s argument that there is a presumption in favor of refunds, but it held that the FERC had not adequately explained its decision to deny refunds and directed the FERC “to consider the relevant factors and weigh them against one another.” In March 2015, Entergy filed with the FERC a motion to establish a briefing schedule on remand and an initial brief on remand to address the December 2014 decision by the D.C. Circuit. The initial brief on remand argued that the FERC, in response to the D.C. Circuit decision, should clarify its policy on refunds and find that refunds are not required in the interruptible load proceeding. The matter is pending.



## Entergy Arkansas Opportunity Sales Proceeding

In June 2009, the LPSC filed a complaint requesting that the FERC determine that certain of Entergy Arkansas’s sales of electric energy to third parties: (a) violated the provisions of the System Agreement that allocate the energy generated by Entergy System resources, (b) imprudently denied the Entergy System and its ultimate consumers the benefits of low-cost Entergy System generating capacity, and (c) violated the provision of the System Agreement that prohibits sales to third parties by individual companies absent an offer of a right-of-first-refusal to other Utility operating companies. The LPSC’s complaint challenges sales made beginning in 2002 and requests refunds. In July 2009 the Utility operating companies filed a response to the complaint requesting that the FERC dismiss the complaint on the merits without hearing because the LPSC has failed to meet its burden of showing any violation of the System Agreement and failed to produce any evidence of imprudent action by the Entergy System. In their response, the Utility operating companies explained that the System Agreement clearly contemplates that the Utility operating companies may make sales to third parties for their own account, subject to the requirement that those sales be included in the load (or load shape) for the applicable Utility operating company. The response further explained that the FERC already had determined that Entergy Arkansas’s short-term wholesale sales did not trigger the “right-of-first-refusal” provision of the System Agreement. While the D.C. Circuit recently determined that the “right-of-first-refusal” issue was not properly before the FERC at the time of its earlier decision on the issue, the LPSC raised no additional claims or facts that would warrant the FERC reaching a different conclusion.

The LPSC filed direct testimony in the proceeding alleging, among other things, (1) that Entergy violated the System Agreement by permitting Entergy Arkansas to make non-requirements sales to non-affiliated third parties rather than making such energy available to the other Utility operating companies' customers; and (2) that over the period 2000 - 2009, these non-requirements sales caused harm to the Utility operating companies' customers and these customers should be compensated for this harm by Entergy. In subsequent testimony, the LPSC modified its original damages claim in favor of quantifying damages by re-running intra-system bills. The Utility operating companies believe the LPSC's allegations are without merit. A hearing in the matter was held in August 2010.

In December 2010 the ALJ issued an initial decision. The ALJ found that the System Agreement allowed for Entergy Arkansas to make the sales to third parties but concluded that the sales should be accounted for in the same manner as joint account sales. The ALJ concluded that “shareholders” should make refunds of the damages to the Utility operating companies, along with interest. Entergy disagreed with several aspects of the ALJ’s initial decision and in January 2011 filed with the FERC exceptions to the decision.

The FERC issued a decision in June 2012 and held that, while the System Agreement is ambiguous, it does provide authority for individual Utility operating companies to make opportunity sales for their own account and Entergy Arkansas made and priced these sales in good faith. The FERC found, however, that the System Agreement does not provide authority for an individual Utility operating company to allocate the energy associated with such opportunity sales as part of its load, but provides a different allocation authority. The FERC further found that the after-the-fact accounting methodology used to allocate the energy used to supply the sales was inconsistent with the System Agreement. Quantifying the effect of the FERC’s decision will require re-running intra-system bills for a ten-year period, and the FERC in its decision established further hearing procedures to determine the calculation of the effects. In July 2012, Entergy and the LPSC filed requests for rehearing of the FERC’s June 2012 decision, which are pending with the FERC.

As required by the procedural schedule established in the calculation proceeding, Entergy filed its direct testimony that included a proposed illustrative re-run, consistent with the directives in FERC’s order, of intra-system bills for 2003, 2004, and 2006, the three years with the highest volume of opportunity sales. Entergy’s proposed illustrative re-run of intra-system bills shows that the potential cost for Entergy Arkansas would be up to $12 million for the years 2003, 2004, and 2006, excluding interest, and the potential benefit would be significantly less than that for each of the other Utility operating companies. Entergy’s proposed illustrative re-run of the intra-system bills also shows an offsetting potential benefit to Entergy Arkansas for the years 2003, 2004, and 2006 resulting from the effects of the FERC’s order on System Agreement Service Schedules MSS-1, MSS-2, and MSS-3, and the potential offsetting cost



would be significantly less than that for each of the other Utility operating companies. Entergy provided to the LPSC an illustrative intra-system bill recalculation as specified by the LPSC for the years 2003, 2004, and 2006, and the LPSC then filed answering testimony in December 2012. In its testimony the LPSC claims that the damages, excluding interest, that should be paid by Entergy Arkansas to the other Utility operating company’s customers for 2003, 2004, and 2006 are $42 million to Entergy Gulf States, Inc., $7 million to Entergy Louisiana, $23 million to Entergy Mississippi, and $4 million to Entergy New Orleans. The FERC staff and certain intervenors filed direct and answering testimony in February 2013. In April 2013, Entergy filed its rebuttal testimony in that proceeding, including a revised illustrative rerun of the intra-system bills for the years 2003, 2004, and 2006. The revised calculation determines the re-pricing of the opportunity sales based on consideration of moveable resources only and the removal of exchange energy received by Entergy Arkansas, which increases the potential cost for Entergy Arkansas over the three years 2003, 2004, and 2006 by $2.3 million from the potential costs identified in the Utility operating companies’ prior filings in September and October 2012. A hearing was held in May 2013 to quantify the effect of repricing the opportunity sales in accordance with the FERC’s decision.

In August 2013 the presiding judge issued an initial decision in the calculation proceeding. The initial decision concludes that the methodology proposed by the LPSC, rather than the methodologies proposed by Entergy or the FERC Staff, should be used to calculate the payments that Entergy Arkansas is to make to the other Utility operating companies. The initial decision also concludes that the other System Agreement service schedules should not be adjusted and that payments by Entergy Arkansas should not be reflected in the rough production cost equalization bandwidth calculations for the applicable years. The initial decision does recognize that the LPSC’s methodology would result in an inequitable windfall to the other Utility operating companies and, therefore, concludes that any payments by Entergy Arkansas should be reduced by 20%. The LPSC, APSC, City Council, and FERC staff filed briefs on exceptions and/or briefs opposing exceptions. Entergy filed a brief on exceptions requesting that FERC reverse the initial decision and a brief opposing certain exceptions taken by the LPSC and FERC staff. The FERC’s review of the initial decision is pending. No payments will be made or received by the Utility operating companies until the FERC issues an order reviewing the initial decision and Entergy submits a subsequent filing to comply with that order.

## Storm Cost Recovery Filings with Retail Regulators

## Entergy Arkansas

## Entergy Arkansas December 2012 Winter Storm

In December 2012 a severe winter storm consisting of ice, snow, and high winds caused significant damage to Entergy Arkansas’s distribution lines, equipment, poles, and other facilities. Total restoration costs for the repair and/or replacement of Entergy Arkansas’s electrical facilities in areas damaged from the winter storm were $63 million, including costs recorded as regulatory assets of approximately $22 million. In the Entergy Arkansas 2013 rate case, the APSC approved inclusion of the construction spending in rate base and approved an increase in the normal storm cost accrual.

## Entergy Louisiana

## Hurricane Isaac

In August 2012, Hurricane Isaac caused extensive damage to portions of 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 January 2013, Entergy Louisiana drew $252 million, from its funded storm reserve escrow accounts. In April 2013, Entergy Louisiana filed a joint application with the LPSC relating to Hurricane Isaac system restoration costs. Specifically, Entergy Louisiana requested that the LPSC determine the amount of such costs that were prudently incurred and are, thus, eligible for recovery from customers. Including carrying costs and additional storm escrow funds for prior storms, Entergy Louisiana requested an LPSC determination that $321.5 million in system restoration costs were prudently incurred. In



May 2013, Entergy Louisiana, and the Louisiana Utilities Restoration Corporation (LURC), an instrumentality of the State of Louisiana, filed with the LPSC an application requesting that the LPSC grant financing orders authorizing the financing of Entergy Louisiana’s storm costs, storm reserves, and issuance costs pursuant to Act 55 of the Louisiana Regular Session of 2007 (Louisiana Act 55). The LPSC Staff filed direct testimony in September 2013 concluding that Hurricane Isaac system restoration costs incurred by Entergy Louisiana were reasonable and prudent, subject to proposed minor adjustments which totaled approximately 1% of the company’s costs. Following an evidentiary hearing and recommendations by the ALJ, the LPSC voted in June 2014 to approve a series of orders which (i) quantify the amount of Hurricane Isaac system restoration costs prudently incurred ($290.8 million for Entergy Louisiana); (ii) determine the level of storm reserves to be re-established ($290 million for Entergy Louisiana); (iii) authorize Entergy Louisiana to utilize Louisiana Act 55 financing for Hurricane Isaac system restoration costs; and (iv) grant other requested relief associated with storm reserves and Act 55 financing of Hurricane Isaac system restoration costs. Entergy Louisiana committed to pass on to customers a minimum of $30.8 million of customer benefits through annual customer credits of approximately $6.2 million for five years. Approvals for the Act 55 financings were obtained from the LURC and the Louisiana State Bond Commission.

In July 2014, Entergy Louisiana issued two series totaling $300 million of 3.78% Series first mortgage bonds due April 2025. Entergy Louisiana 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 $314.85 million in bonds under Louisiana Act 55. From the $309 million of bond proceeds loaned by the LCDA to the LURC, the LURC deposited $16 million in a restricted escrow account as a storm damage reserve for Entergy Louisiana and transferred $293 million directly to Entergy Louisiana. Entergy Louisiana used the $293 million received from the LURC to acquire 2,935,152.69 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.

Entergy and Entergy Louisiana do not report the bonds on their balance sheets because the bonds are the obligation of the LCDA and there is no recourse against Entergy or Entergy Louisiana in the event of a bond default. To service the bonds, Entergy Louisiana collect a system restoration charge on behalf of the LURC, and remits the collections to the bond indenture trustee. Entergy and Entergy Louisiana do not report the collections as revenue because Entergy Louisiana is merely acting as the billing and collection agent for the state.

## Hurricane Gustav and Hurricane Ike

In September 2008, Hurricane Gustav and Hurricane Ike caused catastrophic damage to Entergy’s service territory. Entergy Louisiana filed its Hurricane Gustav and Hurricane Ike storm cost recovery case with the LPSC in May 2009. In September 2009, Entergy Louisiana and the LURC filed with the LPSC an application requesting that the LPSC grant financing orders authorizing the financing of Entergy Louisiana’s storm costs, storm reserves, and issuance costs pursuant to Louisiana Act 55. Entergy Louisiana’s Hurricane Katrina and Hurricane Rita storm costs were financed primarily by Louisiana Act 55 financing, as discussed below. Entergy Louisiana also filed an application requesting LPSC approval for ancillary issues including the mechanism to flow charges and Louisiana Act 55 financing savings to customers via a Storm Cost Offset rider.

In December 2009, Entergy Louisiana entered into a stipulation agreement with the LPSC Staff that provides for total recoverable costs of approximately $628 million, including carrying costs. Under this stipulation, Entergy Louisiana agrees not to recover $11.6 million of its storm restoration spending. The stipulation also permits replenishing Entergy Louisiana’s storm reserve in the amount of $290 million when the Act 55 financings are accomplished. In



March and April 2010, Entergy Louisiana and other parties to the proceeding filed with the LPSC an uncontested stipulated settlement that includes these terms and also includes Entergy Louisiana’s proposal under the Act 55 financings, which includes a commitment to pass on to customers a minimum of $43.3 million of customer benefits through a prospective annual rate reduction of $8.7 million for five years. A stipulation hearing was held before the ALJ on April 13, 2010. On April 21, 2010, the LPSC approved the settlement and subsequently issued financing orders and a ratemaking order intended to facilitate the implementation of the Act 55 financings. In June 2010 the Louisiana State Bond Commission approved the Act 55 financing.

In July 2010, the LCDA issued two series totaling $713.0 million in bonds under Act 55. From the $702.7 million of bond proceeds loaned by the LCDA to the LURC, the LURC deposited $290 million in a restricted escrow account as a storm damage reserve for Entergy Louisiana and transferred $412.7 million directly to Entergy Louisiana. From the bond proceeds received by Entergy Louisiana from the LURC, Entergy Louisiana used $412.7 million to acquire 4,126,940.15 Class B preferred, non-voting, membership interest units of Entergy Holdings Company LLC, a company wholly-owned and consolidated by Entergy, that carry a 9% annual distribution rate. Distributions are payable quarterly commencing on September 15, 2010, 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 billion.

Entergy and Entergy Louisiana do not report the bonds on their balance sheets because the bonds are the obligation of the LCDA, and there is no recourse against Entergy or Entergy Louisiana in the event of a bond default. To service the bonds, Entergy Louisiana collects a system restoration charge on behalf of the LURC, and remits the collections to the bond indenture trustee. Entergy and Entergy Louisiana do not report the collections as revenue because Entergy Louisiana is merely acting as the billing and collection agent for the state.

## Hurricane Katrina and Hurricane Rita

In August and September 2005, Hurricanes Katrina and Rita caused catastrophic damage to large portions of the Utility’s service territories in Louisiana, Mississippi, and Texas, including the effect of extensive flooding that resulted from levee breaks in and around the greater New Orleans area. The storms and flooding resulted in widespread power outages, significant damage to electric distribution, transmission, and generation and gas infrastructure, and the loss of sales and customers due to mandatory evacuations and the destruction of homes and businesses.

In March 2008, Entergy Louisiana and the LURC filed at the LPSC an application requesting that the LPSC grant a financing order authorizing the financing of Entergy Louisiana storm costs, storm reserves, and issuance costs pursuant to Louisiana Act 55. The Louisiana Act 55 financing is expected to produce additional customer benefits as compared to traditional securitization. Entergy Louisiana also filed an application requesting LPSC approval for ancillary issues including the mechanism to flow charges and savings to customers via a Storm Cost Offset rider. On April 8, 2008, the Louisiana Public Facilities Authority (LPFA), which is the issuer of the bonds pursuant to the Act 55 financing, approved requests for the Act 55 financing. On April 10, 2008, Entergy Louisiana and the LPSC Staff filed with the LPSC an uncontested stipulated settlement that includes Entergy Louisiana’s proposal under the Act 55 financing, which includes a commitment to pass on to customers a minimum of $40 million of customer benefits through a prospective annual rate reduction of $8 million for five years. On April 16, 2008, the LPSC approved the settlement and issued two financing orders and one ratemaking order intended to facilitate implementation of the Act 55 financing. In May 2008 the Louisiana State Bond Commission granted final approval of the Act 55 financing.

In July 2008, the LPFA issued $687.7 million in bonds under the aforementioned Act 55. From the $679 million of bond proceeds loaned by the LPFA to the LURC, the LURC deposited $152 million in a restricted escrow account as a storm damage reserve for Entergy Louisiana and transferred $527 million directly to Entergy Louisiana. From the bond proceeds received by Entergy Louisiana from the LURC, Entergy Louisiana invested $545 million, including $17.8 million that was withdrawn from the restricted escrow account as approved by the April 16, 2008 LPSC orders, in



exchange for 5,449,861.85 Class A preferred, non-voting, membership interest units of Entergy Holdings Company LLC, a company wholly-owned and consolidated by Entergy, that carry a 10% annual distribution rate. In August 2008, the LPFA issued $278.4 million in bonds under the aforementioned Act 55. From the $274.7 million of bond proceeds loaned by the LPFA to the LURC, the LURC deposited $87 million in a restricted escrow account as a storm damage reserve for Entergy Louisiana and transferred $187.7 million directly to Entergy Louisiana. From the bond proceeds received by Entergy Louisiana from the LURC, Entergy Louisiana invested $189.4 million, including $1.7 million that was withdrawn from the restricted escrow account as approved by the April 16, 2008 LPSC orders, in exchange for 1,893,918.39 Class A preferred, non-voting, membership interest units of Entergy Holdings Company LLC that carry a 10% annual distribution rate. Distributions are payable quarterly commencing on September 15, 2008 and 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 billion. In February 2012, Entergy Louisiana sold 500,000 of its Class A preferred membership units in Entergy Holdings Company LLC, a wholly-owned Entergy subsidiary, to a third party in exchange for $51 million plus accrued but unpaid distributions on the units. The 500,000 preferred membership units are mandatorily redeemable in January 2112.

Entergy and Entergy Louisiana do not report the bonds on their balance sheets because the bonds are the obligation of the LPFA, and there is no recourse against Entergy or Entergy Louisiana in the event of a bond default. To service the bonds, Entergy Louisiana collect a system restoration charge on behalf of the LURC, and remits the collections to the bond indenture trustee. Entergy and Entergy Louisiana do not report the collections as revenue because Entergy Louisiana is merely acting as the billing and collection agent for the state.

## Entergy Mississippi

On July 1, 2013, Entergy Mississippi and the Mississippi Public Utilities Staff entered into a joint stipulation, wherein both parties agreed that approximately $32 million in storm restoration costs incurred in 2011 and 2012 were prudently incurred and chargeable to the storm damage provision, 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. In February 2015, Entergy Mississippi provided notice to the Mississippi Public Utilities Staff that the storm damage accrual would be set to zero effective with the March 2015 billing cycle as a result of Entergy Mississippi’s storm damage accrual balance exceeding $15 million as of January 31, 2015, but will return to its current level when the storm damage accrual balance becomes less than $10 million.

## Entergy New Orleans

In October 2006 the City Council approved a rate filing settlement agreement that, among other things, authorized a $75 million storm reserve for damage from future storms, which will be created over a ten-year period through a storm reserve rider that began in March 2007. These storm reserve funds are held in a restricted escrow account until needed in response to a storm.

In August 2012, Hurricane Isaac caused extensive damage to Entergy New Orleans’s service area. The storm resulted in widespread power outages, significant damage primarily to distribution infrastructure, and the loss of sales during the power outages. Total restoration costs for the repair and/or replacement of Entergy New Orleans’s electric facilities damaged by Hurricane Isaac were $47.3 million. Entergy New Orleans withdrew $17.4 million from the storm reserve escrow account to partially offset these costs. In February 2014, Entergy New Orleans made a filing with the City Council seeking certification of the Hurricane Isaac costs. In January 2015 the City Council issued a resolution approving the terms of a joint agreement in principle filed by Entergy New Orleans, Entergy Louisiana, and the City Council Advisors determining, among other things, that Entergy New Orleans’s prudently-incurred storm recovery costs were $49.3 million, of which $31.7 million, net of reimbursements from the storm reserve escrow account, remains



recoverable from Entergy New Orleans’s electric customers. The resolution also directs Entergy New Orleans to file an application to securitize the unrecovered Council-approved storm recovery costs of $31.7 million pursuant to the Louisiana Electric Utility Storm Recovery Securitization Act (Louisiana Act 64). In addition, the resolution found that it is reasonable for Entergy New Orleans to include in the principal amount of its potential securitization the costs to fund and replenish Entergy New Orleans’s storm reserve in an amount that achieves the Council-approved funding level of $75 million. In January 2015, in compliance with that directive, Entergy New Orleans filed with the City Council an application requesting that the City Council grant a financing order authorizing the financing of Entergy New Orleans’s storm costs, storm reserves, and issuance costs pursuant to Louisiana Act 64. In April 2015 the City Council’s Utility advisors filed direct testimony recommending that the proposed securitization be approved subject to certain limited modifications, and Entergy New Orleans filed rebuttal testimony later in April 2015. In May 2015 the parties entered into an agreement in principle and the City Council issued a financing order authorizing Entergy New Orleans to issue storm recovery bonds in the aggregate amount of $98.7 million, including $31.8 million for recovery of Entergy New Orleans’s Hurricane Isaac storm recovery costs, including carrying costs, $63.9 million to fund and replenish Entergy New Orleans’s storm reserve, and approximately $3 million for estimated up-front financing costs associated with the securitization. See Note 5 to the financial statements for discussion of the issuance of the securitization bonds in July 2015.

## New Nuclear Generation Development Costs

## Entergy Louisiana

Entergy Louisiana and Entergy Gulf States Louisiana were developing a project option for new nuclear generation at River Bend. In March 2010, Entergy Louisiana and Entergy Gulf States Louisiana filed with the LPSC seeking approval to continue the limited development activities necessary to preserve an option to construct a new unit at River Bend. At its June 2012 meeting the LPSC voted to uphold an ALJ recommendation that the request of Entergy Louisiana and Entergy Gulf States Louisiana be declined on the basis that the LPSC’s rule on new nuclear development does not apply to activities to preserve an option to develop and on the further grounds that the companies improperly engaged in advanced preparation activities prior to certification. The LPSC directed that Entergy Louisiana and Entergy Gulf States Louisiana be permitted to seek recovery of these costs in their upcoming rate case filings that were subsequently filed in February 2013. In the resolution of the rate case proceeding the LPSC provided for an eight-year amortization of costs incurred in connection with the potential development of new nuclear generation at River Bend, without carrying costs, beginning in December 2014, provided, however, that amortization of these costs shall not result in a future rate increase. As of December 31, 2015, Entergy Louisiana has a regulatory asset of $50.4 million on its balance sheet related to these new nuclear generation development costs.

## Entergy Mississippi

Pursuant to the Mississippi Baseload Act and the Mississippi Public Utilities Act, Entergy Mississippi had been developing and preserving a project option for new nuclear generation at Grand Gulf Nuclear Station. In October 2010, Entergy Mississippi filed an application with the MPSC requesting that the MPSC determine that it was in the public interest to preserve the option to construct new nuclear generation at Grand Gulf and that the MPSC approve the deferral of Entergy Mississippi’s costs incurred to date and in the future related to this project, including the accrual of AFUDC or similar carrying charges. In October 2011, Entergy Mississippi and the Mississippi Public Utilities Staff filed with the MPSC a joint stipulation that the MPSC approved in November 2011. The stipulation stated that there should be a deferral of the $57 million of costs incurred through September 2011 in connection with planning, evaluation, monitoring, and other and related generation resource development activities for new nuclear generation at Grand Gulf.

In October 2014, Entergy Mississippi and the Mississippi Public Utilities Staff entered into and filed joint stipulations in Entergy Mississippi’s general rate case proceeding, which are discussed above. In consideration of the comprehensive terms for settlement in that rate case proceeding, the Mississippi Public Utilities Staff and Entergy Mississippi agreed that Entergy Mississippi would request consolidation of the new nuclear generation development costs proceeding with the rate case proceeding for hearing purposes and will not further pursue, except as noted below,



recovery of the costs deferred by MPSC order in the new nuclear generation development docket. The stipulations state, however, that, if Entergy Mississippi decides to move forward with nuclear development in Mississippi, it can at that time re-present for consideration by the MPSC only those costs directly associated with the existing early site permit (ESP), to the extent that the costs are verifiable and prudent and the ESP is still valid and relevant to any such option pursued. After considering the progress of the new nuclear generation costs proceeding in light of the joint stipulations, Entergy Mississippi recorded in 2014 a $56.2 million pre-tax charge to recognize that the regulatory asset associated with new nuclear generation development is no longer probable of recovery. In December 2014 the MPSC issued an order accepting in their entirety the October 2014 stipulations, including the findings and terms of the stipulations regarding new nuclear generation development costs.

## Texas Power Price Lawsuit

In August 2003, a lawsuit was filed in the district court of Chambers County, Texas by Texas residents on behalf of a purported class of the Texas retail customers of Entergy Gulf States, Inc. who were billed and paid for electric power from January 1, 1994 to the present. The named defendants include Entergy Corporation, Entergy Services, Entergy Power, Entergy Power Marketing Corp., and Entergy Arkansas. Entergy Gulf States, Inc. was not a named defendant, but was alleged to be a co-conspirator. The court granted the request of Entergy Gulf States, Inc. to intervene in the lawsuit to protect its interests.

Plaintiff's allege that the defendants implemented a “price gouging accounting scheme” to sell to plaintiffs and similarly situated utility customers higher priced power generated by the defendants while rejecting less expensive power offered from off-system suppliers. In particular, plaintiffs allege that the defendants manipulated and continue to manipulate the dispatch of generation so that power is purchased from affiliated expensive resources instead of buying cheaper off-system power.

Plaintiff's stated in their pleadings that customers in Texas were charged at least $57 million above prevailing market prices for power. Plaintiffs seek actual, consequential and exemplary damages, costs and attorneys' fees, and disgorgement of profits. The plaintiffs' experts have tendered a report calculating damages in a large range, from $153 million to $972 million in present value, under various scenarios as of the date of the report. The Entergy defendants have tendered expert reports challenging the assumptions, methodologies, and conclusions of the plaintiffs' expert reports.

In March 2012 the state district court found that the case met the requirements to be maintained as a class action under Texas law. In April 2012 the court entered an order certifying the class. The defendants appealed the order to the Texas Court of Appeals – First District and oral argument was held in May 2013. In November 2014 the Texas Court of Appeals - First District reversed the state district court’s class certification order and dismissed the case holding that the state district court lacked subject matter jurisdiction to address the issues. Plaintiffs filed a motion for rehearing and a motion for rehearing en banc. In May 2015 the Court of Appeals granted plaintiffs’ motion for rehearing, withdrew its prior opinion, and set the case for resubmission in June 2015. In July 2015 the Court of Appeals issued a new opinion again finding that the plaintiffs’ claims fall within the exclusive jurisdiction of the FERC and, therefore, the trial court lacked subject matter jurisdiction over the case. The Court of Appeals ordered that the state district court dismiss all claims against the Entergy defendants. In September 2015 plaintiffs filed a petition for review at the Supreme Court of Texas. At the request of the Court, the Entergy defendants filed a response in December 2015. In January 2016 the Supreme Court of Texas issued an order requiring the parties to file briefs on the merits.



## NOTE 3. INCOME TAXES

Income taxes for 2015, 2014, and 2013 for Entergy Corporation and Subsidiaries consist of the following:

<table><tr><td></td><td>2015</td><td>2014</td><td>2013</td></tr><tr><td></td><td colspan="3">(In Thousands)</td></tr><tr><td>Current:</td><td></td><td></td><td></td></tr><tr><td>Federal</td><td>$77,166</td><td>$90,061</td><td>$88,291</td></tr><tr><td>Foreign</td><td>97</td><td>90</td><td>101</td></tr><tr><td>State</td><td>157,829</td><td>(12,637)</td><td>20,584</td></tr><tr><td>Total</td><td>235,092</td><td>77,514</td><td>108,976</td></tr><tr><td>Deferred and non-current - net</td><td>(864,799)</td><td>528,326</td><td>126,935</td></tr><tr><td>Investment tax credit adjustments - net</td><td>(13,220)</td><td>(16,243)</td><td>(9,930)</td></tr><tr><td>Income taxes</td><td>($642,927)</td><td>$589,597</td><td>$225,981</td></tr></table>

Total income taxes for Entergy Corporation and Subsidiaries differ from the amounts computed by applying the statutory income tax rate to income before income taxes. The reasons for the differences for the years 2015, 2014, and 2013 are:

<table><tr><td></td><td>2015</td><td>2014</td><td>2013</td></tr><tr><td></td><td colspan="3">(In Thousands)</td></tr><tr><td>Net income (loss) attributable to Entergy Corporation</td><td>($176,562)</td><td>$940,721</td><td>$711,902</td></tr><tr><td>Preferred dividend requirements of subsidiaries</td><td>19,828</td><td>19,536</td><td>18,670</td></tr><tr><td>Consolidated net income (loss)</td><td>(156,734)</td><td>960,257</td><td>730,572</td></tr><tr><td>Income taxes</td><td>(642,927)</td><td>589,597</td><td>225,981</td></tr><tr><td>Income (loss) before income taxes</td><td>($799,661)</td><td>$1,549,854</td><td>$956,553</td></tr><tr><td>Computed at statutory rate (35%)</td><td>($279,881)</td><td>$542,449</td><td>$334,794</td></tr><tr><td>Increases (reductions) in tax resulting from:</td><td></td><td></td><td></td></tr><tr><td>State income taxes net of federal income tax effect</td><td>29,944</td><td>44,708</td><td>13,599</td></tr><tr><td>Regulatory differences - utility plant items</td><td>32,089</td><td>39,321</td><td>32,324</td></tr><tr><td>Equity component of AFUDC</td><td>(18,191)</td><td>(21,108)</td><td>(22,356)</td></tr><tr><td>Amortization of investment tax credits</td><td>(11,136)</td><td>(12,211)</td><td>(13,535)</td></tr><tr><td>Flow-through / permanent differences</td><td>(7,872)</td><td>(18,003)</td><td>(301)</td></tr><tr><td>Net-of-tax regulatory liability</td><td>—</td><td>—</td><td>(2,899)</td></tr><tr><td>New York tax law change (a)</td><td>—</td><td>(21,500)</td><td>—</td></tr><tr><td>Louisiana business combination</td><td>(333,655)</td><td>—</td><td>—</td></tr><tr><td>Termination of business reorganization</td><td>—</td><td>—</td><td>(27,192)</td></tr><tr><td>Provision for uncertain tax positions (b)</td><td>(56,683)</td><td>32,573</td><td>(59,249)</td></tr><tr><td>Valuation allowance</td><td>—</td><td>—</td><td>(31,573)</td></tr><tr><td>Other - net</td><td>2,458</td><td>3,368</td><td>2,369</td></tr><tr><td>Total income taxes as reported</td><td>($642,927)</td><td>$589,597</td><td>$225,981</td></tr><tr><td>Effective Income Tax Rate</td><td>80.4%</td><td>38.0%</td><td>23.6%</td></tr></table>

(a) In March 2014, New York enacted legislation that substantially modifies various aspects of New York tax law. The most significant effect of the legislation for Entergy is the adoption of full water’s-edge unitary combined reporting, meaning that all of Entergy’s domestic entities will be included in New York’s combined filing group. The effect of the tax law change resulted in a deferred state income tax reduction of approximately $21.5 million as shown in the table above.



(b) See “Income Tax Audits - 2008-2009 IRS Audit” below for discussion of the most significant items for 2015 and 2013.

Significant components of accumulated deferred income taxes and taxes accrued for Entergy Corporation and Subsidiaries as of December 31, 2015 and 2014 are as follows:

<table><tr><td></td><td>2015</td><td>2014</td></tr><tr><td></td><td colspan="2">(In Thousands)</td></tr><tr><td>Deferred tax liabilities:</td><td></td><td></td></tr><tr><td>Plant basis differences - net</td><td>($6,804,225)</td><td>($8,128,096)</td></tr><tr><td>Regulatory assets</td><td>(646,392)</td><td>(922,161)</td></tr><tr><td>Nuclear decommissioning trusts</td><td>(1,254,463)</td><td>(1,248,737)</td></tr><tr><td>Pension, net funding</td><td>(365,111)</td><td>(324,881)</td></tr><tr><td>Combined unitary state taxes</td><td>(45,078)</td><td>(162,340)</td></tr><tr><td>Power purchase agreements</td><td>—</td><td>(110,889)</td></tr><tr><td>Other</td><td>(315,844)</td><td>(500,424)</td></tr><tr><td>Total</td><td>(9,431,113)</td><td>(11,397,528)</td></tr><tr><td>Deferred tax assets:</td><td></td><td></td></tr><tr><td>Nuclear decommissioning liabilities</td><td>828,983</td><td>874,493</td></tr><tr><td>Regulatory liabilities</td><td>284,432</td><td>458,230</td></tr><tr><td>Pension and other post-employment benefits</td><td>525,524</td><td>586,455</td></tr><tr><td>Sale and leaseback</td><td>139,720</td><td>153,308</td></tr><tr><td>Compensation</td><td>69,432</td><td>74,692</td></tr><tr><td>Accumulated deferred investment tax credit</td><td>95,248</td><td>100,442</td></tr><tr><td>Provision for allowances and contingencies</td><td>188,282</td><td>160,551</td></tr><tr><td>Power purchase agreements</td><td>38,401</td><td>—</td></tr><tr><td>Net operating loss carryforwards</td><td>360,188</td><td>457,758</td></tr><tr><td>Capital losses and miscellaneous tax credits</td><td>11,075</td><td>12,146</td></tr><tr><td>Valuation allowance</td><td>(91,532)</td><td>(27,387)</td></tr><tr><td>Other</td><td>68,204</td><td>58,334</td></tr><tr><td>Total</td><td>2,517,957</td><td>2,909,022</td></tr><tr><td>Non-current accrued taxes (including unrecognized tax benefits)</td><td>(1,338,806)</td><td>(606,560)</td></tr><tr><td>Accumulated deferred income taxes and taxes accrued</td><td>($8,251,962)</td><td>($9,095,066)</td></tr></table>

Entergy’s estimated tax attributes carryovers and their expiration dates as of December 31, 2015 are as follows:

<table><tr><td>Carryover Description</td><td>Carryover Amount</td><td>Year(s) of expiration</td></tr><tr><td>Federal net operating losses</td><td>$3.6 billion</td><td>2023-2035</td></tr><tr><td>State net operating losses</td><td>$5.2 billion</td><td>2016-2035</td></tr><tr><td>Miscellaneous federal and state credits</td><td>$77.9 million</td><td>2016-2035</td></tr></table>

As a result of the accounting for uncertain tax positions, the amount of the deferred tax assets reflected in the financial statements is less than the amount of the tax effect of the federal and state net operating loss carryovers, tax credit carryovers, and other tax attributes reflected on income tax returns. Because it is more likely than not that the benefit from certain state net operating loss carryovers will not be utilized, valuation allowances of $46 million as of December 31, 2015 and $21 million as of December 31, 2014 have been provided on the deferred tax assets relating to



these state net operating loss carryovers. Additionally, valuation allowances totaling $45.5 million as of December 31, 2015 have been provided on deferred tax assets related to state jurisdictions in which Entergy does not currently expect to be able to utilize separate company tax return losses, preventing realization of such deferred tax assets.

## Unrecognized tax benefits

Accounting standards establish a “more-likely-than-not” recognition threshold that must be met before a tax benefit can be recognized in the financial statements. If a tax deduction is taken on a tax return, but does not meet the more-likely-than-not recognition threshold, an increase in income tax liability, above what is payable on the tax return, is required to be recorded. A reconciliation of Entergy’s beginning and ending amount of unrecognized tax benefits is as follows:

<table><tr><td></td><td>2015</td><td>2014</td><td>2013</td></tr><tr><td></td><td colspan="3">(In Thousands)</td></tr><tr><td>Gross balance at January 1</td><td>$4,736,785</td><td>$4,593,224</td><td>$4,170,403</td></tr><tr><td>Additions based on tax positions related to the current year</td><td>1,850,705</td><td>348,543</td><td>162,338</td></tr><tr><td>Additions for tax positions of prior years</td><td>59,815</td><td>11,637</td><td>410,108</td></tr><tr><td>Reductions for tax positions of prior years (a)</td><td>(3,966,535)</td><td>(213,401)</td><td>(103,360)</td></tr><tr><td>Settlements</td><td>(68,227)</td><td>—</td><td>(43,620)</td></tr><tr><td>Lapse of statute of limitations</td><td>(958)</td><td>(3,218)</td><td>(2,645)</td></tr><tr><td>Gross balance at December 31</td><td>2,611,585</td><td>4,736,785</td><td>4,593,224</td></tr><tr><td>Offsets to gross unrecognized tax benefits:</td><td></td><td></td><td></td></tr><tr><td>Credit and loss carryovers</td><td>(1,264,483)</td><td>(4,295,643)</td><td>(4,400,498)</td></tr><tr><td>Unrecognized tax benefits net of unused tax attributes and payments (b)</td><td>$1,347,102</td><td>$441,142</td><td>$192,726</td></tr></table>

(a) The primary reduction is related to the nuclear decommissioning costs treatment discussed in “Income Tax Audits - 2008-2009 IRS Audit” below.

(b) Potential tax liability above what is payable on tax returns

The balances of unrecognized tax benefits include $955 million, $516 million, and $176 million as of December 31, 2015, 2014, and 2013, respectively, which, if recognized, would lower the effective income tax rates. Because of the effect of deferred tax accounting, the remaining balances of unrecognized tax benefits of $1.657 billion, $4.221 billion, and $4.417 billion as of December 31, 2015, 2014, and 2013, respectively, if disallowed, would not affect the annual effective income tax rate but would accelerate the payment of cash to the taxing authority to an earlier period.

Entergy accrues interest expense, if any, related to unrecognized tax benefits in income tax expense. Entergy’s December 31, 2015, 2014, and 2013 accrued balance for the possible payment of interest is approximately $27 million, $127 million, and $96.4 million, respectively.

## Income Tax Audits

Entergy and its subsidiaries file U.S. federal and various state and foreign income tax returns. IRS examinations are complete for years before 2010. All state taxing authorities’ examinations are completed for years before 2009.

## 2006-2007 IRS Audit

In the first quarter 2015, the IRS finalized tax and interest computations from the 2006-2007 audit that resulted in a reversal of Entergy’s provision for uncertain tax positions related to accrued interest of approximately $20 million,



including decreases of approximately $4 million for Entergy Arkansas, $11 million for Entergy Louisiana, and $1 million for System Energy.

## 2008-2009 IRS Audit

In the fourth quarter 2009, Entergy filed Applications for Change in Accounting Method (the “2009 CAM”) for tax purposes with the IRS for certain costs under Section 263A of the Internal Revenue Code. In the Applications, Entergy proposed to treat the nuclear decommissioning liability associated with the operation of its nuclear power plants as a production cost properly includable in cost of goods sold. The effect of the 2009 CAM was a $5.7 billion reduction in 2009 taxable income. The 2009 CAM was adjusted to $9.3 billion in 2012.

In the fourth quarter 2012 the IRS disallowed the reduction to 2009 taxable income related to the 2009 CAM. In the third quarter 2013, the Internal Revenue Service issued its RAR for the tax years 2008-2009. As a result of the issuance of this RAR, Entergy and the IRS resolved all of the 2008-2009 issues described above except for the 2009 CAM. Entergy disagreed with the IRS’s disallowance of the 2009 CAM and filed a protest with the IRS Appeals Division in October 2013.

In August 2015, Entergy and the IRS agreed on the treatment of the 2009 position regarding nuclear decommissioning liabilities from the 2008-2009 audit. The agreement provides that Entergy is entitled to deduct approximately $118 million of the $9.3 billion claimed in 2009. The agreement effectively settled all matters pertaining to the 2009 tax year and increased Entergy’s 2009 federal income tax liability by $2.4 million.

## 2010-2011 IRS Audit

The IRS examination of the 2010 and 2011 years is ongoing and the audit field work is expected to be completed by the end of the first quarter of 2016. The IRS has not issued any significant notices of proposed adjustments other than for the decommissioning liability position discussed above. The Revenue Agent’s Report is expected to be received shortly after the completion of field work.

## Other Tax Matters

Entergy regularly negotiates with the IRS to achieve settlements. The resolution of audit issues could result in significant changes to the amounts of unrecognized tax benefits in the next twelve months.

In September 2013 the U.S. Treasury Department and the IRS issued final regulations that provide guidance on the deductibility and capitalization of costs incurred associated with tangible property. Entergy and the Registrant Subsidiaries filed with the IRS an automatic application for change in accounting method which is in compliance with the final regulations and the safe harbor provisions of the relevant IRS Revenue Procedures. Entergy estimates that the effect of this accounting method change will result in a net increase to Entergy’s taxable income of approximately $585 million, which will be recognized generally over a four year period beginning with the tax year ended 2014. The adoption of the final regulations and safe harbor method results in approximate changes in the Registrant Subsidiaries taxable income as follows: an increase of $177 million for Entergy Arkansas, an increase of $78 million for Entergy Louisiana, an increase of $26 million for Entergy Mississippi, an increase of $183 million for Entergy Texas, a decrease of $2 million for Entergy New Orleans, and an increase of $22 million for System Energy.

In October 2015 two of Entergy’s Louisiana utilities, Entergy Gulf States Louisiana and Entergy Louisiana, combined their businesses into a legal entity which is identified as Entergy Louisiana herein. Entergy Louisiana maintained a carryover tax basis in the assets received. Additionally, the tax consequences provided for an increase in tax basis as well. To the extent that this increase in tax basis will provide additional tax depreciation, Entergy recorded a deferred tax asset and current tax expense resulting in a net increase in tax basis of approximately $334 million and Entergy Louisiana obtained a corresponding deferred tax asset. Consistent with the terms of an agreement with the LPSC, electric customers of Entergy Louisiana will realize customer credits associated with the business combination.



Accordingly, in October 2015, Entergy recorded a regulatory liability of $107 million ($66 million net-of-tax) which partially offsets the effect of the aforementioned deferred tax asset. The deferred tax asset and the regulatory liability, net-of-tax, increased Entergy Louisiana’s member’s equity by $268 million. See Note 2 to the financial statements for further discussion of the business combination.

In the fourth quarter 2015, System Energy and Entergy Louisiana adopted a new method of accounting for income tax purposes in which the companies’ nuclear decommissioning costs will be treated as production costs of electricity includable in cost of goods sold. The new method results in a reduction of taxable income of $1.2 billion for System Energy and $2.2 billion for Entergy Louisiana.

The Protecting Americans from Tax Hikes Act of 2015 was enacted in December 2015. The most significant provisions affecting Entergy and the Registrant Subsidiaries were a five-year extension of bonus depreciation and permanent extension of the research and experimentation tax credit. The effect of the bonus depreciation extension on 2015 increased Entergy’s tax net operating loss.

## NOTE 4. REVOLVING CREDIT FACILITIES, LINES OF CREDIT, AND SHORT-TERM BORROWINGS

Entergy Corporation has in place a credit facility that has a borrowing capacity of $3.5 billion and expires in August 2020. Entergy Corporation also has the ability to issue letters of credit against 50% of the total borrowing capacity of the credit 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, 2015 was 1.98% on the drawn portion of the facility. Following is a summary of the borrowings outstanding and capacity available under the facility as of December 31, 2015.

<table><tr><td>Capacity (a)</td><td>Borrowings</td><td>Letters of Credit</td><td>Capacity Available</td></tr><tr><td>$3,500</td><td>$835</td><td>$9</td><td>$2,656</td></tr></table>

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

Entergy Corporation has a commercial paper program with a Board-approved program limit of up to $1.5 billion. At December 31, 2015, Entergy Corporation had $422 million of commercial paper outstanding. The weighted-average interest rate for the year ended December 31, 2015 was 0.90%.



Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas each had credit facilities available as of December 31, 2015 as follows:

<table><tr><td>Company</td><td>Expiration Date</td><td>Amount of Facility</td><td>Interest Rate (a)</td><td>Amount Drawn as of December 31, 2015</td><td>Letters of Credit Outstanding as of December 31, 2015</td></tr><tr><td>Entergy Arkansas</td><td>April 2016</td><td>$20 million (b)</td><td>1.92%</td><td>—</td><td>—</td></tr><tr><td>Entergy Arkansas</td><td>August 2020</td><td>$150 million (c)</td><td>1.92%</td><td>—</td><td>—</td></tr><tr><td>Entergy Louisiana</td><td>August 2020</td><td>$350 million (d)</td><td>1.67%</td><td>—</td><td>$3.1 million</td></tr><tr><td>Entergy Mississippi</td><td>May 2016</td><td>$10 million (e)</td><td>1.92%</td><td>—</td><td>—</td></tr><tr><td>Entergy Mississippi</td><td>May 2016</td><td>$20 million (e)</td><td>1.92%</td><td>—</td><td>—</td></tr><tr><td>Entergy Mississippi</td><td>May 2016</td><td>$35 million (e)</td><td>1.92%</td><td>—</td><td>—</td></tr><tr><td>Entergy Mississippi</td><td>May 2016</td><td>$37.5 million (e)</td><td>1.92%</td><td>—</td><td>—</td></tr><tr><td>Entergy New Orleans</td><td>November 2018</td><td>$25 million</td><td>2.17%</td><td>—</td><td>—</td></tr><tr><td>Entergy Texas</td><td>August 2020</td><td>$150 million (f)</td><td>1.92%</td><td>—</td><td>$1.3 million</td></tr></table>

(a) The interest rate is the rate as of December 31, 2015 that would be applied to outstanding borrowings under the facility.

(b) Borrowings under this Entergy Arkansas credit facility may be secured by a security interest in its accounts 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.

(d) The credit facility allows Entergy Louisiana to issue letters of credit against 50% of the borrowing capacity of the facility.

(e) Borrowings under the Entergy Mississippi credit facilities may be secured by a security interest in its accounts receivable at Entergy Mississippi’s option.

(f) The credit facility allows Entergy Texas to issue letters of credit against 50% of the borrowing capacity of the facility.

The commitment fees on the credit facilities range from 0.125% to 0.275% of the undrawn commitment amount. Each of the credit facilities 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 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, 2015:

<table><tr><td>Company</td><td>Amount of Uncommitted Facility</td><td>Letter of Credit Fee</td><td>Letters of Credit Issued as of December 31, 2015</td></tr><tr><td>Entergy Arkansas</td><td>$25 million</td><td>0.70%</td><td>$1.0 million</td></tr><tr><td>Entergy Louisiana</td><td>$125 million</td><td>0.70%</td><td>$17.1 million</td></tr><tr><td>Entergy Mississippi</td><td>$40 million</td><td>0.70%</td><td>$6.0 million</td></tr><tr><td>Entergy New Orleans</td><td>$15 million</td><td>0.75%</td><td>$1.4 million</td></tr><tr><td>Entergy Texas</td><td>$50 million</td><td>0.70%</td><td>$9.4 million</td></tr></table>

The short-term borrowings of the Registrant Subsidiaries are limited to amounts authorized by the FERC. The current FERC-authorized limits are effective through October 31, 2017. In addition to borrowings from commercial banks, these companies may also borrow from the Entergy System money pool. The money pool is an inter-company



borrowing arrangement designed to reduce the Utility subsidiaries’ dependence on external short-term borrowings. Borrowings from the money pool and external short-term borrowings combined may not exceed the FERC-authorized limits. The following are the FERC-authorized limits for short-term borrowings and the outstanding short-term borrowings as of December 31, 2015 (aggregating both money pool and external short-term borrowings) for the Registrant Subsidiaries:

<table><tr><td></td><td>Authorized</td><td>Borrowings</td></tr><tr><td></td><td colspan="2">(In Millions)</td></tr><tr><td>Entergy Arkansas</td><td>$250</td><td>$52.7</td></tr><tr><td>Entergy Louisiana</td><td>$450</td><td>—</td></tr><tr><td>Entergy Mississippi</td><td>$175</td><td>—</td></tr><tr><td>Entergy New Orleans</td><td>$100</td><td>—</td></tr><tr><td>Entergy Texas</td><td>$200</td><td>$22.1</td></tr><tr><td>System Energy</td><td>$200</td><td>—</td></tr></table>

## Entergy Nuclear Vermont Yankee Credit Facilities

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. Entergy Nuclear Vermont Yankee does not have the ability to issue letters of credit against this facility. This facility provides working capital to Entergy Nuclear Vermont Yankee for general business purposes including, without limitation, the decommissioning of Entergy Nuclear Vermont Yankee’s nuclear facilities. The commitment fee is currently 0.25% of the undrawn commitment amount. As of December 31, 2015, $12 million was outstanding on the facility. The weighted average interest rate for the year ended December 31, 2015 was 2.08% on the drawn portion of the facility.

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. Entergy Nuclear Vermont Yankee does not have the ability to issue letters of credit against this facility. This facility provides an additional funding source to Entergy Nuclear Vermont Yankee for general business purposes including, without limitation, the decommissioning of Entergy Nuclear Vermont Yankee’s nuclear facilities. As of December 31, 2015, no amounts were outstanding under the facility. The rate as of December 31, 2015 that would most likely apply to outstanding borrowings under the facility was 2.17% on the drawn portion of the facility.

## Variable Interest Entities

See Note 18 to the financial statements for a discussion of the consolidation of the nuclear fuel company variable interest entities (VIE). The nuclear fuel company variable interest entities have credit facilities and also issue commercial paper to finance the acquisition and ownership of nuclear fuel as follows as of December 31, 2015:

<table><tr><td>Company</td><td>Expiration Date</td><td>Amount of Facility</td><td>Weighted Average Interest Rate on Borrowings (a)</td><td>Amount Outstanding as of December 31, 2015</td></tr><tr><td></td><td></td><td colspan="3">(Dollars in Millions)</td></tr><tr><td>Entergy Arkansas VIE</td><td>June 2016</td><td>$85</td><td>1.98%</td><td>$11.7</td></tr><tr><td>Entergy Louisiana River Bend VIE</td><td>June 2016</td><td>$100</td><td>1.38%</td><td>$0.6</td></tr><tr><td>Entergy Louisiana Waterford VIE</td><td>June 2016</td><td>$90</td><td>1.59%</td><td>$60.4</td></tr><tr><td>System Energy VIE</td><td>June 2016</td><td>$125</td><td>n/a</td><td>$—</td></tr></table>



(a) Includes letter of credit fees and bank fronting fees on commercial paper issuances by the nuclear fuel company variable interest entities for Entergy Arkansas, Entergy Louisiana, and System Energy. The nuclear fuel company variable interest entity for Entergy Louisiana River Bend does not issue commercial paper, but borrows directly on its bank credit facility.

Amounts outstanding on the Entergy Louisiana River Bend variable interest entity’s credit facility, if any, are included in debt on Entergy’s balance sheet and commercial paper outstanding for the other nuclear fuel company variable interest entities is classified as a current liability on the respective balance sheets. The commitment fees on the credit facilities are 0.10% of the undrawn commitment amount for the Entergy Louisiana VIEs and 0.125% of the undrawn commitment amount for the Entergy Arkansas and System Energy VIEs. Each credit facility requires the respective lessee of nuclear fuel (Entergy Arkansas, Entergy Louisiana, or Entergy Corporation as guarantor for System Energy) to maintain a consolidated debt ratio of 70% or less of its total capitalization.

The nuclear fuel company variable interest entities had notes payable that are included in debt on the respective balance sheets as of December 31, 2015 as follows:

<table><tr><td>Company</td><td>Description</td><td>Amount</td></tr><tr><td>Entergy Arkansas VIE</td><td>3.23% Series J due July 2016</td><td>$55 million</td></tr><tr><td>Entergy Arkansas VIE</td><td>2.62% Series K due December 2017</td><td>$60 million</td></tr><tr><td>Entergy Arkansas VIE</td><td>3.65% Series L due July 2021</td><td>$90 million</td></tr><tr><td>Entergy Louisiana River Bend VIE</td><td>3.25% Series Q due July 2017</td><td>$75 million</td></tr><tr><td>Entergy Louisiana River Bend VIE</td><td>3.38% Series R due August 2020</td><td>$70 million</td></tr><tr><td>Entergy Louisiana Waterford VIE</td><td>3.30% Series F due March 2016</td><td>$20 million</td></tr><tr><td>Entergy Louisiana Waterford VIE</td><td>3.25% Series G due July 2017</td><td>$25 million</td></tr><tr><td>Entergy Louisiana Waterford VIE</td><td>3.92% Series H due February 2021</td><td>$40 million</td></tr><tr><td>System Energy VIE</td><td>4.02% Series H due February 2017</td><td>$50 million</td></tr><tr><td>System Energy VIE</td><td>3.78% Series I due October 2018</td><td>$85 million</td></tr></table>

In accordance with regulatory treatment, interest on the nuclear fuel company variable interest entities’ credit facilities, commercial paper, and long-term notes payable is reported in fuel expense.

Entergy Arkansas, Entergy Louisiana, and System Energy each have obtained long-term financing authorizations from the FERC that extend through October 2017 for issuances by its nuclear fuel company variable interest entities.



## NOTE 5. LONG - TERM DEBT

Long-term debt for Entergy Corporation and subsidiaries as of December 31, 2015 and 2014 consisted of:

<table><tr><td rowspan="2">Type of Debt and Maturity</td><td rowspan="2">Weighted Average Interest Rate December 31, 2015</td><td colspan="2">Interest Rate Ranges at December 31,</td><td colspan="2">Outstanding at December 31,</td></tr><tr><td>2015</td><td>2014</td><td>2015</td><td>2014</td></tr><tr><td>Mortgage Bonds</td><td></td><td></td><td></td><td></td><td>(In Thousands)</td></tr><tr><td>2015-2020</td><td>5.96%</td><td>3.25%-7.125%</td><td>3.25%-7.125%</td><td>$1,725,000</td><td>$1,925,000</td></tr><tr><td>2021-2025</td><td>4.24%</td><td>3.05%-5.66%</td><td>3.05%-5.66%</td><td>3,683,276</td><td>3,683,303</td></tr><tr><td>2026-2030</td><td>4.65%</td><td>4.44%-5.65%</td><td>4.44%-5.65%</td><td>287,827</td><td>287,859</td></tr><tr><td>2031-2040</td><td>6.04%</td><td>5.75%-6.38%</td><td>5.75%-6.38%</td><td>1,083,000</td><td>1,115,000</td></tr><tr><td>2041-2064</td><td>5.16%</td><td>4.70%-6.00%</td><td>4.70%-6.00%</td><td>2,010,000</td><td>1,760,000</td></tr><tr><td>Governmental Bonds (a)</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>2015-2021</td><td>2.13%</td><td>1.55%-2.375%</td><td>1.55%-2.875%</td><td>99,700</td><td>131,655</td></tr><tr><td>2022-2030</td><td>5.21%</td><td>4.90%-5.875%</td><td>4.90%-5.875%</td><td>384,680</td><td>444,680</td></tr><tr><td>Securitization Bonds</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>2016-2024</td><td>3.83%</td><td>2.04%-5.93%</td><td>2.04%-5.93%</td><td>784,340</td><td>785,059</td></tr><tr><td>Variable Interest Entities Notes Payable (Note 4)</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>2016-2021</td><td>3.54%</td><td>1.38%-4.02%</td><td>2.62%-5.33%</td><td>570,600</td><td>630,000</td></tr><tr><td>Entergy Corporation Notes</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>due September 2015</td><td>n/a</td><td>—</td><td>3.625%</td><td>—</td><td>550,000</td></tr><tr><td>due January 2017</td><td>n/a</td><td>4.70%</td><td>4.70%</td><td>500,000</td><td>500,000</td></tr><tr><td>due September 2020</td><td>n/a</td><td>5.125%</td><td>5.125%</td><td>450,000</td><td>450,000</td></tr><tr><td>due July 2022</td><td>n/a</td><td>4.00%</td><td>—</td><td>650,000</td><td>—</td></tr><tr><td>Note Payable to NYPA</td><td>(b)</td><td>(b)</td><td>(b)</td><td>34,259</td><td>79,638</td></tr><tr><td>5 Year Credit Facility (Note 4)</td><td>n/a</td><td>1.98%</td><td>1.93%</td><td>835,000</td><td>695,000</td></tr><tr><td>Long-term DOE Obligation (c)</td><td>—</td><td>—</td><td>—</td><td>181,378</td><td>181,329</td></tr><tr><td>Waterford 3 Lease Obligation (d)</td><td>n/a</td><td>7.45%</td><td>7.45%</td><td>108,965</td><td>128,488</td></tr><tr><td>Grand Gulf Lease Obligation (d)</td><td>n/a</td><td>5.13%</td><td>5.13%</td><td>34,361</td><td>50,671</td></tr><tr><td>Vermont Yankee Credit Facility (Note 4)</td><td>n/a</td><td>2.08%</td><td>—</td><td>12,000</td><td>—</td></tr><tr><td>Unamortized Premium and Discount - Net</td><td></td><td></td><td></td><td>(12,067)</td><td>(12,529)</td></tr><tr><td>Unamortized Debt Issuance Costs</td><td></td><td></td><td></td><td>(110,349)</td><td>(113,399)</td></tr><tr><td>Other</td><td></td><td></td><td></td><td>13,960</td><td>14,331</td></tr><tr><td>Total Long-Term Debt</td><td></td><td></td><td></td><td>13,325,930</td><td>13,286,085</td></tr><tr><td>Less Amount Due Within One Year</td><td></td><td></td><td></td><td>214,374</td><td>899,375</td></tr><tr><td>Long-Term Debt Excluding Amount Due Within One Year</td><td></td><td></td><td></td><td>$13,111,556</td><td>$12,386,710</td></tr><tr><td>Fair Value of Long-Term Debt (e)</td><td></td><td></td><td></td><td>$13,578,511</td><td>$13,607,242</td></tr></table>



(a) Consists of pollution control revenue bonds and environmental revenue bonds, some of which are secured by collateral first mortgage bonds.

(b) These notes do not have a stated interest rate, but have an implicit interest rate of 4.8%.

(c) Pursuant to the Nuclear Waste Policy Act of 1982, Entergy’s nuclear owner/licensee subsidiaries have contracts with the DOE for spent nuclear fuel disposal service. The contracts include a one-time fee for generation prior to April 7, 1983. Entergy Arkansas is the only Entergy company that generated electric power with nuclear fuel prior to that date and includes the one-time fee, plus accrued interest, in long-term debt.

(d) See Note 10 to the financial statements for further discussion of the Waterford 3 and Grand Gulf lease obligations.

(e) The fair value excludes lease obligations of $109 million at Entergy Louisiana and $34 million at System Energy, long-term DOE obligations of $181 million at Entergy Arkansas, and the note payable to NYPA of $35 million at Entergy, and includes debt due within one year. Fair values are classified as Level 2 in the fair value hierarchy discussed in Note 16 to the financial statements and are based on prices derived from inputs such as benchmark yields and reported trades.

The annual long-term debt maturities (excluding lease obligations and long-term DOE obligations) for debt outstanding as of December 31, 2015, for the next five years are as follows:

<table><tr><td colspan="2">Amount</td></tr><tr><td></td><td>(In Thousands)</td></tr><tr><td>2016</td><td>$204,079</td></tr><tr><td>2017</td><td>$766,451</td></tr><tr><td>2018</td><td>$822,690</td></tr><tr><td>2019</td><td>$768,588</td></tr><tr><td>2020</td><td>$1,631,181</td></tr></table>

In November 2000, Entergy’s non-utility nuclear business purchased the FitzPatrick and Indian Point 3 power plants in a seller-financed transaction. Entergy issued notes to NYPA with seven annual installments of approximately $108 million commencing one year from the date of the closing, and eight annual installments of $20 million commencing eight years from the date of the closing. These notes do not have a stated interest rate, but have an implicit interest rate of 4.8%. In accordance with the purchase agreement with NYPA, the purchase of Indian Point 2 in 2001 resulted in Entergy becoming liable to NYPA for an additional $10 million per year for 10 years, beginning in September 2003. This liability was recorded upon the purchase of Indian Point 2 in September 2001. As part of the purchase agreement with NYPA, Entergy recorded a liability representing the net present value of the payments Entergy would be liable to NYPA for each year that the FitzPatrick and Indian Point 3 power plants would run beyond their respective original NRC license expiration date. With the planned shutdown of FitzPatrick at the end of its current fuel cycle, Entergy reduced this liability by $26.4 million in 2015 pursuant to the terms of the purchase agreement. Under a provision in a letter of credit supporting these notes, if certain of the Utility operating companies or System Energy were to default on other indebtedness, Entergy could be required to post collateral to support the letter of credit.

Entergy Louisiana, Entergy Mississippi, Entergy Texas, and System Energy have obtained long-term financing authorizations from the FERC that extend through October 2017. Entergy Arkansas has obtained long-term financing authorization from the APSC that extends through December 2018. Entergy New Orleans has obtained long-term financing authorization from the City Council that extends through July 2016.

## Capital Funds Agreement

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



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

• permit the continued commercial operation of Grand Gulf;

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

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

## Entergy Arkansas Debt Issuances

In January 2016, Entergy Arkansas issued $325 million of 3.5% Series first mortgage bonds due April 2026. Entergy Arkansas used the proceeds to pay, prior to maturity, its $175 million of 5.66% Series first mortgage bonds due February 2025, and expects to use the remainder of the proceeds, together with other funds, towards the purchase of a power block at the Union Power Station and for general corporate purposes.

## Entergy Arkansas Securitization Bonds

In June 2010 the APSC issued a financing order authorizing the issuance of bonds to recover Entergy Arkansas’s January 2009 ice storm damage restoration costs, including carrying costs of $11.5 million and $4.6 million of up-front financing costs. In August 2010, Entergy Arkansas Restoration Funding, LLC, a company wholly-owned and consolidated by Entergy Arkansas, issued $124.1 million of storm cost recovery bonds. The bonds have a coupon of 2.30% and an expected maturity date of August 2021. Although the principal amount is not due until the date given above, Entergy Arkansas Restoration Funding expects to make principal payments on the bonds over the next five years in the amount of $13.4 million for 2016, $13.8 million for 2017, $14.1 million for 2018, $14.4 million for 2019, and $7.3 million for 2020. 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.

## Entergy Louisiana Securitization Bonds – Little Gypsy

In August 2011 the LPSC issued a financing order authorizing the issuance of bonds to recover Entergy Louisiana’s investment recovery costs associated with the canceled Little Gypsy repowering project. In September 2011, Entergy Louisiana Investment Recovery Funding I, L.L.C., a company wholly-owned and consolidated by Entergy Louisiana, issued $207.2 million of senior secured investment recovery bonds. The bonds have an interest rate of 2.04% and an expected maturity date of June 2021. Although the principal amount is not due until the date given above, Entergy Louisiana Investment Recovery Funding expects to make principal payments on the bonds over the next five years in the amounts of $21.6 million for 2016, $21.7 million for 2017, $22.3 million for 2018, $22.7 million for 2019, and $23.2 million for 2020. 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. In accordance with the financing order, Entergy Louisiana will apply the proceeds it received from the sale of the investment recovery property as a reimbursement for previously-incurred investment recovery costs. 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.



## Entergy New Orleans Securitization Bonds - Hurricane Isaac

In May 2015 the City Council issued a financing order authorizing the issuance of securitization bonds to recover Entergy New Orleans’s Hurricane Isaac storm restoration costs of $31.8 million, including carrying costs, the costs of funding and replenishing the storm recovery reserve in the amount of $63.9 million, and approximately $3 million of up-front financing costs associated with the securitization. In July 2015, Entergy New Orleans Storm Recovery Funding I, L.L.C., a company wholly owned and consolidated by Entergy New Orleans, issued $98.7 million of storm cost recovery bonds. The bonds have a coupon of 2.67% and an expected maturity date of June 2024. Although the principal amount is not due until the date given above, Entergy New Orleans Storm Recovery Funding expects to make principal payments on the bonds over the next five years in the amounts of $11.4 million for 2016, $10.6 million for 2017, $11 million for 2018, $11.2 million for 2019, and $11.6 million for 2020.

With the proceeds, Entergy New Orleans Storm Recovery Funding purchased from Entergy New Orleans 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 New Orleans balance sheet. The creditors of Entergy New Orleans do not have recourse to the assets or revenues of Entergy New Orleans Storm Recovery Funding, including the storm recovery property, and the creditors of Entergy New Orleans Storm Recovery Funding do not have recourse to the assets or revenues of Entergy New Orleans. Entergy New Orleans has no payment obligations to Entergy New Orleans Storm Recovery Funding except to remit storm recovery charge collections.

## Entergy Texas Securitization Bonds - Hurricane Rita

In April 2007 the PUCT issued a financing order authorizing the issuance of securitization bonds to recover $353 million of Entergy Texas’s Hurricane Rita reconstruction costs and up to $6 million of transaction costs, offset by $32 million of related deferred income tax benefits. In June 2007, Entergy Gulf States Reconstruction Funding I, LLC, a company that is now wholly-owned and consolidated by Entergy Texas, issued $329.5 million of senior secured transition bonds (securitization bonds) as follows:

<table><tr><td></td><td>Amount</td></tr><tr><td></td><td>(In Thousands)</td></tr><tr><td>Senior Secured Transition Bonds, Series A:</td><td></td></tr><tr><td>Tranche A-1 (5.51%) due October 2013</td><td>$93,500</td></tr><tr><td>Tranche A-2 (5.79%) due October 2018</td><td>121,600</td></tr><tr><td>Tranche A-3 (5.93%) due June 2022</td><td>114,400</td></tr><tr><td>Total senior secured transition bonds</td><td>$329,500</td></tr></table>

Although the principal amount of each tranche is not due until the dates given above, Entergy Gulf States Reconstruction Funding expects to make principal payments on the bonds over the next five years in the amounts of $26 million for 2016, $27.6 million for 2017, $29.2 million for 2018, $30.9 million for 2019, and $32.8 million for 2020. All of the scheduled principal payments for 2016 are for Tranche A-2, $23.6 million of the scheduled principal payments for 2017 are for Tranche A-2 and $4 million of the scheduled principal payments for 2017 are for Tranche A-3. All of the scheduled principal payments for 2018-2020 are for Tranche A-3.

With the proceeds, Entergy Gulf States Reconstruction Funding 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 Entergy Gulf States Reconstruction Funding, including the transition property, and the creditors of Entergy Gulf States Reconstruction Funding do not have recourse to the assets or revenues of Entergy Texas. Entergy Texas has no payment obligations to Entergy Gulf States Reconstruction Funding except to remit transition charge collections.



## Entergy Texas Securitization Bonds - Hurricane Ike and Hurricane Gustav

In September 2009 the PUCT authorized the issuance of securitization bonds to recover $566.4 million of Entergy Texas’s Hurricane Ike and Hurricane Gustav restoration costs, plus carrying costs and transaction costs, offset by insurance proceeds. In November 2009, Entergy Texas Restoration Funding, LLC (Entergy Texas Restoration Funding), a company wholly-owned and consolidated by Entergy Texas, issued $545.9 million of senior secured transition bonds (securitization bonds), as follows:

<table><tr><td></td><td>Amount (In Thousands)</td></tr><tr><td>Senior Secured Transition Bonds:</td><td></td></tr><tr><td>Tranche A-1 (2.12%) due February 2016</td><td>$182,500</td></tr><tr><td>Tranche A-2 (3.65%) due August 2019</td><td>144,800</td></tr><tr><td>Tranche A-3 (4.38%) due November 2023</td><td>218,600</td></tr><tr><td>Total senior secured transition bonds</td><td>$545,900</td></tr></table>

Although the principal amount of each tranche is not due until the dates given above, Entergy Texas Restoration Funding expects to make principal payments on the bonds over the next five years in the amount of $42.6 million for 2016, $44.1 million for 2017, $45.8 million for 2018, $47.6 million for 2019, and $49.8 million for 2020. All of the scheduled principal payments for 2016-2017 are for Tranche A-2, $30.8 million of the scheduled principal payments for 2018 are for Tranche A-2 and $15 million are for Tranche A-3. All of the scheduled principle payments for 2019-2020 are for Tranche A-3.

With the proceeds, Entergy Texas Restoration Funding 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 Entergy Texas Restoration Funding, including the transition property, and the creditors of Entergy Texas Restoration Funding do not have recourse to the assets or revenues of Entergy Texas. Entergy Texas has no payment obligations to Entergy Texas Restoration Funding except to remit transition charge collections.



## NOTE 6. PREFERRED EQUITY

The number of shares and units authorized and outstanding and dollar value of preferred stock, preferred membership interests, and non-controlling interest for Entergy Corporation subsidiaries as of December 31, 2015 and 2014 are presented below. All series of the Utility preferred stock are redeemable at the option of the related company.

<table><tr><td rowspan="2"></td><td colspan="3">Shares/Units Authorized</td><td colspan="3">Shares/Units Outstanding</td><td rowspan="2">2015</td><td rowspan="2">2014</td></tr><tr><td>2015</td><td>2014</td><td></td><td>2015</td><td>2014</td><td></td></tr><tr><td>Entergy Corporation</td><td></td><td></td><td></td><td></td><td></td><td></td><td>(Dollars in Thousands)</td><td></td></tr><tr><td>Utility:</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Preferred Stock or Preferred Membership Interests without sinking fund:</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr></table>

(a) In 2007, Entergy Louisiana Holdings, an Entergy subsidiary, purchased 160,000 of these shares from the holders.

(b) Dollar amount outstanding is net of $2,575 thousand of preferred stock issuance costs.

(c) Dollar amount outstanding is net of $751 thousand of preferred stock issuance costs.

In October 2015, Entergy Utility Holding Company, LLC issued 110,000 shares of $1,000 par value 7.5% Series Preferred Stock, all of which are outstanding as of December 31, 2015. The dividends are cumulative and payable quarterly. The preferred stock is redeemable on or after January 1, 2036, at Entergy Utility Holding Company, LLC’s option, at the fixed redemption price of $1,000 per share.

In December 2013, Entergy Finance Holding, Inc. issued 250,000 shares of $100 par value 8.75% Series Preferred Stock, all of which are outstanding as of December 31, 2015. The dividends are cumulative and payable quarterly. The preferred stock is redeemable on or after December 16, 2023, at Entergy Finance Holding, Inc.'s option, at the fixed redemption price of $100 per share.



## NOTE 7. COMMON EQUITY

## Common Stock

Common stock and treasury stock shares activity for Entergy for 2015, 2014, and 2013 is as follows:

<table><tr><td></td><td colspan="2">2015</td><td colspan="2">2014</td><td colspan="2">2013</td></tr><tr><td></td><td>Common Shares Issued</td><td>Treasury Shares</td><td>Common Shares Issued</td><td>Treasury Shares</td><td>Common Shares Issued</td><td>Common Shares Issued</td></tr><tr><td>Beginning Balance, January 1</td><td>254,752,788</td><td>75,512,079</td><td>254,752,788</td><td>76,381,936</td><td>254,752,788</td><td>76,945,239</td></tr><tr><td>Repurchases</td><td>—</td><td>1,468,984</td><td>—</td><td>2,154,490</td><td>—</td><td>—</td></tr><tr><td>Issuances:</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Employee Stock-Based Compensation Plans</td><td>—</td><td>(610,409)</td><td>—</td><td>(3,019,475)</td><td>—</td><td>(557,734)</td></tr><tr><td>Directors&#x27; Plan</td><td>—</td><td>(6,891)</td><td>—</td><td>(4,872)</td><td>—</td><td>(5,569)</td></tr><tr><td>Ending Balance, December 31</td><td>254,752,788</td><td>76,363,763</td><td>254,752,788</td><td>75,512,079</td><td>254,752,788</td><td>76,381,936</td></tr></table>

Entergy Corporation reissues treasury shares to meet the requirements of the Stock Plan for Outside Directors (Directors' Plan), two Equity Ownership Plans of Entergy Corporation and Subsidiaries, the Equity Awards Plan of Entergy Corporation and Subsidiaries, and certain other stock benefit plans. The Directors' Plan awards to non-employee directors a portion of their compensation in the form of a fixed dollar value of shares of Entergy Corporation common stock.

In October 2010 the Board granted authority for a $500 million share repurchase program. As of December 31, 2015, $350 million of authority remains under the $500 million share repurchase program.

Dividends declared per common share were $3.34 in 2015 and $3.32 in 2014 and 2013.

In 2015, System Energy paid its parent, Entergy Corporation, a $70 million distribution out of its common stock.

## Retained Earnings and Dividend Restrictions

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 equity. As of December 31, 2015, under provisions in their mortgage indentures, Entergy Arkansas and Entergy Mississippi had retained earnings unavailable for distribution to Entergy Corporation of $394.9 million and $68.5 million, respectively. Entergy Corporation received dividend payments and distributions from subsidiaries totaling $615 million in 2015, $893 million in 2014, and $702 million in 2013.



## Comprehensive Income

Accumulated other comprehensive income (loss) is included in the equity section of the balance sheets of Entergy and Entergy Louisiana. The following table presents changes in accumulated other comprehensive income (loss) for Entergy for the year ended December 31, 2015 by component:

<table><tr><td></td><td>Cash flow hedges net unrealized gain (loss)</td><td>Pension and other postretirement liabilities</td><td>Net unrealized investment gains (loss)</td><td>Foreign currency translation</td><td>Total Accumulated Other Comprehensive Income (Loss)</td></tr><tr><td></td><td></td><td colspan="4">(In Thousands)</td></tr><tr><td>Beginning balance, January 1, 2015</td><td>$98,118</td><td>($569,789)</td><td>$426,695</td><td>$2,669</td><td>($42,307)</td></tr><tr><td>Other comprehensive income (loss) before reclassifications</td><td>(151,740)</td><td>71,054</td><td>(34,186)</td><td>(641)</td><td>(115,513)</td></tr><tr><td>Amounts reclassified from accumulated other comprehensive income (loss)</td><td>159,592</td><td>32,131</td><td>(24,952)</td><td>—</td><td>166,771</td></tr><tr><td>Net other comprehensive income (loss) for the period</td><td>7,852</td><td>103,185</td><td>(59,138)</td><td>(641)</td><td>51,258</td></tr><tr><td>Ending balance, December 31, 2015</td><td>$105,970</td><td>($466,604)</td><td>$367,557</td><td>$2,028</td><td>$8,951</td></tr></table>

The following table presents changes in accumulated other comprehensive income (loss) for Entergy for the year ended December 31, 2014 by component:

<table><tr><td></td><td>Cash flow hedges net unrealized gain (loss)</td><td>Pension and other postretirement liabilities</td><td>Net unrealized investment gains (loss)</td><td>Foreign currency translation</td><td>Total Accumulated Other Comprehensive Income (Loss)</td></tr><tr><td></td><td></td><td colspan="4">(In Thousands)</td></tr><tr><td>Beginning balance, January 1, 2014</td><td>($81,777)</td><td>($288,223)</td><td>$337,256</td><td>$3,420</td><td>($29,324)</td></tr><tr><td>Other comprehensive income (loss) before reclassifications</td><td>52,433</td><td>(278,361)</td><td>99,900</td><td>(751)</td><td>(126,779)</td></tr><tr><td>Amounts reclassified from accumulated other comprehensive income (loss)</td><td>127,462</td><td>(3,205)</td><td>(10,461)</td><td>—</td><td>113,796</td></tr><tr><td>Net other comprehensive income (loss) for the period</td><td>179,895</td><td>(281,566)</td><td>89,439</td><td>(751)</td><td>(12,983)</td></tr><tr><td>Ending balance, December 31, 2014</td><td>$98,118</td><td>($569,789)</td><td>$426,695</td><td>$2,669</td><td>($42,307)</td></tr></table>



Total reclassifications out of accumulated other comprehensive income (loss) (AOCI) for Entergy for the year ended December 31, 2015 are as follows:

<table><tr><td></td><td>Amounts reclassified from AOCI (In Thousands)</td><td>Income Statement Location</td></tr><tr><td>Cash flow hedges net unrealized gain (loss)</td><td></td><td></td></tr><tr><td>Power contracts</td><td>($243,555)</td><td>Competitive business operating revenues</td></tr><tr><td>Interest rate swaps</td><td>(1,971)</td><td>Miscellaneous - net</td></tr><tr><td>Total realized gain (loss) on cash flow hedges</td><td>(245,526)</td><td></td></tr><tr><td></td><td>85,934</td><td>Income taxes</td></tr><tr><td>Total realized gain (loss) on cash flow hedges (net of tax)</td><td>($159,592)</td><td></td></tr><tr><td>Pension and other postretirement liabilities</td><td></td><td></td></tr><tr><td>Amortization of prior-service costs</td><td>$23,920</td><td>(a)</td></tr><tr><td>Acceleration of prior-service cost due to curtailment</td><td>(374)</td><td>(a)</td></tr><tr><td>Amortization of loss</td><td>(70,296)</td><td>(a)</td></tr><tr><td>Settlement loss</td><td>(1,401)</td><td>(a)</td></tr><tr><td>Total amortization</td><td>(48,151)</td><td></td></tr><tr><td></td><td>16,020</td><td>Income taxes</td></tr><tr><td>Total amortization (net of tax)</td><td>($32,131)</td><td></td></tr><tr><td>Net unrealized investment gain (loss)</td><td></td><td></td></tr><tr><td>Realized gain (loss)</td><td>$48,926</td><td>Interest and investment income</td></tr><tr><td></td><td>(23,974)</td><td>Income taxes</td></tr><tr><td>Total realized investment gain (loss) (net of tax)</td><td>$24,952</td><td></td></tr><tr><td>Total reclassifications for the period (net of tax)</td><td>($166,771)</td><td></td></tr></table>

(a) These accumulated other comprehensive income (loss) components are included in the computation of net periodic pension and other postretirement cost. See Note 11 to the financial statements for additional details.



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

<table><tr><td></td><td>Amounts reclassified from AOCI (In Thousands)</td><td>Income Statement Location</td></tr><tr><td>Cash flow hedges net unrealized gain (loss)</td><td></td><td></td></tr><tr><td>Power contracts</td><td>($193,297)</td><td>Competitive business operating revenues</td></tr><tr><td>Interest rate swaps</td><td>(2,799)</td><td>Miscellaneous - net</td></tr><tr><td>Total realized gain (loss) on cash flow hedges</td><td>(196,096)</td><td></td></tr><tr><td></td><td>68,634</td><td>Income taxes</td></tr><tr><td>Total realized gain (loss) on cash flow hedges (net of tax)</td><td>($127,462)</td><td></td></tr><tr><td>Pension and other postretirement liabilities</td><td></td><td></td></tr><tr><td>Amortization of prior-service costs</td><td>$20,294</td><td>(a)</td></tr><tr><td>Amortization of loss</td><td>(35,836)</td><td>(a)</td></tr><tr><td>Settlement loss</td><td>(3,643)</td><td>(a)</td></tr><tr><td>Total amortization</td><td>(19,185)</td><td></td></tr><tr><td></td><td>22,390</td><td>Income taxes</td></tr><tr><td>Total amortization (net of tax)</td><td>$3,205</td><td></td></tr><tr><td>Net unrealized investment gain (loss)</td><td></td><td></td></tr><tr><td>Realized gain (loss)</td><td>$20,511</td><td>Interest and investment income</td></tr><tr><td></td><td>(10,050)</td><td>Income taxes</td></tr><tr><td>Total realized investment gain (loss) (net of tax)</td><td>$10,461</td><td></td></tr><tr><td>Total reclassifications for the period (net of tax)</td><td>($113,796)</td><td></td></tr></table>

(a) These accumulated other comprehensive income (loss) components are included in the computation of net periodic pension and other postretirement cost. See Note 11 to the financial statements for additional details.

## NOTE 8. COMMITMENTS AND CONTINGENCIES

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.



## Vidalia Purchased Power Agreement

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 $146 million in 2015, $152.8 million in 2014, and $181.1 million in 2013. If the maximum percentage (94%) of the energy is made available to Entergy Louisiana, current production projections would require estimated payments of approximately $150.5 million in 2016, and a total of $1.93 billion for the years 2017 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 million each year for up to 10 years, beginning in October 2002. In October 2011 the LPSC approved a settlement under which Entergy Louisiana agreed to provide credits to customers by crediting billings an additional $20.235 million per year for 15 years beginning January 2012. Entergy Louisiana recorded a regulatory charge and a corresponding regulatory liability to reflect this obligation.

## ANO Damage, Outage, and NRC Reviews

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 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. In February 2014 the APSC approved Entergy Arkansas’s request to exclude from the calculation of its revised energy cost rate $65.9 million of deferred fuel and purchased 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 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 position and is evaluating its options for enforcing its rights under the policy. During 2014, Entergy Arkansas collected $50 million from NEIL. In July 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 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 NRC issued an inspection report on the 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 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 the NRC’s findings have been taken and remain ongoing at ANO.

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 substantial safety significance” for the 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 in October 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 “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 report. The NRC’s final risk significance determination was classified as “yellow with substantial safety significance.”

In March 2015 the NRC issued a letter notifying Entergy of its decision to move ANO into the “multiple/repetitive degraded cornerstone column” (Column 4) of the NRC’s Reactor Oversight Process Action Matrix. Placement into Column 4 requires 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. Entergy Arkansas incurred incremental costs of approximately $53 million in 2015 to prepare for the NRC inspection that began in early 2016. Excluding remediation and response costs that may result from the additional NRC inspection activities, Entergy Arkansas also expects to incur approximately $50 million in 2016 in support of NRC inspection activities and to implement Entergy Arkansas’s performance improvement initiatives developed in 2015. A much lesser amount of incremental expenses is expected to be ongoing annually after 2016.

## Baxter Wilson Plant Event

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 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 and has received all of its previously-acquired insurance proceeds, with $12.9 million allocated to capital spending and $15.3 million allocated to operation and maintenance expenses. In June 2014, Entergy Mississippi filed a rate case with the MPSC, which includes recovery of the 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 capital costs will be reflected in rate base. The final accounting of costs to return the unit to service and insurance proceeds will be addressed in Entergy Mississippi’s next formula rate plan filing.



## Pilgrim NRC Oversight and Planned Shutdown

In September 2015 the NRC placed Pilgrim in its “multiple/repetitive degraded cornerstone column” (Column 4) of its Reactor Oversight Process Action Matrix due to its finding of continuing weaknesses in Pilgrim’s corrective action program that contributed to repeated unscheduled shutdowns and equipment failures. The preliminary estimate of direct costs of Pilgrim’s response to a planned NRC enhanced inspection ranges from $45 million to $60 million, including approximately $30 million in 2016, in operation and maintenance expense, not including any potential capital investment or other costs to address issues that may arise in the inspection.

Entergy determined in October 2015 that it will close Pilgrim, no later than June 1, 2019, because of poor market conditions, reduced revenues, and increased operational costs. Pilgrim currently has approximately 677 MW of Capacity Supply Obligations in ISO New England through May 2019. If Pilgrim shuts down earlier than June 2019 it could have to buy back its Capacity Supply Obligations at prices higher than the capacity rates Pilgrim is currently scheduled to receive. The precise timing of the shutdown depends on several factors, including further discussion with ISO New England. Management expects the timing of the shutdown will be decided in the first half of 2016.

See Note 1 to the financial statements for discussion of the impairment of the Pilgrim plant and related long-lived assets.

## Nuclear Fuel Enrichment Contracts

Entergy subsidiaries are parties to two contracts with American Centrifuge Enrichment, LLC (ACE) under which these subsidiaries purchase nuclear fuel enrichment services. The term of each contract is from 2011 to 2022; however, each contract provided for cancellation of the parties’ purchase and sale obligations for 2016-2022 if, by August 1, 2014, ACE’s planned Advanced Centrifuge Plant was not in commercial operation and ACE did not identify to Entergy’s reasonable satisfaction how it would meet its contractual delivery obligations through output from ACE. In August 2014, Entergy sent notice to ACE that the 2016-2022 obligations were canceled by the operation of this contractual provision. United States Enrichment Corporation (USEC), ACE’s affiliate to which ACE assigned the contracts, filed a demand for arbitration with the American Arbitration Association, claiming damages of approximately $165 million. In July 2015 the parties reached an agreement resolving the dispute that resulted in the dismissal of USEC’s claims. The resolution of the dispute does not have a material effect on Entergy’s results of operations, financial position, or cash flows.

## Nuclear Insurance

## Third Party Liability Insurance

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:

1. The primary level is private insurance underwritten by American Nuclear Insurers (ANI) and provides public liability insurance coverage of $375 million. If this amount is not sufficient to cover claims arising from an accident, the second level, Secondary Financial Protection, applies.

2. Within the Secondary Financial Protection level, each nuclear reactor has a contingent obligation to pay a retrospective premium, equal to its proportionate share of the loss in excess of the primary level, regardless of proximity to the incident or fault, up to a maximum of $127.3 million per reactor per incident (Entergy’s maximum total contingent obligation per incident is $1.4 billion). This consists of a $121.3 million maximum retrospective premium plus a five percent surcharge, which equates to $127.3 million, that may be payable, if needed, at a rate that is currently set at $19 million per year per incident per nuclear power reactor.



3. In the event that one or more acts of terrorism cause a nuclear power plant accident, which results in third-party damages – off-site property and environmental damage, off-site bodily injury, and on-site third-party bodily injury (i.e. contractors), the primary level provided by ANI combined with the Secondary Financial Protection would provide $13.5 billion in coverage. The Terrorism Risk Insurance Reauthorization Act of 2007 created a government program that provides for up to $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.

Currently, 103 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 $13.1 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 and Entergy Louisiana each have two licensed reactors. System Energy has one licensed reactor (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 decommissioning of nuclear power reactors and the ownership of the shutdown Indian Point 1 reactor and Big Rock Point facility.

## Property Insurance

Entergy’s nuclear owner/licensee subsidiaries are members of 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, 2015, Entergy was insured against such losses per the following structures:

Utility Plants (ANO 1 and 2, Grand Gulf, River Bend, and Waterford 3)

• Primary Layer (per plant) - $1.5 billion per occurrence

• Blanket Excess Layer (shared among the Utility plants) - $100 million per occurrence

• Total limit - $1.6 billion per occurrence

• Deductibles:

• $2.5 million per occurrence - Turbine/generator damage

• $2.5 million per occurrence - Other than turbine/generator damage

- $10 million per occurrence plus 10% of amount above $10 million - Damage from a windstorm, flood, earthquake, or volcanic eruption

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. Flood and earthquake coverage are excluded from the primary layer’s first $500 million in coverage. Entergy currently purchases flood coverage at Waterford 3 and River Bend for the primary layer’s first $500 million in coverage.

Entergy Wholesale Commodities Plants (FitzPatrick, Pilgrim, and Palisades)

• Primary Layer (per plant) - $1.115 billion per occurrence

• Total limit (per plant) - $1.115 billion per occurrence

• Deductibles:

• $2.5 million per occurrence - Turbine/generator damage

• $2.5 million per occurrence - Other than turbine/generator damage

- $10 million per occurrence plus 10% of amount above $10 million - Damage from a windstorm, flood, earthquake, or volcanic eruption



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 Palisades for the primary layer’s first $500 million in coverage.

Entergy Wholesale Commodities Plant (Indian Point)

• Primary Layer (per plant) - $1.5 billion per occurrence

• Excess Layer - $100 million per occurrence

• Total limit - $1.6 billion per occurrence

• Deductibles:

• $2.5 million per occurrence - Turbine/generator damage

• $2.5 million per occurrence - Other than turbine/generator damage

- $10 million per occurrence plus 10% of amount above $10 million - Damage from a windstorm, flood, earthquake, or volcanic eruption

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

Entergy Wholesale Commodities Plant (Vermont Yankee)

• Primary Layer (per plant) - $1.06 billion per occurrence

• Total limit - $1.06 billion per occurrence

• Deductibles:

• $2.5 million per occurrence - Turbine/generator damage

• $2.5 million per occurrence - Other than turbine/generator damage

- $10 million per occurrence plus 10% of amount above $10 million - Damage from a windstorm, flood, earthquake, or volcanic eruption

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.

Entergy Wholesale Commodities Plant (Big Rock Point)

• Primary Layer (per plant) - $500 million per occurrence

• Total limit - $500 million per occurrence

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 accidental outage coverage was removed effective October 1, 2014. Accidental outage coverage provides indemnification for the actual cost incurred in the event of an unplanned outage resulting from property damage covered under the NEIL Primary Property Insurance policy, subject to a deductible period. The indemnification for the actual cost incurred is based on market power prices at the time of the loss. The maximum payout indemnity under this policy is limited to a $327.6 million per occurrence. Weekly indemnities for an unplanned outage, covered under NEIL’s Accidental Outage Coverage program, after the deductible period has passed would be the maximum amounts listed below:



• 100% of the weekly indemnity for each week for the first payment period of 52 weeks: then

• 80% of the weekly indemnity for each week for the second payment period of 52 weeks; and thereafter

• 80% of the weekly indemnity for an additional 58 weeks for the third and final payment period.

The following summarizes this coverage effective April 1, 2015:

## Waterford 3

• $2.95 million weekly indemnity

• $413 million maximum indemnity - nuclear

• $277 million maximum indemnity - non-nuclear

• Deductible: 26 week deductible period

## Grand Gulf

• $400,000 weekly indemnity (total for four policies)

• $56 million maximum indemnity - nuclear (total for four policies)

• $37 million maximum indemnity - non-nuclear (total for four policies)

• Deductible: 26 week deductible period

## Indian Point 2, Indian Point 3, and Palisades

• $4.5 million weekly indemnity

• $490 million maximum indemnity - nuclear

• $327.6 million maximum indemnity - non-nuclear

• Deductible: 12 week deductible period

## FitzPatrick and Pilgrim

• $4 million weekly indemnity

• $490 million maximum indemnity - nuclear

• $327.6 million maximum indemnity - non-nuclear

• Deductible: 12 week deductible period

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, 2015, the maximum amounts of such possible assessments per occurrence were as follows:

<table><tr><td></td><td>Assessments (In Millions)</td></tr><tr><td>Utility:</td><td></td></tr><tr><td>Entergy Arkansas</td><td>$44.6</td></tr><tr><td>Entergy Louisiana</td><td>$54.7</td></tr><tr><td>Entergy Mississippi</td><td>$0.10</td></tr><tr><td>Entergy New Orleans</td><td>$0.10</td></tr><tr><td>Entergy Texas</td><td>N/A</td></tr><tr><td>System Energy</td><td>$24.5</td></tr><tr><td>Entergy Wholesale Commodities</td><td>$—</td></tr></table>

Potential assessments for the Entergy Wholesale Commodities plants are covered by insurance obtained through NEIL’s reinsurers.

Entergy maintains property insurance for its nuclear units in excess of the NRC’s minimum requirement of $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 cause 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 billion plus the additional amounts recovered for such losses from reinsurance, indemnity, and any other sources applicable to such losses. The Terrorism Risk Insurance Reauthorization Act of 2007 created a government program that provides for up to $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. The Terrorism Risk Insurance Reauthorization Act of 2015, however, was signed into law by the President of the United States in January 2015 thereby extending the Terrorism Risk Insurance Act for six years until December 31, 2020.

## Conventional Property Insurance

Entergy’s conventional property insurance program provides coverage of up to $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 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 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 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 million in coverage for the Entergy New Orleans gas distribution system on an “each and every loss” basis. This $50 million limit is subject to: the $400 million annual aggregate limit for the natural perils of earthquake, tsunami, and flood; the $125 million annual aggregate limit for the natural perils of named windstorm and associated storm surge. The coverage is subject to a $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 million self-insured retention per occurrence for operational perils and 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.

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 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 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 billion in coverage in excess of existing coverage for a terrorist event. As discussed above, 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 million deductible and is placed on a scheduled location basis. The applicable deductibles are $100,000 to $250,000, except for properties that are damaged by flooding and properties whose values are greater than $20 million; these properties have a $500,000 deductible. Due to the removal of the Vermont Yankee assets from this additional coverage, as of June 1, 2015, two nuclear locations have a $2.5 million deductible, which coincides with the nuclear property insurance deductible at each respective nuclear site.



## Gas System Rebuild Insurance Proceeds (Entergy New Orleans)

Entergy New Orleans received insurance proceeds in 2007 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.

## Employment and Labor-related Proceedings

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 representatives, and third parties not selected for open positions or providing services directly or indirectly to one or more of the Registrant Subsidiaries and other Entergy subsidiaries. Generally, the amount of damages being sought is not specified in these proceedings. These actions include, but are not limited to, allegations of wrongful employment actions; wage disputes and other claims under the Fair Labor Standards Act or its state counterparts; claims of race, gender, age, and disability discrimination; disputes arising under collective bargaining agreements; unfair labor practice proceedings and other administrative proceedings before the National Labor Relations Board or concerning the National Labor Relations Act; claims of retaliation; claims of harassment and hostile work environment; and claims for or regarding benefits under various Entergy Corporation-sponsored plans. Entergy and the Registrant Subsidiaries are responding to these lawsuits and proceedings and deny liability to the claimants. 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 Entergy or the Utility operating companies.

## NOTE 9. ASSET RETIREMENT OBLIGATIONS

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 of the assets. The application of accounting standards related to asset retirement obligations is earnings neutral to the rate-regulated business of the Registrant Subsidiaries.

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:



<table><tr><td rowspan="2"></td><td colspan="2">December 31,</td></tr><tr><td>2015</td><td>2014</td></tr><tr><td></td><td colspan="2">(In Millions)</td></tr><tr><td>Entergy Arkansas</td><td>$85.7</td><td>$59.0</td></tr><tr><td>Entergy Louisiana</td><td>($68.3)</td><td>($82.6)</td></tr><tr><td>Entergy Mississippi</td><td>$77.5</td><td>$76.3</td></tr><tr><td>Entergy New Orleans</td><td>$29.4</td><td>$35.2</td></tr><tr><td>Entergy Texas</td><td>$25.8</td><td>$18.9</td></tr><tr><td>System Energy</td><td>$54.8</td><td>$55.7</td></tr></table>

The cumulative decommissioning and retirement cost liabilities and expenses recorded in 2015 by Entergy were as follows:

<table><tr><td></td><td>Liabilities as of December 31, 2014</td><td>Liabilities Incurred (a)</td><td>Accretion</td><td>Change in Cash Flow Estimate</td><td>Spending</td><td>Liabilities as of December 31, 2015</td></tr><tr><td></td><td></td><td></td><td colspan="4">(In Millions)</td></tr><tr><td>Utility:</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Entergy Arkansas</td><td>$818.4</td><td>$3.5</td><td>$50.4</td><td>$—</td><td>$—</td><td>$872.3</td></tr><tr><td>Entergy Louisiana</td><td>$950.3</td><td>$1.9</td><td>$51.0</td><td>$24.7</td><td>$—</td><td>$1,027.9</td></tr><tr><td>Entergy Mississippi</td><td>$6.8</td><td>$1.1</td><td>$0.4</td><td>$—</td><td>$—</td><td>$8.3</td></tr><tr><td>Entergy New Orleans</td><td>$2.5</td><td>$—</td><td>$0.2</td><td>$—</td><td>$—</td><td>$2.7</td></tr><tr><td>Entergy Texas</td><td>$4.6</td><td>$1.4</td><td>$0.3</td><td>($0.2)</td><td>$—</td><td>$6.1</td></tr><tr><td>System Energy</td><td>$757.9</td><td>$—</td><td>$48.0</td><td>($2.5)</td><td>$—</td><td>$803.4</td></tr><tr><td>Entergy Wholesale Commodities</td><td>$1,917.8</td><td>$—</td><td>$153.8</td><td>$99.6</td><td>($101.7)</td><td>$2,069.5</td></tr></table>

(a) See “Coal Combustion Residuals” below for additional discussion regarding the asset retirement obligations related to coal combustion residuals management.

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

<table><tr><td rowspan="2"></td><td rowspan="2">Liabilities as of December 31, 2013</td><td rowspan="2">Accretion</td><td rowspan="2">Change in Cash Flow Estimate</td><td rowspan="2">Spending</td><td rowspan="2">Liabilities as of December 31, 2014</td></tr><tr></tr><tr><td>Utility:</td><td></td><td></td><td>(In Millions)</td><td></td><td></td></tr><tr><td>Entergy Arkansas</td><td>$723.8</td><td>$47.0</td><td>$47.6</td><td>$—</td><td>$818.4</td></tr><tr><td>Entergy Louisiana</td><td>$882.2</td><td>$48.1</td><td>$20.0</td><td>$—</td><td>$950.3</td></tr><tr><td>Entergy Mississippi</td><td>$6.4</td><td>$0.4</td><td>$—</td><td>$—</td><td>$6.8</td></tr><tr><td>Entergy New Orleans</td><td>$2.3</td><td>$0.2</td><td>$—</td><td>$—</td><td>$2.5</td></tr><tr><td>Entergy Texas</td><td>$4.3</td><td>$0.3</td><td>$—</td><td>$—</td><td>$4.6</td></tr><tr><td>System Energy</td><td>$616.2</td><td>$41.8</td><td>$99.9</td><td>$—</td><td>$757.9</td></tr><tr><td>Entergy Wholesale Commodities</td><td>$1,698.2</td><td>$139.7</td><td>$101.6</td><td>($21.7)</td><td>$1,917.8</td></tr></table>



## Nuclear Plant Decommissioning

Entergy periodically reviews and updates estimated decommissioning costs. The actual decommissioning costs may vary from the estimates because of regulatory requirements, changes in technology, and increased costs of labor, materials, and equipment. As described below, during 2015 and 2014 Entergy updated decommissioning cost estimates for certain nuclear power plants.

In the second quarter 2015, 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 $77.6 million reduction in the decommissioning cost liability, along with a corresponding reduction in the related asset retirement cost asset.

In the third quarter 2015, Entergy Wholesale Commodities recorded a revision to its estimated decommissioning cost liability for Pilgrim as a result of a revised decommissioning cost study. The revised estimate resulted in a $134 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 no later than June 2019. The asset retirement cost asset was included in the Pilgrim carrying value that was written down to fair value in the third quarter 2015. See Note 1 to the financial statements for discussion of the impairment of the value and planned shutdown of the Pilgrim plant.

After shutdown, Pilgrim will transition to decommissioning. The Pilgrim nuclear decommissioning trust had a balance of approximately $896 million as of December 31, 2015, representing excess financial assurance of approximately $270 million for license termination activities above NRC-required assurance levels. Filings with the NRC for 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 federal government takes possession of the fuel and removes it from the site, per its current obligation. No additional funding is anticipated at this time.

In the fourth quarter 2015, 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 $24.9 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 2015, 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 $2.5 million reduction in its decommissioning cost liability, along with a corresponding reduction in the related asset retirement cost asset that will be depreciated over the remaining life of the unit.

In the fourth quarter 2015, Entergy Wholesale Commodities recorded a revision to its estimated decommissioning cost liability for Palisades as a result of a revised decommissioning cost study. The revised estimate resulted in a $42.4 million increase in the decommissioning cost liability, along with a corresponding increase in the related asset retirement cost asset. The asset retirement cost asset was included in the Palisades carrying value that was written down to fair value in the fourth quarter 2015. See Note 1 to the financial statements for discussion of the impairment of the value of the Palisades plant.



In 2013, Entergy Wholesale Commodities recorded two revisions to its estimated decommissioning cost liability for Vermont Yankee. In the third quarter 2013, the estimated decommissioning cost liability increased by $58 million, 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 the third quarter 2013. 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 million increase in the decommissioning cost liability and a corresponding impairment charge, recorded in fourth quarter 2013.

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 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, recorded in September 2014.

Vermont Yankee submitted notification of permanent cessation of operations and permanent removal of fuel from the reactor in January 2015 after final shutdown 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 managing spent fuel, rather than the NRC minimum formula for estimating decommissioning costs. Filings with the NRC for 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 federal government takes possession of the fuel and removes it from the site, per its current obligation.

Entergy 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 Vermont Yankee’s expected costs of decommissioning, spent fuel management costs, and site restoration. In June 2015 the NRC issued an exemption from its regulations to allow Vermont Yankee to use its decommissioning trust fund to pay for approximately $225 million of estimated future spent fuel management costs that will not be paid for using funds from the credit facilities. In August 2015, Vermont and two Vermont utilities filed a petition in the U.S. Court of Appeals for the D.C. Circuit challenging the NRC’s issuance of that exemption. If the appeal were to result in a final decision denying Vermont Yankee the exemption allowing the use of its decommissioning trust fund to pay for these spent fuel management costs, Vermont Yankee would have to satisfy the NRC that it had a plan to obtain additional funds to enable it to pay for these costs until the federal government takes possession of the fuel and removes it from the site. See Note 1 to the financial statements for further discussion regarding the Vermont Yankee plant.

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.

In the fourth quarter 2014, Entergy 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.

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 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. The contract asset represents an 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 by monthly accretion based on the applicable discount rate necessary to ultimately provide for the estimated future value of the decommissioning contract. The monthly accretion is recorded as interest income.

In the third quarter 2015, Entergy Wholesale Commodities recorded a revision to the contract asset for the FitzPatrick plant. Due to a change in expectation regarding the timing of decommissioning cash flows, the result was a write down of the contract asset from $335 million to $131 million, for a charge of $204 million. See Note 1 to the financial statements for further discussion of the impairment of the value and planned shutdown of the FitzPatrick plant.

As of December 31, 2015 the contract asset for the Indian Point 3 and FitzPatrick plants is $420.8 million.

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, 2015 are as follows:

<table><tr><td></td><td>Decommissioning Trust Fair Values</td><td>Regulatory Asset (Liability)</td></tr><tr><td></td><td colspan="2">(In Millions)</td></tr><tr><td>Utility:</td><td></td><td></td></tr><tr><td>ANO 1 and ANO 2</td><td>$771.3</td><td>$280.3</td></tr><tr><td>River Bend</td><td>$651.7</td><td>($26.8)</td></tr><tr><td>Waterford 3</td><td>$390.6</td><td>$158.5</td></tr><tr><td>Grand Gulf</td><td>$701.5</td><td>$108.6</td></tr><tr><td>Entergy Wholesale Commodities</td><td>$2,834.9</td><td>$—</td></tr></table>

The fair values of the decommissioning trust funds and the related asset retirement obligation regulatory assets (liabilities) of Entergy as of December 31, 2014 are as follows:

<table><tr><td></td><td>Decommissioning Trust Fair Values</td><td>Regulatory Asset (Liability)</td></tr><tr><td></td><td colspan="2">(In Millions)</td></tr><tr><td>Utility:</td><td></td><td></td></tr><tr><td>ANO 1 and ANO 2</td><td>$769.9</td><td>$247.6</td></tr><tr><td>River Bend</td><td>$637.7</td><td>($25.5)</td></tr><tr><td>Waterford 3</td><td>$383.6</td><td>$145.5</td></tr><tr><td>Grand Gulf</td><td>$679.8</td><td>$80.4</td></tr><tr><td>Entergy Wholesale Commodities</td><td>$2,899.9</td><td>$—</td></tr></table>



## Coal Combustion Residuals

In June 2010 the EPA issued a proposed rule on coal combustion residuals (CCRs) that contained two primary regulatory options: (1) regulating CCRs destined for disposal in landfills or received (including stored) in surface impoundments as so-called “special wastes” under the hazardous waste program of RCRA Subtitle C; or (2) regulating CCRs destined for disposal in landfills or surface impoundments as non-hazardous wastes under Subtitle D of RCRA. Under both options, CCRs that are beneficially reused in certain processes would remain excluded from hazardous waste regulation. In April 2015 the EPA published the final CCR rule with the material being regulated under the second scenario presented above - as non-hazardous wastes regulated under RCRA Subtitle D. The final regulations create new compliance requirements including modified storage, new notification and reporting practices, product disposal considerations, and CCR unit closure criteria. Entergy believes that on-site disposal options will be available at its facilities, to the extent needed for CCR that cannot be transferred for beneficial reuse.

## NOTE 10. LEASES

## General

As of December 31, 2015, 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, all of which are discussed elsewhere):

<table><tr><td>Year</td><td>Operating Leases</td><td>Capital Leases</td></tr><tr><td></td><td colspan="2">(In Thousands)</td></tr><tr><td>2016</td><td>$78,302</td><td>$4,694</td></tr><tr><td>2017</td><td>64,371</td><td>4,694</td></tr><tr><td>2018</td><td>53,073</td><td>3,909</td></tr><tr><td>2019</td><td>50,574</td><td>3,124</td></tr><tr><td>2020</td><td>33,337</td><td>3,065</td></tr><tr><td>Years thereafter</td><td>79,662</td><td>24,778</td></tr><tr><td>Minimum lease payments</td><td>359,319</td><td>44,264</td></tr><tr><td>Less: Amount representing interest</td><td>—</td><td>13,918</td></tr><tr><td>Present value of net minimum lease payments</td><td>$359,319</td><td>$30,346</td></tr></table>

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 $63.9 million in 2015, $59 million in 2014, and $63.7 million in 2013.

In addition to the above rental expense, railcar operating lease payments and oil tank facilities lease payments are recorded in fuel expense in accordance with regulatory treatment. Railcar operating lease payments were $4.7 million in 2015, $4.8 million in 2014, and $8.6 million in 2013 for Entergy Arkansas and $1.1 million in 2015, $1.7 million in 2014, and $2.2 million in 2013 for Entergy Louisiana. Oil tank facilities lease payments for Entergy Mississippi were $1.6 million in 2015, $1.6 million in 2014, and $3.4 million in 2013.

## Power Purchase Agreements

As of December 31, 2015, 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:



<table><tr><td>Year</td><td>Entergy (In Thousands)</td></tr><tr><td>2016</td><td>29,104</td></tr><tr><td>2017</td><td>29,772</td></tr><tr><td>2018</td><td>30,458</td></tr><tr><td>2019</td><td>31,159</td></tr><tr><td>2020</td><td>31,876</td></tr><tr><td>Years thereafter</td><td>42,789</td></tr><tr><td>Minimum lease payments</td><td>$195,158</td></tr></table>

Total capacity expense under the power purchase agreement accounted for as an operating lease at Entergy Texas was $29.9 million in 2015, $29.2 million in 2014, and $28.6 million in 2013.

## Sale and Leaseback Transactions

## Waterford 3 Lease Obligations

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. The leases expire in July 2017. Entergy Louisiana is required to report the sale-leaseback as a financing transaction in its financial statements.

In December 2015, Entergy Louisiana agreed to purchase the undivided interests in Waterford 3 that are currently being leased. The purchase will be accomplished in a two-step transaction in which Entergy Louisiana will first acquire the equity participant’s beneficial interest in the leased assets, followed by a termination of the leases and transfer of the leased assets to Entergy Louisiana when the outstanding lessor debt is paid.

The purchase price will be approximately $112 million, of which $60 million will be paid in cash and the remaining approximately $52 million will be paid through the issuance of a non-interest bearing mortgage bond, payable in installments through July 2017. The $60 million cash payment represents the purchase price to acquire the undivided interests in the plant. Following the purchase, Entergy Louisiana will also continue to make payments on the lessor debt which remains outstanding. The combination of payments due on the approximately $52 million mortgage bond issued and the debt service on the lessor debt are equal in timing and amount to the remaining lease payments due from the expected closing of the transaction through the remainder of the lease term. Therefore, this transaction will not change the total amount of debt outstanding on Entergy Louisiana’s financial statements related to the Waterford 3 sale-leaseback. Payments include $7.8 million in July 2016 and $106.3 million in 2017. An additional lease payment of $9.2 million was made in January 2016, prior to the closing of this transaction. In February 2016 the FERC authorized the transaction. Consumption of the transaction is subject to customary closing conditions, and is expected to close in the first half of 2016.

Throughout the term of the lease, Entergy Louisiana had accrued a liability for the amount it expected to pay to retain the use of the undivided interests in Waterford 3 at the end of the lease term. Since the sale-leaseback transaction was accounted for as a financing transaction, the accrual of this liability was accounted for as additional interest expense. As of December 2015, the balance of this liability was $62.7 million. Upon entering into the agreement to purchase the equity participant’s beneficial interest in the undivided interests, Entergy Louisiana reduced the balance of the liability to $60 million, and recorded the $2.7 million difference as a credit to interest expense. The $60 million remaining liability will be eliminated upon payment of the cash portion of the purchase price.



Entergy Louisiana had previously issued $193.2 million of non-interest bearing first mortgage bonds as collateral for the equity portion of certain amounts payable under the leases. Upon the acquisition of the beneficial interests described above, these mortgage bonds will be surrendered for cancellation.

The lease transaction documents provide that, 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 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, 2015, Entergy Louisiana was in compliance with these provisions.

As of December 31, 2015, Entergy Louisiana, in connection with the Waterford 3 sale and leaseback transactions, had future minimum lease payments (reflecting an overall implicit rate of 7.45%, and which include the equity portion of lease payments which will, upon the acquisition of the beneficial interests, be payable under the mortgage bond described above) that are recorded as long-term debt, as follows:

<table><tr><td></td><td>Amount (In Thousands)</td></tr><tr><td>2016</td><td>$16,938</td></tr><tr><td>2017</td><td>106,335</td></tr><tr><td>2018</td><td>—</td></tr><tr><td>2019</td><td>—</td></tr><tr><td>2020</td><td>—</td></tr><tr><td>Years thereafter</td><td>—</td></tr><tr><td>Total</td><td>123,273</td></tr><tr><td>Less: Amount representing interest</td><td>14,308</td></tr><tr><td>Present value of net minimum lease payments</td><td>$108,965</td></tr></table>

## Grand Gulf Lease Obligations

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. The initial term of the leases expired in July 2015. System Energy renewed the leases for fair market value with renewal terms 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 $55.6 million and $62.9 million as of December 31, 2015 and 2014, respectively.



As of December 31, 2015, System Energy, in connection with the Grand Gulf sale and leaseback transactions, had future minimum lease payments (reflecting an implicit rate of 5.13%) that are recorded as long-term debt, as follows:

<table><tr><td></td><td>Amount (In Thousands)</td></tr><tr><td>2016</td><td>$17,188</td></tr><tr><td>2017</td><td>17,188</td></tr><tr><td>2018</td><td>17,188</td></tr><tr><td>2019</td><td>17,188</td></tr><tr><td>2020</td><td>17,188</td></tr><tr><td>Years thereafter</td><td>275,000</td></tr><tr><td>Total</td><td>360,940</td></tr><tr><td>Less: Amount representing interest</td><td>326,579</td></tr><tr><td>Present value of net minimum lease payments</td><td>$34,361</td></tr></table>

## NOTE 11. RETIREMENT, OTHER POSTRETIREMENT BENEFITS, AND DEFINED CONTRIBUTION PLANS

## Qualified Pension Plans

Entergy has nine qualified pension plans covering substantially all 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 IV for Non-Bargaining Employees,” and “Entergy Corporation Retirement Plan IV for Bargaining Employees” are non-contributory final average pay plans and provide pension benefits that are based on employees’ credited service and compensation during employment. The “Entergy Corporation Retirement Plan III” 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 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 whose most recent date of hire is 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 in its respective master trust that is maintained by a trustee. Use of the master 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 in the master 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 in that particular trust. The fair value of the trusts' assets is determined by the trustee and certain investment managers. 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 trusts on a pro rata basis.

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 net income and contributions, and are decreased for benefit payments. A plan’s investment net income/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 plans in an amount not less than the minimum required contribution under 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.



## Components of Qualified Net Pension Cost and Other Amounts Recognized as a Regulatory Asset and/or Accumulated Other Comprehensive Income (AOCI)

Entergy Corporation and its subsidiaries’ total 2015, 2014, and 2013 qualified pension costs and amounts recognized as a regulatory asset and/or other comprehensive income, including amounts capitalized, included the following components:

<table><tr><td rowspan="2"></td><td>2015</td><td>2014</td><td>2013</td></tr><tr><td colspan="3">(In Thousands)</td></tr><tr><td>Net periodic pension cost:</td><td></td><td></td><td></td></tr><tr><td>Service cost - benefits earned during the period</td><td>$175,046</td><td>$140,436</td><td>$172,280</td></tr><tr><td>Interest cost on projected benefit obligation</td><td>302,777</td><td>290,076</td><td>263,296</td></tr><tr><td>Expected return on assets</td><td>(394,618)</td><td>(361,462)</td><td>(328,227)</td></tr><tr><td>Amortization of prior service cost</td><td>1,561</td><td>1,600</td><td>2,125</td></tr><tr><td>Recognized net loss</td><td>235,922</td><td>145,095</td><td>213,194</td></tr><tr><td>Curtailment loss</td><td>374</td><td>—</td><td>16,318</td></tr><tr><td>Special termination benefit</td><td>76</td><td>732</td><td>13,139</td></tr><tr><td>Net periodic pension costs</td><td>$321,138</td><td>$216,477</td><td>$352,125</td></tr><tr><td>Other changes in plan assets and benefit obligations recognized as a regulatory asset and/or AOCI (before tax)</td><td></td><td></td><td></td></tr><tr><td>Arising this period:</td><td></td><td></td><td></td></tr><tr><td>Net (gain)/loss</td><td>$50,762</td><td>$1,389,912</td><td>($894,150)</td></tr><tr><td>Amounts reclassified from regulatory asset and/or AOCI to net periodic pension cost in the current year:</td><td></td><td></td><td></td></tr><tr><td>Amortization of prior service cost</td><td>(1,561)</td><td>(1,600)</td><td>(2,125)</td></tr><tr><td>Acceleration of prior service cost to curtailment</td><td>(374)</td><td>—</td><td>(1,307)</td></tr><tr><td>Amortization of net loss</td><td>(235,922)</td><td>(145,095)</td><td>(213,194)</td></tr><tr><td>Total</td><td>($187,095)</td><td>$1,243,217</td><td>($1,110,776)</td></tr><tr><td>Total recognized as net periodic pension (income)/cost, regulatory asset, and/or AOCI (before tax)</td><td>$134,043</td><td>$1,459,694</td><td>($758,651)</td></tr><tr><td>Estimated amortization amounts from regulatory asset and/or AOCI to net periodic cost in the following year:</td><td></td><td></td><td></td></tr><tr><td>Prior service cost</td><td>$1,079</td><td>$1,561</td><td>$1,600</td></tr><tr><td>Net loss</td><td>$195,321</td><td>$237,013</td><td>$146,958</td></tr></table>



Qualified Pension Obligations, Plan Assets, Funded Status, Amounts Recognized in the Balance Sheet for Entergy Corporation and its Subsidiaries as of December 31, 2015 and 2014

<table><tr><td rowspan="3"></td><td colspan="2">December 31,</td></tr><tr><td>2015</td><td>2014</td></tr><tr><td colspan="2">(In Thousands)</td></tr><tr><td>Change in Projected Benefit Obligation (PBO)</td><td></td><td></td></tr><tr><td>Balance at beginning of year</td><td>$7,230,542</td><td>$5,770,999</td></tr><tr><td>Service cost</td><td>175,046</td><td>140,436</td></tr><tr><td>Interest cost</td><td>302,777</td><td>290,076</td></tr><tr><td>Special termination benefit</td><td>76</td><td>732</td></tr><tr><td>Actuarial (gain)/loss</td><td>(460,986)</td><td>1,284,049</td></tr><tr><td>Employee contributions</td><td>524</td><td>560</td></tr><tr><td>Benefits paid</td><td>(399,741)</td><td>(256,310)</td></tr><tr><td>Balance at end of year</td><td>$6,848,238</td><td>$7,230,542</td></tr><tr><td>Change in Plan Assets</td><td></td><td></td></tr><tr><td>Fair value of assets at beginning of year</td><td>$4,827,966</td><td>$4,429,237</td></tr><tr><td>Actual return on plan assets</td><td>(117,130)</td><td>255,599</td></tr><tr><td>Employer contributions</td><td>395,814</td><td>398,880</td></tr><tr><td>Employee contributions</td><td>524</td><td>560</td></tr><tr><td>Benefits paid</td><td>(399,741)</td><td>(256,310)</td></tr><tr><td>Fair value of assets at end of year</td><td>$4,707,433</td><td>$4,827,966</td></tr><tr><td>Funded status</td><td>($2,140,805)</td><td>($2,402,576)</td></tr><tr><td>Amount recognized in the balance sheet</td><td></td><td></td></tr><tr><td>Non-current liabilities</td><td>($2,140,805)</td><td>($2,402,576)</td></tr><tr><td>Amount recognized as a regulatory asset</td><td></td><td></td></tr><tr><td>Prior service cost</td><td>$—</td><td>$3,704</td></tr><tr><td>Net loss</td><td>2,300,222</td><td>2,451,172</td></tr><tr><td></td><td>$2,300,222</td><td>$2,454,876</td></tr><tr><td>Amount recognized as AOCI (before tax)</td><td></td><td></td></tr><tr><td>Prior service cost</td><td>$2,784</td><td>$1,015</td></tr><tr><td>Net loss</td><td>637,472</td><td>671,682</td></tr><tr><td></td><td>$640,256</td><td>$672,697</td></tr></table>

## Other Postretirement Benefits

Entergy also currently offers retiree medical, dental, vision, and life insurance benefits (other postretirement benefits) for eligible retired 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 other postretirement benefits.

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. Entergy Arkansas, Entergy Mississippi, Entergy New Orleans, and Entergy Texas have received regulatory approval to recover accrued other postretirement benefit costs through rates. The LPSC ordered 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 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.

Components of Net Other Postretirement Benefit Cost and Other Amounts Recognized as a Regulatory Asset and/or AOCI

Entergy Corporation’s and its subsidiaries’ total 2015, 2014, and 2013 other postretirement benefit costs, including amounts capitalized and amounts recognized as a regulatory asset and/or other comprehensive income, included the following components:

<table><tr><td rowspan="2"></td><td>2015</td><td>2014</td><td>2013</td></tr><tr><td colspan="3">(In Thousands)</td></tr><tr><td>Other postretirement costs:</td><td></td><td></td><td></td></tr><tr><td>Service cost - benefits earned during the period</td><td>$45,305</td><td>$43,493</td><td>$74,654</td></tr><tr><td>Interest cost on APBO</td><td>71,934</td><td>71,841</td><td>79,453</td></tr><tr><td>Expected return on assets</td><td>(45,375)</td><td>(44,787)</td><td>(40,323)</td></tr><tr><td>Amortization of prior service credit</td><td>(37,280)</td><td>(31,590)</td><td>(14,904)</td></tr><tr><td>Recognized net loss</td><td>31,573</td><td>11,143</td><td>44,178</td></tr><tr><td>Curtailment loss</td><td>—</td><td>—</td><td>12,729</td></tr><tr><td>Net other postretirement benefit cost</td><td>$66,157</td><td>$50,100</td><td>$155,787</td></tr><tr><td>Other changes in plan assets and benefit obligations recognized as a regulatory asset and /or AOCI (before tax)</td><td></td><td></td><td></td></tr><tr><td>Arising this period:</td><td></td><td></td><td></td></tr><tr><td>Prior service credit for period</td><td>($48,192)</td><td>($35,864)</td><td>($116,571)</td></tr><tr><td>Net loss/(gain)</td><td>(154,339)</td><td>287,313</td><td>(405,976)</td></tr><tr><td>Amounts reclassified from regulatory asset and /or AOCI to net periodic benefit cost in the current year:</td><td></td><td></td><td></td></tr><tr><td>Amortization of prior service credit</td><td>37,280</td><td>31,590</td><td>14,904</td></tr><tr><td>Acceleration of prior service credit due to curtailment</td><td>—</td><td>—</td><td>1,989</td></tr><tr><td>Amortization of net loss</td><td>(31,573)</td><td>(11,143)</td><td>(44,178)</td></tr><tr><td>Total</td><td>($196,824)</td><td>$271,896</td><td>($549,832)</td></tr><tr><td>Total recognized as net periodic benefit income/(cost), regulatory asset, and/or AOCI (before tax)</td><td>($130,667)</td><td>$321,996</td><td>($394,045)</td></tr><tr><td>Estimated amortization amounts from regulatory asset and/or AOCI to net periodic benefit cost in the following year</td><td></td><td></td><td></td></tr><tr><td>Prior service credit</td><td>($45,485)</td><td>($37,280)</td><td>($31,589)</td></tr><tr><td>Net loss</td><td>$18,214</td><td>$31,591</td><td>$11,197</td></tr></table>



Other Postretirement Benefit Obligations, Plan Assets, Funded Status, and Amounts Not Yet Recognized and Recognized in the Balance Sheet of Entergy Corporation and its Subsidiaries as of December 31, 2015 and 2014

<table><tr><td rowspan="3"></td><td colspan="2">December 31,</td></tr><tr><td>2015</td><td>2014</td></tr><tr><td colspan="2">(In Thousands)</td></tr><tr><td>Change in APBO</td><td></td><td></td></tr><tr><td>Balance at beginning of year</td><td>$1,739,557</td><td>$1,461,910</td></tr><tr><td>Service cost</td><td>45,305</td><td>43,493</td></tr><tr><td>Interest cost</td><td>71,934</td><td>71,841</td></tr><tr><td>Plan amendments</td><td>(48,192)</td><td>(35,864)</td></tr><tr><td>Plan participant contributions</td><td>29,685</td><td>22,160</td></tr><tr><td>Actuarial (gain)/loss</td><td>(208,017)</td><td>274,061</td></tr><tr><td>Benefits paid</td><td>(102,618)</td><td>(102,439)</td></tr><tr><td>Medicare Part D subsidy received</td><td>3,175</td><td>4,395</td></tr><tr><td>Balance at end of year</td><td>$1,530,829</td><td>$1,739,557</td></tr><tr><td>Change in Plan Assets</td><td></td><td></td></tr><tr><td>Fair value of assets at beginning of year</td><td>$597,627</td><td>$569,850</td></tr><tr><td>Actual return on plan assets</td><td>(8,303)</td><td>31,535</td></tr><tr><td>Employer contributions</td><td>62,678</td><td>76,521</td></tr><tr><td>Plan participant contributions</td><td>29,685</td><td>22,160</td></tr><tr><td>Benefits paid</td><td>(102,618)</td><td>(102,439)</td></tr><tr><td>Fair value of assets at end of year</td><td>$579,069</td><td>$597,627</td></tr><tr><td>Funded status</td><td>($951,760)</td><td>($1,141,930)</td></tr><tr><td>Amounts recognized in the balance sheet</td><td></td><td></td></tr><tr><td>Current liabilities</td><td>($41,326)</td><td>($41,821)</td></tr><tr><td>Non-current liabilities</td><td>(910,434)</td><td>(1,100,109)</td></tr><tr><td>Total funded status</td><td>($951,760)</td><td>($1,141,930)</td></tr><tr><td>Amounts recognized as a regulatory asset</td><td></td><td></td></tr><tr><td>Prior service credit</td><td>($61,833)</td><td>($54,508)</td></tr><tr><td>Net loss</td><td>191,782</td><td>248,918</td></tr><tr><td></td><td>$129,949</td><td>$194,410</td></tr><tr><td>Amounts recognized as AOCI (before tax)</td><td></td><td></td></tr><tr><td>Prior service credit</td><td>($107,673)</td><td>($104,086)</td></tr><tr><td>Net loss</td><td>171,742</td><td>300,518</td></tr><tr><td></td><td>$64,069</td><td>$196,432</td></tr></table>



## Non-Qualified Pension Plans

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 $22.8 million in 2015, $32.4 million in 2014, and $54.5 million in 2013. In 2015, 2014, and 2013 Entergy recognized $5.1 million, $15.1 million, and $33 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 $157.3 million and $151.8 million as of December 31, 2015 and 2014, respectively. The accumulated benefit obligation was $137.6 million and $130.6 million as of December 31, 2015 and 2014, respectively.

Entergy’s non-qualified, non-current pension liability at December 31, 2015 and 2014 was $136.1 million and $135.6 million, respectively; and its current liability was $21.2 million and $16.2 million, respectively. The unamortized prior service cost and net loss are recognized in regulatory assets ($58.8 million at December 31, 2015 and $60.3 million at December 31, 2014) and accumulated other comprehensive income before taxes ($23.5 million at December 31, 2015 and $23.5 million at December 31, 2014).

## Reclassification out of Accumulated Other Comprehensive Income (Loss)

Entergy reclassified the following costs out of accumulated other comprehensive income (loss) (before taxes and including amounts capitalized) as of December 31, 2015:

<table><tr><td></td><td>Qualified Pension Costs</td><td>Other Postretirement Costs</td><td>Non-Qualified Pension Costs</td><td>Total</td></tr><tr><td></td><td colspan="4">(In Thousands)</td></tr><tr><td>Entergy</td><td></td><td></td><td></td><td></td></tr><tr><td>Amortization of prior service cost</td><td>($1,557)</td><td>$25,905</td><td>($428)</td><td>$23,920</td></tr><tr><td>Acceleration of prior service cost due to curtailment</td><td>(374)</td><td>—</td><td>—</td><td>(374)</td></tr><tr><td>Amortization of loss</td><td>(50,508)</td><td>(17,613)</td><td>(2,175)</td><td>(70,296)</td></tr><tr><td>Settlement loss</td><td>—</td><td>—</td><td>(1,401)</td><td>(1,401)</td></tr><tr><td></td><td>($52,439)</td><td>$8,292</td><td>($4,004)</td><td>($48,151)</td></tr></table>

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

<table><tr><td></td><td>Qualified Pension Costs</td><td>Other Postretirement Costs</td><td>Non-Qualified Pension Costs</td><td>Total</td></tr><tr><td></td><td colspan="4">(In Thousands)</td></tr><tr><td>Entergy</td><td></td><td></td><td></td><td></td></tr><tr><td>Amortization of prior service cost</td><td>($1,559)</td><td>$22,280</td><td>($427)</td><td>$20,294</td></tr><tr><td>Amortization of loss</td><td>(26,934)</td><td>(6,689)</td><td>(2,213)</td><td>(35,836)</td></tr><tr><td>Settlement loss</td><td>—</td><td>—</td><td>(3,643)</td><td>(3,643)</td></tr><tr><td></td><td>($28,493)</td><td>$15,591</td><td>($6,283)</td><td>($19,185)</td></tr></table>



## Accounting for Pension and Other Postretirement Benefits

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 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 Louisiana recovers other postretirement benefit costs on a pay-as-you-go basis and records the unrecognized prior service cost, gains and losses, and transition obligation for its other postretirement benefit obligation as other comprehensive income. Accounting standards also 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 phase-in of the difference between actual and expected returns. For other postretirement benefit plan assets Entergy uses fair value when determining MRV.

## Qualified Pension and Other Postretirement Plans' Assets

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.

The target asset 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 increases. The following ranges were established to produce an acceptable, economically efficient plan to manage around the targets.

The target and range asset allocation for postretirement assets reflects recommendations made in the latest optimization study.

Entergy’s qualified pension and postretirement weighted-average asset allocations by asset category at December 31, 2015 and 2014 and the target asset allocation and ranges are as follows:

<table><tr><td>Pension Asset Allocation</td><td>Target</td><td>Range</td><td>Actual 2015</td><td>Actual 2014</td></tr><tr><td>Domestic Equity Securities</td><td>45%</td><td>34% to 53%</td><td>45%</td><td>45%</td></tr><tr><td>International Equity Securities</td><td>20%</td><td>16% to 24%</td><td>19%</td><td>19%</td></tr><tr><td>Fixed Income Securities</td><td>35%</td><td>31% to 41%</td><td>35%</td><td>35%</td></tr><tr><td>Other</td><td>0%</td><td>0% to 10%</td><td>1%</td><td>1%</td></tr></table>



<table><tr><td colspan="2">Postretirement Asset Allocation</td><td colspan="4">Non-Taxable and Taxable</td></tr><tr><td></td><td>Target</td><td>Range</td><td>Actual 2015</td><td>Actual 2014</td><td></td></tr><tr><td>Domestic Equity Securities</td><td>39%</td><td>34% to 44%</td><td>40%</td><td>42%</td><td></td></tr><tr><td>International Equity Securities</td><td>26%</td><td>21% to 31%</td><td>24%</td><td>25%</td><td></td></tr><tr><td>Fixed Income Securities</td><td>35%</td><td>30% to 40%</td><td>36%</td><td>33%</td><td></td></tr><tr><td>Other</td><td>0%</td><td>0% to 5%</td><td>0%</td><td>0%</td><td></td></tr></table>

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 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.

## Concentrations of Credit Risk

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, 2015, 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.

## Fair Value Measurements

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).

The three levels of the fair value hierarchy are described below:

- Level 1 - Level 1 inputs are unadjusted quoted prices for identical assets or liabilities in active markets that the Plan has the ability to access at the measurement date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis.



- Level 2 - Level 2 inputs are inputs other than quoted prices included in Level 1 that are, either directly or indirectly, observable for the asset or liability at the measurement date. Assets are valued based on prices derived by an independent party that uses inputs such as benchmark yields, reported trades, broker/dealer quotes, and issuer spreads. Prices are reviewed and can be challenged with the independent parties and/or overridden if it is believed such would be more reflective of fair value. Level 2 inputs include the following:

- quoted prices for similar assets or liabilities in active markets;

- quoted prices for identical assets or liabilities in inactive markets;

- inputs other than quoted prices that are observable for the asset or liability; or

- inputs that are derived principally from or corroborated by observable market data by correlation or other means.

If an asset or liability has a specified (contractual) term, the Level 2 input must be observable for substantially the full term of the asset or liability.

• Level 3 - Level 3 refers to securities valued based on significant unobservable inputs.

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 on a recurring basis at December 31, 2015, and December 31, 2014, a summary of the investments held in the master trusts for Entergy’s qualified pension and other postretirement plans in which the Registrant Subsidiaries participate.

Qualified Defined Benefit Pension Plan Trusts

<table><tr><td>2015</td><td>Level 1</td><td>Level 2</td><td>Level 3</td><td>Total</td></tr><tr><td></td><td></td><td colspan="3">(In Thousands)</td></tr><tr><td>Equity securities:</td><td></td><td></td><td></td><td></td></tr><tr><td>Corporate stocks:</td><td></td><td></td><td></td><td></td></tr><tr><td>Preferred</td><td>$6,409 (b)</td><td>$— (a)</td><td>$—</td><td>$6,409</td></tr><tr><td>Common</td><td>686,335 (b)</td><td>95</td><td>—</td><td>686,430</td></tr><tr><td>Common collective trusts</td><td>—</td><td>1,873,218 (c)</td><td>—</td><td>1,873,218</td></tr><tr><td>103-12 investment entities</td><td>—</td><td>283,288 (h)</td><td>—</td><td>283,288</td></tr><tr><td>Fixed income securities:</td><td></td><td></td><td></td><td></td></tr><tr><td>U.S. Government securities</td><td>1,879 (b)</td><td>343,805 (a)</td><td>—</td><td>345,684</td></tr><tr><td>Corporate debt instruments</td><td>—</td><td>595,862 (a)</td><td>—</td><td>595,862</td></tr><tr><td>Registered investment companies</td><td>255,720 (d)</td><td>547,208 (e)</td><td>—</td><td>802,928</td></tr><tr><td>Other</td><td>—</td><td>114,215 (f)</td><td>—</td><td>114,215</td></tr><tr><td>Other:</td><td></td><td></td><td></td><td></td></tr><tr><td>Insurance company general account (unallocated contracts)</td><td>—</td><td>35,998 (g)</td><td>—</td><td>35,998</td></tr><tr><td>Total investments</td><td>$950,343</td><td>$3,793,689</td><td>$—</td><td>$4,744,032</td></tr><tr><td>Cash</td><td></td><td></td><td></td><td>373</td></tr><tr><td>Other pending transactions</td><td></td><td></td><td></td><td>1,124</td></tr><tr><td>Less: Other postretirement assets included in total investments</td><td></td><td></td><td></td><td>(38,096)</td></tr><tr><td>Total fair value of qualified pension assets</td><td></td><td></td><td></td><td>$4,707,433</td></tr></table>



<table><tr><td>2014</td><td>Level 1</td><td>Level 2</td><td>Level 3</td><td>Total</td></tr><tr><td></td><td></td><td colspan="3">(In Thousands)</td></tr><tr><td>Equity securities:</td><td></td><td></td><td></td><td></td></tr><tr><td>Corporate stocks:</td><td></td><td></td><td></td><td></td></tr><tr><td>Preferred</td><td>$10,017 (b)</td><td>$— (a)</td><td>$—</td><td>$10,017</td></tr><tr><td>Common</td><td>717,685 (b)</td><td>97</td><td>—</td><td>717,782</td></tr><tr><td>Common collective trusts</td><td>—</td><td>1,886,897 (c)</td><td>—</td><td>1,886,897</td></tr><tr><td>103-12 investment entities</td><td>—</td><td>259,995</td><td>—</td><td>259,995</td></tr><tr><td>Fixed income securities:</td><td></td><td></td><td></td><td></td></tr><tr><td>U.S. Government securities</td><td>240 (b)</td><td>400,059 (a)</td><td>—</td><td>400,299</td></tr><tr><td>Corporate debt instruments</td><td>—</td><td>548,788 (a)</td><td>—</td><td>548,788</td></tr><tr><td>Registered investment companies</td><td>286,534 (d)</td><td>576,641 (e)</td><td>—</td><td>863,175</td></tr><tr><td>Other</td><td>—</td><td>130,295 (f)</td><td>—</td><td>130,295</td></tr><tr><td>Other:</td><td></td><td></td><td></td><td></td></tr><tr><td>Insurance company general account (unallocated contracts)</td><td>—</td><td>37,818 (g)</td><td>—</td><td>37,818</td></tr><tr><td>Total investments</td><td>$1,014,476</td><td>$3,840,590</td><td>$—</td><td>$4,855,066</td></tr><tr><td>Cash</td><td></td><td></td><td></td><td>495</td></tr><tr><td>Other pending transactions</td><td></td><td></td><td></td><td>7,359</td></tr><tr><td>Less: Other postretirement assets included in total investments</td><td></td><td></td><td></td><td>(34,954)</td></tr><tr><td>Total fair value of qualified pension assets</td><td></td><td></td><td></td><td>$4,827,966</td></tr></table>

Other Postretirement Trusts

<table><tr><td>2015</td><td>Level 1</td><td>Level 2</td><td>Level 3</td><td>Total</td></tr><tr><td></td><td></td><td colspan="3">(In Thousands)</td></tr><tr><td>Equity securities:</td><td></td><td></td><td></td><td></td></tr><tr><td>Common collective trust</td><td>$—</td><td>$348,604 (c)</td><td>$—</td><td>$348,604</td></tr><tr><td>Fixed income securities:</td><td></td><td></td><td></td><td></td></tr><tr><td>U.S. Government securities</td><td>33,789 (b)</td><td>42,222 (a)</td><td>—</td><td>76,011</td></tr><tr><td>Corporate debt instruments</td><td>—</td><td>62,629 (a)</td><td>—</td><td>62,629</td></tr><tr><td>Registered investment companies</td><td>3,572 (d)</td><td>—</td><td>—</td><td>3,572</td></tr><tr><td>Other</td><td>—</td><td>49,677 (f)</td><td>—</td><td>49,677</td></tr><tr><td>Total investments</td><td>$37,361</td><td>$503,132</td><td>$—</td><td>$540,493</td></tr><tr><td>Other pending transactions</td><td></td><td></td><td></td><td>480</td></tr><tr><td>Plus: Other postretirement assets included in the investments of the qualified pension trust</td><td></td><td></td><td></td><td>38,096</td></tr><tr><td>Total fair value of other postretirement assets</td><td></td><td></td><td></td><td>$579,069</td></tr></table>



<table><tr><td>2014</td><td>Level 1</td><td>Level 2</td><td>Level 3</td><td>Total</td></tr><tr><td></td><td></td><td colspan="3">(In Thousands)</td></tr><tr><td>Equity securities:</td><td></td><td></td><td></td><td></td></tr><tr><td>Common collective trust</td><td>$—</td><td>$370,228</td><td>(c)</td><td>$—</td></tr><tr><td>Fixed income securities:</td><td></td><td></td><td></td><td></td></tr><tr><td>U.S. Government securities</td><td>36,306</td><td>(b)</td><td>45,618</td><td>(a)</td></tr><tr><td>Corporate debt instruments</td><td>—</td><td>57,830</td><td>(a)</td><td>—</td></tr><tr><td>Registered investment companies</td><td>5,558</td><td>(d)</td><td>—</td><td>—</td></tr><tr><td>Other</td><td>—</td><td>46,968</td><td>(f)</td><td>—</td></tr><tr><td>Total investments</td><td>$41,864</td><td>$520,644</td><td></td><td>$—</td></tr><tr><td>Other pending transactions</td><td></td><td></td><td></td><td>165</td></tr><tr><td>Plus: Other postretirement assets included in the investments of the qualified pension trust</td><td></td><td></td><td></td><td>34,954</td></tr><tr><td>Total fair value of other postretirement assets</td><td></td><td></td><td></td><td>$597,627</td></tr></table>

(a) Certain preferred stocks and certain fixed income debt securities (corporate, government, and securitized) are stated at fair value as determined by broker quotes.

(b) Common stocks, certain preferred stocks, and certain fixed income debt securities (government) are stated at fair value determined by quoted market prices.

(c) The common collective trusts hold investments in accordance with stated objectives. The investment strategy of the trusts is to capture the growth potential of equity markets by replicating the performance of a specified index. Net asset value per share of common collective trusts estimate fair value.

(d) The registered investment company is a money market mutual fund with a stable net asset value of one dollar per share.

(e) The registered investment company holds investments in domestic and international bond markets and estimates fair value using net asset value per share.

(f) The other remaining assets are U.S. municipal and foreign government bonds stated at fair value as determined by broker quotes.

(g) The unallocated insurance contract investments are recorded at contract value, which approximates fair value. The contract value represents contributions made under the contract, plus interest, less funds used to pay benefits and contract expenses, and less distributions to the master trust.

(h) 103-12 investment entities hold investments in accordance with stated objectives. The investment strategy of the investment entities is to capture the growth potential of international equity markets by replicating the performance of a specified index. Net asset value per share of the 103-12 investment entities estimate fair value.

## Accumulated Pension Benefit Obligation

The accumulated benefit obligation for Entergy’s qualified pension plans was $6.3 billion and $6.6 billion at December 31, 2015 and 2014, respectively.



## Estimated Future Benefit Payments

Based upon the assumptions used to measure Entergy’s qualified pension and other postretirement benefit obligations at December 31, 2015, 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:

Estimated Future Benefits Payments

<table><tr><td></td><td>Qualified Pension</td><td>Non-Qualified Pension</td><td>Other Postretirement (before Medicare Subsidy)</td><td>Estimated Future Medicare Subsidy Receipts</td></tr><tr><td>Year(s)</td><td></td><td></td><td>(In Thousands)</td><td></td></tr><tr><td>2016</td><td>$287,575</td><td>$21,187</td><td>$78,016</td><td>$381</td></tr><tr><td>2017</td><td>$301,880</td><td>$10,985</td><td>$80,565</td><td>$432</td></tr><tr><td>2018</td><td>$317,395</td><td>$11,456</td><td>$85,034</td><td>$1,387</td></tr><tr><td>2019</td><td>$334,308</td><td>$10,794</td><td>$88,803</td><td>$1,545</td></tr><tr><td>2020</td><td>$351,112</td><td>$13,443</td><td>$91,540</td><td>$1,733</td></tr><tr><td>2021 - 2025</td><td>$2,039,411</td><td>$80,652</td><td>$487,584</td><td>$11,672</td></tr></table>

## Contributions

Entergy currently expects to contribute approximately $387.5 million to its qualified pension plans and approximately $52.6 million to other postretirement plans in 2016. The expected 2016 pension and other postretirement plan contributions of the Registrant Subsidiaries for their employees are shown below. The 2016 required pension contributions will be known with more certainty when the January 1, 2016 valuations are completed, which is expected by April 1, 2016.

## Actuarial Assumptions

The significant actuarial assumptions used in determining the pension PBO and the other postretirement benefit APBO as of December 31, 2015 and 2014 were as follows:

<table><tr><td></td><td>2015</td><td>2014</td></tr><tr><td>Weighted-average discount rate:</td><td></td><td></td></tr><tr><td>Qualified pension</td><td>4.51% - 4.79%</td><td>4.03% - 4.40%</td></tr><tr><td></td><td>Blended 4.67%</td><td>Blended 4.27%</td></tr><tr><td>Other postretirement</td><td>4.60%</td><td>4.23%</td></tr><tr><td>Non-qualified pension</td><td>3.84%</td><td>3.61%</td></tr><tr><td>Weighted-average rate of increase in future compensation levels</td><td>4.23%</td><td>4.23%</td></tr><tr><td>Assumed health care trend rate:</td><td></td><td></td></tr><tr><td>Pre-65</td><td>6.75%</td><td>7.10%</td></tr><tr><td>Post-65</td><td>7.55%</td><td>7.70%</td></tr><tr><td>Ultimate rate</td><td>4.75%</td><td>4.75%</td></tr><tr><td>Year ultimate rate is reached and beyond:</td><td></td><td></td></tr><tr><td>Pre-65</td><td>2024</td><td>2023</td></tr><tr><td>Post-65</td><td>2024</td><td>2023</td></tr></table>



The significant actuarial assumptions used in determining the net periodic pension and other postretirement benefit costs for 2015, 2014, and 2013 were as follows:

<table><tr><td></td><td>2015</td><td>2014</td><td>2013</td></tr><tr><td>Weighted-average discount rate:</td><td></td><td></td><td></td></tr><tr><td>Qualified pension</td><td>4.03% - 4.40% Blended 4.27%</td><td>5.04% - 5.26% Blended 5.14%</td><td>4.31% - 4.50% Blended 4.36%</td></tr><tr><td>Other postretirement</td><td>4.23%</td><td>5.05%</td><td>4.36%</td></tr><tr><td>Non-qualified pension</td><td>3.61%</td><td>4.29%</td><td>3.37%</td></tr><tr><td>Weighted-average rate of increase in future compensation levels</td><td>4.23%</td><td>4.23%</td><td>4.23%</td></tr><tr><td>Expected long-term rate of return on plan assets:</td><td></td><td></td><td></td></tr><tr><td>Pension assets</td><td>8.25%</td><td>8.50%</td><td>8.50%</td></tr><tr><td>Other postretirement tax deferred assets</td><td>8.05%</td><td>8.30%</td><td>8.50%</td></tr><tr><td>Other postretirement taxable assets</td><td>6.25%</td><td>6.50%</td><td>6.50%</td></tr><tr><td>Assumed health care trend rate:</td><td></td><td></td><td></td></tr><tr><td>Pre-65</td><td>7.10%</td><td>7.25%</td><td>7.50%</td></tr><tr><td>Post-65</td><td>7.70%</td><td>7.00%</td><td>7.25%</td></tr><tr><td>Ultimate rate</td><td>4.75%</td><td>4.75%</td><td>4.75%</td></tr><tr><td>Year ultimate rate is reached and beyond:</td><td></td><td></td><td></td></tr><tr><td>Pre-65</td><td>2023</td><td>2022</td><td>2022</td></tr><tr><td>Post-65</td><td>2023</td><td>2022</td><td>2022</td></tr></table>

With respect to the mortality assumptions, Entergy used the RP-2014 Employee and Health Annuitant Tables, with a fully generational MP-2015 projection scale, in determining its December 31, 2015 pension plans' PBOs and other postretirement benefit APBO. The mortality assumption used in determining Entergy's December 31, 2014 pension plans' PBOs and other postretirement benefit APBO was the RP-2014 Employee and Health Annuitant Tables, with a fully generational MP-2014 projection scale.

A one percentage point change in the assumed health care cost trend rate for 2015 would have the following effects:

<table><tr><td rowspan="2"></td><td colspan="2">1 Percentage Point Increase</td><td colspan="2">1 Percentage Point Decrease</td></tr><tr><td>Impact on the APBO</td><td>Impact on the sum of service costs and interest cost</td><td>Impact on the APBO</td><td>Impact on the sum of service costs and interest cost</td></tr><tr><td>Entergy Corporation and its subsidiaries</td><td>$181,998</td><td>$19,022</td><td>($150,324)</td><td>($15,071)</td></tr></table>

## Defined Contribution Plans

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 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 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 $44.4 million in 2015, $43.3 million in 2014, and $44.5 million in 2013. The majority of the contributions were to the System Savings Plan.

## NOTE 12. STOCK-BASED COMPENSATION

Entergy grants stock options, restricted stock, performance units, and restricted stock unit awards to key employees of the Entergy subsidiaries under its Equity Ownership Plans which are shareholder-approved stock-based compensation plans. The Equity Ownership Plan, as restated in February 2003 (2003 Plan), had 888,602 authorized shares remaining for long-term incentive and restricted unit awards as of December 31, 2015. Effective January 1, 2007, Entergy’s shareholders approved the 2007 Equity Ownership and Long-Term Cash Incentive Plan (2007 Plan). The maximum aggregate number of common shares that can be issued from the 2007 Plan for stock-based awards is 7,000,000 with no more than 2,000,000 available for non-option grants. The 2007 Plan, which only applies to awards made on or after January 1, 2007, will expire after 10 years. As of December 31, 2015, there were 1,104,547 authorized shares remaining for stock-based awards, all of which are available for non-option grants. Effective May 6, 2011, Entergy’s shareholders approved the 2011 Equity Ownership and Long-Term Cash Incentive Plan (2011 Plan). The maximum number of common shares that can be issued from the 2011 Plan for stock-based awards is 5,500,000 with no more than 2,000,000 available for incentive stock option grants. The 2011 Plan, which only applies to awards made on or after May 6, 2011, will expire after 10 years. As of December 31, 2015, there were 720,775 authorized shares remaining for stock-based awards, including 2,000,000 for incentive stock option grants. Effective May 8, 2015, Entergy’s shareholders approved the 2015 Equity Ownership and Long-Term Cash Incentive Plan (2015 Plan). The maximum number of common shares that can be issued from the 2015 Plan for stock-based awards is 6,900,000 with no more than 1,500,000 available for incentive stock option grants. As of December 31, 2015, there were 6,771,686 authorized shares remaining for stock-based awards, including 1,500,000 for incentive stock option grants.

## Stock Options

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:

<table><tr><td></td><td>2015</td><td>2014</td><td>2013</td></tr><tr><td></td><td colspan="3">(In Millions)</td></tr><tr><td>Compensation expense included in Entergy’s Consolidated Net Income</td><td>$4.3</td><td>$4.1</td><td>$4.1</td></tr><tr><td>Tax benefit recognized in Entergy’s Consolidated Net Income</td><td>$1.6</td><td>$1.6</td><td>$1.6</td></tr><tr><td>Compensation cost capitalized as part of fixed assets and inventory</td><td>$0.7</td><td>$0.7</td><td>$0.7</td></tr></table>



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:

<table><tr><td></td><td>2015</td><td>2014</td><td>2013</td></tr><tr><td>Stock price volatility</td><td>23.62%</td><td>24.67%</td><td>24.61%</td></tr><tr><td>Expected term in years</td><td>7.06</td><td>6.95</td><td>6.69</td></tr><tr><td>Risk-free interest rate</td><td>1.59%</td><td>2.16%</td><td>1.31%</td></tr><tr><td>Dividend yield</td><td>4.50%</td><td>4.75%</td><td>4.75%</td></tr><tr><td>Dividend payment per share</td><td>$3.34</td><td>$3.32</td><td>$3.32</td></tr></table>

Stock price volatility is calculated based upon the daily public stock price volatility of Entergy Corporation common stock over a period equal to the expected term of the award. The expected term of the options is based upon historical option exercises and the weighted average life of options when exercised and the estimated weighted average life of all vested but unexercised options. In 2008, Entergy implemented stock ownership guidelines for its senior executive officers. These guidelines require an executive officer to own shares of Entergy Corporation common stock equal to a specified multiple of his or her salary. Until an executive officer achieves this ownership position the executive officer is required to retain 75% of the net-of-tax net profit upon exercise of the option to be held in Entergy Corporation common stock. The reduction in fair value of the stock options due to this restriction is based upon an estimate of the call option value of the reinvested gain discounted to present value over the applicable reinvestment period.

A summary of stock option activity for the year ended December 31, 2015 and changes during the year are presented below:

<table><tr><td></td><td>Number of Options</td><td>Weighted-Average Exercise Price</td><td>Aggregate Intrinsic Value</td><td>Weighted-Average Contractual Life</td></tr><tr><td>Options outstanding as of January 1, 2015</td><td>7,281,396</td><td>$83.25</td><td></td><td></td></tr><tr><td>Options granted</td><td>456,100</td><td>$89.90</td><td></td><td></td></tr><tr><td>Options exercised</td><td>(334,274)</td><td>$71.45</td><td></td><td></td></tr><tr><td>Options forfeited/expired</td><td>(3,402)</td><td>$90.49</td><td></td><td></td></tr><tr><td>Options outstanding as of December 31, 2015</td><td>7,399,820</td><td>$84.19</td><td>$—</td><td>3.7 years</td></tr><tr><td>Options exercisable as of December 31, 2015</td><td>6,392,457</td><td>$85.57</td><td>$—</td><td>3.0 years</td></tr><tr><td>Weighted-average grant-date fair value of options granted during 2015</td><td colspan="4">$11.41</td></tr></table>

The weighted-average grant-date fair value of options granted during the year was $8.71 for 2014 and $8.00 for 2013. The total intrinsic value of stock options exercised was $5.1 million during 2015, $25.5 million during 2014, and $5.7 million during 2013. The intrinsic value, which has no effect on net income, of the stock options exercised is calculated by the difference in Entergy Corporation’s common stock price on the date of exercise and the exercise price of the stock options granted. Because Entergy’s year-end stock price was less than the weighted average exercise price, the aggregate intrinsic value of outstanding stock options as of December 31, 2015 was zero. The intrinsic value of “in the money” stock options is $5 million as of December 31, 2015. Entergy recognizes compensation cost over the vesting period of the options based on their grant-date fair value. The total fair value of options that vested was approximately $4 million during 2015, $4 million during 2014, and $11 million during 2013. Cash received from option exercises was $23.9 million for the year ended December 31, 2015. The tax benefits realized from options exercised was $1.9 million for the year ended December 31, 2015.

The following table summarizes information about stock options outstanding as of December 31, 2015:



<table><tr><td rowspan="2"></td><td colspan="3">Options Outstanding</td><td colspan="2">Options Exercisable</td></tr><tr><td>As of 12/31/2015</td><td>Weighted-Average Remaining Contractual Life-Yrs.</td><td>Weighted Average Exercise Price</td><td>Number Exercisable as of 12/31/2015</td><td>Weighted Average Exercise Price</td></tr><tr><td>Range of Exercise Prices</td><td>$51- $64.99</td><td>1,100,272</td><td>7.62</td><td>$63.82</td><td>$46,009</td></tr><tr><td></td><td>$65- $78.99</td><td>2,798,432</td><td>3.62</td><td>$74.51</td><td>$74.51</td></tr><tr><td></td><td>$79- $91.99</td><td>2,059,516</td><td>2.84</td><td>$91.39</td><td>$1,606,416</td></tr><tr><td></td><td>$92- $108.20</td><td>1,441,600</td><td>2.06</td><td>$108.20</td><td>$1,441,600</td></tr><tr><td></td><td>$51- $108.20</td><td>7,399,820</td><td>3.70</td><td>$84.19</td><td>$6,392,457</td></tr></table>

Stock-based compensation cost related to non-vested stock options outstanding as of December 31, 2015 not yet recognized is approximately $5.6 million and is expected to be recognized over a weighted-average period of 1.70 years.

## Restricted Stock Awards

In January 2015 the Board approved and Entergy granted 292,750 restricted stock awards under the 2011 Equity Ownership and Long-term Cash Incentive Plan. The restricted stock awards were made effective as of January 29, 2015 and were valued at $89.90 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 ratably over the three year vesting period. Shares of restricted stock have the same dividend and voting rights as other common stock and are considered issued and outstanding shares of Entergy upon vesting.

The following table includes information about the restricted stock awards outstanding as of December 31, 2015:

<table><tr><td></td><td>Shares</td><td>Weighted-Average Grant Date Fair Value Per Share</td></tr><tr><td>Outstanding shares at January 1, 2015</td><td>674,445</td><td>$64.82</td></tr><tr><td>Granted</td><td>323,110</td><td>$88.58</td></tr><tr><td>Vested</td><td>(325,623)</td><td>$66.09</td></tr><tr><td>Forfeited</td><td>(29,203)</td><td>$70.31</td></tr><tr><td>Outstanding shares at December 31, 2015</td><td>642,729</td><td>$75.88</td></tr></table>

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

<table><tr><td></td><td>2015</td><td>2014</td><td>2013</td></tr><tr><td></td><td colspan="3">(In Millions)</td></tr><tr><td>Compensation expense included in Entergy’s Consolidated Net Income</td><td>$19.5</td><td>$19.3</td><td>$16.4</td></tr><tr><td>Tax benefit recognized in Entergy’s Consolidated Net Income</td><td>$7.5</td><td>$7.5</td><td>$6.3</td></tr><tr><td>Compensation cost capitalized as part of fixed assets and inventory</td><td>$3.9</td><td>$3.1</td><td>$2.6</td></tr></table>

The total fair value of the restricted stock awards granted was $28.6 million, $24.2 million, and $25.4 million for the years ended December 31, 2015, 2014, and 2013, respectively.



The total fair value of the restricted stock awards vested was $28.7 million, $16.5 million, and $11 million for the years ended December 31, 2015, 2014, and 2013, respectively.

## Long-Term Performance Unit Program

Entergy grants long-term incentive awards earned under its stock benefit plans in the form of performance units, which represents the value of one share of Entergy Corporation common stock at the end of the three-year performance period, plus dividends accrued during the performance period. The Long-Term Performance Unit Program specifies a minimum, target, and maximum achievement level, the achievement of which will determine the number of performance units that may be earned. Entergy measures performance by assessing Entergy’s total shareholder return relative to the total shareholder return of the companies in the Philadelphia Utility Index. There is no payout for performance that falls within the lowest quartile of performance of the peer companies. For top quartile performance, a maximum payout of 200% of target is earned.

The costs of incentive awards are charged to income over the 3-year period. In January 2015 the Board approved and Entergy granted 156,017 performance units under the 2011 Equity Ownership and Long-Term Cash Incentive Plan. The performance units were made effective as of January 29, 2015, and were valued at $99.02 per share. 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 vesting period.

The following table includes information about the long-term performance units outstanding at the target level as of December 31, 2015:

<table><tr><td></td><td>Shares</td><td>Weighted-Average Grant Date Fair Value Per Share</td></tr><tr><td>Outstanding shares at January 1, 2015</td><td>565,104</td><td>$66.53</td></tr><tr><td>Granted</td><td>166,886</td><td>$97.99</td></tr><tr><td>Vested</td><td>(105,503)</td><td>$67.11</td></tr><tr><td>Forfeited</td><td>(58,005)</td><td>$69.73</td></tr><tr><td>Outstanding shares at December 31, 2015</td><td>568,482</td><td>$75.33</td></tr></table>

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

<table><tr><td></td><td>2015</td><td>2014</td><td>2013</td></tr><tr><td></td><td colspan="3">(In Millions)</td></tr><tr><td>Compensation expense included in Entergy’s Consolidated Net Income</td><td>$11.8</td><td>$10.7</td><td>$6.0</td></tr><tr><td>Tax benefit recognized in Entergy’s Consolidated Net Income</td><td>$4.5</td><td>$4.1</td><td>$2.3</td></tr><tr><td>Compensation cost capitalized as part of fixed assets and inventory</td><td>$2.3</td><td>$1.5</td><td>$0.9</td></tr></table>

The total fair value of the long-term performance units granted was $16.4 million, $15.8 million and $16.3 million for the years ended December 31, 2015, 2014, and 2013, respectively.

In January 2015, Entergy issued 105,503 shares of Entergy common stock at a share price of $88.67 for awards earned and dividends accrued under the 2012-2014 Long-Term Performance Unit Program. There was no payout in 2014 and 2013 for the performance units applicable to the 2011-2013 Long-Term Performance Unit Program and 2010-2012 Long-Term Performance Program, respectively.



## Restricted Stock Unit Awards

Entergy grants restricted stock unit awards earned under its stock benefit plans in the form of stock units that are subject to time-based restrictions. The restricted stock units may be settled in shares of Entergy common stock or the cash value of shares of Entergy common stock at the time of vesting. The costs of restricted stock unit awards are charged to income over the restricted period, which varies from grant to grant. The average vesting period for restricted stock unit awards granted is 42 months. As of December 31, 2015, there were 145,018 unvested restricted stock units that are expected to vest over an average period of 32 months.

The following table includes information about the restricted stock unit awards outstanding as of December 31, 2015:

<table><tr><td></td><td>Shares</td><td>Weighted-Average Grant Date Fair Value Per Share</td></tr><tr><td>Outstanding shares at January 1, 2015</td><td>98,334</td><td>$73.42</td></tr><tr><td>Granted</td><td>57,100</td><td>$69.57</td></tr><tr><td>Vested</td><td>(10,416)</td><td>$68.73</td></tr><tr><td>Forfeited</td><td>—</td><td>$—</td></tr><tr><td>Outstanding shares at December 31, 2015</td><td>145,018</td><td>$72.03</td></tr></table>

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

<table><tr><td rowspan="2"></td><td>2015</td><td>2014</td><td>2013</td></tr><tr><td colspan="3">(In Millions)</td></tr><tr><td>Compensation expense included in Entergy’s Consolidated Net Income</td><td>$0.9</td><td>$2.2</td><td>$1.4</td></tr><tr><td>Tax benefit recognized in Entergy’s Consolidated Net Income</td><td>$0.4</td><td>$0.9</td><td>$0.6</td></tr><tr><td>Compensation cost capitalized as part of fixed assets and inventory</td><td>$0.3</td><td>$0.3</td><td>$0.2</td></tr></table>

The total fair value of the restricted stock unit awards granted was $4 million, $3.2 million, and $2.7 million for the years ended December 31, 2015, 2014, and 2013, respectively.

The total fair value of the restricted stock unit awards vested was $3.8 million, $3.3 million, and $2.5 million for the years ended December 31, 2015, 2014, and 2013, respectively.

Entergy paid $0.7 million, $1.7 million, and $2.1 million for the years ended December 31, 2015, 2014, and 2013, respectively, for awards under the Restricted Stock Units Awards Plan.



## NOTE 13. BUSINESS SEGMENT INFORMATION

Entergy’s reportable segments as of December 31, 2015 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 decommissioning of nuclear power plants located in the northern United States and the sale of the electric power produced by 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.

Entergy’s segment financial information is as follows:

<table><tr><td>2015</td><td>Utility</td><td>Entergy Wholesale Commodities*</td><td>All Other</td><td>Eliminations</td><td>Consolidated</td></tr><tr><td></td><td></td><td>(In Thousands)</td><td></td><td></td><td></td></tr><tr><td>Operating revenues</td><td>$9,451,486</td><td>$2,061,827</td><td>$—</td><td>($62)</td><td>$11,513,251</td></tr><tr><td>Asset write-offs, impairments, and related charges</td><td>$68,672</td><td>$2,036,234</td><td>$—</td><td>$—</td><td>$2,104,906</td></tr><tr><td>Depreciation, amortization, &amp; decommissioning</td><td>$1,238,832</td><td>$376,560</td><td>$2,156</td><td>$—</td><td>$1,617,548</td></tr><tr><td>Interest and investment income</td><td>$191,546</td><td>$148,654</td><td>$34,303</td><td>($187,441)</td><td>$187,062</td></tr><tr><td>Interest expense</td><td>$543,132</td><td>$26,788</td><td>$129,750</td><td>($56,201)</td><td>$643,469</td></tr><tr><td>Income taxes</td><td>$16,761</td><td>($610,339)</td><td>($49,349)</td><td>$—</td><td>($642,927)</td></tr><tr><td>Consolidated net income (loss)</td><td>$1,114,516</td><td>($1,065,657)</td><td>($74,353)</td><td>($131,240)</td><td>($156,734)</td></tr><tr><td>Total assets</td><td>$38,356,906</td><td>$8,210,183</td><td>($461,505)</td><td>($1,457,903)</td><td>$44,647,681</td></tr><tr><td>Investment in affiliates - at equity</td><td>$199</td><td>$4,142</td><td>$—</td><td>$—</td><td>$4,341</td></tr><tr><td>Cash paid for long-lived asset additions</td><td>$2,495,194</td><td>$569,824</td><td>$236</td><td>$—</td><td>$3,065,254</td></tr></table>

<table><tr><td>2014</td><td>Utility</td><td>Entergy Wholesale Commodities*</td><td>All Other</td><td>Eliminations</td><td>Consolidated</td></tr><tr><td></td><td></td><td>(In Thousands)</td><td></td><td></td><td></td></tr><tr><td>Operating revenues</td><td>$9,773,822</td><td>$2,719,404</td><td>$1,821</td><td>($126)</td><td>$12,494,921</td></tr><tr><td>Asset write-offs, impairments, and related charges</td><td>$72,225</td><td>$107,527</td><td>$—</td><td>$—</td><td>$179,752</td></tr><tr><td>Depreciation, amortization, &amp; decommissioning</td><td>$1,170,122</td><td>$417,435</td><td>$3,702</td><td>$—</td><td>$1,591,259</td></tr><tr><td>Interest and investment income</td><td>$171,217</td><td>$113,959</td><td>$22,159</td><td>($159,649)</td><td>$147,686</td></tr><tr><td>Interest expense</td><td>$531,729</td><td>$16,646</td><td>$120,908</td><td>($41,776)</td><td>$627,507</td></tr><tr><td>Income taxes</td><td>$472,148</td><td>$176,988</td><td>($59,539)</td><td>$—</td><td>$589,597</td></tr><tr><td>Consolidated net income (loss)</td><td>$846,496</td><td>$294,521</td><td>($62,887)</td><td>($117,873)</td><td>$960,257</td></tr><tr><td>Total assets</td><td>$38,186,286</td><td>$10,279,500</td><td>($659,207)</td><td>($1,392,124)</td><td>$46,414,455</td></tr><tr><td>Investment in affiliates - at equity</td><td>$199</td><td>$36,035</td><td>$—</td><td>$—</td><td>$36,234</td></tr><tr><td>Cash paid for long-lived asset additions</td><td>$2,113,631</td><td>$615,021</td><td>$87</td><td>$—</td><td>$2,728,739</td></tr></table>



<table><tr><td>2013</td><td>Utility</td><td>Entergy Wholesale Commodities*</td><td>All Other</td><td>Eliminations</td><td>Consolidated</td></tr><tr><td></td><td></td><td></td><td>(In Thousands)</td><td></td><td></td></tr><tr><td>Operating revenues</td><td>$9,101,786</td><td>$2,312,758</td><td>$3,558</td><td>($27,155)</td><td>$11,390,947</td></tr><tr><td>Asset write-offs, impairments, and related charges</td><td>$9,411</td><td>$329,336</td><td>$2,790</td><td>$—</td><td>$341,537</td></tr><tr><td>Depreciation, amortization, &amp; decommissioning</td><td>$1,157,843</td><td>$341,163</td><td>$4,142</td><td>$—</td><td>$1,503,148</td></tr><tr><td>Interest and investment income</td><td>$186,724</td><td>$137,727</td><td>$24,179</td><td>($149,330)</td><td>$199,300</td></tr><tr><td>Interest expense</td><td>$509,173</td><td>$16,323</td><td>$122,291</td><td>($43,750)</td><td>$604,037</td></tr><tr><td>Income taxes</td><td>$365,917</td><td>($77,471)</td><td>($62,465)</td><td>$—</td><td>$225,981</td></tr><tr><td>Consolidated net income (loss)</td><td>$846,215</td><td>$42,976</td><td>($53,039)</td><td>($105,580)</td><td>$730,572</td></tr><tr><td>Total assets</td><td>$35,429,568</td><td>$9,696,705</td><td>($492,577)</td><td>($1,343,406)</td><td>$43,290,290</td></tr><tr><td>Investment in affiliates - at equity</td><td>$199</td><td>$40,151</td><td>$—</td><td>$—</td><td>$40,350</td></tr><tr><td>Cash paid for long-lived asset additions</td><td>$2,268,083</td><td>$626,322</td><td>$49</td><td>$—</td><td>$2,894,454</td></tr></table>

Businesses marked with * are sometimes referred to as the “competitive businesses.” Eliminations are primarily intersegment activity. Almost all of Entergy’s goodwill is related to the Utility segment.

Earnings were negatively affected by expenses in 2013 of approximately $110 million ($70 million net-of-tax), including approximately $85 million ($55 million net-of-tax) for Utility and $25 million ($15 million net-of-tax) for Entergy Wholesale Commodities, and expenses in 2014 of approximately $20 million ($12 million net-of-tax), including approximately $15 million ($9 million net-of-tax) for Utility and $5 million ($3 million net-of-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 operation and maintenance” in the consolidated income statements. The property, plant, and equipment impairments are included in “Asset write-offs, impairments, and related charges” in the consolidated income statements. Total restructuring charges were comprised of the following:

<table><tr><td rowspan="2"></td><td colspan="3">2013</td><td colspan="2">2014</td><td colspan="2">2015</td></tr><tr><td>Restructuring Costs</td><td>Paid In Cash</td><td>Non-Cash Portion</td><td>Restructuring Costs</td><td>Paid In Cash</td><td>Paid In Cash</td><td></td></tr><tr><td></td><td></td><td></td><td colspan="5">(In Millions)</td></tr><tr><td>Implementation costs</td><td>$19</td><td>$19</td><td>$—</td><td>$9</td><td>$9</td><td>$—</td><td></td></tr><tr><td>Severance costs</td><td>45</td><td>6</td><td>—</td><td>11</td><td>44</td><td>6</td><td></td></tr><tr><td>Benefits-related costs</td><td>26</td><td>—</td><td>26</td><td>—</td><td>—</td><td>—</td><td></td></tr><tr><td>Property, plant, and equipment impairments</td><td>20</td><td>—</td><td>20</td><td>—</td><td>—</td><td>—</td><td></td></tr><tr><td>Total</td><td>$110</td><td>$25</td><td>$46</td><td>$20</td><td>$53</td><td>$6</td><td></td></tr></table>



## Geographic Areas

For the years ended December 31, 2015, 2014, and 2013, the amount of revenue Entergy derived from outside of the United States was insignificant. As of December 31, 2015 and 2014, Entergy had no long-lived assets located outside of the United States.

## NOTE 14. EQUITY METHOD INVESTMENTS

As of December 31, 2015, Entergy owns investments in the following companies that it accounts for under the equity method of accounting:

<table><tr><td>Investment</td><td>Ownership</td><td>Description</td></tr><tr><td>RS Cogen LLC</td><td>50% member interest</td><td>Co-generation project that produces power and steam on an industrial and merchant basis in the Lake Charles, Louisiana area.</td></tr><tr><td>Top Deer</td><td>50% member interest</td><td>Wind-powered electric generation joint venture.</td></tr></table>

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

<table><tr><td></td><td>2015</td><td>2014</td><td>2013</td></tr><tr><td></td><td colspan="3">(In Thousands)</td></tr><tr><td>Beginning of year</td><td>$36,234</td><td>$40,350</td><td>$46,738</td></tr><tr><td>Loss from the investments</td><td>(36,269)</td><td>(5,169)</td><td>(1,702)</td></tr><tr><td>Other adjustments</td><td>4,376</td><td>1,053</td><td>(4,686)</td></tr><tr><td>End of year</td><td>$4,341</td><td>$36,234</td><td>$40,350</td></tr></table>

Loss from the investments in 2015 includes a $36.8 million pre-tax impairment charge resulting from a write-down of the generating assets of Top Deer, of which Entergy’s owns a 50% interest.

## Transactions with equity method investees

Entergy Louisiana purchased approximately $3.2 million in 2013 of electricity generated from Entergy’s share of RS Cogen. Entergy Louisiana made no purchases in 2015 and 2014 of electricity generated from Entergy’s share of RS Cogen.

EWO Marketing, LLC, an indirect wholly-owned subsidiary of Entergy, paid capacity charges and gas transportation to RS Cogen in the amounts of $24.5 million, $23.1 million, and $22.9 million for 2015, 2014, and 2013, respectively.

Entergy’s operating transactions with its other equity method investees were not significant in 2015, 2014, or 2013.



## NOTE 15. ACQUISITIONS AND DISPOSITIONS

## Acquisitions

## Palisades Purchased Power Agreement

Entergy’s purchase of the Palisades plant in 2007 included a unit-contingent, 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/MWh in 2007 to $61.50/MWh in 2022, and the average price under the PPA is $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 $15 million in 2015, $16 million in 2014, and $18 million in 2013. The amounts to be amortized to revenue for the next five years will be $13 million in 2016, $12 million for 2017, $8 million for 2018, $13 million for 2019, and $15 million for 2020.

## NYPA Value Sharing Agreements

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 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 paid NYPA $6.59 per MWh for power sold from Indian Point 3, up to an annual cap of $48 million, and $3.91 per MWh for power sold from FitzPatrick, up to an annual cap of $24 million. The annual payment for each year’s output was due by January 15 of the following year. Entergy 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 was recorded to the plant asset account as contingent purchase price consideration for the plants. In 2014 and 2013, Entergy Wholesale Commodities recorded approximately $72 million as plant for generation during each of those years. This amount was depreciated over the expected remaining useful life of the plants.

## Dispositions

In December 2015, Entergy sold the Rhode Island State Energy Center, a 583 MW natural gas-fired combined-cycle generating plant owned by Entergy in the Entergy Wholesale Commodities segment. Entergy sold Rhode Island State Energy Center for approximately $490 million and realized a pre-tax gain of $154 million on the sale.

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 million and realized a pre-tax gain of $44 million on the sale.

## NOTE 16. RISK MANAGEMENT AND FAIR VALUES

## Market Risk

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 commodity or 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’ 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 and gas contracts, Entergy Wholesale Commodities also uses a combination of financial contracts, including swaps, collars, and options, to mitigate commodity price risk. When the market price falls, the combination of instruments is expected to settle in gains that offset lower revenue from generation, 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.

## Derivatives

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 natural gas and electricity swaps and options and interest rate swaps. Entergy may enter into financially-settled swap and option contracts to manage market risk that may or may not be designated as hedging instruments.

Entergy enters into derivatives 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, 2015 is approximately 2 years. Planned generation currently under contract from Entergy Wholesale Commodities nuclear power plants is 86% for 2016, of which approximately 62% is sold under financial derivatives and the remainder under normal purchase/normal sale contracts. Total planned generation for 2016 is 36 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 credit support to secure its obligations when the current market prices exceed the contracted power prices. The primary form of credit support to satisfy these requirements is an Entergy Corporation guarantee. As of December 31, 2015, derivative contracts with 2 counterparties were in a liability position (approximately $2 million total). In addition to the corporate guarantee, $9 million in cash collateral was required to be posted by the Entergy subsidiary to its counterparties and $68 million was required to be posted by its counterparties to the Entergy subsidiary. As of December 31, 2014, derivative contracts with 1 counterparty were in a liability position (approximately $1 million total). 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 Louisiana and Entergy New Orleans) and Entergy Mississippi 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 at Entergy Louisiana and Entergy Mississippi and projected winter purchases for gas distribution at Entergy Louisiana and Entergy New Orleans. The total volume of natural gas swaps outstanding as of December 31, 2015 is 39,816,000 MMBtu for Entergy, including 32,140,000 MMBtu for Entergy Louisiana, 7,010,000 MMBtu for Entergy Mississippi, and 666,000 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.

During the second quarter 2015, Entergy participated in the annual FTR auction process for the MISO planning year of June 1, 2015 through May 31, 2016. 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 prior to settlement. Unrealized gains or losses on FTRs held by Entergy Wholesale Commodities are included in operating revenues. The Utility operating companies recognize regulatory liabilities or assets for unrealized gains or losses on FTRs. The total volume of FTRs outstanding as of December 31, 2015 is 46,355 GWh for Entergy, including 9,726 GWh for Entergy Arkansas, 21,383 GWh for Entergy Louisiana, 6,160 GWh for Entergy Mississippi, 3,517 GWh for Entergy New Orleans, and 5,294 GWh for Entergy Texas. Credit support for FTRs held by the Utility operating companies is covered by cash and/or letters of credit issued by each Utility operating company as required by MISO. Credit support for FTRs held by Entergy Wholesale Commodities is covered by cash. As of December 31, 2014, letters of credit posted with MISO covered the FTR exposure for Entergy Arkansas and Entergy Mississippi. As of December 31, 2015, no cash or letters of credit were required to be posted for FTR exposure for the Utility operating companies or Entergy Wholesale Commodities, respectively.



The fair values of Entergy’s derivative instruments in the consolidated balance sheet as of December 31, 2015 are shown in the table below. Certain investments, including those not designated as hedging instruments, are subject to master netting agreements and are presented in the balance sheet on a net basis in accordance with accounting guidance for derivatives and hedging.

<table><tr><td>Instrument</td><td>Balance Sheet Location</td><td>Fair Value (a)</td><td>Offset (b)</td><td>Net (c) (d)</td><td>Business</td></tr><tr><td></td><td></td><td></td><td colspan="3">(In Millions)</td></tr><tr><td>Derivatives designated as hedging instruments</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Assets:</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Electricity swaps and options</td><td>Prepayments and other (current portion)</td><td>$173</td><td>($34)</td><td>$139</td><td>Entergy Wholesale Commodities</td></tr><tr><td>Electricity swaps and options</td><td>Other deferred debits and other assets (non-current portion)</td><td>$17</td><td>($2)</td><td>$15</td><td>Entergy Wholesale Commodities</td></tr><tr><td>Liabilities:</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Electricity swaps and options</td><td>Other current liabilities (current portion)</td><td>$14</td><td>($14)</td><td>$—</td><td>Entergy Wholesale Commodities</td></tr><tr><td>Electricity swaps and options</td><td>Other non-current liabilities (non-current portion)</td><td>$2</td><td>($2)</td><td>$—</td><td>Entergy Wholesale Commodities</td></tr><tr><td>Derivatives not designated as hedging instruments</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Assets:</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Electricity swaps and options</td><td>Prepayments and other (current portion)</td><td>$54</td><td>($13)</td><td>$41</td><td>Entergy Wholesale Commodities</td></tr><tr><td>FTRs</td><td>Prepayments and other</td><td>$24</td><td>($1)</td><td>$23</td><td>Utility and Entergy Wholesale Commodities</td></tr><tr><td>Liabilities:</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Electricity swaps and options</td><td>Other current liabilities (current portion)</td><td>$38</td><td>($32)</td><td>$6</td><td>Entergy Wholesale Commodities</td></tr><tr><td>Natural gas swaps</td><td>Other current liabilities</td><td>$9</td><td>$—</td><td>$9</td><td>Utility</td></tr></table>



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

<table><tr><td>Instrument</td><td>Balance Sheet Location</td><td>Fair Value (a)</td><td>Offset (b)</td><td>Net (c) (d)</td><td>Business</td></tr><tr><td></td><td></td><td></td><td>(In Millions)</td><td></td><td></td></tr><tr><td>Derivatives designated as hedging instruments</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Assets:</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Electricity swaps and options</td><td>Prepayments and other (current portion)</td><td>$149</td><td>($53)</td><td>$96</td><td>Entergy Wholesale Commodities</td></tr><tr><td>Electricity swaps and options</td><td>Other deferred debits and other assets (non-current portion)</td><td>$48</td><td>$—</td><td>$48</td><td>Entergy Wholesale Commodities</td></tr><tr><td>Liabilities:</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Electricity swaps and options</td><td>Other current liabilities (current portion)</td><td>$24</td><td>($24)</td><td>$—</td><td>Entergy Wholesale Commodities</td></tr><tr><td>Derivatives not designated as hedging instruments</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Assets:</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Electricity swaps and options</td><td>Prepayments and other (current portion)</td><td>$97</td><td>($25)</td><td>$72</td><td>Entergy Wholesale Commodities</td></tr><tr><td>Electricity swaps and options</td><td>Other deferred debits and other assets (non-current portion)</td><td>$9</td><td>($8)</td><td>$1</td><td>Entergy Wholesale Commodities</td></tr><tr><td>FTRs</td><td>Prepayments and other</td><td>$50</td><td>($3)</td><td>$47</td><td>Utility and Entergy Wholesale Commodities</td></tr><tr><td>Liabilities:</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Electricity swaps and options</td><td>Other current liabilities (current portion)</td><td>$57</td><td>($55)</td><td>$2</td><td>Entergy Wholesale Commodities</td></tr><tr><td>Electricity swaps and options</td><td>Other non-current liabilities (non-current portion)</td><td>$8</td><td>($8)</td><td>$—</td><td>Entergy Wholesale Commodities</td></tr><tr><td>Natural gas swaps</td><td>Other current liabilities</td><td>$20</td><td>$—</td><td>$20</td><td>Utility</td></tr></table>

(a) Represents the gross amounts of recognized assets/liabilities

(b) Represents the netting of fair value balances with the same counterparty

(c) Represents the net amounts of assets/liabilities presented on the Entergy Consolidated Balance Sheets

(d) Excludes cash collateral in the amount of $9 million posted and $68 million held as of December 31, 2015 and $25 million held as of December 31, 2014, respectively



The effect of Entergy’s derivative instruments designated as cash flow hedges on the consolidated statements of operations for the years ended December 31, 2015, 2014, and 2013 are as follows:

<table><tr><td>Instrument</td><td>Amount of gain (loss) recognized in other comprehensive income</td><td>Income Statement location</td><td>Amount of gain (loss) reclassified from AOCI into income (a)</td></tr><tr><td>2015</td><td>(In Millions)</td><td></td><td>(In Millions)</td></tr><tr><td>Electricity swaps and options</td><td>$254</td><td>Competitive business operating revenues</td><td>($244)</td></tr><tr><td>2014</td><td></td><td></td><td></td></tr><tr><td>Electricity swaps and options</td><td>$81</td><td>Competitive business operating revenues</td><td>($193)</td></tr><tr><td>2013</td><td></td><td></td><td></td></tr><tr><td>Electricity swaps and options</td><td>($190)</td><td>Competitive business operating revenues</td><td>$47</td></tr></table>

(a) Before taxes of ($85) million, ($68) million, and $18 million, for the years ended December 31, 2015, 2014, and 2013, respectively

At each reporting period, Entergy measures its hedges for ineffectiveness. Any ineffectiveness is recognized in earnings during the period. The ineffective portion of cash flow hedges is recorded in competitive businesses operating revenues. The change in fair value of Entergy’s cash flow hedges due to ineffectiveness was $150 thousand, $7 million, and ($6) million for the years ended December 31, 2015, 2014, and 2013, respectively.

Based on market prices as of December 31, 2015, unrealized gains recorded in AOCI on cash flow hedges relating to power sales totaled ($167) million of net unrealized gains. Approximately ($154) million is expected to be reclassified from AOCI to operating revenues in the next twelve months. The actual amount reclassified from AOCI, however, could vary due to future changes in market prices.

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 and the offsetting contract are recorded as assets or liabilities on the balance sheet and offset as they flow through to earnings.



The effect of Entergy’s derivative instruments not designated as hedging instruments on the consolidated statements of operations for the years ended December 31, 2015, 2014, and 2013 is as follows:

<table><tr><td>Instrument</td><td>Amount of gain (loss) recognized in AOCI</td><td>Income Statement location</td><td>Amount of gain (loss) recorded in the income statement</td></tr><tr><td>2015</td><td>(In Millions)</td><td></td><td>(In Millions)</td></tr><tr><td>Natural gas swaps</td><td>$—</td><td>Fuel, fuel-related expenses, and gas purchased for resale</td><td>(a) ($41)</td></tr><tr><td>FTRs</td><td>$—</td><td>Purchased power expense</td><td>(b) $166</td></tr><tr><td>Electricity swaps and options</td><td>$12</td><td>Competitive business operating revenues</td><td>($19)</td></tr><tr><td>2014</td><td></td><td></td><td></td></tr><tr><td>Natural gas swaps</td><td>$—</td><td>Fuel, fuel-related expenses, and gas purchased for resale</td><td>(a) ($8)</td></tr><tr><td>FTRs</td><td>$—</td><td>Purchased power expense</td><td>(b) $229</td></tr><tr><td>Electricity swaps and options</td><td>($13)</td><td>Competitive business operating revenues</td><td>$56</td></tr><tr><td>2013</td><td></td><td></td><td></td></tr><tr><td>Natural gas swaps</td><td>$—</td><td>Fuel, fuel-related expenses, and gas purchased for resale</td><td>(a) $13</td></tr><tr><td>FTRs</td><td>$—</td><td>Purchased power expense</td><td>(b) $3</td></tr><tr><td>Electricity swaps and options</td><td>$1</td><td>Competitive business operating revenues</td><td>($50)</td></tr></table>

(a) Due to regulatory treatment, the natural gas swaps are marked-to-market through fuel, fuel-related expenses, and gas purchased for resale and then such amounts are simultaneously reversed and recorded as an offsetting regulatory asset or liability. The gains or losses recorded as fuel expenses when the swaps are settled are recovered or refunded through fuel cost recovery mechanisms.

(b) Due to regulatory treatment, the changes in the estimated fair value of FTRs for the Utility operating companies are recorded through purchased power expense and then such amounts are simultaneously reversed and recorded as an offsetting regulatory asset or liability. The gains or losses recorded as purchased power expense when the FTRs for the Utility operating companies are settled are recovered or refunded through fuel cost recovery mechanisms.



## Fair Values

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:

- Level 1 - Level 1 inputs are unadjusted quoted prices in active markets for identical assets or liabilities that the entity has the ability to access at the measurement date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Level 1 primarily consists of individually owned common stocks, cash equivalents (temporary cash investments, securitization recovery trust account, and escrow accounts), debt instruments, and gas hedge contracts. Cash equivalents includes all unrestricted highly liquid debt instruments with an original or remaining maturity of three months or less at the date of purchase.

- Level 2 - Level 2 inputs are inputs other than quoted prices included in Level 1 that are, either directly or indirectly, observable for the asset or liability at the measurement date. Assets are valued based on prices derived by independent third parties that use inputs such as benchmark yields, reported trades, broker/dealer quotes, and issuer spreads. Prices are reviewed and can be challenged with the independent parties and/or overridden by Entergy if it is believed such would be more reflective of fair value. Level 2 inputs include the following:

- quoted prices for similar assets or liabilities in active markets;

- quoted prices for identical assets or liabilities in inactive markets;

- inputs other than quoted prices that are observable for the asset or liability; or

- inputs that are derived principally from or corroborated by observable market data by correlation or other means.

Level 2 consists primarily of individually-owned debt instruments or shares in common trusts. Common trust funds are stated at estimated fair value based on the fair market value of the underlying investments.

- Level 3 - Level 3 inputs are pricing inputs that are generally less observable or unobservable from objective sources. These inputs are used with internally developed methodologies to produce management’s best estimate of fair value for the asset or liability. Level 3 consists primarily of FTRs and derivative power contracts used as cash flow hedges of power sales at merchant power plants.

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



valuations of these assets and liabilities are performed by the Entergy Wholesale Commodities Risk Control group and the Entergy Wholesale Commodities Accounting Policy and External Reporting group. The primary functions of the Entergy Wholesale Commodities Risk Control group include: gathering, validating and reporting market data, providing market risk analyses and valuations in support of Entergy Wholesale Commodities' commercial transactions, developing and administering protocols for the management of market risks, and implementing and maintaining controls around changes to market data in the energy trading and risk management system. The Risk Control group is also responsible for managing the energy trading and risk management system, forecasting revenues, forward positions and analysis. The Entergy Wholesale Commodities Accounting Policy and External Reporting group performs functions related to market and counterparty settlements, revenue reporting and analysis and financial accounting. The Entergy Wholesale Commodities Risk Control group reports to the Vice President and Treasurer while the Entergy Wholesale Commodities Accounting Policy and External Reporting group reports to the Chief Accounting Officer.

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

The values of FTRs are based on unobservable inputs, including estimates of congestion costs in MISO between applicable generation and load pricing nodes based on the 50th percentile of historical prices. 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. The values are calculated internally and verified against the data published by MISO. 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 assumptions used in the valuation. The Risk Control groups report to the Vice President and Treasurer. The Accounting Policy group reports to the Chief Accounting Officer.



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, 2015 and December 31, 2014. 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.

<table><tr><td>2015</td><td>Level 1</td><td>Level 2</td><td>Level 3</td><td>Total</td></tr><tr><td></td><td colspan="4">(In Millions)</td></tr><tr><td>Assets:</td><td></td><td></td><td></td><td></td></tr><tr><td>Temporary cash investments</td><td>$1,287</td><td>$—</td><td>$—</td><td>$1,287</td></tr><tr><td>Decommissioning trust funds (a):</td><td></td><td></td><td></td><td></td></tr><tr><td>Equity securities</td><td>468</td><td>2,727</td><td>—</td><td>3,195</td></tr><tr><td>Debt securities</td><td>1,061</td><td>1,094</td><td>—</td><td>2,155</td></tr><tr><td>Power contracts</td><td>—</td><td>—</td><td>195</td><td>195</td></tr><tr><td>Securitization recovery trust account</td><td>50</td><td>—</td><td>—</td><td>50</td></tr><tr><td>Escrow accounts</td><td>425</td><td>—</td><td>—</td><td>425</td></tr><tr><td>FTRs</td><td>—</td><td>—</td><td>23</td><td>23</td></tr><tr><td></td><td>$3,291</td><td>$3,821</td><td>$218</td><td>$7,330</td></tr><tr><td>Liabilities:</td><td></td><td></td><td></td><td></td></tr><tr><td>Power contracts</td><td>$—</td><td>$—</td><td>$6</td><td>$6</td></tr><tr><td>Gas hedge contracts</td><td>9</td><td>—</td><td>—</td><td>9</td></tr><tr><td></td><td>$9</td><td>$—</td><td>$6</td><td>$15</td></tr><tr><td>2014</td><td>Level 1</td><td>Level 2</td><td>Level 3</td><td>Total</td></tr><tr><td></td><td colspan="4">(In Millions)</td></tr><tr><td>Assets:</td><td></td><td></td><td></td><td></td></tr><tr><td>Temporary cash investments</td><td>$1,291</td><td>$—</td><td>$—</td><td>$1,291</td></tr><tr><td>Decommissioning trust funds (a):</td><td></td><td></td><td></td><td></td></tr><tr><td>Equity securities</td><td>452</td><td>2,834</td><td>—</td><td>3,286</td></tr><tr><td>Debt securities</td><td>880</td><td>1,205</td><td>—</td><td>2,085</td></tr><tr><td>Power contracts</td><td>—</td><td>—</td><td>217</td><td>217</td></tr><tr><td>Securitization recovery trust account</td><td>44</td><td>—</td><td>—</td><td>44</td></tr><tr><td>Escrow accounts</td><td>362</td><td>—</td><td>—</td><td>362</td></tr><tr><td>FTRs</td><td>—</td><td>—</td><td>47</td><td>47</td></tr><tr><td></td><td>$3,029</td><td>$4,039</td><td>$264</td><td>$7,332</td></tr><tr><td>Liabilities:</td><td></td><td></td><td></td><td></td></tr><tr><td>Power contracts</td><td>$—</td><td>$—</td><td>$2</td><td>$2</td></tr><tr><td>Gas hedge contracts</td><td>20</td><td>—</td><td>—</td><td>20</td></tr><tr><td></td><td>$20</td><td>$—</td><td>$2</td><td>$22</td></tr></table>

(a) The decommissioning trust funds hold equity and fixed income securities. Equity securities are invested to approximate the returns of major market indices. Fixed income securities are held in various governmental and corporate securities. See Note 17 to the financial statements for additional information on the investment portfolios.



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, 2015, 2014, and 2013:

<table><tr><td rowspan="3"></td><td colspan="2">2015</td><td colspan="2">2014</td><td colspan="2">2013</td></tr><tr><td>Power Contracts</td><td>FTRs</td><td>Power Contracts</td><td>FTRs</td><td>Power Contracts</td><td>FTRs</td></tr><tr><td colspan="6">(In Millions)</td></tr><tr><td>Balance as of January 1,</td><td>$215</td><td>$47</td><td>($133)</td><td>$34</td><td>$178</td><td>$—</td></tr><tr><td>Total gains (losses) for the period (a)</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Included in earnings</td><td>(20)</td><td>(1)</td><td>55</td><td>2</td><td>(73)</td><td>—</td></tr><tr><td>Included in OCI</td><td>254</td><td>—</td><td>131</td><td>—</td><td>(204)</td><td>—</td></tr><tr><td>Included as a regulatory liability/asset</td><td>—</td><td>63</td><td>—</td><td>119</td><td>—</td><td>—</td></tr><tr><td>Issuances of FTRs</td><td>—</td><td>80</td><td>—</td><td>121</td><td>—</td><td>37</td></tr><tr><td>Purchases</td><td>15</td><td>—</td><td>17</td><td>—</td><td>14</td><td>—</td></tr><tr><td>Settlements</td><td>(275)</td><td>(166)</td><td>145</td><td>(229)</td><td>(48)</td><td>(3)</td></tr><tr><td>Balance as of December 31,</td><td>$189</td><td>$23</td><td>$215</td><td>$47</td><td>($133)</td><td>$34</td></tr></table>

(a) Change in unrealized gains or losses for the period included in earnings for derivatives held at the end of the reporting period is $3 million, $120 million, and ($35) million for the years ended December 31, 2015, 2014, and 2013, respectively.

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, 2015:

<table><tr><td>Transaction Type</td><td>Fair Value as of December 31, 2015</td><td>Significant Unobservable Inputs</td><td>Range from Average %</td><td>Effect on Fair Value</td></tr><tr><td></td><td>(In Millions)</td><td></td><td></td><td>(In Millions)</td></tr><tr><td>Power contracts - electricity swaps</td><td>$157</td><td>Unit contingent discount</td><td>+/-3%</td><td>$8</td></tr><tr><td>Power contracts - electricity options</td><td>$32</td><td>Implied volatility</td><td>+/-83%</td><td>$12</td></tr></table>

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:

<table><tr><td>Significant Unobservable Input</td><td>Transaction Type</td><td>Position</td><td>Change to Input</td><td>Effect on Fair Value</td></tr><tr><td>Unit contingent discount</td><td>Electricity swaps</td><td>Sell</td><td>Increase (Decrease)</td><td>Decrease (Increase)</td></tr><tr><td>Implied volatility</td><td>Electricity options</td><td>Sell</td><td>Increase (Decrease)</td><td>Increase (Decrease)</td></tr><tr><td>Implied volatility</td><td>Electricity options</td><td>Buy</td><td>Increase (Decrease)</td><td>Increase (Decrease)</td></tr></table>



## NOTE 17. DECOMMISSIONING TRUST FUNDS

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 30% interest in River Bend formerly owned by Cajun, Entergy 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 realized gains and losses on its debt and equity securities using the specific identification method to determine the cost basis of its securities.

The securities held as of December 31, 2015 and 2014 are summarized as follows:

<table><tr><td></td><td>Fair Value</td><td>Total Unrealized Gains</td><td>Total Unrealized Losses</td></tr><tr><td></td><td></td><td>(In Millions)</td><td></td></tr><tr><td>2015</td><td></td><td></td><td></td></tr><tr><td>Equity Securities</td><td>$3,195</td><td>$1,396</td><td>$2</td></tr><tr><td>Debt Securities</td><td>2,155</td><td>41</td><td>17</td></tr><tr><td>Total</td><td>$5,350</td><td>$1,437</td><td>$19</td></tr><tr><td></td><td></td><td></td><td></td></tr><tr><td></td><td>Fair Value</td><td>Total Unrealized Gains</td><td>Total Unrealized Losses</td></tr><tr><td></td><td></td><td>(In Millions)</td><td></td></tr><tr><td>2014</td><td></td><td></td><td></td></tr><tr><td>Equity Securities</td><td>$3,286</td><td>$1,513</td><td>$1</td></tr><tr><td>Debt Securities</td><td>2,085</td><td>76</td><td>6</td></tr><tr><td>Total</td><td>$5,371</td><td>$1,589</td><td>$7</td></tr></table>

Deferred taxes on unrealized gains/(losses) are recorded in other comprehensive income (loss) for the decommissioning trusts which do not meet the criteria for regulatory accounting treatment as described above. Unrealized gains/(losses) above are reported before deferred taxes of $342 million and $396 million as of December 31, 2015 and 2014, respectively. The amortized cost of debt securities was $2,124 million as of December 31, 2015 and $2,019 million as of December 31, 2014. As of December 31, 2015, the debt securities have an average coupon rate of approximately 3.16%, an average duration of approximately 5.70 years, and an average maturity of approximately 8.55 years. The equity securities are generally held in funds that are designed to approximate or somewhat exceed the return of the Standard & Poor's 500 Index. A relatively small percentage of the equity securities are held in funds intended to replicate the return of the Wilshire 4500 Index or the Russell 3000 Index.



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, 2015:

<table><tr><td rowspan="2"></td><td colspan="2">Equity Securities</td><td colspan="2">Debt Securities</td></tr><tr><td>Fair Value</td><td>Gross Unrealized Losses</td><td>Fair Value</td><td>Gross Unrealized Losses</td></tr><tr><td></td><td colspan="4">(In Millions)</td></tr><tr><td>Less than 12 months</td><td>$54</td><td>$2</td><td>$1,031</td><td>$15</td></tr><tr><td>More than 12 months</td><td>1</td><td>—</td><td>61</td><td>2</td></tr><tr><td>Total</td><td>$55</td><td>$2</td><td>$1,092</td><td>$17</td></tr></table>

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, 2014:

<table><tr><td rowspan="2"></td><td colspan="2">Equity Securities</td><td colspan="2">Debt Securities</td></tr><tr><td>Fair Value</td><td>Gross Unrealized Losses</td><td>Fair Value</td><td>Gross Unrealized Losses</td></tr><tr><td></td><td colspan="4">(In Millions)</td></tr><tr><td>Less than 12 months</td><td>$9</td><td>$1</td><td>$277</td><td>$2</td></tr><tr><td>More than 12 months</td><td>—</td><td>—</td><td>163</td><td>4</td></tr><tr><td>Total</td><td>$9</td><td>$1</td><td>$440</td><td>$6</td></tr></table>

The unrealized losses in excess of twelve months on equity securities above relate to Entergy’s Utility operating companies and System Energy.

The fair value of debt securities, summarized by contractual maturities, as of December 31, 2015 and 2014 are as follows:

<table><tr><td></td><td>2015</td><td>2014</td></tr><tr><td></td><td colspan="2">(In Millions)</td></tr><tr><td>less than 1 year</td><td>$77</td><td>$94</td></tr><tr><td>1 year - 5 years</td><td>857</td><td>783</td></tr><tr><td>5 years - 10 years</td><td>704</td><td>681</td></tr><tr><td>10 years - 15 years</td><td>124</td><td>173</td></tr><tr><td>15 years - 20 years</td><td>50</td><td>79</td></tr><tr><td>20 years+</td><td>343</td><td>275</td></tr><tr><td>Total</td><td>$2,155</td><td>$2,085</td></tr></table>

During the years ended December 31, 2015, 2014, and 2013, proceeds from the dispositions of securities amounted to $2,492 million, $1,872 million, and $2,032 million, respectively. During the years ended December 31, 2015, 2014, and 2013, gross gains of $72 million, $39 million, and $91 million, respectively, and gross losses of $13 million, $8 million, and $11 million, respectively, were reclassified out of other comprehensive income into earnings.



## Other-than-temporary impairments and unrealized gains and losses

Entergy, Entergy Arkansas, 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 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). Entergy did not have any material other-than-temporary impairments relating to credit losses on debt securities for the years ended December 31, 2015, 2014, and 2013. 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. Entergy did not record material charges to other income in 2015, 2014, and 2013, respectively, resulting from the recognition of the other-than-temporary impairment of certain equity securities held in its decommissioning trust funds.

## NOTE 18. VARIABLE INTEREST ENTITIES

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 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 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 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 New Orleans Storm Recovery Funding I, L.L.C., a company wholly-owned and consolidated by Entergy New Orleans, is a variable interest entity, and Entergy New Orleans is the primary beneficiary. In July 2015, Entergy New Orleans Storm Recovery Funding issued storm cost recovery bonds to recover Entergy New Orleans’s Hurricane Isaac storm restoration costs, including carrying costs, the costs of funding and replenishing the storm recovery reserve, and up-front financing costs associated with the securitization. With the proceeds, Entergy New Orleans Storm Recovery Funding purchased from Entergy New Orleans 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 New Orleans balance sheet. The creditors of Entergy New Orleans do not have recourse to the assets or revenues of Entergy New Orleans Storm Recovery Funding, including the storm recovery property, and the creditors of Entergy New Orleans Storm Recovery Funding do not have recourse to the assets or revenues of Entergy New Orleans. Entergy New Orleans has no payment obligations to Entergy New Orleans Storm Recovery Funding except to remit storm recovery charge collections. See Note 5 to the financial statements for additional details regarding the securitization 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 $28.8 million in 2015, $31 million in 2014, and $26.3 million in 2013. System Energy made payments on its lease, including interest, of $52.3 million in 2015, $51.6 million in 2014, and $50.5 million in 2013. 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, including agreements for renewable power, and other agreements that represent variable interests in other legal entities which have been determined to be variable interest entities. 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.

## NOTE 19. QUARTERLY FINANCIAL DATA (UNAUDITED)

Operating results for the four quarters of 2015 and 2014 for Entergy Corporation and subsidiaries were:

<table><tr><td></td><td>Operating Revenues</td><td>Operating Income (Loss)</td><td>Consolidated Net Income (Loss)</td><td>Net Income (Loss) Attributable to Entergy Corporation</td></tr><tr><td></td><td colspan="4">(In Thousands)</td></tr><tr><td>2015:</td><td></td><td></td><td></td><td></td></tr><tr><td>First Quarter</td><td>$2,920,090</td><td>$542,769</td><td>$302,929</td><td>$298,050</td></tr><tr><td>Second Quarter</td><td>$2,713,231</td><td>$377,383</td><td>$153,722</td><td>$148,843</td></tr><tr><td>Third Quarter</td><td>$3,371,406</td><td>($965,016)</td><td>($718,233)</td><td>($723,027)</td></tr><tr><td>Fourth Quarter</td><td>$2,508,523</td><td>($254,300)</td><td>$104,849</td><td>$99,573</td></tr><tr><td>2014:</td><td></td><td></td><td></td><td></td></tr><tr><td>First Quarter</td><td>$3,208,843</td><td>$739,877</td><td>$406,053</td><td>$401,174</td></tr><tr><td>Second Quarter</td><td>$2,996,650</td><td>$454,477</td><td>$194,281</td><td>$189,383</td></tr><tr><td>Third Quarter</td><td>$3,458,110</td><td>$492,859</td><td>$234,916</td><td>$230,037</td></tr><tr><td>Fourth Quarter</td><td>$2,831,318</td><td>$319,674</td><td>$125,006</td><td>$120,127</td></tr></table>



Earnings per Average Common Share

<table><tr><td rowspan="2"></td><td colspan="2">2015</td><td colspan="2">2014</td></tr><tr><td>Basic</td><td>Diluted</td><td>Basic</td><td>Diluted</td></tr><tr><td>First Quarter</td><td>$1.66</td><td>$1.65</td><td>$2.24</td><td>$2.24</td></tr><tr><td>Second Quarter</td><td>$0.83</td><td>$0.83</td><td>$1.06</td><td>$1.05</td></tr><tr><td>Third Quarter</td><td>($4.04)</td><td>($4.04)</td><td>$1.28</td><td>$1.27</td></tr><tr><td>Fourth Quarter</td><td>$0.56</td><td>$0.56</td><td>$0.67</td><td>$0.66</td></tr></table>

Third quarter 2015 results of operations includes $1,642 million ($1,062 million net-of-tax) of impairment and related charges to write down the carrying values of the FitzPatrick and Pilgrim plants and related assets to their fair values. Fourth quarter 2015 results of operations includes $396 million ($256 million net-of-tax) of impairment and related changes to write down the carrying values of the Palisades plant and related assets to their fair values. See Note 1 to the financial statements for further discussion of the charges. As a result of the Entergy Louisiana and Entergy Gulf States Louisiana business combination, results of operations for 2015 also include two items that occurred in October 2015: 1) a deferred tax asset and resulting net increase in tax basis of approximately $334 million and 2) a regulatory liability of $107 million ($66 million net-of-tax) as a result of customer credits to be realized by electric customers of Entergy Louisiana, consistent with the terms of an agreement with the LPSC. See Note 2 to the financial statements for further discussion of the business combination and customer credits. Results of operations for fourth quarter 2015 also include the sale in December 2015 of the 583 MW Rhode Island State Energy Center for a realized gain of $154 million ($100 million net-of-tax) on the sale and the $77 million ($47 million net-of-tax) write-off and related charges to recognize that a portion of the assets associated with Entergy Louisiana’s Waterford 3 replacement steam generator project is no longer probable of recovery. See Note 2 to the financial statements for further discussion of the Waterford 3 write-off.

Results of operations for third quarter 2014 include $113 million ($74 million net-of-tax) of charges related to Vermont Yankee, including the effects of an updated decommissioning cost study along with reassessment of 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 these charges. Results of operations for third quarter 2014 also include the $61 million ($40 million net-of-tax) write-off 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.



## Board of Directors
As of Dec. 31, 2015

## MAUREEN SCANNELL BATEMAN

Attorney, Former Executive Vice President and General Counsel,
State Street Corporation
New York, New York
An Entergy director since 2000. Age 72

## PATRICK J. CONDON

Retired Audit Partner,
Deloitte & Touche LLP
Frankfort, Illinois
Joined the Entergy Board in 2015.
Age 66

## LEO P. DENAULT

Chairman of the Board and Chief Executive Officer,
Entergy Corporation
New Orleans, Louisiana
Chairman and Chief Executive Officer since 2013. Age 56

## ADMIRAL KIRKLAND H. DONALD, USN (RET.)

Former President and Chief Executive Officer,
Systems Planning and Analysis, Inc.
Alexandria, Virginia
An Entergy director since 2013. Age 62

## GARY W. EDWARDS

Former Senior Executive Vice President,
Conoco Inc.
Houston, Texas
Lead director of Entergy. An Entergy director since 2005.
Age 74

## PHILIP L. FREDERICKSON

Former Executive Vice President, Planning, Strategy and Corporate Affairs,
ConocoPhillips
Horseshoe Bay, Texas
Joined the Entergy Board in 2015. Age 59

## ALEXIS M. HERMAN

Chair and Chief Executive Officer,
New Ventures, LLC
McLean, Virginia
An Entergy director since 2003. Age 68

## DONALD C. HINTZ

Former President,
Entergy Corporation and Entergy Services, Inc.
Punta Gorda, Florida
An Entergy director since 2004. Age 72

## STUART L. LEVENICK

Former Group President and Executive Office Member,
Caterpillar Inc.
Peoria, Illinois
An Entergy director since 2005. Age 62

## BLANCHE LAMBERT LINCOLN

Founder and Principal,
Lincoln Policy Group
Arlington, Virginia
An Entergy director since 2011. Age 55

## KAREN A. PUCKETT

President and Chief Executive Officer,
Harte Hanks, Inc.
Monroe, Louisiana
Joined the Entergy Board in 2015. Age 55

## W. J. "BILLY" TAUZIN

Owner,
Tauzin Strategic Networks
Washington, D.C.
An Entergy director since 2005. Age 72

## STEVEN V. WILKINSON

Retired Audit Partner,
Arthur Andersen LLP
Watersmeet, Michigan
An Entergy director since 2003. Age 74



## Executive Officers
As of Dec. 31, 2015

## LEO P. DENAULT

Chairman and Chief Executive Officer
Joined Entergy in 1999 as vice president of corporate development and strategic planning. Became chairman and chief executive officer in 2013, after serving as executive vice president and chief financial officer. Age 56

## THEODORE H. BUNTING, JR.

Group President, Utility Operations
Joined Entergy in 1983. Became group president,
utility operations in 2012, after serving as senior vice
president and chief accounting officer. Age 57

## WILLIAM M. MOHL

President, Entergy Wholesale Commodities
Joined Entergy in 2002. Became president of Entergy
Wholesale Commodities in 2013, after serving as
president and chief executive officer of Entergy Gulf
States Louisiana and Entergy Louisiana. Age 56

## ANDREW S. MARSH

Executive Vice President and Chief Financial Officer
Joined Entergy in 1998. Became executive vice
president and chief financial officer in 2013, after
serving as vice president of system planning. Age 44

## RODERICK K. WEST

Executive Vice President and Chief Administrative Officer
Joined Entergy in 1999. Became executive vice president and chief administrative officer in 2010, after serving as president and chief executive officer of Entergy New Orleans. Age 47

## MARCUS V. BROWN

Executive Vice President and General Counsel
Joined Entergy in 1995. Became executive vice president and general counsel in 2013, after serving as senior vice president and general counsel. Age 54

## PAUL D. HINNENKAMP

Senior Vice President and Chief Operating Officer
Joined Entergy in 2001. Became senior vice president and chief operating officer in 2015, after serving as senior vice president, capital project management and technology. Age 54

## ALYSON M. MOUNT

Senior Vice President and Chief Accounting Officer
Joined Entergy in 2002. Became senior vice president and chief accounting officer in 2012, after serving as vice president and corporate controller. Age 45

## DONALD W. VINCI

Senior Vice President, Human Resources and
Chief Diversity Officer
Joined Entergy in 1985. Became senior vice
president, human resources and chief diversity officer
in 2013, after serving as vice president, human capital
management. Age 57



## Investor Information

## Shareholder News

Entergy’s quarterly earnings results, dividend action and other news and information of investor interest may be obtained by calling Entergy’s investor relations information line at 1-888-ENTERGY (368-3749). In addition to hearing recorded announcements, you can request information to be sent via fax or mail. Visit our investor relations website at entergy.com/investor for earnings reports, financial releases, SEC filings and other investor information, including Entergy’s Corporate Governance Guidelines, Board Committee Charters for the Audit, Corporate Governance and Personnel Committees and Entergy’s Code of Conduct. You can also request and receive information via email. Printed copies of the above are also available without charge by calling 1-888-ENTERGY or writing to:

Entergy Corporation

Investor Relations

P.O. Box 61000

New Orleans, LA 70161

Investor Relations materials are also available on the Entergy Investor Relations mobile web app. The app provides a convenient way to access the company’s latest financial news and information, including financial releases, presentations and SEC filings, as well as the ETR stock quote. The mobile web app is available at enter.gy/ir.

## Institutional Investor Inquiries

Securities analysts and representatives of financial institutions may contact David Borde, vice president, investor relations, at 504-576-5668 or dborde@entergy.com.

## Shareholder Account Information

Wells Fargo Shareowner Services is Entergy’s transfer agent, registrar, dividend disbursing agent and dividend reinvestment and stock purchase plan agent. Shareholders of record with questions about lost certificates, lost or missing dividend checks, or notifications of change of address should contact:

Wells Fargo Shareowner Services

P.O. Box 64874

St. Paul, MN 55164-0874

Phone: 1-855-854-1360

Internet: www.shareholderonline.com

## Common Stock Information

The company’s common stock is listed on the New York and Chicago exchanges under the symbol “ETR.” The Entergy share price is reported daily in the financial press under “Entergy” in most listings of New York Stock Exchange securities. Entergy common stock is a component of the following indices: S&P 500, S&P Utilities Index, Philadelphia Utility Index and the NYSE Composite Index, among others. As of Jan. 29, 2016, there were 179,071,731 shares of Entergy common stock outstanding. Shareholders of record totaled 28,602, and approximately 138,431 investors held Entergy stock in “street name” through a broker.

## Certifications

In May 2015, Entergy’s chief executive officer certified to the New York Stock Exchange that he was not aware of any violation of the NYSE corporate governance listing standards. Also, Entergy filed certifications regarding the quality of the company’s public disclosure, required by Section 302 of the Sarbanes-Oxley Act of 2002, as exhibits to our Annual Report on Form 10-K for the fiscal year ended Dec. 31, 2015.

## Dividend Payments

All of Entergy’s 2015 distributions were taxable as dividend distributions. The board of directors declares dividends quarterly and sets the record and payment dates. Subject to board discretion, those dates for 2016 are:

<table><tr><td>Declaration Date</td><td>Record Date</td><td>Payment Date</td></tr><tr><td>January 29</td><td>February 11</td><td>March 1</td></tr><tr><td>April 6</td><td>May 12</td><td>June 1</td></tr><tr><td>July 29</td><td>August 11</td><td>September 1</td></tr><tr><td>October 28</td><td>November 10</td><td>December 1</td></tr></table>



## Investor Information

Quarterly Dividend Payments (in cents-per-share):

<table><tr><td>Quarter</td><td>2016</td><td>2015</td><td>2014</td><td>2013</td><td>2012</td></tr><tr><td>1</td><td>85</td><td>83</td><td>83</td><td>83</td><td>83</td></tr><tr><td>2</td><td></td><td>83</td><td>83</td><td>83</td><td>83</td></tr><tr><td>3</td><td></td><td>83</td><td>83</td><td>83</td><td>83</td></tr><tr><td>4</td><td></td><td>85</td><td>83</td><td>83</td><td>83</td></tr></table>

## Dividend Reinvestment/Stock Purchase

Entergy offers an automatic Dividend Reinvestment and Stock Purchase Plan administered by Wells Fargo Shareowner Services. The plan is designed to provide Entergy shareholders and other investors with a convenient and economical method to purchase shares of the company's common stock. The plan also accommodates payments of up to $10,000 per month for the purchase of Entergy common shares. First time investors may make an initial minimum purchase of $250. Contact Wells Fargo Shareowner Services by telephone or internet for information and an enrollment form.

## Direct Registration System

Entergy has elected to participate in a Direct Registration System that provides investors with an alternative method for holding shares. DRS will permit investors to move shares between the company’s records and the broker/dealer of their choice.

## Entergy Common Stock Prices

The high and low trading prices for each quarterly period in 2015 and 2014 were as follows (in dollars):

<table><tr><td rowspan="2">Quarter</td><td colspan="2">2015</td><td colspan="2">2014</td></tr><tr><td>High</td><td>Low</td><td>High</td><td>Low</td></tr><tr><td>1</td><td>90.33</td><td>73.88</td><td>67.02</td><td>60.40</td></tr><tr><td>2</td><td>79.84</td><td>69.06</td><td>82.30</td><td>66.41</td></tr><tr><td>3</td><td>74.09</td><td>61.27</td><td>82.48</td><td>70.70</td></tr><tr><td>4</td><td>70.67</td><td>63.90</td><td>92.02</td><td>76.51</td></tr></table>



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Entergy Corporation
Post Office Box 61000
New Orleans, LA 70161
entergy.com