Entergy Corporation (ETR, NYSE)
Industry: Utilities - Regulated Electric
Annual report, fiscal year 2014


ENERGY CORPORATION AND SUBSIDIARIES

2014 ANNUAL REPORT



## Entergy Corporation and Subsidiaries 2014

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, making it one of the nation’s leading nuclear generators. Entergy delivers electricity to 2.8 million utility customers in Arkansas, Louisiana, Mississippi and Texas. Entergy has annual revenues of more than $12 billion and approximately 13,000 employees.

Again this year, in addition to our Annual Report to Shareholders, Entergy is producing an online-only Integrated Report for 2014 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 2014 Integrated Report website. It presents an interactive version of our 2014 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
6 Forward-Looking Information and Regulation G Compliance
9 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 Public Accounting Firm
65 Internal Control Over Financial Reporting
66 Consolidated Income Statements
67 Consolidated Statements of Comprehensive Income
68 Consolidated Statements of Cash Flows
70 Consolidated Balance Sheets
72 Consolidated Statements of Changes in Equity
73 Notes to Financial Statements
187 Directors and Executive Officers
188 Investor Information



## Letter To Our Stakeholders:

The theme of this year’s integrated report is “Powering a New Day.” When I talk to our stakeholders, most don’t understand just how we do that. In fact, during many of these conversations, people are amazed at the true meaning of our vision statement: We Power Life. While they are familiar with us as the power and gas company, they don’t realize how much more we do. We power job creation and economic growth in our communities. We promote and help to develop a skilled and educated workforce, not only for our company, but also for the communities we serve. And we take an active role in cleaner air and water and regional resiliency. On each of those dimensions, we delivered strong results in 2014 and took steps to enhance our long-term performance.

You probably know we provide electricity and natural gas, but think what that means. Whether you are one of our 2.8 million utility customers in Arkansas, Louisiana, Mississippi and Texas, or you live in a community served by one of our Entergy Wholesale Commodities power plants, we provide the power that lets you talk on your smartphone or watch your TV, and we deliver natural gas to heat homes and run appliances. We power homes, businesses, neighborhoods, schools and hospitals. We power small towns and big cities.
Our customers expect power and natural gas to be available reliably and on demand. That means we must continually invest in and modernize our fleet, strengthen our reliability and comply with new regulatory requirements. In 2014, we delivered strong operational performance in both our utility and EWC businesses. We also took steps to strengthen our ability to deliver reliable power and natural gas over the long term.

In our utility business, we developed new long-range supply plans, and we are engaged with customers, communities and regulators on the details of those plans. In 2014, we placed Ninemile 6 in service ahead of schedule and under budget, and we announced an agreement to acquire Union Power Station. Both are clean, fuel-efficient natural gas-fired resources. We also announced several transmission projects in 2014 and early 2015 in Louisiana and Texas, including the Lake Charles transmission project. One of our largest projects ever, the Lake Charles project will move power efficiently and reliably into southern Louisiana, a region with the highest projected job growth in the state. We also developed an accelerated gas pipe replacement program to replace about 100 miles of pipe in Baton Rouge, La., over the next 10 years. In 2014, we restored power quickly and safely following major storms in Arkansas and Mississippi, a critical component of reliability. For the second year in a row, Entergy utilities were the top five performers in proactive outage communications, according to J.D. Power. And all our utilities improved by several points in the annual J.D. Power residential customer satisfaction survey in 2014.

In our EWC business, strong operational performance across our nuclear fleet in 2014 resulted in a 91 percent capacity factor, up from 89 percent in 2013. That means we were able to provide more power at a competitive cost to wholesale power markets in the Northeast and Midwest. We are engaged with key stakeholders to advance the license renewal process for Indian Point Energy Center, a nuclear plant that provides safe, low-cost and reliable power with on-site fuel

“People are amazed at the true meaning of our vision statement: We Power Life.”



while benefiting the environment. We expect license renewal to be a multi-year process during which we will continue to operate Indian Point safely, securely and reliably.

Workforce safety is critical to providing reliable power, and our longstanding goal is to achieve an accident-free work environment. After delivering a record year for employee safety in 2013, our safety performance fell short in 2014. When we recognized the downward performance trend during the year, we instituted hazard recognition programs and reinforced the use of human performance tools. By year-end, accident rates dropped significantly. We’ll continue these and other efforts because workforce safety is a fundamental driver of our business performance and always a top priority at Entergy.

We also power life by helping our local economies to grow, creating thousands of new jobs in the process. Our utilities provide power at low rates – about 20 percent below the national average across all classes – and that’s an important consideration for companies selecting a new location for their operations. Continuing to manage costs is a priority for us, because that helps keep rates low. We completed our first year of operation in MISO, the Midcontinent Independent System Operator, Inc., and the MISO-driven customer savings are proving to be greater than we projected. We also work proactively with state and local leaders to attract new industries to the regions served by our utilities. We help identify potential sites, assist in permitting and provide online tools to streamline the development process. We do all this because economic growth builds our communities and drives sales growth for our utilities, which in turn helps us maintain rate stability, fund investments in our fleet and earn our authorized returns on our investments. We have been very successful in promoting economic development, and that success continued in 2014. We achieved weather-adjusted retail sales growth of 2.3 percent, driven primarily by industrial sales growth of 5 percent. We believe the diverse industrial base in the Gulf South, including chemicals, primary metals, wood products and petrochemicals, will deliver significant utility sales growth through 2017.

We always power life with an eye on the future. We engage with our regulators and stakeholders to ensure reliable and affordable power and natural gas will be readily available for years to come. In our utility business, we engage with regulators to secure rate mechanisms, such as formula rate plans and specific recovery riders, which enable us to recover costs faster and more efficiently. That, in turn, helps us maintain investor confidence and access capital markets to fund investments to modernize our fleet and enhance our reliability. In 2014, the Mississippi Public Service Commission authorized a new formula rate plan as well as solar projects and economic development incentives, which meet customer and community needs while strengthening Entergy Mississippi’s financial position. The Louisiana Public Service Commission approved rider recovery for Entergy Gulf States Louisiana’s accelerated gas pipe replacement program. Entergy Gulf States Louisiana and Entergy Louisiana began the first year of their latest three-year formula rate plan, which includes a mechanism to bring investments like Ninemile 6 into rates upon completion. Entergy New Orleans promptly began rider recovery for costs associated with Ninemile 6. Entergy Texas completed a rate case and became the first utility in Texas to use a distribution rider to improve its financial position and flexibility. And the Arkansas Public Service Commission approved a modest increase in the Entergy Arkansas rate case rehearing.

In our wholesale generation business, we are engaged with regulators and stakeholders to address long-term market design issues in the Northeast that have the potential to produce greater price volatility, and in the extreme, a less reliable system. These issues have implications for the continued
Entergy delivered strong performance in 2014 and created value for our four stakeholder groups.

## Owners

We delivered total shareholder return of 44.8 percent, which ranked in the top quartile of our peer group.

## Customers

We provided reliable power at rates about 20 percent below the national average across all classes, and we took steps to modernize our fleet to keep rates low.

## Employees

We invested in our organization to engage and empower our employees. We implemented plans and programs to improve employee safety, which fell short of our goals in 2014.

## Communities

We invested $16 million in local education, poverty solutions and environmental programs, focus areas that align with and support our business objectives.



operation of critical generating resources in the region. At the end of 2014, Vermont Yankee employees removed Vermont Yankee Nuclear Power Station from the grid after 42 years of safe, secure and reliable operations. We retired the unit for economic reasons due in part to the market design flaws. We are advocates for market structures that fairly compensate existing generators for benefits they provide in terms of system reliability and economic and environmental sustainability.

And we work to prepare for whatever the future may bring. We proactively manage all types of risk related to our business. From short-term fluctuations in wholesale power prices to long-term risks posed by climate change and poverty, we have strategies in place to help mitigate risks that could adversely impact Entergy and our stakeholders. We hedge forward generation from our EWC fleet to mitigate wholesale power price volatility. In 2014, we captured significant upside through our hedging strategies and the close coordination of our commercial teams and plant operation teams, which ensured critical units were available when needed. We invest in clean generation like Ninemile 6 and the planned Union Power Station acquisition to help manage the risk of increased environmental regulation. We invest in wetlands restoration to mitigate risks associated with extreme weather events. In 2014, Entergy announced a $500,000 grant to The Nature Conservancy to restore forests and wetlands in Arkansas, Louisiana, Mississippi and Texas. We also share our analyses of climate change risks and potential responses with our utility customers to reduce the impact of extreme weather events on their businesses and ours. And we invest in poverty solutions to address the financial risk posed by the high number of people living in poverty in the four states served by Entergy utilities. Our Super Tax Day program, which was named the 2014 Best Economic Empowerment program by the U.S. Chamber of Commerce Foundation, helps low-income customers apply for the federal Earned Income Tax Credit and has resulted in $100 million returned to 58,000 Entergy customers since 2009.

We power life for our communities through our corporate giving because our sustained growth depends on healthy, vibrant communities. In addition to poverty solutions and environmental programs, our corporate giving is focused on strengthening education. It’s not just that every child deserves a good education. Communities need strong public education systems to attract economic growth and businesses like Entergy need an educated workforce to grow. Entergy has invested nearly $41 million in education since 2005. In 2014, we provided grants to community colleges in Arkansas and Louisiana to help build a skilled workforce to fill the jobs created by industrial growth in the region. And we worked with Posse Scholars in New Orleans to help prepare selected high school students for college. Within Entergy, our talent management strategies support the development and education of our employees to ensure they have the ability to meet the goals they have for themselves and their families. And we have targeted strategies to support key demographic groups, such as actively participating in events to recruit men and women who have served our country in the military.

## 2014 Key Accomplishments

## Utility

• We placed Ninemile 6 in service ahead of schedule and under budget.

• We announced an agreement to acquire Union Power Station at an attractive price.

• We completed our first year of operation in MISO and expect customers to realize more MISO-driven savings than originally expected.

• All our utilities improved by several points in the annual J.D. Power residential customer satisfaction survey.

## EWC

• We achieved a 91 percent capacity factor at our nuclear fleet, up from 89 percent in 2013.

• We captured significant value for our owners through our hedging strategies when Northeast power prices spiked in early 2014.

• We successfully transitioned Vermont Yankee to a SAFSTOR organization after 42 years of safe, secure and reliable operations.

• We received a favorable ruling from a New York State appellate court related to license renewal for Indian Point.



While we power life for Entergy employees in many ways, our employees power life for our company and our stakeholders. Entergy employees – the most dedicated, conscientious group of people I know – work diligently every day to keep the power on. And they do such a good job that most people rarely give it a thought. By ensuring the power is on every day and natural gas is delivered continuously, our employees drive our success as a company. In 2014, we continued to transform our organization because we need engaged, empowered employees to achieve our goals and compete in a very dynamic industry. We largely completed a companywide restructuring to reduce costs and refocus resources in areas that support utility growth and the long-term value of our EWC fleet. We identified specific leadership and employee practices in 2014 that are hallmarks of healthy, successful organizations and we are instilling these practices throughout our company. Organization transformation takes time and effort, but we are confident it will strengthen our ability to provide sustainable value to our stakeholders over the long term.

We power life for our owners by delivering attractive returns on the investments they make in our business. We believe we must deliver industry-leading returns over the long term in order to attract the capital we need to invest in and grow our business. Short-term fluctuations in power prices affect our performance, but over the long term, consistent execution of our business strategies drives our ability to generate competitive returns to our owners. In 2014, Entergy delivered top-quartile total shareholder return, based on stock price performance and dividends, of 44.8 percent compared to a return of 28.9 percent for the Philadelphia Utility Index. We benefitted from both favorable market conditions and strong execution of our business strategies.

We see significant capacity for stakeholder value creation in powering life through our existing businesses. Our utilities are located in the Gulf South, a region experiencing strong industrial development, and our EWC assets play a critical role in the regions they serve. We believe we can generate top-quartile returns for our owners by pursuing opportunities that advance our business strategies: grow the utility business and preserve optionality and manage risk at EWC. We continually look for ways to further our strategies, either through organic growth or transactions that offer attractive opportunities within our existing businesses. We set a standard that not only should transactions complement our strategies; they must also be executable and not distract us from the significant opportunities before us today. In addition to reinvesting in our utility and EWC businesses, our priority is to provide a dividend payout that is comparable to our industry peers. In 2014, our board established a target dividend payout range of 65 percent to 75 percent of earnings per share from the utility, parent and other segments. At the same time, we are committed to maintaining investment-grade ratings at our utilities and at Entergy Corporation. A strong financial and credit position gives us the financial flexibility to respond opportunistically to changing market conditions in ways that create sustainable value for our stakeholders.

“We see significant capacity for stakeholder value creation in powering life through our existing businesses.”



We power life. It’s an awesome responsibility. It energizes me every day. And when I talk to friends and neighbors, community leaders and investors, and employees throughout the company, it seems to energize them as well. When people learn more about Entergy – from me or another stakeholder – then they are in a better position to engage with us, support our strategies and help drive our success. So talking about Entergy and how we power life helps us succeed as an organization, and quite honestly, it makes me feel great about our company, our employees and all we do to create value for our stakeholders.

I want to express my gratitude and thanks to our approximately 13,000 employees for the strong performance they delivered in 2014. I remain in awe of their spirit, determination and commitment to a job well done. I also want to thank our board of directors for their guidance, especially Stew Myers, who will retire from our board in 2015. Stew literally wrote the book, the finance textbook we all used in graduate school. We are all better for his time on the board. His knowledge and insights informed our plans and strategies and will help create value for our stakeholders for years to come. We also recently welcomed two new board members, Patrick Condon and Karen Puckett, who both joined the board in March. Pat’s expertise in accounting and auditing and Karen’s executive leadership experience at a company undergoing transformational change will enrich the board and provide valuable guidance for management as we pursue opportunities and challenges in the coming years. Under the direction of our board and the Entergy leadership team, our company continues to execute, anticipate and adapt in very dynamic market conditions. With their expertise and dedication, I believe the future of our company is in excellent hands.

We power life in many ways because it makes good business sense for our company and creates value for our stakeholders. But it’s about much more than dollars and cents. We power life in many ways because it’s the right thing to do and our employees deserve to work at a company that holds that ideal. Most importantly, we power life because the customers we serve are our families, friends and neighbors, and the communities we serve are our homes. It is personal for us – it defines the spirit and character of our company and the men and women who work here. That is the true meaning of We Power Life, and yes, it is amazing.



Leo P. Denault
Chairman of the Board and Chief Executive Officer
March 20, 2015

“…it defines the spirit and character of our company and the men and women who work here. That’s the true meaning of We Power Life…”






## 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, 2014; (b) those factors discussed or incorporated by reference in Management’s Financial Discussion and Analysis contained in the Form 10-K for the year ended Dec. 31, 2014; and (c) the following factors (in addition to others described elsewhere in this combined 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’s participation in the System Agreement, which occurred in December 2013, the termination of Entergy Mississippi’s participation in the System Agreement in November 2015, the termination of Entergy Texas’s, Entergy Gulf States Louisiana’s, and Entergy Louisiana’s participation in the System Agreement after expiration of the proposed 60-month notice period or such other period as approved by the FERC;

- 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 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 or potential 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;

- 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;

- 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, including requirements for reduced emissions of sulfur dioxide, nitrogen oxide, greenhouse gases, mercury, 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 disposal fees charged by the U.S. government 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, 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;

- the potential effects of threatened or actual terrorism, cyber-attacks or data security breaches, including increased security costs, 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 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 or cost to decommission nuclear plant sites;

- the implementation of the shutdown of Vermont Yankee and the related decommissioning of 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 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 measure is below.

<table><tr><td colspan="3">GAAP to Non-GAAP Reconciliation</td></tr><tr><td>Earnings Per Share</td><td>2014</td><td>2013</td></tr><tr><td>As-Reported</td><td>$ 5.22</td><td>$ 3.99</td></tr><tr><td>Less Special Items:</td><td></td><td></td></tr><tr><td>Transmission business spin-merge expenses</td><td>-</td><td>$ (0.02)</td></tr><tr><td>HCM implementation expenses</td><td>$ (0.05)</td><td>$ (0.20)</td></tr><tr><td>Decision to close Vermont Yankee</td><td>$ (0.56)</td><td>$ (1.15)</td></tr><tr><td>Total Special Items</td><td>$ (0.61)</td><td>$ (1.37)</td></tr><tr><td>Operational</td><td>$ 5.83</td><td>$ 5.36</td></tr></table>



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

<table><tr><td></td><td>2014</td><td>2013</td><td>2012</td><td>2011</td><td>2010</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>$ 12,494,921</td><td>$ 11,390,947</td><td>$ 10,302,079</td><td>$ 11,229,073</td><td>$ 11,487,577</td></tr><tr><td>Income from continuing operations</td><td>$ 960,257</td><td>$ 730,572</td><td>$ 868,363</td><td>$ 1,367,372</td><td>$ 1,270,305</td></tr><tr><td>Earnings per share from continuing operations:</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Basic</td><td>$ 5.24</td><td>$ 3.99</td><td>$ 4.77</td><td>$ 7.59</td><td>$ 6.72</td></tr><tr><td>Diluted</td><td>$ 5.22</td><td>$ 3.99</td><td>$ 4.76</td><td>$ 7.55</td><td>$ 6.66</td></tr><tr><td>Dividends declared per share</td><td>$ 3.32</td><td>$ 3.32</td><td>$ 3.32</td><td>$ 3.32</td><td>$ 3,24</td></tr><tr><td>Return on common equity</td><td>9.58%</td><td>7.56%</td><td>9.33%</td><td>15.43%</td><td>14.61%</td></tr><tr><td>Book value per share, year-end</td><td>$ 55.83</td><td>$ 54.00</td><td>$ 51.72</td><td>$ 50.81</td><td>$ 47.53</td></tr><tr><td>Total assets</td><td>$ 46,527,854</td><td>$ 43,406,446</td><td>$ 43,202,502</td><td>$ 40,701,699</td><td>$ 38,685,276</td></tr><tr><td>Long-term obligations(a)</td><td>$ 12,740,579</td><td>$ 12,382,127</td><td>$ 12,141,370</td><td>$ 10,268,645</td><td>$ 11,575,973</td></tr><tr><td>Utility Electric Operating Revenues:</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>(In Millions)</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Residential</td><td>$ 3,555</td><td>$ 3,396</td><td>$ 3,022</td><td>$ 3,369</td><td>$ 3,375</td></tr><tr><td>Commercial</td><td>2,553</td><td>2,415</td><td>2,174</td><td>2,333</td><td>2,317</td></tr><tr><td>Industrial</td><td>2,623</td><td>2,405</td><td>2,034</td><td>2,307</td><td>2,207</td></tr><tr><td>Governmental</td><td>227</td><td>218</td><td>198</td><td>205</td><td>212</td></tr><tr><td>Total retail</td><td>8,958</td><td>8,434</td><td>7,428</td><td>8,214</td><td>8,111</td></tr><tr><td>Sales for resale</td><td>330</td><td>210</td><td>179</td><td>216</td><td>389</td></tr><tr><td>Other</td><td>304</td><td>298</td><td>264</td><td>244</td><td>241</td></tr><tr><td>Total</td><td>$ 9,592</td><td>$ 8,942</td><td>$ 7,871</td><td>$ 8,674</td><td>$ 8,741</td></tr><tr><td>Utility Billed Electric Energy Sales:</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>(GWh)</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Residential</td><td>35,932</td><td>35,169</td><td>34,664</td><td>36,684</td><td>37,465</td></tr><tr><td>Commercial</td><td>28,827</td><td>28,547</td><td>28,724</td><td>28,720</td><td>28,831</td></tr><tr><td>Industrial</td><td>43,723</td><td>41,653</td><td>41,181</td><td>40,810</td><td>38,751</td></tr><tr><td>Governmental</td><td>2,428</td><td>2,412</td><td>2,435</td><td>2,474</td><td>2,463</td></tr><tr><td>Total retail</td><td>110,910</td><td>107,781</td><td>107,004</td><td>108,688</td><td>107,510</td></tr><tr><td>Sales for resale</td><td>9,462</td><td>3,020</td><td>3,200</td><td>4,111</td><td>4,372</td></tr><tr><td>Total</td><td>120,372</td><td>110,801</td><td>110,204</td><td>112,799</td><td>111,882</td></tr><tr><td>Entergy Wholesale Commodities:</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Operating revenues</td><td>$ 2,719</td><td>$ 2,313</td><td>$ 2,326</td><td>$ 2,414</td><td>$ 2,566</td></tr><tr><td>Billed electric energy sales (Gwh)</td><td>44,424</td><td>45,127</td><td>46,178</td><td>43,497</td><td>42,934</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



<table><tr><td></td><td>2009</td><td>2010</td><td>2011</td><td>2012</td><td>2013</td><td>2014</td></tr><tr><td>Entergy</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Corporation</td><td>$100.00</td><td>$ 90.27</td><td>$ 97.75</td><td>$ 89.57</td><td>$ 93.47</td><td>$135.30</td></tr><tr><td>S&amp;P 500</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Index</td><td>$100.00</td><td>$115.06</td><td>$117.48</td><td>$136.27</td><td>$180.39</td><td>$205.07</td></tr><tr><td>Philadelphia</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Utility Index</td><td>$100.00</td><td>$105.70</td><td>$126.04</td><td>$125.32</td><td>$139.08</td><td>$179.33</td></tr></table>

Assumes $100 invested at the closing price on Dec. 31, 2009, in Entergy Corporation common stock, the S&P 500 Index, and the Philadelphia Utility 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 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.</td></tr><tr><td>Entergy Texas</td><td>Entergy Texas, Inc., a company formally created as part of the jurisdictional separation of Entergy Gulf States, Inc. The term is also used to refer to the Texas jurisdictional business of Entergy Gulf States, Inc., as the context requires.</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><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></table>



## DEFINITIONS (Continued)

<table><tr><td>Abbreviation or Acronym</td><td>Term</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 kilowatt(s)</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 Gulf States Louisiana (57.5%) and Entergy Texas (42.5%), and 10.9% of which is owned by an Entergy subsidiary in the Entergy Wholesale Commodities business segment</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>OASIS</td><td>Open Access Same Time Information Systems</td></tr><tr><td>Palisades</td><td>Palisades Power Plant (nuclear), owned by an Entergy subsidiary in the Entergy Wholesale Commodities business segment</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 Gulf States Louisiana, L.L.C., Entergy Louisiana, LLC, Entergy Mississippi, Inc., Entergy New Orleans, Inc., Entergy Texas, Inc., and System Energy Resources, Inc.</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 Gulf States 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></table>



## DEFINITIONS (Concluded)

<table><tr><td>Abbreviation or Acronym</td><td>Term</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.</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>U.K.</td><td>United Kingdom of Great Britain and Northern Ireland</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, 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>



# ENTERGY CORPORATION AND SUBSIDIARIES

## MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS

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

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

- 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. In August 2013, Entergy announced plans to close and decommission Vermont Yankee. On December 29, 2014 the Vermont Yankee plant ceased power production and has entered its decommissioning phase. 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</td><td colspan="3">% of Total Assets</td></tr><tr><td>2014</td><td>2013</td><td>2012</td><td>2014</td><td>2013</td><td>2012</td><td>2014</td><td>2013</td><td>2022</td></tr><tr><td>Utility</td><td>78</td><td>80</td><td>78</td><td>88</td><td>116</td><td>110</td><td>82</td><td>82</td><td>82</td></tr><tr><td>Entergy Wholesale Commodities</td><td>22</td><td>20</td><td>22</td><td>31</td><td>6</td><td>5</td><td>22</td><td>22</td><td>22</td></tr><tr><td>Parent &amp; Other</td><td>—</td><td>—</td><td>—</td><td>(19)</td><td>(22)</td><td>(15)</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.



## Results of Operations

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

As discussed in more detail in Note 1 to the financial statements, results of operations for 2013 include $322 million ($202 million after-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 after-tax), including approximately $85 million ($55 million after-tax) for Utility and $25 million ($15 million after-tax) for Entergy Wholesale Commodities, recorded in connection with a strategic imperative intended to optimize the organization through a process known as human capital management. In December 2013, Entergy deferred for future collection approximately $45 million ($30 million after-tax) of these costs in the Arkansas and Louisiana



jurisdictions at the Utility, as approved by the APSC and the LPSC, respectively. See “Human Capital Management Strategic Imperative” below for further discussion.

Net Revenue

Utility

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

<table><tr><td>Amount (In Millions)</td></tr><tr><td>2013 net revenue</td></tr><tr><td>Retail electric price</td></tr><tr><td>Asset retirement obligation</td></tr><tr><td>Volume/weather</td></tr><tr><td>MISO deferral</td></tr><tr><td>Net wholesale revenue</td></tr><tr><td>Other</td></tr><tr><td>2014 net revenue</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>264</td></tr><tr><td>Mark-to-market</td><td>129</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;

- the effect of lower forward power prices on electricity derivative instruments that are not designated as hedges, including additional financial power sales conducted in the fourth quarter 2014 to lock in margins on some in-the-money purchased call options. These additional sales did not qualify for hedge accounting treatment, and decreases in forward prices after those sales were made accounted for the majority of the positive mark-to-market variance. In fourth quarter 2013, Entergy Wholesale Commodities also entered into similar transactions, but the price movements after the forward sales were in the opposite direction and resulted in negative mark-to-market activity in 2013. When these positions settled in the first quarter 2014, the turnaround of the negative 2013 mark also contributed to the positive 2014 mark-to-market variance. See Note 16 to the financial statements for discussion of derivative instruments; 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 realized price 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 realized 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>

## 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 New York and New England power regions, which is where four of the five operating Entergy Wholesale Commodities nuclear power plants are located. A sixth plant, Vermont Yankee, ceased operations in December 2014. The Entergy Wholesale Commodities nuclear business experienced an annual realized price per MWh of $60.35 in 2014, $50.15 in 2013, and $50.29 in 2012. The increase in realized price in 2014 is primarily attributable to a significant increase in first quarter 2014 prices due to cold winter weather and northeastern U.S. gas pipeline infrastructure limitations. Prior to 2009 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 2015 for an expected average contracted energy price of $48 per MWh based on market prices at December 31, 2014. In addition, Entergy Wholesale Commodities has sold forward 74% of its planned nuclear energy output for 2016 for an expected average contracted energy price of $49 per MWh based on market prices at December 31, 2014. The market price trend presents a challenging economic situation for the Entergy Wholesale Commodities plants. The challenge is greater for some of these plants based on a variety of factors such as their market for both energy and capacity, their size, their contracted positions, and the amount of investment required to continue to operate and maintain the safety and integrity of the plants, including the estimated asset retirement costs. If, in the future, economic conditions or regulatory activity no longer support the continued operation or recovery of the costs of a plant it could adversely affect Entergy’s results of operations through loss of revenue, impairment charges, increased depreciation rates, transitional costs, or accelerated decommissioning costs.

On August 27, 2013, Entergy announced its plan to close and decommission Vermont Yankee. This decision was approved by the Board in August 2013. The decision to shut down the plant was primarily due to sustained low natural gas and 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 operated. On December 29, 2014 the Vermont Yankee plant ceased power production. See Note 1 to the financial statements for discussion of impairment of long-lived assets.

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



Commodities Authorizations to Operate Its Nuclear Power Plants” regarding Entergy Wholesale Commodities nuclear plant operating license and related activity.

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

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

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

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

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



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

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

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

## Parent & Other

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

## 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 (1) IRS settlements as discussed further in Note 3 to the financial statements; and (2) a tax benefit associated with the now-terminated plan to spin off and merge the Utility’s transmission business, because certain associated costs became deductible with the termination of the transaction.



## 2013 Compared to 2012

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

<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>2012 Consolidated Net Income (Loss)</td><td>$960,322</td><td>$40,427</td><td>($132,386)</td><td>$868,363</td></tr><tr><td>Net revenue (operating revenue less fuel expense, purchased power, and other regulatory charges/credits)</td><td>555,233</td><td>(51,509)</td><td>7,136</td><td>510,860</td></tr><tr><td>Other operation and maintenance</td><td>184,374</td><td>90,222</td><td>11,946</td><td>286,542</td></tr><tr><td>Asset write-off, impairments, and related charges</td><td>9,411</td><td>(26,188)</td><td>2,790</td><td>(13,987)</td></tr><tr><td>Taxes other than income taxes</td><td>37,547</td><td>5,380</td><td>125</td><td>43,052</td></tr><tr><td>Depreciation and amortization</td><td>76,850</td><td>39,824</td><td>(215)</td><td>116,459</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>6,378</td><td>29,624</td><td>2,268</td><td>38,270</td></tr><tr><td>Interest expense</td><td>32,688</td><td>(1,577)</td><td>3,642</td><td>34,753</td></tr><tr><td>Other expenses</td><td>18,271</td><td>50,274</td><td>—</td><td>68,545</td></tr><tr><td>Income taxes</td><td>316,577</td><td>(138,800)</td><td>17,349</td><td>195,126</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></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.

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

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



## Net Revenue

## Utility

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

<table><tr><td></td><td>Amount (In Millions)</td></tr><tr><td>2012 net revenue</td><td>$4,969</td></tr><tr><td>Retail electric price</td><td>236</td></tr><tr><td>Louisiana Act 55 financing savings obligation</td><td>165</td></tr><tr><td>Grand Gulf recovery</td><td>75</td></tr><tr><td>Volume/weather</td><td>40</td></tr><tr><td>Fuel recovery</td><td>35</td></tr><tr><td>MISO deferral</td><td>12</td></tr><tr><td>Asset retirement obligation</td><td>(23)</td></tr><tr><td>Other</td><td>15</td></tr><tr><td>2013 net revenue</td><td>$5,524</td></tr></table>

The retail electric price variance is primarily due to:

- a formula rate plan increase at Entergy Louisiana, effective January 2013, which includes an increase relating to the Waterford 3 steam generator replacement project, which was placed in service in December 2012. The net income effect of the formula rate plan increase is limited to a portion representing an allowed return on equity with the remainder offset by costs included in other operation and maintenance expenses, depreciation expenses, and taxes other than income taxes;

- the recovery of Hinds plant costs through the power management rider at Entergy Mississippi, as approved by the MPSC, effective with the first billing cycle of 2013. The net income effect of the Hinds plant cost recovery is limited to a portion representing an allowed return on equity on the net plant investment with the remainder offset by the Hinds plant costs in other operation and maintenance expenses, depreciation expenses, and taxes other than income taxes;

- an increase in the capacity acquisition rider at Entergy Arkansas, as approved by the APSC, effective with the first billing cycle of December 2012, relating to the Hot Spring plant acquisition. The net income effect of the Hot Spring plant cost recovery is limited to a portion representing an allowed return on equity on the net plant investment with the remainder offset by the Hot Spring plant costs in other operation and maintenance expenses, depreciation expenses, and taxes other than income taxes;

- increases in the energy efficiency rider, as approved by the APSC, effective July 2013 and July 2012. Energy efficiency revenues are offset by costs included in other operation and maintenance expenses and have minimal effect on net income;

- an annual base rate increase at Entergy Texas, effective July 2012, as a result of the PUCT’s order that was issued in September 2012 in the November 2011 rate case; and

• a formula rate plan increase at Entergy Mississippi, effective September 2013.

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

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



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

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

The fuel recovery variance is primarily due to:

• the deferral of increased capacity costs that will be recovered through fuel adjustment clauses;

• the expiration of the Evangeline gas contract on January 1, 2013; and

- an adjustment to deferred fuel costs recorded in the third quarter 2012 in accordance with a rate order from the PUCT issued in September 2012. See Note 2 to the financial statements for further discussion of this PUCT order issued in Entergy Texas’s 2011 rate case.

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

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

## Entergy Wholesale Commodities

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

<table><tr><td></td><td>Amount (In Millions)</td></tr><tr><td>2012 net revenue</td><td>$1,854</td></tr><tr><td>Mark-to-market</td><td>(58)</td></tr><tr><td>Nuclear volume</td><td>(24)</td></tr><tr><td>Nuclear fuel expenses</td><td>(20)</td></tr><tr><td>Nuclear realized price changes</td><td>58</td></tr><tr><td>Other</td><td>(8)</td></tr><tr><td>2013 net revenue</td><td>$1,802</td></tr></table>

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

- the effect of rising forward power prices on electricity derivative instruments that are not designated as hedges, including additional financial power sales conducted in the fourth quarter 2013 to offset the planned exercise of in-the-money protective call options and to lock in margins. These additional sales did not qualify for hedge accounting treatment, and increases in forward prices after those sales were made accounted for the majority of the negative mark-to-market variance. The underlying transactions resulted in earnings in first quarter 2014 as these positions settled. See Note 16 to the financial statements for discussion of derivative instruments;

- the decrease in net revenue compared to prior year resulting from the exercise of resupply options 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; and



- higher nuclear fuel expenses primarily resulting from the effect of the write-down in March 2012 of the carrying value of Vermont Yankee’s nuclear fuel, which resulted in a lower level of nuclear fuel amortization in 2012, and the subsequent purchase of additional nuclear fuel in early-2013.

These decreases were partially offset by higher capacity prices.

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

<table><tr><td></td><td>2013</td><td>2012</td></tr><tr><td>Owned capacity (MW) (a)</td><td>6,068</td><td>6,612</td></tr><tr><td>GWh billed</td><td>45,127</td><td>46,178</td></tr><tr><td>Average realized price per MWh</td><td>$50.86</td><td>$50.02</td></tr><tr><td>Entergy Wholesale Commodities Nuclear Fleet</td><td></td><td></td></tr><tr><td>Capacity factor</td><td>89%</td><td>89%</td></tr><tr><td>GWh billed</td><td>40,167</td><td>41,042</td></tr><tr><td>Average realized revenue per MWh</td><td>$50.15</td><td>$50.29</td></tr><tr><td>Refueling Outage Days:</td><td></td><td></td></tr><tr><td>FitzPatrick</td><td>—</td><td>34</td></tr><tr><td>Indian Point 2</td><td>—</td><td>28</td></tr><tr><td>Indian Point 3</td><td>28</td><td>—</td></tr><tr><td>Palisades</td><td>—</td><td>34</td></tr><tr><td>Pilgrim</td><td>45</td><td>—</td></tr><tr><td>Vermont Yankee</td><td>27</td><td>—</td></tr></table>

(a) The reduction in owned capacity is due to the retirement of the 544 MW Ritchie Unit 2 in November 2013.

Other Income Statement Items

Utility

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

- an increase of $83 million in compensation and benefits costs primarily due to a decrease in the discount rates used to determine net periodic pension and other postretirement benefit costs 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;

- an increase of $46 million in fossil-fueled generation expenses primarily due to the acquisitions of the Hot Spring plant by Entergy Arkansas and the Hinds plant by Entergy Mississippi in November 2012. Costs related to the Hot Spring and Hinds plants are recovered through the capacity acquisition rider and power management rider, respectively, as previously discussed. Also contributing to the increases is an overall higher scope of work done during plant outages as compared to the prior year;

- an increase of $72 million resulting from implementation costs, severance costs, and curtailment and special termination benefits in 2013 related to the human capital management strategic imperative, partially offset by the deferral of approximately $44 million of these costs. See the “Human Capital Management Strategic Imperative” below for further discussion;

- an increase of $16 million in energy efficiency costs at Entergy Arkansas. These costs are recovered through an energy efficiency rider and have minimal effect on net income;



- an increase of $13 million in nuclear expenses, primarily due to higher labor costs, including higher contract labor;

- the deferral in 2012, as approved by the LPSC and the FERC, of costs related to the transition and implementation of joining the MISO RTO, which reduced 2012 expenses by $10 million; and

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

Also, other operation and maintenance expenses include $36 million in 2013 and $38 million in 2012 of costs incurred related to the now-terminated plan to spin off and merge the Utility’s transmission business.

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

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

Interest expense increased primarily due to net debt issuances in 2013 of $520 million by the Utility operating companies and System Energy and lower allowance for borrowed funds used during construction due to the completion of several major projects in 2012.

## Entergy Wholesale Commodities

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

- an increase of $43 million in compensation and benefits costs primarily due to a decrease in the discount rates used to determine net periodic pension and other postretirement benefit costs 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;

- an increase of $23 million primarily due to the effect of the final court decisions in the Vermont Yankee and Indian Point 2 lawsuits against the U.S. Department of Energy related to spent nuclear fuel disposal recorded in 2012. The damages awarded included the reimbursement of approximately $25 million of spent nuclear fuel storage costs previously recorded as operation and maintenance expenses;

- an increase of $16 million resulting from implementation and severance costs in 2013 related to the human capital management strategic imperative. See “Human Capital Management Strategic Imperative” below for further discussion; and

- approximately $15 million in commitments recorded in connection with the settlement agreement with parties in Vermont regarding the operation and decommissioning of Vermont Yankee. See “Impairment of Long-Lived Assets” in Note 1 to the financial statements for further discussion of the settlement agreement.

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

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



spent nuclear fuel disposal. The effects of recording the proceeds from the judgment reduced the plant in service balances and included a $25 million reduction to previously-recorded depreciation expense.

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 serving the business districts in Houston and New Orleans. Entergy sold Entergy Solutions District Energy for $140 million and realized a pre-tax gain of $44 million on the sale.

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

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

## Parent & Other

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

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

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

## 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, see “Impairment of Long-Lived Assets” in Note 1 to the financial statements.

In April 2007, Entergy submitted to the NRC a joint application to renew the operating licenses for Indian Point 2 and Indian Point 3 for an additional 20 years. The original expiration date of the NRC operating license for Indian Point 2 was in September 2013 and the original expiration date of the NRC operating license for Indian Point 3 is in December 2015. Authorization to operate Indian Point 2 rests, and for Indian Point 3 will rest, on Entergy’s having timely filed a license renewal application that remains pending before the NRC. Indian Point 2 has now entered its “period of extended operation” after expiration of the plant’s initial license term under “timely renewal,” which is a federal statutory rule of general applicability providing for extension of a license for which a renewal application has been timely filed with the licensing agency. Indian Point 3 is expected to reach the same milestone, and to become subject to the same statutorily prescribed extension of its license expiration date, in December 2015. 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 in the second paragraph below. In July 2011 the ASLB granted the State of New York’s motion for summary disposition of an admitted contention challenging the adequacy of a section of Indian Point’s environmental analysis as incorporated in the Final Supplemental Environmental Impact Statement (FSEIS) (discussed below). That section provided cost estimates for Severe Accident Mitigation Alternatives (SAMAs), which are hardware and procedural changes that could be implemented to mitigate estimated impacts of off-site radiological releases in case of a hypothesized severe accident. In addition to finding that the SAMA cost analysis was insufficient, the ASLB directed the NRC staff to explain why cost-beneficial SAMAs should not be required to be implemented. Entergy appealed the ASLB’s decision to the NRC and the NRC staff supported Entergy’s appeal, while the State of New York opposed it. In December 2011 the NRC denied Entergy’s appeal as premature. 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. There is no deadline for the NRC action on either group of appeals from the ASLB.

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 nine of the original 16 admitted consolidated contentions that have been resolved favorably (or in the case of settlement, acceptably) to Entergy. Seven of the original 16 admitted consolidated contentions are on appeal (four total) or pending hearing on Track 2 (three total).

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

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 proposed schedule identifies several milestones leading to the issuance of a new final FSEIS supplement in March 2016. The matters to be addressed in the new supplement include Entergy’s May 2013 submittal of updated cost information for SAMAs; Entergy’s February 2014 submittal of new aquatic impact information; the June 2013 revision by the NRC of its Generic Environmental Impact Statement relied upon in license renewal proceedings; and the NRC’s Continued Storage Of Spent Nuclear Fuel rule, which was published in the Federal Register in September 2014.

The hearing process is an integral component of the NRC’s regulatory framework, and evidentiary hearings on license renewal applications are not uncommon. Entergy is participating fully in the hearing and appeals processes as authorized by the NRC regulations. As noted in Entergy filings at the ASLB and the appellate levels, Entergy believes the contentions proposed by the intervenors are unsupported and without merit. Entergy will continue to work with the NRC staff as it completes its technical and environmental reviews of the Indian Point 2 and 3 license renewal.



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

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 ALJ’s 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 ALJ’s 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 ALJ’s 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 ALJ’s 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 ALJ’s issued a ruling scheduling hearings on the outage proposals and other pending issues in September and October 2015, with post-hearing briefing to follow in December 2015.

The ALJ’s have issued no partial decisions on the several issues that have been the subject of hearing during the past three years and have not announced a schedule for doing so. After the completion of hearings on the merits, the ALJ’s 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.

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, is discretionary in this case. In January 2015, NYSDOS filed with the same court a motion for reargument or, alternatively, leave to appeal to the State Court of Appeals. Entergy timely filed opposing papers. If the Appellate Division denies NYSDOS’s motion, NYSDOS may then file a separate motion for leave to appeal directly with the State Court of Appeals.

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.



## 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. On July 12, 2013, Entergy Arkansas filed a complaint in the Circuit Court in Pope County, Arkansas against the owner of the heavy-lifting apparatus that collapsed, an engineering firm, a 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. The NRC plans to conduct supplemental inspection activity to review the actions taken to address the yellow findings. Entergy will continue to interact with the NRC to address the NRC’s findings.

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



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.”

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

## 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.

<table><tr><td></td><td>2014</td><td>2013</td></tr><tr><td>Debt to capital</td><td>57.6%</td><td>57.9%</td></tr><tr><td>Effect of excluding securitization bonds</td><td>(1.4%)</td><td>(1.6%)</td></tr><tr><td>Debt to capital, excluding securitization bonds (a)</td><td>56.2%</td><td>56.3%</td></tr><tr><td>Effect of subtracting cash</td><td>(2.8%)</td><td>(1.5%)</td></tr><tr><td>Net debt to net capital, excluding securitization bonds (a)</td><td>53.4%</td><td>54.8%</td></tr></table>

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

Net debt consists of debt less cash and cash equivalents. Debt consists of notes payable 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, 2014. To estimate future interest payments for variable rate debt, Entergy used the rate as of December 31, 2014. The amounts below include payments on the Entergy Louisiana and System Energy sale-leaseback transactions, which are included in long-term debt on the balance sheet.

<table><tr><td colspan="7">Long-term debt maturities and estimated interest payments</td></tr><tr><td></td><td>2015</td><td>2016</td><td>2017</td><td>2018-2019</td><td>after 2019</td><td></td></tr><tr><td></td><td></td><td></td><td>(In Millions)</td><td></td><td></td><td></td></tr><tr><td>Utility</td><td>$882</td><td>$746</td><td>$886</td><td>$2,070</td><td>$13,997</td><td></td></tr><tr><td>Entergy Wholesale Commodities</td><td>19</td><td>2</td><td>2</td><td>4</td><td>53</td><td></td></tr><tr><td>Parent and Other</td><td>624</td><td>60</td><td>537</td><td>757</td><td>466</td><td></td></tr><tr><td>Total</td><td>$1,525</td><td>$808</td><td>$1,425</td><td>$2,831</td><td>$14,516</td><td></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 March 2019. Entergy Corporation has the ability to issue letters of credit against 50% of the total borrowing capacity of the facility. The commitment fee is currently 0.275% of the undrawn commitment amount. Commitment fees and interest rates on loans under the credit facility can fluctuate depending on the senior unsecured debt ratings of Entergy Corporation. The weighted average interest rate for the year ended December 31, 2014 was 1.93% on the drawn portion of the facility.

As of December 31, 2014, 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></td><td>(In Millions)</td><td></td><td></td></tr><tr><td>$3,500</td><td>$695</td><td>$9</td><td>$2,796</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, 2014, Entergy Corporation had $484 million of commercial paper outstanding. The weighted-average interest rate for the year ended December 31, 2014 was 0.88%.



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>2015</td><td>2016</td><td>2017</td><td>2018-2019</td><td>after 2019</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>$7</td><td>$28</td></tr></table>

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

Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas each had credit facilities available as of December 31, 2014 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, 2014</td></tr><tr><td>Entergy Arkansas</td><td>April 2015</td><td>$20 million (b)</td><td>1.67%</td><td>—</td></tr><tr><td>Entergy Arkansas</td><td>March 2019</td><td>$150 million (c)</td><td>1.67%</td><td>—</td></tr><tr><td>Entergy Gulf States Louisiana</td><td>March 2019</td><td>$150 million (d)</td><td>1.42%</td><td>—</td></tr><tr><td>Entergy Louisiana</td><td>March 2019</td><td>$200 million (e)</td><td>1.42%</td><td>—</td></tr><tr><td>Entergy Mississippi</td><td>May 2015</td><td>$10 million (f)</td><td>1.67%</td><td>—</td></tr><tr><td>Entergy Mississippi</td><td>May 2015</td><td>$20 million (f)</td><td>1.67%</td><td>—</td></tr><tr><td>Entergy Mississipp</td><td>May 2015</td><td>$35 million (f)</td><td>1.67%</td><td>—</td></tr><tr><td>Entergy Mississippi</td><td>May 2015</td><td>$37.5 million (f)</td><td>1.67%</td><td>—</td></tr><tr><td>Entergy New Orleans</td><td>November 2015</td><td>$25 million</td><td>1.92%</td><td>—</td></tr><tr><td>Entergy Texas</td><td>March 2019</td><td>$150 million (g)</td><td>1.67%</td><td>—</td></tr></table>

(a) The interest rate is the rate as of December 31, 2014 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. As of December 31, 2014, no letters of credit were outstanding.

(d) The credit facility allows Entergy Gulf States Louisiana to issue letters of credit against 50% of the borrowing capacity of the facility. As of December 31, 2014, no letters of credit were outstanding.

(e) The credit facility allows Entergy Louisiana to issue letters of credit against 50% of the borrowing capacity of the facility. As of December 31, 2014, no letters of credit were outstanding.

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

(g) The credit facility allows Entergy Texas to issue letters of credit against 50% of the borrowing capacity of the facility. As of December 31, 2014, $1.3 million in letters of credit were outstanding.

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

<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, 2014</td></tr><tr><td>Entergy Arkansas</td><td>$25 million</td><td>0.70%</td><td>$2.0 million</td></tr><tr><td>Entergy Gulf States Louisiana</td><td>$75 million</td><td>0.70%</td><td>$27.9 million</td></tr><tr><td>Entergy Louisiana</td><td>$50 million</td><td>0.70%</td><td>$4.7 million</td></tr><tr><td>Entergy Mississippi</td><td>$40 million</td><td>0.70%</td><td>$14.4 million</td></tr><tr><td>Entergy Mississippi</td><td>$40 million</td><td>1.50%</td><td>$—</td></tr><tr><td>Entergy New Orleans</td><td>$15 million</td><td>0.75%</td><td>$8.1 million</td></tr><tr><td>Entergy Texas</td><td>$50 million</td><td>0.70%</td><td>$24.5 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, 2014 on non-cancelable operating leases with a term over one year:

<table><tr><td></td><td>2015</td><td>2016</td><td>2017</td><td>2018-2019</td><td>after 2019</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>$90</td><td>$77</td><td>$62</td><td>$97</td><td>$96</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>2015</td><td>2016-2017</td><td>2018-2019</td><td>after 2019</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>$1,525</td><td>$2,233</td><td>$2,831</td><td>$14,516</td><td>$21,105</td></tr><tr><td>Capital lease payments (b)</td><td>$5</td><td>$8</td><td>$7</td><td>$28</td><td>$48</td></tr><tr><td>Operating leases (b) (c)</td><td>$90</td><td>$139</td><td>$97</td><td>$96</td><td>$422</td></tr><tr><td>Purchase obligations (d)</td><td>$1,898</td><td>$2,738</td><td>$2,405</td><td>$5,821</td><td>$12,862</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 $396.2 million to its pension plans and approximately $66.9 million to other postretirement plans in 2015, although the required pension contributions will not be known with more certainty until the January 1, 2015 valuations are completed by April 1, 2015. 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 $441 million of unrecognized tax benefits and interest net of unused tax attributes for which the timing of payments beyond 12 months cannot be reasonably estimated due to uncertainties in the timing of effective settlement of tax positions. See Note 3 to the financial statements for additional information regarding unrecognized tax benefits.

## 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 2015 through 2017.

<table><tr><td>Planned construction and capital investments</td><td>2015</td><td>2016 (In Millions)</td><td>2017</td></tr><tr><td>Utility:</td><td></td><td></td><td></td></tr><tr><td>Generation</td><td>$1,585</td><td>$635</td><td>$1,040</td></tr><tr><td>Transmission</td><td>805</td><td>670</td><td>665</td></tr><tr><td>Distribution</td><td>715</td><td>700</td><td>650</td></tr><tr><td>Other</td><td>230</td><td>190</td><td>155</td></tr><tr><td>Total</td><td>3,335</td><td>2,195</td><td>2,510</td></tr><tr><td>Entergy Wholesale Commodities</td><td>425</td><td>265</td><td>275</td></tr><tr><td>Total</td><td>$3,760</td><td>$2,460</td><td>$2,785</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, NYPA value sharing in January 2015, dry cask storage, and nuclear license renewal.

- Environmental compliance spending, including potential scrubbers at White Bluff to meet pending Arkansas state requirements under the Clean Air Visibility Rule. Entergy continues to review potential environmental spending needs and financing alternatives for any such spending, and future spending estimates could change based on the results of this continuing analysis and the implementation of new environmental laws and regulations.

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

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

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 or reproved 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.

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

## Ninemile Point Unit 6 Self-Build Project

In June 2011, Entergy Louisiana filed with the LPSC an application seeking certification that the public necessity and convenience would be served by Entergy Louisiana’s construction of a combined-cycle gas turbine generating facility (Ninemile 6) at its existing Ninemile Point electric generating station. Ninemile 6 is a nominally-sized 560 MW unit that is expected to cost approximately $655 million to construct when spending is complete, excluding interconnection and transmission upgrades. Entergy Gulf States Louisiana joined in the application, seeking certification of its purchase under a life-of-unit power purchase agreement of up to 25% of the capacity and energy generated by Ninemile 6. The Ninemile 6 capacity and energy is allocated 55% to Entergy Louisiana, 25% to Entergy Gulf States Louisiana, and 20% to Entergy New Orleans. In February 2012 the City Council passed a resolution



authorizing Entergy New Orleans to purchase 20% of the Ninemile 6 energy and capacity. In March 2012 the LPSC unanimously voted to grant the certifications requested by Entergy Gulf States Louisiana and Entergy Louisiana. Following approval by the LPSC, Entergy Louisiana issued full notice to proceed to the project’s engineering, procurement, and construction contractor.

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

## Dividends and Stock Repurchases

Declarations of dividends on Entergy’s common stock are made at the discretion of the Board. Among other things, the Board evaluates the level of Entergy’s common stock dividends based upon Entergy’s earnings, financial strength, and future investment opportunities. At its January 2015 meeting, the Board declared a dividend of $0.83 per share, which is the same quarterly dividend per share that Entergy has paid since the second quarter 2010. Entergy paid $596 million in 2014, $593 million in 2013, and $589 million in 2012 in cash dividends on its common stock.

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

In addition to the authority to fund grant exercises, the Board has authorized share repurchase programs to enable opportunistic purchases in response to market conditions. In October 2010 the Board granted authority for a $500 million share repurchase program. As of December 31, 2014, $350 million of authority remains under the $500 million share repurchase program. The amount of repurchases may vary as a result of material changes in business results or capital spending or new investment opportunities, or if limitations in the credit markets continue for a prolonged period.

## Sources of Capital

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

• internally generated funds;

• cash on hand ($1,422 million as of December 31, 2014);

• 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, 2014, under provisions in their mortgage indentures, Entergy Arkansas and Entergy Mississippi had restricted retained earnings unavailable for distribution to Entergy Corporation of $394.9 million and $68.5 million, respectively. All debt and common and preferred equity issuances by the Registrant Subsidiaries require prior regulatory approval and their preferred equity and debt issuances are also subject to issuance tests set forth in corporate charters, bond indentures, and other agreements. Entergy believes that the Registrant Subsidiaries have sufficient capacity under these tests to meet foreseeable capital needs.

The FERC has jurisdiction over securities issuances by the Utility operating companies and System Energy (except securities with maturities longer than one year issued by Entergy Arkansas and Entergy New Orleans, which are subject to the jurisdiction of the APSC and the City Council, respectively). No regulatory approvals are necessary for Entergy Corporation to issue securities. The current FERC-authorized short-term borrowing limits are effective through October 31, 2015. Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy Texas, and System Energy have obtained long-term financing authorizations from the FERC that extend through October 2015. Entergy Arkansas has obtained long-term financing authorization from the APSC that extends through December 2015. Entergy New Orleans has obtained long-term financing authorization from the City Council that extends through July 2016. Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, and System Energy each have obtained long-term financing authorizations from the FERC that extend through October 2015 for issuances by its nuclear fuel company variable interest entity. In addition to borrowings from commercial banks, the FERC short-term borrowing orders authorize the Registrant Subsidiaries to continue as participants in the Entergy System money pool. The money pool is an intercompany borrowing arrangement designed to reduce Entergy’s subsidiaries’ dependence on external short-term borrowings. Borrowings from the money pool and external short-term borrowings combined may not exceed the FERC-authorized short-term borrowing limits. See Notes 4 and 5 to the financial statements for further discussion of Entergy’s borrowing limits, authorizations, and amounts outstanding.

## 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 Gulf States Louisiana and Entergy Louisiana drew $65 million and $187 million, respectively, from their funded storm reserve escrow accounts. In April 2013, Entergy Gulf States Louisiana and Entergy Louisiana filed a joint application with the LPSC relating to Hurricane Isaac system restoration costs. Specifically, Entergy Gulf States Louisiana and 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 Gulf States Louisiana requested an LPSC determination that $73.8 million in system restoration costs were prudently incurred and Entergy Louisiana requested an LPSC determination that $247.7 million in system restoration costs were prudently incurred. In May 2013, Entergy Gulf States Louisiana, Entergy Louisiana, and the Louisiana Utilities Restoration Corporation (LURC), an instrumentality of the State of Louisiana, filed with the LPSC an application requesting that the LPSC grant financing orders authorizing the financing of Entergy Gulf States Louisiana’s and Entergy Louisiana’s storm costs, storm reserves, and issuance costs pursuant to Act 55 of the Louisiana Regular Session of 2007 (Louisiana Act 55). The LPSC Staff filed direct testimony in September 2013 concluding that Hurricane Isaac system restoration costs incurred by Entergy Gulf States Louisiana and Entergy Louisiana were reasonable and prudent, subject to proposed minor adjustments which totaled approximately 1% of each 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 ($66.5 million for Entergy Gulf States Louisiana and $224.3 million for Entergy Louisiana); (ii) determine the level of storm reserves to be re-established ($90 million for Entergy Gulf States Louisiana and $200 million for Entergy Louisiana); (iii) authorize Entergy Gulf States Louisiana and 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 Gulf States Louisiana committed to pass on to customers a minimum of $6.9 million of customer benefits through annual customer credits of approximately $1.4 million for five years. Entergy Louisiana committed to pass on to customers a minimum of $23.9 million of customer benefits through annual customer credits of approximately $4.8 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 Gulf States Louisiana issued $110 million of 3.78% Series first mortgage bonds due April 2025 and used the proceeds to re-establish and replenish its storm damage escrow reserves and for general corporate purposes. In July 2014, Entergy Louisiana issued $190 million of 3.78% Series first mortgage bonds due April 2025 and used the proceeds to re-establish and replenish its storm damage escrow reserves and for general corporate purposes.

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

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

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



## Cash Flow Activity

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

<table><tr><td rowspan="2"></td><td>2014</td><td>2013</td><td>2012</td></tr><tr><td colspan="3">(In Millions)</td></tr><tr><td>Cash and cash equivalents at beginning of period</td><td>$739</td><td>$533</td><td>$694</td></tr><tr><td>Net cash provided by (used in):</td><td></td><td></td><td></td></tr><tr><td>Operating activities</td><td>3,890</td><td>3,189</td><td>2,940</td></tr><tr><td>Investing activities</td><td>(2,955)</td><td>(2,602)</td><td>(3,639)</td></tr><tr><td>Financing activities</td><td>(252)</td><td>(381)</td><td>538</td></tr><tr><td>Net increase (decrease) in cash and cash equivalents</td><td>683</td><td>206</td><td>(161)</td></tr><tr><td>Cash and cash equivalents at end of period</td><td>$1,422</td><td>$739</td><td>$533</td></tr></table>

## Operating Activities

## 2014 Compared to 2013

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 the same period in 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;

- an increase of $60 million in 2014 as compared to 2013 as a result of $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.

## 2013 Compared to 2012

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

• increased recovery of deferred fuel costs;

• higher Utility net revenues in 2013 resulting from additional generation investments made in 2012;



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

- a decrease of approximately $84 million in storm restoration spending in 2013 due to Hurricane Isaac in August 2012, partially offset by an increase of approximately $23 million in storm restoration spending in 2013 due to the Arkansas December 2012 winter storm;

- a refund of $30.6 million, including interest, paid to AmerenUE in June 2012. The FERC ordered Entergy Arkansas to refund to AmerenUE the rough production cost equalization payments previously collected. See Note 2 to the financial statements for further discussion of the FERC order; and

- a decrease of $14 million in spending on nuclear refueling outages in 2013 as compared to the same period in prior year.

The increase was partially offset by:

- an increase of $79 million in income tax payments primarily due to the 2013 state income tax effects of the settlement of the 2004-2005 IRS audit in the fourth quarter 2012;

- an increase of $52 million in lump sum retirement payments out of the non-qualified pension plan, partially offset by a decrease of $7 million in pension contributions. See “Critical Accounting Estimates - Qualified Pension and Other Postretirement Benefits” below and Note 11 to the financial statements for a discussion of qualified pension and other postretirement benefits funding;

• the decrease in Entergy Wholesale Commodities net revenue that was discussed previously; and

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

## Investing Activities

## 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 Gulf States Louisiana and 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 Gulf States Louisiana and 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 self-build project and spending in 2013 on the generator stator incident at ANO, partially offset by an increase in storm restoration spending. Entergy’s construction spending plans for 2015 through 2017 are discussed further in “Capital Expenditure Plans and Other Uses of Capital” above;

- a change in collateral deposit activity, reflected in the “Decrease (increase) in other investments” line on the Consolidated Statement 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.

## 2013 Compared to 2012

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

- the acquisitions of the Hot Spring plant by Entergy Arkansas and the Hinds plant by Entergy Mississippi in November 2012. See Note 15 to the financial statements for further discussion of these plant acquisitions;

- the withdrawal of a total of $260 million from storm reserve escrow accounts in 2013, primarily by Entergy Gulf States Louisiana and Entergy Louisiana, after Hurricane Isaac. See Note 2 to the financial statements for a discussion of Hurricane Isaac;

- a decrease in construction expenditures, primarily in the Utility business, resulting from spending in 2012 on the uprate project at Grand Gulf and storm restoration spending in 2012 resulting from the Arkansas December 2012 winter storm and Hurricane Isaac, substantially offset by spending in 2013 on the Ninemile 6 self-build project and spending in 2013 related to the generator stator incident at ANO, as discussed previously; and

- 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.

The decrease was partially offset by:

- a change in collateral deposit activity, reflected in the “Decrease (increase) in other investments” line on the Consolidated Statement of Cash Flows, as Entergy returned $50 million more net deposits in 2013 than 2012. Entergy Wholesale Commodities” forward sales contracts are discussed in the “Market and Credit Risk Sensitive Instruments” section below; and

- proceeds of $21 million in 2013 compared to proceeds of $109 million in 2012 from the U.S. Department of Energy resulting from litigation regarding the storage of spent nuclear fuel.

## Financing Activities

## 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.

## 2013 Compared to 2012

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

- long-term debt activity using approximately $69 million of cash in 2013 compared to providing $348 million of cash in 2012. The most significant long-term debt activity in 2013 included the net issuance of approximately



$520 million of long-term debt at the Utility operating companies and System Energy and Entergy Corporation decreasing borrowings outstanding on its long-term credit facility by $540 million;

- Entergy Corporation issued $380 million of commercial paper in 2013 and $665 million in 2012, in part, to repay borrowings on its long-term credit facility;

- a net decrease of $136 million in short-term borrowings by the nuclear fuel company variable interest entities; and

- $51 million in proceeds from the sale to a third party in 2012 of a portion of Entergy Gulf States Louisiana’s investment in Entergy Holdings Company’s Class A preferred membership interests.

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>9.5%</td></tr><tr><td>Entergy Gulf States Louisiana</td><td>9.15%-10.75% Electric; 9.45%-10.45% Gas</td></tr><tr><td>Entergy Louisiana</td><td>9.15% - 10.75%</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 Gulf States Louisiana’s and 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 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 February 2013, Entergy Services, on behalf of the Utility operating companies, made a filing with the FERC requesting to adopt the standard Attachment O formula rate template used by transmission owners to establish transmission rates within MISO. The filing proposed four transmission pricing zones for the Utility operating companies, one for Entergy Arkansas, one for Entergy Mississippi, one for Entergy Texas, and one for Entergy Louisiana, Entergy Gulf States Louisiana, and Entergy New Orleans. In June 2013 the FERC issued an order accepting the use of four transmission pricing zones and set for hearing and settlement judge procedures those issues of material fact that FERC decided could not be resolved based on the existing record. Several parties, including the City Council, filed requests for rehearing of the June 2013 order. 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.



## 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.

## 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. In December 2009 the LPSC and the City Council filed with the FERC a request for rehearing of the FERC's November 2009 order. In February 2011 the FERC denied the LPSC's and the City Council's rehearing requests. In September and October 2012 the U.S. Court of Appeals for the D.C. Circuit denied the LPSC's and the City Council's appeals of the FERC decisions. In January 2013 the LPSC and the City Council filed a petition for a writ of certiorari with the U.S. Supreme Court. In May 2013 the U.S. Supreme Court denied the petition for a writ of certiorari. Effective December 18, 2013, Entergy Arkansas ceased participating in the System Agreement.

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

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



was retained to assist the PUCT Staff in its assessment of the analysis. In April 2013 the PUCT staff filed a study performed by its independent consultant assessing Entergy Texas's January 2013 updated analysis of the effect of termination of certain PPAs on Entergy Texas's costs upon Entergy Texas's exit from the System Agreement. While the independent consultant study concluded that the adjustments made in Entergy Texas's updated analysis were analytically correct, the consultant also recommended further study regarding the effect of the termination of the PPAs on the benefits associated with Entergy Texas joining MISO. Entergy Texas filed a response to the consultant study, noting a number of errors in the analysis and recommending against any further study of this matter. Entergy Texas subsequently agreed to fund further analysis, to be performed by a different independent consultant for the PUCT, regarding the effects of termination of these PPAs. In August 2013 the report of the PUCT's second independent consultant regarding the effects of termination of these PPAs was filed with the PUCT as part of a larger report addressing the results of the consultant's comprehensive analysis of Entergy Texas's transition to operations post-exit from the System Agreement. The report concluded, consistent with Entergy Texas's updated analysis, that under both the "Foundation Case" capacity price forecast and the high capacity price sensitivity that were performed, Entergy Texas and its customers would be better off on a present-value basis if these PPAs terminate. Under the low capacity price sensitivity, there was a net cost to Entergy Texas customers if these PPAs terminate. Consistent with the requirements of the PUCT conditional order approving the change in control to MISO, on October 18, 2013, Entergy Texas gave notice of cancellation to terminate its participation in the System Agreement.

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

In keeping with the commitments made in their March 2013 answer to the protests 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 on October 11, 2013 to amend the System Agreement changing the notice period for an operating company to terminate its participation in the System Agreement from 96 months to 60 months. The proposed amendment also clarifies that the revised notice period will apply to any written notice of termination.



provided by an operating company on or after October 12, 2013. On October 18, 2013, Entergy Texas provided notice to terminate its participation in the System Agreement effective after expiration of the proposed 60-month notice period or such other period as approved by FERC. The proposed amendment and Entergy Texas’s termination notice are without prejudice to continuing efforts among affected operating companies and their retail regulators to search for a consensual means of allowing Entergy Texas an early exit from the System Agreement, which could be different from that proposed in the October 11, 2013 FERC filing. Comments on both filings were filed in November 2013.

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

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

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

## U.S. Department of Justice Investigation

In September 2010, Entergy was notified that the U.S. Department of Justice had commenced a civil investigation of competitive issues concerning certain generation procurement, dispatch, and transmission system practices and policies of the Utility operating companies. In November 2012 the U.S. Department of Justice issued a press release in which the U.S. Department of Justice stated, among other things, that the civil investigation concerning certain generation procurement, dispatch, and transmission system practices and policies of the Utility operating companies would remain open. The release noted, however, the intention of each of the Utility operating companies



to join MISO and Entergy’s agreement with ITC to undertake the spin-off and merger of Entergy’s transmission business. The release stated that if Entergy follows through on these matters, the U.S. Department of Justice’s concerns will be resolved. The release further stated that the U.S. Department of Justice will monitor developments, and in the event that Entergy does not make meaningful progress, the U.S. Department of Justice can and will take appropriate enforcement action, if warranted. On December 13, 2013, Entergy and ITC mutually agreed to terminate the transaction following denial by the MPSC of the joint application related to the transaction. On December 19, 2013, the Utility operating companies successfully completed their planned integration into the MISO RTO.

## 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, 2014.

## Entergy Wholesale Commodities Nuclear Portfolio

<table><tr><td></td><td>2015</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><td></td></tr><tr><td>Percent of planned generation under contract (a):</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Unit-contingent (b)</td><td>47%</td><td>23%</td><td>14%</td><td>14%</td><td>16%</td></tr><tr><td>Unit-contingent with availability guarantees (c)</td><td>18%</td><td>17%</td><td>18%</td><td>3%</td><td>3%</td></tr><tr><td>Firm LD (d)</td><td>40%</td><td>34%</td><td>7%</td><td>—%</td><td>—%</td></tr><tr><td>Offsetting positions (e)</td><td>(19%)</td><td>—%</td><td>—%</td><td>—%</td><td>—%</td></tr><tr><td>Total</td><td>86%</td><td>74%</td><td>39%</td><td>17%</td><td>19%</td></tr><tr><td>Planned generation (TWh) (f) (g)</td><td>35</td><td>36</td><td>35</td><td>35</td><td>36</td></tr><tr><td>Average revenue per MWh on contracted volumes:</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Minimum</td><td>$47</td><td>$47</td><td>$48</td><td>$56</td><td>$57</td></tr><tr><td>Expected based on market prices as of December 31, 2014</td><td>$48</td><td>$49</td><td>$50</td><td>$56</td><td>$57</td></tr><tr><td>Sensitivity: -/+ $10 per MWh market price change</td><td>$47-$50</td><td>$47-$53</td><td>$49-$53</td><td>$56</td><td>$57</td></tr><tr><td>Capacity</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Percent of capacity sold forward (h):</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Bundled capacity and energy contracts (i)</td><td>18%</td><td>18%</td><td>18%</td><td>18%</td><td>18%</td></tr><tr><td>Capacity contracts (j)</td><td>30%</td><td>15%</td><td>16%</td><td>7%</td><td>—%</td></tr><tr><td>Total</td><td>48%</td><td>33%</td><td>34%</td><td>25%</td><td>18%</td></tr><tr><td>Planned net MW in operation (g)</td><td>4,406</td><td>4,406</td><td>4,406</td><td>4,406</td><td>4,404</td></tr><tr><td>Average revenue under contract per kW per month (applies to capacity contracts only)</td><td>$3.9</td><td>$3.4</td><td>$5.6</td><td>$7.0</td><td>$—</td></tr><tr><td>Total Nuclear Energy and Capacity Revenues</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Expected sold and market total revenue per MWh</td><td>$53</td><td>$50</td><td>$50</td><td>$51</td><td>$53</td></tr><tr><td>Sensitivity: -/+ $10 per MWh market price change</td><td>$51-$56</td><td>$46-$56</td><td>$44-$57</td><td>$43-$60</td><td>$45-$61</td></tr></table>



Entergy Wholesale Commodities Non-Nuclear Portfolio

<table><tr><td>Energy</td><td>2015</td><td>2016</td><td>2017</td><td>2018</td><td>2019</td></tr><tr><td>Percent of planned generation under contract (a):</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Cost-based contracts (k)</td><td>38%</td><td>36%</td><td>34%</td><td>34%</td><td>34%</td></tr><tr><td>Firm LD (d)</td><td>7%</td><td>7%</td><td>7%</td><td>7%</td><td>7%</td></tr><tr><td>Total</td><td>45%</td><td>43%</td><td>41%</td><td>41%</td><td>41%</td></tr><tr><td>Planned generation (TWh) (f) (l)</td><td>5</td><td>6</td><td>6</td><td>6</td><td>6</td></tr><tr><td>Capacity</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Percent of capacity sold forward (h):</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Cost-based contracts (k)</td><td>24%</td><td>24%</td><td>26%</td><td>26%</td><td>26%</td></tr><tr><td>Bundled capacity and energy contracts (i)</td><td>8%</td><td>8%</td><td>8%</td><td>8%</td><td>8%</td></tr><tr><td>Capacity contracts (j)</td><td>54%</td><td>53%</td><td>57%</td><td>24%</td><td>—%</td></tr><tr><td>Total</td><td>86%</td><td>85%</td><td>91%</td><td>58%</td><td>34%</td></tr><tr><td>Planned net MW in operation (l)</td><td>1,052</td><td>1,052</td><td>977</td><td>977</td><td>977</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, seller is generally not liable to buyer for any damages.

(c) A sale of power on a unit-contingent basis coupled with a guarantee of availability provides for the payment to the power purchaser of contract damages, if incurred, in the event the seller fails to deliver power as a result of the failure of the specified generation unit to generate power at or above a specified availability threshold. All of Entergy’s outstanding guarantees of availability provide for dollar limits on Entergy’s maximum liability under such guarantees.

(d) 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.

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

(f) 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.

(g) Assumes NRC license renewals for plants whose current licenses expired or expire within five years, and uninterrupted normal operation at all operating 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). For a discussion regarding the license renewal application for Indian Point 2 and Indian Point 3, see “Entergy Wholesale Commodities Authorizations to Operate Its Nuclear Power Plants” above.

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

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

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

(k) Contracts priced in accordance with cost-based rates, a ratemaking concept used for the design and development of rate schedules to ensure that the filed rate schedules recover only the cost of providing the service; these contracts are on owned non-utility resources located within Entergy’s Utility service area and were executed



prior to receiving market-based rate authority under MISO. The percentage sold assumes completion of the necessary transmission upgrades required for the approved transmission rights.

(1) Non-nuclear planned generation and net MW in operation include purchases from affiliated and non-affiliated counterparties under long-term contracts and exclude energy and capacity from Entergy Wholesale Commodities' wind investment. The decrease in planned net MW in operation beginning in 2017 is due to the expiration of a non-affiliated 75 MW contact.

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

Entergy’s purchase of the FitzPatrick and Indian Point 3 plants from NYPA included value sharing agreements with NYPA. In October 2007, NYPA and the subsidiaries that own the FitzPatrick and Indian Point 3 plants amended and restated the value sharing agreements to clarify and amend certain provisions of the original terms. Under the 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 is due by January 15 of the following year. Entergy records the liability for payments to NYPA as power is generated and sold by Indian Point 3 and FitzPatrick. In 2014, 2013, and 2012, 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 collateral to secure its obligations under the agreements. The Entergy subsidiary is required to provide collateral based upon the difference between the current market and contracted power prices in the regions where Entergy Wholesale Commodities sells power. The primary form of collateral to satisfy these requirements is an Entergy Corporation guaranty. Cash and letters of credit are also acceptable forms of collateral. At December 31, 2014, based on power prices at that time, Entergy had liquidity exposure of $159 million under the guarantees in place supporting Entergy Wholesale Commodities transactions and $5 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, 2014, Entergy would have been required to provide approximately $51 million of additional cash or letters of credit under some of the agreements. As of December 31, 2014, the liquidity exposure associated with Entergy Wholesale Commodities assurance requirements, including return of previously posted collateral from counterparties, would increase by $52 million for a $1 per MMBtu increase in gas prices in both the short-and long-term markets.

As of December 31, 2014, substantially all of the counterparties or their guarantors for the planned energy output under contract for Entergy Wholesale Commodities nuclear plants through 2018 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 on March 12, 2012. The three orders require U.S. nuclear operators to undertake plant modifications and perform additional analyses that will, among other things, result in increased operating and capital costs associated with operating nuclear plants. The NRC, with input from the industry, is continuing to determine the specific actions required by the orders. Entergy’s estimated capital expenditures for 2015 through 2017 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.

## 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. A high probability that the plant’s license will be renewed and the plant will operate for some time beyond the original license term has been assumed for purposes of calculating the decommissioning liability for a number of Entergy’s nuclear units. 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 3.25%. A 50 basis point change in this assumption could change the estimated present value of the decommissioning liabilities by approximately 9% 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, when applicable. 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.

Future 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 if the reduction of the liability exceeds the amount of the undepreciated asset retirement cost asset at the date of the revision. Future 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 for which the value is impaired, including a plant that is shutdown, or is nearing its shutdown date, however, for the non-rate-regulated portions of Entergy’s business the increase in the liability will immediately increase operating expense and not the asset retirement cost asset.



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

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

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

In the fourth quarter 2014, System Energy recorded a revision to its estimated decommissioning cost liability for Grand Gulf as a result of a revised decommissioning cost study. The revised estimate resulted in a $99.9 million increase in its decommissioning liability, along with a corresponding increase in the related asset retirement cost asset that will be depreciated over the remaining life of the unit.

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

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

In the fourth quarter 2013, System Energy recorded a revision to its estimated decommissioning cost liability for Grand Gulf as a result of a revised decommissioning cost study. The revised estimate resulted in a $102.3 million increase in its decommissioning liability, along with a corresponding increase in the related asset retirement cost asset that will be depreciated over the remaining life of the unit.

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

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



decommissioning cash flows. The reassessment resulted in a $27.2 million increase in the decommissioning cost liability and a corresponding impairment charge. See Note 1 to the financial statements for further discussion of the Vermont Yankee plant.

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

## 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 for Entergy to operate a plant for a shorter period than previously expected; if there is a significant adverse change in the physical condition of a plant; if investment in a plant significantly exceeds expected levels; or for certain nuclear plants if their operating licenses are not renewed.

If an asset is considered held for use, and Entergy concludes that an impairment analysis has been triggered under the accounting standards, the sum of the expected undiscounted future cash flows from the asset are compared to the asset’s carrying value. The carrying value of the asset includes any capitalized asset retirement cost associated with the decommissioning liability, therefore changes in assumptions that affect the decommissioning liability can increase or decrease the carrying value of the asset subject to impairment. If the expected undiscounted future cash flows exceed the carrying value, no impairment is recorded. If the expected undiscounted future cash flows are less than the carrying value and the carrying value exceeds the fair value, Entergy is required to record an impairment charge to write the asset down to its fair value. If an asset is considered held for sale, an impairment is required to be recognized if the fair value (less costs to sell) of the asset is less than its carrying value.

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

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

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

Entergy evaluates investment securities with unrealized losses at the end of each period to determine whether an other-than-temporary impairment has occurred. The assessment of whether an investment in a debt security has suffered an other-than-temporary impairment is based on whether Entergy has the intent to sell or more likely than not will be required to sell the debt security before recovery of its amortized costs. If Entergy does not expect to recover the entire amortized cost basis of the debt security, an other-than-temporary-impairment is considered to have occurred and it is measured by the present value of cash flows expected to be collected less the amortized cost basis (credit loss). Entergy did not have any material other than temporary impairments relating to credit losses on debt securities in 2014, 2013, or 2012. The assessment of whether an investment in an equity security has suffered an other than temporary impairment is based on a number of factors including, first, whether Entergy has the ability and intent to hold the investment to recover its value, the duration and severity of any losses, and, then, whether it is expected that the investment will recover its value within a reasonable period of time. Entergy’s trusts are managed by third parties who operate in accordance with agreements that define investment guidelines and place restrictions on the purchases and sales of investments. As discussed in Note 1 to the financial statements, unrealized losses on equity securities that are considered other-than-temporarily impaired are recorded in earnings for Entergy Wholesale Commodities. Entergy Wholesale Commodities did not record material charges to other income in 2014, 2013, or 2012 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. Additionally, Entergy currently provides postretirement health care and life insurance benefits for substantially all employees who reach retirement age and meet certain eligibility requirements while still working for Entergy.

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

Entergy’s reported costs of providing these benefits, as described in Note 11 to the financial statements, are affected by numerous factors including the provisions of the plans, changing employee demographics, and various actuarial calculations, assumptions, and accounting mechanisms. Because of the complexity of these calculations, the long-term nature of these obligations, and the importance of the assumptions utilized, Entergy’s estimate of these costs is a critical accounting estimate for the Utility and Entergy Wholesale Commodities segments.



## 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 for 2015 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 reviews market yields on high-quality corporate debt and matches these rates with Entergy’s projected stream of benefit payments. Based on recent market trends, the discount rates used to calculate its 2014 qualified pension benefit obligation and 2015 qualified pension cost ranged from 4.03% to 4.40% for its specific pension plans (4.27% combined rate for all pension plans). The discount rates used to calculate its 2013 qualified pension benefit obligation and 2014 qualified pension cost ranged from 5.04% to 5.26% for its specific pension plans (5.14% combined rate for all pension plans). The discount rates used to calculate its 2012 qualified pension benefit obligation and 2013 qualified pension cost ranged from 4.31% to 4.50% for its specific pension plans (4.36% combined rate for all pension plans). The discount rate used to calculate its 2014 other postretirement benefit obligation and 2015 other postretirement benefit cost was 4.23%. The discount rate used to calculate its 2013 other postretirement benefit obligation and 2014 other postretirement benefit cost was 5.05%. The discount rate used to calculate its 2012 other postretirement benefit obligation and 2013 other postretirement 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, 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. Entergy’s assumed



health care cost trend rate assumption used in measuring 2012 postretirement cost was 7.75% for pre-65 retirees and 7.50% 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 2014 and 2013 benefit obligations was 4.23%.

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

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

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

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

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

## 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 2014 Qualified Pension Cost</td><td>Impact on 2014 Qualified Projected 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>$18,707</td><td>$271,656</td></tr><tr><td>Rate of return on plan assets</td><td>(0.25%)</td><td>$10,631</td><td>$—</td></tr><tr><td>Rate of increase in compensation</td><td>0.25%</td><td>$7,561</td><td>$44,183</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 2014 Postretirement Benefit Cost</td><td>Impact on 2014 Accumulated Postretirement Benefit Obligation</td></tr><tr><td>Discount rate</td><td>(0.25%)</td><td>$4,716</td><td>$63,342</td></tr><tr><td>Health care cost trend</td><td>0.25%</td><td>$7,953</td><td>$55,954</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 2014, Entergy’s total qualified pension cost was $216.5 million, including a $0.7 million special termination charge related to workforce downsizing. Entergy anticipates 2015 qualified pension cost to be $320.7 million. Entergy’s pension funding was approximately $399 million for 2014. Entergy’s contributions to the pension trust are currently estimated to be approximately $396.2 million in 2015, although the required pension contributions will not be known with more certainty until the January 1, 2015 valuations are completed by April 1, 2015.

Minimum required funding calculations as determined under Pension Protection Act guidance are performed annually as of January 1 of each year and are based on measurements of the assets and funding liabilities as measured at that date. Any excess of the funding liability over the calculated fair market value of assets results in a funding shortfall that, under the Pension Protection Act, must be funded over a seven-year rolling period. The Pension Protection Act also imposes certain plan limitations if the funded percentage, which is based on 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 2014 were $50.1 million. Entergy expects 2015 postretirement health care and life insurance benefit costs to be $66.2 million. Entergy contributed $76.5 million to its postretirement plans in 2014. Entergy’s current estimate of contributions to its other postretirement plans is approximately $66.9 million in 2015.

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

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

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



# 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, 2014.

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

Based on management’s assessment of internal controls using the 2013 COSO criteria, management believes that Entergy maintained effective internal control over financial reporting as of December 31, 2014. 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, 2014 and 2013, and the related consolidated income statements, and consolidated statements of comprehensive income, cash flows, and changes in equity for each of the three years in the period ended December 31, 2014. 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, 2014 and 2013, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2014, 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, 2014, 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 26, 2015 expressed an unqualified opinion on the Corporation’s internal control over financial reporting.

/s/ DELOITTE & TOUCHE LLP

New Orleans, Louisiana
February 26, 2015



# Attestation Report of Registered Public Accounting Firm

## 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, 2014, 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, 2014, 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 as of and for the year ended December 31, 2014 of the Corporation and our report dated February 26, 2015 expressed an unqualified opinion on those consolidated financial statements.

/s/ DELOITTE & TOUCHE LLP

New Orleans, Louisiana
February 26, 2015



## ENTERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED INCOME STATEMENTS

<table><tr><td rowspan="3"></td><td colspan="3">For the Years Ended December 31,</td></tr><tr><td>2014</td><td>2013</td><td>2012</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>$9,591,902</td><td>$8,942,360</td><td>$7,870,649</td></tr><tr><td>Natural gas</td><td>181,794</td><td>154,353</td><td>130,836</td></tr><tr><td>Competitive businesses</td><td>2,721,225</td><td>2,294,234</td><td>2,300,594</td></tr><tr><td>TOTAL</td><td>12,494,921</td><td>11,390,947</td><td>10,302,079</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>2,632,558</td><td>2,445,818</td><td>2,036,835</td></tr><tr><td>Purchased power</td><td>1,915,414</td><td>1,554,332</td><td>1,255,800</td></tr><tr><td>Nuclear refueling outage expenses</td><td>267,679</td><td>256,801</td><td>245,600</td></tr><tr><td>Other operation and maintenance</td><td>3,310,536</td><td>3,331,934</td><td>3,045,392</td></tr><tr><td>Asset write-offs, impairments, and related charges</td><td>179,752</td><td>341,537</td><td>355,524</td></tr><tr><td>Decommissioning</td><td>272,621</td><td>242,104</td><td>184,760</td></tr><tr><td>Taxes other than income taxes</td><td>604,606</td><td>600,350</td><td>557,298</td></tr><tr><td>Depreciation and amortization</td><td>1,318,638</td><td>1,261,044</td><td>1,144,585</td></tr><tr><td>Other regulatory charges (credits) - net</td><td>(13,772)</td><td>45,597</td><td>175,104</td></tr><tr><td>TOTAL</td><td>10,488,032</td><td>10,079,517</td><td>9,000,898</td></tr><tr><td>Gain on sale of business</td><td>—</td><td>43,569</td><td>—</td></tr><tr><td>OPERATING INCOME</td><td>2,006,889</td><td>1,354,999</td><td>1,301,181</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>64,802</td><td>66,053</td><td>92,759</td></tr><tr><td>Interest and investment income</td><td>147,686</td><td>199,300</td><td>127,776</td></tr><tr><td>Miscellaneous - net</td><td>(42,016)</td><td>(59,762)</td><td>(53,214)</td></tr><tr><td>TOTAL</td><td>170,472</td><td>205,591</td><td>167,321</td></tr><tr><td>INTEREST EXPENSE</td><td></td><td></td><td></td></tr><tr><td>Interest expense</td><td>661,083</td><td>629,537</td><td>606,596</td></tr><tr><td>Allowance for borrowed funds used during construction</td><td>(33,576)</td><td>(25,500)</td><td>(37,312)</td></tr><tr><td>TOTAL</td><td>627,507</td><td>604,037</td><td>569,284</td></tr><tr><td>INCOME BEFORE INCOME TAXES</td><td>1,549,854</td><td>956,553</td><td>899,218</td></tr><tr><td>Income taxes</td><td>589,597</td><td>225,981</td><td>30,855</td></tr><tr><td>CONSOLIDATED NET INCOME</td><td>960,257</td><td>730,572</td><td>868,363</td></tr><tr><td>Preferred dividend requirements of subsidiaries</td><td>19,536</td><td>18,670</td><td>21,690</td></tr><tr><td>NET INCOME ATTRIBUTABLE TO ENERGY CORPORATION</td><td>$940,721</td><td>$711,902</td><td>$846,673</td></tr><tr><td>Earnings per average common share:</td><td></td><td></td><td></td></tr><tr><td>Basic</td><td>$5.24</td><td>$3.99</td><td>$4.77</td></tr><tr><td>Diluted</td><td>$5.22</td><td>$3.99</td><td>$4.76</td></tr><tr><td>Basic average number of common shares outstanding</td><td>179,506,151</td><td>178,211,192</td><td>177,324,813</td></tr><tr><td>Diluted average number of common shares outstanding</td><td>180,296,885</td><td>178,570,400</td><td>177,737,565</td></tr></table>

See Notes to Financial Statements.



## ENTERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

<table><tr><td rowspan="3"></td><td colspan="3">For the Years Ended December 31,</td></tr><tr><td>2014</td><td>2013</td><td>2012</td></tr><tr><td colspan="3">(In Thousands)</td></tr><tr><td>Net Income</td><td>$960,257</td><td>$730,572</td><td>$868,363</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 $96,141, ($87,940), and ($55,750))</td><td>179,895</td><td>(161,682)</td><td>(97,591)</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 ($152,763), $220,899, and ($61,223))</td><td>(281,566)</td><td>302,489</td><td>(91,157)</td></tr><tr><td>Net unrealized investment gains</td><td></td><td></td><td></td></tr><tr><td>(net of tax expense of $66,594, $118,878, and $61,104)</td><td>89,439</td><td>122,709</td><td>63,609</td></tr><tr><td>Foreign currency translation</td><td></td><td></td><td></td></tr><tr><td>(net of tax expense (benefit) of ($404), $131, and $275)</td><td>(751)</td><td>243</td><td>508</td></tr><tr><td>Other comprehensive income (loss)</td><td>(12,983)</td><td>263,759</td><td>(124,631)</td></tr><tr><td>Comprehensive Income</td><td>947,274</td><td>994,331</td><td>743,732</td></tr><tr><td>Preferred dividend requirements of subsidiaries</td><td>19,536</td><td>18,670</td><td>21,690</td></tr><tr><td>Comprehensive Income Attributable to Entergy Corporation</td><td>$927,738</td><td>$975,661</td><td>$722,042</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>2014</td><td>2013</td><td>2012</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</td><td>$960,257</td><td>$730,572</td><td>$868,363</td></tr><tr><td>Adjustments to reconcile consolidated net income 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>2,127,892</td><td>2,012,076</td><td>1,771,649</td></tr><tr><td>Deferred income taxes, investment tax credits, and non-current taxes accrued</td><td>596,935</td><td>311,789</td><td>(26,479)</td></tr><tr><td>Asset write-offs, impairments and related charges</td><td>123,527</td><td>341,537</td><td>355,524</td></tr><tr><td>Gain on sale of business</td><td>—</td><td>(43,569)</td><td>—</td></tr><tr><td>Changes in working capital:</td><td></td><td></td><td></td></tr><tr><td>Receivables</td><td>98,493</td><td>(180,648)</td><td>(14,202)</td></tr><tr><td>Fuel inventory</td><td>3,524</td><td>4,873</td><td>(11,604)</td></tr><tr><td>Accounts payable</td><td>(12,996)</td><td>94,436</td><td>(6,779)</td></tr><tr><td>Prepaid taxes and taxes accrued</td><td>(62,985)</td><td>(142,626)</td><td>55,484</td></tr><tr><td>Interest accrued</td><td>25,013</td><td>(3,667)</td><td>1,152</td></tr><tr><td>Deferred fuel costs</td><td>(70,691)</td><td>(4,824)</td><td>(99,987)</td></tr><tr><td>Other working capital accounts</td><td>112,390</td><td>(66,330)</td><td>(151,989)</td></tr><tr><td>Changes in provisions for estimated losses</td><td>301,871</td><td>(248,205)</td><td>(24,808)</td></tr><tr><td>Changes in other regulatory assets</td><td>(1,061,537)</td><td>1,105,622</td><td>(398,428)</td></tr><tr><td>Changes in other regulatory liabilities</td><td>87,654</td><td>397,341</td><td>170,421</td></tr><tr><td>Changes in pensions and other postretirement liabilities</td><td>1,308,166</td><td>(1,433,663)</td><td>644,099</td></tr><tr><td>Other</td><td>(647,952)</td><td>314,505</td><td>(192,131)</td></tr><tr><td>Net cash flow provided by operating activities</td><td>3,889,561</td><td>3,189,219</td><td>2,940,285</td></tr></table>

<table><tr><td>Construction/capital expenditures</td><td>(2,119,191)</td><td>(2,287,593)</td><td>(2,674,650)</td></tr><tr><td>Allowance for equity funds used during construction</td><td>68,375</td><td>69,689</td><td>96,131</td></tr><tr><td>Nuclear fuel purchases</td><td>(537,548)</td><td>(517,825)</td><td>(557,960)</td></tr><tr><td>Payment for purchase of plant</td><td>—</td><td>(17,300)</td><td>(456,356)</td></tr><tr><td>Proceeds from sale of assets and businesses</td><td>10,100</td><td>147,922</td><td>—</td></tr><tr><td>Insurance proceeds received for property damages</td><td>40,670</td><td>—</td><td>—</td></tr><tr><td>Changes in securitization account</td><td>1,511</td><td>155</td><td>4,265</td></tr><tr><td>NYPA value sharing payment</td><td>(72,000)</td><td>(71,736)</td><td>(72,000)</td></tr><tr><td>Payments to storm reserve escrow account</td><td>(276,057)</td><td>(7,716)</td><td>(8,957)</td></tr><tr><td>Receipts from storm reserve escrow account</td><td>—</td><td>260,279</td><td>27,884</td></tr><tr><td>Decrease (increase) in other investments</td><td>46,983</td><td>(82,955)</td><td>15,175</td></tr><tr><td>Litigation proceeds for reimbursement of spent nuclear fuel storage costs</td><td>—</td><td>21,034</td><td>109,105</td></tr><tr><td>Proceeds from nuclear decommissioning trust fund sales</td><td>1,872,115</td><td>2,031,552</td><td>2,074,055</td></tr><tr><td>Investment in nuclear decommissioning trust funds</td><td>(1,989,446)</td><td>(2,147,099)</td><td>(2,196,489)</td></tr><tr><td>Net cash flow used in investing activities</td><td>(2,954,488)</td><td>(2,601,593)</td><td>(3,639,797)</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>2014</td><td>2013</td><td>2012</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>3,100,069</td><td>3,746,016</td><td>3,478,361</td></tr><tr><td>Preferred stock of subsidiary</td><td>—</td><td>24,249</td><td>—</td></tr><tr><td>Mandatorily redeemable preferred membership units of subsidiary</td><td>—</td><td>—</td><td>51,000</td></tr><tr><td>Treasury stock</td><td>194,866</td><td>24,527</td><td>62,886</td></tr><tr><td>Retirement of long-term debt</td><td>(2,323,313)</td><td>(3,814,666)</td><td>(3,130,233)</td></tr><tr><td>Repurchase of common stock</td><td>(183,271)</td><td>—</td><td>—</td></tr><tr><td>Changes in credit borrowings and commercial paper - net</td><td>(448,475)</td><td>250,889</td><td>687,675</td></tr><tr><td>Other</td><td>23,579</td><td>—</td><td>—</td></tr><tr><td>Dividends paid:</td><td></td><td></td><td></td></tr><tr><td>Common stock</td><td>(596,117)</td><td>(593,037)</td><td>(589,209)</td></tr><tr><td>Preferred stock</td><td>(19,511)</td><td>(18,802)</td><td>(22,329)</td></tr><tr><td>Net cash flow provided by (used in) financing activities</td><td>(252,173)</td><td>(380,824)</td><td>538,151</td></tr><tr><td>Effect of exchange rates on cash and cash equivalents</td><td>—</td><td>(245)</td><td>(508)</td></tr><tr><td>Net increase (decrease) in cash and cash equivalents</td><td>682,900</td><td>206,557</td><td>(161,869)</td></tr><tr><td>Cash and cash equivalents at beginning of period</td><td>739,126</td><td>532,569</td><td>694,438</td></tr><tr><td>Cash and cash equivalents at end of period</td><td>$1,422,026</td><td>$739,126</td><td>$532,569</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>$611,376</td><td>$570,212</td><td>$546,125</td></tr><tr><td>Income taxes</td><td>$77,799</td><td>$127,735</td><td>$49,214</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>2014</td><td>2013</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>$131,327</td><td>$129,979</td></tr><tr><td>Temporary cash investments</td><td>1,290,699</td><td>609,147</td></tr><tr><td>Total cash and cash equivalents</td><td>1,422,026</td><td>739,126</td></tr><tr><td>Accounts receivable:</td><td></td><td></td></tr><tr><td>Customer</td><td>596,917</td><td>670,641</td></tr><tr><td>Allowance for doubtful accounts</td><td>(35,663)</td><td>(34,311)</td></tr><tr><td>Other</td><td>220,342</td><td>195,028</td></tr><tr><td>Accrued unbilled revenues</td><td>321,659</td><td>340,828</td></tr><tr><td>Total accounts receivable</td><td>1,103,255</td><td>1,172,186</td></tr><tr><td>Deferred fuel costs</td><td>155,140</td><td>116,379</td></tr><tr><td>Accumulated deferred income taxes</td><td>27,783</td><td>175,073</td></tr><tr><td>Fuel inventory - at average cost</td><td>205,434</td><td>208,958</td></tr><tr><td>Materials and supplies - at average cost</td><td>918,584</td><td>915,006</td></tr><tr><td>Deferred nuclear refueling outage costs</td><td>214,188</td><td>192,474</td></tr><tr><td>Prepayments and other</td><td>343,223</td><td>410,489</td></tr><tr><td>TOTAL</td><td>4,389,633</td><td>3,929,691</td></tr><tr><td>OTHER PROPERTY AND INVESTMENTS</td><td></td><td></td></tr><tr><td>Investment in affiliates - at equity</td><td>36,234</td><td>40,350</td></tr><tr><td>Decommissioning trust funds</td><td>5,370,932</td><td>4,903,144</td></tr><tr><td>Non-utility property - at cost (less accumulated depreciation)</td><td>213,791</td><td>199,375</td></tr><tr><td>Other</td><td>405,169</td><td>210,616</td></tr><tr><td>TOTAL</td><td>6,026,126</td><td>5,353,485</td></tr><tr><td>PROPERTY, PLANT, AND EQUIPMENT</td><td></td><td></td></tr><tr><td>Electric</td><td>44,881,419</td><td>42,935,712</td></tr><tr><td>Property under capital lease</td><td>945,784</td><td>941,299</td></tr><tr><td>Natural gas</td><td>377,565</td><td>366,365</td></tr><tr><td>Construction work in progress</td><td>1,425,981</td><td>1,514,857</td></tr><tr><td>Nuclear fuel</td><td>1,542,055</td><td>1,566,904</td></tr><tr><td>TOTAL PROPERTY, PLANT AND EQUIPMENT</td><td>49,172,804</td><td>47,325,137</td></tr><tr><td>Less - accumulated depreciation and amortization</td><td>20,449,858</td><td>19,443,493</td></tr><tr><td>PROPERTY, PLANT AND EQUIPMENT - NET</td><td>28,722,946</td><td>27,881,644</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>836,064</td><td>849,718</td></tr><tr><td>Other regulatory assets (includes securitization property of $724,839 as of December 31, 2014 and $822,218 as of December 31, 2013)</td><td>4,968,553</td><td>3,893,363</td></tr><tr><td>Deferred fuel costs</td><td>238,102</td><td>172,202</td></tr><tr><td>Goodwill</td><td>377,172</td><td>377,172</td></tr><tr><td>Accumulated deferred income taxes</td><td>48,351</td><td>62,011</td></tr><tr><td>Other</td><td>920,907</td><td>887,160</td></tr><tr><td>TOTAL</td><td>7,389,149</td><td>6,241,626</td></tr><tr><td>TOTAL ASSETS</td><td>$46,527,854</td><td>$43,406,446</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>2014</td><td>2013</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>$899,375</td><td>$457,095</td></tr><tr><td>Notes payable and commercial paper</td><td>598,407</td><td>1,046,887</td></tr><tr><td>Accounts payable</td><td>1,166,431</td><td>1,173,313</td></tr><tr><td>Customer deposits</td><td>412,166</td><td>370,997</td></tr><tr><td>Taxes accrued</td><td>128,108</td><td>191,093</td></tr><tr><td>Accumulated deferred income taxes</td><td>38,039</td><td>28,307</td></tr><tr><td>Interest accrued</td><td>206,010</td><td>180,997</td></tr><tr><td>Deferred fuel costs</td><td>91,602</td><td>57,631</td></tr><tr><td>Obligations under capital leases</td><td>2,508</td><td>2,323</td></tr><tr><td>Pension and other postretirement liabilities</td><td>57,994</td><td>67,419</td></tr><tr><td>Other</td><td>248,251</td><td>484,510</td></tr><tr><td>TOTAL</td><td>3,848,891</td><td>4,060,572</td></tr><tr><td>NON-CURRENT LIABILITIES</td><td></td><td></td></tr><tr><td>Accumulated deferred income taxes and taxes accrued</td><td>9,133,161</td><td>8,724,635</td></tr><tr><td>Accumulated deferred investment tax credits</td><td>247,521</td><td>263,765</td></tr><tr><td>Obligations under capital leases</td><td>29,710</td><td>32,218</td></tr><tr><td>Other regulatory liabilities</td><td>1,383,609</td><td>1,295,955</td></tr><tr><td>Decommissioning and asset retirement cost liabilities</td><td>4,458,296</td><td>3,933,416</td></tr><tr><td>Accumulated provisions</td><td>418,128</td><td>115,139</td></tr><tr><td>Pension and other postretirement liabilities</td><td>3,638,295</td><td>2,320,704</td></tr><tr><td>Long-term debt (includes securitization bonds of $784,862 as of December 31, 2014 and $883,013 as of December 31, 2013)</td><td>12,500,109</td><td>12,139,149</td></tr><tr><td>Other</td><td>557,649</td><td>583,667</td></tr><tr><td>TOTAL</td><td>32,366,478</td><td>29,408,648</td></tr><tr><td>Commitments and Contingencies</td><td></td><td></td></tr><tr><td>Subsidiaries&#x27; preferred stock without sinking fund</td><td>210,760</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 2014 and in 2013</td><td>2,548</td><td>2,548</td></tr><tr><td>Paid-in capital</td><td>5,375,353</td><td>5,368,131</td></tr><tr><td>Retained earnings</td><td>10,169,657</td><td>9,825,053</td></tr><tr><td>Accumulated other comprehensive loss</td><td>(42,307)</td><td>(29,324)</td></tr><tr><td>Less - treasury stock, at cost (75,512,079 shares in 2014 and 76,381,936 shares in 2013)</td><td>5,497,526</td><td>5,533,942</td></tr><tr><td>Total common shareholders&#x27; equity</td><td>10,007,725</td><td>9,632,466</td></tr><tr><td>Subsidiaries&#x27; preferred stock without sinking fund</td><td>94,000</td><td>94,000</td></tr><tr><td>TOTAL</td><td>10,101,725</td><td>9,726,466</td></tr><tr><td>TOTAL LIABILITIES AND EQUITY</td><td>$46,527,854</td><td>$43,406,446</td></tr></table>

See Notes to Financial Statements.



## ENTERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
For the Years Ended December 31, 2014, 2013, and 2012

<table><tr><td rowspan="2"></td><td rowspan="2">Subsidiaries&#x27; Preferred Stock</td><td colspan="6">Common Shareholders&#x27; Equity</td></tr><tr><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>Balance at December 31, 2011</td><td>$94,000</td><td>$2,548</td><td>($5,680,468)</td><td>$5,360,682</td><td>$9,446,960</td><td>($168,452)</td><td>$9,055,270</td></tr><tr><td>Consolidated net income (a)</td><td>21,690</td><td>—</td><td>—</td><td>—</td><td>846,673</td><td>—</td><td>868,363</td></tr><tr><td>Other comprehensive loss</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>(124,631)</td><td>(124,631)</td></tr><tr><td>Common stock issuances related to stock plans</td><td>—</td><td>—</td><td>105,649</td><td>(2,830)</td><td>—</td><td>—</td><td>102,819</td></tr><tr><td>Common stock dividends declared</td><td>—</td><td>—</td><td>—</td><td>—</td><td>(589,042)</td><td>—</td><td>(589,042)</td></tr><tr><td>Preferred dividend requirements of subsidiaries (a)</td><td>(21,690)</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>(21,690)</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></table>

See Notes to Financial Statements.

(a) Consolidated net income and preferred dividend requirements of subsidiaries for 2014, 2013, and 2012 include $12.9 million, $12 million, and $15 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 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 Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, and Entergy Texas generate, transmit, and distribute electric power primarily to retail customers in Arkansas, Louisiana, Louisiana, Mississippi, and Texas, respectively. Entergy Gulf States Louisiana also distributes natural gas to retail customers in and around Baton Rouge, Louisiana. Entergy New Orleans sells both electric power and natural gas to retail customers in the City of New Orleans, except for Algiers, where Entergy Louisiana is the electric power supplier. The Entergy Wholesale Commodities segment derives almost all of its revenue from sales of electric power generated by plants owned by subsidiaries in that segment.

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

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

Entergy’s Utility operating companies’ rate schedules include either fuel adjustment clauses or fixed fuel factors, which allow either current recovery in billings to customers or deferral of fuel costs until the costs are billed to customers. Where the fuel component of revenues is billed based on a pre-determined fuel cost (fixed fuel factor), 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, 2014 and 2013, is shown below:

<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>



<table><tr><td>2013</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>$9,667</td><td>$6,601</td><td>$3,066</td><td>$—</td></tr><tr><td>Other</td><td>2,836</td><td>2,465</td><td>371</td><td>—</td></tr><tr><td>Transmission</td><td>3,929</td><td>3,894</td><td>35</td><td>—</td></tr><tr><td>Distribution</td><td>6,716</td><td>6,716</td><td>—</td><td>—</td></tr><tr><td>Other</td><td>1,652</td><td>1,475</td><td>174</td><td>3</td></tr><tr><td>Construction work in progress</td><td>1,515</td><td>1,217</td><td>298</td><td>—</td></tr><tr><td>Nuclear fuel</td><td>1,567</td><td>855</td><td>712</td><td>—</td></tr><tr><td>Property, plant, and equipment - net</td><td>$27,882</td><td>$23,223</td><td>$4,656</td><td>$3</td></tr></table>

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

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

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

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

## Jointly-Owned Generating Stations

Certain Entergy subsidiaries jointly own electric generating facilities with affiliates or third parties. The investments and expenses associated with these generating stations are recorded by the Entergy subsidiaries to the extent of their respective undivided ownership interests. As of December 31, 2014, 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 (In Millions)</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>Independence</td><td>Unit 1</td><td>Coal</td><td>839</td><td>31.50%</td><td>$129</td></tr><tr><td></td><td>Common Facilities</td><td>Coal</td><td></td><td>15.75%</td><td>$34</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>$503</td></tr><tr><td>Ouachita (b)</td><td>Common Facilities</td><td>Gas</td><td></td><td>66.67%</td><td>$169</td></tr><tr><td>Entergy Gulf States</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>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>$261</td></tr><tr><td>Roy S. Nelson</td><td>Unit 6 Common Facilities</td><td>Coal</td><td></td><td>17.70%</td><td>$10</td></tr><tr><td>Big Cajun 2</td><td>Unit 3</td><td>Coal</td><td>594</td><td>24.15%</td><td>$149</td></tr><tr><td>Ouachita (b)</td><td>Common Facilities</td><td>Gas</td><td></td><td>33.33%</td><td>$87</td></tr><tr><td>Entergy Louisiana -</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Acadia</td><td>Common Facilities</td><td>Gas</td><td></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>$251</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>$188</td></tr><tr><td>Roy S. Nelson</td><td>Unit 6 Common Facilities</td><td>Coal</td><td></td><td>13.07%</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>$112</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>$4,819</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>$69</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>10.9%</td><td>$107</td></tr><tr><td>Roy S. Nelson</td><td>Unit 6 Common Facilities</td><td>Coal</td><td></td><td>4.79%</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 Gulf States 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.

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 per Share

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

For the Years Ended December 31,

<table><tr><td></td><td>2014</td><td colspan="2">2013</td><td colspan="2">2012</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 attributable to Entergy Corporation</td><td>$940.7</td><td colspan="2">$711.9</td><td colspan="2">$846.7</td></tr><tr><td>Basic earnings per average common share</td><td>179.5</td><td>$5.24</td><td>178.2</td><td>$3.99</td><td>177.3</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>0.3</td><td>(0.01)</td><td>0.1</td><td>—</td><td>0.3</td></tr><tr><td>Other equity plans</td><td>0.5</td><td>(0.01)</td><td>0.3</td><td>—</td><td>0.1</td></tr><tr><td>Diluted earnings per average common shares</td><td>180.3</td><td>$5.22</td><td>178.6</td><td>$3.99</td><td>177.7</td></tr></table>

The calculation of diluted earnings per share excluded 5,743,013 options outstanding at December 31, 2014, 8,866,542 options outstanding at December 31, 2013, and 7,164,319 options outstanding at December 31, 2012 that could potentially dilute basic earnings per share in the future. Those options were not included in the calculation of diluted earnings per share because the exercise price of those options exceeded the average market price for the year.

## Stock-based Compensation Plans

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

## 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 Gulf States Louisiana does not apply regulatory accounting standards to the Louisiana retail deregulated portion of River Bend, the 30% interest in River Bend formerly owned by Cajun, and its steam business, 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 Gulf States Louisiana to sell the electricity from the deregulated assets to Louisiana retail customers at 4.6 cents per kWh or off-system at higher prices, with certain provisions for sharing incremental revenue above 4.6 cents per kWh between customers and shareholders.

## 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 Gulf States Louisiana has recorded an offsetting amount in other deferred credits for the unrealized gains/(losses). Decommissioning trust funds for Pilgrim, Indian Point 2, Vermont Yankee, and Palisades do not meet the criteria for regulatory accounting treatment. Accordingly, unrealized gains recorded on the assets in these trust funds are recognized in the accumulated other comprehensive income component of equity because these assets are classified as available for sale. Unrealized losses (where cost exceeds fair market value) on the assets in these trust funds are also recorded in the accumulated other comprehensive income component of equity unless the unrealized loss is other than temporary and therefore recorded in earnings. The assessment of whether an investment in a debt security has suffered an other-than-temporary impairment is based on whether Entergy has the intent to sell or more likely than not will be required to sell the debt security before recovery of its amortized costs. Further, if Entergy does not expect to recover the entire amortized cost basis of the debt security, an other-than-temporary impairment is considered to have occurred and it is measured by the present value of cash flows expected to be collected less the amortized cost basis (credit loss). The assessment of whether an investment in an equity security has suffered an other-than-temporary impairment is based on a number of factors including, first, whether Entergy has the ability and intent to hold the investment to recover its value, the duration and severity of any losses, and, then, whether it is expected that the investment will recover its value within a reasonable period of time. Entergy’s trusts are managed by third parties who operate in accordance with



agreements that define investment guidelines and place restrictions on the purchases and sales of investments. See Note 17 to the financial statements for details on the decommissioning trust funds.

## 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 sales criteria. The changes in the fair value of recognized derivatives are recorded each period in current earnings or other comprehensive income, depending on whether a derivative is designated as part of a hedge transaction and the type of hedge transaction. Due to regulatory treatment, an offsetting regulatory asset or liability is recorded for changes in fair value of recognized derivatives for the Registrant Subsidiaries.

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

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

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

## Fair Values

The estimated fair values of Entergy’s financial instruments and derivatives are determined using bid prices, market quotes, and financial modeling. Considerable judgment is required in developing the estimates of fair value. Therefore, estimates are not necessarily indicative of the amounts that Entergy could realize in a current market exchange. Gains or losses realized on financial instruments held by regulated businesses may be reflected in future rates and therefore do not accrue to the benefit or detriment of stockholders. Entergy considers the carrying



amounts of most financial instruments classified as current assets and liabilities to be a reasonable estimate of their fair value because of the short maturity of these instruments. See Note 16 to the financial statements for further discussion of fair value.

## 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 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. On September 28, 2013, Indian Point 2 reached the expiration date of its original NRC operating license and entered into the period of extended operation under the timely renewal rule. In December 2015, Indian Point 3 will reach the expiration date of its original NRC operations license and, similarly, will enter the period of extended operation under the timely renewal rule if its license is not renewed before then. If the NRC does not renew the operating license for either of these plants, the plant’s operating life could be shortened, reducing its projected net cash flows and potentially impairing its value as an asset.

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

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

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



probability-weighted undiscounted net cash flows expected to be generated by the plant and related assets. Projected net cash flows primarily depend on the status of the pending legal and state regulatory matters, as well as projections of future revenues and expenses over the remaining life of the plant. Prior to the first quarter 2012, the probability-weighted undiscounted net cash flows exceeded the carrying value of the Vermont Yankee plant and related assets. The decline, however, in the overall energy market and the projected forward prices of power as of March 31, 2012, which are significant inputs in the determination of net cash flows, resulted in the probability-weighted undiscounted future cash flows being less than the asset group's carrying value. 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 at March 31, 2012 was $162 million, while the carrying value was $517.5 million. Therefore, the assets were written down to their fair value and an impairment charge of $355.5 million ($223.5 million after-tax) was recognized. The impairment charge was recorded as a separate line item in Entergy's consolidated statement of income for 2012, and is included within the results of the Entergy Wholesale Commodities segment.

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

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

<table><tr><td>Significant Unobservable Inputs</td><td>Range</td><td>Weighted Average</td></tr><tr><td>Weighted average cost of capital</td><td>7.5%-8.0%</td><td>7.8%</td></tr><tr><td>Long-term pre-tax operating margin (cash basis)</td><td>6.1%-7.8%</td><td>7.2%</td></tr></table>

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

As a result of the decision to shut down the plant, Entergy recognized non-cash impairment and other related charges of $291.5 million ($183.7 million after-tax) during the third quarter 2013 to write down the carrying value of Vermont Yankee and related assets to their fair values. Entergy performed a fair value analysis based on the income approach, a discounted cash flow method, to determine the amount of impairment. The estimated fair value of the plant and related assets was $62 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. Impairment and other related charges were recorded as a separate line item in Entergy's consolidated statements of income for 2013 and this impairment charge is included within the results of the Entergy Wholesale Commodities segment.

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



used significant observable inputs, including quoted forward power and gas prices, where available. Significant unobservable inputs, such as projected long-term pre-tax operating margins (cash basis), and estimated weighted average costs of capital were also used in the estimation of fair value. In addition, Entergy made certain assumptions regarding future tax deductions associated with the plant and related assets. Based on the use of significant unobservable inputs, the fair value measurement for the entirety of the asset group, and for each type of asset within the asset group, is classified as Level 3 in the fair value hierarchy discussed in Note 16 to the financial statements.

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

<table><tr><td>Significant Unobservable Inputs</td><td>Amount</td></tr><tr><td>Weighted average cost of capital</td><td>7.5%</td></tr><tr><td>Long-term pre-tax operating margin (cash basis)</td><td>7.0%</td></tr></table>

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

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

In addition to the $101.6 million impairment charge in September 2014 and depreciation recorded on the remaining plant balance in 2014, Entergy also recorded charges of $45.8 million related to severance and employee retention costs in 2014 relating to the shutdown of Vermont Yankee.

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

## 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 Gulf States Louisiana on a net-of-tax basis during the construction of River Bend and what the AFUDC would have been on a pre-tax basis. The imputed amount was only calculated on that portion of River Bend that the LPSC allowed in rate base and is being amortized through August 2025.

## 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 Gulf States Louisiana) are included in regulatory assets and are being amortized over the life of the related new issuances, or over the life of the original debt issuance if the debt is not refinanced, in accordance with ratemaking treatment.



## 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 Gulf States Louisiana and Entergy Louisiana, both organized as limited liability companies, have outstanding preferred securities with similar protective rights with respect to unpaid dividends, but provide for the election of board members that would not constitute a majority of the board; and their preferred securities are therefore classified for all periods presented as a component of members' equity.

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

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

In May 2014 the FASB issued ASU No. 2014-09, “Revenue from Contracts with Customers (Topic 606).” The ASU’s core principle is that “an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services.” The ASU details a five-step model that should be followed to achieve the



core principle. ASU 2014-09 is effective for Entergy for the first quarter 2017. Entergy does not expect ASU 2014-09 to affect materially its results of operations, financial position, or cash flows.

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

## 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 and the Registrant Subsidiaries’ balance sheets as of December 31, 2014 and 2013:

## Other Regulatory Assets

Entergy

<table><tr><td></td><td>2014</td><td>2013</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>$2,798.8</td><td>$1,723.1</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)</td><td>736.2</td><td>786.8</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>513.8</td><td>447.6</td></tr><tr><td>Removal costs - recovered through depreciation rates (Note 9) (a)</td><td>245.1</td><td>188.9</td></tr><tr><td>Little Gypsy costs - recovered through securitization (Note 5 - Entergy Louisiana Securitization Bonds - Little Gypsy)</td><td>139.2</td><td>160.6</td></tr><tr><td>Under-recovered retail rate revenues - recovered through rate riders when rates are redetermined periodically</td><td>79.6</td><td>77.7</td></tr><tr><td>Unamortized loss on reacquired debt - recovered over term of debt</td><td>76.2</td><td>83.0</td></tr><tr><td>MISO implementation costs - recovery through retail rate riders (Note 2 - Retail Rate Proceedings)</td><td>69.6</td><td>74.7</td></tr><tr><td>Transition to competition costs - recovered over a 15-year period through February 2021</td><td>66.2</td><td>74.4</td></tr><tr><td>New nuclear generation development costs (Note 2 - New Nuclear Generation Development Costs) (b)</td><td>58.4</td><td>115.2</td></tr><tr><td>Human capital management costs - recovery through retail rate mechanisms (Note 2 - Retail Rate Proceedings)</td><td>42.3</td><td>45.0</td></tr><tr><td>Other</td><td>143.2</td><td>116.4</td></tr><tr><td>Entergy Total</td><td>$4,968.6</td><td>$3,893.4</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>2014</td><td>2013</td></tr><tr><td>Unrealized gains on nuclear decommissioning trust funds (Note 17) (a)</td><td>$656.7</td><td>$529.6</td></tr><tr><td>Vidalia purchased power agreement (Note 8)</td><td>242.8</td><td>263.1</td></tr><tr><td>Louisiana Act 55 financing savings obligation (Note 2)</td><td>156.0</td><td>156.0</td></tr><tr><td>Removal costs - returned to customers through depreciation rates (Note 9) (a)</td><td>82.7</td><td>72.3</td></tr><tr><td>Grand Gulf sale-leaseback - (Note 10 - Sale and Leaseback Transactions)</td><td>79.5</td><td>92.3</td></tr><tr><td>Entergy Mississippi&#x27;s accumulated accelerated Grand Gulf amortization - amortized and credited through the UPSA</td><td>53.6</td><td>60.7</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>Asset retirement obligation - will be returned to customers dependent upon timing of decommissioning (Note 9) (a)</td><td>27.7</td><td>31.5</td></tr><tr><td>Other</td><td>40.2</td><td>46.1</td></tr><tr><td>Entergy Total</td><td>$1,383.6</td><td>$1,296.0</td></tr></table>

(a) Offset by related asset.

## Fuel and purchased power cost recovery

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

<table><tr><td></td><td>2014</td><td>2013</td></tr><tr><td></td><td>(In Millions)</td><td></td></tr><tr><td>Entergy Arkansas (a)</td><td>$209.2</td><td>$68.7</td></tr><tr><td>Entergy Gulf States Louisiana (b)</td><td>$89.5</td><td>$109.7</td></tr><tr><td>Entergy Louisiana (b)</td><td>$17.6</td><td>$37.6</td></tr><tr><td>Entergy Mississippi</td><td>($2.2)</td><td>$38.1</td></tr><tr><td>Entergy New Orleans (b)</td><td>($24.3)</td><td>($19.1)</td></tr><tr><td>Entergy Texas</td><td>$11.9</td><td>($4.1)</td></tr></table>

(a) 2014 includes $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) 2014 and 2013 include $100.1 million for Entergy Gulf States Louisiana, $68 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.

## 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 has since resolved litigation with the railroad regarding the delivery problems. The APSC staff was directed to perform an analysis with Entergy Arkansas’s assistance to determine the additional fuel and purchased energy costs associated with these findings and file the analysis within sixty days of the order. After a final determination of the costs is made by the APSC, Entergy Arkansas will be directed to refund that amount with interest to its customers as a credit on the energy cost recovery rider. Entergy Arkansas requested rehearing of the order.

In February 2010 the APSC denied Entergy Arkansas’s request for rehearing, and held a hearing in September 2010 to determine the amount of damages, if any, that should be assessed against Entergy Arkansas. A



decision is pending. Entergy Arkansas expects the amount of damages, if any, to have an immaterial effect on its results of operations, financial position, or cash flows.

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

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

## Entergy Gulf States Louisiana and Entergy Louisiana

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

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

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

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

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



## Entergy Mississippi

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.

## 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. The District Court’s ruling on the motion for judgment on the pleadings is pending.

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

## Entergy New Orleans

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 December 2011, Entergy Texas filed with the PUCT a request to refund approximately $43 million, including interest, of fuel cost recovery over-collections through October 2011. Entergy Texas and the parties to the proceeding reached an agreement that Entergy Texas would refund $67 million, including interest and additional over-recoveries through December 2011, over a three-month period. Entergy Texas and the parties requested that interim rates consistent with the settlement be approved effective with the March 2012 billing month, and the PUCT approved the application in March 2012. Entergy Texas completed this refund to customers in May 2012.

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. All parties agreed that this case should be bifurcated such that the interim refunds would become final in a separate docket. The current docket would remain in place to potentially address additional rough production cost equalization-related matters that are not part of the interim refunds discussed above. In January 2015, Entergy Texas filed a request for this severance and final approval of the interim refund. Both applications are pending.



At the PUCT’s 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

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 allows Entergy Arkansas to amortize its human capital management costs over a three-and-a-half year period, but also orders 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 will be addressed in Entergy Arkansas's next 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 are effective for all bills rendered after December 31, 2013 and were implemented in the first billing cycle of October 2014.

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

## Filings with the LPSC

## Retail Rates - Electric

## (Entergy Gulf States Louisiana)

In November 2011 the LPSC approved a one-year extension of Entergy Gulf States Louisiana’s formula rate plan. In May 2012, Entergy Gulf States Louisiana made its formula rate plan filing with the LPSC for the 2011 test year. The filing reflected an 11.94% earned return on common equity, which was above the earnings bandwidth and indicated a $6.5 million cost of service rate decrease was necessary under the formula rate plan. The filing also reflected a $22.9 million rate decrease for the incremental capacity rider. Subsequently, in August 2012, Entergy Gulf States Louisiana submitted a revised filing that reflected an earned return on common equity of 11.86%, which indicated a $5.7 million cost of service rate decrease was necessary under the formula rate plan. The revised filing also indicated that a reduction of $20.3 million should be reflected in the incremental capacity rider. The rate reductions were implemented, subject to refund, effective for bills rendered in the first billing cycle of September 2012. Subsequently, in December 2012, Entergy Gulf States Louisiana submitted a revised evaluation report that reflected expected retail jurisdictional cost of $17 million for the first-year capacity charges for the purchase from Entergy Louisiana of one-third of Acadia Unit 2 capacity and energy. This rate change was implemented effective



with the first billing cycle of January 2013. The 2011 test year filings, as revised, were approved by the LPSC in February 2013. In April 2013, Entergy Gulf States Louisiana submitted a revised evaluation report increasing the incremental capacity rider by approximately $7.3 million to reflect the cost of an additional capacity contract.

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



## (Entergy Louisiana)

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.

With completion of the Waterford 3 replacement steam generator project, the LPSC is conducting a prudence review in connection with a filing made by Entergy Louisiana in April 2013 with regard to the following aspects of the replacement project: 1) project management; 2) cost controls; 3) success in achieving stated objectives; 4) the costs of the replacement project; and 5) the outage length and replacement power costs. In July 2014 the LPSC Staff filed testimony recommending potential project and replacement power cost disallowances of up to $71 million, citing a need for further explanation or documentation from Entergy Louisiana. An intervenor filed testimony recommending disallowance of $141 million of incremental project costs, claiming the steam generator fabricator was imprudent. Entergy Louisiana provided further documentation and explanation requested by the LPSC staff. An evidentiary hearing was held in December 2014. At the hearing the parties maintained the positions reflected in pre-filed testimony. A post-hearing briefing schedule has not been established. Entergy Louisiana believes that the replacement steam 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 associated with the resolution of the prudence review.

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 provides for a 10 million rate increase effective with the first billing cycle of December 2014. Major terms of the settlement include 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.

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

## Retail Rates - Gas (Entergy Gulf States Louisiana)

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

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 percent annually; annual filings comparing actual versus planned rider spending with actual spending and explanation of variances exceeding ten percent; and an annual true-up. The joint settlement was approved by the LPSC in January 2015. Implementation of the infrastructure rider will commence with bills rendered on and after the first billing cycle of April 2015.

In January 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 results in a $706 thousand rate increase. The rate increase, if approved, will be implemented effective with the first billing cycle of April 2015.

## Filings with the MPSC (Entergy Mississippi)

## Formula Rate Plan Filings

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

In March 2012, Entergy Mississippi submitted its formula rate plan filing for the 2011 test year. The filing shows an earned return on common equity of 10.92% for the test year, which is within the earnings bandwidth and results in no change in rates. In February 2013 the MPSC approved a joint stipulation between Entergy Mississippi and the Mississippi Public Utilities Staff that provided for no change in rates.



In March 2013, Entergy Mississippi submitted its formula rate plan filing for the 2012 test year. The filing requested a $36.3 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)

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 is requesting 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 Ninemile 6 cost recovery interim rider was implemented in December 2014 to collect $915 thousand from Entergy Louisiana customers in the Algiers area.

## (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. Entergy New Orleans is recovering the costs of its power purchase agreement with Entergy Louisiana for 20% of the capacity and energy of the Ninemile Unit 6 generating station, which commenced operation in December 2014, through a special Ninemile Unit 6 rider.



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 Entergy 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 Entergy 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 Entergy 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.

## 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 have also filed motions for rehearing of the PUCT’s order. The PUCT subsequently denied rehearing of substantive issues. Several parties, including Entergy Texas, have appealed the PUCT’s order to the Travis County District Court. A hearing 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 appealed the Travis County District Court decision and the PUCT appealed the decision on the line-loss factor issue. Entergy Texas expects to file briefs during the first half of 2015.



In September 2013, Entergy Texas filed a rate case requesting a $38.6 million base rate increase reflecting a 10.4% return on common equity based on an adjusted test year ending March 31, 2013. The rate case also proposed (1) a rough production cost equalization adjustment rider recovering Entergy Texas's payment to Entergy New Orleans to achieve rough production cost equalization based on calendar year 2012 production costs and (2) a rate case expense rider recovering the cost of the 2013 rate case and certain costs associated with previous rate cases. The rate case filing also 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, 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.

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

## Entergy Louisiana and Entergy Gulf States Louisiana Business Combination

In June 2014, Entergy Louisiana and Entergy Gulf States Louisiana filed a business combination study report with the LPSC. The report contained a preliminary analysis of the potential combination of Entergy Louisiana and Entergy Gulf States Louisiana into a single public utility, including an overview of the combination that identified its potential customer benefits. Although not part of the business combination, Entergy Louisiana provided notice to the City Council in June 2014 that it would seek authorization to transfer to Entergy New Orleans the assets that currently support the provision of service to Entergy Louisiana's customers in Algiers. Entergy Louisiana subsequently filed the referenced application with the City Council in October 2014. In the summer of 2014, Entergy Louisiana and Entergy Gulf States Louisiana held technical conferences and face-to-face meetings with LPSC staff and other stakeholders to discuss potential effects of the combination, solicit suggestions and concerns, and identify areas in which additional information might be needed.

On September 30, 2014, Entergy Louisiana and Entergy Gulf States Louisiana filed an application with the LPSC 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.

The combination is subject to regulatory review and approval of the LPSC, the FERC, and the NRC. In June 2014, Entergy submitted an application to the NRC for approval of River Bend and Waterford 3 license transfers as part of the steps to complete the business combination. The combination also could be subject to regulatory review of the City Council if Entergy Louisiana continues to own the assets that currently support



Entergy Louisiana’s customers in Algiers at the time the combination is effectuated. In November 2014, Entergy Louisiana filed an application with the City Council seeking authorization to undertake the combination. The application provides that if the City Council approves the Algiers asset transfer before the business combination occurs, the City Council may not need to issue a public interest finding regarding the combination. In December 2014, Entergy Louisiana and Entergy Gulf States Louisiana filed applications with the FERC requesting authorization for the business combination and the Algiers asset transfer. In January 2015, Entergy Services filed an application with the FERC for financing authority for the combined company. If approvals are obtained from the LPSC, the FERC, the NRC, and, if required, the City Council, Entergy Louisiana and Entergy Gulf States Louisiana expect the combination will be effected in the second half of 2015.

The procedural schedule in the LPSC business combination proceeding calls for LPSC Staff and intervenor testimony to be filed in March 2015, with a hearing scheduled for June 2015. Entergy Louisiana and Entergy Gulf States Louisiana have requested that the LPSC issue its decision regarding the business combination in August 2015. In the City Council business combination proceeding, the City Council announced through a resolution that it would not initiate an active review of the business combination filing, but instead would establish a business combination docket for the limited purpose of receiving information filings relative to the business combination proceedings at the LPSC.

It is currently contemplated that Entergy Louisiana and Entergy Gulf States Louisiana will undertake multiple steps to effectuate the combination, which steps would include the following:

- Each of Entergy Louisiana and Entergy Gulf States Louisiana will redeem or repurchase all of their respective outstanding preferred membership interests (which interests have a $100 million liquidation value in the case of Entergy Louisiana and $10 million liquidation value in the case of Entergy Gulf States Louisiana).

• Entergy Gulf States Louisiana will convert from a Louisiana limited liability company to a Texas limited liability company.

- Under the Texas Business Organizations Code (TXBOC), Entergy Louisiana will allocate substantially all of its assets to a new subsidiary (New Entergy Louisiana) and New Entergy Louisiana will assume all of the liabilities of Entergy Louisiana, in a transaction regarded as a merger under the TXBOC. Entergy Louisiana will remain in existence and hold the membership interests in New Entergy Louisiana.

- Under the TXBOC, Entergy Gulf States Louisiana will allocate substantially all of its assets to a new subsidiary (New Entergy Gulf States Louisiana) and New Entergy Gulf States Louisiana will assume all of the liabilities of Entergy Gulf States Louisiana, in a transaction regarded as a merger under the TXBOC. Entergy Gulf States Louisiana will remain in existence and hold the membership interests in New Entergy Gulf States Louisiana.

• Entergy Louisiana and Entergy Gulf States Louisiana will contribute the membership interests in New Entergy Louisiana and New Entergy Gulf States Louisiana to an affiliate the common membership interests of which will be owned by Entergy Louisiana, Entergy Gulf States Louisiana and Entergy Corporation.

• New Entergy Gulf States Louisiana will merge into New Entergy Louisiana with New Entergy Louisiana surviving the merger.

Upon the completion of the steps, New Entergy Louisiana will hold substantially all of the assets, and will have assumed all of the liabilities, of Entergy Louisiana and Entergy Gulf States Louisiana. Entergy Louisiana and Entergy Gulf States Louisiana may modify or supplement the steps to be taken to effect the 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 currently serve Entergy Louisiana’s customers in Algiers. The transaction is expected to result in the transfer of net assets of approximately $60 million. The Algiers asset transfer is also subject to regulatory review and approval of the FERC. As discussed previously, Entergy Louisiana also filed an application with the City Council seeking authorization to undertake the Entergy Louisiana and Entergy Gulf States.



Louisiana business combination. The application provides that if the City Council approves the Algiers asset transfer before the business combination occurs, the City Council may not need to issue a public interest finding regarding the business combination. If the necessary approvals are obtained from the City Council and the FERC, Entergy Louisiana expects to transfer the Algiers assets to Entergy New Orleans in the second half of 2015. In November 2014 the City Council approved a resolution establishing a procedural schedule that provides for a hearing on the joint application in late-May 2015, with a decision to be rendered no later than June 2015.

## 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 Gulf States 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 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></td><td>(In Millions)</td></tr><tr><td>Entergy Arkansas</td><td>$156</td></tr><tr><td>Entergy Gulf States Louisiana</td><td>($75)</td></tr><tr><td>Entergy Louisiana</td><td>$—</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 its response to the LPSC petition, the FERC committed to rule on the pending rehearing request before the end of February. 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 currently being held in



abeyance pending resolution of Entergy’s request for rehearing with respect to the FERC’s determinations regarding interest.

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 Gulf States Louisiana</td><td>($10)</td></tr><tr><td>Entergy Louisiana</td><td>$—</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.

## Calendar Year 2014 Production Costs

Based on certain year-to-date information, Entergy preliminarily estimates that no payments and receipts are required in 2015 to implement the FERC’s remedy based on calendar year 2014 production costs. The actual payments/receipts for 2015, based on calendar year 2014 production costs, will not be calculated until the Utility operating companies’ 2014 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.

## 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:

<table><tr><td rowspan="2"></td><td colspan="8">Payments (Receipts)</td></tr><tr><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>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 Gulf States Louisiana</td><td>($120)</td><td>($124)</td><td>($107)</td><td>$—</td><td>($12)</td><td>$—</td><td>$—</td><td>$—</td></tr><tr><td>Entergy Louisiana</td><td>($91)</td><td>($36)</td><td>($140)</td><td>($22)</td><td>$—</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>

Entergy Arkansas is no longer a participant in the System Agreement 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 proposed a rough production cost equalization adjustment rider in its September 2013 rate filing, which is pending. 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. See “2007 Rate Filing Based on Calendar Year 2006 Production Costs” below, however, for a discussion of a FERC decision that could result in trapped costs at Entergy Arkansas related to a contract with AmerenUE.

Entergy Arkansas and, for December 2012 and 2013, Entergy Texas, record accounts payable and Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas record accounts receivable to reflect the rough production cost equalization payments and receipts required to implement the FERC’s remedy. Entergy Arkansas and, for December 2012 and 2013, Entergy Texas, record a corresponding regulatory asset for the right to collect the payments from customers, and Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas record corresponding regulatory liabilities for their obligations to pass the receipts on to customers. The regulatory asset and liabilities are shown as “System Agreement cost equalization” on the respective balance sheets.

## 2007 Rate Filing Based on Calendar Year 2006 Production Costs

Several parties intervened in the 2007 rate proceeding at the FERC, including the APSC, the MPSC, the Council, and the LPSC, which also filed protests. The PUCT also intervened. Intervenor testimony was filed in which the intervenors and also the FERC Staff advocated a number of positions on issues that affect the level of production costs the individual Utility operating companies are permitted to reflect in the bandwidth calculation, including the level of depreciation and decommissioning expense for nuclear facilities. The effect of the various positions would be to reallocate costs among the Utility operating companies. The Utility operating companies filed rebuttal testimony explaining why the bandwidth payments are properly recoverable under the AmerenUE contract, and explaining why the positions of FERC Staff and intervenors on the other issues should be rejected. A hearing in this proceeding concluded in July 2008, and the ALJ issued an initial decision in September 2008. The ALJ’s initial decision concluded, among other things, that: (1) the decisions to not exercise Entergy Arkansas’s option to purchase the Independence plant in 1996 and 1997 were prudent; (2) Entergy Arkansas properly flowed a portion of the bandwidth payments through to AmerenUE in accordance with the wholesale power contract; and (3) the level of nuclear depreciation and decommissioning expense reflected in the bandwidth calculation should be calculated based on NRC-authorized license life, rather than the nuclear depreciation and decommissioning expense authorized by the retail regulators for purposes of retail ratemaking. Following briefing by the parties, the matter was submitted to the FERC for decision. On January 11, 2010, the FERC issued its decision both affirming and overturning certain of the ALJ’s rulings, including overturning the decision on nuclear depreciation and decommissioning expense. The FERC’s conclusion related to the AmerenUE contract does not permit Entergy Arkansas to recover a portion of its bandwidth payment from AmerenUE. The Utility operating companies requested rehearing of that portion of the decision and requested clarification on certain other portions of the decision.

AmerenUE argued that its wholesale power contract with Entergy Arkansas, pursuant to which Entergy Arkansas sells power to AmerenUE, does not permit Entergy Arkansas to flow through to AmerenUE any portion of Entergy Arkansas’s bandwidth payment. The AmerenUE contract expired in August 2009. In April 2008, AmerenUE filed a complaint with the FERC seeking refunds, plus interest, in the event the FERC ultimately determines that bandwidth payments are not properly recovered under the AmerenUE contract. In response to the FERC’s decision discussed in the previous paragraph, Entergy Arkansas recorded a regulatory provision in the fourth quarter 2009 for a potential refund to AmerenUE.

In May 2012, the FERC issued an order on rehearing in the proceeding. The order may result in the reallocation of costs among the Utility operating companies, although there are still FERC decisions pending in other System Agreement proceedings that could affect the rough production cost equalization payments and receipts. The FERC directed Entergy, within 45 days of the issuance of a pending FERC order on rehearing regarding the functionalization of costs in the 2007 rate filing, to file a comprehensive bandwidth recalculation report showing updated payments and receipts in the 2007 rate filing proceeding. The May 2012 FERC order also denied Entergy’s request for rehearing regarding the AmerenUE contract and ordered Entergy Arkansas to refund to AmerenUE the rough production cost equalization payments collected from AmerenUE. Under the terms of the



FERC’s order a refund of $30.6 million, including interest, was made in June 2012. Entergy and the LPSC appealed certain aspects of the FERC’s decisions to the U.S. Court of Appeals for the D.C. Circuit. On December 7, 2012, the D.C. Circuit dismissed Entergy’s petition for review as premature because Entergy filed a rehearing request of the May 2012 FERC order and that rehearing request is still pending. The court also ordered that the LPSC’s appeal be held in abeyance and that the parties file motions to govern further proceedings within 30 days of the FERC’s completion of the ongoing “Entergy bandwidth proceedings.” On October 16, 2013, the FERC issued two orders related to this proceeding. The first order provided clarification with regard to the derivation of the ratio that should be used to functionalize net operating loss carryforwards for purposes of the annual bandwidth filings. The first order required a compliance filing that Entergy made in November 2013. The second order denied Entergy’s request for rehearing of the FERC’s prior determination that interest should be included on recalculated payment and receipt amounts required in this particular proceeding due to the length of time that had passed. Entergy subsequently appealed certain aspects of the FERC’s decisions to the U.S. Court of Appeals for the D.C. Circuit. On January 23, 2014, the D.C. Circuit returned the LPSC’s appeal to the active docket and consolidated it with Entergy’s petition for appellate review. The appeals are pending. In July 2014 the FERC issued an order accepting Entergy Services’ November 2013 compliance filing. The FERC directed Entergy Services to make a comprehensive bandwidth recalculation report by September 15, 2014 showing all the updated payment/receipt amounts based on the 2006 calendar year data in compliance with all bandwidth formula and bandwidth calculation adjustments that the FERC has accepted or ordered for those years. The FERC also directed the Entergy Operating Companies to make any true-up bandwidth payments associated with the 2006 bandwidth recalculation report with interest following the filing of the comprehensive recalculation report. See discussion below regarding the comprehensive bandwidth recalculation and filings made with the FERC in connection with this proceeding.

## 2008 Rate Filing Based on Calendar Year 2007 Production Costs

Several parties intervened in the 2008 rate proceeding at the FERC, including the APSC, the LPSC, and AmerenUE, which also filed protests. Several other parties, including the MPSC and the City Council, intervened in the proceeding without filing a protest. In direct testimony filed in January 2009, certain intervenors and the FERC staff advocated a number of positions on issues that affect the level of production costs the individual Utility operating companies are permitted to reflect in the bandwidth calculation, including the level of depreciation and decommissioning expense for the nuclear and fossil-fueled generating facilities. The effect of these various positions would be to reallocate costs among the Utility operating companies. In addition, three issues were raised alleging imprudence by the Utility operating companies, including whether the Utility operating companies had properly reflected generating units' minimum operating levels for purposes of making unit commitment and dispatch decisions, whether Entergy Arkansas's sales to third parties from its retained share of the Grand Gulf nuclear facility were reasonable, prudent, and non-discriminatory, and whether Entergy Louisiana's long-term Evangeline gas purchase contract was prudent and reasonable.

The parties reached a partial settlement agreement of certain of the issues initially raised in this proceeding. The partial settlement agreement was conditioned on the FERC accepting the agreement without modification or condition, which the FERC did in August 2009. A hearing on the remaining issues in the proceeding was completed in June 2009, and in September 2009 the ALJ issued an initial decision. The initial decision affirms Entergy's position in the filing, except for two issues that may result in a reallocation of costs among the Utility operating companies. In October 2011 the FERC issued an order on the ALJ's initial decision. The FERC's order resulted in a minor reallocation of payments/receipts among the Utility operating companies on one issue in the 2008 rate filing. Entergy made a compliance filing in December 2011 showing the updated payment/receipt amounts. The LPSC filed a protest in response to the compliance filing. In January 2013 the FERC issued an order accepting Entergy's compliance filing. In the January 2013 order the FERC required Entergy to include interest on the recalculated bandwidth payment and receipt amounts for the period from June 1, 2008 until the date of the Entergy intra-system bill that will reflect the bandwidth recalculation amounts for calendar year 2007. In February 2013, Entergy filed a request for rehearing of the FERC's ruling requiring interest. In March 2013 the LPSC filed a petition for review with the U.S. Court of Appeals for the Fifth Circuit seeking appellate review of the FERC's earlier orders addressing the ALJ's initial decision. In July 2014 the FERC issued an order denying Entergy's rehearing request and decided that it is appropriate to allow interest to be paid on the bandwidth recalculation amounts. The FERC also directed Entergy to file a comprehensive bandwidth recalculation



report by September 15, 2014 showing all the updated payment/receipt amounts based on the 2007 calendar year data in compliance with all bandwidth formula and bandwidth calculation adjustments that the FERC has accepted or ordered for that year. The FERC also directed the Entergy Operating Companies to make any true-up bandwidth payments associated with the 2007 bandwidth recalculation report with interest following the filing of the comprehensive recalculation report. In August 2014 the Fifth Circuit issued its opinion dismissing in part and denying in part the LPSC petition for review of the FERC’s order. In December 2014 the LPSC petitioned the U.S. Supreme Court for a writ of certiorari of the Fifth Circuit’s decision. In September 2014, Entergy filed a petition for review with the U.S. Court of Appeals for the D.C. Circuit seeking appellate review of the FERC’s interest determination. See discussion below regarding the comprehensive bandwidth recalculation and filings made with the FERC in connection with this proceeding.

## 2009 Rate Filing Based on Calendar Year 2008 Production Costs

Several parties intervened in the 2009 rate proceeding at the FERC, including the LPSC and Ameren, which also filed protests. In July 2009 the FERC accepted Entergy's proposed rates for filing, effective June 1, 2009, subject to refund, and set the proceeding for hearing and settlement procedures. Settlement procedures were terminated and a hearing before the ALJ was held in April 2010. In August 2010 the ALJ issued an initial decision. The initial decision substantially affirms Entergy's position in the filing, except for one issue that may result in some reallocation of costs among the Utility operating companies. The LPSC, the FERC trial staff, and Entergy submitted briefs on exceptions in the proceeding. In May 2012 the FERC issued an order affirming the ALJ's initial decision, or finding certain issues in that decision moot. Rehearing and clarification of FERC's order have been requested. In January 2013 the LPSC filed a protest of Entergy's July 2012 compliance filing submitted in response to the FERC's May 2012 order. In October 2013 the FERC issued orders denying the LPSC's rehearing request with respect to the FERC's May 2012 order and addressing Entergy's compliance filing implementing the FERC's directives in the May 2012 order. The compliance filing order referred to guidance provided in a separate order issued on that same day in the 2007 rate proceeding with respect to the ratio used to functionalize net operating loss carryforwards for bandwidth purposes and directed Entergy to make an additional compliance filing in the 2009 rate proceeding consistent with the guidance provided in that order. In November 2013 the LPSC sought rehearing of the FERC's October 2013 order and Entergy submitted its compliance filing implementing the FERC's directives in the October 2013 order. In August 2014, the FERC issued an order accepting the November 2013 compliance filing that was made in response to the FERC's October 2013 order. The LPSC appealed to the U.S. Court of Appeals for the Fifth Circuit the FERC's May 2012 and October 2013 orders. In November 2014 the Fifth Circuit issued its opinion denying the LPSC petition for review of the FERC's order. In December 2014 the LPSC petitioned the U.S. Supreme Court for a writ of certiorari of the Fifth Circuit's decision. See discussion below regarding the comprehensive bandwidth recalculation and filings made with the FERC in connection with this proceeding.

## 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 Gulf States Louisiana</td><td>($22)</td></tr><tr><td>Entergy Louisiana</td><td>($16)</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 updated compliance filings in the 2008 and 2009 rate filing proceedings have not been protested, and one protest was filed at the FERC related to the 2007 rate filing proceeding. The filings are pending at the FERC.

## 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, and the case is pending before the FERC.

## 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. A procedural schedule was adopted in February 2015, and a hearing on the merits is scheduled for November 2015.

## 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. A procedural schedule was adopted in February 2015, and a hearing on the merits is scheduled for November 2015.

## 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. A procedural schedule was adopted in February 2015, and a hearing on the merits is scheduled for November 2015.

## 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. A procedural schedule was adopted in February 2015, and a hearing on the merits is scheduled for November 2015.

## 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. The refunds were made in the fourth quarter 2009.

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.”

## 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 re-run 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, which will effectively amortize the regulatory asset over a five-year period.

## Entergy Gulf States Louisiana and 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 Gulf States Louisiana and Entergy Louisiana drew $65 million and $187 million, respectively, from their funded storm reserve escrow accounts. In April 2013, Entergy Gulf States Louisiana and Entergy Louisiana filed a joint application with the LPSC relating to Hurricane Isaac system restoration costs. Specifically, Entergy Gulf States Louisiana and 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 Gulf States Louisiana requested an LPSC determination that $73.8 million in system restoration costs were prudently incurred and Entergy Louisiana requested an LPSC determination that $247.7 million in system restoration costs were prudently incurred. In May 2013, Entergy Gulf States Louisiana, Entergy Louisiana, and the Louisiana Utilities Restoration Corporation (LURC), an instrumentality of the State of Louisiana, filed with the LPSC an application requesting that the LPSC grant financing orders authorizing the financing of Entergy Gulf States Louisiana’s and Entergy Louisiana’s storm costs, storm reserves, and issuance costs pursuant to Act 55 of the Louisiana Regular Session of 2007 (Louisiana Act 55). The LPSC Staff filed direct testimony in September 2013 concluding that Hurricane Isaac system restoration costs incurred by Entergy Gulf States Louisiana and Entergy Louisiana were reasonable and prudent, subject to proposed minor adjustments which totaled approximately 1% of each 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 (66.5 million for Entergy Gulf States Louisiana and 224.3 million for Entergy Louisiana); (ii) determine the level of storm reserves to be re-established (90 million for Entergy Gulf States Louisiana and 200 million for Entergy Louisiana); (iii) authorize Entergy Gulf States Louisiana and 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 Gulf States Louisiana committed to pass on to customers a minimum of 6.9 million of customer benefits through annual customer credits of approximately 1.4 million for five years. Entergy Louisiana committed to pass on to customers a minimum of 23.9 million of customer benefits through annual customer credits of approximately 4.8 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 Gulf States Louisiana issued $110 million of 3.78% Series first mortgage bonds due April 2025 and used the proceeds to re-establish and replenish its storm damage escrow reserves and for general corporate purposes. In July 2014, Entergy Louisiana issued $190 million of 3.78% Series first mortgage bonds due April 2025 and used the proceeds to re-establish and replenish its storm damage escrow reserves and for general corporate purposes.

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

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

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

## Hurricane Gustav and Hurricane Ike

In September 2008, Hurricane Gustav and Hurricane Ike caused catastrophic damage to Entergy’s service territory. Entergy Gulf States Louisiana and Entergy Louisiana filed their Hurricane Gustav and Hurricane Ike storm cost recovery case with the LPSC in May 2009. In September 2009, Entergy Gulf States Louisiana, Entergy



Louisiana, and the Louisiana Utilities Restoration Corporation (LURC), an instrumentality of the State of Louisiana, filed with the LPSC an application requesting that the LPSC grant financing orders authorizing the financing of Entergy Gulf States Louisiana's and Entergy Louisiana's storm costs, storm reserves, and issuance costs pursuant to Act 55 of the Louisiana Regular Session of 2007 (Act 55). Entergy Gulf States Louisiana's and Entergy Louisiana's Hurricane Katrina and Hurricane Rita storm costs were financed primarily by Act 55 financings, as discussed below. Entergy Gulf States Louisiana and Entergy Louisiana also filed an application requesting LPSC approval for ancillary issues including the mechanism to flow charges and Act 55 financing savings to customers via a Storm Cost Offset rider.

In December 2009, Entergy Gulf States Louisiana and Entergy Louisiana entered into a stipulation agreement with the LPSC Staff that provides for total recoverable costs of approximately $234 million for Entergy Gulf States Louisiana and $394 million for Entergy Louisiana, including carrying costs. Under this stipulation, Entergy Gulf States Louisiana agrees not to recover $4.4 million and Entergy Louisiana agrees not to recover $7.2 million of their storm restoration spending. The stipulation also permits replenishing Entergy Gulf States Louisiana's storm reserve in the amount of $90 million and Entergy Louisiana's storm reserve in the amount of $200 million when the Act 55 financings are accomplished. In March and April 2010, Entergy Gulf States Louisiana, Entergy Louisiana, and other parties to the proceeding filed with the LPSC an uncontested stipulated settlement that includes these terms and also includes Entergy Gulf States Louisiana's and Entergy Louisiana's proposals under the Act 55 financings, which includes a commitment to pass on to customers a minimum of $15.5 million and $27.8 million of customer benefits, respectively, through prospective annual rate reductions of $3.1 million and $5.6 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 two financing orders and one ratemaking order intended to facilitate the implementation of the Act 55 financings. In June 2010 the Louisiana State Bond Commission approved the Act 55 financings.

In July 2010, the Louisiana Local Government Environmental Facilities and Community Development Authority (LCDA) issued $468.9 million in bonds under Act 55. From the $462.4 million of bond proceeds loaned by the LCDA to the LURC, the LURC deposited $200 million in a restricted escrow account as a storm damage reserve for Entergy Louisiana and transferred $262.4 million directly to Entergy Louisiana. From the bond proceeds received by Entergy Louisiana from the LURC, Entergy Louisiana used $262.4 million to acquire 2,624,297.11 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.

In July 2010, the LCDA issued another $244.1 million in bonds under Act 55. From the $240.3 million of bond proceeds loaned by the LCDA to the LURC, the LURC deposited $90 million in a restricted escrow account as a storm damage reserve for Entergy Gulf States Louisiana and transferred $150.3 million directly to Entergy Gulf States Louisiana. From the bond proceeds received by Entergy Gulf States Louisiana from the LURC, Entergy Gulf States Louisiana used $150.3 million to acquire 1,502,643.04 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, Entergy Gulf States Louisiana, and Entergy Louisiana do not report the bonds on their balance sheets because the bonds are the obligation of the LCDA, and there is no recourse against Entergy, Entergy Gulf States Louisiana or Entergy Louisiana in the event of a bond default. To service the bonds, Entergy Gulf States Louisiana and Entergy Louisiana collect a system restoration charge on behalf of the LURC, and remit the



collections to the bond indenture trustee. Entergy Gulf States Louisiana and Entergy Louisiana do not report the collections as revenue because they are merely acting as the billing and collection agents for 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 Gulf States Louisiana, Entergy Louisiana, and the Louisiana Utilities Restoration Corporation (LURC), an instrumentality of the State of Louisiana, filed at the LPSC an application requesting that the LPSC grant financing orders authorizing the financing of Entergy Gulf States Louisiana and Entergy Louisiana storm costs, storm reserves, and issuance costs pursuant to Act 55 of the Louisiana Legislature (Act 55 financings). The Act 55 financings are expected to produce additional customer benefits as compared to traditional securitization. Entergy Gulf States Louisiana and 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 financings, approved requests for the Act 55 financings. On April 10, 2008, Entergy Gulf States Louisiana and Entergy Louisiana and the LPSC Staff filed with the LPSC an uncontested stipulated settlement that includes Entergy Gulf States Louisiana and Entergy Louisiana's proposals under the Act 55 financings, which includes a commitment to pass on to customers a minimum of $10 million and $30 million of customer benefits, respectively, through prospective annual rate reductions of $2 million and $6 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 financings. In May 2008 the Louisiana State Bond Commission granted final approval of the Act 55 financings.

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. 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 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 Gulf States Louisiana and transferred $187.7 million directly to Entergy Gulf States Louisiana. From the bond proceeds received by Entergy Gulf States Louisiana from the LURC, Entergy Gulf States 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 Gulf States 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, Entergy Gulf States Louisiana, 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, Entergy Gulf States Louisiana or Entergy Louisiana in the event of a bond default. To service the bonds, Entergy Gulf States Louisiana and Entergy Louisiana collect a system restoration charge on behalf of the LURC, and remit the collections to the bond indenture trustee. Entergy, Entergy Gulf States Louisiana, and Entergy Louisiana do not report the collections as revenue because they are merely acting as the billing and collection 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.



## New Nuclear Generation Development Costs

## Entergy Gulf States Louisiana and Entergy Louisiana

Entergy Gulf States Louisiana and Entergy Louisiana have been developing and are preserving a project option for new nuclear generation at River Bend. In March 2010, Entergy Gulf States Louisiana and Entergy 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 Gulf States Louisiana and Entergy 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 Gulf States Louisiana and Entergy 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, 2014, Entergy Gulf States Louisiana and Entergy Louisiana each have a regulatory asset of $29.2 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. The Entergy defendants filed responsive briefings, and the parties are awaiting rulings by the Court.

## NOTE 3. INCOME TAXES

Income taxes from continuing operations for 2014, 2013, and 2012 for Entergy Corporation and Subsidiaries consist of the following:

<table><tr><td></td><td>2014</td><td>2013</td><td>2012</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>$90,061</td><td>$88,291</td><td>($47,851)</td></tr><tr><td>Foreign</td><td>90</td><td>101</td><td>143</td></tr><tr><td>State</td><td>(12,637)</td><td>20,584</td><td>(41,516)</td></tr><tr><td>Total</td><td>77,514</td><td>108,976</td><td>(89,224)</td></tr><tr><td>Deferred and non-current - net</td><td>528,326</td><td>126,935</td><td>131,130</td></tr><tr><td>Investment tax credit adjustments - net</td><td>(16,243)</td><td>(9,930)</td><td>(11,051)</td></tr><tr><td>Income tax expense from continuing operations</td><td>$589,597</td><td>$225,981</td><td>$30,855</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 2014, 2013, and 2012 are:

<table><tr><td></td><td>2014</td><td>2013</td><td>2012</td></tr><tr><td></td><td colspan="3">(In Thousands)</td></tr><tr><td>Net income attributable to Entergy Corporation</td><td>$940,721</td><td>$711,902</td><td>$846,673</td></tr><tr><td>Preferred dividend requirements of subsidiaries</td><td>19,536</td><td>18,670</td><td>21,690</td></tr><tr><td>Consolidated net income</td><td>960,257</td><td>730,572</td><td>868,363</td></tr><tr><td>Income taxes</td><td>589,597</td><td>225,981</td><td>30,855</td></tr><tr><td>Income before income taxes</td><td>$1,549,854</td><td>$956,553</td><td>$899,218</td></tr><tr><td>Computed at statutory rate (35%)</td><td>$542,449</td><td>$334,794</td><td>$314,726</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>44,708</td><td>13,599</td><td>40,699</td></tr><tr><td>Regulatory differences - utility plant items</td><td>39,321</td><td>32,324</td><td>35,527</td></tr><tr><td>Equity component of AFUDC</td><td>(21,108)</td><td>(22,356)</td><td>(30,838)</td></tr><tr><td>Amortization of investment tax credits</td><td>(12,211)</td><td>(13,535)</td><td>(14,000)</td></tr><tr><td>Flow-through / permanent differences</td><td>(18,003)</td><td>(301)</td><td>(14,801)</td></tr><tr><td>Net-of-tax regulatory liability</td><td>—</td><td>(2,899)</td><td>(4,356)</td></tr><tr><td>New York tax law change</td><td>(21,500)</td><td>—</td><td>—</td></tr><tr><td>Deferred tax asset on additional depreciation (a)</td><td>—</td><td>—</td><td>(155,300)</td></tr><tr><td>Termination of business reorganization</td><td>—</td><td>(27,192)</td><td>—</td></tr><tr><td>Write-off of regulatory asset for income taxes</td><td>—</td><td>—</td><td>42,159</td></tr><tr><td>Capital losses</td><td>—</td><td>—</td><td>(20,188)</td></tr><tr><td>Provision for uncertain tax positions (b)</td><td>32,573</td><td>(59,249)</td><td>(159,957)</td></tr><tr><td>Valuation allowance</td><td>—</td><td>(31,573)</td><td>—</td></tr><tr><td>Other - net</td><td>3,368</td><td>2,369</td><td>(2,816)</td></tr><tr><td>Total income taxes as reported</td><td>$589,597</td><td>$225,981</td><td>$30,855</td></tr><tr><td>Effective Income Tax Rate</td><td>38.0%</td><td>23.6%</td><td>3.4%</td></tr></table>

(a) See “Income Tax Audits - 2004-2005 IRS Audit” below for discussion of this item.

(b) See “Income Tax Audits - 2008-2009 IRS Audit” below for discussion of the most significant items in 2013 and 2012.

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.



Significant components of accumulated deferred income taxes and taxes accrued for Entergy Corporation and Subsidiaries as of December 31, 2014 and 2013 are as follows:

<table><tr><td></td><td>2014</td><td>2013</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>($8,128,096)</td><td>($7,941,319)</td></tr><tr><td>Regulatory assets</td><td>(922,161)</td><td>(922,312)</td></tr><tr><td>Nuclear decommissioning trusts</td><td>(1,248,737)</td><td>(1,100,439)</td></tr><tr><td>Pension, net funding</td><td>(324,881)</td><td>(299,951)</td></tr><tr><td>Combined unitary state taxes</td><td>(162,340)</td><td>(183,934)</td></tr><tr><td>Power purchase agreements</td><td>(110,889)</td><td>(8,096)</td></tr><tr><td>Other</td><td>(500,424)</td><td>(404,749)</td></tr><tr><td>Total</td><td>(11,397,528)</td><td>(10,860,800)</td></tr><tr><td>Deferred tax assets:</td><td></td><td></td></tr><tr><td>Nuclear decommissioning liabilities</td><td>874,493</td><td>754,828</td></tr><tr><td>Regulatory liabilities</td><td>458,230</td><td>403,370</td></tr><tr><td>Pension and other post-employment benefits</td><td>586,455</td><td>469,190</td></tr><tr><td>Sale and leaseback</td><td>153,308</td><td>176,119</td></tr><tr><td>Compensation</td><td>74,692</td><td>125,552</td></tr><tr><td>Accumulated deferred investment tax credit</td><td>100,442</td><td>106,777</td></tr><tr><td>Provision for allowances and contingencies</td><td>160,551</td><td>66,026</td></tr><tr><td>Net operating loss carryforwards</td><td>457,758</td><td>548,756</td></tr><tr><td>Capital losses and miscellaneous tax credits</td><td>12,146</td><td>13,140</td></tr><tr><td>Valuation allowance</td><td>(27,387)</td><td>(28,146)</td></tr><tr><td>Other</td><td>58,334</td><td>109,606</td></tr><tr><td>Total</td><td>2,909,022</td><td>2,745,218</td></tr><tr><td>Noncurrent accrued taxes (including unrecognized tax benefits)</td><td>(606,560)</td><td>(400,276)</td></tr><tr><td>Accumulated deferred income taxes and taxes accrued</td><td>($9,095,066)</td><td>($8,515,858)</td></tr></table>

Entergy’s estimated tax attributes carryovers and their expiration dates as of December 31, 2014 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>$12.3 billion</td><td>2023-2034</td></tr><tr><td>State net operating losses</td><td>$10.2 billion</td><td>2015-2033</td></tr><tr><td>Miscellaneous federal and state credits</td><td>$97.6 million</td><td>2015-2034</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, a valuation allowance of $21.2 million has been provided on the deferred tax assets relating to these state net operating loss carryovers.

In the third quarter 2013, Entergy reduced a valuation allowance by $44 million ($28 million net of the federal income tax effect) that had been provided on a state net operating loss carryover due to the prospective utilization of such loss carryover.



## 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>2014</td><td>2013</td><td>2012</td></tr><tr><td></td><td colspan="3">(In Thousands)</td></tr><tr><td>Gross balance at January 1</td><td>$4,593,224</td><td>$4,170,403</td><td>$4,387,780</td></tr><tr><td>Additions based on tax positions related to the current year</td><td>348,543</td><td>162,338</td><td>163,612</td></tr><tr><td>Additions for tax positions of prior years</td><td>11,637</td><td>410,108</td><td>1,517,797</td></tr><tr><td>Reductions for tax positions of prior years</td><td>(213,401)</td><td>(103,360)</td><td>(476,873)</td></tr><tr><td>Settlements</td><td>—</td><td>(43,620)</td><td>(1,421,913)</td></tr><tr><td>Lapse of statute of limitations</td><td>(3,218)</td><td>(2,645)</td><td>—</td></tr><tr><td>Gross balance at December 31</td><td>4,736,785</td><td>4,593,224</td><td>4,170,403</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>(4,295,643)</td><td>(4,400,498)</td><td>(4,022,535)</td></tr><tr><td>Unrecognized tax benefits net of unused tax attributes and payments (a)</td><td>$441,142</td><td>$192,726</td><td>$147,868</td></tr></table>

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

The balances of unrecognized tax benefits include $516 million, $176 million, and $203 million as of December 31, 2014, 2013, and 2012, 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 $4.221 billion, $4.417 billion, and $3.968 billion as of December 31, 2014, 2013, and 2012, 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, 2014, 2013, and 2012 accrued balance for the possible payment of interest is approximately $127 million, $96.4 million, and $146.3 million, respectively.

## Income Tax Litigation

In October 2010 the U.S. Tax Court entered a decision in favor of Entergy regarding the ability to credit the U.K. Windfall Tax against U.S. income tax as a foreign tax credit. The U.K. Windfall Tax relates to Entergy’s former investment in London Electricity.

The IRS filed an appeal of the U.K. Windfall Tax decision with the U.S. Court of Appeals for the Fifth Circuit in December 2010. Oral arguments were heard in November 2011. In June 2012 the U.S. Court of Appeals for the Fifth Circuit unanimously affirmed the U.S. Tax Court decision. As a result of this decision, Entergy reversed its liability for uncertain tax positions associated with this issue. On September 4, 2012, the U.S. Solicitor General, on behalf of the Commissioner of Internal Revenue, petitioned the U.S. Supreme Court for a writ of certiorari to review the Fifth Circuit judgment.

Concurrent with the Tax Court’s issuance of a favorable decision regarding the above issues, the Tax Court issued a favorable decision in a separate proceeding, PPL Corp. v. Commissioner, regarding the creditability of the U.K. Windfall Tax. The IRS appealed the PPL decision to the United States Court of Appeals for the Third



Circuit. In December 2011 the Third Circuit reversed the Tax Court’s holding in PPL Corp. v. Commissioner, stating that the U.K. tax was not eligible for the foreign tax credit. PPL Corp. petitioned the U.S. Supreme Court for a writ of certiorari to review the U.S. Court of Appeals for the Third Circuit decision. On October 29, 2012, the U.S. Supreme Court granted PPL Corp.’s petition for certiorari. The Solicitor General’s petition for writ of certiorari in Entergy’s case was held pending the disposition of the PPL case.

On May 20, 2013, the U.S. Supreme Court issued a unanimous decision in PPL’s favor, holding that the U.K. Windfall Tax is a creditable tax for U.S. federal income tax purposes. On May 28, 2013, the Supreme Court denied the petition for certiorari filed by the Commissioner of Internal Revenue in Entergy’s U.K. Windfall Tax case, allowing the decision in Entergy’s favor from the United States Court of Appeals for the Fifth Circuit to become final.

## Income Tax Audits

Entergy and its subsidiaries file U.S. federal and various state and foreign income tax returns. IRS examinations are substantially completed for years before 2009. All state taxing authorities' examinations are completed for years before 2005.

## 2004-2005 IRS Audit

In June 2009, Entergy filed a formal protest with the IRS Appeals Division indicating disagreement with certain issues contained in the 2004-2005 Revenue Agent’s Report (RAR). The most significant issue disputed was the inclusion of nuclear decommissioning liabilities in cost of goods sold for the nuclear power plants owned by the Utility resulting from an Application for Change in Accounting Method for tax purposes (the “2004 CAM”).

During the fourth quarter 2012, Entergy settled the position relating to the 2004 CAM. Under the settlement Entergy conceded its tax position, resulting in an increase in taxable income of approximately $2.97 billion for the tax years 2004 - 2007. The settlement provides that Entergy Louisiana is entitled to additional tax depreciation of approximately $547 million for years 2006 and beyond. The deferred tax asset net of interest charges associated with the settlement is $155 million for Entergy. There was a related increase to Entergy Louisiana’s member’s equity account.

## 2008-2009 IRS Audit

In the third quarter 2008, Entergy Louisiana and Entergy Gulf States Louisiana received $679 million and $274.7 million, respectively, from the Louisiana Utilities Restoration Corporation (“LURC”). These receipts from LURC were from the proceeds of a Louisiana Act 55 financing of the costs incurred to restore service following Hurricane Katrina and Hurricane Rita. See Note 2 to the financial statements for further details regarding the financings.

In June 2012, Entergy effectively settled the tax treatment of the storm restoration, which resulted in an increase to 2008 taxable income of $129 million for Entergy Louisiana and $104 million for Entergy Gulf States Louisiana and a reduction of income tax expense of $172 million, including $143 million for Entergy Louisiana and $20 million for Entergy Gulf States Louisiana. Under the terms of an LPSC-approved settlement related to the Louisiana Act 55 financings, Entergy Louisiana and Entergy Gulf States Louisiana recorded, respectively, a $137 million ($84 million net-of-tax) and a $28 million ($17 million net-of-tax) regulatory charge and a corresponding regulatory liability to reflect their obligations to customers with respect to the settlement.

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 disagrees with the IRS's disallowance of the 2009 CAM and filed a protest with the IRS Appeals Division on October 24, 2013. Two conferences with the Appeals Division have taken place during 2014. The resolution of this issue is in process. The issuance of the RAR by the IRS effectively settled all other issues, which resulted in an adjustment to the provision for uncertain tax positions.

## Other Tax Matters

Entergy regularly negotiates with the IRS to achieve settlements. The resolution of the nuclear decommissioning liability audit issue, discussed above, 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 $548 million, which will be recognized 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 $157 million for Entergy Arkansas, an increase of $42 million for Entergy Gulf States Louisiana, an increase of $49 million for Entergy Louisiana, an increase of $23 million for Entergy Mississippi, an increase of $169 million for Entergy Texas, a decrease of $11 million for Entergy New Orleans, and an increase of $34 million for System Energy.

In March 2013, Entergy Louisiana distributed to its parent, Entergy Louisiana Holdings, Inc., Louisiana income tax credits of $20.6 million, which resulted in a decrease in Entergy Louisiana’s member’s equity account.

The Tax Increase Prevention Act of 2014 was enacted in December 2014. The most significant provisions affecting Entergy and the Registrant Subsidiaries were a one-year extension of 50% bonus depreciation and the research and experimentation tax credit. These provisions do not result in an immediate cash flow benefit but will result in cash flow benefits for Entergy in a future period.

## 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 March 2019. 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, 2014 was 1.93% 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, 2014.

<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>$695</td><td>$9</td><td>$2,796</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, 2014, Entergy Corporation had $484 million of commercial paper outstanding. The weighted-average interest rate for the year ended December 31, 2014 was 0.88%.

Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas each had credit facilities available as of December 31, 2014 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, 2014</td></tr><tr><td>Entergy Arkansas</td><td>April 2015</td><td>$20 million (b)</td><td>1.67%</td><td>—</td></tr><tr><td>Entergy Arkansas</td><td>March 2019</td><td>$150 million (c)</td><td>1.67%</td><td>—</td></tr><tr><td>Entergy Gulf States Louisiana</td><td>March 2019</td><td>$150 million (d)</td><td>1.42%</td><td>—</td></tr><tr><td>Entergy Louisiana</td><td>March 2019</td><td>$200 million (e)</td><td>1.42%</td><td>—</td></tr><tr><td>Entergy Mississippi</td><td>May 2015</td><td>$10 million (f)</td><td>1.67%</td><td>—</td></tr><tr><td>Entergy Mississippi</td><td>May 2015</td><td>$35 million (f)</td><td>1.67%</td><td>—</td></tr><tr><td>Entergy Missouri</td><td>May 2015</td><td>$20 million (f)</td><td>1.67%</td><td>—</td></tr><tr><td>Entergy Mississippi</td><td>May 2015</td><td>$37.5 million (f)</td><td>1.67%</td><td>—</td></tr><tr><td>Entergy New Orleans</td><td>November 2015</td><td>$25 million</td><td>1.92%</td><td>—</td></tr><tr><td>Entergy Texas</td><td>March 2019</td><td>$150 million (g)</td><td>1.67%</td><td>—</td></tr></table>

(a) The interest rate is the rate as of December 31, 2014 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. As of December 31, 2014, no letters of credit were outstanding.

(d) The credit facility allows Entergy Gulf States Louisiana to issue letters of credit against 50% of the borrowing capacity of the facility. As of December 31, 2014, no letters of credit were outstanding.

(e) The credit facility allows Entergy Louisiana to issue letters of credit against 50% of the borrowing capacity of the facility. As of December 31, 2014, no letters of credit were outstanding.

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

(g) The credit facility allows Entergy Texas to issue letters of credit against 50% of the borrowing capacity of the facility. As of December 31, 2014, $1.3 million in letters of credit were outstanding.

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

<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, 2014</td></tr><tr><td>Entergy Arkansas</td><td>$25 million</td><td>0.70%</td><td>$2.0million</td></tr><tr><td>Entergy Gulf States Louisiana</td><td>$75 million</td><td>0.70%</td><td>$27.9million</td></tr><tr><td>Entergy Louisiana</td><td>$50 million</td><td>0.70%</td><td>$4.7million</td></tr><tr><td>Entergy Mississippi</td><td>$40 million</td><td>0.70%</td><td>$14.4million</td></tr><tr><td>Entergy Mississippi</td><td>$40 million</td><td>1.50%</td><td>—</td></tr><tr><td>Entergy New Orleans</td><td>$15 million</td><td>0.75%</td><td>$8.1million</td></tr><tr><td>Entergy Texas</td><td>$50 million</td><td>0.70%</td><td>$24.5million</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, 2015. In addition to borrowings from commercial banks, these companies are authorized under a FERC order to 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, 2014 (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>—</td></tr><tr><td>Entergy Gulf States Louisiana</td><td>$200</td><td>—</td></tr><tr><td>Entergy Louisiana</td><td>$250</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>—</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. The weighted average interest rate that would have applied to any outstanding borrowings at the time Entergy Nuclear Vermont Yankee entered into the facility was 1.92% 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. The weighted average



interest rate that would have applied to any outstanding borrowings at the time Entergy Nuclear Vermont Yankee entered into the facility was 1.92% 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, 2014:

<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, 2014</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>1.61%</td><td>$48.0</td></tr><tr><td>Entergy Gulf States Louisiana VIE</td><td>June 2016</td><td>$100</td><td>n/a</td><td>$—</td></tr><tr><td>Entergy Louisiana VIE</td><td>June 2016</td><td>$90</td><td>1.54%</td><td>$46.0</td></tr><tr><td>System Energy VIE</td><td>June 2016</td><td>$125</td><td>1.68%</td><td>$20.4</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 Gulf States Louisiana does not issue commercial paper, but borrows directly on its bank credit facility.

Amounts outstanding on the Entergy Gulf States Louisiana nuclear fuel company variable interest entity’s credit facility, if any, are included in long-term debt on its 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 and Entergy Gulf States 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 Gulf States Louisiana, 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, 2014 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 Gulf States Louisiana VIE</td><td>3.25% Series Q due July 2017</td><td>$75 million</td></tr><tr><td>Entergy Gulf States Louisiana VIE</td><td>3.38% Series R due August 2020</td><td>$70 million</td></tr><tr><td>Entergy Louisiana VIE</td><td>3.30% Series F due March 2016</td><td>$20 million</td></tr><tr><td>Entergy Louisiana VIE</td><td>3.25% Series G due July 2017</td><td>$25 million</td></tr><tr><td>Entergy Louisiana VIE</td><td>3.92% Series H due February 2021</td><td>$40 million</td></tr><tr><td>System Energy VIE</td><td>5.33% Series G due April 2015</td><td>$60 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 Gulf States Louisiana, Entergy Louisiana, and System Energy each have obtained long-term financing authorizations from the FERC that extend through October 2015 for issuances by its nuclear fuel company variable interest entity.



## NOTE 5. LONG - TERM DEBT

Long-term debt for Entergy Corporation and subsidiaries as of December 31, 2014 and 2013 consisted of:

<table><tr><td rowspan="2">Type of Debt and Maturity</td><td rowspan="2">Weighted Average Interest Rate December 31, 2014</td><td colspan="2">Interest Rate Ranges at December 31,</td><td colspan="2">Outstanding at December 31,</td></tr><tr><td>2014</td><td>2013</td><td>2014</td><td>2013</td></tr><tr><td>Mortgage Bonds</td><td></td><td></td><td></td><td></td><td>(In Thousands)</td></tr><tr><td>2014-2019</td><td>6.49%</td><td>3.25%-7.13%</td><td>1.88%-7.13%</td><td>$1,650,000</td><td>$2,110,000</td></tr><tr><td>2020-2024</td><td>4.18%</td><td>3.05%-5.60%</td><td>3.05%-5.60%</td><td>3,483,303</td><td>3,008,363</td></tr><tr><td>2025-2029</td><td>4.54%</td><td>3.78%-5.66%</td><td>4.44%-5.66%</td><td>762,859</td><td>462,914</td></tr><tr><td>2032-2039</td><td>6.16%</td><td>5.90%-6.38%</td><td>5.90%-7.88%</td><td>660,000</td><td>980,000</td></tr><tr><td>2040-2064</td><td>5.28%</td><td>4.70%-6.20%</td><td>4.70%-6.20%</td><td>2,215,000</td><td>1,410,000</td></tr><tr><td>Governmental Bonds (a)</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>2015-2017</td><td>1.75%</td><td>1.55%-2.88%</td><td>1.55%-2.88%</td><td>86,655</td><td>86,655</td></tr><tr><td>2021-2022</td><td>5.31%</td><td>2.375%-5.88%</td><td>2.375%-5.88%</td><td>291,000</td><td>291,000</td></tr><tr><td>2028-2030</td><td>5.00%</td><td>5.00%</td><td>5.00%</td><td>198,680</td><td>198,680</td></tr><tr><td>Securitization Bonds</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>2016-2023</td><td>3.88%</td><td>2.04%-5.93%</td><td>2.04%-5.93%</td><td>785,059</td><td>883,243</td></tr><tr><td>Variable Interest Entities Notes</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Payable (Note 4)</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>2014-2021</td><td>3.53%</td><td>2.62%-5.33%</td><td>1.38%-5.69%</td><td>630,000</td><td>634,800</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>3.625%</td><td>3.625%</td><td>550,000</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>Note Payable to NYPA</td><td>(b)</td><td>(b)</td><td>(b)</td><td>79,638</td><td>95,011</td></tr><tr><td>5 Year Credit Facility (Note 4)</td><td>n/a</td><td>1.93%</td><td>1.96%</td><td>695,000</td><td>255,000</td></tr><tr><td>Long-term DOE Obligation (c)</td><td>—</td><td>—</td><td>—</td><td>181,329</td><td>181,253</td></tr><tr><td>Waterford 3 Lease Obligation (d)</td><td>n/a</td><td>7.45%</td><td>7.45%</td><td>128,488</td><td>148,716</td></tr><tr><td>Grand Gulf Lease Obligation (d)</td><td>n/a</td><td>5.13%</td><td>5.13%</td><td>50,671</td><td>97,414</td></tr><tr><td>Term Loan - Entergy Arkansas</td><td>n/a</td><td>—</td><td>1.13%</td><td>—</td><td>250,000</td></tr><tr><td>Unamortized Premium and</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Discount - Net</td><td></td><td></td><td></td><td>(12,529)</td><td>(11,172)</td></tr><tr><td>Other</td><td></td><td></td><td></td><td>14,331</td><td>14,367</td></tr><tr><td>Total Long-Term Debt</td><td></td><td></td><td></td><td>13,399,484</td><td>12,596,244</td></tr><tr><td>Less Amount Due Within One Year</td><td></td><td></td><td></td><td>899,375</td><td>457,095</td></tr><tr><td>Long-Term Debt Excluding</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Amount Due Within One Year</td><td></td><td></td><td></td><td>$12,500,109</td><td>$12,139,149</td></tr><tr><td>Fair Value of Long-Term Debt (e)</td><td></td><td></td><td></td><td>$13,607,242</td><td>$12,439,785</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 $128 million at Entergy Louisiana and $51 million at System Energy, long-term DOE obligations of $181 million at Entergy Arkansas, and the note payable to NYPA of $80 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, 2014, 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>2015</td><td>$310,566</td></tr><tr><td>2016</td><td>$765,821</td></tr><tr><td>2017</td><td>$266,801</td></tr><tr><td>2018</td><td>$1,336,396</td></tr><tr><td>2019</td><td>$1,492,107</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. In July 2003 a payment of $102 million was made prior to maturity on the note payable to NYPA. 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 Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy Texas, and System Energy have obtained long-term financing authorizations from the FERC that extend through October 2015. Entergy Arkansas has obtained long-term financing authorization from the APSC that extends through December 2015. Entergy New Orleans has obtained long-term financing authorization from the City Council that extends through July 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 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 $13.2 million for 2015, $13.4 million for 2016, $13.8 million for 2017, $14.1 million for 2018, and $14.4 million for 2019. 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 cancelled Little Gypsy repowering project. In September 2011, Entergy Louisiana Investment Recovery Funding I, L.L.C., a company wholly-owned and consolidated by Entergy Louisiana, issued $207.2 million of senior secured investment recovery bonds. The bonds have an interest rate of 2.04% and an expected maturity date of June 2021. 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 $20.5 million for 2015, $21.6 million for 2016, $21.7 million for 2017, $22.3 million for 2018, and $22.7 million for 2019. 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 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 rowspan="2"></td><td>Amount</td></tr><tr><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 $24.6 million for 2015, $26 million for 2016, $27.6 million for 2017, $29.2 million for 2018, and $30.9 million for 2019. All of the scheduled principal payments for 2015-2016 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 2018-2019 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 rowspan="2"></td><td>Amount</td></tr><tr><td>(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 $41.2 million for 2015, $42.6 million for 2016, $44.1 million for 2017, $45.8 million for 2018, and $47.6 million for 2019. A total of $13.8 million of the scheduled principal payments for 2015 are for Tranche A-1 and $27.4 million are for Tranche A-2. 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 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, 2014 and 2013 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="2">Shares/Units Authorized</td><td colspan="2">Shares/Units Outstanding</td><td rowspan="2">2014</td><td rowspan="2">2013</td></tr><tr><td>2014</td><td>2013</td><td>2014</td><td>2013</td></tr><tr><td>Entergy Corporation</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></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></tr><tr><td>Entergy Arkansas, 4.32%-6.45% Series</td><td>3,413,500</td><td>3,413,500</td><td>3,413,500</td><td>3,413.500</td><td>$116,350</td><td>$116,350</td></tr><tr><td>Entergy Gulf States Louisiana, Series A 8.25%</td><td>100,000</td><td>100,000</td><td>100,000</td><td>100,000</td><td>10,000</td><td>10,000</td></tr><tr><td>Entergy Louisiana, 6.95% Series (a)</td><td>1,000,000</td><td>1,000,000</td><td>840,000</td><td>840,000</td><td>84,000</td><td>84,000</td></tr><tr><td>Entergy Mississippi, 4.36%-6.25% Series</td><td>1,403,807</td><td>1,403,807</td><td>1,403,807</td><td>1,403.807</td><td>50,381</td><td>50,381</td></tr><tr><td>Entergy New Orleans, 4.36%-5.56% Series</td><td>197,798</td><td>197,798</td><td>197,798</td><td>197,798</td><td>19,780</td><td>19,780</td></tr><tr><td>Total Utility Preferred Stock or Preferred Membership Interests without sinking fund</td><td>6,115,105</td><td>6,115,105</td><td>5,955,105</td><td>5,955,105</td><td>280,511</td><td>280,511</td></tr><tr><td>Entergy Wholesale Commodities:</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Preferred Stock without sinking fund:</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Entergy Finance Holding, Inc. 8.75% (b)</td><td>250,000</td><td>250,000</td><td>250,000</td><td>250,000</td><td>24,249</td><td>24,249</td></tr><tr><td>Total Subsidiaries&#x27; Preferred Stock without sinking fund</td><td>6,365,105</td><td>6,365,105</td><td>6,205,105</td><td>6,205,105</td><td>$304,760</td><td>$304,760</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 $751 thousand of preferred stock issuance costs.

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, 2014. 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 2014, 2013, and 2012 is as follows:

<table><tr><td></td><td colspan="2">2014</td><td colspan="2">2013</td><td colspan="2">2012</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>I Treasury Shares</td></tr><tr><td>Beginning Balance, January 1</td><td>254,752,788</td><td>76,381,936</td><td>254,752,788</td><td>76,945,239</td><td>254,752,788</td><td>78,396,988</td></tr><tr><td>Repurchases</td><td>—</td><td>2,154,490</td><td>—</td><td>—</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>(3,019,475)</td><td>—</td><td>(557,734)</td><td>—</td><td>(1,446,305)</td></tr><tr><td>Directors&#x27; Plan</td><td>—</td><td>(4,872)</td><td>—</td><td>(5,569)</td><td>—</td><td>(5,444)</td></tr><tr><td>Ending Balance, December 31</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></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, 2014, $350 million of authority remains under the $500 million share repurchase program.

Dividends declared per common share were $3.32 in 2014, 2013, and 2012.

## 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, 2014, 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 from subsidiaries totaling $893 million in 2014, $702 million in 2013, and $439 million in 2012.



## Comprehensive Income

Accumulated other comprehensive income (loss) is included in the equity section of the balance sheets of Entergy, Entergy Gulf States Louisiana, and Entergy Louisiana. 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 colspan="5">(In Thousands)</td></tr><tr><td>Beginning balance, December 31, 2013</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>

The following table presents changes in accumulated other comprehensive income (loss) for Entergy for the year ended December 31, 2013 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 colspan="5">(In Thousands)</td></tr><tr><td>Beginning balance, December 31, 2012</td><td>$79,905</td><td>($590,712)</td><td>$214,547</td><td>$3,177</td><td>($293,083)</td></tr><tr><td>Other comprehensive income (loss) before reclassifications</td><td>(133,312)</td><td>260,567</td><td>143,936</td><td>243</td><td>271,434</td></tr><tr><td>Amounts reclassified from accumulated other comprehensive income (loss)</td><td>(28,370)</td><td>41,922</td><td>(21,227)</td><td>—</td><td>(7,675)</td></tr><tr><td>Net other comprehensive income (loss) for the period</td><td>(161,682)</td><td>302,489</td><td>122,709</td><td>243</td><td>263,759</td></tr><tr><td>Ending balance, December 31, 2013</td><td>($81,777)</td><td>($288,223)</td><td>$337,256</td><td>$3,420</td><td>($29,324)</td></tr></table>



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</td><td>Income Statement Location</td></tr><tr><td></td><td>(In Thousands)</td><td></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 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, 2013 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>$47,019</td><td>Competitive business operating revenues</td></tr><tr><td>Interest rate swaps</td><td>(1,565)</td><td>Miscellaneous - net</td></tr><tr><td>Total realized gain (loss) on cash flow hedges</td><td>45,454</td><td></td></tr><tr><td></td><td>(17,084)</td><td>Income taxes</td></tr><tr><td>Total realized gain (loss) on cash flow hedges (net of tax)</td><td>$28,370</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>$10,556</td><td>(a)</td></tr><tr><td>Acceleration of prior-service cost due to curtailment</td><td>315</td><td>(a)</td></tr><tr><td>Amortization of loss</td><td>(68,130)</td><td>(a)</td></tr><tr><td>Settlement loss</td><td>(11,612)</td><td>(a)</td></tr><tr><td>Total amortization</td><td>(68,871)</td><td></td></tr><tr><td></td><td>26,949</td><td>Income taxes</td></tr><tr><td>Total amortization (net of tax)</td><td>($41,922)</td><td></td></tr><tr><td>Net unrealized investment gain (loss)</td><td></td><td></td></tr><tr><td>Realized gain (loss)</td><td>$41,622</td><td>Interest and investment income</td></tr><tr><td></td><td>(20,395)</td><td>Income taxes</td></tr><tr><td>Total realized investment gain (loss) (net of tax)</td><td>$21,227</td><td></td></tr><tr><td>Total reclassifications for the period (net of tax)</td><td>$7,675</td><td></td></tr></table>

(a) These accumulated other comprehensive income (loss) components are included in the computation of net periodic pension 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 $152.8 million in 2014, $181.1 million in 2013, and $125.0 million in 2012. If the maximum percentage (94%) of the energy is made available to Entergy Louisiana, current production projections would require estimated payments of approximately $148.5 million in 2015, and a total of $2.06 billion for the years 2016 through 2031. Entergy Louisiana currently recovers the costs of the purchased energy through its fuel adjustment clause.

In an LPSC-approved settlement related to tax benefits from the tax treatment of the Vidalia contract, Entergy Louisiana agreed to credit rates by $11 million each year for up to 10 years, beginning in October 2002. In addition, in accordance with an LPSC settlement, Entergy Louisiana credited rates in August 2007 by $11.3 million (including interest) as a result of a settlement with the IRS of the 2001 tax treatment of the Vidalia contract. In August 2011, Entergy agreed to a settlement with the IRS regarding the mark-to-market income tax treatment of various wholesale electric power purchase and sale contracts, including the Vidalia contract. The agreement with the IRS effectively settled the tax treatment of such contracts which allowed Entergy Louisiana to propose a final settlement with the LPSC regarding Entergy Louisiana's obligation to customers related to the Vidalia contract. In October 2011 the LPSC approved a final settlement under which Entergy Louisiana agreed to provide credits to the fuel adjustment clause resulting from the IRS settlement 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. Entergy Louisiana's use of the cash benefit of the proceeds is not reflected in rate base for ratemaking purposes.

## 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. On July 12, 2013, Entergy Arkansas filed a complaint in the Circuit Court in Pope County, Arkansas against the owner of the heavy-lifting apparatus that collapsed, an engineering firm, a 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. The NRC plans to conduct supplemental inspection activity to review the actions taken to address the yellow findings. Entergy will continue to interact with the NRC to address the NRC's findings.

In September 2014 the NRC issued an inspection report on the flood barrier effectiveness issue that was still under review at the time of the March 2014 inspection report. While Entergy believes that the flood barrier issues that led to the finding have been addressed at ANO, NRC processes still required that the NRC assess the safety significance of the deficiencies. In its September 2014 inspection report, the NRC discussed a preliminary finding of "yellow with 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 on October 28, 2014. During the regulatory conference, Entergy presented information related to the facts and assumptions used by the NRC in arriving at its preliminary finding of "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."

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

## 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, allocating $12.9 million of the expected insurance proceeds to capital spending and $15.3 million 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.

## 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 $19.0 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 $13.6 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, 104 nuclear reactors are participating in the Secondary Financial Protection program. The product of the maximum retrospective premium assessment to the nuclear power industry and the number of nuclear power reactors provides over $13.2 billion in secondary layer insurance coverage to compensate the public in the event of a nuclear power reactor accident. The Price-Anderson Act provides that all potential liability for a nuclear accident is limited to the amounts of insurance coverage available under the primary and secondary layers.

Entergy Arkansas has two licensed reactors and Entergy Gulf States Louisiana, Entergy Louisiana, and System Energy each have one licensed reactor (10% 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, 2014, 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, and the required 12 week deductible waiting period for the accidental outage coverage to take effect, accidental outage coverage was removed effective October 1, 2014. This coverage provides certain fixed indemnities in the event of an unplanned outage that results from a covered NEIL primary property damage loss, subject to a deductible period. The payout for damage resulting from non-nuclear events is limited to a $327.6 million per occurrence sub-limit. The following summarizes this coverage effective October 1, 2014:

## Waterford 3

• $2.95 million weekly indemnity

• $413 million maximum indemnity

• Deductible: 26 week deductible period

## Grand Gulf

• $400,000 weekly indemnity (total for four policies)

• $56 million maximum indemnity (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

• Deductible: 12 week deductible period

## FitzPatrick and Pilgrim

• $4 million weekly indemnity

• $490 million maximum indemnity

• 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, 2014, the maximum amounts of such possible assessments per occurrence were as follows:

<table><tr><td rowspan="2">Utility:</td><td>Assessments</td></tr><tr><td>(In Millions)</td></tr><tr><td>Entergy Arkansas</td><td>$32.2</td></tr><tr><td>Entergy Gulf States Louisiana</td><td>$25.5</td></tr><tr><td>Entergy Louisiana</td><td>$26.1</td></tr><tr><td>Entergy Mississippi</td><td>$0.09</td></tr><tr><td>Entergy New Orleans</td><td>$0.09</td></tr><tr><td>Entergy Texas</td><td>N/A</td></tr><tr><td>System Energy</td><td>$21.5</td></tr><tr><td>Entergy Wholesale Commodities</td><td>$—</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 causes property damage under one or more or all nuclear insurance policies issued by NEIL (including, but not limited to, those described above) within 12 months from the date the first property damage occurs, the maximum recovery under all such nuclear insurance policies shall be an aggregate of $3.24 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. 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.

## 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. 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. Four 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 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>2014</td><td>2013</td></tr><tr><td></td><td colspan="2">(In Millions)</td></tr><tr><td>Entergy Arkansas</td><td>$59.0</td><td>$18.6</td></tr><tr><td>Entergy Gulf States Louisiana</td><td>($36.9)</td><td>($35.3)</td></tr><tr><td>Entergy Louisiana</td><td>($45.7)</td><td>($37.0)</td></tr><tr><td>Entergy Mississippi</td><td>$76.3</td><td>$64.3</td></tr><tr><td>Entergy New Orleans</td><td>$35.2</td><td>$34.9</td></tr><tr><td>Entergy Texas</td><td>$18.9</td><td>$15.1</td></tr><tr><td>System Energy</td><td>$55.7</td><td>$56.0</td></tr></table>

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 (In Millions)</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></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 Gulf States Louisiana</td><td>$403.1</td><td>$23.5</td><td>$20.0</td><td>$—</td><td>$446.6</td></tr><tr><td>Entergy Louisiana</td><td>$479.1</td><td>$24.6</td><td>$—</td><td>$—</td><td>$503.7</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>



The cumulative decommissioning and retirement cost liabilities and expenses recorded in 2013 by Entergy were as follows:

<table><tr><td rowspan="2"></td><td rowspan="2">Liabilities as of December 31, 2012</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, 2013</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>$680.7</td><td>$43.1</td><td>$—</td><td>$—</td><td>$723.8</td></tr><tr><td>Entergy Gulf States Louisiana</td><td>$380.8</td><td>$22.3</td><td>$—</td><td>$—</td><td>$403.1</td></tr><tr><td>Entergy Louisiana</td><td>$418.1</td><td>$21.6</td><td>$39.4</td><td>$—</td><td>$479.1</td></tr><tr><td>Entergy Mississippi</td><td>$6.0</td><td>$0.4</td><td>$—</td><td>$—</td><td>$6.4</td></tr><tr><td>Entergy New Orleans</td><td>$2.2</td><td>$0.1</td><td>$—</td><td>$—</td><td>$2.3</td></tr><tr><td>Entergy Texas</td><td>$4.1</td><td>$0.2</td><td>$—</td><td>$—</td><td>$4.3</td></tr><tr><td>System Energy</td><td>$478.4</td><td>$35.5</td><td>$102.3</td><td>$—</td><td>$616.2</td></tr><tr><td>Entergy Wholesale Commodities</td><td>$1,543.3</td><td>$125.3</td><td>$38.6</td><td>($9.0)</td><td>$1,698.2</td></tr></table>

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 2014 and 2013 Entergy updated decommissioning cost estimates for certain nuclear power plants.

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

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

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

In the fourth quarter 2014, System Energy recorded a revision to its estimated decommissioning cost liability for Grand Gulf as a result of a revised decommissioning cost study. The revised estimate resulted in a $99.9 million increase in its decommissioning liability, along with a corresponding increase in the related asset retirement cost asset that will be depreciated over the remaining life of the unit.

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



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

In the fourth quarter 2013, System Energy recorded a revision to its estimated decommissioning cost liability for Grand Gulf as a result of a revised decommissioning cost study. The revised estimate resulted in a $102.3 million increase in its decommissioning liability, along with a corresponding increase in the related asset retirement cost asset that will be depreciated over the remaining life of the unit.

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

In the fourth quarter 2013, Entergy Wholesale Commodities recorded a revision to its estimated decommissioning cost liability for Vermont Yankee. As a result of 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, which will not result in future cash expenditures. See Note 1 to the financial statements for further discussion of the Vermont Yankee plant.

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

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. The PSDAR for Vermont Yankee, including a site specific cost estimate, was submitted to the NRC in December 2014. Vermont Yankee's future certifications to satisfy the NRC's financial assurance requirements will now be based on the site specific cost estimate, including the estimated cost of managing spent fuel, rather than the NRC minimum formula for estimating decommissioning costs. 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 expected costs of decommissioning, spent fuel management costs, and site restoration. 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.

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. Entergy recorded an asset, which is $599.9 million as of December 31, 2014, representing its estimate of the present value of the difference between the stipulated contract amount for decommissioning the plants less the decommissioning costs estimated in independent decommissioning cost studies. The asset is increased 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.

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, 2014 are as follows:

<table><tr><td></td><td>Decommissioning Trust Fair Values</td><td>Regulatory Asset (Liability)</td></tr><tr><td></td><td>(In Millions)</td><td></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>

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

<table><tr><td></td><td>Decommissioning Trust Fair Values</td><td>Regulatory Asset (Liability)</td></tr><tr><td></td><td>(In Millions)</td><td></td></tr><tr><td>Utility:</td><td></td><td></td></tr><tr><td>ANO 1 and ANO 2</td><td>$710.9</td><td>$219.1</td></tr><tr><td>River Bend</td><td>$573.7</td><td>($28.7)</td></tr><tr><td>Waterford 3</td><td>$347.3</td><td>$128.5</td></tr><tr><td>Grand Gulf</td><td>$603.9</td><td>$60.8</td></tr><tr><td>Entergy Wholesale Commodities</td><td>$2,667.3</td><td>$—</td></tr></table>



## NOTE 10. LEASES

## General

As of December 31, 2014, Entergy had capital leases and non-cancelable operating leases for equipment, buildings, vehicles, and fuel storage facilities with minimum lease payments as follows (excluding power purchase agreement operating leases, nuclear fuel leases and the Grand Gulf and Waterford 3 sale and leaseback transactions, 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>2015</td><td>$90,010</td><td>$4,615</td></tr><tr><td>2016</td><td>77,060</td><td>4,457</td></tr><tr><td>2017</td><td>62,103</td><td>4,457</td></tr><tr><td>2018</td><td>49,630</td><td>3,672</td></tr><tr><td>2019</td><td>47,527</td><td>2,887</td></tr><tr><td>Years thereafter</td><td>95,530</td><td>27,664</td></tr><tr><td>Minimum lease payments</td><td>421,860</td><td>47,752</td></tr><tr><td>Less: Amount representing interest</td><td>—</td><td>15,773</td></tr><tr><td>Present value of net minimum lease payments</td><td>$421,860</td><td>$31,979</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 $59 million in 2014, $63.7 million in 2013, and $69.9 million in 2012.

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 $4.8 million in 2014, $8.6 million in 2013, and $8.5 million in 2012 for Entergy Arkansas and $1.7 million in 2014, $2.2 million in 2013, and $1.7 million in 2012 for Entergy Gulf States Louisiana. Oil tank facilities lease payments for Entergy Mississippi were $1.6 million in 2014, $3.4 million in 2013, and $3.4 million in 2012.

## Power Purchase Agreements

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

<table><tr><td>Year</td><td>Entergy</td></tr><tr><td></td><td>(in Thousands)</td></tr><tr><td>2015</td><td>$28,450</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>31,158</td></tr><tr><td>Years thereafter</td><td>74,664</td></tr><tr><td>Minimum lease payments</td><td>223,606</td></tr></table>

Total capacity expense under the power purchase agreement accounted for as an operating lease at Entergy Texas was $29.2 million in 2014, $28.6 million in 2013, and $19.2 million in 2012.



## 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. At the end of the lease terms, Entergy Louisiana has the option to repurchase the leased interests in Waterford 3 at fair market value or to renew the leases for either fair market value or, under certain conditions, a fixed rate. In the event that Entergy Louisiana does not renew or purchase the interests, Entergy Louisiana would surrender such interests and their associated entitlement of Waterford 3's capacity and energy.

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

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

As of December 31, 2014, 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%) that are recorded as long-term debt, as follows:

<table><tr><td></td><td>Amount (In Thousands)</td></tr><tr><td>2015</td><td>$28,827</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>Years thereafter</td><td>—</td></tr><tr><td>Total</td><td>152,100</td></tr><tr><td>Less: Amount representing interest</td><td>23,612</td></tr><tr><td>Present value of net minimum lease payments</td><td>$128,488</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 was to expire in July 2015. In December 2013, System Energy exercised its options to renew the leases for fair market value with a renewal term for one lease expiring in July 2018 and the renewal term of the other lease expiring in July 2036. At the end of the new lease renewal terms, System Energy has the option to repurchase the leased interests in Grand Gulf or renew the leases at fair market value. In the event that System Energy does not renew or purchase the interests, System Energy would surrender such interests and their associated entitlement of Grand Gulf’s capacity and energy.



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

As of December 31, 2014, 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>2015</td><td>$52,253</td></tr><tr><td>2016</td><td>13,750</td></tr><tr><td>2017</td><td>13,750</td></tr><tr><td>2018</td><td>13,750</td></tr><tr><td>2019</td><td>13,750</td></tr><tr><td>Years thereafter</td><td>233,750</td></tr><tr><td>Total</td><td>341,003</td></tr><tr><td>Less: Amount representing interest</td><td>290,332</td></tr><tr><td>Present value of net minimum lease payments</td><td>$50,671</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 hired or rehired after June 30, 2014 participate in the “Entergy Corporation Cash Balance Plan for Non-Bargaining Employees.” Certain bargaining employees hired or rehired after June 30, 2014, or such later date provided for in their applicable collective bargaining agreements, participate in the “Entergy Corporation Cash Balance Plan for Bargaining Employees.” The Registrant Subsidiaries participate in these four plans: “Entergy Corporation Retirement Plan for Non-Bargaining Employees,” “Entergy Corporation Retirement Plan for Bargaining Employees,” “Entergy Corporation Cash Balance Plan for Non-Bargaining Employees,” and “Entergy Cash Balance Plan for Bargaining Employees.”



The assets of the seven final average pay qualified pension plans are held in a master trust established by Entergy and the assets of the two cash balance pension plans are held in a second master trust established by Entergy. Each pension plan has an undivided beneficial interest in each of the investment accounts 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 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 costs in accordance with contribution guidelines established by the Employee Retirement Income Security Act of 1974, as amended, and the Internal Revenue Code of 1986, as amended. The assets of the plans include common and preferred stocks, fixed-income securities, interest in a money market fund, and insurance contracts. The Registrant Subsidiaries' pension costs are recovered from customers as a component of cost of service in each of their respective jurisdictions.



## 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 2014, 2013, and 2012 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>2014</td><td>2013</td><td>2012</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>$140,436</td><td>$172,280</td><td>$150,763</td></tr><tr><td>Interest cost on projected benefit obligation</td><td>290,076</td><td>263,296</td><td>260,929</td></tr><tr><td>Expected return on assets</td><td>(361,462)</td><td>(328,227)</td><td>(317,423)</td></tr><tr><td>Amortization of prior service cost</td><td>1,600</td><td>2,125</td><td>2,733</td></tr><tr><td>Recognized net loss</td><td>145,095</td><td>213,194</td><td>167,279</td></tr><tr><td>Curtailment loss</td><td>—</td><td>16,318</td><td>—</td></tr><tr><td>Special termination benefit</td><td>732</td><td>13,139</td><td>—</td></tr><tr><td>Net periodic pension costs</td><td>$216,477</td><td>$352,125</td><td>$264,281</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>$1,389,912</td><td>($894,150)</td><td>$552,303</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>(1,600)</td><td>(2,125)</td><td>(2,733)</td></tr><tr><td>Acceleration of prior service cost to curtailment</td><td>—</td><td>(1,307)</td><td>—</td></tr><tr><td>Amortization of net loss</td><td>(145,095)</td><td>(213,194)</td><td>(167,279)</td></tr><tr><td>Total</td><td>1,243,217</td><td>(1,110,776)</td><td>382,291</td></tr><tr><td>Total recognized as net periodic pension (income)/cost, regulatory asset, and/or AOCI (before tax)</td><td>$1,459,694</td><td>($758,651)</td><td>$646,572</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>$1,561</td><td>$1,600</td><td>$2,268</td></tr><tr><td>Net loss</td><td>$237,013</td><td>$146,958</td><td>$219,805</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, 2014 and 2013

<table><tr><td rowspan="3"></td><td colspan="2">December 31,</td></tr><tr><td>2014</td><td>2013</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>$5,770,999</td><td>$6,096,639</td></tr><tr><td>Service cost</td><td>140,436</td><td>172,280</td></tr><tr><td>Interest cost</td><td>290,076</td><td>263,296</td></tr><tr><td>Curtailment</td><td>—</td><td>15,011</td></tr><tr><td>Special termination benefit</td><td>732</td><td>13,139</td></tr><tr><td>Actuarial loss/(gain)</td><td>1,284,049</td><td>(571,990)</td></tr><tr><td>Employee contributions</td><td>560</td><td>598</td></tr><tr><td>Benefits paid</td><td>(256,310)</td><td>(217,974)</td></tr><tr><td>Balance at end of year</td><td>$7,230,542</td><td>$5,770,999</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>$4,429,237</td><td>$3,832,860</td></tr><tr><td>Actual return on plan assets</td><td>255,599</td><td>650,386</td></tr><tr><td>Employer contributions</td><td>398,880</td><td>163,367</td></tr><tr><td>Employee contributions</td><td>560</td><td>598</td></tr><tr><td>Benefits paid</td><td>(256,310)</td><td>(217,974)</td></tr><tr><td>Fair value of assets at end of year</td><td>$4,827,966</td><td>$4,429,237</td></tr><tr><td>Funded status</td><td>($2,402,576)</td><td>($1,341,762)</td></tr><tr><td>Amount recognized in the balance sheet</td><td></td><td></td></tr><tr><td>Non-current liabilities</td><td>($2,402,576)</td><td>($1,341,762)</td></tr><tr><td>Amount recognized as a regulatory asset</td><td></td><td></td></tr><tr><td>Prior service cost</td><td>$3,704</td><td>$5,027</td></tr><tr><td>Net loss</td><td>2,451,172</td><td>1,494,117</td></tr><tr><td></td><td>$2,454,876</td><td>$1,499,144</td></tr><tr><td>Amount recognized as AOCI (before tax)</td><td></td><td></td></tr><tr><td>Prior service cost</td><td>$1,015</td><td>$1,292</td></tr><tr><td>Net loss</td><td>671,682</td><td>383,920</td></tr><tr><td></td><td>$672,697</td><td>$385,212</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.

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



benefits on or after January 1, 2015 and for certain bargaining employees who commence their Entergy retirement benefits on or after January 1, 2015 or such later date as provided for in their applicable collective bargaining agreement. In accordance with accounting standards, certain of the other postretirement benefit changes have been reflected in the December 31, 2013 other postretirement obligation. The changes affecting active bargaining unit employees are being negotiated with the unions prior to implementation, where necessary, and to the extent required by law.

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

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

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

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

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

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



## 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 2014, 2013, and 2012 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>2014</td><td>2013</td><td>2012</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>$43,493</td><td>$74,654</td><td>$68,883</td></tr><tr><td>Interest cost on APBO</td><td>71,841</td><td>79,453</td><td>82,561</td></tr><tr><td>Expected return on assets</td><td>(44,787)</td><td>(40,323)</td><td>(34,503)</td></tr><tr><td>Amortization of transition obligation</td><td>—</td><td>—</td><td>3,177</td></tr><tr><td>Amortization of prior service credit</td><td>(31,590)</td><td>(14,904)</td><td>(18,163)</td></tr><tr><td>Recognized net loss</td><td>11,143</td><td>44,178</td><td>36,448</td></tr><tr><td>Curtailment loss</td><td>—</td><td>12,729</td><td>—</td></tr><tr><td>Net other postretirement benefit cost</td><td>$50,100</td><td>$155,787</td><td>$138,403</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>($35,864)</td><td>($116,571)</td><td>$—</td></tr><tr><td>Net loss/(gain)</td><td>287,313</td><td>(405,976)</td><td>92,584</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 transition obligation</td><td>—</td><td>—</td><td>(3,177)</td></tr><tr><td>Amortization of prior service credit</td><td>31,590</td><td>14,904</td><td>18,163</td></tr><tr><td>Acceleration of prior service credit due to curtailment</td><td>—</td><td>1,989</td><td>—</td></tr><tr><td>Amortization of net loss</td><td>(11,143)</td><td>(44,178)</td><td>(36,448)</td></tr><tr><td>Total</td><td>$271,896</td><td>($549,832)</td><td>$71,122</td></tr><tr><td>Total recognized as net periodic benefit income/(cost), regulatory asset, and/or AOCI (before tax)</td><td>$321,996</td><td>($394,045)</td><td>$209,525</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>($37,280)</td><td>($31,589)</td><td>($13,336)</td></tr><tr><td>Net loss</td><td>$31,591</td><td>$11,197</td><td>$45,217</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, 2014 and 2013

<table><tr><td rowspan="3"></td><td colspan="2">December 31,</td></tr><tr><td>2014</td><td>2013</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>$1,461,910</td><td>$1,846,922</td></tr><tr><td>Service cost</td><td>43,493</td><td>74,654</td></tr><tr><td>Interest cost</td><td>71,841</td><td>79,453</td></tr><tr><td>Plan amendments</td><td>(35,864)</td><td>(116,571)</td></tr><tr><td>Curtailment</td><td>—</td><td>14,718</td></tr><tr><td>Plan participant contributions</td><td>22,160</td><td>19,141</td></tr><tr><td>Actuarial loss/(gain)</td><td>274,061</td><td>(370,004)</td></tr><tr><td>Benefits paid</td><td>(102,439)</td><td>(89,713)</td></tr><tr><td>Medicare Part D subsidy received</td><td>4,395</td><td>3,310</td></tr><tr><td>Balance at end of year</td><td>$1,739,557</td><td>$1,461,910</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>$569,850</td><td>$488,448</td></tr><tr><td>Actual return on plan assets</td><td>31,535</td><td>76,314</td></tr><tr><td>Employer contributions</td><td>76,521</td><td>75,660</td></tr><tr><td>Plan participant contributions</td><td>22,160</td><td>19,141</td></tr><tr><td>Benefits paid</td><td>(102,439)</td><td>(89,713)</td></tr><tr><td>Fair value of assets at end of year</td><td>$597,627</td><td>$569,850</td></tr><tr><td>Funded status</td><td>($1,141,930)</td><td>($892,060)</td></tr><tr><td>Amounts recognized in the balance sheet</td><td></td><td></td></tr><tr><td>Current liabilities</td><td>($41,821)</td><td>($40,602)</td></tr><tr><td>Non-current liabilities</td><td>(1,100,109)</td><td>(851,458)</td></tr><tr><td>Total funded status</td><td>($1,141,930)</td><td>($892,060)</td></tr><tr><td>Amounts recognized as a regulatory asset</td><td></td><td></td></tr><tr><td>Prior service credit</td><td>($54,508)</td><td>($93,332)</td></tr><tr><td>Net loss</td><td>248,918</td><td>165,270</td></tr><tr><td></td><td>$194,410</td><td>$71,938</td></tr><tr><td>Amounts recognized as AOCI (before tax)</td><td></td><td></td></tr><tr><td>Prior service credit</td><td>($104,086)</td><td>($60,988)</td></tr><tr><td>Net loss</td><td>300,518</td><td>107,996</td></tr><tr><td></td><td>$196,432</td><td>$47,008</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 $32.4 million in 2014, $54.5 million in 2013, and $26.5 million in 2012. In 2014, 2013, and 2012 Entergy recognized $15.1 million, $33 million, and $6.3 million, respectively in settlement charges related to the payment of lump sum benefits out of the plan that is included in the non-qualified pension plan cost above. The projected benefit obligation was $151.8



million and $154.3 million as of December 31, 2014 and 2013, respectively. The accumulated benefit obligation was $130.6 million and $131.4 million as of December 31, 2014 and 2013, respectively.

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

## Reclassification out of Accumulated Other Comprehensive Income

Entergy reclassified the following costs out of accumulated other comprehensive income (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>

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

<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>($1,866)</td><td>$12,925</td><td>($503)</td><td>$10,556</td></tr><tr><td>Acceleration of prior service cost due to curtailment</td><td>(1,304)</td><td>1,797</td><td>(178)</td><td>315</td></tr><tr><td>Amortization of loss</td><td>(43,971)</td><td>(21,590)</td><td>(2,569)</td><td>(68,130)</td></tr><tr><td>Settlement loss</td><td>—</td><td>—</td><td>(11,612)</td><td>(11,612)</td></tr><tr><td></td><td>($47,141)</td><td>($6,868)</td><td>($14,862)</td><td>($68,871)</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 Gulf States Louisiana that is not regulated, the unrecognized prior service cost, gains and losses, and transition asset/obligation for its pension and other postretirement benefit obligations are recorded as other comprehensive



income. Entergy Gulf States Louisiana and Entergy Louisiana recover other postretirement benefit costs on a pay-as-you-go basis and record the unrecognized prior service cost, gains and losses, and transition obligation for its other postretirement benefit obligation as other comprehensive income. Accounting standards also 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 changes made in 2012 as recommended in the latest optimization study.

Entergy’s qualified pension and postretirement weighted-average asset allocations by asset category at December 31, 2014 and 2013 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 2014</td><td>Actual 2013</td></tr><tr><td>Domestic Equity Securities</td><td>45%</td><td>34% to 53%</td><td>45%</td><td>46%</td></tr><tr><td>International Equity Securities</td><td>20%</td><td>16% to 24%</td><td>19%</td><td>20%</td></tr><tr><td>Fixed Income Securities</td><td>35%</td><td>31% to 41%</td><td>35%</td><td>33%</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 2014</td><td>Actual 2013</td><td></td></tr><tr><td>Domestic Equity Securities</td><td>39%</td><td>34% to 44%</td><td>42%</td><td>40%</td><td></td></tr><tr><td>International Equity Securities</td><td>26%</td><td>21% to 31%</td><td>25%</td><td>26%</td><td></td></tr><tr><td>Fixed Income Securities</td><td>35%</td><td>30% to 40%</td><td>33%</td><td>34%</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, 2014, all investment managers and assets were materially in compliance with the approved investment guidelines, therefore there were no significant concentrations (defined as greater than 10 percent of plan assets) of risk in Entergy’s pension and other postretirement benefit plan assets.

## 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, 2014, and December 31, 2013, 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

Final Average Pay Pension Plans' Trust

<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 (h)</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>314</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>$4,827,785</td></tr></table>



## Cash Balance Pension Plans' Trust

The Cash Balance pension plans’ trust held $181 thousand of cash as of December 31, 2014.

<table><tr><td>2013</td><td>Level 1</td><td>Level 2</td><td>Level 3</td><td>Total</td></tr><tr><td></td><td></td><td>(In Thousands)</td><td></td><td></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>$6,847 (b)</td><td>$6,038 (a)</td><td>$—</td><td>$12,885</td></tr><tr><td>Common</td><td>915,996 (b)</td><td>—</td><td>—</td><td>915,996</td></tr><tr><td>Common collective trusts</td><td>—</td><td>1,753,958 (c)</td><td>—</td><td>1,753,958</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>180,718 (b)</td><td>152,915 (a)</td><td>—</td><td>333,633</td></tr><tr><td>Corporate debt instruments</td><td>—</td><td>464,652 (a)</td><td>—</td><td>464,652</td></tr><tr><td>Registered investment companies</td><td>316,863 (d)</td><td>486,748 (e)</td><td>—</td><td>803,611</td></tr><tr><td>Other</td><td>—</td><td>129,169 (f)</td><td>—</td><td>129,169</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>36,886 (g)</td><td>—</td><td>36,886</td></tr><tr><td>Total investments</td><td>$1,420,424</td><td>$3,030,366</td><td>$—</td><td>$4,450,790</td></tr><tr><td>Cash</td><td></td><td></td><td></td><td>280</td></tr><tr><td>Other pending transactions</td><td></td><td></td><td></td><td>8,081</td></tr><tr><td>Less: Other postretirement assets included in total investments</td><td></td><td></td><td></td><td>(29,914)</td></tr><tr><td>Total fair value of qualified pension assets</td><td></td><td></td><td></td><td>$4,429,237</td></tr></table>

## Other Postretirement Trusts

<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>(In Thousands)</td><td></td><td></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>$370,228 (c)</td><td>$—</td><td>$370,228</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 (b)</td><td>45,618 (a)</td><td>—</td><td>81,924</td></tr><tr><td>Corporate debt instruments</td><td>—</td><td>57,830 (a)</td><td>—</td><td>57,830</td></tr><tr><td>Registered investment companies</td><td>5,558 (d)</td><td>—</td><td>—</td><td>5,558</td></tr><tr><td>Other</td><td>—</td><td>46,968 (f)</td><td>—</td><td>46,968</td></tr><tr><td>Total investments</td><td>$41,864</td><td>$520,644</td><td>$—</td><td>$562,508</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>



<table><tr><td>2013</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>$356,700</td><td>(c)</td><td>$—</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>40,808</td><td>(b)</td><td>43,471</td><td>(a)</td></tr><tr><td>Corporate debt instruments</td><td>—</td><td></td><td>50,563</td><td>(a)</td></tr><tr><td>Registered investment companies</td><td>4,163</td><td>(d)</td><td>—</td><td>—</td></tr><tr><td>Other</td><td>—</td><td></td><td>43,458</td><td>(f)</td></tr><tr><td>Total investments</td><td>$44,971</td><td></td><td>$494,192</td><td>$—</td></tr><tr><td>Other pending transactions</td><td></td><td></td><td></td><td>773</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>29,914</td></tr><tr><td>Total fair value of other postretirement assets</td><td></td><td></td><td></td><td>$569,850</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 the 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 $6.6 billion and $5.2 billion at December 31, 2014 and 2013, respectively.



## Estimated Future Benefit Payments

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

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>2015</td><td>$262,792</td><td>$16,173</td><td>$78,601</td><td>$455</td></tr><tr><td>2016</td><td>$277,307</td><td>$9,976</td><td>$80,601</td><td>$525</td></tr><tr><td>2017</td><td>$292,841</td><td>$10,774</td><td>$83,425</td><td>$595</td></tr><tr><td>2018</td><td>$310,200</td><td>$12,598</td><td>$88,049</td><td>$1,785</td></tr><tr><td>2019</td><td>$328,533</td><td>$11,431</td><td>$92,253</td><td>$1,984</td></tr><tr><td>2020 - 2024</td><td>$1,966,776</td><td>$70,791</td><td>$506,086</td><td>$13,539</td></tr></table>

## Contributions

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

## Actuarial Assumptions

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

<table><tr><td></td><td>2014</td><td>2013</td></tr><tr><td>Weighted-average discount rate:</td><td></td><td></td></tr><tr><td>Qualified pension</td><td>4.03% - 4.40%</td><td>5.04% - 5.26%</td></tr><tr><td></td><td>Blended 4.27%</td><td>Blended 5.14%</td></tr><tr><td>Other postretirement</td><td>4.23%</td><td>5.05%</td></tr><tr><td>Non-qualified pension</td><td>3.61%</td><td>4.29%</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>7.10%</td><td>7.25%</td></tr><tr><td>Post-65</td><td>7.70%</td><td>7.00%</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>2023</td><td>2022</td></tr><tr><td>Post-65</td><td>2023</td><td>2022</td></tr></table>



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

<table><tr><td></td><td>2014</td><td>2013</td><td>2012</td></tr><tr><td>Weighted-average discount rate:</td><td></td><td></td><td></td></tr><tr><td>Qualified pension</td><td>5.04%-5.26%</td><td>4.31%-4.5%</td><td>5.10%-5.20%</td></tr><tr><td></td><td>Blended 5.14%</td><td>Blended 4.36%</td><td>Blended 5.11%</td></tr><tr><td>Other postretirement</td><td>5.05%</td><td>4.36%</td><td>5.10%</td></tr><tr><td>Non-qualified pension</td><td>4.29%</td><td>3.37%</td><td>4.40%</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>8.50%</td><td>8.50%</td><td>8.50%</td></tr><tr><td>Other postretirement tax deferred assets</td><td>8.30%</td><td>8.50%</td><td>8.50%</td></tr><tr><td>Other post retirement taxable assets</td><td>6.50%</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>7.25%</td><td>7.50%</td><td>7.75%</td></tr><tr><td>Post-65</td><td>7.00%</td><td>7.25%</td><td>7.50%</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>2022</td><td>2022</td><td>2022</td></tr><tr><td>Post-65</td><td>2022</td><td>2022</td><td>2022</td></tr></table>

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

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

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

<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>2014</td><td></td><td></td><td colspan="2">Increase /(Decrease) (In Thousands)</td></tr><tr><td>Entergy Corporation and its subsidiaries</td><td>$234,971</td><td>$16,769</td><td>($190,996)</td><td>($13,566)</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 $43.3 million in 2014, $44.5 million in 2013, and $43.7 million in 2012. 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 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 885,200 authorized shares remaining for long-term incentive and restricted unit awards as of December 31, 2014. 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, 2014, 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, 2014, there were 1,579,563 authorized shares remaining for stock-based awards, including 2,000,000 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>2014</td><td>2013</td><td>2012</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>$4.1</td><td>$4.1</td><td>$7.7</td></tr><tr><td>Tax benefit recognized in Entergy’s Consolidated Net Income</td><td>$1.6</td><td>$1.6</td><td>$3.0</td></tr><tr><td>Compensation cost capitalized as part of fixed assets and inventory</td><td>$0.7</td><td>$0.7</td><td>$1.5</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>2014</td><td>2013</td><td>2012</td></tr><tr><td>Stock price volatility</td><td>24.67%</td><td>24.61%</td><td>25.11%</td></tr><tr><td>Expected term in years</td><td>6.95</td><td>6.69</td><td>6.55</td></tr><tr><td>Risk-free interest rate</td><td>2.16%</td><td>1.31%</td><td>1.22%</td></tr><tr><td>Dividend yield</td><td>4.75%</td><td>4.75%</td><td>4.50%</td></tr><tr><td>Dividend payment per share</td><td>$3.32</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 after-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, 2014 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, 2014</td><td>9,639,849</td><td>$80.06</td><td></td><td></td></tr><tr><td>Options granted</td><td>611,700</td><td>$63.17</td><td></td><td></td></tr><tr><td>Options exercised</td><td>(2,852,350)</td><td>$68.19</td><td></td><td></td></tr><tr><td>Options forfeited/expired</td><td>(117,803)</td><td>$82.48</td><td></td><td></td></tr><tr><td>Options outstanding as of December 31, 2014</td><td>7,281,396</td><td>$83.25</td><td>$30,830,809</td><td>4.3 years</td></tr><tr><td>Options exercisable as of December 31, 2014</td><td>6,232,998</td><td>$86.41</td><td>$6,657,504</td><td>3.6 years</td></tr><tr><td>Weighted-average grant-date fair value of options granted during 2014</td><td>$8.71</td><td></td><td></td><td></td></tr></table>

The weighted-average grant-date fair value of options granted during the year was $8.00 for 2013 and $9.42 for 2012. The total intrinsic value of stock options exercised was $25.5 million during 2014, $5.7 million during 2013, and $39.8 million during 2012. 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. The aggregate intrinsic value of the stock options outstanding as of December 31, 2014 was $30.8 million. 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 2014, $11 million during 2013, and $11 million during 2012.



The following table summarizes information about stock options outstanding as of December 31, 2014:

<table><tr><td></td><td></td><td colspan="2">Options Outstanding</td><td colspan="2">Options Exercisable</td></tr><tr><td>Range of Exercise Prices</td><td>As of 12/31/2014</td><td>Weighted-Avg. Remaining Contractual Life-Yrs.</td><td>Weighted Avg. Exercise Price</td><td>Number Exercisable as of 12/31/2014</td><td>Weighted Avg. Exercise Price</td></tr><tr><td>$51-</td><td>$64.99</td><td>1,138,602</td><td>8.6</td><td>$63.84</td><td>192,152</td></tr><tr><td>$65-</td><td>$78.99</td><td>3,095,377</td><td>4.4</td><td>$74.31</td><td>2,993,429</td></tr><tr><td>$79-</td><td>$91.99</td><td>1,604,717</td><td>2.1</td><td>$91.82</td><td>1,604,717</td></tr><tr><td>$92-</td><td>$108.20</td><td>1,442,700</td><td>3.1</td><td>$108.20</td><td>1,442,700</td></tr><tr><td>$51-</td><td>$108.20</td><td>7,281,396</td><td>4.3</td><td>$83.25</td><td>6,232,998</td></tr><tr><td></td><td></td><td></td><td></td><td></td><td>$86.41</td></tr></table>

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

## Restricted Stock Awards

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

<table><tr><td rowspan="2"></td><td>2014</td><td>2013</td><td>2012</td></tr><tr><td colspan="3">(In Millions)</td></tr><tr><td>Compensation expense included in Entergy’s Consolidated Net Income</td><td>$19.3</td><td>$16.4</td><td>$11.4</td></tr><tr><td>Tax benefit recognized in Entergy’s Consolidated Net Income</td><td>$7.5</td><td>$6.3</td><td>$4.4</td></tr><tr><td>Compensation cost capitalized as part of fixed assets and inventory</td><td>$3.1</td><td>$2.6</td><td>$2.0</td></tr></table>

## Long-Term Performance Unit Program

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



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

<table><tr><td></td><td>2014</td><td>2013</td><td>2012</td></tr><tr><td></td><td colspan="3">(In Millions)</td></tr><tr><td>Fair value of long-term performance units as of December 31,</td><td>$23.4</td><td>$11.1</td><td>$4.3</td></tr><tr><td>Compensation expense included in Entergy’s Consolidated Net Income</td><td>$10.7</td><td>$6.0</td><td>($5.0)</td></tr><tr><td>Tax benefit (expense) recognized in Entergy’s Consolidated Net Income</td><td>$4.1</td><td>$2.3</td><td>($1.9)</td></tr><tr><td>Compensation cost capitalized as part of fixed assets and inventory</td><td>$1.5</td><td>$0.9</td><td>($0.9)</td></tr></table>

There was no payout in 2014 for the performance units granted in 2011 applicable to the 2011 – 2013 performance period.

## Restricted Unit Awards

Entergy grants restricted unit awards earned under its stock benefit plans in the form of stock units that are subject to time-based restrictions. The restricted units are equal to the cash value of shares of Entergy Corporation common stock at the time of vesting. The costs of restricted unit awards are charged to income over the restricted period, which varies from grant to grant. The average vesting period for restricted unit awards granted is 36 months. As of December 31, 2014, there were 98,334 unvested restricted units that are expected to vest over an average period of 21 months.

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

<table><tr><td></td><td>2014</td><td>2013</td><td>2012</td></tr><tr><td></td><td colspan="3">(In Millions)</td></tr><tr><td>Fair value of restricted awards as of December 31,</td><td>$3.3</td><td>$2.5</td><td>$3.0</td></tr><tr><td>Compensation expense included in Entergy’s Consolidated Net Income</td><td>$2.2</td><td>$1.4</td><td>$1.3</td></tr><tr><td>Tax benefit recognized in Entergy’s Consolidated Net Income</td><td>$0.9</td><td>$0.6</td><td>$0.5</td></tr><tr><td>Compensation cost capitalized as part of fixed assets and inventory</td><td>$0.3</td><td>$0.2</td><td>$0.2</td></tr></table>

Entergy paid $1.7 million in 2014 for awards under the Restricted Units Awards Plan.



## NOTE 13. BUSINESS SEGMENT INFORMATION

Entergy’s reportable segments as of December 31, 2014 are Utility and Entergy Wholesale Commodities. Utility includes the generation, transmission, distribution, and sale of electric power in portions of Arkansas, Louisiana, Mississippi, and Texas, and natural gas utility service in portions of Louisiana. Entergy Wholesale Commodities includes the ownership, operation, and 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>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></td><td>(In Thousands)</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>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>$38,295,309</td><td>$10,279,500</td><td>($654,831)</td><td>($1,392,124)</td><td>$46,527,854</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><tr><td></td><td></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>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>$35,539,585</td><td>$9,696,705</td><td>($486,438)</td><td>($1,343,406)</td><td>$43,406,446</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>



<table><tr><td>2012</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>$8,005,091</td><td>$2,326,309</td><td>$4,048</td><td>($33,369)</td><td>$10,302,079</td></tr><tr><td>Depreciation, amortization, &amp; decommissioning</td><td>$1,076,845</td><td>$248,143</td><td>$4,357</td><td>$—</td><td>$1,329,345</td></tr><tr><td>Interest and investment income</td><td>$150,292</td><td>$105,062</td><td>$30,656</td><td>($158,234)</td><td>$127,776</td></tr><tr><td>Interest expense</td><td>$476,485</td><td>$17,900</td><td>$126,913</td><td>($52,014)</td><td>$569,284</td></tr><tr><td>Income taxes</td><td>$49,340</td><td>$61,329</td><td>($79,814)</td><td>$—</td><td>$30,855</td></tr><tr><td>Consolidated net income (loss)</td><td>$960,322</td><td>$40,427</td><td>($26,167)</td><td>($106,219)</td><td>$868,363</td></tr><tr><td>Total assets</td><td>$35,438,130</td><td>$9,623,345</td><td>($509,985)</td><td>($1,348,988)</td><td>$43,202,502</td></tr><tr><td>Investment in affiliates - at equity</td><td>$199</td><td>$46,539</td><td>$—</td><td>$—</td><td>$46,738</td></tr><tr><td>Cash paid for long-lived asset additions</td><td>$3,182,695</td><td>$577,652</td><td>$619</td><td>$—</td><td>$3,760,966</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 after-tax), including approximately $85 million ($55 million after-tax) for Utility and $25 million ($15 million after-tax) for Entergy Wholesale Commodities, and expenses in 2014 of approximately $20 million ($12 million after-tax), including approximately $15 million ($9 million after-tax) for Utility and $5 million ($3 million after-tax) for Entergy Wholesale Commodities, recorded in connection with a strategic imperative intended to optimize the organization through a process known as human capital management. In July 2013 management completed a comprehensive review of Entergy’s organization design and processes. This effort resulted in a new internal organization structure, which resulted in the elimination of approximately 800 employee positions. The restructuring costs associated with this phase of human capital management included implementation costs, severance expenses, benefits-related costs, including pension curtailment losses and special termination benefits, and impairments of corporate property, plant, and equipment. The implementation costs, severance costs, and benefits-related costs are included in “Other 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="3">2014</td><td rowspan="2">Remaining Accrual as of December 31, 2014</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>Non-Cash Portion</td></tr><tr><td></td><td></td><td></td><td></td><td>(In Millions)</td><td></td><td></td><td></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>—</td><td>6</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>$53</td><td>$—</td><td>$6</td></tr></table>

## Geographic Areas

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



## NOTE 14. EQUITY METHOD INVESTMENTS

As of December 31, 2014, 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</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>2014</td><td>2013</td><td>2012</td></tr><tr><td></td><td colspan="3">(In Thousands)</td></tr><tr><td>Beginning of year</td><td>$40,350</td><td>$46,738</td><td>$44,876</td></tr><tr><td>Income (loss) from the investments</td><td>(5,169)</td><td>(1,702)</td><td>1,162</td></tr><tr><td>Dispositions and other adjustments</td><td>1,053</td><td>(4,686)</td><td>700</td></tr><tr><td>End of year</td><td>$36,234</td><td>$40,350</td><td>$46,738</td></tr></table>

## Transactions with equity method investees

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

## NOTE 15. ACQUISITIONS AND DISPOSITIONS

## Acquisitions

## Hot Spring Energy Facility

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

## Hinds Energy Facility

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

## 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 $16 million in 2014, $18 million in 2013, and $17 million in 2012. The amounts to be amortized to revenue for the next five years will be $15 million in 2015, $13 million for 2016, $12 million for 2017, $8 million for 2018, and $13 million for 2019.

## 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, 2013, and 2012, 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 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 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, 2014 is approximately 3 years. Planned generation currently under contract from Entergy Wholesale Commodities nuclear power plants is 86% for 2015, of which approximately 62% is sold under financial derivatives and the remainder under normal purchase/normal sale contracts. Total planned generation for 2015 is 35 TWh.

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

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

Entergy manages fuel price volatility for its Louisiana jurisdictions (Entergy Gulf States Louisiana, Entergy Louisiana, and Entergy New Orleans) and Entergy Mississippi through the purchase of short-term natural gas swaps that financially settle against NYMEX futures. These swaps are marked-to-market through fuel expense with



offsetting regulatory assets or liabilities. All benefits or costs of the program are recorded in fuel costs. The notional volumes of these swaps are based on a portion of projected annual exposure to gas for electric generation and projected winter purchases for gas distribution at Entergy Gulf States Louisiana and Entergy New Orleans. The total volume of natural gas swaps outstanding as of December 31, 2014 is 21,475,000 MMBtu for Entergy, including 8,740,000 MMBtu for Entergy Gulf States Louisiana, 8,810,000 MMBtu for Entergy Louisiana, 3,230,000 MMBtu for Entergy Mississippi, and 695,000 MMBtu for Entergy New Orleans. Credit support for these natural gas swaps is covered by master agreements that do not require collateralization based on mark-to-market value, but do carry adequate assurance language that may lead to collateralization requests.

During the second quarter 2014, Entergy participated in the annual FTR auction process for the MISO planning year of June 1, 2014 through May 31, 2015. FTRs are derivative instruments which represent economic hedges of future congestion charges that will be incurred in serving Entergy's customer load. They are not designated as hedging instruments. Entergy initially records FTRs at their estimated fair value and subsequently adjusts the carrying value to their estimated fair value at the end of each accounting period 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, 2014 is 45,196 GWh for Entergy, including 9,844 GWh for Entergy Arkansas, 9,881 GWh for Entergy Gulf States Louisiana, 10,691 GWh for Entergy Louisiana, 5,403 GWh for Entergy Mississippi, 3,633 GWh for Entergy New Orleans, and 5,669 GWh for Entergy Texas. Credit support for FTRs held by the Utility operating companies is covered by cash 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. No cash collateral was required to be posted for FTR exposure for the Utility operating companies or Entergy Wholesale Commodities.

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 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>$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>



The fair values of Entergy’s derivative instruments in the consolidated balance sheet as of December 31, 2013 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>$118</td><td>($99)</td><td>$19</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>($17)</td><td>$—</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>$197</td><td>($131)</td><td>$66</td><td>Entergy Wholesale Commodities</td></tr><tr><td>Electricity swaps and options</td><td>Other non-current liabilities (non-current portion)</td><td>$46</td><td>($17)</td><td>$29</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>$177</td><td>($122)</td><td>$55</td><td>Entergy Wholesale Commodities</td></tr><tr><td>Natural gas swaps</td><td>Prepayments and other</td><td>$6</td><td>$—</td><td>$6</td><td>Utility</td></tr><tr><td>FTRs</td><td>Prepayments and other</td><td>$36</td><td>($2)</td><td>$34</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>$201</td><td>($89)</td><td>$112</td><td>Entergy Wholesale Commodities</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 amounts of $25 million held as of December 31, 2014 and $47 million posted and $4 million held as of December 31, 2013, respectively



The effect of Entergy’s derivative instruments designated as cash flow hedges on the consolidated income statements for the years ended December 31, 2014, 2013, and 2012 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>2014</td><td>(In Millions)</td><td></td><td>(In Millions)</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><tr><td>2012</td><td></td><td></td><td></td></tr><tr><td>Electricity swaps and options</td><td>$111</td><td>Competitive business operating revenues</td><td>$268</td></tr></table>

(a) Before taxes of ($68) million, $18 million, and $94 million, for the years ended December 31, 2014, 2013, and 2012, 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 $7 million, ($6) million, and ($14) million for the years ended December 31, 2014, 2013, and 2012, respectively.

Based on market prices as of December 31, 2014, unrealized gains recorded in AOCI on cash flow hedges relating to power sales totaled $156 million of net unrealized gains. Approximately $109 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 income statements for the years ended December 31, 2014, 2013, and 2012 is as follows:

<table><tr><td rowspan="2">Instrument</td><td rowspan="2">Amount of gain (loss) recognized in AOCI</td><td rowspan="2">Income Statement location</td><td colspan="2">Amount of gain (loss) recorded in the income statement</td></tr><tr><td>(In Millions)</td><td>(In Millions)</td></tr><tr><td>2014</td><td></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)</td><td>($8)</td></tr><tr><td>FTRs</td><td>—</td><td>Purchased power expense</td><td>(b)</td><td>$229</td></tr><tr><td>Electricity swaps and options</td><td>($13)</td><td>Competitive business operating revenues</td><td></td><td>$56</td></tr><tr><td>2013</td><td></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)</td><td>$13</td></tr><tr><td>FTRs</td><td>—</td><td>Purchased power</td><td>(b)</td><td>$3</td></tr><tr><td>Electricity swaps and options</td><td>$1</td><td>Competitive business operating revenues</td><td></td><td>($50)</td></tr><tr><td>2012</td><td></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)</td><td>($42)</td></tr><tr><td>Electricity swaps and options</td><td>$1</td><td>Competitive business operating revenues</td><td></td><td>$1</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 Vice President, Accounting Policy and External Reporting.



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

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

On a daily basis, Entergy Wholesale Commodities 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 future congestion costs in MISO between applicable generation and load pricing nodes based on prices published by MISO. They are classified as Level 3 assets and liabilities. The valuations of these assets and liabilities are performed by the Entergy Wholesale Commodities Risk Control group for the unregulated business and by the System Planning and Operations Risk Control group for the Utility operating companies. Entergy's Accounting Policy group reviews these valuations for reasonableness, with the assistance of others within the organization with knowledge of the various inputs and assumptions used in the valuation. The System Planning and Operations Risk Control group reports to the Vice President and Treasurer. The Accounting Policy group reports to the Vice President, Accounting Policy and External Reporting.

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, 2014 and December 31, 2013. The assessment of the significance of a particular input to a fair value measurement requires judgment and may affect their placement within the fair value hierarchy levels.



<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 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 (b)</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><tr><td>2013</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 Millions)</td></tr><tr><td>Assets:</td><td></td><td></td><td></td><td></td></tr><tr><td>Temporary cash investments</td><td>$609</td><td>$—</td><td>$—</td><td>$609</td></tr><tr><td>Decommissioning trust funds (a):</td><td></td><td></td><td></td><td></td></tr><tr><td>Equity securities</td><td>472</td><td>2,601 (b)</td><td>—</td><td>3,073</td></tr><tr><td>Debt securities</td><td>783</td><td>1,047</td><td>—</td><td>1,830</td></tr><tr><td>Power contracts</td><td>—</td><td>—</td><td>74</td><td>74</td></tr><tr><td>Securitization recovery trust account</td><td>46</td><td>—</td><td>—</td><td>46</td></tr><tr><td>Escrow accounts</td><td>115</td><td>—</td><td>—</td><td>115</td></tr><tr><td>Gas hedge contracts</td><td>6</td><td>—</td><td>—</td><td>6</td></tr><tr><td>FTRs</td><td>—</td><td>—</td><td>34</td><td>34</td></tr><tr><td></td><td>$2,031</td><td>$3,648</td><td>$108</td><td>$5,787</td></tr><tr><td>Liabilities:</td><td></td><td></td><td></td><td></td></tr><tr><td>Power contracts</td><td>$—</td><td>$—</td><td>$207</td><td>$207</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.

(b) Commingled equity funds may be redeemed semi-monthly.

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



<table><tr><td rowspan="3"></td><td colspan="2">2014</td><td colspan="2">2013</td><td colspan="2">2012</td></tr><tr><td>Power Contracts</td><td>FTRs</td><td>Power Contracts</td><td>FTRs</td><td>Power Contracts</td><td></td></tr><tr><td></td><td colspan="2">(In Millions)</td><td></td><td></td><td></td></tr><tr><td>Balance as of January 1,</td><td>($133)</td><td>$34</td><td>$178</td><td>$—</td><td>$312</td><td></td></tr><tr><td>Realized losses included in earnings</td><td>(65)</td><td>—</td><td>(38)</td><td>—</td><td>(11)</td><td></td></tr><tr><td>Unrealized gains (losses) included in earnings</td><td>120</td><td>2</td><td>(35)</td><td>—</td><td>(4)</td><td></td></tr><tr><td>Unrealized gains (losses) included in OCI</td><td>131</td><td>—</td><td>(204)</td><td>—</td><td>140</td><td></td></tr><tr><td>Unrealized gains included as a regulatory liability / asset</td><td>—</td><td>119</td><td>—</td><td>—</td><td>—</td><td></td></tr><tr><td>Issuances of FTRs</td><td>—</td><td>121</td><td>—</td><td>37</td><td>—</td><td></td></tr><tr><td>Purchases</td><td>17</td><td>—</td><td>14</td><td>—</td><td>9</td><td></td></tr><tr><td>Settlements</td><td>145</td><td>(229)</td><td>(48)</td><td>(3)</td><td>(268)</td><td></td></tr><tr><td>Balance as of December 31,</td><td>$215</td><td>$47</td><td>($133)</td><td>$34</td><td>$178</td><td></td></tr></table>

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, 2014:

<table><tr><td>Transaction Type</td><td>Fair Value as of December 31, 2014</td><td>Unobservable Inputs</td><td>Range from Average %</td><td>Effect on Fair Value</td></tr><tr><td>Electricity swaps</td><td>$165</td><td>Unit contingent discount</td><td>+/-3%</td><td>(In Millions)</td></tr><tr><td>Electricity options</td><td>$50</td><td>Implied volatility</td><td>+/-130%</td><td>$43</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 Gulf States Louisiana has recorded an offsetting amount of unrealized gains/(losses) in other deferred credits. Decommissioning trust funds for Pilgrim, Indian Point 1 and 2, Vermont Yankee, and Palisades do not meet the criteria for regulatory accounting treatment. Accordingly, unrealized gains recorded on the assets in these trust funds are recognized in the accumulated other comprehensive income component of shareholders' equity because these assets are classified as available for sale. Unrealized losses (where cost exceeds fair market value) on the assets in these trust funds are also recorded in the accumulated other comprehensive income component of shareholders' equity unless the unrealized loss is other than temporary and therefore recorded in earnings. Generally, Entergy records 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, 2014 and 2013 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 colspan="3">(In Millions)</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><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 colspan="3">(In Millions)</td></tr><tr><td>2013</td><td></td><td></td><td></td></tr><tr><td>Equity Securities</td><td>$3,073</td><td>$1,260</td><td>$—</td></tr><tr><td>Debt Securities</td><td>1,830</td><td>47</td><td>29</td></tr><tr><td>Total</td><td>$4,903</td><td>$1,307</td><td>$29</td></tr></table>

Deferred taxes on unrealized gains/(losses) are recorded in other comprehensive income 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 $396 million and $329 million as of December 31, 2014 and 2013, respectively. The amortized cost of debt securities was $2,019 million as of December 31, 2014 and $1,843 million as of December 31, 2013. As of December 31, 2014, the debt securities have an average coupon rate of approximately 3.31%, an average duration of approximately 5.65 years, and an average maturity of approximately 8.45 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, 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 fair value and gross unrealized losses of available-for-sale equity and debt securities, summarized by investment type and length of time that the securities have been in a continuous loss position, are as follows as of December 31, 2013:

<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>$—</td><td>$—</td><td>$892</td><td>$24</td></tr><tr><td>More than 12 months</td><td>—</td><td>—</td><td>60</td><td>5</td></tr><tr><td>Total</td><td>$—</td><td>$—</td><td>$952</td><td>$29</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, 2014 and 2013 are as follows:

<table><tr><td></td><td>2014</td><td>2013</td></tr><tr><td></td><td colspan="2">(In Millions)</td></tr><tr><td>less than 1 year</td><td>$94</td><td>$83</td></tr><tr><td>1 year - 5 years</td><td>783</td><td>752</td></tr><tr><td>5 years - 10 years</td><td>681</td><td>620</td></tr><tr><td>10 years - 15 years</td><td>173</td><td>169</td></tr><tr><td>15 years - 20 years</td><td>79</td><td>52</td></tr><tr><td>20 years+</td><td>275</td><td>154</td></tr><tr><td>Total</td><td>$2,085</td><td>$1,830</td></tr></table>

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



## Other-than-temporary impairments and unrealized gains and losses

Entergy, Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, and System Energy evaluate unrealized losses at the end of each period to determine whether an other-than-temporary impairment has occurred. The assessment of whether an investment in a debt security has suffered an other-than-temporary impairment is based on whether Entergy has the intent to sell or more likely than not will be required to sell the debt security before recovery 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, 2014, 2013, and 2012. The assessment of whether an investment in an equity security has suffered an other-than-temporary impairment continues to be based on a number of factors including, first, whether Entergy has the ability and intent to hold the investment to recover its value, the duration and severity of any losses, and, then, whether it is expected that the investment will recover its value within a reasonable period of time. Entergy’s trusts are managed by third parties who operate in accordance with agreements that define investment guidelines and place restrictions on the purchases and sales of investments. Entergy did not record material charges to other income in 2014, 2013, and 2012, 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 Gulf States Louisiana, Entergy Louisiana, and System Energy consolidate the respective companies from which they lease nuclear fuel, usually in a sale and leaseback transaction. This is because Entergy directs the nuclear fuel companies with respect to nuclear fuel purchases, assists the nuclear fuel companies in obtaining financing, and, if financing cannot be arranged, the lessee (Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, or System Energy) is responsible to repurchase nuclear fuel to allow the nuclear fuel company (the VIE) to meet its obligations. During the term of the arrangements, none of the Entergy operating companies have been required to provide financial support apart from their scheduled lease payments. See Note 4 to the financial statements for details of the nuclear fuel companies' credit facility and commercial paper borrowings and long-term debt that are reported by Entergy, Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, and System Energy. These amounts also represent Entergy's and the respective Registrant Subsidiary's maximum exposure to losses associated with their respective interests in the nuclear fuel companies.

Entergy Gulf States Reconstruction Funding I, LLC, and Entergy Texas Restoration Funding, LLC, companies wholly-owned and consolidated by Entergy Texas, are variable interest entities and Entergy Texas is the primary beneficiary. In June 2007, Entergy Gulf States Reconstruction Funding issued senior secured transition bonds (securitization bonds) to finance Entergy Texas's Hurricane Rita reconstruction costs. In November 2009, Entergy Texas Restoration Funding issued senior secured transition bonds (securitization bonds) to finance Entergy Texas's Hurricane Ike and Hurricane Gustav restoration costs. With the proceeds, the variable interest entities purchased from Entergy Texas the transition property, which is the right to recover from customers through a transition charge amounts sufficient to service the securitization bonds. The transition property is reflected as a regulatory asset on the consolidated Entergy Texas balance sheet. The creditors of Entergy Texas do not have recourse to the assets or revenues of the variable interest entities, including the transition property, and the creditors



of the variable interest entities do not have recourse to the assets or revenues of Entergy Texas. Entergy Texas has no payment obligations to the variable interest entities except to remit transition charge collections. See Note 5 to the financial statements for additional details regarding the securitization bonds.

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

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

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

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



## NOTE 19. QUARTERLY FINANCIAL DATA (UNAUDITED)

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

<table><tr><td></td><td>Operating Revenues</td><td>Operating Income</td><td>Consolidated Net Income</td><td>Net Income Attributable to Entergy Corporation</td></tr><tr><td></td><td colspan="4">(In Thousands)</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><tr><td>2013:</td><td></td><td></td><td></td><td></td></tr><tr><td>First Quarter</td><td>$2,608,874</td><td>$394,045</td><td>$166,982</td><td>$161,400</td></tr><tr><td>Second Quarter</td><td>$2,738,208</td><td>$346,512</td><td>$168,055</td><td>$163,723</td></tr><tr><td>Third Quarter</td><td>$3,351,959</td><td>$388,894</td><td>$244,182</td><td>$239,850</td></tr><tr><td>Fourth Quarter</td><td>$2,691,906</td><td>$225,548</td><td>$151,353</td><td>$146,929</td></tr></table>

Earnings per Average Common Share

<table><tr><td rowspan="2"></td><td colspan="2">2014</td><td colspan="2">2013</td></tr><tr><td>Basic</td><td>Diluted</td><td>Basic</td><td>Diluted</td></tr><tr><td>First Quarter</td><td>$2.24</td><td>$2.24</td><td>$0.91</td><td>$0.90</td></tr><tr><td>Second Quarter</td><td>$1.06</td><td>$1.05</td><td>$0.92</td><td>$0.92</td></tr><tr><td>Third Quarter</td><td>$1.28</td><td>$1.27</td><td>$1.35</td><td>$1.34</td></tr><tr><td>Fourth Quarter</td><td>$0.67</td><td>$0.66</td><td>$0.82</td><td>$0.82</td></tr></table>

As discussed in more detail in Note 1 to the financial statements, operating results for 2014 include $154 million ($100 million after-tax) of charges related to Vermont Yankee primarily resulting from the effects of an updated decommissioning cost study completed in the third quarter 2014 along with reassessment of assumptions regarding the timing of decommissioning cash flows and severance and employee retention costs. Results of operations for 2014 also include the $56.2 million ($36.7 million after-tax) write-off of Entergy Mississippi's regulatory asset associated with new nuclear generation development costs as a 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.

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



## Directors and Executive Officers
(age as of Dec. 31, 2014)

## DIRECTORS

## MAUREEN SCANNELL BATEMAN

Attorney, Former Executive Vice President and General Counsel, State Street Corporation, New York, New York
An Entergy director since 2000. Age 71

## PATRICK J. CONDON

Retired Audit Partner, Deloitte & Touche LLP, Frankfort, Illinois
Joined the Entergy Board in 2015. Age 65

## LEO P. DENAULT

Chairman of the Board and Chief Executive Officer,
Entergy Corporation, New Orleans, Louisiana
Chairman and Chief Executive Officer since 2013. Age 55

## ADMIRAL KIRKLAND H. DONALD, USN (RET.)

President and Chief Executive Officer, Systems Planning and Analysis, Inc., Alexandria, Virginia
An Entergy director since 2013. Age 61

## GARY W. EDWARDS

Former Senior Executive Vice President, Conoco Inc.,
Houston, Texas
Lead director of Entergy. An Entergy director since 2005. Age 73

## ALEXIS M. HERMAN

Chair and Chief Executive Officer, New Ventures, LLC,
McLean, Virginia
An Entergy director since 2003. Age 67

## DONALD C. HINTZ

Former President, Entergy Corporation and Entergy Services, Inc., Punta Gorda, Florida
An Entergy director since 2004. Age 71

## STUART L. LEVENICK

Former Group President and Executive Office Member, Caterpillar Inc., Peoria, Illinois
An Entergy director since 2005. Age 61

## BLANCHE LAMBERT LINCOLN

Principal, Lincoln Policy Group, Arlington, Virginia
An Entergy director since 2011. Age 54

## STEWART C. MYERS \( ^{*} \) 

Robert C. Merton (1970) Professor of Financial Economics, MIT Sloan School of Management, Cambridge, Massachusetts
An Entergy director since 2009. Age 74

## KAREN A. PUCKETT

President-Global Markets, CenturyLink, Inc., Monroe, Louisiana
Joined the Entergy Board in 2015. Age 54

## W. J. "BILLY" TAUZIN

Owner, Tauzin Strategic Networks, Washington, D.C.
An Entergy director since 2005. Age 71

## STEVEN V. WILKINSON

Retired Audit Partner, Arthur Andersen LLP, Watersmeet, Michigan
An Entergy director since 2003. Age 73

* Stewart C. Myers reached age 74 before Jan. 1, 2015, and pursuant to our Corporate Governance Guidelines will not stand for re-election at the 2015 Annual Meeting of Shareholders.

## EXECUTIVE OFFICERS

## 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 55

## 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 56

## 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 55

## 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 43

## MARK T. SAVOFF

Executive Vice President and Chief Operating Officer
Joined Entergy in 2003. Former executive vice president, operations. Age 58

## RODERICK K. WEST

Executive Vice President and Chief Administrative Officer
Joined Entergy in 1999. Former president and chief executive officer of Entergy New Orleans. Age 46

## JEFFREY S. FORBES

Executive Vice President, Nuclear Operations/Chief Nuclear Officer
Joined Entergy in 2003. Became executive vice president, nuclear operations/chief nuclear officer in 2013, after serving as senior vice president of nuclear operations. Age 58

## 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 53

## 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 44

## 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 56



## 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 Paula Waters, vice president, investor relations, at 504-576-4380 or pwater1@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. 30, 2015, there were 179,697,449 shares of Entergy common stock outstanding. Shareholders of record totaled 30,762, and approximately 153,511 investors held Entergy stock in “street name” through a broker.

## Certifications

In May 2014, 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, 2014.

## Dividend Payments

All of Entergy’s 2014 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 2015 are:

<table><tr><td>Declaration Date</td><td>Record Date</td><td>Payment Date</td></tr><tr><td>January 30</td><td>February 12</td><td>March 2</td></tr><tr><td>April 1</td><td>May 14</td><td>June 1</td></tr><tr><td>July 30</td><td>August 13</td><td>September 1</td></tr><tr><td>October 30</td><td>November 12</td><td>December 1</td></tr></table>

Quarterly dividend payments (in cents-per-share):

<table><tr><td>Quarter</td><td>2015</td><td>2014</td><td>2013</td><td>2012</td><td>2011</td></tr><tr><td>1</td><td>83</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>83</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 2014 and 2013 were as follows (in dollars):

<table><tr><td></td><td colspan="2">2014</td><td colspan="2">2013</td></tr><tr><td>Quarter</td><td>High</td><td>Low</td><td>High</td><td>Low</td></tr><tr><td>1</td><td>67.02</td><td>60.40</td><td>65.39</td><td>61.09</td></tr><tr><td>2</td><td>82.30</td><td>66.41</td><td>72.10</td><td>63.12</td></tr><tr><td>3</td><td>82.48</td><td>70.70</td><td>72.60</td><td>61.66</td></tr><tr><td>4</td><td>92.02</td><td>76.51</td><td>68.63</td><td>60.22</td></tr></table>



Powered by TCPDF (www.tcpdf.org)




Entergy Corporation
Post Office Box 61000
New Orleans, LA 70161
entergy.com