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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 results of the Contractor's bankruptcy filing and the impact of any inability or other failure of Toshiba to perform its obligations under the Toshiba Guarantee, including any effect on the construction of Plant Vogtle Units 3 and 4, as well as the engineering, procurement, and construction agreement for Plant Vogtle Units 3 and 4 and Georgia Power's DOE loan guarantees;

•	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;

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

•	the ability to successfully operate the electric utilities' generating, transmission, and distribution facilities and Southern Company Gas' natural gas distribution and storage facilities and the successful performance of necessary corporate functions;

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

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

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

•	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 the registrants from time to time with the SEC.

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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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(a)	Represents the Southern Company parent entity.

(b)	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 three-month period ended March 31, 2017.

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

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(a)	Mississippi Power and Southern Company Gas did not issue or redeem any long-term debt during the first three months of 2017.

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

(c)	Represents the Southern Company parent entity.

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(a)	Evaluation of disclosure controls and procedures.

(b)	Changes in internal controls over financial reporting.

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

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

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(*)	Average and maximum amounts are based upon daily balances during the three-month period ended March 31, 2017. No short-term debt was outstanding at March 31, 2017.

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(*)	Average cost of purchased power includes fuel purchased by Georgia Power for tolling agreements where power is generated by the provider.

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(*)	Average and maximum amounts are based upon daily balances during the three-month period ended March 31, 2017. No short-term debt was outstanding at March 31, 2017.

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(*)	Average cost of purchased power includes fuel purchased by Gulf Power for tolling agreements where power is generated by the provider.

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(*)	Average and maximum amounts are based upon daily balances during the three-month period ended March 31, 2017.

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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 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. 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 March 31, 2017. 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 March 31, 2017. 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 $2.87 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 $0.09 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 $0.23 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 and Note 6 to the financial statements of Mississippi Power under "Fuel Inventory" and "Capital Leases," respectively, in Item 8 of the Form 10-K 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 three-month period ended March 31, 2017.

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•	PPA capacity revenues increased $24 million, or 19%, primarily due to new PPAs related to natural gas facilities and additional customer load requirements.

•	PPA energy revenues increased $81 million, or 69%, due to a $60 million increase in renewable energy sales primarily from new solar and wind facilities and a $21 million increase in energy sales primarily from new natural gas PPAs. Overall, total KWH sales under PPAs increased 32% in the first quarter 2017 when compared to the corresponding period in 2016.

•	Non-PPA revenues increased $30 million, or 42%, primarily due to a 62% increase in short-term KWH sales to the wholesale market from Southern Power's natural gas facilities.

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(*)	Average and maximum amounts are based upon daily balances during the three-month period ended March 31, 2017.

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

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(a)	Normal represents the 10-year average from January 1, 2007 through March 31, 2016 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' 2009 rate case is 2,902 for the first three months from 1998 through 2007.

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(a)	Includes other operations and maintenance, depreciation and amortization, taxes other than income taxes, and Merger-related expenses.

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

(*)	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.

(b)	Represents the periods associated with the transportation derivative gains during which the derivatives will be settled and the physical transportation transactions will occur that offset the derivative gains that were previously recognized.

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(a)	Includes other operations and maintenance, depreciation and amortization, taxes other than income taxes, and Merger-related expenses.

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

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(*)	Average and maximum amounts are based upon daily balances during the successor three-month period ended March 31, 2017.

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

(b)	Net fair value of derivative instruments outstanding includes premiums and the intrinsic values associated with weather derivatives of $19 million at March 31, 2017 and $9 million at March 31, 2016.

(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 $92 million at March 31, 2017.

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(A)	INTRODUCTION

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(B)	CONTINGENCIES AND REGULATORY MATTERS

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(*)	In accordance with an accounting order issued on February 17, 2017 by the Alabama PSC, Alabama Power reclassified the $23 million under recovered balance for Rate CNP Compliance to a deferred regulatory asset account.

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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. 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 March 31, 2017. 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 March 31, 2017. 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 $2.87 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 $0.09 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 $0.23 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 and Note 6 to the financial statements of Mississippi Power under "Fuel Inventory" and "Capital Leases," respectively, in Item 8 of the Form 10-K and "Rate Recovery of Kemper IGCC Costs – 2017 Rate Case" herein for additional information.

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(C)	FAIR VALUE MEASUREMENTS

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(a)	Excludes $19 million associated with certain weather derivatives accounted for based on intrinsic value rather than fair value.

(b)	Excludes cash collateral of $92 million.

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

(d)	Excludes receivables related to investment income, pending investment sales, payables related to pending investment purchases, and currencies.

(e)	Includes the investment securities pledged to creditors and collateral received and excludes payables related to the securities lending program. As of March 31, 2017, approximately $56 million of the fair market value of Georgia Power's nuclear decommissioning trust funds' securities were on loan to creditors under the funds' managers' securities lending program.

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(D)	STOCKHOLDERS' EQUITY

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Related to Southern Power Company and excludes redeemable noncontrolling interests. Subsequent to March 31, 2017, approximately $114 million was reclassified from redeemable noncontrolling interests to noncontrolling interests, included in stockholder's equity, due to the expiration of SunPower Corp's option to require Southern Power to purchase its membership interests in one of the solar partnerships. See Note 10 to the financial statements of Southern Power in Item 8 of the Form 10-K for additional information.

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(E)	FINANCING

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(a)	Represents the Southern Company parent entity.

(b)	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)	Mississippi Power and Southern Company Gas did not issue or redeem any long-term debt during the first three months of 2017.

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

(c)	Represents the Southern Company parent entity.

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(F)	RETIREMENT BENEFITS

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(G)	INCOME TAXES

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(H)	DERIVATIVES

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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 the natural gas distribution utilities' fuel-hedging programs, where gains and losses are initially recorded as regulatory liabilities and assets, respectively, and then are included in fuel expense as the underlying fuel is used in operations and ultimately recovered through the respective fuel cost recovery clauses.

•	Cash Flow Hedges — Gains and losses on energy-related derivatives designated as cash flow hedges (which are mainly used to hedge anticipated purchases and sales) are initially deferred in 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.

(*)

Southern Company's and Southern Company Gas' derivative instruments include both long and short natural gas positions. A long position is a contract to purchase natural gas and a short position is a contract to sell natural gas. Southern Company Gas' volume represents the net of long natural gas positions of 3.4 billion mmBtu and short natural gas positions of 3.2 billion mmBtu as of March 31, 2017, which is also included in Southern Company's total volume.

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(*)	Represents the Southern Company parent entity.

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(*)	Gross amounts offset include cash collateral held on deposit in broker margin accounts of $92 million and $62 million as of March 31, 2017 and December 31, 2016, respectively.

(a)	Georgia Power includes other regulatory liabilities, current in other current liabilities.

(b)	Fair value gains and losses recorded in regulatory assets and liabilities include cash collateral held on deposit in broker margin accounts of $4 million at March 31, 2017.

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(a)	Georgia Power includes other regulatory liabilities, current in other current liabilities.

(b)	Georgia Power includes other regulatory liabilities, deferred in other deferred credits and liabilities.

(c)	Fair value gains and losses recorded in regulatory assets and liabilities include cash collateral held on deposit in broker margin accounts of $8 million at 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 $14 million for the three months ended March 31, 2017.

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(*)	Excludes gains (losses) recorded in cost of natural gas associated with weather derivatives of $14 million for the successor three months ended March 31, 2017 and $3 million for the predecessor three months ended March 31, 2016.

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(I)	ACQUISITIONS

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(J)	JOINT OWNERSHIP AGREEMENTS

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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 $108 million ($67 million after tax) and $53 million ($33 million after tax) for the three months ended March 31, 2017 and 2016, respectively. See Note (B) under "Integrated Coal Gasification Combined Cycle – Kemper IGCC Schedule and Cost Estimate" for additional information.

(c)	Segment net income (loss) for the traditional electric operating companies also includes a pre-tax charge for the write-down of Gulf Power's ownership of Plant Scherer Unit 3 of $33 million ($20 million after tax) for the three months ended March 31, 2017. See Note (B) under "Regulatory Matters – Gulf Power – Retail Base Rate Cases" for additional information.

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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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