SouthernCompany.com2016 Annual ReportThe energy to lead Thomas A. Fanning Chairman, President & CEO, Southern Company Shareholder Information Transfer Agent Investor Information Wells Fargo Shareowner Services is Southern Company’s transfer For information about earnings and dividends, stock agent, dividend-paying agent, investment plan administrator and quotes and current news releases, please visit us at registrar. If you have questions concerning your registered Southern investor.southerncompany.com. Southern Company Shareholder Relations materials by logging on at www.icsdelivery.com/so. Institutional Investor Inquiries Southern Company maintains an investor relations office in Atlanta, Georgia, 404.506.0780, to meet the information needs of institutional investors and securities analysts. Electronic Delivery of Proxy Materials Any stockholder may enroll for electronic delivery of proxy Environmental Information Southern Company publishes information on its activities to meet environmental commitments at www.southerncompany.com/ 600 North 18th St. Bin 14N-8195 Birmingham, AL 35203-2206 Southern Company common stock is listed on the NYSE under the ticker symbol SO. On December 31, 2016, Southern Company had 126,338 shareholders of record. Visit our Corporate Responsibility Report at www.southerncompany.com/corporate-responsibility Follow us on Twitter at www.twitter.com/southerncompany The Southern Investment Plan is a convenient way to become corporate-responsibility. a Southern Company shareholder. Participants in the Plan can purchase additional shares in Southern Company through optional To request printed materials, write to: cash purchases and reinvestment of dividends. The Southern Director, Environmental Affairs Investment Plan prospectus can be found at Research and Environmental Affairs Southern Company has paid dividends since 1948. Historically, dividends are declared and paid quarterly at the discretion of Common Stock The 2017 Annual Meeting of Stockholders will be held Wednesday, May 24, at 10 a.m. ET at The Lodge Conference Center at Callaway Visit our website at www.southerncompany.com Gardens, Highway 18, Pine Mountain, Ga. 31822. Company shareowner account, please contact: Wells Fargo Shareowner Services 1110 Centre Pointe Curve, Suite 101 Mendota Heights, Minnesota 55120 Telephone: 1.800.554.7626 Website: shareowneronline.com Telephone: 404.506.0965 Email: stockholders@southernco.com Southern Investment Plan www.southerncompany.com. Dividend Payments the Board of Directors. Annual Meeting Auditors Deloitte & Touche LLP 191 Peachtree St. NE Suite 2000 Atlanta, GA 30303 Chairman’s Message i Dear fellow shareholders, One of the hallmarks of Southern Company has always been innovation. From our earliest days when James Mitchell lobbied London investors to secure the capital to build hydroelectric dams and transmission infrastructure in the state of Alabama at a time when electricity was not yet widely available in much of the southeastern United States, innovation has been a fundamental part of our company’s DNA. Fast forward to the present, where we once again find our- selves in a period of great change and opportunity. We live in an increasingly sophisticated digital age, where technology affects virtually everything we do, from how we manage our business operations to how we live our personal lives. At Southern Company, we are not merely adapting to this changing environment–we have the energy to lead the change. As a company, we are committed to “play offense” in this changing environment. We honor our past by pushing forward to build the future of energy. That’s why I’m so pleased with our historic growth in 2016. We proudly welcomed more than 6,000 new team members with the additions of AGL Resources (now Southern Company Gas) and PowerSecure. Our whole- sale subsidiary, Southern Power, continued to acquire solar, wind and natural gas generation facilities. Southern Company Gas acquired a 50 percent equity interest in the Southern Natural Gas pipeline system. And we announced a strategic alliance between Bloom Energy and PowerSecure for the deployment of fuel cell and battery storage technologies. Considered collectively, these moves are ultimately expected to provide new opportunities for growth beyond our tradi- tional retail and wholesale business models. They are designed to help meet customers’ current and expected future energy needs while diversifying revenue streams and supporting earnings growth. Just as Southern Company has historically embraced the full portfolio strategy with respect to power generation, the company has likewise embraced a strategy of diversification with respect to our portfolio of businesses, with the ultimate objective of supporting the long-term health and prosperity of the enterprise. With the emergence of natural gas and renewables as increas- ingly dominant energy solutions–and with the prospect of distributed generation, new technologies and new strategic alliances–we recognize and value the changing energy land- scape. Southern Company is committed to placing itself at the forefront of a rapidly evolving energy industry. The events of this past year underscore the fact that we are doing more than simply preparing for America’s energy future. We are creating it. The following is a brief synopsis of progress achieved during the past year with respect to our five strategic priorities: Excel at the Fundamentals Our traditional electric operating companies continue to be among the most highly rated utilities for customer satisfaction by J.D. Power, which ranks companies on the basis of power quality and reliability, price, billing and payment, corporate citizenship, communications and customer service. Southern Company was named to Fortune magazine’s World’s Most Admired Electric and Gas Utilities–one of only two companies to rank in the top three for each of the past seven years. 2016 was another outstanding year for our generating fleet, as well as our transmission and distribution systems. The system-wide equivalent forced outage rate (EFOR) for the combined winter and summer peak seasons–a major industry measure of reliability–was 1.76 percent, significantly better than our industry peers’ 2.27 percent, an average of our best peers’ EFOR for 2012-2014. Achieve Success with Major Construction Projects This past year saw significant milestones associated with our major construction projects, the Kemper County Energy Facility in Mississippi, and Plant Vogtle units 3 and 4 near Augusta, Georgia, both of which are at the forefront of innovation. When placed in service, the Kemper County Energy Facility will be the first electric generation facility to utilize Transport SOUTHERN COMPANY 2016 Annual Report Integrated Gasification (TRIG™) technology at commercial scale, deploying low-grade lignite coal to generate electricity from synthesis gas. The facility is able to produce electricity as cleanly as a natural gas facility while capturing 65 percent of the carbon dioxide emissions produced.Progress also continues at our other major construction project, the building of new nuclear units 3 and 4 at Georgia Power’s Plant Vogtle. In November, workers placed the first nuclear reactor vessel in the state of Georgia in more than 30 years. When completed, these new units will generate electricity for homes and businesses throughout the state of Georgia.Support the Building of a National Energy PolicyWe continue our leadership role to support a comprehensive national energy policy through active engagement in public policy debate, working constructively with legislators and reg-ulators to support energy policy that develops the full portfolio of generation sources, embraces innovation and promotes America’s financial integrity. The company is working with lawmakers on both sides of the aisle to advance the North American Energy Security and Infrastructure Act–a bipartisan effort that would help mod-ernize our nation’s energy infrastructure, protect the power grid, strengthen energy security and improve energy efficiency.Promote Energy InnovationOur team at the Energy Innovation Center is busy evaluating ideas and opportunities and developing new products and services to deliver tomorrow’s energy solutions, today. From indoor agriculture to electric transportation options and the charging infrastructure to support them, we are inventing the future of energy. And because no one has a monopoly on good ideas, we are engaged in various partnerships with both the public and pri-vate sectors, engaging some of the finest minds and creative resources available. In October, for example, we announced a strategic alliance between Bloom Energy and our subsidiary, PowerSecure, which will include project investment and joint technology development to provide behind-the-meter energy solutions. Together, Bloom and PowerSecure are delivering reliable on-site generation solutions tuned to the customer’s precise power requirements that can flexibly adapt to changing conditions, allowing for intelligent optimization of their energy usage while driving cost savings and long-term cost certainty.Value and Develop Our PeopleI am proud to report that in 2016 Southern Company was recognized by DiversityInc as one of the “Top 50 Companies for Diversity.” DiversityInc also ranked Southern Company number one on its list of “Top 10 Companies for Opportunity.” This is especially meaningful because it testifies that we were recognized not only for cultivating a diverse workplace, but that we are also considered the number one company in America in which the individuals who comprise that diverse workforce are afforded the opportunity to advance their careers. In addition, we earned a perfect score from the Human Rights Campaign on their Corporate Equality Index for 2017.Studies show that diverse environments not only increase overall business performance, but also provide a space where employee differences foster innovation and true inclusiveness. At Southern Company, we are committed to the notion that true diversity refers not only to diversity of human attributes, but also diversity of thought. As a result, I’ve challenged our leadership with increasing our cultural bandwidth to breed creative disruption as we look for ways to shape energy policy and business strategy.In closing, I would like to emphasize that I have never been more enthusiastic about the future. Rest assured, we remain committed to the ideals that have characterized our company for more than 100 years. James Mitchell’s original vision and purpose is not forgotten. Customers remain at the center of all we do, and our mission continues to be bigger than our bottom line. On behalf of our management and employees, I want to thank you for your continued support.Sincerely,Thomas A. FanningMarch 20, 2017Chairman’s MessageiiSOUTHERN COMPANY 2016 Annual Report 2.70 2.60 2.57 2.19 1.88 2.68 2.68 2.71 2.71 2.80 2.80 2.89 2.89 2.89 2.89 Financial Highlights iii ’12 ’13 ’14 ’15 ’16 ’12 ’12 ’13 ’13 ’14 ’14 ’15 ’15 ’16 ’16 Basic Earnings Per Share (in dollars) Basic Earnings Per Share Excluding Kemper IGCC Impacts, Acquisition and Integration Costs, Equity Return Related to Kemper IGCC Schedule Extension, Southern Company Gas Earnings, net of Acquisition and Integration Costs, Acquisition Debt Financing Costs, Common Stock Share Issuances to Finance a Portion of Southern Natural Gas Company, L.L.C. (SNG) Acquisition, MC Asset Recovery Insurance Settlements and Leveraged Lease Restructure Charge* (in dollars) * Not a financial measure under generally accepted accounting principles. See page 3 for specific adjustments made to this measure by year. 13.10 10.08 8.82 11.68 10.80 1.94 2.01 2.08 2.15 2.22 ’12 ’13 ’14 ’15 ’16 ’12 ’13 ’14 ’15 ’16 Return On Average Common Equity Dividends Per Share (percent) (in dollars) Operating Revenues (in millions) Earnings (in millions) Basic Earnings Per Share Diluted Earnings Per Share Dividends Per Share (amount paid) Dividend Yield (year-end, percent) Average Shares Outstanding (in millions) Return On Average Common Equity (percent) Book Value Per Share Market Price Per Share (year-end, closing) Total Market Value Of Common Stock (year-end, in millions) Total Assets (in millions) Total Kilowatt-Hour Sales (in millions) Retail Wholesale Total mmBtu Sales (in millions) Total Utility Customers* (year-end, in thousands) 2016 2015 Change $19,896 $2,448 $2.57 $2.55 $2.2225 4.5 951 10.80 $25.00 $49.19 $48,717 $109,697 195,641 160,745 34,896 349 9,179 $17,489 $2,367 $2.60 $2.59 $2.1525 4.6 910 11.68 $22.59 $46.79 $42,659 $78,318 190,989 160,484 30,505 – 4,546 13.8)% 3.4)% (1.2)% (1.5)% 3.3)% (2.2)% 4.5)% (7.5)% 10.7)% 5.1)% 14.2)% 40.1)% 2.4)% 0.2)% 14.4)% – 101.9)% * 2016 total utility customers now includes customers of Southern Company Gas. These customers were not previously included in this reporting category prior to Southern Company’s acquisition of Southern Company Gas. SOUTHERN COMPANY 2016 Annual Report iv The energy to build shareholder value Throughout Southern Company’s history, an unwavering commit- accounted for approximately 69 percent of the increase in our ment to customers has been a cornerstone of our business. We shareholder value, compared with approximately 40 percent of believe keeping customers at the center of all we do ultimately the increase in shareholder value for the S&P 500. translates to value creation for investors, and this has been borne out in the results we’ve delivered year after year. Of course, dividends do more than simply provide cash to share- holders; they help shape a company’s approach to risk. Once Over the long term, Southern Company has proved to be a solid again, the proof is in the numbers. In 2016, Southern Company investment, outperforming the S&P 500 over the 10-, 20- and was the second-least volatile stock in the Philadelphia Electric 30-year periods ended December 31, 2016. Our dividend – an Utility Index. Stocks with low volatility are often less prone to important part of that performance – increased for the 15th price swings during times of market stress, and are therefore consecutive year in 2016, and we have paid shareholder dividends considered more stable. every quarter since 1948. Keeping customers first–along with stellar reliability and prices At year-end, Southern Company’s dividend yield was 4.5 percent, below the national average–has enabled us to sustain operational compared with approximately 2.0 percent for the S&P 500. Over success, reinforcing our reputation for delivering exceptional the past 20 years, dividends and dividend reinvestment have long-term shareholder value. Value of $1,000 Invested Over 20 years SOUTHERN COMPANY PHILADELPHIA ELECTRIC UTILITY INDEX S&P 500 INDEX $9,432 $5,554 $4,393 $8,000 $6,000 $4,000 $2,000 $0 1996 2001 2006 2011 2016 This performance graph compares the cumulative return on Southern Company (SO) common stock with the Philadelphia Electric Utility Index (UTY) and the Standard & Poor’s (S&P) 500 Index for the past 20 years. The average annualized return during the 20-year period is 11.9 percent for Southern Company, compared to 8.9 percent for the UTY and 7.7 percent for the S&P 500. The graph assumes that $1,000 was invested in Southern Company common stock and each of the above indices on December 31, 1996, and that all dividends were reinvested. The distribution of shares of Mirant Corporation stock to Southern Company shareholders is treated as a special dividend for the purposes of calculating Southern Company shareholder return. A five-year performance graph is included on page 6. Source: FactSet and Bloomberg SOUTHERN COMPANY 2016 Annual Report This chart shows the volatility of each of the 20 utilities in the Philadelphia Electric Utility Index (UTY). Volatility refers to the tendency of a stock to react to swings in the market. Southern Company had the second-lowest level of volatility in the UTY Index.Source: FactSet and Bloomberg, five-year beta as of December 31, 20161.21.00.80.60.40.20.0This chart shows the power of Southern Company’s dividend. Over the last 20 years, a $1,000 investment in Southern Company grew to $9,432. Price increases contributed $2,583 and dividends, with reinvestment, accounted for an increase of $5,849, or approximately 69 percent of the gain in value. The graph assumes that $1,000 was invested in Southern Company common stock on December 31, 1996, and that all dividends were reinvested.Total SO Value 1996 2001 2006 2011 2016 $8,000$6,000$4,000$2,000$0SOUTHERN COMPANYSOUTHERN COMPANY DIVIDEND VALUE SOUTHERN COMPANY STOCK VALUEValue Created by Dividend and Price PerformanceValue Added by Low Volatility Relative to the MarketSO Dividends and ReinvestmentSO Stock ValuevSOUTHERN COMPANY 2016 Annual Report Bruce Harrington, plant manager (left) and Jeff Parsley, general manager observe the gasifiers at Mississippi Power’s Kemper County Energy Facility in Kemper County, Mississippi. Bird’s-eye view of Unit 3 nuclear island under construction at Georgia Power’s Plant Vogtle, near Augusta, Georgia 582 MW Expected generating capacity of Mississippi Power’s Kemper County Energy Facility 60 Stories Height of Plant Vogtle units 3 and 4 cooling towers, taller than any building in 26 states SOUTHERN COMPANY 2016 Annual Report At both Mississippi Power’s Kemper County Energy Facility and new nuclear units 3 and 4 at Georgia Power’s Plant Vogtle, Southern Company and its subsidiaries are inventing the future of energy by advancing clean coal technology and next generation nuclear solutions that are expected to deliver clean, safe, reliable and affordable energy to customers for decades to come. 2016 saw significant milestones at Southern Company’s two major construction projects, Mississippi Power’s Kemper County Energy Facility, and Georgia Power’s Plant Vogtle units 3 and 4 near Augusta, Georgia.Kemper County Energy FacilityMississippi Power’s state-of-the-art Kemper County Energy Facility has been running on natural gas since August of 2014, supplying a significant portion of the electricity used by Mississippi Power customers, and operating approximately four times more efficiently than the industry average for combined cycled plants. This integrated gasification combined cycle design employs a technology called TRIG™, or Transport Integrated Gasification. TRIG was developed at the Power Systems Development Facility at the National Carbon Capture Center in Wilsonville, Alabama–a research facility operated by the Southern Company system on behalf of the United States Department of Energy. With TRIG, the Kemper County Energy Facility will be able to convert native Mississippi lignite coal into clean-burning synthesis gas while reducing emissions of sulfur dioxide, nitrogen oxides, carbon dioxide and mercury. The technology is designed to capture some 65 percent of the carbon dioxide emissions produced on-site. The facility is also a zero liquid discharge facility which means that none of the water used in generating electricity is released into surrounding rivers and streams.Plant Vogtle Units 3 and 4In November of 2016, workers placed the first new nuclear reactor vessel in the state of Georgia in more than 30 years. The 306-ton reactor vessel was lifted into its permanent location inside the Unit 3 nuclear island using one of the largest cranes in the world–a heavy-lift derrick with a 560-foot front boom. The reactor vessel will function as a heat source from the nuclear fission process to produce steam that will generate electricity for homes and businesses throughout Georgia.Also in November, workers safely placed the CA-01 module for Unit 4–the project’s second heaviest lift. This module, made entirely of steel, will house two steam generators for Unit 4, in addition to other equipment.The energy to advancenew technologiesviiSOUTHERN COMPANY 2016 Annual Report Wholesale energy subsidiary Southern Power helps Southern Company build the future of energy by investing in clean energy solutions. Southern Power is an advocate for the full portfolio of energy resources and its renewable assets– including wind, solar and biomass facilities–account for more than half of the Southern Company system’s renewable generation capacity.As Southern Company’s wholesale energy subsidiary, Southern Power helps meet the electricity needs of municipalities, electric cooperatives, investor-owned utilities and other energy customers throughout the nation. Southern Power and its subsidiaries own or have the rights to more than 45 facilities operating or under construction, representing more than 12,500 megawatts of generating capacity in 11 states. This includes over 3,000 megawatts of renewable generation, including solar, wind and biomass generation facilities. That diversity of geography and sources of power generation have helped Southern Power earn its reputation as America’s premier wholesale energy partner. Wind EnergyIn 2015, due to an improved earnings profile for wind energy, Southern Power began looking to invest in wind projects that included long-term power purchase agree-ments with creditworthy counterparties. By the close of 2016, Southern Power had established itself as a leader in wind generation, investing approximately $2 billion to acquire five wind projects, more than tripling the size of its operating wind fleet in the process. Today, Southern Power owns more than 1,400 megawatts of wind generating capacity at facilities operating or under development in Oklahoma, Texas and Maine.“2016 saw a greater emphasis on wind energy for Southern Power with the acquisition of five new wind facilities,” said Southern Power General Manager of Project Implementation Edgar Nunez. “Customers’ appetite for renewable energy solutions continues to grow, and wind has become an increasingly attractive option. Wind is a mature technology that has a strong economic profile.” Future Growth OpportunitiesThe future of wind energy at Southern Power looks promising. The company recently entered into a joint development agreement that is expected to create growth opportunities over the next five years. That partnership has already identified 10 potential wind projects that would be incremental to the existing fleet and provide approximately 3,000 megawatts of additional renewable generation upon completion.The energy to harnessrenewable resources1,400+MWSouthern Power wind generating capacity nationwide$2BillionSouthern Power investment in wind projects in 2016SOUTHERN COMPANY 2016 Annual Report ix Edgar Nunez, general manager of project implementation for Southern Power, inspects wind turbines at the company’s Salt Fork Wind Facility near Amarillo, Texas. SOUTHERN COMPANY 2016 Annual Report On the job, Khadijah Diggs is helping Southern Company build the future of energy. Off the clock, she is a Team USA triathlete in training for this year’s world champion- ships. Khadijah approaches her role with Southern Company Services’ program management office with commitment and determination. She applies that same energy and discipline as she prepares to compete for her country.As part of the program management team at Southern Company Services, Khadijah Diggs helps organizations within the Southern Company system bring their ideas to fruition through organizational project and program management. She focuses primarily on information technology projects, but lends her expertise to other func-tional areas. Khadijah is currently managing a power plant implementation project, a lease accounting program and an integration project with Southern Company Gas– all key initiatives that require focus and skill.Committed to CompeteCompeting in triathlons didn’t always come naturally for Khadijah. She competed in her first triathlon–the Iron Girl Atlanta Women’s Triathlon at Lake Lanier, Georgia– as part of a sorority event. When she finished third from last she wasn’t discouraged, Khadijah was energized. Before long, she had signed up to compete in two more triathlons.“I just went on like that for about two years, competing in random triathlons,” says Khadijah. “When I realized I had the potential to compete at a higher level, I started training in earnest and made it a goal to represent the United States in the long course triathlon.”A Team USA TriathleteOn November 13, 2016, Khadijah participated in the United States long course national championship in Miami, Florida. As Khadijah crossed the finish line among the top 18 finishers, she had achieved her goal–she was officially a member of Team USA.“I just ran. I didn’t think about anything. When I crossed the line my run coach ran to me, grabbed me and said ‘you did it!’” describes Khadijah. “It was pretty emotional.”Khadijah is currently training for the world championships which will take place in Pentiction, British Columbia, Canada later this year. As preparation, Khadijah trains six days a week averaging more than 200 miles a week swimming, running and biking. Khadijah explains, “When everybody else is watching TV and resting, I am training.”The energy to competefor our countryxSOUTHERN COMPANY 2016 Annual Report Khadijah Diggs, project manager, Southern Company Services, is a member of the Team USA long course triathlon team. Khadijah plans to ride her faithful bike, The Green Machine, in the world championships later this year. 237 The approximate number of miles Khadijah bikes, swims and runs each week while in training. SOUTHERN COMPANY 2016 Annual Report SOUTHERN COMPANY 2016 Annual ReportThroughout the Southern Company system, customers are at the center of all we do. In Mary Esther, Florida, Gulf Power Residential Energy Consultant Carl Jackson is a familiar face in the community, functioning as an advocate and problem solver for customers, providing answers to energy-related questions and assisting with the installation of cost-saving, energy-efficient systems and appliances. Throughout its long and rich history, Southern Company has maintained a steadfast commitment to keep customers at the center of everything we do. It’s a simple business model that has served as our guiding principal for more than 100 years. In that same vein, the company and its subsidiaries have embraced the concept of community involvement with a pledge to be “a citizen wherever we serve.” In Mary Esther, Florida, Gulf Power Residential Energy Consultant Carl Jackson also “serves where he is a citizen.” Community ConnectionsBorn and raised in Mary Esther, Carl is passionate about serving customers in his local community. Because his customers are also his neighbors, Carl shares a special bond with the community that affords him the opportunity to provide uniquely personalized service. A Gulf Power employee for more than 25 years, Carl currently serves as a residential energy consultant, where he works with customers in the greater Fort Walton Beach area to improve their daily lives through energy education.“Working with Gulf Power allows me to be a blessing to others right here in the community where I live,” Carl explains. “I couldn’t ask for a better job.”Energy Savings for CustomersCarl is one of several Gulf Power representatives who help facilitate the Energy Checkup program, which helps customers find ways to conserve energy and save money on their bill, including low-cost and no-cost recommendations. Customers may choose an online checkup or an in-home checkup with an energy expert like Carl for a personalized analysis of their energy consumption, including energy-saving tips and information about energy-efficiency programs.When Carter Gray reached out to Carl for help with his newly purchased home, Carl provided a personalized inspection of the house, including the attic, insulation, HVAC units and other appliances. After his inspection, Carl worked with Mr. Gray to create an energy savings action plan. The first step was to install a new electric water heater.“We have seen a nice savings on our monthly power bill since installing our electric water heater,” Mr. Gray describes. “It’s a big improvement for our family.”The energy to delivercustomer solutionsCustomer Carter Gray (left) converses with Gulf Power Residential Energy Consultant Carl Jackson on the front porch of his home in Mary Esther, Florida. 2billion kWhenergy use avoided through energy-efficiency efforts across the Southern Company system since 200090,000free Energy Checkups conducted by Gulf Power since 2000 1 TABLE OF CONTENTS Definitions � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � Cautionary Statement Regarding Forward-Looking Information � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � Available Information � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � Southern Company Business � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � Southern Company Common Stock and Dividend Information � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � Five-Year Cumulative Performance Graph � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � Management’s Report on Internal Control over Financial Reporting � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � Report of Independent Registered Public Accounting Firm � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � Management’s Discussion and Analysis of Financial Condition and Results of Operations � � � � � � � � � � � � � � � � � � � � � � � � 2 4 5 5 6 6 7 8 9 Consolidated Statements of Income � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � 50 Consolidated Statements of Comprehensive Income � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � 51 Consolidated Statements of Cash Flows � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � 52 Consolidated Balance Sheets � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � 54 Consolidated Statements of Capitalization � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � 56 Consolidated Statements of Stockholders’ Equity � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � 58 Notes to Financial Statements � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � 60 Selected Consolidated Financial and Operating Data � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � 128 Management Council � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � 131 investor.southerncompany.com 2 Definitions DEFINITIONS Term 2012 MPSC CPCN Order � � � � � � � � � � A detailed order issued by the Mississippi PSC in April 2012 confirming the CPCN originally Meaning approved by the Mississippi PSC in 2010 authorizing acquisition, construction, and operation of the Kemper IGCC 2013 ARP � � � � � � � � � � � � � � � � � � � � � � � Alternative Rate Plan approved by the Georgia PSC in 2013 for Georgia Power for the years 2014 through 2016 and subsequently extended through 2019 AFUDC � � � � � � � � � � � � � � � � � � � � � � � � � Allowance for funds used during construction Alabama Power � � � � � � � � � � � � � � � � � Alabama Power Company ARO � � � � � � � � � � � � � � � � � � � � � � � � � � � Asset retirement obligation ASC� � � � � � � � � � � � � � � � � � � � � � � � � � � � Accounting Standards Codification ASU � � � � � � � � � � � � � � � � � � � � � � � � � � � Accounting Standards Update Atlanta Gas Light � � � � � � � � � � � � � � � � Atlanta Gas Light Company, a wholly-owned subsidiary of Southern Company Gas Baseload Act� � � � � � � � � � � � � � � � � � � � State of Mississippi legislation designed to enhance the Mississippi PSC’s authority to facilitate development and construction of baseload generation in the State of Mississippi CCR� � � � � � � � � � � � � � � � � � � � � � � � � � � � Coal combustion residuals Clean Air Act � � � � � � � � � � � � � � � � � � � � Clean Air Act Amendments of 1990 CO2 � � � � � � � � � � � � � � � � � � � � � � � � � � � � Carbon dioxide COD � � � � � � � � � � � � � � � � � � � � � � � � � � � Commercial operation date CPCN � � � � � � � � � � � � � � � � � � � � � � � � � � Certificate of public convenience and necessity CWIP � � � � � � � � � � � � � � � � � � � � � � � � � � Construction work in progress DOE � � � � � � � � � � � � � � � � � � � � � � � � � � � U�S� Department of Energy EPA � � � � � � � � � � � � � � � � � � � � � � � � � � � � U�S� Environmental Protection Agency FASB� � � � � � � � � � � � � � � � � � � � � � � � � � � Financial Accounting Standards Board FERC� � � � � � � � � � � � � � � � � � � � � � � � � � � Federal Energy Regulatory Commission FFB � � � � � � � � � � � � � � � � � � � � � � � � � � � � Federal Financing Bank GAAP � � � � � � � � � � � � � � � � � � � � � � � � � � U�S� generally accepted accounting principles Georgia Power � � � � � � � � � � � � � � � � � � Georgia Power Company Gulf Power � � � � � � � � � � � � � � � � � � � � � Gulf Power Company IGCC � � � � � � � � � � � � � � � � � � � � � � � � � � � IRS � � � � � � � � � � � � � � � � � � � � � � � � � � � � ITC � � � � � � � � � � � � � � � � � � � � � � � � � � � � Kemper IGCC � � � � � � � � � � � � � � � � � � � KWH� � � � � � � � � � � � � � � � � � � � � � � � � � � Kilowatt-hour LIBOR� � � � � � � � � � � � � � � � � � � � � � � � � � London Interbank Offered Rate Merger � � � � � � � � � � � � � � � � � � � � � � � � � The merger, effective July 1, 2016, of a wholly-owned, direct subsidiary of Southern Integrated coal gasification combined cycle Internal Revenue Service Investment tax credit IGCC facility under construction by Mississippi Power in Kemper County, Mississippi Mirror CWIP � � � � � � � � � � � � � � � � � � � � A regulatory liability used by Mississippi Power to record customer refunds resulting from a 2015 Mississippi PSC order Company with and into Southern Company Gas, with Southern Company Gas continuing as the surviving corporation Mississippi Power� � � � � � � � � � � � � � � � Mississippi Power Company mmBtu� � � � � � � � � � � � � � � � � � � � � � � � � Million British thermal units Moody’s � � � � � � � � � � � � � � � � � � � � � � � Moody’s Investors Service, Inc� MPUS� � � � � � � � � � � � � � � � � � � � � � � � � � Mississippi Public Utilities Staff MW � � � � � � � � � � � � � � � � � � � � � � � � � � � Megawatt natural gas distribution utilities� � � � � � � � � � � � � � � � � � � � � � � � � Southern Company Gas’ seven natural gas distribution utilities (Nicor Gas, Atlanta Gas Light, Virginia Natural Gas, Inc�, Elizabethtown Gas, Florida City Gas, Chattanooga Gas Company, and Elkton Gas) NCCR � � � � � � � � � � � � � � � � � � � � � � � � � � Georgia Power’s Nuclear Construction Cost Recovery NDR � � � � � � � � � � � � � � � � � � � � � � � � � � � Alabama Power’s Natural Disaster Reserve Nicor Gas� � � � � � � � � � � � � � � � � � � � � � � Northern Illinois Gas Company, a wholly-owned subsidiary of Southern Company Gas NRC � � � � � � � � � � � � � � � � � � � � � � � � � � � U�S� Nuclear Regulatory Commission OCI � � � � � � � � � � � � � � � � � � � � � � � � � � � � Other comprehensive income Plant Vogtle Units 3 and 4 � � � � � � � � Two new nuclear generating units under construction at Georgia Power’s Plant Vogtle PowerSecure� � � � � � � � � � � � � � � � � � � � PowerSecure, Inc� Southern Company 2016 Annual Report Definitions 3 Term power pool � � � � � � � � � � � � � � � � � � � � � The operating arrangement whereby the integrated generating resources of the traditional Meaning electric operating companies and Southern Power (excluding subsidiaries) are subject to joint commitment and dispatch in order to serve their combined load obligations PPA � � � � � � � � � � � � � � � � � � � � � � � � � � � � Power purchase agreements and contracts for differences that provide the owner of a renewable facility a certain fixed price for the electricity sold to the grid PSC� � � � � � � � � � � � � � � � � � � � � � � � � � � � Public Service Commission PTC � � � � � � � � � � � � � � � � � � � � � � � � � � � � Production tax credit Rate CNP � � � � � � � � � � � � � � � � � � � � � � � Alabama Power’s Rate Certificated New Plant Rate CNP Compliance � � � � � � � � � � � � Alabama Power’s Rate Certificated New Plant Compliance Rate CNP PPA � � � � � � � � � � � � � � � � � � � Alabama Power’s Rate Certificated New Plant Power Purchase Agreement Rate ECR � � � � � � � � � � � � � � � � � � � � � � � Alabama Power’s Rate Energy Cost Recovery Rate NDR � � � � � � � � � � � � � � � � � � � � � � Alabama Power’s Rate Natural Disaster Reserve Rate RSE � � � � � � � � � � � � � � � � � � � � � � � Alabama Power’s Rate Stabilization and Equalization plan ROE � � � � � � � � � � � � � � � � � � � � � � � � � � � Return on equity S&P� � � � � � � � � � � � � � � � � � � � � � � � � � � � S&P Global Ratings, a division of S&P Global Inc� SCS � � � � � � � � � � � � � � � � � � � � � � � � � � � � Southern Company Services, Inc� (the Southern Company system service company) SEC � � � � � � � � � � � � � � � � � � � � � � � � � � � � U�S� Securities and Exchange Commission SEGCO � � � � � � � � � � � � � � � � � � � � � � � � � Southern Electric Generating Company SMEPA � � � � � � � � � � � � � � � � � � � � � � � � � South Mississippi Electric Power Association (now known as Cooperative Energy) Southern Company Gas � � � � � � � � � � Southern Company Gas (formerly known as AGL Resources Inc�) and its subsidiaries Southern Company Gas Capital� � � � � Southern Company Gas Capital Corporation (formerly known as AGL Capital Corporation), a 100%-owned subsidiary of Southern Company Gas Southern Company system � � � � � � � The Southern Company, the traditional electric operating companies, Southern Power, Southern Company Gas (as of July 1, 2016), SEGCO, Southern Nuclear, SCS, Southern LINC, PowerSecure (as of May 9, 2016), and other subsidiaries Southern LINC � � � � � � � � � � � � � � � � � � Southern Communications Services, Inc� Southern Nuclear� � � � � � � � � � � � � � � � Southern Nuclear Operating Company, Inc� Southern Power � � � � � � � � � � � � � � � � � Southern Power Company and its subsidiaries traditional electric operating companies� � � � � � � � � � � � � � � � � � � � � � Alabama Power, Georgia Power, Gulf Power, and Mississippi Power Westinghouse� � � � � � � � � � � � � � � � � � � Westinghouse Electric Company LLC Basic Earnings Per Share Excluding Kemper IGCC Impacts, Acquisition and Integration Costs, Equity Return Related to Kemper IGCC Schedule Extension, Southern Company Gas Earnings, net of Acquisition and Integration Costs, Acquisition Debt Financing Costs, Common Stock Share Issuances to Finance a Portion of Southern Natural Gas Company, L�L�C� (SNG) Acquisition, MC Asset Recovery Insurance Settlements and Leveraged Lease Restructure Charge Basic earnings per share in 2016 of $2�57 plus an excluded 28-cent charge (45 cents pre-tax) related to Mississippi Power’s construction and associated rate recovery of the Kemper IGCC project, plus an excluded 9 cents (13 cents pre-tax) related to the acquisition and integration of Southern Company Gas, PowerSecure International, Inc�, and the 50% interest in SNG, minus 4 cents (3 cents pre-tax) related to the additional allowance for funds used during construction equity as a result of extending the schedule for the Kemper IGCC project, minus 15 cents (24 cents pre-tax) related to earnings, net of acquisition and integration costs, of Southern Company Gas since July 1, 2016 (the date of acquisition), plus 11 cents (18 cents pre-tax) related to the debt financing costs associated with the Southern Company Gas acquisition, plus 3 cents related to the impact of 22�3 million shares of common stock issued in August 2016 to finance a portion of the purchase price of the SNG acquisition� Basic earnings per share in 2015 of $2�60 plus an excluded 25-cent charge (40 cents pre-tax) related to Mississippi Power’s construction of the Kemper IGCC project, plus an excluded 3 cents (5 cents pre-tax) related to the costs of the acquisition of Southern Company Gas, plus an excluded MC Asset Recovery insurance settlement charge of 1 cent (1 cent pre-tax)� Basic earnings per share in 2014 of $2�19 plus an excluded 59-cent charge (97 cents pre-tax) related to Mississippi Power’s construction of the Kemper IGCC project and plus an excluded 2 cents (3 cents pre-tax) related to the reversal of previously recognized revenues recorded in 2014 and 2013 and the recognition of carrying costs associated with the 2015 Mississippi Supreme Court decision which reversed the Mississippi Public Service Commission’s March 2013 rate order related to the Kemper IGCC project� Basic earnings per share in 2013 of $1�88 plus an excluded 83-cent charge ($1�35 pre-tax) related to Mississippi Power’s construction of the Kemper IGCC project, plus an excluded 2-cent charge (3 cents pre-tax) related to the restructuring of a leveraged lease investment, and minus an excluded MC Asset Recovery insurance settlement of 2 cents (1 cent pre-tax)� Basic earnings per share in 2012 of $2�70 minus an excluded MC Asset Recovery insurance settlement of 2 cents (2 cents pre-tax)� investor.southerncompany.com 4 Cautionary Statement Regarding Forward Looking Information CAUTIONARY STATEMENT REGARDING FORWARD LOOKING INFORMATION Southern Company’s 2016 Annual Report contains forward-looking statements� Forward-looking statements include, among other things, statements concerning regulated rates, the strategic goals for the wholesale business, customer and sales growth, economic conditions, fuel and environmental cost recovery and other rate actions, current and proposed environmental regulations and related compliance plans and estimated expenditures, pending or potential litigation matters, access to sources of capital, projections for the qualified pension plans, postretirement benefit plans, and nuclear decommissioning trust fund contributions, financing activities, completion dates of construction projects, filings with state and federal regulatory authorities, impact of the PATH Act, federal income tax benefits, estimated sales and purchases under power sale and purchase agreements, and estimated construction and other plans and expenditures� In some cases, forward-looking statements can be identified by terminology such as “may,” “will,” “could,” “should,” “expects,” “plans,” “anticipates,” “believes,” “estimates,” “projects,” “predicts,” “potential,” or “continue” or the negative of these terms or other similar terminology� There are various factors that could cause actual results to differ materially from those suggested by the forward-looking statements; accordingly, there can be no assurance that such indicated results will be realized� These factors include: • • • • • • • • • • • • • • • • • • • the impact of recent and future federal and state regulatory changes, including environmental laws regulating emissions, discharges, and disposal to air, water, and land, and also changes in tax and other laws and regulations to which Southern Company and its subsidiaries are subject, including potential tax reform legislation, as well as changes in application of existing laws and regulations; current and future litigation, regulatory investigations, proceedings, or inquiries; the effects, extent, and timing of the entry of additional competition in the markets in which Southern Company’s subsidiaries operate; variations in demand for electricity and natural gas, including those relating to weather, the general economy and recovery from the last recession, population and business growth (and declines), the effects of energy conservation and efficiency measures, including from the development and deployment of alternative energy sources such as self-generation and distributed generation technologies, and any potential economic impacts resulting from federal fiscal decisions; available sources and costs of natural gas and other fuels; limits on pipeline capacity; effects of inflation; the ability to control costs and avoid cost overruns during the development, construction, and operation of facilities, which include the development and construction of generating facilities with designs that have not been finalized or previously constructed, including changes in labor costs and productivity, adverse weather conditions, shortages and inconsistent quality of equipment, materials, and labor, sustaining nitrogen supply, contractor or supplier delay, non-performance under construction, operating, or other agreements, operational readiness, including specialized operator training and required site safety programs, unforeseen engineering or design problems, start-up activities (including major equipment failure and system integration), and/or operational performance (including additional costs to satisfy any operational parameters ultimately adopted by any PSC); the ability to construct facilities in accordance with the requirements of permits and licenses, to satisfy any environmental performance standards and the requirements of tax credits and other incentives, and to integrate facilities into the Southern Company system upon completion of construction; investment performance of the Southern Company system’s employee and retiree benefit plans and nuclear decommissioning trust funds; advances in technology; ongoing renewable energy partnerships and development agreements; state and federal rate regulations and the impact of pending and future rate cases and negotiations, including rate actions relating to fuel and other cost recovery mechanisms; legal proceedings and regulatory approvals and actions related to Plant Vogtle Units 3 and 4, including Georgia PSC approvals and NRC actions; actions related to cost recovery for the Kemper IGCC, including the ultimate impact of the 2015 decision of the Mississippi Supreme Court, the Mississippi PSC’s December 2015 rate order, and related legal or regulatory proceedings, Mississippi PSC review of the prudence of Kemper IGCC costs and approval of further permanent rate recovery plans, actions relating to proposed securitization, satisfaction of requirements to utilize grants, and the ultimate impact of the termination of the proposed sale of an interest in the Kemper IGCC to SMEPA; the ability to successfully operate the electric utilities’ generating, transmission, and distribution facilities and Southern Company Gas’ natural gas distribution and storage facilities and the successful performance of necessary corporate functions; the inherent risks involved in operating and constructing nuclear generating facilities, including environmental, health, regulatory, natural disaster, terrorism, and financial risks; the inherent risks involved in transporting and storing natural gas; the performance of projects undertaken by the non-utility businesses and the success of efforts to invest in and develop new opportunities; Southern Company 2016 Annual Report Southern Company Business 5 internal restructuring or other restructuring options that may be pursued; • • potential business strategies, including acquisitions or dispositions of assets or businesses, which cannot be assured to be • • • • • • • • • • • • completed or beneficial to Southern Company or its subsidiaries; the possibility that the anticipated benefits from the Merger cannot be fully realized or may take longer to realize than expected, the possibility that costs related to the integration of Southern Company and Southern Company Gas will be greater than expected, the ability to retain and hire key personnel and maintain relationships with customers, suppliers, or other business partners, and the diversion of management time on integration-related issues; the ability of counterparties of Southern Company and its subsidiaries to make payments as and when due and to perform as required; the ability to obtain new short- and long-term contracts with wholesale customers; the direct or indirect effect on the Southern Company system’s business resulting from cyber intrusion or terrorist incidents and the threat of terrorist incidents; interest rate fluctuations and financial market conditions and the results of financing efforts; changes in Southern Company’s and any of its subsidiaries’ credit ratings, including impacts on interest rates, access to capital markets, and collateral requirements; the impacts of any sovereign financial issues, including impacts on interest rates, access to capital markets, impacts on foreign currency exchange rates, counterparty performance, and the economy in general, as well as potential impacts on the benefits of the DOE loan guarantees; the ability of Southern Company’s electric utilities to obtain additional generating capacity (or sell excess generating capacity) at competitive prices; catastrophic events such as fires, earthquakes, explosions, floods, tornadoes, hurricanes and other storms, droughts, pandemic health events such as influenzas, or other similar occurrences; the direct or indirect effects on the Southern Company system’s business resulting from incidents affecting the U�S� electric grid, natural gas pipeline infrastructure, or operation of generating or storage resources; the effect of accounting pronouncements issued periodically by standard-setting bodies; and other factors discussed elsewhere herein and in other reports (including the Form 10-K) filed by Southern Company from time to time with the SEC� Southern Company expressly disclaims any obligation to update any forward-looking statements� AVAILABLE INFORMATION The Southern Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2016, as well as other documents filed by The Southern Company pursuant to the Securities Exchange Act of 1934, as amended, are available electronically at http://www�sec�gov� SOUTHERN COMPANY BUSINESS The Southern Company (Southern Company or the Company) is a holding company that owns all of the outstanding common stock of Alabama Power, Georgia Power, Gulf Power, and Mississippi Power, each of which is an operating public utility company� The traditional electric operating companies supply electric service in the states of Alabama, Georgia, Florida, and Mississippi� The traditional electric operating companies are vertically integrated utilities that own generation, transmission, and distribution facilities� Southern Company owns all of the common stock of Southern Power Company, which is also an operating public utility company� Southern Power constructs, acquires, owns, and manages generation assets, including renewable energy projects, and sells electricity at market-based rates in the wholesale market� On July 1, 2016, Southern Company completed the Merger for a total purchase price of approximately $8�0 billion and Southern Company Gas became a wholly-owned, direct subsidiary of Southern Company� Southern Company Gas is an energy services holding company whose primary business is the distribution of natural gas in seven states - Illinois, Georgia, Virginia, New Jersey, Florida, Tennessee, and Maryland - through the natural gas distribution utilities� Southern Company Gas is also involved in several other businesses that are complementary to the distribution of natural gas� Southern Company also owns all of the outstanding common stock or membership interests of SCS, Southern LINC, Southern Holdings, Southern Nuclear, PowerSecure, and other direct and indirect subsidiaries� SCS, the system service company, has contracted with Southern Company, each traditional electric operating company, Southern Power, Southern Company Gas, Southern Nuclear, SEGCO, and other subsidiaries to furnish, at direct or allocated cost and upon request, the following services: general and design engineering, operations, purchasing, accounting, finance and treasury, tax, information technology, marketing, auditing, insurance and pension administration, human resources, systems and procedures, digital wireless communication, and other services with respect to business and operations, construction management, and power pool transactions� Southern LINC provides digital wireless communications for use by Southern Company and its subsidiary companies and also markets these services to the public and provides fiber cable services within the Southeast� Southern Holdings is an intermediate holding investor.southerncompany.com 6 Southern Company Common Stock and Dividend Information company subsidiary, primarily for Southern Company’s investments in leveraged leases and for other electric services� Southern Nuclear operates and provides services to the Southern Company system’s nuclear power plants and is currently developing Plant Vogtle Units 3 and 4, which are co-owned by Georgia Power� PowerSecure is a provider of products and services in the areas of distributed generation, energy efficiency, and utility infrastructure� SOUTHERN COMPANY COMMON STOCK AND DIVIDEND INFORMATION The common stock of Southern Company is listed and traded on the New York Stock Exchange (NYSE)� The common stock is also traded on regional exchanges across the U�S� Dividends are payable at the discretion of the board of directors� The high and low stock prices as reported on the NYSE and the dividends on common stock declared by Southern Company for each quarter of the past two years were as follows: 2016 First Quarter Second Quarter Third Quarter Fourth Quarter 2015 First Quarter Second Quarter Third Quarter Fourth Quarter High Low $ $ 51�73 53�64 54�64 52�23 53�16 45�44 46�84 47�50 $ $ 46�00 47�62 50�00 46�20 43�55 41�40 41�81 43�38 The dividend paid per share of Southern Company’s common stock was 54�25¢ for the first quarter 2016 and 56�00¢ each for the second, third, and fourth quarters of 2016� In 2015, Southern Company paid a dividend per share of 52�50¢ for the first quarter and 54�25¢ each for the second, third, and fourth quarters� FIVE-YEAR CUMULATIVE PERFORMANCE GRAPH This performance graph compares the cumulative total shareholder return on the Company’s common stock with the Standard & Poor’s 500 index and the Philadelphia Utility Index for the past five years� The graph assumes that $100 was invested on December 31, 2011 in the Company’s common stock and each of the indices and that all dividends were reinvested� The stockholder return shown for the five-year historical period may not be indicative of future performance� $200 $150 $100 $50 $0 S&P 500 (TR) Southern Company Philadelphia Utilities Index 2011 100 100 100 2012 116 96 99 2013 154 97 110 2014 175 121 142 2015 177 121 133 2016 198 133 157 Southern Company 2016 Annual Report Management’s Report on Internal Control over Financial Reporting 7 MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING Southern Company and Subsidiary Companies 2016 Annual Report The management of The Southern Company (Southern Company) is responsible for establishing and maintaining an adequate system of internal control over financial reporting as required by the Sarbanes-Oxley Act of 2002 and as defined in Exchange Act Rule 13a-15(f). A control system can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Under management’s supervision, an evaluation of the design and effectiveness of Southern Company’s internal control over financial reporting was conducted based on the framework in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this evaluation, management concluded that Southern Company’s internal control over financial reporting was effective as of December 31, 2016. Deloitte & Touche LLP, an independent registered public accounting firm, as auditors of Southern Company’s financial statements, has issued an attestation report on the effectiveness of Southern Company’s internal control over financial reporting as of December 31, 2016. Deloitte & Touche LLP’s report on Southern Company’s internal control over financial reporting is included herein. Thomas A. Fanning Chairman, President, and Chief Executive Officer Art P. Beattie Executive Vice President and Chief Financial Officer February 21, 2017 investor.southerncompany.com 8 Report of Independent Registered Public Accounting Firm REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM To the Board of Directors and Stockholders of The Southern Company We have audited the accompanying consolidated balance sheets and consolidated statements of capitalization of The Southern Company and Subsidiary Companies (the Company) as of December 31, 2016 and 2015, and the related consolidated statements of income, comprehensive income, stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2016. We also have audited the Company’s internal control over financial reporting as of December 31, 2016, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company’s management is responsible for these financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control Over Financial Reporting (page 7). Our responsibility is to express an opinion on these financial statements and an opinion on the Company’s internal control over financial reporting 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 and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions. 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 consolidated financial statements (pages 50 to 126) referred to above present fairly, in all material respects, the financial position of Southern Company and Subsidiary Companies as of December 31, 2016 and 2015, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2016, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2016, based on the criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. As discussed in Note 3 to the financial statements, the Mississippi Public Service Commission rate recovery process associated with the Kemper Integrated Coal Gasification Combined Cycle Project may have a material impact on the Company’s financial statements. Atlanta, Georgia February 21, 2017 Southern Company 2016 Annual Report Management’s Discussion and Analysis of Financial Condition and Results of Operations 9 MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS OVERVIEW Business Activities The Southern Company (Southern Company or the Company) is a holding company that owns all of the common stock of the traditional electric operating companies and the parent entities of Southern Power and Southern Company Gas and owns other direct and indirect subsidiaries. The primary business of the Southern Company system is electricity sales by the traditional electric operating companies and Southern Power and, following the closing of the Merger on July 1, 2016, the distribution of natural gas by Southern Company Gas. The four traditional electric operating companies are vertically integrated utilities providing electric service in four Southeastern states. Southern Power constructs, acquires, owns, and manages power generation assets, including renewable energy projects, and sells electricity at market-based rates in the wholesale market. Southern Company Gas distributes natural gas through the natural gas distribution utilities in seven states and is involved in several other complementary businesses including gas marketing services, wholesale gas services, and gas midstream operations. Many factors affect the opportunities, challenges, and risks of the Southern Company system’s electricity and natural gas businesses. These factors include the ability to maintain constructive regulatory environments, to maintain and grow sales and customers, and to effectively manage and secure timely recovery of costs. These costs include those related to projected long-term demand growth, stringent environmental standards, reliability, fuel, restoration following major storms, and capital expenditures, including constructing new electric generating plants, expanding the electric transmission and distribution systems, and updating and expanding the natural gas distribution systems. Construction continues on Plant Vogtle Units 3 and 4 (45.7% ownership interest by Georgia Power in the two units, each with approximately 1,100 MWs) and Mississippi Power’s 582-MW Kemper IGCC. See Note 3 to the financial statements under “Regulatory Matters – Georgia Power – Nuclear Construction” and “Integrated Coal Gasification Combined Cycle” for additional information. The traditional electric operating companies and natural gas distribution utilities have various regulatory mechanisms that operate to address cost recovery. Effectively operating pursuant to these regulatory mechanisms and appropriately balancing required costs and capital expenditures with customer prices will continue to challenge the Southern Company system for the foreseeable future. See Note 3 to the financial statements under “Regulatory Matters” and “Integrated Coal Gasification Combined Cycle” for additional information. Another major factor affecting the Southern Company system’s businesses is the profitability of the competitive market-based wholesale generating business. Southern Power’s strategy is to construct, acquire, own, manage, and sell power generation assets, including renewable energy projects, and to enter into PPAs primarily with investor-owned utilities, independent power producers, municipalities, and other load-serving entities. Southern Company’s other business activities include providing energy technologies and services to electric utilities and large industrial, commercial, institutional, and municipal customers. Customer solutions include distributed generation systems, utility infrastructure solutions, and energy efficiency products and services. Other business activities also include investments in telecommunications, leveraged lease projects, and gas storage facilities. Management continues to evaluate the contribution of each of these activities to total shareholder return and may pursue acquisitions, dispositions, and other strategic ventures or investments accordingly. In striving to achieve attractive risk-adjusted returns while providing cost-effective energy to more than nine million electric and gas utility customers, the Southern Company system continues to focus on several key performance indicators. These indicators include, but are not limited to, customer satisfaction, plant availability, electric and natural gas system reliability, execution of major construction projects, and earnings per share (EPS). Southern Company’s financial success is directly tied to customer satisfaction. Key elements of ensuring customer satisfaction include outstanding service, high reliability, and competitive prices. Management uses customer satisfaction surveys and reliability indicators to evaluate the results of the Southern Company system. See RESULTS OF OPERATIONS herein for information on the Company’s financial performance. investor.southerncompany.com 10 Management’s Discussion and Analysis of Financial Condition and Results of Operations Merger with Southern Company Gas On July 1, 2016, Southern Company completed the Merger for a total purchase price of approximately $8.0 billion and Southern Company Gas became a wholly-owned, direct subsidiary of Southern Company. Prior to the completion of the Merger, Southern Company and Southern Company Gas operated as separate companies. The discussion and analysis of results of operations and financial condition set forth herein includes Southern Company Gas’ results of operations since July 1, 2016 and financial condition as of December 31, 2016. See Note 12 to the financial statements under “Southern Company – Merger with Southern Company Gas” for additional information regarding the Merger. During 2016 and 2015, the Company recorded in its statements of income costs associated with the Merger of approximately $111 million and $41 million, respectively, of which $80 million and $27 million is included in operating expenses and $31 million and $14 million is included in other income and (expense), respectively. These costs include external transaction costs for financing, legal, and consulting services, as well as customer rate credits and additional compensation-related expenses. Earnings Consolidated net income attributable to Southern Company was $2.4 billion in 2016, an increase of $81 million, or 3.4%, from the prior year. Consolidated net income increased by $114 million as a result of earnings from Southern Company Gas, which was acquired on July 1, 2016. Also contributing to the increase were higher retail electric revenues resulting from non-fuel retail rate increases and warmer weather, primarily in the third quarter 2016, as well as the 2015 correction of a Georgia Power billing error, partially offset by accruals in 2016 for expected refunds at Alabama Power and Georgia Power. Additionally, the increase was due to increases in income tax benefits and renewable energy sales at Southern Power. These increases were partially offset by higher interest expense, non-fuel operations and maintenance expenses, depreciation and amortization, lower wholesale capacity revenues, and higher estimated losses associated with the Kemper IGCC. See Note 12 to the financial statements under “Southern Company – Merger with Southern Company Gas” for additional information regarding the Merger. Consolidated net income attributable to Southern Company was $2.4 billion in 2015, an increase of $404 million, or 20.6%, from the prior year. The increase was primarily related to lower pre-tax charges of $365 million ($226 million after tax) recorded in 2015 compared to pre-tax charges of $868 million ($536 million after tax) recorded in 2014 for revisions of the estimated costs expected to be incurred on Mississippi Power’s construction of the Kemper IGCC and an increase in retail base rates. The increases were partially offset by increases in non-fuel operations and maintenance expenses and depreciation and amortization. Basic EPS was $2.57 in 2016, $2.60 in 2015, and $2.19 in 2014. Diluted EPS, which factors in additional shares related to stock- based compensation, was $2.55 in 2016, $2.59 in 2015, and $2.18 in 2014. EPS for 2016 was negatively impacted by $0.12 per share as a result of an increase in the average shares outstanding. See FINANCIAL CONDITION AND LIQUIDITY – “Financing Activities” herein for additional information. Dividends Southern Company has paid dividends on its common stock since 1948. Dividends paid per share of common stock were $2.2225 in 2016, $2.1525 in 2015, and $2.0825 in 2014. In January 2017, Southern Company declared a quarterly dividend of 56 cents per share. This is the 277th consecutive quarter that Southern Company has paid a dividend equal to or higher than the previous quarter. For 2016, the dividend payout ratio was 86%. RESULTS OF OPERATIONS Discussion of the results of operations is divided into three parts – the Southern Company system’s primary business of electricity sales, its gas business, and its other business activities. Electricity business Gas business Other business activities Net Income 2016 $ 2,571 114 (237) $ 2,448 Amount 2015 (in millions) 2,401 $ — (34) 2,367 $ 2014 1,969 — (6) 1,963 $ $ Southern Company 2016 Annual Report Management’s Discussion and Analysis of Financial Condition and Results of Operations 11 Electricity Business Southern Company’s electric utilities generate and sell electricity to retail and wholesale customers primarily in the Southeast. A condensed statement of income for the electricity business follows: Electric operating revenues Fuel Purchased power Cost of other sales Other operations and maintenance Depreciation and amortization Taxes other than income taxes Estimated loss on Kemper IGCC Total electric operating expenses Operating income Allowance for equity funds used during construction Interest expense, net of amounts capitalized Other income (expense), net Income taxes Net income Less: $ Amount 2016 17,941 4,361 750 58 4,523 2,233 1,039 428 13,392 4,549 200 931 (75) 1,091 2,652 $ 2015 Increase (Decrease) from Prior Year 2016 (in millions) 499 $ (389) 105 58 231 213 44 63 325 174 (26) 157 (43) (235) 183 (964) (1,255) (27) — 33 91 16 (503) (1,645) 681 (19) (20) 23 273 432 Dividends on preferred and preference stock of subsidiaries Net income attributable to noncontrolling interests Net Income Attributable to Southern Company 45 36 2,571 (9) 22 170 $ $ (14) 14 432 $ Electric Operating Revenues Electric operating revenues for 2016 were $17.9 billion, reflecting a $499 million increase from 2015. Details of electric operating revenues were as follows: Retail electric — prior year Estimated change resulting from — Rates and pricing Sales growth (decline) Weather Fuel and other cost recovery Retail electric — current year Wholesale electric revenues Other electric revenues Other revenues Electric operating revenues Percent change Amount 2016 2015 (in millions) $ 14,987 $ 15,550 427 (35) 153 (298) 15,234 1,926 698 83 17,941 $ 375 50 (59) (929) 14,987 1,798 657 — 17,442 $ 2.9% (5.2)% Retail electric revenues increased $247 million, or 1.6%, in 2016 as compared to the prior year. The significant factors driving this change are shown in the preceding table. The increase in rates and pricing in 2016 was primarily due to increases in base tariffs at Georgia Power under the 2013 ARP and the NCCR tariff and increased revenues at Alabama Power under Rate CNP Compliance, all effective January 1, 2016. Also contributing to the increase in rates and pricing for 2016 was the 2015 correction of an error affecting billings since 2013 to a small number of large commercial and industrial customers under a rate plan allowing for variable demand-driven pricing at Georgia Power and the implementation of rates at Mississippi Power for certain Kemper IGCC in-service assets, effective September 2015. These increases were partially offset by accruals in 2016 for expected refunds at Alabama Power and Georgia Power. investor.southerncompany.com 12 Management’s Discussion and Analysis of Financial Condition and Results of Operations Retail electric revenues decreased $563 million, or 3.6%, in 2015 as compared to the prior year. The significant factors driving this change are shown in the preceding table. The increase in rates and pricing in 2015 was primarily due to increased revenues at Alabama Power, associated with an increase in rates under Rate RSE, and at Georgia Power, related to increases in base tariffs under the 2013 ARP and the NCCR tariff, all effective January 1, 2015, as well as higher contributions from variable demand- driven pricing from commercial and industrial customers. The increase in rates and pricing was also due to the implementation of rates at Mississippi Power for certain Kemper IGCC in-service assets, effective September 2015. The increase was partially offset by the 2015 correction of an error affecting billings since 2013 to a small number of large commercial and industrial customers under a rate plan allowing for variable demand-driven pricing at Georgia Power. See Note 3 to the financial statements under “Regulatory Matters – Alabama Power – Rate RSE” and “ – Rate CNP Compliance” and “ – Georgia Power – Rate Plans” and “ – Nuclear Construction” and “Integrated Coal Gasification Combined Cycle – Rate Recovery of Kemper IGCC Costs” and Note 1 to the financial statements under “General” for additional information. Also see “Energy Sales” below for a discussion of changes in the volume of energy sold, including changes related to sales growth (decline) and weather. Electric rates for the traditional electric operating companies include provisions to adjust billings for fluctuations in fuel costs, including the energy component of purchased power costs. Under these provisions, fuel revenues generally equal fuel expenses, including the energy component of PPA costs, and do not affect net income. The traditional electric operating companies each have one or more regulatory mechanisms to recover other costs such as environmental and other compliance costs, storm damage, new plants, and PPA capacity costs. Wholesale electric revenues consist of PPAs primarily with investor-owned utilities and electric cooperatives and short-term opportunity sales. Wholesale electric revenues from PPAs (other than solar and wind PPAs) have both capacity and energy components. Capacity revenues generally represent the greatest contribution to net income and are designed to provide recovery of fixed costs plus a return on investment. Energy revenues will vary depending on fuel prices, the market prices of wholesale energy compared to the Southern Company system’s generation, demand for energy within the Southern Company system’s electric service territory, and the availability of the Southern Company system’s generation. Increases and decreases in energy revenues that are driven by fuel prices are accompanied by an increase or decrease in fuel costs and do not have a significant impact on net income. Electricity sales from solar and wind PPAs do not have a capacity charge and customers either purchase the energy output of a dedicated renewable facility through an energy charge or through a fixed price for electricity. As a result, the Company’s ability to recover fixed and variable operations and maintenance expenses is dependent upon the level of energy generated from these facilities, which can be impacted by weather conditions, equipment performance, and other factors. Wholesale electric revenues at Mississippi Power include FERC-regulated municipal and rural association sales as well as market-based sales. Short-term opportunity sales are made at market-based rates that generally provide a margin above the Southern Company system’s variable cost to produce the energy. Wholesale electric revenues from power sales were as follows: Capacity and other Energy Total 2016 $ 771 1,155 $ 1,926 $ $ 2015 (in millions) 875 923 1,798 $ $ 2014 974 1,210 2,184 In 2016, wholesale revenues increased $128 million, or 7.1%, as compared to the prior year due to a $232 million increase in energy revenues, offset by a $104 million decrease in capacity revenues. The increase in energy revenues was primarily due to an increase in short-term sales and renewable energy sales at Southern Power, partially offset by lower fuel prices. The decrease in capacity revenues was primarily due to the expiration of wholesale contracts at Georgia Power and Gulf Power, the elimination in consolidation of a Southern Power PPA that was remarketed from a third party to Georgia Power in January 2016, and unit retirements at Georgia Power, partially offset by an increase due to a new wholesale contract at Alabama Power in the first quarter 2016. In 2015, wholesale revenues decreased $386 million, or 17.7%, as compared to the prior year due to a $287 million decrease in energy revenues and a $99 million decrease in capacity revenues. The decreases in energy revenues were primarily related to lower fuel costs and lower customer demand due to milder weather as compared to the prior year, partially offset by increases in energy revenues from new solar and wind PPAs at Southern Power. The decreases in capacity revenues were primarily due to the expiration of wholesale contracts in December 2014 at Georgia Power, unit retirements at Georgia Power, and PPA expirations at Southern Power. See FUTURE EARNINGS POTENTIAL – “Regulatory Matters – Gulf Power” for information regarding the expiration of long-term sales agreements at Gulf Power for Plant Scherer Unit 3, which will impact future wholesale earnings, and Gulf Power’s request to rededicate its ownership interest in Scherer Unit 3 to the retail jurisdiction. Southern Company 2016 Annual Report Management’s Discussion and Analysis of Financial Condition and Results of Operations 13 Other Electric Revenues Other electric revenues increased $41 million, or 6.2%, and decreased $15 million, or 2.2%, in 2016 and 2015, respectively, as compared to the prior years. The 2016 increase was primarily due to a $14 million increase in customer temporary facilities services revenues and a $12 million increase in outdoor lighting revenues at Georgia Power. The 2015 decrease was primarily due to a $16 million decrease in transmission revenues at Georgia Power primarily as a result of a contract that expired in December 2014 and a $13 million decrease in co-generation steam revenues at Alabama Power, partially offset by an $11 million increase in outdoor lighting revenues at Georgia Power. Energy Sales Changes in revenues are influenced heavily by the change in the volume of energy sold from year to year. KWH sales for 2016 and the percent change from the prior year were as follows: Residential Commercial Industrial Other Total retail Wholesale Total energy sales Total KWHs Total KWH Percent Change Weather-Adjusted Percent Change 2016 2016 2015 2016(*) 2015(*) (in billions) 53.3 53.7 52.8 0.9 160.7 34.9 195.6 2.3% 0.4 (2.1) (1.7) 0.2 14.4 2.4% (2.3)% 0.5 (0.4) (1.4) (0.7) (7.0) (1.8)% 0.2% (1.0) (2.2) (1.7) (1.0)% 0.4% 0.9 (0.3) (1.3) 0.3% (*) In the first quarter 2015, Mississippi Power updated the methodology to estimate the unbilled revenue allocation among customer classes. This change did not have a significant impact on net income. The KWH sales variances in the above table reflect an adjustment to the estimated allocation of Mississippi Power’s unbilled 2014 and first quarter 2015 KWH sales among customer classes that is consistent with the actual allocation in 2015 and 2016, respectively. Without this adjustment, 2016 weather-adjusted commercial sales decreased 0.9% and industrial KWH sales decreased 2.1% as compared to 2015. Without this adjustment, 2015 weather-adjusted commercial sales increased 0.8% and industrial KWH sales decreased 0.4% as compared to 2014. Changes in retail energy sales are generally the result of changes in electricity usage by customers, changes in weather, and changes in the number of customers. Retail energy sales increased 261 million KWHs in 2016 as compared to the prior year. This increase was primarily due to warmer weather in the third quarter 2016 as compared to the corresponding period in 2015 and customer growth, partially offset by decreased customer usage. The decrease in industrial KWH energy sales was primarily due to decreased sales in the primary metals, chemicals, paper, pipeline, and stone, clay, and glass sectors. A strong dollar, low oil prices, and weak global economic conditions constrained growth in the industrial sector in 2016. Weather-adjusted commercial KWH sales decreased primarily due to decreased customer usage resulting from an increase in electronic commerce transactions and energy saving initiatives, partially offset by customer growth. Weather-adjusted residential KWH sales increased primarily due to customer growth, partially offset by decreased customer usage primarily resulting from an increase in multi-family housing and efficiency improvements in residential appliances and lighting. Household income, one of the primary drivers of residential customer usage, had modest growth in 2016. Retail energy sales decreased 1.2 billion KWHs in 2015 as compared to the prior year. This decrease was primarily the result of milder weather in the first and fourth quarters of 2015 as compared to the corresponding periods in 2014 and decreased customer usage, partially offset by customer growth. Weather-adjusted commercial KWH sales increased primarily due to customer growth and increased customer usage. Weather-adjusted residential KWH sales increased primarily due to customer growth, partially offset by decreased customer usage. Household income, one of the primary drivers of residential customer usage, had modest growth in 2015. The decrease in industrial KWH energy sales was primarily due to decreased sales in the primary metals, chemicals, and paper sectors, partially offset by increased sales in the transportation, stone, clay, and glass, pipeline, lumber, and petroleum sectors. A strong dollar, low oil prices, and weak global economic conditions constrained growth in the industrial sector in 2015. See “Electric Operating Revenues” above for a discussion of significant changes in wholesale revenues related to changes in price and KWH sales. Other Revenues Other revenues increased $83 million in 2016 as compared to the prior year. The 2016 increase was primarily due to revenues from certain non-regulated sales of products and services by the traditional electric operating companies that were reclassified as other revenues for consistency of presentation on a consolidated basis following the PowerSecure acquisition. In prior periods, these revenues were included in other income (expense), net. investor.southerncompany.com 14 Management’s Discussion and Analysis of Financial Condition and Results of Operations Fuel and Purchased Power Expenses Fuel costs constitute the single largest expense for the electric utilities. The mix of fuel sources for generation of electricity is determined primarily by demand, the unit cost of fuel consumed, and the availability of generating units. Additionally, the electric utilities purchase a portion of their electricity needs from the wholesale market. Details of the Southern Company system’s generation and purchased power were as follows: Total generation (in billions of KWHs) Total purchased power (in billions of KWHs) Sources of generation (percent) — Coal Nuclear Gas Hydro Other Renewables Cost of fuel, generated (in cents per net KWH) — 2016 188 16 33 16 46 2 3 2015 187 13 34 16 46 3 1 2014 191 12 42 16 39 3 — Coal Nuclear Gas 3.81 0.87 3.63 3.25 7.13 (*) Average cost of purchased power includes fuel purchased by the Southern Company system for tolling agreements where power is generated Average cost of fuel, generated (in cents per net KWH) Average cost of purchased power (in cents per net KWH)(*) 3.04 0.81 2.48 2.40 5.43 3.55 0.79 2.60 2.64 6.11 by the provider. In 2016, total fuel and purchased power expenses were $5.1 billion, a decrease of $284 million, or 5.3%, as compared to the prior year. The decrease was primarily the result of a $518 million decrease in the average cost of fuel and purchased power primarily due to lower coal and natural gas prices, partially offset by a $234 million increase in the volume of KWHs generated and purchased. In 2015, total fuel and purchased power expenses were $5.4 billion, a decrease of $1.3 billion, or 19.2%, as compared to the prior year. The decrease was primarily the result of a $1.1 billion decrease in the average cost of fuel and purchased power primarily due to lower coal and natural gas prices and a $137 million net decrease in the volume of KWHs generated and purchased due to milder weather in the first and fourth quarters of 2015. Fuel and purchased power energy transactions at the traditional electric operating companies are generally offset by fuel revenues and do not have a significant impact on net income. See FUTURE EARNINGS POTENTIAL – “Regulatory Matters – Fuel Cost Recovery” herein for additional information. Fuel expenses incurred under Southern Power’s PPAs are generally the responsibility of the counterparties and do not significantly impact net income. Fuel In 2016, fuel expense was $4.4 billion, a decrease of $389 million, or 8.2%, as compared to the prior year. The decrease was primarily due to a 14.4% decrease in the average cost of coal per KWH generated, a 4.6% decrease in the average cost of natural gas per KWH generated, and a 2.7% decrease in the volume of KWHs generated by coal, partially offset by a 3.5% increase in the volume of KWHs generated by natural gas. In 2015, fuel expense was $4.8 billion, a decrease of $1.3 billion, or 20.9%, as compared to the prior year. The decrease was primarily due to a 28.4% decrease in the average cost of natural gas per KWH generated, a 19.2% decrease in the volume of KWHs generated by coal, and a 6.8% decrease in the average cost of coal per KWH generated, partially offset by a 15.9% increase in the volume of KWHs generated by natural gas. Purchased Power In 2016, purchased power expense was $750 million, an increase of $105 million, or 16.3%, as compared to the prior year. The increase was primarily due to a 28.8% increase in the volume of KWHs purchased, partially offset by an 11.1% decrease in the average cost per KWH purchased primarily as a result of lower natural gas prices. In 2015, purchased power expense was $645 million, a decrease of $27 million, or 4.0%, as compared to the prior year. The decrease was primarily due to a 14.3% decrease in the average cost per KWH purchased primarily as a result of lower natural gas prices, partially offset by a 5.3% increase in the volume of KWHs purchased. Energy purchases will vary depending on demand for energy within the Southern Company system’s electric service territory, the market prices of wholesale energy as compared to the cost of the Southern Company system’s generation, and the availability of the Southern Company system’s generation. Southern Company 2016 Annual Report Management’s Discussion and Analysis of Financial Condition and Results of Operations 15 Cost of Other Sales Cost of other sales were $58 million in 2016. These costs were related to certain non-regulated sales of products and services by the traditional electric operating companies that were reclassified as cost of other sales for consistency of presentation on a consolidated basis following the PowerSecure acquisition. In prior periods, these costs were included in other income (expense), net. Other Operations and Maintenance Expenses Other operations and maintenance expenses increased $231 million, or 5.4%, in 2016 as compared to the prior year. The increase was primarily related to a $76 million increase in transmission and distribution expenses primarily related to overhead line maintenance, a $37 million decrease in gains from sales of assets at Georgia Power, a $36 million charge in connection with cost containment activities at Georgia Power, and a $35 million increase at Southern Power associated with new solar and wind facilities placed in service in 2015 and 2016. Additionally, the increase was due to a $19 million increase in generation expenses primarily related to environmental costs, a $19 million increase in business development and support expenses at Southern Power, and an $11 million increase in scheduled outage and maintenance costs at generation facilities, partially offset by a $41 million net decrease in employee compensation and benefits, including pension costs. Other operations and maintenance expenses increased $33 million, or 0.8%, in 2015 as compared to the prior year. The increase was primarily related to an $84 million increase in employee compensation and benefits including pension costs, a $62 million increase in generation expenses primarily related to environmental costs, and an $11 million increase in customer accounts, service, and sales costs primarily related to customer incentive and demand-side management programs, partially offset by a $99 million decrease in transmission and distribution costs primarily related to reduced overhead line maintenance and gains from sales of transmission assets and a $32 million decrease in scheduled outage and maintenance costs at generation facilities. Production expenses and transmission and distribution expenses fluctuate from year to year due to variations in outage and maintenance schedules and normal changes in the cost of labor and materials. Depreciation and Amortization Depreciation and amortization increased $213 million, or 10.5%, in 2016 as compared to the prior year primarily due to additional plant in service at the traditional electric operating companies and Southern Power. Depreciation and amortization increased $91 million, or 4.7%, in 2015 as compared to the prior year primarily due to the amortization of $120 million of the regulatory liability for other cost of removal obligations in 2014 at Alabama Power and increases in additional plant in service at the traditional electric operating companies and Southern Power, partially offset by a decrease as a result of a reduction in depreciation rates at Alabama Power effective January 1, 2015, a decrease due to unit retirements at Georgia Power, and a reduction in depreciation at Gulf Power as authorized in the 2013 rate case settlement agreement approved by the Florida PSC. See Note 3 to the financial statements under “Regulatory Matters – Gulf Power – Retail Base Rate Cases” for additional information. See Note 1 to the financial statements under “Regulatory Assets and Liabilities” and “Depreciation and Amortization” for additional information. Taxes Other Than Income Taxes Taxes other than income taxes increased $44 million, or 4.4%, in 2016 as compared to the prior year primarily due to an increase in property taxes due to higher assessed value of property at the traditional electric operating companies, increases in state and municipal utility license tax bases at Alabama Power, an increase in payroll taxes at Georgia Power, and an increase in franchise taxes at Mississippi Power. Taxes other than income taxes increased $16 million, or 1.6%, in 2015 as compared to the prior year primarily due to an increase in property taxes due to higher assessed value of property at the traditional electric operating companies. Estimated Loss on Kemper IGCC In 2016, 2015, and 2014, estimated probable losses on the Kemper IGCC of $428 million, $365 million, and $868 million, respectively, were recorded at Southern Company. These losses reflect revisions of estimated costs expected to be incurred on Mississippi Power’s construction of the Kemper IGCC in excess of the $2.88 billion cost cap established by the Mississippi PSC, net of $245 million of grants awarded to the project by the DOE under the Clean Coal Power Initiative Round 2 (Initial DOE Grants) and excluding the cost of the lignite mine and equipment, the cost of the CO2 pipeline facilities, AFUDC, and certain general exceptions, including change of law, force majeure, and beneficial capital (which exists when Mississippi Power demonstrates that the purpose and effect of the construction cost increase is to produce efficiencies that will result in a neutral or favorable effect on customers relative to the original proposal for the CPCN) (Cost Cap Exceptions). The 2016 loss also reflects $80 million associated with the estimated minimum probable amount of costs not currently in rates that would not be recovered under the probable rate mitigation plan to be filed by June 3, 2017. See Note 3 to the financial statements under “Integrated Coal Gasification Combined Cycle” for additional information. investor.southerncompany.com 16 Management’s Discussion and Analysis of Financial Condition and Results of Operations Allowance for Equity Funds Used During Construction AFUDC equity decreased $26 million, or 11.5%, in 2016 as compared to the prior year primarily due to environmental and generation projects being placed in service at Alabama Power and Gulf Power, partially offset by a higher AFUDC rate and an increase in Kemper IGCC CWIP subject to AFUDC at Mississippi Power. AFUDC equity decreased $19 million, or 7.8%, in 2015 as compared to the prior year primarily due to a reduction in the AFUDC rate at Mississippi Power, as well as placing the combined cycle and the associated common facilities portion of the Kemper IGCC in service in August 2014, partially offset by an increase in construction projects related to environmental and steam generation at Alabama Power. See Note 3 to the financial statements under “Integrated Coal Gasification Combined Cycle” for additional information regarding the Kemper IGCC. Interest Expense, Net of Amounts Capitalized Interest expense, net of amounts capitalized increased $157 million, or 20.3%, in 2016 as compared to the prior year primarily due to an increase in interest expense at Southern Power related to additional debt issued primarily to fund its growth strategy and continuous construction program, increases in both the average outstanding long-term debt balance and the average interest rate at the traditional electric operating companies, and the May 2015 termination of an asset purchase agreement between Mississippi Power and SMEPA and the resulting reversal of accrued interest on related deposits. Interest expense, net of amounts capitalized decreased $20 million, or 2.5%, in 2015 as compared to the prior year primarily due to a decrease of $58 million at Mississippi Power related to the termination of an agreement for SMEPA to purchase a portion of the Kemper IGCC which required the return of SMEPA’s deposits at a lower rate of interest than accrued and a $14 million decrease primarily due to an increase in capitalized interest associated with the construction of solar facilities at Southern Power, partially offset by a $46 million increase due to higher average outstanding long-term debt balances at the traditional electric operating companies. See Note 6 to the financial statements for additional information. Other Income (Expense), Net Other income (expense), net decreased $43 million, or 134.4%, in 2016 as compared to the prior year primarily due to the reclassification of revenues and costs associated with certain non-regulated sales of products and services by the traditional electric operating companies to other revenues and cost of other sales for consistency of presentation on a consolidated basis following the PowerSecure acquisition. The net amounts reclassified were $25 million. Also contributing to the decrease was an $8 million decrease in customer contributions in aid of construction (CIAC) and a $6 million decrease in wholesale operating fee revenue at Georgia Power. Other income (expense), net increased $23 million, or 41.8%, in 2015 as compared to the prior year primarily due to an increase of $9 million in wholesale operating fee revenues, an increase of $9 million in customer CIAC at Georgia Power, and an increase due to Mississippi Power’s $7 million settlement with the Sierra Club in 2014, partially offset by a decrease in sales of non-utility property at Alabama Power. Income Taxes Income taxes decreased $235 million, or 17.7%, in 2016 as compared to the prior year primarily due to increased federal income tax benefits related to ITCs for solar plants placed in service and PTCs from wind generation at Southern Power in 2016. Income taxes increased $273 million, or 25.9%, in 2015 as compared to the prior year primarily due to a reduction in tax benefits related to the estimated probable losses on Mississippi Power’s construction of the Kemper IGCC recorded in 2014 and higher pre-tax earnings, partially offset by increased federal income tax benefits related to ITCs at Southern Power in 2015. See Note 5 to the financial statements under “Effective Tax Rate” for additional information. Southern Company 2016 Annual Report Management’s Discussion and Analysis of Financial Condition and Results of Operations 17 Gas Business Southern Company Gas distributes natural gas through utilities in seven states and is involved in several other complementary businesses including gas marketing services, wholesale gas services, and gas midstream operations. On July 1, 2016, Southern Company Gas became a wholly-owned, direct subsidiary of Southern Company. Prior to the completion of the Merger, Southern Company and Southern Company Gas operated as separate companies. The condensed statement of income herein includes Southern Company Gas’ results of operations since July 1, 2016. See Note 12 to the financial statements under “Southern Company – Merger with Southern Company Gas” for additional information regarding the Merger, including certain pro forma results of operations. A condensed statement of income for the gas business follows: Operating revenues Cost of natural gas Cost of other sales Other operations and maintenance Depreciation and amortization Taxes other than income taxes Total operating expenses Operating income Earnings from equity method investments Interest expense, net of amounts capitalized Other income (expense), net Income taxes Net income Less: Net income attributable to noncontrolling interests Net Income Attributable to Southern Company Gas Seasonality of Results Amount 2016 (in millions) 1,652 613 10 523 238 71 1,455 197 60 81 14 76 114 — 114 $ $ During the period from November through March when natural gas usage and operating revenues are generally higher (Heating Season), more customers are connected to Southern Company Gas’ distribution systems, and natural gas usage is higher in periods of colder weather. Occasionally in the summer, operating revenues are impacted due to peak usage by power generators in response to summer energy demands. Southern Company Gas’ base operating expenses, excluding cost of natural gas, bad debt expense, and certain incentive compensation costs, are incurred relatively equally over any given year. Thus, operating results can vary significantly from quarter to quarter as a result of seasonality. For July 1, 2016 through December 31, 2016, the percentage of operating revenues and net income generated during the Heating Season (November and December) were 67.1% and 96.5%, respectively. Other Business Activities Southern Company’s other business activities include the parent company (which does not allocate operating expenses to business units), products and services in the areas of distributed generation, energy efficiency, and utility infrastructure, and investments in leveraged lease projects and telecommunications. These businesses are classified in general categories and may comprise the following subsidiaries: PowerSecure is a provider of products and services in the areas of distributed generation, energy efficiency, and utility infrastructure; Southern Company Holdings, Inc. (Southern Holdings) invests in various projects, including leveraged lease projects; and Southern LINC provides digital wireless communications for use by Southern Company and its subsidiary companies and also markets these services to the public and provides fiber cable services within the Southeast. On May 9, 2016, Southern Company acquired all of the outstanding stock of PowerSecure for $18.75 per common share in cash, resulting in an aggregate purchase price of $429 million. As a result, PowerSecure became a wholly-owned subsidiary of Southern Company. See Note 12 to the financial statements under “Southern Company – Acquisition of PowerSecure” for additional information. investor.southerncompany.com 18 Management’s Discussion and Analysis of Financial Condition and Results of Operations A condensed statement of income for Southern Company’s other business activities follows: Operating revenues Cost of other sales Other operations and maintenance Depreciation and amortization Taxes other than income taxes Total operating expenses Operating income (loss) Interest expense Other income (expense), net Income taxes Net income (loss) Operating Revenues Amount 2016 $ $ 303 192 194 31 3 420 (117) 305 (31) (216) (237) 2015 $ Increase (Decrease) from Prior Year 2016 (in millions) 256 192 70 17 1 280 (24) 239 (24) (84) (203) $ (14) — 29 (2) — 27 (41) 25 (18) (56) (28) $ $ Southern Company’s non-electric operating revenues for these other business activities increased $256 million, or 544.7%, in 2016 as compared to the prior year. The increase was primarily related to revenues from products and services at PowerSecure, which was acquired on May 9, 2016. Non-electric operating revenues for these other business activities decreased $14 million, or 23.0%, in 2015 as compared to the prior year. The decrease was primarily related to lower operating revenues at Southern Holdings due to higher billings in 2014 related to work performed on a generating plant outage and decreases in revenues at Southern LINC related to lower average per subscriber revenue and fewer subscribers due to continued competition in the industry. Cost of Other Sales Cost of other sales were $192 million in 2016. These costs were primarily related to sales of products and services by PowerSecure, which was acquired on May 9, 2016. Other Operations and Maintenance Expenses Other operations and maintenance expenses for these other business activities increased $70 million, or 56.5%, in 2016 as compared to the prior year. The increase was primarily due to $47 million in operations and maintenance expenses at PowerSecure since the acquisition closed on May 9, 2016 and an increase in parent company expenses of $16 million related to the Merger and the acquisition of PowerSecure. Other operations and maintenance expenses for these other business activities increased $29 million, or 30.5%, in 2015 as compared to the prior year. The increase was primarily due to parent company expenses of $27 million related to the Merger, partially offset by lower operating expenses at Southern Holdings due to work performed on a generating plant outage in 2014. Other Income (Expense), Net Other income (expense), net for these other business activities decreased $24 million in 2016 as compared to the prior year. The decrease was primarily due to an increase of $16 million in parent company expenses related to fees associated with the bridge financing for the Merger. Other income (expense), net for these other business activities decreased $18 million in 2015 as compared to the prior year. The decrease was primarily due to parent company expenses of $14 million related to fees associated with bridge financing for the Merger. Interest Expense Interest expense for these other business activities increased $239 million, or 362.1%, in 2016 as compared to the prior year primarily due to an increase in outstanding long-term debt at the parent company primarily relating to financing a portion of the purchase price for the Merger. Interest expense for these other business activities increased $25 million, or 61.0%, in 2015 as compared the prior year primarily due to an increase in outstanding long-term debt. Income Taxes Income taxes for these other business activities decreased $84 million, or 63.6%, in 2016 as compared to the prior year primarily as a result of changes in pre-tax earnings (losses), partially offset by state income tax benefits realized in 2015. Income taxes for these other business activities decreased $56 million, or 73.7%, in 2015 as compared to the prior year primarily as a result of state income tax benefits realized in 2015 and changes in pre-tax earnings (losses). Southern Company 2016 Annual Report Management’s Discussion and Analysis of Financial Condition and Results of Operations 19 Effects of Inflation The electric operating companies and natural gas distribution utilities are subject to rate regulation that is generally based on the recovery of historical and projected costs. The effects of inflation can create an economic loss since the recovery of costs could be in dollars that have less purchasing power. Southern Power is party to long-term contracts reflecting market-based rates, including inflation expectations. Any adverse effect of inflation on Southern Company’s results of operations has not been substantial in recent years. FUTURE EARNINGS POTENTIAL General The four traditional electric operating companies operate as vertically integrated utilities providing electric service to customers within their service territories in the Southeast. The seven natural gas distribution utilities provide service to customers in their service territories in Illinois, Georgia, Virginia, New Jersey, Florida, Tennessee, and Maryland. Prices for electricity provided and natural gas distributed to retail customers are set by state PSCs or other applicable state regulatory agencies under cost-based regulatory principles. Prices for wholesale electricity sales and natural gas distribution, interconnecting transmission lines, and the exchange of electric power are regulated by the FERC. Retail rates and earnings are reviewed and may be adjusted periodically within certain limitations. Southern Power continues to focus on long-term PPAs. See ACCOUNTING POLICIES – “Application of Critical Accounting Policies and Estimates – Utility Regulation” herein and Note 3 to the financial statements for additional information about regulatory matters. The results of operations for the past three years are not necessarily indicative of future earnings potential. The level of Southern Company’s future earnings depends on numerous factors that affect the opportunities, challenges, and risks of the Southern Company system’s primary businesses of selling electricity and distributing natural gas. These factors include the traditional electric operating companies’ and the natural gas distribution utilities’ ability to maintain a constructive regulatory environment that allows for the timely recovery of prudently-incurred costs during a time of increasing costs and limited projected demand growth over the next several years. The completion and subsequent operation of the Kemper IGCC and Plant Vogtle Units 3 and 4, as well as other ongoing construction projects, and the profitability of Southern Power’s competitive wholesale business and successful additional investments in renewable and other energy projects are other major factors. Current proposals related to potential tax reform legislation are primarily focused on reducing the corporate income tax rate, allowing 100% of capital expenditures to be deducted, and eliminating the interest deduction. The ultimate impact of any tax reform proposals, including any potential changes to the availability or realizability of ITCs and PTCs, is dependent on the final form of any legislation enacted and the related transition rules and cannot be determined at this time, but could have a material impact on Southern Company’s financial statements. Future earnings for the electricity and natural gas businesses will be driven primarily by customer growth. Earnings in the electricity business will also depend upon maintaining and growing sales, considering, among other things, the adoption and/or penetration rates of increasingly energy-efficient technologies, increasing volumes of electronic commerce transactions, and higher multi-family home construction. Earnings for both the electricity and natural gas businesses are subject to a variety of other factors. These factors include weather, competition, new energy contracts with other utilities and other wholesale customers, energy conservation practiced by customers, the use of alternative energy sources by customers, the prices of electricity and natural gas, the price elasticity of demand, and the rate of economic growth or decline in the service territory. In addition, the level of future earnings for the wholesale electric business also depends on numerous factors including regulatory matters, creditworthiness of customers, total electric generating capacity available and related costs, future acquisitions and construction of electric generating facilities, the impact of tax credits from renewable energy projects, and the successful remarketing of capacity as current contracts expire. Demand for electricity and natural gas is primarily driven by economic growth. The pace of economic growth and electricity and natural gas demand may be affected by changes in regional and global economic conditions, which may impact future earnings. In addition, the volatility of natural gas prices has a significant impact on the natural gas distribution utilities’ customer rates, long-term competitive position against other energy sources, and the ability of Southern Company Gas’ gas marketing services and wholesale gas services businesses to capture value from locational and seasonal spreads. Additionally, changes in commodity prices subject a significant portion of Southern Company Gas’ operations to earnings variability. As part of its ongoing effort to adapt to changing market conditions, Southern Company added several new businesses in 2016, including the acquisitions of Southern Company Gas, PowerSecure, and a 50% interest in the Southern Natural Gas Company, L.L.C. (SNG) pipeline system, as well as continued expansion of Southern Power’s renewable energy projects portfolio. Southern Company continues to evaluate and consider a wide array of potential business strategies. These strategies may include business combinations, partnerships, and acquisitions involving other utility or non-utility businesses or properties, disposition of certain assets or businesses, internal restructuring, or some combination thereof. Furthermore, Southern Company may engage in new business ventures that arise from competitive and regulatory changes in the utility industry. Pursuit of any of the above strategies, or any combination thereof, may significantly affect the business operations, risks, and financial condition of Southern Company. See Note 12 to the financial statements for additional information regarding Southern Company’s recent acquisition activity. investor.southerncompany.com 20 Management’s Discussion and Analysis of Financial Condition and Results of Operations Environmental Matters Compliance costs related to federal and state environmental statutes and regulations could affect earnings if such costs cannot continue to be fully recovered in rates on a timely basis for the traditional electric operating companies and the natural gas distribution utilities or through long-term wholesale agreements for the traditional electric operating companies and Southern Power. Environmental compliance spending over the next several years may differ materially from the amounts estimated. The timing, specific requirements, and estimated costs could change as environmental statutes and regulations are adopted or modified, as compliance plans are revised or updated, and as legal challenges to rules are completed. Further, higher costs that are recovered through regulated rates could contribute to reduced demand for electricity and natural gas, which could negatively affect results of operations, cash flows, and financial condition. See Note 3 to the financial statements under “Environmental Matters” for additional information. Environmental Statutes and Regulations General The Southern Company system’s operations are subject to extensive regulation by state and federal environmental agencies under a variety of statutes and regulations governing environmental media, including air, water, and land resources. Applicable statutes include the Clean Air Act; the Clean Water Act; the Comprehensive Environmental Response, Compensation, and Liability Act; the Resource Conservation and Recovery Act; the Toxic Substances Control Act; the Emergency Planning & Community Right-to-Know Act; the Endangered Species Act; the Migratory Bird Treaty Act; the Bald and Golden Eagle Protection Act; and related federal and state regulations. Compliance with these environmental requirements involves significant capital and operating costs, a major portion of which is expected to be recovered through existing ratemaking provisions. Through 2016, the traditional electric operating companies had invested approximately $11.9 billion in environmental capital retrofit projects to comply with these requirements, with annual totals of approximately $0.5 billion, $0.9 billion, and $1.1 billion for 2016, 2015, and 2014, respectively. The Southern Company system expects that capital expenditures to comply with environmental statutes and regulations will total approximately $2.9 billion from 2017 through 2021, with annual totals of approximately $0.9 billion, $0.7 billion, $0.3 billion, $0.4 billion, and $0.6 billion for 2017, 2018, 2019, 2020, and 2021, respectively. These estimated expenditures do not include any potential capital expenditures that may arise from the EPA’s final rules and guidelines or future state plans that would limit CO2 emissions from existing, new, modified, or reconstructed fossil-fuel- fired electric generating units. See “Global Climate Issues” herein for additional information. The Southern Company system also anticipates costs associated with ash pond closure and ground water monitoring under the Disposal of Coal Combustion Residuals from Electric Utilities final rule (CCR Rule), which are reflected in the Company’s ARO liabilities. See FINANCIAL CONDITION AND LIQUIDITY – “Capital Requirements and Contractual Obligations” herein and Note 1 to the financial statements under “Asset Retirement Obligations and Other Costs of Removal” for additional information. The Southern Company system’s ultimate environmental compliance strategy, including potential electric generating unit retirement and replacement decisions, and future environmental capital expenditures will be affected by the final requirements of new or revised environmental regulations, including the environmental regulations described below; the time periods over which compliance with regulations is required; individual state implementation of regulations, as applicable; the outcome of any legal challenges to the environmental rules; any additional rulemaking activities in response to legal challenges and court decisions; the cost, availability, and existing inventory of emissions allowances; the impact of future changes in generation and emissions-related technology; the fuel mix of the electric utilities; and environmental remediation requirements. Compliance costs may arise from existing unit retirements, installation of additional environmental controls, upgrades to the transmission system, closure and monitoring of CCR facilities, and adding or changing fuel sources for certain existing units. The ultimate outcome of these matters cannot be determined at this time. Compliance with any new federal or state legislation or regulations relating to air, water, and land resources or other environmental and health concerns could significantly affect the Southern Company system. Although new or revised environmental legislation or regulations could affect many areas of the electric utilities’ and natural gas distribution utilities’ operations, the full impact of any such changes cannot be determined at this time. Additionally, many commercial and industrial customers may also be affected by existing and future environmental requirements, which for some may have the potential to ultimately affect their demand for electricity and natural gas. Air Quality Compliance with the Clean Air Act and resulting regulations has been and will continue to be a significant focus for the Southern Company system. In 2012, the EPA finalized the Mercury and Air Toxics Standards (MATS) rule, which imposes stringent emissions limits for acid gases, mercury, and particulate matter on coal- and oil-fired electric utility steam generating units. The implementation strategy for the MATS rule included emission controls, retirements, and fuel conversions at affected units within the Southern Company system. All units within the Southern Company system that are subject to the MATS rule completed the measures necessary to achieve compliance with this rule or were retired prior to or during 2016. Southern Company 2016 Annual Report Management’s Discussion and Analysis of Financial Condition and Results of Operations 21 The EPA regulates ground level ozone concentrations through implementation of an eight-hour ozone National Ambient Air Quality Standard (NAAQS). In 2008, the EPA adopted a revised eight-hour ozone NAAQS and published its final area designations in 2012. The only area within the traditional electric operating companies’ service territory designated as an ozone nonattainment area for the 2008 standard is a 15-county area within metropolitan Atlanta, which on December 23, 2016, the EPA proposed to redesignate to attainment. In October 2015, the EPA published a more stringent eight-hour ozone NAAQS. This new standard could potentially require additional emission controls, improvements in control efficiency, and operational fuel changes and could affect the siting of new generating facilities. States were required to recommend area designations by October 2016, and the only area within the Southern Company system’s electric service territory that was proposed for designation is an eight-county area within the Atlanta metropolitan area in Georgia. The EPA is expected to finalize area designations by October 2017. The EPA regulates fine particulate matter concentrations through an annual and 24-hour average NAAQS, based on standards promulgated in 1997, 2006, and 2012. All areas in which the traditional electric operating companies’ generating units are located have been determined by the EPA to be in attainment with those standards. In 2010, the EPA revised the NAAQS for sulfur dioxide (SO2), establishing a new one-hour standard. No areas within the Southern Company system’s service territory have been designated as nonattainment under this standard. However, in 2015, the EPA finalized a data requirements rule to support final EPA designation decisions for all remaining areas under the SO2 standard, which could result in nonattainment designations for areas within the Southern Company system’s electric service territory. Nonattainment designations could require additional reductions in SO2 emissions and increased compliance and operational costs. In 2014, the EPA proposed to delete from the Alabama State Implementation Plan (SIP) the Alabama opacity rule that the EPA approved in 2008, which provides operational flexibility to affected units. In 2013, the U.S. Court of Appeals for the Eleventh Circuit ruled in favor of Alabama Power and vacated an earlier attempt by the EPA to rescind its 2008 approval. The EPA’s latest proposal characterizes the proposed deletion as an error correction within the meaning of the Clean Air Act. Alabama Power believes this interpretation of the Clean Air Act to be incorrect. If finalized, this proposed action could affect unit availability and result in increased operations and maintenance costs for affected units, including units owned by Alabama Power and units owned by SEGCO, which is jointly owned by Alabama Power and Georgia Power. On July 6, 2011, the EPA finalized the Cross State Air Pollution Rule (CSAPR). CSAPR is an emissions trading program that limits SO2 and nitrogen oxide (NOx) emissions from power plants in two phases – Phase 1 in 2015 and Phase 2 in 2017. The Southern Company system has fossil generation in several states that were subject to the requirements of the 2011 CSAPR, including Alabama, Florida, Georgia, Mississippi, North Carolina, and Texas. On October 26, 2016, the EPA published a final rule that updates the CSAPR ozone season NOx program, beginning in 2017, and establishes more stringent ozone-season emissions budgets in Alabama, Mississippi, and Texas and removes Florida and North Carolina from the ozone season program. Georgia’s ozone season NOx budget remains unchanged. North Carolina remains in the CSAPR annual SO2 and NOx programs, along with Alabama, Georgia, and Texas. The EPA finalized regional haze regulations in 2005, with a goal of restoring natural visibility conditions in certain areas (primarily national parks and wilderness areas) by 2064. The rule involves the application of best available retrofit technology to certain sources, including fossil fuel-fired generating facilities, built between 1962 and 1977 and any additional emissions reductions necessary for each designated area to achieve reasonable progress toward the natural visibility conditions goal by 2018 and for each 10-year period thereafter. On December 14, 2016, the EPA finalized revisions to the regional haze regulations. These regulations establish a deadline of July 31, 2021 for states to submit revised SIPs to the EPA demonstrating reasonable progress toward the statutory goal of achieving natural background conditions by 2064. State implementation of the reasonable progress requirements defined in this final rule could require further reductions in SO2 or NOx emissions. In June 2015, the EPA published a final rule requiring certain states (including Alabama, Florida, Georgia, Mississippi, North Carolina, and Texas) to revise or remove the provisions of their SIPs relating to the regulation of excess emissions at industrial facilities, including fossil fuel-fired generating facilities, during periods of startup, shut-down, or malfunction (SSM), and many states have submitted proposed SIP revisions in response to the rule. The Southern Company system has developed and continually updates a comprehensive environmental compliance strategy to assess compliance obligations associated with the current and proposed environmental requirements discussed above. These regulations could result in significant additional capital expenditures and compliance costs that could affect future unit retirement and replacement decisions and results of operations, cash flows, and financial condition if such costs are not recovered through regulated rates or through PPAs. The ultimate impact of the eight-hour ozone and SO2 NAAQS, Alabama opacity rule, CSAPR, regional haze regulations, and SSM rule will depend on various factors, such as implementation, adoption, or other action at the state level, and the outcome of pending and/or future legal challenges, and cannot be determined at this time. investor.southerncompany.com 22 Management’s Discussion and Analysis of Financial Condition and Results of Operations Water Quality The EPA’s final rule establishing standards for reducing effects on fish and other aquatic life caused by new and existing cooling water intake structures at existing power plants and manufacturing facilities became effective in 2014. The effect of this final rule will depend on the results of additional studies that are currently underway and implementation of the rule by regulators based on site-specific factors. National Pollutant Discharge Elimination System (NPDES) permits issued after July 14, 2018 must include conditions to implement and ensure compliance with the standards and protective measures required by the rule. In November 2015, the EPA published a final effluent guidelines rule which imposes stringent technology-based requirements for certain wastestreams from steam electric power plants. The revised technology-based limits and compliance dates will be incorporated into future renewals of NPDES permits at affected units and may require the installation and operation of multiple technologies sufficient to ensure compliance with applicable new numeric wastewater compliance limits. Compliance deadlines between November 1, 2018 and December 31, 2023 will be established in permits based on information provided for each applicable wastestream. In 2015, the EPA and the U.S. Army Corps of Engineers jointly published a final rule revising the regulatory definition of waters of the U.S. for all Clean Water Act (CWA) programs. The final rule significantly expands the scope of federal jurisdiction under the CWA and could have significant impacts on economic development projects which could affect customer demand growth. In addition, this rule could significantly increase permitting and regulatory requirements and costs associated with the siting of new facilities and the installation, expansion, and maintenance of transmission and distribution lines and natural gas pipelines. The rule became effective in August 2015 but, in October 2015, the U.S. Court of Appeals for the Sixth Circuit issued an order staying implementation of the final rule. The case is held in abeyance pending review by the U.S. Supreme Court of challenges to the U.S. Court of Appeals for the Sixth Circuit’s jurisdiction in the case. These water quality regulations could result in significant additional capital expenditures and compliance costs that could affect future unit retirement and replacement decisions and decisions on infrastructure expansion and improvements. Also, results of operations, cash flows, and financial condition could be significantly impacted if such costs are not recovered through regulated rates or through PPAs. The ultimate impact of these final rules will depend on various factors, such as pending and/or future legal challenges, compliance dates, and implementation of the rules, and cannot be determined at this time. Coal Combustion Residuals The traditional electric operating companies currently manage CCR at onsite storage units consisting of landfills and surface impoundments (CCR Units) at 23 current or former electric generating plants. In addition to on-site storage, the traditional electric operating companies also sell a portion of their CCR to third parties for beneficial reuse. Individual states regulate CCR and the states in the Southern Company system’s electric service territory each have their own regulatory requirements. Each traditional electric operating company has an inspection program in place to assist in maintaining the integrity of its coal ash surface impoundments. The CCR Rule became effective in October 2015. The CCR Rule regulates the disposal of CCR, including coal ash and gypsum, as non-hazardous solid waste in CCR Units at active generating power plants. The CCR Rule does not automatically require closure of CCR Units but includes minimum criteria for active and inactive surface impoundments containing CCR and liquids, lateral expansions of existing units, and active landfills. Failure to meet the minimum criteria can result in the required closure of a CCR Unit. On December 16, 2016, President Obama signed the Water Infrastructure Improvements for the Nation Act (WIIN Act). The WIIN Act allows states to establish permit programs for implementing the CCR Rule, if the EPA approves the program, and allows for federal permits and EPA enforcement where a state permitting program does not exist. On October 26, 2016, the Georgia Department of Natural Resources approved amendments to its state solid waste regulations to incorporate the requirements of the CCR Rule and establish additional requirements for all of Georgia Power’s onsite storage units consisting of landfills and surface impoundments. Based on current cost estimates for closure and monitoring of ash ponds pursuant to the CCR Rule, Southern Company has recorded incremental AROs related to the CCR Rule. As further analysis is performed, including evaluation of the expected method of compliance, refinement of assumptions underlying the cost estimates, such as the quantities of CCR at each site, and the determination of timing with respect to compliance activities, the traditional electric operating companies expect to continue to periodically update these estimates. The traditional electric operating companies have posted closure and post- closure care plans to their public websites as required by the CCR Rule; however, the ultimate impact of the CCR Rule will depend on the results of initial and ongoing minimum criteria assessments and the implementation of state or federal permit programs. Southern Company’s results of operations, cash flows, and financial condition could be significantly impacted if such costs are not recovered through regulated rates. See Note 1 to the financial statements under “Asset Retirement Obligations and Other Costs of Removal” for additional information regarding Southern Company’s AROs as of December 31, 2016. Southern Company 2016 Annual Report Management’s Discussion and Analysis of Financial Condition and Results of Operations 23 Environmental Remediation The Southern Company system must comply with other environmental laws and regulations that cover the handling and disposal of waste and releases of hazardous substances. Under these various laws and regulations, the Southern Company system could incur substantial costs to clean up affected sites. The traditional electric operating companies and Southern Company Gas conduct studies to determine the extent of any required cleanup and the Company has recognized in its financial statements the costs to clean up known impacted sites. Amounts for cleanup and ongoing monitoring costs were not material for any year presented. The traditional electric operating companies and the natural gas distribution utilities in Illinois, New Jersey, Georgia, and Florida have each received authority from their respective state PSCs or other applicable state regulatory agencies to recover approved environmental compliance costs through regulatory mechanisms. These regulatory mechanisms are adjusted annually or as necessary within limits approved by the state PSCs or other applicable state regulatory agencies. The traditional electric operating companies and Southern Company Gas may be liable for some or all required cleanup costs for additional sites that may require environmental remediation. See Note 3 to the financial statements under “Environmental Matters – Environmental Remediation” for additional information. Global Climate Issues In October 2015, the EPA published two final actions that would limit CO2 emissions from fossil fuel-fired electric generating units. One of the final actions contains specific emission standards governing CO2 emissions from new, modified, and reconstructed units. The other final action, known as the Clean Power Plan, establishes guidelines for states to develop plans to meet EPA-mandated CO2 emission rates or emission reduction goals for existing units. The EPA’s final guidelines require state plans to meet interim CO2 performance rates between 2022 and 2029 and final rates in 2030 and thereafter. At the same time, the EPA published a proposed federal plan and model rule that, when finalized, states can adopt or that would be put in place if a state either does not submit a state plan or its plan is not approved by the EPA. On February 9, 2016, the U.S. Supreme Court granted a stay of the Clean Power Plan, pending disposition of petitions for review with the courts. The stay will remain in effect through the resolution of the litigation, including any review by the U.S. Supreme Court. These guidelines and standards could result in operational restrictions and material compliance costs, including capital expenditures, which could affect future unit retirement and replacement decisions and decisions on infrastructure expansion and improvements. Southern Company’s results of operations, cash flows, and financial condition could be significantly impacted if such costs are not recovered through regulated rates or through PPAs. However, the ultimate financial and operational impact of the final rules on the Southern Company system cannot be determined at this time and will depend upon numerous factors, including the outcome of pending legal challenges, including legal challenges filed by the traditional electric operating companies, and any individual state implementation of the EPA’s final guidelines in the event the rule is upheld and implemented. In December 2015, parties to the United Nations Framework Convention on Climate Change – including the United States – adopted the Paris Agreement, which establishes a non-binding universal framework for addressing greenhouse gas emissions based on nationally determined contributions. It also sets in place a process for tracking progress toward the goals every five years. The ultimate impact of this agreement depends on its implementation by participating countries and cannot be determined at this time. The EPA’s greenhouse gas reporting rule requires annual reporting of greenhouse gas emissions expressed in terms of metric tons of CO2 equivalent emissions for a company’s operational control of facilities. Based on ownership or financial control of facilities, the Southern Company system’s 2015 greenhouse gas emissions were approximately 102 million metric tons of CO2 equivalent. The preliminary estimate of the Southern Company system’s 2016 greenhouse gas emissions on the same basis, including the addition of Southern Company Gas, is approximately 99 million metric tons of CO2 equivalent. The level of greenhouse gas emissions from year to year will depend on the level of generation, the mix of fuel sources, and other factors. FERC Matters Market-Based Rate Authority The traditional electric operating companies and Southern Power have authority from the FERC to sell electricity at market- based rates. Since 2008, that authority, for certain balancing authority areas, has been conditioned on compliance with the requirements of an energy auction, which the FERC found to be tailored mitigation that addresses potential market power concerns. In accordance with FERC regulations governing such authority, the traditional electric operating companies and Southern Power filed a triennial market power analysis in 2014, which included continued reliance on the energy auction as tailored mitigation. In April 2015, the FERC issued an order finding that the traditional electric operating companies’ and Southern Power’s existing tailored mitigation may not effectively mitigate the potential to exert market power in certain areas served by the traditional electric operating companies and in some adjacent areas. The FERC directed the traditional electric operating companies and Southern Power to show why market-based rate authority should not be revoked in these areas or to provide a mitigation plan to further address market power concerns. The traditional electric operating companies and Southern Power filed a request for rehearing in May 2015 and in June 2015 filed their response with the FERC. investor.southerncompany.com 24 Management’s Discussion and Analysis of Financial Condition and Results of Operations On December 9, 2016, the traditional electric operating companies and Southern Power filed an amendment to their market- based rate tariff that proposed certain changes to the energy auction, as well as several non-tariff changes. On February 2, 2017, the FERC issued an order accepting all such changes subject to an additional condition of cost-based price caps for certain sales outside of the energy auction, finding that all of these changes would provide adequate alternative mitigation for the traditional electric operating companies’ and Southern Power’s potential to exert market power in certain areas served by the traditional electric operating companies and in some adjacent areas. The traditional electric operating companies and Southern Power expect to make a compliance filing within 30 days accepting the terms of the order. While the FERC’s February 2, 2017 order references the market power proceeding discussed above, it remains a separate, ongoing matter. The ultimate outcome of these matters cannot be determined at this time. Southern Company Gas At December 31, 2016, Southern Company Gas’ gas midstream operations was involved in three gas pipeline construction projects with expected capital expenditures of approximately $780 million. These projects, along with Southern Company Gas’ existing pipelines, are intended to provide diverse sources of natural gas supplies to customers, resolve current and long-term supply planning for new capacity, enhance system reliability, and generate economic development in the areas served. One of these projects received FERC approval in August 2016. The remaining projects are pending FERC approval, which is expected to occur in 2017. The ultimate outcome of this matter cannot be determined at this time. Regulatory Matters Alabama Power Alabama Power’s revenues from regulated retail operations are collected through various rate mechanisms subject to the oversight of the Alabama PSC. Alabama Power currently recovers its costs from the regulated retail business primarily through Rate RSE, Rate CNP, Rate ECR, and Rate NDR. In addition, the Alabama PSC issues accounting orders to address current events impacting Alabama Power. See Note 3 to the financial statements under “Regulatory Matters – Alabama Power” for additional information regarding Alabama Power’s rate mechanisms and accounting orders. Rate RSE The Alabama PSC has adopted Rate RSE that provides for periodic annual adjustments based upon Alabama Power’s projected weighted cost of equity (WCE) compared to an allowable range. Rate RSE adjustments are based on forward-looking information for the applicable upcoming calendar year. Rate RSE adjustments for any two-year period, when averaged together, cannot exceed 4.0% and any annual adjustment is limited to 5.0%. If Alabama Power’s actual retail return is above the allowed WCE range, the excess will be refunded to customers unless otherwise directed by the Alabama PSC; however, there is no provision for additional customer billings should the actual retail return fall below the WCE range. On December 1, 2016, Alabama Power made its required annual Rate RSE submission to the Alabama PSC of projected data for calendar year 2017. The Rate RSE adjustment was an increase of 4.48%, or $245 million annually, effective January 1, 2017 and includes the performance based adder of 0.07%. Under the terms of Rate RSE, the maximum increase for 2018 cannot exceed 3.52%. As of December 31, 2016, the 2016 retail return exceeded the allowed WCE range; therefore, Alabama Power established a $73 million Rate RSE refund liability. In accordance with an order issued on February 14, 2017 by the Alabama PSC, Alabama Power was directed to apply the full amount of the refund to reduce the under recovered balance of Rate CNP PPA. Rate CNP PPA Alabama Power’s retail rates, approved by the Alabama PSC, provide for adjustments to recognize the placing of new generating facilities into retail service under Rate CNP. Alabama Power may also recover retail costs associated with certificated PPAs under Rate CNP PPA. On March 8, 2016, the Alabama PSC issued a consent order that Alabama Power leave in effect the current Rate CNP PPA factor for billings for the period April 1, 2016 through March 31, 2017. No adjustment to Rate CNP PPA is expected in 2017. In accordance with an accounting order issued on February 17, 2017 by the Alabama PSC, Alabama Power was authorized to eliminate the under recovered balance in Rate CNP PPA at December 31, 2016, which totaled approximately $142 million. As discussed herein under “Rate RSE,” Alabama Power will utilize the full amount of its $73 million Rate RSE refund liability to reduce the amount of the Rate CNP PPA under recovery and will reclassify the remaining $69 million to a separate regulatory asset. The amortization of the new regulatory asset through Rate RSE will begin concurrently with the effective date of Alabama Power’s next depreciation study, which is expected to occur within the next three to five years. Alabama Power’s current depreciation study became effective January 1, 2017. Rate CNP Compliance Rate CNP Compliance allows for the recovery of Alabama Power’s retail costs associated with laws, regulations, and other such mandates directed at the utility industry involving the environment, security, reliability, safety, sustainability, or similar considerations impacting Alabama Power’s facilities or operations. Rate CNP Compliance is based on forward-looking Southern Company 2016 Annual Report Management’s Discussion and Analysis of Financial Condition and Results of Operations 25 information and provides for the recovery of these costs pursuant to a factor that is calculated annually. Compliance costs to be recovered include operations and maintenance expenses, depreciation, and a return on certain invested capital. Revenues for Rate CNP Compliance, as recorded on the financial statements, are adjusted for differences in actual recoverable costs and amounts billed in current regulated rates. Accordingly, changes in Rate CNP Compliance related operations and maintenance expenses and depreciation generally will have no effect on net income. On December 6, 2016, the Alabama PSC issued a consent order that Alabama Power leave in effect for 2017 the factors associated with Alabama Power’s compliance costs for the year 2016. As stated in the consent order, any under-collected amount for prior years will be deemed recovered before the recovery of any current year amounts. Any under recovered amounts associated with 2017 will be reflected in the 2018 filing. In accordance with an accounting order issued on February 17, 2017 by the Alabama PSC, Alabama Power is authorized to classify any under recovered balance in Rate CNP Compliance up to approximately $36 million to a separate regulatory asset. The amortization of the new regulatory asset through Rate RSE will begin concurrently with the effective date of Alabama Power’s next depreciation study, which is expected to occur within the next three to five years. Alabama Power’s current depreciation study became effective January 1, 2017. Environmental Accounting Order Based on an order from the Alabama PSC, Alabama Power is allowed to establish a regulatory asset to record the unrecovered investment costs, including the unrecovered plant asset balance and the unrecovered costs associated with site removal and closure associated with future unit retirements caused by environmental regulations. These costs are being amortized and recovered over the affected unit’s remaining useful life, as established prior to the decision regarding early retirement through Rate CNP Compliance. See “Environmental Matters – Environmental Statutes and Regulations” herein for additional information regarding environmental regulations. In April 2016, as part of its environmental compliance strategy, Alabama Power ceased using coal at Plant Greene County Units 1 and 2 (300 MWs representing Alabama Power’s ownership interest) and began operating Units 1 and 2 solely on natural gas in June 2016 and July 2016, respectively. As a result, Alabama Power transferred the unrecovered plant asset balances to a regulatory asset at their respective retirement dates. The regulatory asset will be amortized and recovered through Rate CNP Compliance over the units’ remaining useful lives, as established prior to the decision for retirement; therefore, these decisions associated with coal operations had no significant impact on Southern Company’s financial statements. Georgia Power Georgia Power’s revenues from regulated retail operations are collected through various rate mechanisms subject to the oversight of the Georgia PSC. Georgia Power currently recovers its costs from the regulated retail business through the 2013 ARP, which includes traditional base tariff rates, Demand-Side Management (DSM) tariffs, Environmental Compliance Cost Recovery (ECCR) tariffs, and Municipal Franchise Fee (MFF) tariffs. In addition, financing costs related to the construction of Plant Vogtle Units 3 and 4 are being collected through the NCCR tariff and fuel costs are collected through separate fuel cost recovery tariffs. See Note 3 to the financial statements under “Regulatory Matters – Georgia Power” for additional information. Rate Plans Pursuant to the terms and conditions of a settlement agreement related to Southern Company’s acquisition of Southern Company Gas approved by the Georgia PSC on April 14, 2016, the 2013 ARP will continue in effect until December 31, 2019, and Georgia Power will be required to file its next base rate case by July 1, 2019. Furthermore, through December 31, 2019, Georgia Power and Atlanta Gas Light Company each will retain their respective merger savings, net of transition costs, as defined in the settlement agreement; through December 31, 2022, such net merger savings applicable to each will be shared on a 60/40 basis with their respective customers; thereafter, all merger savings will be retained by customers. See Note 3 to the financial statements under “Regulatory Matters – Georgia Power – Rate Plans” for additional information regarding the 2013 ARP and Note 12 to the financial statements under “Southern Company – Merger with Southern Company Gas” for additional information regarding the Merger. In accordance with the 2013 ARP, the Georgia PSC approved increases to tariffs effective January 1, 2015 and 2016 as follows: (1) traditional base tariff rates by approximately $107 million and $49 million, respectively; (2) ECCR tariff by approximately $23 million and $75 million, respectively; (3) DSM tariffs by approximately $3 million in each year; and (4) MFF tariff by approximately $3 million and $13 million, respectively, for a total increase in base revenues of approximately $136 million and $140 million, respectively. Under the 2013 ARP, Georgia Power’s retail ROE is set at 10.95% and earnings are evaluated against a retail ROE range of 10.00% to 12.00%. Two-thirds of any earnings above 12.00% will be directly refunded to customers, with the remaining one-third retained by Georgia Power. There will be no recovery of any earnings shortfall below 10.00% on an actual basis. In 2014, Georgia Power’s retail ROE exceeded 12.00%, and Georgia Power refunded to retail customers approximately $11 million in 2016, as approved by the Georgia PSC on February 18, 2016. In 2015, Georgia Power’s retail ROE was within the allowed retail ROE range. In 2016, Georgia Power’s retail ROE exceeded 12.00%, and Georgia Power expects to refund to retail customers approximately $40 million, subject to review and approval by the Georgia PSC. The ultimate outcome of this matter cannot be determined at this time. investor.southerncompany.com 26 Management’s Discussion and Analysis of Financial Condition and Results of Operations Integrated Resource Plan See “Environmental Matters” herein for additional information regarding proposed and final EPA rules and regulations, including the MATS rule for coal- and oil-fired electric utility steam generating units, revisions to effluent limitations guidelines for steam electric power plants, and additional regulations of CCR and CO2; and Georgia Power’s analysis of the potential costs and benefits of installing the required controls on its fossil generating units in light of these regulations. On July 28, 2016, the Georgia PSC approved the 2016 IRP including the decertification and retirement of Plant Mitchell Units 3, 4A, and 4B (217 MWs) and Plant Kraft Unit 1 (17 MWs), as well as the decertification of the Intercession City unit (143 MWs total capacity). On August 2, 2016, the Plant Mitchell and Plant Kraft units were retired. On August 31, 2016, Georgia Power sold its 33% ownership interest in the Intercession City unit to Duke Energy Florida, LLC. Additionally, the Georgia PSC approved Georgia Power’s environmental compliance strategy and related expenditures proposed in the 2016 IRP, including measures taken to comply with existing government-imposed environmental mandates, subject to limits on expenditures for Plant McIntosh Unit 1 and Plant Hammond Units 1 through 4. The Georgia PSC approved the reclassification of the remaining net book value of Plant Mitchell Unit 3 and costs associated with materials and supplies remaining at the unit retirement date to a regulatory asset. Recovery of the unit’s net book value will continue through December 31, 2019, as provided in the 2013 ARP. The timing of the recovery of the remaining balance of the unit’s net book value as of December 31, 2019 and costs associated with materials and supplies remaining at the unit retirement date was deferred for consideration in Georgia Power’s 2019 base rate case. The Georgia PSC also approved the Renewable Energy Development Initiative to procure an additional 1,200 MWs of renewable resources primarily utilizing market-based prices established through a competitive bidding process with expected in-service dates between 2018 and 2021. Additionally, 200 MWs of self-build capacity for use by Georgia Power was approved, as well as consideration for no more than 200 MWs of capacity as part of a renewable commercial and industrial program. The Georgia PSC also approved recovery of costs up to $99 million through June 30, 2019 to preserve nuclear as an option at a future generation site in Stewart County, Georgia. The timing of cost recovery will be determined by the Georgia PSC in a future base rate case. The ultimate outcome of this matter cannot be determined at this time. Storm Damage Recovery As of December 31, 2016, the balance in Georgia Power’s regulatory asset related to storm damage was $206 million. During October 2016, Hurricane Matthew caused significant damage to Georgia Power’s transmission and distribution facilities. As of December 31, 2016, Georgia Power had recorded incremental restoration cost related to this hurricane of $121 million, of which approximately $116 million was charged to the storm damage reserve and the remainder was capitalized. Georgia Power is accruing $30 million annually through December 31, 2019, as provided in the 2013 ARP, to the storm damage reserve to cover the operations and maintenance costs of damages from major storms to its transmission and distribution facilities, which is recoverable through base rates. The rate of recovery of storm damage costs after December 31, 2019 is expected to be adjusted in Georgia Power’s 2019 base rate case. As a result of this regulatory treatment, costs related to storms are not expected to have a material impact on Southern Company’s financial statements. See Note 3 to the financial statements under “Regulatory Matters – Georgia Power – Storm Damage Recovery” for additional information regarding Georgia Power’s storm damage reserve. Gulf Power Through 2015, long-term non-affiliate capacity sales from Gulf Power’s ownership of Plant Scherer Unit 3 (205 MWs) provided the majority of Gulf Power’s wholesale earnings. Contract expirations at the end of 2015 and the end of May 2016 related to Plant Scherer Unit 3 wholesale sales did not have a material impact on Southern Company’s earnings in 2016. Remaining contract sales from Plant Scherer Unit 3 cover approximately 24% of Gulf Power’s ownership of the unit through 2019. On October 12, 2016, Gulf Power filed a petition (2016 Rate Case) with the Florida PSC requesting an annual increase in retail rates and charges of $106.8 million based on the projected test year of January 1, 2017 through December 31, 2017 and a retail ROE of 11% compared to the current retail ROE of 10.25%. The requested increase includes recovery of the portion of Plant Scherer Unit 3 that has been rededicated to serving retail customers following the contract expirations discussed above. If retail recovery of Plant Scherer Unit 3 is not approved by the Florida PSC in the 2016 Rate Case, Gulf Power may consider an asset sale. The current book value of Gulf Power’s ownership of Plant Scherer Unit 3 could exceed market value which could result in a material loss. The Florida PSC is expected to make a decision on the 2016 Rate Case in the second quarter 2017. Gulf Power has requested that the increase in base rates, if approved by the Florida PSC, become effective in July 2017. On November 2, 2016, the Florida PSC approved Gulf Power’s 2017 annual cost recovery clause factors. The fuel and environmental factors include certain costs associated with the ongoing ownership and operation of Plant Scherer Unit 3. The final disposition of these costs, and the related impact on rates, is subject to the Florida PSC’s ultimate ruling on whether costs associated with Plant Scherer Unit 3 are recoverable from retail customers, which is expected to be decided in the 2016 Rate Case as discussed previously. See Note 3 to the financial statements under “Regulatory Matters – Gulf Power – Retail Base Rate Cases” for additional information. The ultimate outcome of these matters cannot be determined at this time. Southern Company 2016 Annual Report Management’s Discussion and Analysis of Financial Condition and Results of Operations 27 Southern Company Gas Natural Gas Cost Recovery Southern Company Gas has established natural gas cost recovery rates that are approved by the applicable state regulatory agencies in the states in which it serves. Natural gas cost recovery revenues are adjusted for differences in actual recoverable natural gas costs and amounts billed in current regulated rates. Accordingly, changes in the billing factor will not have a significant effect on Southern Company’s revenues or net income, but will affect cash flow. Regulatory Infrastructure Programs Six of Southern Company Gas’ seven natural gas distribution utilities are involved in ongoing capital projects associated with infrastructure improvement programs that have been previously approved by their applicable state regulatory agencies and provide an appropriate return on invested capital. These infrastructure improvement programs are designed to update or expand the natural gas distribution systems of the natural gas distribution utilities to improve reliability and meet operational flexibility and growth. Initial program lengths range from four to 10 years, with the longest set to expire in 2025. The total expected investment under these programs for 2017 is $590 million. On February 21, 2017, the Georgia PSC approved a rate adjustment mechanism for Atlanta Gas Light that included the 2017 capital investment associated with a four-year extension of one of its existing infrastructure programs, with a total additional investment of $177 million through 2020. In addition, Elizabethtown Gas currently has a proposed infrastructure improvement program pending approval by the New Jersey Board of Public Utilities requesting to invest more than $1.1 billion through 2027. The ultimate outcome of these matters cannot be determined at this time. Renewables In accordance with the September 2015 Alabama PSC order approving up to 500 MWs of renewable projects, Alabama Power has entered into agreements to purchase power from and to build 89 MWs of renewable generation sources. The terms of the agreements permit Alabama Power to use the energy and retire the associated renewable energy credits (REC) in service of its customers or to sell RECs, separately or bundled with energy. In 2014, the Georgia PSC approved Georgia Power’s application for the certification of two PPAs executed in 2013 for the purchase of energy from two wind farms in Oklahoma with capacity totaling 250 MWs that began in 2016 and have 20-year terms. As part of the Georgia Power Advanced Solar Initiative (ASI), in 2014, the Georgia PSC approved PPAs executed since April 2015 for the purchase of energy from 555 MWs of solar capacity that began in 2015 and 2016 and have terms ranging from 20 to 30 years. As a result of certain acquisitions by Southern Power, 249 MWs of this contracted capacity is being provided from solar facilities owned by Southern Power through five PPAs that began in 2016. Ownership of any associated REC is specified in each respective PPA. The party that owns the RECs retains the right to use them. In 2014, the Georgia PSC approved Georgia Power’s request to build, own, and operate 30-MW solar generation facilities at three U.S. Army bases and one U.S. Navy base by the end of 2016. One of the four solar generation facilities began commercial operation in December 2015 and the remaining three began in the fourth quarter 2016. In December 2015, the Georgia PSC approved Georgia Power’s request to build, own, and operate a 31-MW solar generation facility at a U.S. Marine Corps base that is expected to begin commercial operation by summer 2017 and a 15-MW solar generation facility at a yet-to-be-determined U.S. military base. The ultimate outcome of this matter cannot be determined at this time. Two PPAs for biomass generation capacity of 58 MWs each were executed in June 2015 and November 2015 and are expected to begin in 2019. See “Georgia Power – Integrated Resource Plan” herein for additional information on Georgia Power’s renewables. In April 2015, the Florida PSC approved Gulf Power’s three energy purchase agreements totaling 120 MWs of utility-scale solar generation located at three military installations in northwest Florida. Purchases under these solar agreements are expected to begin by the summer of 2017. The Florida PSC issued a final approval order on Gulf Power’s Community Solar Pilot Program on April 15, 2016. The program will offer Gulf Power’s customers an opportunity to voluntarily contribute to the construction and operation of a solar photovoltaic facility with electric generating capacity of up to 1 MW through annual subscriptions. The energy generated from the solar facility is expected to provide power to all of Gulf Power’s customers. On November 29, 2016, the Florida PSC approved Gulf Power’s energy purchase agreement for up to 94 MWs of additional wind generation in central Oklahoma. Purchases under this agreement will be for energy only and will be recovered through Gulf Power’s fuel cost recovery clause. investor.southerncompany.com 28 Management’s Discussion and Analysis of Financial Condition and Results of Operations In November 2015, the Mississippi PSC issued orders approving three solar facilities for a combined total of approximately 105 MWs. Mississippi Power will purchase all of the energy produced by the solar facilities for the 25-year term under each of the three PPAs. The projects are expected to be in service by the second quarter 2017 and the resulting energy purchases are expected to be recovered through Mississippi Power’s fuel cost recovery mechanism. Mississippi Power may retire the RECs generated on behalf of its customers or sell the RECs, separately or bundled with energy, to third parties. See Note 12 to the financial statements for information on Southern Power’s renewables activities. Fuel Cost Recovery The traditional electric operating companies each have established fuel cost recovery rates approved by their respective state PSCs. Fuel cost recovery revenues are adjusted for differences in actual recoverable fuel costs and amounts billed in current regulated rates. Accordingly, changes in the billing factor will not have a significant effect on Southern Company’s revenues or net income, but will affect cash flow. The traditional electric operating companies continuously monitor their under or over recovered fuel cost balances and make appropriate filings with their state PSCs to adjust fuel cost recovery rates as necessary. See Note 1 to the financial statements under “Revenues” and Note 3 to the financial statements under “Regulatory Matters – Alabama Power – Rate ECR” and “Regulatory Matters – Georgia Power – Fuel Cost Recovery” for additional information. Construction Program Overview The subsidiary companies of Southern Company are engaged in continuous construction programs to accommodate existing and estimated future loads on their respective systems. The Southern Company system intends to continue its strategy of developing and constructing new electric generating facilities, adding environmental modifications to certain existing units, expanding the electric transmission and distribution systems, and updating and expanding the natural gas distribution systems. For the traditional electric operating companies, major generation construction projects are subject to state PSC approval in order to be included in retail rates. While Southern Power generally constructs and acquires generation assets covered by long- term PPAs, any uncontracted capacity could negatively affect future earnings. Southern Company Gas is engaged in various infrastructure improvement programs designed to update or expand the natural gas distribution systems of the natural gas distribution utilities to improve reliability and meet operational flexibility and growth. The natural gas distribution utilities recover their investment and a return associated with these infrastructure programs through their regulated rates. The Southern Company system’s construction program is currently estimated to total approximately $9.1 billion, $8.2 billion, $7.3 billion, $6.9 billion, and $6.4 billion for 2017, 2018, 2019, 2020, and 2021, respectively. The two largest construction projects currently underway in the Southern Company system are Plant Vogtle Units 3 and 4 (45.7% ownership interest by Georgia Power in the two units, each with approximately 1,100 MWs) and Mississippi Power’s Kemper IGCC. See Note 3 to the financial statements under “Regulatory Matters – Georgia Power – Nuclear Construction” and “Integrated Coal Gasification Combined Cycle” for additional information. See Note 12 to the financial statements under “Southern Power – Construction Projects” for additional information about costs relating to Southern Power’s acquisitions that involve construction of renewable energy facilities. See Note 3 to the financial statements under “Regulatory Matters – Southern Company Gas – Regulatory Infrastructure Programs” for additional information regarding infrastructure improvement programs at the natural gas distribution utilities. Also see FINANCIAL CONDITION AND LIQUIDITY – “Capital Requirements and Contractual Obligations” herein for additional information regarding Southern Company’s capital requirements for its subsidiaries’ construction programs. Integrated Coal Gasification Combined Cycle Mississippi Power continues to progress toward completing the construction and start-up of the Kemper IGCC, which was approved by the Mississippi PSC in the 2010 CPCN proceedings, subject to a construction cost cap of $2.88 billion, net of $245 million of Initial DOE Grants and excluding the Cost Cap Exceptions. The current cost estimate for the Kemper IGCC in total is approximately $6.99 billion, which includes approximately $5.64 billion of costs subject to the construction cost cap and is net of the $137 million in additional grants from the DOE received on April 8, 2016 (Additional DOE Grants), which are expected to be used to reduce future rate impacts to customers. Mississippi Power does not intend to seek any rate recovery for any related costs that exceed the $2.88 billion cost cap, net of the Initial DOE Grants and excluding the Cost Cap Exceptions. Southern Company recorded pre-tax charges to income for revisions to the cost estimate subject to the construction cost cap totaling $348 million ($215 million after tax), $365 million ($226 million after tax), and $868 million ($536 million after tax) in 2016, 2015, and 2014, respectively. Since 2013, in the aggregate, Southern Company has incurred charges of $2.76 billion ($1.71 billion after tax) as a result of changes in the cost estimate above the cost cap for the Kemper IGCC through December 31, 2016. The current cost estimate includes costs through March 15, 2017. In addition to the current construction cost estimate, Mississippi Power is identifying potential improvement projects that ultimately may be completed subsequent to placing the remainder of the Kemper IGCC in service. If completed, such improvement projects would be expected to enhance plant performance, safety, and/or operations. As of December 31, 2016, Southern Company 2016 Annual Report Management’s Discussion and Analysis of Financial Condition and Results of Operations 29 approximately $12 million of related potential costs has been included in the estimated loss on the Kemper IGCC. Other projects have yet to be fully evaluated, have not been included in the current cost estimate, and may be subject to the $2.88 billion cost cap. Any further changes in the estimated costs of the Kemper IGCC subject to the $2.88 billion cost cap, net of the Initial DOE Grants and excluding the Cost Cap Exceptions, will be reflected in Southern Company’s statements of income and these changes could be material. The expected completion date of the Kemper IGCC at the time of the Mississippi PSC’s approval in 2010 was May 2014. The combined cycle and the associated common facilities portion of the Kemper IGCC were placed in service in August 2014. The remainder of the plant, including the gasifiers and the gas clean-up facilities, represents first-of-a-kind technology. The initial production of syngas began on July 14, 2016 for gasifier “B” and on September 13, 2016 for gasifier “A.” Mississippi Power achieved integrated operation of both gasifiers on January 29, 2017, including the production of electricity from syngas in both combustion turbines. Mississippi Power subsequently completed a brief outage to repair and make modifications to further improve the plant’s ability to achieve sustained operations sufficient to support placing the plant in service for customers. Efforts to reach sustained operation of both gasifiers and production of electricity from syngas in both combustion turbines are in process. The plant has produced and captured CO2, and has produced sulfuric acid and ammonia, all of acceptable quality under the related off-take agreements. On February 20, 2017, Mississippi Power determined gasifier “B,” which has been producing syngas over 60% of the time since early November 2016, requires an outage to remove ash deposits from its ash removal system. Gasifier “A” and combustion turbine “A” are expected to remain in operation, producing electricity from syngas, as well as producing chemical by-products. As a result, Mississippi Power currently expects the remainder of the Kemper IGCC, including both gasifiers, will be placed in service by mid-March 2017. Upon placing the remainder of the plant in service, Mississippi Power will be primarily focused on completing the regulatory cost recovery process. In December 2015, the Mississippi PSC issued an order, based on a stipulation between Mississippi Power and the MPUS, authorizing rates that provide for the recovery of approximately $126 million annually related to Kemper IGCC assets previously placed in service. On August 17, 2016, the Mississippi PSC established a discovery docket to manage all filings related to Kemper IGCC prudence issues. On October 3, 2016 and November 17, 2016, Mississippi Power made filings in this docket including a review and explanation of differences between the Kemper IGCC project estimate set forth in the 2010 CPCN proceedings and the most recent Kemper IGCC project estimate, as well as comparisons of current cost estimates and current expected plant operational parameters to the estimates presented in the 2010 CPCN proceedings for the first five years after the Kemper IGCC is placed in service. Compared to amounts presented in the 2010 CPCN proceedings, operations and maintenance expenses have increased an average of $105 million annually and maintenance capital has increased an average of $44 million annually for the first full five years of operations for the Kemper IGCC. Additionally, while the current estimated operational availability estimates reflect ultimate results similar to those presented in the 2010 CPCN proceedings, the ramp up period for the current estimates reflects a lower starting point and a slower escalation rate. In the fourth quarter 2016, as a part of the Integrated Resource Plan process, the Southern Company system completed its regular annual updated fuel forecast, the 2017 Annual Fuel Forecast. This updated fuel forecast reflected significantly lower long- term estimated costs for natural gas than were previously projected. As a result of the updated long-term natural gas forecast, as well as the revised operating expense projections reflected in the discovery docket filings, on February 21, 2017, Mississippi Power filed an updated project economic viability analysis of the Kemper IGCC as required under the 2012 MPSC CPCN Order. The project economic viability analysis measures the life cycle economics of the Kemper IGCC compared to feasible alternatives, natural gas combined cycle generating units, under a variety of scenarios and considering fuel, operating and capital costs, and operating characteristics, as well as federal and state taxes and incentives. The reduction in the projected long-term natural gas prices in the 2017 Annual Fuel Forecast and, to a lesser extent, the increase in the estimated Kemper IGCC operating costs, negatively impact the updated project economic viability analysis. After the remainder of the plant is placed in service, AFUDC equity of approximately $11 million per month will no longer be recorded in income, and Mississippi Power expects to incur approximately $25 million per month in depreciation, taxes, operations and maintenance expenses, interest expense, and regulatory costs in excess of current rates. Mississippi Power expects to file a request for authority from the Mississippi PSC and the FERC to defer all Kemper IGCC costs incurred after the in-service date that cannot be capitalized, are not included in current rates, and are not required to be charged against earnings as a result of the $2.88 billion cost cap until such time as the Mississippi PSC completes its review and includes the resulting allowable costs in rates. In the event that the Mississippi PSC does not grant Mississippi Power’s request for an accounting order, these monthly expenses will be charged to income as incurred and will not be recoverable through rates. The ultimate outcome of this matter cannot now be determined but could have a material impact on Southern Company’s result of operations, financial condition, and liquidity. Mississippi Power is required to file a rate case to address Kemper IGCC cost recovery by June 3, 2017 (2017 Rate Case). Costs incurred through December 31, 2016 totaled $6.73 billion, net of the Initial and Additional DOE Grants. Of this total, $2.76 billion of costs has been recognized through income as a result of the $2.88 billion cost cap, $0.83 billion is included in retail and wholesale rates for the assets in service, and the remainder will be the subject of the 2017 Rate Case to be filed with the Mississippi PSC and expected subsequent wholesale Municipal and Rural Associations rate filing with the FERC. Mississippi Power continues to believe that all costs related to the Kemper IGCC have been prudently incurred in accordance with the investor.southerncompany.com 30 Management’s Discussion and Analysis of Financial Condition and Results of Operations requirements of the 2012 MPSC CPCN Order. Mississippi Power also recognizes significant areas of potential challenge during future regulatory proceedings (and any subsequent, related legal challenges) exist. As described further herein, these challenges include, but are not limited to, prudence issues associated with capital costs, financing costs (AFUDC), and future operating costs, net of chemical revenues; potential operating parameters; income tax issues; costs deferred as regulatory assets; and the 15% portion of the project previously contracted to SMEPA. Although the 2017 Rate Case has not yet been filed and is subject to future developments with either the Kemper IGCC or the Mississippi PSC, consistent with its approach in the 2013 and 2015 rate proceedings in accordance with the law passed in 2013 authorizing multi-year rate plans, Mississippi Power is developing both a traditional rate case requesting full cost recovery of the $3.31 billion (net of $137 million in Additional DOE Grants) not currently in rates and a rate mitigation plan that together represent Mississippi Power’s probable filing strategy. Mississippi Power also expects that timely resolution of the 2017 Rate Case will likely require a negotiated settlement agreement. In the event an agreement acceptable to both Mississippi Power and the MPUS (and other parties) can be negotiated and ultimately approved by the Mississippi PSC, it is reasonably possible that full regulatory recovery of all Kemper IGCC costs will not occur. The impact of such an agreement on Southern Company’s financial statements would depend on the method, amount, and type of cost recovery ultimately excluded. Certain costs, including operating costs, would be recorded to income in the period incurred, while other costs, including investment-related costs, would be charged to income when it is probable they will not be recovered and the amounts can be reasonably estimated. In the event an agreement acceptable to the parties cannot be reached, Mississippi Power intends to fully litigate its request for full recovery through the Mississippi PSC regulatory process and any subsequent legal challenges. Mississippi Power has evaluated various scenarios in connection with its processes to prepare the 2017 Rate Case and has recognized an additional $80 million charge to income, which is the estimated minimum probable amount of the $3.31 billion of Kemper IGCC costs not currently in rates that would not be recovered under the probable rate mitigation plan to be filed by June 3, 2017. Given the variety of potential scenarios and the uncertainty of the outcome of future regulatory proceedings with the Mississippi PSC (and any subsequent related legal challenges), the ultimate outcome of these matters cannot now be determined but could result in further charges that could have a material impact on Southern Company’s results of operations, financial condition, and liquidity. Southern Company and Mississippi Power are defendants in various lawsuits that allege improper disclosure about the Kemper IGCC, as discussed below under “Litigation.” In addition, the SEC is conducting a formal investigation of Southern Company and Mississippi Power concerning the estimated costs and expected in-service date of the Kemper IGCC. Southern Company believes the investigation is focused primarily on periods subsequent to 2010 and on accounting matters, disclosure controls and procedures, and internal controls over financial reporting associated with the Kemper IGCC. See “Other Matters” herein for additional information. The ultimate outcome of these matters cannot be determined at this time. See Note 3 to the financial statements under “Integrated Coal Gasification Combined Cycle” for additional information. Litigation On April 26, 2016, a complaint against Mississippi Power was filed in Harrison County Circuit Court (Circuit Court) by Biloxi Freezing & Processing Inc., Gulfside Casino Partnership, and John Carlton Dean, which was amended and refiled on July 11, 2016 to include, among other things, Southern Company as a defendant. On August 12, 2016, Southern Company and Mississippi Power removed the case to the U.S. District Court for the Southern District of Mississippi. The plaintiffs filed a request to remand the case back to state court, which was granted on November 17, 2016. The individual plaintiff, John Carlton Dean, alleges that Mississippi Power and Southern Company violated the Mississippi Unfair Trade Practices Act. All plaintiffs have alleged that Mississippi Power and Southern Company concealed, falsely represented, and failed to fully disclose important facts concerning the cost and schedule of the Kemper IGCC and that these alleged breaches have unjustly enriched Mississippi Power and Southern Company. The plaintiffs seek unspecified actual damages and punitive damages; ask the Circuit Court to appoint a receiver to oversee, operate, manage, and otherwise control all affairs relating to the Kemper IGCC; ask the Circuit Court to revoke any licenses or certificates authorizing Mississippi Power or Southern Company to engage in any business related to the Kemper IGCC in Mississippi; and seek attorney’s fees, costs, and interest. The plaintiffs also seek an injunction to prevent any Kemper IGCC costs from being charged to customers through electric rates. On December 7, 2016, Southern Company filed motions to dismiss. On June 9, 2016, Treetop Midstream Services, LLC (Treetop) and other related parties filed a complaint against Mississippi Power, Southern Company, and SCS in the state court in Gwinnett County, Georgia. The complaint relates to the cancelled CO2 contract with Treetop and alleges fraudulent misrepresentation, fraudulent concealment, civil conspiracy, and breach of contract on the part of Mississippi Power, Southern Company, and SCS and seeks compensatory damages of $100 million, as well as unspecified punitive damages. Southern Company, Mississippi Power, and SCS have moved to compel arbitration pursuant to the terms of the CO2 contract. Southern Company believes these legal challenges have no merit; however, an adverse outcome in these proceedings could have an impact on Southern Company’s results of operations, financial condition, and liquidity. Southern Company will vigorously defend itself in these matters, and the ultimate outcome of these matters cannot be determined at this time. Southern Company 2016 Annual Report Management’s Discussion and Analysis of Financial Condition and Results of Operations 31 Nuclear Construction In 2008, Georgia Power, acting for itself and as agent for Oglethorpe Power Corporation (OPC), the Municipal Electric Authority of Georgia (MEAG Power), and the City of Dalton, Georgia (Dalton), acting by and through its Board of Water, Light, and Sinking Fund Commissioners, doing business as Dalton Utilities (collectively, Vogtle Owners), entered into an agreement with a consortium consisting of Westinghouse and Stone & Webster, Inc., which was subsequently acquired by Westinghouse and changed its name to WECTEC Global Project Services Inc. (WECTEC) (Westinghouse and WECTEC, collectively, Contractor), pursuant to which the Contractor agreed to design, engineer, procure, construct, and test two AP1000 nuclear units (with electric generating capacity of approximately 1,100 MWs each) and related facilities at Plant Vogtle (Vogtle 3 and 4 Agreement). Under the terms of the Vogtle 3 and 4 Agreement, the Vogtle Owners agreed to pay a purchase price subject to certain price escalations and adjustments, including fixed escalation amounts and index-based adjustments, as well as adjustments for change orders, and performance bonuses for early completion and unit performance. The Vogtle 3 and 4 Agreement also provides for liquidated damages upon the Contractor’s failure to fulfill the schedule and performance guarantees, subject to an aggregate cap of 10% of the contract price, or approximately $920 million to $930 million. In addition, the Vogtle 3 and 4 Agreement provides for limited cost sharing by the Vogtle Owners for Contractor costs under certain conditions (which Georgia Power has not been notified have occurred) with maximum additional capital costs under this provision attributable to Georgia Power (based on Georgia Power’s ownership interest) of approximately $114 million. Each Vogtle Owner is severally (and not jointly) liable for its proportionate share, based on its ownership interest, of all amounts owed to the Contractor under the Vogtle 3 and 4 Agreement. Georgia Power’s proportionate share is 45.7%. In the event of certain credit rating downgrades of any Vogtle Owner, such Vogtle Owner will be required to provide a letter of credit or other credit enhancement. Certain obligations of Westinghouse have been guaranteed by Toshiba Corporation (Toshiba), Westinghouse’s parent company. In the event of certain credit rating downgrades of Toshiba, Westinghouse is required to provide letters of credit or other credit enhancement. In December 2015, Toshiba experienced credit rating downgrades and Westinghouse provided the Vogtle Owners with $920 million of letters of credit. These letters of credit remain in place in accordance with the terms of the Vogtle 3 and 4 Agreement. On February 14, 2017, Toshiba announced preliminary earnings results for the period ended December 31, 2016, which included a substantial goodwill impairment charge at Westinghouse attributed to increased cost estimates to complete its U.S. nuclear projects, including Plant Vogtle Units 3 and 4. Toshiba also warned that it will likely be in a negative equity position as a result of the charges. At the same time, Toshiba reaffirmed its commitment to its U.S. nuclear projects with implementation of management changes and increased oversight. An inability or failure by the Contractor to perform its obligations under the Vogtle 3 and 4 Agreement could have a material impact on the construction of Plant Vogtle Units 3 and 4. Under the terms of the Vogtle 3 and 4 Agreement, the Contractor does not have a right to terminate the Vogtle 3 and 4 Agreement for convenience. The Contractor may terminate the Vogtle 3 and 4 Agreement under certain circumstances, including certain Vogtle Owner suspension or delays of work, action by a governmental authority to permanently stop work, certain breaches of the Vogtle 3 and 4 Agreement by the Vogtle Owners, Vogtle Owner insolvency, and certain other events. In the event of an abandonment of work by the Contractor, the maximum liability of the Contractor under the Vogtle 3 and 4 Agreement is increased significantly, but remains subject to limitations. The Vogtle Owners may terminate the Vogtle 3 and 4 Agreement at any time for convenience, provided that the Vogtle Owners will be required to pay certain termination costs. In 2009, the Georgia PSC voted to certify construction of Plant Vogtle Units 3 and 4 with a certified capital cost of $4.418 billion. In addition, in 2009 the Georgia PSC approved inclusion of the Plant Vogtle Units 3 and 4 related CWIP accounts in rate base, and the State of Georgia enacted the Georgia Nuclear Energy Financing Act, which allows Georgia Power to recover financing costs for nuclear construction projects certified by the Georgia PSC. Financing costs are recovered on all applicable certified costs through annual adjustments to the NCCR tariff by including the related CWIP accounts in rate base during the construction period. The Georgia PSC approved an NCCR tariff of $368 million for 2014, as well as increases to the NCCR tariff of approximately $27 million and $19 million effective January 1, 2015 and 2016, respectively. Georgia Power is required to file semi-annual Vogtle Construction Monitoring (VCM) reports with the Georgia PSC by February 28 and August 31 each year. In accordance with the 2009 certification order, Georgia Power requested amendments to the Plant Vogtle Units 3 and 4 certificate in both the February 2013 (eighth VCM) and February 2015 (twelfth VCM) filings, when projected construction capital costs to be borne by Georgia Power increased by 5% above the certified costs and estimated in-service dates were extended. In October 2013, the Georgia PSC approved a stipulation (2013 Stipulation) between Georgia Power and the Georgia PSC Staff to waive the requirement to amend the Plant Vogtle Units 3 and 4 certificate until the completion of Plant Vogtle Unit 3 or earlier if deemed appropriate by the Georgia PSC and Georgia Power. In April 2015, the Georgia PSC recognized that the certified cost and the 2013 Stipulation did not constitute a cost recovery cap and deemed the amendment requested in the February 2015 filing unnecessary and withdrawn until the completion of construction of Plant Vogtle Unit 3 consistent with the 2013 Stipulation. On December 31, 2015, Westinghouse and the Vogtle Owners entered into a definitive settlement agreement (Contractor Settlement Agreement) to resolve disputes between the Vogtle Owners and the Contractor under the Vogtle 3 and 4 Agreement, including litigation that was pending in the U.S. District Court for the Southern District of Georgia (Vogtle Construction Litigation). Effective December 31, 2015, Georgia Power, acting for itself and as agent for the other Vogtle Owners, and the investor.southerncompany.com 32 Management’s Discussion and Analysis of Financial Condition and Results of Operations Contractor entered into an amendment to the Vogtle 3 and 4 Agreement to implement the Contractor Settlement Agreement. The Contractor Settlement Agreement and the related amendment to the Vogtle 3 and 4 Agreement (i) restrict the Contractor’s ability to seek further increases in the contract price by clarifying and limiting the circumstances that constitute nuclear regulatory changes in law; (ii) provide for enhanced dispute resolution procedures; (iii) revise the guaranteed substantial completion dates to June 30, 2019 for Unit 3 and June 30, 2020 for Unit 4; (iv) provide that delay liquidated damages will commence if the nuclear fuel loading date for each unit does not occur by December 31, 2018 for Unit 3 and December 31, 2019 for Unit 4; and (v) provide that Georgia Power, based on its ownership interest, will pay to the Contractor and capitalize to the project cost approximately $350 million, of which approximately $263 million had been paid as of December 31, 2016. In addition, the Contractor Settlement Agreement provides for the resolution of other open existing items relating to the scope of the project under the Vogtle 3 and 4 Agreement, including cyber security, for which costs are reflected in Georgia Power’s current in-service forecast of $5.440 billion. Further, as part of the settlement and Westinghouse’s acquisition of WECTEC: (i) Westinghouse engaged Fluor Enterprises, Inc., a subsidiary of Fluor Corporation, as a new construction subcontractor and (ii) the Vogtle Owners, Chicago Bridge & Iron Co, N.V., and The Shaw Group Inc. entered into mutual releases of any and all claims arising out of events or circumstances in connection with the construction of Plant Vogtle Units 3 and 4 that occurred on or before the date of the Contractor Settlement Agreement. On January 5, 2016, the Vogtle Construction Litigation was dismissed with prejudice. On December 20, 2016, the Georgia PSC voted to approve a settlement agreement (Vogtle Cost Settlement Agreement) resolving the following prudence matters: (i) none of the $3.3 billion of costs incurred through December 31, 2015 and reflected in the fourteenth VCM report will be disallowed from rate base on the basis of imprudence; (ii) the Contractor Settlement Agreement is reasonable and prudent and none of the amounts paid or to be paid pursuant to the Contractor Settlement Agreement should be disallowed from rate base on the basis of imprudence; (iii) financing costs on verified and approved capital costs will be deemed prudent provided they are incurred prior to December 31, 2019 and December 31, 2020 for Plant Vogtle Units 3 and 4, respectively; and (iv) (a) the in-service capital cost forecast will be adjusted to $5.680 billion (Revised Forecast), which includes a contingency of $240 million above Georgia Power’s current forecast of $5.440 billion, (b) capital costs incurred up to the Revised Forecast will be presumed to be reasonable and prudent with the burden of proof on any party challenging such costs, and (c) Georgia Power would have the burden to show that any capital costs above the Revised Forecast are reasonable and prudent. Under the terms of the Vogtle Cost Settlement Agreement, the certified in-service capital cost for purposes of calculating the NCCR tariff will remain at $4.418 billion. Construction capital costs above $4.418 billion will accrue AFUDC through the date each unit is placed in service. The ROE used to calculate the NCCR tariff was reduced from 10.95% (the ROE rate setting point authorized by the Georgia PSC in the 2013 ARP) to 10.00% effective January 1, 2016. For purposes of the AFUDC calculation, the ROE on costs between $4.418 billion and $5.440 billion will also be 10.00% and the ROE on any amounts above $5.440 billion would be Georgia Power’s average cost of long-term debt. If the Georgia PSC adjusts Georgia Power’s ROE rate setting point in a rate case prior to Plant Vogtle Units 3 and 4 being placed into retail rate base, then the ROE for purposes of calculating both the NCCR tariff and AFUDC will likewise be 95 basis points lower than the revised ROE rate setting point. If Plant Vogtle Units 3 and 4 are not placed in service by December 31, 2020, then (i) the ROE for purposes of calculating the NCCR tariff will be reduced an additional 300 basis points, or $8 million per month, and may, at the Georgia PSC’s discretion, be accrued to be used for the benefit of customers, until such time as the units are placed in service and (ii) the ROE used to calculate AFUDC will be Georgia Power’s average cost of long-term debt. Under the terms of the Vogtle Cost Settlement Agreement, Plant Vogtle Units 3 and 4 will be placed into retail rate base on December 31, 2020 or when placed in service, whichever is later. The Georgia PSC will determine for retail ratemaking purposes the process of transitioning Plant Vogtle Units 3 and 4 from a construction project to an operating plant no later than Georgia Power’s base rate case required to be filed by July 1, 2019. The Georgia PSC has approved fifteen VCM reports covering the periods through June 30, 2016, including construction capital costs incurred, which through that date totaled $3.7 billion. Georgia Power expects to file the sixteenth VCM report, covering the period from July 1 through December 31, 2016, requesting approval of $222 million of construction capital costs incurred during that period, with the Georgia PSC by February 28, 2017. Georgia Power’s CWIP balance for Plant Vogtle Units 3 and 4 was approximately $3.9 billion as of December 31, 2016, and Georgia Power had incurred $1.3 billion in financing costs through December 31, 2016. As of December 31, 2016, Georgia Power had borrowed $2.6 billion related to Plant Vogtle Units 3 and 4 costs through a loan guarantee agreement between Georgia Power and the DOE and a multi-advance credit facility among Georgia Power, the DOE, and the FFB. See Note 6 to the financial statements under “DOE Loan Guarantee Borrowings” for additional information, including applicable covenants, events of default, and mandatory prepayment events. There have been technical and procedural challenges to the construction and licensing of Plant Vogtle Units 3 and 4 at the federal and state level and additional challenges may arise as construction proceeds. Processes are in place that are designed to assure compliance with the requirements specified in the Westinghouse Design Control Document and the combined construction and operating licenses, including inspections by Southern Nuclear and the NRC that occur throughout construction. As a result of such compliance processes, certain license amendment requests have been filed and approved or are pending before the NRC. Various design and other licensing-based compliance matters, including the timely resolution of Inspections, Tests, Analyses, and Acceptance Criteria and the related approvals by the NRC, may arise as construction proceeds, which may result in additional license amendments or require other resolution. If any license amendment requests or other licensing-based compliance issues are not resolved in a timely manner, there may be delays in the project schedule that could result in increased costs either to the Vogtle Owners or the Contractor or to both. Southern Company 2016 Annual Report Management’s Discussion and Analysis of Financial Condition and Results of Operations 33 In addition to Toshiba’s reaffirmation of its commitment, the Contractor provided Georgia Power with revised forecasted in- service dates of December 2019 and September 2020 for Plant Vogtle Units 3 and 4, respectively. Georgia Power is currently reviewing a preliminary summary schedule supporting these dates that ultimately must be reconciled to a detailed integrated project schedule. As construction continues, the risk remains that challenges with Contractor performance including labor productivity, fabrication, delivery, assembly, and installation of plant systems, structures, and components, or other issues could arise and may further impact project schedule and cost. Georgia Power expects the Contractor to employ mitigation efforts and believes the Contractor is responsible for any related costs under the Vogtle 3 and 4 Agreement. Georgia Power estimates its financing costs for Plant Vogtle Units 3 and 4 to be approximately $30 million per month, with total construction period financing costs of approximately $2.5 billion. Additionally, Georgia Power estimates its owner’s costs to be approximately $6 million per month, net of delay liquidated damages. The revised forecasted in-service dates are within the timeframe contemplated in the Vogtle Cost Settlement Agreement and would enable both units to qualify for production tax credits the IRS has allocated to each of Plant Vogtle Units 3 and 4, which require the applicable unit to be placed in service before 2021. The net present value of the production tax credits is estimated at approximately $400 million per unit. Future claims by the Contractor or Georgia Power (on behalf of the Vogtle Owners) could arise throughout construction. These claims may be resolved through formal and informal dispute resolution procedures under the Vogtle 3 and 4 Agreement and, under the enhanced dispute resolution procedures, may be resolved through litigation after the completion of nuclear fuel load for both units. The ultimate outcome of these matters cannot be determined at this time. Income Tax Matters Bonus Depreciation In December 2015, the Protecting Americans from Tax Hikes (PATH) Act was signed into law. Bonus depreciation was extended for qualified property placed in service through 2020. The PATH Act allows for 50% bonus depreciation for 2015 through 2017, 40% bonus depreciation for 2018, and 30% bonus depreciation for 2019 and certain long-lived assets placed in service in 2020. The extension of bonus depreciation included in the PATH Act is expected to result in approximately $1.3 billion of positive cash flows for the 2016 tax year, which was not all realized in 2016 due to a projected consolidated net operating loss (NOL) for Southern Company. Approximately $1.2 billion of positive cash flows is expected to result from bonus depreciation for the 2017 tax year, but may not all be realized in 2017 due to additional NOL projections for the 2017 tax year. As a result of the schedule extension for the Kemper IGCC, approximately $370 million of the 2017 benefit is dependent upon placing the remainder of the Kemper IGCC in service by December 31, 2017. See Note 3 to the financial statements under “Integrated Coal Gasification Combined Cycle” and Note 5 to the financial statements under “Current and Deferred Income Taxes – Net Operating Loss” for additional information. The ultimate outcome of this matter cannot be determined at this time. Tax Credits The PATH Act allows for 30% ITC for solar projects that commence construction by December 31, 2019; 26% ITC for solar projects that commence construction in 2020; 22% ITC for solar projects that commence construction in 2021; and a permanent 10% ITC for solar projects that commence construction on or after January 1, 2022. In addition, the PATH Act extended the PTC for wind projects with a phase out that allows for 100% PTC for wind projects that commenced construction in 2016; 80% PTC for wind projects that commence construction in 2017; 60% PTC for wind projects that commence construction in 2018; and 40% PTC for wind projects that commence construction in 2019. The Company has received ITCs and PTCs in connection with investments in solar, wind, and biomass facilities primarily at Southern Power and Georgia Power. See Note 1 to the financial statements under “Income and Other Taxes” and Note 5 to the financial statements under “Current and Deferred Income Taxes – Tax Credit Carryforwards” for additional information regarding utilization and amortization of credits and the tax benefit related to basis differences. Section 174 Research and Experimental Deduction Southern Company reflected deductions for research and experimental (R&E) expenditures related to the Kemper IGCC in its federal income tax calculations since 2013 and filed amended federal income tax returns for 2008 through 2013 to also include such deductions. In December 2016, Southern Company and the IRS reached a proposed settlement, subject to approval of the U.S. Congress Joint Committee on Taxation, resolving a methodology for these deductions. Due to the uncertainty related to this tax position, Southern Company had unrecognized tax benefits associated with these R&E deductions totaling approximately $464 million as of December 31, 2016. See “Bonus Depreciation” herein and Note 5 to the financial statements under “Unrecognized Tax Benefits” for additional information. This matter is expected to be resolved in the next 12 months; however, the ultimate outcome of this matter cannot be determined at this time. investor.southerncompany.com 34 Management’s Discussion and Analysis of Financial Condition and Results of Operations Other Matters Southern Company and its subsidiaries are involved in various other matters being litigated and regulatory matters that could affect future earnings. In addition, Southern Company and its subsidiaries are subject to certain claims and legal actions arising in the ordinary course of business. The business activities of Southern Company’s subsidiaries are subject to extensive governmental regulation related to public health and the environment, such as regulation of air emissions and water discharges. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements, such as air quality and water standards, has occurred throughout the U.S. This litigation has included claims for damages alleged to have been caused by CO2 and other emissions, CCR, and alleged exposure to hazardous materials, and/or requests for injunctive relief in connection with such matters. The ultimate outcome of such pending or potential litigation against Southern Company and its subsidiaries cannot be predicted at this time; however, for current proceedings not specifically reported herein or in Note 3 to the financial statements, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on Southern Company’s financial statements. See Note 3 to the financial statements for a discussion of various other contingencies, regulatory matters, and other matters being litigated which may affect future earnings potential. On January 20, 2017, a purported securities class action complaint was filed against Southern Company and certain of its and Mississippi Power’s officers in the U.S. District Court for the Northern District of Georgia, Atlanta Division, by Monroe County Employees’ Retirement System on behalf of all persons who purchased shares of Southern Company’s common stock between April 25, 2012 and October 29, 2013. The complaint alleges that Southern Company and certain of its and Mississippi Power’s officers made materially false and misleading statements regarding the Kemper IGCC in violation of certain provisions under the Securities Exchange Act of 1934, as amended. The complaint seeks, among other things, compensatory damages and litigation costs and attorneys’ fees. Southern Company believes this legal challenge has no merit; however, an adverse outcome in this proceeding could have an impact on Southern Company’s results of operations, financial condition, and liquidity. Southern Company will vigorously defend itself in this matter, and the ultimate outcome of this matter cannot be determined at this time. The SEC is conducting a formal investigation of Southern Company and Mississippi Power concerning the estimated costs and expected in-service date of the Kemper IGCC. Southern Company believes the investigation is focused primarily on periods subsequent to 2010 and on accounting matters, disclosure controls and procedures, and internal controls over financial reporting associated with the Kemper IGCC. See ACCOUNTING POLICIES – “Application of Critical Accounting Policies and Estimates” herein for additional information on the Kemper IGCC estimated construction costs and expected in-service date. The ultimate outcome of this matter cannot be determined at this time; however, it is not expected to have a material impact on the financial statements of Southern Company. ACCOUNTING POLICIES Application of Critical Accounting Policies and Estimates Southern Company prepares its consolidated financial statements in accordance with GAAP. Significant accounting policies are described in Note 1 to the financial statements. In the application of these policies, certain estimates are made that may have a material impact on Southern Company’s results of operations and related disclosures. Different assumptions and measurements could produce estimates that are significantly different from those recorded in the financial statements. Senior management has reviewed and discussed the following critical accounting policies and estimates with the Audit Committee of Southern Company’s Board of Directors. Utility Regulation Southern Company’s traditional electric operating companies and natural gas distribution utilities, which collectively comprised approximately 91% of Southern Company’s total operating revenues for 2016, are subject to retail regulation by their respective state PSCs or other applicable state regulatory agencies and wholesale regulation by the FERC. These regulatory agencies set the rates the traditional electric operating companies and the natural gas distribution utilities are permitted to charge customers based on allowable costs, including a reasonable ROE. As a result, the traditional electric operating companies and the natural gas distribution utilities apply accounting standards which require the financial statements to reflect the effects of rate regulation. Through the ratemaking process, the regulators may require the inclusion of costs or revenues in periods different than when they would be recognized by a non-regulated company. This treatment may result in the deferral of expenses and the recording of related regulatory assets based on anticipated future recovery through rates or the deferral of gains or creation of liabilities and the recording of related regulatory liabilities. The application of the accounting standards has a further effect on the Company’s financial statements as a result of the estimates of allowable costs used in the ratemaking process. These estimates may differ from those actually incurred by the traditional electric operating companies and the natural gas distribution utilities; therefore, the accounting estimates inherent in specific costs such as depreciation, AROs, and pension and other postretirement benefits have less of a direct impact on the Company’s results of operations and financial condition than they would on a non-regulated company. Southern Company 2016 Annual Report Management’s Discussion and Analysis of Financial Condition and Results of Operations 35 As reflected in Note 1 to the financial statements, significant regulatory assets and liabilities have been recorded. Management reviews the ultimate recoverability of these regulatory assets and any requirement to refund these regulatory liabilities based on applicable regulatory guidelines and GAAP. However, adverse legislative, judicial, or regulatory actions could materially impact the amounts of such regulatory assets and liabilities and could adversely impact the Company’s financial statements. Kemper IGCC Estimated Construction Costs, Project Completion Date, and Rate Recovery During 2016, Mississippi Power further revised its cost estimate to complete construction and start-up of the Kemper IGCC to an amount that exceeds the $2.88 billion cost cap, net of the Initial DOE Grants and excluding the Cost Cap Exceptions. Mississippi Power does not intend to seek any rate recovery for any costs related to the construction of the Kemper IGCC that exceed the $2.88 billion cost cap, net of the Initial DOE Grants and excluding the Cost Cap Exceptions. As a result of revisions to the cost estimate, Southern Company recorded total pre-tax charges to income for the estimated probable losses on the Kemper IGCC subject to the construction cost cap of $127 million ($78 million after tax) in the fourth quarter 2016, $88 million ($54 million after tax) in the third quarter 2016, $81 million ($50 million after tax) in the second quarter 2016, $53 million ($33 million after tax) in the first quarter 2016, $183 million ($113 million after tax) in the fourth quarter 2015, $150 million ($93 million after tax) in the third quarter 2015, $23 million ($14 million after tax) in the second quarter 2015, $9 million ($6 million after tax) in the first quarter 2015, $70 million ($43 million after tax) in the fourth quarter 2014, $418 million ($258 million after tax) in the third quarter 2014, $380 million ($235 million after tax) in the first quarter 2014, $40 million ($25 million after tax) in the fourth quarter 2013, $150 million ($93 million after tax) in the third quarter 2013, $450 million ($278 million after tax) in the second quarter 2013, and $540 million ($333 million after tax) in the first quarter 2013. In the aggregate, Southern Company has incurred charges of $2.76 billion ($1.71 billion after tax) as a result of changes in the cost estimate above the cost cap for the Kemper IGCC through December 31, 2016. Mississippi Power’s revised cost estimate reflects an expected in-service date of mid-March 2017 and includes certain post- in-service costs which are expected to be subject to the cost cap. Mississippi Power has experienced, and may continue to experience, material changes in the cost estimate for the Kemper IGCC. Further cost increases and/or extensions of the expected in-service date may result from factors including, but not limited to, difficulties integrating the systems required for sustained operations, sustaining nitrogen supply, major equipment failure, unforeseen engineering or design problems including any repairs and/or modifications to systems, and/or operational performance (including additional costs to satisfy any operational parameters ultimately adopted by the Mississippi PSC). In addition to the current construction cost estimate, Mississippi Power is also identifying potential improvement projects that ultimately may be completed subsequent to placing the remainder of the Kemper IGCC in service. If completed, such improvement projects would be expected to enhance plant performance, safety, and/or operations. As of December 31, 2016, approximately $12 million of related potential costs has been included in the estimated loss on the Kemper IGCC. Other projects have yet to be fully evaluated, have not been included in the current cost estimate, and may be subject to the $2.88 billion cost cap. In subsequent periods, any further changes in the estimated costs of the Kemper IGCC subject to the $2.88 billion cost cap, net of the Initial DOE Grants and excluding the Cost Cap Exceptions, will be reflected in Southern Company’s statements of income and these changes could be material. Any extension of the in-service date beyond mid-March 2017 is currently estimated to result in additional base costs of approximately $25 million to $35 million per month, which includes maintaining necessary levels of start-up labor, materials, and fuel, as well as operational resources required to execute start-up and commissioning activities. However, additional costs may be required for remediation of any further equipment and/or design issues identified. Any extension of the in-service date with respect to the Kemper IGCC beyond mid-March 2017 would also increase costs for the Cost Cap Exceptions, which are not subject to the $2.88 billion cost cap established by the Mississippi PSC. These costs include AFUDC, which is currently estimated to total approximately $16 million per month, as well as carrying costs and operating expenses on Kemper IGCC assets placed in service and consulting and legal fees of approximately $3 million per month. Mississippi Power continues to believe that all costs related to the Kemper IGCC have been prudently incurred in accordance with the requirements of the 2012 MPSC CPCN Order. Mississippi Power also recognizes significant areas of potential challenge during future regulatory proceedings (and any subsequent, related legal challenges) exist. As described further in Note 3 to the financial statements under “Integrated Coal Gasification Combined Cycle – Rate Recovery of Kemper IGCC Costs,” “ – Prudence,” “ – Lignite Mine and CO2 Pipeline Facilities,” “ – Termination of Proposed Sale of Undivided Interest,” “ – Bonus Depreciation,” “ – Investment Tax Credits,” and “ – Section 174 Research and Experimental Deduction,” these challenges include, but are not limited to, prudence issues associated with capital costs, financing costs (AFUDC), and future operating costs, net of chemical revenues; potential operating parameters; income tax issues; costs deferred as regulatory assets; and the 15% portion of the project previously contracted to SMEPA. Although the 2017 Rate Case has not yet been filed and is subject to future developments with either the Kemper IGCC or the Mississippi PSC, consistent with its approach in the 2013 and 2015 rate proceedings in accordance with the law passed in 2013 authorizing multi-year rate plans, Mississippi Power is developing both a traditional rate case requesting full cost recovery of the amounts not currently in rates and a rate mitigation plan that together represent Mississippi Power’s probable filing strategy. Mississippi Power also expects that timely resolution of the 2017 Rate Case will likely require a negotiated settlement agreement. In the event an agreement acceptable to both Mississippi Power and the MPUS (and other parties) can be negotiated and ultimately approved by the Mississippi PSC, it is reasonably possible that full regulatory recovery of all Kemper investor.southerncompany.com 36 Management’s Discussion and Analysis of Financial Condition and Results of Operations IGCC costs will not occur. The impact of such an agreement on Southern Company’s financial statements would depend on the method, amount, and type of cost recovery ultimately excluded. Certain costs, including operating costs, would be recorded to income in the period incurred, while other costs, including investment-related costs, would be charged to income when it is probable they will not be recovered and the amounts can be reasonably estimated. In the event an agreement acceptable to the parties cannot be reached, Mississippi Power intends to fully litigate its request for full recovery through the Mississippi PSC regulatory process and any subsequent legal challenges. Mississippi Power has evaluated various scenarios in connection with its processes to prepare the 2017 Rate Case and has recognized an additional $80 million charge to income, which is the estimated minimum probable amount of the $3.31 billion of Kemper IGCC costs not currently in rates that would not be recovered under the probable rate mitigation plan to be filed by June 3, 2017. Given the significant judgment involved in estimating the future costs to complete construction and start-up, the project completion date, the ultimate rate recovery for the Kemper IGCC, and the potential impact on Southern Company’s results of operations, Southern Company considers these items to be critical accounting estimates. See Note 3 to the financial statements under “Integrated Coal Gasification Combined Cycle” for additional information. Asset Retirement Obligations AROs are computed as the fair value of the estimated ultimate costs for an asset’s future retirement and are recorded in the period in which the liability is incurred. The costs are capitalized as part of the related long-lived asset and depreciated over the asset’s useful life. In the absence of quoted market prices, AROs are estimated using present value techniques in which estimates of future cash outlays associated with the asset retirements are discounted using a credit-adjusted risk-free rate. Estimates of the timing and amounts of future cash outlays are based on projections of when and how the assets will be retired and the cost of future removal activities. The liability for AROs primarily relates to facilities that are subject to the CCR Rule, principally ash ponds, and the decommissioning of the Southern Company system’s nuclear facilities – Alabama Power’s Plant Farley and Georgia Power’s ownership interests in Plant Hatch and Plant Vogtle Units 1 and 2. In addition, the Southern Company system has retirement obligations related to various landfill sites, asbestos removal, mine reclamation, land restoration related to solar and wind facilities, and disposal of polychlorinated biphenyls in certain transformers. The Southern Company system also has identified retirement obligations related to certain electric transmission and distribution facilities, certain wireless communication towers, property associated with the Southern Company system’s rail lines and natural gas pipelines, and certain structures authorized by the U.S. Army Corps of Engineers. However, liabilities for the removal of these assets have not been recorded as the fair value of the retirement obligations cannot be reasonably estimated. A liability for these AROs will be recognized when sufficient information becomes available to support a reasonable estimation of the ARO. The cost estimates for AROs related to the disposal of CCR are based on information using various assumptions related to closure and post-closure costs, timing of future cash outlays, inflation and discount rates, and the potential methods for complying with the CCR Rule requirements for closure. As further analysis is performed, including evaluation of the expected method of compliance, refinement of assumptions underlying the cost estimates, such as the quantities of CCR at each site, and the determination of timing with respect to compliance activities, including the potential for closing ash ponds prior to the end of their currently anticipated useful life, the traditional electric operating companies expect to continue to periodically update these estimates. See FUTURE EARNINGS POTENTIAL – “Environmental Matters – Environmental Statutes and Regulations – Coal Combustion Residuals” herein for additional information. Given the significant judgment involved in estimating AROs, Southern Company considers the liabilities for AROs to be critical accounting estimates. See Note 1 to the financial statements under “Asset Retirement Obligations and Other Costs of Removal” and “Nuclear Decommissioning” for additional information. Pension and Other Postretirement Benefits Southern Company’s calculation of pension and other postretirement benefits expense is dependent on a number of assumptions. These assumptions include discount rates, healthcare cost trend rates, expected long-term return on plan assets, mortality rates, expected salary and wage increases, and other factors. Components of pension and other postretirement benefits expense include interest and service cost on the pension and other postretirement benefit plans, expected return on plan assets, and amortization of certain unrecognized costs and obligations. Actual results that differ from the assumptions utilized are accumulated and amortized over future periods and, therefore, generally affect recognized expense and the recorded obligation in future periods. While the Company believes that the assumptions used are appropriate, differences in actual experience or significant changes in assumptions would affect its pension and other postretirement benefits costs and obligations. Key elements in determining Southern Company’s pension and other postretirement benefit expense are the expected long- term return on plan assets and the discount rate used to measure the benefit plan obligations and the periodic benefit plan expense for future periods. The expected long-term return on pension and other postretirement benefit plan assets is based Southern Company 2016 Annual Report Management’s Discussion and Analysis of Financial Condition and Results of Operations 37 on Southern Company’s investment strategy, historical experience, and expectations for long-term rates of return that consider external actuarial advice. Southern Company determines the long-term return on plan assets by applying the long-term rate of expected returns on various asset classes to Southern Company’s target asset allocation. For purposes of determining its liability related to the pension and other postretirement benefit plans, Southern Company discounts the future related cash flows using a single-point discount rate for each plan developed from the weighted average of market-observed yields for high quality fixed income securities with maturities that correspond to expected benefit payments. For 2015 and prior years, Southern Company computed the interest cost component of its net periodic pension and other postretirement benefit plan expense using the same single-point discount rate. For 2016, Southern Company adopted a full yield curve approach for calculating the interest cost component whereby the discount rate for each year is applied to the liability for that specific year. As a result, the interest cost component of net periodic pension and other postretirement benefit plan expense decreased by approximately $96 million in 2016. The following table illustrates the sensitivity to changes in Southern Company’s long-term assumptions with respect to the assumed discount rate, the assumed salaries, and the assumed long-term rate of return on plan assets: Change in Assumption 25 basis point change in discount rate 25 basis point change in salaries 25 basis point change in long-term return on plan assets N/A – Not applicable Increase/ (Decrease) in Total Benefit Expense for 2017 $34/$(39) $20/$(19) $31/$(31) Increase/ (Decrease) in Projected Obligation for Pension Plan at December 31, 2016 (in millions) $418/$(396) $97/$(94) N/A Increase/(Decrease) in Projected Obligation for Other Postretirement Benefit Plans at December 31, 2016 $64/$(61) $–/$– N/A See Note 2 to the financial statements for additional information regarding pension and other postretirement benefits. Goodwill and Other Intangible Assets The acquisition method of accounting requires the assets acquired and liabilities assumed to be recorded at the date of acquisition at their respective estimated fair values. Southern Company recognizes goodwill as of the acquisition date, as a residual over the fair values of the identifiable net assets acquired. Goodwill is tested for impairment on an annual basis in the fourth quarter of the year as well as on an interim basis as events and changes in circumstances occur. Primarily as a result of the acquisitions of Southern Company Gas and PowerSecure in 2016, goodwill totaled approximately $6.3 billion at December 31, 2016. Definite-lived intangible assets acquired are amortized over the estimated useful lives of the respective assets to reflect the pattern in which the economic benefits of the intangible assets are consumed. Whenever events or changes in circumstances indicate that the carrying amount of the intangible assets may not be recoverable, the intangible assets will be reviewed for impairment. Primarily as a result of the acquisitions of Southern Company Gas and PowerSecure and PPA fair value adjustments resulting from Southern Power’s acquisitions, other intangible assets, net of amortization totaled approximately $1.0 billion at December 31, 2016. The judgments made in determining the estimated fair value assigned to each class of assets acquired and liabilities assumed, as well as asset lives, can significantly impact Southern Company’s results of operations. Fair values and useful lives are determined based on, among other factors, the expected future period of benefit of the asset, the various characteristics of the asset, and projected cash flows. As the determination of an asset’s fair value and useful life involves management making certain estimates and because these estimates form the basis for the determination of whether or not an impairment charge should be recorded, Southern Company considers these estimates to be critical accounting estimates. See Note 1 to the financial statements under “Goodwill and Other Intangible Assets and Liabilities” for additional information regarding Southern Company’s goodwill and other intangible assets and Note 12 to the financial statements for additional information related to Southern Company’s recent acquisitions. Derivatives and Hedging Activities Derivative instruments are recorded on the balance sheets as either assets or liabilities measured at their fair value, unless the transactions qualify for the normal purchases or normal sales scope exception and are instead subject to traditional accrual accounting. For those transactions that do not qualify as a normal purchase or normal sale, changes in the derivatives’ fair values are recognized concurrently in earnings unless specific hedge accounting criteria are met. If the derivatives meet those criteria, derivative gains and losses offset related results of the hedged item in the income statement in the case of a fair value hedge, or gains and losses are deferred in OCI until the hedged transaction affects earnings in the case of a cash flow hedge. Certain subsidiaries of Southern Company enter into energy-related derivatives that are designated as regulatory hedges where gains and losses are initially recorded as regulatory liabilities and assets and then are included in fuel expense as the underlying fuel is used in operations and ultimately recovered through billings to customers. investor.southerncompany.com 38 Management’s Discussion and Analysis of Financial Condition and Results of Operations Southern Company uses derivative instruments to reduce the impact to the results of operations due to the risk of changes in the price of natural gas, to manage fuel hedging programs per guidelines of state regulatory agencies, and to mitigate residual changes in the price of electricity, weather, interest rates, and foreign currency exchange rates. The fair value of commodity derivative instruments used to manage exposure to changing prices reflects the estimated amounts that Southern Company would receive or pay to terminate or close the contracts at the reporting date. To determine the fair value of the derivative instruments, Southern Company utilizes market data or assumptions that market participants would use in pricing the derivative asset or liability, including assumptions about risk and the risks inherent in the inputs of the valuation technique. Southern Company classifies derivative assets and liabilities based on the lowest level of input that is significant to the fair value measurement. The assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy. The determination of the fair value of the derivative instruments incorporates various required factors. These factors include: • • • the creditworthiness of the counterparties involved and the impact of credit enhancements (such as cash deposits and letters of credit); events specific to a given counterparty; and the impact of Southern Company’s nonperformance risk on its liabilities. Given the assumptions used in pricing the derivative asset or liability, Southern Company considers the valuation of derivative assets and liabilities a critical accounting estimate. See FINANCIAL CONDITION AND LIQUIDITY – “Market Price Risk” herein for more information. Contingent Obligations Southern Company is subject to a number of federal and state laws and regulations as well as other factors and conditions that subject it to environmental, litigation, income tax, and other risks. See FUTURE EARNINGS POTENTIAL herein and Note 3 to the financial statements for more information regarding certain of these contingencies. Southern Company periodically evaluates its exposure to such risks and records reserves for those matters where a non-tax-related loss is considered probable and reasonably estimable and records a tax asset or liability if it is more likely than not that a tax position will be sustained. The adequacy of reserves can be significantly affected by external events or conditions that can be unpredictable; thus, the ultimate outcome of such matters could materially affect Southern Company’s results of operations, cash flows, or financial condition. Recently Issued Accounting Standards In 2014, the FASB issued ASC 606, Revenue from Contracts with Customers, replacing the existing accounting standard and industry specific guidance for revenue recognition with a five-step model for recognizing and measuring revenue from contracts with customers. The underlying principle of the guidance is to recognize revenue to depict the transfer of goods or services to customers at the amount expected to be collected. The new standard also requires enhanced disclosures regarding the nature, amount, timing, and uncertainty of revenue and the related cash flows arising from contracts with customers. While Southern Company expects most of its revenue to be included in the scope of ASC 606, it has not fully completed its evaluation of such arrangements. The majority of Southern Company’s revenue, including energy provided to customers, is from tariff offerings that provide natural gas or electricity without a defined contractual term. For such arrangements, Southern Company generally expects that the revenue from contracts with these customers will continue to be equivalent to the electricity or natural gas supplied and billed in that period (including unbilled revenues) and the adoption of ASC 606 will not result in a significant shift in the timing of revenue recognition for such sales. Southern Company’s ongoing evaluation of other revenue streams and related contracts includes longer term contractual commitments and unregulated sales to customers. Some revenue arrangements, such as certain PPAs and alternative revenue programs, are expected to be excluded from the scope of ASC 606 and therefore, be accounted for and presented separately from revenues under ASC 606 on Southern Company’s financial statements. In addition, the power and utilities industry is currently addressing other specific industry issues, including the applicability of ASC 606 to CIAC. If final implementation guidance indicates CIAC will be accounted for under ASC 606 and offsetting regulatory treatment is not permitted, it could have a material impact on Southern Company’s financial statements. The new standard is effective for interim and annual reporting periods beginning after December 15, 2017. Southern Company must select a transition method to be applied either retrospectively to each prior reporting period presented or retrospectively with a cumulative effect adjustment to retained earnings at the date of initial adoption. As the ultimate impact of the new standard has not yet been determined, Southern Company has not elected its transition method. On February 25, 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842) (ASU 2016-02). ASU 2016-02 requires lessees to recognize on the balance sheet a lease liability and a right-of-use asset for all leases. ASU 2016-02 also changes the recognition, measurement, and presentation of expense associated with leases and provides clarification regarding the identification of certain components of contracts that would represent a lease. The accounting required by lessors is relatively unchanged and there is no change to the accounting for existing leveraged leases. ASU 2016-02 is effective for fiscal years beginning after Southern Company 2016 Annual Report Management’s Discussion and Analysis of Financial Condition and Results of Operations 39 December 15, 2018, with early adoption permitted. Southern Company is currently evaluating the new standard and has not yet determined its ultimate impact; however, adoption of ASU 2016-02 is expected to have a significant impact on Southern Company’s balance sheet. On March 30, 2016, the FASB issued ASU No. 2016-09, Compensation-Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting (ASU 2016-09). ASU 2016-09 changes the accounting for income taxes and the cash flow presentation for share-based payment award transactions effective for fiscal years beginning after December 15, 2016. The new guidance requires all excess tax benefits and deficiencies related to the exercise or vesting of stock compensation to be recognized as income tax expense or benefit in the income statement. Previously, Southern Company recognized any excess tax benefits and deficiencies related to the exercise and vesting of stock compensation as additional paid-in capital. In addition, the new guidance requires excess tax benefits for share-based payments to be included in net cash provided from operating activities rather than net cash provided from financing activities on the statement of cash flows. Southern Company elected to adopt the guidance in 2016 and reflect the related adjustments as of January 1, 2016. Prior year’s data presented in the financial statements has not been adjusted. Southern Company also elected to recognize forfeitures as they occur. The new guidance did not have a material impact on the results of operations, financial position, or cash flows of Southern Company. See Notes 5, 8, and 14 to the financial statements for disclosures impacted by ASU 2016-09. On October 24, 2016, the FASB issued ASU No. 2016-16, Income Taxes (Topic 740), Intra-Entity Transfers of Assets Other Than Inventory (ASU 2016-16). Current GAAP prohibits the recognition of current and deferred income taxes for an affiliate asset transfer until the asset has been sold to an outside party. ASU 2016-16 requires an entity to recognize the income tax consequences of an affiliate transfer of an asset other than inventory when the transfer occurs. ASU 2016-16 is effective for annual reporting periods beginning after December 15, 2017 and interim periods within those annual periods. The amendments will be applied on a modified retrospective basis through a cumulative-effect adjustment directly to retained earnings as of the beginning of the period of adoption. Southern Company is currently assessing the impact of the standard on its financial statements and has not yet determined its ultimate impact. On November 17, 2016, the FASB issued ASU No. 2016-18, Statement of Cash Flows (Topic 230): Restricted Cash (ASU 2016-18). ASU 2016-18 eliminates the need to reflect transfers between cash and restricted cash in operating, investing, and financing activities in the statement of cash flows. Upon adoption, the net change in cash and cash equivalents during the period will include amounts generally described as restricted cash or restricted cash equivalents. ASU 2016-18 is effective for fiscal years beginning after December 15, 2017, with early adoption permitted, and will be applied retrospectively to each period presented. Southern Company does not intend to adopt the guidance early. The adoption of ASU 2016-18 will not have a material impact on the financial statements of Southern Company. FINANCIAL CONDITION AND LIQUIDITY Overview Earnings in all periods presented were negatively affected by revisions to the cost estimate for the Kemper IGCC; however, Southern Company’s financial condition remained stable at December 31, 2016. The Southern Company system’s cash requirements primarily consist of funding ongoing operations, common stock dividends, capital expenditures, and debt maturities. The Southern Company system’s capital expenditures and other investing activities include investments to meet projected long-term demand requirements, including to build new electric generation facilities, to maintain existing electric generation facilities, to comply with environmental regulations including adding environmental modifications to certain existing electric generating units, to expand and improve electric transmission and distribution facilities, to update and expand natural gas distribution systems, and for restoration following major storms. Operating cash flows provide a substantial portion of the Southern Company system’s cash needs. For the three-year period from 2017 through 2019, Southern Company’s projected common stock dividends, capital expenditures, and debt maturities are expected to exceed operating cash flows. Southern Company plans to finance future cash needs in excess of its operating cash flows primarily by accessing borrowings from financial institutions and through debt and equity issuances in the capital markets. Southern Company intends to continue to monitor its access to short-term and long-term capital markets as well as bank credit arrangements to meet future capital and liquidity needs. See FUTURE EARNINGS POTENTIAL – “Income Tax Matters – Bonus Depreciation” and “Sources of Capital,” “Financing Activities,” and “Capital Requirements and Contractual Obligations” herein for additional information. Southern Company’s investments in the qualified pension plans and the nuclear decommissioning trust funds increased in value as of December 31, 2016 as compared to December 31, 2015. On December 19, 2016, the traditional electric operating companies and certain other subsidiaries voluntarily contributed an aggregate of $900 million to Southern Company’s qualified pension plan. In addition, on September 12, 2016, Southern Company Gas voluntary contributed $125 million to its qualified pension plan. No mandatory contributions to the qualified pension plans are anticipated during 2017. See “Contractual Obligations” herein and Notes 1 and 2 to the financial statements under “Nuclear Decommissioning” and “Pension Plans,” respectively, for additional information. investor.southerncompany.com 40 Management’s Discussion and Analysis of Financial Condition and Results of Operations Net cash provided from operating activities in 2016 totaled $4.9 billion, a decrease of $1.4 billion from 2015. The decrease in net cash provided from operating activities was primarily due to voluntary contributions to the qualified pension plan of approximately $1.0 billion and a $1.2 billion increase in unutilized ITCs and PTCs. Net cash provided from operating activities in 2015 totaled $6.3 billion, an increase of $459 million from 2014. Significant changes in operating cash flow for 2015 as compared to 2014 included an increase in fuel cost recovery, partially offset by the timing of vendor payments. Net cash used for investing activities in 2016, 2015, and 2014 totaled $20.0 billion, $7.3 billion, and $6.4 billion, respectively. The cash used for investing activities in 2016 was primarily due to the closing of the Merger, the acquisition of PowerSecure, Southern Company Gas’ investment in SNG, the construction of electric generation, transmission, and distribution facilities, the installation of equipment at electric generating facilities to comply with environmental standards, and Southern Power’s acquisitions and construction of renewable facilities and a natural gas facility. The cash used for investing activities in 2015 and 2014 was primarily due to gross property additions for installation of equipment at electric generating facilities to comply with environmental standards, construction of electric generation, transmission, and distribution facilities, Southern Power’s acquisitions of solar facilities, and purchases of nuclear fuel. Net cash provided from financing activities totaled $15.7 billion in 2016 primarily due to issuances of long-term debt and common stock associated with completing the Merger and funding the subsidiaries’ continuous construction programs, Southern Power’s acquisitions, and Southern Company Gas’ investment in SNG, partially offset by redemptions of long-term debt and common stock dividend payments. Net cash provided from financing activities totaled $1.7 billion in 2015 due to issuances of long-term debt and common stock and an increase in short-term debt, partially offset by common stock dividend payments and redemptions of long-term debt and preferred and preference stock. Net cash provided from financing activities totaled $644 million in 2014 due to issuances of long-term debt and common stock, partially offset by common stock dividend payments, redemptions of long-term debt, and a reduction in short-term debt. Fluctuations in cash flow from financing activities vary from year to year based on capital needs and the maturity or redemption of securities. Significant balance sheet changes in 2016 included an increase of $17.3 billion in total property, plant, and equipment primarily related to the inclusion of Southern Company Gas as a result of the Merger, installation of equipment at electric generating facilities to comply with environmental standards, construction of electric generation, transmission, and distribution facilities, and Southern Power’s acquisitions; an increase of $6.2 billion in goodwill related to the acquisitions of Southern Company Gas and PowerSecure; an increase of $1.5 billion in equity investments in unconsolidated subsidiaries primarily related to Southern Company Gas’ investment in SNG; an increase of $1.9 billion in other regulatory assets, deferred primarily related to the inclusion of Southern Company Gas as a result of the Merger and changes in ash pond closure strategy, principally for Georgia Power; increases of $17.9 billion in long-term debt and $4.6 billion in total stockholder’s equity primarily associated with financing and completing the Merger and to fund the subsidiaries’ continuous construction programs and Southern Power’s acquisitions; and increases of $1.8 billion in accumulated deferred income taxes and $1.6 billion in other cost of removal obligations primarily related to the inclusion of Southern Company Gas as a result of the Merger. See Notes 1 and 12 to the financial statements for additional information regarding AROs and the Merger, respectively. At the end of 2016, the market price of Southern Company’s common stock was $49.19 per share (based on the closing price as reported on the New York Stock Exchange) and the book value was $25.00 per share, representing a market-to-book value ratio of 197%, compared to $46.79, $22.59, and 207%, respectively, at the end of 2015. Southern Company’s consolidated ratio of common equity to total capitalization plus short-term debt was 33.3% and 40.5% at December 31, 2016 and 2015, respectively. See Note 6 to the financial statements for additional information. Sources of Capital Southern Company intends to meet its future capital needs through operating cash flows, short-term debt, term loans, and external security issuances. Equity capital can be provided from any combination of the Company’s stock plans, private placements, or public offerings. The amount and timing of additional equity capital and debt issuances in 2017, as well as in subsequent years, will be contingent on Southern Company’s investment opportunities and the Southern Company system’s capital requirements and will depend upon prevailing market conditions and other factors. See “Capital Requirements and Contractual Obligations” herein for additional information. Except as described herein, the traditional electric operating companies, Southern Power, and Southern Company Gas plan to obtain the funds required for construction and other purposes from operating cash flows, external security issuances, term loans, short-term borrowings, and equity contributions or loans from Southern Company. However, the amount, type, and timing of any future financings, if needed, will depend upon prevailing market conditions, regulatory approval, and other factors. In addition, Georgia Power may make borrowings through a loan guarantee agreement (Loan Guarantee Agreement) between Georgia Power and the DOE, the proceeds of which may be used to reimburse Georgia Power for a portion of certain costs of construction relating to Plant Vogtle Units 3 and 4 that are eligible for financing under the Loan Guarantee Agreement (Eligible Project Costs). Under the Loan Guarantee Agreement, the DOE agreed to guarantee borrowings of up to $3.46 billion (not to exceed 70% of Eligible Project Costs) to be made by Georgia Power under a multi-advance credit facility (FFB Credit Facility) among Georgia Power, the DOE, and the FFB. Eligible Project Costs incurred through December 31, 2016 would allow Southern Company 2016 Annual Report Management’s Discussion and Analysis of Financial Condition and Results of Operations 41 for borrowings of up to $2.7 billion under the FFB Credit Facility, of which Georgia Power has borrowed $2.6 billion. See Note 6 to the financial statements under “DOE Loan Guarantee Borrowings” for additional information regarding the Loan Guarantee Agreement and Note 3 to the financial statements under “Regulatory Matters – Georgia Power – Nuclear Construction” for additional information regarding Plant Vogtle Units 3 and 4. Mississippi Power received $245 million of Initial DOE Grants in prior years that were used for the construction of the Kemper IGCC. An additional $25 million of grants from the DOE is expected to be received for commercial operation of the Kemper IGCC. On April 8, 2016, Mississippi Power received approximately $137 million in Additional DOE Grants for the Kemper IGCC, which are expected to be used to reduce future rate impacts for customers. See Note 3 to the financial statements under “Integrated Coal Gasification Combined Cycle” for information regarding legislation related to the securitization of certain costs of the Kemper IGCC. The issuance of securities by the traditional electric operating companies and Nicor Gas is generally subject to the approval of the applicable state PSC or other applicable state regulatory agency. The issuance of all securities by Mississippi Power and short-term securities by Georgia Power is generally subject to regulatory approval by the FERC. Additionally, with respect to the public offering of securities, Southern Company and certain of its subsidiaries file registration statements with the SEC under the Securities Act of 1933, as amended (1933 Act). The amounts of securities authorized by the appropriate regulatory authorities, as well as the securities registered under the 1933 Act, are continuously monitored and appropriate filings are made to ensure flexibility in the capital markets. Southern Company, each traditional electric operating company, and Southern Power generally obtain financing separately without credit support from any affiliate. In addition, Southern Company Gas Capital obtains external financing for Southern Company Gas and its subsidiaries, other than Nicor Gas, which obtains financing separately without credit support from any affiliates. See Note 6 to the financial statements under “Bank Credit Arrangements” for additional information. The Southern Company system does not maintain a centralized cash or money pool. Therefore, funds of each company are not commingled with funds of any other company in the Southern Company system. As of December 31, 2016, Southern Company’s current liabilities exceeded current assets by $3.2 billion, primarily due to $2.6 billion of long-term debt that is due within one year, including approximately $0.8 billion at the parent company, $0.6 billion at Alabama Power, $0.5 billion at Georgia Power, $0.1 billion at Gulf Power, and $0.6 billion at Southern Power. To meet short-term cash needs and contingencies, the Southern Company system has substantial cash flow from operating activities and access to capital markets and financial institutions. Southern Company, the traditional electric operating companies, Southern Power, and Southern Company Gas intend to utilize operating cash flows, as well as commercial paper, lines of credit, bank notes, and securities issuances, as market conditions permit, as well as, under certain circumstances for the traditional electric operating companies, Southern Power, and Southern Company Gas, equity contributions and/or loans from Southern Company to meet their short-term capital needs. In addition, Georgia Power expects to utilize borrowings through the FFB Credit Facility as an additional source of long-term borrowed funds. At December 31, 2016, Southern Company and its subsidiaries had approximately $2.0 billion of cash and cash equivalents. Committed credit arrangements with banks at December 31, 2016 were as follows: Executable Term Loans Expires Within One Year One Year Two Years (in millions) Term Out (in millions) No Term Out Company Expires 2017 2018 2020 (in millions) Total Unused (in millions) 2,250 $ 1,335 1,750 280 173 600 2,000 55 8,443 $ $ — $ Southern Company(a) 35 Alabama Power — Georgia Power 85 Gulf Power 173 Mississippi Power Southern Power Company(b) — Southern Company Gas(c) 75 55 Other 423 $ Southern Company Consolidated (a) Represents the Southern Company parent entity. (b) Excludes credit agreements (Project Credit Facilities) assumed with the acquisition of certain solar facilities, which were non-recourse to 2,250 $ — — 1,335 — 1,732 45 280 — 150 — 522 — 1,949 20 55 65 8,273 $ 1,250 $ 800 1,750 — — 600 — — 4,400 $ 1,000 $ 500 — 195 — — 1,925 — 3,620 $ — — 25 13 — — 20 58 $ — — — 13 — — — 13 $ $ — $ — $ $ $ — 35 — 60 160 — 75 35 365 Southern Power Company, the proceeds of which were used to finance project costs related to such solar facilities. See Note 12 to the financial statements under “Southern Power” for additional information. Also excludes a $120 million continuing letter of credit facility entered into by Southern Power in December 2016 for standby letters of credit expiring in 2019. At December 31, 2016, the total amount available under the letter of credit facility was $82 million. (c) Southern Company Gas, as the parent entity, guarantees the obligations of Southern Company Gas Capital, which is the borrower of $1.3 billion of these arrangements. Southern Company Gas’ committed credit arrangements also include $700 million for which Nicor Gas is the borrower and which is restricted for working capital needs of Nicor Gas. See Note 6 to the financial statements under “Bank Credit Arrangements” for additional information. investor.southerncompany.com 42 Management’s Discussion and Analysis of Financial Condition and Results of Operations Most of these bank credit arrangements, as well as the term loan arrangements of Southern Company, Alabama Power, Gulf Power, Mississippi Power, and Southern Power Company, contain covenants that limit debt levels and contain cross acceleration or cross default provisions to other indebtedness (including guarantee obligations) that are restricted only to the indebtedness of the individual company. Such cross default provisions to other indebtedness would trigger an event of default if the applicable borrower defaulted on indebtedness or guarantee obligations over a specified threshold. Such cross acceleration provisions to other indebtedness would trigger an event of default if the applicable borrower defaulted on indebtedness, the payment of which was then accelerated. At December 31, 2016, Southern Company, the traditional electric operating companies, Southern Power Company, Southern Company Gas, and Nicor Gas were in compliance with all such covenants. None of the bank credit arrangements contain material adverse change clauses at the time of borrowings. Subject to applicable market conditions, Southern Company and its subsidiaries expect to renew or replace their bank credit arrangements as needed, prior to expiration. In connection therewith, Southern Company and its subsidiaries may extend the maturity dates and/or increase or decrease the lending commitments thereunder. A portion of the unused credit with banks is allocated to provide liquidity support to the pollution control revenue bonds of the traditional electric operating companies and the commercial paper programs of Southern Company, the traditional electric operating companies, Southern Power Company, Southern Company Gas, and Nicor Gas. The amount of variable rate pollution control revenue bonds of the traditional electric operating companies outstanding requiring liquidity support as of December 31, 2016 was approximately $1.9 billion. In addition, at December 31, 2016, the traditional electric operating companies had approximately $423 million of fixed rate pollution control revenue bonds outstanding that were required to be remarketed within the next 12 months. Southern Company, the traditional electric operating companies, Southern Power Company, Southern Company Gas, and Nicor Gas make short-term borrowings primarily through commercial paper programs that have the liquidity support of the committed bank credit arrangements described above. Short-term borrowings are included in notes payable in the balance sheets. Details of short-term borrowings were as follows: Short-term Debt at the End of the Period Amount Outstanding (in millions) Weighted Average Interest Rate Short-term Debt During the Period(*) Weighted Average Interest Rate Average Amount Outstanding (in millions) Maximum Amount Outstanding (in millions) $ $ $ 1,970 500 1,563 795 1,582 400 December 31, 2016: Commercial paper Short-term bank debt Total December 31, 2015: Commercial paper Short-term bank debt Total December 31, 2014: Commercial paper Short-term bank debt $ $ $ $ $ 1,909 123 2,032 740 500 1,240 803 — 803 1.1% $ 1.7% 1.1% $ $ $ $ 0.7% 1.4% 0.9% 0.3% —% 0.3% 976 176 1,152 842 444 1,286 0.8% 1.7% 1.1% 0.4% 1.1% 0.5% 754 98 852 0.2% 0.8% 0.3% Total (*) Average and maximum amounts are based upon daily balances during the twelve-month periods ended December 31, 2016, 2015, and 2014. $ $ In addition to the short-term borrowings in the table above, Southern Power’s subsidiary Project Credit Facilities had total amounts outstanding as of December 31, 2016 of $209 million at a weighted average interest rate of 2.1%. For the year ended December 31, 2016, the Project Credit Facilities had a maximum amount outstanding of $828 million and an average amount outstanding of $566 million at a weighted average interest rate of 2.1%. The amounts outstanding as of December 31, 2016 under the Project Credit Facilities were fully repaid subsequent to December 31, 2016. Furthermore, in connection with the acquisition of a solar facility on July 1, 2016, a subsidiary of Southern Power assumed a $217 million construction loan, which was fully repaid in September 2016. During this period, the credit agreement had a maximum amount outstanding of $217 million and an average amount outstanding of $137 million at a weighted average interest rate of 2.2%. The Company believes the need for working capital can be adequately met by utilizing commercial paper programs, lines of credit, bank term loans, and operating cash flows. Southern Company 2016 Annual Report Management’s Discussion and Analysis of Financial Condition and Results of Operations 43 Financing Activities In May and August 2016, Southern Company issued an aggregate of 50.8 million shares of common stock in underwritten offerings for an aggregate purchase price of approximately $2.5 billion. Of the 50.8 million shares, approximately 2.6 million were issued from treasury and the remainder were newly issued shares. The proceeds were used to fund a portion of the consideration for the Merger and related transaction costs, to fund a portion of the purchase price for the SNG investment and related transaction costs, and for other general corporate purposes. During the fourth quarter 2016, Southern Company issued approximately 8.0 million shares of common stock through at-the- market issuances pursuant to sales agency agreements related to Southern Company’s continuous equity offering program and received cash proceeds of approximately $381 million, net of $3 million in fees and commissions. In addition, during 2016, Southern Company issued approximately 20 million shares of common stock primarily through employee equity compensation plans and received proceeds of approximately $874 million. The following table outlines the long-term debt financing activities for Southern Company and its subsidiaries for the year ended December 31, 2016: Company Senior Note Issuances Senior Note Maturities and Redemptions Revenue Bond Maturities, Redemptions, and Repurchases (in millions) Other Long-Term Debt Issuances Other Long-Term Debt Redemptions and Maturities(a) $ $ $ Southern Company(b) Alabama Power Georgia Power Gulf Power Mississippi Power Southern Power Southern Company Gas(c) Other $ — — 4 — — — — — — 4 Southern Company Consolidated (a) Includes reductions in capital lease obligations resulting from cash payments under capital leases. (b) Represents the Southern Company parent entity. (c) Reflects only long-term debt financing activities occurring subsequent to completion of the Merger. The senior notes were issued by Southern 1,350 45 425 2 1,400 65 — 79 (279) 3,087 8,500 400 650 — — 2,831 900 — — 13,281 — — 10 — 653 86 — 65 (228) 586 500 200 700 235 300 200 420 — — 2,555 Elimination(d) $ $ $ $ $ $ Company Gas Capital and guaranteed by Southern Company Gas, as the parent entity. (d) Includes intercompany loans from Southern Company to Mississippi Power and PowerSecure, as well as reductions in affiliate capital lease obligations at Georgia Power. These transactions are eliminated in Southern Company’s Consolidated Financial Statements. In February 2016, Southern Company entered into $700 million notional amount of forward-starting interest rate swaps to hedge exposure to interest rate changes related to anticipated debt issuances. These interest rate swaps were settled in May 2016. In May 2016, Southern Company issued the following series of senior notes for an aggregate principal amount of $8.5 billion: • • • • • • • $0.5 billion of 1.55% Senior Notes due July 1, 2018; $1.0 billion of 1.85% Senior Notes due July 1, 2019; $1.5 billion of 2.35% Senior Notes due July 1, 2021; $1.25 billion of 2.95% Senior Notes due July 1, 2023; $1.75 billion of 3.25% Senior Notes due July 1, 2026; $0.5 billion of 4.25% Senior Notes due July 1, 2036; and $2.0 billion of 4.40% Senior Notes due July 1, 2046. The net proceeds were used to fund a portion of the consideration for the Merger and related transaction costs and for other general corporate purposes. In September 2016, Southern Company issued $800 million aggregate principal amount of Series 2016A 5.25% Junior Subordinated Notes due October 1, 2076. The proceeds were used to repay short-term indebtedness that was incurred to repay at maturity $500 million aggregate principal amount of Southern Company’s Series 2011A 1.95% Senior Notes due September 1, 2016 and for other general corporate purposes. investor.southerncompany.com 44 Management’s Discussion and Analysis of Financial Condition and Results of Operations In December 2016, Southern Company issued $550 million aggregate principal amount of Series 2016B Junior Subordinated Notes due March 15, 2057, which bear interest at a fixed rate of 5.50% per year up to, but not including, March 15, 2022. From, and including, March 15, 2022, the Series 2016B Junior Subordinated Notes will bear interest at a floating rate based on three-month LIBOR. The proceeds were used for general corporate purposes. Except as described herein, Southern Company’s subsidiaries used the proceeds of the debt issuances shown in the table above for their redemptions and maturities shown in the table above, to repay short-term indebtedness, and for general corporate purposes, including their continuous construction programs and, for Southern Power, its growth strategy. In addition, certain of Georgia Power’s and Southern Power’s issuances were allocated to eligible renewable energy expenditures. Georgia Power’s “Other Long-Term Debt Issuances” reflected in the table above include borrowings in June and December 2016 under the FFB Credit Facility in an aggregate principal amount of $300 million and $125 million, respectively. The interest rate applicable to the $300 million principal amount is 2.571% and the interest rate applicable to the $125 million principal amount is 3.142%, both for interest periods that extend to the final maturity date of February 20, 2044. The proceeds were used to reimburse Georgia Power for Eligible Project Costs relating to the construction of Plant Vogtle Units 3 and 4. In June 2016, Southern Power Company issued €600 million aggregate principal amount of Series 2016A 1.00% Senior Notes due June 20, 2022 and €500 million aggregate principal amount of Series 2016B 1.85% Senior Notes due June 20, 2026. The net proceeds are being allocated to renewable energy generation projects. Southern Power Company’s obligations under its euro- denominated fixed-rate notes were effectively converted to fixed-rate U.S. dollars at issuance through cross-currency swaps, mitigating foreign currency exchange risk associated with the interest and principal payments. See Note 11 to the financial statements under “Foreign Currency Derivatives” for additional information. In September 2016, Southern Company Gas Capital issued $350 million aggregate principal amount of 2.45% Senior Notes due October 1, 2023 and $550 million aggregate principal amount of 3.95% Senior Notes due October 1, 2046, both of which are guaranteed by Southern Company Gas. The proceeds were primarily used to repay a $360 million promissory note issued to Southern Company for the purpose of funding a portion of the purchase price for a 50% equity interest in SNG, to fund the purchase of Piedmont Natural Gas Company, Inc.’s interest in SouthStar Energy Services, LLC, to make a voluntary contribution to Southern Company Gas’ pension plan, and for general corporate purposes. See Note 12 to the financial statements under “Southern Company – Investment in Southern Natural Gas” and “ – Acquisition of Remaining Interest in SouthStar” for additional information. Subsequent to December 31, 2016, Alabama Power repaid at maturity $200 million aggregate principal amount of its Series 2007A 5.55% Senior Notes due February 1, 2017. In March 2016, Alabama Power entered into three bank term loan agreements with maturity dates of March 2021, in an aggregate principal amount of $45 million, one of which bears interest at 2.38% per annum and two of which bear interest based on three-month LIBOR. In March 2016, Mississippi Power entered into an unsecured term loan agreement with a syndicate of financial institutions for an aggregate amount of $1.2 billion. Mississippi Power borrowed $900 million in March 2016 under the term loan agreement and the remaining $300 million in October 2016. Mississippi Power used the initial proceeds to repay $900 million in maturing bank loans in March 2016 and the remaining $300 million to repay at maturity Mississippi Power’s Series 2011A 2.35% Senior Notes due October 15, 2016. This loan matures on April 1, 2018 and bears interest based on one-month LIBOR. In May 2016, Gulf Power entered into an 11-month floating rate bank loan bearing interest based on one-month LIBOR. This short-term loan was for $100 million aggregate principal amount and the proceeds were used to repay existing indebtedness and for working capital and other general corporate purposes. In September 2016, Southern Power Company repaid $80 million of an outstanding $400 million floating rate bank loan and extended the maturity date of the remaining $320 million from September 2016 to September 2018. In addition, Southern Power Company entered into a $60 million aggregate principal amount floating rate bank loan bearing interest based on one-month LIBOR due September 2017. The proceeds were used to repay existing indebtedness and for other general corporate purposes. In addition to any financings that may be necessary to meet capital requirements and contractual obligations, Southern Company and its subsidiaries plan to continue, when economically feasible, a program to retire higher-cost securities and replace these obligations with lower-cost capital if market conditions permit. Credit Rating Risk At December 31, 2016, Southern Company and its subsidiaries did not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade. There are certain contracts that could require collateral, but not accelerated payment, in the event of a credit rating change of certain subsidiaries to BBB and/or Baa2 or below. These contracts are for physical electricity and natural gas purchases and sales, fuel purchases, fuel transportation and storage, energy price risk management, transmission, interest rate management, foreign currency risk management, and construction of new generation at Plant Vogtle Units 3 and 4. Southern Company 2016 Annual Report Management’s Discussion and Analysis of Financial Condition and Results of Operations 45 The maximum potential collateral requirements under these contracts at December 31, 2016 were as follows: Credit Ratings Maximum Potential Collateral Requirements (in millions) At BBB and/or Baa2 At BBB- and/or Baa3 At BB+ and/or Ba1(*) (*) Any additional credit rating downgrades at or below BB- and/or Ba3 could increase collateral requirements up to an additional $91 million. $ $ $ 39 691 2,723 Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. Additionally, a credit rating downgrade could impact the ability of Southern Company and its subsidiaries to access capital markets and would be likely to impact the cost at which they do so. On May 12, 2016, Fitch Ratings, Inc. (Fitch) downgraded the senior unsecured long-term debt rating of Southern Company to A- from A and revised the ratings outlook from negative to stable. Fitch also downgraded the senior unsecured long-term debt rating of Mississippi Power to BBB+ from A- and revised the ratings outlook from negative to stable. On May 13, 2016, Moody’s downgraded the senior unsecured long-term debt rating of Southern Company to Baa2 from Baa1 and revised the ratings outlook from negative to stable. On July 11, 2016, S&P raised Southern Company Gas’ and Nicor Gas’ corporate and senior unsecured long-term debt ratings from BBB+ to A- and revised their ratings outlooks from positive to negative. On January 10, 2017, S&P revised its consolidated credit rating outlook for Southern Company (including the traditional electric operating companies, Southern Power, and Southern Company Gas) from negative to stable. On February 6, 2017, Moody’s placed Mississippi Power on a ratings review for potential downgrade. Mississippi Power’s current rating for unsecured debt is Baa3. Market Price Risk The Southern Company system is exposed to market risks, including commodity price risk, interest rate risk, weather risk, and occasionally foreign currency exchange rate risk. To manage the volatility attributable to these exposures, the applicable company nets the exposures, where possible, to take advantage of natural offsets and enters into various derivative transactions for the remaining exposures pursuant to the applicable company’s policies in areas such as counterparty exposure and risk management practices. The Southern Company system’s policy is that derivatives are to be used primarily for hedging purposes and mandates strict adherence to all applicable risk management policies. Derivative positions are monitored using techniques including, but not limited to, market valuation, value at risk, stress testing, and sensitivity analysis. To mitigate future exposure to a change in interest rates, Southern Company and certain of its subsidiaries enter into derivatives that have been designated as hedges. Derivatives that have been designated as hedges outstanding at December 31, 2016 have a notional amount of $4.0 billion, of which $0.1 billion are to mitigate interest rate volatility related to projected debt financings in 2017. The remaining $3.9 billion are related to existing fixed and floating rate obligations. The weighted average interest rate on $6.4 billion of long-term variable interest rate exposure at January 1, 2017 was 1.68%. If Southern Company sustained a 100 basis point change in interest rates for all long-term variable interest rate exposure, the change would affect annualized interest expense by approximately $63 million at January 1, 2017. See Note 1 to the financial statements under “Financial Instruments” and Note 11 to the financial statements for additional information. Due to cost-based rate regulation and other various cost recovery mechanisms, the traditional electric operating companies and natural gas distribution utilities continue to have limited exposure to market volatility in interest rates, foreign currency exchange rates, commodity fuel prices, and prices of electricity. In addition, Southern Power’s exposure to market volatility in commodity fuel prices and prices of electricity is limited because its long-term sales contracts shift substantially all fuel cost responsibility to the purchaser. However, Southern Power has been and may continue to be exposed to market volatility in energy-related commodity prices as a result of uncontracted generating capacity. To mitigate residual risks relative to movements in electricity prices, the traditional electric operating companies and Southern Power may enter into physical fixed-price contracts for the purchase and sale of electricity through the wholesale electricity market and, to a lesser extent, financial hedge contracts for natural gas purchases; however, a significant portion of contracts are priced at market. The traditional electric operating companies and certain of the natural gas distribution utilities manage fuel-hedging programs implemented per the guidelines of their respective state PSCs or other applicable state regulatory agencies. Southern Company had no material change in market risk exposure for the year ended December 31, 2016 when compared to the year ended December 31, 2015. investor.southerncompany.com 46 Management’s Discussion and Analysis of Financial Condition and Results of Operations The changes in fair value of energy-related derivative contracts are substantially attributable to both the volume and the price of natural gas. For the years ended December 31, the changes in fair value of energy-related derivative contracts, the majority of which are composed of regulatory hedges, were as follows: 2016 Changes 2015 Changes Contracts outstanding at the beginning of the period, assets (liabilities), net Acquisitions Contracts realized or settled Current period changes(*) Contracts outstanding at the end of the period, assets (liabilities), net (*) Current period changes also include the changes in fair value of new contracts entered into during the period, if any. $ (213) (54) 141 171 45 $ (188) — 142 (167) (213) $ Fair Value (in millions) $ The net hedge volumes of energy-related derivative contracts were 500 million mmBtu and 224 million mmBtu for the years ended December 31, 2016 and 2015, respectively. For the traditional electric operating companies and Southern Power, the weighted average swap contract cost above or (below) market prices was approximately $(0.05) per mmBtu as of December 31, 2016 and $1.14 per mmBtu as of December 31, 2015. The majority of the natural gas hedge gains and losses are recovered through the traditional electric operating companies’ fuel cost recovery clauses. At December 31, 2016 and 2015, substantially all of the Southern Company system’s energy-related derivative contracts were designated as regulatory hedges and were related to the applicable company’s fuel-hedging program. Therefore, gains and losses are initially recorded as regulatory liabilities and assets, respectively, and then are included in fuel expense as they are recovered through the energy cost recovery clause. Certain other gains and losses on energy-related derivatives, designated as cash flow hedges, are initially deferred in OCI before being recognized in income in the same period as the hedged transaction. Gains and losses on energy-related derivative contracts that are not designated or fail to qualify as hedges are recognized in the statements of income as incurred and were not material for any year presented. The Southern Company system uses exchange-traded market-observable contracts, which are categorized as Level 1 of the fair value hierarchy, and over-the-counter contracts that are not exchange traded but are fair valued using prices which are market observable, and thus fall into Level 2 of the fair value hierarchy. See Note 10 to the financial statements for further discussion of fair value measurements. The maturities of the energy-related derivative contracts at December 31, 2016 were as follows: Level 1 Level 2 Level 3 Fair value of contracts outstanding at end of period Total Fair Value $ (7) 52 — $ 45 Fair Value Measurements December 31, 2016 Maturity Year 1 Years 2&3 Years 4&5 $ (in millions) 15 $ 52 — $ 67 $ (15) (7) — (22) $ (7) 7 — $ — The Southern Company system is exposed to market price risk in the event of nonperformance by counterparties to energy- related and interest rate derivative contracts. The Southern Company system only enters into agreements and material transactions with counterparties that have investment grade credit ratings by Moody’s and S&P, or with counterparties who have posted collateral to cover potential credit exposure. Therefore, the Southern Company system does not anticipate market risk exposure from nonperformance by the counterparties. For additional information, see Note 1 to the financial statements under “Financial Instruments” and Note 11 to the financial statements. Southern Company performs periodic reviews of its leveraged lease transactions, both domestic and international, and the creditworthiness of the lessees, including a review of the value of the underlying leased assets and the credit ratings of the lessees. Southern Company’s domestic lease transactions generally do not have any credit enhancement mechanisms; however, the lessees in its international lease transactions have pledged various deposits as additional security to secure the obligations. The lessees in the Company’s international lease transactions are also required to provide additional collateral in the event of a credit downgrade below a certain level. Southern Company 2016 Annual Report Management’s Discussion and Analysis of Financial Condition and Results of Operations 47 Capital Requirements and Contractual Obligations The Southern Company system’s construction program is currently estimated to total approximately $9.1 billion for 2017, $8.2 billion for 2018, $7.3 billion for 2019, $6.9 billion for 2020, and $6.4 billion for 2021. These amounts include expenditures of approximately $0.7 billion, $0.5 billion, $0.3 billion, and $0.1 billion for the construction of Plant Vogtle Units 3 and 4 in 2017, 2018, 2019, and 2020, respectively, $0.3 billion for the construction of the Kemper IGCC in 2017, and $1.5 billion per year for 2017 through 2021 for acquisitions and/or construction of new Southern Power generating facilities. These amounts also include capital expenditures related to contractual purchase commitments for nuclear fuel and capital expenditures covered under long-term service agreements. Estimated capital expenditures to comply with environmental statutes and regulations included in these amounts are $0.9 billion, $0.7 billion, $0.3 billion, $0.4 billion, and $0.6 billion for 2017, 2018, 2019, 2020, and 2021, respectively. These estimated expenditures do not include potential compliance costs that may arise from the EPA’s final rules and guidelines or future state plans that would limit CO2 emissions from existing, new, modified, or reconstructed fossil-fuel- fired electric generating units. See FUTURE EARNINGS POTENTIAL – “Environmental Matters – Environmental Statutes and Regulations” and “– Global Climate Issues” herein for additional information. The traditional electric operating companies also anticipate costs associated with closure and monitoring of ash ponds in accordance with the CCR Rule, which are reflected in the Company’s ARO liabilities. These costs, which could change as the Southern Company system continues to refine its assumptions underlying the cost estimates and evaluate the method and timing of compliance activities, are estimated to be approximately $0.4 billion, $0.3 billion, $0.3 billion, $0.4 billion, and $0.4 billion for 2017, 2018, 2019, 2020, and 2021, respectively. See Note 1 to the financial statements under “Asset Retirement Obligations and Other Costs of Removal” for additional information. The construction programs are subject to periodic review and revision, and actual construction costs may vary from these estimates because of numerous factors. These factors include: changes in business conditions; changes in load projections; changes in environmental statutes and regulations; the outcome of any legal challenges to the environmental rules; changes in electric generating plants, including unit retirements and replacements and adding or changing fuel sources at existing electric generating units, to meet regulatory requirements; changes in FERC rules and regulations; state regulatory agency approvals; changes in the expected environmental compliance program; changes in legislation; the cost and efficiency of construction labor, equipment, and materials; project scope and design changes; storm impacts; and the cost of capital. In addition, there can be no assurance that costs related to capital expenditures will be fully recovered. Additionally, planned expenditures for plant acquisitions may vary due to market opportunities and Southern Power’s ability to execute its growth strategy. See Note 12 to the financial statements under “Southern Power” for additional information regarding Southern Power’s plant acquisitions. In addition, the construction program includes the development and construction of new electric generating facilities with designs that have not been finalized or previously constructed, including first-of-a-kind technology, which may result in revised estimates during construction. See Note 3 to the financial statements under “Regulatory Matters – Georgia Power – Nuclear Construction” and “Integrated Coal Gasification Combined Cycle” for information regarding additional factors that may impact construction expenditures. As a result of NRC requirements, Alabama Power and Georgia Power have external trust funds for nuclear decommissioning costs; however, Alabama Power currently has no additional funding requirements. For additional information, see Note 1 to the financial statements under “Nuclear Decommissioning.” In addition, as discussed in Note 2 to the financial statements, Southern Company provides postretirement benefits to the majority of its employees and funds trusts to the extent required by PSCs, other applicable state regulatory agencies, or the FERC. Other funding requirements related to obligations associated with scheduled maturities of long-term debt, as well as the related interest, derivative obligations, preferred and preference stock dividends, leases, unrecognized tax benefits, pipeline charges, storage capacity, gas supply, asset management agreements, standby letters of credit and performance/surety bonds, other purchase commitments, and trusts are detailed in the contractual obligations table that follows. See Notes 1, 2, 5, 6, 7, and 11 to the financial statements for additional information. investor.southerncompany.com 48 Management’s Discussion and Analysis of Financial Condition and Results of Operations Contractual Obligations The Southern Company system’s contractual obligations at December 31, 2016 were as follows: Long-term debt(a) — Principal Interest Preferred and preference stock dividends(b) Financial derivative obligations(c) Operating leases(d) Capital leases(d) Unrecognized tax benefits(e) Pipeline charges, storage capacity, and gas supply(f) Asset management agreements(g) Standby letters of credit, performance/surety bonds(h) Purchase commitments — Capital(i) Fuel(j) Purchased power(k) Other(l) Trusts — Nuclear decommissioning(m) Pension and other postretirement benefit plans(n) $ 2017 2018-2019 2020-2021 (in millions) $ 2,556 1,635 45 516 152 16 484 822 10 85 8,797 3,763 362 479 $ 7,025 3,034 91 101 247 32 — 1,049 7 1 14,649 4,379 753 560 $ 4,448 2,592 91 12 190 22 — 746 — — 12,055 2,248 782 777 After 2021 30,890 24,055 — 1 1,195 79 — 2,591 — — — 7,095 2,651 3,024 $ Total 44,919 31,316 227 630 1,784 149 484 5,208 17 86 35,501 17,485 4,548 4,840 5 146 19,873 11 293 32,232 11 — 23,974 99 — 71,680 126 439 147,759 $ Total (a) All amounts are reflected based on final maturity dates except for amounts related to FFB borrowings. As it relates to the FFB borrowings, the final maturity date is February 20, 2044; however, principal amortization is reflected beginning in 2020. See Note 6 to the financial statements under “DOE Loan Guarantee Borrowings” for additional information. Southern Company and its subsidiaries plan to continue, when economically feasible, to retire higher-cost securities and replace these obligations with lower-cost capital if market conditions permit. Variable rate interest obligations are estimated based on rates as of January 1, 2017, as reflected in the statements of capitalization. Fixed rates include, where applicable, the effects of interest rate derivatives employed to manage interest rate risk. Long-term debt principal for 2017 includes $40 million of pollution control revenue bonds that are classified on the balance sheet at December 31, 2016 as short-term since they are variable rate demand obligations that are supported by short-term credit facilities; however, the final maturity date is in 2028. Long-term debt excludes capital lease amounts (shown separately). $ $ $ $ (b) Represents preferred and preference stock of subsidiaries. Preferred and preference stock do not mature; therefore, amounts are provided for the next five years only. (c) Includes derivative liabilities related to cash flow hedges of forecasted debt, as well as energy-related derivatives. For additional information, see Notes 1 and 11 to the financial statements. (d) Excludes PPAs that are accounted for as leases and included in “Purchased power.” (e) See Note 5 to the financial statements under “Unrecognized Tax Benefits” for additional information. (f) Includes charges recoverable through a natural gas cost recovery mechanism, or alternatively billed to marketers selling retail natural gas, and demand charges associated with Southern Company Gas’ wholesale gas services. The gas supply balance includes amounts for gas commodity purchase commitments associated with Southern Company Gas’ gas marketing services of 33 million mmBtu at floating gas prices calculated using forward natural gas prices at December 31, 2016 and valued at $106 million. Southern Company Gas provides guarantees to certain gas suppliers for certain of its subsidiaries in support of payment obligations. (g) Represents fixed-fee minimum payments for asset management agreements associated with wholesale gas services. (h) Guarantees are provided to certain municipalities and other agencies and certain natural gas suppliers in support of payment obligations. (i) The Southern Company system provides estimated capital expenditures for a five-year period, including capital expenditures associated with environmental regulations. These amounts exclude contractual purchase commitments for nuclear fuel and capital expenditures covered under long-term service agreements which are reflected in “Fuel” and “Other,” respectively. At December 31, 2016, significant purchase commitments were outstanding in connection with the construction program. See FUTURE EARNINGS POTENTIAL – “Environmental Matters – Environmental Statutes and Regulations” herein for additional information. (j) Primarily includes commitments to purchase coal, nuclear fuel, and natural gas, as well as the related transportation and storage. In most cases, these contracts contain provisions for price escalation, minimum purchase levels, and other financial commitments. Natural gas purchase commitments are based on various indices at the time of delivery. Amounts reflected for natural gas purchase commitments have been estimated based on the New York Mercantile Exchange future prices at December 31, 2016. (k) Estimated minimum long-term obligations for various PPA purchases from gas-fired, biomass, and wind-powered facilities. Includes a total of $292 million of biomass PPAs that is contingent upon the counterparties meeting specified contract dates for commercial operation. Subsequent to December 31, 2016, the specified contract dates for commercial operation were extended from 2017 to 2019 and may change further as a result of regulatory action. See FUTURE EARNINGS POTENTIAL – “Regulatory Matters – Renewables” herein for additional information. (l) Includes long-term service agreements, contracts for the procurement of limestone, contractual environmental remediation liabilities, and operation and maintenance agreements. Long-term service agreements include price escalation based on inflation indices. Southern Company 2016 Annual Report Management’s Discussion and Analysis of Financial Condition and Results of Operations 49 (m) Projections of nuclear decommissioning trust fund contributions for Plant Hatch and Plant Vogtle Units 1 and 2 are based on the 2013 ARP for Georgia Power. Alabama Power also has external trust funds for nuclear decommissioning costs; however, Alabama Power currently has no additional funding requirements. See Note 1 to the financial statements under “Nuclear Decommissioning” for additional information. (n) The Southern Company system forecasts contributions to the pension and other postretirement benefit plans over a three-year period. Southern Company anticipates no mandatory contributions to the qualified pension plans during the next three years. Amounts presented represent estimated benefit payments for the nonqualified pension plans, estimated non-trust benefit payments for the other postretirement benefit plans, and estimated contributions to the other postretirement benefit plan trusts, all of which will be made from corporate assets of Southern Company’s subsidiaries. See Note 2 to the financial statements for additional information related to the pension and other postretirement benefit plans, including estimated benefit payments. Certain benefit payments will be made through the related benefit plans. Other benefit payments will be made from corporate assets of Southern Company’s subsidiaries. investor.southerncompany.com 50 Consolidated Statements of Income CONSOLIDATED STATEMENTS OF INCOME For the Years Ended December 31, 2016, 2015, and 2014 Operating Revenues: Retail electric revenues Wholesale electric revenues Other electric revenues Natural gas revenues Other revenues Total operating revenues Operating Expenses: Fuel Purchased power Cost of natural gas Cost of other sales Other operations and maintenance Depreciation and amortization Taxes other than income taxes Estimated loss on Kemper IGCC Total operating expenses Operating Income Other Income and (Expense): Allowance for equity funds used during construction Earnings from equity method investments Interest expense, net of amounts capitalized Other income (expense), net Total other income and (expense) Earnings Before Income Taxes Income taxes Consolidated Net Income Less: Dividends on preferred and preference stock of subsidiaries Net income attributable to noncontrolling interests Consolidated Net Income Attributable to Southern Company Common Stock Data: Earnings per share (EPS) — Basic EPS Diluted EPS Average number of shares of common stock outstanding — (in millions) Basic Diluted 2016 2015 (in millions) $ $ $ 15,234 1,926 698 1,596 442 19,896 4,361 750 613 260 5,240 2,502 1,113 428 15,267 4,629 202 59 (1,317) (93) (1,149) 3,480 951 2,529 45 36 2,448 2.57 2.55 951 958 $ $ $ 14,987 1,798 657 — 47 17,489 4,750 645 — — 4,416 2,034 997 365 13,207 4,282 226 — (840) (39) (653) 3,629 1,194 2,435 54 14 2,367 2.60 2.59 910 914 $ $ $ 2014 15,550 2,184 672 — 61 18,467 6,005 672 — — 4,354 1,945 981 868 14,825 3,642 245 — (835) (44) (634) 3,008 977 2,031 68 — 1,963 2.19 2.18 897 901 The accompanying notes are an integral part of these consolidated financial statements. Southern Company 2016 Annual Report Consolidated Statements of Comprehensive Income 51 CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME For the Years Ended December 31, 2016, 2015, and 2014 Consolidated Net Income Other comprehensive income: Qualifying hedges: Changes in fair value, net of tax of $(84), $(8), and $(6), respectively Reclassification adjustment for amounts included in net income, net of tax of $43, $4, and $3, respectively Pension and other postretirement benefit plans: Benefit plan net gain (loss), net of tax of $10, $(1), and $(32), respectively Reclassification adjustment for amounts included in net income, net of tax of $3, $4, and $2, respectively Total other comprehensive income (loss) Less: 2016 2015 2014 (in millions) $ 2,529 $ 2,435 $ 2,031 (136) (13) 69 13 4 (50) 6 (2) 7 (2) (10) 5 (51) 3 (53) Dividends on preferred and preference stock of subsidiaries Comprehensive income attributable to noncontrolling interests Consolidated Comprehensive Income Attributable to Southern Company $ 45 36 2,398 54 14 2,365 $ 68 — 1,910 $ The accompanying notes are an integral part of these consolidated financial statements. investor.southerncompany.com 52 Consolidated Statements of Cash Flows CONSOLIDATED STATEMENTS OF CASH FLOWS For the Years Ended December 31, 2016, 2015, and 2014 Operating Activities: Consolidated net income Adjustments to reconcile consolidated net income to net cash provided from operating activities — Depreciation and amortization, total Deferred income taxes Collateral deposits Allowance for equity funds used during construction Pension, postretirement, and other employee benefits Pension and postretirement funding Settlement of asset retirement obligations Stock based compensation expense Hedge settlements Estimated loss on Kemper IGCC Income taxes receivable, non-current Other, net Changes in certain current assets and liabilities — -Receivables -Fossil fuel for generation -Natural gas for sale -Materials and supplies -Other current assets -Accounts payable -Accrued taxes -Accrued compensation -Retail fuel cost over recovery — short-term -Mirror CWIP -Other current liabilities Net cash provided from operating activities Investing Activities: Business acquisitions, net of cash acquired Property additions Investment in restricted cash Distribution of restricted cash Nuclear decommissioning trust fund purchases Nuclear decommissioning trust fund sales Cost of removal, net of salvage Change in construction payables, net Investment in unconsolidated subsidiaries Prepaid long-term service agreement Other investing activities Net cash used for investing activities 2016 2015 (in millions) 2014 $ 2,529 $ 2,435 $ 2,031 2,923 (127) (102) (202) (65) (1,029) (171) 121 (233) 428 (122) (36) (544) 178 (226) (31) (174) 301 1,456 36 (231) — 215 4,894 (10,689) (7,310) (733) 742 (1,160) 1,154 (245) (121) (1,444) (134) (108) (20,048) 2,395 1,404 — (226) 83 (7) (37) 99 (17) 365 (413) (33) 243 61 — (44) (108) (353) 352 (41) 289 (271) 98 6,274 (1,719) (5,674) (160) 154 (1,424) 1,418 (167) 402 — (197) 87 (7,280) 2,293 709 — (245) (9) (506) (17) 63 — 868 — 13 (352) 408 — (67) (57) 267 (105) 255 (23) 180 109 5,815 (731) (5,246) (11) 57 (916) 914 (170) (107) — (181) (17) (6,408) Southern Company 2016 Annual Report Financing Activities: Increase (decrease) in notes payable, net Proceeds — Long-term debt Interest-bearing refundable deposit Common stock Short-term borrowings Redemptions and repurchases — Long-term debt Common stock Interest-bearing refundable deposits Preferred and preference stock Short-term borrowings Distributions to noncontrolling interests Capital contributions from noncontrolling interests Purchase of membership interests from noncontrolling interests Payment of common stock dividends Other financing activities Net cash provided from financing activities Net Change in Cash and Cash Equivalents Cash and Cash Equivalents at Beginning of Year Cash and Cash Equivalents at End of Year Consolidated Statements of Cash Flows 53 2016 2015 (in millions) 2014 1,228 73 (676) 16,368 — 3,758 — (3,145) — — — (478) (72) 682 (129) (2,104) (383) 15,725 571 1,404 1,975 7,029 — 256 755 (3,604) (115) (275) (412) (255) (18) 341 — (1,959) (116) 1,700 694 710 1,404 $ 3,169 125 806 — (816) (5) — — — (1) 8 — (1,866) (100) 644 51 659 710 $ $ The accompanying notes are an integral part of these consolidated financial statements. investor.southerncompany.com 54 Consolidated Balance Sheets CONSOLIDATED BALANCE SHEETS At December 31, 2016 and 2015 Assets Current Assets: Cash and cash equivalents Receivables — Customer accounts receivable Energy marketing receivable Unbilled revenues Under recovered regulatory clause revenues Income taxes receivable, current Other accounts and notes receivable Accumulated provision for uncollectible accounts Materials and supplies Fossil fuel for generation Natural gas for sale Prepaid expenses Other regulatory assets, current Other current assets Total current assets Property, Plant, and Equipment: In service Less accumulated depreciation Plant in service, net of depreciation Other utility plant, net Nuclear fuel, at amortized cost Construction work in progress Total property, plant, and equipment Other Property and Investments: Goodwill Equity investments in unconsolidated subsidiaries Other intangible assets, net of amortization of $62 and $12 at December 31, 2016 and December 31, 2015, respectively Nuclear decommissioning trusts, at fair value Leveraged leases Miscellaneous property and investments Total other property and investments Deferred Charges and Other Assets: Deferred charges related to income taxes Unamortized loss on reacquired debt Other regulatory assets, deferred Income taxes receivable, non-current Other deferred charges and assets Total deferred charges and other assets Total Assets The accompanying notes are an integral part of these consolidated financial statements. 2016 2015 (in millions) $ 1,975 $ 1,404 1,565 623 706 18 544 377 (43) 1,462 689 631 364 581 230 9,722 98,416 29,852 68,564 — 905 8,977 78,446 6,251 1,549 970 1,606 774 270 11,420 1,629 223 6,851 11 1,395 10,109 109,697 1,058 — 397 63 144 398 (13) 1,061 868 — 495 580 71 6,526 75,118 24,253 50,865 233 934 9,082 61,114 2 6 317 1,512 755 160 2,752 1,560 227 4,989 413 737 7,926 78,318 $ $ Southern Company 2016 Annual Report Liabilities and Stockholders’ Equity Current Liabilities: Securities due within one year Notes payable Energy marketing trade payables Accounts payable Customer deposits Accrued taxes — Accrued income taxes Unrecognized tax benefits Other accrued taxes Accrued interest Accrued compensation Asset retirement obligations, current Liabilities from risk management activities, net of collateral Acquisitions payable Other regulatory liabilities, current Over recovered regulatory clause revenues, current Other current liabilities Total current liabilities Long-Term Debt (See accompanying statements) Deferred Credits and Other Liabilities: Accumulated deferred income taxes Deferred credits related to income taxes Accumulated deferred investment tax credits Employee benefit obligations Asset retirement obligations, deferred Unrecognized tax benefits, deferred Accrued environmental remediation Other cost of removal obligations Other regulatory liabilities, deferred Other deferred credits and liabilities Total deferred credits and other liabilities Total Liabilities Redeemable Preferred Stock of Subsidiaries (See accompanying statements) Redeemable Noncontrolling Interests (See accompanying statements) Total Stockholders’ Equity (See accompanying statements) Total Liabilities and Stockholders’ Equity Commitments and Contingent Matters (See notes) The accompanying notes are an integral part of these consolidated financial statements. Consolidated Balance Sheets 55 2016 (in millions) 2015 $ $ 2,587 2,241 597 2,228 558 193 385 667 518 915 378 107 489 236 135 683 12,917 42,629 14,092 219 2,228 2,299 4,136 — 397 2,748 258 880 27,257 82,803 118 164 26,612 109,697 $ $ 2,674 1,376 — 1,905 404 9 10 484 249 777 217 156 — 278 106 484 9,129 24,688 12,322 187 1,219 2,582 3,542 370 42 1,162 254 678 22,358 56,175 118 43 21,982 78,318 investor.southerncompany.com 56 Consolidated Statements of Capitalization CONSOLIDATED STATEMENTS OF CAPITALIZATION At December 31, 2016 and 2015 Interest Rates 1.95% to 5.30% 1.30% to 7.20% 1.50% to 5.40% 1.85% to 5.55% 2.38% to 4.75% 2.35% to 9.10% 1.00% to 8.70% Interest Rates 4.55% 0.65% to 5.15% Long-Term Debt: Long-term debt payable to affiliated trusts — Variable rate (3.95% at 1/1/17) due 2042 Long-term senior notes and debt — Maturity 2016 2017 2018 2019 2020 2021 2022 through 2051 Variable rates (0.76% to 3.50% at 1/1/16) due 2016 Variable rates (1.82% to 3.75% at 1/1/17) due 2017 Variable rates (1.88% to 2.24% at 1/1/17) due 2018 Variable rates (1.87% to 2.10% at 1/1/17) due 2021 Variable rate (3.75% at 1/1/17) due 2032 to 2036 Total long-term senior notes and debt Other long-term debt — Pollution control revenue bonds — Maturity 2019 2022 through 2049 Variable rate (0.22% at 1/1/16) due 2016 Variable rates (0.77% to 0.87% at 1/1/17) due 2017 Variable rates (0.82% to 0.86% at 1/1/17) due 2021 Variable rates (0.75% to 0.87% at 1/1/17) due 2022 to 2053 Plant Daniel revenue bonds (7.13%) due 2021 FFB loans — 2.57% to 3.86% due 2020 2.57% to 3.86% due 2021 2.57% to 3.86% due 2022 to 2044 First mortgage bonds — 4.70% due 2019 2.66% to 6.58% due 2023 to 2038 Gas facility revenue bonds — Variable rate (1.28% at 1/1/17) due 2022 to 2033 Junior subordinated notes (5.25% to 6.25%) due 2057 to 2076 Total other long-term debt Unamortized fair value adjustment of long-term debt Capitalized lease obligations Unamortized debt premium Unamortized debt discount Unamortized debt issuance expense Total long-term debt (annual interest requirement — $1.6 billion) Less amount due within one year Long-term debt excluding amount due within one year 2016 2015 (in millions) 2016 2015 (percent of total) $ 206 $ 206 — 2,019 2,353 3,076 1,326 2,655 21,797 — 461 1,520 25 15 35,247 25 1,429 — 76 65 1,739 270 44 44 2,537 50 575 200 2,350 9,404 578 136 52 (194) (213) 45,216 2,587 42,629 1,360 1,995 1,697 1,176 1,327 200 10,972 1,278 400 — — 13 20,418 25 1,509 4 76 65 1,659 270 37 37 2,126 — — — 1,000 6,808 — 146 61 (36) (241) 27,362 2,674 24,688 61.3% 52.6% Southern Company 2016 Annual Report Redeemable Preferred Stock of Subsidiaries: Cumulative preferred stock $100 par or stated value — 4.20% to 5.44% Authorized — 20 million shares Outstanding — 1 million shares $1 par value — 5.83% Authorized — 28 million shares Outstanding — 2 million shares: $25 stated value Total redeemable preferred stock of subsidiaries (annual dividend requirement — $6 million) Redeemable Noncontrolling Interests Common Stockholders’ Equity: Common stock, par value $5 per share — Authorized — 1.5 billion shares Issued — 2016: 991 million shares — 2015: 915 million shares Treasury — 2016: 0.8 million shares — 2015: 3.4 million shares Paid-in capital Treasury, at cost Retained earnings Accumulated other comprehensive loss Total common stockholders’ equity Preferred and Preference Stock of Subsidiaries and Noncontrolling Interests: Non-cumulative preferred stock $25 par value — 6.00% to 6.13% Authorized — 60 million shares Outstanding — 2 million shares Preference stock Authorized — 65 million shares Outstanding — $1 par value — 6.45% to 6.50% — 8 million shares (non-cumulative) Outstanding — $100 par or stated value — 5.60% to 6.50% — 4 million shares (non-cumulative) Noncontrolling interests Total preferred and preference stock of subsidiaries and noncontrolling interests (annual dividend requirement — $39 million) Total stockholders’ equity Total Capitalization Consolidated Statements of Capitalization 57 2016 2015 (in millions) 2016 2015 (percent of total) 81 37 118 164 81 37 118 43 4,952 4,572 0.2 0.2 0.3 0.1 9,661 (31) 10,356 (180) 24,758 6,282 (142) 10,010 (130) 20,592 35.6 44.0 45 45 196 368 1,245 196 368 781 1,854 26,612 69,523 $ 1,390 21,982 46,831 $ 2.7 3.0 100.0% 100.0% The accompanying notes are an integral part of these consolidated financial statements. investor.southerncompany.com 58 Consolidated Statements of Stockholders’ Equity CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY For the Years Ended December 31, 2016, 2015, and 2014 Southern Company Common Stockholders’ Equity Number of Common Shares Issued Treasury (in thousands) Common Stock Par Value Paid-In Capital Treasury Retained Earnings Accumulated Other Comprehensive Income (Loss) Preferred and Preference Stock of Subsidiaries (in millions) Non controlling Interests Total 892,733 (5,647) $ 4,461 $ 5,362 $ (250) $ 9,510 $ (75) $ 756 $ — $ 19,764 — — — — 15,769 4,996 — — — — — — — — — (74) — — 78 — — — — — — — 501 86 — — — 6 — — 227 — — — — (3) 1,963 — — — (1,866) — — 2 — (53) — — — — — — — — — — — — — — — — — — — 1,963 (53) 806 86 (1,866) 221 221 (2) 2 (2) 7 908,502 (725) 4,539 5,955 (26) 9,609 (128) 756 221 20,926 — — — — 6,571 (2,599) — — — — — — — — — — — — — — — (28) — — 33 — — — — — — — — — — 223 100 — — — — — — 4 — — — — (115) — — — — — (1) 2,367 — — — — (1,959) — — — — (7) — (2) — — — — — — — — — — — — — — — (150) — — — 3 — — — — — — — 2,367 (2) 256 100 (115) (1,959) (150) 567 567 (18) (18) 12 (1) 12 (2) Balance at December 31, 2013 Consolidated net income attributable to Southern Company Other comprehensive income (loss) Stock issued Stock-based compensation Cash dividends of $2.0825 per share Contributions from noncontrolling interests Net loss attributable to noncontrolling interests Other Balance at December 31, 2014 Consolidated net income attributable to Southern Company Other comprehensive income (loss) Stock issued Stock-based compensation Stock repurchased, at cost Cash dividends of $2.1525 per share Preference stock redemptions Contributions from noncontrolling interests Distributions to noncontrolling interests Net income attributable to noncontrolling interests Other Southern Company 2016 Annual Report Consolidated Statements of Stockholders’ Equity 59 Southern Company Common Stockholders’ Equity Number of Common Shares Issued Treasury (in thousands) Common Stock Par Value Paid-In Capital Treasury Retained Earnings Accumulated Other Comprehensive Income (Loss) Preferred and Preference Stock of Subsidiaries (in millions) Non controlling Interests Total 915,073 (3,352) 4,572 6,282 (142) 10,010 (130) 609 781 21,982 — — — — — — — — 76,140 2,599 380 3,263 — — — — — — — — — — — — 120 — — — — — — — — — 115 — — — — — — — — (66) — — — (4) — (4) 2,448 — — — (2,104) — — — — 2 — (50) — — — — — — — — — — — — — — — — — — — — — — — 2,448 (50) 3,758 120 (2,104) 618 618 (57) (57) (129) (129) 32 — 32 (6) 991,213 (819) $ 4,952 $ 9,661 $ (31) $ 10,356 $ (180) $ 609 $ 1,245 $ 26,612 Balance at December 31, 2015 Consolidated net income attributable to Southern Company Other comprehensive income (loss) Stock issued Stock-based compensation Cash dividends of $2.2225 per share Contributions from noncontrolling interests Distributions to noncontrolling interests Purchase of membership interests from noncontrolling interests Net income attributable to redeemable noncontrolling interests Other Balance at December 31, 2016 The accompanying notes are an integral part of these consolidated financial statements. investor.southerncompany.com 60 Notes to Financial Statements NOTES TO FINANCIAL STATEMENTS Note Page Index to the Notes to Financial Statements 1 Summary of Significant Accounting Policies ...................................................................................................................... 61 2 Retirement Benefits ............................................................................................................................................................... 71 3 Contingencies and Regulatory Matters ............................................................................................................................... 81 4 Joint Ownership Agreements ................................................................................................................................................ 96 5 Income Taxes ............................................................................................................................................................................ 97 6 Financing .................................................................................................................................................................................. 100 7 Commitments .......................................................................................................................................................................... 106 8 Common Stock ......................................................................................................................................................................... 107 9 Nuclear Insurance .................................................................................................................................................................... 111 10 Fair Value Measurements ....................................................................................................................................................... 112 11 Derivatives ............................................................................................................................................................................... 114 12 Acquisitions .............................................................................................................................................................................. 119 13 Segment and Related Information ....................................................................................................................................... 125 14 Quarterly Financial Information (Unaudited) ..................................................................................................................... 127 Southern Company 2016 Annual Report Notes to Financial Statements 61 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES General The Southern Company (Southern Company or the Company) is the parent company of four traditional electric operating companies, Southern Power, Southern Company Gas (as of July 1, 2016), SCS, Southern LINC, Southern Company Holdings, Inc. (Southern Holdings), Southern Nuclear, PowerSecure (as of May 9, 2016), and other direct and indirect subsidiaries. The traditional electric operating companies – Alabama Power, Georgia Power, Gulf Power, and Mississippi Power – are vertically integrated utilities providing electric service in four Southeastern states. Southern Power constructs, acquires, owns, and manages generation assets, including renewable energy projects, and sells electricity at market-based rates in the wholesale market. Southern Company Gas distributes natural gas through the natural gas distribution utilities in seven states and is involved in several other complementary businesses including gas marketing services, wholesale gas services, and gas midstream operations. SCS, the system service company, provides, at cost, specialized services to Southern Company and its subsidiary companies. Southern LINC provides digital wireless communications for use by Southern Company and its subsidiary companies and also markets these services to the public and provides fiber cable services within the Southeast. Southern Holdings is an intermediate holding company subsidiary, primarily for Southern Company’s investments in leveraged leases and for other electric services. Southern Nuclear operates and provides services to the Southern Company system’s nuclear power plants. PowerSecure is a provider of products and services in the areas of distributed generation, energy efficiency, and utility infrastructure. The financial statements reflect Southern Company’s investments in the subsidiaries on a consolidated basis. The equity method is used for entities in which the Company has significant influence but does not control and for variable interest entities where the Company has an equity investment but is not the primary beneficiary. Intercompany transactions have been eliminated in consolidation. The traditional electric operating companies, Southern Power, certain subsidiaries of Southern Company Gas, and certain other subsidiaries are subject to regulation by the FERC, and the traditional electric operating companies and natural gas distribution utilities are also subject to regulation by their respective state PSCs or other applicable state regulatory agencies. As such, the consolidated financial statements reflect the effects of rate regulation in accordance with GAAP and comply with the accounting policies and practices prescribed by relevant state PSCs or other applicable state regulatory agencies. The preparation of financial statements in conformity with GAAP requires the use of estimates, and the actual results may differ from those estimates. Certain prior years’ data presented in the financial statements have been reclassified to conform to the current year presentation. These reclassifications had no impact on Southern Company’s results of operations, financial position, or cash flows. In June 2015, Georgia Power identified an error affecting the billing to a small number of large commercial and industrial customers under a rate plan allowing for variable demand-driven pricing from January 1, 2013 to June 30, 2015. In the second quarter 2015, Georgia Power recorded an out of period adjustment of approximately $75 million to decrease retail revenues, resulting in a decrease to net income of approximately $47 million. Georgia Power evaluated the effects of this error on the interim and annual periods that included the billing error. Based on an analysis of qualitative and quantitative factors, Georgia Power determined the error was not material to any affected period and, therefore, an amendment of previously filed financial statements was not required. Recently Issued Accounting Standards In 2014, the FASB issued ASC 606, Revenue from Contracts with Customers, replacing the existing accounting standard and industry specific guidance for revenue recognition with a five-step model for recognizing and measuring revenue from contracts with customers. The underlying principle of the guidance is to recognize revenue to depict the transfer of goods or services to customers at the amount expected to be collected. The new standard also requires enhanced disclosures regarding the nature, amount, timing, and uncertainty of revenue and the related cash flows arising from contracts with customers. While Southern Company expects most of its revenue to be included in the scope of ASC 606, it has not fully completed its evaluation of such arrangements. The majority of Southern Company’s revenue, including energy provided to customers, is from tariff offerings that provide natural gas or electricity without a defined contractual term. For such arrangements, Southern Company generally expects that the revenue from contracts with these customers will continue to be equivalent to the electricity or natural gas supplied and billed in that period (including unbilled revenues) and the adoption of ASC 606 will not result in a significant shift in the timing of revenue recognition for such sales. investor.southerncompany.com 62 Notes to Financial Statements Southern Company’s ongoing evaluation of other revenue streams and related contracts includes longer term contractual commitments and unregulated sales to customers. Some revenue arrangements, such as certain PPAs and alternative revenue programs, are expected to be excluded from the scope of ASC 606 and therefore, be accounted for and presented separately from revenues under ASC 606 on Southern Company’s financial statements. In addition, the power and utilities industry is currently addressing other specific industry issues, including the applicability of ASC 606 to contributions in aid of construction (CIAC). If final implementation guidance indicates CIAC will be accounted for under ASC 606 and offsetting regulatory treatment is not permitted, it could have a material impact on Southern Company’s financial statements. The new standard is effective for interim and annual reporting periods beginning after December 15, 2017. Southern Company must select a transition method to be applied either retrospectively to each prior reporting period presented or retrospectively with a cumulative effect adjustment to retained earnings at the date of initial adoption. As the ultimate impact of the new standard has not yet been determined, Southern Company has not elected its transition method. On February 25, 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842) (ASU 2016-02). ASU 2016-02 requires lessees to recognize on the balance sheet a lease liability and a right-of-use asset for all leases. ASU 2016-02 also changes the recognition, measurement, and presentation of expense associated with leases and provides clarification regarding the identification of certain components of contracts that would represent a lease. The accounting required by lessors is relatively unchanged and there is no change to the accounting for existing leveraged leases. ASU 2016-02 is effective for fiscal years beginning after December 15, 2018, with early adoption permitted. Southern Company is currently evaluating the new standard and has not yet determined its ultimate impact; however, adoption of ASU 2016-02 is expected to have a significant impact on Southern Company’s balance sheet. On March 30, 2016, the FASB issued ASU No. 2016-09, Compensation-Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting (ASU 2016-09). ASU 2016-09 changes the accounting for income taxes and the cash flow presentation for share-based payment award transactions effective for fiscal years beginning after December 15, 2016. The new guidance requires all excess tax benefits and deficiencies related to the exercise or vesting of stock compensation to be recognized as income tax expense or benefit in the income statement. Previously, Southern Company recognized any excess tax benefits and deficiencies related to the exercise and vesting of stock compensation as additional paid-in capital. In addition, the new guidance requires excess tax benefits for share-based payments to be included in net cash provided from operating activities rather than net cash provided from financing activities on the statement of cash flows. Southern Company elected to adopt the guidance in 2016 and reflect the related adjustments as of January 1, 2016. Prior year’s data presented in the financial statements has not been adjusted. Southern Company also elected to recognize forfeitures as they occur. The new guidance did not have a material impact on the results of operations, financial position, or cash flows of Southern Company. See Notes 5, 8, and 14 for disclosures impacted by ASU 2016-09. On October 24, 2016, the FASB issued ASU No. 2016-16, Income Taxes (Topic 740), Intra-Entity Transfers of Assets Other Than Inventory (ASU 2016-16). Current GAAP prohibits the recognition of current and deferred income taxes for an affiliate asset transfer until the asset has been sold to an outside party. ASU 2016-16 requires an entity to recognize the income tax consequences of an affiliate transfer of an asset other than inventory when the transfer occurs. ASU 2016-16 is effective for annual reporting periods beginning after December 15, 2017 and interim periods within those annual periods. The amendments will be applied on a modified retrospective basis through a cumulative-effect adjustment directly to retained earnings as of the beginning of the period of adoption. Southern Company is currently assessing the impact of the standard on its financial statements and has not yet determined its ultimate impact. On November 17, 2016, the FASB issued ASU No. 2016-18, Statement of Cash Flows (Topic 230): Restricted Cash (ASU 2016-18). ASU 2016-18 eliminates the need to reflect transfers between cash and restricted cash in operating, investing, and financing activities in the statement of cash flows. Upon adoption, the net change in cash and cash equivalents during the period will include amounts generally described as restricted cash or restricted cash equivalents. ASU 2016-18 is effective for fiscal years beginning after December 15, 2017, with early adoption permitted, and will be applied retrospectively to each period presented. Southern Company does not intend to adopt the guidance early. The adoption of ASU 2016-18 will not have a material impact on the financial statements of Southern Company. Regulatory Assets and Liabilities The traditional electric operating companies and natural gas distribution utilities are subject to accounting requirements for the effects of rate regulation. Regulatory assets represent probable future revenues associated with certain costs that are expected to be recovered from customers through the ratemaking process. Regulatory liabilities represent probable future reductions in revenues associated with amounts that are expected to be credited to customers through the ratemaking process. Southern Company 2016 Annual Report Regulatory assets and (liabilities) reflected in the balance sheets at December 31 relate to: Notes to Financial Statements 63 Retiree benefit plans Deferred income tax charges Asset retirement obligations-asset Environmental remediation-asset Other regulatory assets Remaining net book value of retired assets Under recovered regulatory clause revenues Loss on reacquired debt Property damage reserves-asset Kemper IGCC Vacation pay Long-term debt fair value adjustment Deferred PPA charges Nuclear outage Fuel-hedging-asset Other cost of removal obligations Deferred income tax credits Over recovered regulatory clause revenues Property damage reserves-liability Other regulatory liabilities Asset retirement obligations-liability 2016 2015 Note (in millions) $ 3,959 1,590 1,080 491 355 351 273 243 206 201 182 155 141 97 35 (2,774) (219) (203) (177) (110) (10) $ 3,440 1,514 481 78 299 283 142 248 92 216 178 — 163 88 225 (1,177 ) (187 ) (261 ) (178 ) (35 ) (45 ) (a,n) (b) (b,n) (j,n) (k) (o) (g) (c) (i) (h) (f,n) (p) (e,n) (g) (d,n) (b) (b) (g) (l) (m) (b,n) Total regulatory assets (liabilities), net Note: The recovery and amortization periods for these regulatory assets and (liabilities) are as follows: (a) Recovered and amortized over the average remaining service period which may range up to 15 years. See Note 2 for additional information. (b) Asset retirement and other cost of removal obligations are recorded, deferred income tax assets are recovered, and deferred income tax 5,866 5,564 $ $ liabilities are amortized over the related property lives, which may range up to 70 years. Asset retirement and removal liabilities will be settled and trued up following completion of the related activities. (c) Recovered over either the remaining life of the original issue or, if refinanced, over the remaining life of the new issue, which may range up to 50 years. (d) Recorded over the life of the underlying hedged purchase contracts, which generally do not exceed five years. Upon final settlement, actual costs incurred are recovered through fuel and energy cost recovery mechanisms. (e) Recovered over the life of the PPA for periods up to seven years. (f) Recorded as earned by employees and recovered as paid, generally within one year. This includes both vacation and banked holiday pay. (g) Recorded and recovered or amortized as approved or accepted by the appropriate state PSCs or other applicable regulatory agencies over periods generally not exceeding ten years. (h) Includes $97 million of regulatory assets currently in rates to be recovered over periods of two, seven, or 10 years. For additional information, see Note 3 under “Integrated Coal Gasification Combined Cycle – Rate Recovery of Kemper IGCC Costs – Regulatory Assets and Liabilities.” (i) Previous under-recovery as of December 2013 is recorded and recovered or amortized as approved by the Georgia PSC through 2019. Amortization of $185 million related to the under-recovery from January 2014 through December 2016 will be determined by the Georgia PSC in the 2019 base rate case. See Note 3 for additional information. (j) Recovered through environmental cost recovery mechanisms when the remediation is performed or the work is performed. (k) Comprised of numerous immaterial components including deferred income tax charges - Medicare subsidy, cancelled construction projects, building and generating plant leases, property tax, and other miscellaneous assets. These costs are recorded and recovered or amortized as approved by the appropriate state PSCs over periods generally not exceeding 50 years. (l) Recovered as storm restoration and potential reliability-related expenses are incurred as approved by the appropriate state PSCs. (m) Comprised of numerous immaterial components including retiree benefit plans, fuel-hedging gains, and other liabilities that are recorded and recovered or amortized as approved by the appropriate state PSCs or other applicable regulatory agencies generally over periods not exceeding 4 years. (n) Not earning a return as offset in rate base by a corresponding asset or liability. (o) Amortized as approved by the appropriate state PSCs over periods generally up to 11 years. (p) Recorded in relation to the Merger. Recovered over the remaining life of the original debt issuances, which range up to 22 years. For additional information see Note 12 under “Southern Company – Merger with Southern Company Gas.” investor.southerncompany.com 64 Notes to Financial Statements In the event that a portion of a traditional electric operating company’s or a natural gas distribution utility’s operations is no longer subject to applicable accounting rules for rate regulation, such company would be required to write off to income or reclassify to accumulated OCI related regulatory assets and liabilities that are not specifically recoverable through regulated rates. In addition, the traditional electric operating company or natural gas distribution utility would be required to determine if any impairment to other assets, including plant, exists and write down the assets, if impaired, to their fair values. All regulatory assets and liabilities are to be reflected in rates. See Note 3 under “Regulatory Matters – Alabama Power,” “Regulatory Matters – Georgia Power,” “Regulatory Matters – Gulf Power,” “Regulatory Matters – Southern Company Gas,” and “Integrated Coal Gasification Combined Cycle” for additional information. Revenues Wholesale capacity revenues from PPAs are recognized either on a levelized basis over the appropriate contract period or the amount billable under the contract terms. Energy and other revenues are recognized as services are provided. Unbilled revenues related to retail sales are accrued at the end of each fiscal period. Retail rates for the traditional electric operating companies and natural gas distribution utilities may include provisions to adjust billings for fluctuations in fuel and purchased gas costs, fuel hedging, the energy component of purchased power costs, and certain other costs. Revenues are adjusted for differences between these actual costs and amounts billed in current regulated rates. Under or over recovered regulatory clause revenues are recorded in the balance sheets and are recovered or returned to customers through adjustments to the billing factors. Southern Company’s electric utility subsidiaries and Southern Company Gas have a diversified base of customers. No single customer or industry comprises 10% or more of revenues. For all periods presented, uncollectible accounts averaged less than 1% of revenues. Fuel Costs Fuel costs are expensed as the fuel is used. Fuel expense generally includes fuel transportation costs and the cost of purchased emissions allowances as they are used. Fuel expense also includes the amortization of the cost of nuclear fuel and a charge, based on nuclear generation, for the permanent disposal of spent nuclear fuel. Income and Other Taxes Southern Company uses the liability method of accounting for deferred income taxes and provides deferred income taxes for all significant income tax temporary differences. Taxes that are collected from customers on behalf of governmental agencies to be remitted to these agencies are presented net on the statements of income. In accordance with regulatory requirements, deferred federal ITCs for the traditional electric operating companies and Southern Company Gas are amortized over the average lives of the related property with such amortization normally applied as a credit to reduce depreciation in the statements of income. Under current tax law, certain projects at Southern Power are eligible for federal ITCs or cash grants. Southern Power has elected to receive ITCs. The credits are recorded as a deferred credit and are amortized to income tax expense over the life of the asset. Furthermore, the tax basis of the asset is reduced by 50% of the credits received, resulting in a net deferred tax asset. Southern Power has elected to recognize the tax benefit of this basis difference as a reduction to income tax expense in the year in which the plant reaches commercial operation. In addition, certain projects are eligible for federal PTCs, which are recorded to income tax expense based on KWH production. Federal ITCs and PTCs, as well as state ITCs and other state tax credits available to reduce income taxes payable, were not fully utilized in 2016 and will be carried forward and utilized in future years. In addition, Southern Company is expected to have a consolidated federal net operating loss (NOL) carryforward for the 2016 tax year along with various state NOL carryforwards, which could result in income tax benefits in the future, if utilized. See Note 5 under “Current and Deferred Income Taxes – Tax Credit Carryforwards” and “ – Net Operating Loss” for additional information. Southern Company recognizes tax positions that are “more likely than not” of being sustained upon examination by the appropriate taxing authorities. See Note 5 under “Unrecognized Tax Benefits” for additional information. Southern Company 2016 Annual Report Property, Plant, and Equipment Property, plant, and equipment is stated at original cost less any regulatory disallowances and impairments. Original cost includes: materials; labor; minor items of property; appropriate administrative and general costs; payroll-related costs such as taxes, pensions, and other benefits; and the interest capitalized and cost of equity funds used during construction. The Southern Company system’s property, plant, and equipment in service consisted of the following at December 31: Notes to Financial Statements 65 Electric utilities: Generation Transmission Distribution General Plant acquisition adjustment Electric utility plant in service Natural gas distribution utilities: Transportation and distribution Utility plant in service Information technology equipment and software Communications equipment Storage facilities Other Total other plant in service Total plant in service 2016 2015 (in millions) $ 48,836 11,156 18,418 4,629 126 83,165 11,996 95,161 544 424 1,463 824 3,255 98,416 $ $ $ 41,648 10,544 17,670 4,377 123 74,362 — 74,362 222 418 — 116 756 75,118 The cost of replacements of property, exclusive of minor items of property, is capitalized. The cost of maintenance, repairs, and replacement of minor items of property is charged to other operations and maintenance expenses as incurred or performed with the exception of nuclear refueling costs, which are recorded in accordance with specific state PSC orders. Alabama Power and Georgia Power defer and amortize nuclear refueling costs over the unit’s operating cycle. The refueling cycles for Alabama Power’s Plant Farley and Georgia Power’s Plants Hatch and Vogtle Units 1 and 2 range from 18 to 24 months, depending on the unit. Assets acquired under a capital lease are included in property, plant, and equipment and are further detailed in the table below: Office building Nitrogen plant Computer-related equipment Gas pipeline Less: Accumulated amortization Balance, net of amortization Asset Balances at December 31, 2016 2015 (in millions) $ 61 83 63 6 (69) $ 144 $ $ 61 83 61 6 (59) 152 The amount of non-cash property additions recognized for the years ended December 31, 2016, 2015, and 2014 was $1.5 billion, $844 million, and $528 million, respectively. These amounts are comprised of construction-related accounts payable outstanding at each year end. Also, the amount of non-cash property additions associated with capitalized leases for the years ended December 31, 2016, 2015, and 2014 was $18 million, $13 million, and $25 million, respectively. Depreciation and Amortization Depreciation of the original cost of utility plant in service is provided primarily by using composite straight-line rates, which approximated 3.0% in 2016 and 2015 and 3.1% in 2014. Depreciation studies are conducted periodically to update the composite rates. These studies are filed with the respective state PSC or other applicable state and federal regulatory agencies for the traditional electric operating companies and natural gas distribution utilities. Accumulated depreciation for utility plant in service totaled $29.3 billion and $23.7 billion at December 31, 2016 and 2015, respectively. When property subject to composite depreciation is retired or otherwise disposed of in the normal course of business, its original cost, together with the cost of removal, less salvage, is charged to accumulated depreciation. For other property dispositions, the applicable cost and accumulated depreciation are removed from the balance sheet accounts, and a gain or loss is recognized. Minor items of investor.southerncompany.com 66 Notes to Financial Statements property included in the original cost of the plant are retired when the related property unit is retired. Certain of Southern Power’s generation assets are depreciated on a units-of-production basis, using hours or starts, to better match outage and maintenance costs to the usage of and revenues from these assets. Cost, net of salvage value, of these assets is depreciated on an hours or starts units-of-production basis. Under the terms of the 2013 ARP, Georgia Power amortized approximately $14 million in each of 2014, 2015, and 2016 of its remaining regulatory liability related to other cost of removal obligations. See Note 3 under “Regulatory Matters – Gulf Power – Retail Base Rate Cases” for information regarding depreciation and amortization adjustments related to the other cost of removal regulatory liability. Depreciation of the original cost of other plant in service is provided primarily on a straight-line basis over estimated useful lives ranging from three to 65 years. Accumulated depreciation for other plant in service totaled $550 million and $510 million at December 31, 2016 and 2015, respectively. Asset Retirement Obligations and Other Costs of Removal AROs are computed as the present value of the estimated ultimate costs for an asset’s future retirement and are recorded in the period in which the liability is incurred. The costs are capitalized as part of the related long-lived asset and depreciated over the asset’s useful life. In the absence of quoted market prices, AROs are estimated using present value techniques in which estimates of future cash outlays associated with the asset retirements are discounted using a credit-adjusted risk-free rate. Estimates of the timing and amounts of future cash outlays are based on projections of when and how the assets will be retired and the cost of future removal activities. Each traditional electric operating company and natural gas distribution utility has received accounting guidance from its state PSC or applicable state regulatory agency allowing the continued accrual or recovery of other retirement costs for long-lived assets that it does not have a legal obligation to retire. Accordingly, the accumulated removal costs for these obligations are reflected in the balance sheets as a regulatory liability and amounts to be recovered are reflected in the balance sheet as a regulatory asset. The liability for AROs primarily relates to facilities that are subject to the Disposal of Coal Combustion Residuals from Electric Utilities final rule published by the EPA in April 2015 (CCR Rule), principally ash ponds, and the decommissioning of the Southern Company system’s nuclear facilities – Alabama Power’s Plant Farley and Georgia Power’s ownership interests in Plant Hatch and Plant Vogtle Units 1 and 2. In addition, the Southern Company system has retirement obligations related to various landfill sites, asbestos removal, mine reclamation, land restoration related to solar and wind facilities, and disposal of polychlorinated biphenyls in certain transformers. The Southern Company system also has identified retirement obligations related to certain electric transmission and distribution facilities, certain wireless communication towers, property associated with the Southern Company system’s rail lines and natural gas pipelines, and certain structures authorized by the U.S. Army Corps of Engineers. However, liabilities for the removal of these assets have not been recorded as the fair value of the retirement obligations cannot be reasonably estimated. A liability for these AROs will be recognized when sufficient information becomes available to support a reasonable estimation of the ARO. The Company will continue to recognize in the statements of income allowed removal costs in accordance with regulatory treatment. Any differences between costs recognized in accordance with accounting standards related to asset retirement and environmental obligations and those reflected in rates are recognized as either a regulatory asset or liability, as ordered by the various state PSCs, and are reflected in the balance sheets. See “Nuclear Decommissioning” herein for additional information on amounts included in rates. Details of the AROs included in the balance sheets are as follows: Balance at beginning of year Liabilities incurred Liabilities settled Accretion Cash flow revisions Balance at end of year 2016 2015 (in millions) $ 3,759 66 (171) 162 698 $ 4,514 $ $ 2,201 662 (37) 115 818 3,759 The increases in cash flow revisions and liabilities incurred in 2016 primarily relate to changes in ash pond closure strategy. The cash flow revisions in 2015 are primarily related to an increase in AROs associated with facilities impacted by the CCR Rule and Georgia Power’s updated nuclear decommissioning study. The cost estimates for AROs related to the CCR Rule are based on information as of December 31, 2016 using various assumptions related to closure and post-closure costs, timing of future cash outlays, inflation and discount rates, and the potential methods for complying with the CCR Rule requirements for closure. As further analysis is performed, including evaluation of the expected method of compliance, refinement of assumptions underlying the cost estimates, such as the quantities of CCR at each site, and the determination of timing with respect to compliance activities, including the potential for closing ash ponds prior to the end of their currently anticipated useful life, the traditional electric operating companies expect to continue to periodically update these estimates. Southern Company 2016 Annual Report Notes to Financial Statements 67 Nuclear Decommissioning The NRC requires licensees of commercial nuclear power reactors to establish a plan for providing reasonable assurance of funds for future decommissioning. Alabama Power and Georgia Power have external trust funds (Funds) to comply with the NRC’s regulations. Use of the Funds is restricted to nuclear decommissioning activities. The Funds are managed and invested in accordance with applicable requirements of various regulatory bodies, including the NRC, the FERC, and state PSCs, as well as the IRS. While Alabama Power and Georgia Power are allowed to prescribe an overall investment policy to the Funds’ managers, neither Southern Company nor its subsidiaries or affiliates are allowed to engage in the day-to-day management of the Funds or to mandate individual investment decisions. Day-to-day management of the investments in the Funds is delegated to unrelated third party managers with oversight by the management of Southern Company, Alabama Power, and Georgia Power. The Funds’ managers are authorized, within certain investment guidelines, to actively buy and sell securities at their own discretion in order to maximize the return on the Funds’ investments. The Funds are invested in a tax-efficient manner in a diversified mix of equity and fixed income securities and are reported as trading securities. Southern Company records the investment securities held in the Funds at fair value, as disclosed in Note 10, as management believes that fair value best represents the nature of the Funds. Gains and losses, whether realized or unrealized, are recorded in the regulatory liability for AROs in the balance sheets and are not included in net income or OCI. Fair value adjustments and realized gains and losses are determined on a specific identification basis. The Funds at Georgia Power participate in a securities lending program through the managers of the Funds. Under this program, the Funds’ investment securities are loaned to institutional investors for a fee. Securities loaned are fully collateralized by cash, letters of credit, and/or securities issued or guaranteed by the U.S. government or its agencies or instrumentalities. As of December 31, 2016 and 2015, approximately $56 million and $76 million, respectively, of the fair market value of the Funds’ securities were on loan and pledged to creditors under the Funds’ managers’ securities lending program. The fair value of the collateral received was approximately $58 million and $78 million at December 31, 2016 and 2015, respectively, and can only be sold by the borrower upon the return of the loaned securities. The collateral received is treated as a non-cash item in the statements of cash flows. At December 31, 2016, investment securities in the Funds totaled $1.6 billion, consisting of equity securities of $878 million, debt securities of $685 million, and $41 million of other securities. At December 31, 2015, investment securities in the Funds totaled $1.5 billion, consisting of equity securities of $817 million, debt securities of $654 million, and $38 million of other securities. These amounts include the investment securities pledged to creditors and collateral received and exclude receivables related to investment income and pending investment sales and payables related to pending investment purchases and the lending pool. Sales of the securities held in the Funds resulted in cash proceeds of $1.2 billion, $1.4 billion, and $0.9 billion in 2016, 2015, and 2014, respectively, all of which were reinvested. For 2016, fair value increases, including reinvested interest and dividends and excluding the Funds’ expenses, were $114 million, which included $48 million related to unrealized gains on securities held in the Funds at December 31, 2016. For 2015, fair value increases, including reinvested interest and dividends and excluding the Funds’ expenses, were $11 million, which included $83 million related to unrealized losses on securities held in the Funds at December 31, 2015. For 2014, fair value increases, including reinvested interest and dividends and excluding the Funds’ expenses, were $98 million, which included $19 million related to unrealized gains and losses on securities held in the Funds at December 31, 2014. While the investment securities held in the Funds are reported as trading securities, the Funds continue to be managed with a long-term focus. Accordingly, all purchases and sales within the Funds are presented separately in the statements of cash flows as investing cash flows, consistent with the nature of the securities and purpose for which the securities were acquired. For Alabama Power, approximately $19 million and $20 million at December 31, 2016 and 2015, respectively, previously recorded in internal reserves is being transferred into the Funds through 2040 as approved by the Alabama PSC. The NRC’s minimum external funding requirements are based on a generic estimate of the cost to decommission only the radioactive portions of a nuclear unit based on the size and type of reactor. Alabama Power and Georgia Power have filed plans with the NRC designed to ensure that, over time, the deposits and earnings of the Funds will provide the minimum funding amounts prescribed by the NRC. At December 31, 2016 and 2015, the accumulated provisions for the external decommissioning trust funds were as follows: Plant Farley Plant Hatch Plant Vogtle Units 1 and 2 External Trust Funds 2016 2015 (in millions) $ 790 511 303 $ 734 487 288 Site study cost is the estimate to decommission a specific facility as of the site study year. The decommissioning cost estimates are based on prompt dismantlement and removal of the plant from service. The actual decommissioning costs may vary from these estimates because of changes in the assumed date of decommissioning, changes in NRC requirements, or changes in the investor.southerncompany.com 68 Notes to Financial Statements assumptions used in making these estimates. The estimated costs of decommissioning as of December 31, 2016 based on the most current studies, which were performed in 2013 for Alabama Power’s Plant Farley and in 2015 for the Georgia Power plants, were as follows for Alabama Power’s Plant Farley and Georgia Power’s ownership interests in Plant Hatch and Plant Vogtle Units 1 and 2: Decommissioning periods: Beginning year Completion year Site study costs: Radiated structures Spent fuel management Non-radiated structures Total site study costs Plant Farley Plant Hatch Plant Vogtle Units 1 and 2 2037 2076 $ $ 1,362 — 80 1,442 2034 2075 (in millions) $ $ 678 160 64 902 2047 2079 $ $ 568 147 89 804 For ratemaking purposes, Alabama Power’s decommissioning costs are based on the site study, and Georgia Power’s decommissioning costs are based on the NRC generic estimate to decommission the radioactive portion of the facilities and the site study estimate for spent fuel management as of 2012. Under the 2013 ARP, the Georgia PSC approved Georgia Power’s annual decommissioning cost for ratemaking of $4 million and $2 million for Plant Hatch and Plant Vogtle Units 1 and 2, respectively. Georgia Power expects the Georgia PSC to review and adjust, if necessary, the amounts collected in rates for nuclear decommissioning costs in Georgia Power’s 2019 base rate case. Significant assumptions used to determine these costs for ratemaking were an inflation rate of 4.5% and 2.4% for Alabama Power and Georgia Power, respectively, and a trust earnings rate of 7.0% and 4.4% for Alabama Power and Georgia Power, respectively. Amounts previously contributed to the Funds for Plant Farley are currently projected to be adequate to meet the decommissioning obligations. Alabama Power will continue to provide site-specific estimates of the decommissioning costs and related projections of funds in the external trust to the Alabama PSC and, if necessary, would seek the Alabama PSC’s approval to address any changes in a manner consistent with NRC and other applicable requirements. Allowance for Funds Used During Construction and Interest Capitalized The traditional electric operating companies and certain of the natural gas distribution utilities record AFUDC, which represents the estimated debt and equity costs of capital funds that are necessary to finance the construction of new regulated facilities. While cash is not realized currently, AFUDC increases the revenue requirement and is recovered over the service life of the plant through a higher rate base and higher depreciation. The equity component of AFUDC is not included in calculating taxable income. Interest related to the construction of new facilities not included in the traditional electric operating companies’ and natural gas distribution utilities’ regulated rates is capitalized in accordance with standard interest capitalization requirements. AFUDC and interest capitalized, net of income taxes were 11.4%, 12.8%, and 16.0% of net income for 2016, 2015, and 2014, respectively. Cash payments for interest totaled $1.1 billion, $809 million, and $732 million in 2016, 2015, and 2014, respectively, net of amounts capitalized of $125 million, $124 million, and $111 million, respectively. Impairment of Long-Lived Assets Southern Company evaluates long-lived assets for impairment when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable. The determination of whether an impairment has occurred is based on either a specific regulatory disallowance or an estimate of undiscounted future cash flows attributable to the assets, as compared with the carrying value of the assets. If an impairment has occurred, the amount of the impairment recognized is determined by either the amount of regulatory disallowance or by estimating the fair value of the assets and recording a loss if the carrying value is greater than the fair value. For assets identified as held for sale, the carrying value is compared to the estimated fair value less the cost to sell in order to determine if an impairment loss is required. Until the assets are disposed of, their estimated fair value is re-evaluated when circumstances or events change. See Note 3 under “Integrated Coal Gasification Combined Cycle – Kemper IGCC Schedule and Cost Estimate” for additional information. Goodwill and Other Intangible Assets and Liabilities At December 31, 2016 and 2015, goodwill was $6.3 billion and $2 million, respectively. The increase in goodwill relates to Southern Company’s acquisitions of PowerSecure and Southern Company Gas. See Note 12 under “Southern Company – Acquisition of PowerSecure” and “– Merger with Southern Company Gas” for additional information. Southern Company 2016 Annual Report Goodwill is not amortized, but is subject to an annual impairment test during the fourth quarter of each year, or more frequently if impairment indicators arise. Southern Company evaluated its goodwill in the fourth quarter 2016 and determined that no impairment was required. At December 31, 2016, other intangible assets were as follows: Notes to Financial Statements 69 Other intangible assets subject to amortization: Customer relationships Trade names Patents Backlog Storage and transportation contracts Software and other PPA fair value adjustments Total other intangible assets subject to amortization Other intangible assets not subject to amortization: Federal Communications Commission licenses Total other intangible assets Estimated Useful Life Gross Carrying Amount Accumulated Amortization (in millions) Other Intangible Assets, Net 11-26 years 5-28 years 3-10 years 5 years 1-5 years 1-12 years 19-20 years $ $ $ 268 158 4 5 64 2 456 957 75 1,032 $ $ $ (32) (5) — (1) (2) — (22) (62) — (62) $ $ $ 236 153 4 4 62 2 434 895 75 970 At December 31, 2015, other intangible assets consisted of Southern Power’s PPA fair value adjustments with a net carrying amount of $317 million. The increase in other intangible assets primarily relates to Southern Company’s acquisitions of PowerSecure and Southern Company Gas, as well as additional PPA fair value adjustments resulting from Southern Power’s acquisitions. Amortization associated with other intangible assets in 2016, 2015, and 2014 was $50 million, $3 million, and $3 million, respectively. As of December 31, 2016, the estimated amortization associated with other intangible assets is as follows: 2017 2018 2019 2020 2021 Amortization (in millions) $ 108 93 74 63 56 Included in other deferred credits and liabilities on the balance sheet is $91 million of intangible liabilities that were recorded during acquisition accounting for transportation contracts at Southern Company Gas. At December 31, 2016, the accumulated amortization of these intangible liabilities was $21 million. The estimated amortization associated with the intangible liabilities that will be recorded in natural gas revenues is as follows: 2017 2018 2019 Amortization (in millions) $ 29 24 17 See Note 12 under “Southern Company – Acquisition of PowerSecure” and “– Merger with Southern Company Gas” for additional information. Also see Note 12 under “Southern Power” for additional information regarding Southern Power’s PPA fair value adjustments. Storm Damage Reserves Each traditional electric operating company maintains a reserve to cover or is allowed to defer and recover the cost of damages from major storms to its transmission and distribution lines and generally the cost of uninsured damages to its generation facilities and other property. In accordance with their respective state PSC orders, the traditional electric operating companies accrued $40 million in each of 2016, 2015, and 2014. Alabama Power, Gulf Power, and Mississippi Power also have authority based on orders from their state PSCs to accrue certain additional amounts as circumstances warrant. In 2016, 2015, and 2014, investor.southerncompany.com 70 Notes to Financial Statements there were no such additional accruals. See Note 3 under “Regulatory Matters – Alabama Power – Rate NDR” and “Regulatory Matters – Georgia Power – Storm Damage Recovery” for additional information regarding Alabama Power’s NDR and Georgia Power’s deferred storm costs, respectively. Leveraged Leases Southern Company has several leveraged lease agreements, with original terms ranging up to 45 years, which relate to international and domestic energy generation, distribution, and transportation assets. Southern Company receives federal income tax deductions for depreciation and amortization, as well as interest on long-term debt related to these investments. Southern Company reviews all important lease assumptions at least annually, or more frequently if events or changes in circumstances indicate that a change in assumptions has occurred or may occur. These assumptions include the effective tax rate, the residual value, the credit quality of the lessees, and the timing of expected tax cash flows. Southern Company’s net investment in domestic and international leveraged leases consists of the following at December 31: 2016 2015 Net rentals receivable Unearned income Investment in leveraged leases Deferred taxes from leveraged leases Net investment in leveraged leases A summary of the components of income from the leveraged leases follows: $ $ (in millions) $ 1,481 (707) 774 (309) 465 1,487 (732) 755 (303) 452 $ Pretax leveraged lease income Income tax expense Net leveraged lease income Cash and Cash Equivalents 2016 2015 2014 $ 25 (9) 16 $ (in millions) $ $ 20 (7) 13 $ $ 24 (9) 15 For purposes of the financial statements, temporary cash investments are considered cash equivalents. Temporary cash investments are securities with original maturities of 90 days or less. Materials and Supplies Generally, materials and supplies include the average cost of transmission, distribution, and generating plant materials. Materials are charged to inventory when purchased and then expensed or capitalized to plant, as appropriate, at weighted average cost when installed. Fuel Inventory Fuel inventory includes the average cost of coal, natural gas, oil, transportation, and emissions allowances of the electric utilities. Fuel is recorded to inventory when purchased and then expensed, at weighted average cost, as used and recovered by the traditional electric operating companies through fuel cost recovery rates approved by each state PSC. Emissions allowances granted by the EPA are included in inventory at zero cost. Natural Gas for Sale The natural gas distribution utilities, with the exception of Nicor Gas, carry natural gas inventory on a weighted average cost of gas (WACOG) basis. Nicor Gas’ natural gas inventory is carried at cost on a last-in, first-out (LIFO) basis. Inventory decrements occurring during the year that are restored prior to year-end are charged to cost of natural gas at the estimated annual replacement cost. Inventory decrements that are not restored prior to year-end are charged to cost of natural gas at the actual LIFO cost of the inventory layers liquidated. The cost of natural gas, including inventory costs, is recovered from customers under a purchased gas recovery mechanism adjusted for differences between actual costs and amounts billed; therefore, LIFO liquidations have no impact on Southern Company’s net income. Natural gas inventories for Southern Company Gas’ non-utility businesses are carried at the lower of weighted average cost or current market price, with cost determined on a WACOG basis. For any declines in market prices below the WACOG considered to be other than temporary, an adjustment is recorded to reduce the value of natural gas inventories to market value. Southern Company 2016 Annual Report Notes to Financial Statements 71 Financial Instruments Southern Company and its subsidiaries use derivative financial instruments to limit exposure to fluctuations in interest rates, the prices of certain fuel purchases, electricity purchases and sales, and occasionally foreign currency exchange rates. All derivative financial instruments are recognized as either assets or liabilities on the balance sheets (included in “Other” or shown separately as “Risk Management Activities”) and are measured at fair value. See Note 10 for additional information regarding fair value. Substantially all of the Southern Company system’s bulk energy purchases and sales contracts that meet the definition of a derivative are excluded from fair value accounting requirements because they qualify for the “normal” scope exception, and are accounted for under the accrual method. Derivative contracts that qualify as cash flow hedges of anticipated transactions or are recoverable through the traditional electric operating companies’ and the natural gas distribution utilities’ fuel-hedging programs result in the deferral of related gains and losses in OCI or regulatory assets and liabilities, respectively, until the hedged transactions occur. Any ineffectiveness arising from cash flow hedges is recognized currently in net income. Other derivative contracts that qualify as fair value hedges are marked to market through current period income and are recorded on a net basis in the statements of income. Cash flows from derivatives are classified on the statements of cash flows in the same category as the hedged item. See Note 11 for additional information regarding derivatives. Beginning in 2016, the Company offsets fair value amounts recognized for multiple derivative instruments executed with the same counterparty under a master netting arrangement. At December 31, 2016, the amount included in accounts payable in the balance sheets that the Company has recognized for the obligation to return cash collateral arising from derivative instruments was immaterial. Southern Company is exposed to losses related to financial instruments in the event of counterparties’ nonperformance. The Company has established controls to determine and monitor the creditworthiness of counterparties in order to mitigate the Company’s exposure to counterparty credit risk. Comprehensive Income The objective of comprehensive income is to report a measure of all changes in common stock equity of an enterprise that result from transactions and other economic events of the period other than transactions with owners. Comprehensive income consists of net income, changes in the fair value of qualifying cash flow hedges and marketable securities, certain changes in pension and other postretirement benefit plans, reclassifications for amounts included in net income, and dividends on preferred and preference stock of subsidiaries. Accumulated OCI (loss) balances, net of tax effects, were as follows: Qualifying Hedges Marketable Securities Pension and Other Postretirement Benefit Plans Accumulated Other Comprehensive Income (Loss) $ $ (48) (67) (115) $ $ (in millions) — $ — — $ (82) 17 (65) $ $ (130) (50) (180) Balance at December 31, 2015 Current period change Balance at December 31, 2016 2. RETIREMENT BENEFITS Southern Company has a defined benefit, trusteed, pension plan covering substantially all employees, with the exception of employees at Southern Company Gas, as discussed below, and PowerSecure. This qualified pension plan is funded in accordance with requirements of the Employee Retirement Income Security Act of 1974, as amended (ERISA). On December 19, 2016, the traditional electric operating companies and certain other subsidiaries voluntarily contributed an aggregate of $900 million to Southern Company’s qualified pension plan. No mandatory contributions to the qualified pension plan are anticipated for the year ending December 31, 2017. Southern Company also provides certain defined benefit pension plans for a selected group of management and highly compensated employees. Benefits under these non-qualified pension plans are funded on a cash basis. In addition, Southern Company provides certain medical care and life insurance benefits for retired employees through other postretirement benefit plans. The traditional electric operating companies fund related other postretirement trusts to the extent required by their respective regulatory commissions. For the year ending December 31, 2017, no other postretirement trust contributions are expected. In addition, Southern Company Gas has a qualified defined benefit, trusteed, pension plan covering certain eligible employees, which was closed in 2012 to new employees. This qualified pension plan is funded in accordance with requirements of ERISA. Southern Company Gas voluntarily contributed $125 million to its qualified pension plan on September 12, 2016. No mandatory contributions to the Southern Company Gas qualified pension plan are anticipated for the year ending December 31, 2017. Southern Company Gas also provides certain non-qualified defined benefit and defined contribution pension plans for a selected group of management and highly compensated employees. Benefits under these non-qualified pension plans are investor.southerncompany.com 72 Notes to Financial Statements funded on a cash basis. In addition, Southern Company Gas provides certain medical care and life insurance benefits for eligible retired employees through a postretirement benefit plan. Southern Company Gas also has a separate unfunded supplemental retirement health care plan that provides medical care and life insurance benefits to employees of discontinued businesses. For the year ending December 31, 2017, no other postretirement trust contributions are expected. Actuarial Assumptions The weighted average rates assumed in the actuarial calculations used to determine both the net periodic costs for the pension and other postretirement benefit plans for the following year and the benefit obligations as of the measurement date are presented below. Assumptions used to determine net periodic costs: Pension plans Discount rate – benefit obligations Discount rate – interest costs Discount rate – service costs Expected long-term return on plan assets Annual salary increase Other postretirement benefit plans Discount rate – benefit obligations Discount rate – interest costs Discount rate – service costs Expected long-term return on plan assets Annual salary increase Assumptions used to determine benefit obligations: Pension plans Discount rate Annual salary increase Other postretirement benefit plans Discount rate Annual salary increase 2016 2015 2014 4.58% 3.88 4.98 8.16 4.37 4.38% 3.66 4.85 6.66 4.37 4.17% 4.17 4.48 8.20 3.59 4.04% 4.04 4.39 6.97 3.59 5.02% 5.02 5.02 8.20 3.59 4.85% 4.85 4.85 7.15 3.59 2016 2015 4.40% 4.37 4.23% 4.37 4.67% 4.46 4.51% 4.46 The Company estimates the expected rate of return on pension plan and other postretirement benefit plan assets using a financial model to project the expected return on each current investment portfolio. The analysis projects an expected rate of return on each of seven different asset classes in order to arrive at the expected return on the entire portfolio relying on each trust’s target asset allocation and reasonable capital market assumptions. The financial model is based on four key inputs: anticipated returns by asset class (based in part on historical returns), each trust’s target asset allocation, an anticipated inflation rate, and the projected impact of a periodic rebalancing of each trust’s portfolio. An additional assumption used in measuring the accumulated other postretirement benefit obligations (APBO) was a weighted average medical care cost trend rate. The weighted average medical care cost trend rates used in measuring the APBO as of December 31, 2016 were as follows: Pre-65 Post-65 medical Post-65 prescription Initial Cost Trend Rate Ultimate Cost Trend Rate 6.50% 5.00 10.00 4.50% 4.50 4.50 Year That Ultimate Rate is Reached 2025 2025 2025 An annual increase or decrease in the assumed medical care cost trend rate of 1% would affect the APBO and the service and interest cost components at December 31, 2016 as follows: Benefit obligation Service and interest costs 1 Percent Increase 1 Percent Decrease $ (in millions) 128 4 $ 110 3 Southern Company 2016 Annual Report Pension Plans The total accumulated benefit obligation for the pension plans was $11.3 billion at December 31, 2016 and $9.6 billion at December 31, 2015. Changes in the projected benefit obligations and the fair value of plan assets during the plan years ended December 31, 2016 and 2015 were as follows: Notes to Financial Statements 73 Change in benefit obligation Benefit obligation at beginning of year Acquisitions Service cost Interest cost Benefits paid Actuarial (gain) loss Balance at end of year Change in plan assets Fair value of plan assets at beginning of year Acquisitions Actual return (loss) on plan assets Employer contributions Benefits paid Fair value of plan assets at end of year Accrued liability 2016 2015 (in millions) $ $ 10,542 1,244 262 422 (466) 381 12,385 9,234 837 902 1,076 (466) 11,583 (802) $ 10,909 — 257 445 (487) (582) 10,542 9,690 — (14) 45 (487) 9,234 $ (1,308) At December 31, 2016, the projected benefit obligations for the qualified and non-qualified pension plans were $11.8 billion and $627 million, respectively. All pension plan assets are related to the qualified pension plans. Amounts presented in the following tables do not include regulatory assets of $369 million recognized by Southern Company Gas associated with its pension plans prior to its acquisition on July 1, 2016. Amounts recognized in the balance sheets at December 31, 2016 and 2015 related to the Company’s pension plans consist of the following: Other regulatory assets, deferred Other current liabilities Employee benefit obligations Other regulatory liabilities, deferred Accumulated OCI 2016 2015 (in millions) $ 3,207 (53) (749) (87) 100 $ 2,998 (46) (1,262) — 125 Presented below are the amounts included in accumulated OCI and regulatory assets at December 31, 2016 and 2015 related to the defined benefit pension plans that had not yet been recognized in net periodic pension cost along with the estimated amortization of such amounts for 2017. Balance at December 31, 2016: Accumulated OCI Regulatory assets Total Balance at December 31, 2015: Accumulated OCI Regulatory assets Total Estimated amortization in net periodic pension cost in 2017: Accumulated OCI Regulatory assets Total Prior Service Cost Net (Gain) Loss (in millions) $ 4 51 $ 55 $ $ $ $ 3 27 30 1 11 12 $ $ $ $ $ $ 96 3,069 3,165 122 2,971 3,093 7 155 162 investor.southerncompany.com 74 Notes to Financial Statements The components of OCI and the changes in the balance of regulatory assets related to the defined benefit pension plans for the years ended December 31, 2016 and 2015 are presented in the following table: Balance at December 31, 2014 Net (gain) loss Reclassification adjustments: Amortization of prior service costs Amortization of net gain (loss) Total reclassification adjustments Total change Balance at December 31, 2015 Net (gain) loss Change in prior service costs Reclassification adjustments: Amortization of prior service costs Amortization of net gain (loss) Total reclassification adjustments Total change Balance at December 31, 2016 Regulatory Assets Accumulated OCI (in millions) 134 1 $ $ 3,073 155 (24) (206) (230) (75) 2,998 243 37 (13) (145) (158) 122 3,120 $ $ (1) (9) (10) (9) 125 (20) 2 (1) (6) (7) (25) 100 $ $ Components of net periodic pension cost were as follows: Service cost Interest cost Expected return on plan assets Recognized net (gain) loss Net amortization Net periodic pension cost 2016 262 422 (782) 150 14 66 $ $ 2015 (in millions) $ $ 257 445 (724) 215 25 218 2014 213 435 (645) 110 26 139 $ $ Net periodic pension cost is the sum of service cost, interest cost, and other costs netted against the expected return on plan assets. The expected return on plan assets is determined by multiplying the expected rate of return on plan assets and the market-related value of plan assets. In determining the market-related value of plan assets, the Company has elected to amortize changes in the market value of all plan assets over five years rather than recognize the changes immediately. As a result, the accounting value of plan assets that is used to calculate the expected return on plan assets differs from the current fair value of the plan assets. Future benefit payments reflect expected future service and are estimated based on assumptions used to measure the projected benefit obligation for the pension plans. At December 31, 2016, estimated benefit payments were as follows: 2017 2018 2019 2020 2021 2022 to 2026 Benefit Payments (in millions) $ 571 593 620 646 666 3,673 Southern Company 2016 Annual Report Other Postretirement Benefits Changes in the APBO and in the fair value of plan assets during the plan years ended December 31, 2016 and 2015 were as follows: Notes to Financial Statements 75 Change in benefit obligation Benefit obligation at beginning of year Acquisitions Service cost Interest cost Benefits paid Actuarial (gain) loss Plan amendments Retiree drug subsidy Balance at end of year Change in plan assets Fair value of plan assets at beginning of year Acquisitions Actual return (loss) on plan assets Employer contributions Benefits paid Fair value of plan assets at end of year Accrued liability 2016 2015 (in millions) $ $ 1,989 338 22 76 (119) (16) — 7 2,297 833 100 58 65 (112) 944 (1,353) $ $ 1,986 — 23 78 (102) (38) 34 8 1,989 900 — (12) 39 (94) 833 (1,156) Amounts presented in the following tables do not include regulatory assets of $77 million recognized by Southern Company Gas associated with its other postretirement benefit plan prior to its acquisition on July 1, 2016. Amounts recognized in the balance sheets at December 31, 2016 and 2015 related to the Company’s other postretirement benefit plans consist of the following: Other regulatory assets, deferred Other current liabilities Employee benefit obligations Other regulatory liabilities, deferred Accumulated OCI $ 2016 2015 (in millions) 419 $ (4) (1,349) (41) 7 433 (4) (1,152) (22) 8 Presented below are the amounts included in accumulated OCI and net regulatory assets (liabilities) at December 31, 2016 and 2015 related to the other postretirement benefit plans that had not yet been recognized in net periodic other postretirement benefit cost along with the estimated amortization of such amounts for 2017. Balance at December 31, 2016: Accumulated OCI Net regulatory assets Total Balance at December 31, 2015: Accumulated OCI Net regulatory assets Total Estimated amortization as net periodic postretirement benefit cost in 2017: Net regulatory assets Prior Service Cost Net (Gain) Loss (in millions) $ — 25 $ 25 $ — 32 32 $ $ 6 $ 7 353 $ 360 $ $ $ 8 379 387 13 investor.southerncompany.com 76 Notes to Financial Statements The components of OCI, along with the changes in the balance of net regulatory assets (liabilities), related to the other postretirement benefit plans for the plan years ended December 31, 2016 and 2015 are presented in the following table: Accumulated OCI Net Regulatory Assets (Liabilities) (in millions) Balance at December 31, 2014 Net (gain) loss Change in prior service costs Reclassification adjustments: Amortization of prior service costs Amortization of net gain (loss) Total reclassification adjustments Total change Balance at December 31, 2015 Net (gain) loss Reclassification adjustments: Amortization of prior service costs Amortization of net gain (loss) Total reclassification adjustments Total change Balance at December 31, 2016 Components of the other postretirement benefit plans’ net periodic cost were as follows: Service cost Interest cost Expected return on plan assets Net amortization Net periodic postretirement benefit cost $ $ $ $ $ 8 — — — — — — 8 (1) — — — (1) 7 2016 22 76 (60) 21 59 $ 2015 (in millions) 23 78 (58) 21 64 $ $ $ 366 33 33 (4) (17) (21) 45 411 (13) (6) (14) (20) (33) $ 378 2014 21 79 (59) 6 47 $ $ Future benefit payments, including prescription drug benefits, reflect expected future service and are estimated based on assumptions used to measure the APBO for the other postretirement benefit plans. Estimated benefit payments are reduced by drug subsidy receipts expected as a result of the Medicare Prescription Drug, Improvement, and Modernization Act of 2003 as follows: 2017 2018 2019 2020 2021 2022 to 2026 Benefit Plan Assets Benefit Payments Subsidy Receipts Total (in millions) $ $ 145 150 155 159 162 823 (10) (11) (12) (13) (14) (73) $ 135 139 143 146 148 750 Pension plan and other postretirement benefit plan assets are managed and invested in accordance with all applicable requirements, including ERISA and the Internal Revenue Code of 1986, as amended (Internal Revenue Code). The Company’s investment policies for both the pension plans and the other postretirement benefit plans cover a diversified mix of assets as described below. Derivative instruments may be used to gain efficient exposure to the various asset classes and as hedging tools. Additionally, the Company minimizes the risk of large losses primarily through diversification but also monitors and manages other aspects of risk. The investment strategy for plan assets related to the Company’s qualified pension plans is to be broadly diversified across major asset classes. The asset allocation is established after consideration of various factors that affect the assets and liabilities of the pension plan including, but not limited to, historical and expected returns and interest rates, volatility, correlations of asset classes, the current level of assets and liabilities, and the assumed growth in assets and liabilities. Because a significant Southern Company 2016 Annual Report Notes to Financial Statements 77 portion of the liability of the pension plans is long-term in nature, the assets are invested consistent with long-term investment expectations for return and risk. To manage the actual asset class exposures relative to the target asset allocation, the Southern Company plan employs a formal rebalancing program. As additional risk management, external investment managers and service providers are subject to written guidelines to ensure appropriate and prudent investment practices. Investment Strategies and Benefit Plan Asset Fair Values A description of the major asset classes that the pension and other postretirement benefit plans are comprised of, along with the valuation methods used for fair value measurement, is provided below: Description • Domestic equity: A mix of large and small capitalization stocks with generally an equal distribution of value and growth attributes, managed both actively and through passive index approaches. • • • • International equity: A mix of growth stocks and value stocks with both developed and emerging market exposure, managed both actively and through passive index approaches. Fixed income: A mix of domestic and international bonds. Trust-owned life insurance (TOLI): Investments of the Company’s taxable trusts aimed at minimizing the impact of taxes on the portfolio. Special situations: Investments in opportunistic strategies with the objective of diversifying and enhancing returns and exploiting short-term inefficiencies, as well as investments in promising new strategies of a longer-term nature. • Real estate: Investments in traditional private market, equity-oriented investments in real properties (indirectly through pooled funds or partnerships) and in publicly traded real estate securities. • Private equity: Investments in private partnerships that invest in private or public securities typically through privately-negotiated and/or structured transactions, including leveraged buyouts, venture capital, and distressed debt. Valuation Methodology Domestic and International equities such as common stocks, American depositary receipts, and real estate investment trusts that trade on public exchanges are classified as Level 1 investments and are valued at the closing price in the active market. Equity funds with unpublished prices are valued as Level 2 when the underlying holdings are comprised of Level 1 or Level 2 equity securities. Investments in fixed income securities are generally classified as Level 2 investments and are valued based on prices reported in the market place. Additionally, the value of fixed income securities takes into consideration certain items such as broker quotes, spreads, yield curves, interest rates, and discount rates that apply to the term of a specific instrument. Investments in TOLI policies are classified as Level 2 investments and are valued based on the underlying investments held in the policy’s separate accounts. The underlying assets are equity and fixed income pooled funds that are comprised of Level 1 and Level 2 securities. Investments in real estate, private equity, and special situations are generally classified as Net Asset Value as a Practical Expedient, since the underlying assets typically do not have publicly available observable inputs. The fund manager values the assets using various inputs and techniques depending on the nature of the underlying investments. Techniques may include purchase multiples for comparable transactions, comparable public company trading multiples, discounted cash flow analysis, prevailing market capitalization rates, recent sales of comparable investments, and independent third-party appraisals. The fair value of partnerships is determined by aggregating the value of the underlying assets less liabilities. The fair values, and actual allocations relative to the target allocations, of Southern Company’s pension plan (excluding Southern Company Gas) as of December 31, 2016 and 2015 are presented below. The fair values presented are prepared in accordance with GAAP. For purposes of determining the fair value of the pension plan and other postretirement benefit plan assets and the appropriate level designation, management relies on information provided by the plan’s trustee. This information is reviewed and evaluated by management with changes made to the trustee information as appropriate. These fair values exclude cash, receivables related to investment income and pending investment sales, and payables related to pending investment purchases. investor.southerncompany.com 78 Notes to Financial Statements As of December 31, 2016: Assets: Domestic equity(*) International equity(*) Fixed income: U.S. Treasury, government, and agency bonds Mortgage- and asset- backed securities Corporate bonds Pooled funds Cash equivalents and other Fair Value Measurements Using Quoted Prices in Active Markets for Identical Assets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Net Asset Value as a Practical Expedient (NAV) (in millions) Target Allocation Actual Allocation Total $ 2,010 1,231 $ 927 1,110 $ — $ — — $ — 2,937 2,341 26% 25 23 29% 22 29 — — — — 588 13 991 524 — — — — — — — — 588 13 991 524 2 — — — 4,155 996 310 — — $ 4,547 — — — 1,152 180 549 1,881 $ 998 1,462 180 549 10,583 Real estate investments Special situations Private equity Total 13 2 5 100% (*) Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is 14 3 9 100% — $ — $ $ well-diversified with no significant concentrations of risk. Fair Value Measurements Using Quoted Prices in Active Markets for Identical Assets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Net Asset Value as a Practical Expedient (NAV) (in millions) Target Allocation Actual Allocation Total $ 1,632 1,190 $ 681 962 $ — $ — — $ — 2,313 2,152 26% 25 23 30% 23 23 — — — — — 299 — — 3,121 $ 454 199 1,140 500 145 — — — 4,081 $ — — — — — — — — — — — — $ — $ — 1,185 160 536 1,881 $ 454 199 1,140 500 145 1,484 160 536 9,083 14 3 9 100% 16 2 6 100% As of December 31, 2015: Assets: Domestic equity(a) International equity(a) Fixed income: U.S. Treasury, government, and agency bonds Mortgage- and asset- backed securities Corporate bonds Pooled funds Cash equivalents and other Real estate investments Special situations(b) Private equity Total Liabilities: Derivatives Total 100% (a) Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is 100% $ $ (1) 3,120 $ $ — 4,081 $ — $ $ — $ — $ 1,881 $ (1) 9,082 well-diversified with no significant concentrations of risk. (b) The 2015 presentation above has been revised to separately reflect special situations, consistent with the 2016 presentation. Southern Company 2016 Annual Report The fair values of Southern Company Gas’ pension plan assets for the period ended December 31, 2016 are presented below. The fair value measurements exclude cash, receivables related to investment income, pending investment sales, and payables related to pending investment purchases. For 2016, special situations (absolute return and hedge funds) investment assets are presented in the tables below based on the nature of the investment. Notes to Financial Statements 79 Fair Value Measurements Using Quoted Prices in Active Markets for Identical Assets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Net Asset Value as a Practical Expedient (NAV) (in millions) Total $ 142 — $ 343 185 $ — — $ — $ — 485 185 As of December 31, 2016: Assets: Domestic equity(*) International equity(*) Fixed income: U.S. Treasury, government, and agency bonds Corporate bonds Pooled funds Cash equivalents and other 85 41 66 100 19 2 983 (*) Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is Real estate investments Private equity Total — — — — — — $ — — — — 83 15 2 100 85 41 66 5 — — 725 — — — 12 4 — 158 $ $ $ $ well-diversified with no significant concentrations of risk. The assets of Southern Company Gas’ pension plan were allocated 69% equity, 20% fixed income, 1% cash, and 10% other at December 31, 2016, compared to the asset class targets of 53% equity, 15% fixed income, 2% cash, and 30% other. Southern Company Gas’ pension plan investment policy provides for variation around the target asset allocation in the form of ranges. The fair values of Southern Company’s (excluding Southern Company Gas) other postretirement benefit plan assets as of December 31, 2016 and 2015 are presented below. These fair value measurements exclude cash, receivables related to investment income, pending investment sales, and payables related to pending investment purchases. Fair Value Measurements Using Quoted Prices in Active Markets for Identical Assets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Net Asset Value as a Practical Expedient (NAV) (in millions) Target Allocation Actual Allocation Total $ 118 37 $ — — — 28 61 24 30 49 $ — — $ — $ — 146 98 39% 23 29 40% 21 31 — — — — — — 24 30 49 As of December 31, 2016: Assets: Domestic equity(*) International equity(*) Fixed income: U.S. Treasury, government, and agency bonds Corporate bonds Pooled funds Cash equivalents and other Trust-owned life insurance Real estate investments Special situations Private equity Total 5 1 2 100% (*) Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is 5 1 3 100% $ — — — — — $ — — — 35 5 17 41 382 46 5 17 $ 57 $ 838 41 — 11 — — $ 207 — 382 — — — 574 well-diversified with no significant concentrations of risk. investor.southerncompany.com 80 Notes to Financial Statements As of December 31, 2015: Assets: Domestic equity(a) International equity(a) Fixed income: U.S. Treasury, government, and agency bonds Mortgage- and asset- backed securities Corporate bonds Pooled funds Cash equivalents and other Fair Value Measurements Using Quoted Prices in Active Markets for Identical Assets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Net Asset Value as a Practical Expedient (NAV) (in millions) Target Allocation Actual Allocation Total $ 106 40 $ — 52 63 22 $ — — $ — $ — 158 103 42% 21 28 38% 23 30 — — 22 — — — 11 — 11 — — 168 7 38 42 9 370 — — — 603 — — — — — — — — $ — 7 — 38 — 42 — 20 — 370 — 51 40 5 5 18 18 63 $ 834 Trust-owned life insurance Real estate investments Special situations(b) Private equity Total 6 1 2 100% (a) Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is 5 1 3 100% $ $ $ well-diversified with no significant concentrations of risk. (b) The 2015 presentation above has been revised to separately reflect special situations, consistent with the 2016 presentation. The fair values of Southern Company Gas’ other postretirement benefit plan assets for the period ended December 31, 2016 are presented below. These fair value measurements exclude cash, receivables related to investment income, pending investment sales, and payables related to pending investment purchases. For 2016, special situations (absolute return and hedge funds) investment assets are presented in the tables below based on the nature of the investment. Fair Value Measurements Using Quoted Prices in Active Markets for Identical Assets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) (in millions) Net Asset Value as a Practical Expedient (NAV) Total $ 3 — $ 58 18 $ — — $ — $ — 61 18 As of December 31, 2016: Assets: Domestic equity(*) International equity(*) Fixed income: Pooled funds Cash equivalents and other 23 3 105 $ (*) Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is — — $ — 23 — 99 — 2 2 — 1 4 Total $ $ $ well-diversified with no significant concentrations of risk. The assets of Southern Company Gas’ other postretirement benefit plans were allocated 74% equity, 23% fixed income, 1% cash, and 2% other at December 31, 2016, compared to the asset class targets of 72% equity, 24% fixed income, 1% cash, and 3% other. Southern Company Gas’ other postretirement plan’s investment policy provides for some variation in these targets in the form of ranges around the target. Employee Savings Plan Southern Company and its subsidiaries also sponsor 401(k) defined contribution plans covering substantially all employees and provide matching contributions up to specified percentages of an employee’s eligible pay. Total matching contributions made to the plans for 2016, 2015, and 2014 were $105 million, $92 million, and $87 million, respectively. Southern Company 2016 Annual Report Notes to Financial Statements 81 3. CONTINGENCIES AND REGULATORY MATTERS General Litigation Matters Nicor Gas and Nicor Energy Services Company, wholly-owned subsidiaries of Southern Company Gas, and Nicor Inc. are defendants in a putative class action initially filed in 2011 in state court in Cook County, Illinois. The plaintiffs purport to represent a class of the customers who purchased the Gas Line Comfort Guard product from Nicor Energy Services Company and variously allege that the marketing, sale, and billing of the Gas Line Comfort Guard product violated the Illinois Consumer Fraud and Deceptive Business Practices Act, constituting common law fraud and resulting in unjust enrichment of these entities. The plaintiffs seek, on behalf of the classes they purport to represent, actual and punitive damages, interest, costs, attorney fees, and injunctive relief. On February 8, 2017, the judge denied the plaintiffs’ motion for class certification and Southern Company Gas’ motion for summary judgment. The ultimate outcome of this matter cannot be determined at this time. On January 20, 2017, a purported securities class action complaint was filed against Southern Company and certain of its and Mississippi Power’s officers in the U.S. District Court for the Northern District of Georgia, Atlanta Division, by Monroe County Employees’ Retirement System on behalf of all persons who purchased shares of Southern Company’s common stock between April 25, 2012 and October 29, 2013. The complaint alleges that Southern Company and certain of its and Mississippi Power’s officers made materially false and misleading statements regarding the Kemper IGCC in violation of certain provisions under the Securities Exchange Act of 1934, as amended. The complaint seeks, among other things, compensatory damages and litigation costs and attorneys’ fees. Southern Company believes this legal challenge has no merit; however, an adverse outcome in this proceeding could have an impact on Southern Company’s results of operations, financial condition, and liquidity. Southern Company will vigorously defend itself in this matter, and the ultimate outcome of this matter cannot be determined at this time. Southern Company and its subsidiaries are subject to certain claims and legal actions arising in the ordinary course of business. In addition, the business activities of Southern Company’s subsidiaries are subject to extensive governmental regulation related to public health and the environment, such as regulation of air emissions and water discharges. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements such as air quality and water standards, has occurred throughout the U.S. This litigation has included claims for damages alleged to have been caused by CO2 and other emissions, CCR, and alleged exposure to hazardous materials, and/or requests for injunctive relief in connection with such matters. The ultimate outcome of such pending or potential litigation against Southern Company and its subsidiaries cannot be predicted at this time; however, for current proceedings not specifically reported herein, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on Southern Company’s financial statements. Environmental Matters Environmental Remediation The Southern Company system must comply with environmental laws and regulations that cover the handling and disposal of waste and releases of hazardous substances. Under these various laws and regulations, the Southern Company system could incur substantial costs to clean up affected sites. The traditional electric operating companies and the natural gas distribution utilities in Illinois, New Jersey, Georgia, and Florida, have each received authority from their respective state PSCs or other applicable state regulatory agencies to recover approved environmental compliance costs through regulatory mechanisms. These regulatory mechanisms are adjusted annually or as necessary within limits approved by the state PSCs or other applicable state regulatory agencies. Georgia Power’s environmental remediation liability as of December 31, 2016 was $17 million. Georgia Power has been designated or identified as a potentially responsible party at sites governed by the Georgia Hazardous Site Response Act and/or by the federal Comprehensive Environmental Response, Compensation, and Liability Act, and assessment and potential cleanup of such sites is expected. Gulf Power’s environmental remediation liability includes estimated costs of environmental remediation projects of approximately $44 million as of December 31, 2016. These estimated costs primarily relate to site closure criteria by the Florida Department of Environmental Protection (FDEP) for potential impacts to soil and groundwater from herbicide applications at Gulf Power’s substations. The schedule for completion of the remediation projects is subject to FDEP approval. The projects have been approved by the Florida PSC for recovery through Gulf Power’s environmental cost recovery clause; therefore, these liabilities have no impact on net income. Southern Company Gas’ environmental remediation liability as of December 31, 2016 was $426 million based on the estimated cost of environmental investigation and remediation associated with known current and former operating sites. These environmental remediation expenditures are recoverable from customers through rate mechanisms approved by the applicable state regulatory agencies of the natural gas distribution utilities, with the exception of one site representing $5 million of the total accrued remediation costs. investor.southerncompany.com 82 Notes to Financial Statements In September 2015, the EPA filed an administrative complaint and notice of opportunity for hearing against Nicor Gas. The complaint alleges violation of the regulatory requirements applicable to polychlorinated biphenyls in the Nicor Gas natural gas distribution system and the EPA seeks a total civil penalty of approximately $0.3 million. On January 26, 2017, the EPA notified Nicor Gas that it agreed to voluntarily dismiss its administrative complaint with prejudice and without payment of a civil penalty or other further obligation on the part of Nicor Gas. The ultimate outcome of these matters cannot be determined at this time; however, the final disposition of these matters is not expected to have a material impact on Southern Company’s financial statements. Nuclear Fuel Disposal Costs Acting through the DOE and pursuant to the Nuclear Waste Policy Act of 1982, the U.S. government entered into contracts with Alabama Power and Georgia Power that require the DOE to dispose of spent nuclear fuel and high level radioactive waste generated at Plants Hatch and Farley and Plant Vogtle Units 1 and 2 beginning no later than January 31, 1998. The DOE has yet to commence the performance of its contractual and statutory obligation to dispose of spent nuclear fuel. Consequently, Alabama Power and Georgia Power pursued and continue to pursue legal remedies against the U.S. government for its partial breach of contract. In 2014, the Court of Federal Claims entered a judgment in favor of Georgia Power and Alabama Power in their spent nuclear fuel lawsuit seeking damages for the period from January 1, 2005 through December 31, 2010. In March 2015, Georgia Power recovered approximately $18 million, based on its ownership interests, which was credited to accounts where the original costs were charged and reduced rate base, fuel, and cost of service for the benefit of customers. Also in March 2015, Alabama Power recovered approximately $26 million, which was applied to reduce the cost of service for the benefit of customers. In 2014, Alabama Power and Georgia Power filed additional lawsuits against the U.S. government for the costs of continuing to store spent nuclear fuel at Plants Farley and Hatch and Plant Vogtle Units 1 and 2 for the period from January 1, 2011 through December 31, 2013. The damage period was subsequently extended to December 31, 2014. Damages will continue to accumulate until the issue is resolved or storage is provided. No amounts have been recognized in the financial statements as of December 31, 2016 for any potential recoveries from the additional lawsuits. The final outcome of these matters cannot be determined at this time; however, no material impact on Southern Company’s net income is expected. On-site dry spent fuel storage facilities are operational at all three plants and can be expanded to accommodate spent fuel through the expected life of each plant. FERC Matters Market-Based Rate Authority The traditional electric operating companies and Southern Power have authority from the FERC to sell electricity at market- based rates. Since 2008, that authority, for certain balancing authority areas, has been conditioned on compliance with the requirements of an energy auction, which the FERC found to be tailored mitigation that addresses potential market power concerns. In accordance with FERC regulations governing such authority, the traditional electric operating companies and Southern Power filed a triennial market power analysis in 2014, which included continued reliance on the energy auction as tailored mitigation. In April 2015, the FERC issued an order finding that the traditional electric operating companies’ and Southern Power’s existing tailored mitigation may not effectively mitigate the potential to exert market power in certain areas served by the traditional electric operating companies and in some adjacent areas. The FERC directed the traditional electric operating companies and Southern Power to show why market-based rate authority should not be revoked in these areas or to provide a mitigation plan to further address market power concerns. The traditional electric operating companies and Southern Power filed a request for rehearing in May 2015 and in June 2015 filed their response with the FERC. On December 9, 2016, the traditional electric operating companies and Southern Power filed an amendment to their market- based rate tariff that proposed certain changes to the energy auction, as well as several non-tariff changes. On February 2, 2017, the FERC issued an order accepting all such changes subject to an additional condition of cost-based price caps for certain sales outside of the energy auction, finding that all of these changes would provide adequate alternative mitigation for the traditional electric operating companies’ and Southern Power’s potential to exert market power in certain areas served by the traditional electric operating companies and in some adjacent areas. The traditional electric operating companies and Southern Power expect to make a compliance filing within 30 days accepting the terms of the order. While the FERC’s February 2, 2017 order references the market power proceeding discussed above, it remains a separate, ongoing matter. The ultimate outcome of these matters cannot be determined at this time. Southern Company 2016 Annual Report Southern Company Gas At December 31, 2016, Southern Company Gas’ gas midstream operations was involved in three gas pipeline construction projects with expected capital expenditures of approximately $780 million. These projects, along with Southern Company Gas’ existing pipelines, are intended to provide diverse sources of natural gas supplies to customers, resolve current and long-term supply planning for new capacity, enhance system reliability, and generate economic development in the areas served. One of these projects received FERC approval in August 2016. The remaining projects are pending FERC approval, which is expected to occur in 2017. The ultimate outcome of this matter cannot be determined at this time. Notes to Financial Statements 83 Regulatory Matters Alabama Power Rate RSE The Alabama PSC has adopted Rate RSE that provides for periodic annual adjustments based upon Alabama Power’s projected weighted cost of equity (WCE) compared to an allowable range. Rate RSE adjustments are based on forward-looking information for the applicable upcoming calendar year. Retail rates remain unchanged when the WCE ranges between 5.75% and 6.21% with an adjusting point of 5.98% and eligibility for a performance-based adder of seven basis points, or 0.07%, to the WCE adjusting point if Alabama Power (i) has an “A” credit rating equivalent with at least one of the recognized rating agencies or (ii) is in the top one-third of a designated customer value benchmark survey. Rate RSE adjustments for any two-year period, when averaged together, cannot exceed 4.0% and any annual adjustment is limited to 5.0%. If Alabama Power’s actual retail return is above the allowed WCE range, the excess will be refunded to customers unless otherwise directed by the Alabama PSC; however, there is no provision for additional customer billings should the actual retail return fall below the WCE range. On December 1, 2016, Alabama Power made its required annual Rate RSE submission to the Alabama PSC of projected data for calendar year 2017. The Rate RSE adjustment was an increase of 4.48%, or $245 million annually, effective January 1, 2017 and includes the performance based adder of 0.07%. Under the terms of Rate RSE, the maximum increase for 2018 cannot exceed 3.52%. As of December 31, 2016, the 2016 retail return exceeded the allowed WCE range; therefore, Alabama Power established a $73 million Rate RSE refund liability. In accordance with an order issued on February 14, 2017 by the Alabama PSC, Alabama Power was directed to apply the full amount of the refund to reduce the under recovered balance of Rate CNP PPA. Rate CNP PPA Alabama Power’s retail rates, approved by the Alabama PSC, provide for adjustments to recognize the placing of new generating facilities into retail service under Rate CNP. Alabama Power may also recover retail costs associated with certificated PPAs under Rate CNP PPA. On March 8, 2016, the Alabama PSC issued a consent order that Alabama Power leave in effect the current Rate CNP PPA factor for billings for the period April 1, 2016 through March 31, 2017. No adjustment to Rate CNP PPA is expected in 2017. As of December 31, 2016 and 2015, Alabama Power had an under recovered certificated PPA balance of $142 million and $99 million, respectively, which is included in other regulatory assets, deferred in the balance sheet. In accordance with an accounting order issued on February 17, 2017 by the Alabama PSC, Alabama Power was authorized to eliminate the under recovered balance in Rate CNP PPA at December 31, 2016, which totaled approximately $142 million. As discussed herein under “Rate RSE,” Alabama Power will utilize the full amount of its $73 million Rate RSE refund liability to reduce the amount of the Rate CNP PPA under recovery and will reclassify the remaining $69 million to a separate regulatory asset. The amortization of the new regulatory asset through Rate RSE will begin concurrently with the effective date of Alabama Power’s next depreciation study, which is expected to occur within the next three to five years. Alabama Power’s current depreciation study became effective January 1, 2017. Rate CNP Compliance Rate CNP Compliance allows for the recovery of Alabama Power’s retail costs associated with laws, regulations, and other such mandates directed at the utility industry involving the environment, security, reliability, safety, sustainability, or similar considerations impacting Alabama Power’s facilities or operations. Rate CNP Compliance is based on forward-looking information and provides for the recovery of these costs pursuant to a factor that is calculated annually. Compliance costs to be recovered include operations and maintenance expenses, depreciation, and a return on certain invested capital. Revenues for Rate CNP Compliance, as recorded on the financial statements, are adjusted for differences in actual recoverable costs and amounts billed in current regulated rates. Accordingly, changes in the billing factor will have no significant effect on revenues or net income, but will affect annual cash flow. Changes in compliance related operations and maintenance expenses and depreciation generally will have no effect on net income. On December 6, 2016, the Alabama PSC issued a consent order that Alabama Power leave in effect for 2017 the factors associated with Alabama Power’s compliance costs for the year 2016. As stated in the consent order, any under-collected amount for prior years will be deemed recovered before the recovery of any current year amounts. Any under recovered amounts associated with 2017 will be reflected in the 2018 filing. investor.southerncompany.com 84 Notes to Financial Statements In accordance with an accounting order issued on February 17, 2017 by the Alabama PSC, Alabama Power is authorized to classify any under recovered balance in Rate CNP Compliance up to approximately $36 million to a separate regulatory asset. The amortization of the new regulatory asset through Rate RSE will begin concurrently with the effective date of Alabama Power’s next depreciation study, which is expected to occur within the next three to five years. Alabama Power’s current depreciation study became effective January 1, 2017. Rate ECR Alabama Power has established energy cost recovery rates under Alabama Power’s Rate ECR as approved by the Alabama PSC. Rates are based on an estimate of future energy costs and the current over or under recovered balance. Revenues recognized under Rate ECR and recorded on the financial statements are adjusted for the difference in actual recoverable fuel costs and amounts billed in current regulated rates. The difference in the recoverable fuel costs and amounts billed give rise to the over or under recovered amounts recorded as regulatory assets or liabilities. Alabama Power, along with the Alabama PSC, continually monitors the over or under recovered cost balance to determine whether an adjustment to billing rates is required. Changes in the Rate ECR factor have no significant effect on Southern Company’s net income, but will impact operating cash flows. Currently, the Alabama PSC may approve billing rates under Rate ECR of up to 5.910 cents per KWH. In December 2015, the Alabama PSC issued a consent order that Alabama Power decrease the Rate ECR factor from 2.681 cents per KWH to 2.030 cents per KWH. On December 6, 2016, the Alabama PSC approved a decrease in Alabama Power’s Rate ECR factor from 2.030 to 2.015 cents per KWH, equal to 0.15%, or $8 million annually, based upon projected billings, effective January 1, 2017. The rate will return to 5.910 cents per KWH in 2018 absent a further order from the Alabama PSC. At December 31, 2016 and 2015, Alabama Power’s over recovered fuel costs totaled $76 million and $238 million, respectively, and are included in other regulatory liabilities, current. These classifications are based on estimates, which include such factors as weather, generation availability, energy demand, and the price of energy. A change in any of these factors could have a material impact on the timing of any recovery or return of fuel costs. In accordance with an accounting order issued on February 17, 2017 by the Alabama PSC, Alabama Power is authorized to classify any under recovered balance in Rate ECR up to approximately $36 million to a separate regulatory asset. The amortization of the new regulatory asset through Rate RSE will begin concurrently with the effective date of Alabama Power’s next depreciation study, which is expected to occur within the next three to five years. Alabama Power’s current depreciation study became effective January 1, 2017. Rate NDR Based on an order from the Alabama PSC, Alabama Power maintains a reserve for operations and maintenance expenses to cover the cost of damages from major storms to its transmission and distribution facilities. The order approves a separate monthly Rate NDR charge to customers consisting of two components. The first component is intended to establish and maintain a reserve balance for future storms and is an on-going part of customer billing. The second component of the Rate NDR charge is intended to allow recovery of any existing deferred storm-related operations and maintenance costs and any future reserve deficits over a 24-month period. The Alabama PSC order gives Alabama Power authority to record a deficit balance in the NDR when costs of storm damage exceed any established reserve balance. Absent further Alabama PSC approval, the maximum total Rate NDR charge consisting of both components is $10 per month per non-residential customer account and $5 per month per residential customer account. Alabama Power has the authority, based on an order from the Alabama PSC, to accrue certain additional amounts as circumstances warrant. The order allows for reliability-related expenditures to be charged against the additional accruals when the NDR balance exceeds $75 million. Alabama Power may designate a portion of the NDR to reliability-related expenditures as a part of an annual budget process for the following year or during the current year for identified unbudgeted reliability-related expenditures that are incurred. Accruals that have not been designated can be used to offset storm charges. Additional accruals to the NDR will enhance Alabama Power’s ability to deal with the financial effects of future natural disasters, promote system reliability, and offset costs retail customers would otherwise bear. No such accruals were recorded or designated in any period presented. As revenue from the Rate NDR charge is recognized, an equal amount of operations and maintenance expenses related to the NDR will also be recognized. As a result, the Rate NDR charge will not have an effect on net income but will impact operating cash flows. Environmental Accounting Order Based on an order from the Alabama PSC, Alabama Power is allowed to establish a regulatory asset to record the unrecovered investment costs, including the unrecovered plant asset balance and the unrecovered costs associated with site removal and closure associated with future unit retirements caused by environmental regulations. These costs are being amortized and recovered over the affected unit’s remaining useful life, as established prior to the decision regarding early retirement through Rate CNP Compliance. Southern Company 2016 Annual Report Notes to Financial Statements 85 In April 2015, as part of its environmental compliance strategy, Alabama Power retired Plant Gorgas Units 6 and 7 (200 MWs). Additionally, in April 2015, Alabama Power ceased using coal at Plant Barry Units 1 and 2 (250 MWs), but such units will remain available on a limited basis with natural gas as the fuel source. In accordance with the joint stipulation entered in connection with a civil enforcement action by the EPA, Alabama Power retired Plant Barry Unit 3 (225 MWs) in August 2015 and it is no longer available for generation. In April 2016, as part of its environmental compliance strategy, Alabama Power ceased using coal at Plant Greene County Units 1 and 2 (300 MWs representing Alabama Power’s ownership interest) and began operating Units 1 and 2 solely on natural gas in June 2016 and July 2016, respectively. In accordance with this accounting order from the Alabama PSC, Alabama Power transferred the unrecovered plant asset balances to a regulatory asset at their respective retirement dates. The regulatory asset will be amortized and recovered through Rate CNP Compliance over the units’ remaining useful lives, as established prior to the decision for retirement; therefore, these decisions associated with coal operations had no significant impact on Southern Company’s financial statements. Georgia Power Rate Plans Pursuant to the terms and conditions of a settlement agreement related to Southern Company’s acquisition of Southern Company Gas approved by the Georgia PSC on April 14, 2016, the 2013 ARP will continue in effect until December 31, 2019, and Georgia Power will be required to file its next base rate case by July 1, 2019. Furthermore, through December 31, 2019, Georgia Power and Atlanta Gas Light Company each will retain their respective merger savings, net of transition costs, as defined in the settlement agreement; through December 31, 2022, such net merger savings applicable to each will be shared on a 60/40 basis with their respective customers; thereafter, all merger savings will be retained by customers. In accordance with the 2013 ARP, the Georgia PSC approved increases to tariffs effective January 1, 2015 and 2016 as follows: (1) traditional base tariff rates by approximately $107 million and $49 million, respectively; (2) Environmental Compliance Cost Recovery tariff by approximately $23 million and $75 million, respectively; (3) Demand-Side Management tariffs by approximately $3 million in each year; and (4) Municipal Franchise Fee tariff by approximately $3 million and $13 million, respectively, for a total increase in base revenues of approximately $136 million and $140 million, respectively. Under the 2013 ARP, Georgia Power’s retail ROE is set at 10.95% and earnings are evaluated against a retail ROE range of 10.00% to 12.00%. Two-thirds of any earnings above 12.00% will be directly refunded to customers, with the remaining one-third retained by Georgia Power. There will be no recovery of any earnings shortfall below 10.00% on an actual basis. In 2014, Georgia Power’s retail ROE exceeded 12.00%, and Georgia Power refunded to retail customers approximately $11 million in 2016, as approved by the Georgia PSC on February 18, 2016. In 2015, Georgia Power’s retail ROE was within the allowed retail ROE range. In 2016, Georgia Power’s retail ROE exceeded 12.00%, and Georgia Power expects to refund to retail customers approximately $40 million, subject to review and approval by the Georgia PSC. The ultimate outcome of this matter cannot be determined at this time. Integrated Resource Plan On July 28, 2016, the Georgia PSC approved the 2016 IRP including the decertification and retirement of Plant Mitchell Units 3, 4A, and 4B (217 MWs) and Plant Kraft Unit 1 (17 MWs), as well as the decertification of the Intercession City unit (143 MWs total capacity). On August 2, 2016, the Plant Mitchell and Plant Kraft units were retired. On August 31, 2016, Georgia Power sold its 33% ownership interest in the Intercession City unit to Duke Energy Florida, LLC. Additionally, the Georgia PSC approved Georgia Power’s environmental compliance strategy and related expenditures proposed in the 2016 IRP, including measures taken to comply with existing government-imposed environmental mandates, subject to limits on expenditures for Plant McIntosh Unit 1 and Plant Hammond Units 1 through 4. The Georgia PSC approved the reclassification of the remaining net book value of Plant Mitchell Unit 3 and costs associated with materials and supplies remaining at the unit retirement date to a regulatory asset. Recovery of the unit’s net book value will continue through December 31, 2019, as provided in the 2013 ARP. The timing of the recovery of the remaining balance of the unit’s net book value as of December 31, 2019 and costs associated with materials and supplies remaining at the unit retirement date was deferred for consideration in Georgia Power’s 2019 base rate case. The Georgia PSC also approved the Renewable Energy Development Initiative to procure an additional 1,200 MWs of renewable resources primarily utilizing market-based prices established through a competitive bidding process with expected in-service dates between 2018 and 2021. Additionally, 200 MWs of self-build capacity for use by Georgia Power was approved, as well as consideration for no more than 200 MWs of capacity as part of a renewable commercial and industrial program. The Georgia PSC also approved recovery of costs up to $99 million through June 30, 2019 to preserve nuclear as an option at a future generation site in Stewart County, Georgia. The timing of cost recovery will be determined by the Georgia PSC in a future base rate case. The ultimate outcome of this matter cannot be determined at this time. investor.southerncompany.com 86 Notes to Financial Statements Fuel Cost Recovery Georgia Power has established fuel cost recovery rates approved by the Georgia PSC. In December 2015, the Georgia PSC approved Georgia Power’s request to lower annual billings by approximately $350 million effective January 1, 2016. On May 17, 2016, the Georgia PSC approved Georgia Power’s request to further lower annual billings by approximately $313 million effective June 1, 2016. On December 6, 2016, the Georgia PSC approved the delay of Georgia Power’s next fuel case, which was previously scheduled to be filed by February 28, 2017. The Georgia PSC will review Georgia Power’s cumulative over or under recovered fuel balance no later than September 1, 2018 and evaluate the need to file a fuel case unless Georgia Power deems it necessary to file a fuel case at an earlier time. Under an Interim Fuel Rider, Georgia Power continues to be allowed to adjust its fuel cost recovery rates prior to the next fuel case if the under recovered fuel balance exceeds $200 million. Georgia Power’s fuel cost recovery mechanism includes costs associated with a natural gas hedging program, as revised and approved by the Georgia PSC, allowing the use of an array of derivative instruments within a 48-month time horizon effective January 1, 2016. Georgia Power’s over recovered fuel balance totaled approximately $84 million at December 31, 2016 and is included in over recovered regulatory clause revenues, current. At December 31, 2015, Georgia Power’s over recovered fuel balance totaled approximately $116 million, including $10 million in over recovered regulatory clause revenues, current and $106 million in other deferred credits and liabilities. Fuel cost recovery revenues as recorded on the financial statements are adjusted for differences in actual recoverable fuel costs and amounts billed in current regulated rates. Accordingly, changes in the billing factor will not have a significant effect on Southern Company’s revenues or net income, but will affect cash flow. Storm Damage Recovery As of December 31, 2016, the balance in Georgia Power’s regulatory asset related to storm damage was $206 million. During October 2016, Hurricane Matthew caused significant damage to Georgia Power’s transmission and distribution facilities. As of December 31, 2016, Georgia Power had recorded incremental restoration cost related to this hurricane of $121 million, of which approximately $116 million was charged to the storm damage reserve and the remainder was capitalized. Georgia Power is accruing $30 million annually through December 31, 2019, as provided in the 2013 ARP, to the storm damage reserve to cover the operations and maintenance costs of damages from major storms to its transmission and distribution facilities, which is recoverable through base rates. The rate of recovery of storm damage costs after December 31, 2019 is expected to be adjusted in Georgia Power’s 2019 base rate case. As a result of this regulatory treatment, costs related to storms are not expected to have a material impact on Southern Company’s financial statements. Nuclear Construction In 2008, Georgia Power, acting for itself and as agent for Oglethorpe Power Corporation (OPC), the Municipal Electric Authority of Georgia (MEAG Power), and the City of Dalton, Georgia (Dalton), acting by and through its Board of Water, Light, and Sinking Fund Commissioners, doing business as Dalton Utilities (collectively, Vogtle Owners), entered into an agreement with a consortium consisting of Westinghouse and Stone & Webster, Inc., which was subsequently acquired by Westinghouse and changed its name to WECTEC Global Project Services Inc. (WECTEC) (Westinghouse and WECTEC, collectively, Contractor), pursuant to which the Contractor agreed to design, engineer, procure, construct, and test two AP1000 nuclear units (with electric generating capacity of approximately 1,100 MWs each) and related facilities at Plant Vogtle (Vogtle 3 and 4 Agreement). Under the terms of the Vogtle 3 and 4 Agreement, the Vogtle Owners agreed to pay a purchase price subject to certain price escalations and adjustments, including fixed escalation amounts and index-based adjustments, as well as adjustments for change orders, and performance bonuses for early completion and unit performance. The Vogtle 3 and 4 Agreement also provides for liquidated damages upon the Contractor’s failure to fulfill the schedule and performance guarantees, subject to an aggregate cap of 10% of the contract price, or approximately $920 million to $930 million. In addition, the Vogtle 3 and 4 Agreement provides for limited cost sharing by the Vogtle Owners for Contractor costs under certain conditions (which Georgia Power has not been notified have occurred) with maximum additional capital costs under this provision attributable to Georgia Power (based on Georgia Power’s ownership interest) of approximately $114 million. Each Vogtle Owner is severally (and not jointly) liable for its proportionate share, based on its ownership interest, of all amounts owed to the Contractor under the Vogtle 3 and 4 Agreement. Georgia Power’s proportionate share is 45.7%. In the event of certain credit rating downgrades of any Vogtle Owner, such Vogtle Owner will be required to provide a letter of credit or other credit enhancement. Certain obligations of Westinghouse have been guaranteed by Toshiba Corporation (Toshiba), Westinghouse’s parent company. In the event of certain credit rating downgrades of Toshiba, Westinghouse is required to provide letters of credit or other credit enhancement. In December 2015, Toshiba experienced credit rating downgrades and Westinghouse provided the Vogtle Owners with $920 million of letters of credit. These letters of credit remain in place in accordance with the terms of the Vogtle 3 and 4 Agreement. Southern Company 2016 Annual Report Notes to Financial Statements 87 On February 14, 2017, Toshiba announced preliminary earnings results for the period ended December 31, 2016, which included a substantial goodwill impairment charge at Westinghouse attributed to increased cost estimates to complete its U.S. nuclear projects, including Plant Vogtle Units 3 and 4. Toshiba also warned that it will likely be in a negative equity position as a result of the charges. At the same time, Toshiba reaffirmed its commitment to its U.S. nuclear projects with implementation of management changes and increased oversight. An inability or failure by the Contractor to perform its obligations under the Vogtle 3 and 4 Agreement could have a material impact on the construction of Plant Vogtle Units 3 and 4. Under the terms of the Vogtle 3 and 4 Agreement, the Contractor does not have a right to terminate the Vogtle 3 and 4 Agreement for convenience. The Contractor may terminate the Vogtle 3 and 4 Agreement under certain circumstances, including certain Vogtle Owner suspension or delays of work, action by a governmental authority to permanently stop work, certain breaches of the Vogtle 3 and 4 Agreement by the Vogtle Owners, Vogtle Owner insolvency, and certain other events. In the event of an abandonment of work by the Contractor, the maximum liability of the Contractor under the Vogtle 3 and 4 Agreement is increased significantly, but remains subject to limitations. The Vogtle Owners may terminate the Vogtle 3 and 4 Agreement at any time for convenience, provided that the Vogtle Owners will be required to pay certain termination costs. In 2009, the Georgia PSC voted to certify construction of Plant Vogtle Units 3 and 4 with a certified capital cost of $4.418 billion. In addition, in 2009 the Georgia PSC approved inclusion of the Plant Vogtle Units 3 and 4 related CWIP accounts in rate base, and the State of Georgia enacted the Georgia Nuclear Energy Financing Act, which allows Georgia Power to recover financing costs for nuclear construction projects certified by the Georgia PSC. Financing costs are recovered on all applicable certified costs through annual adjustments to the NCCR tariff by including the related CWIP accounts in rate base during the construction period. The Georgia PSC approved an NCCR tariff of $368 million for 2014, as well as increases to the NCCR tariff of approximately $27 million and $19 million effective January 1, 2015 and 2016, respectively. Georgia Power is required to file semi-annual Vogtle Construction Monitoring (VCM) reports with the Georgia PSC by February 28 and August 31 each year. In accordance with the 2009 certification order, Georgia Power requested amendments to the Plant Vogtle Units 3 and 4 certificate in both the February 2013 (eighth VCM) and February 2015 (twelfth VCM) filings, when projected construction capital costs to be borne by Georgia Power increased by 5% above the certified costs and estimated in-service dates were extended. In October 2013, the Georgia PSC approved a stipulation (2013 Stipulation) between Georgia Power and the Georgia PSC Staff to waive the requirement to amend the Plant Vogtle Units 3 and 4 certificate until the completion of Plant Vogtle Unit 3 or earlier if deemed appropriate by the Georgia PSC and Georgia Power. In April 2015, the Georgia PSC recognized that the certified cost and the 2013 Stipulation did not constitute a cost recovery cap and deemed the amendment requested in the February 2015 filing unnecessary and withdrawn until the completion of construction of Plant Vogtle Unit 3 consistent with the 2013 Stipulation. On December 31, 2015, Westinghouse and the Vogtle Owners entered into a definitive settlement agreement (Contractor Settlement Agreement) to resolve disputes between the Vogtle Owners and the Contractor under the Vogtle 3 and 4 Agreement, including litigation that was pending in the U.S. District Court for the Southern District of Georgia (Vogtle Construction Litigation). Effective December 31, 2015, Georgia Power, acting for itself and as agent for the other Vogtle Owners, and the Contractor entered into an amendment to the Vogtle 3 and 4 Agreement to implement the Contractor Settlement Agreement. The Contractor Settlement Agreement and the related amendment to the Vogtle 3 and 4 Agreement (i) restrict the Contractor’s ability to seek further increases in the contract price by clarifying and limiting the circumstances that constitute nuclear regulatory changes in law; (ii) provide for enhanced dispute resolution procedures; (iii) revise the guaranteed substantial completion dates to June 30, 2019 for Unit 3 and June 30, 2020 for Unit 4; (iv) provide that delay liquidated damages will commence if the nuclear fuel loading date for each unit does not occur by December 31, 2018 for Unit 3 and December 31, 2019 for Unit 4; and (v) provide that Georgia Power, based on its ownership interest, will pay to the Contractor and capitalize to the project cost approximately $350 million, of which approximately $263 million had been paid as of December 31, 2016. In addition, the Contractor Settlement Agreement provides for the resolution of other open existing items relating to the scope of the project under the Vogtle 3 and 4 Agreement, including cyber security, for which costs are reflected in Georgia Power’s current in-service forecast of $5.440 billion. Further, as part of the settlement and Westinghouse’s acquisition of WECTEC: (i) Westinghouse engaged Fluor Enterprises, Inc., a subsidiary of Fluor Corporation, as a new construction subcontractor and (ii) the Vogtle Owners, Chicago Bridge & Iron Co, N.V., and The Shaw Group Inc. entered into mutual releases of any and all claims arising out of events or circumstances in connection with the construction of Plant Vogtle Units 3 and 4 that occurred on or before the date of the Contractor Settlement Agreement. On January 5, 2016, the Vogtle Construction Litigation was dismissed with prejudice. On December 20, 2016, the Georgia PSC voted to approve a settlement agreement (Vogtle Cost Settlement Agreement) resolving the following prudence matters: (i) none of the $3.3 billion of costs incurred through December 31, 2015 and reflected in the fourteenth VCM report will be disallowed from rate base on the basis of imprudence; (ii) the Contractor Settlement Agreement is reasonable and prudent and none of the amounts paid or to be paid pursuant to the Contractor Settlement Agreement should be disallowed from rate base on the basis of imprudence; (iii) financing costs on verified and approved capital costs will be deemed prudent provided they are incurred prior to December 31, 2019 and December 31, 2020 for Plant Vogtle Units 3 and 4, respectively; and (iv) (a) the in-service capital cost forecast will be adjusted to $5.680 billion (Revised Forecast), which includes a contingency of $240 million above Georgia Power’s current forecast of $5.440 billion, (b) capital costs incurred up to the Revised Forecast will be presumed to be reasonable and prudent with the burden of proof on any party challenging such costs, and (c) Georgia Power would have the burden to show that any capital costs above the Revised Forecast are reasonable and prudent. Under the terms of the Vogtle Cost Settlement Agreement, the certified in-service capital cost for purposes investor.southerncompany.com 88 Notes to Financial Statements of calculating the NCCR tariff will remain at $4.418 billion. Construction capital costs above $4.418 billion will accrue AFUDC through the date each unit is placed in service. The ROE used to calculate the NCCR tariff was reduced from 10.95% (the ROE rate setting point authorized by the Georgia PSC in the 2013 ARP) to 10.00% effective January 1, 2016. For purposes of the AFUDC calculation, the ROE on costs between $4.418 billion and $5.440 billion will also be 10.00% and the ROE on any amounts above $5.440 billion would be Georgia Power’s average cost of long-term debt. If the Georgia PSC adjusts Georgia Power’s ROE rate setting point in a rate case prior to Plant Vogtle Units 3 and 4 being placed into retail rate base, then the ROE for purposes of calculating both the NCCR tariff and AFUDC will likewise be 95 basis points lower than the revised ROE rate setting point. If Plant Vogtle Units 3 and 4 are not placed in service by December 31, 2020, then (i) the ROE for purposes of calculating the NCCR tariff will be reduced an additional 300 basis points, or $8 million per month, and may, at the Georgia PSC’s discretion, be accrued to be used for the benefit of customers, until such time as the units are placed in service and (ii) the ROE used to calculate AFUDC will be Georgia Power’s average cost of long-term debt. Under the terms of the Vogtle Cost Settlement Agreement, Plant Vogtle Units 3 and 4 will be placed into retail rate base on December 31, 2020 or when placed in service, whichever is later. The Georgia PSC will determine for retail ratemaking purposes the process of transitioning Plant Vogtle Units 3 and 4 from a construction project to an operating plant no later than Georgia Power’s base rate case required to be filed by July 1, 2019. The Georgia PSC has approved fifteen VCM reports covering the periods through June 30, 2016, including construction capital costs incurred, which through that date totaled $3.7 billion. Georgia Power expects to file the sixteenth VCM report, covering the period from July 1 through December 31, 2016, requesting approval of $222 million of construction capital costs incurred during that period, with the Georgia PSC by February 28, 2017. Georgia Power’s CWIP balance for Plant Vogtle Units 3 and 4 was approximately $3.9 billion as of December 31, 2016, and Georgia Power had incurred $1.3 billion in financing costs through December 31, 2016. As of December 31, 2016, Georgia Power had borrowed $2.6 billion related to Plant Vogtle Units 3 and 4 costs through a loan guarantee agreement between Georgia Power and the DOE and a multi-advance credit facility among Georgia Power, the DOE, and the FFB. See Note 6 under “DOE Loan Guarantee Borrowings” for additional information, including applicable covenants, events of default, and mandatory prepayment events. There have been technical and procedural challenges to the construction and licensing of Plant Vogtle Units 3 and 4 at the federal and state level and additional challenges may arise as construction proceeds. Processes are in place that are designed to assure compliance with the requirements specified in the Westinghouse Design Control Document and the combined construction and operating licenses, including inspections by Southern Nuclear and the NRC that occur throughout construction. As a result of such compliance processes, certain license amendment requests have been filed and approved or are pending before the NRC. Various design and other licensing-based compliance matters, including the timely resolution of Inspections, Tests, Analyses, and Acceptance Criteria and the related approvals by the NRC, may arise as construction proceeds, which may result in additional license amendments or require other resolution. If any license amendment requests or other licensing-based compliance issues are not resolved in a timely manner, there may be delays in the project schedule that could result in increased costs either to the Vogtle Owners or the Contractor or to both. In addition to Toshiba’s reaffirmation of its commitment, the Contractor provided Georgia Power with revised forecasted in- service dates of December 2019 and September 2020 for Plant Vogtle Units 3 and 4, respectively. Georgia Power is currently reviewing a preliminary summary schedule supporting these dates that ultimately must be reconciled to a detailed integrated project schedule. As construction continues, the risk remains that challenges with Contractor performance including labor productivity, fabrication, delivery, assembly, and installation of plant systems, structures, and components, or other issues could arise and may further impact project schedule and cost. Georgia Power expects the Contractor to employ mitigation efforts and believes the Contractor is responsible for any related costs under the Vogtle 3 and 4 Agreement. Georgia Power estimates its financing costs for Plant Vogtle Units 3 and 4 to be approximately $30 million per month, with total construction period financing costs of approximately $2.5 billion. Additionally, Georgia Power estimates its owner’s costs to be approximately $6 million per month, net of delay liquidated damages. The revised forecasted in-service dates are within the timeframe contemplated in the Vogtle Cost Settlement Agreement and would enable both units to qualify for production tax credits the IRS has allocated to each of Plant Vogtle Units 3 and 4, which require the applicable unit to be placed in service before 2021. The net present value of the production tax credits is estimated at approximately $400 million per unit. Future claims by the Contractor or Georgia Power (on behalf of the Vogtle Owners) could arise throughout construction. These claims may be resolved through formal and informal dispute resolution procedures under the Vogtle 3 and 4 Agreement and, under the enhanced dispute resolution procedures, may be resolved through litigation after the completion of nuclear fuel load for both units. The ultimate outcome of these matters cannot be determined at this time. Southern Company 2016 Annual Report Notes to Financial Statements 89 Gulf Power Retail Base Rate Cases In 2013, the Florida PSC approved a settlement agreement among Gulf Power and all of the intervenors to Gulf Power’s retail base rate case (Gulf Power 2013 Rate Case Settlement Agreement). Under the terms of the Gulf Power 2013 Rate Case Settlement Agreement, Gulf Power (1) increased base rates approximately $35 million and $20 million annually effective January 2014 and 2015, respectively; (2) continued its authorized retail ROE midpoint (10.25%) and range (9.25% – 11.25%); and (3) accrued a return similar to AFUDC on certain transmission system upgrades placed into service after January 2014 through January 1, 2017. The Gulf Power 2013 Rate Case Settlement Agreement also provides that Gulf Power may reduce depreciation and record a regulatory asset that will be included as an offset to the other cost of removal regulatory liability in an aggregate amount up to $62.5 million from January 2014 through June 2017. In any given month, such depreciation reduction may not exceed the amount necessary for the retail ROE, as reported to the Florida PSC monthly, to reach the midpoint of the authorized retail ROE range then in effect. Recovery of the regulatory asset will occur over a period to be determined by the Florida PSC in the Gulf Power 2016 Rate Case, as defined below. For 2014 and 2015, Gulf Power recognized reductions in depreciation expense of $8.4 million and $20.1 million, respectively. No net reduction in depreciation was recorded by Gulf Power in 2016. On October 12, 2016, Gulf Power filed a petition (Gulf Power 2016 Rate Case) with the Florida PSC requesting an annual increase in retail rates and charges of $106.8 million based on the projected test year of January 1, 2017 through December 31, 2017 and a retail ROE of 11% compared to the current retail ROE of 10.25%. The requested increase includes recovery of the portion of Plant Scherer Unit 3 that has been rededicated to serving retail customers following the contract expirations at the end of 2015 and May 2016. If retail recovery of Plant Scherer Unit 3 is not approved by the Florida PSC in the 2016 Rate Case, Gulf Power may consider an asset sale. The current book value of Gulf Power’s ownership of Plant Scherer Unit 3 could exceed market value which could result in a material loss. The Florida PSC is expected to make a decision on the Gulf Power 2016 Rate Case in the second quarter 2017. Gulf Power has requested that the increase in base rates, if approved by the Florida PSC, become effective in July 2017. The ultimate outcome of this matter cannot be determined at this time. Southern Company Gas Natural Gas Cost Recovery Southern Company Gas has established natural gas cost recovery rates that are approved by the applicable state regulatory agencies in the states in which it serves. Natural gas cost recovery revenues are adjusted for differences in actual recoverable natural gas costs and amounts billed in current regulated rates. Accordingly, changes in the billing factor will not have a significant effect on Southern Company’s revenues or net income, but will affect cash flow. Regulatory Infrastructure Programs Six of Southern Company Gas’ seven natural gas distribution utilities are involved in ongoing capital projects associated with infrastructure improvement programs that have been previously approved by their applicable state regulatory agencies and provide an appropriate return on invested capital. These infrastructure improvement programs are designed to update or expand the natural gas distribution systems of the natural gas distribution utilities to improve reliability and meet operational flexibility and growth. Initial program lengths range from four to 10 years, with the longest set to expire in 2025. On February 21, 2017, the Georgia PSC approved a rate adjustment mechanism for Atlanta Gas Light that included the 2017 capital investment associated with a four-year extension of one of its existing infrastructure programs, with a total additional investment of $177 million through 2020. In addition, Elizabethtown Gas currently has a proposed infrastructure improvement program pending approval by the New Jersey Board of Public Utilities requesting to invest more than $1.1 billion through 2027. The ultimate outcome of these matters cannot be determined at this time. Integrated Coal Gasification Combined Cycle Kemper IGCC Overview The Kemper IGCC utilizes IGCC technology with an expected output capacity of 582 MWs. The Kemper IGCC is fueled by locally mined lignite (an abundant, lower heating value coal) from a mine owned by Mississippi Power and situated adjacent to the Kemper IGCC. The mine, operated by North American Coal Corporation, started commercial operation in 2013. In connection with the Kemper IGCC, Mississippi Power constructed and plans to operate approximately 61 miles of CO2 pipeline infrastructure for the transport of captured CO2 for use in enhanced oil recovery. investor.southerncompany.com 90 Notes to Financial Statements Kemper IGCC Schedule and Cost Estimate In 2012, the Mississippi PSC issued the 2012 MPSC CPCN Order, a detailed order confirming the CPCN originally approved by the Mississippi PSC in 2010 authorizing the acquisition, construction, and operation of the Kemper IGCC. The certificated cost estimate of the Kemper IGCC included in the 2012 MPSC CPCN Order was $2.4 billion, net of $245 million of grants awarded to the Kemper IGCC project by the DOE under the Clean Coal Power Initiative Round 2 (Initial DOE Grants) and excluding the cost of the lignite mine and equipment, the cost of the CO2 pipeline facilities, and AFUDC related to the Kemper IGCC. The 2012 MPSC CPCN Order approved a construction cost cap of up to $2.88 billion, with recovery of prudently-incurred costs subject to approval by the Mississippi PSC. The Kemper IGCC was originally projected to be placed in service in May 2014. Mississippi Power placed the combined cycle and the associated common facilities portion of the Kemper IGCC in service in August 2014. The remainder of the plant, including the gasifiers and the gas clean-up facilities, represents first-of-a-kind technology. The initial production of syngas began on July 14, 2016 for gasifier “B” and on September 13, 2016 for gasifier “A.” Mississippi Power achieved integrated operation of both gasifiers on January 29, 2017, including the production of electricity from syngas in both combustion turbines. Mississippi Power subsequently completed a brief outage to repair and make modifications to further improve the plant’s ability to achieve sustained operations sufficient to support placing the plant in service for customers. Efforts to reach sustained operation of both gasifiers and production of electricity from syngas in both combustion turbines are in process. The plant has produced and captured CO2, and has produced sulfuric acid and ammonia, all of acceptable quality under the related off-take agreements. On February 20, 2017, Mississippi Power determined gasifier “B,” which has been producing syngas over 60% of the time since early November 2016, requires an outage to remove ash deposits from its ash removal system. Gasifier “A” and combustion turbine “A” are expected to remain in operation, producing electricity from syngas, as well as producing chemical by-products. As a result, Mississippi Power currently expects the remainder of the Kemper IGCC, including both gasifiers, will be placed in service by mid-March 2017. Mississippi Power’s Kemper IGCC 2010 project estimate, current cost estimate (which includes the impacts of the Mississippi Supreme Court’s (Court) decision discussed herein under “Rate Recovery of Kemper IGCC Costs – 2013 MPSC Rate Order”), and actual costs incurred as of December 31, 2016, all of which include 100% of the costs for the Kemper IGCC, are as follows: Cost Category Plant Subject to Cost Cap(c)(e) Lignite Mine and Equipment CO2 Pipeline Facilities AFUDC(d) Combined Cycle and Related Assets Placed in Service – Incremental(e) General Exceptions Deferred Costs(e) Additional DOE Grants(f) Total Kemper IGCC(g) 2010 Project Estimate(a) Current Cost Estimate(b) Actual Costs $ $ 2.40 0.21 0.14 0.17 — 0.05 — — 2.97 (in billions) $ 5.64 0.23 0.11 0.79 0.04 0.10 0.22 (0.14) 6.99 $ $ $ 5.44 0.23 0.11 0.75 0.04 0.09 0.21 (0.14) 6.73 (a) The 2010 Project Estimate is the certificated cost estimate adjusted to include the certificated estimate for the CO2 pipeline facilities approved in 2011 by the Mississippi PSC, as well as the lignite mine and equipment, AFUDC, and general exceptions. (b) Amounts in the Current Cost Estimate include certain estimated post-in-service costs which are expected to be subject to the cost cap. (c) The 2012 MPSC CPCN Order approved a construction cost cap of up to $2.88 billion, net of the Initial DOE Grants and excluding the cost of the lignite mine and equipment, the cost of the CO2 pipeline facilities, AFUDC, and certain general exceptions, including change of law, force majeure, and beneficial capital (which exists when Mississippi Power demonstrates that the purpose and effect of the construction cost increase is to produce efficiencies that will result in a neutral or favorable effect on customers relative to the original proposal for the CPCN) (Cost Cap Exceptions). The Current Cost Estimate and the Actual Costs include non-incremental operating and maintenance costs related to the combined cycle and associated common facilities placed in service in August 2014 that are subject to the $2.88 billion cost cap and exclude post-in-service costs for the lignite mine. See “Rate Recovery of Kemper IGCC Costs – 2013 MPSC Rate Order” herein for additional information. (d) Mississippi Power’s 2010 Project Estimate included recovery of financing costs during construction rather than the accrual of AFUDC. This approach was not approved by the Mississippi PSC as described in “Rate Recovery of Kemper IGCC Costs – 2013 MPSC Rate Order.” The Current Cost Estimate also reflects the impact of a settlement agreement with the wholesale customers for cost-based rates under FERC’s jurisdiction. (e) Non-capital Kemper IGCC-related costs incurred during construction were initially deferred as regulatory assets. Some of these costs are now included in rates and are being recognized through income; however, such costs continue to be included in the Current Cost Estimate and the Actual Costs at December 31, 2016. The wholesale portion of debt carrying costs, whether deferred or recognized through income, is not included in the Current Cost Estimate and the Actual Costs at December 31, 2016. See “Rate Recovery of Kemper IGCC Costs – Regulatory Assets and Liabilities” herein for additional information. (f) On April 8, 2016, Mississippi Power received approximately $137 million in additional grants from the DOE for the Kemper IGCC (Additional DOE Grants), which are expected to be used to reduce future rate impacts for customers. (g) The Current Cost Estimate and the Actual Costs include $2.76 billion that will not be recovered for costs above the cost cap, $0.83 billion of investment costs included in current rates for the combined cycle and related assets in service, and $0.08 billion of costs that were previously expensed for the combined cycle and related assets in service. The Current Cost Estimate and the Actual Costs exclude $0.25 billion of costs not included in current rates for post-June 2013 mine operations, the lignite fuel inventory, and the nitrogen plant capital lease, which will be included in the 2017 Rate Case to be filed by June 3, 2017. See Note 6 under “Capital Leases” and “Rate Recovery of Kemper IGCC Costs – 2017 Rate Case” herein for additional information. Southern Company 2016 Annual Report Notes to Financial Statements 91 Of the total costs, including post-in-service costs for the lignite mine, incurred as of December 31, 2016, $3.67 billion was included in property, plant, and equipment (which is net of the Initial DOE Grants, the Additional DOE Grants, and estimated probable losses of $2.84 billion), $6 million in other property and investments, $75 million in fossil fuel stock, $47 million in materials and supplies, $29 million in other regulatory assets, current, $172 million in other regulatory assets, deferred, $3 million in other current assets, and $14 million in other deferred charges and assets in the balance sheet. Mississippi Power does not intend to seek rate recovery for any costs related to the construction of the Kemper IGCC that exceed the $2.88 billion cost cap, net of the Initial DOE Grants and excluding the Cost Cap Exceptions. Southern Company recorded pre- tax charges to income for revisions to the cost estimate of $348 million ($215 million after tax), $365 million ($226 million after tax), and $868 million ($536 million after tax) in 2016, 2015, and 2014, respectively. Since 2013, in the aggregate, Southern Company has incurred charges of $2.76 billion ($1.71 billion after tax) as a result of changes in the cost estimate above the cost cap for the Kemper IGCC through December 31, 2016. The increases to the cost estimate in 2016 primarily reflect $186 million for the extension of the Kemper IGCC’s projected in-service date from August 31, 2016 to March 15, 2017 and $162 million for increased efforts related to operational readiness and challenges in start-up and commissioning activities, including the cost of repairs and modifications to both gasifiers, mechanical improvements to coal feed and ash management systems, and outage work, as well as certain post-in- service costs expected to be subject to the cost cap. In addition to the current construction cost estimate, Mississippi Power is identifying potential improvement projects that ultimately may be completed subsequent to placing the remainder of the Kemper IGCC in service. If completed, such improvement projects would be expected to enhance plant performance, safety, and/or operations. As of December 31, 2016, approximately $12 million of related potential costs has been included in the estimated loss on the Kemper IGCC. Other projects have yet to be fully evaluated, have not been included in the current cost estimate, and may be subject to the $2.88 billion cost cap. Any extension of the in-service date beyond mid-March 2017 is currently estimated to result in additional base costs of approximately $25 million to $35 million per month, which includes maintaining necessary levels of start-up labor, materials, and fuel, as well as operational resources required to execute start-up and commissioning activities. Additional costs may be required for remediation of any further equipment and/or design issues identified. Any extension of the in-service date with respect to the Kemper IGCC beyond mid-March 2017 would also increase costs for the Cost Cap Exceptions, which are not subject to the $2.88 billion cost cap established by the Mississippi PSC. These costs include AFUDC, which is currently estimated to total approximately $16 million per month, as well as carrying costs and operating expenses on Kemper IGCC assets placed in service and consulting and legal fees of approximately $3 million per month. For additional information, see “2015 Rate Case” herein. Further cost increases and/or extensions of the expected in-service date may result from factors including, but not limited to, difficulties integrating the systems required for sustained operations, sustaining nitrogen supply, major equipment failure, unforeseen engineering or design problems including any repairs and/or modifications to systems, and/or operational performance (including additional costs to satisfy any operational parameters ultimately adopted by the Mississippi PSC). Any further changes in the estimated costs of the Kemper IGCC subject to the $2.88 billion cost cap, net of the Initial DOE Grants and excluding the Cost Cap Exceptions, will be reflected in Southern Company’s statements of income and these changes could be material. Rate Recovery of Kemper IGCC Costs Given the variety of potential scenarios and the uncertainty of the outcome of future regulatory proceedings with the Mississippi PSC (and any subsequent related legal challenges), the ultimate outcome of the rate recovery matters discussed herein, including the resolution of legal challenges, cannot now be determined but could result in further material charges that could have a material impact on Southern Company’s results of operations, financial condition, and liquidity. As of December 31, 2016, in addition to the $2.76 billion of costs above the Mississippi PSC’s $2.88 billion cost cap that have been recognized as a charge to income, Mississippi Power had incurred approximately $1.99 billion in costs subject to the cost cap and approximately $1.46 billion in Cost Cap Exceptions related to the construction and start-up of the Kemper IGCC that are not included in current rates. These costs primarily relate to the following: Cost Category Gasifiers and Gas Clean-up Facilities Lignite Mine Facility CO2 Pipeline Facilities Combined Cycle and Common Facilities AFUDC General exceptions Plant inventory Lignite inventory Regulatory and other deferred assets Subtotal Additional DOE Grants Total Actual Costs (in billions) $ 1.88 0.31 0.11 0.16 0.69 0.07 0.03 0.08 0.12 3.45 (0.14) 3.31 $ investor.southerncompany.com 92 Notes to Financial Statements Of these amounts, approximately 29% is related to wholesale and approximately 71% is related to retail, including the 15% portion that was previously contracted to be sold to SMEPA. Mississippi Power and its wholesale customers have generally agreed to the similar regulatory treatment for wholesale tariff purposes as approved by the Mississippi PSC for retail for Kemper IGCC-related costs. See “Termination of Proposed Sale of Undivided Interest” herein for further information. Prudence On August 17, 2016, the Mississippi PSC issued an order establishing a discovery docket to manage all filings related to the prudence of the Kemper IGCC. On October 3, 2016, Mississippi Power made a required compliance filing, which included a review and explanation of differences between the Kemper IGCC project estimate set forth in the 2010 CPCN proceedings and the most recent Kemper IGCC project estimate, as well as comparisons of current cost estimates and current expected plant operational parameters to the estimates presented in the 2010 CPCN proceedings for the first five years after the Kemper IGCC is placed in service. Compared to amounts presented in the 2010 CPCN proceedings, operations and maintenance expenses have increased an average of $105 million annually and maintenance capital has increased an average of $44 million annually for the first full five years of operations for the Kemper IGCC. Additionally, while the current estimated operational availability estimates reflect ultimate results similar to those presented in the 2010 CPCN proceedings, the ramp up period for the current estimates reflects a lower starting point and a slower escalation rate. On November 17, 2016, Mississippi Power submitted a supplemental filing to the October 3, 2016 compliance filing to present revised non-fuel operations and maintenance expense projections for the first year after the Kemper IGCC is placed in service. This supplemental filing included approximately $68 million in additional estimated operations and maintenance costs expected to be required to support the operations of the Kemper IGCC during that period. Mississippi Power will not seek recovery of the $68 million in additional estimated costs from customers if incurred. Mississippi Power expects the Mississippi PSC to address these matters in connection with the 2017 Rate Case. Economic Viability Analysis In the fourth quarter 2016, as a part of its Integrated Resource Plan process, the Southern Company system completed its regular annual updated fuel forecast, the 2017 Annual Fuel Forecast. This updated fuel forecast reflected significantly lower long-term estimated costs for natural gas than were previously projected. As a result of the updated long-term natural gas forecast, as well as the revised operating expense projections reflected in the discovery docket filings discussed above, on February 21, 2017, Mississippi Power filed an updated project economic viability analysis of the Kemper IGCC as required under the 2012 MPSC CPCN Order confirming authorization of the Kemper IGCC. The project economic viability analysis measures the life cycle economics of the Kemper IGCC compared to feasible alternatives, natural gas combined cycle generating units, under a variety of scenarios and considering fuel, operating and capital costs, and operating characteristics, as well as federal and state taxes and incentives. The reduction in the projected long-term natural gas prices in the 2017 Annual Fuel Forecast and, to a lesser extent, the increase in the estimated Kemper IGCC operating costs, negatively impact the updated project economic viability analysis. Mississippi Power expects the Mississippi PSC to address this matter in connection with the 2017 Rate Case. 2017 Accounting Order Request After the remainder of the plant is placed in service, AFUDC equity of approximately $11 million per month will no longer be recorded in income, and Mississippi Power expects to incur approximately $25 million per month in depreciation, taxes, operations and maintenance expenses, interest expense, and regulatory costs in excess of current rates. Mississippi Power expects to file a request for authority from the Mississippi PSC and the FERC to defer all Kemper IGCC costs incurred after the in-service date that cannot be capitalized, are not included in current rates, and are not required to be charged against earnings as a result of the $2.88 billion cost cap until such time as the Mississippi PSC completes its review and includes the resulting allowable costs in rates. In the event that the Mississippi PSC does not grant Mississippi Power’s request, these monthly expenses will be charged to income as incurred and will not be recoverable through rates. 2017 Rate Case Mississippi Power continues to believe that all costs related to the Kemper IGCC have been prudently incurred in accordance with the requirements of the 2012 MPSC CPCN Order. Mississippi Power also recognizes significant areas of potential challenge during future regulatory proceedings (and any subsequent, related legal challenges) exist. As described further herein and under “Prudence,” “Lignite Mine and CO2 Pipeline Facilities,” “Termination of Proposed Sale of Undivided Interest,” “Bonus Depreciation,” “Investment Tax Credits,” and “Section 174 Research and Experimental Deduction,” these challenges include, but are not limited to, prudence issues associated with capital costs, financing costs (AFUDC), and future operating costs net of chemical revenues; potential operating parameters; income tax issues; costs deferred as regulatory assets; and the 15% portion of the project previously contracted to SMEPA. Legislation to authorize a multi-year rate plan and legislation to provide for alternate financing through securitization of up to $1.0 billion of prudently-incurred costs was enacted into law in 2013. Mississippi Power expects to utilize this legislation to securitize prudently-incurred qualifying facility costs in excess of the certificated cost estimate of $2.4 billion. Qualifying facility costs include, but are not limited to, pre-construction costs, construction costs, regulatory costs, and accrued AFUDC. The Court’s decision regarding the 2013 MPSC Rate Order did not impact Mississippi Power’s ability to utilize alternate financing through securitization or the February 2013 legislation. Southern Company 2016 Annual Report Notes to Financial Statements 93 Although the 2017 Rate Case has not yet been filed and is subject to future developments with either the Kemper IGCC or the Mississippi PSC, consistent with its approach in the 2013 and 2015 rate proceedings in accordance with the law passed in 2013 authorizing multi-year rate plans, Mississippi Power is developing both a traditional rate case requesting full cost recovery of the amounts not currently in rates and a rate mitigation plan that together represent Mississippi Power’s probable filing strategy. Mississippi Power also expects that timely resolution of the 2017 Rate Case will likely require a negotiated settlement agreement. In the event an agreement acceptable to both Mississippi Power and the Mississippi Public Utilities Staff (MPUS) (and other parties) can be negotiated and ultimately approved by the Mississippi PSC, it is reasonably possible that full regulatory recovery of all Kemper IGCC costs will not occur. The impact of such an agreement on Mississippi Power’s financial statements would depend on the method, amount, and type of cost recovery ultimately excluded. Certain costs, including operating costs, would be recorded to income in the period incurred, while other costs, including investment-related costs, would be charged to income when it is probable they will not be recovered and the amounts can be reasonably estimated. In the event an agreement acceptable to the parties cannot be reached, Mississippi Power intends to fully litigate its request for full recovery through the Mississippi PSC regulatory process and any subsequent legal challenges. Mississippi Power has evaluated various scenarios in connection with its processes to prepare the 2017 Rate Case and has recognized an additional $80 million charge to income, which is the estimated minimum probable amount of the $3.31 billion of Kemper IGCC costs not currently in rates that would not be recovered under the probable rate mitigation plan to be filed by June 3, 2017. 2015 Rate Case On August 13, 2015, the Mississippi PSC approved Mississippi Power’s request for interim rates, which presented an alternative rate proposal (In-Service Asset Proposal) designed to recover Mississippi Power’s costs associated with the Kemper IGCC assets that are commercially operational and currently providing service to customers (the transmission facilities, combined cycle, natural gas pipeline, and water pipeline) and other related costs. The interim rates were designed to collect approximately $159 million annually and became effective in September 2015, subject to refund and certain other conditions. On December 3, 2015, the Mississippi PSC issued an order (In-Service Asset Rate Order) adopting in full a stipulation (2015 Stipulation) entered into between Mississippi Power and the MPUS regarding the In-Service Asset Proposal. The In-Service Asset Rate Order provided for retail rate recovery of an annual revenue requirement of approximately $126 million, based on Mississippi Power’s actual average capital structure, with a maximum common equity percentage of 49.733%, a 9.225% return on common equity, and actual embedded interest costs. The In-Service Asset Rate Order also included a prudence finding of all costs in the stipulated revenue requirement calculation for the in-service assets. The stipulated revenue requirement excluded the costs of the Kemper IGCC related to the 15% undivided interest that was previously projected to be purchased by SMEPA but reserved Mississippi Power’s right to seek recovery in a future proceeding. See “Termination of Proposed Sale of Undivided Interest” herein for additional information. Mississippi Power is required to file the 2017 Rate Case by June 3, 2017. With implementation of the new rates on December 17, 2015, the interim rates were terminated and, in March 2016, Mississippi Power completed customer refunds of approximately $11 million for the difference between the interim rates collected and the permanent rates. 2013 MPSC Rate Order In January 2013, Mississippi Power entered into a settlement agreement with the Mississippi PSC that was intended to establish the process for resolving matters regarding cost recovery related to the Kemper IGCC (2013 Settlement Agreement). Under the 2013 Settlement Agreement, Mississippi Power agreed to limit the portion of prudently-incurred Kemper IGCC costs to be included in retail rate base to the $2.4 billion certificated cost estimate, plus the Cost Cap Exceptions, but excluding AFUDC, and any other costs permitted or determined to be excluded from the $2.88 billion cost cap by the Mississippi PSC. In March 2013, the Mississippi PSC issued a rate order approving retail rate increases of 15% effective March 19, 2013 and 3% effective January 1, 2014, which collectively were designed to collect $156 million annually beginning in 2014 (2013 MPSC Rate Order) to be used to mitigate customer rate impacts after the Kemper IGCC is placed in service, based on a mirror CWIP methodology (Mirror CWIP rate). On February 12, 2015, the Court reversed the 2013 MPSC Rate Order based on, among other things, its findings that (1) the Mirror CWIP rate treatment was not provided for under the Baseload Act and (2) the Mississippi PSC should have determined the prudence of Kemper IGCC costs before approving rate recovery through the 2013 MPSC Rate Order. The Court also found the 2013 Settlement Agreement unenforceable due to a lack of public notice for the related proceedings. On July 7, 2015, the Mississippi PSC ordered that the Mirror CWIP rate be terminated effective July 20, 2015 and required the fourth quarter 2015 refund of the $342 million collected under the 2013 MPSC Rate Order, along with associated carrying costs of $29 million. The Court’s decision did not impact the 2012 MPSC CPCN Order or the February 2013 legislation described above. Because the 2013 MPSC Rate Order did not provide for the inclusion of CWIP in rate base as permitted by the Baseload Act, Mississippi Power continues to record AFUDC on the Kemper IGCC. Through December 31, 2016, AFUDC recorded since the original May 2014 estimated in-service date for the Kemper IGCC has totaled $398 million, which will continue to accrue at approximately $16 million per month until the remainder of the plant is placed in service. Mississippi Power has not recorded any AFUDC on Kemper IGCC costs in excess of the $2.88 billion cost cap, except for Cost Cap Exception amounts. investor.southerncompany.com 94 Notes to Financial Statements 2012 MPSC CPCN Order The 2012 MPSC CPCN Order included provisions relating to both Mississippi Power’s recovery of financing costs during the course of construction of the Kemper IGCC and Mississippi Power’s recovery of costs following the date the Kemper IGCC is placed in service. With respect to recovery of costs following the in-service date of the Kemper IGCC, the 2012 MPSC CPCN Order provided for the establishment of operational cost and revenue parameters including availability factor, heat rate, lignite heat content, and chemical revenue based upon assumptions in Mississippi Power’s petition for the CPCN. Mississippi Power expects the Mississippi PSC to apply operational parameters in connection with the 2017 Rate Case and future proceedings related to the operation of the Kemper IGCC. To the extent the Mississippi PSC determines the Kemper IGCC does not meet the operational parameters ultimately adopted by the Mississippi PSC or Mississippi Power incurs additional costs to satisfy such parameters, there could be a material adverse impact on the financial statements. See “Prudence” herein for additional information. Regulatory Assets and Liabilities Consistent with the treatment of non-capital costs incurred during the pre-construction period, the Mississippi PSC issued an accounting order in 2011 granting Mississippi Power the authority to defer all non-capital Kemper IGCC-related costs to a regulatory asset through the in-service date, subject to review of such costs by the Mississippi PSC. Such costs include, but are not limited to, carrying costs on Kemper IGCC assets currently placed in service, costs associated with Mississippi PSC and MPUS consultants, prudence costs, legal fees, and operating expenses associated with assets placed in service. In August 2014, Mississippi Power requested confirmation by the Mississippi PSC of Mississippi Power’s authority to defer all operating expenses associated with the operation of the combined cycle subject to review of such costs by the Mississippi PSC. In addition, Mississippi Power is authorized to accrue carrying costs on the unamortized balance of such regulatory assets at a rate and in a manner to be determined by the Mississippi PSC in future cost recovery mechanism proceedings. Beginning in the third quarter 2015 and the second quarter 2016, in connection with the implementation of retail and wholesale rates, respectively, Mississippi Power began expensing certain ongoing project costs and certain retail debt carrying costs (associated with assets placed in service and other non-CWIP accounts) that previously were deferred as regulatory assets and began amortizing certain regulatory assets associated with assets placed in service and consulting and legal fees. The amortization periods for these regulatory assets vary from two years to 10 years as set forth in the In-Service Asset Rate Order and the settlement agreement with wholesale customers. As of December 31, 2016, the balance associated with these regulatory assets was $97 million, of which $29 million is included in current assets. Other regulatory assets associated with the remainder of the Kemper IGCC totaled $104 million as of December 31, 2016. The amortization period for these assets is expected to be determined by the Mississippi PSC in the 2017 Rate Case. The In-Service Asset Rate Order requires Mississippi Power to submit an annual true-up calculation of its actual cost of capital, compared to the stipulated total cost of capital, with the first occurring as of May 31, 2016. At December 31, 2016, Mississippi Power’s related regulatory liability included in its balance sheet totaled approximately $7 million. See “2015 Rate Case” herein for additional information. Lignite Mine and CO2 Pipeline Facilities In conjunction with the Kemper IGCC, Mississippi Power owns the lignite mine and equipment and has acquired and will continue to acquire mineral reserves located around the Kemper IGCC site. The mine started commercial operation in June 2013. In 2010, Mississippi Power executed a 40-year management fee contract with Liberty Fuels Company, LLC (Liberty Fuels), a wholly-owned subsidiary of The North American Coal Corporation, which developed, constructed, and is operating and managing the mining operations. The contract with Liberty Fuels is effective through the end of the mine reclamation. As the mining permit holder, Liberty Fuels has a legal obligation to perform mine reclamation and Mississippi Power has a contractual obligation to fund all reclamation activities. In addition to the obligation to fund the reclamation activities, Mississippi Power currently provides working capital support to Liberty Fuels through cash advances for capital purchases, payroll, and other operating expenses. In addition, Mississippi Power has constructed and will operate the CO2 pipeline for the planned transport of captured CO2 for use in enhanced oil recovery. Mississippi Power entered into agreements with Denbury Onshore (Denbury) and Treetop Midstream Services, LLC (Treetop), pursuant to which Denbury would purchase 70% of the CO2 captured from the Kemper IGCC and Treetop would purchase 30% of the CO2 captured from the Kemper IGCC. On June 3, 2016, Mississippi Power cancelled its contract with Treetop and amended its contract with Denbury to reflect, among other things, Denbury’s agreement to purchase 100% of the CO2 captured from the Kemper IGCC, an initial contract term of 16 years, and termination rights if Mississippi Power has not satisfied its contractual obligation to deliver captured CO2 by July 1, 2017, in addition to Denbury’s existing termination rights in the event of a change in law, force majeure, or an event of default by Mississippi Power. Any termination or material modification of the agreement with Denbury could impact the operations of the Kemper IGCC and result in a material reduction in Mississippi Power’s revenues to the extent Mississippi Power is not able to enter into other similar contractual arrangements or otherwise sequester the CO2 produced. Additionally, sustained oil price reductions could result in significantly lower revenues than Mississippi Power originally forecasted to be available to offset customer rate impacts, which could have a material impact on Mississippi Power’s financial statements. The ultimate outcome of these matters cannot be determined at this time. Southern Company 2016 Annual Report Notes to Financial Statements 95 Termination of Proposed Sale of Undivided Interest In 2010 and as amended in 2012, Mississippi Power and SMEPA entered into an agreement whereby SMEPA agreed to purchase a 15% undivided interest in the Kemper IGCC (15% Undivided Interest). On May 20, 2015, SMEPA notified Mississippi Power of its termination of the agreement. Mississippi Power previously received a total of $275 million of deposits from SMEPA that were required to be returned to SMEPA with interest. On June 3, 2015, Southern Company, pursuant to its guarantee obligation, returned approximately $301 million to SMEPA. Subsequently, Mississippi Power issued a promissory note in the aggregate principal amount of approximately $301 million to Southern Company, which matures on December 1, 2017. Litigation On April 26, 2016, a complaint against Mississippi Power was filed in Harrison County Circuit Court (Circuit Court) by Biloxi Freezing & Processing Inc., Gulfside Casino Partnership, and John Carlton Dean, which was amended and refiled on July 11, 2016 to include, among other things, Southern Company as a defendant. On August 12, 2016, Southern Company and Mississippi Power removed the case to the U.S. District Court for the Southern District of Mississippi. The plaintiffs filed a request to remand the case back to state court, which was granted on November 17, 2016. The individual plaintiff, John Carlton Dean, alleges that Mississippi Power and Southern Company violated the Mississippi Unfair Trade Practices Act. All plaintiffs have alleged that Mississippi Power and Southern Company concealed, falsely represented, and failed to fully disclose important facts concerning the cost and schedule of the Kemper IGCC and that these alleged breaches have unjustly enriched Mississippi Power and Southern Company. The plaintiffs seek unspecified actual damages and punitive damages; ask the Circuit Court to appoint a receiver to oversee, operate, manage, and otherwise control all affairs relating to the Kemper IGCC; ask the Circuit Court to revoke any licenses or certificates authorizing Mississippi Power or Southern Company to engage in any business related to the Kemper IGCC in Mississippi; and seek attorney’s fees, costs, and interest. The plaintiffs also seek an injunction to prevent any Kemper IGCC costs from being charged to customers through electric rates. On December 7, 2016, Southern Company and Mississippi Power filed motions to dismiss. On June 9, 2016, Treetop, Greenleaf, Tenrgys, LLC, Tellus Energy, LLC, WCOA, LLC, and Tellus Operating Group filed a complaint against Mississippi Power, Southern Company, and SCS in the state court in Gwinnett County, Georgia. The complaint relates to the cancelled CO2 contract with Treetop and alleges fraudulent misrepresentation, fraudulent concealment, civil conspiracy, and breach of contract on the part of Mississippi Power, Southern Company, and SCS and seeks compensatory damages of $100 million, as well as unspecified punitive damages. Southern Company, Mississippi Power, and SCS have moved to compel arbitration pursuant to the terms of the CO2 contract. Southern Company believes these legal challenges have no merit; however, an adverse outcome in these proceedings could have an impact on Southern Company’s results of operations, financial condition, and liquidity. Southern Company will vigorously defend itself in these matters, and the ultimate outcome of these matters cannot be determined at this time. Baseload Act In 2008, the Baseload Act was signed by the Governor of Mississippi. The Baseload Act authorizes, but does not require, the Mississippi PSC to adopt a cost recovery mechanism that includes in retail base rates, prior to and during construction, all or a portion of the prudently-incurred pre-construction and construction costs incurred by a utility in constructing a base load electric generating plant. Prior to the passage of the Baseload Act, such costs would traditionally be recovered only after the plant was placed in service. The Baseload Act also provides for periodic prudence reviews by the Mississippi PSC and prohibits the cancellation of any such generating plant without the approval of the Mississippi PSC. In the event of cancellation of the construction of the plant without approval of the Mississippi PSC, the Baseload Act authorizes the Mississippi PSC to make a public interest determination as to whether and to what extent the utility will be afforded rate recovery for costs incurred in connection with such cancelled generating plant. See “Rate Recovery of Kemper IGCC Costs” herein for additional information. Bonus Depreciation In December 2015, the Protecting Americans from Tax Hikes (PATH) Act was signed into law. Bonus depreciation was extended for qualified property placed in service through 2020. The PATH Act allows for 50% bonus depreciation for 2015 through 2017, 40% bonus depreciation for 2018, and 30% bonus depreciation for 2019 and certain long-lived assets placed in service in 2020. The extension of bonus depreciation included in the PATH Act is expected to result in approximately $20 million of positive cash flows for the 2016 tax year, which was not all realized in 2016 due to a projected consolidated net operating loss (NOL) for Southern Company. Dependent upon placing the remainder of the Kemper IGCC in service by December 31, 2017, Mississippi Power expects approximately $370 million of positive cash flows from bonus depreciation for the 2017 tax year, which may not all be realized in 2017 due to additional NOL projections for the 2017 tax year. See “Kemper IGCC Schedule and Cost Estimate” herein and Note 5 under “Current and Deferred Income Taxes – Net Operating Loss” for additional information. The ultimate outcome of this matter cannot be determined at this time. investor.southerncompany.com 96 Notes to Financial Statements Investment Tax Credits The IRS allocated $133 million (Phase I) and $279 million (Phase II) of Internal Revenue Code Section 48A tax credits to Mississippi Power in connection with the Kemper IGCC. These tax credits were dependent upon meeting the IRS certification requirements, including an in-service date no later than May 11, 2014 for the Phase I credits and April 19, 2016 for the Phase II credits. In addition, the capture and sequestration (via enhanced oil recovery) of at least 65% of the CO2 produced by the Kemper IGCC during operations in accordance with the Internal Revenue Code was also a requirement of the Phase II credits. As a result of schedule extensions for the Kemper IGCC, the Phase I tax credits were recaptured in 2013 and the Phase II tax credits were recaptured in 2015. Section 174 Research and Experimental Deduction Southern Company reflected deductions for research and experimental (R&E) expenditures related to the Kemper IGCC in its federal income tax calculations since 2013 and has filed amended federal income tax returns for 2008 through 2013 to also include such deductions. The Kemper IGCC is based on first-of-a-kind technology, and Southern Company believes that a significant portion of the plant costs qualify as deductible R&E expenditures under Internal Revenue Code Section 174. In December 2016, Southern Company and the IRS reached a proposed settlement, subject to approval of the U.S. Congress Joint Committee on Taxation, resolving a methodology for these deductions. Due to the uncertainty related to this tax position, Southern Company had unrecognized tax benefits associated with these R&E deductions totaling approximately $464 million as of December 31, 2016. See Note 5 under “Unrecognized Tax Benefits” for additional information. This matter is expected to be resolved in the next 12 months; however, the ultimate outcome of this matter cannot be determined at this time. 4. JOINT OWNERSHIP AGREEMENTS Alabama Power owns an undivided interest in Units 1 and 2 at Plant Miller and related facilities jointly with PowerSouth Energy Cooperative, Inc. Georgia Power owns undivided interests in Plants Vogtle, Hatch, Wansley, and Scherer in varying amounts jointly with one or more of the following entities: OPC, MEAG Power, the City of Dalton, Georgia, Florida Power & Light Company, and Jacksonville Electric Authority. In addition, Georgia Power has joint ownership agreements with OPC for the Rocky Mountain facilities. On August 31, 2016, Georgia Power sold its 33% ownership interest in the Intercession City combustion turbine unit to Duke Energy Florida, LLC. Southern Power owns an undivided interest in Plant Stanton Unit A and related facilities jointly with the Orlando Utilities Commission, Kissimmee Utility Authority, and Florida Municipal Power Agency. At December 31, 2016, Alabama Power’s, Georgia Power’s, and Southern Power’s percentage ownership and investment (exclusive of nuclear fuel) in jointly-owned facilities in commercial operation with the above entities were as follows: Facility (Type) Plant Vogtle (nuclear) Units 1 and 2 Plant Hatch (nuclear) Plant Miller (coal) Units 1 and 2 Plant Scherer (coal) Units 1 and 2 Plant Wansley (coal) Rocky Mountain (pumped storage) Plant Stanton (combined cycle) Unit A Percent Ownership Plant in Service 45.7% 50.1 91.8 8.4 53.5 25.4 65.0 $ 3,545 1,297 1,657 258 1,046 181 155 Accumulated Depreciation (in millions) $ 2,111 585 587 90 308 129 58 CWIP $ 74 81 23 3 12 — — Georgia Power also owns 45.7% of Plant Vogtle Units 3 and 4, which are currently under construction and had a CWIP balance of approximately $3.9 billion as of December 31, 2016. See Note 3 under “Regulatory Matters – Georgia Power – Nuclear Construction” for additional information. Alabama Power and Georgia Power have contracted to operate and maintain their jointly-owned facilities, except for Rocky Mountain, as agents for their respective co-owners. Southern Power has a service agreement with SCS whereby SCS is responsible for the operation and maintenance of Plant Stanton Unit A. The companies’ proportionate share of their plant operating expenses is included in the corresponding operating expenses in the statements of income and each company is responsible for providing its own financing. Southern Company Gas has a 50% undivided ownership interest with The Williams Companies, Inc. in a 115-mile pipeline facility being constructed in northwest Georgia. The CWIP balance representing Southern Company Gas’ share of construction costs was approximately $124 million as of December 31, 2016. Southern Company Gas also has an agreement to lease its 50% undivided ownership in the pipeline facility once it is placed in service, which is currently expected to be later in 2017. Under the lease, Southern Company Gas will receive approximately $26 million annually for an initial term of 25 years. The lessee will be responsible for maintaining the pipeline during the lease term and for providing service to transportation customers under its FERC-regulated tariff. Southern Company 2016 Annual Report Notes to Financial Statements 97 5. INCOME TAXES Southern Company files a consolidated federal income tax return and various state income tax returns, some of which are combined or unitary. Under a joint consolidated income tax allocation agreement, each Southern Company subsidiary’s current and deferred tax expense is computed on a stand-alone basis and no subsidiary is allocated more current expense than would be paid if it filed a separate income tax return. PowerSecure and Southern Company Gas became participants in the income tax allocation agreement as of May 9, 2016 and July 1, 2016, respectively. In accordance with IRS regulations, each company is jointly and severally liable for the federal tax liability. Current and Deferred Income Taxes Details of income tax provisions are as follows: Federal — Current Deferred State — Current Deferred Total 2016 2015 2014 (in millions) $ $ (177) 1,266 1,089 (33) 138 105 1,194 $ 1,184 (342) 842 (108) 217 109 951 $ $ $ 175 695 870 93 14 107 977 Net cash payments (refunds) for income taxes in 2016, 2015, and 2014 were $(148) million, $(9) million, and $272 million, respectively. The tax effects of temporary differences between the carrying amounts of assets and liabilities in the financial statements and their respective tax bases, which give rise to deferred tax assets and liabilities, are as follows: Deferred tax liabilities — Accelerated depreciation Property basis differences Leveraged lease basis differences Employee benefit obligations Premium on reacquired debt Regulatory assets associated with employee benefit obligations Regulatory assets associated with AROs Other Total Deferred tax assets — Federal effect of state deferred taxes Employee benefit obligations Over recovered fuel clause Other property basis differences Deferred costs ITC carryforward Federal NOL carryforward Unbilled revenue Other comprehensive losses AROs Estimated Loss on Kemper IGCC Deferred state tax assets Other Total Valuation allowance Total deferred income taxes Portion included in accumulated deferred tax assets Accumulated deferred income taxes 2016 2015 (in millions) $ $ 15,392 2,708 314 737 89 1,584 1,781 907 23,512 597 1,868 66 401 100 1,974 1,084 92 152 1,732 484 266 679 9,495 (23) 14,040 (52) 14,092 $ $ 12,767 1,603 308 579 95 1,378 1,422 793 18,945 479 1,720 104 695 83 770 38 111 85 1,482 451 222 443 6,683 (4) 12,266 (56) 12,322 investor.southerncompany.com 98 Notes to Financial Statements The application of bonus depreciation provisions in current tax law significantly increased deferred tax liabilities related to accelerated depreciation. At December 31, 2016, the tax-related regulatory assets to be recovered from customers were $1.6 billion. These assets are primarily attributable to tax benefits flowed through to customers in prior years, deferred taxes previously recognized at rates lower than the current enacted tax law, and taxes applicable to capitalized interest. At December 31, 2016, the tax-related regulatory liabilities to be credited to customers were $219 million. These liabilities are primarily attributable to deferred taxes previously recognized at rates higher than the current enacted tax law and to unamortized ITCs. In accordance with regulatory requirements, deferred federal ITCs for the traditional electric operating companies are amortized over the life of the related property with such amortization normally applied as a credit to reduce depreciation in the statements of income. Credits amortized in this manner amounted to $22 million in 2016, $21 million in 2015, and $22 million in 2014. Southern Power’s deferred federal ITCs are amortized to income tax expense over the life of the asset. Credits amortized in this manner amounted to $37 million in 2016, $19 million in 2015, and $11 million in 2014. Also, Southern Power received cash related to federal ITCs under the renewable energy incentives of $162 million and $74 million for the years ended December 31, 2015 and 2014, respectively. No cash was received related to these incentives in 2016. Furthermore, the tax basis of the asset is reduced by 50% of the ITCs received, resulting in a net deferred tax asset. Southern Power has elected to recognize the tax benefit of this basis difference as a reduction to income tax expense in the year in which the plant reaches commercial operation. The tax benefit of the related basis differences reduced income tax expense by $173 million in 2016, $54 million in 2015, and $48 million in 2014. See “Unrecognized Tax Benefits” below for further information. Tax Credit Carryforwards At December 31, 2016, Southern Company had federal ITC and PTC carryforwards (primarily related to Southern Power) which are expected to result in $1.8 billion of federal income tax benefits. The federal ITC carryforwards begin expiring in 2032 but are expected to be fully utilized by 2022. The PTC carryforwards begin expiring in 2036 but are expected to be fully utilized by 2022. The acquisition of additional renewable projects and carrying back the federal NOL, as well as potential tax reform legislation on existing renewable incentives, could further delay existing tax credit carryforwards. The ultimate outcome of these matters cannot be determined at this time. Additionally, Southern Company had state ITC carryforwards for the state of Georgia totaling $202 million, which begin expiring in 2020 but are expected to be fully utilized. Net Operating Loss At December 31, 2016, Southern Company had a consolidated federal NOL carryforward of $3 billion, of which $2.8 billion is projected for the 2016 tax year. The federal NOL will begin expiring in 2033. However, portions of the NOL are expected to be carried back to prior tax years and forward to future tax years. The ultimate outcome of this matter cannot be determined at this time. At December 31, 2016, the state NOL carryforwards for Southern Company’s subsidiaries were as follows: Jurisdiction Mississippi Oklahoma Georgia New York New York City Florida Other states Total NOL Carryforwards $ $ 3,448 839 685 229 209 198 146 5,754 Net State Income Tax Benefit (in millions) $ 112 31 25 11 12 7 5 203 $ Tax Year NOL Begins Expiring 2032 2036 2019 2036 2036 2034 Various Southern Company 2016 Annual Report Effective Tax Rate A reconciliation of the federal statutory income tax rate to the effective income tax rate is as follows: Notes to Financial Statements 99 Federal statutory rate State income tax, net of federal deduction Employee stock plans dividend deduction Non-deductible book depreciation AFUDC-Equity ITC basis difference Federal PTCs Amortization of ITC Other Effective income tax rate 2016 35.0% 2.1 (1.2) 0.9 (2.0) (5.0) (1.2) (0.9) (0.4) 27.3% 2015 35.0% 1.9 (1.2) 1.2 (2.2) (1.5) — (0.5) 0.2 32.9% 2014 35.0% 2.3 (1.4) 1.4 (2.9) (1.6) — (0.5) 0.2 32.5% Southern Company’s effective tax rate is typically lower than the statutory rate due to employee stock plans’ dividend deduction, non-taxable AFUDC equity, and federal income tax benefits from ITCs and PTCs. On March 30, 2016, the FASB issued ASU 2016-09, which changes the accounting for income taxes for share-based payment award transactions. Entities are required to recognize all excess tax benefits and deficiencies related to the exercise or vesting of stock compensation as income tax expense or benefit in the income statement. The adoption of ASU 2016-09 did not have a material impact on Southern Company’s overall effective tax rate. See Note 1 under “Recently Issued Accounting Standards” for additional information. Unrecognized Tax Benefits Changes during the year in unrecognized tax benefits were as follows: Unrecognized tax benefits at beginning of year Tax positions increase from current periods Tax positions increase from prior periods Tax positions decrease from prior periods Balance at end of year 2016 $ 433 45 21 (15) $ 484 $ 2015 (in millions) 170 43 240 (20) 433 $ 2014 7 64 102 (3) 170 $ $ The tax positions increase from current and prior periods for 2016 and 2015 relate primarily to deductions for R&E expenditures associated with the Kemper IGCC and federal income tax benefits from deferred ITCs. See Note 3 under “Integrated Coal Gasification Combined Cycle” and “Section 174 Research and Experimental Deduction” herein for more information. The tax positions decrease from prior periods for 2016 and 2015 relates to federal income tax benefits from deferred ITCs. The impact on Southern Company’s effective tax rate, if recognized, is as follows: Tax positions impacting the effective tax rate Tax positions not impacting the effective tax rate Balance of unrecognized tax benefits 2016 $ $ 20 464 484 2015 (in millions) 10 $ 423 433 $ 2014 $ $ 10 160 170 The tax positions impacting the effective tax rate primarily relate to federal deferred income tax credits and Southern Company’s estimate of the uncertainty related to the amount of those benefits. If these tax positions are not able to be recognized due to a federal audit adjustment in the amount that has been estimated, the amount of tax credit carryforwards discussed above would be reduced by approximately $92 million. The tax positions not impacting the effective tax rate for 2016, 2015, and 2014 relate to deductions for R&E expenditures associated with the Kemper IGCC. See “Section 174 Research and Experimental Deduction” herein for more information. These amounts are presented on a gross basis without considering the related federal or state income tax impact. Accrued interest for all tax positions other than the Section 174 R&E deductions was immaterial for all years presented. Southern Company classifies interest on tax uncertainties as interest expense. Southern Company did not accrue any penalties on uncertain tax positions. investor.southerncompany.com 100 Notes to Financial Statements It is reasonably possible that the amount of the unrecognized tax benefits could change within 12 months. The settlement of federal and state audits and the U.S. Congress Joint Committee on Taxation approval of the R&E expenditures associated with the Kemper IGCC could impact the balances significantly. At this time, an estimate of the range of reasonably possible outcomes cannot be determined. See “Section 174 Research and Experimental Deduction” herein for more information. The IRS has finalized its audits of Southern Company’s consolidated federal income tax returns through 2012. Southern Company has filed its 2013, 2014, and 2015 federal income tax returns and has received partial acceptance letters from the IRS; however, the IRS has not finalized its audits. Southern Company is a participant in the Compliance Assurance Process of the IRS. The audits for Southern Company’s state income tax returns have either been concluded, or the statute of limitations has expired, for years prior to 2011. Section 174 Research and Experimental Deduction Southern Company reflected deductions for R&E expenditures related to the Kemper IGCC in its federal income tax calculations since 2013 and filed amended federal income tax returns for 2008 through 2013 to also include such deductions. The Kemper IGCC is based on first-of-a-kind technology, and Southern Company believes that a significant portion of the plant costs qualify as deductible R&E expenditures under Internal Revenue Code Section 174. In December 2016, Southern Company and the IRS reached a proposed settlement, subject to approval of the U.S. Congress Joint Committee on Taxation, resolving a methodology for these deductions. Due to the uncertainty related to this tax position, Southern Company had unrecognized tax benefits associated with these R&E deductions totaling approximately $464 million and associated interest of $28 million as of December 31, 2016. This matter is expected to be resolved in the next 12 months; however, the ultimate outcome of this matter cannot be determined at this time. See Note 3 under “Integrated Coal Gasification Combined Cycle” for additional information regarding the Kemper IGCC. 6. FINANCING Long-Term Debt Payable to an Affiliated Trust Alabama Power has formed a wholly-owned trust subsidiary for the purpose of issuing preferred securities. The proceeds of the related equity investments and preferred security sales were loaned back to Alabama Power through the issuance of junior subordinated notes totaling $206 million as of December 31, 2016 and 2015, which constitute substantially all of the assets of this trust and are reflected in the balance sheets as long-term debt payable. Alabama Power considers that the mechanisms and obligations relating to the preferred securities issued for its benefit, taken together, constitute a full and unconditional guarantee by it of the trust’s payment obligations with respect to these securities. At December 31, 2016 and 2015, trust preferred securities of $200 million were outstanding. Securities Due Within One Year A summary of scheduled maturities and redemptions of securities due within one year at December 31 was as follows: 2016 2015 Senior notes Other long-term debt Pollution control revenue bonds(*) Capitalized leases Unamortized debt issuance expense Total $ $ 1,995 485 76 32 (1) 2,587 1,810 829 4 32 (1) 2,674 $ (in millions) $ (*) Includes $40 million of pollution control revenue bonds classified as short-term since they are variable rate demand obligations that are supported by short-term credit facilities; however, the final maturity date is in 2028. Maturities through 2021 applicable to total long-term debt are as follows: $2.6 billion in 2017; $3.9 billion in 2018; $3.2 billion in 2019; $1.4 billion in 2020; and $3.1 billion in 2021. Bank Term Loans Southern Company and certain of its subsidiaries have entered into various bank term loan agreements. At December 31, 2016, Southern Company, Alabama Power, Gulf Power, Mississippi Power, and Southern Power Company had outstanding bank term loans totaling $400 million, $45 million, $100 million, $1.2 billion, and $380 million, respectively, of which $2.0 billion are reflected in the statements of capitalization as long-term debt and $100 million are reflected in the balance sheet as notes payable. At December 31, 2015, Southern Company, Mississippi Power, and Southern Power Company had outstanding bank term loans totaling $400 million, $900 million, and $400 million, respectively. Southern Company 2016 Annual Report Notes to Financial Statements 101 In March 2016, Alabama Power entered into three bank term loan agreements with maturity dates of March 2021, in an aggregate principal amount of $45 million, one of which bears interest at 2.38% per annum and two of which bear interest based on three-month LIBOR. In March 2016, Mississippi Power entered into an unsecured term loan agreement with a syndicate of financial institutions for an aggregate amount of $1.2 billion. Mississippi Power borrowed $900 million in March 2016 under the term loan agreement and the remaining $300 million in October 2016. Mississippi Power used the initial proceeds to repay $900 million in maturing bank loans in March 2016 and the remaining $300 million to repay at maturity Mississippi Power’s Series 2011A 2.35% Senior Notes due October 15, 2016. This loan matures on April 1, 2018 and bears interest based on one-month LIBOR. In May 2016, Gulf Power entered into an 11-month floating rate bank loan bearing interest based on one-month LIBOR. This short-term loan was for $100 million aggregate principal amount and the proceeds were used to repay existing indebtedness and for working capital and other general corporate purposes. In September 2016, Southern Power Company repaid $80 million of an outstanding $400 million floating rate bank loan and extended the maturity date of the remaining $320 million from September 2016 to September 2018. In addition, Southern Power Company entered into a $60 million aggregate principal amount floating rate bank loan bearing interest based on one-month LIBOR due September 2017. The proceeds were used to repay existing indebtedness and for other general corporate purposes. The outstanding bank loans as of December 31, 2016 have covenants that limit debt levels to a percentage of total capitalization. The percentage is 70% for Southern Company and 65% for Alabama Power, Gulf Power, Mississippi Power, and Southern Power Company, as defined in the agreements. For purposes of these definitions, debt excludes any long-term debt payable to affiliated trusts, other hybrid securities, and, for Southern Company and Mississippi Power, any securitized debt relating to the securitization of certain costs of the Kemper IGCC. Additionally, for Southern Company and Southern Power Company, for purposes of these definitions, debt excludes any project debt incurred by certain subsidiaries of Southern Power Company to the extent such debt is non-recourse to Southern Power Company and capitalization excludes the capital stock or other equity attributable to such subsidiary. At December 31, 2016, each of Southern Company, Alabama Power, Gulf Power, Mississippi Power, and Southern Power Company was in compliance with its debt limits. DOE Loan Guarantee Borrowings Pursuant to the loan guarantee program established under Title XVII of the Energy Policy Act of 2005 (Title XVII Loan Guarantee Program), Georgia Power and the DOE entered into a loan guarantee agreement (Loan Guarantee Agreement) in February 2014, under which the DOE agreed to guarantee the obligations of Georgia Power under a note purchase agreement (FFB Note Purchase Agreement) among the DOE, Georgia Power, and the FFB and a related promissory note (FFB Promissory Note). The FFB Note Purchase Agreement and the FFB Promissory Note provide for a multi-advance term loan facility (FFB Credit Facility), under which Georgia Power may make term loan borrowings through the FFB. Proceeds of advances made under the FFB Credit Facility are used to reimburse Georgia Power for a portion of certain costs of construction relating to Plant Vogtle Units 3 and 4 that are eligible for financing under the Title XVII Loan Guarantee Program (Eligible Project Costs). Aggregate borrowings under the FFB Credit Facility may not exceed the lesser of (i) 70% of Eligible Project Costs or (ii) approximately $3.46 billion. All borrowings under the FFB Credit Facility are full recourse to Georgia Power, and Georgia Power is obligated to reimburse the DOE for any payments the DOE is required to make to the FFB under the guarantee. Georgia Power’s reimbursement obligations to the DOE are full recourse and secured by a first priority lien on (i) Georgia Power’s 45.7% undivided ownership interest in Plant Vogtle Units 3 and 4 (primarily the units under construction, the related real property, and any nuclear fuel loaded in the reactor core) and (ii) Georgia Power’s rights and obligations under the principal contracts relating to Plant Vogtle Units 3 and 4. There are no restrictions on Georgia Power’s ability to grant liens on other property. Advances may be requested under the FFB Credit Facility on a quarterly basis through 2020. The final maturity date for each advance under the FFB Credit Facility is February 20, 2044. Interest is payable quarterly and principal payments will begin on February 20, 2020. Borrowings under the FFB Credit Facility will bear interest at the applicable U.S. Treasury rate plus a spread equal to 0.375%. In connection with its entry into the agreements with the DOE and the FFB, Georgia Power incurred issuance costs of approximately $66 million, which are being amortized over the life of the borrowings under the FFB Credit Facility. In June and December 2016, Georgia Power made borrowings under the FFB Credit Facility in an aggregate principal amount of $300 million and $125 million, respectively. The interest rate applicable to the $300 million principal amount is 2.571% and the interest rate applicable to the $125 million principal amount is 3.142%, both for an interest period that extends to the final maturity date of February 20, 2044. At December 31, 2016 and 2015, Georgia Power had $2.6 billion and $2.2 billion of borrowings outstanding under the FFB Credit Facility, respectively. Future advances are subject to satisfaction of customary conditions, as well as certification of compliance with the requirements of the Title XVII Loan Guarantee Program, including accuracy of project-related representations and warranties, delivery of updated project-related information, and evidence of compliance with the prevailing wage requirements of the Davis-Bacon Act of 1931, as amended, and certification from the DOE’s consulting engineer that proceeds of the advances are used to reimburse Eligible Project Costs. investor.southerncompany.com 102 Notes to Financial Statements Under the Loan Guarantee Agreement, Georgia Power is subject to customary borrower affirmative and negative covenants and events of default. In addition, Georgia Power is subject to project-related reporting requirements and other project-specific covenants and events of default. In the event certain mandatory prepayment events occur, the FFB’s commitment to make further advances under the FFB Credit Facility will terminate and Georgia Power will be required to prepay the outstanding principal amount of all borrowings under the FFB Credit Facility over a period of five years (with level principal amortization). Among other things, these mandatory prepayment events include (i) the termination of the Vogtle 3 and 4 Agreement; (ii) cancellation of Plant Vogtle Units 3 and 4 by the Georgia PSC, or by Georgia Power if authorized by the Georgia PSC; and (iii) cost disallowances by the Georgia PSC that could have a material adverse effect on completion of Plant Vogtle Units 3 and 4 or Georgia Power’s ability to repay the outstanding borrowings under the FFB Credit Facility. Under certain circumstances, insurance proceeds and any proceeds from an event of taking must be applied to immediately prepay outstanding borrowings under the FFB Credit Facility. Georgia Power also may voluntarily prepay outstanding borrowings under the FFB Credit Facility. Under the FFB Promissory Note, any prepayment (whether mandatory or optional) will be made with a make-whole premium or discount, as applicable. In connection with any cancellation of Plant Vogtle Units 3 and 4 that results in a mandatory prepayment event, the DOE may elect to continue construction of Plant Vogtle Units 3 and 4. In such an event, the DOE will have the right to assume Georgia Power’s rights and obligations under the principal agreements relating to Plant Vogtle Units 3 and 4 and to acquire all or a portion of Georgia Power’s ownership interest in Plant Vogtle Units 3 and 4. Senior Notes Southern Company and its subsidiaries issued a total of $13.3 billion of senior notes in 2016. Southern Company issued $8.5 billion and its subsidiaries issued a total of $4.8 billion. These amounts include senior notes issued by Southern Company Gas subsequent to the Merger. The proceeds of Southern Company’s issuances were used to fund a portion of the consideration for the Merger and related transaction costs and for general corporate purposes. Except as described below, the proceeds of Southern Company’s subsidiaries’ issuances were used to repay long-term indebtedness, to repay short-term indebtedness, and for other general corporate purposes, including the applicable subsidiaries’ continuous construction programs, and, for Southern Power, its growth strategy. Certain of Georgia Power’s and Southern Power’s issuances were allocated to eligible renewable energy expenditures. The proceeds of Southern Company Gas’ issuances were primarily used to repay a $360 million promissory note issued to Southern Company for the purpose of funding a portion of the purchase price for a 50% equity interest in Southern Natural Gas Company, L.L.C. (SNG), to fund the purchase of Piedmont Natural Gas Company, Inc.’s (Piedmont) interest in SouthStar Energy Services, LLC (SouthStar), and to make a voluntary contribution to Southern Company Gas’ pension plan. See Note 12 under “Southern Company – Investment in Southern Natural Gas” and “ – Acquisition of Remaining Interest in SouthStar” for additional information. At December 31, 2016 and 2015, Southern Company and its subsidiaries had a total of $33.0 billion and $19.1 billion, respectively, of senior notes outstanding. At December 31, 2016 and 2015, Southern Company had a total of $10.3 billion and $2.4 billion, respectively, of senior notes outstanding. These amounts include senior notes due within one year. Subsequent to December 31, 2016, Alabama Power repaid at maturity $200 million aggregate principal amount of its Series 2007A 5.55% Senior Notes due February 1, 2017. Since Southern Company is a holding company, the right of Southern Company and, hence, the right of creditors of Southern Company (including holders of Southern Company senior notes) to participate in any distribution of the assets of any subsidiary of Southern Company, whether upon liquidation, reorganization or otherwise, is subject to prior claims of creditors and preferred and preference stockholders of such subsidiary. Junior Subordinated Notes At December 31, 2016 and 2015, Southern Company had a total of $2.4 billion and $1.0 billion, respectively, of junior subordinated notes outstanding. In September 2016, Southern Company issued $800 million aggregate principal amount of Series 2016A 5.25% Junior Subordinated Notes due October 1, 2076. The proceeds were used to repay short-term indebtedness that was incurred to repay at maturity $500 million aggregate principal amount of Southern Company’s Series 2011A 1.95% Senior Notes due September 1, 2016 and for other general corporate purposes. In December 2016, Southern Company issued $550 million aggregate principal amount of Series 2016B Junior Subordinated Notes due March 15, 2057, which bear interest at a fixed rate of 5.50% per year up to, but not including, March 15, 2022. From, and including, March 15, 2022, the Series 2016B Junior Subordinated Notes will bear interest at a floating rate based on three-month LIBOR. The proceeds were used for general corporate purposes. Southern Company 2016 Annual Report Notes to Financial Statements 103 Pollution Control Revenue Bonds Pollution control revenue bond obligations represent loans to the traditional electric operating companies from public authorities of funds derived from sales by such authorities of revenue bonds issued to finance pollution control and solid waste disposal facilities. In some cases, the pollution control revenue bond obligations represent obligations under installment sales agreements with respect to facilities constructed with the proceeds of revenue bonds issued by public authorities. The traditional electric operating companies had $3.3 billion of outstanding pollution control revenue bond obligations at December 31, 2016 and 2015, which includes pollution control revenue bonds due within one year. The traditional electric operating companies are required to make payments sufficient for the authorities to meet principal and interest requirements of such bonds. Proceeds from certain issuances are restricted until qualifying expenditures are incurred. Plant Daniel Revenue Bonds In 2011, in connection with Mississippi Power’s election under its operating lease of Plant Daniel Units 3 and 4 to purchase the assets, Mississippi Power assumed the obligations of the lessor related to $270 million aggregate principal amount of Mississippi Business Finance Corporation Taxable Revenue Bonds, 7.13% Series 1999A due October 20, 2021, issued for the benefit of the lessor. See “Assets Subject to Lien” herein for additional information. Gas Facility Revenue Bonds Pivotal Utility Holdings, Inc., a subsidiary of Southern Company Gas, is party to a series of loan agreements with the New Jersey Economic Development Authority and Brevard County, Florida under which five series of gas facility revenue bonds have been issued with maturities ranging from 2022 to 2033. These revenue bonds are issued by state agencies or counties to investors, and proceeds from the issuance then are loaned to Southern Company Gas. The amount of gas facility revenue bonds outstanding at December 31, 2016 was $200 million. Other Revenue Bonds Other revenue bond obligations represent loans to Mississippi Power from a public authority of funds derived from the sale by such authority of revenue bonds issued to finance a portion of the costs of constructing the Kemper IGCC and related facilities. Mississippi Power had $50 million of such obligations outstanding related to tax-exempt revenue bonds at December 31, 2016 and 2015. Such amounts are reflected in the statements of capitalization as long-term senior notes and debt. First Mortgage Bonds Nicor Gas, a subsidiary of Southern Company Gas, had $625 million of first mortgage bonds outstanding at December 31, 2016. These bonds have been issued with maturities ranging from 2019 to 2038. Substantially all of Nicor Gas’ properties are subject to the lien of the indenture securing these first mortgage bonds. See “Assets Subject to Lien” herein for additional information. Capital Leases Assets acquired under capital leases are recorded in the balance sheets as property, plant, and equipment and the related obligations are classified as long-term debt. In 2013, Mississippi Power entered into a nitrogen supply agreement for the air separation unit of the Kemper IGCC, which resulted in a capital lease obligation at December 31, 2016 and 2015 of approximately $74 million and $77 million, respectively, with an annual interest rate of 4.9% for both years. Amortization of the capital lease asset for the air separation unit will begin when the Kemper IGCC is placed in service. See Note 3 under “Integrated Coal Gasification Combined Cycle” for additional information regarding the Kemper IGCC. At December 31, 2016 and 2015, the capitalized lease obligations for Georgia Power’s corporate headquarters building were $28 million and $35 million, respectively, with an annual interest rate of 7.9% for both years. At December 31, 2016 and 2015, Alabama Power had capitalized lease obligations of $4 million and $5 million, respectively, for a natural gas pipeline with an annual interest rate of 6.9%. At December 31, 2016 and 2015, a subsidiary of Southern Company had capital lease obligations of approximately $29 million and $30 million, respectively, for certain computer equipment including desktops, laptops, servers, printers, and storage devices with annual interest rates that range from 1.4% to 3.4%. Assets Subject to Lien Each of Southern Company’s subsidiaries is organized as a legal entity, separate and apart from Southern Company and its other subsidiaries. There are no agreements or other arrangements among the Southern Company system companies under which the assets of one company have been pledged or otherwise made available to satisfy obligations of Southern Company or any of its other subsidiaries. investor.southerncompany.com 104 Notes to Financial Statements Gulf Power has granted one or more liens on certain of its property in connection with the issuance of certain series of pollution control revenue bonds with an aggregate outstanding principal amount of $41 million as of December 31, 2016. The revenue bonds assumed in conjunction with Mississippi Power’s purchase of Plant Daniel Units 3 and 4 are secured by Plant Daniel Units 3 and 4 and certain related personal property. See “Plant Daniel Revenue Bonds” herein for additional information. See “DOE Loan Guarantee Borrowings” above for information regarding certain borrowings of Georgia Power that are secured by a first priority lien on (i) Georgia Power’s 45.7% undivided ownership interest in Plant Vogtle Units 3 and 4 (primarily the units under construction, the related real property, and any nuclear fuel loaded in the reactor core) and (ii) Georgia Power’s rights and obligations under the principal contracts relating to Plant Vogtle Units 3 and 4. The first mortgage bonds issued by Nicor Gas are secured by substantially all of Nicor Gas’ properties. See “First Mortgage Bonds” herein for additional information. During 2016, in accordance with its overall growth strategy, Southern Power acquired the Mankato project. Under the terms of the remaining 10-year PPA and the 20-year expansion PPA, approximately $408 million of assets, primarily related to property, plant, and equipment, are subject to lien at December 31, 2016. See Note 12 under “Southern Power” for additional information. Bank Credit Arrangements At December 31, 2016, committed credit arrangements with banks were as follows: Company 2017 2018 (in millions) 2020 Total Unused (in millions) Expires Executable Term Loans One Year (in millions) Two Years Expires Within One Year Term Out No Term Out (in millions) $ — $ Southern Company(a) 35 Alabama Power — Georgia Power 85 Gulf Power 173 Mississippi Power Southern Power Company(b) — Southern Company Gas(c) 75 55 Other 423 $ Southern Company Consolidated (a) Represents the Southern Company parent entity. (b) Excludes credit agreements (Project Credit Facilities) assumed with the acquisition of certain solar facilities, which were non-recourse to Southern Power Company, the proceeds of which were used to finance project costs related to such solar facilities. See Note 12 under “Southern Power” for additional information. Also excludes a $120 million continuing letter of credit facility entered into by Southern Power in December 2016 for standby letters of credit expiring in 2019. At December 31, 2016, the total amount available under the letter of credit facility was $82 million. 2,250 $ — $ — $ — $ 1,335 1,732 280 150 522 1,949 55 8,273 2,250 $ 1,335 1,750 280 173 600 2,000 55 8,443 1,250 $ 800 1,750 — — 600 — — 4,400 $ 1,000 $ 500 — 195 — — 1,925 — 3,620 $ — — 25 13 — — 20 58 $ — — 45 — — — 20 65 — — — 13 — — — 13 — 35 — 60 160 — 75 35 365 $ $ $ $ $ (c) Southern Company Gas, as the parent entity, guarantees the obligations of Southern Company Gas Capital, which is the borrower of $1.3 billion of these arrangements. Southern Company Gas’ committed credit arrangements also include $700 million for which Nicor Gas is the borrower and which is restricted for working capital needs of Nicor Gas. Most of the bank credit arrangements require payment of commitment fees based on the unused portion of the commitments or the maintenance of compensating balances with the banks. Commitment fees average less than 1/4 of 1% for Southern Company, the traditional electric operating companies, Southern Power Company, Southern Company Gas, and Nicor Gas. Compensating balances are not legally restricted from withdrawal. Subject to applicable market conditions, Southern Company and its subsidiaries expect to renew or replace their bank credit arrangements as needed, prior to expiration. In connection therewith, Southern Company and its subsidiaries may extend the maturity dates and/or increase or decrease the lending commitments thereunder. Southern Company’s, Southern Company Gas’, and Nicor Gas’ credit arrangements contain covenants that limit debt levels to 70% of total capitalization, as defined in the agreements, and most of these other bank credit arrangements contain covenants that limit debt levels to 65% of total capitalization, as defined in the agreements. For purposes of these definitions, debt excludes the long-term debt payable to affiliated trusts and, in certain arrangements, other hybrid securities, and, for Southern Company and Mississippi Power, any securitized debt relating to the securitization of certain costs of the Kemper IGCC. Additionally, for Southern Company and Southern Power Company, for purposes of these definitions, debt excludes any project debt incurred by certain subsidiaries of Southern Power Company to the extent such debt is non-recourse to Southern Power Company and capitalization excludes the capital stock or other equity attributable to such subsidiaries. At December 31, 2016, Southern Company, the traditional electric operating companies, Southern Power Company, Southern Company Gas, and Nicor Gas were each in compliance with their respective debt limit covenants. Southern Company 2016 Annual Report Notes to Financial Statements 105 A portion of the $8.3 billion unused credit with banks is allocated to provide liquidity support to the pollution control revenue bonds of the traditional electric operating companies and the commercial paper programs of Southern Company, the traditional electric operating companies, Southern Power Company, Southern Company Gas, and Nicor Gas. The amount of variable rate pollution control revenue bonds of the traditional electric operating companies outstanding requiring liquidity support as of December 31, 2016 was approximately $1.9 billion. In addition, at December 31, 2016, the traditional electric operating companies had approximately $0.4 billion of fixed rate pollution control revenue bonds outstanding that were required to be remarketed within the next 12 months. Southern Company, the traditional electric operating companies, Southern Power Company, Southern Company Gas, and Nicor Gas make short-term borrowings primarily through commercial paper programs that have the liquidity support of the committed bank credit arrangements described above. Commercial paper and short-term bank term loans are included in notes payable in the balance sheets. Details of short-term borrowings were as follows: December 31, 2016: Commercial paper Short-term bank debt Total December 31, 2015: Commercial paper Short-term bank debt Total Short-term Debt at the End of the Period Amount Outstanding (in millions) $ $ $ $ 1,909 123 2,032 740 500 1,240 Weighted Average Interest Rate 1.1% 1.7% 1.1% 0.7% 1.4% 0.9% In addition to the short-term borrowings in the table above, Southern Power’s subsidiary Project Credit Facilities had total amounts outstanding of $209 million and $137 million at a weighted average interest rate of 2.1% and 2.0% as of December 31, 2016 and 2015, respectively. The amounts outstanding as of December 31, 2016 under the Project Credit Facilities were fully repaid subsequent to December 31, 2016. Redeemable Preferred Stock of Subsidiaries Each of the traditional electric operating companies has issued preferred and/or preference stock. The preferred stock of Alabama Power and Mississippi Power contains a feature that allows the holders to elect a majority of such subsidiary’s board of directors if preferred dividends are not paid for four consecutive quarters. Because such a potential redemption-triggering event is not solely within the control of Alabama Power and Mississippi Power, this preferred stock is presented as “Redeemable Preferred Stock of Subsidiaries” in a manner consistent with temporary equity under applicable accounting standards. The preferred and preference stock at Georgia Power and the preference stock at Alabama Power and Gulf Power do not contain such a provision. As a result, under applicable accounting standards, the preferred and preference stock at Georgia Power and the preference stock at Alabama Power and Gulf Power are presented as “Preferred and Preference Stock of Subsidiaries,” a separate component of “Stockholders’ Equity,” on Southern Company’s balance sheets, statements of capitalization, and statements of stockholders’ equity. The following table presents changes during the year in redeemable preferred stock of subsidiaries for Southern Company: Balance at December 31, 2013 Issued Redeemed Balance at December 31, 2014 Issued Redeemed Other Balance at December 31, 2015 Issued Redeemed Balance at December 31, 2016 Redeemable Preferred Stock of Subsidiaries (in millions) $ $ 375 — — 375 — (262) 5 118 — — 118 investor.southerncompany.com 106 Notes to Financial Statements 7. COMMITMENTS Fuel and Purchased Power Agreements To supply a portion of the fuel requirements of the generating plants, the Southern Company system has entered into various long-term commitments for the procurement and delivery of fossil and nuclear fuel which are not recognized on the balance sheets. In 2016, 2015, and 2014, the traditional electric operating companies and Southern Power incurred fuel expense of $4.4 billion, $4.8 billion, and $6.0 billion, respectively, the majority of which was purchased under long-term commitments. Southern Company expects that a substantial amount of the Southern Company system’s future fuel needs will continue to be purchased under long-term commitments. In addition, the Southern Company system has entered into various long-term commitments for the purchase of capacity and electricity, some of which are accounted for as operating leases or have been used by a third party to secure financing. Total capacity expense under PPAs accounted for as operating leases was $232 million, $227 million, and $198 million for 2016, 2015, and 2014, respectively. Estimated total obligations under these commitments at December 31, 2016 were as follows: Operating Leases(*) Other (in millions) 2017 2018 2019 2020 2021 2022 and thereafter Total (*) A total of $197 million of biomass PPAs included under operating leases is contingent upon the counterparties meeting specified contract 242 246 249 246 249 1,041 2,273 $ $ $ $ 8 7 6 5 5 43 74 dates for commercial operation. Subsequent to December 31, 2016, the specified contract dates for commercial operation were extended from 2017 to 2019 and may change further as a result of regulatory action. Pipeline Charges, Storage Capacity, and Gas Supply Pipeline charges, storage capacity, and gas supply include charges recoverable through a natural gas cost recovery mechanism, or alternatively, billed to marketers selling retail natural gas, as well as demand charges associated with Southern Company Gas’ wholesale gas services. The gas supply balance includes amounts for gas commodity purchase commitments associated with Southern Company Gas’ gas marketing services of 33 million mmBtu at floating gas prices calculated using forward natural gas prices at December 31, 2016 and valued at $106 million. Southern Company Gas provides guarantees to certain gas suppliers for certain of its subsidiaries in support of payment obligations. Expected future contractual obligations for pipeline charges, storage capacity, and gas supply that are not recognized on the balance sheets as of December 31, 2016 were as follows: 2017 2018 2019 2020 2021 2022 and thereafter Total Operating Leases Pipeline Charges, Storage Capacity, and Gas Supply (in millions) $ $ 822 602 447 394 352 2,591 5,208 The Southern Company system has operating lease agreements with various terms and expiration dates. Total rent expense was $169 million, $130 million, and $118 million for 2016, 2015, and 2014, respectively. Southern Company includes any step rents, escalations, and lease concessions in its computation of minimum lease payments, which are recognized on a straight-line basis over the minimum lease term. Southern Company 2016 Annual Report As of December 31, 2016, estimated minimum lease payments under operating leases were as follows: Minimum Lease Payments Notes to Financial Statements 107 2017 2018 2019 2020 2021 2022 and thereafter Total Barges & Railcars $ 31 19 10 10 8 11 $ 89 $ Other (in millions) 121 115 103 90 82 1,184 1,695 $ Total $ $ 152 134 113 100 90 1,195 1,784 For the traditional electric operating companies, a majority of the barge and railcar lease expenses are recoverable through fuel cost recovery provisions. In addition to the above rental commitments, Alabama Power and Georgia Power have obligations upon expiration of certain railcar leases with respect to the residual value of the leased property. These leases have terms expiring through 2024 with maximum obligations under these leases of $44 million. At the termination of the leases, the lessee may renew the lease, exercise its purchase option, or the property can be sold to a third party. Alabama Power and Georgia Power expect that the fair market value of the leased property would substantially reduce or eliminate the payments under the residual value obligations. Guarantees In 2013, Georgia Power entered into an agreement that requires Georgia Power to guarantee certain payments of a gas supplier for Plant McIntosh for a period up to 15 years. The guarantee is expected to be terminated if certain events occur within one year of the initial gas deliveries in 2018. In the event the gas supplier defaults on payments, the maximum potential exposure under the guarantee is approximately $43 million. As discussed above under “Operating Leases,” Alabama Power and Georgia Power have entered into certain residual value guarantees. 8. COMMON STOCK Stock Issued In May and August 2016, Southern Company issued an aggregate of 50.8 million shares of common stock in underwritten offerings for an aggregate purchase price of approximately $2.5 billion. Of the 50.8 million shares, approximately 2.6 million were issued from treasury and the remainder were newly issued shares. The proceeds were used to fund a portion of the consideration for the Merger and related transaction costs, to fund a portion of the purchase price for the SNG investment and related transaction costs, and for other general corporate purposes. During the fourth quarter 2016, Southern Company issued approximately 8.0 million shares of common stock through at-the- market issuances pursuant to sales agency agreements related to Southern Company’s continuous equity offering program and received cash proceeds of approximately $381 million, net of $3 million in fees and commissions. In addition, during 2016, Southern Company issued approximately 20 million shares of common stock primarily through employee equity compensation plans and received proceeds of approximately $874 million. Shares Reserved At December 31, 2016, a total of 94 million shares were reserved for issuance pursuant to the Southern Investment Plan, the Employee Savings Plan, the Outside Directors Stock Plan, and the Omnibus Incentive Compensation Plan (which includes stock options and performance share units as discussed below). Of the total 94 million shares reserved, there were 14 million shares of common stock remaining available for awards under the Omnibus Incentive Compensation Plan as of December 31, 2016. Stock-Based Compensation Stock-based compensation primarily in the form of performance share units may be granted through the Omnibus Incentive Compensation Plan to a large segment of Southern Company system employees ranging from line management to executives. As of December 31, 2016, there were 5,229 current and former employees participating in the stock option and performance share unit programs. investor.southerncompany.com 108 Notes to Financial Statements In conjunction with the Merger, stock-based compensation in the form of Southern Company restricted stock and performance share units was also granted to certain executives of Southern Company Gas through the Southern Company Omnibus Incentive Compensation Plan. Stock Options Through 2009, stock-based compensation granted to employees consisted exclusively of non-qualified stock options. The exercise price for stock options granted equaled the stock price of Southern Company common stock on the date of grant. Stock options vest on a pro rata basis over a maximum period of three years from the date of grant or immediately upon the retirement or death of the employee. Options expire no later than 10 years after the grant date. All unvested stock options vest immediately upon a change in control where Southern Company is not the surviving corporation. Compensation expense is generally recognized on a straight-line basis over the three-year vesting period with the exception of employees that are retirement eligible at the grant date and employees that will become retirement eligible during the vesting period. Compensation expense in those instances is recognized at the grant date for employees that are retirement eligible and through the date of retirement eligibility for those employees that become retirement eligible during the vesting period. In 2015, Southern Company discontinued the granting of stock options. The estimated fair values of stock options granted were derived using the Black-Scholes stock option pricing model. Expected volatility was based on historical volatility of Southern Company’s stock over a period equal to the expected term. Southern Company used historical exercise data to estimate the expected term that represents the period of time that options granted to employees are expected to be outstanding. The risk-free rate was based on the U.S. Treasury yield curve in effect at the time of grant that covers the expected term of the stock options. The following table shows the assumptions used in the pricing model and the weighted average grant-date fair value of stock options granted: Year Ended December 31 Expected volatility Expected term (in years) Interest rate Dividend yield Weighted average grant-date fair value Southern Company’s activity in the stock option program for 2016 is summarized below: 2014 14.6% 5 1.5% 4.9% $2.20 Outstanding at December 31, 2015 Exercised Cancelled Outstanding at December 31, 2016 Exercisable at December 31, 2016 Shares Subject to Option 35,749,906 11,120,613 43,429 24,585,864 21,133,320 $ Weighted Average Exercise Price 40.96 40.26 41.38 41.28 41.26 $ $ The number of stock options vested, and expected to vest in the future, as of December 31, 2016 was not significantly different from the number of stock options outstanding at December 31, 2016 as stated above. As of December 31, 2016, the weighted average remaining contractual term for the options outstanding and options exercisable was approximately six years and five years, respectively, and the aggregate intrinsic value for the options outstanding and options exercisable was $195 million and $168 million, respectively. For the years ended December 31, 2016, 2015, and 2014, total compensation cost for stock option awards recognized in income was $3 million, $6 million, and $27 million, respectively, with the related tax benefit also recognized in income of $1 million, $2 million, and $10 million, respectively. As of December 31, 2016, the total unrecognized compensation cost related to stock option awards not yet vested was immaterial. The total intrinsic value of options exercised during the years ended December 31, 2016, 2015, and 2014 was $120 million, $48 million, and $125 million, respectively. The actual tax benefit for the tax deductions from stock option exercises totaled $46 million, $19 million, and $48 million for the years ended December 31, 2016, 2015, and 2014, respectively. Prior to the adoption of ASU 2016-09, the excess tax benefits related to the exercise of stock options were recognized in Southern Company’s financial statements with a credit to equity. Upon the adoption of ASU 2016-09, beginning in 2016, all tax benefits related to the exercise of stock options are recognized in income. Southern Company has a policy of issuing shares to satisfy share option exercises. Cash received from issuances related to option exercises under the share-based payment arrangements for the years ended December 31, 2016, 2015, and 2014 was $448 million, $154 million, and $400 million, respectively. Southern Company 2016 Annual Report Notes to Financial Statements 109 Performance Share Units From 2010 through 2014, stock-based compensation granted to employees included performance share units in addition to stock options. Beginning in 2015, stock-based compensation consisted exclusively of performance share units. Performance share units granted to employees vest at the end of a three-year performance period. All unvested performance share units vest immediately upon a change in control where Southern Company is not the surviving corporation. Shares of Southern Company common stock are delivered to employees at the end of the performance period with the number of shares issued ranging from 0% to 200% of the target number of performance share units granted, based on achievement of the performance goals established by the Compensation Committee of the Southern Company Board of Directors. The performance goal for all performance share units issued from 2010 through 2014 was based on the total shareholder return (TSR) for Southern Company common stock during the three-year performance period as compared to a group of industry peers. For these performance share units, at the end of three years, active employees receive shares based on Southern Company’s performance while retired employees receive a pro rata number of shares based on the actual months of service during the performance period prior to retirement. The fair value of TSR-based performance share unit awards is determined as of the grant date using a Monte Carlo simulation model to estimate the TSR of Southern Company’s common stock among the industry peers over the performance period. Southern Company recognizes compensation expense on a straight-line basis over the three-year performance period without remeasurement. Beginning in 2015, Southern Company issued two additional types of performance share units to employees in addition to the TSR- based awards. These included performance share units with performance goals based on cumulative earnings per share (EPS) over the performance period and performance share units with performance goals based on Southern Company’s equity-weighted ROE over the performance period. The EPS-based and ROE-based awards each represent 25% of total target grant date fair value of the performance share unit awards granted. The remaining 50% of the target grant date fair value consists of TSR-based awards. In contrast to the Monte Carlo simulation model used to determine the fair value of the TSR-based awards, the fair values of the EPS-based awards and the ROE-based awards are based on the closing stock price of Southern Company common stock on the date of the grant. Compensation expense for the EPS-based and ROE-based awards is generally recognized ratably over the three- year performance period initially assuming a 100% payout at the end of the performance period. The TSR-based performance share units, along with the EPS-based and ROE-based awards, vest immediately upon the retirement of the employee. As a result, compensation expense for employees that are retirement eligible at the grant date is recognized immediately while compensation expense for employees that become retirement eligible during the vesting period is recognized over the period from grant date to the date of retirement eligibility. The expected payout related to the EPS-based and ROE-based awards is reevaluated annually with expense recognized to date increased or decreased based on the number of shares currently expected to be issued. Unlike the TSR-based awards, the compensation expense ultimately recognized for the EPS-based awards and the ROE-based awards will be based on the actual number of shares issued at the end of the performance period. In determining the fair value of the TSR-based awards issued to employees, the expected volatility was based on the historical volatility of Southern Company’s stock over a period equal to the performance period. The risk-free rate was based on the U.S. Treasury yield curve in effect at the time of grant that covers the performance period of the awards. The following table shows the assumptions used in the pricing model and the weighted average grant-date fair value of performance share award units granted: Year Ended December 31 Expected volatility Expected term (in years) Interest rate Annualized dividend rate(*) Weighted average grant-date fair value 2016 15.0% 3 0.8% N/A 45.06 $ 2015 12.9% 3 1.0% 2014 12.6% 3 0.6% N/A 46.38 $ $ $ 2.03 37.54 N/A - Not applicable (*) Beginning in 2015, cash dividends paid on Southern Company’s common stock are accumulated and payable in additional shares of Southern Company’s common stock at the end of the three-year performance period and are embedded in the grant date fair value which equates to the grant date stock price. The weighted average grant-date fair value of both EPS-based and ROE-based performance share units granted during 2016 and 2015 was $48.87 and $47.75, respectively. Total unvested performance share units outstanding as of December 31, 2015 were 2,480,392. During 2016, 1,717,167 performance share units were granted, 937,121 performance share units were vested, and 35,899 performance share units were forfeited, resulting in 3,224,539 unvested performance share units outstanding at December 31, 2016. No shares were issued in January 2017 for the three-year performance and vesting period ended December 31, 2016. For the years ended December 31, 2016, 2015, and 2014, total compensation cost for performance share units recognized in income was $96 million, $88 million, and $33 million, respectively, with the related tax benefit also recognized in income of $37 million, $34 million, and $13 million, respectively. As of December 31, 2016, $32 million of total unrecognized compensation cost related to performance share award units will be recognized over a weighted-average period of approximately 22 months. investor.southerncompany.com 110 Notes to Financial Statements Southern Company Gas Restricted Stock Awards At the effective time of the Merger, each outstanding award of existing Southern Company Gas performance share units was converted into an award of Southern Company’s restricted stock units (RSU). Under the terms of the RSU awards, the employees received Southern Company stock when they satisfy the requisite service period by being continuously employed through the original three-year vesting schedule of the award being replaced. Southern Company issued 742,461 RSUs with a grant-date fair value of $53.83, based on the closing stock price of Southern Company common stock on the date of the grant. As a portion of the fair value of the award related to pre-combination service, the grant date fair value was allocated to pre- or post-combination service and accounted for as Merger consideration or compensation cost, respectively. Approximately $13 million of the grant date fair value was allocated to Merger consideration. As of December 31, 2016, total compensation cost and related tax benefit for RSUs recognized in income was $13 million and $4 million, respectively. As of December 31, 2016, $12 million of total unrecognized compensation cost related to RSUs is expected to be recognized over a weighted-average period of approximately 20 months. Southern Company Gas Change in Control Awards Southern Company awarded performance share units to certain Southern Company Gas employees who continued their employment with the Southern Company in lieu of certain change in control benefits the employee was entitled to receive following the Merger (change in control awards). Shares of Southern Company common stock and/or cash equal to the dollar value of the change in control benefit will vest and be issued one-third each year as long as the employee remains in service with Southern Company or its subsidiaries at each vest date. In addition to the change in control benefit, Southern Company common stock could be issued to the employees at the end of a performance period based on achievement of certain Southern Company common stock price metrics, as well performance goals established by the Compensation Committee of the Southern Company Board of Directors (achievement shares). The change in control benefits are accounted for as a liability award with the fair value equal to the guaranteed dollar value of the change in control benefit. The grant-date fair value of the achievement portion of the award was determined using a Monte Carlo simulation model to estimate the number of achievement shares expected to vest based on the Southern Company common stock price. The expected payout is reevaluated annually with expense recognized to date increased or decreased proportionately based on the expected performance. The compensation expense ultimately recognized for the achievement shares will be based on the actual performance. As of December 31, 2016, total compensation cost and related tax benefit for the change in control awards recognized in income was immaterial. As of December 31, 2016, approximately $20 million of total unrecognized compensation cost related to change in control awards is expected to be recognized over a weighted-average period of approximately 23 months. Diluted Earnings Per Share For Southern Company, the only difference in computing basic and diluted EPS is attributable to awards outstanding under the stock option and performance share plans. The effect of both stock options and performance share award units was determined using the treasury stock method. Shares used to compute diluted EPS were as follows: 2016 Average Common Stock Shares 2015 (in millions) 2014 As reported shares Effect of options and performance share award units Diluted shares 951 7 958 910 4 914 897 4 901 Prior to the adoption of ASU 2016-09, the effect of options and performance share award units included the assumed impacts of any excess tax benefits from the exercise of all “in the money” outstanding share based awards. In accordance with the new guidance, no prior year information was adjusted. Stock options and performance share award units that were not included in the diluted EPS calculation because they were anti-dilutive were immaterial as of December 31, 2016 and 2015. Common Stock Dividend Restrictions The income of Southern Company is derived primarily from equity in earnings of its subsidiaries. At December 31, 2016, consolidated retained earnings included $7.0 billion of undistributed retained earnings of the subsidiaries. Southern Company 2016 Annual Report Notes to Financial Statements 111 9. NUCLEAR INSURANCE Under the Price-Anderson Amendments Act (Act), Alabama Power and Georgia Power maintain agreements of indemnity with the NRC that, together with private insurance, cover third-party liability arising from any nuclear incident occurring at the companies’ nuclear power plants. The Act provides funds up to $13.4 billion for public liability claims that could arise from a single nuclear incident. Each nuclear plant is insured against this liability to a maximum of $375 million by American Nuclear Insurers (ANI), with the remaining coverage provided by a mandatory program of deferred premiums that could be assessed, after a nuclear incident, against all owners of commercial nuclear reactors. A company could be assessed up to $127 million per incident for each licensed reactor it operates but not more than an aggregate of $19 million per incident to be paid in a calendar year for each reactor. Such maximum assessment, excluding any applicable state premium taxes, for Alabama Power and Georgia Power, based on its ownership and buyback interests in all licensed reactors, is $255 million and $247 million, respectively, per incident, but not more than an aggregate of $38 million and $37 million, respectively, per company to be paid for each incident in any one year. Both the maximum assessment per reactor and the maximum yearly assessment are adjusted for inflation at least every five years. The next scheduled adjustment is due no later than September 10, 2018. See Note 4 for additional information on joint ownership agreements. Alabama Power and Georgia Power are members of Nuclear Electric Insurance Limited (NEIL), a mutual insurer established to provide property damage insurance in an amount up to $1.5 billion for members’ operating nuclear generating facilities. Additionally, both companies have NEIL policies that currently provide decontamination, excess property insurance, and premature decommissioning coverage up to $1.25 billion for nuclear losses in excess of the $1.5 billion primary coverage. In 2014, NEIL introduced a new excess non-nuclear policy providing coverage up to $750 million for non-nuclear losses in excess of the $1.5 billion primary coverage. NEIL also covers the additional costs that would be incurred in obtaining replacement power during a prolonged accidental outage at a member’s nuclear plant. Members can purchase this coverage, subject to a deductible waiting period of up to 26 weeks, with a maximum per occurrence per unit limit of $490 million. After the deductible period, weekly indemnity payments would be received until either the unit is operational or until the limit is exhausted in approximately three years. Alabama Power and Georgia Power each purchase limits based on the projected full cost of replacement power, subject to ownership limitations. Each facility has elected a 12-week deductible waiting period. A builders’ risk property insurance policy has been purchased from NEIL for the construction of Plant Vogtle Units 3 and 4. This policy provides the Vogtle Owners up to $2.75 billion for accidental property damage occurring during construction. Under each of the NEIL policies, members are subject to assessments each year if losses exceed the accumulated funds available to the insurer. The maximum annual assessments for Alabama Power and Georgia Power as of December 31, 2016 under the NEIL policies would be $53 million and $82 million, respectively. Claims resulting from terrorist acts are covered under both the ANI and NEIL policies (subject to normal policy limits). The aggregate, however, that NEIL will pay for all claims resulting from terrorist acts in any 12-month period is $3.2 billion plus such additional amounts NEIL can recover through reinsurance, indemnity, or other sources. For all on-site property damage insurance policies for commercial nuclear power plants, the NRC requires that the proceeds of such policies shall be dedicated first for the sole purpose of placing the reactor in a safe and stable condition after an accident. Any remaining proceeds are to be applied next toward the costs of decontamination and debris removal operations ordered by the NRC, and any further remaining proceeds are to be paid either to the applicable company or to its debt trustees as may be appropriate under the policies and applicable trust indentures. In the event of a loss, the amount of insurance available might not be adequate to cover property damage and other expenses incurred. Uninsured losses and other expenses, to the extent not recovered from customers, would be borne by Alabama Power or Georgia Power, as applicable, and could have a material effect on Southern Company’s financial condition and results of operations. All retrospective assessments, whether generated for liability, property, or replacement power, may be subject to applicable state premium taxes. investor.southerncompany.com 112 Notes to Financial Statements 10. FAIR VALUE MEASUREMENTS Fair value measurements are based on inputs of observable and unobservable market data that a market participant would use in pricing the asset or liability. The use of observable inputs is maximized where available and the use of unobservable inputs is minimized for fair value measurement and reflects a three-tier fair value hierarchy that prioritizes inputs to valuation techniques used for fair value measurement. • • • Level 1 consists of observable market data in an active market for identical assets or liabilities. Level 2 consists of observable market data, other than that included in Level 1, that is either directly or indirectly observable. Level 3 consists of unobservable market data. The input may reflect the assumptions of the Company of what a market participant would use in pricing an asset or liability. If there is little available market data, then the Company’s own assumptions are the best available information. In the case of multiple inputs being used in a fair value measurement, the lowest level input that is significant to the fair value measurement represents the level in the fair value hierarchy in which the fair value measurement is reported. As of December 31, 2016, assets and liabilities measured at fair value on a recurring basis during the period, together with their associated level of the fair value hierarchy, were as follows: Fair Value Measurements Using Quoted Prices in Active Markets for Identical Assets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Net Asset Value as a Practical Expedient (NAV) (in millions) $ $ 338 — 589 48 — — 22 — — 11 1,172 9 2,189 $ $ 333 14 73 168 92 73 310 183 — 15 — — 1,261 $ — — $ — $ — — — — — — — — — — 1 1 $ — — — — — — 20 — — — 20 $ $ Total 671 14 662 216 92 73 332 183 20 26 1,172 10 3,471 As of December 31, 2016: Assets: Energy-related derivatives(a)(b) Interest rate derivatives Nuclear decommissioning trusts:(c) Domestic equity Foreign equity U.S. Treasury and government agency securities Municipal bonds Corporate bonds Mortgage and asset backed securities Private equity Other Cash equivalents Other investments Total Liabilities: Energy-related derivatives(a)(b) Interest rate derivatives Foreign currency derivatives Contingent consideration Total 630 29 58 18 735 (a) Energy-related derivatives exclude $4 million associated with certain weather derivatives accounted for based on intrinsic value rather than $ — $ — — — $ — $ $ — — — 18 18 285 29 58 — 372 345 — — — 345 $ $ $ $ $ fair value. (b) Energy-related derivatives exclude cash collateral of $62 million. (c) Includes the investment securities pledged to creditors and collateral received, and excludes receivables related to investment income, pending investment sales, and payables related to pending investment purchases and the lending pool. See Note 1 under “Nuclear Decommissioning” for additional information. Southern Company 2016 Annual Report As of December 31, 2015, assets and liabilities measured at fair value on a recurring basis during the period, together with their associated level of the fair value hierarchy, were as follows: Notes to Financial Statements 113 As of December 31, 2015: Assets: Energy-related derivatives Interest rate derivatives Nuclear decommissioning trusts:(*) Domestic equity Foreign equity U.S. Treasury and government agency securities Municipal bonds Corporate bonds Mortgage and asset backed securities Private equity Other Cash equivalents Other investments Total Liabilities: Energy-related derivatives Interest rate derivatives Total Fair Value Measurements Using Quoted Prices in Active Markets for Identical Assets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) (in millions) Net Asset Value as a Practical Expedient (NAV) $ $ $ $ — — 541 47 — — 11 — — 16 790 9 1,414 — — — $ $ $ $ 7 22 69 160 152 64 278 145 — 9 — — 906 220 30 250 $ — — $ — $ — — — — — — — — — — 1 1 $ — — — — — — 17 — — — 17 $ $ $ — — $ — $ — $ — $ — $ Total 7 22 610 207 152 64 289 145 17 25 790 10 2,338 220 30 250 (*) Includes the investment securities pledged to creditors and collateral received, and excludes receivables related to investment income, pending investment sales, and payables related to pending investment purchases and the lending pool. See Note 1 under “Nuclear Decommissioning” for additional information. Valuation Methodologies The energy-related derivatives primarily consist of exchange-traded and over-the-counter financial products for natural gas and physical power products, including, from time to time, basis swaps. These are standard products used within the energy industry and are valued using the market approach. The inputs used are mainly from observable market sources, such as forward natural gas prices, power prices, implied volatility, and overnight index swap interest rates. Interest rate derivatives are also standard over-the-counter products that are valued using observable market data and assumptions commonly used by market participants. The fair value of interest rate derivatives reflects the net present value of expected payments and receipts under the swap agreement based on the market’s expectation of future interest rates. Additional inputs to the net present value calculation may include the contract terms, counterparty credit risk, and occasionally, implied volatility of interest rate options. The fair value of cross-currency swaps reflects the net present value of expected payments and receipts under the swap agreement based on the market’s expectation of future foreign currency exchange rates. Additional inputs to the net present value calculation may include the contract terms, counterparty credit risk, and discount rates. The interest rate derivatives and cross-currency swaps are categorized as Level 2 under Fair Value Measurements as these inputs are based on observable data and valuations of similar instruments. See Note 11 for additional information on how these derivatives are used. The NRC requires licensees of commissioned nuclear power reactors to establish a plan for providing reasonable assurance of funds for future decommissioning. For fair value measurements of the investments within the nuclear decommissioning trusts, external pricing vendors are designated for each asset class with each security specifically assigned a primary pricing source. For investments held within commingled funds, fair value is determined at the end of each business day through the net asset value, which is established by obtaining the underlying securities’ individual prices from the primary pricing source. A market price secured from the primary source vendor is then evaluated by management in its valuation of the assets within the trusts. As a general approach, fixed income market pricing vendors gather market data (including indices and market research reports) and integrate relative credit information, observed market movements, and sector news into proprietary pricing models, pricing systems, and mathematical tools. Dealer quotes and other market information, including live trading levels and pricing analysts’ judgments, are also obtained when available. See Note 1 under “Nuclear Decommissioning” for additional information. investor.southerncompany.com 114 Notes to Financial Statements Southern Power has contingent payment obligations related to certain acquisitions whereby Southern Power is obligated to pay generation-based payments to the seller over a 10-year period beginning at the commercial operation date. The obligation is measured at fair value using significant inputs such as forecasted facility generation in MW-hours, a fixed dollar amount per MW-hour, and a discount rate, and is evaluated periodically. The fair value of contingent consideration reflects the net present value of expected payments and any change arising from forecasted generation is expected to be immaterial. “Other investments” include investments that are not traded in the open market. The fair value of these investments have been determined based on market factors including comparable multiples and the expectations regarding cash flows and business plan executions. As of December 31, 2016 and 2015, the fair value measurements of private equity investments held in the nuclear decommissioning trust that are calculated at net asset value per share (or its equivalent) as a practical expedient, as well as the nature and risks of those investments, were as follows: As of December 31, 2016 As of December 31, 2015 Fair Value Unfunded Commitments Redemption Frequency Redemption Notice Period (in millions) $ 20 17 $ $ 25 28 $ Not Applicable Not Applicable Not Applicable Not Applicable Private equity funds include a fund-of-funds that invests in high-quality private equity funds across several market sectors, a fund that invests in real estate assets, and a fund that acquires companies to create resale value. Private equity funds do not have redemption rights. Distributions from these funds will be received as the underlying investments in the funds are liquidated. Liquidations are expected to occur at various times over the next 10 years. As of December 31, 2016 and 2015, other financial instruments for which the carrying amount did not equal fair value were as follows: Long-term debt, including securities due within one year: 2016 2015 Carrying Amount Fair Value (in millions) $ $ 45,080 27,216 $ $ 46,286 27,913 The fair values are determined using Level 2 measurements and are based on quoted market prices for the same or similar issues or on the current rates available to Southern Company, Alabama Power, Georgia Power, Gulf Power, Mississippi Power, Southern Power, Southern Company Gas, and Nicor Gas. 11. DERIVATIVES The Southern Company system is exposed to market risks, including commodity price risk, interest rate risk, weather risk, and occasionally foreign currency exchange rate risk. To manage the volatility attributable to these exposures, each company nets its exposures, where possible, to take advantage of natural offsets and enters into various derivative transactions for the remaining exposures pursuant to each company’s policies in areas such as counterparty exposure and risk management practices. Each company’s policy is that derivatives are to be used primarily for hedging purposes and mandates strict adherence to all applicable risk management policies. Derivative positions are monitored using techniques including, but not limited to, market valuation, value at risk, stress testing, and sensitivity analysis. Derivative instruments are recognized at fair value in the balance sheets as either assets or liabilities and are presented on a net basis. See Note 10 for additional information. In the statements of cash flows, the cash impacts of settled energy-related and interest rate derivatives are recorded as operating activities. The cash impacts of settled foreign currency derivatives are classified as operating or financing activities to correspond with classification of the hedged interest or principal, respectively. See Note 1 under “Financial Instruments” for additional information. Energy-Related Derivatives Southern Company and certain subsidiaries enter into energy-related derivatives to hedge exposures to electricity, natural gas, and other fuel price changes. However, due to cost-based rate regulations and other various cost recovery mechanisms, the traditional electric operating companies and natural gas distribution utilities have limited exposure to market volatility in energy-related commodity prices. Each of the traditional electric operating companies and certain of the natural gas distribution utilities manage fuel-hedging programs, implemented per the guidelines of their respective state PSCs or other applicable state regulatory agencies, through the use of financial derivative contracts, which is expected to continue to mitigate price volatility. The traditional electric operating companies (with respect to wholesale generating capacity) and Southern Power have limited Southern Company 2016 Annual Report Notes to Financial Statements 115 exposure to market volatility in energy-related commodity prices because their long-term sales contracts shift substantially all fuel cost responsibility to the purchaser. However, the traditional electric operating companies and Southern Power may be exposed to market volatility in energy-related commodity prices to the extent any uncontracted capacity is used to sell electricity. Southern Company Gas uses storage and transportation capacity contracts to manage market price risks. Southern Company Gas purchases natural gas for storage when the current market price paid to buy and transport natural gas plus the cost to store and finance the natural gas is less than the market price Southern Company Gas will receive in the future, resulting in a positive net adjusted operating margin. Southern Company Gas uses New York Mercantile Exchange (NYMEX) futures and over-the-counter (OTC) contracts to sell natural gas at that future price to substantially protect the adjusted operating margin ultimately realized when the stored natural gas is sold. Southern Company Gas also enters into transactions to secure transportation capacity between delivery points in order to serve its customers and various markets. Southern Company Gas uses NYMEX futures and OTC contracts to capture the price differential between the locations served by the capacity in order to substantially protect the adjusted operating margin ultimately realized when natural gas is physically flowed between the delivery points. These contracts generally meet the definition of derivatives, but are not designated as hedges for accounting purposes. Southern Company Gas also enters into weather derivative contracts as economic hedges of adjusted operating margins in the event of warmer-than-normal weather. Exchange-traded options are carried at fair value, with changes reflected in operating revenues. Non-exchange-traded options are accounted for using the intrinsic value method. Changes in the intrinsic value for non-exchange-traded contracts are reflected in the statements of income. Energy-related derivative contracts are accounted for under one of three methods: • Regulatory Hedges – Energy-related derivative contracts which are designated as regulatory hedges relate primarily to the traditional electric operating companies’ and natural gas distribution utilities’ fuel-hedging programs, where gains and losses are initially recorded as regulatory liabilities and assets, respectively, and then are included in fuel expense as the underlying fuel is used in operations and ultimately recovered through the respective fuel cost recovery clauses. • Cash Flow Hedges – Gains and losses on energy-related derivatives designated as cash flow hedges (which are mainly used to hedge anticipated purchases and sales) are initially deferred in OCI before being recognized in the statements of income in the same period as the hedged transactions are reflected in earnings. • Not Designated – Gains and losses on energy-related derivative contracts that are not designated or fail to qualify as hedges are recognized in the statements of income as incurred. Some energy-related derivative contracts require physical delivery as opposed to financial settlement, and this type of derivative is both common and prevalent within the electric and natural gas industries. When an energy-related derivative contract is settled physically, any cumulative unrealized gain or loss is reversed and the contract price is recognized in the respective line item representing the actual price of the underlying goods being delivered. At December 31, 2016, the net volume of energy-related derivative contracts for natural gas positions totaled 500 million mmBtu for the Southern Company system, with the longest hedge date of 2020 over which the respective entity is hedging its exposure to the variability in future cash flows for forecasted transactions and the longest non-hedge date of 2022 for derivatives not designated as hedges. In addition to the volumes discussed above, the traditional electric operating companies and Southern Power enter into physical natural gas supply contracts that provide the option to sell back excess gas due to operational constraints. The maximum expected volume of natural gas subject to such a feature is 9 million mmBtu. For cash flow hedges, the amounts expected to be reclassified from accumulated OCI to earnings for the next 12-month period ending December 31, 2017 are $17 million for Southern Company. Interest Rate Derivatives Southern Company and certain subsidiaries may also enter into interest rate derivatives to hedge exposure to changes in interest rates. The derivatives employed as hedging instruments are structured to minimize ineffectiveness. Derivatives related to existing variable rate securities or forecasted transactions are accounted for as cash flow hedges where the effective portion of the derivatives’ fair value gains or losses is recorded in OCI and is reclassified into earnings at the same time the hedged transactions affect earnings, with any ineffectiveness recorded directly to earnings. Derivatives related to existing fixed rate securities are accounted for as fair value hedges, where the derivatives’ fair value gains or losses and hedged items’ fair value gains or losses are both recorded directly to earnings, providing an offset, with any difference representing ineffectiveness. Fair value gains or losses on derivatives that are not designated or fail to qualify as hedges are recognized in the statements of income as incurred. investor.southerncompany.com 116 Notes to Financial Statements At December 31, 2016, the following interest rate derivatives were outstanding: Cash Flow Hedges of Forecasted Debt Cash Flow Hedges of Existing Debt Fair Value Hedges of Existing Debt Derivatives not Designated as Hedges Notional Amount (in millions) Interest Rate Received Weighted Average Interest Rate Paid Hedge Maturity Date Fair Value Gain (Loss) December 31, 2016 (in millions) $ 80 3-month LIBOR 2.32% December 2026 $ — 900 250 250 500 200 300 1-month LIBOR 0.79% March 2018 1.30% LIBOR + 0.17% August 2017 3-month 5.40% 1.95% 4.25% 3-month LIBOR + 4.02% 3-month LIBOR + 0.76% 3-month LIBOR + 2.46% 3-month June 2018 December 2018 December 2019 2.75% LIBOR + 0.92% June 2020 1,500 2.35% 1-month LIBOR + 0.87% July 2021 47(a,b) 3-month LIBOR 2.21% January 2017(c) 3 — — (2) 1 1 (18) 1 (14) $ Total (a) Swaption at RE Roserock LLC. See Note 12 for additional information. (b) Amortizing notional amount. (c) Represents the mandatory settlement date. Settlement amount was based on a 15-year amortizing swap. 4,027 $ The estimated pre-tax gains (losses) expected to be reclassified from accumulated OCI to interest expense for the next 12-month period ending December 31, 2017 total $(21) million. Deferred gains and losses are expected to be amortized into earnings through 2046. Foreign Currency Derivatives Southern Company and certain subsidiaries may also enter into foreign currency derivatives to hedge exposure to changes in foreign currency exchange rates, such as that arising from the issuance of debt denominated in a currency other than U.S. dollars. Derivatives related to forecasted transactions are accounted for as cash flow hedges where the effective portion of the derivatives’ fair value gains or losses is recorded in OCI and is reclassified into earnings at the same time that the hedged transactions affect earnings, including foreign currency gains or losses arising from changes in the U.S. currency exchange rates. Any ineffectiveness is recorded directly to earnings. The derivatives employed as hedging instruments are structured to minimize ineffectiveness. At December 31, 2016, the following foreign currency derivatives were outstanding: Cash Flow Hedges of Existing Debt Total Pay Notional (in millions) Pay Rate Receive Notional (in millions) Receive Rate Hedge Maturity Date Fair Value Gain (Loss) at December 31, 2016 (in millions) $ $ 677 564 1,241 2.95% 3.78% € 600 500 € 1,100 1.00% 1.85% June 2022 June 2026 $ $ (34) (24) (58) The estimated pre-tax gains (losses) that will be reclassified from accumulated OCI to earnings for the next 12-month period ending December 31, 2017 total $(25) million. Southern Company 2016 Annual Report Notes to Financial Statements 117 Derivative Financial Statement Presentation and Amounts Southern Company and its subsidiaries enter into derivative contracts that may contain provisions that permit intra-contract netting of derivative receivables and payables for routine billing and offsets related to events of default and settlements. Southern Company and certain subsidiaries also utilize master netting agreements to mitigate exposure to counterparty credit risk. These agreements may contain provisions that permit netting across product lines and against cash collateral. At December 31, 2016, fair value amounts of derivative assets and liabilities on the balance sheets are presented net to the extent that there are netting arrangements or similar agreements with the counterparties. At December 31, 2015, the fair value amounts of derivative instruments were presented gross on the balance sheets. At December 31, 2016 and 2015, the fair value of energy-related derivatives, interest rate derivatives, and foreign currency derivatives was reflected in the balance sheets as follows: Derivative Category and Balance Sheet Location Assets Liabilities Assets Liabilities 2016 2015 (in millions) Derivatives designated as hedging instruments for regulatory purposes Energy-related derivatives: Other current assets/Liabilities from risk management activities, net of collateral Other deferred charges and assets/Other deferred credits and liabilities Total derivatives designated as hedging instruments for regulatory purposes Derivatives designated as hedging instruments in cash flow and fair value hedges Energy-related derivatives: $ 73 25 $ 27 33 $ 3 $ 130 — 87 $ 98 $ 60 $ 3 $ 217 Other current assets/Liabilities from risk management activities, net of collateral $ 23 $ $ 3 $ 2 Interest rate derivatives: Other current assets/Liabilities from risk management activities, net of collateral Other deferred charges and assets/Other deferred credits and liabilities Foreign currency derivatives: Other current assets/Liabilities from risk management activities, net of collateral Other deferred charges and assets/Other deferred credits and liabilities Total derivatives designated as hedging instruments in cash flow and fair value hedges Derivatives not designated as hedging instruments $ 12 1 — — 36 7 1 28 25 33 19 — — — $ 94 $ 22 Energy-related derivatives: Other current assets/Liabilities from risk management activities, net of collateral Other deferred charges and assets/Other deferred credits and liabilities Interest rate derivatives: Other current assets/Liabilities from risk management activities, net of collateral $ 489 $ 483 $ 1 66 1 81 — — 3 Total derivatives not designated as hedging instruments Gross amounts recognized Gross amounts offset(a) Net amounts recognized in the Balance Sheets(b) (a) Gross amounts offset include cash collateral held on deposit in broker margin accounts of $62 million as of December 31, 2016. (b) At December 31, 2015, the fair value amounts for derivative contracts subject to netting arrangements were presented gross on the 556 690 (462) 228 564 718 (524) 194 4 29 (15) 14 $ $ $ $ $ $ $ $ $ $ $ $ balance sheet. 23 7 — — 32 1 — — 1 250 (15) 235 $ $ $ $ $ $ investor.southerncompany.com 118 Notes to Financial Statements At December 31, 2016 and 2015, the pre-tax effects of unrealized derivative gains (losses) arising from energy-related derivatives designated as regulatory hedging instruments and deferred were as follows: Unrealized Losses Unrealized Gains Derivative Category Energy-related derivatives:(a) Balance Sheet Location 2016 2015 Balance Sheet Location Other regulatory assets, current Other regulatory assets, deferred (in millions) (16) $ $ (19) (130) Other regulatory liabilities, current (87) Other regulatory liabilities, deferred 2016 2015 (in millions) $ 56 $ 3 12 — 3 Total energy-related derivative gains (losses)(b) (a) At December 31, 2016, the unrealized gains and losses for derivative contracts subject to netting arrangements were presented net on the balance sheet. At December 31, 2015, the unrealized gains and losses for derivative contracts were presented gross on the balance sheet. (b) Fair value gains and losses recorded in regulatory assets and liabilities include cash collateral held on deposit in broker margin accounts of $ (35) $ 68 (217) $ $ $8 million as of December 31, 2016. For the years ended December 31, 2016, 2015, and 2014, the pre-tax effects of energy-related derivatives, interest rate derivatives, and foreign currency derivatives designated as cash flow hedging instruments on the statements of income were as follows: Derivatives in Cash Flow Hedging Relationships Gain (Loss) Recognized in OCI on Derivative (Effective Portion) Amount Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion) Amount 2015 (in millions) $ — 2014 $ — Derivative Category 2016 Energy-related derivatives $ 18 2015 (in millions) $ — 2014 Statements of Income Location 2016 $ — Depreciation and $ 2 Interest rate derivatives Foreign currency derivatives (180) (58) (22) — amortization Cost of natural gas Interest expense, net of amounts capitalized (16) — Interest expense, net of amounts capitalized Other income (expense), net(*) (1) (18) (13) (82) — (9) — — — (8) — — (8) (16) Total (*) The reclassification from accumulated OCI into other income (expense), net completely offsets currency gains and losses arising from changes $ (220) (112) (22) (9) $ $ $ $ $ in the U.S. currency exchange rates used to record the euro-denominated notes. For the years ended December 31, 2016, 2015, and 2014, the pre-tax effects of interest rate derivatives designated as fair value hedging instruments were as follows: Derivatives in Fair Value Hedging Relationships Derivative Category Statements of Income Location 2016 Gain (Loss) 2015 (in millions) 2014 Interest rate derivatives: Interest expense, net of amounts capitalized $ (21) $ 2 $ (3) For all years presented, the pre-tax effects of interest rate derivatives designated as fair value hedging instruments were offset by changes to the carrying value of long-term debt. There was no material ineffectiveness recorded in earnings for any period presented. Southern Company 2016 Annual Report For the years ended December 31, 2016, 2015, and 2014, the pre-tax effects of energy-related derivatives not designated as hedging instruments on the statements of income were as follows: Notes to Financial Statements 119 Derivatives Not Designated as Hedging Instruments Derivative Category Statements of Income Location 2016 2014 Unrealized Gain (Loss) Recognized in Income Amount 2015 (in millions) (5) $ 3 — — (2) 2 — 33 3 38 $ 6 (4) — — 2 Energy-related derivatives Wholesale electric revenues Fuel Natural gas revenues(*) Cost of natural gas $ Total (*) Excludes gains (losses) recorded in cost of natural gas associated with weather derivatives of $6 million for the period ended December 31, 2016. $ $ $ For the years ended December 31, 2016, 2015, and 2014, the pre-tax effects of interest rate derivatives not designated as hedging instruments were immaterial. Contingent Features The Company does not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade. There are certain derivatives that could require collateral, but not accelerated payment, in the event of various credit rating changes of certain Southern Company subsidiaries. At December 31, 2016, the fair value of derivative liabilities with contingent features was immaterial. The maximum potential collateral requirements arising from the credit-risk-related contingent features, at a rating below BBB- and/or Baa3, were immaterial and include certain agreements that could require collateral in the event that one or more Southern Company system power pool participants has a credit rating change to below investment grade. Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. If collateral is required, fair value amounts recognized for the right to reclaim cash collateral or the obligation to return cash collateral are not offset against fair value amounts recognized for derivatives executed with the same counterparty. Southern Company maintains accounts with brokers or the clearing houses of certain exchanges to facilitate financial derivative transactions. Based on the value of the positions in these accounts and the associated margin requirements, Southern Company may be required to deposit cash into these accounts. At December 31, 2016, cash collateral held on deposit in broker margin accounts was $62 million. Southern Company is exposed to losses related to financial instruments in the event of counterparties’ nonperformance. Southern Company only enters into agreements and material transactions with counterparties that have investment grade credit ratings by Moody’s and S&P or with counterparties who have posted collateral to cover potential credit exposure. Southern Company has also established risk management policies and controls to determine and monitor the creditworthiness of counterparties in order to mitigate Southern Company’s exposure to counterparty credit risk. Southern Company may require counterparties to pledge additional collateral when deemed necessary. Therefore, Southern Company does not anticipate a material adverse effect on the financial statements as a result of counterparty nonperformance. 12. ACQUISITIONS Southern Company Merger with Southern Company Gas Southern Company Gas is an energy services holding company whose primary business is the distribution of natural gas through the natural gas distribution utilities. On July 1, 2016, Southern Company completed the Merger for a total purchase price of approximately $8.0 billion and Southern Company Gas became a wholly-owned, direct subsidiary of Southern Company. investor.southerncompany.com 120 Notes to Financial Statements The Merger was accounted for using the acquisition method of accounting with the assets acquired and liabilities assumed recognized at fair value as of the acquisition date. The following table presents the purchase price allocation: Southern Company Gas Purchase Price Current assets Property, plant, and equipment Goodwill Intangible assets Regulatory assets Other assets Current liabilities Other liabilities Long-term debt Noncontrolling interests Total purchase price December 31, 2016 (in millions) $ 1,557 10,108 5,967 400 1,118 229 (2,201) (4,742) (4,261) (174) 8,001 $ The excess of the purchase price over the estimated fair values of the assets acquired and liabilities assumed of $6.0 billion is recognized as goodwill, which is primarily attributable to positioning the Southern Company system to provide natural gas infrastructure to meet customers’ growing energy needs and to compete for growth across the energy value chain. Southern Company anticipates that much of the value assigned to goodwill will not be deductible for tax purposes. The valuation of identifiable intangible assets included customer relationships, trade names, and storage and transportation contracts with estimated lives of one to 28 years. The estimated fair value measurements of identifiable intangible assets were primarily based on significant unobservable inputs (Level 3). The results of operations for Southern Company Gas have been included in the consolidated financial statements from the date of acquisition and consist of operating revenues of $1.7 billion and net income of $114 million. The following summarized unaudited pro forma consolidated statement of earnings information assumes that the acquisition of Southern Company Gas was completed on January 1, 2015. The summarized unaudited pro forma consolidated statement of earnings information includes adjustments for (i) intercompany sales, (ii) amortization of intangible assets, (iii) adjustments to interest expense to reflect current interest rates on Southern Company Gas debt and additional interest expense associated with borrowings by Southern Company to fund the Merger, and (iv) the elimination of nonrecurring expenses associated with the Merger. Operating revenues (in millions) Net income attributable to Southern Company (in millions) Basic EPS Diluted EPS 2016 21,791 2,591 2.70 2.68 $ $ $ $ 2015 21,430 2,665 2.85 2.84 $ $ $ $ These unaudited pro forma results are for comparative purposes only and may not be indicative of the results that would have occurred had this acquisition been completed on January 1, 2015 or the results that would be attained in the future. During 2016 and 2015, Southern Company recorded in its statements of income costs associated with the Merger of approximately $111 million and $41 million, respectively, of which $80 million and $27 million is included in operating expenses and $31 million and $14 million is included in other income and (expense), respectively. These costs include external transaction costs for financing, legal, and consulting services, as well as customer rate credits and additional compensation-related expenses. Acquisition of PowerSecure On May 9, 2016, Southern Company acquired all of the outstanding stock of PowerSecure, a provider of products and services in the areas of distributed generation, energy efficiency, and utility infrastructure, for $18.75 per common share in cash, resulting in an aggregate purchase price of $429 million. As a result, PowerSecure became a wholly-owned subsidiary of Southern Company. Southern Company 2016 Annual Report The acquisition of PowerSecure was accounted for using the acquisition method of accounting with the assets acquired and liabilities assumed recognized at fair value as of the acquisition date. The allocation of the purchase price is as follows: Notes to Financial Statements 121 PowerSecure Purchase Price Current assets Property, plant, and equipment Intangible assets Goodwill Other assets Current liabilities Long-term debt, including current portion Deferred credits and other liabilities Total purchase price December 31, 2016 (in millions) $ $ 172 46 101 282 4 (114) (48) (14) 429 The excess of the purchase price over the estimated fair values of the assets acquired and liabilities assumed of $282 million was recognized as goodwill, which is primarily attributable to expected business expansion opportunities for PowerSecure. Southern Company anticipates that the majority of the value assigned to goodwill will not be deductible for tax purposes. The valuation of identifiable intangible assets included customer relationships, trade names, patents, backlog, and software with estimated lives of one to 26 years. The estimated fair value measurements of identifiable intangible assets were primarily based on significant unobservable inputs (Level 3). The results of operations for PowerSecure have been included in the consolidated financial statements from the date of acquisition and are immaterial to the consolidated financial results of Southern Company. Pro forma results of operations have not been presented for the acquisition because the effects of the acquisition were immaterial to Southern Company’s consolidated financial results for all periods presented. Alliance with Bloom Energy Corporation On October 24, 2016, a subsidiary of Southern Company acquired from an affiliate of Bloom Energy Corporation (Bloom) all of the equity interests of 2016 ESA HoldCo, LLC and its subsidiary, 2016 ESA Project Company, LLC. 2016 ESA Project Company, LLC expects to acquire 50 MWs of Bloom fuel cell systems to serve commercial and industrial customers under long-term PPAs. In connection with this transaction, PowerSecure and Bloom agreed to pursue a strategic alliance to develop technology for behind-the-meter energy solutions. Investment in Southern Natural Gas On July 10, 2016, Southern Company and Kinder Morgan, Inc. entered into a definitive agreement for Southern Company to acquire a 50% equity interest in SNG, which is the owner of a 7,000-mile pipeline system connecting natural gas supply basins in Texas, Louisiana, Mississippi, and Alabama to markets in Louisiana, Mississippi, Alabama, Florida, Georgia, South Carolina, and Tennessee. On August 31, 2016, Southern Company assigned its rights and obligations under the definitive agreement to a wholly-owned, indirect subsidiary of Southern Company Gas. On September 1, 2016, Southern Company Gas completed the acquisition for a purchase price of approximately $1.4 billion. The investment in SNG is accounted for using the equity method. Acquisition of Remaining Interest in SouthStar SouthStar is a retail natural gas marketer and markets natural gas to residential, commercial, and industrial customers, primarily in Georgia and Illinois. Southern Company Gas previously had an 85% ownership interest in SouthStar, with Piedmont owning the remaining 15%. In October 2016, Southern Company Gas purchased Piedmont’s 15% interest in SouthStar for $160 million. Southern Power During 2016 and 2015, in accordance with its overall growth strategy, Southern Power or one of its wholly-owned subsidiaries, Southern Renewable Partnerships, LLC (SRP) or Southern Renewable Energy, Inc. (SRE), acquired or contracted to acquire the projects discussed below. Also, on March 29, 2016, Southern Power acquired an additional 15% interest in Desert Stateline, 51% of which was initially acquired in August 2015. As a result, Southern Power and the class B member are now entitled to 66% and 34%, respectively, of all cash distributions from Desert Stateline. In addition, Southern Power will continue to be entitled to substantially all of the federal tax benefits with respect to the transaction. investor.southerncompany.com 122 Notes to Financial Statements The following table presents Southern Power’s acquisitions during and subsequent to the year ended December 31, 2016. Project Facility Resource Acquisitions During the Year Ended December 31, 2016 Boulder 1 Seller; Acquisition Date Solar Calipatria Solar East Pecos Solar Grant Plains Wind Grant Wind Wind Henrietta Solar Lamesa Solar SunPower Corp. November 16, 2016 Solar Frontier Americas Holding LLC February 11, 2016 First Solar, Inc. March 4, 2016 Apex Clean Energy Holdings, LLC August 26, 2016 Apex Clean Energy Holdings, LLC April 7, 2016 SunPower Corp. July 1, 2016 RES America Developments Inc. July 1, 2016 Approximate Nameplate Capacity (MW) Location 100 Clark County, NV 20 Imperial County, CA Southern Power Percentage Ownership Actual/ Expected COD PPA Contract Period 51%(a) December 2016 90%(b) February 2016 20 years 20 years 120 Pecos County, 100% March 2017 15 years TX 147 Grant County, 100% December OK 2016 151 Grant County, 100% April 2016 OK 20 years and 12 years(c) 20 years 102 Kings County, CA 51%(a) July 2016 20 years 102 Dawson County, 100% Second 15 years TX quarter 2017 Mankato(d) Natural Gas Calpine Corporation 375 Mankato, MN 100% N/A(e) 10 years Passadumkeag Wind Rutherford Solar Salt Fork Wind Tyler Bluff Wind Wake Wind Wind October 26, 2016 Quantum Utility Generation, LLC June 30, 2016 Cypress Creek Renewables, LLC July 1, 2016 EDF Renewable Energy, Inc. December 1, 2016 EDF Renewable Energy, Inc. December 21, 2016 Invenergy Wind Global LLC October 26, 2016 Acquisitions Subsequent to December 31, 2016 Bethel Wind Invenergy Wind Global LLC January 6, 2017 42 Penobscot County, ME 74 Rutherford County, NC 100% July 2016 15 years 90%(b) December 2016 174 Donley and Gray Counties, TX 100% December 2016 125 Cooke County, 100% December TX 2016 257 Floyd and 90.1%(f) October 2016 12 years Crosby Counties, TX 276 Castro County, 100% January 2017 12 years TX 15 years 14 years and 12 years 12 years (a) Southern Power owns 100% of the class A membership interests and a wholly-owned subsidiary of the seller owns 100% of the class B membership interests. Southern Power and the class B member are entitled to 51% and 49%, respectively, of all cash distributions from the project. In addition, Southern Power is entitled to substantially all of the federal tax benefits with respect to the transaction. (b) Southern Power owns 90%, with the minority owner, Turner Renewable Energy, LLC (TRE), owning 10%. (c) In addition to the 20-year and 12-year PPAs, the facility has a 10-year contract with Allianz Risk Transfer (Bermuda) Ltd. (d) Under the terms of the remaining 10-year PPA and the 20-year expansion PPA, approximately $408 million of assets, primarily related to property, plant, and equipment, are subject to lien at December 31, 2016. (e) The acquisition included a fully operational 375-MW natural gas-fired combined-cycle facility. (f) Southern Power owns 90.1%, with the minority owner, Invenergy Wind Global LLC, owning 9.9%. Acquisitions During the Year Ended December 31, 2016 Southern Power’s aggregate purchase price for acquisitions during the year ended December 31, 2016 was approximately $2.3 billion. Including the minority owner TRE’s 10% ownership interest in Calipatria and Rutherford, SunPower Corp’s 49% ownership interest in Boulder 1 and Henrietta, along with the assumption of $217 million in construction debt (non-recourse to Southern Power), and Invenergy Wind Global LLC’s 9.9% ownership interest in Wake Wind, the total aggregate purchase price is approximately $2.6 billion for the project facilities acquired during the year ended December 31, 2016. The allocations of the Southern Company 2016 Annual Report purchase price to individual assets have not been finalized, except for Calipatria, East Pecos, Lamesa, and Rutherford, which were finalized with no changes to amounts originally reported. The fair values of the assets and liabilities acquired through the business combinations were recorded as follows: Notes to Financial Statements 123 CWIP Property, plant, and equipment Intangible assets(a) Other assets Accounts payable Debt Total purchase price Funded by: Southern Power(b)(c) 2,345 Noncontrolling interests(d)(e) 258 2,603 Total purchase price (a) Intangible assets consist of acquired PPAs that will be amortized over 10 and 20-year terms. The estimated amortization for future periods is $ $ $ 2016 (in millions) 2,354 $ 302 128 52 (16) (217) 2,603 approximately $9 million per year. (b) At December 31, 2016, $461 million is included in acquisitions payable on the balance sheets. (c) Includes approximately $281 million of contingent consideration, of which $67 million remains payable at December 31, 2016. (d) Includes approximately $51 million of non-cash contributions recorded as capital contributions from noncontrolling interests in the statements of stockholders’ equity. (e) Includes approximately $142 million of contingent consideration, all of which had been paid at December 31, 2016 by the noncontrolling interests. The following table presents Southern Power’s acquisitions for the year ended December 31, 2015. During the year ended December 31, 2016, the fair values of assets and liabilities acquired for all projects listed below were finalized with no changes to amounts originally reported. Approximate Nameplate Capacity (MW) Location Southern Power Percentage Ownership Actual COD Project Facility Resource Acquisitions for the Year Ended December 31, 2015 Desert Stateline First Solar Inc. August 31, 2015 Seller; Acquisition Date Solar 299(a) San Bernardino County, CA Garland and Garland A Solar Recurrent Energy, LLC December 17, 2015 205 Kern County, CA 51%(b) From December 2015 to July 2016 51%(b) October and August 2016 PPA Contract Period 20 years 15 years and 20 years 20 years Kay Wind Wind Lost Hills Blackwell Morelos Solar Solar North Star Solar Roserock Solar Tranquillity Solar Apex Clean Energy Holdings, LLC December 11, 2015 First Solar Inc. April 15, 2015 Solar Frontier Americas Holding, LLC October 22, 2015 First Solar Inc. April 30, 2015 Recurrent Energy, LLC November 23, 2015 Recurrent Energy, LLC August 28, 2015 299 Kay County, OK 100% December 2015 33 Kern County, CA 51%(b) April 2015 29 years 15 Kern County, CA 90%(c) November 2015 20 years 61 160 205 Fresno County, CA Pecos County, TX Fresno County, CA 51%(b) June 2015 20 years 51%(b) November 2016 July 2016 51%(b) 20 years 18 years (a) The facility has a total of 299 MWs, of which 110 MWs were placed in service in the fourth quarter 2015 and the remainder by July 2016. (b) Southern Power owns 100% of the class A membership interests and a wholly-owned subsidiary of the seller owns 100% of the class B membership interests. Southern Power and the class B member are entitled to 51% and 49%, respectively, of all cash distributions from the project. In addition, Southern Power is entitled to substantially all of the federal tax benefits with respect to the transaction. (c) Southern Power owns 90%, with the minority owner, TRE, owning 10%. investor.southerncompany.com 124 Notes to Financial Statements Acquisitions During the Year Ended December 31, 2015 Southern Power’s aggregate purchase price for the project facilities acquired during the year ended December 31, 2015 was approximately $1.4 billion. Including the minority owner TRE’s 10% ownership interest in Morelos, First Solar Inc.’s 49% ownership interest in Desert Stateline, Lost Hills Blackwell, and North Star, and Recurrent Energy, LLC’s 49% ownership interest in Garland, Garland A, Roserock, and Tranquillity, the total aggregate purchase price was approximately $1.9 billion for the project facilities acquired during the year ended December 31, 2015. The fair values of the assets and liabilities acquired through the business combinations were recorded as follows: CWIP Property, plant, and equipment Intangible assets(a) Other assets Accounts payable Total purchase price Funded by: Southern Power(b) Noncontrolling interests(c)(d) Total purchase price (a) Intangible assets consist of acquired PPAs that will be amortized over 20-year terms. The estimated amortization for future periods is $ $ $ 2015 (in millions) 1,367 $ 315 274 64 (89) 1,931 1,440 491 1,931 approximately $14 million per year. (b) Includes approximately $195 million of contingent consideration, all of which has been paid at December 31, 2016. (c) Includes approximately $227 million of non-cash contributions recorded as capital contributions from noncontrolling interests in the statements of stockholders’ equity. (d) Includes approximately $76 million of contingent consideration, all of which had been paid at December 31, 2016 by the noncontrolling interests. Construction Projects Construction Projects Completed During 2016, in accordance with Southern Power’s overall growth strategy, Southern Power completed construction of, and placed in service, the projects set forth in the table below. Total costs of construction incurred for these projects were $3.2 billion. Solar Facility Butler Seller CERSM, LLC and Community Energy, Inc. Approximate Nameplate Capacity (MW) Location 103 Taylor County, GA Actual COD December 2016 PPA Contract Period 30 years(a) Butler Solar Farm Strata Solar 22 Taylor County, GA February 2016 20 years(a) Development, LLC First Solar Development, LLC Recurrent Energy, LLC Recurrent Energy, LLC Longview Solar, LLC Recurrent Energy, LLC N/A Recurrent Energy, LLC Desert Stateline 299(b) San Bernardino County, CA 20 years Garland Garland A Pawpaw Roserock(c) Sandhills Tranquillity (a) Affiliate PPA approved by the FERC. (b) The facility has a total of 299 MWs, of which 110 MWs were placed in service in the fourth quarter 2015 and the remainder by July 2016. (c) Prior to placing the Roserock facility in service, certain solar panels were damaged. While the facility is currently generating energy as expected, Southern Power is pursuing remedies under its insurance policies and other contracts to repair or replace these solar panels. Kern County, CA Kern County, CA Taylor County, GA Pecos County, TX Taylor County, GA Fresno County, CA 185 20 30 160 146 205 15 years 20 years 30 years 20 years 25 years 18 years From December 2015 to July 2016 October 2016 August 2016 March 2016 November 2016 October 2016 July 2016 Construction Projects in Progress At December 31, 2016, Southern Power continued construction of the East Pecos and Lamesa solar facilities that were acquired in 2016. In addition, as part of Southern Power’s acquisition of Mankato in 2016, Southern Power commenced construction of an additional 345-MW expansion, which is fully contracted under a new 20-year PPA. Total aggregate construction costs, excluding the acquisition costs, are expected to be $530 million to $590 million for East Pecos, Lamesa, and Mankato. At December 31, 2016, the construction costs totaled $386 million and are included in CWIP. The ultimate outcome of these matters cannot be determined at this time. Southern Company 2016 Annual Report Notes to Financial Statements 125 The following table presents Southern Power’s construction projects in progress as of December 31, 2016: Resource Solar Solar Natural Gas Approximate Nameplate Capacity (MW) 120 102 345 Location Pecos County, TX Dawson County, TX Mankato, MN Actual/Expected COD March 2017 Second quarter 2017 Second quarter 2019 PPA Contract Period 15 years 15 years 20 years Project Facility East Pecos Lamesa Mankato Development Projects In December 2016, as part of Southern Power’s renewable development strategy, SRP entered into a joint development agreement with Renewable Energy Systems Americas, Inc. to develop and construct approximately 3,000 MWs across 10 wind projects expected to be placed in service between 2018 and 2020. Also in December 2016, Southern Power signed agreements and made payments to purchase wind turbine equipment from Siemens Wind Power, Inc. and Vestas-American Wind Technology, Inc. to be used for construction of the facilities. Once these wind projects reach commercial operations, they are expected to qualify for 100% PTCs. The ultimate outcome of these matters cannot be determined at this time. 13. SEGMENT AND RELATED INFORMATION The primary business of the Southern Company system is electricity sales by the traditional electric operating companies and Southern Power and, as a result of closing the Merger, the distribution of natural gas by Southern Company Gas. The four traditional electric operating companies – Alabama Power, Georgia Power, Gulf Power, and Mississippi Power – are vertically integrated utilities providing electric service in four Southeastern states. Southern Power constructs, acquires, owns, and manages power generation assets, including renewable energy projects, and sells electricity at market-based rates in the wholesale market. Southern Company Gas distributes natural gas through the natural gas distribution utilities in seven states and is involved in several other complementary businesses including gas marketing services, wholesale gas services, and gas midstream operations. Southern Company’s reportable business segments are the sale of electricity by the four traditional electric operating companies, the sale of electricity in the competitive wholesale market by Southern Power, and the sale of natural gas and other complementary products and services by Southern Company Gas. Revenues from sales by Southern Power to the traditional electric operating companies were $419 million, $417 million, and $383 million in 2016, 2015, and 2014, respectively. The “All Other” column includes the Southern Company parent entity, which does not allocate operating expenses to business segments. Also, this category includes segments below the quantitative threshold for separate disclosure. These segments include providing energy technologies and services to electric utilities and large industrial, commercial, institutional, and municipal customers; as well as investments in telecommunications and leveraged lease projects. All other inter-segment revenues are not material. Financial data for business segments and products and services for the years ended December 31, 2016, 2015, and 2014 was as follows: Electric Utilities Traditional Electric Operating Companies Southern Power Eliminations Total Southern Company Gas All Other (in millions) Eliminations Consolidated $ 16,803 $ 1,577 $ (439) $ 17,941 $ 1,652 $ 463 $ (160) $ 19,896 1,881 6 2 814 1,286 2,233 72,141 352 7 — 117 (195) — — — — — 2,233 13 2 931 1,091 238 2 60 81 76 31 20 (3) 317 (216) — (15) — (12) — 2,502 20 59 1,317 951 338 15,169 — (316) 2,571 86,994 114 21,853 (230) 2,474 (7) (1,624) 2,448 109,697 4,852 2,114 — 6,966 618 41 (1) 7,624 2016 Operating revenues Depreciation and amortization Interest income Earnings from equity method investments Interest expense Income taxes Segment net income (loss)(a)(b) Total assets Gross property additions investor.southerncompany.com 126 Notes to Financial Statements Electric Utilities Traditional Electric Operating Companies Southern Power Eliminations Total Southern Company Gas All Other (in millions) Eliminations Consolidated $ $ $ $ $ 152 (105) 14 6 1,390 — $ — — — 1 17,442 — (5) (439) $ 16,491 $ — — — — — — — 77 21 248 2 1,772 19 — (3) — — (397) 2,020 22 215 8,905 2,186 69,052 (1) 69 (132) 1 774 1,326 1 697 1,305 2015 Operating revenues Depreciation and amortization Interest income Earnings from equity method investments Interest expense Income taxes Segment net income (loss)(a)(b) Total assets Gross property additions 2014 Operating revenues Depreciation and amortization Interest income Earnings from equity method investments Interest expense Income taxes Segment net income (loss)(a)(b) Total assets(c) Gross property additions (a) Attributable to Southern Company. (b) Segment net income (loss) for the traditional electric operating companies includes pre-tax charges for estimated probable losses on the (449) $ 18,406 $ 1 705 1,056 1 794 1,053 1,797 64,300 1,969 69,402 (2) (1,061) 2,401 77,560 (1) 43 (76) (32) 1,819 — 89 (3) (3) 1,143 1,929 18 172 5,233 — (2) — 1,709 17 (3) (312) — (131) — — — — — — 220 1 17,354 $ — (2) — — — — — — — — 5,568 — $ 1,005 16 3 6,510 6,129 1,501 5,124 (98) 942 159 40 — — — — — 11 $ $ $ $ 1 17,489 2,034 23 — 840 1,194 2,367 78,318 6,169 18,467 1,945 19 — 835 977 1,963 70,233 6,522 Kemper IGCC of $428 million ($264 million after tax) in 2016, $365 million ($226 million after tax) in 2015, and $868 million ($536 million after tax) in 2014. See Note 3 under “Integrated Coal Gasification Combined Cycle – Kemper IGCC Schedule and Cost Estimate” for additional information. (c) Net of $202 million of unamortized debt issuance costs as of December 31, 2014. Also net of $488 million of deferred tax assets as of December 31, 2014. Products and Services Year 2016 2015 2014 Year 2016 Electric Utilities’ Revenues Retail Wholesale Other Total $ 15,234 14,987 15,550 (in millions) $ $ 1,926 1,798 2,184 781 657 672 $ 17,941 17,442 18,406 Southern Company Gas’ Revenues Gas Distribution Operations Gas Marketing Services (in millions) All Other Total $ 1,266 $ 354 $ 32 $ 1,652 Southern Company 2016 Annual Report Notes to Financial Statements 127 14. QUARTERLY FINANCIAL INFORMATION (UNAUDITED) Summarized quarterly financial information for 2016 and 2015 is as follows: Quarter Ended March 2016 June 2016 September 2016 December 2016 March 2015 June 2015 September 2015 December 2015 Operating Revenues Operating Income $ $ 3,992 4,459 6,264 5,181 4,183 4,337 5,401 3,568 $ $ 940 1,185 1,917 587 957 1,098 1,649 578 Consolidated Net Income Attributable to Southern Company Per Common Share Trading Price Range Basic Earnings Diluted Earnings Dividends High Low $ $ (in millions) 489 623 1,139 197 508 629 959 271 $ 0.53 0.67 1.18 0.20 0.56 0.69 1.05 0.30 $ $ 0.53 $ 0.66 1.17 0.20 0.56 $ 0.69 1.05 0.30 $ 0.5425 $ 0.5600 0.5600 0.5600 0.5250 $ 0.5425 0.5425 0.5425 51.73 $ 46.00 47.62 53.64 50.00 54.64 46.20 52.23 43.55 53.16 $ 41.40 45.44 41.81 46.84 43.38 47.50 In accordance with the adoption of ASU 2016-09 (see Note 1 under “Recently Issued Accounting Standards”), previously reported amounts for income tax expense were reduced by $9 million in the third quarter 2016, $11 million in the second quarter 2016, and $5 million in the first quarter 2016. In addition, basic and diluted EPS increased from previously reported amounts of $1.17 and $1.16 in the third quarter 2016, respectively, $0.65 and $0.65 in the second quarter 2016, respectively, and $0.53 and $0.53 in the first quarter 2016, respectively. As a result of the revisions to the cost estimate for the Kemper IGCC, Southern Company recorded total pre-tax charges to income for the estimated probable losses on the Kemper IGCC of $206 million ($127 million after tax) in the fourth quarter 2016, $88 million ($54 million after tax) in the third quarter 2016, $81 million ($50 million after tax) in the second quarter 2016, $53 million ($33 million after tax) in the first quarter 2016, $183 million ($113 million after tax) in the fourth quarter 2015, $150 million ($93 million after tax) in the third quarter 2015, $23 million ($14 million after tax) in the second quarter 2015, and $9 million ($6 million after tax) in the first quarter 2015. See Note 3 under “Integrated Coal Gasification Combined Cycle” for additional information. The Southern Company system’s business is influenced by seasonal weather conditions. investor.southerncompany.com 128 Selected Consolidated Financial and Operating Data SELECTED CONSOLIDATED FINANCIAL AND OPERATING DATA For the Periods Ended December 2012 through 2016 Operating Revenues (in millions) Total Assets (in millions)(b)(c) Gross Property Additions (in millions) Return on Average Common Equity (percent) Cash Dividends Paid Per Share of Common Stock Consolidated Net Income Attributable to Southern Company (in millions) Earnings Per Share — Basic Diluted Capitalization (in millions): Common stock equity Preferred and preference stock of subsidiaries and noncontrolling interests Redeemable preferred stock of subsidiaries Redeemable noncontrolling interests Long-term debt(b) Total (excluding amounts due within one year) Capitalization Ratios (percent): Common stock equity Preferred and preference stock of subsidiaries and noncontrolling interests Redeemable preferred stock of subsidiaries Redeemable noncontrolling interests Long-term debt(b) Total (excluding amounts due within one year) Other Common Stock Data: Book value per share Market price per share: High Low Close (year-end) Market-to-book ratio (year-end) (percent) Price-earnings ratio (year-end) (times) Dividends paid (in millions) Dividend yield (year-end) (percent) Dividend payout ratio (percent) Shares outstanding (in thousands): Average Year-end Stockholders of record (year-end) $ $ $ $ $ $ $ $ $ $ $ 2016(a) 19,896 109,697 7,624 10.80 2.2225 2,448 2.57 2.55 $ $ $ $ $ $ 2015 17,489 78,318 6,169 11.68 2.1525 2,367 2.60 2.59 $ $ $ $ $ $ 2014 18,467 70,233 6,522 10.08 2.0825 1,963 2.19 2.18 $ $ $ $ $ $ 2013 17,087 64,264 5,868 8.82 2.0125 1,644 1.88 1.87 $ $ $ $ $ $ 2012 16,537 62,814 5,059 13.10 1.9425 2,350 2.70 2.67 24,758 $ 20,592 $ 19,949 $ 19,008 $ 18,297 1,854 118 164 42,629 69,523 35.6 2.7 0.2 0.2 61.3 100.0 25.00 54.64 46.00 49.19 196.8 19.1 2,104 4.5 86.0 $ $ $ $ 1,390 118 43 24,688 46,831 44.0 3.0 0.3 0.1 52.6 100.0 22.59 53.16 41.40 46.79 207.2 18.0 1,959 4.6 82.7 977 375 39 20,644 41,984 47.5 2.3 0.9 0.1 49.2 100.0 21.98 51.28 40.27 49.11 223.4 22.4 1,866 4.2 95.0 $ $ $ $ $ $ $ $ 756 375 — 21,205 41,344 46.0 1.8 0.9 — 51.3 100.0 21.43 48.74 40.03 41.11 191.8 21.9 1,762 4.9 107.1 $ $ $ $ 707 375 — 19,143 38,522 47.5 1.8 1.0 — 49.7 100.0 21.09 48.59 41.75 42.81 203.0 15.9 1,693 4.5 72.0 951,332 990,394 126,338 910,024 911,721 131,771 897,194 907,777 137,369 876,755 887,086 143,800 871,388 867,768 149,628 (a) The 2016 selected financial and operating data includes the operations of Southern Company Gas from the date of the Merger, July 1, 2016, through December 31, 2016. See Note 12 under “Merger with Southern Company Gas” for additional information. (b) A reclassification of debt issuance costs from Total Assets to Long-term debt of $202 million, $139 million, and $133 million is reflected for years 2014, 2013, and 2012, respectively, in accordance with new accounting standards adopted in 2015 and applied retrospectively. (c) A reclassification of deferred tax assets from Total Assets of $488 million, $143 million, and $202 million is reflected for years 2014, 2013, and 2012, respectively, in accordance with new accounting standards adopted in 2015 and applied retrospectively. Southern Company 2016 Annual Report Selected Consolidated Financial and Operating Data 129 $ $ 2016(a) 6,614 5,394 3,171 55 15,234 1,926 17,160 1,596 1,140 19,896 53,337 53,733 52,792 883 160,745 34,896 195,641 12.40 10.04 6.01 9.48 5.52 8.77 2015 2014 2013 2012 $ $ 6,383 5,317 3,172 115 14,987 1,798 16,785 — 704 17,489 52,121 53,525 53,941 897 160,484 30,505 190,989 12.25 9.93 5.88 9.34 5.89 8.79 $ $ 6,499 5,469 3,449 133 15,550 2,184 17,734 — 733 18,467 53,347 53,243 54,140 909 161,639 32,786 194,425 12.18 10.27 6.37 9.62 6.66 9.12 $ $ 6,011 5,214 3,188 128 14,541 1,855 16,396 — 691 17,087 50,575 52,551 52,429 902 156,457 26,944 183,401 11.89 9.92 6.08 9.29 6.88 8.94 $ $ 5,891 5,097 3,071 128 14,187 1,675 15,862 — 675 16,537 50,454 53,007 51,674 919 156,054 27,563 183,617 11.68 9.62 5.94 9.09 6.08 8.64 12,387 13,318 13,765 13,144 13,187 $ 1,541 $ 1,630 $ 1,679 $ 1,562 $ 1,540 46,291 44,223 46,549 45,502 45,740 32,272 35,781 34.2 61.5 36,794 36,195 33.2 59.9 37,234 35,396 19.8 59.6 27,555 33,557 21.5 63.2 31,705 35,479 20.8 59.5 Operating Revenues (in millions): Residential Commercial Industrial Other Total retail Wholesale Total revenues from sales of electricity Natural gas revenues Other revenues Total Kilowatt-Hour Sales (in millions): Residential Commercial Industrial Other Total retail Wholesale sales Total Average Revenue Per Kilowatt-Hour (cents): Residential Commercial Industrial Total retail Wholesale Total sales Average Annual Kilowatt-Hour Use Per Residential Customer Average Annual Revenue Per Residential Customer Plant Nameplate Capacity Ratings (year-end) (megawatts) Maximum Peak-Hour Demand (megawatts): Winter Summer System Reserve Margin (at peak) (percent)(b) Annual Load Factor (percent) Plant Availability (percent): Fossil-steam Nuclear 89.4 94.2 (a) The 2016 selected financial and operating data includes the operations of Southern Company Gas from the date of the Merger, July 1, 2016, 86.4 93.3 85.8 91.5 86.1 93.5 87.7 91.5 through December 31, 2016. See Note 12 under “Merger with Southern Company Gas” for additional information. (b) Beginning in 2014, system reserve margin is calculated to include unrecognized capacity. investor.southerncompany.com 130 Selected Consolidated Financial and Operating Data Source of Energy Supply (percent): Coal Nuclear Oil and gas Hydro Other renewables Purchased power Total Gas Sales Volumes (mmBtu in millions): Firm Interruptible Total Traditional Electric Operating Company Customers (year- end) (in thousands): Residential Commercial(b) Industrial(b) Other Total electric customers Gas distribution operations customers Total utility customers Employees (year-end) 2016(a) 2015 2014 2013 2012 30.6 14.7 42.2 2.1 2.4 8.0 100.0 296 53 349 3,970 595 17 11 4,593 4,586 9,179 32,020 32.3 15.2 42.7 2.6 0.8 6.4 100.0 — — — 3,928 590 17 11 4,546 — 4,546 26,703 39.3 14.8 37.0 2.5 0.4 6.0 100.0 — — — 3,890 586 17 11 4,504 — 4,504 26,369 36.9 15.5 37.2 3.9 0.1 6.4 100.0 — — — 3,859 582 17 9 4,467 — 4,467 26,300 35.2 16.2 38.2 1.7 0.1 8.6 100.0 — — — 3,832 579 17 8 4,436 — 4,436 26,439 (a) The 2016 selected financial and operating data includes the operations of Southern Company Gas from the date of the Merger, July 1, 2016, through December 31, 2016. See Note 12 under “Merger with Southern Company Gas” for additional information. (b) A reclassification of customers from commercial to industrial is reflected for years 2012-2015 to be consistent with the rate structure approved by the Georgia PSC. The impact to operating revenues, kilowatt-hour sales, and average revenue per kilowatt-hour by class is not material. Southern Company 2016 Annual Report Management Council 131 MANAGEMENT COUNCIL Thomas A. Fanning Chairman, President, and CEO Fanning, 60, joined the Company as a financial analyst in 1980. He has held his current position since December 2010. Previously, Fanning served as executive vice president and chief operating officer for Southern Company, president and CEO of Gulf Power, and chief financial officer (CFO) for Southern Company, Georgia Power, and Mississippi Power. Art P. Beattie Executive Vice President and Chief Financial Officer Beattie, 62, joined the Company in 1976 as a junior accountant with Alabama Power. He has held his current position since August 2010. Beattie is responsible for the Company’s accounting, finance, tax, investor relations, treasury, and risk management functions. He also serves as chief risk officer. Previously, Beattie served in several executive accounting and finance positions at Alabama Power, including CFO, treasurer, and comptroller. W. Paul Bowers Executive Vice President Chairman, President, and CEO, Georgia Power Bowers, 60, joined the Company as a residential sales representative with Gulf Power in 1979. He has held his current position since January 2011. Previously, Bowers served as CFO for Southern Company. He also served as president of Southern Company Generation, president and CEO of Southern Power, president and CEO of Southern Company’s former United Kingdom subsidiary, and senior vice president and chief marketing officer for Southern Company. Stanley W. Connally, Jr. Chairman, President, and CEO, Gulf Power Connally, 47, joined the Company in 1989 as a co-op student at Georgia Power. He has held his current position since July 2012. Previously, he served as senior vice president and senior production officer for Georgia Power. He has served as plant manager at plants Watson, Daniel and Barry. He has also worked in customer operations and sales and marketing. Mark A. Crosswhite Executive Vice President Chairman, President, and CEO, Alabama Power Crosswhite, 54, joined the Company in 2004 as senior vice president and general counsel for Southern Company Generation. He has held his current position since March 2014. He was previously executive vice president and COO for Southern Company, president and CEO of Gulf Power, and executive vice president of external affairs and senior vice president and general counsel at Alabama Power. Prior to joining the Company, he was a partner in the law firm of Balch & Bingham LLP in Birmingham, Alabama, where he practiced for 17 years. Andrew W. Evans Executive Vice President Chairman, President, and CEO, Southern Company Gas Evans, 50, was appointed president of Southern Company Gas in May 2015 and chairman and CEO of Southern Company Gas in January 2016. He was appointed executive vice president of Southern Company in July 2016. Previously, he held several positions of leadership, including president and chief operating officer, executive vice president and CFO, and treasurer since joining Southern Company Gas in 2002. Prior to that, he served in various finance and business development roles at Mirant Corporation, National Economic Research Associates, and the Federal Reserve Bank of Boston. Kimberly S. Greene Executive Vice President and Chief Operating Officer Greene, 50, has held her current role since March 2014. Previously, she was president and CEO of Southern Company Services. Prior to that, she was employed by Tennessee Valley Authority, where she served as CFO, group president of strategy and external relations, and chief generation officer. Prior to her time at Tennessee Valley Authority, she served as senior vice president of finance and treasurer for Southern Company and has held various positions with Mirant Corporation, including chief commercial officer, South Region. James Y. Kerr II Executive Vice President, General Counsel, and Chief Compliance Officer Kerr, 53, assumed his current role in March 2014. Previously, he was a partner with McGuireWoods LLP and a senior advisor at McGuireWoods Consulting LLC. He also served as co-chairman of McGuireWoods’ energy industry team with focus in the areas of energy transactions and finance, energy regulation, energy policy, and energy litigation. Prior to joining McGuireWoods, Kerr served as a commissioner on the North Carolina Utilities Commission and was the former president of the National Association of Regulatory Utility Commissioners. Stephen E. Kuczynski Chairman, President. and CEO, Southern Nuclear Kuczynski, 54, joined the Company in July 2011 as chairman, president, and CEO of Southern Nuclear. Previously, he was senior vice president of engineering and technical services for Exelon Nuclear. He also served as senior vice president of Exelon Nuclear’s Midwest operations, senior vice president of operations support. and plant manager and later site vice president of Exelon’s Byron Nuclear Station. investor.southerncompany.com 132 Management Council Mark S. Lantrip Executive Vice President Chairman, President, and CEO, Southern Company Services, Inc. Lantrip, 62, joined the Company in 1981 as an analyst in Gulf Power’s corporate planning department. He assumed his current position in March 2014. Previously, Lantrip was executive vice president of finance and treasurer of Southern Company Services and treasurer of Southern Company, with responsibility for financial planning and analysis, enterprise risk management, trust finance, capital markets, and treasury. Nancy E. Sykes Executive Vice President and Chief Human Resources Officer, Southern Company Services, Inc. Sykes, 48, joined the Company in December 2016 as executive vice president and chief human resources officer, managing the human resources and labor relations function for the overall Southern Company enterprise. Previously, she served as vice president and chief human resources officer for United States Steel Corporation and vice president for human resources, Asia Pacific, at Goodyear Tire and Rubber Company. Prior to Goodyear, Sykes worked at General Electric for 20 years in a number of positions serving the company’s industrial businesses. Anthony L. Wilson Chairman, President, and CEO, Mississippi Power Wilson, 54, joined the Company in 1984 as an engineering co-op student. Since 2002, he served in a variety of officer roles at Georgia Power, including distribution vice president, transmission vice president, and customer service and operations executive vice president. Wilson was appointed president of Mississippi Power in October 2015 and assumed the CEO role in January 2016. Christopher C. Womack Executive Vice President and President, External Affairs Womack, 59, joined the Company in 1988 as a governmental affairs representative for Alabama Power. He has held his current position since January 2009. Previously, Womack was executive vice president of external affairs for Georgia Power. He has also served as senior vice president of human resources and chief people officer for Southern Company, as well as senior vice president and senior production officer for Southern Company Generation. . l y n a p m o c e y g r a w w w y b . d e r a p e r P Southern Company 2016 Annual Report Thomas A. Fanning Thomas A. Fanning Chairman, President & CEO, Southern Company Chairman, President & CEO, Southern Company Shareholder Information Shareholder Information Transfer Agent Transfer Agent Investor Information Investor Information Wells Fargo Shareowner Services is Southern Company’s transfer Wells Fargo Shareowner Services is Southern Company’s transfer For information about earnings and dividends, stock For information about earnings and dividends, stock agent, dividend-paying agent, investment plan administrator and agent, dividend-paying agent, investment plan administrator and registrar. If you have questions concerning your registered Southern registrar. If you have questions concerning your registered Southern quotes and current news releases, please visit us at quotes and current news releases, please visit us at investor.southerncompany.com. investor.southerncompany.com. Company shareowner account, please contact: Company shareowner account, please contact: Wells Fargo Shareowner Services Wells Fargo Shareowner Services 1110 Centre Pointe Curve, Suite 101 1110 Centre Pointe Curve, Suite 101 Mendota Heights, Minnesota 55120 Mendota Heights, Minnesota 55120 Telephone: 1.800.554.7626 Telephone: 1.800.554.7626 Website: shareowneronline.com Website: shareowneronline.com Southern Company Shareholder Relations Southern Company Shareholder Relations Telephone: 404.506.0965 Telephone: 404.506.0965 Email: stockholders@southernco.com Email: stockholders@southernco.com Southern Investment Plan Southern Investment Plan The Southern Investment Plan is a convenient way to become The Southern Investment Plan is a convenient way to become a Southern Company shareholder. Participants in the Plan can a Southern Company shareholder. Participants in the Plan can purchase additional shares in Southern Company through optional purchase additional shares in Southern Company through optional Institutional Investor Inquiries Institutional Investor Inquiries Southern Company maintains an investor relations office in Southern Company maintains an investor relations office in Atlanta, Georgia, 404.506.0780, to meet the information needs Atlanta, Georgia, 404.506.0780, to meet the information needs of institutional investors and securities analysts. of institutional investors and securities analysts. Electronic Delivery of Proxy Materials Electronic Delivery of Proxy Materials Any stockholder may enroll for electronic delivery of proxy Any stockholder may enroll for electronic delivery of proxy materials by logging on at www.icsdelivery.com/so. materials by logging on at www.icsdelivery.com/so. Environmental Information Environmental Information Southern Company publishes information on its activities to meet Southern Company publishes information on its activities to meet environmental commitments at www.southerncompany.com/ environmental commitments at www.southerncompany.com/ corporate-responsibility. corporate-responsibility. To request printed materials, write to: To request printed materials, write to: cash purchases and reinvestment of dividends. The Southern cash purchases and reinvestment of dividends. The Southern Director, Environmental Affairs Director, Environmental Affairs Investment Plan prospectus can be found at Investment Plan prospectus can be found at www.southerncompany.com. www.southerncompany.com. Dividend Payments Dividend Payments Research and Environmental Affairs Research and Environmental Affairs 600 North 18th St. 600 North 18th St. Bin 14N-8195 Bin 14N-8195 Birmingham, AL 35203-2206 Birmingham, AL 35203-2206 Southern Company has paid dividends since 1948. Historically, Southern Company has paid dividends since 1948. Historically, dividends are declared and paid quarterly at the discretion of dividends are declared and paid quarterly at the discretion of Common Stock Common Stock the Board of Directors. the Board of Directors. Annual Meeting Annual Meeting Southern Company common stock is listed on the NYSE under the Southern Company common stock is listed on the NYSE under the ticker symbol SO. On December 31, 2016, Southern Company had ticker symbol SO. On December 31, 2016, Southern Company had 126,338 shareholders of record. 126,338 shareholders of record. The 2017 Annual Meeting of Stockholders will be held Wednesday, The 2017 Annual Meeting of Stockholders will be held Wednesday, May 24, at 10 a.m. ET at The Lodge Conference Center at Callaway May 24, at 10 a.m. ET at The Lodge Conference Center at Callaway Visit our website at www.southerncompany.com Visit our website at www.southerncompany.com Gardens, Highway 18, Pine Mountain, Ga. 31822. Gardens, Highway 18, Pine Mountain, Ga. 31822. Auditors Auditors Deloitte & Touche LLP Deloitte & Touche LLP 191 Peachtree St. NE 191 Peachtree St. NE Suite 2000 Suite 2000 Atlanta, GA 30303 Atlanta, GA 30303 Visit our Corporate Responsibility Report at Visit our Corporate Responsibility Report at www.southerncompany.com/corporate-responsibility www.southerncompany.com/corporate-responsibility Follow us on Twitter at www.twitter.com/southerncompany Follow us on Twitter at www.twitter.com/southerncompany SouthernCompany.com2016 Annual ReportThe energy to lead