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•	the impact of recent and future federal and state regulatory changes, including environmental laws and regulations, and also changes in tax (including the Tax Reform Legislation) 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 liabilities to comply with federal and state laws, regulations, and legal requirements related to CCR, including amounts for required closure of ash ponds and ground water monitoring;

•	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, including Plant Vogtle Units 3 and 4 which includes components based on new technology that only recently began initial operation in the global nuclear industry at this scale, including changes in labor costs, availability, and productivity; challenges with management of contractors, subcontractors, or vendors; adverse weather conditions; shortages, increased costs, or inconsistent quality of equipment, materials, and labor; contractor or supplier delay; non-performance 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 the timely resolution of ITAAC and the related approvals by the NRC; challenges with start-up activities, including major equipment failure and system integration; and/or operational performance;

•	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;

•	the ability to control operating and maintenance costs;

•	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, and fuel and other cost recovery mechanisms;

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•	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;

•	legal proceedings and regulatory approvals and actions related to Plant Vogtle Units 3 and 4, including Georgia PSC approvals 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 with respect to the portion of MEAG's ownership interest in Plant Vogtle Units 3 and 4 involving JEA, any inability of Georgia Power to receive repayment of such funding;

•	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 proposed disposition of Plant Mankato, 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;

•	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)	AMEA will also be served by Plant Franklin Unit 1 through December 2019.

(3)

On November 5, 2018, Southern Power entered into an agreement with Northern States Power to sell all of its equity interests in Plant Mankato (including the 385-MW expansion currently under construction). The ultimate outcome of this matter cannot be determined at this time. See Note 15 to the financial statements under "Southern Power – Sales of Natural Gas Plants" in Item 8 herein for additional information.

(4)	Subject to commercial operation of the 385-MW expansion project.

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

(6)	JEA will also be served by Plant Wansley Unit 6 during 2019.

(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)

Reflects cost estimates for environmental 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 ash pond closure and groundwater monitoring under the CCR Rule and the related state rules. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Laws and Regulations" and FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" of Southern Company and each traditional electric operating company in Item 7 herein for additional information.

(d)	Excludes up to 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.

(e)

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 – "Infrastructure Replacement Programs and Capital Projects" of 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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•	possible disruption of the integrated resource planning processes within the states in the Southern Company system's service territory;

•	delays and additional processes for developing transmission plans; and

•	possible impacts on state jurisdiction of approving, certifying, and pricing new transmission facilities.

•	operator error or failure of equipment or processes;

•	accidents;

•	operating limitations that may be imposed by environmental or other regulatory requirements or in connection with joint owner arrangements;

•	labor disputes;

•	physical attacks;

•	fuel or material supply interruptions and/or shortages;

•	transmission disruption or capacity constraints, including with respect to the Southern Company system's and third parties' transmission, storage, and transportation facilities;

•	compliance with mandatory reliability standards, including mandatory cyber security standards;

•	implementation of new technologies;

•	information technology system failures;

•	cyber intrusions;

•	environmental events, such as spills or releases; and

•	catastrophic events such as fires, earthquakes, explosions, floods, tornadoes, hurricanes and other storms, droughts, pandemic health events, or other similar occurrences.

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•	the potential harmful effects on the environment and human health and safety resulting from a release of radioactive materials in connection with the operation of nuclear facilities and the storage, handling, and disposal of radioactive material, including spent nuclear fuel;

•	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 the nuclear operations of Alabama Power and Georgia Power or those of other commercial nuclear facility owners in the U.S.;

•	potential liabilities arising out of the operation of these facilities;

•	significant capital expenditures relating to maintenance, operation, security, and repair of these facilities, including repairs and upgrades required by the NRC;

•	actual or threatened cyber intrusions or physical attacks; and

•	the potential impact of an accident or natural disaster.

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

•	changes in labor costs, availability, and productivity;

•	challenges related to management of contractors, subcontractors, or vendors;

•	work stoppages;

•	contractor or supplier delay;

•	non-performance under construction, operating, or other agreements;

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

•	delays in start-up activities (including major equipment failure and system integration) 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 permitting and licensing requirements (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;

•	changes in project design or scope;

•	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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(a)	Excludes financing costs expected to be capitalized through AFUDC of approximately $315 million.

(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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•	prevailing market prices for coal, natural gas, uranium, fuel oil, biomass, 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;

•	Southern Company, Southern Company Gas, and certain of their subsidiaries have retained obligations in connection with transitional agreements related to dispositions that subject these companies 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 or performance 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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•	an economic downturn or uncertainty;

•	bankruptcy or financial distress at an unrelated energy company, financial institution, or sovereign entity;

•	capital markets volatility and disruption, either nationally or internationally;

•	changes in tax policy, including further interpretation and guidance on tax reform;

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•	volatility in market prices for electricity and natural gas;

•	actual or threatened cyber or physical attacks on the Southern Company system's facilities or unrelated energy companies' facilities;

•	war or threat of war; or

•	the overall health of the utility and financial institution industries.

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Item 1B.	UNRESOLVED STAFF COMMENTS.

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

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•

The traditional electric operating companies are vertically integrated utilities providing electric service in three Southeastern states as of January 1, 2019. On January 1, 2019, Southern Company completed its sale of Gulf Power to NextEra Energy for an aggregate cash purchase price of approximately $5.8 billion (less $1.3 billion of indebtedness assumed), subject to customary working capital adjustments. At December 31, 2018, the assets and liabilities of Gulf Power were classified as held for sale on Southern Company's balance sheet. Unless otherwise noted, the disclosures herein related to specific asset and liability balances at December 31, 2018 exclude assets and liabilities held for sale. See Note 15 under "Assets Held for Sale" for additional information. A preliminary gain of $2.5 billion pre-tax ($1.3 billion after tax) associated with the sale of Gulf Power is expected to be recorded in 2019.

•

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. On May 22, 2018, Southern Power sold a noncontrolling 33% equity interest in SP Solar, a limited partnership indirectly owning substantially all of Southern Power's solar facilities, for approximately $1.2 billion and, on December 11, 2018, Southern Power sold a noncontrolling tax equity interest in SP Wind, a holding company owning a portfolio of eight operating wind facilities, for approximately $1.2 billion. On November 5, 2018, Southern Power entered into an agreement to sell all of its equity interests in Plant Mankato (including the 385-MW expansion currently under construction) for an aggregate purchase price of approximately $650 million, which is expected to close mid-2019. The ultimate outcome of this matter cannot be determined at this time.

•	Southern Company Gas distributes natural gas through its natural gas distribution utilities and is involved in several other complementary businesses including gas pipeline investments, wholesale gas services, and gas marketing services. In July 2018, Southern Company Gas completed sales of three of its natural gas distribution utilities.

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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.

(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 $154 million decrease related to natural gas revenues, including alternative revenue programs, and a $74 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)	Excludes financing costs expected to be capitalized through AFUDC of approximately $315 million.

(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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•	the creditworthiness of the counterparties involved and the impact of credit enhancements (such as cash deposits and letters of credit);

•	events specific to a given counterparty; and

•	the impact of Southern Company's nonperformance risk on its liabilities.

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(a)	Represents the Southern Company parent entity.

(b)	Does not include Southern Power Company's $120 million continuing letter of credit facility for standby letters of credit expiring in 2021, of which $17 million was unused at December 31, 2018. Southern Power's subsidiaries are not parties to its bank credit arrangement.

(c)

Southern Company Gas, as the parent entity, guarantees the obligations of Southern Company Gas Capital, which is the borrower of $1.4 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.

(d)	Amounts used are for letters of credit.

(e)	Excludes $280 million of committed credit arrangements of Gulf Power, which was sold on January 1, 2019. See Note 15 to the financial statements under "Southern Company's Sale of Gulf Power" for additional information.

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(*)	Average and maximum amounts are based upon daily balances during the 12-month periods ended December 31, 2018, 2017, and 2016.

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

(b)	Represents the Southern Company parent entity.

(c)

In November 2018, SEGCO, as borrower, and Alabama Power, as guarantor, entered into a $100 million long-term delayed draw floating rate bank term loan bearing interest based on three-month LIBOR, which SEGCO used to repay at maturity $100 million aggregate principal amount of Series 2013A Senior Notes due December 1, 2018. See Note 9 to the financial statements under "Guarantees" for additional information.

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

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(a)	Includes potential collateral requirements related to Gulf Power of $111 million and $221 million at a credit rating of BBB- and/or Baa3 and BB+ and/or Ba1, respectively. See Note 15 to the financial statements under "Southern Company's Sale of Gulf Power" for information regarding the sale of Gulf Power on January 1, 2019.

(b)	Any additional credit rating downgrades at or below BB- and/or Ba3 could increase collateral requirements up to an additional $38 million.

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(a)	Current period changes also include the changes in fair value of new contracts entered into during the period, if any.

(b)	Excludes premium and intrinsic value associated with weather derivatives of $8 million and $11 million at December 31, 2018 and 2017, respectively.

(c)	Includes $6 million of net liabilities related to Gulf Power. See Note 15 to the financial statements under "Southern Company's Sale of Gulf Power" for information regarding the sale of Gulf Power on January 1, 2019.

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(a)

All amounts are reflected based on final maturity dates except for amounts related to FFB borrowings and certain revenue bonds. As it relates to the FFB borrowings, the final maturity date is February 20, 2044; however, principal amortization is reflected beginning in 2020. See Note 8 to the financial statements under "Long-term Debt – DOE Loan Guarantee Borrowings" and "Securities Due Within One Year" for additional information. Southern Company and its subsidiaries plan to continue, when economically feasible, to retire higher-cost securities and replace these obligations with lower-cost capital if market conditions permit. Variable rate interest obligations are estimated based on rates at December 31, 2018, as reflected in the statements of capitalization. Fixed rates include, where applicable, the effects of interest rate derivatives employed to manage interest rate risk. Long-term debt excludes capital lease amounts (shown separately).

(b)	Represents preferred stock of Alabama Power. Preferred stock does not mature; therefore, amounts are provided for the next five years only.

(c)	See Notes 1 and 14 to the financial statements.

(d)	Excludes PPAs that are accounted for as leases and included in "Purchased power."

(e)

Includes charges recoverable through a natural gas cost recovery mechanism, or alternatively billed to Marketers selling retail natural gas, and demand charges associated with Southern Company Gas' wholesale gas services. The gas supply balance includes amounts for gas commodity purchase commitments associated with Southern Company Gas' gas marketing services of 47 million mmBtu at floating gas prices calculated using forward natural gas prices at December 31, 2018 and valued at $150 million. Southern Company Gas provides guarantees to certain gas suppliers for certain of its subsidiaries in support of payment obligations.

(f)	Represents fixed-fee minimum payments for asset management agreements associated with wholesale gas services.

(g)

The Southern Company system provides estimated capital expenditures for a five-year period, including capital expenditures associated with environmental regulations. These amounts exclude contractual purchase commitments for nuclear fuel, capital expenditures covered under LTSAs, and estimated capital expenditures for AROs, which are reflected in "Fuel," "Other," and "ARO settlements," respectively. These amounts also exclude up to approximately $0.5 billion per year on average for 2019 through 2023 for Southern Power's planned expenditures for plant acquisitions and placeholder growth. At December 31, 2018, significant purchase commitments were outstanding in connection with the construction program. See FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Laws and Regulations" and "Construction Programs" herein for additional information.

(h)

Primarily includes commitments to purchase coal, nuclear fuel, and natural gas, as well as the related transportation and storage. In most cases, these contracts contain provisions for price escalation, minimum purchase levels, and other financial commitments. Natural gas purchase commitments are based on various indices at the time of delivery. Amounts reflected for natural gas purchase commitments have been estimated based on the NYMEX future prices at December 31, 2018.

(i)	Estimated minimum long-term obligations for various PPA purchases from gas-fired, biomass, and wind-powered facilities and capacity payments related to Plant Vogtle Units 1 and 2. See Note 9 to the financial statements under "Fuel and Power Purchase Agreements" for additional information.

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(j)	Includes LTSAs, contracts for the procurement of limestone, contractual environmental remediation liabilities, and operation and maintenance agreements. LTSAs include price escalation based on inflation indices.

(k)

Represents estimated costs for a five-year period associated with closing and monitoring ash ponds in accordance with the CCR Rule and the related state rules, which are reflected in Southern Company's ARO liabilities. Material expenditures in future years for ARO settlements also will be required for ash ponds, nuclear decommissioning, and other liabilities reflected in Southern Company's AROs. See FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Laws and Regulations – Coal Combustion Residuals" herein and Note 6 to the financial statements for additional information.

(l)

Projections of nuclear decommissioning trust fund contributions for Plant Hatch and Plant Vogtle Units 1 and 2 are based on the 2013 ARP for Georgia Power. Alabama Power also has external trust funds for nuclear decommissioning costs; however, Alabama Power currently has no additional funding requirements. See Note 6 to the financial statements under "Nuclear Decommissioning" for additional information.

(m)

The Southern Company system forecasts contributions to the pension and other postretirement benefit plans over a three-year period. Southern Company anticipates no mandatory contributions to the qualified pension plans during the next three years. Amounts presented represent estimated benefit payments for the nonqualified pension plans, estimated non-trust benefit payments for the other postretirement benefit plans, and estimated contributions to the other postretirement benefit plan trusts, all of which will be made from corporate assets of Southern Company's subsidiaries. See Note 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 Southern Company's subsidiaries.

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(*)	Average and maximum amounts are based upon daily balances during the 12-month periods ended December 31, 2018, 2017, and 2016.

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(*)	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)

All amounts are reflected based on final maturity dates. Alabama Power plans 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, 2018, as reflected in the statements of capitalization. Fixed rates include, where applicable, the effects of interest rate derivatives employed to manage interest rate risk. Long-term debt excludes capital lease amounts (shown separately).

(b)	Preferred stock does not mature; therefore, amounts are provided for the next five years only.

(c)	Includes derivative liabilities related to cash flow hedges of forecasted debt, as well as energy-related derivatives. For additional information, see Notes 1 and 14 to the financial statements.

(d)	Excludes PPAs that are accounted for as leases and are included in purchased power.

(e)

Alabama Power provides estimated capital expenditures for a five-year period, including capital expenditures associated with environmental regulations. These amounts exclude contractual purchase commitments for nuclear fuel, capital expenditures covered under LTSAs, and estimated capital expenditures for AROs, which are reflected in "Fuel," "Other," and "ARO settlements," respectively. At December 31, 2018, purchase commitments were outstanding in connection with the construction program. See FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Laws and Regulations" herein for additional information.

(f)

Includes commitments to purchase coal, nuclear fuel, and natural gas, as well as the related transportation and storage. In most cases, these contracts contain provisions for price escalation, minimum purchase levels, and other financial commitments. Natural gas purchase commitments are based on various indices at the time of delivery. Amounts reflected for natural gas purchase commitments have been estimated based on the NYMEX future prices at December 31, 2018.

(g)	Estimated minimum long-term obligations for various long-term commitments for the purchase of capacity and energy.

(h)	Includes LTSAs and contracts for the procurement of limestone. LTSAs include price escalation based on inflation indices.

(i)

Represents estimated costs for a five-year period associated with closing and monitoring ash ponds in accordance with the CCR Rule and the related state rule, which are reflected in Alabama Power's ARO liabilities. Material expenditures in future years for ARO settlements also will be required for ash ponds, nuclear decommissioning, and other liabilities reflected in Alabama Power's AROs. See FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Laws and Regulations – Coal Combustion Residuals" herein and Note 6 to the financial statements for additional information.

(j)

Alabama Power forecasts contributions to the pension and other postretirement benefit plans over a three-year period. Alabama Power anticipates 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 Alabama Power's corporate assets. 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 Alabama Power's corporate assets.

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(a)	Excludes financing costs expected to be capitalized through AFUDC of approximately $315 million.

(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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(*)	Average and maximum amounts are based upon daily balances during the 12-month periods ended December 31, 2018, 2017, and 2016.

•	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

•	$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

•	$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

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•	$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

•	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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(*)	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)

All amounts are reflected based on final maturity dates except for amounts related to FFB borrowings and certain pollution control revenue bonds. As it relates to the FFB borrowings, the final maturity date is February 20, 2044; however, principal amortization is reflected beginning in 2020. See Note 8 to the financial statements under "Long-term Debt – DOE Loan Guarantee Borrowings" for additional information. Georgia Power plans 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, 2018, as reflected in the statements of capitalization. Fixed rates include, where applicable, the effects of interest rate derivatives employed to manage interest rate risk. Long-term debt excludes capital lease amounts (shown separately).

(b)	See Notes 1 and 14 to the financial statements.

(c)	Excludes PPAs that are accounted for as leases and included in "Purchased power." See Note 8 to the financial statements under "Long-term Debt – Capital Leases – Georgia Power" and Note 9 to the financial statements under "Operating Leases" for additional information.

(d)

Georgia Power provides estimated capital expenditures for a five-year period, including capital expenditures associated with environmental regulations. These amounts exclude contractual purchase commitments for nuclear fuel, capital expenditures covered under LTSAs, and estimated capital expenditures for AROs, which are reflected in "Fuel," "Other," and "ARO settlements," respectively. At December 31, 2018, significant purchase commitments were outstanding in connection with the construction program. See FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Laws and Regulations" and "Retail Regulatory Matters – Nuclear Construction" herein for additional information.

(e)

Includes commitments to purchase coal, nuclear fuel, and natural gas, as well as the related transportation and storage. In most cases, these contracts contain provisions for price escalation, minimum purchase levels, and other financial commitments. Natural gas purchase commitments are based on various indices at the time of delivery. Amounts reflected for natural gas purchase commitments have been estimated based on the NYMEX future prices at December 31, 2018.

(f)	Estimated minimum long-term obligations for various PPA purchases from gas-fired, biomass, and wind-powered facilities and capacity payments related to Plant Vogtle Units 1 and 2. See Note 9 to the financial statements under "Fuel and Power Purchase Agreements" for additional information.

(g)	Includes LTSAs and contracts for the procurement of limestone. LTSAs include price escalation based on inflation indices.

(h)

Represents estimated costs for a five-year period associated with closing and monitoring ash ponds and landfills in accordance with the CCR Rule and the related state rule, which are reflected in Georgia Power's AROs. Material expenditures in future years for ARO settlements also will be required for ash ponds, nuclear decommissioning, and other liabilities and are reflected in Georgia Power's AROs. See FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Laws and Regulations – Coal Combustion Residuals" herein and Note 6 to the financial statements for additional information.

(i)	Projections of nuclear decommissioning trust fund contributions for Plant Hatch and Plant Vogtle Units 1 and 2 are based on the 2013 ARP. See Note 6 to the financial statements under "Nuclear Decommissioning" for additional information.

(j)

Georgia Power forecasts contributions to the pension and other postretirement benefit plans over a three-year period. Georgia Power anticipates 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 Georgia Power's corporate assets. 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 Georgia Power's corporate assets.

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(*)	Adjusted to include the impacts of station service in 2018 and test period energy produced in 2017 and 2016 for the Kemper County energy facility, which was accounted for in accordance with FERC guidance.

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(*)	Average and maximum amounts are based upon daily balances during the 12-month periods ended December 31, 2018, 2017, and 2016.

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(*)	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)

All amounts are reflected based on final maturity dates. Mississippi Power plans 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, 2018, as reflected in the statements of capitalization. Fixed rates include, where applicable, the effects of interest rate derivatives employed to manage interest rate risk. For additional information, see Note 8 to the financial statements.

(b)	Derivative obligations are for energy-related derivatives. For additional information, see Notes 1 and 14 to the financial statements.

(c)	See Note 9 to the financial statements for additional information.

(d)

Mississippi Power provides estimated capital expenditures for a five-year period, including capital expenditures associated with environmental regulations. At December 31, 2018, significant purchase commitments were outstanding in connection with the construction program. These amounts exclude capital expenditures covered under LTSAs and estimated capital expenditures for AROs, which are reflected separately. See FUTURE EARNINGS POTENTIAL – "Environmental Matters" for additional information.

(e)

Includes commitments to purchase coal and natural gas, as well as the related transportation and storage. In most cases, these contracts contain provisions for price escalation, minimum purchase levels, and other financial commitments. Natural gas purchase commitments are based on various indices at the time of delivery. Amounts reflected for natural gas purchase commitments have been estimated based on the NYMEX future prices at December 31, 2018.

(f)	LTSAs include price escalation based on inflation indices.

(g)	Estimated minimum long-term commitments for the purchase of solar energy. Energy costs associated with solar PPAs are recovered through the fuel clause. See Notes 2 and 9 to the financial statements for additional information.

(h)

Represents estimated costs for a five-year period associated with closing and monitoring ash ponds in accordance with the CCR Rule, which are reflected in Mississippi Power's ARO liabilities. Material expenditures in future years for ARO settlements also will be required for ash ponds and other liabilities reflected in Mississippi Power's AROs. See FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Laws and Regulations – Coal Combustion Residuals" herein and Note 6 to the financial statements for additional information.

(i)

Mississippi Power forecasts contributions to the pension and other postretirement benefit plans over a three-year period. Mississippi Power anticipates 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 Mississippi Power's corporate assets. 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 Mississippi Power's corporate assets.

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•	On May 22, 2018, Southern Power sold a noncontrolling 33% equity interest in SP Solar, a limited partnership indirectly owning substantially all of Southern Power's solar facilities, for approximately $1.2 billion.

•	On December 4, 2018, Southern Power sold all of its equity interests in Plant Oleander and Plant Stanton Unit A (together, the Florida Plants) to NextEra Energy for $203 million.

•	On December 11, 2018, Southern Power sold a noncontrolling tax equity interest in SP Wind, a holding company owning a portfolio of eight operating wind facilities, for approximately $1.2 billion.

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•	PPA capacity revenues decreased $19 million, or 3%, primarily due to decreases of $16 million from the contractual expiration of an affiliate natural gas PPA and $5 million from the Florida Plants sold in December 2018.

•

PPA energy revenues increased $170 million, or 18%, primarily due to a $142 million increase in sales related to existing natural gas facilities driven by an $88 million increase in the average cost of fuel and a $54 million increase in the volume of KWHs sold due to customer load, a $12 million increase related to PPAs associated with new renewable facilities, and a $16 million increase related to PPAs associated with existing renewable facilities primarily due to an increase in the volume of KWHs sold.

•	Non-PPA revenues decreased $22 million, or 4%, primarily due to a $56 million decrease in the volume of KWHs sold from uncovered natural gas capacity through short-term sales, partially offset by a $35 million increase in the market price of energy.

•	PPA capacity revenues increased $58 million, or 11%, primarily due to additional customer capacity requirements and a new PPA related to Plant Mankato acquired in late 2016.

•

PPA energy revenues increased $276 million, or 40%, primarily due to a $213 million increase in renewable energy sales arising from new solar and wind facilities and a $50 million increase in sales related to existing natural gas PPAs primarily due to an $85 million increase in the average cost of fuel, partially offset by a $35 million decrease in the volume of KWHs sold primarily due to reduced customer load.

•	Non-PPA revenues increased $164 million, or 50%, primarily due to a $156 million increase in the volume of KWHs sold primarily from uncovered natural gas capacity through short-term opportunity sales, as well as an $8 million increase in the market price of energy.

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

(a)	In July 2017, Southern Power purchased 100% of the Cactus Flats facility. In August 2018, Southern Power closed on a tax equity partnership and now owns 100% of the class B membership interests.

(b)	In November 2018, Southern Power entered into an agreement to sell all of its equity interests in Plant Mankato, including this expansion currently under construction. See "Sales of Natural Gas Plants" below.

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(c)	In May 2018, Southern Power purchased 100% of the Wild Horse Mountain facility. 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 August 2018, Southern Power purchased 100% of the membership interests of the Reading facility from the joint development arrangement with Renewable Energy Systems Americas, Inc. described below. 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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•	Assessing whether specific property is explicitly or implicitly identified in the agreement;

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

•	Assessing whether the arrangement conveys to the purchaser the right to use the identified property.

•	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.

•	Future demand for electricity based on projections of economic growth and estimates of available generating capacity;

•	Future power and natural gas prices, which have been quite volatile in recent years; and

•	Future operating costs.

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(*)	Average and maximum amounts are based upon daily balances during the twelve-month periods ended December 31, 2018, 2017, and 2016.

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(*)	Any additional credit rating downgrades at or below BB- and/or Ba3 could increase collateral requirements up to an additional $38 million.

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(*)	Current period changes also include changes in the fair value of new contracts entered into during the period, if any.

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(a)

All amounts are reflected based on final maturity dates and 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. Included in debt principal is an $18 million gain related to the foreign currency hedge of €1.1 billion. Southern Power plans to continue, when economically feasible, to retire higher-cost securities and replace these obligations with lower-cost capital if market conditions permit.

(b)	For additional information, see Notes 1 and 14 to the financial statements.

(c)	Operating lease commitments include certain land leases for solar and wind facilities that may be subject to annual price escalation based on indices. See Note 9 to the financial statements for additional information.

(d)

Southern Power provides estimated capital expenditures for a five-year period, including capital expenditures associated with environmental regulations. Excluded from these amounts are planned expenditures for plant acquisitions and placeholder growth of $2.3 billion. Also excluded from these amounts are capital expenditures covered under LTSAs which are reflected in "Other." See Note (g) below. At December 31, 2018, significant purchase commitments were outstanding in connection with the construction program. No ARO settlements are projected during the five-year period.

(e)	Primarily includes commitments to purchase, transport, and store natural gas. Amounts reflected are based on contracted cost and may contain provisions for price escalation. Amounts reflected for natural gas purchase commitments are based on various indices at the time of delivery and have been estimated based on the NYMEX future prices at December 31, 2018.

(f)	Purchased power commitments will be resold under a third party agreement at cost.

(g)	Includes commitments related to LTSAs, operation and maintenance agreements, and transmission. LTSAs include price escalation based on inflation indices. Transmission commitments are based on the Southern Company system's current tariff rate for point-to-point transmission.

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•	On June 4, 2018, Southern Company Gas completed the stock sale of Pivotal Home Solutions to American Water Enterprises LLC for a total cash purchase price of $365 million, which includes the final working capital adjustment.

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On July 1, 2018, a Southern Company Gas subsidiary, Pivotal Utility Holdings, completed the sales of the assets of two of its natural gas distribution utilities, Elizabethtown Gas and Elkton Gas, to South Jersey Industries, Inc. for a total cash purchase price of $1.7 billion, which includes the final working capital and other adjustments. This disposition resulted in a pre-tax gain that was entirely offset by $205 million of income tax expense, resulting in no material net income impact.

•

On July 29, 2018, Southern Company Gas and its wholly-owned direct subsidiary, NUI Corporation, completed the stock sale of Pivotal Utility Holdings, which primarily consisted of Florida City Gas, to NextEra Energy for a total cash purchase price of $587 million, which includes the final working capital adjustment less indebtedness assumed at closing. This disposition resulted in a net gain of $16 million, which includes $103 million of income tax expense.

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(*)	Includes Piedmont's 15% interest in SouthStar, which was acquired by Southern Company Gas in 2016. See Note 7 to the financial statements under "Southern Company Gas" for additional information.

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(*)	Includes a $154 million decrease related to natural gas revenues, including alternative revenue programs, and a $74 million decrease related to other revenues. See Note 15 to the financial statements under "Southern Company Gas" for additional information.

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(*)	Normal represents the 10-year average from January 1, 2008 through December 31, 2017 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.

(a)	Includes total customers of approximately 407,000 and 402,000 at December 31, 2017 and 2016, respectively, related to Elizabethtown Gas, Elkton Gas, and Florida City Gas, which were sold in 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.

(b)	Includes customers in Ohio contracted through an annual auction process to serve for a 12-month period beginning April 1 of each year. At December 31, 2018 and 2017, there were approximately 70,000 and 140,000 contracted customers, respectively. At December 31, 2016, there were no contracted customers.

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(a)	Includes other operations and maintenance, depreciation and amortization, taxes other than income taxes, goodwill impairment, gain on dispositions, net, and Merger-related expenses.

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

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(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.

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

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(a)	At December 31, 2018, the WACOG of wholesale gas services' expected natural gas withdrawals from storage was $2.90 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 periods associated with the transportation derivative net gains during which the derivatives will be settled and the physical transportation transactions will occur that offset the derivative gains and losses that were previously recognized.

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(a)	Includes other operations and maintenance, depreciation and amortization, taxes other than income taxes, goodwill impairment, gain on dispositions, net, and Merger-related expenses.

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

•	On June 4, 2018, Southern Company Gas completed the stock sale of Pivotal Home Solutions to American Water Enterprises LLC. Southern Company Gas and American Water Enterprises LLC entered into a transition services

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On July 1, 2018, a Southern Company Gas subsidiary, Pivotal Utility Holdings, completed the sales of the assets of two of its natural gas distribution utilities, Elizabethtown Gas and Elkton Gas, to South Jersey Industries, Inc. Southern Company Gas and South Jersey Industries, Inc. entered into transition services agreements whereby Southern Company Gas will provide certain administrative and operational services through no later than July 31, 2020.

•

On July 29, 2018, Southern Company Gas and its wholly-owned direct subsidiary, NUI Corporation, completed the stock sale of Pivotal Utility Holdings, which primarily consisted of Florida City Gas, to NextEra Energy. Southern Company Gas and NextEra Energy entered into a transition services agreement whereby Southern Company Gas will provide certain administrative and operational services through no later than July 29, 2020.

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(a)	Represents Southern Company Gas' expected total capital expenditures, excluding AFUDC, at completion, which may change.

(b)

In 2014, Southern Company Gas entered into a joint venture to construct and operate a natural gas pipeline that will run from West Virginia through Virginia and into eastern North Carolina to meet the region's growing demand for natural gas. The proposed pipeline project is expected to transport natural gas to customers in Virginia. In August 2017, the Atlantic Coast Pipeline received FERC approval.

(c)

In 2014, Southern Company Gas entered into a joint venture to construct and operate a natural gas pipeline that will transport low-cost natural gas from the Marcellus Shale area to customers in New Jersey. Southern Company Gas believes this will alleviate takeaway constraints in the Marcellus region and help mitigate some of the price volatility experienced during recent winters. On January 19, 2018, the PennEast Pipeline received FERC approval.

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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)	Represents the authorized ROE, or the midpoint of the authorized ROE range, at December 31, 2018.

(b)	The authorized ROE range for Atlanta Gas Light and Virginia Natural Gas was 10.55% - 10.95% and 9.00% - 10.00%, respectively, at December 31, 2018.

(c)

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.

(d)	Recovery of fixed customer service costs separately from assumed natural gas volumes used by customers.

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

(f)	Recovery of program costs at Atlanta Gas Light was incorporated in GRAM, which the Georgia PSC approved in February 2017. See "Infrastructure Replacement Programs and Capital Projects – Atlanta Gas Light" herein for additional information.

(g)	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.

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

(i)	See "Rate Proceedings" herein and Note 2 to the financial statements under "Southern Company Gas – Rate Proceedings" for additional information.

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(*)	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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(*)

Payments made to Elizabethtown Gas, Elkton Gas, and Florida City Gas, which were sold in July 2018, were $14 million and $12 million for the successor years ended December 31, 2018 and 2017, respectively, $3 million for the successor period of July 1, 2016 through December 31, 2016, and $13 million for the predecessor period of January 1, 2016 through June 30, 2016. See Note 15 to the financial statements under "Southern Company Gas" for additional information on these dispositions.

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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 Southern Company Gas' nonperformance risk on its liabilities.

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(*)	Average and maximum amounts are based upon daily balances during the 12-month periods.

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(a)	Current period changes also include the changes in fair value of new contracts entered into during the period, if any.

(b)	Net fair value of derivative contracts outstanding excludes premium and intrinsic value associated with weather derivatives of $8 million and $11 million at December 31, 2018 and 2017, respectively, and includes premium and intrinsic value associated with weather derivatives of $4 million at December 31, 2016, and $5 million at June 30, 2016.

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(a)	Valued using NYMEX futures prices.

(b)	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 $277 million as well as premium and associated intrinsic value associated with weather derivatives of $8 million at December 31, 2018.

(*)

Increases in VaR at December 31, 2018 and 2017 were driven by significant natural gas price increases in Sequent's key markets. The natural gas price increase in 2018 was 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. The natural gas price increase in 2017 was driven by colder-than-normal weather. As weather and natural gas prices moderated subsequent to December 31, 2018 and 2017, VaR reduced to a level consistent with December 31, 2016.

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(a)	Amounts are reflected based on final maturity dates. Southern Company Gas plans 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, 2018, as reflected in the statements of capitalization.

(b)

Includes charges recoverable through a natural gas cost recovery mechanism, or alternatively billed to Marketers, and demand charges associated with Sequent. The gas supply balance includes amounts for Nicor Gas and SouthStar gas commodity purchase commitments of 47 million mmBtu at floating gas prices calculated using forward natural gas prices at December 31, 2018 and valued at $150 million. Southern Company Gas provides guarantees to certain gas suppliers for certain of its subsidiaries, including SouthStar, in support of payment obligations.

(c)

Certain operating leases have provisions for step rent or escalation payments and certain lease concessions are accounted for by recognizing the future minimum lease payments on a straight-line basis over the respective minimum lease terms. However, this accounting treatment does not affect the future annual operating lease cash obligations as shown herein. In terms of rental charges and duration of contracts, Southern Company Gas' most significant operating leases relate to real estate.

(d)	Represent fixed-fee minimum payments for Sequent's affiliated asset management agreements.

(e)	See Notes 1 and 14 to the financial statements for additional information.

(f)

Southern Company Gas forecasts contributions to the pension and other postretirement benefit plans over a three-year period. Southern Company Gas anticipates 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 Southern Company Gas' corporate assets. 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 Southern Company Gas' corporate assets.

(g)	Estimated capital expenditures are provided through 2023. At December 31, 2018, significant purchase commitments were outstanding in connection with infrastructure and other construction programs.

(h)	Includes contractual environmental remediation liabilities that are generally recoverable through base rates or rate rider mechanisms and LTSAs.

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Item 7A.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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Item 8.	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

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

(b)	Southern Company Gas' 2016 costs represent services provided subsequent to the Merger.

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(*)	Represents costs incurred for the period subsequent to Southern Company Gas' investment in SNG.

(*)	Represents costs incurred for the period subsequent to Southern Company's acquisition of Southern Company Gas.

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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, and, prior to its sale, Elkton Gas; and

•

Revenue true-up adjustment – included within the provisions of the Georgia Rate Adjustment Mechanism (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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(a)	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.

(b)	Mississippi Power's decrease in 2017 resulted from the Kemper IGCC project suspension in June 2017.

(a)	Fixed rates authorized by the Georgia PSC and Tennessee Public Utilities Commission for Atlanta Gas Light and Chattanooga Gas, respectively.

(b)	Variable rate determined by the FERC method of AFUDC accounting.

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(a)	On April 11, 2018, Southern Company Gas entered into a stock purchase agreement for the sale of Pivotal Home Solutions. In contemplation of this transaction and based on the purchase price, a goodwill impairment charge of $42 million was recorded in the first quarter 2018. See Note 15 under "Southern Company Gas" for additional information.

(b)	Gas distribution operations reflects goodwill allocated to Elizabethtown Gas, Elkton Gas, and Florida City Gas, which were sold during the third quarter 2018. Gas marketing services reflects goodwill associated with Pivotal Home Solutions, which was sold on June 4, 2018. See Note 15 under "Southern Company Gas" for additional information.

(c)	Total does not add due to rounding.

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(a)	Balances as of December 31, 2018 reflect the sale of Pivotal Home Solutions. See Note 15 under "Southern Company Gas – Sale of Pivotal Home Solutions" for additional information.

(b)	Balances as of December 31, 2018 exclude Plant Mankato-related intangible assets that were reclassified as assets held for sale. See Note 15 under "Southern Power – Sales of Natural Gas Plants" for additional information.

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(a)	Recorded as a reduction to operating revenues.

(b)	Included in depreciation and amortization.

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

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(*)	Includes accruals at Gulf Power of $26.9 million in 2018 and $3.5 million in each of 2017 and 2016. See Note 15 under "Southern Company's Sale of Gulf Power" for information regarding the sale of Gulf Power.

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(*)	Reflects the reclassification related to stranded tax effects resulting from the Tax Reform Legislation as allowed by ASU 2018-02. See "Recently Adopted Accounting Standards – Other" herein for additional information.

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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)

Asset retirement 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 $28 million for the retiree Medicare drug subsidy, which is being recovered and amortized through 2027.

(c)	Through 2019, Georgia Power is recovering approximately $30 million annually for storm damage, which is expected to be adjusted in the Georgia Power 2019 Base Rate Case. See "Georgia Power – Storm Damage Recovery" herein for additional information.

(d)	Recorded and recovered or amortized over periods generally not exceeding 10 years.

(e)	Recovered through environmental cost recovery mechanisms when the remediation is performed or the work is performed.

(f)	Recovered over either the remaining life of the original issue or, if refinanced, over the remaining life of the new issue, which may range up to 50 years.

(g)	Amortized over periods not exceeding eight years.

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

(i)	Recovered over the remaining life of the original debt issuances, which range up to 20 years. For additional information see Note 15 under "Southern Company Merger with Southern Company Gas."

(j)	Related to Gulf Power and reclassified as assets held for sale at December 31, 2018. See Note 15 under "Southern Company's Sale of Gulf Power" for information regarding the sale of Gulf Power.

(k)	Comprised of numerous immaterial components including nuclear outage, fuel-hedging losses, cancelled construction projects, building and generating plant leases, property tax, and other miscellaneous assets. These costs are recorded and recovered or amortized over periods generally not exceeding 50 years.

(l)	Amortized as storm restoration and potential reliability-related expenses are incurred.

(m)	Comprised of numerous components including retiree benefit plans, fuel-hedging gains, AROs, and other liabilities that are recorded and recovered or amortized over periods not exceeding 20 years.

(n)

At December 31, 2018, represents amounts accrued and outstanding for refund, including approximately $109 million as a result of Alabama Power's 2018 retail return exceeding the allowed range, approximately $55 million pursuant to the Georgia Power Tax Reform Settlement Agreement, and approximately $100 million, subject to review and approval by the Georgia PSC, as a result of Georgia Power's 2018 retail ROE exceeding the allowed retail ROE range. See "Alabama Power – Rate RSE" and "Georgia Power – Rate Plans" herein for additional information.

(o)	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 be determined in future rate proceedings. See "Georgia Power," "Mississippi Power," and "Southern Company Gas" herein and Note 10 for additional information.

(p)	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 15 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 50 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 $10 million for 2018 and $13 million for 2017 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 50 years. See Note 10 for additional information.

(e)	Recorded and recovered or amortized over periods not exceeding 10 years. See "Rate CNP PPA," "Rate CNP Compliance," and" Rate ECR" herein for additional information.

(f)	Will be amortized concurrently with the effective date of Alabama Power's next depreciation study. See "Rate RSE" herein for additional information.

(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 the remaining life of the original issue, which may range up to 50 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 up to 8 years.

(k)	Comprised of components including generation site selection/evaluation costs, PPA capacity (to be recovered over the next 12 months), and other miscellaneous assets. Capitalized upon initialization of related construction projects, if applicable.

(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)	Refund accrued as a result of the 2018 retail return exceeding the allowed range. See "Rate RSE" herein for additional information.

(n)	Amortized as storm restoration and potential reliability-related expenses are incurred.

(o)	Comprised of several components, primarily $33 million deferred as a result of the Alabama PSC accounting order regarding the Tax Reform Legislation. See "Tax Reform Accounting Order" herein for additional information.

(p)	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)

Through 2019, Georgia Power is recovering approximately $60 million annually for AROs, which is expected to be adjusted in the Georgia Power 2019 Base Rate Case. Asset retirement and removal liabilities will be settled and trued up following completion of the related activities. See Note 6 for additional information on AROs. Other cost of removal obligations and deferred income tax assets are recovered and deferred income tax liabilities are amortized over the related property lives, which may range up to 65 years. Included in the deferred income tax assets is $17 million for the retiree Medicare drug subsidy, which is being recovered and amortized through 2022.

(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 $610 million of deferred income tax liabilities, neither of which are subject to normalization. The recovery and amortization of these amounts is expected to be determined in the Georgia Power 2019 Base Rate Case. See "Rate Plans" herein and Note 10 for additional information.

(d)	Through 2019, Georgia Power is recovering approximately $30 million annually for storm damage, which is expected to be adjusted in the Georgia Power 2019 Base Rate Case. See "Storm Damage Recovery" herein and Note 1 under "Storm Damage Reserves" for additional information.

(e)

The net book value of Plant Branch Units 1 through 4 at December 31, 2018 was $87 million, which is being amortized over the units' remaining useful lives through 2024. The net book value of Plant Mitchell Unit 3 at December 31, 2018 was $9 million, which will continue to be amortized through December 31, 2019 as provided in the 2013 ARP. Amortization of the remaining approximately $4 million net book value of Plant Mitchell Unit 3 at December 31, 2019 and a total of approximately $31 million related to obsolete inventories of certain retired units is expected to be determined in the Georgia Power 2019 Base Rate Case. See "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, which currently does not exceed 34 years.

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

(h)	Through 2019, Georgia Power is recovering approximately $2 million annually for environmental remediation, which is expected to be adjusted in the Georgia Power 2019 Base Rate Case. See Note 3 under Environmental Remediation for additional information.

(i)

Comprised of several components including future generation costs, deferred nuclear outage costs, cancelled construction projects, building lease, and fuel-hedging losses. The timing of recovery of approximately $50 million for a future generation site is expected to be determined in the Georgia Power 2019 Base Rate Case. Nuclear outage costs are recorded and recovered or amortized over the outage cycles of each nuclear unit, which do not exceed 24 months. Approximately $30 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. The building lease is recorded and recovered or amortized through 2020. Fuel-hedging losses are recovered through Georgia Power's fuel cost recovery mechanism upon final settlement. See "Integrated Resource Plan" herein for additional information on future generation costs.

(j)	At December 31, 2018, approximately $55 million was accrued and outstanding for refund pursuant to the Georgia Power Tax Reform Settlement Agreement and approximately $100 million was accrued for refund, subject to review and approval by the Georgia PSC, as a result of the 2018 retail ROE exceeding the allowed retail ROE range. See "Rate Plans" herein for additional information.

(k)

Comprised of Demand-Side Management (DSM) tariff over recovery and fuel-hedging gains. The amortization of DSM tariff over recovery of $3 million at December 31, 2018 is expected to be determined in the Georgia Power 2019 Base Rate Case. Fuel-hedging gains are refunded through Georgia Power's fuel cost recovery mechanism upon final settlement. See "Rate Plans" herein for additional information on customer refunds and DSM tariffs.

(l)	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)	Excludes financing costs expected to be capitalized through AFUDC of approximately $315 million.

(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 15 years. See Note 11 for additional information.

(b)	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. 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.

(c)

Includes $91 million of regulatory assets and $22 million of regulatory liabilities. The retail portion includes $75 million of regulatory assets and $22 million of regulatory liabilities that are being recovered in rates over an eight-year period through 2025 and a six-year period through 2023, respectively. Recovery of the wholesale portion of the regulatory assets in the amount of $16 million is expected to be determined in a settlement agreement with wholesale customers in 2019. For additional information, see "Kemper County Energy Facility – Rate Recovery – Kemper Settlement Agreement" herein.

(d)	Retail portion includes approximately $26 million being recovered over a five-year period through 2021 and 2022 for Plant Watson and Plant Greene County, respectively. Recovery of the wholesale portion of approximately $15 million is expected to be determined in a settlement agreement with wholesale customers in 2019.

(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 the purchase option and the revenue requirement assuming operating lease accounting treatment for the extended term, 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 Plan" herein.

(h)

Comprised of $9 million related to vacation pay, $8 million related to loss on reacquired debt, and other miscellaneous assets. These costs are recorded and recovered or amortized over periods which may range up to 50 years. This amount also includes fuel-hedging assets which are recorded over the life of the underlying hedged purchase contracts, which generally do not exceed three years. Upon final settlement, actual costs incurred are recovered through the ECM.

(i)

Includes excess deferred income taxes primarily associated with Tax Reform Legislation of $377 million, of which $266 million is related to protected deferred income taxes to be recovered over the related property lives utilizing the average rate assumption method in accordance with IRS normalization principles and $111 million related to unprotected (not subject to normalization). The unprotected portion associated with the Kemper County energy facility is $46 million, of which $33 million is being amortized over eight years through 2025 for retail and the amortization of $15 million is expected to be determined in a settlement agreement with wholesale customers in 2019. Mississippi Power also has $9 million of excess deferred income tax benefits associated with the System Restoration Rider being amortized over an eight-year period through 2025. Amortization of the remaining portions of the unprotected deferred income taxes associated with the Tax Reform Legislation are expected to be determined in Mississippi Power's next base rate proceeding, which is scheduled to be filed in the fourth quarter 2019 (Mississippi Power 2019 Base Rate Case). See "Kemper County Energy Facility" and "FERC Matters – Mississippi Power – Municipal and Rural Associations Tariff" herein and Note 10 for additional information.

(j)	For additional information, see "System Restoration Rider" herein.

(k)	Comprised of numerous immaterial components including deferred income tax credits and other miscellaneous liabilities that are recorded and 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 is performed or the work is performed.

(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, which range up to 20 years.

(e)

Recorded and recovered or amortized over periods generally not exceeding seven years. In addition to natural gas cost recovery mechanisms, the natural gas distribution utilities are authorized to utilize other cost recovery mechanisms, such as regulatory riders, which vary by utility but allow recovery of certain costs, such as those related to infrastructure replacement programs, as well as environmental remediation and energy efficiency plans.

(f)

Comprised of several components including unamortized loss on reacquired debt, weather normalization, franchise gas, deferred depreciation, and financial instrument-hedging assets, which are recovered or amortized over periods generally not exceeding 10 years, except for financial hedging-instruments. Financial instrument-hedging assets are recorded over the life of the underlying hedged purchase contracts, which generally do not exceed two years. Upon final settlement, actual costs incurred are recovered, and actual income earned is refunded through the energy cost recovery clause.

(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 several components including amounts to be refunded to customers as a result of the Tax Reform Legislation, energy efficiency programs, and unamortized bond issuance costs and financial instrument-hedging liabilities which are recovered or amortized over periods generally not exceeding 20 years, except for financial hedging-instruments. Financial instrument-hedging liabilities are recorded over the life of the underlying hedged purchase contracts, which generally do not exceed two years. Upon final settlement, actual 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)	Includes excess deferred income tax liabilities not subject to normalization as a result of the Tax Reform Legislation, the recovery and amortization of which is expected to be determined by the applicable state regulatory agencies in future rate proceedings. See "Rate Proceedings" herein and Note 10 for additional details.

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(*)	At December 31, 2017, $85 million of Southern Company Gas' total environmental remediation liability related to Elizabethtown Gas, which was sold on July 1, 2018. See Note 15 under "Southern Company Gas" for more information regarding Southern Company Gas' sale of Elizabethtown Gas.

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(a)	Retail electric revenues include $75 million of leases and a net increase of $60 million from certain cost recovery mechanisms that are not accounted for as revenue under ASC 606. See Note 2 for additional information on cost recovery mechanisms.

(b)	See Note 1 under "Revenues" for additional information on alternative revenue programs at the natural gas distribution utilities. Alternative revenue program revenues are presented net of any previously recognized program amounts billed to customers during the same accounting period.

(c)	Wholesale energy revenues include $299 million of revenues accounted for as derivatives, primarily related to short-term physical energy sales in the wholesale electricity market. See Note 1 under "Revenues – Southern Power" and Note 14 for additional information on energy-related derivative contracts.

(d)	Wholesale energy and wholesale capacity revenues include $384 million and $121 million, respectively, of PPA contracts accounted for as leases.

(e)

Other natural gas revenues related to Southern Company Gas' energy and risk management activities are presented net of the related costs of those activities and include gross third-party revenues of $7.0 billion of which $3.9 billion relates to contracts that are accounted for as derivatives. See Note 16 under "Southern Company Gas" for additional information on the components of wholesale gas services operating revenues.

(f)	Other revenues include $322 million of revenues not accounted for under ASC 606.

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(a)	Retail revenues at Alabama Power, Georgia Power, and Mississippi Power include a net increase or (net reduction) of $152 million, $(19) million, and $(13) million, respectively, related to certain cost recovery mechanisms that are not accounted for as revenue under ASC 606. See Note 2 for additional information on cost recovery mechanisms.

(b)	Retail revenues and other revenues at Georgia Power include $74 million and $135 million, respectively, of revenues accounted for as leases.

(c)	Wholesale energy revenues at Alabama Power, Georgia Power, and Mississippi Power include $20 million, $29 million, and $4 million, respectively, accounted for as derivatives primarily related to short-term physical energy sales in the wholesale electricity market. See Note 14 for additional information on energy-related derivative contracts.

(d)	Other revenues at Alabama Power and Georgia Power include $57 million and $109 million, respectively, of revenues not accounted for under ASC 606.

(a)	PPA capacity revenues and PPA energy revenues include $186 million and $413 million, respectively, related to PPAs accounted for as leases. See Note 1 under "Revenues – Southern Power" for additional information on capacity revenues accounted for as leases.

(b)	Non-PPA revenues include $242 million of revenues from short-term sales related to physical energy sales in the wholesale electricity market accounted for as derivatives. See Note 1 under "Revenues – Southern Power" and Note 14 for additional information on energy-related derivative contracts.

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(a)	See Note 1 under "Revenues – Southern Company Gas" for additional information on alternative revenue programs at the natural gas distribution utilities. Alternative revenue program revenues are presented net of any previously recognized program amounts billed to customers during the same accounting period.

(b)

Wholesale gas services revenues are presented net of the related costs associated with its energy trading and risk management activities. Operating revenues, as presented, include gross third-party revenues of $7.0 billion of which $3.9 billion relates to contracts that are accounted for as derivatives. See Note 16 under "Southern Company Gas" for additional information on the components of wholesale gas services operating revenues and Note 14 for additional information on energy-related derivative contracts.

(c)	Gas marketing services includes $3 million of revenues not accounted for under ASC 606.

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(*)	Excludes amounts related to held for sale assets. See Note 15 under "Southern Company's Sale of Gulf Power" for additional information.

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(*)	Represents Georgia Power's affiliate PPAs with Southern Power. See Note 1 under "Affiliate Transactions" and Note 9 under "Fuel and Power Purchase Agreements – Affiliate" for additional information.

(*)	Mississippi Power's decrease in 2017 is primarily the result of recording a loss on its lignite mine in June 2017.

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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.

(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 also entered into an agreement to lease its 50% undivided ownership in the Dalton Pipeline that became effective when it was placed in service in August 2017. Under the lease, Southern Company Gas will receive approximately $26 million annually for an initial term of 25 years. 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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(*)	Based on Georgia Power's ownership interests.

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(a)	For Southern Company and Mississippi Power, includes $40 million in pollution control revenue bonds classified as short term since they are variable rate demand obligations supported by short-term credit facilities; however, the final maturity dates range from 2020 to 2028.

(b)	Represents unamortized debt related amounts, acquisition accounting fair value adjustments, and/or fair value hedges. See Note 14 for additional information regarding fair value hedges.

(a)

For Southern Company and Mississippi Power, includes $50 million in revenue bonds classified as short term at December 31, 2017 that were remarketed in an index rate mode subsequent to December 31, 2017. Also for Southern Company and Mississippi Power, includes $40 million in pollution control revenue bonds classified as short term since they are variable rate demand obligations supported by short-term credit facilities; however, the final maturity dates range from 2020 to 2028.

(b)	Represents unamortized debt related amounts, acquisition accounting fair value adjustments, and fair value hedges. See Note 14 for additional information regarding fair value hedges.

(a)	Amounts include principal amortization related to the FFB borrowings beginning in 2020; however, the final maturity date is February 20, 2044. See "Long-term Debt – 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 $10.0 billion and $10.2 billion of senior notes at the Southern Company parent entity at December 31, 2018 and 2017, respectively.

(b)	Represents senior notes issued by Southern Company Gas Capital, which are fully and unconditionally guaranteed by Southern Company Gas. See "Structural Considerations" herein for additional information.

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(*)	Includes $3.3 billion of junior subordinated notes at the Southern Company parent entity at both December 31, 2018 and 2017.

•	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

•	$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

•	$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

•	$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

•	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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(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. These borrowings totaled $2.6 billion at both December 31, 2018 and 2017. See "Long-term Debt – DOE Loan Guarantee Borrowings" herein for additional information. Also includes capital lease obligations of $142 million and $154 million at December 31, 2018 and 2017, respectively. See "Long-term Debt – Capital Leases – Georgia Power" herein for additional information.

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

(c)	Nicor Gas' first mortgage bonds are secured by substantially all of Nicor Gas' properties. See "Long-term Debt – Other Long-Term Debt – Southern Company Gas" herein for additional information.

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(a)	Represents the Southern Company parent entity.

(b)	Southern Power's subsidiaries are not parties to its bank credit arrangement.

(c)

Southern Company Gas provides a parent guarantee of the obligations of its subsidiary Southern Company Gas Capital, which is the borrower of $1.4 billion ($1.395 billion unused) of this arrangement. Southern Company Gas' committed credit arrangement also includes $500 million (all unused) 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.

(d)	Amounts used are for letters of credit.

(e)	Excludes $280 million of committed credit arrangements of Gulf Power, which was sold on January 1, 2019. See Note 15 under "Southern Company's Sale of Gulf Power" for additional information.

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

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

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

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(a)	Executory costs such as taxes, maintenance, and insurance (including the estimated profit thereon) are estimated and included in total minimum lease payments.

(b)	Calculated using an adjusted incremental borrowing rate to reduce the present value of the net minimum lease payments to fair value.

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

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(*)	Represents effective income tax benefit rate for Mississippi Power due to a loss before income taxes in 2016.

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(*)	Represents other Southern Company subsidiaries. Alabama Power, Georgia Power, and Southern Company Gas did not have state NOL carryforwards at December 31, 2018.

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(*)	Only applicable to Nicor Gas union employees. The pension bands for the former Nicor Gas plan reflect the negotiated rates in accordance with the union agreements.

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(*)	Amounts for Southern Company exclude regulatory assets of $268 million associated with unamortized amounts in Southern Company Gas' pension plans prior to its acquisition by Southern Company on July 1, 2016.

(*)	Amounts for Southern Company exclude regulatory assets of $268 million associated with unamortized amounts in Southern Company Gas' pension plans prior to its acquisition by Southern Company on July 1, 2016.

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(*)	Amounts for Southern Company exclude regulatory assets of $268 million associated with unamortized amounts in Southern Company Gas' pension plans prior to its acquisition by Southern Company on July 1, 2016.

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(a)	Amounts for Southern Company exclude regulatory assets of $57 million associated with unamortized amounts in Southern Company Gas' other postretirement benefit plans prior to its acquisition by Southern Company on July 1, 2016.

(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 $57 million associated with unamortized amounts in Southern Company Gas' other postretirement benefit plans prior to its acquisition by Southern Company on July 1, 2016.

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(*)	Amounts for Southern Company exclude regulatory assets of $57 million associated with unamortized amounts in Southern Company Gas' other postretirement benefit plans prior to its acquisition by Southern Company on July 1, 2016.

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(*)	Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds.

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(a)	Target and actual allocations reflect the asset allocations for only the Southern Company system pension plan prior to its merger with the Southern Company Gas pension plan on January 1, 2018.

(b)	Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds.

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(*)	Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds.

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(*)	Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds.

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(a)	Target and actual allocations reflect the asset allocations for only the Southern Company other postretirement benefit plans prior to the merger of the plans with the Southern Company Gas other postretirement benefit plans on January 1, 2018.

(b)	Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds.

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(*)	Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds.

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•	Southern Company Gas' outstanding RSUs, restricted stock awards, and non-employee director stock awards were deemed fully vested and were canceled and converted into the right to receive an amount in cash equal to the product of (i) the total number of shares of Southern Company Gas' common stock subject to such award and (ii) the Merger consideration of $66 per share;

•

Southern Company Gas' outstanding stock options, all of which were fully vested, were canceled and converted into the right to receive an amount in cash equal to the product of (i) the total number of shares of Southern Company Gas' common stock subject to such options and (ii) the excess of the Merger consideration of $66 per share over the applicable exercise price per share of such options; and

•

each outstanding award of a Southern Company Gas PSU was converted into an award of Southern Company RSUs. The conversion ratio was the product of (i) the greater of (a) 125% of the number of units underlying such award based on target level achievement of all relevant performance goals and (b) the number of units underlying such award based on the actual level of achievement of all relevant performance goals against target and (ii) an exchange ratio based on the Merger consideration of $66 per share as compared to the volume-weighted average price per share of Southern Company common stock.

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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 $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)	Energy-related derivatives exclude $11 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 $193 million.

(c)	For additional detail, see the nuclear decommissioning trusts sections for Alabama Power and Georgia Power in this table.

(d)	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.

(e)	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)	Includes long-term debt of Gulf Power, which is classified as liabilities held for sale on Southern Company's balance sheet at December 31, 2018. See Note 15 under "Southern Company's Sale of Gulf Power" 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.

(*)

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 4,159 million mmBtu and short natural gas positions of 4,039 million mmBtu at December 31, 2018, which is also included in Southern Company's total volume.

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(*)	Represents the Southern Company parent entity.

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(a)	Gross amounts offset include cash collateral held on deposit in broker margin accounts of $277 million and $193 million at December 31, 2018 and 2017, respectively.

(b)	Net amounts of derivative instruments outstanding exclude premium and intrinsic value associated with weather derivatives of $8 million and $11 million at December 31, 2018 and 2017, respectively.

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(*)	Fair value gains and losses recorded in regulatory assets and liabilities include cash collateral held on deposit in broker margin accounts of $6 million at December 31, 2017.

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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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(*)	Amounts reflect gains or losses on cash flow hedges that were reclassified from AOCI into earnings.

(*)	Excludes the impact of weather derivatives recorded in natural gas revenues of $5 million, $23 million, and $6 million for the years ended December 31, 2018, 2017, and 2016, respectively, as they are accounted for based on intrinsic value rather than fair value.

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Excludes the impact of weather derivatives recorded in natural gas revenues of $5 million and $23 million for the successor years ended December 31, 2018 and 2017, respectively, $6 million for the successor period of July 1, 2016 through December 31, 2016, and $3 million for the predecessor period of January 1, 2016 through June 30, 2016, as they are accounted for based on intrinsic value rather than fair value.

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

(*)	On July 31, 2017, Southern Power purchased 100% of the Cactus Flats facility. In August 2018, Southern Power closed on a tax equity partnership and owns 100% of the class B membership interests.

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(a)	In July 2017, Southern Power purchased 100% of the Cactus Flats facility. In August 2018, Southern Power closed on a tax equity partnership and now owns 100% of the class B membership interests.

(b)	In November 2018, Southern Power entered into an agreement to sell all of its equity interests in Plant Mankato, including this expansion currently under construction. See "Sales of Natural Gas Plants" below.

(c)	In May 2018, Southern Power purchased 100% of the Wild Horse Mountain facility. 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 August 2018, Southern Power purchased 100% of the membership interests of the Reading facility from the joint development arrangement with Renewable Energy Systems Americas, Inc. described below. 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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(*)	Earnings before income taxes for the Florida Plants in 2018 represents the period from January 1, 2018 to December 4, 2018 (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 $1.1 billion ($722 million after tax) in 2018, $3.4 billion ($2.4 billion after tax) in 2017, and $428 million ($264 million after tax) in 2016. 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 pre-tax impairment charges of $156 million ($117 million after tax) in 2018. See Note 15 under "Southern Power – Development Projects" and " – Sales of Natural Gas Plants" for additional information.

(d)	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.

(e)	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.

(f)	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, $399 million, and $168 million for the successor years ended December 31, 2018 and 2017 and the successor period of July 1, 2016 through December 31, 2016, respectively, and $215 million for the predecessor period ended June 30, 2016. 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) for the year ended December 31, 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 for the year ended December 31, 2018 recorded in contemplation of the sale of Pivotal Home Solutions. See Note 15 under "Southern Company Gas" for additional information.

(d)	Operating revenues for the gas marketing services disposition were $55 million, $129 million, and $56 million for the successor years ended December 31, 2018 and 2017 and the successor period of July 1, 2016 through December 31, 2016, respectively, and $64 million for the predecessor period ended June 30, 2016 See Note 15 under "Southern Company Gas" for additional information.

(e)	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)	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 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 pre-tax and $(76) million after tax, $353 million pre-tax and $40 million after tax, and $(27) million pre-tax and $(15) million after tax, respectively. See Note 15 under "Southern Company Gas" for additional information.

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(a)

As a result of revisions to the cost estimate for the Kemper IGCC and the project's June 2017 suspension, Mississippi Power recorded total pre-tax charges to income related to the Kemper IGCC of $108 million ($67 million after tax) in the first quarter 2017, $3.0 billion ($2.1 billion after tax) in the second quarter 2017, $34 million ($21 million after tax) in the third quarter 2017, and $208 million ($185 million after tax) in the fourth quarter 2017. See Note 2 under "Mississippi Power – Kemper County Energy Facility" for additional information.

(b)

As a result of the Tax Reform Legislation, the Southern Company system recorded a total income tax benefit of $264 million in the fourth quarter 2017, comprised primarily of income tax expense of $372 million recorded at Mississippi Power, income tax benefit of $743 million recorded at Southern Power, and income tax expense of $93 million recorded at Southern Company Gas. See Note 10 for additional information.

(c)	Gulf Power recorded a pre-tax charge of $33 million ($20 million after tax) for the write-down of its ownership in Plant Scherer Unit 3 in the first quarter 2017. See Note 2 under "Southern Company – Gulf Power" 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

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Item 9B.	OTHER INFORMATION

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(1)	Includes services performed in connection with financing transactions.

(2)	Represents non-statutory audit services in 2018 and 2017.

(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 2018 and a review report on internal controls in 2018 and 2017.

(7)	Includes subscription fees for Deloitte & Touche LLP's technical accounting research tool in 2017.

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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:

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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's Sale of Gulf Power" 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, as a result of lower 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. This valuation allowance 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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(*)	Deductions represent write-offs of accounts considered to be uncollectible, less recoveries of amounts previously written off.

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