ALABAMA POWER CO - Annual Report: 2019 (Form 10-K)

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(*)	At December 31, 2019

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

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•	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

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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.

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

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(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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(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.

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

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(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.

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(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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(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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(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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(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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(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)	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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(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.

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

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(*)	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.

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(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.

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

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

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(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.

(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.

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(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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(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.

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•	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.

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(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.

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(a)	See "Alabama Power" herein for additional information.

(b)	See "Mississippi Power" herein for additional information.

(*)	Prior to October 1, 2022: $25.50; on or after October 1, 2022: Stated Capital

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(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.

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(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.

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(*)	Included in other current assets and other property and investments on the balance sheets.

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(*)	Represents effective income tax benefit rate for Mississippi Power due to a loss before income taxes in 2017.

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(*)	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.

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(*)	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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(*)	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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(*)	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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(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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(*)	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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(*)	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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•	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.

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(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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(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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(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.

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•

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.

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(*)

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.

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(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.

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(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.

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(*)	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.

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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.

(*)	Southern Power owns 100% of the Class B membership interests under a tax equity partnership.

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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 "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.

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(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).

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(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.

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(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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(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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(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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(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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(*)	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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(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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(*)	Deductions represent write-offs of accounts considered to be uncollectible, less recoveries of amounts previously written off.

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(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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(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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(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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