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(*)	At December 31, 2019

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Documents incorporated by reference: specified portions of The Southern Company's Definitive Proxy Statement on Schedule 14A relating to the 2020 Annual Meeting of Stockholders are incorporated by reference into PART III. In addition, specified portions of Alabama Power Company's Definitive Proxy Statement on Schedule 14A relating to its 2020 Annual Meeting of Shareholders are incorporated by reference into PART III.

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•	the impact of recent and future federal and state regulatory changes, including tax, environmental, and other laws and regulations to which Southern Company and its subsidiaries are subject, as well as changes in application of existing laws and regulations;

•	the extent and timing of costs and legal requirements related to CCR;

•	current and future litigation or regulatory investigations, proceedings, or inquiries, including litigation and other disputes related to the Kemper County energy facility;

•	the effects, extent, and timing of the entry of additional competition in the markets in which Southern Company's subsidiaries operate, including from the development and deployment of alternative energy sources;

•	variations in demand for electricity and natural gas;

•	available sources and costs of natural gas and other fuels;

•	the ability to complete necessary or desirable pipeline expansion or infrastructure projects, limits on pipeline capacity, and operational interruptions to natural gas distribution and transmission activities;

•	transmission constraints;

•	effects of inflation;

•

the ability to control costs and avoid cost and schedule overruns during the development, construction, and operation of facilities or other projects, including Plant Vogtle Units 3 and 4, which includes components based on new technology that only within the last few years began initial operation in the global nuclear industry at this scale, and including changes in labor costs, availability, and productivity; challenges with management of contractors or vendors; subcontractor performance; adverse weather conditions; shortages, delays, increased costs, or inconsistent quality of equipment, materials, and labor; contractor or supplier delay; delays due to judicial or regulatory action; nonperformance under construction, operating, or other agreements; operational readiness, including specialized operator training and required site safety programs; engineering or design problems; design and other licensing-based compliance matters, including, for nuclear units, the timely submittal by Southern Nuclear of the ITAAC documentation for each unit and the related reviews and approvals by the NRC necessary to support NRC authorization to load fuel; challenges with start-up activities, including major equipment failure, system integration, or regional transmission upgrades; and/or operational performance;

•	the ability to overcome or mitigate the current challenges at Plant Vogtle Units 3 and 4, as described in Note 2 to the financial statements under "Georgia Power – Nuclear Construction" in Item 8 herein, that could impact the cost and schedule for the project;

•	legal proceedings and regulatory approvals and actions related to construction projects, such as Plant Vogtle Units 3 and 4 and pipeline projects, including PSC approvals and FERC and NRC actions;

•	under certain specified circumstances, a decision by holders of more than 10% of the ownership interests of Plant Vogtle Units 3 and 4 not to proceed with construction and the ability of other Vogtle Owners to tender a portion of their ownership interests to Georgia Power following certain construction cost increases;

•	in the event Georgia Power becomes obligated to provide funding to MEAG Power with respect to the portion of MEAG Power's ownership interest in Plant Vogtle Units 3 and 4 involving JEA, any inability of Georgia Power to receive repayment of such funding;

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•	the ability to construct facilities in accordance with the requirements of permits and licenses (including satisfaction of NRC requirements), 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 employee and retiree benefit plans and nuclear decommissioning trust funds;

•	advances in technology;

•	performance of counterparties under 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 ROE, equity ratios, additional generating capacity, and fuel and other cost recovery mechanisms;

•	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;

•	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;

•	internal restructuring or other restructuring options that may be pursued;

•	potential business strategies, including acquisitions or dispositions of assets or businesses, including the pending disposition by Southern Company Gas of its interests in Pivotal LNG and Atlantic Coast Pipeline, which cannot be assured to be completed or beneficial to Southern Company or its subsidiaries;

•	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 physical attack and the threat of physical attacks;

•	interest rate fluctuations and financial market conditions and the results of financing efforts;

•	access to capital markets and other financing sources;

•	changes in Southern Company's and any of its subsidiaries' credit ratings;

•	changes in the method of determining LIBOR or the replacement of LIBOR with an alternative reference rate;

•	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, 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;

•	impairments of goodwill or long-lived assets;

•	the effect of accounting pronouncements issued periodically by standard-setting bodies; and

•	other factors discussed elsewhere herein and in other reports filed by the Registrants from time to time with the SEC.

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Item 1.	BUSINESS

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(1)	The MWs and related facility units may change due to unit rating changes or assignment of units to contracts.

(2)	PPA block sales to current requirement services PPA counterparties.

(3)	Georgia Power will be served by Plant Harris Unit 2 through May 2020.

(4)	AMEA will be served by Plant Franklin Unit 1 through May 2020.

(5)	On January 17, 2020, Southern Power completed the sale of its equity interests in Plant Mankato. See Note 15 to the financial statements under "Southern Power – Sales of Natural Gas and Biomass Plants" in Item 8 herein for additional information.

(6)	Represents sale of power purchased from NCEMC under a PPA.

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(1)	Represents forecasted incremental capacity needs over the contract term.

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(a)	Totals may not add due to rounding.

(b)	Includes the Subsidiary Registrants, as well as the other subsidiaries. See "Other Businesses" herein for additional information.

(c)	Includes approximately $0.5 billion contingent upon approval by the Alabama PSC related to Alabama Power's September 6, 2019 CCN filing. See FUTURE EARNINGS POTENTIAL – "Regulatory Matters – Alabama Power – Petition for Certificate of Convenience and Necessity" in Item 7 herein for additional information.

(d)

Reflects cost estimates for environmental laws and regulations. These estimated expenditures do not include any potential compliance costs associated with pending regulation of CO2 emissions from fossil fuel-fired electric generating units or costs associated with closure and monitoring of ash ponds and landfills in accordance with the CCR Rule and the related state rules. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters" and FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements" and "Contractual Obligations" in Item 7 herein for additional information.

(e)	Does not include approximately $0.5 billion for planned expenditures for plant acquisitions and placeholder growth, which may vary materially due to market opportunities and Southern Power's ability to execute its growth strategy.

(f)	Includes costs for ongoing capital projects associated with infrastructure improvement programs for certain natural gas distribution utilities that have been previously approved by their applicable state regulatory agencies. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Construction Programs – Southern Company Gas" in Item 7 herein for additional information.

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•	changes in the availability or price of natural gas and other forms of energy;

•	general economic conditions;

•	energy conservation, including state-supported energy efficiency programs;

•	legislation and regulations;

•	the cost and capability to convert from natural gas to alternative energy products; and

•	technological changes resulting in displacement or replacement of natural gas appliances.

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•	the potential harmful effects on the environment and human health and safety resulting from a release of radioactive materials;

•	uncertainties with respect to the ability to dispose of spent nuclear fuel and the need for longer term on-site storage;

•	uncertainties with respect to the technological and financial aspects of decommissioning nuclear plants at the end of licensed lives and the ability to maintain and anticipate adequate capital reserves for decommissioning;

•	limitations on the amounts and types of insurance commercially available to cover losses that might arise in connection with any nuclear operations; and

•	significant capital expenditures relating to maintenance, operation, security, and repair of these facilities.

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•	shortages, delays, increased costs, or inconsistent quality of equipment, materials, and labor;

•	challenges with management of contractors, subcontractors, or vendors;

•	work stoppages;

•	contractor or supplier delay;

•	nonperformance under construction, operating, or other agreements;

•	delays in or failure to receive necessary permits, approvals, tax credits, and other regulatory authorizations;

•	challenges with start-up activities (including major equipment failure, system integration, or regional transmission upgrades) and/or operational performance;

•	operational readiness, including specialized operator training and required site safety programs;

•	impacts of new and existing laws and regulations, including environmental laws and regulations;

•	the outcome of any legal challenges to projects, including legal challenges to regulatory approvals;

•	failure to construct in accordance with permits and licenses (including satisfaction of NRC requirements);

•	failure to satisfy any environmental performance standards and the requirements of tax credits and other incentives;

•	continued public and policymaker support for projects;

•	adverse weather conditions or natural disasters;

•	engineering or design problems;

•	design and other licensing-based compliance matters;

•	environmental and geological conditions;

•	delays or increased costs to interconnect facilities to transmission grids; and

•	increased financing costs as a result of changes in market interest rates or as a result of project delays.

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•	prevailing market prices for coal, natural gas, uranium, fuel oil, and other fuels, as applicable, used in the generation facilities of the traditional electric operating companies and Southern Power and, in the case of natural gas, distributed by Southern Company Gas, including associated transportation costs, and supplies of such commodities;

•	demand for energy and the extent of additional supplies of energy available from current or new competitors;

•	liquidity in the general wholesale electricity and natural gas markets;

•	weather conditions impacting demand for electricity and natural gas;

•	seasonality;

•	transmission or transportation constraints, disruptions, or inefficiencies;

•	availability of competitively priced alternative energy sources;

•	forced or unscheduled plant outages for the Southern Company system, its competitors, or third party providers;

•	the financial condition of market participants;

•	the economy in the Southern Company system's service territory, the nation, and worldwide, including the impact of economic conditions on demand for electricity and the demand for fuels, including natural gas;

•	natural disasters, wars, embargos, physical or cyber attacks, and other catastrophic events; and

•	federal, state, and foreign energy and environmental regulation and legislation.

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•	they may not result in an increase in income or provide adequate or expected funds or return on capital or other anticipated benefits;

•	they may result in Southern Company or its subsidiaries entering into new or additional lines of business, which may have new or different business or operational risks;

•	they may not be successfully integrated into the acquiring company's operations and/or internal control processes;

•	the due diligence conducted prior to a transaction may not uncover situations that could result in financial or legal exposure or may not appropriately evaluate the likelihood or quantify the exposure from identified risks;

•	they may result in decreased earnings, revenues, or cash flow;

•	they may involve retained obligations in connection with transitional agreements or deferred payments related to dispositions that subject Southern Company or its subsidiaries to additional risk;

•	Southern Company or the applicable subsidiary may not be able to achieve the expected financial benefits from the use of funds generated by any dispositions;

•	expected benefits of a transaction may be dependent on the cooperation, performance, or credit risk of a counterparty; or

•	for the traditional electric operating companies and Southern Company Gas, costs associated with such investments that were expected to be recovered through regulated rates may not be recoverable.

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Item 1B.	UNRESOLVED STAFF COMMENTS.

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(a)	See "Jointly-Owned Facilities" and "Titles to Property" herein and Note 5 to the financial statements under "Joint Ownership Agreements" in Item 8 herein for additional information.

(b)

Alabama Power and Georgia Power each own 50% of the outstanding common stock of SEGCO, an operating public utility company. Alabama Power and Georgia Power are each entitled to one-half of SEGCO's capacity and energy. Alabama Power acts as SEGCO's agent in the operation of SEGCO's units and furnishes fuel to SEGCO for its units. See Note 7 to the financial statements under "SEGCO" in Item 8 herein for additional information.

(c)	Generation is dedicated to a single industrial customer. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Credit Rating Risk" in Item 7 herein.

(d)	On January 17, 2020, Southern Power completed the sale of its equity interest in Plant Mankato to a subsidiary of Xcel. See Note 15 to the financial statements under "Southern Power – Sales of Natural Gas and Biomass Plants" in Item 8 herein for additional information.

(e)	Operated by OPC.

(f)

Southern Power owns a 67% equity interest in SP Solar (a limited partnership indirectly owning all of Southern Power's solar facilities, except the Roserock and Gaskell West facilities). SP Solar is the 51% majority owner of Boulder 1, Garland, Henrietta, Imperial Valley, Lost Hills Blackwell, North Star, and Tranquillity; the 66% majority owner of Desert Stateline; and the sole owner of the remaining SP Solar facilities. Southern Power is the 51% majority owner of Roserock and also the controlling partner in a tax equity partnership owning Gaskell West. All of these entities are consolidated subsidiaries of Southern Power and the capacity shown in the table is 100% of the nameplate capacity for the respective facility.

(g)

Southern Power is the controlling member in SP Wind (a tax equity entity owning all of Southern Power's wind facilities, except Cactus Flats and Wildhorse Mountain). SP Wind is the 90.1% majority owner of Wake Wind and owns 100% of the remaining SP Wind facilities. Southern Power is the controlling partner in tax equity partnerships owning Cactus Flats and Wildhorse Mountain. All of these entities are consolidated subsidiaries of Southern Power and the capacity shown in the table is 100% of the nameplate capacity for the respective facility.

(h)	Southern Power has two noncontrolling interest partners that own approximately 10 MWs of the facility.

(i)	Southern Power has an equity method investment in the facility as the Class B member.

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Item 3.	LEGAL PROCEEDINGS

Item 4.	MINE SAFETY DISCLOSURES

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Item 5.	MARKET FOR REGISTRANTS' COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

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Item 6.	SELECTED FINANCIAL DATA

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(a)

Southern Company recorded a $2.6 billion pre-tax ($1.4 billion after tax) gain associated with the sale of Gulf Power in 2019. Georgia Power recorded a pre-tax estimated probable loss of $1.1 billion ($0.8 billion after tax) in the second quarter 2018 to reflect its revised estimate to complete construction and start-up of Plant Vogtle Units 3 and 4. In addition, pre-tax charges of $3.4 billion ($2.4 billion after tax) were recorded by Mississippi Power related to the suspension of the Kemper IGCC in 2017. Earnings in all periods presented were impacted by losses related to the Kemper IGCC. See Notes 2 and 15 to the financial statements in Item 8 herein for additional information.

(b)	See Note 15 to the financial statements under "Southern Power – Sales of Renewable Facility Interests" in Item 8 herein for additional information on 2018 changes in noncontrolling interests.

(c)	Amounts related to Gulf Power were reclassified to liabilities held for sale at December 31, 2018. See Note 15 to the financial statements under "Southern Company" in Item 8 herein for additional information.

(d)	The 2019 selected financial and operating data excludes Gulf Power, which was sold effective January 1, 2019. See Note 15 to the financial statements under "Southern Company" in Item 8 herein for additional information.

(e)	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.

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(a)	The 2019 selected financial and operating data excludes Gulf Power, which was sold effective January 1, 2019. See Note 15 to the financial statements under "Southern Company" in Item 8 herein for additional information.

(b)	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.

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(a)	The 2019 selected financial and operating data excludes Gulf Power, which was sold effective January 1, 2019. See Note 15 to the financial statements under "Southern Company" in Item 8 herein for additional information.

(b)	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.

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(*)	Georgia Power recorded a pre-tax estimated probable loss of $1.1 billion ($0.8 billion after tax) in the second quarter 2018 to reflect its revised estimate to complete construction and start-up of Plant Vogtle Units 3 and 4.

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(a)	As a result of the Tax Reform Legislation, Mississippi Power recorded an income tax expense (benefit) of $(35) million and $372 million in 2018 and 2017, respectively.

(b)	Pre-tax charges of $3.4 billion ($2.4 billion after tax) were recorded by Mississippi Power related to the suspension of the Kemper IGCC in 2017. Earnings in all periods presented were impacted by losses related to the Kemper IGCC.

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(a)	As a result of the Tax Reform Legislation, Southern Power recorded an income tax expense (benefit) of $79 million and $(743) million in 2018 and 2017, respectively.

(b)	See Note 15 to the financial statements under "Southern Power – Sales of Renewable Facility Interests" in Item 8 herein for additional information on 2018 changes in noncontrolling interests.

(c)	Prior to December 2017, Southern Power had no employees but was billed for employee-related costs from SCS.

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(a)	As a result of the Merger, pushdown accounting was applied to create a new cost basis for Southern Company Gas' assets, liabilities, and equity as of the acquisition date. Accordingly, the successor financial statements reflect the new basis of accounting, and successor and predecessor period financial results are presented but are not comparable.

(b)	During 2018, Southern Company Gas completed the Southern Company Gas Dispositions. See Note 15 to the financial statements under "Southern Company Gas" in Item 8 herein for additional information.

(c)	As a result of the Tax Reform Legislation, Southern Company Gas recorded income tax expense of $93 million in 2017.

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(a)	As a result of the Merger, pushdown accounting was applied to create a new cost basis for Southern Company Gas' assets, liabilities, and equity as of the acquisition date. Accordingly, the successor financial statements reflect the new basis of accounting, and successor and predecessor period financial results are presented but are not comparable.

(b)	During 2018, Southern Company Gas completed the Southern Company Gas Dispositions. See Note 15 to the financial statements under "Southern Company Gas" in Item 8 herein for additional information.

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Item 7.	MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Item 7A.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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•	The traditional electric operating companies – Alabama Power, Georgia Power, and Mississippi Power – are vertically integrated utilities providing electric service to retail customers in three Southeastern states in addition to wholesale customers in the Southeast.

•

Southern Power develops, constructs, acquires, owns, and manages power generation assets, including renewable energy projects, and sells electricity at market-based rates in the wholesale market. Southern Power continually seeks opportunities to execute its strategy to create value through various transactions including acquisitions, dispositions, and sales of partnership interests, development and construction of new generating facilities, and entry into PPAs primarily with investor-owned utilities, IPPs, municipalities, electric cooperatives, and other load-serving entities, as well as commercial and industrial customers. In general, Southern Power commits to the construction or acquisition of new generating capacity only after entering into or assuming long-term PPAs for the new facilities.

•

Southern Company Gas is an energy services holding company whose primary business is the distribution of natural gas. Southern Company Gas owns natural gas distribution utilities in four states – Illinois, Georgia, Virginia, and Tennessee – and is also involved in several other complementary businesses. Southern Company Gas manages its business through four reportable segments – gas distribution operations, gas pipeline investments, wholesale gas services, which includes Sequent, a natural gas asset optimization company, and gas marketing services, which includes SouthStar, a provider of energy-related products and services to natural gas markets – and one non-reportable segment, all other. See Notes 7 and 16 to the financial statements for additional information.

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•	On September 25, 2019, the Virginia Commission approved Virginia Natural Gas' Steps to Advance Virginia's Energy (SAVE) program request to amend and extend the program through 2024 with estimated capital spend totaling approximately $365 million.

•	On October 2, 2019, the Illinois Commission approved a $168 million annual base rate increase for Nicor Gas, including $65 million related to the recovery of investments under the Investing in Illinois program, which became effective October 8, 2019.

•	On December 19, 2019, the Georgia PSC approved a $65 million annual base rate increase for Atlanta Gas Light, effective January 1, 2020.

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(a)

Weather-adjusted KWH sales are estimated by removing from KWH sales the effect of deviations from normal temperature conditions, based on statistical models of the historical relationship between temperatures and energy sales. Normal temperature conditions are defined as those experienced in the applicable service territory over a specified historical period. This metric is useful because it allows trends in historical operations to be evaluated apart from the influence of weather conditions. Management also considers this metric in developing long-term capital and financial plans.

(b)	Kilowatt-hour sales comparisons to the prior year were significantly impacted by the disposition of Gulf Power on January 1, 2019. These changes exclude Gulf Power.

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(a)	Excludes Gulf Power, which was sold on January 1, 2019.

(b)	Average cost of purchased power includes fuel purchased by the Southern Company system for tolling agreements where power is generated by the provider.

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(*)	Includes a $245 million decrease related to natural gas revenues, including alternative revenue programs, and a $55 million decrease related to other revenues. See Note 15 to the financial statements under "Southern Company Gas" for additional information.

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(a)	For 2018, cost of fuel, generated and average cost of fuel, generated excludes a $30 million adjustment associated with a May 2018 Alabama PSC accounting order related to excess deferred income taxes. See FUTURE EARNINGS POTENTIAL – "Regulatory Matters – Alabama Power – Tax Reform Accounting Order" herein for additional information.

(b)	KWHs generated by hydro are excluded from the average cost of fuel, generated.

(c)	Average cost of purchased power includes fuel, energy, and transmission purchased by Alabama Power for tolling agreements where power is generated by the provider.

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•

PPA capacity revenues decreased $98 million, or 17%, primarily due to the sales of the Florida Plants in December 2018 and Plant Nacogdoches in June 2019. In addition, the change reflects a reduction of $34 million from the expiration of an affiliate natural gas PPA, offset by a $36 million increase in new PPA capacity revenues from existing natural gas facilities, of which $13 million related to the expansion unit at Plant Mankato.

•	PPA energy revenues decreased $59 million, or 5%, primarily due to a $67 million decrease in sales from natural gas facilities primarily driven by a $103 million decrease in the average cost of fuel and purchased power, partially offset by a $36 million increase in the volume of KWHs sold due to increased customer load.

•	Non-PPA revenues decreased $109 million, or 23%, primarily due to a $72 million decrease in the volume of KWHs sold through short-term sales and a $37 million decrease in the market price of energy.

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(*)	Includes a $245 million decrease related to natural gas revenues, including alternative revenue programs, and a $55 million decrease related to other revenues. See Note 15 to the financial statements under "Southern Company Gas" for additional information.

(a)	Normal represents the 10-year average from January 1, 2009 through December 31, 2018 for Illinois at Chicago Midway International Airport and for Georgia at Atlanta Hartsfield-Jackson International Airport, based on information obtained from the National Oceanic and Atmospheric Administration, National Climatic Data Center.

(b)	Heating Degree Days in Illinois are expected to have a limited financial impact in future years. On October 2, 2019, Nicor Gas received approval for a volume balancing adjustment, a revenue decoupling mechanism for residential customers that provides a monthly benchmark level of revenue per rate class for recovery.

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(*)	Gas marketing services' customers are primarily located in Georgia and Illinois. Also included as of December 31, 2018 were approximately 70,000 customers in Ohio contracted through an annual auction process to serve for 12 months beginning April 1, 2018.

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(*)	Includes total volumes of natural gas sold of 38 mmBtu for 2018 related to Elizabethtown Gas, Elkton Gas, and Florida City Gas, which were sold in July 2018. See Note 15 to the financial statements under "Southern Company Gas – Sale of Elizabethtown Gas and Elkton Gas" and " – Sale of Florida City Gas" for additional information.

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(a)	Includes other operations and maintenance, depreciation and amortization, taxes other than income taxes, impairment charges, and gain (loss) on dispositions, net.

(b)	Nicor Gas' revenue tax expenses, which are passed through directly to customers.

(a)	Adjusted operating margin and operating expenses are adjusted for Nicor Gas' revenue tax expenses, which are passed through directly to customers.

(b)	Operating expenses for gas distribution operations and gas marketing services include the gain on dispositions, net. Net income for gas distribution operations and gas marketing services includes the gain on dispositions, net and the associated income tax expense. See Note 15 to the financial statements under "Southern Company Gas" for additional information.

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(a)	At December 31, 2019, the WACOG of wholesale gas services' expected natural gas withdrawals from storage was $1.87 per mmBtu.

(b)	Represents expected operating losses from planned storage withdrawals associated with existing inventory positions and could change as wholesale gas services adjusts its daily injection and withdrawal plans in response to changes in future market conditions and forward NYMEX price fluctuations.

(c)	Represents the expected net gains during the periods in which the derivatives will be settled and the physical transportation transactions will occur that offset the derivative gains and losses previously recognized.

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(a)	Includes other operations and maintenance, depreciation and amortization, taxes other than income taxes, impairment charges, and (gain) loss on dispositions, net.

(b)	Nicor Gas' revenue tax expenses, which are passed through directly to customers.

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(a)	During 2019, Southern Power made a total investment of approximately $167 million in DSGP and now holds a controlling interest and consolidates 100% of DSGP's operating results. Southern Power records net income attributable to noncontrolling interests for approximately 10 MWs of the facility.

(b)

Southern Power's 18-MW share of the facility was repowered between June and August 2019. In December 2019, a Class C member joined the existing partnership between the Class A member and Southern Power and made an investment to repower the remaining 10 MWs. In connection with the Class C member joining the partnership, the original fuel cells (before repower), which had a carrying value of approximately $55 million, were distributed to the Class A member in a non-cash transaction that was excluded from the statements of cash flows.

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(a)	Includes non-registrant subsidiaries.

(b)	The 2018 and preliminary 2019 amounts include GHG emissions attributable to disposed assets through the date of the applicable disposition. See Note 15 to the financial statements for additional information regarding disposition activities.

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(a)	Effective January 1, 2020, CCR AROs will be recovered through the ECCR tariff. See "Integrated Resource Plan" herein for additional information on recovery of compliance costs for CCR AROs.

(b)	Totals may not add due to rounding.

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•	distributing natural gas for Marketers;

•	constructing, operating, and maintaining the gas system infrastructure, including responding to customer service calls and leaks;

•	reading meters and maintaining underlying customer premise information for Marketers; and

•	planning and contracting for capacity on interstate transportation and storage systems.

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(a)	Atlanta Gas Light's authorized ROE and ROE range became effective on January 1, 2020. Atlanta Gas Light's ROE for 2019 was 10.75%.

(b)

Regulatory mechanisms that allow recovery of costs in the event of unseasonal weather, but are not direct offsets to the potential impacts on earnings of weather and customer consumption. These mechanisms are designed to help stabilize operating results by increasing base rate amounts charged to customers when weather is warmer than normal and decreasing amounts charged when weather is colder than normal.

(c)	Allows for recovery of fixed customer service costs separately from assumed natural gas volumes used by customers. On October 2, 2019, Nicor Gas received approval for a volume balancing adjustment, a revenue decoupling mechanism for residential customers that provides a monthly benchmark level of revenue per rate class for recovery.

(d)	Programs that update or expand distribution systems and LNG facilities.

(e)	The recovery (refund) of bad debt expense over (under) an established benchmark expense. Nicor Gas, Virginia Natural Gas, and Chattanooga Gas recover the gas portion of bad debt expense through their purchased gas adjustment mechanisms.

(f)	Recovery of costs associated with plans to achieve specified energy savings goals.

(g)	Regulatory mechanism allowing annual adjustments to base rates up or down based on authorized ROE and/or ROE range.

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(a)	Excludes financing costs expected to be capitalized through AFUDC of approximately $300 million, of which $23 million had been accrued through December 31, 2019.

(b)	Net of $1.7 billion received from Toshiba under the Guarantee Settlement Agreement and approximately $188 million in related customer refunds.

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(a)

Southern Power completed the sale of its equity interests in Plant Mankato, including the expansion, to a subsidiary of Xcel on January 17, 2020. The expansion unit started providing energy under a PPA with Northern States Power on June 1, 2019. See "Acquisitions and Dispositions – Southern Power – Sales of Natural Gas and Biomass Plants" herein and Note 15 to the financial statements under "Southern Power" and "Assets Held for Sale" for additional information.

(b)	In May 2018, Southern Power purchased 100% of the membership interests of the Wildhorse Mountain facility. In December 2019, Southern Power entered into a tax equity partnership and, as a result, owns 100% of the Class B membership interests.

(c)	In August 2018, Southern Power purchased 100% of the membership interests of the Reading facility pursuant to a joint development arrangement. Southern Power may enter into a tax equity partnership, in which case it would then own 100% of the Class B membership interests. The ultimate outcome of this matter cannot be determined at this time.

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(d)

In October 2019, Southern Power purchased 100% of the membership interests of the Skookumchuck facility pursuant to a joint development arrangement. In December 2019, Southern Power entered into a tax equity agreement as the Class B member with funding of the tax equity amounts expected to occur upon commercial operation. Shortly after commercial operation, Southern Power may sell a noncontrolling interest in these Class B membership interests to another partner. The ultimate outcome of this matter cannot be determined at this time.

(*)	Includes replacement of pipes, compressors, and transmission mains along with other improvements such as new meters. Scope of program miles is an estimate and subject to change.

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(*)	Cash flows resulting from bonus depreciation for Southern Power would also be impacted by Southern Power's use of tax equity partnerships.

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•	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 nonperformance risk on liabilities.

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•	Assessing whether specific property is explicitly or implicitly identified in the agreement;

•	Determining whether the fulfillment of the arrangement is dependent on the use of the identified property; and

•	Assessing whether the arrangement conveys to the counterparty substantially all of the economic benefits and the right to direct the use of the asset.

•	Assessing whether the contract meets the definition of a derivative;

•	Assessing whether the contract meets the definition of a capacity contract;

•	Assessing the probability at inception and throughout the term of the individual contract that the contract will result in physical delivery; and

•	Ensuring that the contract quantities do not exceed available generating capacity (including purchased capacity).

•	Identifying the hedging instrument, the forecasted hedged transaction, and the nature of the risk being hedged; and

•	Assessing hedge effectiveness at inception and throughout the contract term.

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•	decreases in assets and liabilities held for sale of $5.0 billion and $3.3 billion, respectively, and an increase of $2.7 billion in total stockholders' equity primarily related to the sale of Gulf Power;

•

an increase of $2.3 billion in total property, plant, and equipment primarily related to the traditional electric operating companies' construction of electric generation, transmission, and distribution facilities, including installation of equipment to comply with environmental standards, net of $1.2 billion and $1.0 billion reclassified to other regulatory assets and regulatory assets associated with AROs, respectively, as a result of generating unit retirements at Alabama Power and Georgia Power;

•	an increase in other regulatory assets of $1.8 billion primarily related to the $1.2 billion reclassification from property, plant, and equipment discussed above and a $0.8 billion increase in regulatory assets associated with retiree benefit plans primarily resulting from a decrease in the overall discount rate used to calculate benefit obligations;

•	increases in operating lease right-of-use assets, net of amortization and operating lease obligations, each totaling $1.8 billion, recorded upon the adoption of ASC 842;

•	an increase of $1.4 billion in regulatory assets associated with AROs primarily related to the $1.0 billion reclassification from property, plant, and equipment discussed above and ARO revisions at Alabama Power and Mississippi Power related to the CCR Rule;

•	an increase of $1.3 billion in accumulated deferred income taxes primarily related to the expected utilization of tax credit carryforwards in the 2019 tax year as a result of increased taxable income from the sale of Gulf Power; and

•	a decrease of $0.9 billion in notes payable related to net repayments of short-term bank debt and commercial paper.

•	an increase of $1.5 billion in total common stockholder's equity primarily due to a $1.2 billion capital contribution from Southern Company;

•	increases of $0.9 billion in regulatory assets associated with AROs and $0.7 billion in other regulatory assets, deferred primarily due to the impacts of retiring and reclassifying Plant Gorgas Units 8, 9, and 10;

•	an increase of $0.6 billion in cash and cash equivalents; and

•	an increase of $0.3 billion in AROs, deferred primarily due to an increase in the ARO estimate related to ash pond facilities.

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•	an increase of $1.8 billion in long-term debt (including securities due within one year) primarily due to borrowings from the FFB for construction of Plant Vogtle Units 3 and 4, issuances of senior notes, and pollution control revenue bonds being reoffered to the public;

•	an increase of $1.6 billion in property, plant, and equipment to comply with environmental standards and the construction of generation, transmission, and distribution facilities, net of approximately $0.8 billion reclassified to regulatory assets due to the retirement of certain generating units as approved in the Georgia Power 2019 IRP;

•	increases in operating lease right-of-use assets, net of amortization and operating lease obligations, each totaling $1.4 billion, recorded upon the adoption of ASC 842;

•	an increase of $1.2 billion in regulatory assets primarily due to the $0.8 billion reclassification from property, plant, and equipment discussed above and $0.2 billion associated with retiree benefit plans primarily as a result of a decrease in the overall discount rate used to calculate benefit obligations; and

•	an increase of $742 million in total common stockholder's equity primarily due to capital contributions from Southern Company.

•	a decrease of $231 million in long-term debt, primarily due to the reclassification of $249 million of senior notes to securities due within one year and the redemption of $25 million of senior notes, partially offset by $43 million in pollution control revenue bonds reoffered to the public;

•	an increase of $107 million in other property and investments primarily due to a new tolling arrangement accounted for as a sales-type lease;

•	increases of $67 million in regulatory assets associated with AROs and $31 million in AROs, deferred primarily due to ARO revisions; and

•	a net change of $57 million in accumulated deferred income tax assets and liabilities primarily due to the recognition of a tax loss on the CO2 pipeline transfer and the alternative minimum tax carryforward from prior years.

•	a $662 million decrease in stockholders' equity due to returns of capital to Southern Company;

•	a $635 million decrease in accumulated deferred income tax assets primarily related to the utilization of tax credits for the 2019 tax year;

•	a $619 million decrease in long-term debt (including securities due within one year) related to the maturity of $600 million in senior notes;

•	a $449 million increase in notes payable due to net issuances of commercial paper; and

•	increases in operating lease right-of-use assets, net of amortization and operating lease obligations totaling $369 million and $376 million, respectively, recorded upon the adoption of ASC 842.

•	an increase of $950 million in property, plant, and equipment primarily due to utility capital expenditures and infrastructure investments recovered through replacement programs, partially offset by $115 million of asset impairment charges;

•	additional paid-in-capital of $841 million primarily related to capital contributions from Southern Company;

•	decreases of $373 million and $414 million in energy marketing receivables and payables, respectively, due to lower natural gas prices and volumes of natural gas sold;

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•	a $287 million decrease in equity investments in unconsolidated subsidiaries primarily due to $151 million associated with Pivotal LNG and Atlantic Coast Pipeline reclassified to assets held for sale, as well as distributions from SNG and the sale of Triton;

•	a $203 million increase in accumulated deferred income taxes primarily due to accelerated tax depreciation and other timing differences;

•	reclassification of $171 million in total assets held for sale associated with Pivotal LNG and Atlantic Coast Pipeline;

•	a $95 million decrease in long-term debt primarily due to the redemption of $300 million in senior notes and the repayment of $50 million in first mortgage bonds, partially offset by the issuance of $300 million in first mortgage bonds; and

•	increases of $93 million in operating right-of-use assets and $92 million in operating lease obligations, respectively, related to the adoption of ASC 842.

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(*)	Includes $600 million and $465 million of securities due within one year and notes payable, respectively, at the parent company.

(a)

At December 31, 2019, Southern Power also had a continuing letter of credit facility for standby letters of credit, of which $23 million was unused. Subsequent to December 31, 2019, Southern Power entered into an additional $60 million continuing letter of credit facility for standby letters of credit. Southern Power's subsidiaries are not parties to its bank credit arrangement or to the letter of credit facilities.

(b)	Includes $1.245 billion and $500 million at Southern Company Gas Capital and Nicor Gas, respectively.

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(*)	Average and maximum amounts are based upon daily balances during the 12-month periods ended December 31, 2019, 2018, and 2017.

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(a)	Includes reductions in finance lease obligations resulting from cash payments under finance leases.

(b)	Represents reductions in affiliate finance lease obligations at Georgia Power, which are eliminated in Southern Company's consolidated financial statements.

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•	$173 million aggregate principal amount of Development Authority of Bartow County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Bowen Project), First Series 2009;

•	approximately $105 million aggregate principal amount of Development Authority of Burke County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Vogtle Project), First Series 2013;

•	$65 million aggregate principal amount of Development Authority of Burke County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Vogtle Project), Second Series 2008;

•	$55 million aggregate principal amount of Development Authority of Burke County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Vogtle Project), Fifth Series 1994; and

•	approximately $72 million aggregate principal amount of Development Authority of Bartow County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Bowen Project), First Series 2013.

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(*)

Excludes amounts related to Plant Mankato, which was sold on January 17, 2020. Southern Power has PPAs that could require collateral, but not accelerated payment, in the event of a downgrade of Southern Power's credit. The PPAs require credit assurances without stating a specific credit rating. The amount of collateral required would depend upon actual losses resulting from a credit downgrade. Southern Power had $104 million of cash collateral posted related to PPA requirements at December 31, 2019.

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(*)	Includes $1.8 billion of hedges of existing debt at the Southern Company parent.

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(*)	Includes $1.5 billion of long-term variable interest rate exposure at the Southern Company parent entity.

(a)	Excludes cash collateral held on deposit in broker margin accounts of $99 million, $277 million, and $193 million at December 31, 2019, 2018, and 2017, respectively, and premium and intrinsic value associated with weather derivatives of $4 million, $8 million, and $11 million at December 31, 2019, 2018, and 2017, respectively.

(b)	The changes in fair value of energy-related derivative contracts are substantially attributable to both the volume and the price of natural gas. Current period changes also include the changes in fair value of new contracts entered into during the period, if any.

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(a)	Valued using NYMEX futures prices.

(b)	Level 2 amounts for Southern Company Gas are valued using basis transactions that represent the cost to transport natural gas from a NYMEX delivery point to the contract delivery point. These transactions are based on quotes obtained either through electronic trading platforms or directly from brokers.

(c)	Excludes cash collateral of $99 million as well as premium and associated intrinsic value associated with weather derivatives of $4 million at December 31, 2019.

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(*)	The increase in VaR at December 31, 2018 reflects significant natural gas price increases in Sequent's key markets driven by an industry-wide lower-than-normal natural gas storage inventory position and colder-than-normal weather in the middle of fourth quarter 2018. As weather and natural gas prices moderated subsequent to December 31, 2018, VaR reduced.

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(a)	Includes the Subsidiary Registrants, as well the other subsidiaries.

(b)	Includes amounts contingent upon approval by the Alabama PSC related to Alabama Power's September 6, 2019 CCN filing totaling $0.5 billion for 2020, $0.2 billion for 2021, $0.3 billion for 2022, and $0.1 billion for 2023. See FUTURE EARNINGS POTENTIAL – "Regulatory Matters – Alabama Power – Petition for Certificate of Convenience and Necessity" herein for additional information.

(c)	These amounts include expenditures of approximately $1.6 billion, $0.9 billion, and $0.3 billion for the construction of Plant Vogtle Units 3 and 4 in 2020, 2021, and 2022, respectively.

(d)	These amounts do not include approximately $0.5 billion per year for 2020 through 2024 for Southern Power's planned expenditures for plant acquisitions and placeholder growth, which may vary materially due to market opportunities and Southern Power's ability to execute its growth strategy.

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(*)	Includes funding requirements related to pension and other postretirement benefit plans, nuclear decommissioning trusts of Georgia Power, and preferred stock dividends of Alabama Power.

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Long-term debt – Represents scheduled maturities of long-term debt, as well as the related interest. All amounts are reflected based on final maturity dates except for amounts related to Georgia Power's FFB borrowings. The final maturity date for Georgia Power's FFB borrowings is February 20, 2044; however, principal amortization is reflected beginning in February 2020. The interest amounts also include the effects of interest rate derivatives employed to manage interest rate risk and effects of foreign currency swaps employed to manage foreign currency exchange rate risk, as applicable. For Southern Company and Southern Power, debt principal includes a $5 million loss related to Southern Power's foreign currency hedge of €1.1 billion. The Registrants 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 at December 31, 2019, as reflected in the statements of capitalization for each Registrant. Long-term debt excludes finance lease amounts, which are shown separately. See Note 8 to the financial statements for additional information.

•	Financial derivative obligations – See Note 14 to the financial statements for additional information.

•

Operating and finance leases – See Note 9 to the financial statements for additional information. Operating lease commitments may include certain land leases for facilities that may be subject to annual price escalation based on indices. Estimated lease payments for Southern Company and Alabama Power exclude amounts contingent upon approval by the Alabama PSC related to Alabama Power's September 6, 2019 CCN filing totaling $1 million for 2021, $2 million for 2022, $3 million for 2023, $4 million for 2024, and $85 million for after 2024. See Note 2 to the financial statements under "Alabama Power – Petition for Certificate of Convenience and Necessity" for additional information.

•

Purchase commitments – Capital – Estimated capital expenditures are provided for a five-year period, including capital expenditures associated with environmental regulations. These amounts exclude contractual purchase commitments for nuclear fuel, capital expenditures covered under LTSAs, and estimated capital expenditures for AROs, which are reflected in the "fuel," "other," and "ARO settlements" categories, respectively, where applicable. Estimated capital expenditures for Southern Company and Alabama Power exclude amounts contingent upon approval by the Alabama PSC related to Alabama Power's September 6, 2019 CCN filing totaling $0.5 billion for 2020, $0.2 billion for 2021, $0.3 billion for 2022, and $0.1 billion for 2023. See Note 2 to the financial statements under "Alabama Power – Petition for Certificate of Convenience and Necessity" for additional information. Estimated capital expenditures for Southern Company and Southern Power exclude approximately $0.5 billion per year for 2020 through 2024 for Southern Power's planned expenditures for plant acquisitions and placeholder growth. At December 31, 2019, significant purchase commitments were outstanding in connection with the Registrants' construction programs. See FUTURE EARNINGS POTENTIAL – "Environmental Matters" and "Construction Programs" herein and "Capital Requirements" herein for additional information.

•

Purchase commitments – Fuel – Primarily includes commitments to purchase coal (for the traditional electric operating companies), natural gas (for the traditional electric operating companies and Southern Power), and nuclear fuel (for Alabama Power and Georgia Power), 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 NYMEX future prices at December 31, 2019.

•	Purchase commitments – Purchased power – Represents estimated minimum obligations for various PPAs for the purchase of capacity and energy, as well as, for Georgia Power, capacity payments related to Plant Vogtle Units 1 and 2. Amounts exclude PPAs accounted for as leases, which are reflected in the "operating leases" and "finance leases" categories, where applicable.

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Purchase commitments – Other – Includes LTSAs (for all Registrants), contracts for the procurement of limestone (for Alabama Power and Georgia Power), contractual environmental remediation liabilities (for Southern Company Gas), operation and maintenance agreements (for Southern Power), and transmission agreements (for Southern Power). LTSAs include price escalation based on inflation indices. Southern Power's transmission commitments are based on the Southern Company system's current tariff rate for point-to-point transmission.

•

Pension and other postretirement benefit plans – The Southern Company system 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. The Registrants forecast contributions to their pension and other postretirement benefit plans over a three-year period. The Registrants anticipate no mandatory contributions to the qualified pension plan 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 the applicable subsidiaries. See Note 11 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 the applicable subsidiaries.

•

ARO settlements – Represents estimated costs for a five-year period associated with closing and monitoring ash ponds at the traditional electric operating companies in accordance with the CCR Rule and the related state rules, which are reflected in the applicable Registrants' ARO liabilities. Material expenditures in future years for ARO settlements also will be required for ash ponds, nuclear decommissioning (for Alabama Power and Georgia Power), and other liabilities reflected in the applicable Registrants' AROs. See Note 6 to the financial statements for additional information.

•	Preferred stock dividends – Represents preferred stock of Alabama Power. Preferred stock does not mature; therefore, amounts are provided for the next five years only.

•

Nuclear decommissioning trusts – As a result of NRC requirements, Alabama Power and Georgia Power have external trust funds for nuclear decommissioning costs. Based on its most recent site study completed in 2018, Alabama Power currently has no additional funding requirements. Alabama Power's next site study is expected to be conducted by 2023. Georgia Power's projections of nuclear decommissioning trust fund contributions for Plant Hatch and Plant Vogtle Units 1 and 2 are based on the 2019 ARP. See Note 6 to the financial statements under "Nuclear Decommissioning" for additional information.

•

Pipeline charges, storage capacity, and gas supply – Includes charges at Southern Company Gas recoverable through a natural gas cost recovery mechanism, or alternatively billed to Marketers selling retail natural gas, and demand charges associated with Sequent. The gas supply balance includes amounts for Nicor Gas and SouthStar gas commodity purchase commitments of 45 million mmBtu at floating gas prices calculated using forward natural gas prices at December 31, 2019 and valued at $84 million. Southern Company Gas provides guarantees to certain gas suppliers for certain of its subsidiaries, including SouthStar, in support of payment obligations.

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Item 8.	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

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We tested the effectiveness of management's controls over the evaluation of the likelihood of (1) the recovery in future rates of costs incurred as property, plant, and equipment and deferred as regulatory assets, and (2) a refund or a future reduction in rates that should be reported as regulatory liabilities. We also tested the effectiveness of management's controls over the initial recognition of amounts as property, plant, and equipment; regulatory assets or liabilities; and the monitoring and evaluation of regulatory developments that may affect the likelihood of recovering costs in future rates or of a future reduction in rates.

•

We read relevant regulatory orders issued by the Commissions for the regulated utility subsidiaries, regulatory statutes, interpretations, procedural memorandums, filings made by intervenors, and other publicly available information to assess the likelihood of recovery in future rates or of a future reduction in rates based on precedence of the Commissions' treatment of similar costs under similar circumstances. We evaluated the external information and compared it to management's recorded regulatory asset and liability balances for completeness.

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•	For regulatory matters in process, we inspected filings with the Commissions by both Southern Company's regulated utility subsidiaries and other interested parties that may impact the regulated utility subsidiaries' future rates for any evidence that might contradict management's assertions.

•	We evaluated regulatory filings for any evidence that intervenors are challenging full recovery of the cost of any capital projects. We tested selected costs included in the capitalized project costs for completeness and accuracy.

•	We obtained representation from management regarding probability of recovery for regulatory assets or refund or future reduction in rates for regulatory liabilities to assess management's assertion that amounts are probable of recovery, refund, or a future reduction in rates.

•	We evaluated Southern Company's disclosures related to the impacts of rate regulation, including the balances recorded and regulatory developments.

•	We tested the effectiveness of internal controls over the on-going evaluation and monitoring of the construction schedule and capital cost forecast and over the disclosure of matters related to the construction and ultimate cost recovery of Plant Vogtle Units 3 and 4.

•	We involved construction specialists to assist in our evaluation of Georgia Power's processes for on-going evaluation and monitoring of the construction schedule and cost forecast and to assess the disclosures of challenges to the achievement of such forecasts.

•	We attended meetings with Georgia Power and Southern Company officials, project managers (including contractors), independent regulatory monitors, and co-owners of the project to evaluate and monitor construction status and identify cost and schedule challenges.

•	We read reports of external independent monitors employed by the Georgia Public Service Commission to monitor the status of construction at Plant Vogtle Units 3 and 4 to evaluate the completeness of Georgia Power's disclosure of challenges to the achievement of cost and schedule forecasts.

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•	We inquired of Georgia Power and Southern Company officials and project managers regarding the status of construction, the construction schedule, and cost forecasts to assess the financial statement disclosures with respect to project status and potential risks and uncertainties to the achievement of such forecasts.

•	We inspected regulatory filings and transcripts of Georgia Public Service Commission hearings regarding the construction of Plant Vogtle Units 3 and 4 to identify potential challenges to the recovery of Georgia Power's construction costs and to evaluate the disclosures with respect to such uncertainties.

•	We inquired of Georgia Power and Southern Company management and internal and external legal counsel regarding any potential legal actions or issues arising from project construction or issues involving the co-owners of the project.

•	We compared the financial statement disclosures relating to this matter to the information gathered through the conduct of all our procedures to evaluate whether there were omissions relating to significant facts or uncertainties regarding the status of construction or other factors which could impact the ultimate cost recovery of Plant Vogtle Units 3 and 4.

•	We obtained representation from management regarding disclosure of all matters related to the cost and/or status, including matters related to a co-owner or regulatory development, that could result in a potential disallowance of costs related to the construction of Plant Vogtle Units 3 and 4.

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(a)	Excludes redeemable noncontrolling interests. See Note 7 to the financial statements under "Southern Power – Redeemable Noncontrolling Interests" for additional information.

(b)	See Note 8 under "Equity Units" for additional information.

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(a)	Excludes redeemable noncontrolling interests. See Note 7 to the financial statements under "Noncontrolling Interests" for additional information.

(b)	In connection with Southern Power becoming a participant to the Southern Company qualified pension plan and other postretirement benefit plan, $27 million of other comprehensive income, net of tax of $9 million, was transferred from SCS.

(c)	See Note 15 under "Southern Power - Sales of Renewable Facility Interests" for additional information.

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General

Southern Company is the parent company of three traditional electric operating companies, as well as Southern Power, Southern Company Gas, SCS, Southern Linc, Southern Holdings, Southern Nuclear, PowerSecure, and other direct and indirect subsidiaries. The traditional electric operating companies – Alabama Power, Georgia Power, and Mississippi Power – are vertically integrated utilities providing electric service in three Southeastern states. On January 1, 2019, Southern Company completed the sale of Gulf Power (another traditional electric operating company through December 31, 2018) to NextEra Energy. Southern Power develops, 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 natural gas distribution utilities, including Nicor Gas (Illinois), Atlanta Gas Light (Georgia), Virginia Natural Gas, and Chattanooga Gas (Tennessee). In 2018, Southern Company Gas sold its other natural gas utilities – Elizabethtown Gas (New Jersey), Florida City Gas, and Elkton Gas (Maryland). Southern Company Gas is also involved in several other complementary businesses including gas pipeline investments, wholesale gas services, and gas marketing services. 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 optics services within the Southeast. Southern Holdings is an intermediate holding company subsidiary, primarily for Southern Company's leveraged lease and other investments. Southern Nuclear operates and provides services to the Southern Company system's nuclear power plants, including Alabama Power's Plant Farley and Georgia Power's Plant Hatch and Plant Vogtle Units 1 and 2, and is currently managing construction of and developing Plant Vogtle Units 3 and 4, which are co-owned by Georgia Power. PowerSecure provides energy solutions to electric utilities and their customers in the areas of distributed generation, energy storage and renewables, and energy efficiency. See Note 15 for information regarding disposition activities at Southern Power and Southern Company Gas, as well as additional information regarding Southern Company's sale of Gulf Power.

The Registrants' financial statements reflect investments in subsidiaries on a consolidated basis. Intercompany transactions have been eliminated in consolidation. The equity method is used for investments in entities in which a Registrant has significant influence but does not have control and for VIEs where a Registrant has an equity investment but is not the primary beneficiary. Southern Power has partial ownership in certain legal entities for which the contractual provisions represent profit-sharing arrangements because the allocations of cash distributions and tax benefits are not based on fixed ownership percentages. For these arrangements, the noncontrolling interest is accounted for under a balance sheet approach utilizing the HLBV method. The HLBV method calculates each partner's share of income based on the change in net equity the partner can legally claim in a HLBV at the end of the period compared to the beginning of the period. See "Variable Interest Entities" herein and Note 7 for additional information.

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 respective financial statements of the Registrants 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 the Registrants' results of operations, financial position, or cash flows. In addition, during 2018, Southern Company Gas recast its reportable segments. See Note 16 under "Southern Company Gas" for additional information.

At December 31, 2019 and 2018, Southern Company and Southern Power each had assets and liabilities held for sale on their balance sheets. At December 31, 2019, Southern Company Gas had assets and liabilities held for sale on its balance sheet. Unless otherwise noted, the disclosures herein related to specific asset and liability balances at December 31, 2019 and 2018 exclude assets and liabilities held for sale. See Note 15 under "Assets Held for Sale" for additional information including major classes of assets and liabilities classified as held for sale by Southern Company, Southern Power, and Southern Company Gas.

Recently Adopted Accounting Standards

See Note 4 for information on the Registrants' adoption of ASC 606, Revenue from Contracts with Customers (ASC 606) effective January 1, 2018.

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In 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. The Registrants adopted the new standard effective January 1, 2019. See Note 9 for additional information and related disclosures.

Affiliate Transactions

The traditional electric operating companies, Southern Power, and Southern Company Gas have agreements with SCS under which certain of the following services are rendered to them at direct or allocated cost: general executive and advisory, general and design engineering, operations, purchasing, accounting, finance, treasury, legal, tax, information technology, marketing, auditing, insurance and pension administration, human resources, systems and procedures, digital wireless communications, cellular tower space, and other services with respect to business and operations, construction management, and Southern Company power pool transactions. These costs are primarily included in other operations and maintenance expenses or capitalized to property, plant, and equipment. Costs for these services from SCS in 2019, 2018, and 2017 were as follows:

	Alabama Power			Georgia Power			Mississippi Power			Southern Power(*)			Southern Company Gas
	(in millions)
2019	$	527		$	704		$	118		$	90		$	183
2018	508			653			104			98			194
2017	479			625			140			218			63

(*)	Prior to December 2017, Southern Power had no employees but was billed for employee-related costs from SCS.

Alabama Power and Georgia Power also have agreements with Southern Nuclear under which Southern Nuclear renders the following nuclear-related services at cost: general executive and advisory services; general operations, management, and technical services; administrative services including procurement, accounting, employee relations, systems, and procedures services; strategic planning and budgeting services; other services with respect to business and operations; and, for Georgia Power, construction management. These costs are primarily included in other operations and maintenance expenses or capitalized to property, plant, and equipment. Costs for these services in 2019, 2018, and 2017 amounted to $256 million, $247 million, and $248 million, respectively, for Alabama Power and $760 million, $780 million, and $675 million, respectively, for Georgia Power. See Note 2 under "Georgia Power – Nuclear Construction" for additional information regarding Southern Nuclear's construction management of Plant Vogtle Units 3 and 4 for Georgia Power.

Cost allocation methodologies used by SCS and Southern Nuclear prior to the repeal of the Public Utility Holding Company Act of 1935, as amended, were approved by the SEC. Subsequently, additional cost allocation methodologies have been reported to the FERC and management believes they are reasonable. The FERC permits services to be rendered at cost by system service companies.

Alabama Power's and Georgia Power's power purchases from affiliates through the Southern Company power pool are included in purchased power, affiliates on their respective statements of income. Mississippi Power's and Southern Power's power purchases from affiliates through the Southern Company power pool are included in purchased power on their respective statements of income and were as follows:

	Mississippi Power			Southern Power
	(in millions)
2019	$	3		$	14
2018	15			41
2017	16			27

Georgia Power has entered into several PPAs with Southern Power for capacity and energy. Georgia Power's total expenses associated with these PPAs were $177 million, $216 million, and $235 million in 2019, 2018, and 2017, respectively. Southern Power's total revenues from all PPAs with Georgia Power, included in wholesale revenue affiliates on Southern Power's consolidated statements of income, were $174 million, $215 million, and $233 million for 2019, 2018, and 2017, respectively.

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Included within these revenues were affiliate PPAs accounted for as operating leases, which totaled $116 million, $65 million, and $81 million for 2019, 2018, and 2017, respectively. See Note 9 for additional information.

SCS (as agent for Alabama Power, Georgia Power, and Southern Power) and Southern Company Gas have long-term interstate natural gas transportation agreements with SNG. The interstate transportation service provided to Alabama Power, Georgia Power, Southern Power, and Southern Company Gas by SNG pursuant to these agreements is governed by the terms and conditions of SNG's natural gas tariff and is subject to FERC regulation. See Note 7 under "Southern Company Gas – Equity Method Investments – SNG" for additional information. Transportation costs under these agreements in 2019, 2018, and 2017 were as follows:

	Alabama Power			Georgia Power			Southern Power			Southern Company Gas
	(in millions)
2019	$	17		$	99		$	28		$	31
2018	8			101			25			32
2017	9			102			25			32

In November 2018, SNG purchased the natural gas lateral pipeline serving Plant McDonough Units 4 through 6 from Georgia Power at net book value, as approved by the Georgia PSC. In January 2020, SNG paid Georgia Power $142 million, which included $71 million contributed to SNG by Southern Company Gas for its proportionate share. During the interim period, Georgia Power received a discounted shipping rate to reflect the deferred consideration and SNG constructed an extension to the pipeline.

SCS, as agent for the traditional electric operating companies and Southern Power, has agreements with certain subsidiaries of Southern Company Gas to purchase natural gas. Natural gas purchases made under these agreements were immaterial for Alabama Power and Mississippi Power and as follows for Georgia Power and Southern Power in 2019, 2018, and 2017:

	Georgia Power			Southern Power
	(in millions)
2019	$	4		$	64
2018	21			119
2017	22			119

Alabama Power and Mississippi Power jointly own Plant Greene County. The companies have an agreement under which Alabama Power operates Plant Greene County and Mississippi Power reimburses Alabama Power for its proportionate share of non-fuel operations and maintenance expenses, which totaled $9 million, $8 million, and $9 million in 2019, 2018, and 2017, respectively. See Note 5 under "Joint Ownership Agreements" for additional information.

Alabama Power has an agreement with Gulf Power under which Alabama Power made transmission system upgrades to ensure firm delivery of energy under a non-affiliate PPA from a combined cycle plant located in Autauga County, Alabama. Under a related tariff, Alabama Power received $11 million in each of 2018 and 2017. See Note 15 under "Southern Company" for information regarding the sale of Gulf Power.

Alabama Power has agreements with PowerSecure for services related to utility infrastructure construction, distributed energy, and energy efficiency projects. Costs for these services amounted to approximately $7 million, $24 million, and $11 million in 2019, 2018, and 2017, respectively.

See Note 7 under "SEGCO" for information regarding Alabama Power's and Georgia Power's equity method investment in SEGCO and related affiliate purchased power costs, as well as Alabama Power's gas pipeline ownership agreement with SEGCO.

Georgia Power has a joint ownership agreement with Gulf Power under which Gulf Power owns a 25% portion of Plant Scherer Unit 3. Under this agreement, Georgia Power operates Plant Scherer Unit 3 and Gulf Power reimburses Georgia Power for its 25% proportionate share of the related non-fuel expenses, which were $8 million and $11 million in 2018 and 2017, respectively. See Note 5 under "Joint Ownership Agreements" and Note 15 under "Southern Company" for additional information.

Mississippi Power has an agreement with Gulf Power under which Gulf Power owns a portion of Plant Daniel. Mississippi Power operates Plant Daniel and Gulf Power reimburses Mississippi Power for its proportionate share of all associated non-fuel

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operations and maintenance expenses, which totaled $31 million in each of 2018 and 2017. See Note 5 under "Joint Ownership Agreements" and Note 15 under "Southern Company" for additional information.

Southern Power has several agreements with SCS for transmission services. Transmission services purchased by Southern Power from SCS totaled $15 million, $12 million, and $13 million for 2019, 2018, and 2017, respectively, and were charged to other operations and maintenance expenses in Southern Power's consolidated statements of income. All charges were billed to Southern Power based on the Southern Company Open Access Transmission Tariff as filed with the FERC.

The traditional electric operating companies and Southern Power may jointly enter into various types of wholesale energy, natural gas, and certain other contracts, either directly or through SCS as agent. Each participating company may be jointly and severally liable for the obligations incurred under these agreements. See Note 14 under "Contingent Features" for additional information. Southern Power and the traditional electric operating companies generally settle amounts related to the above transactions on a monthly basis in the month following the performance of such services or the purchase or sale of electricity. See "Revenues – Southern Power" herein for additional information.

The traditional electric operating companies, Southern Power, and Southern Company Gas provide incidental services to and receive such services from other Southern Company subsidiaries which are generally minor in duration and amount. Except as described herein, the traditional electric operating companies, Southern Power, and Southern Company Gas neither provided nor received any material services to or from affiliates in any year presented.

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.

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 AOCI 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 2 for additional information including details of regulatory assets and liabilities reflected in the balance sheets for Southern Company, the traditional electric operating companies, and Southern Company Gas.

Revenues

The Registrants generate revenues from a variety of sources which are accounted for under various revenue accounting guidance, including ASC 606, lease, derivative, and regulatory accounting. Other than the timing of recognition of guaranteed and fixed billing arrangements at Southern Company Gas, the adoption of ASC 606 in 2018 had no impact on the timing or amount of revenue recognized under previous guidance. See Note 4 for information regarding the Registrants' adoption of ASC 606 and related disclosures.

Traditional Electric Operating Companies

The majority of the revenues of the traditional electric operating companies are generated from contracts with retail electric customers. Retail revenues recognized under ASC 606 are consistent with prior revenue recognition policies. These revenues, generated from the integrated service to deliver electricity when and if called upon by the customer, are recognized as a single performance obligation satisfied over time, at a tariff rate, and as electricity is delivered to the customer during the month. Unbilled revenues related to retail sales are accrued at the end of each fiscal period. Retail rates may include provisions to adjust billings for fluctuations in fuel 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 from or returned to customers, respectively, through adjustments to the billing factors. See Note 2 for additional information regarding regulatory matters of the traditional electric operating companies.

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 generally recognized as services are provided. The accounting for these revenues under ASC 606 is consistent with prior revenue recognition policies. The contracts for capacity and energy in a wholesale PPA have multiple performance obligations where the contract's total transaction price is allocated to each performance obligation based on the standalone selling price. The standalone selling price is primarily determined by the price

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charged to customers for the specific goods or services transferred with the performance obligations. Generally, the traditional electric operating companies recognize revenue as the performance obligations are satisfied over time as electricity is delivered to the customer or as generation capacity is available to the customer.

For both retail and wholesale revenues, the traditional electric operating companies generally have a right to consideration in an amount that corresponds directly with the value to the customer of the entity's performance completed to date and may recognize revenue in the amount to which the entity has a right to invoice and has elected to recognize revenue for its sales of electricity and capacity using the invoice practical expedient. In addition, payment for goods and services rendered is typically due in the subsequent month following satisfaction of the Registrants' performance obligation.

Southern Power

Southern Power sells capacity and energy at rates specified under contractual terms in long-term PPAs. These PPAs are accounted for as operating leases, non-derivatives, or normal sale derivatives. Capacity revenues from PPAs classified as operating leases are recognized on a straight-line basis over the term of the agreement. Energy revenues are recognized in the period the energy is delivered.

Southern Power's non-lease contracts commonly include capacity and energy which are considered separate performance obligations. In these contracts, the total transaction price is allocated to each performance obligation based on the standalone selling price. The standalone selling price is primarily determined by the price charged to customers for the specific goods or services transferred with the performance obligations. Generally, Southern Power recognizes revenue as the performance obligations are satisfied over time, as electricity is delivered to the customer or as generation capacity is made available to the customer.

Southern Power generally has a right to consideration in an amount that corresponds directly with the value to the customer of the entity's performance completed to date and may recognize revenue in the amount to which the entity has a right to invoice. In addition, payment for goods and services rendered is typically due in the subsequent month following satisfaction of Southern Power's performance obligation.

When multiple contracts exist with the same counterparty, the revenues from each contract are accounted for as separate arrangements.

Southern Power may also enter into contracts to sell short-term capacity in the wholesale electricity markets. These sales are generally classified as mark-to-market derivatives and net unrealized gains and losses on such contracts are recorded in wholesale revenues. See Note 14 and "Financial Instruments" herein for additional information.

Southern Company Gas

Gas Distribution Operations

Southern Company Gas records revenues when goods or services are provided to customers. Those revenues are based on rates approved by the state regulatory agencies of the natural gas distribution utilities. The natural gas market for Atlanta Gas Light was deregulated in 1997. Accordingly, Marketers, rather than a traditional utility, sell natural gas to end-use customers in Georgia and handle customer billing functions. As required by the Georgia PSC, Atlanta Gas Light bills Marketers in equal monthly installments for each residential, commercial, and industrial end-use customer's distribution costs as well as for capacity costs utilizing a seasonal rate design for the calculation of each residential end-use customer's annual straight-fixed-variable charge, which reflects the historic volumetric usage pattern for the entire residential class.

The majority of the revenues of Southern Company Gas are generated from contracts with natural gas distribution customers. Revenues from this integrated service to deliver gas when and if called upon by the customer is recognized as a single performance obligation satisfied over time and is recognized at a tariff rate as gas is delivered to the customer during the month.

The standalone selling price is primarily determined by the price charged to customers for the specific goods or services transferred with the performance obligations. Generally, Southern Company Gas recognizes revenue as the performance obligations are satisfied over time as natural gas is delivered to the customer. The performance obligations related to wholesale gas services are satisfied, and revenue is recognized, at a point in time when natural gas is delivered to the customer.

Southern Company Gas generally has a right to consideration in an amount that corresponds directly with the value to the customer of the entity's performance completed to date and may recognize revenue in the amount to which the entity has a right to invoice and has elected to recognize revenue for its sales of natural gas using the invoice practical expedient. In addition, payment for goods and services rendered is typically due in the subsequent month following satisfaction of Southern Company Gas' performance obligation.

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With the exception of Atlanta Gas Light, the natural gas distribution utilities have rate structures that include volumetric rate designs that allow the opportunity to recover certain costs based on gas usage. Revenues from sales and transportation services are recognized in the same period in which the related volumes are delivered to customers. Revenues from residential and certain commercial and industrial customers are recognized on the basis of scheduled meter readings. Additionally, unbilled revenues are recognized for estimated deliveries of gas not yet billed to these customers, from the last bill date to the end of the accounting period. For other commercial and industrial customers and for all wholesale customers, revenues are based on actual deliveries through the end of the period.

The tariffs for several of the natural gas distribution utilities include provisions which allow for the recognition of certain revenues prior to the time such revenues are billed to customers. These provisions are referred to as alternative revenue programs and provide for the recognition of certain revenues prior to billing, as long as the amounts recognized will be collected from customers within 24 months of recognition. These programs are as follows:

•	Weather normalization adjustments – reduce customer bills when winter weather is colder than normal and increase customer bills when weather is warmer than normal and are included in the tariffs for Virginia Natural Gas, Chattanooga Gas, and, prior to its sale, Elizabethtown Gas;

•	Revenue normalization mechanisms – mitigate the impact of conservation and declining customer usage and are contained in the tariffs for Virginia Natural Gas, Chattanooga Gas, Nicor Gas (effective November 1, 2019), and, prior to its sale, Elkton Gas; and

•

Revenue true-up adjustment – included within the provisions of the GRAM program in which Atlanta Gas Light participates as a short-term alternative to formal rate case filings, the revenue true-up feature provides for a monthly positive (or negative) adjustment to record revenue in the amount of any variance to budgeted revenues, which are submitted and approved annually as a requirement of GRAM. Such adjustments are reflected in customer billings in a subsequent program year.

Wholesale Gas Services

Southern Company Gas nets revenues from energy and risk management activities with the associated costs. Profits from sales between segments are eliminated and are recognized as goods or services sold to end-use customers. Southern Company Gas records transactions that qualify as derivatives at fair value with changes in fair value recognized in earnings in the period of change and characterized as unrealized gains or losses. Gains and losses on derivatives held for energy trading purposes are presented on a net basis in revenue.

Gas Marketing Services

Southern Company Gas recognizes revenues from natural gas sales and transportation services in the same period in which the related volumes are delivered to customers and recognizes sales revenues from residential and certain commercial and industrial customers on the basis of scheduled meter readings. Southern Company Gas also recognizes unbilled revenues for estimated deliveries of gas not yet billed to these customers from the most recent meter reading date to the end of the accounting period. For other commercial and industrial customers and for all wholesale customers, revenues are based on actual deliveries during the period.

Southern Company Gas recognizes revenues on 12-month utility-bill management contracts as the lesser of cumulative earned or cumulative billed amounts. Prior to the sale of Pivotal Home Solutions in 2018, revenues for warranty and repair contracts were recognized on a straight-line basis over the contract term while revenues for maintenance services were recognized at the time such services were performed. See Note 15 under "Southern Company Gas – Sale of Pivotal Home Solutions" for additional information.

Concentration of Revenue

Southern Company, Alabama Power, Georgia Power, Mississippi Power (with the exception of its cost-based MRA electric tariffs described below), and Southern Company Gas each have a diversified base of customers and no single customer or industry comprises 10% or more of each company's revenues.

Mississippi Power serves long-term contracts with rural electric cooperative associations and municipalities located in southeastern Mississippi under cost-based MRA electric tariffs, which are subject to regulation by the FERC. The contracts with these wholesale customers represented 15.7% of Mississippi Power's total operating revenues in 2019 and are generally subject to 10-year rolling cancellation notices. Historically, these wholesale customers have acted as a group and any changes in contractual relationships for one customer are likely to be followed by the other wholesale customers.

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Significant portions of Southern Power's revenues have been derived from certain customers pursuant to PPAs. The following table shows the percentage of total revenues for Southern Power's top three customers for each of the years presented:

	2019		2018		2017
Georgia Power	9.0	%	9.8	%	11.3	%
Duke Energy Corporation	N/A		6.8	%	6.7	%
Southern California Edison	6.8	%	6.2	%	N/A
Morgan Stanley Capital Group	4.9	%	N/A		4.5	%

On January 29, 2019, Pacific Gas & Electric Company (PG&E) filed petitions to reorganize under Chapter 11 of the U.S. Bankruptcy Code. Southern Power, together with its noncontrolling partners, owns four solar facilities where PG&E is the energy off-taker for approximately 207 MWs of capacity under long-term PPAs. PG&E is also the transmission provider for these four facilities and two of Southern Power's other solar facilities. At December 31, 2019, Southern Power had outstanding accounts receivables due from PG&E of $2 million related to the PPAs and $33 million related to the transmission interconnections (of which $27 million is classified in receivables – other and $6 million is classified in other deferred charges and assets). Subsequent to December 31, 2019, Southern Power received $15 million in accordance with a November 2019 bankruptcy court order granting payment of transmission interconnections for amounts due and owing. Southern Power continues to evaluate the recoverability of its investments in these solar facilities under various scenarios, including selling the related energy into the competitive markets, and has concluded that these solar facilities are not impaired. PG&E has continued to perform under the terms of the PPAs. Southern Power does not expect a material impact to its financial statements if, as a result of the bankruptcy proceedings, PG&E does not perform in accordance with the PPAs or the terms of the PPAs are renegotiated; however, the ultimate outcome of this matter cannot be determined at this time.

Fuel Costs

Fuel costs for the traditional electric operating companies and Southern Power 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. For Alabama Power and Georgia Power, fuel expense also includes the amortization of the cost of nuclear fuel. For the traditional electric operating companies, fuel costs also include gains and/or losses from fuel-hedging programs as approved by their respective state PSCs.

Cost of Natural Gas

Excluding Atlanta Gas Light, which does not sell natural gas to end-use customers, Southern Company Gas charges its utility customers for natural gas consumed using natural gas cost recovery mechanisms set by the applicable state regulatory agencies. Under these mechanisms, all prudently-incurred natural gas costs are passed through to customers without markup, subject to regulatory review. Southern Company Gas defers or accrues the difference between the actual cost of natural gas and the amount of commodity revenue earned in a given period such that no operating income is recognized related to these costs. The deferred or accrued amount is either billed or refunded to customers prospectively through adjustments to the commodity rate. Deferred and accrued natural gas costs are included in the balance sheets as regulatory assets and regulatory liabilities, respectively.

Southern Company Gas' gas marketing services' customers are charged for actual or estimated natural gas consumed. Within cost of natural gas, Southern Company Gas also includes costs of lost and unaccounted for gas, adjustments to reduce the value of inventories to market value, and gains and losses associated with certain derivatives.

Income Taxes

The Registrants use the liability method of accounting for deferred income taxes and provide deferred income taxes for all significant income tax temporary differences. In accordance with regulatory requirements, deferred federal ITCs for the traditional electric operating companies are deferred and amortized over the average life of the related property, with such amortization normally applied as a credit to reduce depreciation and amortization in the statements of income. Southern Power's and the natural gas distribution utilities' deferred federal ITCs, as well as certain state ITCs for Nicor Gas, are deferred and amortized to income tax expense over the life of the respective asset.

Under current tax law, certain projects at Southern Power related to the construction of renewable facilities are eligible for federal ITCs. Southern Power estimates eligible costs which, as they relate to acquisitions, may not be finalized until the allocation of the purchase price to assets has been finalized. Southern Power applies the deferred method to ITCs. Under the deferred method, the ITCs are recorded as a deferred credit and amortized to income tax expense over the life of the respective asset. 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

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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. State ITCs are recognized as an income tax benefit in the period in which the credits are generated. In addition, certain projects are eligible for federal and state PTCs, which are recognized as an income tax benefit 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 2019 and will be carried forward and utilized in future years. In addition, Southern Company is expected to have various state net operating loss (NOL) carryforwards for certain of its subsidiaries, which would result in income tax benefits in the future, if utilized. See Note 10 under "Current and Deferred Income Taxes – Tax Credit Carryforwards" and " – Net Operating Loss Carryforwards" for additional information.

The Registrants recognize tax positions that are "more likely than not" of being sustained upon examination by the appropriate taxing authorities. See Note 10 under "Unrecognized Tax Benefits" for additional information.

Other Taxes

Taxes imposed on and collected from customers on behalf of governmental agencies are presented net on the Registrants' statements of income and are excluded from the transaction price in determining the revenue related to contracts with a customer accounted for under ASC 606.

Southern Company Gas is taxed on its gas revenues by various governmental authorities, but is allowed to recover these taxes from its customers. Revenue taxes imposed on the natural gas distribution utilities are recorded at the amount charged to customers, which may include a small administrative fee, as operating revenues, and the related taxes imposed on Southern Company Gas are recorded as operating expenses on the statements of income. Revenue taxes included in operating expenses were $114 million, $111 million, and $98 million in 2019, 2018, and 2017, respectively.

Allowance for Funds Used During Construction and Interest Capitalized

The traditional electric operating companies and the natural gas distribution utilities, with the exception of Elizabethtown Gas and Elkton Gas prior to their sales, 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 asset through a higher rate base and higher depreciation. The equity component of AFUDC is not taxable.

Interest related to financing the construction of new facilities at Southern Power and new facilities not included in the traditional electric operating companies' and Southern Company Gas' regulated rates is capitalized in accordance with standard interest capitalization requirements.

Total AFUDC and interest capitalized for the Registrants in 2019, 2018, and 2017 was as follows:

	Southern Company			Alabama Power			Georgia Power(*)			Mississippi Power			Southern Power			Southern Company Gas
	(in millions)
2019	$	202		$	71		$	103		$	—		$	15		$	13
2018	210			84			94			—			17			14
2017	249			54			63			72			11			19

(*)	See Note 2 under "Georgia Power – Nuclear Construction" for information on the inclusion of a portion of construction costs related to Plant Vogtle Units 3 and 4 in Georgia Power's rate base.

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The average AFUDC composite rates for 2019, 2018, and 2017 for the traditional electric operating companies and the natural gas distribution utilities were as follows:

	2019		2018		2017
Alabama Power	8.4	%	8.3	%	8.3	%
Georgia Power(*)	6.9	%	7.3	%	5.6	%
Mississippi Power	7.3	%	3.3	%	6.7	%
Southern Company Gas:
Atlanta Gas Light	7.8	%	7.9	%	8.1	%
Chattanooga Gas	7.1	%	7.4	%	7.4	%
Nicor Gas	2.3	%	2.1	%	1.2	%

(*)	Excludes AFUDC related to the construction of Plant Vogtle Units 3 and 4. See Note 2 under "Georgia Power – Nuclear Construction" for additional information.

Impairment of Long-Lived Assets

The Registrants evaluate long-lived assets and finite-lived intangible 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, a sales transaction price that is less than the asset group's carrying value, or an estimate of undiscounted future cash flows attributable to the asset group, 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 "Other Matters – Southern Company" and " – Southern Company Gas" and Note 15 under "Southern Company Gas – Proposed Sale of Pivotal LNG and Atlantic Coast Pipeline" for information regarding impairment charges recorded in 2019 and Note 15 under "Southern Power" for information regarding impairment charges recorded at Southern Power in 2018. Also see "Revenues" herein for additional information.

Goodwill and Other Intangible Assets and Liabilities

Southern Power's intangible assets consist primarily of certain PPAs acquired, which are amortized over the term of the respective PPA. Southern Company Gas' goodwill and other intangible assets and liabilities primarily relate to its 2016 acquisition by Southern Company. In addition to these items, Southern Company's goodwill and other intangible assets also relate to its 2016 acquisition of PowerSecure.

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, as discussed below. Southern Company and Southern Company Gas each evaluated its goodwill in the fourth quarter 2019 and determined no additional impairment was required.

A goodwill impairment charge of $32 million was recorded in the second quarter 2019 in contemplation of the July 22, 2019 sale of PowerSecure's utility infrastructure services business. In the third quarter 2019, impairment charges of $2 million and $3 million were recorded to goodwill and other intangible assets, net, respectively, in contemplation of the December 31, 2019 sale of PowerSecure's lighting business. See Note 15 under "Southern Company" for additional information.

At December 31, 2019 and 2018, goodwill was as follows:

	At December 31, 2019			At December 31, 2018
	(in millions)
Southern Company	$	5,280		$	5,315
Southern Company Gas:
Gas distribution operations	$	4,034		$	4,034
Gas marketing services	981			981
Southern Company Gas total	$	5,015		$	5,015

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At December 31, 2019 and 2018, other intangible assets were as follows:

	At December 31, 2019										At December 31, 2018
	Gross Carrying Amount			Accumulated Amortization			Other Intangible Assets, Net				Gross Carrying Amount			Accumulated Amortization			Other Intangible Assets, Net
	(in millions)										(in millions)
Southern Company
Other intangible assets subject to amortization:
Customer relationships(a)	$	212		$	(116	)	$	96			$	223		$	(94	)	$	129
Trade names(a)	64			(25		)	39				70			(21		)	49
Storage and transportation contracts	64			(62		)	2				64			(54		)	10
PPA fair value adjustments(b)	390			(69		)	321				405			(61		)	344
Other	11			(8		)	3				11			(5		)	6
Total other intangible assets subject to amortization	$	741		$	(280	)	$	461			$	773		$	(235	)	$	538
Other intangible assets not subject to amortization:
Federal Communications Commission licenses	75			—			75				75			—			75
Total other intangible assets	$	816		$	(280	)	$	536			$	848		$	(235	)	$	613
Southern Power
Other intangible assets subject to amortization:
PPA fair value adjustments(b)	$	390		$	(69	)	$	321			$	405		$	(61	)	$	344
Southern Company Gas
Other intangible assets subject to amortization:
Gas marketing services
Customer relationships	$	156		$	(104	)	$	52			$	156		$	(84	)	$	72
Trade names	26			(10		)	16				26			(7		)	19
Wholesale gas services
Storage and transportation contracts	64			(62		)	2				64			(54		)	10
Total other intangible assets subject to amortization	$	246		$	(176	)	$	70			$	246		$	(145	)	$	101

(a)	The decrease in the gross carrying amount during 2019 primarily reflects the sales of two PowerSecure business units. See Note 15 for additional information.

(b)	The decrease in the gross carrying amount during 2019 reflects the sale of Plant Nacogdoches, partially offset by additional PPA fair value adjustments related to the acquisition of DSGP. See Note 15 under "Southern Power" for additional information.

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Amortization associated with other intangible assets in 2019, 2018, and 2017 was as follows:

	2019			2018			2017
	(in millions)
Southern Company(a)	$	61		$	89		$	124
Southern Power(b)	19			25			25
Southern Company Gas:
Gas marketing services	$	23		$	32		$	54
Wholesale gas services(b)	8			20			32
Southern Company Gas total	$	31		$	52		$	86

(a)	Includes $27 million, $45 million, and $57 million in 2019, 2018, and 2017, respectively, recorded as a reduction to operating revenues.

(b)	Recorded as a reduction to operating revenues.

At December 31, 2019, the estimated amortization associated with other intangible assets for the next five years is as follows:

	2020			2021			2022			2023			2024
	(in millions)
Southern Company(*)	$	48		$	42		$	38		$	37		$	35
Southern Power(*)	20			20			20			20			20
Southern Company Gas	19			13			10			9			7

(*)	Excludes amounts related to held for sale assets. See Note 15 under "Southern Power – Sales of Natural Gas and Biomass Plants" for additional information.

Intangible liabilities of $91 million recorded under acquisition accounting for transportation contracts at Southern Company Gas were fully amortized as of December 31, 2019.

Acquisition Accounting

At the time of an acquisition, management will assess whether acquired assets and activities meet the definition of a business. For acquisitions that meet the definition of a business, operating results from the date of acquisition are included in the acquiring entity's financial statements. The purchase price, including any contingent consideration, is allocated based on the fair value of the identifiable assets acquired and liabilities assumed (including any intangible assets). Assets acquired that do not meet the definition of a business are accounted for as an asset acquisition. The purchase price of each asset acquisition is allocated based on the relative fair value of assets acquired.

Determining the fair value of assets acquired and liabilities assumed requires management judgment and management may engage independent valuation experts to assist in this process. Fair values are determined by using market participant assumptions and typically include the timing and amounts of future cash flows, incurred construction costs, the nature of acquired contracts, discount rates, power market prices, and expected asset lives. Any due diligence or transition costs incurred for potential or successful acquisitions are expensed as incurred.

Historically, contingent consideration primarily relates to fixed amounts due to the seller once an acquired construction project is placed in service. For contingent consideration with variable payments, management fair values the arrangement with any changes recorded in the statements of income. See Note 13 for additional fair value information.

Development Costs

For Southern Power, development costs are capitalized once a project is probable of completion, primarily based on a review of its economics and operational feasibility, as well as the status of power off-take agreements and regulatory approvals, if applicable. Southern Power's capitalized development costs are included in CWIP on the balance sheets. All of Southern Power's development costs incurred prior to the determination that a project is probable of completion are expensed as incurred and included in other operations and maintenance expense in the statements of income. If it is determined that a project is no longer probable of completion, any of Southern Power's capitalized development costs are expensed and included in other operations and maintenance expense in the statements of income.

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Long-Term Service Agreements

The traditional electric operating companies and Southern Power have entered into LTSAs for the purpose of securing maintenance support for certain of their generating facilities. The LTSAs cover all planned inspections on the covered equipment, which generally includes the cost of all labor and materials. The LTSAs also obligate the counterparties to cover the costs of unplanned maintenance on the covered equipment subject to limits and scope specified in each contract.

Payments made under the LTSAs for the performance of any planned inspections or unplanned capital maintenance are recorded in the statements of cash flows as investing activities. Receipts of major parts into materials and supplies inventory prior to planned inspections are treated as noncash transactions in the statements of cash flows. Any payments made prior to the work being performed are recorded as prepayments in other current assets and noncurrent assets on the balance sheets. At the time work is performed, an appropriate amount is accrued for future payments or transferred from the prepayment and recorded as property, plant, and equipment or expensed.

Transmission Receivables/Prepayments

As a result of Southern Power's acquisition and construction of generating facilities, Southern Power has transmission receivables and/or prepayments representing the portion of interconnection network and transmission upgrades that will be reimbursed to Southern Power. Upon completion of the related project, transmission costs are generally reimbursed by the interconnection provider within a five-year period and the receivable/prepayments are reduced as payments or services are received.

Cash and Cash Equivalents

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.

Restricted Cash

At December 31, 2019 and 2018, Southern Company Gas had restricted cash held as collateral for worker's compensation, life insurance, and long-term disability insurance. At December 31, 2018, Georgia Power had restricted cash related to the redemption of certain pollution control revenue bonds in January 2019. See Note 8 under "Long-term Debt" for additional information.

The following tables provide a reconciliation of cash, cash equivalents, and restricted cash reported within the balance sheets that total to the amounts shown in the statements of cash flows for the Registrants that had restricted cash at December 31, 2019 and/or 2018:

	Southern Company			Southern Company Gas
	(in millions)
At December 31, 2019
Cash and cash equivalents	$	1,975		$	46
Restricted cash:
Other accounts and notes receivable	3			3
Total cash, cash equivalents, and restricted cash	$	1,978		$	49

	Southern Company			Georgia Power			Southern Company Gas
	(in millions)
At December 31, 2018
Cash and cash equivalents	$	1,396		$	4		$	64
Cash and cash equivalents classified as assets held for sale	9			—			—
Restricted cash:
Restricted cash	—			108			—
Other accounts and notes receivable	114			—			6
Total cash, cash equivalents, and restricted cash	$	1,519		$	112		$	70

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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, for Mississippi Power, the cost of uninsured damages to its generation facilities and other property. Alabama Power and Mississippi Power also have authority based on orders from their state PSCs to accrue certain additional amounts as circumstances warrant. Alabama Power recorded an additional accrual of $84 million in 2019 and no such additional accruals in 2018 or 2017. There were no such additional accruals for Mississippi Power in any year presented. In accordance with their respective state PSC orders, the traditional electric operating companies accrued the following amounts related to storm damage reserves in 2019, 2018, and 2017:

	Southern    Company(a)(b)			Alabama Power(b)			Georgia Power			Mississippi Power
	(in millions)
2019	$	170		$	139		$	30		$	1
2018	74			16			30			1
2017	41			4			30			3

(a)	Includes accruals at Gulf Power of $26.9 million in 2018 and $3.5 million in 2017. See Note 15 under "Southern Company" for information regarding the sale of Gulf Power.

(b)	Includes $39 million applied in 2019 to Alabama Power's NDR from its remaining excess deferred income tax regulatory liability balance in accordance with an Alabama PSC order.

See Note 2 under "Alabama Power – Rate NDR," "Georgia Power – Storm Damage Recovery," and "Mississippi Power – System Restoration Rider" for additional information regarding each company's storm damage reserve.

Leveraged Leases

A subsidiary of Southern Holdings 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. See Note 3 under "Other Matters – Southern Company" for information regarding an impairment charge associated with one of the leveraged leases.

On December 30, 2019, Southern Company completed the sale of one of its leveraged lease investments for approximately $20 million.

Southern Company's net investment in domestic and international leveraged leases consists of the following at December 31:

	2019				2018
	(in millions)
Net rentals receivable	$	1,410			$	1,563
Unearned income	(622		)		(765		)
Investment in leveraged leases	788				798
Deferred taxes from leveraged leases	(238		)		(255		)
Net investment in leveraged leases	$	550			$	543

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A summary of the components of income from the leveraged leases follows:

	2019				2018				2017
	(in millions)
Pretax leveraged lease income	$	11			$	25			$	25
Net impact of Tax Reform Legislation	—				—				48
Income tax expense	—				(6		)		(9		)
Net leveraged lease income	$	11			$	19			$	64

Materials and Supplies

Materials and supplies for the traditional electric operating companies generally includes the average cost of transmission, distribution, and generating plant materials. Materials and supplies for Southern Company Gas generally includes propane gas inventory, fleet fuel, and other materials and supplies. Materials and supplies for Southern Power generally includes the average cost of generating plant materials.

Materials are recorded to inventory when purchased and then expensed or capitalized to property, plant, and equipment, as appropriate, at weighted average cost when installed. In addition, certain major parts are recorded as inventory when acquired and then capitalized at cost when installed to property, plant, and equipment.

Fuel Inventory

Fuel inventory for the traditional electric operating companies includes the average cost of coal, natural gas, oil, transportation, and emissions allowances. Fuel inventory for Southern Power, which is included in other current assets, includes the average cost of oil, natural gas, biomass, and emissions allowances. Fuel is recorded to inventory when purchased and then expensed, at weighted average cost, as used. Emissions allowances granted by the EPA are included in inventory at zero cost. The traditional electric operating companies recover fuel expense through fuel cost recovery rates approved by each state PSC or, for wholesale rates, the FERC.

Natural Gas for Sale

With the exception of Nicor Gas, the natural gas distribution utilities record natural gas inventories on a WACOG basis. In Georgia's deregulated, competitive environment, Marketers sell natural gas to firm end-use customers at market-based prices. On a monthly basis, Atlanta Gas Light assigns to Marketers the majority of the pipeline storage services that it has under contract, along with a corresponding amount of inventory. Atlanta Gas Light retains and manages a portion of its pipeline storage assets and related natural gas inventories for system balancing and to serve system demand.

Nicor Gas' natural gas inventory is carried at cost on a 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 or Southern Company Gas' net income. At December 31, 2019, the Nicor Gas LIFO inventory balance was $161 million. Based on the average cost of gas purchased in December 2019, the estimated replacement cost of Nicor Gas' inventory at December 31, 2019 was $214 million.

Southern Company Gas' gas marketing services, wholesale gas services, and all other segments record inventory at LOCOM, with cost determined on a WACOG basis. For these segments, Southern Company Gas evaluates the weighted average cost of its natural gas inventories against market prices to determine whether any declines in market prices below the WACOG are other than temporary. For any declines considered to be other than temporary, Southern Company Gas recorded LOCOM adjustments to cost of natural gas to reduce the value of its natural gas inventories to market value. LOCOM adjustments for wholesale gas services were $21 million and $10 million during 2019 and 2018, respectively, and immaterial for 2017.

Energy Marketing Receivables and Payables

Southern Company Gas' wholesale gas services provides services to retail gas marketers, wholesale gas marketers, utility companies, and industrial customers. These counterparties utilize netting agreements that enable wholesale gas services to net receivables and payables by counterparty upon settlement. Southern Company Gas' wholesale gas services also nets across product lines and against cash collateral, provided the netting and cash collateral agreements include such provisions. While the

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amounts due from, or owed to, wholesale gas services' counterparties are settled net, they are recorded on a gross basis in the balance sheets as energy marketing receivables and energy marketing payables.

Southern Company Gas' wholesale gas services has trade and credit contracts that contain minimum credit rating requirements. These credit rating requirements typically give counterparties the right to suspend or terminate credit if Southern Company Gas' credit ratings are downgraded to non-investment grade status. Under such circumstances, Southern Company Gas' wholesale gas services would need to post collateral to continue transacting business with some of its counterparties. As of December 31, 2019 and 2018, the required collateral in the event of a credit rating downgrade was $11 million and $30 million, respectively.

Credit policies were established to determine and monitor the creditworthiness of counterparties, including requirements to post collateral or other credit security, as well as the quality of pledged collateral. Collateral or credit security is most often in the form of cash or letters of credit from an investment-grade financial institution, but may also include cash or U.S. government securities held by a trustee. When Southern Company Gas' wholesale gas services is engaged in more than one outstanding derivative transaction with the same counterparty and it also has a legally enforceable netting agreement with that counterparty, the "net" mark-to-market exposure represents the netting of the positive and negative exposures with that counterparty combined with a reasonable measure of Southern Company Gas' credit risk. Southern Company Gas' wholesale gas services also uses other netting agreements with certain counterparties with whom it conducts significant transactions.

See "Concentration of Credit Risk" herein for additional information.

Provision for Uncollectible Accounts

The customers of the traditional electric operating companies and the natural gas distribution utilities are billed monthly. For the majority of receivables, a provision for uncollectible accounts is established based on historical collection experience and other factors. For the remaining receivables, if the company is aware of a specific customer's inability to pay, a provision for uncollectible accounts is recorded to reduce the receivable balance to the amount reasonably expected to be collected. If circumstances change, the estimate of the recoverability of accounts receivable could change as well. Circumstances that could affect this estimate include, but are not limited to, customer credit issues, customer deposits, and general economic conditions. Customers' accounts are written off once they are deemed to be uncollectible. For all periods presented, uncollectible accounts averaged less than 1% of revenues for each Registrant.

Credit risk exposure at Nicor Gas is mitigated by a bad debt rider approved by the Illinois Commission. The bad debt rider provides for the recovery from (or refund to) customers of the difference between Nicor Gas' actual bad debt experience on an annual basis and the benchmark bad debt expense used to establish its base rates for the respective year.

Concentration of Credit Risk

Southern Company Gas' wholesale gas services business has a concentration of credit risk for services it provides to its counterparties. This credit risk is generally concentrated in 20 of its counterparties and is measured by 30-day receivable exposure plus forward exposure. Counterparty credit risk is evaluated using a S&P equivalent credit rating, which is determined by a process of converting the lower of the S&P or Moody's rating to an internal rating ranging from 9 to 1, with 9 being equivalent to AAA/Aaa by S&P and Moody's, respectively, and 1 being equivalent to D/Default by S&P and Moody's, respectively. A counterparty that does not have an external rating is assigned an internal rating based on the strength of its financial ratios. As of December 31, 2019, the top 20 counterparties represented 59%, or $218 million, of the total counterparty exposure and had a weighted average S&P equivalent rating of A-.

Concentration of credit risk occurs at Atlanta Gas Light for amounts billed for services and other costs to its customers, which consist of 16 Marketers in Georgia (including SouthStar). The credit risk exposure to Marketers varies seasonally, with the lowest exposure in the non-peak summer months and the highest exposure in the peak winter months. Marketers are responsible for the retail sale of natural gas to end-use customers in Georgia. The functions of the retail sale of gas include the purchase and sale of natural gas, customer service, billings, and collections. The provisions of Atlanta Gas Light's tariff allow Atlanta Gas Light to obtain credit security support in an amount equal to a minimum of two times a Marketer's highest month's estimated bill from Atlanta Gas Light.

Financial Instruments

The traditional electric operating companies and Southern Power 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. Southern Company Gas uses derivative financial instruments to limit exposure to fluctuations in natural gas prices, weather, interest rates, and commodity prices. 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

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fair value. See Note 13 for additional information regarding fair value. Substantially all of the traditional electric operating companies' and Southern Power'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 AOCI or regulatory assets and liabilities, respectively, until the hedged transactions occur. For 2017, ineffectiveness arising from cash flow hedges was recognized in net income. Upon the adoption of ASU No. 2017-12, Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities (ASU 2017-12) in 2018, ineffectiveness is no longer separately measured and recorded in earnings. 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 14 for additional information regarding derivatives.

The Registrants offset fair value amounts recognized for multiple derivative instruments executed with the same counterparty under netting arrangements. The Registrants had no outstanding collateral repayment obligations or rights to reclaim collateral arising from derivative instruments recognized at December 31, 2019.

The Registrants are exposed to potential losses related to financial instruments in the event of counterparties' nonperformance. The Registrants have established risk management policies and controls to determine and monitor the creditworthiness of counterparties in order to mitigate their exposure to counterparty credit risk.

Southern Company Gas

Southern Company Gas enters into weather derivative contracts as economic hedges of natural gas revenues in the event of warmer-than-normal weather in the Heating Season. Exchange-traded options are carried at fair value, with changes reflected in natural gas revenues. Non-exchange-traded options are accounted for using the intrinsic value method. Changes in the intrinsic value for non-exchange-traded contracts are also reflected in natural gas revenues in the statements of income.

Wholesale gas services 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 that can be received in the future, resulting in positive net natural gas revenues. NYMEX futures and OTC contracts are used to sell natural gas at that future price to substantially protect the natural gas revenues that will ultimately be realized when the stored natural gas is sold. Southern Company Gas enters into transactions to secure transportation capacity between delivery points in order to serve its customers and various markets. NYMEX futures and OTC contracts are used to capture the price differential or spread between the locations served by the capacity in order to substantially protect the natural gas revenues that will ultimately be realized when the physical flow of natural gas between delivery points occurs. These contracts generally meet the definition of derivatives and are carried at fair value on the balance sheets, with changes in fair value recorded in natural gas revenues on the statements of income in the period of change. These contracts are not designated as hedges for accounting purposes.

The purchase, transportation, storage, and sale of natural gas are accounted for on a weighted average cost or accrual basis, as appropriate, rather than on the fair value basis utilized for the derivatives used to mitigate the natural gas price risk associated with the storage and transportation portfolio. Monthly demand charges are incurred for the contracted storage and transportation capacity and payments associated with asset management agreements, and these demand charges and payments are recognized on the statements of income in the period they are incurred. This difference in accounting methods can result in volatility in reported earnings, even though the economic margin is substantially unchanged from the dates the transactions were consummated.

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 attributable to the Registrant, changes in the fair value of qualifying cash flow hedges, and reclassifications for amounts included in net income. Comprehensive income also consists of certain changes in pension and other postretirement benefit plans for Southern Company, Southern Power, and Southern Company Gas.

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AOCI (loss) balances, net of tax effects, for Southern Company, Southern Power, and Southern Company Gas were as follows:

	Qualifying Hedges				Pension and Other Postretirement Benefit Plans				Accumulated Other Comprehensive Income (Loss)
	(in millions)
Southern Company
Balance at December 31, 2018	$	(121	)		$	(82	)		$	(203	)
Current period change	(58		)		(60		)		(118		)
Balance at December 31, 2019	$	(179	)		$	(142	)		$	(321	)
Southern Power
Balance at December 31, 2018	$	36			$	(20	)		$	16
Current period change	(25		)		(17		)		(42		)
Balance at December 31, 2019	$	11			$	(37	)		$	(26	)
Southern Company Gas
Balance at December 31, 2018	$	(3	)		$	29			$	26
Current period change	(3		)		(16		)		(19		)
Balance at December 31, 2019	$	(6	)		$	13			$	7

Variable Interest Entities

The Registrants may hold ownership interests in a number of business ventures with varying ownership structures. Partnership interests and other variable interests are evaluated to determine if each entity is a VIE. The primary beneficiary of a VIE is required to consolidate the VIE when it has both the power to direct the activities of the VIE that most significantly impact the VIE's economic performance and the obligation to absorb losses or the right to receive benefits from the VIE that could potentially be significant to the VIE. See Note 7 for additional information regarding VIEs.

Alabama Power has established a wholly-owned trust to issue preferred securities. See Note 8 under "Long-term Debt" for additional information. However, Alabama Power is not considered the primary beneficiary of the trust. Therefore, the investment in the trust is reflected as other investments, and the related loan from the trust is reflected as long-term debt in Alabama Power's balance sheets.

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Southern Company

Regulatory Assets and Liabilities

Regulatory assets and (liabilities) reflected in the consolidated balance sheets of Southern Company at December 31, 2019 and 2018 relate to:

	2019				2018				Note
	(in millions)
Retiree benefit plans	$	4,423			$	3,658			(a,o)
Asset retirement obligations-asset	4,381				2,933				(b,o)
Remaining net book value of retired assets	1,275				211				(c)
Deferred income tax charges	803				799				(b,n)
Property damage reserves-asset	410				416				(d)
Environmental remediation-asset	349				366				(e,o)
Loss on reacquired debt	323				346				(f)
Under recovered regulatory clause revenues	254				407				(g)
Vacation pay	186				182				(h,o)
Long-term debt fair value adjustment	107				121				(i)
Other regulatory assets	492				581				(j)
Deferred income tax credits	(6,301		)		(6,455		)		(b,n)
Other cost of removal obligations	(2,084		)		(2,297		)		(b)
Customer refunds	(285		)		(293		)		(k)
Over recovered regulatory clause revenues	(205		)		(47		)		(g)
Property damage reserves-liability	(204		)		(76		)		(l)
Other regulatory liabilities	(86		)		(132		)		(m)
Total regulatory assets (liabilities), net	$	3,838			$	720

Note: Unless otherwise noted, the recovery and amortization periods for these regulatory assets and (liabilities) are approved by the respective PSC or regulatory agency and are as follows:

(a)	Recovered and amortized over the average remaining service period, which may range up to 15 years. See Note 11 for additional information.

(b)

AROs and other cost of removal obligations are recorded, deferred income tax assets are recovered, and deferred income tax liabilities are amortized over the related property lives, which may range up to 80 years. Asset retirement and removal liabilities will be settled and trued up following completion of the related activities. Included in the deferred income tax assets is $23 million for the retiree Medicare drug subsidy, which is being recovered and amortized through 2027.

(c)	Amortized over periods not exceeding 18 years.

(d)	Effective January 1, 2020, Georgia Power is recovering approximately $213 million annually for storm damage. See "Georgia Power – Rate Plans – 2019 ARP" and " – Storm Damage Recovery" herein for additional information.

(e)	Recovered through environmental cost recovery mechanisms when the remediation work is performed. See Note 3 for additional information.

(f)	Recovered over either the remaining life of the original issue or, if refinanced, over the remaining life of the new issue. At December 31, 2019, the remaining amortization periods do not exceed 34 years.

(g)	Recorded and recovered or amortized over periods generally not exceeding six years.

(h)	Recorded as earned by employees and recovered as paid, generally within one year.

(i)	Recovered over the remaining life of the original debt issuances at acquisition, which range up to 19 years as of December 31, 2019.

(j)	Comprised of numerous immaterial components including nuclear outage costs, fuel-hedging losses, cancelled construction projects, property tax, and other miscellaneous assets. These costs are amortized over remaining periods generally not exceeding eight years as of December 31, 2019.

(k)

At December 31, 2019 and 2018, primarily includes approximately $53 million and $109 million, respectively, at Alabama Power and $110 million and $100 million, respectively, at Georgia Power as a result of each company exceeding its allowed retail return range, as well as approximately $105 million and $55 million, respectively, pursuant to the Georgia Power Tax Reform Settlement Agreement. See "Alabama Power – Rate RSE" and "Georgia Power – Rate Plans" herein for additional information.

(l)	Amortized as related expenses are incurred. See "Alabama Power – Rate NDR" and "Mississippi Power – System Restoration Rider" herein for additional information.

(m)	Comprised of numerous components including building leases, fuel-hedging gains, and other liabilities that are recovered over remaining periods not exceeding 20 years.

(n)	As a result of the Tax Reform Legislation, these accounts include certain deferred income tax assets and liabilities not subject to normalization, including $778 million of liabilities being amortized over periods not exceeding six years as of December 31, 2019. See "Georgia Power," "Mississippi Power," and "Southern Company Gas" herein and Note 10 for additional information.

(o)	Not earning a return as offset in rate base by a corresponding asset or liability.

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Gulf Power

On January 1, 2019, Southern Company completed its sale of Gulf Power to NextEra Energy. See Note 15 under "Southern Company" for additional information.

In accordance with a Florida PSC-approved settlement agreement, Gulf Power's rates effective for the first billing cycle in July 2017 increased by approximately $54 million annually (2017 Gulf Power Rate Case Settlement Agreement), including a $62 million increase in base revenues, less an $8 million purchased power capacity cost recovery clause credit. The 2017 Gulf Power Rate Case Settlement Agreement also resulted in a $32.5 million write-down of Gulf Power's ownership of Plant Scherer Unit 3, which was recorded in the first quarter 2017.

As a continuation of the 2017 Gulf Power Rate Case Settlement Agreement, in March 2018, the Florida PSC approved a stipulation and settlement agreement addressing Gulf Power's retail revenue requirement effects of the Tax Reform Legislation (Gulf Power Tax Reform Settlement Agreement). Beginning on April 1, 2018, the Gulf Power Tax Reform Settlement Agreement resulted in annual reductions of approximately $18 million to Gulf Power's base rates and approximately $16 million to Gulf Power's environmental cost recovery rates and a one-time refund of approximately $69 million for the retail portion of unprotected (not subject to normalization) deferred tax liabilities, which was credited to customers through Gulf Power's fuel cost recovery rates over the remainder of 2018.

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Alabama Power

Regulatory Assets and Liabilities

Regulatory assets and (liabilities) reflected in the balance sheets of Alabama Power at December 31, 2019 and 2018 relate to:

	2019				2018				Note
	(in millions)
Retiree benefit plans	$	1,131			$	947			(a,o)
Asset retirement obligations	1,043				147				(b)
Deferred income tax charges	245				241				(b,c,d)
(Over) under recovered regulatory clause revenues	(72		)		176				(e)
Regulatory clauses	142				142				(f)
Vacation pay	72				71				(g,o)
Loss on reacquired debt	52				56				(h)
Nuclear outage	78				49				(i)
Remaining net book value of retired assets	649				43				(j)
Other regulatory assets	67				57				(k,l)
Deferred income tax credits	(1,960		)		(2,027		)		(b,d)
Other cost of removal obligations	(412		)		(497		)		(b)
Customer refunds	(56		)		(142		)		(m)
Natural disaster reserve	(150		)		(20		)		(n)
Other regulatory liabilities	(19		)		(12		)		(l)
Total regulatory assets (liabilities), net	$	810			$	(769	)

Note: Unless otherwise noted, the recovery and amortization periods for these regulatory assets and (liabilities) have been accepted or approved by the Alabama PSC and are as follows:

(a)	Recovered and amortized over the average remaining service period which may range up to 14 years. See Note 11 for additional information.

(b)	Asset retirement and removal assets and liabilities are recorded, deferred income tax assets are recovered, and deferred income tax credits are amortized over the related property lives, which may range up to 53 years. Asset retirement and other cost of removal assets and liabilities will be settled and trued up following completion of the related activities.

(c)	Included in the deferred income tax charges are $9 million for 2019 and $10 million for 2018 for the retiree Medicare drug subsidy, which is being recovered and amortized through 2027.

(d)	As a result of the Tax Reform Legislation, these accounts include certain deferred income tax assets and liabilities not subject to normalization. The recovery and amortization of these amounts will occur ratably over the related property lives, which may range up to 53 years. See Note 10 for additional information.

(e)	Recorded monthly and expected to be recovered or returned within three years. See "Rate CNP PPA," "Rate CNP Compliance," and" Rate ECR" herein for additional information.

(f)	In accordance with an accounting order issued in 2017 by the Alabama PSC, these regulatory assets will be amortized concurrently with the effective date of Alabama Power's next depreciation study, which is expected to occur no later than 2022.

(g)	Recorded as earned by employees and recovered as paid, generally within one year. This includes both vacation and banked holiday pay.

(h)	Recovered over either the remaining life of the original issue or, if refinanced, over the remaining life of the new issue. At December 31, 2019, the remaining amortization periods do not exceed 30 years.

(i)	Nuclear outage costs are deferred to a regulatory asset when incurred and amortized over a subsequent 18-month period.

(j)	Recorded and amortized over remaining periods not exceeding 18 years.

(k)	Comprised of components including generation site selection/evaluation costs, which are capitalized upon initiation of related construction projects, if applicable, and PPA capacity costs, which are to be recovered over the next 12 months.

(l)	Fuel-hedging assets and liabilities are recorded over the life of the underlying hedged purchase contracts, which generally do not exceed three and a half years. Upon final settlement, actual costs incurred are recovered through the energy cost recovery clause.

(m)	Includes $53 million for 2019 and $109 million for 2018 due to the retail return exceeding the allowed range. The December 31, 2018 balance also includes a $33 million excess deferred tax liability used to increase the Rate NDR balance in 2019. See "Rate RSE," "Rate NDR," and "Tax Reform Accounting Order" herein for additional information.

(n)	Amortized as expenses are incurred. See "Rate NDR" herein for additional information.

(o)	Not earning a return as offset in rate base by a corresponding asset or liability.

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Petition for Certificate of Convenience and Necessity

On September 6, 2019, Alabama Power filed a petition for a CCN with the Alabama PSC for authorization to procure additional generating capacity through the turnkey construction of a new combined cycle facility and long-term contracts for the purchase of power from others, both as more fully described below, as well as the acquisition of an existing combined cycle facility in Autauga County, Alabama (Autauga Combined Cycle Acquisition). In addition, Alabama Power will pursue approximately 200 MWs of certain demand side management and distributed energy resource programs. This filing was predicated on the results of Alabama Power's 2019 IRP provided to the Alabama PSC, which identified an approximately 2,400-MW resource need for Alabama Power, driven by the need for additional winter reserve capacity. See Note 15 under "Alabama Power" for additional information regarding the Autauga Combined Cycle Acquisition.

The procurement of these resources is subject to the satisfaction or waiver of certain conditions, including, among other customary conditions, approval by the Alabama PSC. The completion of the Autauga Combined Cycle Acquisition is also subject to approval by the FERC. Alabama Power expects to obtain all regulatory approvals by the end of the third quarter 2020.

On May 8, 2019, Alabama Power entered into an Agreement for Engineering, Procurement, and Construction with Mitsubishi Hitachi Power Systems Americas, Inc. and Black & Veatch Construction, Inc. to construct an approximately 720-MW combined cycle facility at Plant Barry (Plant Barry Unit 8), which is expected to be placed in service by the end of 2023.

The capital investment associated with the construction of Plant Barry Unit 8 and the Autauga Combined Cycle Acquisition is currently estimated to total approximately $1.1 billion.

Alabama Power entered into additional long-term PPAs totaling approximately 640 MWs of generating capacity consisting of approximately 240 MWs of combined cycle generation expected to begin later in 2020 and approximately 400 MWs of solar generation coupled with battery energy storage systems (solar/battery systems) expected to begin in 2022 through 2024. The terms of the agreements for the solar/battery systems permit Alabama Power to use the energy and retire the associated renewable energy credits (REC) in service of customers or to sell RECs, separately or bundled with energy.

Upon certification, Alabama Power expects to recover costs associated with Plant Barry Unit 8 pursuant to its Rate CNP New Plant. Additionally, Alabama Power expects to recover costs associated with the Autauga Combined Cycle Acquisition through the inclusion in Rate RSE of revenues from the existing power sales agreement and, on expiration of that agreement, pursuant to Rate CNP New Plant. The recovery of costs associated with laws, regulations, and other such mandates directed at the utility industry are expected to be recovered through Rate CNP Compliance. Alabama Power expects to recover the capacity-related costs associated with the PPAs through its Rate CNP PPA. In addition, fuel and energy-related costs are expected to be recovered through Rate ECR. Any remaining costs associated with the Autauga Combined Cycle Acquisition and Plant Barry Unit 8 will be incorporated through the annual filing of Rate RSE.

The ultimate outcome of these matters cannot be determined at this time.

Construction Work in Progress Accounting Order

On October 1, 2019, the Alabama PSC acknowledged that Alabama Power would begin certain limited preparatory activities associated with Plant Barry Unit 8 construction to meet the target in-service date by authorizing Alabama Power to record the related costs as CWIP prior to the issuance of an order on the CCN petition. Should a CCN not be granted and Alabama Power does not proceed with the related construction of Plant Barry Unit 8, Alabama Power may transfer those costs and any costs that directly result from the non-issuance of the CCN to a regulatory asset which would be amortized over a five-year period. If the balance of incurred costs reaches 5% of the estimated in-service cost of the total project prior to issuance of an order on the CCN petition, Alabama Power will confer with the Alabama PSC regarding the appropriateness of additional authorization. The Sierra Club subsequently filed a petition for reconsideration of the accounting order. The Alabama PSC voted to deny the petition for reconsideration on January 7, 2020.

Rate RSE

The Alabama PSC has adopted Rate RSE that provides for periodic annual adjustments based upon Alabama Power's projected weighted common equity return (WCER) 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%. When the projected WCER is under the allowed range, there is an adjusting point of 5.98% and eligibility for a performance-based adder of seven basis points, or 0.07%, to the WCER 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. If Alabama Power's actual retail return is above the allowed WCER range, the excess will be refunded to customers unless otherwise directed by the Alabama PSC; however, there is no

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provision for additional customer billings should the actual retail return fall below the WCER range. Prior to January 2019, retail rates remained unchanged when the WCER range was between 5.75% and 6.21%.

Effective in January 2017, Rate RSE increased 4.48%, or $245 million annually. At December 31, 2017, Alabama Power's actual retail return was within the allowed WCER range. Retail rates under Rate RSE were unchanged for 2018.

In conjunction with Rate RSE, Alabama Power has an established retail tariff that provides for an adjustment to customer billings to recognize the impact of a change in the statutory income tax rate. In accordance with this tariff, Alabama Power returned $267 million to retail customers through bill credits during 2018 as a result of the change in the federal income tax rate under the Tax Reform Legislation.

In May 2018, the Alabama PSC approved modifications to Rate RSE and other commitments designed to position Alabama Power to address the growing pressure on its credit quality resulting from the Tax Reform Legislation, without increasing retail rates under Rate RSE in the near term. Alabama Power plans to reduce growth in total debt by increasing equity, with corresponding reductions in debt issuances, thereby de-leveraging its capital structure. Alabama Power's goal is to achieve an equity ratio of approximately 55% by the end of 2025. At December 31, 2019 and 2018, Alabama Power's equity ratio was approximately 50% and 47%, respectively.

The approved modifications to Rate RSE began for billings in January 2019. The modifications include reducing the top of the allowed WCER range from 6.21% to 6.15% and modifications to the refund mechanism applicable to prior year actual results. The modifications to the refund mechanism allow Alabama Power to retain a portion of the revenue that causes the actual WCER for a given year to exceed the allowed range.

Generally, during a year without a Rate RSE upward adjustment, if Alabama Power's actual WCER is between 6.15% and 7.65%, customers will receive 25% of the amount between 6.15% and 6.65%, 40% of the amount between 6.65% and 7.15%, and 75% of the amount between 7.15% and 7.65%. Customers will receive all amounts in excess of an actual WCER of 7.65%. During a year with a Rate RSE upward adjustment, if Alabama Power's actual WCER exceeds 6.15%, customers receive 50% of the amount between 6.15% and 6.90% and all amounts in excess of an actual WCER of 6.90%.

In conjunction with these modifications to Rate RSE, in May 2018, Alabama Power consented to a moratorium on any upward adjustments under Rate RSE for 2019 and 2020 and to return $50 million to customers through bill credits in 2019.

At December 31, 2018, Alabama Power's retail return exceeded the allowed WCER range, which resulted in Alabama Power establishing a regulatory liability of $109 million for Rate RSE refunds. In accordance with an Alabama PSC order issued on February 5, 2019, Alabama Power applied $78 million to reduce the Rate ECR under recovered balance and the remaining $31 million was refunded to customers through bill credits starting in July 2019.

On November 27, 2019, Alabama Power made its required annual Rate RSE submission to the Alabama PSC of projected data for calendar year 2020. Projected earnings were within the specified range; therefore, retail rates under Rate RSE remain unchanged for 2020.

During 2019, Alabama Power provided to the Alabama PSC and the Alabama Office of the Attorney General information related to the operation and utilization of Rate RSE, in accordance with the rules governing the operation of Rate RSE. The ultimate outcome of this matter cannot be determined at this time.

At December 31, 2019, Alabama Power's WCER exceeded 6.15%, resulting in Alabama Power establishing a current regulatory liability of $53 million for Rate RSE refunds, which will be refunded to customers through bill credits in April 2020.

Rate CNP New Plant

Rate CNP New Plant allows for recovery of Alabama Power's retail costs associated with newly developed or acquired certificated generating facilities placed into retail service. No adjustments to Rate CNP New Plant occurred during the period 2017 through 2019. See "Petition for Certificate of Convenience and Necessity" herein for additional information.

Rate CNP PPA

Rate CNP PPA allows for the recovery of Alabama Power's retail costs associated with certificated PPAs. No adjustments to Rate CNP PPA occurred during the period 2017 through 2019 and no adjustment is expected for 2020. At December 31, 2019 and 2018, Alabama Power had an under recovered Rate CNP PPA balance of $40 million and $25 million, respectively, which is included in other regulatory assets, deferred on Southern Company's balance sheets and deferred under recovered regulatory clause revenues on Alabama Power's balance sheets.

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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 factors that are calculated and submitted to the Alabama PSC by December 1 with rates effective for the following calendar year. 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 Southern Company's or Alabama Power's revenues or net income, but will affect annual cash flow. Changes in Rate CNP Compliance-related operations and maintenance expenses and depreciation generally will have no effect on net income.

In November 2018, Alabama Power submitted calculations associated with its cost of complying with governmental mandates, as provided under Rate CNP Compliance. The filing reflected a projected under recovered retail revenue requirement for governmental mandates of approximately $205 million, which was recovered in the billing months of January 2019 through December 2019.

On November 27, 2019, Alabama Power submitted calculations associated with its cost of complying with governmental mandates, as provided under Rate CNP Compliance. The filing reflected a projected over recovered retail revenue requirement for governmental mandates, which resulted in a rate decrease of approximately $68 million that became effective for the billing month of January 2020.

At December 31, 2019, Alabama Power had an over recovered Rate CNP Compliance balance of $62 million, of which $55 million is included in other regulatory liabilities, current and $7 million is included in other regulatory liabilities, deferred on the balance sheet, compared to an under recovered balance of $42 million at December 31, 2018 included in customer accounts receivable on the balance sheet.

Rate ECR

Rate ECR recovers Alabama Power's retail energy costs 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 gives 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 or Alabama Power's net income but will impact operating cash flows. The Alabama PSC may approve billing rates under Rate ECR of up to 5.910 cents per KWH.

In May 2018, the Alabama PSC approved an increase to Rate ECR from 2.015 cents per KWH to 2.353 cents per KWH effective July 2018 through December 2018. In December 2018, the Alabama PSC issued a consent order to leave this rate in effect through December 31, 2019.

As discussed herein under "Rate RSE," in accordance with an Alabama PSC order issued on February 5, 2019, Alabama Power utilized $78 million of the 2018 Rate RSE refund liability to reduce the Rate ECR under recovered balance.

On December 3, 2019, the Alabama PSC approved a decrease to Rate ECR from 2.353 to 2.160 cents per KWH, equal to 1.82%, or approximately $102 million annually, effective January 1, 2020. The rate will adjust to 5.910 cents per KWH in January 2021 absent a further order from the Alabama PSC.

At December 31, 2019, Alabama Power's over recovered fuel costs totaled $49 million, of which $32 million is included in other regulatory liabilities, current and $17 million is included in other regulatory liabilities, deferred on Southern Company's and Alabama Power's balance sheets. At December 31, 2018, Alabama Power's under recovered fuel costs totaled $109 million, of which $18 million is included in customer accounts receivable and $91 million is included in deferred under recovered regulatory clause revenues on Southern Company's and Alabama Power's balance sheets. 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.

Tax Reform Accounting Order

In May 2018, the Alabama PSC approved an accounting order that authorized Alabama Power to defer the benefits of federal excess deferred income taxes associated with the Tax Reform Legislation for the year ended December 31, 2018 as a regulatory

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liability and to use up to $30 million of such deferrals to offset under recovered amounts under Rate ECR. The final excess deferred tax liability for the year ended December 31, 2018 totaled approximately $69 million, of which $30 million was used to offset the Rate ECR under recovered balance. On December 3, 2019, the Alabama PSC issued an order authorizing Alabama Power to apply the remaining deferred balance of approximately $39 million to increase the balance in the NDR. See "Rate NDR" herein and Note 10 under "Current and Deferred Income Taxes" for additional information.

Software Accounting Order

On February 5, 2019, the Alabama PSC approved an accounting order that authorizes Alabama Power to establish a regulatory asset for operations and maintenance costs associated with software implementation projects. The regulatory asset will be amortized ratably over the life of the related software.

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. When the reserve balance falls below $50 million, a reserve establishment charge will be activated (and the on-going reserve maintenance charge concurrently suspended) until the reserve balance reaches $75 million.

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 enhance Alabama Power's ability to mitigate the financial effects of future natural disasters, promote system reliability, and offset costs retail customers would otherwise bear. There were no such accruals in 2017 and 2018.

As discussed herein under "Tax Reform Accounting Order," in accordance with an Alabama PSC order issued on December 3, 2019, Alabama Power applied the remaining excess deferred income tax regulatory liability balance of approximately $39 million to increase the balance in the NDR. Alabama Power also accrued an additional $84 million to the NDR in December 2019 resulting in an accumulated balance of $150 million at December 31, 2019. Of this amount, Alabama Power designated $37 million to be applied to budgeted reliability-related expenditures for 2020, which is included in other regulatory liabilities, current. The remaining NDR balance of $113 million is included in other regulatory liabilities, deferred on the balance sheet.

In December 2017, the reserve maintenance charge was suspended and the reserve establishment charge was activated and collected approximately $16 million annually through 2019. Effective with the March 2020 billings, the reserve establishment charge will be suspended and the reserve maintenance charge will be activated as a result of the NDR balance exceeding $75 million. Alabama Power expects to collect approximately $5 million in 2020 and $3 million annually thereafter unless the NDR balance falls below $50 million.

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 (Environmental Accounting Order), 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. The regulatory asset is 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.

On April 15, 2019, Alabama Power retired Plant Gorgas Units 8, 9, and 10 and reclassified approximately $654 million of the unrecovered asset balances to regulatory assets, which are being recovered over the units' remaining useful lives, the latest being

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through 2037, as established prior to the decision to retire. At December 31, 2019, the related regulatory assets totaled $649 million, of which $63 million is included in other regulatory assets, current and $586 million is included in other regulatory assets, deferred on the balance sheet. Additionally, approximately $700 million of net capitalized asset retirement costs were reclassified to a regulatory asset in accordance with accounting guidance provided by the Alabama PSC. The asset retirement costs are being recovered through 2055.

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Georgia Power

Regulatory Assets and Liabilities

Regulatory assets and (liabilities) reflected in the balance sheets of Georgia Power at December 31, 2019 and 2018 relate to:

	2019				2018				Note
	(in millions)
Retiree benefit plans	$	1,516			$	1,295			(a, m)
Asset retirement obligations	3,119				2,644				(b, m)
Deferred income tax charges	523				522				(b, c, m)
Storm damage reserves	410				416				(d)
Remaining net book value of retired assets	596				127				(e)
Loss on reacquired debt	262				277				(f, m)
Vacation pay	93				91				(g, m)
Other cost of removal obligations	156				68				(b)
Environmental remediation	52				55				(h)
Fuel-hedging (realized and unrealized) losses	53				15				(i, m)
Other regulatory assets	50				120				(j)
Deferred income tax credits	(3,078		)		(3,080		)		(b, c)
Customer refunds	(229		)		(165		)		(k)
Other regulatory liabilities	(16		)		(7		)		(l, m)
Total regulatory assets (liabilities), net	$	3,507			$	2,378

Note: Unless otherwise noted, the recovery and amortization periods for these regulatory assets and (liabilities) are approved by the Georgia PSC and are as follows:

(a)	Recovered and amortized over the average remaining service period which may range up to 13 years. See Note 11 for additional information.

(b)

Effective January 1, 2020, Georgia Power is recovering CCR AROs through its Environmental Compliance Cost Recovery (ECCR) tariff and approximately $5 million annually for other AROs through its traditional base tariffs. See "Rate Plans – 2019 ARP" and "Integrated Resource Plan" herein for additional information on recovery of compliance costs for CCR AROs. Other cost of removal obligations, non-CCR AROs, and deferred income tax assets are recovered and deferred income tax liabilities are amortized over the related property lives, which may range up to 60 years. Included in the deferred income tax assets is $13 million for the retiree Medicare drug subsidy, which is being recovered and amortized through 2022. See Note 6 for additional information on AROs.

(c)

As a result of the Tax Reform Legislation, these balances include $145 million of deferred income tax assets related to CWIP for Plant Vogtle Units 3 and 4 and approximately $660 million of deferred income tax liabilities, neither of which are subject to normalization. The recovery of deferred income tax assets related to CWIP for Plant Vogtle Units 3 and 4 is expected to be determined in a future regulatory proceeding. Effective January 1, 2020, the deferred income tax liabilities are being amortized through 2022. See "Rate Plans" herein and Note 10 for additional information.

(d)	Effective January 1, 2020, Georgia Power is recovering $213 million annually for storm damage. See "Rate Plans – 2019 ARP" and "Storm Damage Recovery" herein and Note 1 under "Storm Damage Reserves" for additional information.

(e)

The net book values of Plant Hammond Units 1 through 4 ($488 million at December 31, 2019) and Plant Branch Units 1 through 4 ($69 million and $87 million at December 31, 2019 and 2018, respectively) are being amortized over the units' remaining useful lives, which vary between 2020 and 2035. The net book values of Plant McIntosh Unit 1 ($30 million at December 31, 2019) and Plant Mitchell Unit 3 ($8 million and $9 million at December 31, 2019 and 2018, respectively) are being amortized through 2022. The balance at December 31, 2018 also includes $31 million related to obsolete inventories of certain retired units, which was fully amortized under the 2019 ARP. See "Rate Plans – 2019 ARP" and "Integrated Resource Plan" herein for additional information.

(f)	Recovered over either the remaining life of the original issue or, if refinanced, over the remaining life of the new issue. At December 31, 2019, the amortization periods do not exceed 33 years.

(g)	Recorded as earned by employees and recovered as paid, generally within one year.

(h)	Effective January 1, 2020, Georgia Power is recovering $12 million annually for environmental remediation. See Note 3 under "Environmental Remediation" for additional information.

(i)	Recovered through Georgia Power's fuel cost recovery mechanism upon final settlement, within four years.

(j)

Comprised of several components including deferred nuclear outage costs and cancelled construction projects. Nuclear outage costs are recorded as incurred and recovered over the outage cycles of each nuclear unit, which do not exceed 24 months. Approximately $22 million of costs associated with construction of environmental controls that will not be completed as a result of unit retirements are being amortized through 2022.

(k)	At December 31, 2019 and 2018, includes approximately $110 million and $100 million, respectively, as a result of the retail ROE exceeding the allowed retail ROE range and approximately $105 million and $55 million, respectively, related to the Georgia Power Tax Reform Settlement Agreement. See "Rate Plans" herein for additional information.

(l)	Comprised of Demand-Side Management (DSM) tariffs over recovery, building lease, and fuel-hedging gains. DSM tariffs over recovery of $10 million at December 31, 2019 is being amortized through 2022. The building lease is being amortized through 2030. Fuel-hedging gains are refunded through Georgia Power's fuel cost recovery mechanism upon final settlement, within four years.

(m)	Generally not earning a return as they are excluded from rate base or are offset in rate base by a corresponding asset or liability.

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Rate Plans

2019 ARP

On December 17, 2019, the Georgia PSC voted to approve the 2019 ARP, under which Georgia Power increased its rates on January 1, 2020 and will increase rates annually for 2021 and 2022 as detailed below based on compliance filings to be made at least 90 days prior to the effective date. Georgia Power will recover estimated increases through its existing tariffs as follows:

Tariff	2020			2021			2022
	(in millions)
Traditional base	$	—		$	120		$	192
ECCR(a)	318			55			184
DSM	12			1			1
Municipal Franchise Fee	12			4			9
Total(b)	$	342		$	181		$	386

(a)	Effective January 1, 2020, CCR AROs will be recovered through the ECCR tariff. See "Integrated Resource Plan" herein for additional information on recovery of compliance costs for CCR AROs.

(b)	Totals may not add due to rounding.

Further, under the 2019 ARP, Georgia Power's retail ROE is set at 10.50%, and earnings will be evaluated against a retail ROE range of 9.50% to 12.00%. The Georgia PSC also approved an increase in the retail equity ratio to 56% from 55%. Any retail earnings above 12.00% will be shared, with 40% being applied to reduce regulatory assets, 40% directly refunded to customers, and the remaining 20% retained by Georgia Power. There will be no recovery of any earnings shortfall below 9.50% on an actual basis. However, if at any time during the term of the 2019 ARP, Georgia Power projects that its retail earnings will be below 9.50% for any calendar year, it could petition the Georgia PSC for implementation of the Interim Cost Recovery (ICR) tariff to adjust Georgia Power's retail rates to achieve a 9.50% ROE. The Georgia PSC would have 90 days to rule on Georgia Power's request. The ICR tariff would expire at the earlier of January 1, 2023 or the end of the calendar year in which the ICR tariff becomes effective. In lieu of requesting implementation of an ICR tariff, or if the Georgia PSC chooses not to implement the ICR tariff, Georgia Power may file a full rate case.

Additionally, under the 2019 ARP and pursuant to the sharing mechanism approved in the 2013 ARP whereby two-thirds of any earnings above the top of the allowed ROE range are shared with Georgia Power's customers, (i) Georgia Power used 50% (approximately $50 million) of the customer share of earnings above the band in 2018 to reduce regulatory assets and 50% (approximately $50 million) will be refunded to customers in 2020 and (ii) Georgia Power will forgo its share of 2019 earnings in excess of the earnings band so that 50% (approximately $60 million) of all earnings over the 2019 band will be refunded to customers and 50% (approximately $60 million) were used to reduce regulatory assets.

Except as provided above, Georgia Power will not file for a general base rate increase while the 2019 ARP is in effect. Georgia Power is required to file a general base rate case by July 1, 2022, in response to which the Georgia PSC would be expected to determine whether the 2019 ARP should be continued, modified, or discontinued.

2013 ARP

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 in 2016, the 2013 ARP continued in effect until December 31, 2019. Furthermore, through December 31, 2019, Georgia Power retained its merger savings, net of transition costs, as defined in the settlement agreement; through December 31, 2022, such net merger savings will be shared on a 60/40 basis with customers; thereafter, all merger savings will be retained by customers.

There were no changes to Georgia Power's traditional base tariffs, ECCR tariff, DSM tariffs, or Municipal Franchise Fee tariffs in 2017, 2018, or 2019.

Under the 2013 ARP, Georgia Power's retail ROE was set at 10.95% and earnings were evaluated against a retail ROE range of 10.00% to 12.00%. Two-thirds of any earnings above 12.00% were to be directly refunded to customers, with the remaining one-third retained by Georgia Power. On February 5, 2019, the Georgia PSC approved a settlement between Georgia Power and the staff of the Georgia PSC under which Georgia Power's retail ROE for 2017 was stipulated to exceed 12.00% and Georgia Power reduced certain regulatory assets by approximately $4 million in lieu of providing refunds to retail customers. In 2019 and 2018, Georgia Power's retail ROE exceeded 12.00% and, under the modified sharing mechanism pursuant to the 2019 ARP, Georgia

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Power has reduced regulatory assets by a total of approximately $110 million and expects to refund a total of approximately $110 million to customers, subject to review and approval by the Georgia PSC. See "2019 ARP" and "Integrated Resource Plan" herein for additional information.

Tax Reform Settlement Agreement

In April 2018, the Georgia PSC approved the Georgia Power Tax Reform Settlement Agreement. To reflect the federal income tax rate reduction impact of the Tax Reform Legislation, Georgia Power issued bill credits of approximately $95 million and $130 million in 2019 and 2018, respectively, and is issuing bill credits of approximately $105 million in February 2020, for a total of $330 million. In addition, Georgia Power deferred as a regulatory liability (i) the revenue equivalent of the tax expense reduction resulting from legislation lowering the Georgia state income tax rate from 6.00% to 5.75% in 2019 and (ii) the entire benefit of federal and state excess accumulated deferred income taxes. At December 31, 2019, the related regulatory liability balance totaled $659 million, which is being amortized over a three-year period ending December 31, 2022 in accordance with the 2019 ARP.

To address some of the negative cash flow and credit quality impacts of the Tax Reform Legislation, the Georgia PSC also approved an increase in Georgia Power's retail equity ratio to the lower of (i) Georgia Power's actual common equity weight in its capital structure or (ii) 55%, until the Georgia PSC approved the 2019 ARP. Benefits from reduced federal income tax rates in excess of the amounts refunded to customers were retained by Georgia Power to cover the carrying costs of the incremental equity in 2018 and 2019.

See "2019 ARP" herein for additional information.

Integrated Resource Plan

On July 16, 2019, the Georgia PSC voted to approve Georgia Power's modified triennial IRP (Georgia Power 2019 IRP). In the Georgia Power 2019 IRP, the Georgia PSC approved the decertification and retirement of Plant Hammond Units 1 through 4 (840 MWs) and Plant McIntosh Unit 1 (142.5 MWs) effective July 29, 2019. In accordance with the 2019 ARP, the remaining net book values at December 31, 2019 of $488 million for the Plant Hammond units are being recovered over a period equal to the respective unit's remaining useful life, which varies between 2024 and 2035, and $30 million for Plant McIntosh Unit 1 is being recovered over a three-year period ending December 31, 2022. In addition, approximately $20 million of related unusable materials and supplies inventory balances and approximately $295 million of net capitalized asset retirement costs were reclassified to a regulatory asset. In accordance with the modifications to the earnings sharing mechanism approved in the 2019 ARP, Georgia Power fully amortized the regulatory assets associated with these unusable materials and supplies inventory balances as well as a regulatory asset of approximately $50 million related to costs for a future generation site in Stewart County, Georgia. See "Rate Plans – 2019 ARP" herein for additional information.

Also in the Georgia Power 2019 IRP, the Georgia PSC approved Georgia Power's proposed environmental compliance strategy associated with ash pond and certain landfill closures and post-closure care in compliance with the CCR Rule and the related state rule. In the 2019 ARP, the Georgia PSC approved recovery of the estimated under recovered balance of these compliance costs at December 31, 2019 over a three-year period ending December 31, 2022 and recovery of estimated compliance costs for 2020, 2021, and 2022 over three-year periods ending December 31, 2022, 2023, and 2024, respectively, with recovery of construction contingency beginning in the year following actual expenditure. The under recovered balance at December 31, 2019 was $175 million and the estimated compliance costs expected to be incurred in 2020, 2021, and 2022 are $265 million, $290 million, and $390 million, respectively. The ECCR tariff is expected to be revised for actual expenditures and updated estimates through future annual compliance filings. See Note 6 for additional information regarding Georgia Power's AROs.

On February 4, 2020, the Georgia PSC voted to deny a motion for reconsideration filed by the Sierra Club regarding the Georgia PSC's decision in the 2019 ARP allowing Georgia Power to recover compliance costs for CCR AROs.

Additionally, the Georgia PSC rejected a request to certify approximately 25 MWs of capacity at Plant Scherer Unit 3 for the retail jurisdiction beginning January 1, 2020 following the expiration of a wholesale PPA. Georgia Power may offer such capacity in the wholesale market or to the retail jurisdiction in a future IRP.

The Georgia PSC also approved Georgia Power to (i) issue requests for proposals (RFP) for capacity beginning in 2022 or 2023 and in 2026, 2027, or 2028; (ii) procure up to an additional 2,210 MWs of renewable resources through competitive RFPs; and (iii) invest in a portfolio of up to 80 MWs of battery energy storage technologies.

Fuel Cost Recovery

Georgia Power has established fuel cost recovery rates approved by the Georgia PSC. In 2016, the Georgia PSC approved Georgia Power's request to lower annual billings under an interim fuel rider by approximately $313 million which was in effect

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from June 1, 2016 through December 31, 2017. Georgia Power is scheduled to file its next fuel case no later than March 16, 2020, with new rates, if any, to be effective June 1, 2020. Georgia Power continues to be allowed to adjust its fuel cost recovery rates under an interim fuel rider prior to the next fuel case if the under or over recovered fuel balance exceeds $200 million. Georgia Power's over recovered fuel balance totaled $73 million at December 31, 2019 and is included in other deferred credits and liabilities on Southern Company's and Georgia Power's balance sheets. At December 31, 2018, Georgia Power's under recovered fuel balance totaled $115 million and is included in under recovered fuel clause revenues on Southern Company's and Georgia Power's balance sheets.

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.

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 or Georgia Power's revenues or net income but will affect operating cash flows.

Storm Damage Recovery

Georgia Power defers and recovers certain costs related to damages from major storms as mandated by the Georgia PSC. Beginning January 1, 2020, Georgia Power is recovering $213 million annually under the 2019 ARP. At December 31, 2019 and 2018, the balance in the regulatory asset related to storm damage was $410 million and $416 million, respectively, with $213 million and $30 million, respectively, included in other regulatory assets, current on Southern Company's balance sheets and regulatory assets – storm damage reserves on Georgia Power's balance sheets and $197 million and $386 million, respectively, included in other regulatory assets, deferred on Southern Company's and Georgia Power's balance sheets. The rate of storm damage cost recovery is expected to be adjusted in future regulatory proceedings as necessary. As a result of this regulatory treatment, costs related to storms are not expected to have a material impact on Southern Company's or Georgia Power's financial statements.

Nuclear Construction

In 2009, the Georgia PSC certified construction of Plant Vogtle Units 3 and 4. Georgia Power holds a 45.7% ownership interest in Plant Vogtle Units 3 and 4. In 2012, the NRC issued the related combined construction and operating licenses, which allowed full construction of the two AP1000 nuclear units (with electric generating capacity of approximately 1,100 MWs each) and related facilities to begin. Until March 2017, construction on Plant Vogtle Units 3 and 4 continued under the Vogtle 3 and 4 Agreement, which was a substantially fixed price agreement. In March 2017, the EPC Contractor filed for bankruptcy protection under Chapter 11 of the U.S. Bankruptcy Code.

In connection with the EPC Contractor's bankruptcy filing, Georgia Power, acting for itself and as agent for the other Vogtle Owners, entered into several transitional arrangements to allow construction to continue. In July 2017, Georgia Power, acting for itself and as agent for the other Vogtle Owners, entered into the Vogtle Services Agreement, whereby Westinghouse provides facility design and engineering services, procurement and technical support, and staff augmentation on a time and materials cost basis. The Vogtle Services Agreement provides that it will continue until the start-up and testing of Plant Vogtle Units 3 and 4 are complete and electricity is generated and sold from both units. The Vogtle Services Agreement is terminable by the Vogtle Owners upon 30 days' written notice.

In October 2017, Georgia Power, acting for itself and as agent for the other Vogtle Owners, executed the Bechtel Agreement, a cost reimbursable plus fee arrangement, whereby Bechtel is reimbursed for actual costs plus a base fee and an at-risk fee, which is subject to adjustment based on Bechtel's performance against cost and schedule targets. Each Vogtle Owner is severally (not jointly) liable for its proportionate share, based on its ownership interest, of all amounts owed to Bechtel under the Bechtel Agreement. The Vogtle Owners may terminate the Bechtel Agreement at any time for their convenience, provided that the Vogtle Owners will be required to pay amounts related to work performed prior to the termination (including the applicable portion of the base fee), certain termination-related costs, and, at certain stages of the work, the applicable portion of the at-risk fee. Bechtel may terminate the Bechtel Agreement under certain circumstances, including certain Vogtle Owner suspensions of work, certain breaches of the Bechtel Agreement by the Vogtle Owners, Vogtle Owner insolvency, and certain other events.

See Note 8 under "Long-term Debt – DOE Loan Guarantee Borrowings" for information on the Amended and Restated Loan Guarantee Agreement, including applicable covenants, events of default, mandatory prepayment events, and conditions to borrowing.

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Cost and Schedule

Georgia Power's approximate proportionate share of the remaining estimated capital cost to complete Plant Vogtle Units 3 and 4 by the expected in-service dates of November 2021 and November 2022, respectively, is as follows:

	(in billions)
Base project capital cost forecast(a)(b)	$	8.2
Construction contingency estimate	0.2
Total project capital cost forecast(a)(b)	8.4
Net investment as of December 31, 2019(b)	(5.9		)
Remaining estimate to complete(a)	$	2.5

(a)	Excludes financing costs expected to be capitalized through AFUDC of approximately $300 million, of which $23 million had been accrued through December 31, 2019.

(b)	Net of $1.7 billion received from Toshiba under the Guarantee Settlement Agreement and approximately $188 million in related customer refunds.

As of December 31, 2019, approximately $140 million of the $366 million construction contingency estimate established in the second quarter 2018 was allocated to the base capital cost forecast for cost risks including, among other factors, construction productivity; craft labor incentives; adding resources for supervision, field support, project management, initial test program, start-up, and operations and engineering support; subcontracts; and procurement. As and when construction contingency is spent, Georgia Power may request the Georgia PSC to evaluate those expenditures for rate recovery.

Georgia Power estimates that its financing costs for construction of Plant Vogtle Units 3 and 4 will total approximately $3.1 billion, of which $2.2 billion had been incurred through December 31, 2019.

As part of its ongoing processes, Southern Nuclear continues to evaluate cost and schedule forecasts on a regular basis to incorporate current information available, particularly in the areas of commodity installation, system turnovers, and workforce statistics.

In April 2019, Southern Nuclear established aggressive target values for monthly construction production and system turnover activities as part of a strategy to maintain and, where possible, build margin to the regulatory-approved in-service dates of November 2021 for Unit 3 and November 2022 for Unit 4. The project has faced challenges with the April 2019 aggressive strategy targets, including, but not limited to, electrical and pipefitting labor productivity and closure rates for work packages, which resulted in a backlog of activities and completion percentages below the April 2019 aggressive strategy targets. However, Southern Nuclear and Georgia Power believe that existing productivity levels and pace of activity completion are sufficient to meet the regulatory-approved in-service dates.

In February 2020, Southern Nuclear updated its cost and schedule forecast, which did not change the projected overall capital cost forecast and confirmed the expected in-service dates of November 2021 for Unit 3 and November 2022 for Unit 4. This update included initiatives to improve productivity while refining and extending system turnover plans and certain near-term milestone dates. Other milestone dates did not change. Achievement of the aggressive site work plan relies on meeting increased monthly production and activity target values during 2020. To meet these 2020 targets, existing craft, including subcontractors, construction productivity must improve and be sustained above historical average levels, appropriate levels of craft laborers, particularly electrical and pipefitter craft labor, must be maintained, and additional supervision and other field support resources must be retained. Southern Nuclear and Georgia Power continue to believe that pursuit of an aggressive site work plan is an appropriate strategy to achieve completion of the units by their regulatory-approved in-service dates.

As construction, including subcontract work, continues and testing and system turnover activities increase, challenges with management of contractors and vendors; subcontractor performance; supervision of craft labor and related craft labor productivity, particularly in the installation of electrical and mechanical commodities, ability to attract and retain craft labor, and/or related cost escalation; procurement, fabrication, delivery, assembly, installation, system turnover, and the initial testing and start-up, including any required engineering changes or any remediation related thereto, of plant systems, structures, or components (some of which are based on new technology that only within the last few years began initial operation in the global nuclear industry at this scale), or regional transmission upgrades, any of which may require additional labor and/or materials; or other issues could arise and change the projected schedule and estimated cost.

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. 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

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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 submittal by Southern Nuclear of the ITAAC documentation for each unit and the related reviews and approvals by the NRC necessary to support NRC authorization to load fuel, may arise, which may result in additional license amendments or require other resolution. As part of the aggressive site work plan, in January 2020, Southern Nuclear notified the NRC of its intent to load fuel in 2020. 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.

The ultimate outcome of these matters cannot be determined at this time. However, any extension of the regulatory-approved project schedule is currently estimated to result in additional base capital costs of approximately $50 million per month, based on Georgia Power's ownership interests, and AFUDC of approximately $12 million per month. While Georgia Power is not precluded from seeking recovery of any future capital cost forecast increase, management will ultimately determine whether or not to seek recovery. Any further changes to the capital cost forecast that are not expected to be recoverable through regulated rates will be required to be charged to income and such charges could be material.

Joint Owner Contracts

In November 2017, the Vogtle Owners entered into an amendment to their joint ownership agreements for Plant Vogtle Units 3 and 4 to provide for, among other conditions, additional Vogtle Owner approval requirements. Effective in August 2018, the Vogtle Owners further amended the joint ownership agreements to clarify and provide procedures for certain provisions of the joint ownership agreements related to adverse events that require the vote of the holders of at least 90% of the ownership interests in Plant Vogtle Units 3 and 4 to continue construction (as amended, and together with the November 2017 amendment, the Vogtle Joint Ownership Agreements). The Vogtle Joint Ownership Agreements also confirm that the Vogtle Owners' sole recourse against Georgia Power or Southern Nuclear for any action or inaction in connection with their performance as agent for the Vogtle Owners is limited to removal of Georgia Power and/or Southern Nuclear as agent, except in cases of willful misconduct.

As a result of an increase in the total project capital cost forecast and Georgia Power's decision not to seek rate recovery of the increase in the base capital costs in conjunction with the nineteenth VCM report in 2018, the holders of at least 90% of the ownership interests in Plant Vogtle Units 3 and 4 were required to vote to continue construction. In September 2018, the Vogtle Owners unanimously voted to continue construction of Plant Vogtle Units 3 and 4.

Amendments to the Vogtle Joint Ownership Agreements

In connection with the vote to continue construction, Georgia Power entered into (i) a binding term sheet (Vogtle Owner Term Sheet) with the other Vogtle Owners and MEAG Power's wholly-owned subsidiaries MEAG Power SPVJ, LLC (MEAG SPVJ), MEAG Power SPVM, LLC (MEAG SPVM), and MEAG Power SPVP, LLC (MEAG SPVP) to take certain actions which partially mitigate potential financial exposure for the other Vogtle Owners, including additional amendments to the Vogtle Joint Ownership Agreements and the purchase of PTCs from the other Vogtle Owners at pre-established prices, and (ii) a term sheet (MEAG Term Sheet) with MEAG Power and MEAG SPVJ to provide funding with respect to MEAG SPVJ's ownership interest in Plant Vogtle Units 3 and 4 under certain circumstances. On January 14, 2019, Georgia Power, MEAG Power, and MEAG SPVJ entered into an agreement to implement the provisions of the MEAG Term Sheet. On February 18, 2019, Georgia Power, the other Vogtle Owners, and MEAG Power's wholly-owned subsidiaries MEAG SPVJ, MEAG SPVM, and MEAG SPVP entered into certain amendments to the Vogtle Joint Ownership Agreements to implement the provisions of the Vogtle Owner Term Sheet.

The ultimate outcome of these matters cannot be determined at this time.

Regulatory Matters

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 Plant Vogtle Units 3 and 4. Financing costs are recovered on all applicable certified costs through annual adjustments to the NCCR tariff up to the certified capital cost of $4.418 billion. At December 31, 2019, Georgia Power had recovered approximately $2.2 billion of financing costs. Financing costs related to capital costs above $4.418 billion are being recognized through AFUDC and are expected to be recovered through retail rates over the life of Plant Vogtle Units 3 and 4; however, Georgia Power will not record AFUDC related to any capital costs in excess of the total deemed reasonable by the Georgia PSC (currently $7.3 billion) and not requested for rate recovery. On December 17, 2019, the Georgia PSC approved Georgia Power's request to decrease the NCCR tariff by $62 million annually, effective January 1, 2020.

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Georgia Power is required to file semi-annual VCM reports with the Georgia PSC by February 28 and August 31 of each year. In 2013, in connection with the eighth VCM report, the Georgia PSC approved a stipulation between Georgia Power and the staff of the Georgia PSC to waive the requirement to amend the Plant Vogtle Units 3 and 4 certificate in accordance with the 2009 certification order until the completion of Plant Vogtle Unit 3, or earlier if deemed appropriate by the Georgia PSC and Georgia Power.

In 2016, the Georgia PSC voted to approve a settlement agreement (Vogtle Cost Settlement Agreement) resolving certain prudency matters in connection with the fifteenth VCM report. In December 2017, the Georgia PSC voted to approve (and issued its related order on January 11, 2018) Georgia Power's seventeenth VCM report and modified the Vogtle Cost Settlement Agreement. The Vogtle Cost Settlement Agreement, as modified by the January 11, 2018 order, resolved the following regulatory matters related to Plant Vogtle Units 3 and 4: (i) none of the $3.3 billion of costs incurred through December 31, 2015 and reflected in the fourteenth VCM report should be disallowed from rate base on the basis of imprudence; (ii) the Contractor Settlement Agreement was reasonable and prudent and none of the amounts paid pursuant to the Contractor Settlement Agreement should be disallowed from rate base on the basis of imprudence; (iii) (a) capital costs incurred up to $5.68 billion would be presumed to be reasonable and prudent with the burden of proof on any party challenging such costs, (b) Georgia Power would have the burden to show that any capital costs above $5.68 billion were prudent, and (c) a revised capital cost forecast of $7.3 billion (after reflecting the impact of payments received under the Guarantee Settlement Agreement and related customer refunds) was found reasonable; (iv) construction of Plant Vogtle Units 3 and 4 should be completed, with Southern Nuclear serving as project manager and Bechtel as primary contractor; (v) approved and deemed reasonable Georgia Power's revised schedule placing Plant Vogtle Units 3 and 4 in service in November 2021 and November 2022, respectively; (vi) confirmed that the revised cost forecast does not represent a cost cap and that prudence decisions on cost recovery will be made at a later date, consistent with applicable Georgia law; (vii) reduced the ROE used to calculate the NCCR tariff (a) from 10.95% (the ROE rate setting point authorized by the Georgia PSC in the 2013 ARP) to 10.00% effective January 1, 2016, (b) from 10.00% to 8.30%, effective January 1, 2020, and (c) from 8.30% to 5.30%, effective January 1, 2021 (provided that the ROE in no case will be less than Georgia Power's average cost of long-term debt); (viii) reduced the ROE used for AFUDC equity for Plant Vogtle Units 3 and 4 from 10.00% to Georgia Power's average cost of long-term debt, effective January 1, 2018; and (ix) agreed that upon Unit 3 reaching commercial operation, retail base rates would be adjusted to include carrying costs on those capital costs deemed prudent in the Vogtle Cost Settlement Agreement. The January 11, 2018 order also stated that if Plant Vogtle Units 3 and 4 are not commercially operational by June 1, 2021 and June 1, 2022, respectively, the ROE used to calculate the NCCR tariff will be further reduced by 10 basis points each month (but not lower than Georgia Power's average cost of long-term debt) until the respective Unit is commercially operational. The ROE reductions negatively impacted earnings by approximately $75 million, $100 million, and $25 million in 2019, 2018, and 2017, respectively, and are estimated to have negative earnings impacts of approximately $140 million, $240 million, and $190 million in 2020, 2021, and 2022, respectively. In its January 11, 2018 order, the Georgia PSC also stated if other conditions change and assumptions upon which Georgia Power's seventeenth VCM report are based do not materialize, the Georgia PSC reserved the right to reconsider the decision to continue construction.

In February 2018, Georgia Interfaith Power & Light, Inc. (GIPL) and Partnership for Southern Equity, Inc. (PSE) filed a petition appealing the Georgia PSC's January 11, 2018 order with the Fulton County Superior Court. In March 2018, Georgia Watch filed a similar appeal to the Fulton County Superior Court for judicial review of the Georgia PSC's decision and denial of Georgia Watch's motion for reconsideration. In December 2018, the Fulton County Superior Court granted Georgia Power's motion to dismiss the two appeals. On January 9, 2019, GIPL, PSE, and Georgia Watch filed an appeal of this decision with the Georgia Court of Appeals. On October 29, 2019, the Georgia Court of Appeals issued an opinion affirming the Fulton County Superior Court's ruling that the Georgia PSC's January 11, 2018 order was not a final, appealable decision. In addition, the Georgia Court of Appeals remanded the case to the Fulton County Superior Court to clarify its ruling as to whether the petitioners showed that review of the Georgia PSC's final order would not provide them an adequate remedy. Georgia Power believes the petitions have no merit; however, an adverse outcome in the litigation combined with subsequent adverse action by the Georgia PSC could have a material impact on Southern Company's and Georgia Power's results of operations, financial condition, and liquidity.

On February 18, 2020, the Georgia PSC approved Georgia Power's twentieth VCM report and its concurrently-filed twenty-first VCM report, including approval of (i) $1.2 billion of construction capital costs incurred from July 1, 2018 through June 30, 2019 and (ii) $21.5 million of expenditures related to Georgia Power's portion of an administrative claim filed in the Westinghouse bankruptcy proceedings (which expenditures had previously been deferred by the Georgia PSC for later approval). Through the twenty-first VCM, the Georgia PSC has approved total construction capital costs incurred through June 30, 2019 of $6.7 billion (before $1.7 billion of payments received under the Guarantee Settlement Agreement and approximately $188 million in related customer refunds). On February 19, 2020, Georgia Power filed its twenty-second VCM report with the Georgia PSC covering the period from July 1, 2019 through December 31, 2019, requesting approval of $674 million of construction capital costs incurred during that period.

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The ultimate outcome of these matters cannot be determined at this time.

Mississippi Power

Regulatory Assets and Liabilities

Regulatory assets and (liabilities) reflected in the balance sheets of Mississippi Power at December 31, 2019 and 2018 relate to:

	2019				2018				Note
	(in millions)
Retiree benefit plans – regulatory assets	$	213			$	171			(a)
Asset retirement obligations	210				143				(b)
Kemper County energy facility assets, net	61				69				(c)
Remaining net book value of retired assets	30				41				(d)
Property tax	47				44				(e)
Deferred charges related to income taxes	33				34				(b)
Plant Daniel Units 3 and 4	34				36				(f)
ECO Plan carryforward	—				26				(g)
Other regulatory assets	48				28				(h)
Deferred credits related to income taxes	(358		)		(377		)		(i)
Other cost of removal obligations	(189		)		(185		)		(b)
Property damage	(55		)		(56		)		(j)
Other regulatory liabilities	(10		)		(9		)		(k)
Total regulatory assets (liabilities), net	$	64			$	(35	)

Note: Unless otherwise noted, the recovery and amortization periods for these regulatory assets and (liabilities) are approved by the Mississippi PSC and are as follows:

(a)	Recovered and amortized over the average remaining service period which may range up to 14 years. See Note 11 for additional information.

(b)	Asset retirement and other cost of removal obligations will be settled and trued up upon completion of removal activities over a period to be determined by the Mississippi PSC. Asset retirement and other cost of removal obligations and deferred charges related to income taxes are generally recovered over the related property lives, which may range up to 48 years.

(c)	Includes $78 million of regulatory assets and $18 million of regulatory liabilities that are expected to be fully amortized by 2025 and 2023, respectively. For additional information, see "Kemper County Energy Facility – Rate Recovery" herein.

(d)	Retail portion includes approximately $16 million being recovered over a five-year period through 2021 and 2022 for Plant Watson and Plant Greene County, respectively. Wholesale portion includes approximately $14 million being recovered over a 12-year period through 2031 for Plant Watson and Plant Greene County.

(e)	Recovered through the ad valorem tax adjustment clause over a 12-month period beginning in April of the following year. See "Ad Valorem Tax Adjustment" herein for additional information.

(f)	Represents the difference between the revenue requirement under purchase accounting and operating lease accounting, which will be amortized over a 10-year period beginning October 2021.

(g)	Generally recovered through the ECO Plan clause in the year following the deferral. See "Environmental Compliance Overview Plan" herein.

(h)

Includes $9 million related to vacation pay and $5 million related to other miscellaneous assets, all of which are recorded and recovered over periods not exceeding one year; $6 million related to loss on reacquired debt, which is recorded and amortized over either the remaining life of the original issue, or if refinanced, over the remaining life of the new issue (at December 31, 2019, the amortization periods did not exceed 22 years); and $27 million related to fuel-hedging assets, which are recorded over the life of the underlying hedged purchase contracts, which generally do not exceed three years, and are recovered through Mississippi Power's energy cost management clause upon settlement.

(i)

Includes excess deferred income taxes primarily associated with Tax Reform Legislation of $358 million, of which $252 million is related to protected deferred income taxes being recovered over the related property lives, which may range up to 48 years, and $106 million related to unprotected deferred income taxes (not subject to normalization). The unprotected retail portion includes $28 million associated with the Kemper County energy facility being amortized over an eight-year period through 2025. The unprotected wholesale portion includes $18 million of excess deferred income taxes being amortized over three-year periods through 2022. An additional $8 million associated with the System Restoration Rider is being amortized over an eight-year period through 2025. The amortization period for the remaining unprotected deferred income taxes is expected to be determined in the Mississippi Power 2019 Base Rate Case. See "Kemper County Energy Facility" and "Municipal and Rural Associations Tariff" herein and Note 10 for additional information.

(j)	See "System Restoration Rider" herein.

(k)	Refunded or amortized generally over periods not exceeding one year.

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2019 Base Rate Case

On November 26, 2019, Mississippi Power filed a base rate case (Mississippi Power 2019 Base Rate Case) with the Mississippi PSC. The filing includes a requested annual decrease in Mississippi Power's retail rates of $5.8 million, or 0.6%, which is driven primarily by changes in the amortization rates of certain regulatory assets and liabilities and cost reductions, partially offset by an increase in Mississippi Power's requested return on investment and depreciation associated with the filing of an updated depreciation study. The revenue requirements included in the filing are based on a projected test year period of January 1, 2020 through December 31, 2020, a 53% average equity ratio, and a 7.728% return on investment. The filing reflects the elimination of separate rates for costs associated with the Kemper County energy facility and energy efficiency initiatives; those costs are proposed to be included in the PEP, ECO Plan, and ad valorem tax adjustment factor, as applicable. On December 10, 2019, the Mississippi PSC suspended the base rate case filing through no later than March 25, 2020. If no further action is taken by the Mississippi PSC, the proposed rates may be effective beginning on March 26, 2020. The ultimate outcome of this matter cannot be determined at this time.

Operations Review

In August 2018, the Mississippi PSC began an operations review of Mississippi Power, for which the final report is expected prior to the conclusion of the Mississippi Power 2019 Base Rate Case. The review includes, but is not limited to, a comparative analysis of its costs, its cost recovery framework, and ways in which it may streamline management operations for the reasonable benefit of ratepayers. The ultimate outcome of this matter cannot be determined at this time.

Reserve Margin Plan

On December 31, 2019, Mississippi Power updated its proposed Reserve Margin Plan (RMP), originally filed in August 2018, as required by the Mississippi PSC. In 2018, Mississippi Power had proposed alternatives to reduce its reserve margin and lower or avoid operating costs, with the most economic alternatives being the two-year and seven-year acceleration of the retirement of Plant Watson Units 4 and 5, respectively, to the first quarter 2022 and the four-year acceleration of the retirement of Plant Greene County Units 1 and 2 to the third quarter 2021 and the third quarter 2022, respectively. The December 2019 update noted that Plant Daniel Units 1 and 2 currently have long-term economics similar to Plant Watson Unit 5. The Plant Greene County unit retirements would require the completion by Alabama Power of proposed transmission and system reliability improvements, as well as agreement by Alabama Power. The RMP filing also states that, in the event the Mississippi PSC ultimately approves an alternative that includes an accelerated retirement, Mississippi Power would require authorization to defer in a regulatory asset for future recovery the remaining net book value of the units at the time of retirement. A decision by the Mississippi PSC that does not include recovery of the remaining book value of any generating units retired could have a material impact on Southern Company's and Mississippi Power's financial statements. The ultimate outcome of this matter cannot be determined at this time. See Note 3 under "Other Matters – Mississippi Power" for additional information on Plant Daniel Units 1 and 2.

Performance Evaluation Plan

Mississippi Power's retail base rates generally are set under the PEP, a rate plan approved by the Mississippi PSC. Typically, two PEP filings are made for each calendar year: the PEP projected filing, which is typically filed prior to the beginning of the year based on a projected revenue requirement, and the PEP lookback filing, which is filed after the end of the year and allows for review of the actual revenue requirement compared to the projected filing.

In February 2018, Mississippi Power revised its annual projected PEP filing for 2018 to reflect the impacts of the Tax Reform Legislation. The revised filing requested an increase of $26 million in annual revenues, based on a performance adjusted ROE of 9.33% and an increased equity ratio of 55%. In July 2018, Mississippi Power and the MPUS entered into a settlement agreement, which was approved by the Mississippi PSC in August 2018, with respect to the 2018 PEP filing and all unresolved PEP filings for prior years (PEP Settlement Agreement). Rates under the PEP Settlement Agreement became effective with the first billing cycle of September 2018. The PEP Settlement Agreement provided for an increase of approximately $21.6 million in annual base retail revenues, which excluded certain compensation costs contested by the MPUS, as well as approximately $2 million subsequently approved for recovery through the 2018 Energy Efficiency Cost Rider. Under the PEP Settlement Agreement, Mississippi Power deferred a portion of the contested compensation costs for 2018 and 2019 as a regulatory asset, which totaled $4 million as of December 31, 2019 and is included in other regulatory assets, deferred on the balance sheet. The Mississippi PSC is expected to rule on the appropriate treatment for such costs in connection with the Mississippi Power 2019 Base Rate Case. The ultimate outcome of this matter cannot be determined at this time.

Pursuant to the PEP Settlement Agreement, Mississippi Power's performance-adjusted allowed ROE is 9.31% and its allowed equity ratio is capped at 51%, pending further review by the Mississippi PSC. In lieu of the requested equity ratio increase, Mississippi Power retained $44 million of excess accumulated deferred income taxes resulting from the Tax Reform Legislation

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until the conclusion of the Mississippi Power 2019 Base Rate Case. Further, Mississippi Power agreed to seek equity contributions sufficient to restore its equity ratio to 50% by December 31, 2018. Since Mississippi Power's actual average equity ratio for 2018 was more than 1% lower than the 50% target, Mississippi Power deferred the corresponding difference in its revenue requirement of approximately $4 million as a regulatory liability for resolution in the Mississippi Power 2019 Base Rate Case. Pursuant to the PEP Settlement Agreement, PEP proceedings are suspended until after the conclusion of the Mississippi Power 2019 Base Rate Case and Mississippi Power was not required to make any PEP filings for regulatory years 2018, 2019, and 2020. The PEP Settlement Agreement also resolved all open PEP filings with no change to customer rates.

Energy Efficiency

In May 2018, the Mississippi PSC issued an order approving Mississippi Power's revised annual projected Energy Efficiency Cost Rider 2018 compliance filing, which increased annual retail revenues by approximately $3 million effective with the first billing cycle for June 2018.

On February 5, 2019, the Mississippi PSC issued an order approving Mississippi Power's Energy Efficiency Cost Rider 2019 compliance filing, which included a slight decrease in annual retail revenues, effective with the first billing cycle in March 2019.

As part of the Mississippi Power 2019 Base Rate Case, Mississippi Power has proposed that the Energy Efficiency Cost Rider be eliminated and those costs be included in the PEP. The ultimate outcome of this matter cannot be determined at this time.

Environmental Compliance Overview Plan

In accordance with a 2011 accounting order from the Mississippi PSC, Mississippi Power has the authority to defer in a regulatory asset for future recovery all plant retirement- or partial retirement-related costs resulting from environmental regulations. The Mississippi PSC approved $41 million and $17 million of costs that were reclassified to regulatory assets associated with the fuel conversion of Plant Watson and Plant Greene County, respectively, for amortization over five-year periods ending in July 2021 and July 2022, respectively.

In August 2018, the Mississippi PSC approved an annual increase in revenues related to the ECO Plan of approximately $17 million, effective with the first billing cycle for September 2018. This increase represented the maximum 2% annual increase in revenues and primarily related to the carryforward from the prior year.

The increase was the result of Mississippi PSC approval of an agreement between Mississippi Power and the MPUS to settle the 2018 ECO Plan filing (ECO Settlement Agreement) and was sufficient to recover costs through 2019, including remaining amounts deferred from prior years along with the related carrying costs. In accordance with the ECO Settlement Agreement, ECO Plan proceedings are suspended until after the conclusion of the Mississippi Power 2019 Base Rate Case and Mississippi Power was not required to make any ECO Plan filings for 2018, 2019, and 2020, with any necessary adjustments reflected in the Mississippi Power 2019 Base Rate Case. The ECO Settlement Agreement contains the same terms as the PEP Settlement Agreement described herein with respect to allowed ROE and equity ratio. At December 31, 2019, Mississippi Power has recorded $2 million in other regulatory liabilities, deferred on the balance sheet related to the actual December 31, 2018 average equity ratio differential from target applicable to the ECO Plan.

On October 24, 2019, the Mississippi PSC approved Mississippi Power's July 9, 2019 request for a CPCN to complete certain environmental compliance projects, primarily associated with the Plant Daniel coal units co-owned 50% with Gulf Power. The total estimated cost is approximately $125 million, with Mississippi Power's share of approximately $66 million being proposed for recovery through its ECO Plan. Approximately $17 million of Mississippi Power's share is associated with ash pond closure and is reflected in Mississippi Power's ARO liabilities. See Note 6 for additional information on AROs and Note 3 under "Other Matters – Mississippi Power" for additional information on Gulf Power's ownership in Plant Daniel.

Fuel Cost Recovery

Mississippi Power annually establishes and is required to file for an adjustment to the retail fuel cost recovery factor that is approved by the Mississippi PSC. The Mississippi PSC approved an increase of $39 million effective February 2018 and decreases of $35 million and $24 million, effective in February 2019 and 2020, respectively. At December 31, 2019 and 2018, over recovered retail fuel costs included in other current liabilities on Southern Company's balance sheets and over recovered regulatory clause liabilities on Mississippi Power's balance sheets were approximately $23 million and $8 million, respectively.

Mississippi Power has wholesale MRA and Market Based (MB) fuel cost recovery factors. Effective with the first billing cycle for January 2019, the wholesale MRA fuel rate increased $16 million annually and the wholesale MB fuel rate decreased by an immaterial amount. Effective January 1, 2020, the wholesale MRA fuel rate increased $1 million annually and the wholesale MB fuel rate decreased by an immaterial amount. At December 31, 2019 and 2018, over recovered wholesale MRA fuel costs included in other current liabilities on Southern Company's balance sheets and over recovered regulatory clause liabilities on

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Mississippi Power's balance sheets were approximately $6 million. At December 31, 2019 and 2018, over/under recovered wholesale MB fuel costs included in the balance sheets were immaterial.

Mississippi Power's operating revenues are adjusted for differences in actual recoverable fuel cost and amounts billed in accordance with the currently approved cost recovery rate. Accordingly, changes in the billing factor should have no significant effect on Mississippi Power's revenues or net income but will affect operating cash flows.

Ad Valorem Tax Adjustment

Mississippi Power establishes annually an ad valorem tax adjustment factor that is approved by the Mississippi PSC to collect the ad valorem taxes paid by Mississippi Power. In 2019, 2018, and 2017, the Mississippi PSC approved Mississippi Power's annual ad valorem tax adjustment factor filing, which included rate increases of $2 million, $7 million, and $8 million in 2019, 2018, and 2017, respectively.

System Restoration Rider

Mississippi Power carries insurance for the cost of certain types of damage to generation plants and general property. However, Mississippi Power is self-insured for the cost of storm, fire, and other uninsured casualty damage to its property, including transmission and distribution facilities. As permitted by the Mississippi PSC and the FERC, Mississippi Power accrues for the cost of such damage through an annual expense accrual credited to regulatory liability accounts for the retail and wholesale jurisdictions. The cost of repairing actual damage resulting from such events that individually exceed $50,000 is charged to the reserve. Every three years the Mississippi PSC, the MPUS, and Mississippi Power agree on SRR revenue level(s) for the ensuing period, based on historical data, expected exposure, type and amount of insurance coverage, excluding insurance cost, and any other relevant information. The accrual amount and the reserve balance are determined based on the SRR revenue level(s). If a significant change in circumstances occurs, then the SRR revenue level can be adjusted more frequently if Mississippi Power and the MPUS or the Mississippi PSC deem the change appropriate. The property damage reserve accrual will be the difference between the approved SRR revenues and the SRR revenue requirement, excluding any accrual to the reserve. In addition, SRR allows Mississippi Power to set up a regulatory asset, pending review, if the allowable actual retail property damage costs exceed the amount in the retail property damage reserve. Mississippi Power made retail accruals of $1 million, $1 million, and $3 million for 2019, 2018, and 2017, respectively. Mississippi Power also accrued $0.3 million annually in 2019, 2018, and 2017 for the wholesale jurisdiction. As of December 31, 2019, the property damage reserve balances were $54 million and $1 million for retail and wholesale, respectively.

The SRR rate was zero for all years presented and Mississippi Power accrued $1 million, $2 million, and $4 million to the property damage reserve in 2019, 2018, and 2017, respectively.

Kemper County Energy Facility

Overview

The Kemper County energy facility was designed to utilize IGCC technology with an expected output capacity of 582 MWs and to be fueled by locally mined lignite (an abundant, lower heating value coal) from a mine owned by Mississippi Power and situated adjacent to the Kemper County energy facility.

Schedule and Cost Estimate

In 2012, the Mississippi PSC issued an order confirming the CPCN originally approved by the Mississippi PSC in 2010 authorizing the acquisition, construction, and operation of the Kemper County energy facility. The 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 County energy facility 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 County energy facility in service in August 2014. The combined cycle and associated common facilities portions of the Kemper County energy facility were dedicated as Plant Ratcliffe in April 2018.

In June 2017, the Mississippi PSC stated its intent to issue an order, which occurred in July 2017, directing Mississippi Power to pursue a settlement under which the Kemper County energy facility would be operated as a natural gas plant, rather than an IGCC plant, and address all issues associated with the Kemper County energy facility. The order established a new docket for the purpose of pursuing a global settlement of the related costs (Kemper Settlement Docket). In June 2017, Mississippi Power notified the Mississippi PSC that it would begin a process to suspend operations and start-up activities on the gasifier portion of the Kemper County energy facility, given the uncertainty as to its future.

At the time of project suspension in June 2017, the total cost estimate for the Kemper County energy facility was approximately $7.38 billion, including approximately $5.95 billion of costs subject to the construction cost cap, net of $137 million in additional

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grants from the DOE received in April 2016. In the aggregate, Mississippi Power had recorded charges to income of $3.07 billion ($1.89 billion after tax) as a result of changes in the cost estimate above the cost cap for the Kemper IGCC through May 2017.

Given the Mississippi PSC's stated intent regarding no further rate increase for the Kemper County energy facility and the subsequent suspension, cost recovery of the gasifier portions became no longer probable; therefore, Mississippi Power recorded an additional charge to income in June 2017 of $2.8 billion ($2.0 billion after tax), which included estimated costs associated with the gasification portions of the plant and lignite mine. During the third and fourth quarters of 2017, Mississippi Power recorded charges to income of $242 million ($206 million after tax), including $164 million for ongoing project costs, estimated mine and gasifier-related costs, and certain termination costs during the suspension period prior to conclusion of the Kemper Settlement Docket, as well as the charge associated with the Kemper Settlement Agreement discussed below.

In 2019, Mississippi Power recorded pre-tax and after-tax charges to income of $24 million, primarily associated with the expected close out of a related DOE contract, as well as other abandonment and related closure costs and ongoing period costs, net of salvage proceeds, for the mine and gasifier-related assets. The after-tax amount for 2019 includes an adjustment related to the tax abandonment of the Kemper IGCC following the filing of the 2018 tax return. In 2018, Mississippi Power recorded pre-tax charges to income of $37 million ($68 million benefit after tax), primarily associated with abandonment and related closure costs and ongoing period costs, net of salvage proceeds, for the mine and gasifier-related assets, as well as the impact of a change in the valuation allowance for the related state income tax NOL carryforward.

Mississippi Power expects to substantially complete mine reclamation activities in 2020 and dismantlement of the abandoned gasifier-related assets and site restoration activities are expected to be completed in 2024. The additional pre-tax period costs associated with dismantlement and site restoration activities, including related costs for compliance and safety, ARO accretion, and property taxes, are estimated to total $17 million in 2020, $15 million to $16 million annually in 2021 through 2023, and $5 million in 2024.

See Note 10 for additional information.

Rate Recovery

In February 2018, the Mississippi PSC voted to approve a settlement agreement related to cost recovery for the Kemper County energy facility among Mississippi Power, the MPUS, and certain intervenors (Kemper Settlement Agreement), which resolved all cost recovery issues, modified the CPCN to limit the Kemper County energy facility to natural gas combined cycle operation, and provided for an annual revenue requirement of approximately $99.3 million for costs related to the Kemper County energy facility, which included the impact of the Tax Reform Legislation. The revenue requirement was based on (i) a fixed ROE for 2018 of 8.6% excluding any performance adjustment, (ii) a ROE for 2019 calculated in accordance with PEP, excluding the performance adjustment, (iii) for future years, a performance-based ROE calculated pursuant to PEP, and (iv) amortization periods for the related regulatory assets and liabilities of eight years and six years, respectively. The revenue requirement also reflects a disallowance related to a portion of Mississippi Power's investment in the Kemper County energy facility requested for inclusion in rate base, which was recorded in the fourth quarter 2017 as an additional charge to income of approximately $78 million ($85 million net of accumulated depreciation of $7 million) pre-tax ($48 million after tax).

Under the Kemper Settlement Agreement, retail customer rates were reduced by approximately $26.8 million annually, effective with the first billing cycle of April 2018, and include no recovery for costs associated with the gasifier portion of the Kemper County energy facility in 2018 or at any future date.

On November 26, 2019, Mississippi Power filed the Mississippi Power 2019 Base Rate Case, which reflects the elimination of separate rates for costs associated with the Kemper County energy facility; these costs are proposed to be included in rates for PEP, ECO Plan, and ad valorem tax adjustment factor, as applicable. The ultimate outcome of this matter cannot be determined at this time.

Lignite Mine and CO₂ Pipeline Facilities

Mississippi Power owns the lignite mine and equipment and mineral reserves located around the Kemper County energy facility site. The mine started commercial operation in June 2013. In connection with the Kemper County energy facility construction, Mississippi Power also constructed a pipeline for the transport of captured CO₂.

In 2010, Mississippi Power executed a 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 responsible for the mining operations 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. As a result of the

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abandonment of the Kemper IGCC, final mine reclamation began in 2018 and is expected to be substantially completed in 2020, with monitoring expected to continue through 2027. See Note 6 for additional information.

On December 31, 2019, Mississippi Power transferred ownership of the CO₂ pipeline to an unrelated gas pipeline company, with no resulting impact on income. In conjunction with the transfer of the CO₂ pipeline, the parties agreed to enter into a 15-year firm transportation agreement, which is expected to be signed by March 2020, providing for the conversion by the pipeline company of the CO₂ pipeline to a natural gas pipeline to be used for the delivery of natural gas to Plant Ratcliffe. The agreement will be treated as a finance lease for accounting purposes upon commencement, which is expected to occur by August 2020. See Note 9 for additional information.

Government Grants

In 2010, the DOE, through a cooperative agreement with SCS, agreed to fund $270 million of the Kemper County energy facility through the grants awarded to the project by the DOE under the Clean Coal Power Initiative Round 2. In 2016, additional DOE grants in the amount of $137 million were awarded to the Kemper County energy facility. Through December 31, 2018, Mississippi Power received total DOE grants of $387 million, of which $382 million reduced the construction costs of the Kemper County energy facility and $5 million reimbursed Mississippi Power for expenses associated with DOE reporting. In December 2018, Mississippi Power filed with the DOE its request for property closeout certification under the contract related to the $387 million of grants received. Mississippi Power expects to close out the DOE contract related to the Kemper County energy facility in 2020. In connection with the DOE closeout discussions, on April 29, 2019, the Civil Division of the Department of Justice informed Southern Company and Mississippi Power of an investigation related to the Kemper County energy facility. The ultimate outcome of this matter cannot be determined at this time; however, it could have a material impact on Southern Company's and Mississippi Power's financial statements.

Municipal and Rural Associations Tariff

Mississippi Power provides wholesale electric service to Cooperative Energy, East Mississippi Electric Power Association, and the City of Collins, all located in southeastern Mississippi, under a long-term, cost-based, FERC-regulated MRA tariff.

In 2017, Mississippi Power and Cooperative Energy executed, and the FERC accepted, a Shared Service Agreement (SSA), as part of the MRA tariff, under which Mississippi Power and Cooperative Energy will share in providing electricity to the Cooperative Energy delivery points under the tariff, effective January 1, 2018. The SSA may be cancelled by Cooperative Energy with 10 years notice after December 31, 2020. As of December 31, 2019, Cooperative Energy has the option to decrease its use of Mississippi Power's generation services under the MRA tariff up to 2.5% annually, with required notice, up to a maximum total reduction of 11%, or approximately $9 million in cumulative annual base revenues.

On May 7, 2019, the FERC accepted Mississippi Power's requested $3.7 million annual decrease in MRA base rates effective January 1, 2019, as agreed upon in a settlement agreement reached with its wholesale customers resolving all matters related to the Kemper County energy facility, similar to the retail rate settlement agreement approved by the Mississippi PSC in February 2018, and reflecting the impacts of the Tax Reform Legislation.

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Southern Company Gas

Regulatory Assets and Liabilities

Regulatory assets and (liabilities) reflected in the balance sheets of Southern Company Gas at December 31, 2019 and 2018 relate to:

	2019				2018				Note
	(in millions)
Environmental remediation	$	296			$	311			(a,b)
Retiree benefit plans	167				161				(a,c)
Long-term debt fair value adjustment	107				121				(d)
Under recovered regulatory clause revenues	72				90				(e)
Other regulatory assets	68				59				(f)
Other cost of removal obligations	(1,606		)		(1,585		)		(g)
Deferred income tax credits	(874		)		(940		)		(g,i)
Over recovered regulatory clause revenues	(82		)		(43		)		(e)
Other regulatory liabilities	(22		)		(46		)		(h)
Total regulatory assets (liabilities), net	$	(1,874	)		$	(1,872	)

Note: Unless otherwise noted, the recovery and amortization periods for these regulatory assets and (liabilities) have been approved or accepted by the relevant state PSC or other regulatory body and are as follows:

(a)	Not earning a return as offset in rate base by a corresponding asset or liability.

(b)	Recovered through environmental cost recovery mechanisms when the remediation work is performed. See Note 3 for additional information.

(c)	Recovered and amortized over the average remaining service period which range up to 15 years. See Note 11 for additional information.

(d)	Recovered over the remaining life of the original debt issuances at acquisition, which range up to 19 years as of December 31, 2019.

(e)	Recorded and recovered or amortized over periods generally not exceeding six years. In addition to natural gas cost recovery mechanisms, the natural gas distribution utilities have various other cost recovery mechanisms for the recovery of costs, including those related to infrastructure replacement programs.

(f)

Includes financial instrument-hedging assets totaling $11 million and $8 million at December 31, 2019 and 2018, respectively, which are recorded over the life of the underlying hedged purchase contracts generally not exceeding two years, vacation pay assets totaling $11 million at both December 31, 2019 and 2018, which are recorded as earned by employees and recovered as paid, generally within one year, and several other miscellaneous components, which are recovered or amortized over periods generally not exceeding eight years.

(g)	Other cost of removal obligations are recorded and deferred income tax liabilities are amortized over the related property lives, which may range up to 80 years. Cost of removal liabilities will be settled and trued up following completion of the related activities.

(h)

Comprised of numerous components, including amounts to be refunded to customers as a result of the Tax Reform Legislation and energy efficiency programs, which are recovered or amortized over remaining periods generally not exceeding 20 years. Upon final settlement, actual energy efficiency program costs incurred are recovered, and actual income earned is refunded through the energy cost recovery clause. See "Rate Proceedings" herein for additional information regarding customer refunds resulting from the Tax Reform Legislation.

(i)	As of December 31, 2019, includes $12 million of excess deferred income tax liabilities not subject to normalization as a result of the Tax Reform Legislation which are being amortized through 2024. See "Rate Proceedings" herein and Note 10 for additional details.

Infrastructure Replacement Programs and Capital Projects

In addition to capital expenditures recovered through base rates by each of the natural gas distribution utilities, Nicor Gas and Virginia Natural Gas have separate rate riders that provide timely recovery of capital expenditures for specific infrastructure replacement programs. Descriptions of the infrastructure replacement programs and capital projects at the natural gas distribution utilities follow.

Nicor Gas

In 2013, Illinois enacted legislation that allows Nicor Gas to provide more widespread safety and reliability enhancements to its distribution system. The legislation stipulates that rate increases to customers as a result of any infrastructure investments shall not exceed a cumulative annual average of 4.0% or, in any given year, 5.5% of base rate revenues. In 2014, the Illinois Commission approved the nine-year regulatory infrastructure program, Investing in Illinois, subject to annual review. In conjunction with the base rate case order issued by the Illinois Commission in January 2018, Nicor Gas is recovering program costs incurred prior to December 31, 2017 through base rates. Additionally, the Illinois Commission's approval of Nicor Gas' rate case on October 2, 2019 included $65 million in annual revenues related to the recovery of program costs from January 1, 2018 through September 30, 2019 under the Investing in Illinois program. See "Rate Proceedings" herein for additional information.

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Virginia Natural Gas

In 2012, the Virginia Commission approved the Steps to Advance Virginia's Energy (SAVE) program, an accelerated infrastructure replacement program. In 2016 and on September 25, 2019, the Virginia Commission approved amendments and extensions to the SAVE program. The latest extension allows Virginia Natural Gas to continue replacing aging pipeline infrastructure through 2024 and increases its authorized investment under the previously-approved plan from $35 million to $40 million in 2019 with additional annual investments of $50 million in 2020, $60 million in 2021, $70 million in each year from 2022 through 2024, and a total potential variance of up to $5 million allowed for the program, for a maximum total investment over the six-year term (2019 through 2024) of $365 million.

The SAVE program is subject to annual review by the Virginia Commission. In accordance with the base rate case order issued by the Virginia Commission in 2017, Virginia Natural Gas is recovering program costs incurred prior to September 1, 2017 through base rates. Program costs incurred subsequent to September 1, 2017 are currently recovered through a separate rider and are subject to future base rate case proceedings.

On December 6, 2019, Virginia Natural Gas filed an application with the Virginia Commission for a 24.1-mile header improvement project to improve resiliency and increase the supply of natural gas delivered to energy suppliers, including Virginia Natural Gas. The cost of the project is expected to total $346 million. The Virginia Commission is expected to rule on this application in the second quarter 2020. Construction is expected to begin in June 2021 and the project is expected to be placed in service in the fourth quarter 2022. The ultimate outcome of this matter cannot be determined at this time.

Atlanta Gas Light

GRAM

In December 2019, the Georgia PSC approved the continuation of GRAM as part of Atlanta Gas Light's 2019 rate case order. Various infrastructure programs previously authorized by the Georgia PSC, including the Integrated Vintage Plastic Replacement Program to replace aging plastic pipe and the Integrated System Reinforcement Program to upgrade Atlanta Gas Light's distribution system and LNG facilities in Georgia, continue under GRAM and the recovery of and return on the infrastructure program investments are included in annual base rate adjustments. The future expected costs to be recovered through rates related to allowed, but not incurred, costs are recognized in an unrecognized ratemaking amount that is not reflected on the balance sheets. This allowed cost is primarily the equity return on the capital investment under the infrastructure programs in place prior to GRAM. See "Unrecognized Ratemaking Amounts" herein for additional information. The Georgia PSC reviews Atlanta Gas Light's performance annually under GRAM. See "Rate Proceedings" herein for additional information.

Pursuant to the GRAM approval, Atlanta Gas Light and the staff of the Georgia PSC agreed to a variation of the Integrated Customer Growth Program to extend pipeline facilities to serve customers in areas without pipeline access and create new economic development opportunities in Georgia. As a result, a new tariff was created, effective October 10, 2017, to provide up to $15 million annually for Atlanta Gas Light to commit to strategic economic development projects. Projects under this tariff must be approved by the Georgia PSC.

PRP

Atlanta Gas Light previously recovered PRP costs through a PRP surcharge established in 2015 to address recovery of the under recovered PRP balance and the related carrying costs. The under recovered balance at December 31, 2019 was $135 million, including $70 million of unrecognized equity return. Effective January 2018, PRP costs are being recovered through GRAM and base rates until the earlier of the full recovery of the under recovered amount or December 31, 2025.

One of the capital projects under the PRP experienced construction issues and Atlanta Gas Light was required to complete mitigation work prior to placing it in service. These mitigation costs were included in base rates in 2018. In 2017, Atlanta Gas Light recovered $20 million from the settlement of contractor litigation claims and recovered an additional $7 million from the final settlement of contractor litigation claims during the first quarter 2018. Mitigation costs recovered through the legal process are retained by Atlanta Gas Light.

Natural Gas Cost Recovery

With the exception of Atlanta Gas Light, the natural gas distribution utilities are authorized by the relevant regulatory agencies in the states in which they serve to use natural gas cost recovery mechanisms that adjust rates to reflect changes in the wholesale cost of natural gas and ensure recovery of all costs prudently incurred in purchasing natural gas for customers. Natural gas cost recovery revenues are adjusted for differences in actual recoverable natural gas costs and amounts billed in current regulated rates. Changes in the billing factor will not have a significant effect on Southern Company's or Southern Company Gas' revenues or net income, but will affect cash flows. At December 31, 2019 and 2018, the over recovered balances were $74 million and

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$15 million, respectively, which were included in other regulatory liabilities on Southern Company's and Southern Company Gas' balance sheets.

Rate Proceedings

Nicor Gas

In January 2018, the Illinois Commission approved a $137 million increase in annual base rate revenues, including $93 million related to the recovery of investments under the Investing in Illinois program, effective in February 2018, based on a ROE of 9.8%. In May 2018, the Illinois Commission approved Nicor Gas' rehearing request for revised base rates to incorporate the reduction in the federal income tax rate as a result of the Tax Reform Legislation. The resulting decrease of approximately $44 million in annual base rate revenues became effective May 5, 2018. The benefits of the Tax Reform Legislation from January 25, 2018 through May 4, 2018 were refunded to customers via bill credits and concluded in the second quarter 2019.

In November 2018, Nicor Gas filed a general base rate case with the Illinois Commission. On October 2, 2019, the Illinois Commission approved a $168 million annual base rate increase effective October 8, 2019. The base rate increase included $65 million related to the recovery of program costs under the Investing in Illinois program and was based on a ROE of 9.73% and an equity ratio of 54.2%. Additionally, the Illinois Commission approved a volume balancing adjustment, a revenue decoupling mechanism for residential customers that provides a monthly benchmark level of revenue per rate class for recovery.

Atlanta Gas Light

In February 2018, Atlanta Gas Light revised its annual base rate filing to reflect the impacts of the Tax Reform Legislation and requested a $16 million rate reduction. In May 2018, the Georgia PSC approved a stipulation for Atlanta Gas Light's annual base rates to remain at the 2017 level for 2018 and 2019, with customer credits of $8 million in each of July 2018 and October 2018 to reflect the impacts of the Tax Reform Legislation. The Georgia PSC maintained Atlanta Gas Light's previously authorized earnings band based on a ROE between 10.55% and 10.95% and increased the allowed equity ratio by 4% to an equity ratio of 55% to address the negative cash flow and credit metric impacts of the Tax Reform Legislation.

On June 3, 2019, Atlanta Gas Light filed a general base rate case with the Georgia PSC. On December 19, 2019, the Georgia PSC approved a $65 million annual base rate increase, effective January 1, 2020, based on a ROE of 10.25% and an equity ratio of 56%. Earnings will be evaluated against a ROE range of 10.05% to 10.45%, with disposition of any earnings above 10.45% to be determined by the Georgia PSC. Additionally, the Georgia PSC approved continuation of the previously authorized inclusion in base rates of the recovery of and return on the infrastructure program investments, including, but not limited to, GRAM adjustments, and a reauthorization and continuation of GRAM until terminated by the Georgia PSC. GRAM filing rate adjustments will be based on the authorized ROE of 10.25%. GRAM adjustments for 2021 may not exceed 5% of 2020 base rates. The 5% limitation does not set a precedent in any future rate proceedings by Atlanta Gas Light.

On January 31, 2020, in accordance with the Georgia PSC's order for the 2019 rate case, Atlanta Gas Light filed a recommended notice of proposed rulemaking for a long-range planning tool. The proposal provides for participating natural gas utilities to file a comprehensive capacity supply and related infrastructure delivery plan for a 10-year period, including capital and related operations and maintenance expense budgets. Participating natural gas utilities would file an updated 10-year plan at least once every third year under the proposal. Related costs of implementing an approved comprehensive plan would be included in the utility's next rate case or GRAM filing. The rulemaking process is expected to be completed during 2020.

Virginia Natural Gas

In 2017, the Virginia Commission approved a settlement for a $34 million increase in annual base rate revenues, effective September 1, 2017, including $13 million related to the recovery of investments under the SAVE program. See "Infrastructure Replacement Programs and Capital Projects" herein for additional information. An authorized ROE range of 9.0% to 10.0% with a midpoint of 9.5% will be used to determine the revenue requirement in any filing, other than for a change in base rates.

In December 2018, the Virginia Commission approved Virginia Natural Gas' annual information form filing, which reduced annual base rates by $14 million effective January 1, 2019 due to lower tax expense as a result of the Tax Reform Legislation, along with customer refunds, via bill credits, for $14 million related to 2018 tax benefits deferred as a regulatory liability at December 31, 2018. These customer refunds were completed in the first quarter 2019.

On February 3, 2020, Virginia Natural Gas filed a notice of intent with the Virginia Commission as required prior to the filing of a base rate case, which will occur between April 3, 2020 and April 30, 2020. The ultimate outcome of this matter cannot be determined at this time.

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Unrecognized Ratemaking Amounts

The following table illustrates Southern Company Gas' authorized ratemaking amounts that are not recognized on its balance sheets. These amounts are primarily composed of an allowed equity rate of return on assets associated with certain regulatory infrastructure programs. These amounts will be recognized as revenues in Southern Company Gas' financial statements in the periods they are billable to customers, the majority of which will be recovered by 2025.

	December 31, 2019				December 31, 2018
	(in millions)
Atlanta Gas Light	$	70			$	95
Virginia Natural Gas	10				11
Nicor Gas	2				4
Total	$	82			$	110

General Litigation Matters

The Registrants are involved in various other matters being litigated and regulatory matters. The ultimate outcome of such pending or potential litigation or regulatory matters against each Registrant and any subsidiaries cannot be determined 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 such Registrant's financial statements.

The Registrants believe the pending legal challenges discussed below have no merit; however, the ultimate outcome of these matters cannot be determined at this time.

Southern Company

In January 2017, a securities class action complaint was filed against Southern Company, certain of its officers, and certain former Mississippi Power officers in the U.S. District Court for the Northern District of Georgia 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, certain of its officers, and certain former Mississippi Power officers made materially false and misleading statements regarding the Kemper County energy facility 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. In 2017, the plaintiffs filed an amended complaint that provided additional detail about their claims, increased the purported class period by one day, and added certain other former Mississippi Power officers as defendants. Also in 2017, the defendants filed a motion to dismiss the plaintiffs' amended complaint with prejudice, to which the plaintiffs filed an opposition. In March 2018, the court issued an order granting, in part, the defendants' motion to dismiss. The court dismissed certain claims against certain officers of Southern Company and Mississippi Power and dismissed the allegations related to a number of the statements that plaintiffs challenged as being false or misleading. In April 2018, the defendants filed a motion for reconsideration of the court's order, seeking dismissal of the remaining claims in the lawsuit. In August 2018, the court denied the motion for reconsideration and denied a motion to certify the issue for interlocutory appeal. On August 22, 2019, the court certified the plaintiffs' proposed class. On September 5, 2019, the defendants filed a petition for interlocutory appeal of the class certification order with the U.S. Court of Appeals for the Eleventh Circuit. On December 19, 2019, the U.S. District Court for the Northern District of Georgia entered an order staying all deadlines in the case pending mediation. The stay automatically expires on March 31, 2020.

In February 2017, Jean Vineyard and Judy Mesirov each filed a shareholder derivative lawsuit in the U.S. District Court for the Northern District of Georgia. Each of these lawsuits names as defendants Southern Company, certain of its directors, certain of its officers, and certain former Mississippi Power officers. In 2017, these two shareholder derivative lawsuits were consolidated in the U.S. District Court for the Northern District of Georgia. The complaints allege that the defendants caused Southern Company to make false or misleading statements regarding the Kemper County energy facility cost and schedule. Further, the complaints allege that the defendants were unjustly enriched and caused the waste of corporate assets and also allege that the individual defendants violated their fiduciary duties. Each plaintiff seeks to recover, on behalf of Southern Company, unspecified actual damages and, on each plaintiff's own behalf, attorneys' fees and costs in bringing the lawsuit. Each plaintiff also seeks certain changes to Southern Company's corporate governance and internal processes. In April 2018, the court entered an order staying this lawsuit until 30 days after the resolution of any dispositive motions or any settlement, whichever is earlier, in the securities class action.

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In May 2017, Helen E. Piper Survivor's Trust filed a shareholder derivative lawsuit in the Superior Court of Gwinnett County, Georgia that names as defendants Southern Company, certain of its directors, certain of its officers, and certain former Mississippi Power officers. The complaint alleges that the individual defendants, among other things, breached their fiduciary duties in connection with schedule delays and cost overruns associated with the construction of the Kemper County energy facility. The complaint further alleges that the individual defendants authorized or failed to correct false and misleading statements regarding the Kemper County energy facility schedule and cost and failed to implement necessary internal controls to prevent harm to Southern Company. The plaintiff seeks to recover, on behalf of Southern Company, unspecified actual damages and disgorgement of profits and, on its behalf, attorneys' fees and costs in bringing the lawsuit. The plaintiff also seeks certain unspecified changes to Southern Company's corporate governance and internal processes. In May 2018, the court entered an order staying this lawsuit until 30 days after the resolution of any dispositive motions or any settlement, whichever is earlier, in the securities class action. On August 5, 2019, the court granted a motion filed by the plaintiff on July 17, 2019 to substitute a new named plaintiff, Martin J. Kobuck, in place of Helen E. Piper Survivor's Trust.

Georgia Power

In 2011, plaintiffs filed a putative class action against Georgia Power in the Superior Court of Fulton County, Georgia alleging that Georgia Power's collection in rates of amounts for municipal franchise fees (which fees are paid to municipalities) exceeded the amounts allowed in orders of the Georgia PSC and alleging certain state tort law claims. In 2016, the Georgia Court of Appeals reversed the trial court's previous dismissal of the case and remanded the case to the trial court. Georgia Power filed a petition for writ of certiorari with the Georgia Supreme Court, which was granted in 2017. In June 2018, the Georgia Supreme Court affirmed the judgment of the Georgia Court of Appeals and remanded the case to the trial court for further proceedings. Following a motion by Georgia Power, on February 13, 2019, the Superior Court of Fulton County ordered the parties to submit petitions to the Georgia PSC for a declaratory ruling to address certain terms the court previously held were ambiguous as used in the Georgia PSC's orders. The order entered by the Superior Court of Fulton County also conditionally certified the proposed class. In March 2019, Georgia Power and the plaintiffs filed petitions with the Georgia PSC seeking confirmation of the proper application of the municipal franchise fee schedule pursuant to the Georgia PSC's orders. On October 23, 2019, the Georgia PSC issued an order that found and concluded that Georgia Power has appropriately implemented the municipal franchise fee schedule. On March 6, 2019, Georgia Power filed a notice of appeal with the Georgia Court of Appeals regarding the Superior Court of Fulton County's February 2019 order. The amount of any possible losses cannot be calculated at this time because, among other factors, it is unknown whether conditional class certification will be upheld and the ultimate composition of any class and whether any losses would be subject to recovery from any municipalities.

Mississippi Power

In May 2018, Southern Company and Mississippi Power received a notice of dispute and arbitration demand filed by Martin Product Sales, LLC (Martin) based on two agreements, both related to Kemper IGCC byproducts for which Mississippi Power provided termination notices in 2017. Martin alleges breach of contract, breach of good faith and fair dealing, fraud and misrepresentation, and civil conspiracy and makes a claim for damages in the amount of approximately $143 million, as well as additional unspecified damages, attorney's fees, costs, and interest. A portion of the claim for damages was on behalf of Martin Transport, Inc. (Martin Transport), an affiliate of Martin. In the first quarter 2019, Mississippi Power and Southern Company filed motions to dismiss, which were denied by the arbitration panel on May 10, 2019. On September 27, 2019, Martin Transport filed a separate complaint against Mississippi Power in the Circuit Court of Kemper County, Mississippi alleging claims of fraud, negligent misrepresentation, promissory estoppel, and equitable estoppel, each arising out of the same alleged facts and circumstances that underlie Martin's arbitration demand. Martin Transport seeks compensatory damages of $5 million and punitive damages of $50 million. In November 2019, Martin Transport's claim was combined with the Martin arbitration case and the separate court case was dismissed. On December 16, 2019, Southern Company and Mississippi Power each filed motions for summary judgment on all claims. On February 17, 2020, the arbitration panel granted Southern Company's motion and dismissed Southern Company from the arbitration. An adverse outcome in this proceeding could have a material impact on Southern Company's and Mississippi Power's financial statements.

In November 2018, Ray C. Turnage and 10 other individual plaintiffs filed a putative class action complaint against Mississippi Power and three members of the Mississippi PSC in the U.S. District Court for the Southern District of Mississippi. Mississippi Power received Mississippi PSC approval in 2013 to charge a mirror CWIP rate premised upon including in its rate base pre-construction and construction costs for the Kemper IGCC prior to placing the Kemper IGCC into service. The Mississippi Supreme Court reversed that approval and ordered Mississippi Power to refund the amounts paid by customers under the previously-approved mirror CWIP rate. The plaintiffs allege that the initial approval process, and the amount approved, were improper. They also allege that Mississippi Power underpaid customers by up to $23.5 million in the refund process by applying an incorrect interest rate. The plaintiffs seek to recover, on behalf of themselves and their putative class, actual damages, punitive

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damages, pre-judgment interest, post-judgment interest, attorney's fees, and costs. In response to Mississippi Power and the Mississippi PSC each filing a motion to dismiss, the plaintiffs filed an amended complaint on March 14, 2019. The amended complaint included four additional plaintiffs and additional claims for gross negligence, reckless conduct, and intentional wrongdoing. Mississippi Power and the Mississippi PSC have each filed a motion to dismiss the amended complaint. An adverse outcome in this proceeding could have a material impact on Mississippi Power's financial statements.

See Note 2 under "Kemper County Energy Facility" for additional information.

Southern Power

Southern Power indirectly owns a 51% membership interest in RE Roserock LLC (Roserock), the owner of the Roserock facility in Pecos County, Texas. Prior to the facility being placed in service in 2016, certain solar panels were damaged during installation by the construction contractor, McCarthy Building Companies, Inc. (McCarthy), and certain solar panels were damaged by a hail event that also occurred during construction. In connection therewith, Southern Power withheld payment of approximately $26 million to the construction contractor, which placed a lien on the Roserock facility for the same amount. In 2017, Roserock filed a lawsuit in the state district court in Pecos County, Texas against XL Insurance America, Inc. and North American Elite Insurance Company seeking recovery from an insurance policy for damages resulting from the hail event and McCarthy's installation practices. In June 2018, the court granted Roserock's motion for partial summary judgment, finding that the insurers were in breach of contract and in violation of the Texas Insurance Code for failing to pay any monies owed for the hail claim. Separate lawsuits were filed between Roserock and McCarthy, as well as other parties, and that litigation was consolidated in the U.S. District Court for the Western District of Texas. On April 18, 2019, Roserock and the parties to the state and federal lawsuits executed a settlement agreement and mutual release that resolved both lawsuits. Following execution of the agreement, the lawsuits were dismissed, Southern Power paid McCarthy the amounts previously withheld, and McCarthy released its lien. As part of the settlement, Roserock received funds that covered all related legal costs, damages, and the replacement costs of certain solar panels. Funds received by Southern Power in excess of the initial replacement costs were recognized as a gain and included in other income (expense), net, with a portion allocated to noncontrolling interests. As a result, Southern Power recognized a $12 million after-tax gain in the second quarter 2019.

Environmental Remediation

The Southern Company system must comply with environmental laws and regulations governing 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 conduct studies to determine the extent of any required cleanup and have recognized the estimated costs to clean up known impacted sites in the financial statements. A liability for environmental remediation costs is recognized only when a loss is determined to be probable and reasonably estimable. The traditional electric operating companies and the natural gas distribution utilities in Illinois and Georgia 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. At December 31, 2019 and 2018, the environmental remediation liabilities of Alabama Power and Mississippi Power were immaterial.

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. For all years presented, Georgia Power recovered approximately $2 million annually through the ECCR tariff. Effective January 1, 2020, Georgia Power is recovering approximately $12 million annually through the ECCR tariff under the 2019 ARP. Georgia Power recognizes a liability for environmental remediation costs only when it determines a loss is probable and reasonably estimable and reduces the reserve as expenditures are incurred. Any difference between the liabilities accrued and costs recovered through rates is deferred as a regulatory asset or liability. The annual recovery amount is expected to be adjusted in future regulatory proceedings.

On December 23, 2019, Mississippi Power entered into an agreement with the Mississippi Commission on Environmental Quality related to groundwater conditions arising from the closed ash pond at Plant Watson. Mississippi Power paid a civil penalty of $200,000 and will complete an assessment and remediation consistent with the requirements of the agreement and the CCR Rule. It is anticipated that corrective action will be needed; however, an estimate of remedial costs will not be available until further site assessment is completed. Mississippi Power expects to recover the retail portion of remedial costs through the ECO Plan and the wholesale portion through MRA rates.

Southern Company Gas is subject to environmental remediation liabilities associated with 40 former MGP sites in four different states. Southern Company Gas' accrued environmental remediation liability at December 31, 2019 and 2018 was based on the

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estimated cost of environmental investigation and remediation associated with known current and former MGP operating sites. These environmental remediation expenditures are generally recoverable from customers through rate mechanisms approved by the applicable state regulatory agencies of the natural gas distribution utilities.

At December 31, 2019 and 2018, the environmental remediation liability and the balance of under recovered environmental remediation costs were reflected in the balance sheets as follows:

	Southern Company			Georgia Power			Southern Company Gas
	(in millions)
December 31, 2019:
Environmental remediation liability:
Other current liabilities	$	51		$	15		$	36
Accrued environmental remediation	234			—			233
Under recovered environmental remediation costs:
Other regulatory assets, current	$	49		$	12		$	37
Other regulatory assets, deferred	300			40			260
December 31, 2018:
Environmental remediation liability:
Other current liabilities	$	49		$	23		$	26
Accrued environmental remediation	268			—			268
Under recovered environmental remediation costs:
Other regulatory assets, current	$	21		$	2		$	19
Other regulatory assets, deferred	345			53			292

The ultimate outcome of these matters cannot be determined at this time; however, as a result of the regulatory treatment for environmental remediation expenses described above, the final disposition of these matters is not expected to have a material impact on the financial statements of the applicable Registrants.

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 Farley, Hatch, and 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, Alabama Power and Georgia Power filed lawsuits against the U.S. government for the costs of continuing to store spent nuclear fuel at Plants Farley, Hatch, and 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. On June 12, 2019, the Court of Federal Claims granted Alabama Power's and Georgia Power's motion for summary judgment on damages not disputed by the U.S. government, awarding those undisputed damages to Alabama Power and Georgia Power. However, those undisputed damages are not collectible and no amounts will be recognized in the financial statements until the court enters final judgment on the remaining damages.

In 2017, Alabama Power and Georgia Power filed additional lawsuits against the U.S. government in the Court of Federal Claims for the costs of continuing to store spent nuclear fuel at Plants Farley, Hatch, and Vogtle Units 1 and 2 for the period from January 1, 2015 through December 31, 2017. Damages will continue to accumulate until the issue is resolved, the U.S. government disposes of Alabama Power's and Georgia Power's spent nuclear fuel pursuant to its contractual obligations, or alternative storage is otherwise provided. No amounts have been recognized in the financial statements as of December 31, 2019 for any potential recoveries from the pending lawsuits.

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The final outcome of these matters cannot be determined at this time. However, Alabama Power and Georgia Power expect to credit any recoveries for the benefit of customers in accordance with direction from their respective PSC; therefore, no material impact on Southern Company's, Alabama Power's, or Georgia Power'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.

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 $13.9 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 $450 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 $138 million per incident for each licensed reactor it operates but not more than an aggregate of $20 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 $275 million and $267 million, respectively, per incident, but not more than an aggregate of $41 million and $40 million, respectively, 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 November 1, 2023. See Note 5 under "Joint Ownership Agreements" 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 and policies 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. Alabama Power and Georgia Power each purchase limits based on the projected full cost of replacement power, subject to ownership limitations, and have each elected a 12-week deductible waiting period for each nuclear plant.

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, 2019 under the NEIL policies would be $58 million and $85 million, respectively.

Claims resulting from terrorist acts are covered under both the ANI and NEIL policies (subject to normal policy limits). The aggregate 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, Alabama Power's, and Georgia Power'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.

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Other Matters

Southern Company

As discussed in Note 1 under "Leveraged Leases," a subsidiary of Southern Holdings has several leveraged lease agreements. The ability of the lessees to make required payments to the Southern Holdings subsidiary is dependent on the operational performance of the assets. In 2017, the financial and operational performance of one of the lessees and the associated generation assets raised significant concerns about the short-term ability of the generation assets to produce cash flows sufficient to support ongoing operations and the lessee's contractual obligations and its ability to make the remaining semi-annual lease payments through the end of the lease term in 2047. In addition, following the expiration of the existing power offtake agreement in 2032, the lessee also is exposed to remarketing risk, which encompasses the price and availability of alternative sources of generation. While all lease payments through December 31, 2019 have been paid in full due to recent operational improvements, operational and remarketing risks and the resulting cash liquidity challenges persist, and significant concerns continue regarding the lessee's ability to make the remaining semi-annual lease payments. These challenges may also impact the expected residual value of the generation assets. Southern Company has evaluated the recoverability of the lease receivable and the expected residual value of the generation assets under various scenarios. Based on current forecasts of energy prices in the years following the expiration of the existing PPA, Southern Company concluded that it is no longer probable that all of the associated rental payments will be received over the term of the lease. As a result, during the fourth quarter 2019, Southern Company revised the estimate of cash flows to be received under the leveraged lease, which resulted in an impairment charge of $17 million ($13 million after tax). If any future lease payment is not paid in full, the Southern Holdings subsidiary may be unable to make its corresponding payment to the holders of the underlying non-recourse debt related to the generation assets. Failure to make the required payment to the debtholders could represent an event of default that would give the debtholders the right to foreclose on, and take ownership of, the generation assets from the Southern Holdings subsidiary, in effect terminating the lease and resulting in the write-off of the related lease receivable, which totaled approximately $76 million at December 31, 2019. Southern Company will continue to monitor the operational performance of the underlying assets and evaluate the ability of the lessee to continue to make the required lease payments. The ultimate outcome of this matter cannot be determined at this time.

Alabama Power

On October 16, 2019, Alabama Power agreed to a consent order regarding a fish kill investigation. The consent order required Alabama Power to pay approximately $50,000 to the Alabama Department of Environmental Management in civil penalties and approximately $172,000 to the Alabama Department of Conservation and Natural Resources in fish restocking costs. Alabama Power paid the penalties and restocking costs during the fourth quarter 2019.

Mississippi Power

In 2013, Mississippi Power submitted a lost revenue claim under the Deepwater Horizon Economic and Property Damages Settlement Agreement associated with the oil spill that occurred in the Gulf of Mexico in 2010. In May 2018, Mississippi Power's claim was settled. The settlement proceeds of $18 million, net of expenses and income tax, were included in Mississippi Power's earnings for 2018. Mississippi Power received half of the settlement proceeds in 2018 and half in 2019.

In conjunction with Southern Company's sale of Gulf Power, NextEra Energy held back $75 million of the purchase price pending Mississippi Power and Gulf Power negotiating a mutually acceptable revised operating agreement for Plant Daniel. In addition, Mississippi Power and Gulf Power committed to seek a restructuring of their 50% undivided ownership interests in Plant Daniel such that each of them would, after the restructuring, own 100% of a generating unit. On January 15, 2019, Gulf Power provided notice to Mississippi Power that Gulf Power will retire its share of the generating capacity of Plant Daniel on January 15, 2024. Mississippi Power has the option to purchase Gulf Power's ownership interest for $1 on January 15, 2024, provided that Mississippi Power exercises the option no later than 120 days prior to that date. Mississippi Power is assessing the potential operational and economic effects of Gulf Power's notice. The ultimate outcome of these matters remains subject to completion of Mississippi Power's evaluations and applicable regulatory approvals, including by the FERC and the Mississippi PSC, and cannot be determined at this time. See Note 15 under "Southern Company" for information regarding the sale of Gulf Power.

Southern Company Gas

Gas Pipeline Projects

At December 31, 2019, Southern Company Gas was involved in two gas pipeline construction projects, the Atlantic Coast Pipeline project and the PennEast Pipeline project.

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The Atlantic Coast Pipeline has experienced challenges to its permits since construction began in 2018. During the third and fourth quarters 2018, a FERC stop work order, together with delays in obtaining permits necessary for construction and construction delays due to judicial actions, impacted the cost and schedule for the project. Project cost estimates are approximately $8.0 billion ($400 million for Southern Company Gas), excluding financing costs. On October 4, 2019, the U.S. Supreme Court agreed to hear Atlantic Coast Pipeline's appeal of a lower court ruling that overturned a key permit for the project. On January 7, 2020, the U.S. Court of Appeals for the Fourth Circuit vacated another key permit. The operator of the joint venture has indicated that it currently expects to complete construction by the end of 2021 and place the project in service shortly thereafter.

On February 7, 2020, Southern Company Gas entered into an agreement with Dominion Atlantic Coast Pipeline, LLC for the sale of its interest in Atlantic Coast Pipeline. The transaction is expected to be completed in the first half of 2020; however, the ultimate outcome cannot be determined at this time. See Note 15 under "Southern Company Gas – Proposed Sale of Pivotal LNG and Atlantic Coast Pipeline" for additional information.

Expected project costs related to the PennEast Pipeline for Southern Company Gas total approximately $300 million, excluding financing costs. In January 2018, the PennEast Pipeline received initial FERC approval. Work continues with state and federal agencies to obtain the required permits to begin construction on the PennEast Pipeline. On September 10, 2019, an appellate court ruled that the PennEast Pipeline does not have federal eminent domain authority over lands in which a state has property rights interests. On February 18, 2020, PennEast Pipeline filed a petition for a writ of certiorari to seek U.S. Supreme Court review of the appellate court decision. On December 30, 2019, PennEast Pipeline filed a two-year extension request with the FERC to complete the project by January 19, 2022.

Additionally, on January 30, 2020, PennEast Pipeline filed an amendment with the FERC to construct the pipeline project in two phases. The first phase would consist of 68 miles of pipe, constructed entirely within Pennsylvania, which is expected to be completed by November 2021. The second phase would include the remaining route in Pennsylvania and New Jersey and is targeted for completion in 2023. FERC approval of the amended plan is required prior to beginning the first phase.

The ultimate outcome of these matters cannot be determined at this time; however, any work delays, whether caused by judicial or regulatory action, abnormal weather, or other conditions, may result in additional cost or schedule modifications or, ultimately, in project cancellation, any of which could result in an impairment of one or both of Southern Company Gas' investments and could have a material impact on Southern Company's and Southern Company Gas' financial statements. Southern Company Gas evaluated its investments and determined there was no impairment as of December 31, 2019.

See Note 3 under "Guarantees" and Note 7 under "Southern Company Gas" for additional information.

Natural Gas Storage Facilities

A wholly-owned subsidiary of Southern Company Gas owns and operates a natural gas storage facility consisting of two salt dome caverns in Louisiana. Periodic integrity tests are required in accordance with rules of the Louisiana Department of Natural Resources (DNR). In 2017, in connection with an ongoing integrity project, updated seismic mapping indicated the proximity of one of the caverns to the edge of the salt dome may be less than the required minimum and could result in Southern Company Gas retiring the cavern early.

In the third quarter 2019, management determined that it no longer planned to obtain the core samples during 2020 that are necessary to determine the composition of the sheath surrounding the edge of the salt dome. Core sampling is a requirement of the Louisiana DNR to put the cavern back in service; as a result, the cavern will not return to service by 2021. This change in plan, which affects the future operation of the entire storage facility, resulted in a pre-tax impairment charge of $91 million ($69 million after-tax) recorded by Southern Company Gas in 2019. Southern Company Gas continues to monitor the pressure and overall structural integrity of the entire facility pending any future decisions regarding decommissioning.

Southern Company Gas has two other natural gas storage facilities located in California and Texas, which could be impacted by ongoing changes in the U.S. natural gas storage market. Recent sales of natural gas storage facilities have resulted in losses for the sellers and may imply an impact on future rates and/or asset values. Sustained diminished natural gas storage values could trigger impairment of either or both of these natural gas storage facilities, which have a combined net book value of $326 million at December 31, 2019.

The ultimate outcome of these matters cannot be determined at this time, but could have a material impact on the financial statements of Southern Company and Southern Company Gas.

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Commitments

To supply a portion of the fuel requirements of the Southern Company system's electric generating plants, the Southern Company system has entered into various long-term commitments not recognized on the balance sheets for the procurement and delivery of fossil fuel and, for Alabama Power and Georgia Power, nuclear fuel. The majority of the Registrants' fuel expense for the periods presented was purchased under long-term commitments. Each Registrant expects that a substantial amount of its future fuel needs will continue to be purchased under long-term commitments.

Georgia Power has commitments, in the form of capacity purchases, regarding a portion of a 5% interest in the original cost of Plant Vogtle Units 1 and 2 owned by MEAG Power that are in effect until the later of the retirement of the plant or the latest stated maturity date of MEAG Power's bonds issued to finance such ownership interest. The payments for capacity are required whether or not any capacity is available. Portions of the capacity payments made to MEAG Power for its Plant Vogtle Units 1 and 2 investment relate to costs in excess of Georgia Power's allowed investment for ratemaking purposes. The present value of these portions at the time of the disallowance was written off. Generally, the cost of such capacity is included in purchased power in Southern Company's statements of income and in purchased power, non-affiliates in Georgia Power's statements of income. Georgia Power's capacity payments related to this commitment totaled $6 million, $8 million, and $9 million in 2019, 2018, and 2017, respectively. At December 31, 2019, Georgia Power's estimated long-term obligations related to this commitment totaled $56 million, consisting of $5 million for 2020, $5 million for 2021, $4 million for 2022, $3 million for 2023, $4 million for 2024, and $35 million for 2025 and thereafter.

See Note 9 for information regarding PPAs accounted for as leases.

Southern Company Gas has commitments for pipeline charges, storage capacity, and gas supply, including charges recoverable through natural gas cost recovery mechanisms or, alternatively, billed to marketers selling retail natural gas, as well as demand charges associated with Southern Company Gas' wholesale gas services. Gas supply commitments include amounts for gas commodity purchases associated with Southern Company Gas' gas marketing services of 45 million mmBtu at floating gas prices calculated using forward natural gas prices at December 31, 2019 and valued at $84 million. Southern Company Gas provides guarantees to certain gas suppliers for certain of its subsidiaries in support of payment obligations. Southern Company Gas' expected future contractual obligations for pipeline charges, storage capacity, and gas supply that are not recognized on the balance sheets at December 31, 2019 were as follows:

	Pipeline Charges, Storage Capacity, and Gas Supply
	(in millions)
2020	$	725
2021	559
2022	526
2023	454
2024	330
2025 and thereafter	1,677
Total	$	4,271

Guarantees

SCS may enter into various types of wholesale energy and natural gas contracts acting as an agent for the traditional electric operating companies and Southern Power. Under these agreements, each of the traditional electric operating companies and Southern Power may be jointly and severally liable. Accordingly, Southern Company has entered into keep-well agreements with each of the traditional electric operating companies to ensure they will not subsidize or be responsible for any costs, losses, liabilities, or damages resulting from the inclusion of Southern Power as a contracting party under these agreements.

Alabama Power has guaranteed a $100 million principal amount long-term bank loan entered into by SEGCO in November 2018. Georgia Power has agreed to reimburse Alabama Power for the portion of such obligation corresponding to Georgia Power's proportionate ownership of SEGCO's stock if Alabama Power is called upon to make such payment under its guarantee. At December 31, 2019, the capitalization of SEGCO consisted of $87 million of equity and $100 million of long-term debt, on which the annual interest requirement is derived from a variable rate index. In addition, SEGCO had short-term debt outstanding of $26 million. See Note 7 under "SEGCO" for additional information.

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In 2017, Atlantic Coast Pipeline executed a $3.4 billion revolving credit facility with a stated maturity date of October 2021. Southern Company Gas entered into a guarantee agreement to support its share of the revolving credit facility. Southern Company Gas' maximum exposure to loss under the terms of the guarantee is limited to 5% of the outstanding borrowings under the credit facility, and totaled $88 million as of December 31, 2019. See "Other Matters – Southern Company Gas – Gas Pipeline Projects" herein and Note 7 under "Southern Company Gas" for additional information regarding the Atlantic Coast Pipeline.

As discussed in Note 9, Alabama Power and Georgia Power have entered into certain residual value guarantees related to railcar leases.

The Registrants generate revenues from a variety of sources, some of which are not accounted for as revenue from contracts with customers, such as leases, derivatives, and certain cost recovery mechanisms. ASC 606 became effective on January 1, 2018 and the Registrants adopted it using the modified retrospective method applied to open contracts and only to the version of contracts in effect as of January 1, 2018. In accordance with the modified retrospective method, the Registrants' previously issued financial statements have not been restated to comply with ASC 606 and the Registrants did not have a cumulative-effect adjustment to retained earnings. See Note 1 under "Revenues" for additional information on the revenue policies of the Registrants. See Notes 9 and 14 for additional information on revenue accounted for under lease and derivative accounting guidance, respectively.

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The following tables disaggregate revenue from contracts with customers for 2019 and 2018:

2019	Southern Company			Alabama Power			Georgia Power			Mississippi Power			Southern Power			Southern Company Gas
	(in millions)
Operating revenues
Retail electric revenues
Residential	$	6,164		$	2,509		$	3,377		$	278		$	—		$	—
Commercial	5,065			1,677			3,097			291			—			—
Industrial	3,126			1,460			1,360			306			—			—
Other	90			25			54			11			—			—
Total retail electric revenues	14,445			5,671			7,888			886			—			—
Natural gas distribution revenues
Residential	1,413			—			—			—			—			1,413
Commercial	389			—			—			—			—			389
Transportation	907			—			—			—			—			907
Industrial	35			—			—			—			—			35
Other	245			—			—			—			—			245
Total natural gas distribution revenues	2,989			—			—			—			—			2,989
Wholesale electric revenues
PPA energy revenues	833			145			60			11			648			—
PPA capacity revenues	453			102			54			3			322			—
Non-PPA revenues	232			81			9			352			238			—
Total wholesale electric revenues	1,518			328			123			366			1,208			—
Other natural gas revenues
Gas pipeline investments	32			—			—			—			—			32
Wholesale gas services	2,095			—			—			—			—			2,095
Gas marketing services	440			—			—			—			—			440
Other natural gas revenues	42			—			—			—			—			42
Total natural gas revenues	2,609			—			—			—			—			2,609
Other revenues	1,035			153			407			19			12			—
Total revenue from contracts with customers	22,596			6,152			8,418			1,271			1,220			5,598
Other revenue sources(a)	4,266			(27		)	(10		)	(7		)	718			3,637
Other adjustments(b)	(5,443		)	—			—			—			—			(5,443		)
Total operating revenues	$	21,419		$	6,125		$	8,408		$	1,264		$	1,938		$	3,792

(a)	Other revenue sources primarily relate to revenues from customers accounted for as derivatives and leases, as well as alternative revenues program at Southern Company Gas and other cost recovery mechanisms at the traditional electric operating companies.

(b)	Other adjustments relate to the cost of Southern Company Gas' energy and risk management activities. Wholesale gas services revenues are presented net of the related costs of those activities on the statement of income. See Note 16 under "Southern Company Gas" for additional information on the components of wholesale gas services' operating revenues.

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2018	Southern Company			Alabama Power			Georgia Power			Mississippi Power			Southern Power			Southern Company Gas
	(in millions)
Operating revenues
Retail electric revenues
Residential	$	6,586		$	2,285		$	3,295		$	277		$	—		$	—
Commercial	5,255			1,541			3,025			290			—			—
Industrial	3,152			1,364			1,321			326			—			—
Other	94			25			56			9			—			—
Total retail electric revenues	15,087			5,215			7,697			902			—			—
Natural gas distribution revenues
Residential	1,525			—			—			—			—			1,525
Commercial	436			—			—			—			—			436
Transportation	944			—			—			—			—			944
Industrial	40			—			—			—			—			40
Other	230			—			—			—			—			230
Total natural gas distribution revenues	3,175			—			—			—			—			3,175
Wholesale electric revenues
PPA energy revenues	950			158			81			15			727			—
PPA capacity revenues	498			101			53			6			394			—
Non-PPA revenues	263			119			24			329			230			—
Total wholesale electric revenues	1,711			378			158			350			1,351			—
Other natural gas revenues
Gas pipeline investments	32			—			—			—			—			32
Wholesale gas services	3,083			—			—			—			—			3,083
Gas marketing services	571			—			—			—			—			571
Other natural gas revenues	53			—			—			—			—			53
Total other natural gas revenues	3,739			—			—			—			—			3,739
Other revenues	1,529			210			236			22			13			—
Total revenue from contracts with customers	25,241			5,803			8,091			1,274			1,364			6,914
Other revenue sources(a)	5,108			229			329			(9		)	841			3,849
Other adjustments(b)	(6,854		)	—			—			—			—			(6,854		)
Total operating revenues	$	23,495		$	6,032		$	8,420		$	1,265		$	2,205		$	3,909

(a)	Other revenue sources primarily relate to revenues from customers accounted for as derivatives and leases, as well as alternative revenues program at Southern Company Gas and other cost recovery mechanisms at the traditional electric operating companies.

(b)	Other adjustments relate to the cost of Southern Company Gas' energy and risk management activities. Wholesale gas services revenues are presented net of the related costs of those activities on the statement of income. See Note 16 under "Southern Company Gas" for additional information on the components of wholesale gas services' operating revenues.

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Contract Balances

The following table reflects the closing balances of receivables, contract assets, and contract liabilities related to revenues from contracts with customers at December 31, 2019 and 2018:

	Southern Company			Alabama Power			Georgia Power			Mississippi Power			Southern Power			Southern Company Gas
	(in millions)
Accounts Receivables
As of December 31, 2019	$	2,413		$	586		$	688		$	79		$	97		$	749
As of December 31, 2018	2,630			520			721			100			118			952
Contract Assets
As of December 31, 2019	$	117		$	—		$	69		$	—		$	—		$	—
As of December 31, 2018	102			—			58			—			—			—
Contract Liabilities
As of December 31, 2019	$	52		$	10		$	13		$	—		$	1		$	1
As of December 31, 2018	32			12			7			—			11			2

As of December 31, 2019 and 2018, Georgia Power had contract assets primarily related to fixed retail customer bill programs, where the payment is contingent upon Georgia Power's continued performance and the customer's continued participation in the program over the one-year contract term, and unregulated service agreements, where payment is contingent on project completion. Alabama Power had contract liabilities for outstanding performance obligations primarily related to extended service agreements. Contract liabilities for Georgia Power and Southern Power relate to cash collections recognized in advance of revenue for certain unregulated service agreements and certain levelized PPAs, respectively. Southern Company's unregulated distributed generation business had contract assets of $40 million and $39 million at December 31, 2019 and 2018, respectively, and contract liabilities of $28 million and $11 million at December 31, 2019 and 2018, respectively, for outstanding performance obligations.

The following table reflects revenue from contracts with customers recognized in 2019 included in the contract liability at December 31, 2018:

	Southern Company			Alabama Power			Georgia Power			Southern Power			Southern Company Gas
	(in millions)
Revenue Recognized
2019	$	30		$	11		$	6		$	11		$	2

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Remaining Performance Obligations

The traditional electric operating companies and Southern Power have long-term contracts with customers in which revenues are recognized as performance obligations are satisfied over the contract term. These contracts primarily relate to PPAs whereby the traditional electric operating companies and Southern Power provide electricity and generation capacity to a customer. The revenue recognized for the delivery of electricity is variable; however, certain PPAs include a fixed payment for fixed generation capacity over the term of the contract. Southern Company's unregulated distributed generation business also has partially satisfied performance obligations related to certain fixed price contracts. Revenues from contracts with customers related to these performance obligations remaining at December 31, 2019 are expected to be recognized as follows:

	2020			2021			2022			2023			2024			2025 and Thereafter
	(in millions)
Southern Company	$	490		$	430		$	336		$	324		$	323		$	2,108
Alabama Power	21			25			22			22			22			118
Georgia Power	60			49			32			32			23			61
Southern Power	287			280			281			271			279			1,948

Revenue expected to be recognized for performance obligations remaining at December 31, 2019 was immaterial for Mississippi Power.

Property, plant, and equipment is stated at original cost or fair value at acquisition, as appropriate, less any regulatory disallowances and impairments. Original cost may include: 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/or cost of equity funds used during construction.

The Registrants' property, plant, and equipment in service consisted of the following at December 31, 2019 and 2018:

At December 31, 2019:	Southern Company			Alabama Power			Georgia Power			Mississippi Power			Southern Power			Southern Company Gas
	(in millions)
Electric utilities:
Generation	$	50,329		$	15,329		$	18,341		$	2,786		$	13,241		$	—
Transmission	12,157			4,719			6,590			808			—			—
Distribution	19,846			7,798			11,024			1,024			—			—
General/other	4,650			2,177			2,182			239			29			—
Electric utilities' plant in service	86,982			30,023			38,137			4,857			13,270			—
Southern Company Gas:
Natural gas distribution utilities transportation and distribution	13,518			—			—			—			—			13,518
Storage facilities	1,634			—			—			—			—			1,634
Other	1,192			—			—			—			—			1,192
Southern Company Gas plant in service	16,344			—			—			—			—			16,344
Other plant in service	1,788			—			—			—			—			—
Total plant in service	$	105,114		$	30,023		$	38,137		$	4,857		$	13,270		$	16,344

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At December 31, 2018:	Southern Company			Alabama Power			Georgia Power			Mississippi Power			Southern Power			Southern Company Gas
	(in millions)
Electric utilities:
Generation	$	52,324		$	16,533		$	19,145		$	2,849		$	13,246		$	—
Transmission	11,344			4,380			6,156			769			—			—
Distribution	18,746			7,389			10,389			968			—			—
General/other	4,446			2,100			1,985			314			25			—
Electric utilities' plant in service	86,860			30,402			37,675			4,900			13,271			—
Southern Company Gas:
Natural gas distribution utilities transportation and distribution	12,409			—			—			—			—			12,409
Storage facilities	1,640			—			—			—			—			1,640
Other	1,128			—			—			—			—			1,128
Southern Company Gas plant in service	15,177			—			—			—			—			15,177
Other plant in service	1,669			—			—			—			—			—
Total plant in service	$	103,706		$	30,402		$	37,675		$	4,900		$	13,271		$	15,177

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 and certain maintenance costs including those described below.

In accordance with orders from their respective state PSCs, Alabama Power and Georgia Power defer nuclear outage operations and maintenance expenses to a regulatory asset when the charges are incurred. Alabama Power amortizes the costs over a subsequent 18-month period with Plant Farley's fall outage cost amortization beginning in January of the following year and spring outage cost amortization beginning in July of the same year. Georgia Power amortizes its costs over each unit's operating cycle, or 18 months for Plant Vogtle Units 1 and 2 and 24 months for Plant Hatch Units 1 and 2.

A portion of Mississippi Power's railway track maintenance costs is charged to fuel stock and recovered through Mississippi Power's fuel clause.

The portion of Southern Company Gas' non-working gas used to maintain the structural integrity of natural gas storage facilities that is considered to be non-recoverable is depreciated, while the recoverable or retained portion is not depreciated.

Finance Leases

Assets acquired under a finance lease (previously referred to as a capital lease) are included in property, plant, and equipment and are further detailed in the table below for the applicable Registrants at December 31, 2018:

At December 31, 2018:	Southern Company			Georgia Power
	(in millions)
Office buildings	$	216		$	61
PPAs(*)	—			144
Computer-related equipment	43			—
Gas pipeline	7			—
Less: Accumulated amortization	(75		)	(84		)
Balance, net of amortization	$	191		$	121

(*)	Represents Georgia Power's affiliate PPAs with Southern Power. See Note 1 under "Affiliate Transactions" for additional information.

See Note 9 for additional information, including finance lease right-of-use (ROU) assets, net included in property, plant, and equipment at December 31, 2019.

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Depreciation and Amortization

The traditional electric operating companies' and Southern Company Gas' depreciation of the original cost of utility plant in service is provided primarily by using composite straight-line rates. The approximate rates for 2019, 2018, and 2017 are as follows:

	2019		2018		2017
Alabama Power	3.1	%	3.0	%	2.9	%
Georgia Power	2.6	%	2.6	%	2.7	%
Mississippi Power	3.7	%	4.2	%	3.4	%
Southern Company Gas	2.9	%	2.9	%	2.9	%

Depreciation studies are conducted periodically to update the composite rates. These studies are filed with the respective state PSC and/or other applicable state and federal regulatory agencies for the traditional electric operating companies and natural gas distribution utilities. Effective January 1, 2020, Georgia Power's and Atlanta Gas Light's depreciation rates were revised by the Georgia PSC in connection with their respective base rate cases. On November 26, 2019, an updated depreciation study was filed with the Mississippi PSC in conjunction with the Mississippi Power 2019 Base Rate Case requesting a $16 million increase in total annual depreciation. See Note 2 for additional information.

When property, plant, and equipment 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 property included in the original cost of the asset are retired when the related property unit is retired.

At December 31, 2019 and 2018, accumulated depreciation for utility plant in service totaled $30.0 billion and $30.3 billion, respectively, for Southern Company and $4.5 billion and $4.3 billion, respectively, for Southern Company Gas.

Depreciation of the original cost of other plant in service is provided primarily on a straight-line basis over estimated useful lives, which for Southern Company range up to 65 years and for Southern Company Gas range from five to 15 years for transportation equipment, 40 to 60 years for storage facilities, and up to 65 years for other assets. At December 31, 2019 and 2018, accumulated depreciation for other plant in service totaled $732 million and $766 million, respectively, for Southern Company and $155 million and $129 million, respectively, for Southern Company Gas.

Southern Power

Southern Power applies component depreciation, where depreciation is computed principally by the straight-line method over the estimated useful life of the asset. Certain of Southern Power's generation assets related to natural gas-fired facilities 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. The primary assets in Southern Power's property, plant, and equipment are generating facilities, which generally have estimated useful lives as follows:

Southern Power Generating Facility	Useful life
Natural gas	Up to 45 years
Biomass(*)	Up to 40 years
Solar	Up to 35 years
Wind	Up to 30 years

(*)	See Note 15 under "Southern Power – Sales of Natural Gas and Biomass Plants" for information on Southern Power's sale of its biomass facility on June 13, 2019.

Southern Power reviews its estimated useful lives and salvage values on an ongoing basis. The results of these reviews could result in changes which could have a material impact on Southern Power's net income in the near term.

When Southern Power's depreciable property, plant, and equipment is retired, or otherwise disposed of in the normal course of business, the applicable cost and accumulated depreciation is removed and a gain or loss is recognized in the statements of income.

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Joint Ownership Agreements

At December 31, 2019, the Registrants' percentage ownership and investment (exclusive of nuclear fuel) in jointly-owned facilities in commercial operation were as follows:

Facility (Type)	Percent Ownership			Plant in Service				Accumulated Depreciation				CWIP
				(in millions)
Alabama Power
Greene County (natural gas) Units 1 and 2	60.0	%	(a)	$	182			$	71			$	1
Plant Miller (coal) Units 1 and 2	91.8		(b)	2,058				630				65
Georgia Power
Plant Hatch (nuclear)	50.1	%	(c)	$	1,316			$	603			$	40
Plant Vogtle (nuclear) Units 1 and 2	45.7		(c)	3,565				2,177				96
Plant Scherer (coal) Units 1 and 2	8.4		(c)	266				94				14
Plant Scherer (coal) Unit 3	75.0		(c)	1,267				492				47
Plant Wansley (coal)	53.5		(c)	1,059				367				10
Rocky Mountain (pumped storage)	25.4		(d)	182				139				—
Mississippi Power
Greene County (natural gas) Units 1 and 2	40.0	%	(a)	$	118			$	46			$	1
Plant Daniel (coal) Units 1 and 2	50.0		(e)	750				214				11
Southern Company Gas
Dalton Pipeline (natural gas pipeline)	50.0	%	(f)	$	271			$	10			$	—

(a)	Jointly owned by Alabama Power and Mississippi Power and operated and maintained by Alabama Power.

(b)	Jointly owned with PowerSouth and operated and maintained by Alabama Power.

(c)

Georgia Power owns undivided interests in Plants Hatch, Vogtle Units 1 and 2, Scherer, and Wansley in varying amounts jointly with one or more of the following entities: OPC, MEAG Power, Dalton, Florida Power & Light Company, JEA, and Gulf Power. Georgia Power has been contracted to operate and maintain the plants as agent for the co-owners and is jointly and severally liable for third party claims related to these plants.

(d)	Jointly owned with OPC, which is the operator of the plant.

(e)

Jointly owned by Gulf Power and Mississippi Power. In accordance with the operating agreement, Mississippi Power acts as Gulf Power's agent with respect to the operation and maintenance of these units. See Note 3 under "Other Matters – Mississippi Power" for information regarding a commitment between Mississippi Power and Gulf Power to seek a restructuring of their 50% undivided ownership interests in Plant Daniel.

(f)

Jointly owned with The Williams Companies, Inc., The Dalton Pipeline is a 115-mile natural gas pipeline that serves as an extension of the Transco natural gas pipeline system into northwest Georgia. Southern Company Gas leases its 50% undivided ownership for approximately $26 million annually for an initial term through 2042. The lessee is responsible for maintaining the pipeline during the lease term and for providing service to transportation customers under its FERC-regulated tariff.

Georgia Power also owns 45.7% of Plant Vogtle Units 3 and 4, which are currently under construction and had a CWIP balance of $5.8 billion at December 31, 2019. See Note 2 under "Georgia Power – Nuclear Construction" for additional information.

The Registrants' proportionate share of their jointly-owned facility operating expenses is included in the corresponding operating expenses in the statements of income and each Registrant is responsible for providing its own financing.

Assets Subject to Lien

In October 2018, the Mississippi PSC approved executed agreements between Mississippi Power and its largest retail customer, Chevron Products Company (Chevron), for Mississippi Power to continue providing retail service to the Chevron refinery in Pascagoula, Mississippi through 2038. The agreements grant Chevron a security interest in the co-generation assets, with a lease receivable balance of $118 million at December 31, 2019, located at the refinery that is exercisable upon the occurrence of (i) certain bankruptcy events or (ii) other events of default coupled with specific reductions in steam output at the facility and a downgrade of Mississippi Power's credit rating to below investment grade by two of the three rating agencies.

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On January 17, 2020, Southern Power completed the sale of its equity interests in Plant Mankato to a subsidiary of Xcel. As of December 31, 2019, under the terms of the PPA and the expansion PPA for Plant Mankato, approximately $547 million of assets, primarily related to property, plant, and equipment, were subject to lien. See Note 15 under "Southern Power – Sales of Natural Gas and Biomass Plants" for additional information.

See Note 8 under "Secured Debt" for information regarding debt secured by certain assets of Georgia Power, Mississippi Power, and Southern Company Gas.

AROs are computed as the present value of the estimated costs for an asset's future retirement and are recorded in the period in which the liability is incurred. The estimated 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 regulatory liabilities and amounts to be recovered are reflected in the balance sheets as regulatory assets.

The ARO liabilities for the traditional electric operating companies primarily relate to facilities that are subject to the CCR Rule and the related state rules, principally ash ponds. In addition, Alabama Power and Georgia Power have retirement obligations related to the decommissioning of nuclear facilities (Alabama Power's Plant Farley and Georgia Power's ownership interests in Plant Hatch and Plant Vogtle Units 1 and 2). See "Nuclear Decommissioning" herein for additional information. The traditional electric operating companies also have AROs related to various landfill sites, asbestos removal, and underground storage tanks, as well as, for Alabama Power, disposal of polychlorinated biphenyls in certain transformers and sulfur hexafluoride gas in certain substation breakers, for Georgia Power, gypsum cells and restoration of land at the end of long-term land leases for solar facilities, and, for Mississippi Power, mine reclamation and water wells. The ARO liability for Southern Power primarily relates to Southern Power's solar and wind facilities, which are located on long-term land leases requiring the restoration of land at the end of the lease.

The traditional electric operating companies and Southern Company Gas also have identified other retirement obligations, such as obligations related to certain electric transmission and distribution facilities, certain asbestos-containing material within long-term assets not subject to ongoing repair and maintenance activities, certain wireless communication towers, the disposal of polychlorinated biphenyls in certain transformers, leasehold improvements, equipment on customer property, and property associated with the Southern Company system's rail lines and natural gas pipelines. However, liabilities for the removal of these assets have not been recorded because the settlement timing for certain retirement obligations related to these assets is indeterminable and, therefore, the fair value of the retirement obligations cannot be reasonably estimated. A liability for these retirement obligations will be recognized when sufficient information becomes available to support a reasonable estimation of the ARO.

Southern Company and the traditional electric operating companies will continue to recognize in their respective 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 in the balance sheets as ordered by the various state PSCs.

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Details of the AROs included in the balance sheets are as follows:

	Southern Company			Alabama Power			Georgia Power			Mississippi Power			Southern Power(*)
	(in millions)
Balance at December 31, 2017	$	4,824		$	1,709		$	2,638		$	174		$	78
Liabilities incurred	29			—			27			—			2
Liabilities settled	(244		)	(55		)	(116		)	(35		)	—
Accretion	217			106			94			5			4
Cash flow revisions	4,737			1,450			3,186			16			—
Reclassification to held for sale	(169		)	—			—			—			—
Balance at December 31, 2018	$	9,394		$	3,210		$	5,829		$	160		$	84
Liabilities incurred	37			—			35			1			1
Liabilities settled	(328		)	(127		)	(151		)	(35		)	—
Accretion	402			145			243			7			4
Cash flow revisions	281			312			(172		)	57			—
Balance at December 31, 2019	$	9,786		$	3,540		$	5,784		$	190		$	89

(*)	Included in other deferred credits and liabilities on Southern Power's consolidated balance sheets.

In June 2018, Alabama Power recorded an increase of approximately $1.2 billion to its AROs related to the CCR Rule. Mississippi Power also recorded an increase of approximately $11 million to its AROs related to an ash pond at Plant Greene County, which is jointly-owned with Alabama Power. The revised cost estimates were based on information from feasibility studies performed on ash ponds in use at plants operated by Alabama Power, including Plant Greene County. During the second quarter 2018, Alabama Power's management completed its analysis of these studies which indicated that additional closure costs, primarily related to increases in estimated ash volume, water management requirements, and design revisions, will be required to close these ash ponds under the planned closure-in-place methodology.

Also in June 2018, Alabama Power completed an updated decommissioning cost site study for Plant Farley. The estimated cost of decommissioning based on the study resulted in an increase in Alabama Power's ARO liability of approximately $300 million. In December 2018, Georgia Power completed updated decommissioning cost site studies for Plant Hatch and Plant Vogtle Units 1 and 2. The estimated cost of decommissioning based on the studies resulted in an increase in Georgia Power's ARO liability of approximately $130 million. See "Nuclear Decommissioning" below for additional information.

In December 2018, Georgia Power recorded an increase of approximately $3.1 billion to its AROs related to the CCR Rule and the related state rule. During the second half of 2018, Georgia Power completed a strategic assessment related to its plans to close the ash ponds at all of its generating plants in compliance with the CCR Rule and the related state rule. This assessment included engineering and constructability studies related to design assumptions for ash pond closures and advanced engineering methods. The results indicated that additional closure costs will be required to close these ash ponds, primarily due to changes in closure strategies, the estimated amount of ash to be excavated, and additional water management requirements necessary to support closure strategies. These factors also impact the estimated timing of future cash outlays.

The 2018 reclassification of a portion of the ARO liability to liabilities held for sale by Southern Company represents the AROs related to Gulf Power. See Note 15 under "Southern Company" and "Assets Held for Sale" for additional information.

During 2019, Alabama Power recorded increases totaling approximately $312 million to its AROs primarily related to the CCR Rule and the related state rule based on management's completion of closure designs during the second and third quarters 2019 under the planned closure-in-place methodology for all but one of its ash pond facilities. During 2019, Mississippi Power recorded an increase of approximately $57 million to its AROs related to the CCR Rule, primarily associated with the ash pond facility at Plant Greene County, which is jointly owned with Alabama Power. The additional estimated costs to close these ash ponds under the planned closure-in-place methodology primarily relate to cost inputs from contractor bids, internal drainage and dewatering system designs, and increases in the estimated ash volumes. Alabama Power anticipates increasing the ARO for its remaining ash pond facility within the next nine months upon completion of a feasibility study and the related cost estimate, and the increase could be material.

During the second half of 2019, Georgia Power completed an assessment of its plans to close the ash ponds at all of its generating plants in compliance with the CCR Rule and the related state rule. Cost estimates were revised to reflect further refined costs for

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closure plans and updates to the timing of future cash outlays. As a result, in December 2019, Georgia Power recorded a decrease of approximately $174 million to its AROs related to the CCR Rule and the related state rule.

The cost estimates for AROs related to the CCR Rule and related state rules are based on information at December 31, 2019 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 and related state requirements for closure. The traditional electric operating companies expect to continue to update their cost estimates and ARO liabilities periodically as additional information related to these assumptions becomes available. Additionally, the closure designs and plans in the States of Alabama and Georgia are subject to approval by environmental regulatory agencies. Absent continued recovery of ARO costs through regulated rates, Southern Company's and the traditional electric operating companies' results of operations, cash flows, and financial condition could be materially impacted. The ultimate outcome of this matter cannot be determined at this time.

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 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.

Alabama Power and Georgia Power record the investment securities held in the Funds at fair value, as disclosed in Note 13, 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, Georgia Power's 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. At December 31, 2019 and 2018, approximately $28 million and $27 million, respectively, of the fair market value of Georgia Power's 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 $29 million and $28 million at December 31, 2019 and 2018, 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.

Investment securities in the Funds for December 31, 2019 and 2018 were as follows:

	Southern Company			Alabama Power			Georgia Power
	(in millions)
At December 31, 2019:
Equity securities	$	1,159		$	743		$	416
Debt securities	798			218			580
Other securities	77			60			17
Total investment securities in the Funds	$	2,034		$	1,021		$	1,013
At December 31, 2018:
Equity securities	$	919		$	594		$	325
Debt securities	726			201			525
Other securities	74			51			23
Total investment securities in the Funds	$	1,719		$	846		$	873

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These amounts exclude receivables related to investment income and pending investment sales and payables related to pending investment purchases. For Southern Company and Georgia Power, these amounts include Georgia Power's investment securities pledged to creditors and collateral received and excludes payables related to Georgia Power's securities lending program.

The fair value increases (decreases) of the Funds, including unrealized gains (losses) and reinvested interest and dividends and excluding the Funds' expenses, for 2019, 2018, and 2017 are shown in the table below.

	Southern Company			Alabama Power			Georgia Power
	(in millions)
Fair value increases (decreases)
2019	$	344		$	194		$	150
2018	(67		)	(38		)	(29		)
2017	233			125			108
Unrealized gains (losses)
At December 31, 2019	$	259		$	149		$	110
At December 31, 2018	(183		)	(96		)	(87		)
At December 31, 2017	181			98			83

The investment securities held in 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 $16 million and $17 million at December 31, 2019 and 2018, 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, 2019 and 2018, the accumulated provisions for the external decommissioning trust funds were as follows:

	2019				2018
	(in millions)
Alabama Power
Plant Farley	$	1,021			$	846
Georgia Power
Plant Hatch	$	634			$	547
Plant Vogtle Units 1 and 2	379				326
Total	$	1,013			$	873

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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 assumptions used in making these estimates. The estimated costs of decommissioning at December 31, 2019 based on the most current studies, which were each performed in 2018, were as follows:

	Plant Farley				Plant  Hatch(*)				Plant Vogtle  Units 1 and 2(*)
Decommissioning periods:
Beginning year	2037				2034				2047
Completion year	2076				2075				2079
	(in millions)
Site study costs:
Radiated structures	$	1,234			$	734			$	601
Spent fuel management	387				172				162
Non-radiated structures	99				56				79
Total site study costs	$	1,720			$	962			$	842

(*)	Based on Georgia Power's ownership interests.

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 2018. Significant assumptions used to determine these costs for ratemaking were an estimated inflation rate of 4.5% and 2.75% for Alabama Power and Georgia Power, respectively, and an estimated trust earnings rate of 7.0% and 4.75% 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.

Under the 2013 ARP, Georgia Power's annual decommissioning cost for ratemaking was a total of $5 million for Plant Hatch and Plant Vogtle Units 1 and 2. Effective January 1, 2020, in connection with the 2019 ARP, this total annual amount was reduced to $4 million. See Note 2 under "Georgia Power – Rate Plans – 2019 ARP" for additional information.

The Registrants may hold ownership interests in a number of business ventures with varying ownership structures. Partnership interests and other variable interests are evaluated to determine if each entity is a VIE. If a venture is a VIE for which a Registrant is the primary beneficiary, the assets, liabilities, and results of operations of the entity are consolidated. The Registrants reassess the conclusion as to whether an entity is a VIE upon certain occurrences, which are deemed reconsideration events.

For entities that are not determined to be VIEs, the Registrants evaluate whether they have control or significant influence over the investee to determine the appropriate consolidation and presentation. Generally, entities under the control of a Registrant are consolidated, and entities over which a Registrant can exert significant influence, but which a Registrant does not control, are accounted for under the equity method of accounting. However, the Registrants may also invest in partnerships and limited liability companies that maintain separate ownership accounts. All such investments are required to be accounted for under the equity method unless the interest is so minor that there is virtually no influence over operating and financial policies, as are all investments in joint ventures.

Investments accounted for under the equity method are recorded within equity investments in unconsolidated subsidiaries in the balance sheets and, for Southern Company and Southern Company Gas, the equity income is recorded within earnings from equity method investments in the statements of income. See "SEGCO" and "Southern Company Gas" herein for additional information.

SEGCO

Alabama Power and Georgia Power own equally all of the outstanding capital stock of SEGCO, which owns electric generating units with a total rated capacity of 1,020 MWs, as well as associated transmission facilities. Alabama Power and Georgia Power

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account for SEGCO using the equity method; Southern Company consolidates SEGCO. The capacity of these units is sold equally to Alabama Power and Georgia Power. Alabama Power and Georgia Power make payments sufficient to provide for the operating expenses, taxes, interest expense, and a ROE. The share of purchased power included in purchased power, affiliates in the statements of income totaled $93 million in 2019, $102 million in 2018, and $76 million in 2017 for Alabama Power and $95 million in 2019, $105 million in 2018, and $78 million in 2017 for Georgia Power.

SEGCO paid $14 million of dividends in 2019, $18 million in 2018, and $24 million in 2017, of which one-half of each was paid to each of Alabama Power and Georgia Power. In addition, Alabama Power and Georgia Power each recognize 50% of SEGCO's net income.

Alabama Power, which owns and operates a generating unit adjacent to the SEGCO generating units, has a joint ownership agreement with SEGCO for the ownership of an associated gas pipeline. Alabama Power owns 14% of the pipeline with the remaining 86% owned by SEGCO.

See Note 3 under "Guarantees" for additional information regarding guarantees of Alabama Power and Georgia Power related to SEGCO.

Southern Power

Variable Interest Entities

Southern Power has certain subsidiaries that are determined to be VIEs. Southern Power is considered the primary beneficiary of these VIEs because it controls the most significant activities of the VIEs, including operating and maintaining the respective assets, and has the obligation to absorb expected losses of these VIEs to the extent of its equity interests.

SP Solar and SP Wind

In May 2018, Southern Power sold a noncontrolling 33% limited partnership interest in SP Solar to Global Atlantic Financial Group Limited (Global Atlantic). See Note 15 under "Southern Power" for additional information. A wholly-owned subsidiary of Southern Power is the general partner and holds a 1% ownership interest in SP Solar and another wholly-owned subsidiary of Southern Power owns the remaining 66% ownership in SP Solar. SP Solar qualifies as a VIE since the arrangement is structured as a limited partnership and the 33% limited partner does not have substantive kick-out rights against the general partner.

At December 31, 2019 and 2018, SP Solar had total assets of $6.4 billion and $6.3 billion, respectively, total liabilities of $381 million and $113 million, respectively, and noncontrolling interests of $1.1 billion and $1.2 billion, respectively. Cash distributions from SP Solar are allocated 67% to Southern Power and 33% to Global Atlantic in accordance with their partnership interest percentage. Under the terms of the limited partnership agreement, distributions without limited partner consent are limited to available cash and SP Solar is obligated to distribute all such available cash to its partners each quarter. Available cash includes all cash generated in the quarter subject to the maintenance of appropriate operating reserves.

In December 2018, Southern Power sold a noncontrolling tax-equity interest in SP Wind to three financial investors. SP Wind owns eight operating wind farms. See Note 15 under "Southern Power" for additional information. Southern Power owns 100% of the Class B membership interests and the three financial investors own 100% of the Class A membership interests. SP Wind qualifies as a VIE since the structure of the arrangement is similar to a limited partnership and the Class A members do not have substantive kick-out rights against Southern Power.

At December 31, 2019 and 2018, SP Wind had total assets of $2.5 billion and $2.5 billion, respectively, total liabilities of $128 million and $51 million, respectively, and noncontrolling interests of $45 million and $47 million, respectively. Under the terms of the limited liability agreement, distributions without Class A member consent are limited to available cash and SP Wind is obligated to distribute all such available cash to its members each quarter. Available cash includes all cash generated in the quarter subject to the maintenance of appropriate operating reserves. Cash distributions from SP Wind are generally allocated 60% to Southern Power and 40% to the three financial investors in accordance with the limited liability agreement.

Southern Power consolidates both SP Solar and SP Wind, as the primary beneficiary, since it controls the most significant activities of each entity, including operating and maintaining their assets. Certain transfers and sales of the assets in the VIEs are subject to partner consent and the liabilities are non-recourse to the general credit of Southern Power. Liabilities consist of customary working capital items and do not include any long-term debt.

Other Variable Interest Entities

Southern Power has other consolidated VIEs that relate to certain subsidiaries that have either sold noncontrolling interests to tax-equity investors or acquired less than a 100% interest from facility developers. These entities are considered VIEs because the

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arrangements are structured similar to a limited partnership and the noncontrolling members do not have substantive kick-out rights.

At December 31, 2019 and 2018, the other VIEs had total assets of $1.1 billion and $858 million, respectively, total liabilities of $104 million and $80 million, respectively, and noncontrolling interests of $409 million and $241 million, respectively. Under the terms of the partnership agreements, distributions of all available cash are required each month or quarter and additional distributions require partner consent.

In August 2019, Southern Power completed the acquisition of a majority interest in DSGP and gained control of its most significant activities. As a result, Southern Power became the primary beneficiary of this VIE and began accounting for it as a consolidated entity. Upon consolidation of DSGP, Southern Power recorded an additional $107 million in assets, $51 million in liabilities, and $56 million in noncontrolling interest. There was no cash transferred as a result of this consolidation. From the date of Southern Power's first investment in June 2019 until gaining control in August 2019, Southern Power applied the equity method of accounting. See Note 15 under "Southern Power" for additional information.

Equity Method Investments

At December 31, 2019, Southern Power had equity method investments in several wind and battery storage projects totaling $28 million.

Redeemable Noncontrolling Interests

In 2017, Southern Power reclassified approximately $114 million from redeemable noncontrolling interests to non-redeemable noncontrolling interests due to the expiration of an option allowing SunPower Corporation to require Southern Power to purchase its redeemable noncontrolling interest at fair market value. In addition, in 2017, Turner Renewable Energy, LLC redeemed at fair value its 10% interest of redeemable noncontrolling interest in certain of Southern Power's solar facilities. At December 31, 2019, 2018, and 2017, there were no outstanding redeemable noncontrolling interests.

The following table presents the changes in Southern Power's redeemable noncontrolling interests for the year ended December 31, 2017:

	2017
	(in millions)
Beginning balance	$	164
Net income attributable to redeemable noncontrolling interests	2
Distributions to redeemable noncontrolling interests	(2		)
Capital contributions from redeemable noncontrolling interests	2
Redemption of redeemable noncontrolling interests	(59		)
Reclassification to non-redeemable noncontrolling interests	(114		)
Change in fair value of redeemable noncontrolling interests	7
Ending balance	$	—

The following table presents the attribution of net income to Southern Power and the noncontrolling interests for the year ended December 31, 2017:

	2017
	(in millions)
Net income	$	1,117
Less: Net income attributable to noncontrolling interests	44
Less: Net income attributable to redeemable noncontrolling interests	2
Net income attributable to Southern Power	$	1,071

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Southern Company Gas

Equity Method Investments

The carrying amounts of Southern Company Gas' equity method investments at December 31, 2019 and 2018 and related income from those investments for the years ended December 31, 2019, 2018, and 2017 were as follows:

Investment Balance	2019				2018
	(in millions)
SNG(a)	$	1,137			$	1,261
Atlantic Coast Pipeline(b)	—				83
PennEast Pipeline	82				71
Pivotal JAX LNG(b)	—				53
Other(c)	32				70
Total	$	1,251			$	1,538

(a)	Decrease primarily relates to the continued amortization of deferred tax assets established upon acquisition, as well as distributions in excess of earnings.

(b)

As a result of the proposed sale of Southern Company Gas' interests in Pivotal LNG and Atlantic Coast Pipeline, these amounts are classified as held for sale at December 31, 2019. See Note 3 under "Other Matters – Southern Company Gas" and Note 15 under "Southern Company Gas – Proposed Sale of Pivotal LNG and Atlantic Coast Pipeline" and "Assets Held for Sale," respectively, for additional information.

(c)	Decrease primarily relates to the sale of Triton. See Note 15 under "Southern Company Gas" for additional information.

Earnings from Equity Method Investments	2019				2018				2017
	(in millions)
SNG	$	141			$	131			$	88
Atlantic Coast Pipeline(a)	13				7				6
PennEast Pipeline(a)	6				5				6
Other(b)	(3		)		5				6
Total	$	157			$	148			$	106

(a)	Amounts primarily result from AFUDC equity recorded by the project entity.

(b)	Decrease primarily relates to the sale of Triton. See Note 15 under "Southern Company Gas" for additional information.

SNG

In 2016, Southern Company Gas, through a wholly-owned, indirect subsidiary, acquired a 50% equity interest in SNG, which is accounted for as an equity method investment. Selected financial information of SNG at December 31, 2019 and 2018 and for the years ended December 31, 2019, 2018, and 2017 is as follows:

Balance Sheet Information	2019				2018
	(in millions)
Current assets	$	85			$	104
Property, plant, and equipment	2,570				2,606
Deferred charges and other assets	158				121
Total Assets	$	2,813			$	2,831
Current liabilities	$	227			$	103
Long-term debt	1,214				1,103
Other deferred charges and other liabilities	86				212
Total Liabilities	$	1,527			$	1,418
Total Stockholders' Equity	$	1,286			$	1,413
Total Liabilities and Stockholders' Equity	$	2,813			$	2,831

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Income Statement Information	2019				2018				2017
	(in millions)
Revenues	$	630			$	604			$	544
Operating income	335				310				242
Net income	280				261				175

Atlantic Coast and PennEast Pipelines

In 2014, Southern Company Gas entered into a joint venture, whereby it holds a 5% ownership interest in the Atlantic Coast Pipeline, an interstate pipeline company formed to develop and operate an approximate 605-mile natural gas pipeline in North Carolina, Virginia, and West Virginia with expected initial transportation capacity of 1.5 Bcf per day. On February 7, 2020, Southern Company Gas entered into an agreement with Dominion Atlantic Coast Pipeline, LLC for the sale of its interest in Atlantic Coast Pipeline. The transaction is expected to be completed in the first half of 2020; however, the ultimate outcome cannot be determined at this time. See Note 15 under "Southern Company Gas – Proposed Sale of Pivotal LNG and Atlantic Coast Pipeline" for additional information.

Also in 2014, Southern Company Gas entered into a partnership in which it holds a 20% ownership interest in the PennEast Pipeline, an interstate pipeline company formed to develop and operate an approximate 118-mile natural gas pipeline between New Jersey and Pennsylvania. The expected initial transportation capacity of 1.0 Bcf per day is under long-term contracts, mainly with public utilities and other market-serving entities, such as electric generation companies, in New Jersey, Pennsylvania, and New York.

See Note 3 under "Other Matters – Southern Company Gas – Gas Pipeline Projects" and "Guarantees" for additional information on these pipeline projects.

Other

On May 29, 2019, Southern Company Gas sold its investment in Triton, a cargo container leasing company that was aggregated into Southern Company Gas' all other segment. See Note 15 under "Southern Company Gas" for additional information.

Southern Company Gas owns a 50% equity method investment in a LNG liquefaction and storage facility in Jacksonville, Florida, which was placed in service in October 2018. This facility is outfitted with a 2.0 million gallon storage tank with the capacity to produce in excess of 120,000 gallons of LNG per day. During 2019, net loss from this investment was $2 million. On February 7, 2020, Southern Company Gas entered into an agreement with Dominion Modular LNG Holdings, Inc. for the sale of its interest in Pivotal LNG, which includes the investment in this facility in Jacksonville, Florida. The transaction is expected to be completed in the first half of 2020; however, the ultimate outcome cannot be determined at this time. See Note 15 under "Southern Company Gas – Proposed Sale of Pivotal LNG and Atlantic Coast Pipeline" for additional information.

Long-term Debt

Maturities of long-term debt for the next five years are as follows:

	Southern Company(a)(b)			Alabama Power			Georgia Power(a)			Mississippi Power			Southern Power(b)			Southern Company Gas
	(in millions)
2020	$	2,991		$	251		$	1,025		$	281		$	825		$	—
2021	3,214			311			397			270			300			330
2022	2,003			751			527			—			677			46
2023	2,413			301			175			—			290			400
2024	492			22			477			—			—			—

(a)	Amounts include principal amortization related to the FFB borrowings beginning in February 2020; however, the final maturity date is February 20, 2044. See "DOE Loan Guarantee Borrowings" herein for additional information.

(b)	Southern Power's 2022 maturity represents euro-denominated debt at the U.S. dollar denominated hedge settlement amount.

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In addition to the items described herein, long-term debt at December 31, 2019 and 2018 consists of senior notes (for all Registrants), junior subordinated notes (for Southern Company and Georgia Power), first mortgage bonds and medium-term notes (for Southern Company and Southern Company Gas), and bank term loans (for Southern Company and Alabama Power).

The traditional electric operating companies also have pollution control revenue bond obligations, which 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 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.

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 at December 31, 2019 and 2018, 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. See Note 1 under "Variable Interest Entities" for additional information on the accounting treatment for this trust and the related securities.

At December 31, 2019 and 2018, Mississippi Power had $270 million aggregate principal amount outstanding of Mississippi Business Finance Corporation Taxable Revenue Bonds, 7.13% Series 1999A due October 20, 2021. Mississippi Power assumed the obligations in 2011 in connection with its election under its operating lease of Plant Daniel Units 3 and 4 to purchase the assets. The bonds were recorded at fair value at the date of assumption, or $346 million, reflecting a premium of $76 million. See "Secured Debt" herein for additional information. At December 31, 2019 and 2018, Mississippi Power also had $50 million of tax-exempt revenue bond obligations outstanding representing 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 County energy facility.

See Note 9 for information related to finance lease obligations.

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 in 2014 and the Amended and Restated Loan Guarantee Agreement in March 2019. Under the Amended and Restated Loan Guarantee Agreement, the DOE agreed to guarantee the obligations of Georgia Power under note purchase agreements among the DOE, Georgia Power, and the FFB and related promissory notes which provide for two multi-advance term loan facilities (FFB Credit Facilities). Under the FFB Credit Facilities, Georgia Power may make term loan borrowings through the FFB in an amount up to approximately $5.130 billion, provided that total aggregate borrowings under the FFB Credit Facilities may not exceed 70% of (i) Eligible Project Costs minus (ii) approximately $1.492 billion (reflecting the amounts received by Georgia Power under the Guarantee Settlement Agreement less the related customer refunds).

In March and December 2019, Georgia Power made borrowings under the FFB Credit Facilities in an aggregate principal amount of $835 million and $383 million, respectively, with applicable interest rates of 3.213% and 2.537%, respectively, both for an interest period that extends to the final maturity date of February 20, 2044. At December 31, 2019 and 2018, Georgia Power had $3.8 billion and $2.6 billion of borrowings outstanding under the FFB Credit Facilities, respectively.

All borrowings under the FFB Credit Facilities 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 its 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.

In addition to the conditions described above, 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.

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Upon satisfaction of all conditions described above, advances may be requested on a quarterly basis through 2023. The final maturity date for each advance under the FFB Credit Facilities is February 20, 2044. Interest is payable quarterly and principal payments will begin on February 20, 2020. Borrowings under the FFB Credit Facilities will bear interest at the applicable U.S. Treasury rate plus a spread equal to 0.375%.

Under the Amended and Restated 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 Facilities will terminate and Georgia Power will be required to prepay the outstanding principal amount of all borrowings under the FFB Credit Facilities over a period of five years (with level principal amortization). Among other things, these mandatory prepayment events include (i) the termination of the Vogtle Services Agreement or rejection of the Vogtle Services Agreement in any Westinghouse bankruptcy if Georgia Power does not maintain access to intellectual property rights under the related intellectual property licenses; (ii) termination of the Bechtel Agreement, unless the Vogtle Owners enter into a replacement agreement; (iii) cancellation of Plant Vogtle Units 3 and 4 by the Georgia PSC or by Georgia Power; (iv) failure of the holders of 90% of the ownership interests in Plant Vogtle Units 3 and 4 to vote to continue construction following certain schedule extensions; (v) 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 Facilities; or (vi) loss of or failure to receive necessary regulatory approvals. 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 Facilities. Georgia Power also may voluntarily prepay outstanding borrowings under the FFB Credit Facilities. Under the FFB Credit Facilities, 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, 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.

Secured Debt

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.

Outstanding secured debt at December 31, 2019 and 2018 for the applicable Registrants was as follows:

	Georgia Power(a)			Mississippi  Power(b)			Southern Company  Gas(c)
	(in millions)
December 31, 2019	$	3,999		$	270		$	1,575
December 31, 2018	2,767			270			1,325

(a)

Includes Georgia Power's FFB loans 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. See "Long-term Debt – DOE Loan Guarantee Borrowings" herein for additional information. Also includes finance lease obligations of $156 million and $142 million at December 31, 2019 and 2018, respectively. See Note 9 for additional information on finance lease obligations.

(b)	Represents revenue bonds assumed in conjunction with Mississippi Power's purchase of Plant Daniel Units 3 and 4 that are secured by Plant Daniel Units 3 and 4 and certain related personal property. See "Long-term Debt" herein for additional information.

(c)	Nicor Gas' first mortgage bonds are secured by substantially all of Nicor Gas' properties.

Each Registrant's senior notes, junior subordinated notes, pollution control and other revenue bond obligations, bank term loans, credit facility borrowings, and notes payable are effectively subordinated to all secured debt of each respective Registrant.

Equity Units

In August 2019, Southern Company issued 34.5 million 2019 Series A Equity Units (Equity Units), initially in the form of corporate units (Corporate Units), at a stated amount of $50 per Corporate Unit, for a total stated amount of $1.725 billion. Net

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proceeds from the issuance were approximately $1.682 billion. The proceeds were used to repay short-term indebtedness and for other general corporate purposes, including investments in Southern Company's subsidiaries.

Each Corporate Unit is comprised of (i) a 1/40 undivided beneficial ownership interest in $1,000 principal amount of Southern Company's Series 2019A Remarketable Junior Subordinated Notes (Series 2019A RSNs) due 2024, (ii) a 1/40 undivided beneficial ownership interest in $1,000 principal amount of Southern Company's Series 2019B Remarketable Junior Subordinated Notes (together with the Series 2019A RSNs, the RSNs) due 2027, and (iii) a stock purchase contract, which obligates the holder to purchase from Southern Company, no later than August 1, 2022, a certain number of shares of Southern Company's common stock for $50 in cash (Stock Purchase Contract). Southern Company has agreed to remarket the RSNs in 2022, at which time each interest rate on the RSNs will reset at the applicable market rate. Holders may choose to either remarket their RSNs, receive the proceeds, and use those funds to settle the related Stock Purchase Contract or retain the RSNs and use other funds to settle the related Stock Purchase Contract. If the remarketing is unsuccessful, holders will have the right to put their RSNs to Southern Company at a price equal to the principal amount. The Corporate Units carry an annual distribution rate of 6.75% of the stated amount, which is comprised of a quarterly interest payment on the RSNs of 2.70% per year and a quarterly purchase contract adjustment payment of 4.05% per year.

Each Stock Purchase Contract obligates the holder to purchase, and Southern Company to sell, for $50 a number of shares of Southern Company common stock determined based on the applicable market value (as determined under the related Stock Purchase Contract) in accordance with the conversion ratios set forth below (subject to anti-dilution adjustments):

•	If the applicable market value is equal to or greater than $68.64, 0.7284 shares.

•	If the applicable market value is less than $68.64 but greater than $57.20, a number of shares equal to $50 divided by the applicable market value.

•	If the applicable market value is less than or equal to $57.20, 0.8741 shares.

A holder's ownership interest in the RSNs is pledged to Southern Company to secure the holder's obligation under the related Stock Purchase Contract. If a holder of a Stock Purchase Contract chooses at any time to have its RSNs released from the pledge, such holder's obligation under such Stock Purchase Contract must be secured by a U.S. Treasury security equal to the aggregate principal amount of the RSNs. At the time of issuance, the RSNs were recorded on Southern Company's consolidated balance sheet as long-term debt and the present value of the contract adjustment payments of $198 million was recorded as a liability, representing the obligation to make contract adjustment payments, with an offsetting reduction to paid-in capital. The liability balance at December 31, 2019 was $185 million, of which $66 million was classified as current. The difference between the face value and present value of the contract adjustment payments will be accreted to interest expense on the consolidated statements of income over the three-year period ending in 2022. The liability recorded for the contract adjustment payments is considered non-cash and excluded from the consolidated statements of cash flows. To settle the Stock Purchase Contracts, Southern Company will be required to issue a maximum of 30.2 million shares of common stock (subject to anti-dilution adjustments and a make-whole adjustment if certain fundamental changes occur).

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Bank Credit Arrangements

At December 31, 2019, committed credit arrangements with banks were as follows:

	Expires
Company	2020				2022				2024				Total				Unused				Due within One Year
	(in millions)
Southern Company parent	$	—			$	—			$	2,000			$	2,000			$	1,999			$	—
Alabama Power	3				525				800				1,328				1,328				3
Georgia Power	—				—				1,750				1,750				1,733				—
Mississippi Power	—				150				—				150				150				—
Southern Power(a)	—				—				600				600				591				—
Southern Company Gas(b)	—				—				1,750				1,750				1,745				—
SEGCO	30				—				—				30				30				30
Southern Company	$	33			$	675			$	6,900			$	7,608			$	7,576			$	33

(a)	Southern Power's subsidiaries are not parties to its bank credit arrangement.

(b)

Southern Company Gas, as the parent entity, guarantees the obligations of Southern Company Gas Capital, which is the borrower of $1.25 billion of this arrangement. Southern Company Gas' committed credit arrangement also includes $500 million for which Nicor Gas is the borrower and which is restricted for working capital needs of Nicor Gas. Pursuant to this multi-year credit arrangement, the allocations between Southern Company Gas Capital and Nicor Gas may be adjusted. See "Structural Considerations" herein for additional information.

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, 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.

These bank credit arrangements, as well as the term loan arrangements of Alabama Power, Georgia Power, Southern Power, and SEGCO, contain covenants that limit debt levels and contain cross-acceleration or, in the case of Southern Power, 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 Southern Power 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. 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 the other subsidiaries' 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. Additionally, for Southern Company and Southern Power, for purposes of these definitions, debt excludes any project debt incurred by certain subsidiaries of Southern Power to the extent such debt is non-recourse to Southern Power and capitalization excludes the capital stock or other equity attributable to such subsidiaries. At December 31, 2019, the Registrants, Nicor Gas, and SEGCO were in compliance with all such covenants. None of the bank credit arrangements contain material adverse change clauses at the time of borrowings.

A portion of the unused credit with banks is allocated to provide liquidity support to the revenue bonds of the traditional electric operating companies and the commercial paper programs of the Registrants and Nicor Gas. The amount of variable rate revenue bonds of the traditional electric operating companies outstanding requiring liquidity support at December 31, 2019 was approximately $1.4 billion (comprised of approximately $854 million at Alabama Power, $550 million at Georgia Power, and $40 million at Mississippi Power). In addition, at December 31, 2019, the traditional electric operating companies had approximately $275 million (comprised of approximately $87 million at Alabama Power and $188 million at Georgia Power) of revenue bonds outstanding that are required to be remarketed within the next 12 months.

In addition to its credit arrangement described above, at December 31, 2019, Southern Power also had a $120 million continuing letter of credit facility expiring in 2021 for standby letters of credit. At December 31, 2019, $97 million had been used for letters of credit, primarily as credit support for PPA requirements, and $23 million was unused. At December 31, 2018, the total amount

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used under this facility was $103 million. Subsequent to December 31, 2019, Southern Power entered into an additional $60 million continuing letter of credit facility expiring in 2023 for standby letters of credit. Southern Power's subsidiaries are not parties to these letter of credit facilities. Also, at December 31, 2019 and 2018, Southern Power had $104 million and $103 million, respectively, of cash collateral posted related to PPA requirements, which is included in other deferred charges and assets in Southern Power's consolidated balance sheets.

Notes Payable

The Registrants, Nicor Gas, and SEGCO make short-term borrowings primarily through commercial paper programs that have the liquidity support of the committed bank credit arrangements described above under "Bank Credit Arrangements." Southern Power's subsidiaries are not parties or obligors to its commercial paper program. Southern Company Gas maintains commercial paper programs at Southern Company Gas Capital and at Nicor Gas. Nicor Gas' commercial paper program supports working capital needs at Nicor Gas as Nicor Gas is not permitted to make money pool loans to affiliates. All of Southern Company Gas' other subsidiaries benefit from Southern Company Gas Capital's commercial paper program. See "Structural Considerations" herein for additional information.

In addition, Southern Company and certain of its subsidiaries have entered into various bank term loan agreements. Unless otherwise stated, the proceeds of these loans were used to repay existing indebtedness and for general corporate purposes, including working capital and, for the subsidiaries, their continuous construction programs.

Commercial paper and short-term bank term loans are included in notes payable in the balance sheets. Details of short-term borrowings for the applicable Registrants were as follows:

	Notes Payable at December 31, 2019							Notes Payable at December 31, 2018
	Amount Outstanding				Weighted Average Interest Rate			Amount Outstanding				Weighted Average Interest Rate
	(in millions)							(in millions)
Southern Company
Commercial paper	$	1,705			2.1	%		$	1,064			3.0	%
Short-term bank debt	350				2.3	%		1,851				3.1	%
Total	$	2,055			2.1	%		$	2,915			3.1	%
Georgia Power
Commercial paper	$	115			2.1	%		$	294			3.1	%
Short-term bank debt	250				2.2	%		—				—	%
Total	$	365			2.2	%		$	294			3.1	%
Southern Power
Commercial paper	$	449			2.1	%		$	—			—	%
Short-term bank debt	100				2.6	%		100				3.1	%
Total	$	549			2.2	%		$	100			3.1	%
Southern Company Gas
Commercial paper:
Southern Company Gas Capital	$	372			2.1	%		$	403			3.1	%
Nicor Gas	278				1.8	%		247				3.0	%
Total	$	650			2.0	%		$	650			3.0	%

See "Bank Credit Arrangements" herein for information on bank term loan covenants that limit debt levels and cross-acceleration or cross-default provisions.

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Outstanding Classes of Capital Stock

Southern Company

Common Stock

Stock Issued

During 2019, Southern Company issued approximately 19.5 million shares of common stock through employee equity compensation plans and received proceeds of approximately $844 million.

See "Equity Units" herein for additional information.

Shares Reserved

At December 31, 2019, a total of 104 million shares were reserved for issuance pursuant to the Southern Investment Plan, employee savings plans, the Outside Directors Stock Plan, the Omnibus Incentive Compensation Plan (which includes stock options and performance share units as discussed in Note 12), and an at-the-market program. Of the total 104 million shares reserved, 9 million shares are available for awards under the Omnibus Incentive Compensation Plan at December 31, 2019.

Diluted Earnings Per Share

For Southern Company, the only difference in computing basic and diluted earnings per share (EPS) is attributable to awards outstanding under stock-based compensation plans and the Equity Units. Earnings per share dilution resulting from stock-based compensation plans and the Equity Units issuance is determined using the treasury stock method. Shares used to compute diluted EPS were as follows:

	Average Common Stock Shares
	2019			2018			2017
	(in millions)
As reported shares	1,046			1,020			1,000
Effect of stock-based compensation	8			5			8
Diluted shares	1,054			1,025			1,008

Stock-based compensation awards that were not included in the diluted EPS calculation because they were anti-dilutive were immaterial in all years presented.

The Equity Units issued in August 2019 were excluded from the calculation of diluted EPS for 2019 as the dilutive stock price threshold was not met.

Redeemable Preferred Stock of Subsidiaries

The preferred stock of Alabama 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, this preferred stock is presented as "Redeemable Preferred Stock of Subsidiaries" on Southern Company's balance sheets and statements of capitalization in a manner consistent with temporary equity under applicable accounting standards.

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The following table presents changes during the year in redeemable preferred stock of subsidiaries for Southern Company:

	Redeemable Preferred Stock of Subsidiaries
	(in millions)
Balance at December 31, 2016:	$	118
Issued(a)	250
Redeemed(a)	(38		)
Issuance costs(a)	(6		)
Balance at December 31, 2017:	324
Redeemed(b)	(33		)
Balance at December 31, 2018 and 2019:	$	291

(a)	See "Alabama Power" herein for additional information.

(b)	See "Mississippi Power" herein for additional information.

Alabama Power

Alabama Power has preferred stock, Class A preferred stock, and common stock outstanding. Alabama Power also has authorized preference stock, none of which is outstanding. Alabama Power's preferred stock and Class A preferred stock, without preference between classes, rank senior to Alabama Power's common stock with respect to payment of dividends and voluntary and involuntary dissolution. The preferred stock and Class A preferred stock of Alabama Power contain a feature that allows the holders to elect a majority of Alabama Power'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, the preferred stock and Class A preferred stock is presented as "Redeemable Preferred Stock" on Alabama Power's balance sheets and statements of capitalization in a manner consistent with temporary equity under applicable accounting standards.

Alabama Power's preferred stock is subject to redemption at a price equal to the par value plus a premium. Alabama Power's Class A preferred stock is subject to redemption at a price equal to the stated capital. All series of Alabama Power's preferred stock currently are subject to redemption at the option of Alabama Power. The Class A preferred stock is subject to redemption on or after October 1, 2022, or following the occurrence of a rating agency event. Information for each outstanding series is in the table below:

Preferred Stock	Par Value/Stated Capital Per Share		Shares Outstanding			Redemption Price Per Share
4.92% Preferred Stock	$100		80,000			$103.23
4.72% Preferred Stock	$100		50,000			$102.18
4.64% Preferred Stock	$100		60,000			$103.14
4.60% Preferred Stock	$100		100,000			$104.20
4.52% Preferred Stock	$100		50,000			$102.93
4.20% Preferred Stock	$100		135,115			$105.00
5.00% Class A Preferred Stock	$25		10,000,000			Stated Capital(*)

(*)	Prior to October 1, 2022: $25.50; on or after October 1, 2022: Stated Capital

In 2017, Alabama Power issued 10 million shares ($250 million aggregate stated capital) of 5.00% Class A Preferred Stock, Cumulative, Par Value $1 Per Share (Stated Capital $25 Per Share). The proceeds were used in 2017 to redeem all 2 million shares ($50 million aggregate stated capital) of 6.50% Series Preference Stock, 6 million shares ($150 million aggregate stated capital) of 6.45% Series Preference Stock, and 1.52 million shares ($38 million aggregate stated capital) of 5.83% Class A Preferred Stock and for other general corporate purposes, including Alabama Power's continuous construction program.

There were no changes for the years ended December 31, 2019 and 2018 in redeemable preferred stock of Alabama Power.

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Georgia Power

Georgia Power has preferred stock, Class A preferred stock, preference stock, and common stock authorized, but only common stock outstanding as of December 31, 2019 and 2018. In 2017, Georgia Power redeemed all of its outstanding shares of Class A preferred stock and preference stock.

Mississippi Power

Mississippi Power has preferred stock and common stock authorized, but only common stock outstanding as of December 31, 2019. In October 2018, Mississippi Power completed the redemption of all outstanding shares and depository shares of its Preferred Stock that contained a feature allowing the holders to elect a majority of Mississippi Power's board of directors if preferred dividends were not paid for four consecutive quarters. Because such a potential redemption-triggering event was not solely within the control of Mississippi Power, this preferred stock was presented as "Cumulative Redeemable Preferred Stock" on Mississippi Power's balance sheets and statements of capitalization in a manner consistent with temporary equity under applicable accounting standards.

Dividend Restrictions

The income of Southern Company is derived primarily from equity in earnings of its subsidiaries. At December 31, 2019, consolidated retained earnings included $5.3 billion of undistributed retained earnings of the subsidiaries.

The traditional electric operating companies and Southern Power can only pay dividends to Southern Company out of retained earnings or paid-in-capital.

See Note 7 under "Southern Power" for information regarding the distribution requirements for certain Southern Power subsidiaries.

By regulation, Nicor Gas is restricted, to the extent of its retained earnings balance, in the amount it can dividend or loan to affiliates and is not permitted to make money pool loans to affiliates. At December 31, 2019, the amount of Southern Company Gas' subsidiary retained earnings restricted for dividend payment totaled $951 million.

Structural Considerations

Since Southern Company and Southern Company Gas are holding companies, the right of Southern Company and Southern Company Gas and, hence, the right of creditors of Southern Company or Southern Company Gas to participate in any distribution of the assets of any respective subsidiary of Southern Company or Southern Company Gas, whether upon liquidation, reorganization or otherwise, is subject to prior claims of creditors and preferred stockholders of such subsidiary.

Southern Company Gas' 100%-owned subsidiary, Southern Company Gas Capital, was established to provide for certain of Southern Company Gas' ongoing financing needs through a commercial paper program, the issuance of various debt, hybrid securities, and other financing arrangements. Southern Company Gas fully and unconditionally guarantees all debt issued by Southern Company Gas Capital. Nicor Gas is not permitted by regulation to make loans to affiliates or utilize Southern Company Gas Capital for its financing needs.

Southern Power Company's senior notes, bank term loan, commercial paper, and bank credit arrangement are unsecured senior indebtedness, which rank equally with all other unsecured and unsubordinated debt of Southern Power Company. Southern Power's subsidiaries are not issuers, borrowers, or obligors, as applicable, under any of these unsecured senior debt arrangements, which are effectively subordinated to any future secured debt of Southern Power Company and any potential claims of creditors of Southern Power's subsidiaries.

On January 1, 2019, the Registrants adopted the provisions of FASB ASC Topic 842 (as amended), Leases (ASC 842), which require lessees to recognize leases with a term of greater than 12 months on the balance sheet as lease obligations, representing the discounted future fixed payments due, along with ROU assets that will be amortized over the term of each lease.

The Registrants elected the transition methodology provided by ASC 842, whereby the applicable requirements were applied on a prospective basis as of the adoption date of January 1, 2019, without restating prior periods. The Registrants also elected the package of practical expedients provided by ASC 842 that allows prior determinations of whether existing contracts are, or contain, leases and the classification of existing leases to continue without reassessment. Additionally, the Registrants applied the use-of-hindsight practical expedient in determining lease terms as of the date of adoption and elected the practical expedient that allows existing land easements not previously accounted for as leases not to be reassessed.

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Lessee

As lessee, the Registrants lease certain electric generating units (including renewable energy facilities), real estate/land, communication towers, railcars, and other equipment and vehicles. The major categories of lease obligations are as follows:

	As of December 31, 2019
	Southern Company			Alabama Power			Georgia Power			Mississippi Power			Southern Power			Southern Company Gas
	(in millions)
Electric generating units	$	990		$	125		$	1,487		$	—		$	—		$	—
Real estate/land	782			4			54			2			398			74
Communication towers	154			2			3			—			—			18
Railcars	51			21			26			3			—			—
Other	93			8			12			1			—			—
Total	$	2,070		$	160		$	1,582		$	6		$	398		$	92

Real estate/land leases primarily consist of commercial real estate leases at Southern Company, Georgia Power, and Southern Company Gas and various land leases primarily associated with renewable energy facilities at Southern Power. The commercial real estate leases have remaining terms of up to 25 years while the land leases have remaining terms of up to 47 years, including renewal periods.

Communication towers are leased for the installation of equipment to provide cellular phone service to customers and to support the automated meter infrastructure programs at the traditional electric operating companies and Nicor Gas. Communication tower leases have terms of up to 15 years with options to renew for periods up to 20 years.

While renewal options exist in many of the leases, other than for land leases associated with renewable energy facilities at Southern Power and for communication tower leases at Southern Company Gas, the expected term used in calculating the lease obligation generally reflects only the noncancelable period of the lease as it is not considered reasonably certain that the lease will be extended. The expected term of land leases associated with renewable energy facilities includes renewal periods reasonably certain of exercise resulting in an expected lease term at least equal to the expected life of the renewable energy facilities.

Contracts that Contain a Lease

While not specifically structured as a lease, some of the PPAs at Alabama Power and Georgia Power are deemed to represent a lease of the underlying electric generating units when the terms of the PPA convey the right to control the use of the underlying assets. Amounts recorded for leases of electric generating units are generally based on the amount of scheduled capacity payments due over the remaining term of the PPA, which varies between three and 18 years. Georgia Power has several PPAs with Southern Power that Georgia Power accounts for as leases with a lease obligation of $624 million at December 31, 2019. The amount paid for energy under these affiliate PPAs reflects a price that would be paid in an arm's-length transaction as those amounts have been reviewed and approved by the Georgia PSC.

During 2019, Alabama Power entered into additional long-term PPAs totaling approximately 640 MWs of additional generating capacity consisting of combined cycle generation expected to commence later in 2020 and solar generation coupled with battery energy storage systems expected to commence in 2022 through 2024. Both the combined cycle PPA and the 20-year term battery energy storage systems of the solar generation PPAs are deemed operating leases. The 28-year term battery energy storage systems of the solar generation PPAs are deemed finance leases. The estimated minimum lease payments for these agreements, which are contingent upon approval by the Alabama PSC, total $95 million. See Note 2 under "Alabama Power – Petition for Certificate of Convenience and Necessity" for additional information.

Short-term Leases

Leases with an initial term of 12 months or less are not recorded on the balance sheet; the Registrants generally recognize lease expense for these leases on a straight-line basis over the lease term.

Residual Value Guarantees

Residual value guarantees exist primarily in railcar leases at Alabama Power and Georgia Power and the amounts probable of being paid under those guarantees are included in the lease payments. All such amounts are immaterial as of December 31, 2019.

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Lease and Nonlease Components

For all asset categories, with the exception of electric generating units, gas pipelines, and real estate leases, the Registrants combine lease payments and any nonlease components, such as asset maintenance, for purposes of calculating the lease obligation and the right-of-use asset.

Balance sheet amounts recorded for operating and finance leases are as follows:

	As of December 31, 2019
	Southern Company			Alabama Power			Georgia Power			Mississippi Power			Southern Power			Southern Company Gas
	(in millions)
Operating Leases
Operating lease ROU assets, net	$	1,800		$	132		$	1,428		$	6		$	369		$	93
Operating lease obligations - current	$	229		$	49		$	144		$	2		$	22		$	14
Operating lease obligations - non-current	1,615			107			1,282			4			376			78
Total operating lease obligations	$	1,844		$	156		$	1,426		$	6		$	398		$	92
Finance Leases
Finance lease ROU assets, net	$	216		$	4		$	130		$	—		$	—		$	—
Finance lease obligations - current	$	21		$	1		$	11		$	—		$	—		$	—
Finance lease obligations - non-current	205			3			145			—			—			—
Total finance lease obligations	$	226		$	4		$	156		$	—		$	—		$	—

Lease costs for the year ended December 31, 2019, which includes both amounts recognized as operations and maintenance expense and amounts capitalized as part of the cost of another asset, are as follows:

	Southern Company			Alabama Power			Georgia Power			Mississippi Power			Southern Power			Southern Company Gas
	(in millions)
2019
Lease cost
Operating lease cost	$	310		$	54		$	206		$	3		$	28		$	18
Finance lease cost:
Amortization of ROU assets	28			1			15			—			—			—
Interest on lease obligations	12			—			18			—			—			—
Total finance lease cost	40			1			33			—			—			—
Short-term lease costs	48			19			22			—			—			—
Variable lease cost	105			6			85			—			7			—
Sublease income	—			(1		)	—			—			—			—
Total lease cost	$	503		$	79		$	346		$	3		$	35		$	18

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Georgia Power has variable lease payments that are based on the amount of energy produced by certain renewable generating facilities subject to PPAs.

Rent expense and PPA capacity expense related to leases for 2018 and 2017, prior to the adoption of ASC 842, were as follows:

	Southern Company(a)(b)(c)			Alabama Power			Georgia Power(a)			Mississippi Power(b)			Southern Power(c)			Southern Company Gas
	(in millions)
2018:
Rent expense	$	192		$	23		$	34		$	4		$	31		$	15
PPA capacity expense	231			44			206			—			—			—
2017:
Rent expense	$	176		$	25		$	31		$	3		$	29		$	15
PPA capacity expense	235			41			225			—			—			—

(a)	Georgia Power's energy-only solar PPAs accounted for as leases contained contingent rent expense of $72 million and $73 million for 2018 and 2017, respectively, of which $29 million in each of 2018 and 2017 related to solar PPAs with Southern Power.

(b)	Mississippi Power's energy-only solar PPAs accounted for as operating leases contained contingent rent expense of $10 million and $5 million in 2018 and 2017, respectively.

(c)	Rent expense includes contingent rent expense related to Southern Power's land leases based on wind production and escalation in the Consumer Price Index for All Urban Consumers.

Other information with respect to cash and noncash activities related to leases, as well as weighted-average lease terms and discount rates, is as follows:

	2019
	Southern Company			Alabama Power			Georgia Power			Mississippi Power			Southern Power			Southern Company Gas
	(in millions)
Other information
Cash paid for amounts included in the measurements of lease obligations:
Operating cash flows from operating leases	$	323		$	54		$	210		$	3		$	27		$	18
Operating cash flows from finance leases	10			—			19			—			—			—
Financing cash flows from finance leases	32			1			13			—			—			—
ROU assets obtained in exchange for new operating lease obligations	118			7			21			—			2			19
ROU assets obtained in exchange for new finance lease obligations	35			2			24			—			—			—

	As of December 31, 2019
	Southern Company		Alabama Power		Georgia Power		Mississippi Power		Southern Power		Southern Company Gas
Weighted-average remaining lease term in years:
Operating leases	14.2		3.1		10.2		7.0		32.8		9.9
Finance leases	18.8		12.1		10.5		N/A		N/A		N/A
Weighted-average discount rate:
Operating leases	4.53	%	3.33	%	4.46	%	4.02	%	5.66	%	3.70	%
Finance leases	5.04	%	3.60	%	10.76	%	N/A		N/A		N/A

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Maturities of lease liabilities are as follows:

	As of December 31, 2019
	Southern Company			Alabama Power			Georgia Power			Mississippi Power			Southern Power			Southern Company Gas
	(in millions)
Maturity Analysis
Operating leases:
2020	$	289		$	54		$	205		$	2		$	26		$	18
2021	268			52			198			1			23			17
2022	260			53			197			1			23			14
2023	208			4			198			1			24			11
2024	163			1			161			—			24			10
Thereafter	1,514			1			831			2			812			44
Total	2,702			165			1,790			7			932			114
Less: Present value discount	858			9			364			1			534			22
Operating lease obligations	$	1,844		$	156		$	1,426		$	6		$	398		$	92
Finance leases:
2020	$	31		$	1		$	28		$	—		$	—		$	—
2021	25			1			24			—			—			—
2022	22			1			25			—			—			—
2023	18			1			25			—			—			—
2024	15			—			25			—			—			—
Thereafter	246			—			134			—			—			—
Total	357			4			261			—			—			—
Less: Present value discount	131			—			105									—
Finance lease obligations	$	226		$	4		$	156		$	—		$	—		$	—

Payments made under PPAs at Georgia Power for energy generated from certain renewable energy facilities accounted for as operating and finance leases are considered variable lease costs and are therefore not reflected in the above maturity analysis.

As of December 31, 2019, Southern Company, Alabama Power, Mississippi Power, and Southern Power have additional leases that have not yet commenced, as detailed in the following table:

	Southern Company	Alabama Power(a)	Mississippi Power(b)	Southern Power
Lease category	PPAs, land, pipelines,  and aircraft	PPAs	Pipelines	Land
Expected commencement date	2020-2024	2020-2024	2020	2020
Longest lease term expiration	40 years	28 years	15 years	40 years
Estimated total obligations (in millions)	$248	$95	$23	$87

(a)	See Note 2 under "Alabama Power – Petition for Certificate of Convenience and Necessity" for additional information. Alabama Power will have variable operating lease payments and variable finance lease payments that are based on the amount of energy produced by certain renewable generating facilities subject to PPAs.

(b)	See Note 2 under "Mississippi Power – Kemper County Energy Facility – Lignite Mine and CO2 Pipeline Facilities" for additional information. Estimated total obligations include non-lease components.

Lessor

The Registrants are each considered lessors in various arrangements that have been determined to contain a lease due to the customer's ability to control the use of the underlying asset owned by the applicable Registrant. For the traditional electric

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operating companies, these arrangements consist of outdoor lighting contracts accounted for as operating leases with initial terms of up to seven years, after which the contracts renew on a month-to-month basis at the customer's option. For Mississippi Power, these arrangements also include a tolling arrangement related to an electric generating unit accounted for as a sales-type lease with a term of 20 years. For Southern Power, these arrangements consist of PPAs related to electric generating units, including renewable energy facilities, accounted for as operating leases with terms of up to 27 years. For Southern Company, these arrangements also include PPAs related to fuel cells accounted for as operating leases with terms of up to 15 years. Southern Company Gas is the lessor in operating leases related to gas pipelines with remaining terms of up to 23 years.

Lease income for the year ended December 31, 2019 is as follows:

	Southern Company			Alabama Power			Georgia Power			Mississippi Power			Southern Power			Southern Company Gas
	(in millions)
2019
Lease income - interest income on sales-type leases	$	9		$	—		$	—		$	9		$	—		$	—
Lease income - operating leases	273			24			71			—			160			35
Variable lease income	403			—			—			—			434			—
Total lease income	$	685		$	24		$	71		$	9		$	594		$	35

Lease income for Southern Power is included in wholesale revenues. Lease payments received under tolling arrangements and PPAs consist of either scheduled payments or variable payments based on the amount of energy produced by the underlying electric generating units. Scheduled payments to be received under outdoor lighting contracts, tolling arrangements, and PPAs accounted for as leases are presented in the following maturity analyses.

No profit or loss was recognized by Mississippi Power upon commencement of a tolling arrangement accounted for as a sales-type lease during the first quarter 2019. The undiscounted cash flows to be received under the lease are as follows:

	At December 31, 2019
	Southern Company			Mississippi Power
	(in millions)
2020	$	17		$	17
2021	15			15
2022	15			15
2023	14			14
2024	14			14
Thereafter	138			138
Total undiscounted cash flows	$	213		$	213
Lease receivable(*)	118			118
Difference between undiscounted cash flows and discounted cash flows	$	95		$	95

(*)	Included in other current assets and other property and investments on the balance sheets.

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The undiscounted cash flows to be received under operating leases and contracts accounted for as operating leases (adjusted for intercompany eliminations) are as follows:

	At December 31, 2019
	Southern Company			Alabama Power			Georgia Power			Southern Power			Southern Company Gas
	(in millions)
2020	$	155		$	26		$	26		$	84		$	35
2021	141			23			19			86			35
2022	125			16			8			87			35
2023	110			7			2			88			34
2024	103			3			—			90			33
Thereafter	1,063			20			—			387			463
Total	$	1,697		$	95		$	55		$	822		$	635

Southern Power receives payments for renewable energy under PPAs accounted for as operating leases that are considered contingent rents and are therefore not reflected in the table above. Southern Power allocates revenue to the nonlease components of PPAs based on the stand-alone selling price of capacity and energy. The undiscounted cash flows to be received under outdoor lighting contracts accounted for as operating leases at Mississippi Power are immaterial.

Southern Company files a consolidated federal income tax return and the Registrants file 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. In accordance with IRS regulations, each company is jointly and severally liable for the federal tax liability.

Federal Tax Reform Legislation

Following the enactment of the Tax Reform Legislation, the SEC staff issued Staff Accounting Bulletin 118 – "Income Tax Accounting Implications of the Tax Cuts and Jobs Act" (SAB 118), which provided for a measurement period of up to one year from the enactment date to complete accounting under GAAP for the tax effects of the legislation. Due to the complex and comprehensive nature of the enacted tax law changes and their application under GAAP, the Registrants considered all amounts recorded in the financial statements as a result of the Tax Reform Legislation "provisional" as discussed in SAB 118 and subject to revision prior to filing the 2017 tax return in the fourth quarter 2018. As of December 31, 2018, each of the Registrants considered the measurement of impacts from the Tax Reform Legislation on deferred income tax assets and liabilities, primarily due to the impact of the reduction of the corporate income tax rate, to be complete.

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Current and Deferred Income Taxes

Details of income tax provisions are as follows:

	2019
	Southern Company			Alabama Power			Georgia Power			Mississippi Power			Southern Power			Southern Company Gas
	(in millions)
Federal —
Current	$	156		$	61		$	264		$	(6	)	$	(717	)	$	(120	)
Deferred	1,237			125			180			26			647			195
	1,393			186			444			20			(70		)	75
State —
Current	275			12			6			(1		)	1			37
Deferred	130			72			22			11			13			18
	405			84			28			10			14			55
Total	$	1,798		$	270		$	472		$	30		$	(56	)	$	130

	2018
	Southern Company			Alabama Power			Georgia Power			Mississippi Power			Southern Power			Southern Company Gas
	(in millions)
Federal —
Current	$	167		$	91		$	393		$	(567	)	$	85		$	334
Deferred	231			123			(249		)	575			(154		)	33
	398			214			144			8			(69		)	367
State —
Current	188			26			81			(10		)	(9		)	131
Deferred	(137		)	51			(11		)	(100		)	(86		)	(34		)
	51			77			70			(110		)	(95		)	97
Total	$	449		$	291		$	214		$	(102	)	$	(164	)	$	464

	2017
	Southern Company			Alabama Power			Georgia Power			Mississippi Power			Southern Power			Southern Company Gas
	(in millions)
Federal —
Current	$	(62	)	$	136		$	256		$	194		$	(566	)	$	103
Deferred	(6		)	336			504			(753		)	(312		)	170
	(68		)	472			760			(559		)	(878		)	273
State —
Current	37			23			116			—			(110		)	27
Deferred	173			73			(46		)	27			49			67
	210			96			70			27			(61		)	94
Total	$	142		$	568		$	830		$	(532	)	$	(939	)	$	367

Southern Company's and Southern Power's ITCs and PTCs generated in the current tax year and carried forward from prior tax years that cannot be utilized in the current tax year are reclassified from current to deferred taxes in federal income tax expense in the tables above. Southern Power's ITCs and PTCs reclassified in this manner include $51 million for 2019, $128 million for

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2018, and $316 million for 2017. Southern Power received $734 million and $5 million of cash related to federal ITCs under renewable energy initiatives in 2019 and 2018, respectively. No cash was received in 2017. See "Deferred Tax Assets and Liabilities" and "Tax Credit Carryforwards" herein for additional information.

In accordance with regulatory requirements, deferred federal ITCs for the traditional electric operating companies are deferred and amortized over the average life of the related property, with such amortization normally applied as a credit to reduce depreciation and amortization in the statements of income. Southern Power's and the natural gas distribution utilities' deferred federal ITCs, as well as certain state ITCs for Nicor Gas, are deferred and amortized to income tax expense over the life of the respective asset. ITCs amortized in 2019, 2018, and 2017 were immaterial for the traditional electric operating companies and Southern Company Gas and were as follows for Southern Company and Southern Power:

	Southern Company			Southern Power
	(in millions)
2019	$	181		$	151
2018	87			58
2017	79			57

Southern Power recognized tax credits and reduced the tax basis of the asset 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 $5 million in 2019, $1 million in 2018, and $18 million in 2017. See "Unrecognized Tax Benefits" herein for further information.

State ITCs and other state credits, which are recognized in the period in which the credits are generated, reduced Georgia Power's income tax expense by $51 million in 2019, $21 million in 2018, and $37 million in 2017 and reduced Southern Power's income tax expense by $32 million in 2017.

Southern Power's federal and state PTCs, which are recognized in the period in which the credits are generated, reduced Southern Power's income tax expense by $12 million in 2019, $141 million in 2018, and $139 million in 2017.

Legal Entity Reorganizations

In April 2018, Southern Power completed the final stage of a legal entity reorganization of various direct and indirect subsidiaries that own and operate substantially all of its solar facilities, including certain subsidiaries owned in partnership with various third parties. In September 2018, Southern Power also completed a legal entity reorganization of eight operating wind facilities under a new holding company, SP Wind. The reorganizations resulted in net state tax benefits related to certain changes in apportionment rates totaling approximately $65 million, which were recorded in 2018.

Effective Tax Rate

Southern Company's effective tax rate is typically lower than the statutory rate due to employee stock plans' dividend deduction, non-taxable AFUDC equity at the traditional electric operating companies, flowback of excess deferred income taxes at the regulated utilities, and federal income tax benefits from ITCs and PTCs primarily at Southern Power. Each Registrant's effective tax rate for 2018 varied significantly as compared to 2017 due to the 14% lower 2018 federal tax rate resulting from the Tax Reform Legislation.

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A reconciliation of the federal statutory income tax rate to the effective income tax rate is as follows:

	2019
	Southern Company		Alabama Power		Georgia Power		Mississippi Power		Southern Power		Southern Company Gas
Federal statutory rate	21.0	%	21.0	%	21.0	%	21.0	%	21.0	%	21.0	%
State income tax, net of federal deduction	4.9		4.9		1.0		4.3		4.0		6.1
Employee stock plans' dividend deduction	(0.4	)	—		—		—		—		—
Non-deductible book depreciation	0.3		0.6		0.5		0.4		—		—
Flowback of excess deferred income taxes	(2.1	)	(5.3	)	—		(12.6	)	—		(6.0	)
AFUDC-Equity	(0.4	)	(0.8	)	(0.6	)	(0.1	)	—		—
ITC basis difference	(0.1	)	—		—		—		(1.9	)	—
Amortization of ITC	(0.8	)	(0.1	)	(0.1	)	(0.1	)	(16.1	)	(0.1	)
Tax impact from sale of subsidiaries	5.1		—		—		—		(27.6	)	(1.4	)
Noncontrolling interests	—		—		—		—		0.8		—
Other	—		(0.4	)	(0.3	)	4.9		(0.6	)	(1.4	)
Effective income tax (benefit) rate	27.5	%	19.9	%	21.5	%	17.8	%	(20.4	)%	18.2	%

	2018
	Southern Company		Alabama Power		Georgia Power		Mississippi Power		Southern Power		Southern Company Gas
Federal statutory rate	21.0	%	21.0	%	21.0	%	21.0	%	21.0	%	21.0	%
State income tax, net of federal deduction	1.8		5.0		5.5		(65.1	)	(90.8	)	9.2
Employee stock plans' dividend deduction	(1.0	)	—		—		—		—		—
Non-deductible book depreciation	0.8		0.6		1.2		0.7		—		—
Flowback of excess deferred income taxes	(4.0	)	(1.8	)	—		(4.1	)	—		(3.0	)
AFUDC-Equity	(1.0	)	(1.0	)	(1.4	)	—		—		—
ITC basis difference	(0.6	)	—		—		—		(0.2	)	—
Federal PTCs	(4.7	)	—		—		—		(156.6	)	—
Amortization of ITC	(2.0	)	(0.1	)	(0.2	)	(0.2	)	(55.4	)	(0.1	)
Tax impact from sale of subsidiaries	8.6		—		—		—		—		28.5
Tax Reform Legislation	(1.4	)	—		(4.9	)	(26.3	)	96.1		(0.4	)
Noncontrolling interests	(0.4	)	—		—		—		(14.9	)	—
Other	(0.8	)	(0.1	)	0.1		(1.4	)	2.0		0.3
Effective income tax (benefit) rate	16.3	%	23.6	%	21.3	%	(75.4	)%	(198.8	)%	55.5	%

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	2017
	Southern Company		Alabama Power		Georgia Power		Mississippi Power(*)		Southern Power		Southern Company Gas
Federal statutory rate	35.0	%	35.0	%	35.0	%	(35.0	)%	35.0	%	35.0	%
State income tax, net of federal deduction	12.5		4.5		2.0		0.6		(22.2	)	10.0
Employee stock plans' dividend deduction	(4.0	)	—		—		—		—		—
Non-deductible book depreciation	3.1		0.9		0.7		0.1		—		—
Flowback of excess deferred income taxes	(0.3	)	—		(0.1	)	—		—		(0.2	)
AFUDC-Equity	(2.6	)	(1.0	)	(0.6	)	—		—		—
AFUDC-Equity portion of Kemper IGCC charge	15.7		—		—		5.3		—		—
ITC basis difference	(1.7	)	—		—		—		(10.0	)	—
Federal PTCs	(12.1	)	—		—		—		(72.5	)	—
Amortization of ITC	(4.2	)	(0.2	)	(0.1	)	—		(20.6	)	(0.2	)
Tax Reform Legislation	(25.6	)	0.3		(0.4	)	11.9		(416.1	)	15.0
Noncontrolling interests	(1.4	)	—		—		—		(8.6	)	—
Other	(1.1	)	0.1		0.2		—		(10.7	)	0.6
Effective income tax (benefit) rate	13.3	%	39.6	%	36.7	%	(17.1	)%	(525.7	)%	60.2	%

(*)	Represents effective income tax benefit rate for Mississippi Power due to a loss before income taxes in 2017.

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Deferred Tax Assets and Liabilities

The tax effects of temporary differences between the carrying amounts of assets and liabilities in the financial statements of the Registrants and their respective tax bases, which give rise to deferred tax assets and liabilities, are as follows:

	December 31, 2019
	Southern Company			Alabama Power			Georgia Power			Mississippi Power			Southern Power			Southern Company Gas
	(in millions)
Deferred tax liabilities —
Accelerated depreciation	$	8,711		$	2,402		$	3,058		$	315		$	1,422		$	1,288
Property basis differences	1,843			912			643			143			—			133
Federal effect of net state deferred tax assets	—			—			—			24			—			—
Leveraged lease basis differences	236			—			—			—			—			—
Employee benefit obligations	704			242			351			38			12			12
Premium on reacquired debt	83			13			70			—			—			—
Regulatory assets –
Storm damage reserves	109			—			109			—			—			—
Employee benefit obligations	1,174			311			403			55			—			45
Remaining book value of retired assets	341			174			159			8			—			—
AROs	1,723			613			1,066			44			—			—
AROs	814			360			405			—			—			—
Other	523			134			81			68			11			198
Total deferred income tax liabilities	16,261			5,161			6,345			695			1,445			1,676
Deferred tax assets —
Federal effect of net state deferred tax liabilities	277			162			63			—			24			56
Employee benefit obligations	1,385			334			488			72			5			111
Other property basis differences	230			—			65			—			146			—
ITC and PTC carryforward	2,098			11			435			—			1,445			—
Other partnership basis difference	169			—			—			—			169			—
Other comprehensive losses	112			8			18			—			10			—
AROs	2,537			973			1,471			44			—			—
Estimated loss on plants under construction	283			—			283			—			—			—
Other deferred state tax attributes	402			—			13			251			72			8
Regulatory liability associated with the Tax Reform Legislation (not subject to normalization)	401			240			133			28			—			—
Other	786			173			154			56			46			287
Total deferred income tax assets	8,680			1,901			3,123			451			1,917			462
Valuation allowance	(137		)	—			(35		)	(41		)	(36		)	(5		)
Net deferred income tax assets	8,543			1,901			3,088			410			1,881			457
Net deferred income taxes (assets)/liabilities	$	7,718		$	3,260		$	3,257		$	285		$	(436	)	$	1,219
Recognized in the balance sheets:
Accumulated deferred income taxes – assets	$	(170	)	$	—		$	—		$	(139	)	$	(551	)	$	—
Accumulated deferred income taxes – liabilities	$	7,888		$	3,260		$	3,257		$	424		$	115		$	1,219

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	December 31, 2018
	Southern Company			Alabama Power			Georgia Power			Mississippi Power			Southern Power			Southern Company Gas
	(in millions)
Deferred tax liabilities —
Accelerated depreciation	$	8,461		$	2,236		$	3,005		$	335		$	1,483		$	1,176
Property basis differences	1,807			865			633			162			—			134
Federal effect of net state deferred tax assets	—			—			—			36			—			—
Leveraged lease basis differences	253			—			—			—			—			—
Employee benefit obligations	477			149			290			25			6			6
Premium on reacquired debt	88			14			74			—			—			—
Regulatory assets –
Storm damage reserves	111			—			111			—			—			—
Employee benefit obligations	975			260			344			45			—			45
Remaining book value of retired assets	56			6			39			11			—			—
AROs	1,232			276			925			31			—			—
AROs	1,210			607			575			—			—			—
Other	537			171			102			57			34			132
Total deferred income tax liabilities	15,207			4,584			6,098			702			1,523			1,493
Deferred tax assets —
Federal effect of net state deferred tax liabilities	260			155			71			—			22			46
Employee benefit obligations	1,273			286			444			62			7			150
Other property basis differences	251			—			61			—			172			—
ITC and PTC carryforward	2,730			11			430			—			2,128			—
Alternative minimum tax carryforward	62			—			—			32			21			—
Other partnership basis difference	162			—			—			—			162			—
Other comprehensive losses	82			10			3			—			—			—
AROs	2,442			883			1,500			31			—			—
Estimated loss on plants under construction	346			—			283			63			—			—
Other deferred state tax attributes	415			—			19			251			72			—
Regulatory liability associated with the Tax Reform Legislation (not subject to normalization)	294			130			127			29			—			8
Other	731			147			140			47			47			285
Total deferred income tax assets	9,048			1,622			3,078			515			2,631			489
Valuation allowance	(123		)	—			(42		)	(41		)	(27		)	(12		)
Net deferred income tax assets	8,925			1,622			3,036			474			2,604			477
Net deferred income taxes (assets)/liabilities	$	6,282		$	2,962		$	3,062		$	228		$	(1,081	)	$	1,016
Recognized in the balance sheets:
Accumulated deferred income taxes – assets	$	(276	)	$	—		$	—		$	(150	)	$	(1,186	)	$	—
Accumulated deferred income taxes – liabilities	$	6,558		$	2,962		$	3,062		$	378		$	105		$	1,016

The traditional electric operating companies and natural gas distribution utilities have tax-related regulatory assets (deferred income tax charges) and regulatory liabilities (deferred income tax credits). The regulatory 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. The regulatory liabilities are primarily attributable to deferred taxes previously recognized at rates higher than the current enacted tax law and to unamortized ITCs. See Note 2 for each Registrant's related balances at December 31, 2019 and 2018.

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Tax Credit Carryforwards

Federal ITC/PTC carryforwards at December 31, 2019 were as follows:

	Southern Company			Alabama Power			Georgia Power			Southern Power
	(in millions)
Federal ITC/PTC carryforwards	$	1,751		$	11		$	88		$	1,445
Year in which federal ITC/PTC carryforwards begin expiring	2032			2033			2032			2036
Year by which federal ITC/PTC carryforwards are expected to be utilized	2024			2022			2022			2024

The estimated tax credit utilization reflects the various sale transactions described in Note 15 and could be further delayed by numerous factors, including the acquisition of additional renewable projects, the purchase of rights to additional PTCs of Plant Vogtle Units 3 and 4 pursuant to certain joint ownership agreements, and changes in taxable income projections. See Note 2 under "Georgia Power – Nuclear Construction" for additional information on Plant Vogtle Units 3 and 4.

At December 31, 2019, Georgia Power also had approximately $360 million in state investment and other state tax credit carryforwards for the State of Georgia that will expire between 2020 and 2029 and are not expected to be fully utilized. Georgia Power has a net state valuation allowance of $28 million associated with these carryforwards.

The ultimate outcome of these matters cannot be determined at this time.

Net Operating Loss Carryforwards

Southern Company has fully utilized the carryforward from federal NOLs generated in 2016 and 2017. At December 31, 2019, the state and local NOL carryforwards for Southern Company's subsidiaries were as follows:

Company/Jurisdiction	Approximate NOL Carryforwards			Approximate Net State Income Tax Benefit			Tax Year NOL Begins Expiring
	(in millions)
Mississippi Power
Mississippi	$	5,099		$	201		2031
Southern Power
Oklahoma	830			39			2035
Florida	258			11			2033
South Carolina	56			2			2034
Other states	21			2			Various
Southern Power Total	$	1,165		$	54
Other(*)
Georgia	171			7			2020
New York	220			11			2035
New York City	207			15			2035
Other states	368			18			Various
Southern Company Total	$	7,230		$	306

(*)	Represents other Southern Company subsidiaries. Alabama Power, Georgia Power, and Southern Company Gas did not have material state or local NOL carryforwards at December 31, 2019.

State NOLs for Mississippi, Oklahoma, and Florida are not expected to be fully utilized prior to expiration. At December 31, 2019, Mississippi Power had a net state valuation allowance of $32 million for the Mississippi NOL and Southern Power had net state valuation allowances of $16 million for the Oklahoma NOL and $11 million for the Florida NOL.

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The ultimate outcome of these matters cannot be determined at this time.

Unrecognized Tax Benefits

The Registrants had no material changes in unrecognized tax benefits during 2019. Unrecognized tax benefits changes in 2018 and 2017 for Southern Company, Mississippi Power, and Southern Power are provided below. The remaining Registrants did not have any material unrecognized tax benefits for the periods presented.

	Southern Company			Mississippi Power			Southern Power
	(in millions)
Unrecognized tax benefits at December 31, 2016	$	484		$	465		$	17
Tax positions changes –
Increase from current periods	10			—			—
Increase from prior periods	10			2			—
Decrease from prior periods	(196		)	(177		)	(17		)
Reductions due to settlements	(290		)	(290		)	—
Unrecognized tax benefits at December 31, 2017	18			—			—
Tax positions changes –
Decrease from prior periods	(18		)	—			—
Unrecognized tax benefits at December 31, 2018	$	—		$	—		$	—

Mississippi Power's tax positions changes from prior periods and reductions due to settlements for 2017 related to state tax benefits, deductions for R&E expenditures, and charitable contribution carryforwards that were impacted as a result of the settlement of R&E expenditures associated with the Kemper County energy facility, as well as federal income tax benefits from deferred ITCs. See Note 2 under "Mississippi Power – Kemper County Energy Facility" and "Section 174 Research and Experimental Deduction" herein for more information.

Southern Power's decrease from prior periods for 2017 primarily relates to federal income tax benefits from deferred ITCs.

The impact on the effective tax rate of Southern Company, if recognized, was as follows for 2017:

	Southern Company
	(in millions)
2017
Tax positions impacting the effective tax rate	$	18
Tax positions not impacting the effective tax rate	—
Balance of unrecognized tax benefits	$	18

All of the Registrants classify interest on tax uncertainties as interest expense. Accrued interest for all tax positions other than the Section 174 R&E deductions was immaterial for all years presented. None of the Registrants accrued any penalties on uncertain tax positions.

It is reasonably possible that the amount of the unrecognized tax benefits could change within 12 months. New audit findings or settlements associated with ongoing audits could result in significant unrecognized tax benefits. At this time, a range of reasonably possible outcomes cannot be determined.

The IRS has finalized its audits of Southern Company's consolidated federal income tax returns through 2018. Southern Company is a participant in the Compliance Assurance Process of the IRS. The audits for the Registrants' state income tax returns have either been concluded, or the statute of limitations has expired, for years prior to 2015.

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Section 174 Research and Experimental Deduction

Southern Company, on behalf of Mississippi Power, reflected deductions for R&E expenditures related to the Kemper County energy facility in its federal income tax returns, as amended, since 2008. In 2017, the U.S. Congress Joint Committee on Taxation approved a settlement between Southern Company and the IRS, resolving a methodology for these deductions. As a result of this approval, Mississippi Power recognized $176 million in 2017 of previously unrecognized tax benefits and reversed $36 million of associated accrued interest.

The Southern Company system has a qualified defined benefit, trusteed pension plan covering substantially all employees, with the exception of PowerSecure employees. The qualified pension plan is funded in accordance with requirements of the Employee Retirement Income Security Act of 1974, as amended (ERISA). In December 2019, the Registrants voluntarily contributed the following amounts to the qualified pension plan:

	Southern Company			Alabama Power			Georgia Power			Mississippi Power			Southern Power			Southern Company Gas
	(in millions)
Contributions to qualified pension plan	$	1,136		$	362		$	200		$	54		$	24		$	145

No mandatory contributions to the qualified pension plan are anticipated for the year ending December 31, 2020. The Southern Company system also provides certain non-qualified defined benefits for a select group of management and highly compensated employees, which are funded on a cash basis. In addition, the Southern Company system provides certain medical care and life insurance benefits for retired employees through other postretirement benefit plans. The traditional electric operating companies fund other postretirement trusts to the extent required by their respective regulatory commissions. Southern Company Gas 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, 2020, no contributions to any other postretirement trusts are expected.

In January 2018, the qualified defined benefit pension plan of Southern Company Gas was merged into the Southern Company system's qualified defined benefit pension plan and the pension plan was reopened to all non-union employees of Southern Company Gas. Prior to January 2018, Southern Company Gas had a separate qualified defined benefit, trusteed pension plan covering certain eligible employees, which was closed in 2012 to new employees. Also in January 2018, Southern Company Gas' non-qualified retirement plans were merged into the Southern Company system's non-qualified retirement plan (defined benefit and defined contribution).

Effective in December 2017, 538 employees transferred from SCS to Southern Power. Accordingly, Southern Power assumed various compensation and benefit plans including participation in the Southern Company system's qualified defined benefit, trusteed pension plan covering substantially all employees. With the transfer of employees, Southern Power assumed the related benefit obligations from SCS of $139 million for the qualified pension plan (along with trust assets of $138 million) and $11 million for other postretirement benefit plans, together with $36 million in prior service costs and net gains/losses in OCI. In 2018, Southern Power also began providing certain defined benefits under the non-qualified pension plan for a select group of management and highly compensated employees. No obligation related to these benefits was assumed in the employee transfer; however, obligations for services rendered by employees following the transfer are being recognized by Southern Power and are funded on a cash basis. In addition, Southern Power provides certain medical care and life insurance benefits for retired employees through other postretirement benefit plans that are funded on a cash basis. Prior to the transfer of employees in December 2017, substantially all expenses charged by SCS, including pension and other postretirement benefit costs, were recorded in Southern Power's other operations and maintenance expense. The disclosures included herein exclude Southern Power for periods prior to the transfer of employees in December 2017.

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On January 1, 2019, Southern Company completed the sale of Gulf Power to NextEra Energy. See Note 15 under "Southern Company" for additional information. The portion of the Southern Company system's pension and other postretirement benefit plans attributable to Gulf Power reflected in Southern Company's consolidated balance sheet as held for sale at December 31, 2018 consisted of:

	Pension Plans			Other Postretirement Benefit Plans
	(in millions)
Projected benefit obligation	$	526		$	69
Plan assets	492			17
Accrued liability	$	(34	)	$	(52	)

All amounts presented in the remainder of this note reflect the benefit plan obligations and related plan assets for the Southern Company system's pension and other postretirement benefit plans, including the amounts attributable to Gulf Power prior to January 1, 2019.

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.

	2019
Assumptions used to determine net periodic costs:	Southern Company		Alabama Power		Georgia Power		Mississippi Power		Southern Power		Southern Company Gas
Pension plans
Discount rate – benefit obligations	4.49	%	4.51	%	4.48	%	4.49	%	4.65	%	4.47	%
Discount rate – interest costs	4.12		4.14		4.10		4.12		4.35		4.11
Discount rate – service costs	4.70		4.73		4.72		4.73		4.75		4.57
Expected long-term return on plan assets	7.75		7.75		7.75		7.75		7.75		7.75
Annual salary increase	4.34		4.46		4.46		4.46		4.46		3.07
Other postretirement benefit plans
Discount rate – benefit obligations	4.37	%	4.40	%	4.36	%	4.35	%	4.50	%	4.32	%
Discount rate – interest costs	3.98		4.01		3.97		3.95		4.14		3.91
Discount rate – service costs	4.63		4.67		4.64		4.64		4.65		4.56
Expected long-term return on plan assets	6.86		6.76		6.85		6.79		—		6.49
Annual salary increase	4.34		4.46		4.46		4.46		4.46		3.07

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	2018
Assumptions used to determine net periodic costs:	Southern Company		Alabama Power		Georgia Power		Mississippi Power		Southern Power		Southern Company Gas
Pension plans
Discount rate – benefit obligations	3.80	%	3.81	%	3.79	%	3.80	%	3.94	%	3.74	%
Discount rate – interest costs	3.45		3.45		3.42		3.46		3.69		3.41
Discount rate – service costs	3.98		4.00		3.99		3.99		4.01		3.84
Expected long-term return on plan assets	7.95		7.95		7.95		7.95		7.95		7.95
Annual salary increase	4.34		4.46		4.46		4.46		4.46		3.07
Other postretirement benefit plans
Discount rate – benefit obligations	3.68	%	3.71	%	3.68	%	3.68	%	3.81	%	3.62	%
Discount rate – interest costs	3.29		3.31		3.29		3.29		3.47		3.21
Discount rate – service costs	3.91		3.93		3.91		3.91		3.93		3.82
Expected long-term return on plan assets	6.83		6.83		6.80		6.99		—		5.89
Annual salary increase	4.34		4.46		4.46		4.46		4.46		3.07

	2017
Assumptions used to determine net periodic costs:	Southern Company		Alabama Power		Georgia Power		Mississippi Power		Southern Company Gas
Pension plans
Discount rate – benefit obligations	4.40	%	4.44	%	4.40	%	4.44	%	4.39	%
Discount rate – interest costs	3.77		3.76		3.72		3.81		3.76
Discount rate – service costs	4.81		4.85		4.83		4.83		4.64
Expected long-term return on plan assets	7.92		7.95		7.95		7.95		7.60
Annual salary increase	4.37		4.46		4.46		4.46		3.50
Other postretirement benefit plans
Discount rate – benefit obligations	4.23	%	4.27	%	4.23	%	4.22	%	4.15	%
Discount rate – interest costs	3.54		3.58		3.55		3.55		3.40
Discount rate – service costs	4.64		4.70		4.63		4.65		4.55
Expected long-term return on plan assets	6.84		6.83		6.79		6.88		6.03
Annual salary increase	4.37		4.46		4.46		4.46		3.50

	2019
Assumptions used to determine benefit obligations:	Southern Company		Alabama Power		Georgia Power		Mississippi Power		Southern Power		Southern Company Gas
Pension plans
Discount rate	3.41	%	3.44	%	3.40	%	3.41	%	3.52	%	3.39	%
Annual salary increase	4.73		4.73		4.73		4.73		4.73		4.73
Other postretirement benefit plans
Discount rate	3.24	%	3.28	%	3.22	%	3.22	%	3.39	%	3.19	%
Annual salary increase	4.73		4.73		4.73		4.73		4.73		4.73

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	2018
Assumptions used to determine benefit obligations:	Southern Company		Alabama Power		Georgia Power		Mississippi Power		Southern Power		Southern Company Gas
Pension plans
Discount rate	4.49	%	4.51	%	4.48	%	4.49	%	4.65	%	4.47	%
Annual salary increase	4.34		4.46		4.46		4.46		4.46		3.07
Other postretirement benefit plans
Discount rate	4.37	%	4.40	%	4.36	%	4.35	%	4.50	%	4.32	%
Annual salary increase	4.34		4.46		4.46		4.46		4.46		3.07

The Registrants estimate 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 the 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 for the Registrants at December 31, 2019 were as follows:

	Initial Cost Trend Rate			Ultimate Cost Trend Rate			Year That Ultimate Rate is Reached
Pre-65	6.00	%		4.50	%		2027
Post-65 medical	5.00			4.50			2027
Post-65 prescription	6.50			4.50			2027

Pension Plans

The total accumulated benefit obligation for the pension plans at December 31, 2019 and 2018 was as follows:

	Southern Company			Alabama Power			Georgia Power			Mississippi Power			Southern Power			Southern Company Gas
	(in millions)
December 31, 2019	$	13,391		$	3,053		$	4,222		$	615		$	151		$	963
December 31, 2018	11,683			2,550			3,613			513			101			842

The actuarial loss of $2.3 billion recorded in the remeasurement of the Southern Company system pension plans at December 31, 2019 was primarily due to a 108 basis point decrease in the overall discount rate used to calculate the benefit obligation as a result of lower market interest rates. The actuarial gain of $1.1 billion recorded in the remeasurement of the Southern Company system pension plans at December 31, 2018 was primarily due to a 69 basis point increase in the overall discount rate used to calculate the benefit obligation as a result of higher market interest rates.

---

Changes in the projected benefit obligations and the fair value of plan assets during the plan years ended December 31, 2019 and 2018 were as follows:

	2019
	Southern Company			Alabama Power			Georgia Power			Mississippi Power			Southern Power			Southern Company Gas
	(in millions)
Change in benefit obligation
Benefit obligation at beginning of year	$	12,763		$	2,816		$	3,905		$	557		$	123		$	907
Dispositions	(509		)	—			—			—			—			—
Service cost	292			69			74			12			7			25
Interest cost	492			114			156			22			5			36
Benefits paid	(596		)	(125		)	(194		)	(26		)	(4		)	(64		)
Actuarial (gain) loss	2,346			530			669			106			54			163
Balance at end of year	14,788			3,404			4,610			671			185			1,067
Change in plan assets
Fair value of plan assets at beginning of year	11,611			2,575			3,663			505			123			798
Dispositions	(509		)	—			—			—			—			—
Actual return (loss) on plan assets	2,343			524			730			103			43			172
Employer contributions	1,208			383			243			59			7			144
Benefits paid	(596		)	(125		)	(194		)	(26		)	(4		)	(64		)
Fair value of plan assets at end of year	14,057			3,357			4,442			641			169			1,050
Accrued liability	$	(731	)	$	(47	)	$	(168	)	$	(30	)	$	(16	)	$	(17	)

	2018
	Southern Company			Alabama Power			Georgia Power			Mississippi Power			Southern Power			Southern Company Gas
	(in millions)
Change in benefit obligation
Benefit obligation at beginning of year	$	13,808		$	2,998		$	4,188		$	602		$	139		$	1,184
Dispositions	(107		)	—			—			—			(3		)	(104		)
Service cost	359			78			87			17			9			34
Interest cost	464			101			139			20			5			39
Benefits paid	(618		)	(124		)	(191		)	(24		)	(3		)	(98		)
Actuarial (gain) loss	(1,143		)	(237		)	(318		)	(58		)	(24		)	(148		)
Balance at end of year	12,763			2,816			3,905			557			123			907
Change in plan assets
Fair value of plan assets at beginning of year	12,992			2,836			4,058			563			138			1,068
Dispositions	(107		)	—			—			—			(3		)	(104		)
Actual return (loss) on plan assets	(711		)	(150		)	(218		)	(37		)	(9		)	(70		)
Employer contributions	55			13			14			3			—			2
Benefits paid	(618		)	(124		)	(191		)	(24		)	(3		)	(98		)
Fair value of plan assets at end of year	11,611			2,575			3,663			505			123			798
Accrued liability	$	(1,152	)	$	(241	)	$	(242	)	$	(52	)	$	—		$	(109	)

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The projected benefit obligations for the qualified and non-qualified pension plans at December 31, 2019 are shown in the following table. All pension plan assets are related to the qualified pension plan.

	Southern Company			Alabama Power			Georgia Power			Mississippi Power			Southern Power			Southern Company Gas
	(in millions)
Projected benefit obligations:
Qualified pension plan	$	14,055		$	3,286		$	4,480		$	639		$	159		$	999
Non-qualified pension plan	733			118			130			31			26			68

Amounts recognized in the balance sheets at December 31, 2019 and 2018 related to the Registrants' pension plans consist of the following:

	Southern Company			Alabama Power			Georgia Power			Mississippi Power			Southern Power			Southern Company Gas
	(in millions)
December 31, 2019:
Prepaid pension costs	$	2		$	71		$	—		$	2		$	10		$	—
Other regulatory assets, deferred(*)	4,072			1,130			1,416			204			—			172
Other deferred charges and assets	—			—			—			—			—			82
Other current liabilities	(54		)	(8		)	(11		)	(2		)	(2		)	(2		)
Employee benefit obligations	(679		)	(110		)	(157		)	(30		)	(24		)	(97		)
Other regulatory liabilities, deferred	(79		)	—			—			—			—			—
AOCI	185			—			—			—			46			(14		)
December 31, 2018:
Prepaid pension costs	$	—		$	—		$	—		$	—		$	1		$	—
Other regulatory assets, deferred(*)	3,566			955			1,230			167			—			160
Other deferred charges and assets	—			—			—			—			—			74
Other current liabilities	(55		)	(12		)	(15		)	(3		)	—			(3		)
Employee benefit obligations	(1,097		)	(229		)	(227		)	(49		)	(1		)	(179		)
Other regulatory liabilities, deferred	(108		)	—			—			—			—			—
AOCI	97			—			—			—			26			(44		)

(*)	Amounts for Southern Company exclude regulatory assets of $252 million and $268 million at December 31, 2019 and 2018, respectively, associated with unamortized amounts in Southern Company Gas' pension plans prior to its 2016 acquisition by Southern Company.

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Presented below are the amounts included in regulatory assets at December 31, 2019 and 2018 related to the portion of the defined benefit pension plan attributable to Southern Company, the traditional electric operating companies, and Southern Company Gas that had not yet been recognized in net periodic pension cost.

	Southern Company			Alabama Power			Georgia Power			Mississippi Power			Southern Company Gas
	(in millions)
Balance at December 31, 2019
Regulatory assets:
Prior service cost	$	13		$	6		$	10		$	2		$	(15	)
Net (gain) loss	3,980			1,124			1,406			201			113
Regulatory amortization	—			—			—			—			74
Total regulatory assets(*)	$	3,993		$	1,130		$	1,416		$	203		$	172
Balance at December 31, 2018
Regulatory assets:
Prior service cost	$	17		$	6		$	12		$	2		$	(17	)
Net (gain) loss	3,441			949			1,218			165			83
Regulatory amortization	—			—			—			—			94
Total regulatory assets(*)	$	3,458		$	955		$	1,230		$	167		$	160

(*)	Amounts for Southern Company exclude regulatory assets of $252 million and $268 million at December 31, 2019 and 2018, respectively, associated with unamortized amounts in Southern Company Gas' pension plans prior to its 2016 acquisition by Southern Company.

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The changes in the balance of regulatory assets related to the portion of the defined benefit pension plan attributable to Southern Company, the traditional electric operating companies, and Southern Company Gas for the years ended December 31, 2019 and 2018 are presented in the following table:

	Southern Company			Alabama Power			Georgia Power			Mississippi Power			Southern Company Gas
	(in millions)
Regulatory assets (liabilities):(*)
Balance at December 31, 2017	$	3,155		$	890		$	1,105		$	158		$	217
Net (gain) loss	498			120			196			19			20
Change in prior service costs	1			—			—			—			(18		)
Dispositions	12			—			—			—			(34		)
Reclassification adjustments:
Amortization of prior service costs	(4		)	(1		)	(2		)	—			2
Amortization of net gain (loss)	(204		)	(54		)	(69		)	(10		)	(12		)
Amortization of regulatory assets(*)	—			—			—			—			(15		)
Total reclassification adjustments	(208		)	(55		)	(71		)	(10		)	(25		)
Total change	303			65			125			9			(57		)
Balance at December 31, 2018	$	3,458		$	955		$	1,230		$	167		$	160
Net (gain) loss	801			213			231			42			30
Dispositions	(144		)	—			—			—			—
Reclassification adjustments:
Amortization of prior service costs	(3		)	(1		)	(1		)	—			2
Amortization of net gain (loss)	(119		)	(37		)	(44		)	(6		)	—
Amortization of regulatory assets(*)	—			—			—			—			(20		)
Total reclassification adjustments	(122		)	(38		)	(45		)	(6		)	(18		)
Total change	535			175			186			36			12
Balance at December 31, 2019	$	3,993		$	1,130		$	1,416		$	203		$	172

(*)	Amounts for Southern Company exclude regulatory assets of $252 million and $268 million at December 31, 2019 and 2018, respectively, associated with unamortized amounts in Southern Company Gas' pension plans prior to its 2016 acquisition by Southern Company.

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Presented below are the amounts included in AOCI at December 31, 2019 and 2018 related to the portion of the defined benefit pension plan attributable to Southern Company, Southern Power, and Southern Company Gas that had not yet been recognized in net periodic pension cost.

	Southern Company			Southern Power			Southern Company Gas
	(in millions)
Balance at December 31, 2019
AOCI:
Prior service cost	$	(3	)	$	—		$	(6	)
Net (gain) loss	188			46			(8		)
Total AOCI	$	185		$	46		$	(14	)
Balance at December 31, 2018
AOCI:
Prior service cost	$	(3	)	$	—		$	(6	)
Net (gain) loss	100			26			(38		)
Total AOCI	$	97		$	26		$	(44	)

The components of OCI related to the portion of the defined benefit pension plan attributable to Southern Company, Southern Power, and Southern Company Gas for the years ended December 31, 2019 and 2018 are presented in the following table:

	Southern Company			Southern Power			Southern Company Gas
	(in millions)
AOCI:
Balance at December 31, 2017	$	107		$	33		$	(42	)
Net (gain) loss	7			(5		)	6
Dispositions	(8		)	—			(8		)
Reclassification adjustments:
Amortization of net gain (loss)	(9		)	(2		)	—
Total reclassification adjustments	(9		)	(2		)	—
Total change	(10		)	(7		)	(2		)
Balance at December 31, 2018	$	97		$	26		$	(44	)
Net (gain) loss	88			20			30
Balance at December 31, 2019	$	185		$	46		$	(14	)

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Components of net periodic pension cost for the Registrants were as follows:

	Southern Company			Alabama Power			Georgia Power			Mississippi Power			Southern Power			Southern Company Gas
	(in millions)
2019
Service cost	$	292		$	69		$	74		$	12		$	7		$	25
Interest cost	492			114			156			22			5			36
Expected return on plan assets	(885		)	(206		)	(292		)	(40		)	(10		)	(60		)
Recognized net (gain) loss	120			37			44			6			1			2
Net amortization	2			—			1			—			—			14
Prior service cost	—			—			—			—			—			(3		)
Net periodic pension cost	$	21		$	14		$	(17	)	$	—		$	3		$	14
2018
Service cost	$	359		$	78		$	87		$	17		$	9		$	34
Interest cost	464			101			139			20			5			39
Expected return on plan assets	(943		)	(207		)	(296		)	(41		)	(10		)	(75		)
Recognized net (gain) loss	213			54			69			10			1			12
Net amortization	4			1			2			—			—			15
Prior service cost	—			—			—			—			—			(2		)
Net periodic pension cost	$	97		$	27		$	1		$	6		$	5		$	23
2017
Service cost	$	293		$	63		$	74		$	15					$	23
Interest cost	455			98			138			20						42
Expected return on plan assets	(897		)	(196		)	(283		)	(40		)				(70		)
Recognized net (gain) loss	162			42			57			7						18
Net amortization	12			2			3			1						1
Net periodic pension cost	$	25		$	9		$	(11	)	$	3					$	14

The service cost component of net periodic pension cost is included in operations and maintenance expenses and all other components of net periodic pension cost are included in other income (expense), net in the Registrants' statements of income.

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 Registrants have elected to amortize changes in the market value of return-seeking plan assets over five years and to recognize the changes in the market value of liability-hedging plan assets immediately. Given the significant concentration in return-seeking plan assets, 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.

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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, 2019, estimated benefit payments were as follows:

	Southern Company			Alabama Power			Georgia Power			Mississippi Power			Southern Power			Southern Company Gas
	(in millions)
Benefit Payments:
2020	$	628		$	135		$	204		$	27		$	5		$	62
2021	646			141			208			28			6			62
2022	671			147			214			30			6			64
2023	693			153			220			30			6			62
2024	715			157			226			32			7			62
2025 to 2029	3,868			860			1,209			174			36			316

Other Postretirement Benefits

Changes in the APBO and the fair value of the Registrants' plan assets during the plan years ended December 31, 2019 and 2018 were as follows:

	2019
	Southern Company			Alabama Power			Georgia Power			Mississippi Power			Southern Power			Southern Company Gas
	(in millions)
Change in benefit obligation
Benefit obligation at beginning of year	$	1,865		$	403		$	675		$	81		$	9		$	244
Dispositions	(69		)	—			—			—			—			—
Service cost	18			5			5			1			1			1
Interest cost	69			16			26			3			—			9
Benefits paid	(126		)	(27		)	(47		)	(6		)	(1		)	(17		)
Actuarial (gain) loss	223			63			80			8			2			13
Retiree drug subsidy	5			2			3			—			—			—
Balance at end of year	1,985			462			742			87			11			250
Change in plan assets
Fair value of plan assets at beginning of year	928			360			344			23			—			98
Dispositions	(18		)	—			—			—			—			—
Actual return (loss) on plan assets	189			76			68			4			—			21
Employer contributions	83			2			35			5			1			13
Benefits paid	(121		)	(25		)	(44		)	(6		)	(1		)	(17		)
Fair value of plan assets at end of year	1,061			413			403			26			—			115
Accrued liability	$	(924	)	$	(49	)	$	(339	)	$	(61	)	$	(11	)	$	(135	)

---

	2018
	Southern Company			Alabama Power			Georgia Power			Mississippi Power			Southern Power			Southern Company Gas
	(in millions)
Change in benefit obligation
Benefit obligation at beginning of year	$	2,339		$	517		$	863		$	97		$	11		$	310
Dispositions	(18		)	—			—			—			—			(18		)
Service cost	24			6			6			1			1			2
Interest cost	75			17			28			3			—			10
Benefits paid	(129		)	(28		)	(47		)	(5		)	(1		)	(17		)
Actuarial (gain) loss	(432		)	(111		)	(178		)	(15		)	(2		)	(43		)
Retiree drug subsidy	6			2			3			—			—			—
Balance at end of year	1,865			403			675			81			9			244
Change in plan assets
Fair value of plan assets at beginning of year	1,053			406			386			25			—			125
Dispositions	(18		)	—			—			—			—			(18		)
Actual return (loss) on plan assets	(57		)	(25		)	(20		)	(1		)	—			(5		)
Employer contributions	73			5			22			4			1			13
Benefits paid	(123		)	(26		)	(44		)	(5		)	(1		)	(17		)
Fair value of plan assets at end of year	928			360			344			23			—			98
Accrued liability	$	(937	)	$	(43	)	$	(331	)	$	(58	)	$	(9	)	$	(146	)

Amounts recognized in the balance sheets at December 31, 2019 and 2018 related to the Registrants' other postretirement benefit plans consist of the following:

	Southern Company			Alabama Power			Georgia Power			Mississippi Power			Southern Power			Southern Company Gas
	(in millions)
December 31, 2019:
Other regulatory assets, deferred(a)	$	183		$	3		$	96		$	10		$	—		$	(11	)
Other current liabilities	(5		)	—			—			—			—			—
Employee benefit obligations(b)	(919		)	(49		)	(339		)	(61		)	(11		)	(135		)
Other regulatory liabilities, deferred	(62		)	(2		)	—			—			—			—
AOCI	2			—			—			—			2			(4		)
December 31, 2018:
Other regulatory assets, deferred(a)	$	99		$	—		$	60		$	6		$	—		$	(4	)
Other current liabilities	(6		)	—			—			—			—			—
Employee benefit obligations(b)	(931		)	(43		)	(331		)	(58		)	(9		)	146
Other regulatory liabilities, deferred	(77		)	(8		)	—			(2		)	—			—
AOCI	(4		)	—			—			—			1			(4		)

(a)	Amounts for Southern Company exclude regulatory assets of $50 million and $57 million at December 31, 2019 and 2018, respectively, associated with unamortized amounts in Southern Company Gas' other postretirement benefit plans prior to its 2016 acquisition by Southern Company.

(b)	Included in other deferred credits and liabilities on Southern Power's consolidated balance sheets.

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Presented below are the amounts included in net regulatory assets (liabilities) at December 31, 2019 and 2018 related to the other postretirement benefit plans of Southern Company, the traditional electric operating companies, and Southern Company Gas that had not yet been recognized in net periodic other postretirement benefit cost.

	Southern Company			Alabama Power			Georgia Power			Mississippi Power			Southern Company Gas
	(in millions)
Balance at December 31, 2019:
Regulatory assets (liabilities):
Prior service cost	$	11		$	3		$	4		$	—		$	1
Net (gain) loss	110			(2		)	92			10			(43		)
Regulatory amortization	—			—			—			—			31
Total regulatory assets (liabilities)(*)	$	121		$	1		$	96		$	10		$	(11	)
Balance at December 31, 2018:
Regulatory assets (liabilities):
Prior service cost	$	14		$	8		$	4		$	—		$	2
Net (gain) loss	8			(16		)	56			4			(43		)
Regulatory amortization	—			—			—			—			37
Total regulatory assets (liabilities)(*)	$	22		$	(8	)	$	60		$	4		$	(4	)

(*)	Amounts for Southern Company exclude regulatory assets of $50 million and $57 million at December 31, 2019 and 2018, respectively, associated with unamortized amounts in Southern Company Gas' other postretirement benefit plans prior to its 2016 acquisition by Southern Company.

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The changes in the balance of net regulatory assets (liabilities) related to the other postretirement benefit plans for the plan years ended December 31, 2019 and 2018 are presented in the following table:

	Southern Company			Alabama Power			Georgia Power			Mississippi Power			Southern Company Gas
	(in millions)
Net regulatory assets (liabilities):(*)
Balance at December 31, 2017	$	341		$	56		$	202		$	17		$	46
Net (gain) loss	(298		)	(60		)	(132		)	(12		)	(42		)
Change in prior service costs	—			—			—			—			(2		)
Reclassification adjustments:
Amortization of prior service costs	(7		)	(4		)	(1		)	—			—
Amortization of net gain (loss)	(14		)	(1		)	(9		)	(1		)	—
Amortization of regulatory assets(*)	—			—			—			—			(6		)
Total reclassification adjustments	(21		)	(5		)	(10		)	(1		)	(6		)
Total change	(319		)	(65		)	(142		)	(13		)	(50		)
Balance at December 31, 2018	$	22		$	(9	)	$	60		$	4		$	(4	)
Net (gain) loss	90			14			37			6			(1		)
Dispositions	5			—			—			—			—
Change in prior service costs	5			—			—			—			—
Reclassification adjustments:
Amortization of prior service costs	(3		)	(4		)	—			—			—
Amortization of net gain (loss)	2			—			(1		)	—			—
Amortization of regulatory assets(*)	—			—			—			—			(6		)
Total reclassification adjustments	(1		)	(4		)	(1		)	—			(6		)
Total change	99			10			36			6			(7		)
Balance at December 31, 2019	$	121		$	1		$	96		$	10		$	(11	)

(*)	Amounts for Southern Company exclude regulatory assets of $50 million and $57 million at December 31, 2019 and 2018, respectively, associated with unamortized amounts in Southern Company Gas' other postretirement benefit plans prior to its 2016 acquisition by Southern Company.

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Presented below are the amounts included in AOCI at December 31, 2019 and 2018 related to the other postretirement benefit plans of Southern Company, Southern Power, and Southern Company Gas that had not yet been recognized in net periodic other postretirement benefit cost.

	Southern Company			Southern Power			Southern Company Gas
	(in millions)
Balance at December 31, 2019
AOCI:
Prior service cost	$	1		$	—		$	1
Net (gain) loss	1			2			(5		)
Total AOCI	$	2		$	2		$	(4	)
Balance at December 31, 2018
AOCI:
Prior service cost	$	1		$	—		$	1
Net (gain) loss	(5		)	1			(5		)
Total AOCI	$	(4	)	$	1		$	(4	)

The components of OCI related to the other postretirement benefit plans for the plan years ended December 31, 2019 and 2018 are presented in the following table:

	Southern Company			Southern Power			Southern Company Gas
	(in millions)
AOCI:
Balance at December 31, 2017	$	4		$	3		$	(3	)
Net (gain) loss	(8		)	(2		)	(2		)
Change from employee transfer	—			—			1
Total change	(8		)	(2		)	(1		)
Balance at December 31, 2018	$	(4	)	$	1		$	(4	)
Net (gain) loss	5			1			—
Reclassification adjustments:
Amortization of net gain (loss)	1			—			—
Total change	6			1			—
Balance at December 31, 2019	$	2		$	2		$	(4	)

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Components of the other postretirement benefit plans' net periodic cost for the Registrants were as follows:

	Southern Company			Alabama Power			Georgia Power			Mississippi Power			Southern Power			Southern Company Gas
	(in millions)
2019
Service cost	$	18		$	5		$	5		$	1		$	1		$	1
Interest cost	69			16			26			3			—			9
Expected return on plan assets	(65		)	(26		)	(25		)	(2		)	—			(7		)
Net amortization	—			4			1			—			—			6
Net periodic postretirement benefit cost	$	22		$	(1	)	$	7		$	2		$	1		$	9
2018
Service cost	$	24		$	6		$	6		$	1		$	1		$	2
Interest cost	75			17			28			3			—			10
Expected return on plan assets	(69		)	(26		)	(25		)	(2		)	—			(7		)
Net amortization	21			5			10			1			—			6
Net periodic postretirement benefit cost	$	51		$	2		$	19		$	3		$	1		$	11
2017
Service cost	$	24		$	6		$	7		$	1					$	2
Interest cost	79			17			29			3						10
Expected return on plan assets	(66		)	(25		)	(25		)	(1		)				(7		)
Net amortization	20			5			9			1						1
Net periodic postretirement benefit cost	$	57		$	3		$	20		$	4					$	6

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The service cost component of net periodic postretirement benefit cost is included in operations and maintenance expenses and all other components of net periodic postretirement benefit cost are included in other income (expense), net in the Registrants' statements of income.

The Registrants' 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. The Registrants' 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:

	Southern Company			Alabama Power			Georgia Power			Mississippi Power			Southern Power			Southern Company Gas
	(in millions)
Benefit payments:
2020	$	130		$	29		$	49		$	6		$	—		$	18
2021	129			29			49			6			—			18
2022	129			29			49			6			1			18
2023	130			29			49			6			1			19
2024	129			29			48			6			1			18
2025 to 2029	630			145			238			29			3			83
Subsidy receipts:
2020	$	(5	)	$	(1	)	$	(2	)	$	—		$	—		$	—
2021	(6		)	(2		)	(2		)	—			—			—
2022	(6		)	(2		)	(3		)	—			—			—
2023	(6		)	(2		)	(3		)	—			—			—
2024	(6		)	(2		)	(3		)	(1		)	—			—
2025 to 2029	(30		)	(9		)	(13		)	(2		)	—			—
Total:
2020	$	125		$	28		$	47		$	6		$	—		$	18
2021	123			27			47			6			—			18
2022	123			27			46			6			1			18
2023	124			27			46			6			1			19
2024	123			27			45			5			1			18
2025 to 2029	600			136			225			27			3			83

Benefit Plan Assets

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. The Registrants' 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 Registrants minimize the risk of large losses primarily through diversification but also monitor and manage other aspects of risk.

The investment strategy for plan assets related to the Southern Company system's qualified pension plan 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 portion of the liability of the pension plan 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 system 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. Management believes the portfolio is well-diversified with no significant concentrations of risk.

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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	Valuation Methodology
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 large and small capitalization growth and value stocks with developed and emerging markets exposure, managed both actively and through fundamental indexing approaches.	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 (such as commingled/pooled funds) are valued as Level 2 when the underlying holdings are comprised of Level 1 or Level 2 equity securities.
Fixed income: A mix of domestic and international bonds.	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.
Trust-owned life insurance (TOLI): Investments of taxable trusts aimed at minimizing the impact of taxes on the portfolio.	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.
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.	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 the Southern Company system's pension plans at December 31, 2019 and 2018 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. The Registrants did not have any investments classified as Level 3 at December 31, 2019 or 2018.

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These fair values exclude cash, receivables related to investment income and pending investment sales, and payables related to pending investment purchases.

	Fair Value Measurements Using
	Quoted Prices in Active Markets for Identical Assets			Significant Other Observable Inputs			Net Asset Value as a Practical Expedient						Target Allocation		Actual Allocation
At December 31, 2019:	(Level 1)			(Level 2)			(NAV)			Total
	(in millions)
Southern Company
Assets:
Equity:													51	%	51	%
Domestic equity	$	2,220		$	898		$	—		$	3,118
International equity	2,360			1,286			—			3,646
Fixed income:													23		29
U.S. Treasury, government, and agency bonds	—			965			—			965
Mortgage- and asset-backed securities	—			9			—			9
Corporate bonds	—			1,315			—			1,315
Pooled funds	—			684			—			684
Cash equivalents and other	1,317			—			—			1,317
Real estate investments	539			—			1,418			1,957			14		12
Special situations	—			—			155			155			3		1
Private equity	—			—			953			953			9		7
Total	$	6,436		$	5,157		$	2,526		$	14,119		100	%	100	%
Liabilities:
Derivatives	(1		)	—			—			(1		)
Total	$	6,435		$	5,157		$	2,526		$	14,118		100	%	100	%
Alabama Power
Assets:
Equity:													51	%	51	%
Domestic equity	$	530		$	214		$	—		$	744
International equity	564			307			—			871
Fixed income:													23		29
U.S. Treasury, government, and agency bonds	—			230			—			230
Mortgage- and asset-backed securities	—			2			—			2
Corporate bonds	—			314			—			314
Pooled funds	—			163			—			163
Cash equivalents and other	315			—			—			315
Real estate investments	129			—			339			468			14		12
Special situations	—			—			37			37			3		1
Private equity	—			—			228			228			9		7
Total	$	1,538		$	1,230		$	604		$	3,372		100	%	100	%

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	Fair Value Measurements Using
	Quoted Prices in Active Markets for Identical Assets			Significant Other Observable Inputs			Net Asset Value as a Practical Expedient						Target Allocation		Actual Allocation
At December 31, 2019:	(Level 1)			(Level 2)			(NAV)			Total
	(in millions)
Georgia Power
Assets:
Equity:													51	%	51	%
Domestic equity	$	701		$	284		$	—		$	985
International equity	746			407			—			1,153
Fixed income:													23		29
U.S. Treasury, government, and agency bonds	—			305			—			305
Mortgage- and asset-backed securities	—			3			—			3
Corporate bonds	—			415			—			415
Pooled funds	—			216			—			216
Cash equivalents and other	416			—			—			416
Real estate investments	170			—			448			618			14		12
Special situations	—			—			49			49			3		1
Private equity	—			—			301			301			9		7
Total	$	2,033		$	1,630		$	798		$	4,461		100	%	100	%
Mississippi Power
Assets:
Equity:													51	%	51	%
Domestic equity	$	101		$	41		$	—		$	142
International equity	108			59			—			167
Fixed income:													23		29
U.S. Treasury, government, and agency bonds	—			44			—			44
Corporate bonds	—			60			—			60
Pooled funds	—			31			—			31
Cash equivalents and other	60			—			—			60
Real estate investments	25			—			65			90			14		12
Special situations	—			—			7			7			3		1
Private equity	—			—			43			43			9		7
Total	$	294		$	235		$	115		$	644		100	%	100	%

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	Fair Value Measurements Using
	Quoted Prices in Active Markets for Identical Assets			Significant Other Observable Inputs			Net Asset Value as a Practical Expedient						Target Allocation		Actual Allocation
At December 31, 2019:	(Level 1)			(Level 2)			(NAV)			Total
	(in millions)
Southern Power
Assets:
Equity:													51	%	51	%
Domestic equity	$	27		$	11		$	—		$	38
International equity	28			16			—			44
Fixed income:													23		29
U.S. Treasury, government, and agency bonds	—			12			—			12
Corporate bonds	—			16			—			16
Pooled funds	—			8			—			8
Cash equivalents and other	16			—			—			16
Real estate investments	6			—			17			23			14		12
Special situations	—			—			2			2			3		1
Private equity	—			—			11			11			9		7
Total	$	77		$	63		$	30		$	170		100	%	100	%
Southern Company Gas
Assets:
Equity:													51	%	51	%
Domestic equity	$	166		$	67		$	—		$	233
International equity	176			96			—			272
Fixed income:													23		29
U.S. Treasury, government, and agency bonds	—			72			—			72
Mortgage- and asset-backed securities	—			1			—			1
Corporate bonds	—			98			—			98
Pooled funds	—			51			—			51
Cash equivalents and other	98			—			—			98
Real estate investments	40			—			106			146			14		12
Special situations	—			—			12			12			3		1
Private equity	—			—			71			71			9		7
Total	$	480		$	385		$	189		$	1,054		100	%	100	%

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	Fair Value Measurements Using
	Quoted Prices in Active Markets for Identical Assets			Significant Other Observable Inputs			Net Asset Value as a Practical Expedient						Target Allocation		Actual Allocation
At December 31, 2018:	(Level 1)			(Level 2)			(NAV)			Total
	(in millions)
Southern Company
Assets:
Equity:													51	%	53	%
Domestic equity	$	2,102		$	1,030		$	—		$	3,132
International equity	1,344			1,325			—			2,669
Fixed income:													23		24
U.S. Treasury, government, and agency bonds	—			930			—			930
Mortgage- and asset-backed securities	—			7			—			7
Corporate bonds	—			1,195			—			1,195
Pooled funds	—			654			—			654
Cash equivalents and other	270			2			—			272
Real estate investments	419			—			1,361			1,780			14		15
Special situations	—			—			171			171			3		1
Private equity	—			—			821			821			9		7
Total	$	4,135		$	5,143		$	2,353		$	11,631		100	%	100	%
Alabama Power
Assets:
Equity:													51	%	53	%
Domestic equity	$	466		$	228		$	—		$	694
International equity	298			293			—			591
Fixed income:													23		24
U.S. Treasury, government, and agency bonds	—			206			—			206
Mortgage- and asset-backed securities	—			2			—			2
Corporate bonds	—			265			—			265
Pooled funds	—			145			—			145
Cash equivalents and other	60			1			—			61
Real estate investments	93			—			302			395			14		15
Special situations	—			—			38			38			3		1
Private equity	—			—			182			182			9		7
Total	$	917		$	1,140		$	522		$	2,579		100	%	100	%

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	Fair Value Measurements Using
	Quoted Prices in Active Markets for Identical Assets			Significant Other Observable Inputs			Net Asset Value as a Practical Expedient						Target Allocation		Actual Allocation
At December 31, 2018:	(Level 1)			(Level 2)			(NAV)			Total
	(in millions)
Georgia Power
Assets:
Equity:													51	%	53	%
Domestic equity	$	663		$	325		$	—		$	988
International equity	424			418			—			842
Fixed income:													23		24
U.S. Treasury, government, and agency bonds	—			294			—			294
Mortgage- and asset-backed securities	—			2			—			2
Corporate bonds	—			377			—			377
Pooled funds	—			206			—			206
Cash equivalents and other	85			1			—			86
Real estate investments	132			—			429			561			14		15
Special situations	—			—			54			54			3		1
Private equity	—			—			259			259			9		7
Total	$	1,304		$	1,623		$	742		$	3,669		100	%	100	%
Mississippi Power
Assets:
Equity:													51	%	53	%
Domestic equity	$	91		$	45		$	—		$	136
International equity	59			59			—			118
Fixed income:													23		24
U.S. Treasury, government, and agency bonds	—			40			—			40
Corporate bonds	—			52			—			52
Pooled funds	—			28			—			28
Cash equivalents and other	12			—			—			12
Real estate investments	18			—			59			77			14		15
Special situations	—			—			7			7			3		1
Private equity	—			—			36			36			9		7
Total	$	180		$	224		$	102		$	506		100	%	100	%

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	Fair Value Measurements Using
	Quoted Prices in Active Markets for Identical Assets			Significant Other Observable Inputs			Net Asset Value as a Practical Expedient						Target Allocation		Actual Allocation
At December 31, 2018:	(Level 1)			(Level 2)			(NAV)			Total
	(in millions)
Southern Power
Assets:
Equity:													51	%	53	%
Domestic equity	$	22		$	11		$	—		$	33
International equity	14			14			—			28
Fixed income:													23		24
U.S. Treasury, government, and agency bonds	—			10			—			10
Corporate bonds	—			13			—			13
Pooled funds	—			7			—			7
Cash equivalents and other	3			—			—			3
Real estate investments	4			—			15			19			14		15
Special situations	—			—			2			2			3		1
Private equity	—			—			9			9			9		7
Total	$	43		$	55		$	26		$	124		100	%	100	%
Southern Company Gas
Assets:
Equity:													51	%	53	%
Domestic equity	$	145		$	71		$	—		$	216
International equity	92			91			—			183
Fixed income:													23		24
U.S. Treasury, government, and agency bonds	—			64			—			64
Corporate bonds	—			82			—			82
Pooled funds	—			45			—			45
Cash equivalents and other	19			—			—			19
Real estate investments	29			—			94			123			14		15
Special situations	—			—			12			12			3		1
Private equity	—			—			56			56			9		7
Total	$	285		$	353		$	162		$	800		100	%	100	%

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The fair values of the applicable Registrants' other postretirement benefit plan assets at December 31, 2019 and 2018 are presented below. The Registrants did not have any investments classified as Level 3 at December 31, 2019 or 2018. 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			Significant Other Observable Inputs			Net Asset Value as a Practical Expedient			Total			Target Allocation		Actual Allocation
At December 31, 2019:	(Level 1)			(Level 2)			(NAV)
	(in millions)
Southern Company
Assets:
Equity:													63	%	64	%
Domestic equity	$	95		$	81		$	—		$	176
International equity	69			80			—			149
Fixed income:													28		30
U.S. Treasury, government, and agency bonds	—			31			—			31
Corporate bonds	—			35			—			35
Pooled funds	—			82			—			82
Cash equivalents and other	42			—			—			42
Trust-owned life insurance	—			463			—			463
Real estate investments	15			—			38			53			5		4
Special situations	—			—			4			4			1		—
Private equity	—			—			25			25			3		2
Total	$	221		$	772		$	67		$	1,060		100	%	100	%
Alabama Power
Assets:
Equity:													68	%	67	%
Domestic equity	$	26		$	8		$	—		$	34
International equity	21			11			—			32
Fixed income:													24		27
U.S. Treasury, government, and agency bonds	—			10			—			10
Corporate bonds	—			11			—			11
Pooled funds	—			6			—			6
Cash equivalents and other	12			—			—			12
Trust-owned life insurance	—			281			—			281
Real estate investments	5			—			12			17			4		4
Special situations	—			—			1			1			1		—
Private equity	—			—			8			8			3		2
Total	$	64		$	327		$	21		$	412		100	%	100	%

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	Fair Value Measurements Using
	Quoted Prices in Active Markets for Identical Assets			Significant Other Observable Inputs			Net Asset Value as a Practical Expedient			Total			Target Allocation		Actual Allocation
At December 31, 2019:	(Level 1)			(Level 2)			(NAV)
	(in millions)
Georgia Power
Assets:
Equity:													60	%	61	%
Domestic equity	$	48		$	7		$	—		$	55
International equity	25			36			—			61
Fixed income:													33		34
U.S. Treasury, government, and agency bonds	—			7			—			7
Corporate bonds	—			11			—			11
Pooled funds	—			45			—			45
Cash equivalents and other	16			—			—			16
Trust-owned life insurance	—			182			—			182
Real estate investments	5			—			11			16			4		3
Special situations	—			—			1			1			1		—
Private equity	—			—			8			8			2		2
Total	$	94		$	288		$	20		$	402		100	%	100	%
Mississippi Power
Assets:
Equity:													43	%	41	%
Domestic equity	$	3		$	1		$	—		$	4
International equity	4			2			—			6
Fixed income:													37		42
U.S. Treasury, government, and agency bonds	—			6			—			6
Corporate bonds	—			2			—			2
Pooled funds	—			1			—			1
Cash equivalents and other	2			—			—			2
Real estate investments	1			—			2			3			11		10
Special situations	—			—			—			—			2		1
Private equity	—			—			1			1			7		6
Total	$	10		$	12		$	3		$	25		100	%	100	%

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	Fair Value Measurements Using
	Quoted Prices in Active Markets for Identical Assets			Significant Other Observable Inputs			Net Asset Value as a Practical Expedient			Total			Target Allocation		Actual Allocation
At December 31, 2019:	(Level 1)			(Level 2)			(NAV)
	(in millions)
Southern Company Gas
Assets:
Equity:													72	%	73	%
Domestic equity	$	2		$	58		$	—		$	60
International equity	2			21			—			23
Fixed income:													26		25
U.S. Treasury, government, and agency bonds	—			1			—			1
Corporate bonds	—			1			—			1
Pooled funds	—			25			—			25
Cash equivalents and other	2			—			—			2
Real estate investments	—			—			1			1			1		1
Private equity	—			—			1			1			1		1
Total	$	6		$	106		$	2		$	114		100	%	100	%

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	Fair Value Measurements Using
	Quoted Prices in Active Markets for Identical Assets			Significant Other Observable Inputs			Net Asset Value as a Practical Expedient						Target Allocation		Actual Allocation
At December 31, 2018:	(Level 1)			(Level 2)			(NAV)			Total
	(in millions)
Southern Company
Assets:
Equity:													62	%	62	%
Domestic equity	$	100		$	76		$	—		$	176
International equity	45			75			—			120
Fixed income:													29		30
U.S. Treasury, government, and agency bonds	—			34			—			34
Corporate bonds	—			35			—			35
Pooled funds	—			81			—			81
Cash equivalents and other	13			—			—			13
Trust-owned life insurance	—			386			—			386
Real estate investments	13			—			40			53			5		5
Special situations	—			—			4			4			1		—
Private equity	—			—			24			24			3		3
Total	$	171		$	687		$	68		$	926		100	%	100	%
Alabama Power
Assets:
Equity:													64	%	66	%
Domestic equity	$	35		$	10		$	—		$	45
International equity	12			12			—			24
Fixed income:													28		28
U.S. Treasury, government, and agency bonds	—			10			—			10
Corporate bonds	—			11			—			11
Pooled funds	—			6			—			6
Cash equivalents and other	3			—			—			3
Trust-owned life insurance	—			233			—			233
Real estate investments	4			—			13			17			4		4
Special situations	—			—			2			2			1		—
Private equity	—			—			8			8			3		2
Total	$	54		$	282		$	23		$	359		100	%	100	%

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	Fair Value Measurements Using
	Quoted Prices in Active Markets for Identical Assets			Significant Other Observable Inputs			Net Asset Value as a Practical Expedient						Target Allocation		Actual Allocation
At December 31, 2018:	(Level 1)			(Level 2)			(NAV)			Total
	(in millions)
Georgia Power
Assets:
Equity:													60	%	59	%
Domestic equity	$	41		$	9		$	—		$	50
International equity	17			32			—			49
Fixed income:													33		35
U.S. Treasury, government, and agency bonds	—			7			—			7
Corporate bonds	—			10			—			10
Pooled funds	—			44			—			44
Cash equivalents and other	5			—			—			5
Trust-owned life insurance	—			153			—			153
Real estate investments	4			—			11			15			4		4
Special situations	—			—			2			2			1		—
Private equity	—			—			7			7			2		2
Total	$	67		$	255		$	20		$	342		100	%	100	%
Mississippi Power
Assets:
Equity:													41	%	42	%
Domestic equity	$	3		$	2		$	—		$	5
International equity	2			2			—			4
Fixed income:													38		39
U.S. Treasury, government, and agency bonds	—			6			—			6
Corporate bonds	—			2			—			2
Pooled funds	—			1			—			1
Cash equivalents and other	1			—			—			1
Real estate investments	1			—			2			3			11		12
Special situations	—			—			—			—			3		1
Private equity	—			—			1			1			7		6
Total	$	7		$	13		$	3		$	23		100	%	100	%

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	Fair Value Measurements Using
	Quoted Prices in Active Markets for Identical Assets			Significant Other Observable Inputs			Net Asset Value as a Practical Expedient						Target Allocation		Actual Allocation
At December 31, 2018:	(Level 1)			(Level 2)			(NAV)			Total
	(in millions)
Southern Company Gas
Assets:
Equity:													71	%	69	%
Domestic equity	$	2		$	47		$	—		$	49
International equity	1			17			—			18
Fixed income:													25		28
U.S. Treasury, government, and agency bonds	—			1			—			1
Corporate bonds	—			1			—			1
Pooled funds	—			24			—			24
Cash equivalents and other	1			—			—			1
Real estate investments	—			—			1			1			2		2
Special situations	—			—			—			—			1		—
Private equity	—			—			1			1			1		1
Total	$	4		$	90		$	2		$	96		100	%	100	%

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 2019, 2018, and 2017 were as follows:

	Southern Company			Alabama Power			Georgia Power			Mississippi Power			Southern Power			Southern Company Gas
	(in millions)
2019	$	113		$	25		$	27		$	4		$	2		$	15
2018	119			24			26			5			3			18
2017	118			23			26			5			N/A			19

Stock-Based Compensation

Stock-based compensation primarily in the form of Southern Company performance share units (PSU) and restricted stock units (RSU) may be granted through the Omnibus Incentive Compensation Plan to Southern Company system employees ranging from line management to executives. Southern Company Gas and Southern Power had no employee participants in the stock-based compensation plans until 2017 and 2018, respectively. In conjunction with the Merger, stock-based compensation in the form of Southern Company RSUs and PSUs was granted to certain executives of Southern Company Gas through the Southern Company Omnibus Incentive Compensation Plan.

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At December 31, 2019, the number of current and former employees participating in stock-based compensation programs for the Registrants was as follows:

	Southern Company		Alabama Power		Georgia Power		Mississippi Power		Southern Power		Southern Company Gas
Number of employees	2,320		307		370		89		50		285

The majority of PSUs and RSUs awarded contain terms where employees become immediately vested in PSUs and RSUs upon retirement. 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. In addition, the Registrants recognize forfeitures as they occur.

All unvested PSUs and RSUs vest immediately upon a change in control where Southern Company is not the surviving corporation.

Performance Share Units

PSUs granted to employees vest at the end of a three-year performance period. 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 PSUs granted, based on achievement of the performance goals established by the Compensation Committee of the Southern Company Board of Directors.

Southern Company has issued three types of PSUs, each with a unique performance goal. These types of PSUs include total shareholder return (TSR) awards based on the TSR for Southern Company common stock during the three-year performance period as compared to a group of industry peers; ROE awards based on Southern Company's equity-weighted return over the performance period; and EPS awards based on Southern Company's cumulative EPS over the performance period. EPS awards were last granted in 2017.

The fair value of TSR 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 industry peers over the performance period. In determining the fair value of the TSR awards issued to employees, the expected volatility is based on the historical volatility of Southern Company's stock over a period equal to the performance period. The risk-free rate is 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 TSR awards granted:

Year Ended December 31	2019		2018		2017
Expected volatility	15.6%		14.9%		15.6%
Expected term (in years)	3		3		3
Interest rate	2.4%		2.4%		1.4%
Weighted average grant-date fair value	$62.71		$43.75		$49.08

The Registrants recognize TSR award compensation expense on a straight-line basis over the three-year performance period without remeasurement.

The fair values of EPS awards and ROE awards are based on the closing stock price of Southern Company common stock on the date of the grant. The weighted average grant-date fair value of the awards granted during 2019, 2018, and 2017 was $49.38, $43.49, and $49.21, respectively. Compensation expense for EPS and ROE awards is generally recognized ratably over the three-year performance period adjusted for expected changes in EPS and ROE performance. Total compensation cost recognized for vested EPS awards and ROE awards reflects final performance metrics.

Southern Company had 2.5 million unvested PSUs outstanding at December 31, 2018. In February 2019, the PSUs that vested for the three-year performance period ended December 31, 2018 were converted into 1.7 million shares outstanding at a share price of $49.24.

During 2019, Southern Company granted 1.2 million PSUs and 1.2 million PSUs were vested or forfeited, resulting in 2.5 million unvested PSUs outstanding at December 31, 2019. In February 2020, the PSUs that vested for the three-year performance period ended December 31, 2019 were converted into 1.8 million shares outstanding at a share price of $68.59.

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Total PSU compensation cost, and the related tax benefit recognized in income, for the years ended December 31, 2019, 2018, and 2017 are as follows:

	2019				2018				2017
	(in millions)
Southern Company
Compensation cost recognized in income	$	77			$	91			$	74
Tax benefit of compensation cost recognized in income	20				24				29
Southern Company Gas
Compensation cost recognized in income	$	14			$	11			$	8
Tax benefit of compensation cost recognized in income	4				3				3

Total PSU compensation cost and the related tax benefit recognized in income were immaterial for all periods presented for Alabama Power, Georgia Power, Mississippi Power, and Southern Power. The compensation cost related to the grant of Southern Company PSUs to the employees of each Subsidiary Registrant is recognized in each Subsidiary Registrant's financial statements with a corresponding credit to equity representing a capital contribution from Southern Company.

At December 31, 2019, Southern Company's total unrecognized compensation cost related to PSUs was $31 million and is expected to be recognized over a weighted-average period of approximately 12 months. The total unrecognized compensation cost related to PSUs as of December 31, 2019 was immaterial for all other Registrants.

Restricted Stock Units

The fair value of RSUs is based on the closing stock price of Southern Company common stock on the date of the grant. The weighted average grant-date fair values of RSUs granted during 2019, 2018, and 2017 were $50.44, $43.81, and $49.25, respectively. For most RSU awards, one-third of the RSUs vest each year throughout a three-year service period and compensation cost for RSUs is generally recognized over the corresponding one-, two-, or three-year vesting period. Shares of Southern Company common stock are delivered to employees at the end of each vesting period.

Southern Company had 1.1 million RSUs outstanding at December 31, 2018. During 2019, Southern Company granted 0.6 million RSUs and 0.4 million RSUs were vested or forfeited, resulting in 1.3 million unvested RSUs outstanding at December 31, 2019, including RSUs related to employee retention agreements.

For the years ended December 31, 2019, 2018, and 2017, Southern Company's total compensation cost for RSUs recognized in income was $28 million, $27 million, and $25 million, respectively. The related tax benefit also recognized in income was $7 million, $7 million, and $10 million for the years ended December 31, 2019, 2018, and 2017, respectively. Total unrecognized compensation cost related to RSUs as of December 31, 2019 for Southern Company of $14 million will be recognized over a weighted-average period of approximately 10 months.

Total RSUs outstanding and total compensation cost and related tax benefit for the RSUs recognized in income for the years ended December 31, 2019, 2018, and 2017, as well as the total unrecognized compensation cost as of December 31, 2019, were immaterial for all other Registrants. The compensation cost related to the grant of Southern Company RSUs to the employees of each Subsidiary Registrant is recognized in such Subsidiary Registrant's financial statements with a corresponding credit to equity representing a capital contribution from Southern Company.

Stock Options

In 2015, Southern Company discontinued granting stock options. Stock options expire no later than 10 years after the grant date and the latest possible exercise will occur by November 2024. As of December 31, 2019, the weighted average remaining contractual term for the options outstanding and exercisable was approximately three years.

As of December 31, 2017, all stock option awards are vested and compensation cost fully recognized. Total compensation cost for stock option awards and the related tax benefits recognized in income for the year ended December 31, 2017 were immaterial for Southern Company, Alabama Power, Georgia Power, and Mississippi Power.

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Southern Company's activity in the stock option program for 2019 is summarized below:

	Shares Subject to Option			Weighted Average Exercise Price
	(in millions)
Outstanding at December 31, 2018	17.5			$	41.92
Exercised	11.6			41.62
Outstanding and Exercisable at December 31, 2019	5.9			$	42.52

Southern Company's cash receipts from issuances related to stock options exercised under the share-based payment arrangements for the years ended December 31, 2019, 2018, and 2017 were $482 million, $41 million, and $239 million, respectively.

At December 31, 2019, the aggregate intrinsic value for the options outstanding and exercisable was as follows:

	Southern Company			Alabama Power			Georgia Power			Mississippi Power
	(in millions)
Total intrinsic value for outstanding and exercisable options	$	124		$	14		$	35		$	6

Total intrinsic value of options exercised, and the related tax benefit, for the years ended December 31, 2019, 2018, and 2017 are presented below:

Year Ended December 31	2019				2018				2017
	(in millions)
Southern Company
Intrinsic value of options exercised	$	167			$	9			$	64
Tax benefit of options exercised	35				2				25
Alabama Power
Intrinsic value of options exercised	$	21			$	2			$	12
Tax benefit of options exercised	4				—				5
Georgia Power
Intrinsic value of options exercised	$	30			$	2			$	13
Tax benefit of options exercised	6				—				5
Mississippi Power
Intrinsic value of options exercised	$	4			$	1			$	2
Tax benefit of options exercised	1				—				1

Total intrinsic value of options exercised, and the related tax benefit recognized in income, for the years ended December 31, 2019 and 2018 was immaterial for Southern Power and Southern Company Gas.

Merger Stock Compensation

Southern Company Restricted Stock Awards

At the effective time of the Merger, each outstanding award of existing Southern Company Gas PSUs was converted into an award of Southern Company RSUs. Under the terms of the restricted stock awards, the employees received Southern Company stock when they satisfied the requisite service period by being continuously employed through the original three-year vesting schedule of the award being replaced. Southern Company issued 0.7 million 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. Approximately $13 million of the grant date fair value, which was related to pre-combination service, was accounted for as Merger consideration. Southern Company Gas recognized the remaining fair value as compensation expense on a straight-line basis over the remaining vesting period. The compensation cost related to the grant of RSUs to Southern Company Gas employees is recognized in Southern Company Gas' financial statements with a corresponding credit to equity, representing a capital contribution from Southern Company. As of

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December 31, 2018, all RSUs were vested. For the years ended December 31, 2018 and 2017, total compensation cost for RSUs recognized in income and the related tax benefit were immaterial.

Southern Company Gas Change in Control Awards

Southern Company awarded PSUs 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 vested and were issued one-third each year as long as the employee remained in service with Southern Company or its subsidiaries at each vest date. In addition to the change in control benefit, Southern Company common stock was 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 were accounted for as a liability award with the fair value equal to the guaranteed dollar value of the change in control benefit. The compensation cost of the change in control benefit was recognized in Southern Company Gas' financial statements with a corresponding credit to a liability. 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 compensation cost of the achievement shares was recognized in Southern Company Gas' financial statements with a corresponding credit to equity, representing a capital contribution from Southern Company. The expected payout was reevaluated annually with expense recognized to date increased or decreased proportionately based on the expected performance. The compensation cost ultimately recognized for the achievement shares was based on the actual performance. As of December 31, 2019, all change in control awards are vested. For the year ended December 31, 2017, total compensation cost and the related tax benefit for the change in control awards recognized in income was $12 million and $6 million, respectively. Total compensation cost and the related tax benefit for the change in control awards recognized in income were immaterial for all other periods presented.

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 each Registrant of what a market participant would use in pricing an asset or liability. If there is little available market data, then each Registrant'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.

Net asset value as a practical expedient is the classification used for assets that do not have readily determinative fair values. Fund managers value the assets using various inputs and techniques depending on the nature of the underlying investments.

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At December 31, 2019, 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				Significant Other Observable Inputs				Significant Unobservable Inputs				Net Asset Value as a Practical Expedient
At December 31, 2019:	(Level 1)				(Level 2)				(Level 3)				(NAV)				Total
	(in millions)
Southern Company
Assets:
Energy-related derivatives(a)(b)	$	388			$	267			$	22			$	—			$	677
Interest rate derivatives	—				2				—				—				2
Foreign currency derivatives	—				16				—				—				16
Investments in trusts:(c)(d)
Domestic equity	751				135				—				—				886
Foreign equity	68				220				—				—				288
U.S. Treasury and government agency securities	—				307				—				—				307
Municipal bonds	—				85				—				—				85
Pooled funds – fixed income	—				17				—				—				17
Corporate bonds	23				297				—				—				320
Mortgage and asset backed securities	—				87				—				—				87
Private equity	—				—				—				56				56
Cash and cash equivalents	1				—				—				—				1
Other	17				5				—				—				22
Cash equivalents	1,393				2				—				—				1,395
Other investments	9				21				—				—				30
Total	$	2,650			$	1,461			$	22			$	56			$	4,189
Liabilities:
Energy-related derivatives(a)(b)	$	442			$	254			$	7			$	—			$	703
Interest rate derivatives	—				24				—				—				24
Foreign currency derivatives	—				24				—				—				24
Contingent consideration	—				—				19				—				19
Total	$	442			$	302			$	26			$	—			$	770

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	Fair Value Measurements Using
	Quoted Prices in Active Markets for Identical Assets				Significant Other Observable Inputs				Significant Unobservable Inputs				Net Asset Value as a Practical Expedient
At December 31, 2019:	(Level 1)				(Level 2)				(Level 3)				(NAV)				Total
	(in millions)
Alabama Power
Assets:
Energy-related derivatives	$	—			$	4			$	—			$	—			$	4
Nuclear decommissioning trusts:(c)
Domestic equity	488				123				—				—				611
Foreign equity	68				64				—				—				132
U.S. Treasury and government agency securities	—				21				—				—				21
Municipal bonds	—				1				—				—				1
Corporate bonds	23				144				—				—				167
Mortgage and asset backed securities	—				29				—				—				29
Private equity	—				—				—				56				56
Other	3				1				—				—				4
Cash equivalents	691				2				—				—				693
Other investments	—				21				—				—				21
Total	$	1,273			$	410			$	—			$	56			$	1,739
Liabilities:
Energy-related derivatives	$	—			$	24			$	—			$	—			$	24
Georgia Power
Assets:
Energy-related derivatives	$	—			$	4			$	—			$	—			$	4
Nuclear decommissioning trusts:(c)(d)
Domestic equity	263				1				—				—				264
Foreign equity	—				152				—				—				152
U.S. Treasury and government agency securities	—				286				—				—				286
Municipal bonds	—				84				—				—				84
Corporate bonds	—				153				—				—				153
Mortgage and asset backed securities	—				57				—				—				57
Other	13				4				—				—				17
Total	$	276			$	741			$	—			$	—			$	1,017
Liabilities:
Energy-related derivatives	$	—			$	53			$	—			$	—			$	53
Interest rate derivatives	—				17				—				—				17
Total	$	—			$	70			$	—			$	—			$	70

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	Fair Value Measurements Using
	Quoted Prices in Active Markets for Identical Assets				Significant Other Observable Inputs				Significant Unobservable Inputs				Net Asset Value as a Practical Expedient
At December 31, 2019:	(Level 1)				(Level 2)				(Level 3)				(NAV)				Total
	(in millions)
Mississippi Power
Assets:
Energy-related derivatives	$	—			$	1			$	—			$	—			$	1
Cash equivalents	281				—				—				—				281
Total	$	281			$	1			$	—			$	—			$	282
Liabilities:
Energy-related derivatives	$	—			$	27			$	—			$	—			$	27
Southern Power
Assets:
Energy-related derivatives	$	—			$	3			$	—			$	—			$	3
Foreign currency derivatives	—				16				—				—				16
Cash equivalents	113				—				—				—				113
Total	$	113			$	19			$	—			$	—			$	132
Liabilities:
Energy-related derivatives	$	—			$	3			$	—			$	—			$	3
Foreign currency derivatives	—				24				—				—				24
Contingent consideration	—				—				19				—				19
Total	$	—			$	27			$	19			$	—			$	46
Southern Company Gas
Assets:
Energy-related derivatives(a)(b)	$	388			$	255			$	22			$	—			$	665
Interest rate derivatives	—				2				—				—				2
Non-qualified deferred compensation trusts:
Domestic equity	—				11				—				—				11
Foreign equity	—				4				—				—				4
Pooled funds - fixed income	—				17				—				—				17
Cash equivalents	1				—				—				—				1
Cash equivalents	8				—				—				—				8
Total	$	397			$	289			$	22			$	—			$	708
Liabilities:
Energy-related derivatives(a)(b)	$	442			$	147			$	7			$	—			$	596

(a)	Energy-related derivatives exclude $4 million associated with premiums and certain weather derivatives accounted for based on intrinsic value rather than fair value.

(b)	Energy-related derivatives exclude cash collateral of $99 million.

(c)	Excludes receivables related to investment income, pending investment sales, payables related to pending investment purchases, and currencies. See Note 6 under "Nuclear Decommissioning" for additional information.

(d)	Includes investment securities pledged to creditors and collateral received and excludes payables related to the securities lending program. See Note 6 under "Nuclear Decommissioning" for additional information.

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At December 31, 2018, 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				Significant Other Observable Inputs				Significant Unobservable Inputs				Net Asset Value as a Practical Expedient
At December 31, 2018:	(Level 1)				(Level 2)				(Level 3)				(NAV)				Total
	(in millions)
Southern Company
Assets:
Energy-related derivatives(a)(b)	$	469			$	292			$	—			$	—			$	761
Foreign currency derivatives	—				75				—				—				75
Investments in trusts:(c)(d)
Domestic equity	601				107				—				—				708
Foreign equity	53				173				—				—				226
U.S. Treasury and government agency securities	—				261				—				—				261
Municipal bonds	—				83				—				—				83
Pooled funds – fixed income	—				14				—				—				14
Corporate bonds	24				290				—				—				314
Mortgage and asset backed securities	—				68				—				—				68
Private equity	—				—				—				45				45
Cash and cash equivalents	16				—				—				—				16
Other	34				4				—				—				38
Cash equivalents	765				1				—				—				766
Other investments	—				12				—				—				12
Total	$	1,962			$	1,380			$	—			$	45			$	3,387
Liabilities:
Energy-related derivatives(a)(b)	$	648			$	316			$	—			$	—			$	964
Interest rate derivatives	—				49				—				—				49
Foreign currency derivatives	—				23				—				—				23
Contingent consideration	—				—				21				—				21
Total	$	648			$	388			$	21			$	—			$	1,057

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	Fair Value Measurements Using
	Quoted Prices in Active Markets for Identical Assets				Significant Other Observable Inputs				Significant Unobservable Inputs				Net Asset Value as a Practical Expedient
At December 31, 2018:	(Level 1)				(Level 2)				(Level 3)				(NAV)				Total
	(in millions)
Alabama Power
Assets:
Energy-related derivatives	$	—			$	6			$	—			$	—			$	6
Nuclear decommissioning trusts:(c)
Domestic equity	396				95				—				—				491
Foreign equity	53				50				—				—				103
U.S. Treasury and government agency securities	—				18				—				—				18
Municipal bonds	—				1				—				—				1
Corporate bonds	24				135				—				—				159
Mortgage and asset backed securities	—				23				—				—				23
Private equity	—				—				—				45				45
Other	6				—				—				—				6
Cash equivalents	116				1				—				—				117
Other investments	—				12				—				—				12
Total	$	595			$	341			$	—			$	45			$	981
Liabilities:
Energy-related derivatives	$	—			$	10			$	—			$	—			$	10
Georgia Power
Assets:
Energy-related derivatives	$	—			$	6			$	—			$	—			$	6
Nuclear decommissioning trusts:(c)(d)
Domestic equity	205				1				—				—				206
Foreign equity	—				119				—				—				119
U.S. Treasury and government agency securities	—				243				—				—				243
Municipal bonds	—				82				—				—				82
Corporate bonds	—				155				—				—				155
Mortgage and asset backed securities	—				45				—				—				45
Other	19				4				—				—				23
Total	$	224			$	655			$	—			$	—			$	879
Liabilities:
Energy-related derivatives	$	—			$	21			$	—			$	—			$	21
Interest rate derivatives	—				2				—				—				2
Total	$	—			$	23			$	—			$	—			$	23

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	Fair Value Measurements Using
	Quoted Prices in Active Markets for Identical Assets				Significant Other Observable Inputs				Significant Unobservable Inputs				Net Asset Value as a Practical Expedient
At December 31, 2018:	(Level 1)				(Level 2)				(Level 3)				(NAV)				Total
	(in millions)
Mississippi Power
Assets:
Energy-related derivatives	$	—			$	3			$	—			$	—			$	3
Cash equivalents	255				—				—				—				255
Total	$	255			$	3			$	—			$	—			$	258
Liabilities:
Energy-related derivatives	$	—			$	9			$	—			$	—			$	9
Southern Power
Assets:
Energy-related derivatives	$	—			$	4			$	—			$	—			$	4
Foreign currency derivatives	—				75				—				—				75
Cash equivalents	46				—				—				—				46
Total	$	46			$	79			$	—			$	—			$	125
Liabilities:
Energy-related derivatives	$	—			$	8			$	—			$	—			$	8
Foreign currency derivatives	—				23				—				—				23
Contingent consideration	—				—				21				—				21
Total	$	—			$	31			$	21			$	—			$	52
Southern Company Gas
Assets:
Energy-related derivatives(a)(b)	$	469			$	272			$	—			$	—			$	741
Non-qualified deferred compensation trusts:
Domestic equity	—				11				—				—				11
Foreign equity	—				4				—				—				4
Pooled funds - fixed income	—				14				—				—				14
Cash equivalents	4				—				—				—				4
Cash equivalents	40				—				—				—				40
Total	$	513			$	301			$	—			$	—			$	814
Liabilities:
Energy-related derivatives(a)(b)	$	648			$	261			$	—			$	—			$	909

(a)	Energy-related derivatives exclude $8 million associated with premiums and certain weather derivatives accounted for based on intrinsic value rather than fair value.

(b)	Energy-related derivatives exclude cash collateral of $277 million.

(c)	Excludes receivables related to investment income, pending investment sales, payables related to pending investment purchases, and currencies. See Note 6 under "Nuclear Decommissioning" for additional information.

(d)	Includes investment securities pledged to creditors and collateral received and excludes payables related to the securities lending program. See Note 6 under "Nuclear Decommissioning" for additional information.

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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 14 for additional information on how these derivatives are used.

For fair value measurements of the investments within the nuclear decommissioning trusts and the non-qualified deferred compensation 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.

The NRC requires licensees of commissioned nuclear power reactors to establish a plan for providing reasonable assurance of funds for future decommissioning. See Note 6 under "Nuclear Decommissioning" for additional information.

Southern Power has contingent payment obligations related to certain acquisitions whereby Southern Power is primarily obligated to make generation-based payments to the seller, which commenced at the commercial operation of the respective facility and continue through 2026. The obligation is categorized as Level 3 under Fair Value Measurements as the fair value is determined using significant unobservable inputs for the forecasted facility generation in MW-hours, as well as other inputs such as a fixed dollar amount per MW-hour, and a discount rate. The fair value of contingent consideration reflects the net present value of expected payments and any periodic change arising from forecasted generation is expected to be immaterial.

"Other investments" include investments traded in the open market that have maturities greater than 90 days, which are categorized as Level 2 under Fair Value Measurements and are comprised of corporate bonds, treasury bonds, and/or agency bonds.

The fair value measurements of private equity investments held in Alabama Power's nuclear decommissioning trusts that are calculated at net asset value per share (or its equivalent) as a practical expedient totaled $56 million and $45 million at December 31, 2019 and 2018, respectively. Unfunded commitments related to the private equity investments totaled $70 million and $50 million at December 31, 2019 and 2018, respectively. Private equity investments include high-quality private equity funds across several market sectors and funds that invest in real estate assets. Private equity funds do not have redemption rights. Distributions from these funds will be received as the underlying investments in the funds are liquidated.

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At December 31, 2019 and 2018, other financial instruments for which the carrying amount did not equal fair value were as follows:

	Southern   Company(a)(b)			Alabama Power			Georgia Power			Mississippi Power			Southern Power			Southern Company Gas(b)
	(in millions)
At December 31, 2019:
Long-term debt, including securities due within one year:
Carrying amount	$	44,561		$	8,517		$	11,660		$	1,589		$	4,398		$	5,845
Fair value	48,339			9,525			12,680			1,671			4,708			6,509
At December 31, 2018:
Long-term debt, including securities due within one year:
Carrying amount	$	45,023		$	8,120		$	9,838		$	1,579		$	5,017		$	5,940
Fair value	44,824			8,370			9,800			1,546			4,980			5,965

(a)	Amounts at December 31, 2018 include long-term debt of Gulf Power, which was classified as liabilities held for sale on Southern Company's balance sheet at December 31, 2018. See Note 15 under "Southern Company" and "Assets Held for Sale" for additional information.

(b)	The long-term debt of Southern Company Gas is recorded at amortized cost, including the fair value adjustments at the effective date of the Merger. Southern Company Gas amortizes the fair value adjustments over the lives of the respective bonds.

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 the Registrants.

	2019
	(in millions)
Beginning balance	$	—
Transfers to Level 3	(32		)
Transfers from Level 3	3
Instruments realized or otherwise settled during period	(4		)
Changes in fair value	47
Ending balance	$	14

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Southern Company, the traditional electric operating companies, Southern Power, and Southern Company Gas are 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. Southern Company Gas' wholesale gas operations use various contracts in its commercial activities that generally meet the definition of derivatives. For the traditional electric operating companies, Southern Power, and Southern Company Gas' other businesses, 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 13 for additional fair value information. In the statements of cash flows, any cash impacts of settled energy-related and interest rate derivatives are recorded as operating activities. Any 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

The traditional electric operating companies, Southern Power, and Southern Company Gas 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 the 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 of Southern Company Gas 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 are expected to continue to mitigate price volatility. The traditional electric operating companies (with respect to wholesale generating capacity) and Southern Power have limited 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 retains exposure to price changes that can, in a volatile energy market, be material and can adversely affect its results of operations.

Southern Company Gas also enters into weather derivative contracts as economic hedges of 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 operating revenues.

Energy-related derivative contracts are accounted for under one of three methods:

•

Regulatory Hedges – Energy-related derivative contracts designated as regulatory hedges relate primarily to the traditional electric operating companies' and the 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 AOCI before being recognized in the statements of income in the same period and in the same income statement line item as the earnings effect of the hedged transactions.

•	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.

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At December 31, 2019, the net volume of energy-related derivative contracts for natural gas positions, together with the longest hedge date 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 for derivatives not designated as hedges, were as follows:

	Net Purchased mmBtu		Longest Hedge Date		Longest Non-Hedge Date
	(in millions)
Southern Company(*)	589		2023		2029
Alabama Power	88		2022		—
Georgia Power	175		2023		—
Mississippi Power	101		2023		—
Southern Power	7		2020		2020
Southern Company Gas(*)	218		2022		2029

(*)

Southern Company Gas' derivative instruments include both long and short natural gas positions. A long position is a contract to purchase natural gas and a short position is a contract to sell natural gas. Southern Company Gas' volume represents the net of long natural gas positions of 4,096 million mmBtu and short natural gas positions of 3,878 million mmBtu at December 31, 2019, which is also included in Southern Company's total volume.

At December 31, 2019, the net volume of Southern Power's energy-related derivative contracts for power to be sold was 1 million MWHs, all of which expire in 2020.

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 natural gas due to operational constraints. The maximum expected volume of natural gas subject to such a feature is 23 million mmBtu for Southern Company, which includes 6 million mmBtu for Alabama Power, 7 million mmBtu for Georgia Power, 3 million mmBtu for Mississippi Power, and 7 million mmBtu for Southern Power.

For cash flow hedges of energy-related derivatives, the estimated pre-tax gains (losses) expected to be reclassified from AOCI to earnings for the year ending December 31, 2020 are immaterial for Southern Power.

Interest Rate Derivatives

Southern Company and certain subsidiaries may 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 derivatives' fair value gains or losses are recorded in OCI and are reclassified into earnings at the same time and presented on the same income statement line item as the earnings effect of the hedged transactions. 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 on the same income statement line item. 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.

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At December 31, 2019, the following interest rate derivatives were outstanding:

	Notional Amount				Interest Rate Received		Weighted Average Interest Rate Paid		Hedge Maturity Date		Fair Value Gain (Loss) December 31, 2019
	(in millions)										(in millions)
Cash Flow Hedges of Forecasted Debt
Georgia Power	$	250			3-month LIBOR		2.23%		March 2025		$	(6	)
Georgia Power	250				3-month LIBOR		2.40%		March 2030		(11		)
Southern Company Gas	200				3-month LIBOR		1.81%		September 2030		2
Fair Value Hedges of Existing Debt
Southern Company parent	300				2.75%		3-month LIBOR + 0.92%		June 2020		—
Southern Company parent	1,500				2.35%		1-month LIBOR + 0.87%		July 2021		(7		)
Southern Company	$	2,500									$	(22	)

The estimated pre-tax gains (losses) related to interest rate derivatives expected to be reclassified from AOCI to interest expense for the year ending December 31, 2020 total $(22) million for Southern Company and are immaterial for all other Registrants. Deferred gains and losses related to interest rate derivatives are expected to be amortized into earnings through 2046 for the Southern Company parent entity, 2035 for Alabama Power, 2044 for Georgia Power, 2028 for Mississippi Power, and 2046 for Southern Company Gas.

Foreign Currency Derivatives

Southern Company and certain subsidiaries, including Southern Power, may 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 derivatives' fair value gains or losses are recorded in OCI and are reclassified into earnings at the same time and on the same income statement line as the earnings effect of the hedged transactions, including foreign currency gains or losses arising from changes in the U.S. currency exchange rates. The derivatives employed as hedging instruments are structured to minimize ineffectiveness.

At December 31, 2019, the following foreign currency derivatives were outstanding:

	Pay Notional			Pay Rate	Receive Notional			Receive Rate	Hedge Maturity Date	Fair Value Gain (Loss) December 31, 2019
	(in millions)				(in millions)					(in millions)
Cash Flow Hedges of Existing Debt
Southern Power	$	677		2.95%	€	600		1.00%	June 2022	$	(7	)
Southern Power	564			3.78%	500			1.85%	June 2026	(1		)
Total	$	1,241			€	1,100				$	(8	)

The estimated pre-tax gains (losses) related to Southern Power's foreign currency derivatives expected to be reclassified from AOCI to earnings for the year ending December 31, 2020 are $(24) million.

Derivative Financial Statement Presentation and Amounts

Southern Company, the traditional electric operating companies, Southern Power, and Southern Company Gas enter into derivative contracts that may contain certain 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

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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. The 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, 2019 and 2018, the fair value of energy-related derivatives, interest rate derivatives, and foreign currency derivatives was reflected in the balance sheets as follows:

	2019						2018
Derivative Category and Balance Sheet Location	Assets			Liabilities			Assets			Liabilities
	(in millions)
Southern Company
Derivatives designated as hedging instruments for regulatory purposes
Energy-related derivatives:
Other current assets/Other current liabilities	$	3		$	70		$	8		$	23
Other deferred charges and assets/Other deferred credits and liabilities	6			44			9			26
Assets held for sale, current/Liabilities held for sale, current	—			—			—			6
Total derivatives designated as hedging instruments for regulatory purposes	$	9		$	114		$	17		$	55
Derivatives designated as hedging instruments in cash flow and fair value hedges
Energy-related derivatives:
Other current assets/Other current liabilities	$	1		$	6		$	3		$	7
Other deferred charges and assets/Other deferred credits and liabilities	—			—			1			2
Interest rate derivatives:
Other current assets/Other current liabilities	2			23			—			19
Other deferred charges and assets/Other deferred credits and liabilities	—			1			—			30
Foreign currency derivatives:
Other current assets/Other current liabilities	—			24			—			23
Other deferred charges and assets/Other deferred credits and liabilities	16			—			75			—
Total derivatives designated as hedging instruments in cash flow and fair value hedges	$	19		$	54		$	79		$	81
Derivatives not designated as hedging instruments
Energy-related derivatives:
Other current assets/Other current liabilities	$	461		$	358		$	561		$	575
Other deferred charges and assets/Other deferred credits and liabilities	207			225			180			325
Total derivatives not designated as hedging instruments	$	668		$	583		$	741		$	900
Gross amounts recognized	$	696		$	751		$	837		$	1,036
Gross amounts offset(a)	$	(463	)	$	(562	)	$	(524	)	$	(801	)
Net amounts recognized in the Balance Sheets(b)	$	233		$	189		$	313		$	235

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	2019						2018
Derivative Category and Balance Sheet Location	Assets			Liabilities			Assets			Liabilities
	(in millions)
Alabama Power
Derivatives designated as hedging instruments for regulatory purposes
Energy-related derivatives:
Other current assets/Other current liabilities	$	2		$	14		$	3		$	4
Other deferred charges and assets/Other deferred credits and liabilities	2			10			3			6
Total derivatives designated as hedging instruments for regulatory purposes	$	4		$	24		$	6		$	10
Gross amounts recognized	$	4		$	24		$	6		$	10
Gross amounts offset	$	(2	)	$	(2	)	$	(4	)	$	(4	)
Net amounts recognized in the Balance Sheets	$	2		$	22		$	2		$	6
Georgia Power
Derivatives designated as hedging instruments for regulatory purposes
Energy-related derivatives:
Other current assets/Other current liabilities	$	1		$	32		$	2		$	8
Other deferred charges and assets/Other deferred credits and liabilities	3			21			4			13
Total derivatives designated as hedging instruments for regulatory purposes	$	4		$	53		$	6		$	21
Derivatives designated as hedging instruments in cash flow and fair value hedges
Interest rate derivatives:
Other current assets/Other current liabilities	$	—		$	17		$	—		$	2
Total derivatives designated as hedging instruments in cash flow and fair value hedges	$	—		$	17		$	—		$	2
Gross amounts recognized	$	4		$	70		$	6		$	23
Gross amounts offset	$	(3	)	$	(3	)	$	(6	)	$	(6	)
Net amounts recognized in the Balance Sheets	$	1		$	67		$	—		$	17

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	2019						2018
Derivative Category and Balance Sheet Location	Assets			Liabilities			Assets			Liabilities
	(in millions)
Mississippi Power
Derivatives designated as hedging instruments for regulatory purposes
Energy-related derivatives:
Other current assets/Other current liabilities	$	—		$	15		$	1		$	3
Other deferred charges and assets/Other deferred credits and liabilities	1			12			2			6
Total derivatives designated as hedging instruments for regulatory purposes	$	1		$	27		$	3		$	9
Gross amounts recognized	$	1		$	27		$	3		$	9
Gross amounts offset	$	(1	)	$	(1	)	$	(2	)	$	(2	)
Net amounts recognized in the Balance Sheets	$	—		$	26		$	1		$	7
Southern Power
Derivatives designated as hedging instruments in cash flow and fair value hedges
Energy-related derivatives:
Other current assets/Other current liabilities	$	1		$	2		$	3		$	6
Other deferred charges and assets/Other deferred credits and liabilities	—			—			1			2
Foreign currency derivatives:
Other current assets/Other current liabilities	—			24			—			23
Other deferred charges and assets/Other deferred credits and liabilities	16			—			75			—
Total derivatives designated as hedging instruments in cash flow and fair value hedges	$	17		$	26		$	79		$	31
Derivatives not designated as hedging instruments
Energy-related derivatives:
Other current assets/Other current liabilities	$	2		$	1		$	—		$	—
Total derivatives not designated as hedging instruments	$	2		$	1		$	—		$	—
Gross amounts recognized	$	19		$	27		$	79		$	31
Gross amounts offset	$	—		$	—		$	(3	)	$	(3	)
Net amounts recognized in the Balance Sheets	$	19		$	27		$	76		$	28

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	2019						2018
Derivative Category and Balance Sheet Location	Assets			Liabilities			Assets			Liabilities
	(in millions)
Southern Company Gas
Derivatives designated as hedging instruments for regulatory purposes
Energy-related derivatives:
Assets from risk management activities/Liabilities from risk management activities-current	$	—		$	9		$	2		$	8
Other deferred charges and assets/Other deferred credits and liabilities	—			1			—			1
Total derivatives designated as hedging instruments for regulatory purposes	$	—		$	10		$	2		$	9
Derivatives designated as hedging instruments in cash flow and fair value hedges
Energy-related derivatives:
Assets from risk management activities/Liabilities from risk management activities-current	$	—		$	4		$	—		$	1
Interest rate derivatives:
Assets from risk management activities/Liabilities from risk management activities-current	2			—			—			—
Total derivatives designated as hedging instruments in cash flow and fair value hedges	$	2		$	4		$	—		$	1
Derivatives not designated as hedging instruments
Energy-related derivatives:
Assets from risk management activities/Liabilities from risk management activities-current	$	459		$	357		$	559		$	574
Other deferred charges and assets/Other deferred credits and liabilities	207			225			180			325
Total derivatives not designated as hedging instruments	$	666		$	582		$	739		$	899
Gross amounts recognized	$	668		$	596		$	741		$	909
Gross amounts offset(a)	$	(456	)	$	(555	)	$	(508	)	$	(785	)
Net amounts recognized in the Balance Sheets (b)	$	212		$	41		$	233		$	124

(a)	Gross amounts offset include cash collateral held on deposit in broker margin accounts of $99 million and $277 million at December 31, 2019 and 2018, respectively.

(b)	Net amounts of derivative instruments outstanding exclude premium and intrinsic value associated with weather derivatives of $4 million and $8 million at December 31, 2019 and 2018, respectively.

Energy-related derivatives not designated as hedging instruments were immaterial for the traditional electric operating companies at December 31, 2019 and 2018.

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At December 31, 2019 and 2018, the pre-tax effects of unrealized derivative gains (losses) arising from energy-related derivative instruments designated as regulatory hedging instruments and deferred were as follows:

Regulatory Hedge Unrealized Gain (Loss) Recognized in the Balance Sheet at December 31, 2019
Derivative Category and Balance Sheet Location	Southern Company			Alabama Power			Georgia Power			Mississippi Power			Southern Company Gas
	(in millions)
Energy-related derivatives:
Other regulatory assets, current	$	(63	)	$	(14	)	$	(31	)	$	(15	)	$	(3	)
Other regulatory assets, deferred	(37		)	(8		)	(18		)	(11		)	—
Other regulatory liabilities, current	6			2			—			—			4
Total energy-related derivative gains (losses)	$	(94	)	$	(20	)	$	(49	)	$	(26	)	$	1

Regulatory Hedge Unrealized Gain (Loss) Recognized in the Balance Sheet at December 31, 2018
Derivative Category and Balance Sheet Location	Southern Company			Alabama Power			Georgia Power			Mississippi Power			Southern Company Gas
	(in millions)
Energy-related derivatives:
Other regulatory assets, current	$	(19	)	$	(3	)	$	(6	)	$	(2	)	$	(8	)
Other regulatory assets, deferred	(16		)	(3		)	(9		)	(4		)	—
Assets held for sale, current	(6		)	—			—			—			—
Other regulatory liabilities, current	1			—			—			—			1
Total energy-related derivative gains (losses)	$	(40	)	$	(6	)	$	(15	)	$	(6	)	$	(7	)

For the years ended December 31, 2019, 2018, and 2017, the pre-tax effects of cash flow hedge accounting on AOCI for the applicable Registrants were as follows:

Gain (Loss) Recognized in OCI on Derivative	2019			2018			2017
	(in millions)
Southern Company
Energy-related derivatives	$	(13	)	$	17		$	(47	)
Interest rate derivatives	(57		)	(1		)	(2		)
Foreign currency derivatives	(84		)	(78		)	140
Total	$	(154	)	$	(62	)	$	91
Georgia Power
Interest rate derivatives	$	(59	)	$	—		$	1
Southern Power
Energy-related derivatives	$	(4	)	$	10		$	(38	)
Foreign currency derivatives	(84		)	(78		)	140
Total	$	(88	)	$	(68	)	$	102
Southern Company Gas
Energy-related derivatives	$	(9	)	$	7		$	(9	)
Interest rate derivatives	2			—			—
Total	$	(7	)	$	7		$	(9	)

For all years presented, the pre-tax effects of energy-related derivatives and interest rate derivatives designated as cash flow hedging instruments on AOCI were immaterial for the other Registrants. In addition, for the year ended December 31, 2017, there

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was no material ineffectiveness recorded in earnings for any Registrant. Upon the adoption of ASU 2017-12, beginning in 2018, ineffectiveness was no longer separately measured and recorded in earnings.

The pre-tax effects of cash flow and fair value hedge accounting on income for the years ended December 31, 2019, 2018, and 2017 were as follows:

Location and Amount of Gain (Loss) Recognized in Income on Cash Flow and Fair Value Hedging Relationships	2019			2018			2017
	(in millions)
Southern Company
Total cost of natural gas	$	1,319		$	1,539		$	1,601
Gain (loss) on energy-related cash flow hedges(a)	(2		)	2			(2		)
Total depreciation and amortization	3,038			3,131			3,010
Gain (loss) on energy-related cash flow hedges(a)	(6		)	7			(16		)
Total interest expense, net of amounts capitalized	(1,736		)	(1,842		)	(1,694		)
Gain (loss) on interest rate cash flow hedges(a)	(20		)	(21		)	(21		)
Gain (loss) on foreign currency cash flow hedges(a)	(24		)	(24		)	(23		)
Gain (loss) on interest rate fair value hedges(b)	42			(12		)	(22		)
Total other income (expense), net	252			114			163
Gain (loss) on foreign currency cash flow hedges(a)(c)	(24		)	(60		)	160
Alabama Power
Total interest expense, net of amounts capitalized	$	(336	)	$	(323	)	$	(305	)
Gain (loss) on interest rate cash flow hedges(a)	(6		)	(6		)	(6		)
Georgia Power
Total interest expense, net of amounts capitalized	$	(409	)	$	(397	)	$	(419	)
Gain (loss) on interest rate cash flow hedges(a)	(3		)	(4		)	(4		)
Gain (loss) on interest rate fair value hedges(b)	2			2			(3		)
Mississippi Power
Total interest expense, net of amounts capitalized	$	(69	)	$	(76	)	$	(42	)
Gain (loss) on interest rate cash flow hedges(a)	(2		)	(2		)	(2		)
Southern Power
Total depreciation and amortization	$	479		$	493		$	503
Gain (loss) on energy-related cash flow hedges(a)	(6		)	7			(17		)
Total interest expense, net of amounts capitalized	(169		)	(183		)	(191		)
Gain (loss) on foreign currency cash flow hedges(a)	(24		)	(24		)	(23		)
Total other income (expense), net	47			23			1
Gain (loss) on foreign currency cash flow hedges(a)(c)	(24		)	(60		)	159
Southern Company Gas
Total cost of natural gas	$	1,319		$	1,539		$	1,601
Gain (loss) on energy-related cash flow hedges(a)	(2		)	2			(2		)

(a)	Reclassified from AOCI into earnings.

(b)	For fair value hedges, changes in the fair value of the derivative contracts are generally equal to changes in the fair value of the underlying debt and have no material impact on income.

(c)	The reclassification from AOCI into other income (expense), net completely offsets currency gains and losses arising from changes in the U.S. currency exchange rates used to record the euro-denominated notes.

The pre-tax effects of cash flow hedge accounting on income for interest rate derivatives were immaterial for Southern Company Gas for all years presented.

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At December 31, 2019 and 2018, the following amounts were recorded on the balance sheets related to cumulative basis adjustments for fair value hedges:

	Carrying Amount of the Hedged Item							Cumulative Amount of Fair Value Hedging Adjustment included in Carrying Amount of the Hedged Item
Balance Sheet Location of Hedged Items	At December 31, 2019			At December 31, 2018				At December 31, 2019			At December 31, 2018
	(in millions)							(in millions)
Southern Company
Securities due within one year	$	—		$	(498	)		$	—		$	2
Long-term debt	(2,093		)	(2,052		)		3			41
Georgia Power
Securities due within one year	$	—		$	(498	)		$	—		$	2

The pre-tax effects of energy-related derivatives not designated as hedging instruments on the statements of income for the years ended December 31, 2019, 2018, and 2017 for the applicable Registrants were as follows:

		Gain (Loss)
Derivatives in Non-Designated Hedging Relationships	Statements of Income Location	2019				2018				2017
		(in millions)
Southern Company
Energy-related derivatives	Natural gas revenues(*)	$	223			$	(122	)		$	(80	)
	Cost of natural gas	10				(6		)		(2		)
	Wholesale electric revenues	2				2				(4		)
Total derivatives in non-designated hedging relationships		$	235			$	(126	)		$	(86	)
Southern Company Gas
Energy-related derivatives	Natural gas revenues(*)	$	223			$	(122	)		$	(80	)
	Cost of natural gas	10				(6		)		(2		)
Total derivatives in non-designated hedging relationships		$	233			$	(128	)		$	(82	)

(*)	Excludes the impact of weather derivatives recorded in natural gas revenues of $3 million, $5 million, and $23 million for the years ended December 31, 2019, 2018, and 2017, respectively, as they are accounted for based on intrinsic value rather than fair value.

The pre-tax effects of energy-related derivatives not designated as hedging instruments were immaterial for all other Registrants for all years presented.

Contingent Features

Southern Company, the traditional electric operating companies, Southern Power, and Southern Company Gas do 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, 2019, the Registrants had no collateral posted with derivative counterparties to satisfy these arrangements.

For the Registrants with interest rate derivatives at December 31, 2019, the fair value of interest rate derivative liabilities with contingent features and the maximum potential collateral requirements arising from the credit-risk-related contingent features, at a rating below BBB- and/or Baa3, was immaterial. At December 31, 2019, the fair value of energy-related derivative liabilities with contingent features and the maximum potential collateral requirements arising from the credit-risk-related contingent features, at a rating below BBB- and/or Baa3, were immaterial for all Registrants. The maximum potential collateral requirements arising from the credit-risk-related contingent features for the traditional electric operating companies and Southern Power include certain agreements that could require collateral in the event that one or more Southern Company power pool participants has a credit

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rating change to below investment grade. Following the sale of Gulf Power to NextEra Energy, Gulf Power is continuing to participate in the Southern Company power pool for a defined transition period that, subject to certain potential adjustments, is scheduled to end on January 1, 2024.

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.

Alabama Power and Southern Power maintain accounts with certain regional transmission organizations to facilitate financial derivative transactions. Based on the value of the positions in these accounts and the associated margin requirements, Alabama Power and Southern Power may be required to post collateral. At December 31, 2019, cash collateral posted in these accounts was immaterial. Southern Company Gas 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 Gas may be required to deposit cash into these accounts. At December 31, 2019, cash collateral held on deposit in broker margin accounts was $99 million.

The Registrants are exposed to losses related to financial instruments in the event of counterparties' nonperformance. The Registrants only enter 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. The Registrants have also established risk management policies and controls to determine and monitor the creditworthiness of counterparties in order to mitigate their exposure to counterparty credit risk. Prior to entering into a physical transaction, Southern Company Gas assigns physical wholesale counterparties an internal credit rating and credit limit based on the counterparties' Moody's, S&P, and Fitch ratings, commercially available credit reports, and audited financial statements. Southern Company Gas may require counterparties to pledge additional collateral when deemed necessary.

In addition, Southern Company Gas conducts credit evaluations and obtains appropriate internal approvals for the counterparty's line of credit before any transaction with the counterparty is executed. In most cases, the counterparty must have an investment grade rating, which includes a minimum long-term debt rating of Baa3 from Moody's and BBB- from S&P. Generally, Southern Company Gas requires credit enhancements by way of a guaranty, cash deposit, or letter of credit for transaction counterparties that do not have investment grade ratings.

Southern Company Gas also utilizes master netting agreements whenever possible to mitigate exposure to counterparty credit risk. When Southern Company Gas is engaged in more than one outstanding derivative transaction with the same counterparty and it also has a legally enforceable netting agreement with that counterparty, the "net" mark-to-market exposure represents the netting of the positive and negative exposures with that counterparty and a reasonable measure of Southern Company Gas' credit risk. Southern Company Gas also uses other netting agreements with certain counterparties with whom it conducts significant transactions. Master netting agreements enable Southern Company Gas to net certain assets and liabilities by counterparty. Southern Company Gas also nets across product lines and against cash collateral provided the master netting and cash collateral agreements include such provisions. Southern Company Gas may require counterparties to pledge additional collateral when deemed necessary.

The Registrants do not anticipate a material adverse effect on their respective financial statements as a result of counterparty nonperformance.

Southern Company

On January 1, 2019, Southern Company completed the sale of all of the capital stock of Gulf Power to 700 Universe, LLC, a wholly-owned subsidiary of NextEra Energy, for an aggregate cash purchase price of approximately $5.8 billion (less $1.3 billion of indebtedness assumed), including the final working capital adjustments. The gain associated with the sale of Gulf Power totaled $2.6 billion pre-tax ($1.4 billion after tax). The assets and liabilities of Gulf Power were classified as assets held for sale and liabilities held for sale on Southern Company's balance sheet as of December 31, 2018. See "Assets Held for Sale" herein for additional information.

On July 22, 2019, PowerSecure completed the sale of its utility infrastructure services business for approximately $65 million, including the final working capital adjustments. In contemplation of this sale, a goodwill impairment charge of $32 million was recorded in the second quarter 2019.

On December 30, 2019, Southern Company completed the sale of one of its leveraged lease investments for an aggregate cash purchase price of approximately $20 million. The sale resulted in an immaterial gain.

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On December 31, 2019, PowerSecure completed the sale of its lighting business for approximately $9 million, which included cash of $4 million and a note receivable from the buyer of $5 million. In contemplation of this sale, an impairment charge of $18 million was recorded in the third quarter 2019 related to goodwill, identifiable intangibles, and other assets.

Alabama Power

On September 6, 2019, Alabama Power entered into the Autauga Combined Cycle Acquisition, a purchase and sale agreement to acquire all of the equity interests in Tenaska Alabama II Partners, L.P. Tenaska Alabama II Partners, L.P. owns and operates an approximately 885-MW combined cycle generation facility in Autauga County, Alabama. The transaction is expected to close by September 1, 2020. As part of the Autauga Combined Cycle Acquisition, Alabama Power will assume an existing power sales agreement under which the full output of the generating facility remains committed to another third party for its remaining term of approximately three years. The estimated revenues from the power sales agreement are expected to offset the associated costs of operation during the remaining term.

The completion of the Autauga Combined Cycle Acquisition is subject to the satisfaction or waiver of certain conditions, including, among other customary conditions, approval by the Alabama PSC and the FERC. Alabama Power expects to obtain all regulatory approvals by the end of the third quarter 2020.

The ultimate outcome of this matter cannot be determined at this time.

Southern Power

During 2019 and 2018, Southern Power or one of its wholly-owned subsidiaries acquired, completed, or continued construction of the facilities discussed below. Acquisition-related costs were expensed as incurred and were not material for any of the years presented.

Acquisitions During 2019

During 2019, Southern Power acquired a controlling interest in the fuel cell generation facility listed below and acquired the Skookumchuck wind facility discussed under "Construction Projects" below.

Project Facility	Resource	Seller	Approximate Nameplate Capacity (MW)		Location	Southern Power Ownership Percentage	COD	PPA Remaining Period
DSGP(a)	Fuel Cell	Bloom Energy	28		Delaware	100% of Class B	N/A(b)	15 years

(a)	During 2019, Southern Power made a total investment of approximately $167 million in DSGP and now holds a controlling interest and consolidates 100% of DSGP's operating results. Southern Power records net income attributable to noncontrolling interests for approximately 10 MWs of the facility.

(b)

Southern Power's 18-MW share of the facility was repowered between June and August 2019. In December 2019, a Class C member joined the existing partnership between the Class A member and Southern Power and made an investment to repower the remaining 10 MWs. In connection with the Class C member joining the partnership, the original fuel cells (before repower), which had a carrying value of approximately $55 million, were distributed to the Class A member in a non-cash transaction that was excluded from the statements of cash flows.

Acquisitions During 2018

During 2018, Southern Power acquired and completed the project below and acquired the Wildhorse Mountain and Reading wind facilities discussed under "Construction Projects" below.

Project Facility	Resource	Seller	Approximate Nameplate Capacity (MW)		Location	Southern Power Ownership Percentage		COD	PPA Contract Period
Gaskell West 1	Solar	Recurrent Energy Development Holdings, LLC	20		Kern County, CA	100% of Class B	(*)	March 2018	20 years

(*)	Southern Power owns 100% of the Class B membership interests under a tax equity partnership.

The Gaskell West 1 facility did not have operating revenues or activities prior to being placed in service during March 2018.

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Construction Projects

During 2019, Southern Power completed construction of and placed in service the 385-MW Plant Mankato expansion and the Wildhorse Mountain facility, acquired and continued construction of the Skookumchuck facility, and continued construction of the Reading facility. Total aggregate construction costs, excluding acquisition costs, are expected to be between $490 million and $535 million for the two facilities under construction. At December 31, 2019, total costs of construction incurred for the two facilities under construction were $417 million and are included in CWIP. The ultimate outcome of these matters cannot be determined at this time.

Project Facility	Resource	Approximate Nameplate Capacity (MW)	Location	Actual/Expected COD	PPA Contract Period
Projects Completed During the Year Ended December 31, 2019
Mankato expansion(a)	Natural Gas	385	Mankato, MN	May 2019	20 years
Wildhorse Mountain(b)	Wind	100	Pushmataha County, OK	December 2019	20 years
Projects Under Construction at December 31, 2019
Reading(c)	Wind	200	Osage and Lyon Counties, KS	Second quarter 2020	12 years
Skookumchuck(d)	Wind	136	Lewis and Thurston Counties, WA	Second quarter 2020	20 years

(a)	Southern Power completed the sale of its equity interests in Plant Mankato, including the expansion, to a subsidiary of Xcel on January 17, 2020. The expansion unit started providing energy under a PPA with Northern States Power on June 1, 2019. See "Sales of Natural Gas and Biomass Plants" below and "Assets Held for Sale" herein for additional information.

(b)	In May 2018, Southern Power purchased 100% of the membership interests of the Wildhorse Mountain facility. In December 2019, Southern Power entered into a tax equity partnership and, as a result, owns 100% of the Class B membership interests.

(c)	In August 2018, Southern Power purchased 100% of the membership interests of the Reading facility pursuant to a joint development arrangement. Southern Power may enter into a tax equity partnership, in which case it would then own 100% of the Class B membership interests. The ultimate outcome of this matter cannot be determined at this time.

(d)

In October 2019, Southern Power purchased 100% of the membership interests of the Skookumchuck facility pursuant to a joint development arrangement. In December 2019, Southern Power entered into a tax equity agreement as the Class B member with funding of the tax equity amounts expected to occur upon commercial operation. Shortly after commercial operation, Southern Power may sell a noncontrolling interest in these Class B membership interests to another partner. The ultimate outcome of this matter cannot be determined at this time.

Development Projects

Southern Power continues to evaluate and refine the deployment of the remaining wind turbine equipment purchased in 2016 and 2017 to development and construction projects. Wind projects utilizing equipment purchased in 2016 and 2017, and reaching commercial operation by the end of 2020 and 2021, are expected to qualify for 100% and 80% PTCs, respectively. The significant majority of this equipment either has been deployed to completed projects, projects under construction, or projects that are probable of being completed or has been sold to third parties. In 2018, as a result of a review of various options for probable dispositions of wind turbine equipment not deployed to development or construction projects, Southern Power recorded a $36 million asset impairment charge on the equipment. Sales during 2019 resulted in gains totaling approximately $17 million.

Sales of Renewable Facility Interests

In May 2018, Southern Power completed the sale of a noncontrolling 33% equity interest in SP Solar, a limited partnership indirectly owning substantially all of Southern Power's solar facilities, to Global Atlantic for approximately $1.2 billion. Since Southern Power retained control of the limited partnership through its wholly-owned general partner, the sale was recorded as an equity transaction. On the date of the transaction, the noncontrolling interest was increased by $511 million to reflect 33% of the carrying value of the partnership. This difference, partially offset by the tax impact and other related transaction charges, also resulted in a $410 million decrease to Southern Power's common stockholder's equity.

In December 2018, Southern Power completed the sale of a noncontrolling tax equity interest in SP Wind, which owns a portfolio of eight operating wind facilities, to three financial investors for approximately $1.2 billion. The tax equity investors together will generally receive 40% of the cash distributions from available cash and will receive 99% of the tax attributes, including future PTCs.

Southern Power consolidates each entity, as the primary beneficiary of the VIE, since it controls the most significant activities, including operating and maintaining the assets.

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Sales of Natural Gas and Biomass Plants

In December 2018, Southern Power completed the sale of all of its equity interests in the Florida Plants to NextEra Energy for $203 million, including working capital adjustments. In contemplation of this sale transaction, Southern Power recorded an asset impairment charge of approximately $119 million ($89 million after tax) in May 2018.

On June 13, 2019, Southern Power completed the sale of its equity interests in Plant Nacogdoches, a 115-MW biomass facility located in Nacogdoches County, Texas, to Austin Energy, for a purchase price of approximately $461 million, including working capital adjustments. Southern Power recorded a gain of $23 million ($88 million after tax) on the sale.

On January 17, 2020, Southern Power completed the sale of its equity interests in Plant Mankato (including the 385-MW expansion unit completed in May 2019) to a subsidiary of Xcel for a purchase price of approximately $663 million, including estimated working capital adjustments. The sale resulted in a gain of approximately $39 million ($23 million after tax) in 2020. The assets and liabilities of Plant Mankato are classified as held for sale on Southern Company's and Southern Power's balance sheets as of December 31, 2019 and 2018. See "Assets Held for Sale" herein for additional information.

Southern Company Gas

Sale of Pivotal Home Solutions

In June 2018, Southern Company Gas completed the stock sale of Pivotal Home Solutions to American Water Enterprises LLC for a total cash purchase price of $365 million, which includes the final working capital adjustment. This disposition resulted in a net loss of $67 million, which includes $34 million of income tax expense. In contemplation of the transaction, a goodwill impairment charge of $42 million was recorded during the first quarter 2018. The income tax expense included tax on goodwill not deductible for tax purposes and for which a deferred tax liability had not been recorded previously. Southern Company Gas and American Water Enterprises LLC entered into a transition services agreement whereby Southern Company Gas provided certain administrative and operational services through November 4, 2018.

Sales of Elizabethtown Gas and Elkton Gas

In July 2018, a Southern Company Gas subsidiary, Pivotal Utility Holdings, completed the sales of the assets of two of its natural gas distribution utilities, Elizabethtown Gas and Elkton Gas, to South Jersey Industries, Inc. for a total cash purchase price of $1.7 billion, which includes the final working capital and other adjustments. This disposition resulted in a pre-tax gain that was entirely offset by $205 million of income tax expense, resulting in no material net income impact. The income tax expense included tax on goodwill not deductible for tax purposes and for which a deferred tax liability had not been recorded previously. Southern Company Gas and South Jersey Industries, Inc. entered into transition services agreements whereby Southern Company Gas will provide certain administrative and operational services through no later than July 31, 2020.

Sale of Florida City Gas

In July 2018, Southern Company Gas and its wholly-owned direct subsidiary, NUI Corporation, completed the stock sale of Pivotal Utility Holdings, which primarily consisted of Florida City Gas, to NextEra Energy for a total cash purchase price of $587 million, which includes the final working capital adjustment. This disposition resulted in a net gain of $16 million, which includes $103 million of income tax expense. The income tax expense included tax on goodwill not deductible for tax purposes and for which a deferred tax liability had not been recorded previously. Southern Company Gas and NextEra Energy entered into a transition services agreement whereby Southern Company Gas will provide certain administrative and operational services through no later than July 29, 2020.

Sale of Triton

On May 29, 2019, Southern Company Gas sold its investment in Triton, a cargo container leasing company that was aggregated into Southern Company Gas' all other segment. This disposition resulted in a pre-tax loss of $6 million and a net after-tax gain of $7 million as a result of reversing a $13 million federal income tax valuation allowance.

Proposed Sale of Pivotal LNG and Atlantic Coast Pipeline

On February 7, 2020, Southern Company Gas entered into agreements with Dominion Modular LNG Holdings, Inc. and Dominion Atlantic Coast Pipeline, LLC for the sale of its interests in Pivotal LNG and Atlantic Coast Pipeline, respectively, for an aggregate purchase price of $165 million, including estimated working capital and timing adjustments. Southern Company Gas may also receive two payments of $5 million each, contingent upon certain milestones related to Pivotal LNG being met by Dominion Modular LNG Holdings, Inc. after the completion of the sale. Based on the terms of these pending transactions, Southern Company Gas recorded an asset impairment charge, exclusive of the contingent payments, for Pivotal LNG of

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approximately $24 million ($17 million after tax) as of December 31, 2019. The completion of each transaction is subject to the satisfaction or waiver of certain conditions, including, among other customary closing conditions, the completion of the other transaction and, for the sale of the interest in Atlantic Coast Pipeline, the expiration or termination of any applicable waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976. The transactions are expected to be completed in the first half of 2020; however, the ultimate outcome cannot be determined at this time. The assets and liabilities of Pivotal LNG and the interest in Atlantic Coast Pipeline are classified as held for sale as of December 31, 2019. See Notes 3 and 7 under "Southern Company Gas – Gas Pipeline Projects" and "Southern Company Gas – Equity Method Investments," respectively, and "Assets Held for Sale" herein for additional information.

Assets Held for Sale

As discussed previously, Southern Company, Southern Power, and Southern Company Gas each have assets and liabilities held for sale on their balance sheets at December 31, 2019 and/or 2018. Assets and liabilities held for sale have been classified separately on each company's balance sheet at the lower of carrying value or fair value less costs to sell at the time the criteria for held-for-sale classification were met. For assets and liabilities held for sale recorded at fair value on a nonrecurring basis, the fair value of assets held for sale is based primarily on unobservable inputs (Level 3), which includes the agreed upon sales prices in executed sales agreements.

Since the depreciation of the assets sold in the Gulf Power transaction and Southern Company Gas' Elizabethtown Gas, Elkton Gas, and Florida City Gas transactions continued to be reflected in customer rates through the closing date of each sale and was reflected in the carryover basis of the assets when sold, Southern Company and Southern Company Gas continued to record depreciation on those assets through the respective closing date of each transaction. Upon classification as held for sale in May 2018 for the Florida Plants, November 2018 for Plant Mankato, and April 2019 for Plant Nacogdoches, Southern Power ceased recognizing depreciation and amortization on the long-lived assets being sold.

The following table provides the major classes of assets and liabilities classified as held for sale for Southern Company, Southern Power, and Southern Company Gas at December 31, 2019 and/or 2018:

	Southern Company							Southern Power							Southern Company Gas
	At December 31,							At December 31,							At December 31,
	2019			2018				2019			2018				2019
	(in millions)							(in millions)							(in millions)
Assets Held for Sale:
Current assets	$	19		$	393			$	17		$	8			$	2
Total property, plant, and equipment	565			4,583				547			536				18
Goodwill and other intangible assets	40			40				40			40				—
Equity investments in unconsolidated subsidiaries	151			—				—			—				151
Other non-current assets	14			727				14			—				—
Total Assets Held for Sale	$	789		$	5,743			$	618		$	584			$	171
Liabilities Held for Sale:
Current liabilities	$	5		$	425			$	3		$	15			$	2
Long-term debt	—			1,286				—			—				—
Accumulated deferred income taxes	—			618				—			—				—
Other non-current liabilities	—			932				—			—				—
Total Liabilities Held for Sale	$	5		$	3,261			$	3		$	15			$	2

Southern Company, Southern Power, and Southern Company Gas each concluded that the asset sales, both individually and combined, did not represent a strategic shift in operations that has, or is expected to have, a major effect on its operations and financial results; therefore, none of the assets related to the sales have been classified as discontinued operations for any of the periods presented.

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Gulf Power and Southern Power's Florida Plants, Plant Nacogdoches, and Plant Mankato represented individually significant components of Southern Company and Southern Power, respectively; therefore, pre-tax income for these components for the years ended December 31, 2019, 2018, and 2017 are presented below:

	2019			2018			2017
	(in millions)
Earnings before income taxes:(a)
Gulf Power	N/A			$	140		$	229
Southern Power's Florida Plants(b)	N/A			$	49		$	37
Southern Power's Plant Nacogdoches(c)	$	13		$	27		$	25
Southern Power's Plant Mankato	$	29		N/M			N/M

N/M - Not material

(a)	Earnings before income taxes for Southern Power's components reflect the cessation of depreciation and amortization on the long-lived assets being sold upon classification as held for sale.

(b)	Earnings before income taxes for the Florida Plants in 2018 represents the period from January 1, 2018 to December 4, 2018 (the divestiture date).

(c)	Earnings before income taxes for Plant Nacogdoches in 2019 represents January 1, 2019 through June 13, 2019 (the divestiture date).

Southern Company

Southern Company's reportable business segments are the sale of electricity by the 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 $398 million, $435 million, and $392 million in 2019, 2018, and 2017, respectively. Revenues from sales of natural gas from Southern Company Gas to the traditional electric operating companies and Southern Power were $14 million and $64 million, respectively, in 2019, $32 million and $119 million, respectively, in 2018, and $23 million and $119 million, respectively, in 2017. 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 solutions to electric utilities and their customers in the areas of distributed generation, energy storage and renewables, and energy efficiency, as well as investments in telecommunications and leveraged lease projects. All other inter-segment revenues are not material.

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Financial data for business segments and products and services for the years ended December 31, 2019, 2018, and 2017 was as follows:

	Electric Utilities
	Traditional Electric Operating Companies			Southern Power			Eliminations			Total			Southern Company Gas			All Other			Eliminations			Consolidated
	(in millions)
2019
Operating revenues	$	15,569		$	1,938		$	(412	)	$	17,095		$	3,792		$	690		$	(158	)	$	21,419
Depreciation and amortization	1,993			479			—			2,472			487			79			—			3,038
Interest income	38			9			—			47			3			16			(6		)	60
Earnings from equity method investments	2			3			—			5			157			—			—			162
Interest expense	818			169			—			987			232			517			—			1,736
Income taxes (benefit)	764			(56		)	—			708			130			960			—			1,798
Segment net income (loss)(a)(b)(c)(d)(e)	2,929			339			—			3,268			585			908			(22		)	4,739
Goodwill	—			2			—			2			5,015			263			—			5,280
Total assets	81,063			14,300			(713		)	94,650			21,687			3,511			(1,148		)	118,700
Gross property additions	5,748			489			—			6,237			1,418			159			—			7,814
2018
Operating revenues	$	16,843		$	2,205		$	(477	)	$	18,571		$	3,909		$	1,213		$	(198	)	$	23,495
Depreciation and amortization	2,072			493			—			2,565			500			66			—			3,131
Interest income	23			8			—			31			4			8			(5		)	38
Earnings from equity method investments	(1		)	—			—			(1		)	148			2			(1		)	148
Interest expense	852			183			—			1,035			228			580			(1		)	1,842
Income taxes (benefit)	371			(164		)	—			207			464			(222		)	—			449
Segment net income (loss)(a)(b)(f)(g)	2,117			187			—			2,304			372			(453		)	3			2,226
Goodwill	—			2			—			2			5,015			298			—			5,315
Total assets	79,382			14,883			(306		)	93,959			21,448			3,285			(1,778		)	116,914
Gross property additions	6,077			315			—			6,392			1,399			414			—			8,205
2017
Operating revenues	$	16,884		$	2,075		$	(419	)	$	18,540		$	3,920		$	741		$	(170	)	$	23,031
Depreciation and amortization	1,954			503			—			2,457			501			52			—			3,010
Interest income	14			7			—			21			3			11			(9		)	26
Earnings from equity method investments	1			—			—			1			106			(1		)	—			106
Interest expense	820			191			—			1,011			200			490			(7		)	1,694
Income taxes (benefit)	1,021			(939		)	—			82			367			(307		)	—			142
Segment net income (loss)(a)(b)(h)(i)	(193		)	1,071			—			878			243			(279		)	—			842
Goodwill	—			2			—			2			5,967			299			—			6,268
Total assets	72,204			15,206			(325		)	87,085			22,987			2,552			(1,619		)	111,005
Gross property additions	3,836			268			—			4,104			1,525			355			—			5,984

(a)	Attributable to Southern Company.

(b)

Segment net income (loss) for the traditional electric operating companies includes pre-tax charges for estimated losses on plants under construction of $24 million ($24 million after tax) in 2019, $1.1 billion ($722 million after tax) in 2018, and $3.4 billion ($2.4 billion after tax) in 2017. See Note 2 under "Georgia Power – Nuclear Construction" and "Mississippi Power – Kemper County Energy Facility – Schedule and Cost Estimate" for additional information.

(c)	Segment net income (loss) for Southern Power includes a $23 million pre-tax gain ($88 million gain after tax) on the sale of Plant Nacogdoches in 2019. See Note 15 under "Southern Power" for additional information.

(d)	Segment net income (loss) for Southern Company Gas in 2019 includes pre-tax impairment charges totaling $115 million ($86 million after tax). See Notes 3 and 15 under "Other Matters – Southern Company Gas" and "Southern Company Gas – Proposed Sale of Pivotal LNG and Atlantic Coast Pipeline," respectively, for additional information.

(e)

Segment net income (loss) for the "All Other" column in 2019 includes the pre-tax gain associated with the sale of Gulf Power of $2.6 billion ($1.4 billion after tax), the pre-tax loss, including related impairment charges, on the sales of certain PowerSecure business units totaling $58 million ($52 million after tax), and a pre-tax impairment charge of $17 million ($13 million after tax) related to a leveraged lease investment. See Notes 3 and 15 under "Other Matters – Southern Company" and "Southern Company," respectively, for additional information.

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(f)	Segment net income (loss) for Southern Power includes pre-tax impairment charges of $156 million ($117 million after tax) in 2018. See Note 15 under "Southern Power" for additional information.

(g)	Segment net income (loss) for Southern Company Gas includes a net gain on dispositions of $291 million ($51 million loss after tax) in 2018 related to the Southern Company Gas Dispositions and a goodwill impairment charge of $42 million in 2018 related to the sale of Pivotal Home Solutions. See Note 15 under "Southern Company Gas" for additional information.

(h)	Segment net income (loss) for the traditional electric operating companies includes a pre-tax charge for the write-down of Gulf Power's ownership of Plant Scherer Unit 3 of $33 million ($20 million after tax) in 2017. See Note 2 under "Southern Company – Gulf Power" for additional information.

(i)	Segment net income (loss) includes income tax expense of $367 million for the traditional electric operating companies, income tax benefit of $743 million for Southern Power, and income tax expense of $93 million for Southern Company Gas in 2017 related to the Tax Reform Legislation.

Products and Services

Electric Utilities' Revenues
Year	Retail				Wholesale				Other				Total
	(in millions)
2019	$	14,084			$	2,152			$	859			$	17,095
2018	15,222				2,516				833				18,571
2017	15,330				2,426				784				18,540

Southern Company Gas' Revenues
Year	Gas Distribution Operations				Gas Marketing Services				All Other				Total
	(in millions)
2019	$	3,001			$	456			$	335			$	3,792
2018	3,155				568				186				3,909
2017	3,024				860				36				3,920

Southern Company Gas

Southern Company Gas manages its business through four reportable segments - gas distribution operations, gas pipeline investments, wholesale gas services, and gas marketing services. The non-reportable segments are combined and presented as all other. During 2018, Southern Company Gas changed its reportable segments to further align the way its Chief Operating Decision Maker reviews operating results and reclassified prior year data to conform to the new reportable segment presentation. This change resulted in a new reportable segment, gas pipeline investments, which was formerly included in gas midstream operations.

Gas distribution operations is the largest component of Southern Company Gas' business and includes natural gas local distribution utilities that construct, manage, and maintain intrastate natural gas pipelines and gas distribution facilities in four states. In July 2018, Southern Company Gas sold three of its natural gas distribution utilities, Elizabethtown Gas, Elkton Gas, and Florida City Gas. See Note 15 under "Southern Company Gas" for additional information.

Gas pipeline investments consists of joint ventures in natural gas pipeline investments including a 50% interest in SNG, two significant pipeline construction projects, and a 50% joint ownership interest in the Dalton Pipeline. These natural gas pipelines enable the provision of diverse sources of natural gas supplies to the customers of Southern Company Gas. See Notes 3, 5, 7, and 15 for additional information.

Wholesale gas services provides natural gas asset management and/or related logistics services for each of Southern Company Gas' utilities except Nicor Gas as well as for non-affiliated companies. Additionally, wholesale gas services engages in natural gas storage and gas pipeline arbitrage and related activities.

Gas marketing services provides natural gas marketing to end-use customers primarily in Georgia and Illinois through SouthStar. In June 2018, Southern Company Gas sold Pivotal Home Solutions, which provided home equipment protection products and services. See Note 15 under "Southern Company Gas – Sale of Pivotal Home Solutions" for additional information.

The all other column includes segments below the quantitative threshold for separate disclosure, including storage and fuels operations, Pivotal LNG, the investment in Triton through its sale on May 29, 2019, and other subsidiaries that fall below the quantitative threshold for separate disclosure. See Note 15 under "Southern Company Gas – Proposed Sale of Pivotal LNG and Atlantic Coast Pipeline" for additional information.

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Financial data for business segments for the years ended December 31, 2019, 2018, and 2017 was as follows:

	Gas Distribution Operations(a)(b)			Gas Pipeline Investments			Wholesale Gas Services(c)			Gas Marketing Services(b)(d)			Total			All Other(e)			Eliminations			Consolidated
	(in millions)
2019
Operating revenues	$	3,028		$	32		$	294		$	456		$	3,810		$	44		$	(62	)	$	3,792
Depreciation and amortization	422			5			1			26			454			33			—			487
Operating income (loss)	573			20			219			112			924			(154		)	—			770
Earnings from equity method investments	—			162			—			—			162			(5		)	—			157
Interest expense	(187		)	(30		)	(5		)	(3		)	(225		)	(7		)	—			(232		)
Income taxes (benefit)	63			58			52			27			200			(70		)	—			130
Segment net income (loss)	337			94			163			83			677			(92		)	—			585
Gross property additions	1,433			1			1			4			1,439			27			—			1,466
Total assets at December 31, 2019	18,204			1,678			850			1,496			22,228			10,759			(11,300		)	21,687
2018
Operating revenues	$	3,186		$	32		$	144		$	568		$	3,930		$	55		$	(76	)	$	3,909
Depreciation and amortization	409			5			2			37			453			47			—			500
Operating income (loss)	904			20			70			19			1,013			(98		)	—			915
Earnings from equity method investments	—			145			—			—			145			3			—			148
Interest expense	(178		)	(34		)	(9		)	(6		)	(227		)	(1		)	—			(228		)
Income taxes (benefit)	409			28			4			54			495			(31		)	—			464
Segment net income (loss)	334			103			38			(40		)	435			(63		)	—			372
Gross property additions	1,429			32			—			6			1,467			54			—			1,521
Total assets at December 31, 2018	17,266			1,763			1,302			1,587			21,918			11,112			(11,582		)	21,448
2017
Operating revenues	$	3,207		$	17		$	6		$	860		$	4,090		$	64		$	(234	)	$	3,920
Depreciation and amortization	391			2			2			62			457			44			—			501
Operating income (loss)	645			10			(51		)	113			717			(57		)	—			660
Earnings from equity method investments	—			103			—			—			103			3			—			106
Interest expense	(153		)	(26		)	(7		)	(5		)	(191		)	(9		)	—			(200		)
Income taxes(f)	178			109			—			24			311			56			—			367
Segment net income (loss)(f)	353			(22		)	(57		)	84			358			(115		)	—			243
Gross property additions	1,330			117			1			9			1,457			51			—			1,508
Total assets at December 31, 2017	19,358			1,699			1,096			2,147			24,300			12,726			(14,039		)	22,987

(a)	Operating revenues for the three gas distribution operations dispositions were $244 million and $399 million for 2018 and 2017, respectively. See Note 15 under "Southern Company Gas" for additional information.

(b)

Segment net income for gas distribution operations includes a gain on dispositions of $324 million ($16 million after tax) in 2018. Segment net income for gas marketing services includes a loss on disposition of $(33) million ($(67) million loss after tax) and a goodwill impairment charge of $42 million in 2018 recorded in contemplation of the sale of Pivotal Home Solutions. See Note 15 under "Southern Company Gas" for additional information.

(c)	The revenues for wholesale gas services are netted with costs associated with its energy and risk management activities. A reconciliation of operating revenues and intercompany revenues is shown in the following table.

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	Third Party Gross Revenues			Intercompany Revenues			Total Gross Revenues			Less Gross Gas Costs			Operating Revenues
	(in millions)
2019	$	5,703		$	275		$	5,978		$	5,684		$	294
2018	6,955			451			7,406			7,262			144
2017	6,152			481			6,633			6,627			6

(d)	Operating revenues for the gas marketing services disposition were $55 million and $129 million in 2018 and 2017, respectively. See Note 15 under "Southern Company Gas" for additional information.

(e)	Segment net income (loss) for the "All Other" column in 2019 includes pre-tax impairment charges totaling $115 million ($86 million after tax). See Notes 3 and 15 under "Other Matters – Southern Company Gas" and "Southern Company Gas – Proposed Sale of Pivotal LNG and Atlantic Coast Pipeline," respectively, for additional information.

(f)	Includes the impact of the Tax Reform Legislation and new income tax apportionment factors in several states resulting from Southern Company Gas' inclusion in the consolidated Southern Company state tax filings.

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The tables below provide summarized quarterly financial information for each Registrant for 2019 and 2018. Each Registrant's business is influenced by seasonal weather conditions.

Quarter Ended	Southern Company(a)			Alabama Power			Georgia Power			Mississippi Power(b)			Southern Power(c)			Southern Company Gas(d)
	(in millions)
March 2019
Operating Revenues	$	5,412		$	1,408		$	1,833		$	287		$	443		$	1,474
Operating Income (Loss)	3,691			338			448			56			60			353
Net Income (Loss)	2,059			217			311			37			27			270
Net Income (Loss) Attributable to Registrant	2,084			217			311			37			56			270
June 2019
Operating Revenues	$	5,098		$	1,513		$	2,117		$	313		$	510		$	689
Operating Income (Loss)	1,342			445			647			54			153			134
Net Income (Loss)	931			296			448			37			203			106
Net Income (Loss) Attributable to Registrant	899			296			448			37			174			106
September 2019
Operating Revenues	$	5,995		$	1,841		$	2,755		$	370		$	574		$	498
Operating Income (Loss)	2,013			676			1,161			93			167			(35		)
Net Income (Loss)	1,345			469			839			65			111			(29		)
Net Income (Loss) Attributable to Registrant	1,316			469			839			65			86			(29		)
December 2019
Operating Revenues	$	4,914		$	1,363		$	1,703		$	294		$	411		$	1,131
Operating Income (Loss)	690			134			205			22			15			318
Net Income (Loss)	409			88			122			—			(12		)	238
Net Income (Loss) Attributable to Registrant	440			88			122			—			23			238

(a)

Southern Company recorded a preliminary pre-tax gain associated with the sale of Gulf Power of $2.5 billion ($1.3 billion after tax) in the first quarter 2019 and recorded subsequent adjustments of $(15) million ($(11) million after tax) in the second quarter 2019, $4 million ($4 million after tax) in the third quarter 2019, and $70 million ($102 million after tax) in the fourth quarter 2019. In addition, Southern Company recorded a pre-tax loss, including related impairment charges, on the sales of certain PowerSecure business units totaling $32 million in the second quarter 2019, $14 million ($15 million after tax) in the third quarter 2019, and $12 million ($5 million after tax) in the fourth quarter 2019, as well as a pre-tax impairment charge of $17 million ($13 million after tax) in the fourth quarter 2019 related to a leveraged lease investment. See Notes 3 and 15 under "Other Matters – Southern Company" and "Southern Company," respectively, for additional information. Also see notes (b), (c), and (d) below.

(b)

Mississippi Power recorded total pre-tax charges to income of $2 million ($1 million after tax) in the first quarter 2019, $4 million ($3 million after tax) in the second quarter 2019, $4 million ($3 million after tax) in the third quarter 2019, and $14 million ($17 million after tax) in the fourth quarter 2019 as a result of abandonment and related closure costs and ongoing period costs, net of salvage proceeds, for the mine and gasifier-related assets at the Kemper County energy facility. The fourth quarter charges include impacts associated with the expected close out of a DOE contract related to the Kemper County energy facility, as well as an adjustment related to the tax abandonment of the Kemper IGCC following the filing of the 2018 tax return. See Note 2 under "Mississippi Power – Kemper County Energy Facility" for additional information.

(c)	Southern Power recorded a pre-tax gain of $23 million ($88 million gain after tax) in the second quarter 2019 on the sale of Plant Nacogdoches. See Note 15 under "Southern Power" for additional information.

(d)

Southern Company Gas recorded pre-tax impairment charges of $92 million ($65 million after tax) in the third quarter 2019, and a subsequent adjustment of $(1) million ($4 million after tax) in the fourth quarter 2019, related to a natural gas storage facility in Louisiana and $24 million ($17 million after tax) in the fourth quarter 2019 in contemplation of the sale of its interests in Pivotal LNG and Atlantic Coast Pipeline. See Notes 3 and 15 under "Other Matters – Southern Company Gas" and "Southern Company Gas – Proposed Sale of Pivotal LNG and Atlantic Coast Pipeline," respectively, for additional information.

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Quarter Ended	Southern   Company(a)			Alabama Power			Georgia Power(b)			Mississippi Power(c)			Southern Power(d)			Southern Company Gas(e)
	(in millions)
March 2018
Operating Revenues	$	6,372		$	1,473		$	1,961		$	302		$	509		$	1,639
Operating Income (Loss)	1,376			372			513			7			60			388
Net Income (Loss)	936			225			352			(7		)	115			279
Net Income (Loss) Attributable to Registrant	938			225			352			(7		)	121			279
June 2018
Operating Revenues	$	5,627		$	1,503		$	2,048		$	297		$	555		$	730
Operating Income (Loss)	63			380			(472		)	54			16			49
Net Income (Loss)	(127		)	259			(396		)	46			45			(31		)
Net Income (Loss) Attributable to Registrant	(154		)	259			(396		)	46			22			(31		)
September 2018
Operating Revenues	$	6,159		$	1,740		$	2,593		$	358		$	635		$	492
Operating Income (Loss)	2,174			561			991			80			136			374
Net Income (Loss)	1,222			373			664			47			146			46
Net Income (Loss) Attributable to Registrant	1,164			373			664			47			92			46
December 2018
Operating Revenues	$	5,337		$	1,316		$	1,818		$	308		$	506		$	1,048
Operating Income (Loss)	578			164			257			52			30			104
Net Income (Loss)	269			73			173			149			(60		)	78
Net Income (Loss) Attributable to Registrant	278			73			173			149			(48		)	78

(a)	See notes (b), (c), (d), and (e) below.

(b)	Georgia Power recorded an estimated probable loss of $1.1 billion in the second quarter 2018 to reflect its revised estimate to complete construction and start-up of Plant Vogtle Units 3 and 4. See Note 2 under "Georgia Power – Nuclear Construction" for additional information.

(c)

As a result of the abandonment and related closure activities for the mine and gasifier-related assets at the Kemper County energy facility, Mississippi Power recorded total pre-tax charges to income of $44 million ($33 million after tax) in the first quarter 2018, immaterial amounts in the second and third quarters 2018, and a pre-tax credit to income of $9 million in the fourth quarter 2018. In addition, Mississippi Power recorded a credit to earnings of $95 million in the fourth quarter 2018 primarily resulting from the reduction of a valuation allowance for a state income tax NOL carryforward associated with the Kemper County energy facility. See Note 2 under "Mississippi Power – Kemper County Energy Facility" and Note 10 for additional information.

(d)

Southern Power recorded pre-tax impairment charges of $119 million ($89 million after tax) in the second quarter 2018 in contemplation of the sale of the Florida Plants and $36 million ($27 million after tax) in the third quarter 2018 related to wind turbine equipment. See Note 15 under "Southern Power – Sales of Natural Gas and Biomass Plants" and " – Development Projects" for additional information. As a result of the Tax Reform Legislation, Southern Power recorded income tax expense of $75 million in the fourth quarter 2018. See Note 10 for additional information.

(e)

Southern Company Gas recorded a goodwill impairment charge of $42 million in the first quarter 2018 in contemplation of the sale of Pivotal Home Solutions. Southern Company Gas also recorded gains (losses) on dispositions in the second, third, and fourth quarters 2018 of $(36) million ($(76) million after tax), $353 million ($40 million after tax), and $(27) million ($(15) million after tax), respectively. See Note 15 under "Southern Company Gas" for additional information.

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The table below provides quarterly earnings per share financial information for Southern Company common stock for 2019 and 2018.

	Earnings Per Common Share(*)
Quarter Ended	Basic				Diluted
March 2019	$	2.01			$	1.99
June 2019	0.86				0.85
September 2019	1.26				1.25
December 2019	0.42				0.42
March 2018	$	0.93			$	0.92
June 2018	(0.15		)		(0.15		)
September 2018	1.14				1.13
December 2018	0.27				0.27

(*)	See the notes below the two preceding tables for additional information.

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Item 9.	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

Item 9A.	CONTROLS AND PROCEDURES

Item 9B.	OTHER INFORMATION

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Item 10.	DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

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Item 14.	PRINCIPAL ACCOUNTANT FEES AND SERVICES

(1)	Includes services performed in connection with financing transactions.

(2)	Represents non-statutory audit services.

(3)	Represents registration fees for attendance at Deloitte & Touche LLP-sponsored education seminars.

(4)	Represents fees in connection with audits of Southern Power partnerships.

(5)	Includes fees in connection with statutory audits of several Southern Company Gas subsidiaries.

(6)	Represents fees for non-statutory audit services in 2019 and 2018 and a review report on internal controls in 2018.

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Item 15.	EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

(a)	The following documents are filed as a part of this report on Form 10-K:

(1)	Financial Statements and Financial Statement Schedules:

(2)	Exhibits:

Item 16.	FORM 10-K SUMMARY

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THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

SCHEDULE II — VALUATION AND QUALIFYING ACCOUNTS

FOR THE YEARS ENDED DECEMBER 31, 2019, 2018, AND 2017

(Stated in Millions of Dollars)

					Additions
Description	Balance at Beginning of Period				Charged to Income				Charged to Other Accounts					Deductions				Reclassified to Held for Sale(c)				Balance at End of Period
Provision for uncollectible accounts(a)
2019	$	50			$	68			$	—				$	69			$	—			$	49
2018	44				69				(1		)			61				1				50
2017	43				56				—					55				—				44
Tax valuation allowance (net state)(b)
2019	$	100			$	13			$	—				$	—			$	—			$	113
2018	148				(38		)		—					10				—				100
2017	22				126				—					—				—				148

(a)	Deductions represent write-offs of accounts considered to be uncollectible, less recoveries of amounts previously written off.

(b)

In 2017, Mississippi Power established a valuation allowance for the State of Mississippi net operating loss carryforward expected to expire prior to being fully utilized. This valuation allowance was reduced in 2018 as a result of higher projected state taxable income. In 2018, Georgia Power established a valuation allowance for certain Georgia state tax credits expected to expire prior to being fully utilized, as a result of lower projected state taxable income. See Note 10 to the financial statements in Item 8 herein for additional information.

(c)	Represents provision for uncollectible accounts at Gulf Power presented on Southern Company's balance sheet at December 31, 2018 as assets held for sale, current. See Note 15 to the financial statements under "Southern Company" and "Assets Held for Sale" in Item 8 herein for additional information.

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ALABAMA POWER COMPANY

SCHEDULE II — VALUATION AND QUALIFYING ACCOUNTS

FOR THE YEARS ENDED DECEMBER 31, 2019, 2018, AND 2017

(Stated in Millions of Dollars)

					Additions
Description	Balance at Beginning of Period				Charged to Income				Charged to Other Accounts				Deductions(*)				Balance at End of Period
Provision for uncollectible accounts
2019	$	10			$	24			$	—			$	12			$	22
2018	9				13				—				12				10
2017	10				10				—				11				9

(*)	Deductions represent write-offs of accounts considered to be uncollectible, less recoveries of amounts previously written off.

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GEORGIA POWER COMPANY

SCHEDULE II — VALUATION AND QUALIFYING ACCOUNTS

FOR THE YEARS ENDED DECEMBER 31, 2019, 2018, AND 2017

(Stated in Millions of Dollars)

					Additions
Description	Balance at Beginning of Period				Charged to Income				Charged to Other Accounts				Deductions				Balance at End of Period
Provision for uncollectible accounts(a)
2019	$	2			$	13			$	—			$	13			$	2
2018	3				11				—				12				2
2017	3				11				—				11				3
Tax valuation allowance (net state)(b)
2019	$	33			$	(5	)		$	—			$	—			$	28
2018	—				39				—				6				33
2017	—				—				—				—				—

(a)	Deductions represent write-offs of accounts considered to be uncollectible, less recoveries of amounts previously written off.

(b)	In 2018, Georgia Power established a valuation allowance for certain Georgia state tax credits expected to expire prior to being fully utilized, which was reduced in 2019 as a result of higher projected state taxable income. See Note 10 to the financial statements in Item 8 herein for additional information.

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MISSISSIPPI POWER COMPANY

SCHEDULE II — VALUATION AND QUALIFYING ACCOUNTS

FOR THE YEARS ENDED DECEMBER 31, 2019, 2018, AND 2017

(Stated in Millions of Dollars)

					Additions
Description	Balance at Beginning of Period				Charged to Income				Charged to Other Accounts				Deductions				Balance at End of Period
Provision for uncollectible accounts(a)
2019	$	1			$	2			$	—			$	2			$	1
2018	1				1				—				1				1
2017	—				2				—				1				1
Tax valuation allowance (net state)(b)
2019	$	32			$	—			$	—			$	—			$	32
2018	124				(92		)		—				—				32
2017	—				124				—				—				124

(a)	Deductions represent write-offs of accounts considered to be uncollectible, less recoveries of amounts previously written off.

(b)	In 2017, Mississippi Power established a valuation allowance for the State of Mississippi net operating loss carryforward expected to expire prior to being fully utilized, which was reduced in 2018 as a result of higher projected state taxable income. See Note 10 to the financial statements in Item 8 herein for additional information.

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SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES

SCHEDULE II — VALUATION AND QUALIFYING ACCOUNTS

FOR THE YEARS ENDED DECEMBER 31, 2019, 2018, AND 2017

(Stated in Millions of Dollars)

					Additions
Description	Balance at Beginning of Period				Charged to Income				Charged to Other Accounts				Deductions				Balance at End of Period
Tax valuation allowance (net state)
2019	$	22			$	7			$	—			$	—			$	29
2018	10				12				—				—				22
2017	—				10				—				—				10

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SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES

SCHEDULE II — VALUATION AND QUALIFYING ACCOUNTS

FOR THE YEARS ENDED DECEMBER 31, 2019, 2018, AND 2017

(Stated in Millions of Dollars)

					Additions
Description	Balance at Beginning of Period				Charged to Income				Charged to Other Accounts				Deductions				Balance at End of Period
Provision for uncollectible accounts(a)
2019	$	30			$	29			$	—			$	41			$	18
2018	28				33				(1		)		30				30
2017	27				28				—				27				28
Tax valuation allowance (net state)(b)
2019	$	12			$	(8	)		$	—			$	—			$	4
2018	11				1				—				—				12
2017	19				—				—				8				11

(a)	Deductions represent write-offs of accounts considered to be uncollectible, less recoveries of amounts previously written off.

(b)

In 2019, Southern Company Gas reversed a $13 million valuation allowance for a federal deferred tax asset in connection with the sale of Triton. Additionally, in 2019, a $5 million valuation allowance was established for a state net operating loss carryforward expected to expire prior to being fully utilized. See Note 10 to the financial statements and Note 15 to the financial statements under "Southern Company Gas" in Item 8 herein for additional information.

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