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the impact of recent and future federal and state regulatory changes, including legislative and regulatory initiatives regarding deregulation and restructuring of the electric utility industry, environmental laws including regulation of water, coal combustion residuals, and emissions of sulfur, nitrogen, carbon, soot, particulate matter, hazardous air pollutants, including mercury, and other substances, and also changes in tax and other laws and regulations to which Southern Company and its subsidiaries are subject, as well as changes in application of existing laws and regulations;

•	current and future litigation, regulatory investigations, proceedings, or inquiries, including the pending EPA civil actions against certain Southern Company subsidiaries, FERC matters, and Internal Revenue Service and state tax audits;

•	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, including those relating to weather, the general economy and recovery from the recent recession, population and business growth (and declines), the effects of energy conservation 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;

•

ability to control costs and avoid cost overruns during the development and construction of facilities, which include the development and construction of facilities with designs that have not been finalized or previously constructed, including changes in labor costs and productivity factors, adverse weather conditions, shortages and inconsistent quality of equipment, materials, and labor, contractor or supplier delay or non-performance under construction or other agreements, delays associated with start-up activities, including major equipment failure, system integration, and operations, and/or unforeseen engineering problems;

•	ability to construct facilities in accordance with the requirements of permits and licenses and to satisfy any operational and environmental performance standards, including the requirements of tax credits and other incentives;

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

•	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 actions relating to proposed securitization, Mississippi PSC approval of Mississippi Power's proposed rate recovery plan, as ultimately amended, which includes the ability to complete the proposed sale of an interest in the Kemper IGCC to SMEPA, the ability to utilize bonus depreciation, which currently requires that the Kemper IGCC be placed in service in 2014, and satisfaction of requirements to utilize investment tax credits and grants;

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•	Mississippi PSC review of the prudence of Kemper IGCC costs;

•	the outcome of any legal or regulatory proceedings regarding the Mississippi PSC's issuance of the CPCN for the Kemper IGCC, the settlement agreement between Mississippi Power and the Mississippi PSC, or the State of Mississippi legislation designed to enhance the Mississippi PSC's authority to facilitate development and construction of baseload generation in the State of Mississippi;

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

•	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 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 terrorist incidents and the threat of terrorist incidents, including cyber intrusion;

•	interest rate fluctuations and financial market conditions and the results of financing efforts, including Southern Company's and its subsidiaries' credit ratings;

•	the impacts of any potential U.S. credit rating downgrade or other sovereign financial issues, including impacts on interest rates, access to capital markets, impacts on 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 and its subsidiaries to obtain additional generating capacity at competitive prices;

•	catastrophic events such as fires, earthquakes, explosions, floods, hurricanes, 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 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 filed by the registrants from time to time with the SEC.

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Item 1.	BUSINESS

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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 of new transmission facilities.

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•	operator error or failure of equipment or processes, particularly with older generating facilities;

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

•	labor disputes;

•	terrorist attacks;

•	fuel or material supply interruptions;

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

•	implementation of technologies with which the Southern Company system is developing experience;

•	information technology system failure;

•	cyber intrusion; and

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

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

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

•	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 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 United States;

•	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 a natural disaster.

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•	any acquisitions would result in an increase in income or provide an adequate return of capital or other anticipated benefits;

•	any acquisitions would be successfully integrated into the acquiring company’s operations and internal controls;

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•	the due diligence conducted prior to an acquisition would uncover situations that could result in financial or legal exposure or that the acquiring company will appropriately quantify the exposure from known risks;

•	any disposition would not result in decreased earnings, revenue, or cash flow;

•	use of cash for acquisitions would not adversely affect cash available for capital expenditures and other uses; or

•	any dispositions, investments, or acquisitions would not have a material adverse effect on the liquidity, results of operations, or financial condition of Southern Company or its subsidiaries.

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

•	labor costs;

•	varied productivity and production;

•	work stoppages;

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

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

•	delays associated with start-up activities, including major equipment failure, system integration, and operations, and/or unforeseen engineering problems;

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

•	the outcome of legal challenges to regulatory approvals;

•	failure to construct in accordance with licensing requirements;

•	continued public and policymaker support for such projects;

•	adverse weather conditions;

•	other unforeseen engineering 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 used in the generation facilities of the traditional operating companies and Southern Power, including associated transportation costs, and

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

•	liquidity in the general wholesale electricity market;

•	weather conditions impacting demand for electricity;

•	seasonality;

•	transmission or transportation constraints or inefficiencies;

•	availability of competitively priced alternative energy sources;

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

•	the financial condition of market participants;

•	the economy in the service territory, the nation, and worldwide, including the impact of economic conditions on demand for electricity and the demand for fuels;

•	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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•	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 such as dividend tax rates;

•	market prices for electricity and gas;

•	terrorist attacks or threatened attacks on Southern Company'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

•	established a new governance team focused on accounting, legal, and regulatory affairs that meets regularly with the Kemper IGCC project and construction teams and provides further oversight around disclosures of the Kemper IGCC cost estimating process and schedule;

•	re-emphasized and enhanced communication across functional areas and departments; and

•	applied appropriate performance management actions.

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Item 9B.	OTHER INFORMATION

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1.	The estimated probable losses of $729 million after-tax, or $0.83 per share, relating to Mississippi Power's construction of the Kemper IGCC. See RESULTS OF OPERATIONS – "Estimated Loss on Kemper IGCC" and Note 3 to the financial statements under "Integrated Coal Gasification Combined Cycle" for additional information.

2.	The $16 million after-tax, or $0.02 per share, charge related to the restructuring of a leveraged lease investment that was completed on March 1, 2013. See RESULTS OF OPERATIONS – "Other Business Activities – Other Income (Expense), Net" for additional information.

3.	Insurance settlement proceeds of $12 million after-tax, or $0.02 per share, related to the March 2009 litigation settlement with MC Asset Recovery, LLC. See RESULTS OF OPERATIONS – "Other Business Activities – Other Operations and Maintenance Expenses" and Note 3 to the financial statements under "Insurance Recovery" for additional information.

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•	Eliminate the provision of Rate RSE establishing an allowed range of ROE.

•	Eliminate the provision of Rate RSE limiting Alabama Power's capital structure to an allowed equity ratio of 45%.

•	Replace these two provisions with a provision that establishes rates based upon an allowed weighted cost of equity (WCE) range of 5.75% to 6.21%, with an adjusting point of 5.98%. If calculated under the previous Rate RSE provisions, the resulting WCE would range from 5.85% to 6.53%, with an adjusting point of 6.19%.

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•	Provide eligibility for a performance-based adder of seven basis points, or 0.07%, to the WCE adjusting point if Alabama Power (i) has an "A" credit rating equivalent with at least one of the recognized rating agencies or (ii) is in the top one-third of a designated customer value benchmark survey.

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•	Effective January 1, 2015 and 2016, the traditional base tariff rates will increase by an estimated $101 million and $36 million, respectively, to recover additional generation capacity-related costs;

•	Effective January 1, 2015 and 2016, the ECCR tariff will increase by an estimated $76 million and $131 million, respectively, to recover additional environmental compliance costs;

•	Effective January 1, 2015, the DSM tariffs will increase by an estimated $6 million and decrease by an estimated $1 million effective January 1, 2016; and

•	The MFF tariff will increase consistent with these adjustments.

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(a)	No credit arrangements expire in 2017.

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(a)	Excludes notes payable related to other energy service contracts of $5 million and $6 million at December 31, 2012 and 2011, respectively.

(b)	Average and maximum amounts are based upon daily balances during the twelve-month periods ended December 31, 2013, 2012, and 2011.

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(a)

All amounts are reflected based on final maturity dates. Southern Company and its subsidiaries plan to continue 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, 2014, as reflected in the statements of capitalization. Fixed rates include, where applicable, the effects of interest rate derivatives employed to manage interest rate risk. Long-term debt excludes capital lease amounts (shown separately).

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

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

(f)

The Southern Company system provides estimated capital expenditures for a three-year period, including capital expenditures and compliance costs associated with environmental regulations. Estimates reflect the proposed sale of 15% of the Kemper IGCC to SMEPA. See Note 3 to the financial statements under "Integrated Coal Gasification Combined Cycle" for additional information. These amounts exclude contractual purchase commitments for nuclear fuel and capital expenditures covered under long-term service agreements which are reflected separately. At December 31, 2013, 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.

(g)

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, 2013.

(h)

Estimated minimum long-term obligations for various PPA purchases from gas-fired, biomass, and wind-powered facilities. A total of $1.3 billion of biomass PPAs is contingent upon the counterparty meeting specified contract dates for posting collateral and commercial operation. See Note 3 to the financial statements under "Retail Regulatory Matters – Georgia Power – Renewables Development" for additional information.

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

(j)	Projections of nuclear decommissioning trust fund contributions are based on the 2010 ARP for 2014 and on the 2013 ARP thereafter for Georgia Power. See Note 1 to the financial statements under "Nuclear Decommissioning" for additional information.

(k)

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 plan during the next three years. Amounts presented represent estimated benefit payments for the nonqualified pension plans, estimated non-trust benefit payments for the other postretirement benefit plans, and estimated contributions to the other postretirement benefit plan trusts, all of which will be made from corporate assets of 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 legislative and regulatory initiatives regarding deregulation and restructuring of the electric utility industry, environmental laws including regulation of water, coal combustion residuals, and emissions of sulfur, nitrogen, carbon, soot, particulate matter, hazardous air pollutants, including mercury, and other substances, and also changes in tax and other laws and regulations to which Southern Company and its subsidiaries are subject, as well as changes in application of existing laws and regulations;

•	current and future litigation, regulatory investigations, proceedings, or inquiries, including the pending EPA civil actions against certain Southern Company subsidiaries, FERC matters, and Internal Revenue Service and state tax audits;

•	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, including those relating to weather, the general economy and recovery from the recent recession, population and business growth (and declines), the effects of energy conservation 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;

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ability to control costs and avoid cost overruns during the development and construction of facilities, which include the development and construction of facilities with designs that have not been finalized or previously constructed, including changes in labor costs and productivity factors, adverse weather conditions, shortages and inconsistent quality of equipment, materials, and labor, contractor or supplier delay or non-performance under construction or other agreements, delays associated with start-up activities, including major equipment failure, system integration, and operations, and/or unforeseen engineering problems;

•	ability to construct facilities in accordance with the requirements of permits and licenses and to satisfy any operational and environmental performance standards, including the requirements of tax credits and other incentives;

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

•	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 actions relating to proposed securitization, Mississippi PSC approval of Mississippi Power's proposed rate recovery plan, as ultimately amended, which includes the ability to complete the proposed sale of an interest in the Kemper IGCC to SMEPA, the ability to utilize bonus depreciation, which currently requires that the Kemper IGCC be placed in service in 2014, and satisfaction of requirements to utilize investment tax credits and grants;

•	Mississippi PSC review of the prudence of Kemper IGCC costs;

•	the outcome of any legal or regulatory proceedings regarding the Mississippi PSC's issuance of the CPCN for the Kemper IGCC, the settlement agreement between Mississippi Power and the Mississippi PSC, or the State of Mississippi

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

•	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 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 terrorist incidents and the threat of terrorist incidents, including cyber intrusion;

•	interest rate fluctuations and financial market conditions and the results of financing efforts, including Southern Company's and its subsidiaries' credit ratings;

•	the impacts of any potential U.S. credit rating downgrade or other sovereign financial issues, including impacts on interest rates, access to capital markets, impacts on 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 and its subsidiaries to obtain additional generating capacity at competitive prices;

•	catastrophic events such as fires, earthquakes, explosions, floods, hurricanes, 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 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 Southern Company from time to time with the SEC.

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*	Integrated coal gasification combined cycle electric generating plant located in Kemper County, Mississippi (Kemper IGCC).

(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 70 years. Asset retirement and removal assets and liabilities will be settled and trued up following completion of the related activities. At December 31, 2013, other cost of removal obligations included $43 million that will be amortized over the three-year period from January 2014 through December 2016 in accordance with Georgia Power's Alternate Rate Plan for the years 2014 through 2016 (2013 ARP). See Note 3 under "Retail Regulatory Matters" for additional information.

(b)	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.

(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 appropriate state PSCs over periods generally not exceeding 10 years.

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

(f)

Comprised of numerous immaterial components including storm damage reserves, nuclear and generating plant outage costs, property taxes, post-retirement benefits, generation site selection/evaluation costs, power purchase agreement (PPA) capacity, demand side management cost deferrals, regulatory deferrals, building leases, net book value of retired generating units, Plant Daniel Units 3 and 4 regulatory assets, and other miscellaneous assets. These costs are recorded and recovered or amortized as approved by the appropriate state PSC over periods generally not exceeding, as applicable, 10 years or over the remaining life of the asset but not beyond 2031.

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

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

(i)	Recovered and amortized as approved or accepted by the appropriate state PSC over the life of the contract.

(j)	Recovered and amortized as approved by the appropriate state PSCs over periods not exceeding 15 years.

(k)	For additional information, See Note 3 under "Integrated Coal Gasification Combined Cycle."

(l)

Comprised of immaterial components including over recovered regulatory clause revenues, state income tax credits, fuel-hedging liabilities, mine reclamation and remediation liabilities, PPA credits, and other liabilities that are recorded and recovered or amortized as approved by the appropriate state PSCs generally over periods not exceeding 10 years, except for PPA credits that are recovered over the life of the PPA for periods up to 14 years.

(m)	Costs associated with construction of environmental controls that will not be completed as a result of unit retirements and amortized over nine years in accordance with the 2013 ARP.

(n)	Recovered over the life of the PPA for periods up to 14 years.

(o)	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 energy cost recovery clause.

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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.

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•	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.

•	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.

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Real estate investments and private equity. Investments in private equity and real estate are generally classified as Level 3 as the underlying assets typically do not have observable inputs. The fund manager values the assets using various inputs and techniques depending on the nature of the underlying investments. In the case of private equity, techniques may include purchase multiples for comparable transactions, comparable public company trading multiples, and discounted cash flow analysis. Real estate managers generally use prevailing market capitalization rates, recent sales of comparable investments, and independent third-party appraisals to value underlying real estate investments. The fair value of partnerships is determined by aggregating the value of the underlying assets.

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•	Eliminate the provision of Rate RSE establishing an allowed range of ROE.

•	Eliminate the provision of Rate RSE limiting Alabama Power's capital structure to an allowed equity ratio of 45%.

•	Replace these two provisions with a provision that establishes rates based upon an allowed weighted cost of equity (WCE) range of 5.75% to 6.21%, with an adjusting point of 5.98%. If calculated under the previous Rate RSE provisions, the resulting WCE would range from 5.85% to 6.53%, with an adjusting point of 6.19%.

•	Provide eligibility for a performance-based adder of seven basis points, or 0.07%, to the WCE adjusting point if Alabama Power (i) has an "A" credit rating equivalent with at least one of the recognized rating agencies or (ii) is in the top one-third of a designated customer value benchmark survey.

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•	Effective January 1, 2015 and 2016, the traditional base tariff rates will increase by an estimated $101 million and $36 million, respectively, to recover additional generation capacity-related costs;

•	Effective January 1, 2015 and 2016, the ECCR tariff will increase by an estimated $76 million and $131 million, respectively, to recover additional environmental compliance costs;

•	Effective January 1, 2015, the DSM tariffs will increase by an estimated $6 million and decrease by an estimated $1 million effective January 1, 2016; and

•	The MFF tariff will increase consistent with these adjustments.

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(a)	The 2012 MPSC CPCN Order approved a construction cost cap of up to $2.88 billion, net of the DOE Grants and excluding the Cost Cap Exceptions.

(b)	Mississippi Power’s original estimate included recovery of financing costs during construction which was not approved by the Mississippi PSC in June 2012 as described in "Rate Recovery of Kemper IGCC Costs."

(c)	The 2012 MPSC CPCN Order approved deferral of non-capital Kemper IGCC-related costs during construction as described in "Rate Recovery of Kemper IGCC Costs – Regulatory Assets."

(d)	The 2010 Project Estimate is the certificated cost estimate adjusted to include the certificated estimate for the CO2 pipeline facilities which was approved in 2011 by the Mississippi PSC.

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(a)	No credit arrangements expire in 2017.

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

(2)	Calculated Georgia Power's incremental borrowing rate at the inception of the leases.

(3)	When the PPAs with non-affiliates begin in 2015, Georgia Power will recognize capital lease assets and capital lease obligations totaling $333 million, equal to the lesser of the present value of the net minimum lease payments or the estimated fair value of the leased property.

(4)	A total of $1.3 billion of biomass PPAs included under the non-affiliate capital and operating leases is contingent upon the counterparty meeting specified contract dates for posting collateral and commercial operation.

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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)	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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(a)	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 operating companies' 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 and 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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•	Eliminate the provision of Rate RSE establishing an allowed range of ROE.

•	Eliminate the provision of Rate RSE limiting the Company's capital structure to an allowed equity ratio of 45%.

•	Replace these two provisions with a provision that establishes rates based upon an allowed weighted cost of equity (WCE) range of 5.75% to 6.21%, with an adjusting point of 5.98%. If calculated under the previous Rate RSE provisions, the resulting WCE would range from 5.85% to 6.53%, with an adjusting point of 6.19%.

•	Provide eligibility for a performance-based adder of seven basis points, or 0.07%, to the WCE adjusting point if the Company (i) has an "A" credit rating equivalent with at least one of the recognized rating agencies or (ii) is in the top one-third of a designated customer value benchmark survey.

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(a)	No credit arrangements expire in 2016 or 2017.

(a)	Average and maximum amounts are based upon daily balances during the twelve-month periods ended December 31, 2013, 2012, and 2011.

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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.

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(a)

All amounts are reflected based on final maturity dates. The Company plans to continue 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, 2014, 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)	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 three-year period, including capital expenditures and compliance costs associated with existing environmental regulations. Such amounts exclude the Company's estimates of potential incremental environmental compliance investment to comply with proposed water and coal combustion residuals rules, which are approximately $3 million, $9 million, and $143 million for 2014, 2015, and 2016, respectively. These amounts also exclude contractual purchase commitments for nuclear fuel and capital expenditures covered under long-term service agreements, which are reflected separately. At December 31, 2013, 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, 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, 2013.

(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 legislative and regulatory initiatives regarding deregulation and restructuring of the electric utility industry, environmental laws including regulation of water, coal combustion residuals, and emissions of sulfur, nitrogen, carbon, soot, particulate matter, hazardous air pollutants, including mercury, and other substances, and also changes in tax and other laws and regulations to which the Company is subject, as well as changes in application of existing laws and regulations;

•	current and future litigation, regulatory investigations, proceedings, or inquiries, including FERC matters, pending EPA civil action against the Company, and Internal Revenue Service and state tax audits;

•	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 recent recession, population and business growth (and declines), the effects of energy conservation 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;

•	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 operational and 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, or 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 terrorist incidents and the threat of terrorist incidents, including cyber intrusion;

•	interest rate fluctuations and financial market conditions and the results of financing efforts, including the Company's credit ratings;

•	the impacts of any potential U.S. credit rating downgrade or other sovereign financial issues, including impacts on interest rates, access to capital markets, impacts on currency exchange rates, counterparty performance, and the economy in general;

•	the ability of the Company to obtain additional generating capacity at competitive prices;

•	catastrophic events such as fires, earthquakes, explosions, floods, tornadoes, hurricanes, 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)	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 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 ten years.

(e)	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 energy cost recovery clause.

(f)	Comprised of components including generation site selection/evaluation costs, PPA capacity, 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 other liabilities. 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 $20 million for 2013 and $21 million for 2012 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 2015 through 2017.

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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.

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•	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 and private equity. Investments in private equity and real estate are generally classified as Level 3 as the underlying assets typically do not have observable inputs. The fund manager values the assets using various inputs and techniques depending on the nature of the underlying investments. In the case of private equity, techniques may include purchase multiples for comparable transactions, comparable public company trading multiples, and discounted cash flow analysis. Real estate managers generally use prevailing market capitalization rates, recent sales of comparable investments, and independent third-party appraisals to value underlying real estate investments. The fair value of partnerships is determined by aggregating the value of the underlying assets.

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•	Eliminate the provision of Rate RSE establishing an allowed range of ROE.

•	Eliminate the provision of Rate RSE limiting the Company's capital structure to an allowed equity ratio of 45%.

•	Replace these two provisions with a provision that establishes rates based upon an allowed weighted cost of equity (WCE) range of 5.75% to 6.21%, with an adjusting point of 5.98%. If calculated under the previous Rate RSE provisions, the resulting WCE would range from 5.85% to 6.53%, with an adjusting point of 6.19%.

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•	Provide eligibility for a performance-based adder of seven basis points, or 0.07%, to the WCE adjusting point if the Company (i) has an "A" credit rating equivalent with at least one of the recognized rating agencies or (ii) is in the top one-third of a designated customer value benchmark survey.

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

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

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(a)	No credit arrangements expire in 2016 or 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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(a)	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.

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

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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.

•	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 and 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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*

In the first quarter 2012, the Company began using new actual advanced meter data to compute unbilled revenues. The weather-adjusted KWH sales variances shown above reflect an adjustment to the estimated allocation of the Company's unbilled January 2012 KWH sales among customer classes that is consistent with the actual allocation in 2013. Without this adjustment, 2013 weather-adjusted residential KWH sales decreased 0.4% as compared to 2012 while weather-adjusted commercial KWH sales increased 0.2% as compared to 2012.

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•	Effective January 1, 2015 and 2016, the traditional base tariff rates will increase by an estimated $101 million and $36 million, respectively, to recover additional generation capacity-related costs;

•	Effective January 1, 2015 and 2016, the ECCR tariff will increase by an estimated $76 million and $131 million, respectively, to recover additional environmental compliance costs;

•	Effective January 1, 2015, the DSM tariffs will increase by an estimated $6 million and decrease by an estimated $1 million effective January 1, 2016; and

•	The MFF tariff will increase consistent with these adjustments.

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(a)	No credit arrangements expire in 2014, 2015, or 2017.

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(a)	Excludes notes payable related to other energy service contracts of $2 million in 2012 and 2011.

(b)	Average and maximum amounts are based upon daily balances during the twelve-month periods ended December 31, 2013, 2012, and 2011.

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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.

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(a)

All amounts are reflected based on final maturity dates. The Company plans to continue 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, 2014, 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)	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 three-year period, including capital expenditures and compliance costs 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 separately. At December 31, 2013, 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.

(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, 2013.

(g)

Estimated minimum long-term obligations for various PPA purchases from gas-fired, biomass, and wind-powered facilities. A total of $1.3 billion of biomass PPAs is contingent upon the counterparty meeting specified contract dates for posting collateral and commercial operation. See Note 3 to the financial statements under "Retail Regulatory Matters – Renewables Development" 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 are based on the 2010 ARP for 2014 and on the 2013 ARP thereafter. 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 legislative and regulatory initiatives regarding deregulation and restructuring of the electric utility industry, environmental laws including regulation of water, coal combustion residuals, and emissions of sulfur, nitrogen, carbon, soot, particulate matter, hazardous air pollutants, including mercury, and other substances, and also changes in tax and other laws and regulations to which the Company is subject, as well as changes in application of existing laws and regulations;

•	current and future litigation, regulatory investigations, proceedings, or inquiries, including the pending EPA civil action against the Company and Internal Revenue Service and state tax audits;

•	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 recent recession, population and business growth (and declines), the effects of energy conservation 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;

•

ability to control costs and avoid cost overruns during the development and construction of facilities, which include the development and construction of facilities with designs that have not been finalized or previously constructed, including changes in labor costs and productivity factors, adverse weather conditions, shortages and inconsistent quality of equipment, materials, and labor, contractor or supplier delay or non-performance under construction or other agreements, delays associated with start-up activities, including major equipment failure, system integration, and operations, and/or unforeseen engineering problems;

•	ability to construct facilities in accordance with the requirements of permits and licenses and to satisfy any operational and environmental performance standards, including the requirements of tax credits and other incentives;

•	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;

•	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, or 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 terrorist incidents and the threat of terrorist incidents, including cyber intrusion;

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•	interest rate fluctuations and financial market conditions and the results of financing efforts, including the Company's credit ratings;

•	the impacts of any potential U.S. credit rating downgrade or other sovereign financial issues, including impacts on interest rates, access to capital markets, impacts on currency exchange rates, counterparty performance, and the economy in general, as well as potential impacts on benefits of the DOE loan guarantees;

•	the ability of the Company to obtain additional generating capacity at competitive prices;

•	catastrophic events such as fires, earthquakes, explosions, floods, hurricanes, 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)

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. At December 31, 2013, other cost of removal obligations included $43 million that will be amortized over the three-year period of January 2014 through December 2016 in accordance with the Company's Alternate Rate Plan for the years 2014 through 2016 (2013 ARP).

(c)	Recorded and recovered or amortized as approved by the Georgia PSC over periods generally not exceeding nine years.

(d)	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 39 years.

(e)	Fuel-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 through the Company's fuel cost recovery mechanism.

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

(g)	See Note 6 under "Capital Leases." Recovered over the remaining lives of the buildings through 2026.

(h)	Costs associated with construction of environmental controls that will not be completed as a result of unit retirements and amortized over nine years in accordance with the 2013 ARP.

(i)	Amortization period over original remaining life beginning October 2013 through December 2022 as approved by the Georgia PSC in the 2013 ARP.

(j)	Additional tax benefits resulting from the Georgia state income tax credit settlement that were amortized over a 21-month period that began in April 2012 and ended in December 2013, in accordance with a Georgia PSC order. See Note 5 under "Current and Deferred Income Taxes" for additional information.

(k)	Not earning a return as 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.

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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.

•	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 and private equity. Investments in private equity and real estate are generally classified as Level 3 as the underlying assets typically do not have observable inputs. The fund manager values the assets using various inputs and techniques depending on the nature of the underlying investments. In the case of private equity, techniques may include purchase multiples for comparable transactions, comparable public company trading multiples, and discounted cash flow analysis. Real estate managers generally use prevailing market capitalization rates, recent sales of comparable investments, and independent third-party appraisals to value underlying real estate investments. The fair value of partnerships is determined by aggregating the value of the underlying assets.

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•	Effective January 1, 2015 and 2016, the traditional base tariff rates will increase by an estimated $101 million and $36 million, respectively, to recover additional generation capacity-related costs;

•	Effective January 1, 2015 and 2016, the ECCR tariff will increase by an estimated $76 million and $131 million, respectively, to recover additional environmental compliance costs;

•	Effective January 1, 2015, the DSM tariffs will increase by an estimated $6 million and decrease by an estimated $1 million effective January 1, 2016; and

•	The MFF tariff will increase consistent with these adjustments.

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(a)	No credit arrangements expire in 2014, 2015, or 2017.

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

(2)	Calculated at the Company's incremental borrowing rate at the inception of the leases.

(3)	When the PPAs begin in 2015, the Company will recognize capital lease assets and capital lease obligations totaling $482 million, equal to the lesser of the present value of the net minimum lease payments or the estimated fair value of the leased property.

(4)	A total of $1.3 billion of biomass PPAs included under the non-affiliate capital and operating leases is contingent upon the counterparty meeting specified contract dates for posting collateral and commercial operation.

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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)	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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(a)	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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(a)	No credit arrangements expire in 2015, 2017, or 2018.

(a)	Excludes notes payable related to other energy service contracts of $3.2 million and $3.6 million at December 31, 2012 and 2011, respectively.

(b)	Average and maximum amounts are based upon daily balances during the twelve-month periods ended December 31, 2013, 2012, and 2011.

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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.

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(a)

All amounts are reflected based on final maturity dates. The Company plans to continue 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, 2014, 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)	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 PPAs that are accounted for as leases and are included in purchased power.

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

(f)

The Company provides estimated capital expenditures for a three-year period, including capital expenditures and compliance costs associated with environmental regulations. These amounts exclude capital expenditures covered under long-term service agreements, which are reflected in Other. At December 31, 2013, significant purchase commitments were outstanding in connection with the construction program. See FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Statutes and Regulations" for additional information.

(g)

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, 2013.

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

(i)	Includes long-term service agreements and contracts for the procurement of limestone. 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 legislative and regulatory initiatives regarding deregulation and restructuring of the electric utility industry, environmental laws including regulation of water, coal combustion residuals, and emissions of sulfur, nitrogen, carbon, soot, particulate matter, hazardous air pollutants, including mercury, and other substances, and also changes in tax and other laws and regulations to which the Company is subject, as well as changes in application of existing laws and regulations;

•	current and future litigation, regulatory investigations, proceedings, or inquiries, including the pending EPA civil action against the Company and Internal Revenue Service and state tax audits;

•	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 recent recession, population and business growth (and declines), the effects of energy conservation 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;

•	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 fuel and other cost recovery mechanisms;

•	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 terrorist incidents and the threat of terrorist incidents, including cyber intrusion;

•	interest rate fluctuations and financial market conditions and the results of financing efforts, including the Company's credit ratings;

•	the impacts of any potential U.S. credit rating downgrade or other sovereign financial issues, including impacts on interest rates, access to capital markets, impacts on currency exchange rates, counterparty performance, and the economy in general;

•	the ability of the Company to obtain additional generating capacity at competitive prices;

•	catastrophic events such as fires, earthquakes, explosions, floods, hurricanes, 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

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

(b)	Recovered and amortized over periods not exceeding 14 years.

(c)	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.

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

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

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

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

(h)	Recovered through the environmental cost recovery clause when the remediation is performed.

(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)	Recovered over the life of the PPA for periods up to 14 years.

(l)	Comprised primarily of net book value of retired meters, deferred rate case expenses, and generation site evaluation costs. These costs are recorded and recovered or amortized as approved by the Florida PSC, generally over periods not exceeding eight years, or deferred pursuant to Florida statute while the Company continues to evaluate certain potential new generating projects.

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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 and private equity. Investments in private equity and real estate are generally classified as Level 3 as the underlying assets typically do not have observable inputs. The fund manager values the assets using various inputs and techniques depending on the nature of the underlying investments. In the case of private equity, techniques may include purchase multiples for comparable transactions, comparable public company trading multiples, and discounted cash flow analysis. Real estate managers generally use prevailing market capitalization rates, recent sales of comparable investments, and independent third-party appraisals to value underlying real estate investments. The fair value of partnerships is determined by aggregating the value of the underlying assets.

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(a)	Includes net plant acquisition adjustment of $2.0 million.

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(a)	No credit arrangements expire in 2015, 2017, or 2018.

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(a)	Excludes notes payable related to other energy service contracts of $3.2 million for the period ended December 31, 2012.

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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.

•	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)	The 2012 MPSC CPCN Order approved a construction cost cap of up to $2.88 billion, net of the DOE Grants and excluding the Cost Cap Exceptions.

(b)	The Company’s original estimate included recovery of financing costs during construction which was not approved by the Mississippi PSC in June 2012 as described in "Rate Recovery of Kemper IGCC Costs."

(c)	The 2012 MPSC CPCN Order approved deferral of non-capital Kemper IGCC-related costs during construction as described in "Rate Recovery of Kemper IGCC Costs - Regulatory Assets."

(d)	The 2010 Project Estimate is the certificated cost estimate adjusted to include the certificated estimate for the CO2 pipeline facilities which was approved in 2011 by the Mississippi PSC.

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(a)	No credit arrangements expire in 2015, 2017, or 2018.

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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.

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(a)

All amounts are reflected based on final maturity dates. The Company plans to continue 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, 2014, 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 three-year period, including capital expenditures and compliance costs associated with environmental regulations. Estimates reflect the proposed sale of 15% of the Kemper IGCC to SMEPA. At December 31, 2013, 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" 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, 2013.

(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 legislative and regulatory initiatives regarding deregulation and restructuring of the electric utility industry, environmental laws including regulation of water, coal combustion residuals, and emissions of sulfur, nitrogen, carbon, soot, particulate matter, hazardous air pollutants, including mercury, and other substances, and also changes in tax and other laws and regulations to which the Company is subject, as well as changes in application of existing laws and regulations;

•	current and future litigation, regulatory investigations, proceedings, or inquiries, including FERC matters, the pending EPA civil action, and IRS and state tax audits;

•	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 recent recession, population and business growth (and declines), the effects of energy conservation 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;

•

ability to control costs and avoid cost overruns during the development and construction of facilities, which includes the development and construction of facilities with designs that have not been finalized or previously constructed, including changes in labor costs and productivity factors, adverse weather conditions, shortages and inconsistent quality of equipment, material, and labor, contractor or supplier delay or non-performance under construction or other agreements, delays associated with start-up activities, including major equipment failure, system integration, and operations, and/or unforeseen engineering problems;

•	ability to construct facilities in accordance with the requirements of permits and licenses and to satisfy any operational and environmental performance standards, including the requirements of tax credits and other incentives;

•	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;

•

actions related to cost recovery for the Kemper IGCC, including actions relating to proposed securitization, Mississippi PSC approval of the Company's proposed rate recovery plan, as ultimately amended, which includes the ability to complete the proposed sale of an interest in the Kemper IGCC to SMEPA, the ability to utilize bonus depreciation, which currently requires that the Kemper IGCC be placed in service in 2014, and satisfaction of requirements to utilize investment tax credits and grants;

•	Mississippi PSC review of the prudence of Kemper IGCC costs;

•	the outcome of any legal or regulatory proceedings regarding the Mississippi PSC's issuance of the CPCN for the Kemper IGCC, the settlement agreement between the Company and the Mississippi PSC, or the Baseload Act;

•	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;

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

•	interest rate fluctuations and financial market conditions and the results of financing efforts, including the Company's credit ratings;

•	the impacts of any potential U.S. credit rating downgrade or other sovereign financial issues, including impacts on interest rates, access to capital markets, impacts on currency exchange rates, counterparty performance, and the economy in general;

•	the ability of the Company to obtain additional generating capacity at competitive prices;

•	catastrophic events such as fires, earthquakes, explosions, floods, hurricanes, 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)	Recorded and recovered as approved by the Mississippi PSC.

(c)	Asset retirement and removal assets and liabilities and deferred income tax assets are recovered, and removal assets and deferred income tax liabilities are amortized over the related property lives, which may range up to 50 years. Asset retirement and removal assets and liabilities will be settled and trued up following completion of the related activities.

(d)	Recovered through the ad valorem tax adjustment clause over a 12-month period beginning in April of the following year. See Note 3 under "Ad Valorem Tax Adjustment" for additional information.

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

(f)	Fuel-hedging assets and liabilities are recorded over the life of the underlying hedged purchase contracts, which generally do not exceed four years. Upon final settlement, costs are recovered through the Energy Cost Management clause (ECM).

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

(h)	For additional information, see Note 3 under "Integrated Coal Gasification Combined Cycle."

(i)	For additional information, see Note 1 under "Provision for Property Damage" and Note 3 under "Retail Regulatory Matters – System Restoration Rider."

(j)	Deferred and amortized over a 10-year period beginning October 2021, as approved by the Mississippi PSC for the difference between the revenue requirement under the purchase option and the revenue requirement assuming operating lease accounting treatment for the extended term.

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

(l)	Recovered and amortized over a 10-year period beginning in 2012, as approved by the Mississippi PSC for the retail portion and a five-year period for the wholesale portion, as approved by FERC.

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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 and private equity. Investments in private equity and real estate are generally classified as Level 3 as the underlying assets typically do not have observable inputs. The fund manager values the assets using various inputs and techniques depending on the nature of the underlying investments. In the case of private equity, techniques may include purchase multiples for comparable transactions, comparable public company trading multiples, and discounted cash flow analysis. Real estate managers generally use prevailing market capitalization rates, recent sales of comparable investments, and independent third-party appraisals to value underlying real estate investments. The fair value of partnerships is determined by aggregating the value of the underlying assets.

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(a)	The 2012 MPSC CPCN Order approved a construction cost cap of up to $2.88 billion, net of the DOE Grants and excluding the Cost Cap Exceptions.

(b)	The Company’s original estimate included recovery of financing costs during construction which was not approved by the Mississippi PSC in June 2012 as described in "Rate Recovery of Kemper IGCC Costs."

(c)	The 2012 MPSC CPCN Order approved deferral of non-capital Kemper IGCC-related costs during construction as described in "Rate Recovery of Kemper IGCC Costs – Regulatory Assets."

(d)	The 2010 Project Estimate is the certificated cost estimate adjusted to include the certificated estimate for the CO2 pipeline facilities which was approved in 2011 by the Mississippi PSC.

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(a)	No credit arrangements expire in 2015, 2017, or 2018.

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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.

•	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 and 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)	Bridge agreement for requirements service agreement effective January 1, 2016.

(b)	Represents estimated average annual capacity purchases.

(c)	Includes an option which expires on February 28, 2014 to reduce the amount by 5 MWs.

(d)	This agreement is contracted with Plant Franklin from June 2015 through December 2015.

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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 hedged transaction, and the nature of the risk being hedged; and

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

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

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

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•	Future operating costs.

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(a)	Average and maximum amounts are based upon daily balances during the twelve-month periods ended December 31, 2013, 2012, and 2011.

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(a)	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. The Company plans 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 for the Plant Stanton Unit A land lease are subject to annual price escalation based on the Consumer Price Index for All Urban Consumers.

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

(e)	The Company provides estimated capital expenditures for a three-year period. Amounts represent current estimates of total expenditures, excluding capital expenditures covered under long-term service agreements.

(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, 2013.

(g)	Purchased power commitments of $36.8 million in 2014, $75.9 million in 2015-2016, $79.0 million in 2017-2018, and $124.4 million after 2018 will be resold under a third party agreement to Energy United EMC. The purchases will be resold at cost.

(h)	Includes long-term service agreements, capital leases, and operation and maintenance agreements. Long-term service agreements include price escalation based on inflation indices.

(i)	Transmission commitments are based on Southern Company'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 legislative and regulatory initiatives regarding deregulation and restructuring of the electric utility industry, environmental laws including regulation of water and emissions of sulfur, nitrogen, carbon, soot, particulate matter, hazardous air pollutants, including mercury, and other substances, and also changes in tax and other laws and regulations to which the Company is subject, as well as changes in application of existing laws and regulations;

•	current and future litigation, regulatory investigations, proceedings, or inquiries, including Internal Revenue Service and state tax audits;

•	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 recent recession, population and business growth (and declines), the effects of energy conservation 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;

•	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 operational and environmental performance standards, including the requirements of tax credits and other incentives;

•	advances in technology;

•	state and federal rate regulations;

•	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 terrorist incidents and the threat of terrorist incidents, including cyber intrusion;

•	interest rate fluctuations and financial market conditions and the results of financing efforts, including the Company's credit ratings;

•	the impacts of any potential U.S. credit rating downgrade or other sovereign financial issues, including impacts on interest rates, access to capital markets, impacts on currency exchange rates, counterparty performance, and the economy in general;

•	the ability of the Company to obtain additional generating capacity at competitive prices;

•	catastrophic events such as fires, earthquakes, explosions, floods, hurricanes, 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

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•	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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•	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.

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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. The need to use unobservable inputs would typically apply to long-term energy-related derivative contracts and generally results from the nature of the energy industry, as each participant forecasts its own power supply and demand and those of other participants, which directly impact the valuation of each unique contract.

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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 other comprehensive income (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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(1)	No position other than director.

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Item 11.	EXECUTIVE COMPENSATION

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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 the companies in Gulf Power’s industry;

•	Motivate and 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 of an independent compensation consultant by the Compensation Committee, Pay Governance LLC, 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 ongoing perquisites and no income tax gross-ups for the Chief Executive Officer except on certain relocation-related benefits.

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•	Business unit performance, which includes return on equity (ROE) or net income, and operational performance, compared to target levels established early in the year, and EPS determine the actual payouts under the short-term (annual) performance-based compensation program (Performance Pay Program).

•	Southern Company Common Stock (Common Stock) price changes result in higher or lower ultimate values of stock options.

•	Southern Company total shareholder return compared to those of industry peers leads to higher or lower payouts under the Performance Share Program (performance shares).

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

•	EPS is defined as Southern Company’s net income from ongoing business activities divided by average shares outstanding during the year. The EPS performance measure is applicable to all participants in the Performance Pay Program.

•	For Southern Company’s traditional operating companies, including Gulf Power, the business unit financial performance goal is ROE, which is defined as the traditional operating company’s net income divided by average equity for the year. For Southern Power, the business unit financial performance goal is net income.

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For Southern Company’s traditional operating companies, including Gulf Power, operational goals are safety, customer satisfaction, plant availability, transmission and distribution system reliability, and culture. For the nuclear operating company, Southern Nuclear, operational goals are safety, plant operations, and culture. Each of these operational goals is explained in more detail under Goal Details below. The level of achievement for each operational goal is determined according to the respective performance schedule, and the total operational goal performance is determined by the weighted average result. Each business unit has its own operational goals.

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•	Discount rate for the Pension Plan was increased to 5.05% as of December 31, 2013 from 4.30% as of December 31, 2012.

•	Discount rate for the supplemental pension plans was increased to 4.50% as of December 31, 2013 from 3.70% as of December 31, 2012.

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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 upon leaving the board;

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

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

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(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)	Consists of reimbursement for taxes on imputed income associated with gifts and activities provided to attendees at Southern Company system-sponsored events and group life insurance.

(4)	Messrs. MacQueen and Rehwinkel were elected to Gulf Power's board of directors effective July 25, 2013 and November 21, 2013, respectively.

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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.

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(1)	Includes shares available for future issuance under the Omnibus Incentive Compensation Plan (28,421,692) and the Outside Directors Stock Plan (1,111,547).

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

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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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