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•	the impact of recent and future federal and state regulatory changes, including environmental laws regulating emissions, discharges, and disposal to air, water, and land, and also changes in tax and other laws and regulations to which Southern Company and its subsidiaries are subject, including potential tax reform legislation, as well as changes in application of existing laws and regulations;

•	current and future litigation, regulatory investigations, proceedings, or inquiries;

•	the effects, extent, and timing of the entry of additional competition in the markets in which Southern Company's subsidiaries operate;

•

variations in demand for electricity and natural gas, including those relating to weather, the general economy and recovery from the last recession, population and business growth (and declines), the effects of energy conservation and efficiency measures, including from the development and deployment of alternative energy sources such as self-generation and distributed generation technologies, and any potential economic impacts resulting from federal fiscal decisions;

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

•	limits on pipeline capacity;

•	effects of inflation;

•

the ability to control costs and avoid cost overruns during the development, construction, and operation of facilities, which include the development and construction of generating facilities with designs that have not been finalized or previously constructed, including changes in labor costs and productivity, adverse weather conditions, shortages and inconsistent quality of equipment, materials, and labor, sustaining nitrogen supply, contractor or supplier delay, non-performance under construction, operating, or other agreements, operational readiness, including specialized operator training and required site safety programs, unforeseen engineering or design problems, start-up activities (including major equipment failure and system integration), and/or operational performance (including additional costs to satisfy any operational parameters ultimately adopted by any PSC);

•	the ability to construct facilities in accordance with the requirements of permits and licenses, to satisfy any environmental performance standards and the requirements of tax credits and other incentives, and to integrate facilities into the Southern Company system upon completion of construction;

•	investment performance of the Southern Company system's employee and retiree benefit plans and nuclear decommissioning trust funds;

•	advances in technology;

•	ongoing renewable energy partnerships and development agreements;

•	state and federal rate regulations and the impact of pending and future rate cases and negotiations, including rate actions relating to fuel and other cost recovery mechanisms;

•	legal proceedings and regulatory approvals and actions related to Plant Vogtle Units 3 and 4, including Georgia PSC approvals and NRC actions;

•	actions related to cost recovery for the Kemper IGCC, including the ultimate impact of the 2015 decision of the Mississippi Supreme Court, the Mississippi PSC's December 2015 rate order, and related legal or regulatory proceedings, Mississippi

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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;

•	the inherent risks involved in operating and constructing nuclear generating facilities, including environmental, health, regulatory, natural disaster, terrorism, and financial risks;

•	the inherent risks involved in transporting and storing natural gas;

•	the performance of projects undertaken by the non-utility businesses and the success of efforts to invest in and develop new opportunities;

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

•	potential business strategies, including acquisitions or dispositions of assets or businesses, which cannot be assured to be completed or beneficial to Southern Company or its subsidiaries;

•

the possibility that the anticipated benefits from the Merger cannot be fully realized or may take longer to realize than expected, the possibility that costs related to the integration of Southern Company and Southern Company Gas will be greater than expected, the ability to retain and hire key personnel and maintain relationships with customers, suppliers, or other business partners, and the diversion of management time on integration-related issues;

•	the ability of counterparties of Southern Company and its subsidiaries to make payments as and when due and to perform as required;

•	the ability to obtain new short- and long-term contracts with wholesale customers;

•	the direct or indirect effect on the Southern Company system's business resulting from cyber intrusion or terrorist incidents and the threat of terrorist incidents;

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

•	changes in Southern Company's and any of its subsidiaries' credit ratings, including impacts on interest rates, access to capital markets, and collateral requirements;

•	the impacts of any sovereign financial issues, including impacts on interest rates, access to capital markets, impacts on foreign currency exchange rates, counterparty performance, and the economy in general, as well as potential impacts on the benefits of the DOE loan guarantees;

•	the ability of Southern Company's electric utilities to obtain additional generating capacity (or sell excess generating capacity) at competitive prices;

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

•	the direct or indirect effects on the Southern Company system's business resulting from incidents affecting the U.S. electric grid, natural gas pipeline infrastructure, or operation of generating or storage resources;

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

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

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Item 1.	BUSINESS

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(1)	Alabama Municipal Electric Authority will also be served by Plant Franklin Unit 1 from January 2018 through December 2019.

(2)	Subject to commercial operation of the expansion project.

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

(4)	Century Aluminum PPA is partially served by Plant Franklin Unit 3.

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

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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.

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•	operator error or failure of equipment or processes;

•	accidents or explosions;

•	operating limitations that may be imposed by environmental or other regulatory requirements;

•	labor disputes;

•	terrorist attacks (physical and/or cyber);

•	fuel or material supply interruptions;

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

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

•	implementation of new technologies;

•	information technology system failure;

•	cyber intrusion;

•	an environmental event, such as a spill or release; and

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

•	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;

•	the threat of a possible terrorist attack, including a potential cyber security attack; and

•	the potential impact of an accident or natural disaster.

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•	shortages and inconsistent quality of equipment, materials, and labor;

•	changes in labor costs and productivity;

•	work stoppages;

•	contractor or supplier delay or non-performance under construction, operating, or other agreements or non-performance by other major participants in construction projects;

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

•	delays associated with start-up activities, including major equipment failure and system integration, and/or operational performance (including additional costs to satisfy any operational parameters ultimately adopted by any PSC or other applicable state regulatory agency);

•	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 legal challenges to projects, including legal challenges to regulatory approvals;

•	failure to construct in accordance with permitting and licensing requirements;

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

•	continued public and policymaker support for such projects;

•	adverse weather conditions or natural disasters;

•	other unforeseen 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

•	unanticipated cost increases, including materials and labor, and increased financing costs as a result of changes in market interest rates or as a result of construction schedule delays.

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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;

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•	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, acts of terrorism, 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 an adequate 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 the acquiring company may not appropriately evaluate the likelihood or quantify the exposure from identified risks;

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

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

•	for the traditional electric operating companies, costs associated with such investments that were expected to be recovered through 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;

•	volatility in market prices for electricity and natural gas;

•	terrorist attacks or threatened 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

Item 7A.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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Item 8.	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

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Item 9.	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

Item 9A.	CONTROLS AND PROCEDURES

Item 9B.	OTHER INFORMATION

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(*)

In the first quarter 2015, Mississippi Power updated the methodology to estimate the unbilled revenue allocation among customer classes. This change did not have a significant impact on net income. The KWH sales variances in the above table reflect an adjustment to the estimated allocation of Mississippi Power's unbilled 2014 and first quarter 2015 KWH sales among customer classes that is consistent with the actual allocation in 2015 and 2016, respectively. Without this adjustment, 2016 weather-adjusted commercial sales decreased 0.9% and industrial KWH sales decreased 2.1% as compared to 2015. Without this adjustment, 2015 weather-adjusted commercial sales increased 0.8% and industrial KWH sales decreased 0.4% as compared to 2014.

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(*)	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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•	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)

Excludes credit agreements (Project Credit Facilities) assumed with the acquisition of certain solar facilities, which were non-recourse to Southern Power Company, the proceeds of which were used to finance project costs related to such solar facilities. See Note 12 to the financial statements under "Southern Power" for additional information. Also excludes a $120 million continuing letter of credit facility entered into by Southern Power in December 2016 for standby letters of credit expiring in 2019. At December 31, 2016, the total amount available under the letter of credit facility was $82 million.

(c)	Southern Company Gas, as the parent entity, guarantees the obligations of Southern Company Gas Capital, which is the borrower of $1.3 billion of these arrangements. Southern Company Gas' committed credit arrangements also include $700 million for which Nicor Gas is the borrower and which is restricted for working capital needs of Nicor Gas.

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(*)	Average and maximum amounts are based upon daily balances during the twelve-month periods ended December 31, 2016, 2015, and 2014.

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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)	Reflects only long-term debt financing activities occurring subsequent to completion of the Merger. The senior notes were issued by Southern Company Gas Capital and guaranteed by Southern Company Gas, as the parent entity.

(d)	Includes intercompany loans from Southern Company to Mississippi Power and PowerSecure, as well as reductions in affiliate capital lease obligations at Georgia Power. These transactions are eliminated in Southern Company's Consolidated Financial Statements.

•	$0.5 billion of 1.55% Senior Notes due July 1, 2018;

•	$1.0 billion of 1.85% Senior Notes due July 1, 2019;

•	$1.5 billion of 2.35% Senior Notes due July 1, 2021;

•	$1.25 billion of 2.95% Senior Notes due July 1, 2023;

•	$1.75 billion of 3.25% Senior Notes due July 1, 2026;

•	$0.5 billion of 4.25% Senior Notes due July 1, 2036; and

•	$2.0 billion of 4.40% Senior Notes due July 1, 2046.

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(*)	Any additional credit rating downgrades at or below BB- and/or Ba3 could increase collateral requirements up to an additional $91 million.

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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. As it relates to the FFB borrowings, the final maturity date is February 20, 2044; however, principal amortization is reflected beginning in 2020. See Note 6 to the financial statements under "DOE Loan Guarantee Borrowings" for additional information. Southern Company and its subsidiaries plan to continue, when economically feasible, to retire higher-cost securities and replace these obligations with lower-cost capital if market conditions permit. Variable rate interest obligations are estimated based on rates as of January 1, 2017, as reflected in the statements of capitalization. Fixed rates include, where applicable, the effects of interest rate derivatives employed to manage interest rate risk. Long-term debt principal for 2017 includes $40 million of pollution control revenue bonds that are classified on the balance sheet at December 31, 2016 as short-term since they are variable rate demand obligations that are supported by short-term credit facilities; however, the final maturity date is in 2028. Long-term debt excludes capital lease amounts (shown separately).

(b)	Represents preferred and preference stock of subsidiaries. Preferred and preference stock do not mature; therefore, amounts are provided for the next five years only.

(c)	Includes derivative liabilities related to cash flow hedges of forecasted debt, as well as energy-related derivatives. For additional information, see Notes 1 and 11 to the financial statements.

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

(e)	See Note 5 to the financial statements under "Unrecognized Tax Benefits" for additional information.

(f)

Includes charges recoverable through a natural gas cost recovery mechanism, or alternatively billed to marketers selling retail natural gas, and demand charges associated with Southern Company Gas' wholesale gas services. The gas supply balance includes amounts for gas commodity purchase commitments associated with Southern Company Gas' gas marketing services of 33 million mmBtu at floating gas prices calculated using forward natural gas prices at December 31, 2016 and valued at $106 million. Southern Company Gas provides guarantees to certain gas suppliers for certain of its subsidiaries in support of payment obligations.

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

(h)	Guarantees are provided to certain municipalities and other agencies and certain natural gas suppliers in support of payment obligations.

(i)

The Southern Company system provides estimated capital expenditures for a five-year period, including capital expenditures associated with environmental regulations. These amounts exclude contractual purchase commitments for nuclear fuel and capital expenditures covered under long-term service agreements which are reflected in "Fuel" and "Other," respectively. At December 31, 2016, significant purchase commitments were outstanding in connection with the construction program. See FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Statutes and Regulations" herein for additional information.

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(j)

Primarily includes commitments to purchase coal, nuclear fuel, and natural gas, as well as the related transportation and storage. In most cases, these contracts contain provisions for price escalation, minimum purchase levels, and other financial commitments. Natural gas purchase commitments are based on various indices at the time of delivery. Amounts reflected for natural gas purchase commitments have been estimated based on the New York Mercantile Exchange future prices at December 31, 2016.

(k)

Estimated minimum long-term obligations for various PPA purchases from gas-fired, biomass, and wind-powered facilities. Includes a total of $292 million of biomass PPAs that is contingent upon the counterparties meeting specified contract dates for commercial operation. Subsequent to December 31, 2016, the specified contract dates for commercial operation were extended from 2017 to 2019 and may change further as a result of regulatory action. See FUTURE EARNINGS POTENTIAL – "Regulatory Matters – Renewables" herein for additional information.

(l)	Includes long-term service agreements, contracts for the procurement of limestone, contractual environmental remediation liabilities, and operation and maintenance agreements. Long-term service agreements include price escalation based on inflation indices.

(m)

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

(n)

The Southern Company system forecasts contributions to the pension and other postretirement benefit plans over a three-year period. Southern Company anticipates no mandatory contributions to the qualified pension plans during the next three years. Amounts presented represent estimated benefit payments for the nonqualified pension plans, estimated non-trust benefit payments for the other postretirement benefit plans, and estimated contributions to the other postretirement benefit plan trusts, all of which will be made from corporate assets of Southern Company's subsidiaries. See Note 2 to the financial statements for additional information related to the pension and other postretirement benefit plans, including estimated benefit payments. Certain benefit payments will be made through the related benefit plans. Other benefit payments will be made from corporate assets of Southern Company's subsidiaries.

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•	the impact of recent and future federal and state regulatory changes, including environmental laws regulating emissions, discharges, and disposal to air, water, and land, and also changes in tax and other laws and regulations to which Southern Company and its subsidiaries are subject, including potential tax reform legislation, as well as changes in application of existing laws and regulations;

•	current and future litigation, regulatory investigations, proceedings, or inquiries;

•	the effects, extent, and timing of the entry of additional competition in the markets in which Southern Company's subsidiaries operate;

•

variations in demand for electricity and natural gas, including those relating to weather, the general economy and recovery from the last recession, population and business growth (and declines), the effects of energy conservation and efficiency measures, including from the development and deployment of alternative energy sources such as self-generation and distributed generation technologies, and any potential economic impacts resulting from federal fiscal decisions;

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

•	limits on pipeline capacity;

•	effects of inflation;

•

the ability to control costs and avoid cost overruns during the development, construction, and operation of facilities, which include the development and construction of generating facilities with designs that have not been finalized or previously constructed, including changes in labor costs and productivity, adverse weather conditions, shortages and inconsistent quality of equipment, materials, and labor, sustaining nitrogen supply, contractor or supplier delay, non-performance under construction, operating, or other agreements, operational readiness, including specialized operator training and required site safety programs, unforeseen engineering or design problems, start-up activities (including major equipment failure and system integration), and/or operational performance (including additional costs to satisfy any operational parameters ultimately adopted by any PSC);

•	the ability to construct facilities in accordance with the requirements of permits and licenses, to satisfy any environmental performance standards and the requirements of tax credits and other incentives, and to integrate facilities into the Southern Company system upon completion of construction;

•	investment performance of the Southern Company system's employee and retiree benefit plans and nuclear decommissioning trust funds;

•	advances in technology;

•	ongoing renewable energy partnerships and development agreements;

•	state and federal rate regulations and the impact of pending and future rate cases and negotiations, including rate actions relating to fuel and other cost recovery mechanisms;

•	legal proceedings and regulatory approvals and actions related to Plant Vogtle Units 3 and 4, including Georgia PSC approvals and NRC actions;

•

actions related to cost recovery for the Kemper IGCC, including the ultimate impact of the 2015 decision of the Mississippi Supreme Court, the Mississippi PSC's December 2015 rate order, and related legal or regulatory proceedings, Mississippi PSC review of the prudence of Kemper IGCC costs and approval of further permanent rate recovery plans, actions relating to proposed securitization, satisfaction of requirements to utilize grants, and the ultimate impact of the termination of the proposed sale of an interest in the Kemper IGCC to SMEPA;

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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;

•	the inherent risks involved in operating and constructing nuclear generating facilities, including environmental, health, regulatory, natural disaster, terrorism, and financial risks;

•	the inherent risks involved in transporting and storing natural gas;

•	the performance of projects undertaken by the non-utility businesses and the success of efforts to invest in and develop new opportunities;

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

•	potential business strategies, including acquisitions or dispositions of assets or businesses, which cannot be assured to be completed or beneficial to Southern Company or its subsidiaries;

•

the possibility that the anticipated benefits from the Merger cannot be fully realized or may take longer to realize than expected, the possibility that costs related to the integration of Southern Company and Southern Company Gas will be greater than expected, the ability to retain and hire key personnel and maintain relationships with customers, suppliers, or other business partners, and the diversion of management time on integration-related issues;

•	the ability of counterparties of Southern Company and its subsidiaries to make payments as and when due and to perform as required;

•	the ability to obtain new short- and long-term contracts with wholesale customers;

•	the direct or indirect effect on the Southern Company system's business resulting from cyber intrusion or terrorist incidents and the threat of terrorist incidents;

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

•	changes in Southern Company's and any of its subsidiaries' credit ratings, including impacts on interest rates, access to capital markets, and collateral requirements;

•	the impacts of any sovereign financial issues, including impacts on interest rates, access to capital markets, impacts on foreign currency exchange rates, counterparty performance, and the economy in general, as well as potential impacts on the benefits of the DOE loan guarantees;

•	the ability of Southern Company's electric utilities to obtain additional generating capacity (or sell excess generating capacity) at competitive prices;

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

•	the direct or indirect effects on the Southern Company system's business resulting from incidents affecting the U.S. electric grid, natural gas pipeline infrastructure, or operation of generating or storage resources;

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

•	other factors discussed elsewhere herein and in other reports (including the Form 10-K) filed by Southern Company from time to time with the SEC.

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(a)	Recovered and amortized over the average remaining service period which may range up to 15 years. See Note 2 for additional information.

(b)	Asset retirement and other cost of removal obligations are recorded, deferred income tax assets are recovered, and deferred income tax liabilities are amortized over the related property lives, which may range up to 70 years. Asset retirement and removal liabilities will be settled and trued up following completion of the related activities.

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

(d)	Recorded over the life of the underlying hedged purchase contracts, which generally do not exceed five years. Upon final settlement, actual costs incurred are recovered through fuel and energy cost recovery mechanisms.

(e)	Recovered over the life of the PPA for periods up to seven years.

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

(g)	Recorded and recovered or amortized as approved or accepted by the appropriate state PSCs or other applicable regulatory agencies over periods generally not exceeding ten years.

(h)	Includes $97 million of regulatory assets currently in rates to be recovered over periods of two, seven, or 10 years. For additional information, see Note 3 under "Integrated Coal Gasification Combined Cycle – Rate Recovery of Kemper IGCC Costs – Regulatory Assets and Liabilities."

(i)	Previous under-recovery as of December 2013 is recorded and recovered or amortized as approved by the Georgia PSC through 2019. Amortization of $185 million related to the under-recovery from January 2014 through December 2016 will be determined by the Georgia PSC in the 2019 base rate case. See Note 3 for additional information.

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

(k)	Comprised of numerous immaterial components including deferred income tax charges - Medicare subsidy, cancelled construction projects, building and generating plant leases, property tax, and other miscellaneous assets. These costs are recorded and recovered or amortized as approved by the appropriate state PSCs over periods generally not exceeding 50 years.

(l)	Recovered as storm restoration and potential reliability-related expenses are incurred as approved by the appropriate state PSCs.

(m)	Comprised of numerous immaterial components including retiree benefit plans, fuel-hedging gains, and other liabilities that are recorded and recovered or amortized as approved by the appropriate state PSCs or other applicable regulatory agencies generally over periods not exceeding 4 years.

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

(o)	Amortized as approved by the appropriate state PSCs over periods generally up to 11 years.

(p)	Recorded in relation to the Merger. Recovered over the remaining life of the original debt issuances, which range up to 22 years. For additional information see Note 12 under "Southern Company – Merger with Southern Company Gas."

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(*)	Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well-diversified with no significant concentrations of risk.

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(a)	Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well-diversified with no significant concentrations of risk.

(b)	The 2015 presentation above has been revised to separately reflect special situations, consistent with the 2016 presentation.

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(*)	Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well-diversified with no significant concentrations of risk.

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(*)	Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well-diversified with no significant concentrations of risk.

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(a)	Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well-diversified with no significant concentrations of risk.

(b)	The 2015 presentation above has been revised to separately reflect special situations, consistent with the 2016 presentation.

(*)	Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well-diversified with no significant concentrations of risk.

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(a)	The 2010 Project Estimate is the certificated cost estimate adjusted to include the certificated estimate for the CO2 pipeline facilities approved in 2011 by the Mississippi PSC, as well as the lignite mine and equipment, AFUDC, and general exceptions.

(b)	Amounts in the Current Cost Estimate include certain estimated post-in-service costs which are expected to be subject to the cost cap.

(c)

The 2012 MPSC CPCN Order approved a construction cost cap of up to $2.88 billion, net of the Initial DOE Grants and excluding the cost of the lignite mine and equipment, the cost of the CO2 pipeline facilities, AFUDC, and certain general exceptions, including change of law, force majeure, and beneficial capital (which exists when Mississippi Power demonstrates that the purpose and effect of the construction cost increase is to produce efficiencies that will result in a neutral or favorable effect on customers relative to the original proposal for the CPCN) (Cost Cap Exceptions). The Current Cost Estimate and the Actual Costs include non-incremental operating and maintenance costs related to the combined cycle and associated common facilities placed in service in August 2014 that are subject to the $2.88 billion cost cap and exclude post-in-service costs for the lignite mine. See "Rate Recovery of Kemper IGCC Costs – 2013 MPSC Rate Order" herein for additional information.

(d)

Mississippi Power's 2010 Project Estimate included recovery of financing costs during construction rather than the accrual of AFUDC. This approach was not approved by the Mississippi PSC as described in "Rate Recovery of Kemper IGCC Costs – 2013 MPSC Rate Order." The Current Cost Estimate also reflects the impact of a settlement agreement with the wholesale customers for cost-based rates under FERC's jurisdiction.

(e)

Non-capital Kemper IGCC-related costs incurred during construction were initially deferred as regulatory assets. Some of these costs are now included in rates and are being recognized through income; however, such costs continue to be included in the Current Cost Estimate and the Actual Costs at December 31, 2016. The wholesale portion of debt carrying costs, whether deferred or recognized through income, is not included in the Current Cost Estimate and the Actual Costs at December 31, 2016. See "Rate Recovery of Kemper IGCC Costs – Regulatory Assets and Liabilities" herein for additional information.

(f)	On April 8, 2016, Mississippi Power received approximately $137 million in additional grants from the DOE for the Kemper IGCC (Additional DOE Grants), which are expected to be used to reduce future rate impacts for customers.

(g)

The Current Cost Estimate and the Actual Costs include $2.76 billion that will not be recovered for costs above the cost cap, $0.83 billion of investment costs included in current rates for the combined cycle and related assets in service, and $0.08 billion of costs that were previously expensed for the combined cycle and related assets in service. The Current Cost Estimate and the Actual Costs exclude $0.25 billion of costs not included in current rates for post-June 2013 mine operations, the lignite fuel inventory, and the nitrogen plant capital lease, which will be included in the 2017 Rate Case to be filed by June 3, 2017. See Note 6 under "Capital Leases" and "Rate Recovery of Kemper IGCC Costs – 2017 Rate Case" herein for additional information.

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(*)	Includes $40 million of pollution control revenue bonds classified as short-term since they are variable rate demand obligations that are supported by short-term credit facilities; however, the final maturity date is in 2028.

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(a)	Represents the Southern Company parent entity.

(b)

Excludes credit agreements (Project Credit Facilities) assumed with the acquisition of certain solar facilities, which were non-recourse to Southern Power Company, the proceeds of which were used to finance project costs related to such solar facilities. See Note 12 under "Southern Power" for additional information. Also excludes a $120 million continuing letter of credit facility entered into by Southern Power in December 2016 for standby letters of credit expiring in 2019. At December 31, 2016, the total amount available under the letter of credit facility was $82 million.

(c)	Southern Company Gas, as the parent entity, guarantees the obligations of Southern Company Gas Capital, which is the borrower of $1.3 billion of these arrangements. Southern Company Gas' committed credit arrangements also include $700 million for which Nicor Gas is the borrower and which is restricted for working capital needs of Nicor Gas.

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(*)	A total of $197 million of biomass PPAs included under operating leases is contingent upon the counterparties meeting specified contract dates for commercial operation. Subsequent to December 31, 2016, the specified contract dates for commercial operation were extended from 2017 to 2019 and may change further as a result of regulatory action.

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(*)	Beginning in 2015, cash dividends paid on Southern Company's common stock are accumulated and payable in additional shares of Southern Company's common stock at the end of the three-year performance period and are embedded in the grant date fair value which equates to the grant date stock price.

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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 the Company of what a market participant would use in pricing an asset or liability. If there is little available market data, then the Company's own assumptions are the best available information.

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(a)	Energy-related derivatives exclude $4 million associated with certain weather derivatives accounted for based on intrinsic value rather than fair value.

(b)	Energy-related derivatives exclude cash collateral of $62 million.

(c)	Includes the investment securities pledged to creditors and collateral received, and excludes receivables related to investment income, pending investment sales, and payables related to pending investment purchases and the lending pool. See Note 1 under "Nuclear Decommissioning" for additional information.

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(*)	Includes the investment securities pledged to creditors and collateral received, and excludes receivables related to investment income, pending investment sales, and payables related to pending investment purchases and the lending pool. See Note 1 under "Nuclear Decommissioning" for additional information.

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•

Regulatory Hedges – Energy-related derivative contracts which are designated as regulatory hedges relate primarily to the traditional electric operating companies' and natural gas distribution utilities' fuel-hedging programs, where gains and losses are initially recorded as regulatory liabilities and assets, respectively, and then are included in fuel expense as the underlying fuel is used in operations and ultimately recovered through the respective fuel cost recovery clauses.

•	Cash Flow Hedges – Gains and losses on energy-related derivatives designated as cash flow hedges (which are mainly used to hedge anticipated purchases and sales) are initially deferred in OCI before being recognized in the statements of income in the same period as the hedged transactions are reflected in earnings.

•	Not Designated – Gains and losses on energy-related derivative contracts that are not designated or fail to qualify as hedges are recognized in the statements of income as incurred.

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(a)	Swaption at RE Roserock LLC. See Note 12 for additional information.

(b)	Amortizing notional amount.

(c)	Represents the mandatory settlement date. Settlement amount was based on a 15-year amortizing swap.

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(a)	Gross amounts offset include cash collateral held on deposit in broker margin accounts of $62 million as of December 31, 2016.

(b)	At December 31, 2015, the fair value amounts for derivative contracts subject to netting arrangements were presented gross on the balance sheet.

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(a)	At December 31, 2016, the unrealized gains and losses for derivative contracts subject to netting arrangements were presented net on the balance sheet. At December 31, 2015, the unrealized gains and losses for derivative contracts were presented gross on the balance sheet.

(b)	Fair value gains and losses recorded in regulatory assets and liabilities include cash collateral held on deposit in broker margin accounts of $8 million as of December 31, 2016.

(*)	The reclassification from accumulated OCI into other income (expense), net completely offsets currency gains and losses arising from changes in the U.S. currency exchange rates used to record the euro-denominated notes.

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(*)	Excludes gains (losses) recorded in cost of natural gas associated with weather derivatives of $6 million for the period ended December 31, 2016.

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(a)	Southern Power owns 100% of the class A membership interests and a wholly-owned subsidiary of the seller owns 100% of the class B membership interests. Southern Power and the class B member are entitled to 51% and 49%, respectively, of all cash distributions from the project. In addition, Southern Power is entitled to substantially all of the federal tax benefits with respect to the transaction.

(b)	Southern Power owns 90%, with the minority owner, Turner Renewable Energy, LLC (TRE), owning 10%.

(c)	In addition to the 20-year and 12-year PPAs, the facility has a 10-year contract with Allianz Risk Transfer (Bermuda) Ltd.

(d)	Under the terms of the remaining 10-year PPA and the 20-year expansion PPA, approximately $408 million of assets, primarily related to property, plant, and equipment, are subject to lien at December 31, 2016.

(e)	The acquisition included a fully operational 375-MW natural gas-fired combined-cycle facility.

(f)	Southern Power owns 90.1%, with the minority owner, Invenergy Wind Global LLC, owning 9.9%.

(a)	Intangible assets consist of acquired PPAs that will be amortized over 10 and 20-year terms. The estimated amortization for future periods is approximately $9 million per year.

(b)	At December 31, 2016, $461 million is included in acquisitions payable on the balance sheets.

(c)	Includes approximately $281 million of contingent consideration, of which $67 million remains payable at December 31, 2016.

(d)	Includes approximately $51 million of non-cash contributions recorded as capital contributions from noncontrolling interests in the statements of stockholders' equity.

(e)	Includes approximately $142 million of contingent consideration, all of which had been paid at December 31, 2016 by the noncontrolling interests.

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(a)	The facility has a total of 299 MWs, of which 110 MWs were placed in service in the fourth quarter 2015 and the remainder by July 2016.

(b)	Southern Power owns 100% of the class A membership interests and a wholly-owned subsidiary of the seller owns 100% of the class B membership interests. Southern Power and the class B member are entitled to 51% and 49%, respectively, of all cash distributions from the project. In addition, Southern Power is entitled to substantially all of the federal tax benefits with respect to the transaction.

(c)	Southern Power owns 90%, with the minority owner, TRE, owning 10%.

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(a)	Intangible assets consist of acquired PPAs that will be amortized over 20-year terms. The estimated amortization for future periods is approximately $14 million per year.

(b)	Includes approximately $195 million of contingent consideration, all of which has been paid at December 31, 2016.

(c)	Includes approximately $227 million of non-cash contributions recorded as capital contributions from noncontrolling interests in the statements of stockholders' equity.

(d)	Includes approximately $76 million of contingent consideration, all of which had been paid at December 31, 2016 by the noncontrolling interests.

(a)	Affiliate PPA approved by the FERC.

(b)	The facility has a total of 299 MWs, of which 110 MWs were placed in service in the fourth quarter 2015 and the remainder by July 2016.

(c)	Prior to placing the Roserock facility in service, certain solar panels were damaged. While the facility is currently generating energy as expected, Southern Power is pursuing remedies under its insurance policies and other contracts to repair or replace these solar panels.

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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 probable losses on the Kemper IGCC of $428 million ($264 million after tax) in 2016, $365 million ($226 million after tax) in 2015, and $868 million ($536 million after tax) in 2014. See Note 3 under "Integrated Coal Gasification Combined Cycle – Kemper IGCC Schedule and Cost Estimate" for additional information.

(c)	Net of $202 million of unamortized debt issuance costs as of December 31, 2014. Also net of $488 million of deferred tax assets as of December 31, 2014.

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(*)	Average and maximum amounts are based upon daily balances during the twelve-month periods ended December 31, 2016, 2015, and 2014.

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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. The Company 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 as of January 1, 2017, as reflected in the statements of capitalization. Fixed rates include, where applicable, the effects of interest rate derivatives employed to manage interest rate risk.

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

(c)	Includes derivative liabilities related to cash flow hedges of forecasted debt, as well as energy-related derivatives. For additional information, see Notes 1 and 11 to the financial statements.

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

(e)

The Company provides estimated capital expenditures for a five-year period, including capital expenditures associated with environmental regulations. These amounts exclude contractual purchase commitments for nuclear fuel and capital expenditures covered under long-term service agreements which are reflected in "Fuel" and "Other," respectively. At December 31, 2016, purchase commitments were outstanding in connection with the construction program. See FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Statutes 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 New York Mercantile Exchange future prices at December 31, 2016.

(g)	Estimated minimum long-term obligations for various long-term commitments for the purchase of capacity and energy. Amounts are related to the Company's certificated PPAs which include MWs purchased from gas-fired and wind-powered facilities.

(h)	Includes long-term service agreements and contracts for the procurement of limestone. Long-term service agreements include price escalation based on inflation indices.

(i)

The Company forecasts contributions to the pension and other postretirement benefit plans over a three-year period. The Company 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 the Company's corporate assets. See Note 2 to the financial statements for additional information related to the pension and other postretirement benefit plans, including estimated benefit payments. Certain benefit payments will be made through the related benefit plans. Other benefit payments will be made from the Company's corporate assets.

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•	the impact of recent and future federal and state regulatory changes, including environmental laws regulating emissions, discharges, and disposal to air, water, and land, and also changes in tax and other laws and regulations to which the Company is subject, including potential tax reform legislation, as well as changes in application of existing laws and regulations;

•	current and future litigation, regulatory investigations, proceedings, or inquiries;

•	the effects, extent, and timing of the entry of additional competition in the markets in which the Company operates;

•

variations in demand for electricity, including those relating to weather, the general economy and recovery from the last recession, population and business growth (and declines), the effects of energy conservation and efficiency measures, including from the development and deployment of alternative energy sources such as self-generation and distributed generation technologies, and any potential economic impacts resulting from federal fiscal decisions;

•	available sources and costs of fuels;

•	effects of inflation;

•	the ability to control costs and avoid cost overruns during the development and construction of facilities, to construct facilities in accordance with the requirements of permits and licenses, and to satisfy any environmental performance standards;

•	investment performance of the Company's employee and retiree benefit plans and nuclear decommissioning trust funds;

•	advances in technology;

•	state and federal rate regulations and the impact of pending and future rate cases and negotiations, including rate actions relating to fuel and other cost recovery mechanisms;

•	the inherent risks involved in operating nuclear generating facilities, including environmental, health, regulatory, natural disaster, terrorism, and financial risks;

•	the ability to successfully operate generating, transmission, and distribution facilities and the successful performance of necessary corporate functions;

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

•	potential business strategies, including acquisitions or dispositions of assets or businesses, which cannot be assured to be completed or beneficial to the Company;

•	the ability of counterparties of the Company 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 Company's business resulting from cyber intrusion or terrorist incidents and the threat of terrorist incidents;

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

•	changes in the Company's credit ratings, including impacts on interest rates, access to capital markets, and collateral requirements;

•	the impacts of any sovereign financial issues, including impacts on interest rates, access to capital markets, impacts on foreign currency exchange rates, counterparty performance, and the economy in general;

•	the ability of the Company to obtain additional generating capacity (or sell excess generating capacity) at competitive prices;

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

•	the direct or indirect effects on the Company's business resulting from incidents affecting the U.S. electric grid or operation of generating resources;

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

•	other factors discussed elsewhere herein and in other reports (including the Form 10-K) filed by the Company from time to time with the SEC.

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(a)	Asset retirement and removal assets and liabilities 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 50 years. Asset retirement and other cost of removal assets and liabilities will be settled and trued up following completion of the related activities.

(b)	Recovered over the remaining life of the original issue, which may range up to 50 years.

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

(d)	Recorded and recovered or amortized as approved or accepted by the Alabama PSC over periods not exceeding 10 years. See Note 3 under "Retail Regulatory Matters" for additional information.

(e)	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.

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

(g)	Comprised of components including mine reclamation and remediation liabilities and fuel-hedging gains. Recorded as accepted by the Alabama PSC. Mine reclamation and remediation liabilities will be settled following completion of the related activities.

(h)	Utilized as storm restoration and potential reliability-related expenses are incurred, as approved by the Alabama PSC.

(i)	Recovered and amortized over the average remaining service period which may range up to 15 years. See Note 2 for additional information.

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

(k)	Included in the deferred income tax charges are $16 million for 2016 and $17 million for 2015 for the retiree Medicare drug subsidy, which is recovered and amortized, as approved by the Alabama PSC, over the average remaining service period which may range up to 15 years.

(l)	Recorded and amortized as approved by the Alabama PSC for a period up to 11 years.

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•	Domestic equity. A mix of large and small capitalization stocks with generally an equal distribution of value and growth attributes, managed both actively and through passive index approaches.

•	International equity. A mix of growth stocks and value stocks with both developed and emerging market exposure, managed both actively and through passive index approaches.

•	Fixed income. A mix of domestic and international bonds.

•	Trust-owned life insurance (TOLI). Investments of the Company's taxable trusts aimed at minimizing the impact of taxes on the portfolio.

•	Special situations. Investments in opportunistic strategies with the objective of diversifying and enhancing returns and exploiting short-term inefficiencies as well as investments in promising new strategies of a longer-term nature.

•	Real estate investments. Investments in traditional private market, equity-oriented investments in real properties (indirectly through pooled funds or partnerships) and in publicly traded real estate securities.

•	Private equity. Investments in private partnerships that invest in private or public securities typically through privately-negotiated and/or structured transactions, including leveraged buyouts, venture capital, and distressed debt.

•

Domestic and international equity. Investments in equity securities such as common stocks, American depositary receipts, and real estate investment trusts that trade on a public exchange are classified as Level 1 investments and are valued at the closing price in the active market. Equity investments with unpublished prices (i.e. pooled funds) are valued as Level 2, when the underlying holdings used to value the investment are comprised of Level 1 or Level 2 equity securities.

•	Fixed income. Investments in fixed income securities are generally classified as Level 2 investments and are valued based on prices reported in the market place. Additionally, the value of fixed income securities takes into consideration certain items such as broker quotes, spreads, yield curves, interest rates, and discount rates that apply to the term of a specific instrument.

•	TOLI. Investments in TOLI policies are classified as Level 2 investments and are valued based on the underlying investments held in the policy's separate account. The underlying assets are equity and fixed income pooled funds that are comprised of Level 1 and Level 2 securities.

•

Real estate investments, private equity, and special situations investments. Investments in real estate, private equity, and special situations are generally classified as Net Asset Value as a Practical Expedient, since the underlying assets typically do not have publicly available observable inputs. The fund manager values the assets using various inputs and techniques depending on the nature of the underlying investments. Techniques may include purchase multiples for comparable transactions, comparable public company trading multiples, discounted cash flow analysis, prevailing market capitalization rates, recent sales of comparable investments, and independent third-party appraisals. The fair value of partnerships is determined by aggregating the value of the underlying assets less liabilities.

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(*)	Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well-diversified with no significant concentrations of risk.

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(*)	Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well-diversified with no significant concentrations of risk.

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(*)	Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well-diversified with no significant concentrations of risk.

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(*)	Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well-diversified with no significant concentrations of risk.

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(1)	Jointly owned with an affiliate, Mississippi Power.

(2)	Jointly owned with PowerSouth Energy Cooperative, Inc.

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(*)	Also includes a make-whole premium prior to October 1, 2017

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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 the Company of what a market participant would use in pricing an asset or liability. If there is little available market data, then the Company's own assumptions are the best available information.

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(*)	Excludes receivables related to investment income, pending investment sales, and payables related to pending investment purchases. See Note 1 under "Nuclear Decommissioning" for additional information.

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(*)	Excludes receivables related to investment income, pending investment sales, and payables related to pending investment purchases. See Note 1 under "Nuclear Decommissioning" for additional information.

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•

Regulatory Hedges – Energy-related derivative contracts which are designated as regulatory hedges relate primarily to the Company's 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 energy cost recovery clause.

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•	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.

(*)	At December 31, 2015, the fair value amounts for derivative contracts subject to netting arrangements were presented gross on the balance sheet.

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(*)	At December 31, 2016, the unrealized gains and losses for derivative contracts subject to netting arrangements were presented net on the balance sheet. At December 31, 2015, the unrealized gains and losses for derivative contracts were presented gross on the balance sheet.

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(*)	Average and maximum amounts are based upon daily balances during the twelve-month periods ended December 31, 2016, 2015, and 2014.

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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. As it relates to the FFB borrowings, the final maturity date is February 20, 2044; however, principal amortization is reflected beginning in 2020. See Note 6 to the financial statements under "DOE Loan Guarantee Borrowings" for additional information. The Company 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 as of January 1, 2017, as reflected in the statements of capitalization. Fixed rates include, where applicable, the effects of interest rate derivatives employed to manage interest rate risk. Long-term debt excludes capital lease amounts (shown separately).

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

(c)	Includes derivative liabilities related to energy-related derivatives. For additional information, see Notes 1 and 11 to the financial statements.

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

(e)

The Company provides estimated capital expenditures for a five-year period, including capital expenditures associated with environmental regulations. These amounts exclude contractual purchase commitments for nuclear fuel and capital expenditures covered under long-term service agreements which are reflected in "Fuel" and "Other," respectively. At December 31, 2016, significant purchase commitments were outstanding in connection with the construction program. See FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Statutes and Regulations" and "Retail Regulatory Matters – Nuclear Construction" 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 New York Mercantile Exchange future prices at December 31, 2016.

(g)

Estimated minimum long-term obligations for various PPA purchases from gas-fired, biomass, and wind-powered facilities. Includes a total of $292 million of biomass PPAs that is contingent upon the counterparties meeting specified contract dates for commercial operation. Subsequent to December 31, 2016, the specified contract dates for commercial operation were extended from 2017 to 2019 and may change further as a result of regulatory action. See FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Renewables" herein for additional information.

(h)	Includes long-term service agreements and contracts for the procurement of limestone. Long-term service agreements include price escalation based on inflation indices.

(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 1 to the financial statements under "Nuclear Decommissioning" for additional information.

(j)

The Company forecasts contributions to the pension and other postretirement benefit plans over a three-year period. The Company 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 the Company's corporate assets. See Note 2 to the financial statements for additional information related to the pension and other postretirement benefit plans, including estimated benefit payments. Certain benefit payments will be made through the related benefit plans. Other benefit payments will be made from the Company's corporate assets.

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•	the impact of recent and future federal and state regulatory changes, including environmental laws regulating emissions, discharges, and disposal to air, water, and land, and also changes in tax and other laws and regulations to which the Company is subject, including potential tax reform legislation, as well as changes in application of existing laws and regulations;

•	current and future litigation, regulatory investigations, proceedings, or inquiries;

•	the effects, extent, and timing of the entry of additional competition in the markets in which the Company operates;

•

variations in demand for electricity, including those relating to weather, the general economy and recovery from the last recession, population and business growth (and declines), the effects of energy conservation and efficiency measures, including from the development and deployment of alternative energy sources such as self-generation and distributed generation technologies, and any potential economic impacts resulting from federal fiscal decisions;

•	available sources and costs of fuels;

•	effects of inflation;

•	the ability to control costs and avoid cost overruns during the development, construction, and operation of facilities, which include the development and construction of generating facilities with designs that have not been finalized or previously constructed;

•	the ability to construct facilities in accordance with the requirements of permits and licenses, to satisfy any environmental performance standards and the requirements of tax credits and other incentives, and to integrate facilities into the Southern Company system upon completion of construction;

•	investment performance of the Company's employee and retiree benefit plans and nuclear decommissioning trust funds;

•	advances in technology;

•	state and federal rate regulations and the impact of pending and future rate cases and negotiations, including rate cases related to fuel and other cost recovery mechanisms;

•	the ability to successfully operate generating, transmission, and distribution 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;

•	the inherent risks involved in operating and constructing nuclear generating facilities, including environmental, health, regulatory, natural disaster, terrorism, and financial risks;

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

•	potential business strategies, including acquisitions or dispositions of assets or businesses, which cannot be assured to be completed or beneficial to the Company;

•	the ability of counterparties of the Company 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 Company's business resulting from cyber intrusion or terrorist incidents and the threat of terrorist incidents;

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

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•	changes in the Company's credit ratings, including impacts on interest rates, access to capital markets, and collateral requirements;

•	the impacts of any sovereign financial issues, including impacts on interest rates, access to capital markets, impacts on foreign currency exchange rates, counterparty performance, and the economy in general, as well as potential impacts on the benefits of the DOE loan guarantees;

•	the ability of the Company to obtain additional generating capacity (or sell excess generating capacity) at competitive prices;

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

•	the direct or indirect effects on the Company's business resulting from incidents affecting the U.S. electric grid or operation of generating resources;

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

•	other factors discussed elsewhere herein and in other reports (including the Form 10-K) filed by the Company from time to time with the SEC.

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(a)	Recovered and amortized over the average remaining service period which may range up to 13 years. See Note 2 for additional information.

(b)

Asset retirement and 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 70 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 $26 million for the retiree Medicare drug subsidy, which is recovered and amortized, as approved by the Georgia PSC, through 2022.

(c)	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 36 years.

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

(e)	Costs associated with construction of environmental controls that will not be completed as a result of unit retirements are being amortized as approved by the Georgia PSC over periods not exceeding nine years or through 2022.

(f)

Amortized as approved by the Georgia PSC over periods not exceeding 10 years or through 2024. The net book value of Plant Mitchell Unit 3 at December 31, 2016 was $12 million, which will continue to be amortized through December 31, 2019 as provided in the 2013 ARP. Amortization of the remaining net book value of Plant Mitchell Unit 3 at December 31, 2019, which is expected to be approximately $5 million, and $31 million related to obsolete inventories of certain retired units will be determined by the Georgia PSC in the 2019 base rate case. See Note 3 under "Retail Regulatory Matters – Integrated Resource Plan" for additional information.

(g)	Previous under-recovery as of December 2013 is recorded and recovered or amortized as approved by the Georgia PSC through 2019. Amortization of $185 million related to the under-recovery from January 2014 through December 2016 will be determined by the Georgia PSC in the 2019 base rate case. See Note 3 for additional information.

(h)

Comprised of several components including deferred nuclear outages, environmental remediation, building lease, and demand-side management tariff under-recovery. Deferred nuclear outages are recorded and recovered or amortized over the outage cycles of each nuclear unit, which does not exceed 24 months. The building lease is recorded and recovered or amortized as approved by the Georgia PSC through 2020. The amortization of environmental remediation and demand-side management tariff under-recovery of $46 million at December 31, 2016 will be determined by the Georgia PSC in the 2019 base rate case.

(i)	Comprised primarily of fuel-hedging gains, which upon final settlement are refunded through the Company's fuel cost recovery mechanism.

(j)	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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•	Domestic equity. A mix of large and small capitalization stocks with generally an equal distribution of value and growth attributes, managed both actively and through passive index approaches.

•	International equity. A mix of growth stocks and value stocks with both developed and emerging market exposure, managed both actively and through passive index approaches.

•	Fixed income. A mix of domestic and international bonds.

•	Trust-owned life insurance (TOLI). Investments of the Company's taxable trusts aimed at minimizing the impact of taxes on the portfolio.

•	Special situations. Investments in opportunistic strategies with the objective of diversifying and enhancing returns and exploiting short-term inefficiencies as well as investments in promising new strategies of a longer-term nature.

•	Real estate investments. Investments in traditional private market, equity-oriented investments in real properties (indirectly through pooled funds or partnerships) and in publicly traded real estate securities.

•	Private equity. Investments in private partnerships that invest in private or public securities typically through privately-negotiated and/or structured transactions, including leveraged buyouts, venture capital, and distressed debt.

•

Domestic and international equity. Investments in equity securities such as common stocks, American depositary receipts, and real estate investment trusts that trade on a public exchange are classified as Level 1 investments and are valued at the closing price in the active market. Equity investments with unpublished prices (i.e. pooled funds) are valued as Level 2, when the underlying holdings used to value the investment are comprised of Level 1 or Level 2 equity securities.

•	Fixed income. Investments in fixed income securities are generally classified as Level 2 investments and are valued based on prices reported in the market place. Additionally, the value of fixed income securities takes into consideration certain items such as broker quotes, spreads, yield curves, interest rates, and discount rates that apply to the term of a specific instrument.

•	TOLI. Investments in TOLI policies are classified as Level 2 investments and are valued based on the underlying investments held in the policy's separate account. The underlying assets are equity and fixed income pooled funds that are comprised of Level 1 and Level 2 securities.

•

Real estate investments, private equity, and special situations investments. Investments in real estate, private equity, and special situations are generally classified as Net Asset Value as a Practical Expedient, since the underlying assets typically do not have publicly available observable inputs. The fund manager values the assets using various inputs and techniques depending on the nature of the underlying investments. Techniques may include purchase multiples for comparable transactions, comparable public company trading multiples, discounted cash flow analysis, prevailing market capitalization rates, recent sales of comparable investments, and independent third-party appraisals. The fair value of partnerships is determined by aggregating the value of the underlying assets less liabilities.

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(*)	Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well-diversified with no significant concentrations of risk.

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(*)	Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well-diversified with no significant concentrations of risk.

(*)	Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well-diversified with no significant concentrations of risk.

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(*)	Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well-diversified with no significant concentrations of risk.

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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.

(c)	A total of $197 million of biomass PPAs included under the non-affiliate operating leases is contingent upon the counterparties meeting specified contract dates for commercial operation. Subsequent to December 31, 2016, the specified contract dates for commercial operation were extended from 2017 to 2019 and may change further as a result of regulatory action.

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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 the Company of what a market participant would use in pricing an asset or liability. If there is little available market data, then the Company's own assumptions are the best available information.

(*)	Includes the investment securities pledged to creditors and collateral received, and excludes receivables related to investment income, pending investment sales, and payables related to pending investment purchases and the lending pool. See Note 1 under "Nuclear Decommissioning" for additional information.

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(*)	Includes the investment securities pledged to creditors and collateral received, and excludes receivables related to investment income, pending investment sales, and payables related to pending investment purchases and the lending pool. See Note 1 under "Nuclear Decommissioning" for additional information.

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•

Regulatory Hedges – Energy-related derivative contracts which are designated as regulatory hedges relate primarily to the Company's fuel-hedging program, 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 fuel cost recovery mechanism.

•	Not Designated – Gains and losses on energy-related derivative contracts that are not designated or fail to qualify as hedges are recognized in the statements of income as incurred.

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(*)	At December 31, 2015, the fair value amounts for derivative contracts subject to netting arrangements were presented gross on the balance sheet.

(*)	At December 31, 2016, the unrealized gains and losses for energy-related derivative contracts subject to netting arrangements were presented net on the balance sheet. At December 31, 2015, the unrealized gains and losses for energy-related derivative contracts subject to netting arrangements were presented gross on the balance sheet.

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(*)	Average and maximum amounts are based upon daily balances during the year.

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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. The Company 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 as of January 1, 2017, as reflected in the statements of capitalization. Fixed rates include, where applicable, the effects of interest rate derivatives employed to manage interest rate risk.

(b)	Includes derivative liabilities related to cash flow hedges of forecasted debt, as well as energy-related derivatives. For additional information, see Notes 1 and 10 to the financial statements.

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

(d)	Excludes a PPA accounted for as a lease, which is included in "Purchased power."

(e)

The Company provides estimated capital expenditures for a five-year period, including capital expenditures associated with environmental regulations. These amounts exclude capital expenditures covered under long-term service agreements, which are reflected in "Other." At December 31, 2016, significant purchase commitments were outstanding in connection with the construction program. See FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Statutes and Regulations" for additional information.

(f)

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 New York Mercantile Exchange future prices at December 31, 2016.

(g)	The capacity and transmission related costs associated with PPAs are recovered through the purchased power capacity clause. Energy costs associated with PPAs are recovered through the fuel clause. See Notes 3 and 7 to the financial statements for additional information.

(h)	Includes long-term service agreements and contracts for the procurement of limestone. Long-term service agreements include price escalation based on inflation indices. Limestone costs are recovered through the environmental cost recovery clause. See Note 3 to the financial statements for additional information.

(i)

The Company forecasts contributions to the pension and other postretirement benefit plans over a three-year period. The Company 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 the Company's corporate assets. See Note 2 to the financial statements for additional information related to the pension and other postretirement benefit plans, including estimated benefit payments. Certain benefit payments will be made through the related benefit plans. Other benefit payments will be made from the Company's corporate assets.

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•	the impact of recent and future federal and state regulatory changes, including environmental laws regulating emissions, discharges, and disposal to air, water, and land, and also changes in tax and other laws and regulations to which the Company is subject, including potential tax reform legislation, as well as changes in application of existing laws and regulations;

•	current and future litigation, regulatory investigations, proceedings, or inquiries;

•	the effects, extent, and timing of the entry of additional competition in the markets in which the Company operates;

•

variations in demand for electricity, including those relating to weather, the general economy and recovery from the last recession, population and business growth (and declines), the effects of energy conservation and efficiency measures, including from the development and deployment of alternative energy sources such as self-generation and distributed generation technologies, and any potential economic impacts resulting from federal fiscal decisions;

•	available sources and costs of fuels;

•	effects of inflation;

•	the ability to control costs and avoid cost overruns during the development and construction of facilities, to construct facilities in accordance with the requirements of permits and licenses, and to satisfy any environmental performance standards;

•	investment performance of the Company's employee and retiree benefit plans;

•	advances in technology;

•	state and federal rate regulations and the impact of pending and future rate cases and negotiations, including rate actions relating to fuel and other cost recovery mechanisms;

•	the ability to successfully operate generating, transmission, and distribution facilities and the successful performance of necessary corporate functions;

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

•	potential business strategies, including acquisitions or dispositions of assets or businesses, which cannot be assured to be completed or beneficial to the Company;

•	the ability of counterparties of the Company 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 Company's business resulting from cyber intrusion or terrorist incidents and the threat of terrorist incidents;

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

•	changes in the Company's credit ratings, including impacts on interest rates, access to capital markets, and collateral requirements;

•	the impacts of any sovereign financial issues, including impacts on interest rates, access to capital markets, impacts on foreign currency exchange rates, counterparty performance, and the economy in general;

•	the ability of the Company to obtain additional generating capacity (or sell excess generating capacity) at competitive prices;

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

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•	the direct or indirect effects on the Company's business resulting from incidents affecting the U.S. electric grid or operation of generating resources;

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

•	other factors discussed elsewhere herein and in other reports (including the Form 10-K) filed by the Company from time to time with the SEC.

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(a)	Recovered and amortized over the average remaining service period which may range up to 14 years. See Note 2 for additional information.

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

(c)	Recovered over the life of the PPA for periods up to seven years.

(d)	Recovered through the environmental cost recovery clause when the remediation or the work is performed.

(e)	Recorded and recovered or amortized as approved by the Florida PSC.

(f)	Asset retirement and removal assets and liabilities 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 65 years. Asset retirement and removal assets and liabilities will be settled and trued up following completion of the related activities.

(g)	Recorded as authorized by the Florida PSC in a settlement agreement approved in December 2013 (2013 Rate Case Settlement Agreement). See Note 3 for additional information.

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

(i)	Comprised primarily of vacation pay. Other regulatory assets costs, with the exception of vacation pay, are recorded and recovered or amortized as approved by the Florida PSC. Vacation pay, including banked holiday pay, does not earn a return as offset in rate base by a corresponding liability; it is recorded as earned by employees and recovered as paid, generally within one year.

(j)	Recovered over either the remaining life of the original issue or, if refinanced, over the life of the new issue, which may range up to 40 years.

(k)	Recorded and recovered or amortized as approved by the Florida PSC, generally within one year.

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•	Domestic equity. A mix of large and small capitalization stocks with generally an equal distribution of value and growth attributes, managed both actively and through passive index approaches.

•	International equity. A mix of growth stocks and value stocks with both developed and emerging market exposure, managed both actively and through passive index approaches.

•	Fixed income. A mix of domestic and international bonds.

•	Special situations. Investments in opportunistic strategies with the objective of diversifying and enhancing returns and exploiting short-term inefficiencies as well as investments in promising new strategies of a longer-term nature.

•	Real estate investments. Investments in traditional private market, equity-oriented investments in real properties (indirectly through pooled funds or partnerships) and in publicly traded real estate securities.

•	Private equity. Investments in private partnerships that invest in private or public securities typically through privately-negotiated and/or structured transactions, including leveraged buyouts, venture capital, and distressed debt.

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•

Domestic and international equity. Investments in equity securities such as common stocks, American depositary receipts, and real estate investment trusts that trade on a public exchange are classified as Level 1 investments and are valued at the closing price in the active market. Equity investments with unpublished prices (i.e. pooled funds) are valued as Level 2, when the underlying holdings used to value the investment are comprised of Level 1 or Level 2 equity securities.

•	Fixed income. Investments in fixed income securities are generally classified as Level 2 investments and are valued based on prices reported in the market place. Additionally, the value of fixed income securities takes into consideration certain items such as broker quotes, spreads, yield curves, interest rates, and discount rates that apply to the term of a specific instrument.

•

Real estate investments, private equity, and special situations investments. Investments in real estate, private equity, and special situations are generally classified as Net Asset Value as a Practical Expedient, since the underlying assets typically do not have publicly available observable inputs. The fund manager values the assets using various inputs and techniques depending on the nature of the underlying investments. Techniques may include purchase multiples for comparable transactions, comparable public company trading multiples, discounted cash flow analysis, prevailing market capitalization rates, recent sales of comparable investments, and independent third-party appraisals. The fair value of partnerships is determined by aggregating the value of the underlying assets less liabilities.

(*)	Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well-diversified with no significant concentrations of risk.

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(*)	Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well-diversified with no significant concentrations of risk.

(*)	Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well-diversified with no significant concentrations of risk.

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(*)	Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well-diversified with no significant concentrations of risk.

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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 the Company of what a market participant would use in pricing an asset or liability. If there is little available market data, then the Company's own assumptions are the best available information.

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•	Regulatory Hedges — Energy-related derivative contracts which are designated as regulatory hedges relate primarily to the Company's 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 fuel cost recovery clause.

•	Cash Flow Hedges — Gains and losses on energy-related derivatives designated as cash flow hedges (which are mainly used to hedge anticipated purchases and sales) are initially deferred in OCI before being recognized in the statements of income in the same period as the hedged transactions are reflected in earnings.

•	Not Designated — Gains and losses on energy-related derivative contracts that are not designated or fail to qualify as hedges are recognized in the statements of income as incurred.

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(*)	At December 31, 2015, the fair value amounts for derivative contracts subject to netting arrangements were presented gross on the balance sheet.

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(*)	At December 31, 2016, the unrealized gains and losses for derivative contracts subject to netting arrangements were presented net on the balance sheet. At December 31, 2015, the unrealized gains and losses for derivative contracts were presented gross on the balance sheet.

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(*)

In the first quarter 2015, the Company updated the methodology to estimate the unbilled revenue allocation among customer classes. This change did not have a material impact on net income. The KWH sales variances in the above table reflect an adjustment to the estimated allocation of the Company's unbilled 2014 and first quarter 2015 KWH sales among customer classes that is consistent with the actual allocation in 2015 and 2016, respectively. Without this adjustment, 2016 weather-adjusted residential sales decreased 1.0%, commercial sales decreased 0.6%, and industrial KWH sales decreased 1.0% as compared to the corresponding period in 2015. Without this adjustment, 2015 weather-adjusted residential sales decreased 1.8%, commercial sales decreased 2.1%, and industrial KWH sales increased 0.3% as compared to the corresponding period in 2014.

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(a)	The 2010 Project Estimate is the certificated cost estimate adjusted to include the certificated estimate for the CO2 pipeline facilities approved in 2011 by the Mississippi PSC, as well as the lignite mine and equipment, AFUDC, and general exceptions.

(b)	Amounts in the Current Cost Estimate include certain estimated post-in-service costs which are expected to be subject to the cost cap.

(c)	The 2012 MPSC CPCN Order approved a construction cost cap of up to $2.88 billion, net of the Initial DOE Grants and excluding the Cost Cap Exceptions. The Current Cost Estimate and the Actual Costs include non-incremental operating and maintenance costs related to the combined cycle and associated

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(d)

The Company's 2010 Project Estimate included recovery of financing costs during construction rather than the accrual of AFUDC. This approach was not approved by the Mississippi PSC as described in "Rate Recovery of Kemper IGCC Costs – 2013 MPSC Rate Order." The Current Cost Estimate also reflects the impact of a settlement agreement with the wholesale customers for cost-based rates under FERC's jurisdiction. See "FERC Matters" herein for additional information.

(e)

Non-capital Kemper IGCC-related costs incurred during construction were initially deferred as regulatory assets. Some of these costs are now included in rates and are being recognized through income; however, such costs continue to be included in the Current Cost Estimate and the Actual Costs at December 31, 2016. The wholesale portion of debt carrying costs, whether deferred or recognized through income, is not included in the Current Cost Estimate and the Actual Costs at December 31, 2016. See "Rate Recovery of Kemper IGCC Costs – Regulatory Assets and Liabilities" herein for additional information.

(f)

The Current Cost Estimate and the Actual Costs include $2.76 billion that will not be recovered for costs above the cost cap, $0.83 billion of investment costs included in current rates for the combined cycle and related assets in service, and $0.08 billion of costs that were previously expensed for the combined cycle and related assets in service. The Current Cost Estimate and the Actual Costs exclude $0.25 billion of costs not included in current rates for post-June 2013 mine operations, the lignite fuel inventory, and the nitrogen plant capital lease, which will be included in the 2017 Rate Case to be filed by June 3, 2017. See Note 1 to the financial statements under "Fuel Inventory," Note 6 to the financial statements under "Capital Leases," and "Rate Recovery of Kemper IGCC Costs – 2017 Rate Case" herein for additional information.

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

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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 certain pollution control revenue bonds. Long-term debt principal for 2017 includes $40 million of pollution control revenue bonds that are classified on the balance sheet at December 31, 2016 as short-term since they are variable rate demand obligations that are supported by short-term credit facilities; however, the final maturity date is in 2028. The Company 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 as of January 1, 2017, as reflected in the statements of capitalization. Fixed rates include, where applicable, the effects of interest rate derivatives employed to manage interest rate risk. Long-term debt excludes capital lease amounts (shown separately).

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

(c)	For additional information, see Notes 1 and 10 to the financial statements.

(d)	See Note 5 to the financial statements under "Unrecognized Tax Benefits" for additional information.

(e)	See Note 7 to the financial statements for additional information.

(f)	Capital lease related to a 20-year nitrogen supply agreement for the Kemper IGCC. See Note 6 to the financial statements for additional information.

(g)

The Company provides estimated capital expenditures for a five-year period, including capital expenditures associated with environmental regulations. At December 31, 2016, significant purchase commitments were outstanding in connection with the construction program. These amounts exclude capital expenditures covered under long-term service agreements, which are reflected separately. See FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Statutes and Regulations" herein for additional information. See Note 3 to the financial statements under "Integrated Coal Gasification Combined Cycle" for additional information.

(h)

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 New York Mercantile Exchange future prices at December 31, 2016.

(i)	Long-term service agreements include price escalation based on inflation indices.

(j)

The Company forecasts contributions to the pension and other postretirement benefit plans over a three-year period. The Company 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 the Company's corporate assets. See Note 2 to the financial statements for additional information related to the pension and other postretirement benefit plans, including estimated benefit payments. Certain benefit payments will be made through the related benefit plans. Other benefit payments will be made from the Company's corporate assets.

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•	the impact of recent and future federal and state regulatory changes, including environmental laws regulating emissions, discharges, and disposal to air, water, and land, and also changes in tax and other laws and regulations to which the Company is subject, including potential tax reform legislation, as well as changes in application of existing laws and regulations;

•	current and future litigation, regulatory investigations, proceedings, or inquiries;

•	the effects, extent, and timing of the entry of additional competition in the markets in which the Company operates;

•

variations in demand for electricity, including those relating to weather, the general economy and recovery from the last recession, population and business growth (and declines), the effects of energy conservation and efficiency measures, including from the development and deployment of alternative energy sources such as self-generation and distributed generation technologies, and any potential economic impacts resulting from federal fiscal decisions;

•	available sources and costs of fuels;

•	effects of inflation;

•

the ability to control costs and avoid cost overruns during the development, construction, and operation of facilities, which include the development and construction of generating facilities with designs that have not been finalized or previously constructed, including changes in labor costs and productivity, adverse weather conditions, shortages and inconsistent quality of equipment, materials, and labor, sustaining nitrogen supply, contractor or supplier delay, non-performance under operating or other agreements, operational readiness, including specialized operator training and required site safety programs, unforeseen engineering or design problems, start-up activities (including major equipment failure and system integration), and/or operational performance (including additional costs to satisfy any operational parameters ultimately adopted by the Mississippi PSC);

•	the ability to construct facilities in accordance with the requirements of permits and licenses, to satisfy any environmental performance standards and the requirements of tax credits and other incentives, and to integrate facilities into the Southern Company system upon completion of construction;

•	investment performance of the Company's employee and retiree benefit plans;

•	advances in technology;

•	state and federal rate regulations and the impact of pending and future rate cases and negotiations, including rate actions relating to fuel and other cost recovery mechanisms;

•	the ability to successfully operate generating, transmission, and distribution facilities and the successful performance of necessary corporate functions;

•

actions related to cost recovery for the Kemper IGCC, including the ultimate impact of the 2015 decision of the Mississippi Supreme Court, the Mississippi PSC's December 2015 rate order, and related legal or regulatory proceedings, Mississippi PSC review of the prudence of Kemper IGCC costs and approval of further permanent rate recovery plans, actions relating to proposed securitization, satisfaction of requirements to utilize grants, and the ultimate impact of the termination of the proposed sale of an interest in the Kemper IGCC to SMEPA;

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

•	potential business strategies, including acquisitions or dispositions of assets or businesses, which cannot be assured to be completed or beneficial to the Company;

•	the ability of counterparties of the Company to make payments as and when due and to perform as required;

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•	the ability to obtain new short- and long-term contracts with wholesale customers;

•	the direct or indirect effect on the Company's business resulting from cyber intrusion or terrorist incidents and the threat of terrorist incidents;

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

•	changes in the Company's credit ratings, including impacts on interest rates, access to capital markets, and collateral requirements;

•	the impacts of any sovereign financial issues, including impacts on interest rates, access to capital markets, impacts on foreign currency exchange rates, counterparty performance, and the economy in general;

•	the ability of the Company to obtain additional generating capacity (or sell excess generating capacity) at competitive prices;

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

•	the direct or indirect effects on the Company's business resulting from incidents affecting the U.S. electric grid or operation of generating resources;

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

•	other factors discussed elsewhere herein and in other reports (including the Form 10-K) filed by the Company from time to time with the SEC.

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(a)	Recovered and amortized over the average remaining service period which may range up to 14 years. See Note 2 for additional information.

(b)	Other regulatory liabilities is comprised of numerous immaterial components including deferred income tax credits and other miscellaneous liabilities that are recorded and refunded or amortized as approved by the Mississippi PSC generally over periods not exceeding one year.

(c)	Asset retirement and 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 49 years. Asset retirement and removal assets and liabilities will be settled and trued up following completion of the related activities.

(d)	The retail portion of property taxes is recovered through the ad valorem tax adjustment clause over a 12-month period beginning in April of the following year. See Note 3 under "Retail Regulatory Matters – Ad Valorem Tax Adjustment" for additional information.

(e)	Other regulatory assets is comprised of numerous immaterial components including vacation pay, loss on reacquired debt, and other miscellaneous assets. These costs are recorded and recovered or amortized as approved by the Mississippi PSC over periods which may range up to 50 years.

(f)	Fuel-hedging assets and liabilities 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.

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

(h)	Includes $97 million of regulatory assets currently in rates to be recovered over periods of two, seven, or 10 years. For additional information, see Note 3 under "Integrated Coal Gasification Combined Cycle – Rate Recovery of Kemper IGCC Costs – Regulatory Assets and Liabilities."

(i)	For additional information, see Note 1 under "Provision for Property Damage."

(j)	The difference between the revenue requirement under the purchase option and the revenue requirement assuming operating lease accounting treatment for the extended term is deferred and amortized over a 10-year period beginning October 2021.

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•	Domestic equity. A mix of large and small capitalization stocks with generally an equal distribution of value and growth attributes, managed both actively and through passive index approaches.

•	International equity. A mix of growth stocks and value stocks with both developed and emerging market exposure, managed both actively and through passive index approaches.

•	Fixed income. A mix of domestic and international bonds.

•	Special situations. Investments in opportunistic strategies with the objective of diversifying and enhancing returns and exploiting short-term inefficiencies as well as investments in promising new strategies of a longer-term nature.

•	Real estate investments. Investments in traditional private market, equity-oriented investments in real properties (indirectly through pooled funds or partnerships) and in publicly traded real estate securities.

•	Private equity. Investments in private partnerships that invest in private or public securities typically through privately-negotiated and/or structured transactions, including leveraged buyouts, venture capital, and distressed debt.

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•

Domestic and international equity. Investments in equity securities such as common stocks, American depositary receipts, and real estate investment trusts that trade on a public exchange are classified as Level 1 investments and are valued at the closing price in the active market. Equity investments with unpublished prices (i.e. pooled funds) are valued as Level 2, when the underlying holdings used to value the investment are comprised of Level 1 or Level 2 equity securities.

•	Fixed income. Investments in fixed income securities are generally classified as Level 2 investments and are valued based on prices reported in the market place. Additionally, the value of fixed income securities takes into consideration certain items such as broker quotes, spreads, yield curves, interest rates, and discount rates that apply to the term of a specific instrument.

•

Real estate investments, private equity, and special situations investments. Investments in real estate, private equity, and special situations are generally classified as Net Asset Value as a Practical Expedient, since the underlying assets typically do not have publicly available observable inputs. The fund manager values the assets using various inputs and techniques depending on the nature of the underlying investments. Techniques may include purchase multiples for comparable transactions, comparable public company trading multiples, discounted cash flow analysis, prevailing market capitalization rates, recent sales of comparable investments, and independent third-party appraisals. The fair value of partnerships is determined by aggregating the value of the underlying assets less liabilities.

(*)	Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well-diversified with no significant concentrations of risk.

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(*)	Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well-diversified with no significant concentrations of risk.

(*)	Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well-diversified with no significant concentrations of risk.

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(*)	Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well-diversified with no significant concentrations of risk.

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(a)	The 2010 Project Estimate is the certificated cost estimate adjusted to include the certificated estimate for the CO2 pipeline facilities approved in 2011 by the Mississippi PSC, as well as the lignite mine and equipment, AFUDC, and general exceptions.

(b)	Amounts in the Current Cost Estimate include certain estimated post-in-service costs which are expected to be subject to the cost cap.

(c)

The 2012 MPSC CPCN Order approved a construction cost cap of up to $2.88 billion, net of the Initial DOE Grants and excluding the cost of the lignite mine and equipment, the cost of the CO2 pipeline facilities, AFUDC, and certain general exceptions, including change of law, force majeure, and beneficial capital (which exists when the Company demonstrates that the purpose and effect of the construction cost increase is to produce efficiencies that will result in a neutral or favorable effect on customers relative to the original proposal for the CPCN) (Cost Cap Exceptions). The Current Cost Estimate and the Actual Costs include non-incremental operating and maintenance costs related to the combined cycle and associated common facilities placed in service in August 2014 that are subject to the $2.88 billion cost cap and exclude post-in-service costs for the lignite mine. See "Rate Recovery of Kemper IGCC Costs – 2013 MPSC Rate Order" herein for additional information.

(d)

The Company's 2010 Project Estimate included recovery of financing costs during construction rather than the accrual of AFUDC. This approach was not approved by the Mississippi PSC as described in "Rate Recovery of Kemper IGCC Costs – 2013 MPSC Rate Order." The Current Cost Estimate also reflects the impact of a settlement agreement with the wholesale customers for cost-based rates under FERC's jurisdiction. See "FERC Matters" herein for additional information.

(e)

Non-capital Kemper IGCC-related costs incurred during construction were initially deferred as regulatory assets. Some of these costs are now included in rates and are being recognized through income; however, such costs continue to be included in the Current Cost Estimate and the Actual Costs at December 31, 2016. The wholesale portion of debt carrying costs, whether deferred or recognized through income, is not included in the Current Cost Estimate and the Actual Costs at December 31, 2016. See "Rate Recovery of Kemper IGCC Costs – Regulatory Assets and Liabilities" herein for additional information.

(f)	On April 8, 2016, the Company received approximately $137 million in Additional DOE Grants, which are expected to be used to reduce future rate impacts for customers.

(g)

The Current Cost Estimate and the Actual Costs include $2.76 billion that will not be recovered for costs above the cost cap, $0.83 billion of investment costs included in current rates for the combined cycle and related assets in service, and $0.08 billion of costs that were previously expensed for the combined cycle and related assets in service. The Current Cost Estimate and the Actual Costs exclude $0.25 billion of costs not included in current rates for post-June 2013 mine operations, the lignite fuel inventory, and the nitrogen plant capital lease, which will be included in the 2017 Rate Case to be filed by June 3, 2017. See Note 1 under "Fuel Inventory," Note 6 under "Capital Leases," and "Rate Recovery of Kemper IGCC Costs – 2017 Rate Case" herein for additional information.

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(*)	Pollution control revenue bonds are classified as short term since they are variable rate demand obligations that are supported by short-term credit facilities; however, the final maturity date is in 2028.

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(*)	There are 1,200,000 outstanding depositary shares, each representing one-fourth of a share of the 5.25% preferred 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 the Company of what a market participant would use in pricing an asset or liability. If there is little available market data, then the Company's own assumptions are the best available information.

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Regulatory Hedges – Energy-related derivative contracts which are designated as regulatory hedges relate primarily to the Company's 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.

•	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 operations as incurred.

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(*)	At December 31, 2015, the fair value amounts for derivative contracts subject to netting arrangements were presented gross on the balance sheet.

(*)	At December 31, 2016, the unrealized gains and losses for derivative contracts subject to netting arrangements were presented net on the balance sheet. At December 31, 2015, the unrealized gains and losses for derivative contracts were presented gross on the balance sheet.

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•	Capacity revenues generally represent the greatest contribution to net income and are designed to provide recovery of fixed costs plus a return on investment.

•

Energy is generally sold at variable cost or is indexed to published gas indices. Energy revenues will vary depending on the energy demand of the Company's customers and their generation capacity, as well as the market prices of wholesale energy compared to the cost of the Company's energy. Energy revenues also include fees for support services, fuel storage, and unit start charges. Increases and decreases in energy revenues under PPAs that are driven by fuel or purchased power prices are accompanied by an increase or decrease in fuel and purchased power costs and do not have a significant impact on net income.

•

The Company's electricity sales from solar and wind generating facilities are predominantly through long-term PPAs; however, these solar and wind PPAs do not have a capacity charge and customers either purchase the energy output of a dedicated renewable facility through an energy charge or pay a fixed price for electricity sold to the grid. As a result, the Company's ability to recover fixed and variable operations and maintenance expenses is dependent upon the level of energy generated from these facilities, which can be impacted by weather conditions, equipment performance, and other factors.

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•	PPA capacity revenues decreased $28 million as a result of a $44 million decrease in non-affiliate capacity revenues primarily as a result of PPA expirations and subsequent generation capacity remarketing into the short-term markets, partially offset by a $16 million increase in affiliate capacity revenues due to new PPAs.

•	PPA energy revenues increased $134 million primarily due to a $170 million increase in renewable energy sales arising from new solar and wind facilities, partially offset by a decrease of $36 million in fuel revenues related to PPAs served by natural gas facilities. Overall, total KWH sales under PPAs increased 7% in 2016 when compared to 2015.

•	Non-PPA revenues increased $78 million primarily due to a 23% increase in KWH sales. Underlying this increase was a $113 million increase in short-term sales to non-affiliates as a result of remarketing generation capacity from expired PPAs, partially offset by a $35 million decrease in power pool sales primarily associated with a reduction in capacity available for sale.

•	PPA capacity revenues increased $23 million ($50 million increase related to affiliates, partially offset by a $27 million decrease related to non-affiliates), primarily due to a 1% increase in total MW capacity contracted with affiliates associated with new natural gas PPAs.

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PPA energy revenues decreased $78 million due to a $141 million decrease primarily related to a 34% decrease in the average price of energy driven by lower natural gas prices passed through in fuel revenues, partially offset by a 13% increase in KWH sales. This decrease in natural gas PPA energy revenues was partially offset by a $63 million increase in energy revenues from PPAs related to the Company's acquisitions of solar and wind facilities. Overall, total KWH sales under PPAs increased 15% in 2015 when compared to 2014.

•	Non-PPA revenues decreased $63 million primarily due to lower natural gas prices, partially offset by a 19% increase in non-PPA KWH sales.

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•	Fuel expense increased $15 million, or 3%, primarily due to a $22 million increase associated with the volume of KWHs generated, partially offset by a $7 million decrease associated with the average cost of natural gas per KWH generated.

•	Purchased power expense increased $9 million, or 10%, primarily due to a $53 million increase associated with the volume of KWHs purchased, partially offset by a $28 million decrease associated with the average cost of purchased power and a $16 million decrease associated with a PPA expiration.

•	Fuel expense decreased $155 million, or 26%, primarily due to a $228 million decrease associated with the average cost of natural gas per KWH generated, partially offset by a $73 million increase associated with the volume of KWHs generated.

•	Purchased power expense decreased $78 million, or 46%, primarily due to a $60 million decrease associated with the volume of KWHs purchased as well as an $18 million decrease associated with the average cost of purchased power.

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(a)	The Company owns 100% of the class A membership interests and a wholly-owned subsidiary of the seller owns 100% of the class B membership interests. The Company and the class B member are entitled to 51% and 49%, respectively, of all cash distributions from the project. In addition, the Company is entitled to substantially all of the federal tax benefits with respect to the transaction.

(b)	The Company owns 90%, with the minority owner, TRE, owning 10%.

(c)	In addition to the 20-year and 12-year PPAs, the facility has a 10-year contract with Allianz Risk Transfer (Bermuda) Ltd.

(d)	Under the terms of the remaining 10-year PPA and the 20-year expansion PPA, approximately $408 million of assets, primarily related to property, plant, and equipment, are subject to lien at December 31, 2016.

(e)	The acquisition included a fully operational 375-MW natural gas-fired combined-cycle facility.

(f)	The Company owns 90.1%, with the minority owner, Invenergy, owning 9.9%.

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(a)	Affiliate PPA approved by the FERC.

(b)	The facility has a total of 299 MWs, of which 110 MWs were placed in service in the fourth quarter 2015 and 189 MWs were placed in service through July 2016.

(c)	Prior to placing the Roserock facility in service, certain solar panels were damaged. While the facility is currently generating energy as expected, the Company is pursuing remedies under its insurance policies and other contracts to repair or replace these solar panels.

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

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

•	Assessing whether the arrangement conveys to the 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

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•	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, 2016, 2015, and 2014.

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(*)	Any additional credit rating downgrades at or below BB- and/or Ba3 could increase collateral requirements up to an additional $91 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 $82 million related to the foreign currency hedge of €1.1 billion. The Company 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 9 to the financial statements.

(c)	Operating lease commitments include certain land leases for solar and wind facilities that are subject to annual price escalation based on indices. See Note 7 to the financial statements under "Commitments" for additional information.

(d)	See Note 5 to the financial statements under "Unrecognized Tax Benefits" for additional information.

(e)

The Company provides estimated capital expenditures for a five-year period, including capital expenditures associated with environmental regulations. Amounts represent current estimates of total expenditures, excluding capital expenditures covered under LTSAs which are reflected in "Other." See Note (h) below. At December 31, 2016, significant purchase commitments were outstanding in connection with the construction program.

(f)	Primarily includes commitments to purchase, transport, and store natural gas fuel. 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 New York Mercantile Exchange future prices at December 31, 2016.

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

(h)	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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•	the impact of recent and future federal and state regulatory changes, including environmental laws regulating emissions, discharges, and disposal to air, water, and land, and also changes in tax and other laws and regulations to which the Company is subject, including potential tax reform legislation, as well as changes in application of existing laws and regulations;

•	current and future litigation, regulatory investigations, proceedings, or inquiries;

•	the effects, extent, and timing of the entry of additional competition in the markets in which the Company operates;

•

variations in demand for electricity, including those relating to weather, the general economy and recovery from the last recession, population and business growth (and declines), the effects of energy conservation and efficiency measures, including from the development and deployment of alternative energy sources such as self-generation and distributed generation technologies, and any potential economic impacts resulting from federal fiscal decisions;

•	available sources and costs of fuels;

•	effects of inflation;

•	the ability to control costs and avoid cost overruns during the development and construction of generating facilities, to construct facilities in accordance with the requirements of permits and licenses, and to satisfy any environmental performance standards, including the requirements of tax credits and other incentives;

•	advances in technology;

•	state and federal rate regulations;

•	the ability to successfully operate generating facilities and the successful performance of necessary corporate functions;

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

•	potential business strategies, including acquisitions or dispositions of assets or businesses, which cannot be assured to be completed or beneficial to the Company;

•	the ongoing renewable energy partnerships and development agreements;

•	the ability of counterparties of the Company 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 Company's business resulting from cyber intrusion or terrorist incidents and the threat of terrorist incidents;

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

•	changes in the Company's credit ratings, including impacts on interest rates, access to capital markets, and collateral requirements;

•	the impacts of any sovereign financial issues, including impacts on interest rates, access to capital markets, impacts on foreign currency exchange rates, counterparty performance, and the economy in general;

•	the ability of the Company to obtain additional generating capacity (or sell excess generating capacity) at competitive prices;

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

•	the direct or indirect effects on the Company's business resulting from incidents affecting the U.S. electric grid or operation of generating resources;

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

•	other factors discussed elsewhere herein and in other reports (including the Form 10-K) filed by the Company from time to time with the SEC.

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(a)	The Company owns 100% of the class A membership interests and a wholly-owned subsidiary of the seller owns 100% of the class B membership interests. The Company and the class B member are entitled to 51% and 49%, respectively, of all cash distributions from the project. In addition, the Company is entitled to substantially all of the federal tax benefits with respect to the transaction.

(b)	The Company owns 90%, with the minority owner, TRE, owning 10%.

(c)	In addition to the 20-year and 12-year PPAs, the facility has a 10-year contract with Allianz Risk Transfer (Bermuda) Ltd.

(d)	Under the terms of the remaining 10-year PPA and the 20-year expansion PPA, approximately $408 million of assets, primarily related to property, plant, and equipment, are subject to lien at December 31, 2016.

(e)	The acquisition included a fully operational 375-MW natural gas-fired combined-cycle facility.

(f)	The Company owns 90.1%, with the minority owner, Invenergy, owning 9.9%.

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(a)	Intangible assets consist of acquired PPAs that will be amortized over 10 and 20-year terms. The estimated amortization for future periods is approximately $9 million per year. See Note 1 for additional information.

(b)	At December 31, 2016, $461 million is included in acquisitions payable on the consolidated balance sheets.

(c)	Includes approximately $281 million of contingent consideration, of which $67 million remains payable at December 31, 2016.

(d)	Includes approximately $51 million of non-cash contributions recorded as capital contributions from noncontrolling interests in the consolidated statements of stockholders' equity.

(e)	Includes approximately $142 million of contingent consideration, all of which had been paid at December 31, 2016 by the noncontrolling interests.

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(a)	The facility has a total of 299 MWs, of which 110 MWs were placed in service in the fourth quarter 2015 and the remainder by July 2016.

(b)	The Company owns 100% of the class A membership interests and a wholly-owned subsidiary of the seller owns 100% of the class B membership interests. The Company and the class B member are entitled to 51% and 49%, respectively, of all cash distributions from the project. In addition, the Company is entitled to substantially all of the federal tax benefits with respect to the transaction.

(c)	The Company owns 90%, with the minority owner, TRE, owning 10%.

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(a)	Intangible assets consist of acquired PPAs that will be amortized over 20-year terms. The estimated amortization for future periods is approximately $14 million per year. See Note 1 under "Impairment of Long-Lived Assets and Intangibles" for additional information.

(b)	Includes approximately $195 million of contingent consideration, all of which had been paid at December 31, 2016.

(c)	Includes approximately $227 million of non-cash contributions recorded as capital contributions from noncontrolling interests in the consolidated statements of stockholders' equity.

(d)	Includes approximately $76 million of contingent consideration, all of which had been paid at December 31, 2016 by the noncontrolling interests.

(a)	Affiliate PPA approved by the FERC.

(b)	The facility has a total of 299 MWs, of which 110 MWs were placed in service in the fourth quarter 2015 and the remainder by July 2016.

(c)	Prior to placing the Roserock facility in service, certain solar panels were damaged. While the facility is currently generating energy as expected, the Company is pursuing remedies under its insurance policies and other contracts to repair or replace these solar panels.

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(*)

ITCs and PTCs generated in the current tax year and carried forward from prior tax years that cannot be utilized in the current tax year are reclassified from current to deferred taxes in federal income tax expense above. ITCs and PTCs reclassified in this manner include $1.13 billion for 2016, $246 million for 2015, and $305 million for 2014. These ITCs and PTCs are included in the following table of temporary differences as unrealized tax credits.

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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 the Company of what a market participant would use in pricing an asset or liability. If there is little available market data, then the Company's own assumptions are the best available information.

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•	Cash Flow Hedges – Gains and losses on energy-related derivatives designated as cash flow hedges which are used to hedge anticipated purchases and sales and are initially deferred in OCI before being recognized in the consolidated statements of income in the same period as the hedged transactions are reflected in earnings.

•	Not Designated – Gains and losses on energy-related derivative contracts that are not designated or fail to qualify as hedges are recognized in the consolidated statements of income as incurred.

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(a)	Swaption at RE Roserock LLC.

(b)	Amortizing notional amount.

(c)	Represents the mandatory settlement date. Settlement amount was based on a 15-year amortizing swap.

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(*)	At December 31, 2015, the fair value amounts for derivative contracts subject to netting arrangements were presented gross on the consolidated balance sheet.

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(a)	Normal represents the 10-year average from January 1, 2006 through December 31, 2015 for Illinois at Chicago Midway International Airport and for Georgia at Atlanta Hartsfield-Jackson International Airport, based on information obtained from the National Oceanic and Atmospheric Administration, National Climatic Data Center.

(b)	The 10-year average Heating Degree Days established by the Illinois Commission in Nicor Gas' last rate case is 5,600 for the 12 months from 1999 through 2008.

(a)	Includes customer and contract counts at December 31, 2016.

(b)	Includes average customer and contract counts for the years ended December 31, 2015 and 2014.

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(a)	Adjusted for the following operating expenses: other operations and maintenance, depreciation and amortization, taxes other than income taxes, and Merger-related expenses.

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

(*)	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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(*)	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)

Represents expected operating gains 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. Also includes the impact of purchase accounting adjustments to reflect natural gas storage inventory at market value. Excluding the impact of these adjustments, the expected net operating gains at December 31, 2016 would have been $85 million.

(b)	Represents the periods associated with the transportation derivative (gains) and losses 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)	Adjusted for the following operating expenses: other operations and maintenance, depreciation and amortization, taxes other than income taxes, goodwill impairment in 2015, and Merger-related expenses.

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

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(a)	Represents the Company's expected capital expenditures and ownership interest as applicable, which may change.

(b)	In 2014, the Company 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.

(c)	In 2014, the Company 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. The Company believes this will alleviate takeaway constraints in the Marcellus region and help mitigate some of the price volatility experienced during recent winters.

(d)

In 2014, the Company entered into two agreements associated with the construction of the Dalton Pipeline, which will serve as an extension of the Transco pipeline system and provide additional natural gas supply to customers in Georgia. The first is a construction and ownership agreement and the second is an agreement to lease ownership in this lateral pipeline extension once it is placed in service.

(e)	The Dalton Pipeline received FERC approval on August 3, 2016, and construction is currently underway.

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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)	The authorized return on equity represents those authorized at December 31, 2016.

(b)

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

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

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

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

(f)	The recovery of 50% of net synergy savings achieved on mergers and acquisitions.

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

(h)	The Georgia PSC approved Atlanta Gas Light's petition for the Georgia Rate Adjustment Mechanism (GRAM) on February 21, 2017.

(i)	Elizabethtown Gas filed a general rate case with the New Jersey BPU on September 1, 2016, which is scheduled to be resolved during 2017. See Note 3 to the financial statements under "Regulatory Matters – Base Rate Cases" for additional information.

(j)	On December 13, 2016, Virginia Natural Gas filed a notice of intent with the Virginia Commission as required at least 60 days prior to the filing of a general base rate case.

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(a)	Cast iron, bare steel, mid-vintage plastic, and risk-based materials.

(b)	Represents expenditures on qualifying infrastructure that have been placed into service after the rate freeze expiration date, December 9, 2014.

(c)	Early vintage plastic, risk-based mid-vintage plastic, and mid-vintage neighborhood convenience.

(d)	Four-inch and smaller mains, associated service lines, and in some instances above-ground facilities associated with rear-lot easements.

(e)	Cast iron and bare steel.

(f)	Galvanized and X-Tube steel. Reflects expenditures and miles of pipe installed since the Company acquired Florida City Gas in 2004.

(g)	Large diameter pressure improvement and system reinforcement projects.

(h)	New business construction and strategic line extension.

(i)	The Georgia PSC approved Atlanta Gas Light's petition for GRAM on February 21, 2017. See Note 3 to the financial statements under "Regulatory Matters – Base Rate Cases" for additional information.

(j)	On December 13, 2016, Virginia Natural Gas filed a notice of intent with the Virginia Commission as required at least 60 days prior to the filing of a general base rate case.

(k)	Elizabethtown Gas filed a general rate case with the New Jersey BPU on September 1, 2016, which is scheduled to be resolved during 2017. See Note 3 to the financial statements under "Regulatory Matters – Base Rate Cases" for additional information.

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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 the Company's nonperformance risk on its liabilities.

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(*)	Southern Company Gas guarantees the obligations of Southern Company Gas Capital.

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(*)	Average and maximum amounts are based upon daily balances during the successor period of July 1, 2016 through December 31, 2016 and the predecessor years ended December 31, 2015 and 2014.

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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 includes premium and associated intrinsic value associated with weather derivatives of $4 million at December 31, 2016, $5 million at June 30, 2016, $10 million at December 31, 2015, and $3 million at December 31, 2014.

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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 $62 million at December 31, 2016.

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(a)

Amounts are reflected based on final maturity dates. The Company 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 January 1, 2017, as reflected in the statements of capitalization. Fixed rates include, where applicable, the effects of interest rate derivatives employed to manage interest rate risk.

(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 33 million mmBtu at floating gas prices calculated using forward natural gas prices at December 31, 2016 and valued at $106 million. As the Company does for certain of its affiliates, it provides guarantees to certain gas suppliers of 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. The Company's operating leases are primarily for real estate.

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

(e)	Guarantees are provided to certain municipalities and other agencies and certain gas suppliers of SouthStar in support of payment obligations.

(f)	Includes liabilities related to energy-related derivatives. For additional information, see Notes 1 and 10 to the financial statements.

(g)

The Company forecasts contributions to the pension and other postretirement benefit plans over a three-year period. The Company 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 the Company's corporate assets. See Note 2 to the financial statements for additional information related to the pension and other postretirement benefit plans, including estimated benefit payments. Certain benefit payments will be made through the related benefit plans. Other benefit payments will be made from the Company's corporate assets.

(h)	Estimated capital expenditures are provided through 2021.

(i)	Includes contractual environmental remediation liabilities that are generally recoverable through base rates or rate rider mechanisms and long-term service agreements.

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•	the impact of recent and future federal and state regulatory changes, including environmental laws, and also changes in tax and other laws and regulations to which the Company is subject, including potential tax reform legislation, as well as changes in application of existing laws and regulations;

•	current and future litigation, regulatory investigations, proceedings, or inquiries;

•	the effects, extent, and timing of the entry of additional competition in the markets in which the Company operates;

•	variations in demand for natural gas, including those relating to weather, the general economy and recovery from the last recession, population and business growth (and declines), the effects of energy conservation and efficiency measures, including from the development and deployment of alternative energy sources, and any potential economic impacts resulting from federal fiscal decisions;

•	available sources and costs of natural gas;

•	limits on pipeline capacity;

•	effects of inflation;

•	the ability to control costs and avoid cost overruns during the development and construction of facilities;

•	investment performance of the Company's employee and retiree benefit plans;

•	advances in technology;

•	state and federal rate regulations and the impact of pending and future rate cases and negotiations, including rate actions relating to natural gas and other cost recovery mechanisms;

•	the inherent risks involved in transporting and storing natural gas;

•	the ability to successfully operate the natural gas distribution and storage facilities and the successful performance of necessary corporate functions;

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

•	potential business strategies, including acquisitions or dispositions of assets or businesses, which cannot be assured to be completed or beneficial to the Company;

•

the possibility that the anticipated benefits from the Merger cannot be fully realized or may take longer to realize than expected, the possibility that costs related to integration with Southern Company will be greater than expected, the ability to retain and hire key personnel and maintain relationships with customers, suppliers, or other business partners, and the diversion of management time on integration related issues;

•	the ability of counterparties of the Company to make payments as and when due and to perform as required;

•	the direct or indirect effect on the Company's business resulting from cyber intrusion or terrorist incidents and the threat of terrorist incidents;

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

•	changes in the Company's credit ratings, including impacts on interest rates, access to capital markets, and collateral requirements;

•	the impacts of any sovereign financial issues, including impacts on interest rates, access to capital markets, impacts on foreign currency exchange rates, counterparty performance, and the economy in general;

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

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•	the direct or indirect effects on the Company's business resulting from incidents affecting the U.S. natural gas pipeline infrastructure or operation of storage resources;

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

•	other factors discussed elsewhere herein and in other reports (including the Form 10-K) filed by the Company from time to time with the SEC.

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(a)	Deferred income tax assets and liabilities are amortized over the related property lives, which range up to 30 years.

(b)	Recovered over the remaining life of the original debt issuances, which range up to 22 years.

(c)	Recorded and recovered or amortized as approved or accepted by the applicable state regulatory agencies over periods not exceeding nine years.

(d)	Financial instrument-hedging assets and 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.

(e)	Comprised of several components including unamortized loss on reacquired debt, weather normalization, franchise gas, and deferred depreciation expense, which are recovered or amortized as approved by the applicable state regulatory agencies over periods generally not exceeding ten years.

(f)	Comprised of several components including energy efficiency programs and unamortized bond issuance costs which are recovered or amortized as approved by the applicable state regulatory agencies over periods generally not exceeding four years.

(g)	Recovered and amortized over the average remaining service period which range up to 11 years. See Note 2 for additional information.

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

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

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(a)	Effective January 1, 2016, the Company uses a spot rate approach to estimate the service cost and interest cost components. Previously, the Company estimated these components using a single weighted average discount rate.

(b)	Only applicable to Nicor Gas union employees. The pension bands for the former Nicor plan reflect the negotiated rates of 2.0% for each of 2016 and 2017, in accordance with a March 2014 union agreement.

(*)	Only applicable to Nicor Gas union employees. The pension bands for the former Nicor plan reflect the negotiated rates of 2.0% for each of 2016 and 2017, in accordance with a March 2014 union agreement.

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•	Domestic equity. A mix of large and small capitalization stocks with generally an equal distribution of value and growth attributes, managed both actively and through passive index approaches.

•	International equity. A mix of growth stocks and value stocks with both developed and emerging market exposure, managed both actively and through passive index approaches.

•	Fixed income. A mix of domestic and international bonds.

•	Special situations. Investments in opportunistic strategies with the objective of diversifying and enhancing returns and exploiting short-term inefficiencies as well as investments in promising new strategies of a longer-term nature.

•	Real estate investments. Investments in traditional private market, equity-oriented investments in real properties (indirectly through pooled funds or partnerships) and in publicly traded real estate securities.

•	Private equity. Investments in private partnerships that invest in private or public securities typically through privately-negotiated and/or structured transactions, including leveraged buyouts, venture capital, and distressed debt.

•

Domestic and international equity. Investments in equity securities such as common stocks, American depositary receipts, and real estate investment trusts that trade on a public exchange are classified as Level 1 investments and are valued at the closing price in the active market. Equity investments with unpublished prices (i.e. pooled funds) are valued as Level 2, when the underlying holdings used to value the investment are comprised of Level 1 or Level 2 equity securities.

•	Fixed income. Investments in fixed income securities are generally classified as Level 2 investments and are valued based on prices reported in the market place. Additionally, the value of fixed income securities takes into consideration certain items such as broker quotes, spreads, yield curves, interest rates, and discount rates that apply to the term of a specific instrument.

•

Real estate investments, private equity, and special situations investments. Investments in real estate, private equity, and special situations are generally classified as Net Asset Value as a Practical Expedient, since the underlying assets typically do not have publicly available observable inputs. The fund manager values the assets using various inputs and techniques depending on the nature of the underlying investments. Techniques may include purchase multiples for comparable transactions, comparable public company trading multiples, discounted cash flow analysis, prevailing market

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(*)	Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well-diversified with no significant concentrations of risk.

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(a)	Includes $9 million at December 31, 2015 of medical benefit (health and welfare) component for 401(h) accounts to fund a portion of the other retirement benefits.

(b)	Includes funds that invest primarily in U.S. common stocks.

(c)	Includes funds that invest primarily in foreign equity and equity-related securities.

(d)	Includes funds that invest primarily in common stocks of emerging markets.

(e)	Includes funds that invest primarily in investment grade debt and fixed income securities.

(f)	Includes funds that invest in limited/general partnerships, managed accounts, and other investment entities issued by non-traditional firms or "hedge funds."

(g)	Includes funds that invest primarily in investment vehicles and commodity pools as a "fund of funds."

(h)	Includes funds that invest in private equity and small buyout funds, partnership investments, direct investments, secondary investments, directly/indirectly in real estate and may invest in equity securities of real estate related companies, real estate mortgage loans, and real estate mezzanine loans.

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(*)	Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well-diversified with no significant concentrations of risk.

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(a)	Includes funds that invest primarily in U.S. common stocks.

(b)	Includes funds that invest primarily in foreign equity and equity-related securities.

(c)	Includes funds that invest primarily in common stocks of emerging markets.

(d)	Includes funds that invest primarily in investment grade debt and fixed income securities.

(e)	Includes funds that invest in limited/general partnerships, managed accounts, and other investment entities issued by non-traditional firms or "hedge funds."

(f)	Includes funds that invest primarily in investment vehicles and commodity pools as a "fund of funds."

(g)	Includes funds that invest in private equity and small buyout funds, partnership investments, direct investments, secondary investments, directly/indirectly in real estate and may invest in equity securities of real estate related companies, real estate mortgage loans, and real estate mezzanine loans.

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•	Southern Company Gas' outstanding restricted stock units, 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 performance share unit was converted into an award of Southern Company's restricted stock units (RSUs).

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(a)	Energy-related derivatives excludes $4 million associated with certain weather derivatives accounted for based on intrinsic value rather than fair value.

(b)	Energy-related derivatives excludes cash collateral of $62 million.

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(a)	Energy-related derivatives excludes $10 million associated with certain weather derivatives accounted for based on intrinsic value rather than fair value.

(b)	Energy-related derivatives excludes cash collateral of $96 million.

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•

Regulatory Hedges — Energy-related derivative contracts which are designated as regulatory hedges relate primarily to the Company's fuel-hedging programs, where gains and losses are initially recorded as regulatory liabilities and assets, respectively, and then are included in the cost of natural gas as the underlying natural gas is used in operations and ultimately recovered through the respective 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 other OCI before being recognized in the statements of income in the same period as the hedged transactions are reflected in earnings.

•	Not Designated — Gains and losses on energy-related derivative contracts that are not designated or fail to qualify as hedges are recognized in the statements of income in the period of change.

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(a)	The gross amounts of recognized assets and liabilities are netted on the balance sheets to the extent that there were netting arrangements with the counterparties.

(b)	The gross amounts of recognized assets and liabilities do not include cash collateral held on deposit in broker margin accounts of $62 million as of December 31, 2016 and $96 million as of December 31, 2015.

(c)	As of December 31, 2016 and 2015, letters of credit from counterparties offset an immaterial portion of these assets under master netting arrangements.

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(*)	Fair value gains and losses included in regulatory assets and liabilities include cash collateral held on deposit in broker margin accounts of $8 million as of December 31, 2016 and $19 million as of December 31, 2015.

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(*)	Excludes gains (losses) recorded in cost of natural gas associated with weather derivatives of $6 million for the successor periods of July 1, 2016 through December 31, 2016 and $3 million, $12 million, and $(7) million for the predecessor periods of January 1, 2016 through June 30, 2016 and the years ended December 31, 2015 and 2014, respectively.

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•	rate credits of $18 million to be paid to customers in New Jersey and Maryland;

•	sharing of Merger savings with customers in Georgia starting in 2020;

•	phasing-out the use of the Nicor name or logo by certain of the Company's gas marketing services subsidiaries in conducting non-utility business in Illinois;

•	reaffirming that Elizabethtown Gas would file a base rate case no later than September 1, 2016, with another base rate case no later than three years after the 2016 rate case; and

•	requiring Elkton Gas to file a base rate case within two years of closing the Merger.

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(*)	The revenues for wholesale gas services are netted with costs associated with its energy and risk management activities. A reconciliation of operating revenues and intercompany revenues is shown in the following table.

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(*)	The revenues for wholesale gas services are netted with costs associated with its energy and risk management activities. A reconciliation of operating revenues and intercompany revenues is shown in the following table.

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(*)	Primarily reflects $7 million due to the suspension of depreciation and amortization during 2014 and $19 million of goodwill attributable to Tropical Shipping that was impaired in 2014, based on the negotiated sales price.

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(a)	Long-term notes payable maturities are as follows: $22 million in 2017 (7.20%); $155 million in 2018 (3.50%); $300 million in 2019 (5.25%); $330 million in 2021 (3.50% to 9.10%); and $3.1 billion in 2022-2046 (2.45% to 8.70%).

(b)	First mortgage bonds maturities are as follows: $50 million in 2019 (4.70%) and $575 million in 2023-2038 (2.66% to 6.58%).

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(1)	Ages listed are as of December 31, 2016.

(2)	No position other than director.

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(1)	Ages listed are as of December 31, 2016.

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Item 11.	EXECUTIVE COMPENSATION

•	Business unit financial and operational performance and Southern Company earnings per share (EPS), based on actual results as adjusted by the Compensation Committee, compared to target performance levels established early in the year, determine the actual payouts under the annual cash incentive award program (Performance Pay Program).

•	Southern Company's total shareholder return (TSR) compared to those of industry peers, cumulative EPS, and equity-weighted return on equity (ROE) over a three-year period lead to higher or lower payouts under the long-term equity incentive award program (Performance Share Program).

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•	Employees' commitment and performance have a significant impact on achieving business results;

•	Compensation and benefits offered must attract, retain, and engage employees and must be financially sustainable;

•	Compensation should be consistent with performance: higher pay for higher performance and lower pay for lower performance; and

•	Both business drivers and culture should influence the compensation and benefit program.

•	Be competitive with Gulf Power's industry peers;

•	Reward achievement of Gulf Power's goals;

•	Be aligned with the interests of Southern Company's stockholders and Gulf Power's customers; and

•	Not encourage excessive risk-taking.

•	Retention by the Compensation Committee of an independent compensation consultant, Pay Governance LLC (Pay Governance), that provides no other services to Gulf Power or Southern Company.

•	Inclusion of a claw-back provision that permits the Compensation Committee to recoup performance pay from any employee if determined to have been based on erroneous results, and requires recoupment from an executive officer in the event of a material financial restatement due to fraud or misconduct of the executive officer.

•	Provision of limited perquisites with no income tax gross-ups for the Chairman, President, and Chief Executive Officer, except on certain relocation-related benefits.

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•	Short-term compensation

◦	Base salary

◦	Performance Pay Program

•	Long-term compensation

◦	Performance Share Program

•	Benefits

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•	Continuing industry-leading reliability and customer satisfaction, while maintaining reasonable retail prices;

•	Business Unit Financial Goal: Net Income

•	Business Unit Operational Goals: Varies by business unit

•	Southern Company Financial Goal: EPS

•	Individual Performance Goals for the Chief Executive Officer

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EPS: Southern Company's adjusted EPS result was $2.89, exceeding the $2.82 target. The adjusted EPS result excludes the impact of charges related to the Kemper IGCC, equity return related to the Kemper IGCC schedule extension, and earnings, acquisition costs, integration costs, and financing costs related to Southern Company Gas, PowerSecure, and Southern Natural Gas. This is consistent with the earnings results publicly communicated to investors.

•	Net Income: Gulf Power's adjusted net income result was $130.7 million, exceeding the $118.8 million target. The adjusted result excludes the impact of integration costs.

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•	Financial planning is provided for most officers of Gulf Power, including all of the named executive officers. Gulf Power provides an annual subsidy of up to $8,200 to be used for financial planning, tax preparation fees, and estate planning. In the initial year, the maximum allowed amount is $13,200.

•

The Southern Company system has aircraft that are used to facilitate business travel. All flights on these aircraft must have a business purpose, except limited personal use that is associated with business travel is permitted for the President and Chief Executive Officer. Additionally, limited personal use related to relocation is permissible but must be approved. The amount reported for such personal use is the incremental cost of providing the benefit, primarily fuel costs. Also, if seating is available, Southern Company permits a spouse or other family member to accompany an employee on a flight. However, because in such cases the aircraft is being used for a business purpose, there is no incremental cost associated with the family travel, and no amounts are included for such travel. Any additional expenses incurred that are related to family travel are included.

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•	Other miscellaneous perquisites reflects the full cost to Gulf Power of providing the following items: personal use of company-provided computers, personal use of company-provided tickets for sporting and other entertainment events, and gifts distributed to and activities provided to attendees at company-sponsored events.

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•	Retirement or Retirement-Eligible - Termination of a named executive officer who is at least 50 years old and has at least 10 years of credited service.

•	Resignation - Voluntary termination of a named executive officer who is not retirement-eligible.

•	Lay Off - Involuntary termination of a named executive officer who is not retirement-eligible not for cause.

•	Involuntary Termination - Involuntary termination of a named executive officer for cause. Cause includes individual performance below minimum performance standards and misconduct, such as violation of the Company's Drug and Alcohol Policy.

•	Death or Disability - Termination of a named executive officer due to death or disability.

•	Southern Company Change-in-Control I - Consummation of an acquisition by another entity of 20% or more of Common Stock or, following consummation of a merger with another entity, Southern Company's stockholders own 65% or less of the entity surviving the merger.

•	Southern Company Change-in-Control II - Consummation of an acquisition by another entity of 35% or more of Common Stock or, following consummation of a merger with another entity, Southern Company's stockholders own less than 50% of Southern Company surviving the merger.

•	Southern Company Does Not Survive a Merger - Consummation of a merger or other event and Southern Company is not the surviving company or the Common Stock is no longer publicly traded.

•	Company Change-in-Control - Consummation of an acquisition by another entity, other than another subsidiary of Southern Company, of 50% or more of the stock of Gulf Power, consummation of a merger with another entity and Gulf Power is not the surviving company, or the sale of substantially all the assets of Gulf Power.

•

Involuntary Change-in-Control Termination or Voluntary Change-in-Control Termination for Good Reason - Employment is terminated within two years of a change in control, other than for cause, or the employee voluntarily terminates for good reason. Good reason for voluntary termination within two years of a change in control generally is satisfied when there is a material reduction in salary, performance-based compensation opportunity, or benefits; relocation of over 50 miles; or a diminution in duties and responsibilities.

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•	As of December 31, 2016, the severance payment was two times the base salary and target payout under the annual Performance Pay Program for Mr. Connally and one times the base salary and target payout under the annual Performance Pay Program for the other named executive officers.

•	The estimated cost of providing the six months of outplacement services is $6,000 per named executive officer.

•	If any portion of the severance amount constitutes an "excess parachute payment" under Section 280G of the Internal Revenue Code and is therefore subject to an excise tax, the severance amount will be reduced unless the after-tax "unreduced amount" exceeds the after-tax "reduced amount." Excise tax gross-ups will not be provided on change-in-control severance payments.

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•	in Common Stock units which earn dividends as if invested in Common Stock and are distributed in shares of Common Stock or cash upon leaving the board; or

•	at the prime interest rate which is paid in cash upon leaving the board.

(1)	Includes amounts voluntarily deferred in the Director Deferred Compensation Plan.

(2)	Includes fair market value of equity grants on grant dates. All such stock awards are vested immediately upon grant.

(3)	Includes value of charitable contribution made in each director's name.

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(1)	"Beneficial ownership" means the sole or shared power to vote, or to direct the voting of, a security and/or investment power with respect to a security or any combination thereof.

(2)	Indicates the number of deferred stock units held under the Director Deferred Compensation Plan.

(3)	Indicates shares of Common Stock that certain executive officers have the right to acquire within 60 days. Shares indicated are included in the Shares Beneficially Owned column.

(4)	Shares indicated are included in the Shares Beneficially Owned column.

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•	The Southern Company Audit Committee is responsible for overseeing the Code of Ethics, which includes policies relating to conflicts of interest. The Code of Ethics requires that all employees and directors avoid conflicts of interest, defined as situations where the person's private interests conflict, or even appear to conflict, with the interests of Southern Company as a whole.

•	Southern Company also has a Contract Manual and other formal written procurement policies and procedures that guide the purchase of goods and services, including requiring competitive bids for purchases of materials for $10,000 and above and for purchases of services for $25,000 and above or approval based on documented business needs for sole sourcing arrangements.

•	At least annually, each director and executive officer completes a detailed questionnaire that asks about any business relationship that may give rise to a conflict of interest and all transactions in which the Southern Company or a subsidiary is involved and in which the executive officer, director, or a related party has a direct or indirect material interest.

•	Southern Company also conducts a review of financial systems to identify potential conflicts of interest and related party transactions.

•	A determination of the need for the goods and services;

•	Preparation and evaluation of requests for proposals by the lead support organization;

•	The writing of contracts;

•	Controls and guidance regarding the evaluation of the proposals; and

•	Negotiation of contract terms and conditions.

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

(2)	Represents registration fees for attendance at Deloitte & Touche LLP-sponsored education seminars in 2015 and 2016 and subscription fees for Deloitte & Touche LLP's technical accounting research tool in 2015.

(1)	Includes fees for services performed in connection with financing transactions billed by Deloitte & Touche LLP in 2016 and PricewaterhouseCoopers LLP in 2015. Also includes fees for audits of several subsidiaries by Deloitte & Touche LLP in 2016 and PricewaterhouseCoopers LLP in 2015.

(2)	Represents fees for a review report on internal controls provided to third parties billed by Deloitte & Touche LLP in 2016 and PricewaterhouseCoopers LLP in 2015.

(3)	Represents fees billed by Deloitte & Touche LLP for tax compliance services in 2016 and PricewaterhouseCoopers LLP for tax compliance, planning, and advisory services in 2015.

(4)	Represents registration fees for attendance at Deloitte & Touche LLP-sponsored education seminars in 2016 and subscription fees for Deloitte & Touche LLP's technical accounting research tool in 2016.

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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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(*)

The refund ordered by the Mississippi PSC pursuant to the 2015 Mississippi Supreme Court decision relative to Mirror CWIP involved refunding all billed amounts to all historical customers and included an interest component. The refund of approximately $371 million in 2015 was of sufficient magnitude to resolve most past due amounts beyond 30 days aged receivables, accounting for the negative provision of $(2.0) million where risk of collectibility was offset by applying the refund to past due amounts. It was also of sufficient size to offset amounts previously written off in the 2012-2015 time frame, accounting for the net recoveries of $1.5 million.

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