~~Proposed Sale of Undivided Interest to SMEPA~~

In 2010, Mississippi Power and SMEPA entered into an asset purchase agreement (APA) whereby SMEPA agreed to purchase a 17.5% undivided interest in the Kemper IGCC. In 2012, the Mississippi PSC approved the sale and transfer of the 17.5% undivided interest in the Kemper IGCC to SMEPA. Later in 2012, Mississippi Power and SMEPA signed an amendment to the APA whereby SMEPA reduced its purchase commitment percentage from a 17.5% to a 15% undivided interest in the Kemper IGCC. In March 2013, Mississippi Power and SMEPA signed an amendment to the APA whereby they agreed to amend a 2011 power supply agreement between the parties to reduce the capacity amounts to be received by SMEPA by half (approximately 75 MWs) at the sale and transfer of the undivided interest in the Kemper IGCC to SMEPA. Capacity revenues under the 2011 power supply agreement were $4 million in the first quarter 2015 and $17 million in 2014.

By letter agreement dated October 6, 2014, Mississippi Power and SMEPA agreed in principle on certain issues related to SMEPA's proposed purchase of a 15% undivided interest in the Kemper IGCC. The parties agreed to further amend the APA as follows: (1) Mississippi Power agreed to cap at $2.88 billion the portion of the purchase price payable for development and construction costs, net of the Cost Cap Exceptions, title insurance reimbursement, and AFUDC and/or carrying costs through the Closing Commitment Date (defined below); (2) SMEPA agreed to close the purchase within 180 days after the date of the execution of the amended APA or before the Kemper IGCC in-service date, whichever occurs first (Closing Commitment Date), subject only to satisfaction of certain conditions; and (3) AFUDC and/or carrying costs will continue to be accrued on the capped development and construction costs, the Cost Cap Exceptions, and any operating costs, net of revenues until the amended APA is executed by both parties, and thereafter AFUDC and/or carrying costs and payment of interest on SMEPA's deposited money will be suspended and waived provided closing occurs by the Closing Commitment Date. The letter agreement also provided for certain post-closing adjustments to address any differences between the actual and the estimated amounts of post-in-service date costs (both expenses and capital) and revenue credits for those portions of the Kemper IGCC previously placed in service.

By letter dated December 18, 2014, SMEPA notified Mississippi Power that SMEPA decided not to extend the December 31, 2014 estimated closing date in the APA or revise the APA to include the contemplated amendments; however, both parties agree that the APA will remain in effect until closing or until either party gives notice of termination.

The closing of this transaction is also conditioned upon execution of a joint ownership and operating agreement, the absence of material adverse effects, receipt of all construction permits, and appropriate regulatory approvals, as well as SMEPA's receipt of Rural Utilities Service (RUS) funding. In 2012, SMEPA received a conditional loan commitment from RUS for the purchase.

In 2012, in January 2014, and in October 2014, Mississippi Power received $150 million, $75 million, and $50 million, respectively, of interest-bearing refundable deposits from SMEPA to be applied to the purchase. While the expectation is that these amounts will be applied to the purchase price at closing, Mississippi Power would be required to refund the deposits upon the termination of the APA or within 15 days of a request by SMEPA for a full or partial refund. Accordingly, the deposits have been presented as a current liability in the balance sheet and as financing proceeds in the statement of cash flow. Southern Company has agreed to guarantee the obligations of Mississippi Power with respect to any refund of the deposits to SMEPA.

~~The ultimate outcome of these matters cannot be determined at this time.~~

~~Income Tax Matters~~

~~See MANAGEMENT'S DISCUSSION AND ANALYSIS~~ – ~~FUTURE EARNINGS POTENTIAL~~ – ~~"Income Tax Matters" of Mississippi Power in Item 7 of the Form 10-K for additional information.~~

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~~FINANCIAL CONDITION AND RESULTS OF OPERATIONS~~

~~Section 174 Research and Experimental Deduction~~

Southern Company, on behalf of Mississippi Power, reflected deductions for research and experimental (R&E) expenditures related to the Kemper IGCC in its federal income tax calculations for 2013 and 2014. Due to the uncertainty related to this tax position, Mississippi Power had unrecognized tax benefits totaling approximately $211 million at March 31, 2015. See Note 5 to the financial statements of Mississippi Power under "Unrecognized Tax Benefits" in Item 8 of the Form 10-K and Notes (B) and (G) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" and "Unrecognized Tax Benefits," respectively, herein for additional information. The ultimate outcome of this tax matter cannot be determined at this time.

Other Matters

Mississippi Power is involved in various other matters being litigated and regulatory matters that could affect future earnings. In addition, Mississippi Power is subject to certain claims and legal actions arising in the ordinary course of business. Mississippi Power's business activities are subject to extensive governmental regulation related to public health and the environment, such as regulation of air emissions and water discharges. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements, such as air quality and water standards, has occurred throughout the U.S. This litigation has included claims for damages alleged to have been caused by CO₂ and other emissions, CCR, and alleged exposure to hazardous materials, and/or requests for injunctive relief in connection with such matters.

The ultimate outcome of such pending or potential litigation against Mississippi Power cannot be predicted at this time; however, for current proceedings not specifically reported in Note (B) to the Condensed Financial Statements herein or in Note 3 to the financial statements of Mississippi Power in Item 8 of the Form 10-K, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on Mississippi Power's financial statements. See Note (B) to the Condensed Financial Statements herein for a discussion of various other contingencies, regulatory matters, and other matters being litigated which may affect future earnings potential.

The SEC is conducting a formal investigation of Southern Company and Mississippi Power concerning the estimated costs and expected in-service date of the Kemper IGCC. Southern Company and Mississippi Power believe the investigation is focused primarily on periods subsequent to 2010 and on accounting matters, disclosure controls and procedures, and internal controls over financial reporting associated with the Kemper IGCC. See ACCOUNTING POLICIES – "Application of Critical Accounting Policies and Estimates" herein for additional information on the Kemper IGCC estimated construction costs and expected in-service date. Southern Company and Mississippi Power are cooperating fully with the SEC. The ultimate outcome of this matter cannot be determined at this time; however, it is not expected to have a material impact on the financial statements of Mississippi Power.

ACCOUNTING POLICIES

Application of Critical Accounting Policies and Estimates

Mississippi Power prepares its financial statements in accordance with GAAP. Significant accounting policies are described in Note 1 to the financial statements of Mississippi Power in Item 8 of the Form 10-K. In the application of these policies, certain estimates are made that may have a material impact on Mississippi Power's results of operations and related disclosures. Different assumptions and measurements could produce estimates that are significantly different from those recorded in the financial statements. See MANAGEMENT'S DISCUSSION AND ANALYSIS – ACCOUNTING POLICIES – "Application of Critical Accounting Policies and Estimates" of Mississippi Power in Item 7 of the Form 10-K for a complete discussion of Mississippi Power's critical accounting policies and estimates related to Electric Utility Regulation, Asset Retirement Obligations, Contingent Obligations, Unbilled Revenues, Pension and Other Postretirement Benefits, and AFUDC.

Kemper IGCC Estimated Construction Costs, Project Completion Date, and Rate Recovery

During ~~2015,~~2016, Mississippi Power further revised its cost estimate to complete construction and start-up of the Kemper IGCC to an amount that exceeds the $2.88 billion cost cap, net of the Initial DOE Grants and excluding the Cost Cap Exceptions. Mississippi Power does not intend to seek any rate recovery ~~or any joint owner contributions~~ for any costs related to the construction of the Kemper IGCC that exceed the $2.88 billion cost cap, net of the Initial DOE Grants and excluding the Cost Cap Exceptions.

As a result of the revisions to the cost estimate, Mississippi Power recorded total pre-tax charges to income for the estimated probable losses on the Kemper IGCC of $53 million ($33 million after tax) in the first quarter 2016, $183 million ($113 million after tax) in the fourth quarter 2015, $150 million ($93 million after tax) in the third

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quarter 2015, $23 million ($14 million after tax) in the second quarter 2015, $9 million ($6 million after tax) in the first quarter 2015, $70 million ($43 million after tax) in the fourth quarter 2014, $418 million ($258 million after tax) in the third

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~~MANAGEMENT'S DISCUSSION AND ANALYSIS OF~~

~~FINANCIAL CONDITION AND RESULTS OF OPERATIONS~~

quarter 2014, $380 million ($235 million after tax) in the first quarter 2014, $40 million ($25 million after tax) in the fourth quarter 2013, $150 million ($93 million after tax) in the third quarter 2013, $450 million ($278 million after tax) in the second quarter 2013, $462 million ($285 million after tax) in the first quarter 2013, and $78 million ($48 million after tax) in the fourth quarter 2012. In the aggregate, Mississippi Power has incurred charges of ~~$2.06~~$2.47 billion ($~~1.27~~1.52 billion after tax) as a result of changes in the cost estimate above the cost cap for the Kemper IGCC through March 31, ~~2015.~~2016.

Mississippi Power has experienced, and may continue to experience, material changes in the cost estimate for the Kemper IGCC. In subsequent periods, any further changes in the estimated costs to complete construction and start-up of the Kemper IGCC subject to the $2.88 billion cost cap, net of the Initial DOE Grants and excluding the Cost Cap Exceptions, will be reflected in Mississippi Power's statements of ~~operations~~income and these changes could be material. Any further cost increases and/or extensions of the in-service date with respect to the Kemper IGCC may result from factors including, but not limited to, labor costs and productivity, adverse weather conditions, shortages and inconsistent quality of equipment, materials, and labor, contractor or supplier delay, non-performance under ~~construction~~operating or other agreements, operational readiness, including specialized operator training and required site safety programs, unforeseen engineering or design problems, start-up activities for this first-of-a-kind technology (including, but not limited to, major equipment failure and system integration), and/or operational performance (including, but not limited to, additional costs to satisfy any operational parameters ultimately adopted by the Mississippi PSC).

Mississippi Power's revised cost estimate includes costs through ~~March 31,~~September 30, 2016. Any ~~further~~ extension of the in-service date beyond September 30, 2016 is currently estimated to result in additional base costs of approximately $25 million to ~~$30~~$35 million per month, which includes maintaining necessary levels of start-up labor, materials, and fuel, as well as operational resources required to execute start-up and commissioning activities. However, additional costs may be required for remediation of any further equipment and/or design issues identified. Any ~~further~~ extension of the in-service date with respect to the Kemper IGCC beyond September 30, 2016 would also increase costs for the Cost Cap Exceptions, which are not subject to the $2.88 billion cost cap established by the Mississippi PSC. These costs include AFUDC, which is currently estimated to total approximately ~~$13~~$14 million per month, as well as carrying costs and operating expenses on Kemper IGCC assets placed in service and consulting ~~fees~~ and legal fees ~~which are being deferred as regulatory assets and are estimated to total~~of approximately $6$2 million per month.

Given the significant judgment involved in estimating the future costs to complete construction and start-up, the project completion date, the ultimate rate recovery for the Kemper IGCC, and the potential impact on Mississippi Power's results of operations, Mississippi Power considers these items to be critical accounting estimates. See ~~MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined Cycle" of Mississippi Power in Item 7 and~~ Note 3 to the financial statements of Mississippi Power under "Integrated Coal Gasification Combined Cycle" in Item 8 of the Form 10-K ~~and FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined Cycle"~~ and Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" herein for additional information.

Recently Issued Accounting Standards

~~In May 2014, the Financial Accounting Standards Board (FASB) issued ASC 606,~~ ~~Revenue from Contracts with Customers. ASC 606 revises the accounting for revenue recognition.~~ On ~~April 29, 2015,~~February 25, 2016, the FASB issued ~~an exposure draft proposing the standard be effective for fiscal years beginning after December 15, 2017. Mississippi Power continues~~ASU No. 2016-02, Leases(Topic 842) (ASU 2016-02). ASU 2016-02 requires lessees to ~~evaluate the requirements of ASC 606. The ultimate impact of the new standard has not yet been determined.~~

~~On April 7, 2015, the FASB issued Accounting Standards Update (ASU) No. 2015-03,~~ ~~Interest – Imputation of Interest (Subtopic 835-30):Simplifying the Presentation of Debt Issuance Costs. The ASU requires that debt issuance costs related to a recognized debt liability be presented in~~recognize on the balance sheet as a ~~direct deduction from the carrying amount of that debt~~lease liability and a right-of-use asset for all leases. ASU 2016-02 also changes the recognition, measurement, and presentation of expense associated with leases and provides clarification regarding the identification of certain components of contracts that would represent a lease. The accounting required by lessors is relatively unchanged. ASU 2016-02 is effective for fiscal years beginning after December 15, ~~2015.~~2018, with early adoption permitted. Mississippi Power is currently ~~reflects unamortized debt issuance costs in other deferred charges~~evaluating the new standard and ~~assets~~has not yet determined its ultimate impact; however, adoption of ASU 2016-02 is expected to have a significant impact on ~~its~~Mississippi Power's balance sheet. ~~Upon adoption,~~

On March 30, 2016, the ~~reclassification will not have a material impact on~~FASB issued ASU No. 2016-09, Compensation-Stock Compensation(Topic 718): Improvements to Employee Share-Based Payment Accounting (ASU 2016-09). ASU 2016-09 changes the ~~results of operations, financial position, or~~accounting for income taxes and the cash ~~flows of Mississippi Power.~~flow presentation for share-based payment award transactions. Most

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

significantly, entities are required to recognize all excess tax benefits and deficiencies related to the exercise or vesting of stock compensation as income tax expense or benefit in the income statement. Mississippi Power currently recognizes any excess tax benefits and deficiencies related to the exercise and vesting of stock compensation in additional paid-in capital. ASU 2016-09 is effective for fiscal years beginning after December 15, 2016, with early adoption permitted. Mississippi Power is currently evaluating the new standard and has not yet determined its ultimate impact.

FINANCIAL CONDITION AND LIQUIDITY

Overview

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Overview" of Mississippi Power in Item 7 of the Form 10-K and FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined Cycle" herein for additional information. Earnings for the three months ended March 31, ~~2015 and 2014~~2016 were negatively affected by revisions to the cost estimate for the Kemper ~~IGCC~~IGCC.

Through March 31, 2016, Mississippi Power has incurred non-recoverable cash expenditures of $2.11 billion and ~~the Court's decision~~is expected to ~~reverse the 2013 MPSC Rate Order; however, Mississippi Power's financial condition remained stable as a result~~incur approximately $0.36 billion in additional non-recoverable cash expenditures through completion of the ~~financing activities described herein. Mississippi Power's cash requirements primarily consist~~construction and start-up of ~~funding debt maturities, including $900 million maturing April 1, 2016, ongoing operations and capital expenditures, as well as~~ the potential requirement to refund amounts collected under the 2013 MPSC Rate Order and associated carrying costs ($311 million through March 31, 2015) and the SMEPA deposits ($275 million at March 31, 2015). See FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined Cycle – Proposed Sale of Undivided Interest to SMEPA" and "Rate Recovery of Kemper ~~IGCC Costs – 2013 MPSC Rate Order" and "~~ – ~~2015 Mississippi Supreme Court Decision" herein for additional information.~~ IGCC.

For the three-year period from ~~2015~~2016 through ~~2017,~~2018, Mississippi Power's capital expenditures and debt maturities are expected to materially exceed operating cash flows. In addition to the Kemper IGCC, projected capital expenditures in that period include investments to maintain existing generation facilities, ~~including the Plant Daniel scrubber project,~~ to add environmental ~~equipment for~~modifications to existing generating units, to add or change fuel sources for certain existing units, and to expand and improve transmission and distribution facilities. ~~See "Sources of Capital" herein for additional information.~~

~~Through March 31, 2015,~~On January 28, 2016, Mississippi Power ~~has incurred non-recoverable cash expenditures of $1.49 billion and is expected~~issued a promissory note for up to ~~incur approximately $567~~$275 million to Southern Company, which matures in ~~additional non-recoverable cash expenditures through completion of the Kemper IGCC.~~

December 2017, bearing interest based on one-month LIBOR. During the first three months of ~~2015,~~2016, Mississippi Power ~~received $75~~borrowed $100 million ~~in equity contributions~~under this promissory note. In addition, on January 19, 2016, Mississippi Power borrowed an additional $100 million from Southern ~~Company. Subsequent~~Company pursuant to a promissory note issued in November 2015. On March ~~31, 2015,~~8, 2016, Mississippi Power entered into ~~two floating rate bank loans with a maturity date of April 1, 2016, in~~an unsecured term loan agreement for an aggregate ~~principal~~ amount of ~~$475 million, bearing interest based on one-month LIBOR. The proceeds of these loans were used~~$1.2 billion to repay existing indebtedness and for ~~the repayment of term loans in an aggregate principal amount of $275 million, working capital, and~~ other general corporate purposes. Mississippi Power ~~also amended three outstanding floating rate bank loans for an aggregate principal amount~~borrowed $900 million under the term loan agreement and has the right to borrow the remaining $300 million on or before October 15, 2016.

As of ~~$425~~March 31, 2016, Mississippi Power's current liabilities exceeded current assets by approximately $363 million ~~which, among other things, extended the maturity dates from various dates~~primarily due to $300 million in ~~2015~~senior notes scheduled to ~~April 1, 2016.~~mature on October 15, 2016 and $25 million in short-term debt. Mississippi Power intends to utilize operating cash flows and lines of credit ~~bank term loans, and commercial paper, as market conditions permit,~~(to the extent available) as well as loans and, under certain circumstances, equity contributions ~~and/or loans~~ from Southern Company to fund ~~Mississippi Power's short-term~~the remainder of its capital needs. See "Capital Requirements and Contractual Obligations," "Sources of Capital," and "Financing Activities" herein for additional information.

Net cash ~~provided from~~used for operating activities totaled ~~$204~~$25 million for the first three months of ~~2015, an increase~~2016, a decrease of ~~$172~~$229 million as compared to the corresponding period in ~~2014.~~2015. The ~~increase~~decrease in cash provided from operating activities is primarily due to ~~R&E~~lower research and experimental tax deductions, a reduction in the customer liability associated with Kemper IGCC refunds due to offsetting service provided, a decrease in prepaid income taxes, and ~~bonus depreciation reducing tax payments,~~a decrease in Mirror CWIP regulatory liability due to the Mirror CWIP refund, partially offset by an increase in ~~fuel recovery, and Mirror CWIP, net of the Kemper IGCC regulatory deferral, partially offset by the timing of payments for accounts payable and fuel purchases.~~receivables. See Notes (B) and ~~Note~~ (G) to the Condensed Financial Statements herein for additional information. Net cash used for investing activities totaled ~~$233~~$214 million for the first three months of ~~2015~~2016 primarily due to gross property additions related to the Kemper ~~IGCC and the Plant Daniel scrubber project.~~IGCC. Net cash provided from financing activities totaled ~~$30~~$199 million for the first three months of ~~2015~~2016 primarily due to ~~capital contributions from Southern Company and short-term borrowings,~~long-term debt issuances, partially offset by redemptions of long-term ~~debt.~~debt and short-term borrowings. Fluctuations in cash flow from financing activities vary from period to period based on capital needs and the maturity or redemption of securities.

Significant balance sheet changes for the first three months of 2015 include a decrease in securities due within one year of $775 million and an increase in long-term debt of $698 million, primarily due to refinancing or replacing maturing debt. See "Sources of Capital" herein for additional information. Total property, plant, and equipment

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Significant balance sheet changes for the first three months of 2016 include an increase in long-term debt of $1.1 billion. A portion of this debt was used to repay securities and notes payable resulting in a $425 million decrease in securities due within one year and a $475 million decrease in notes payable. Total property, plant, and equipment increased ~~$197 million, other regulatory assets, deferred increased $34 million, and the Mirror CWIP regulatory liability increased $40~~$140 million primarily due to the construction and startup activities for the Kemper IGCC. See "Integrated Coal Gasification Combined Cycle" herein for additional information. Additional changes included a decrease in prepaid income taxes of $29 million, a decrease in other accrued taxes of $55 million primarily due to ad valorem tax payments, and increases in accumulated deferred income taxes, a portion of which is reflected in other deferred charges and assets, and accrued income taxes of $95 million and $43 million, respectively, primarily due to R&E tax deductions and the related reserve. See FUTURE EARNINGS POTENTIAL – "Income Tax Matters" and Note (G) to the Condensed Financial Statements herein for additional information. Total common stockholder's equity increased $113 million primarily due to the receipt of $75 million in capital contributions from Southern Company and due to net income for the quarter.The customer liability associated with Kemper IGCC refunds decreased $51 million.

Capital Requirements and Contractual Obligations

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" of Mississippi Power in Item 7 of the Form 10-K for a description of Mississippi Power's capital requirements for its construction program, including estimated capital expenditures for new generating resources and to comply with existing environmental statutes and regulations, scheduled maturities of long-term debt, as well as related interest, leases, purchase commitments, derivative obligations, preferred stock dividends, trust funding requirements, and unrecognized tax benefits. ~~Mississippi Power has no~~Approximately $300 million will be required through March 31, 2017 to fund maturities of long-term debt, ~~maturing at or prior~~and $25 million will be required to ~~March 31, 2016. Approximately $900 million in bank term loans are scheduled to mature on April 1, 2016.~~fund maturities of short-term debt. See "Sources of Capital" herein for additional information.

The construction program of Mississippi Power is currently estimated to be $841 million for 2016, $216 million for 2017, and $264 million for 2018, which includes expenditures related to the construction of the Kemper IGCC of $665 million in 2016.

The construction program is subject to periodic review and revision, and actual construction costs may vary from these estimates because of numerous factors. These factors include: changes in business conditions; changes in load projections; storm impacts; changes in environmental statutes and regulations; the outcome of any legal challenges to the environmental rules; changes in generating plants, including unit retirements and replacements and adding or changing fuel sources at existing units, to meet regulatory requirements; changes in FERC rules and regulations; Mississippi PSC approvals; changes in the expected environmental compliance program; changes in legislation; the cost and efficiency of construction labor, equipment, and materials; project scope and design changes; and the cost of capital. See Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle – Kemper IGCC Schedule and Cost Estimate" herein for additional information and further risks related to the estimated schedule and costs and rate recovery for the Kemper IGCC.

Sources of Capital

~~Except as described herein,~~In December 2015, the Mississippi ~~Power plans to obtain~~PSC approved the ~~funds required~~In-Service Asset Rate Order, which among other things, provided for construction and other purposes from operating cash flows, security issuances, term loans, and/or short-term debt, as well as, under certain circumstances, equity contributions and/or loans from Southern Company. Operating cash flows would be adversely impacted by $156retail rate recovery of an annual revenue requirement of approximately $126 million ~~annually with the removal of rates implemented under the 2013 MPSC Rate Order.~~effective December 17, 2015. The amount, type, and timing of future financings will depend upon regulatory approval, prevailing market conditions, and other factors, which ~~may include~~includes resolution of Kemper IGCC cost recovery. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" and – FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined Cycle – Rate Recovery of Kemper IGCC Costs – 2013 MPSC Rate Order" and " – 2015 ~~Mississippi Supreme Court Decision"~~Rate Case" of Mississippi Power in Item 7 of the Form 10-K ~~and herein~~for additional information. Also see MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Income Tax Matters – Bonus Depreciation" of Mississippi Power in Item 7 of the Form 10-K for additional information.

Mississippi Power received $245 million of Initial DOE Grants in prior years that were used for the construction of the Kemper IGCC. An additional $25 million of grants from the DOE ~~Grants~~ is expected to be received for commercial operation of the Kemper IGCC. On April 8, 2016, Mississippi Power received approximately $137 million in Additional DOE Grants for the Kemper IGCC, which are expected to be used to reduce future rate impacts for customers. In addition, see Note 3 to the financial statements of Mississippi Power under "Integrated Coal Gasification Combined Cycle" in Item 8 of the Form 10-K for information regarding legislation related to the securitization of certain costs of the Kemper IGCC.

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

As of March 31, 2015, Mississippi Power's current liabilities exceeded current assets by approximately $578 million primarily due to refundable deposits from SMEPA and the potential Mirror CWIP refund. Subsequent to March 31, 2015,On January 28, 2016, Mississippi Power ~~entered into two floating rate bank loans with~~issued a ~~maturity date of April 1, 2016,~~promissory note for up to $275 million to Southern Company, which matures in ~~an aggregate principal amount of $475 million,~~December 2017, bearing interest based on one-month LIBOR. ~~The proceeds~~During the first three months of ~~these loans were used~~2016, Mississippi Power borrowed $100 million from Southern Company pursuant to the $275 million promissory note with a $50 million draw occurring on each of January 29, 2016 and March 14, 2016. In addition, on January 19, 2016, Mississippi Power borrowed $100 million from Southern Company pursuant to a promissory note issued in November 2015. On March 8, 2016, Mississippi Power entered into an unsecured term loan agreement for ~~the repayment of term loans in~~ an aggregate ~~principal~~ amount of ~~$275 million, working capital,~~$1.2 billion to repay existing indebtedness and for other general corporate purposes. Mississippi Power ~~also amended three outstanding floating rate~~borrowed $900 million under the term loan agreement and has the right to borrow the remaining $300 million on or before October 15, 2016. Mississippi Power used the initial proceeds to repay $900 million in maturing bank loans ~~for an aggregate principal amount of $425~~on March 8, 2016 and expects the remaining $300 million ~~which, among other things, extended the maturity dates from various dates~~to be used to repay senior notes maturing in ~~2015~~October 2016. The term loan pursuant to this agreement matures on April 1, ~~2016.~~ 2018 and bears interest based on one-month LIBOR.

Mississippi Power intends to utilize operating cash flows and lines of credit ~~bank term loans, and commercial paper, as market conditions permit,~~(to the extent available) as well as loans and, under certain circumstances, equity contributions ~~and/or loans~~ from Southern Company to fund Mississippi Power's short-term capital needs.

At March 31, ~~2015,~~2016, Mississippi Power had approximately ~~$134~~$58 million of cash and cash equivalents. Committed credit arrangements with banks at March 31, ~~2015~~2016 were as follows:


Expires	Expires							Executable Term Loans				Due Within One Year				Expires					Executable Term Loans				Due Within One Year
2015		2016		Total		Unused		One Year		Two Years		Term Out		No Term Out
(in millions)				(in millions)				(in millions)				(in millions)
2016																2016	Total		Unused		One Year		Two Years		Term Out		No Term Out
																	(in millions)				(in millions)				(in millions)
$	135	$	165	$	300	$	270	$	25	$	40	$	65	$	235	205	$	205	$	180	$	30	$	15	$	45	$	160

PPA energy revenuesremained flat; however, a $20 million increase in renewable energy sales, arising from new solar and wind facilities, was offset by a decrease of $20 million in ~~purchased power expenses.~~fuel revenues related to natural gas PPAs.

~~Wholesale Revenues~~–~~Non-Affiliates~~

Revenues not covered by PPA decreased $31 million primarily due to a 23% decrease in non-PPA KWH sales associated with increased scheduled outages and a reduction in demand driven by milder weather in 2016 as compared to 2015.

First Quarter 2015 vs. First Quarter 2014
(change in millions)
(% change)
$(46) (16.5)

Wholesale revenues ~~from sales to non-affiliates~~ will vary depending on the energy demand of ~~those~~Southern Power's customers and their generation capacity, as well as the market prices of wholesale energy compared to the cost of Southern Power's energy. Increases and decreases in revenues under PPAs that are driven by fuel prices are accompanied by an increase or decrease in fuel costs and do not have a significant impact on net income.

Capacity revenues are an integral component of Southern Power's natural gas and biomass PPAs and generally represent the greatest contribution to net income. Energy under the PPAs is generally sold at variable cost or is indexed to published gas indices. Energy revenues also include fees for support services, fuel storage, and unit start charges.

Southern Power's electricity sales from solar and wind generating facilities are also through long-term PPAs, but do not have a capacity charge. Instead, the customers purchase the energy output of a dedicated renewable facility through an energy charge. As a result, Southern Power's ability to recover fixed and variable operations and maintenance expenses is dependent upon the level of energy generated from these facilities, which can be impacted by weather conditions, equipment performance, and other factors.

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SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

~~Details of the changes in wholesale revenues from non-affiliates were as follows:~~

First Quarter
2015
(in millions) (% change)
Wholesale Revenues – Non-Affiliates, prior year $ 278

Change resulting from -
Capacity (7 ) (2.5 )
Energy (39 ) (14.0 )
Wholesale Revenues – Non-Affiliates, current year $ 232
(16.5 )%

The decrease in capacity was primarily the result of contract expirations. The decrease in energy revenues reflects a 20.8% decrease in the average price of energy and a 20.0% decrease in non-affiliate KWH sales for the first quarter 2015. This was primarily due to lower fuel revenues, reduced load, and contract expirations, partially offset by an increase in energy revenues from new solar PPAs.

~~Wholesale Revenues~~–~~Affiliates~~

First Quarter 2015 vs. First Quarter 2014
(change in millions)
(% change)
$42 58.3

Wholesale revenues from sales to affiliate companies will vary depending on demand and the availability and cost of generating resources at each company. Sales to affiliate companies that are not covered by PPAs are made in accordance with the IIC, as approved by the FERC.

Wholesale revenues from affiliates for the first quarter 2015 were $114 million compared to $72 million for the corresponding period in 2014. The increase was primarily the result of a $38 million increase in energy revenues from sales under the IIC as a result of lower natural gas prices.

Fuel and Purchased Power Expenses

Fuel costs constitute the single largest expense for Southern Power. Additionally, Southern Power purchases a portion of its electricity needs from the wholesale market. Details of Southern Power's generation and purchased power were as follows:

First Quarter 2015
vs.
First Quarter 2014
(change in millions)
(% change)
Fuel $ 13
10.4
Purchased power – non-affiliates (12 ) (42.9)
Purchased power – affiliates (19 ) (65.5)
Total fuel and purchased power expenses $ (18 )



	First Quarter 2016	First Quarter 2015
Generation (in billions of KWHs)	7.7	7.9
Purchased power (in billions of KWHs)	0.6	0.5
Total generation and purchased power	8.3	8.4
Total generation and purchased power (excluding solar, wind and tolling)	5.3	5.9

Southern ~~Power~~Power's PPAs for natural ~~gas-fired~~gas and biomass generation generally provide that the purchasers are responsible for either procuring the fuel (tolling agreements) or reimbursing Southern Power for substantially all of the cost of ~~fuel.~~fuel relating to the energy delivered under such PPAs. Consequently, any increase or decrease in such fuel ~~cost~~costs is generally accompanied by an increase or decrease in related fuel ~~revenue~~revenues under the PPAs and does not have a significant impact on net income. Southern Power is responsible for the cost of fuel for generating units that are not covered under PPAs. Power from these generating units is sold into the wholesale market or ~~sold to affiliates under~~into the ~~IIC.~~power pool, for capacity owned directly by Southern Power (excluding its subsidiaries).

Purchased power expenses will vary depending on demand and the availability and cost of generating resources throughout the Southern Company system and other contract resources. Load requirements are submitted to the power pool on an hourly basis and are fulfilled with the lowest cost alternative, whether that is generation owned by Southern Power, ~~Company, affiliate-owned generation,~~affiliate companies, or external ~~purchases.~~parties.

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	First Quarter 2016 vs. First Quarter 2015
	(change in millions)			(% change)
Fuel	$	(47	)	(34.1)
Purchased power	(7		)	(26.9)
Total fuel and purchased power expenses	$	(54	)

In the first quarter 2016, total fuel and purchased power expenses were $110 million compared to $164 million for the corresponding period in 2015. The decrease was primarily due to the following:

Fuel expense decreased $47 million primarily due to a $28 million decrease associated with the average cost of natural gas per KWH generated and a $19 million decrease associated with the volume of KWHs generated.

Purchased power expense decreased $7 million due to a $12 million decrease in the average cost of purchased power and a $4 million decrease associated with a PPA expiration, partially offset by a $9 million increase associated with the volume of KWHs purchased.

Other Operations and Maintenance Expenses



First Quarter 2016 vs. First Quarter 2015
(change in millions)		(% change)
$27		51.9

In the first quarter 2016, other operations and maintenance expenses were $79 million compared to $52 million for the corresponding period in 2015. The increase was primarily due to a $14 million increase associated with

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scheduled outage and maintenance expenses, a $6 million increase in business support services expenses, and a $5 million increase in expenses associated with new solar and wind facilities placed in service in 2015 and 2016.

Depreciation and Amortization



First Quarter 2016 vs. First Quarter 2015
(change in millions)		(% change)
$14		23.7

In the first quarter ~~2015, total fuel~~2016, depreciation and ~~purchased power expenses were $164~~amortization was $73 million compared to ~~$182~~$59 million for the corresponding period in ~~2014.~~2015. The ~~decrease~~increase was ~~the result of a $97 million decrease in the average cost of fuel and purchased power~~ primarily due to ~~lower natural gas prices, partially offset by a $79 million~~additional depreciation related to new solar and wind facilities placed in service in 2015 and 2016.

Interest Expense, net ~~increase in the volume~~ of ~~KWHs generated and purchased primarily due to increased demand resulting from lower natural gas prices.~~Amounts Capitalized

~~Fuel~~



First Quarter 2016 vs. First Quarter 2015
(change in millions)		(% change)
$(1)		(4.5)

In the first quarter ~~2015, fuel~~2016, interest expense, net of amounts capitalized was ~~$138~~$21 million compared to ~~$125~~$22 million for the corresponding period in 2014. The increase was due to an 88.4% increase in the volume of KWHs generated primarily due to increased demand resulting from lower natural gas prices, partially offset by a 41.1% decrease in the average cost of natural gas per KWH generated.

~~Purchased Power~~

In the first quarter 2015, purchased power expense was $26 million compared to $57 million for the corresponding period in 2014. The decrease was the result of a 52.8% decrease in the volume of KWHs purchased and a 5.5% decrease in the average cost per KWH of purchased power primarily due to lower natural gas prices.

~~Other Operations and Maintenance Expenses~~

First Quarter 2015 vs. First Quarter 2014
(change in millions) (% change)
$(1) (1.9)

~~In the first quarter 2015, other operations and maintenance expenses were $52 million compared to $53 million for the corresponding period in 2014.~~2015. The decrease was primarily due to a $7$9 million ~~decrease as a result~~increase in capitalized interest associated with the construction of ~~lower outage costs,~~solar facilities, largely offset by ~~a $6~~an increase of $8 million ~~increase~~ in ~~expenses associated with labor, maintenance, support services, and new plants placed in service in 2014.~~

~~Depreciation and Amortization~~

First Quarter 2015 vs. First Quarter 2014
(change in millions)
(% change)
$8 15.7

~~In the first quarter 2015, depreciation and amortization was $59 million compared to $51 million for the corresponding period in 2014. The increase was primarily~~interest expense related to ~~solar facilities placed in service in 2014.~~additional debt issued primarily to fund Southern Power's growth strategy and continuous construction program.

Income Taxes (Benefit)



First Quarter ~~2015~~2016 vs. First Quarter ~~2014~~2015
(change in millions)		(% change)
$9(35)		N/M

N/M – Not meaningful

In the first quarter ~~2015,~~2016, income ~~taxes were $12~~tax benefit was $(23) million compared to $3an expense of $12 million for the corresponding period in ~~2014.~~2015. The ~~increase~~change was primarily due to ~~beneficial changes impacting 2014 state income taxes and higher pre-tax earnings~~a $28 million increase in ~~2015, partially offset by increased~~ federal income tax benefits from solar ITCs and wind PTCs in 2016 and a $7 million decrease in tax expense related to ~~ITCs~~lower pre-tax earnings in ~~2015.~~2016.

See Note (G) to the Condensed Financial Statements herein for additional information.

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~~MANAGEMENT'S DISCUSSION AND ANALYSIS OF~~

~~FINANCIAL CONDITION AND RESULTS OF OPERATIONS~~

FUTURE EARNINGS POTENTIAL

The results of operations discussed above are not necessarily indicative of Southern Power's future earnings potential. The level of Southern Power's future earnings depends on numerous factors that affect the opportunities, challenges, and risks of Southern Power's competitive wholesale business. These factors include: Southern Power's ability to achieve sales growth while containing costs; regulatory matters; creditworthiness of customers; total generating capacity available in Southern Power's market areas; the successful remarketing of capacity as current contracts expire; and Southern Power's ability to execute its ~~acquisition and value creation~~growth strategy, including ~~successfully expanding~~successful additional investments in renewable and other energy projects, and to construct generating facilities, including the impact of federal ITCs. Demand for electricity is primarily driven by economic growth. The pace of economic growth and electricity demand may be affected by changes in regional and global economic conditions, which may impact future earnings.

Other factors that could influence future earnings include weather, demand, cost of ~~generating~~generation from units within the power pool, and operational limitations. For additional information relating to these issues, see RISK FACTORS in

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Item 1A and MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL of Southern Power in Item 7 of the Form 10-K.

Power Sales Agreements

See BUSINESS – "The Southern Company System – Southern Power" in Item 1 of the Form 10-K for additional information regarding Southern Power's PPAs with investor-owned utilities, independent power purchasers, municipalities, electric cooperatives, and other load-serving entities.

At December 31, 2015, Southern Power's generation contract coverage ratio, which compares contracted capacity (MW) to available demonstrated capacity (MW), was an average of 75% for the next five years (through 2020) and 70% for the next 10 years (through 2025), with an average remaining contract duration of approximately 10 years.

Southern Power believes an investment contract ratio better identifies the value of assets covered since it represents the ratio of investment under contract to total investment using the respective generation facilities' net book value (or expected in-service value for facilities under construction or being acquired) as the investment amount. At March 31, 2016, the investment coverage ratio was 91% for the next five years (through 2020) and 90% for the next 10 years (through 2025), with an average remaining contract duration of approximately 18 years. At December 31, 2015, the investment coverage ratio would have been 91% for the next five years (through 2020) and 90% for the next 10 years (through 2025), with an average remaining contract duration of approximately 18 years.

Environmental Matters

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters" of Southern Power in Item 7 of the Form 10-K for information on the development by federal and state environmental regulatory agencies of additional control strategies for emissions of air pollution from industrial sources, including electric generating facilities. Compliance with possible additional federal or state legislation or regulations related to global climate change, air quality, water quality, or other environmental and health concerns could also significantly affect Southern Power. While Southern Power's PPAs generally contain provisions that permit charging the counterparty with some of the new costs incurred as a result of changes in environmental laws and regulations, the full impact of any such regulatory or legislative changes cannot be determined at this time.

Acquisitions

During ~~2015, Southern Power Company acquired or contracted to acquire the following projects~~2016, in accordance with its overall growth strategy, ~~which are included in Southern Power's capital program estimates for 2015.~~

~~Kay County Wind Facility~~

~~On February 24, 2015,~~ Southern Power ~~Company,~~acquired or contracted to acquire through its wholly-owned ~~subsidiary~~subsidiaries, Southern Renewable Partnerships, LLC or Southern Renewable Energy, Inc., ~~entered into a purchase agreement~~the projects set forth in the following table. Acquisition-related costs were expensed as incurred and were not material. See Note (I) to the Condensed Financial Statements under "Southern Power" herein for additional information.



Project Facility	Approx. Nameplate Capacity	Location	Percentage Ownership		Expected/Actual COD	PPA Contract Period
	(MW)
SOLAR
Calipatria^(a)	20	Imperial County, CA	90	%	February 11, 2016	20 years
East Pecos^(b)	120	Pecos County, TX	100	%	Fourth quarter 2016	15 years
WIND
Grant Wind^(c)	151	Grant County, OK	100	%	April 8, 2016	20 years
Passadumkeag^(d)	40	Penobscot County, ME	100	%	Second quarter 2016	15 years

(a) Calipatria - On February 11, 2016, Southern Power, together with ~~Kay Wind Holdings,~~the minority owner, Turner Renewable Energy, LLC ~~a wholly-owned subsidiary of Apex Clean Energy Holdings, LLC, the developer of the project, to acquire~~(TRE), which owns 10%, acquired all of the outstanding membership interests of Kay Wind, LLC (Kay Wind) for approximately $492 million, with potential purchase price adjustments based on performance testing. Kay Wind is constructing and owns an approximately 299-MW wind facility in Kay County, Oklahoma. The wind facility is expected to begin commercial operation in late 2015, and the entire output of the facility is contracted under separate 20-year PPAs with Westar Energy, Inc. and Grand River Dam Authority. In March 2015, Kay Wind obtained the necessary financing for the construction of the facility, and the acquisition is expected to close in the fourth quarter 2015. The completion of the acquisition is subject to Kay Wind achieving certain construction and project milestones, and various other customary conditions to closing. The ultimate outcome of this matter cannot be determined at this time. See Note 2 to the financial statements of Southern Power ~~in Item 8 of the Form 10-K~~ ~~for additional information.~~Calipatria Solar, LLC.

~~Lost Hills-Blackwell Solar Facilities~~

On April 15, 2015, Southern Power Company, through its subsidiary Southern Renewable Partnerships, LLC (SRP), acquired 100% of the class A membership interests of Lost Hills Blackwell Holdings, LLC (Lost Hills Blackwell) from a wholly-owned subsidiary of First Solar, Inc. (First Solar), the developer of the project, for approximately $74 million. Concurrently, a wholly-owned subsidiary of First Solar acquired 100% of the class B membership interests of Lost Hills Blackwell for approximately $34 million. SRP and the class B member are entitled to 51% and 49%, respectively, of all cash distributions from Lost Hills Blackwell. In addition, Southern Power Company is

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entitled to substantially all of the federal tax benefits with respect to the transaction. Lost Hills Blackwell constructed and owns the approximately 20-MW Lost Hills and the approximately 12-MW Blackwell solar facilities in Kern County, California. These solar facilities began commercial operation on April 17, 2015, and their entire output is contracted under PPAs, initially to the City of Roseville and then to Pacific Gas and Electric Company, that together extend approximately 29 years.

~~North Star Solar Facility~~

(b) East Pecos - On ~~April 30, 2015,~~March 4, 2016, Southern Power ~~Company, through its subsidiary SRP,~~ acquired ~~100% of~~all the ~~class A~~outstanding membership interests of NSEast Pecos Solar, ~~Holdings, LLC (North Star) from a wholly-owned subsidiary of First Solar,~~LLC. Total construction costs, which include the ~~developer of the project, for approximately $208 million.~~ ~~Concurrently, a wholly-owned subsidiary of First Solar acquired 100% of the class B membership interests of North Star for approximately $99 million. SRP and the class B member~~acquisition price allocated to CWIP, are entitled to 51% and 49%, respectively, of all cash distributions from North Star. In addition, Southern Power Company is entitled to substantially all of the federal tax benefits with respect to the transaction. North Star is constructing and owns the approximately 60-MW North Star solar facility in Fresno County, California, which is expected to ~~begin commercial operation in June 2015. The entire output of the project is contracted under a 20-year PPA with Pacific Gas and Electric Company.~~be approximately $200 million to $220 million. The ultimate outcome of this matter cannot be determined at this time.

(c) Grant Wind - Subsequent to March 31, 2016, Southern Power acquired all the outstanding membership interests of Grant Wind, LLC.

(d) Passadumkeag - On March 11, 2016, Southern Power entered into an agreement to acquire all of the outstanding membership interests of Quantum Wind Acquisition I, LLC, which is expected to close in the second quarter 2016. The ultimate outcome of this matter cannot be determined at this time.

Construction Projects

~~During 2015,~~See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Acquisitions" and "Construction Projects" of Southern Power ~~Company commenced or plans to commence~~in Item 7 of the ~~following construction projects~~Form 10-K for additional information.

During the first quarter 2016, in accordance with its overall growth strategy, Southern Power completed construction of and placed in service the Butler Solar Farm and Pawpaw solar facilities. In addition, Southern Power continued construction of the projects set forth in the table below. Through March 31, 2016, total costs of construction incurred for the projects below were $2.2 billion, of which ~~are included~~$1.5 billion remains in ~~Southern Power's capital program estimates for 2015.~~CWIP. The ultimate outcome of these matters cannot be determined at this time.

~~Decatur County Solar Projects~~

~~On February 19,~~



Solar Facility	Approx. Nameplate Capacity	Location	Expected/Actual COD	PPA Contract Period	Estimated Construction Costs
	(MW)				(in millions)
Butler	103	Taylor County, GA	Fourth quarter 2016	30 years	$	220	-	230	(a)
Desert Stateline	299^(b)	San Bernardino County, CA	Through third quarter 2016	20 years	$	1,200	-	1,300	(c)
Garland and Garland A^(d)	205	Kern County, CA	Fourth quarter 2016 Third quarter 2016	15 years and 20 years	$	532	-	552	(e)
Roserock^(d)	160	Pecos County, TX	Fourth quarter 2016	20 years	$	333	-	353	(e)
Sandhills	146	Taylor County, GA	Fourth quarter 2016	25 years	$	260	-	280
Tranquillity^(d)	205	Fresno County, CA	Third quarter 2016	18 years	$	473	-	493	(f)


(a)	Butler - Total estimated construction costs include the acquisition price of all outstanding membership interests of the related entity.

(b) Desert Stateline - The facility has a total of 299 MWs, of which 110 MWs were placed in service in the fourth quarter 2015 ~~Southern Power Company acquired all of~~and 76 MWs were placed in service in the ~~outstanding membership interests of Decatur Parkway Solar Project, LLC and Decatur County Solar Project, LLC from TradeWind Energy, Inc. as part of Southern Power's plans~~first quarter 2016. Subsequent to ~~build two solar photovoltaic facilities: the Decatur Parkway Solar Project and the Decatur County Solar Project. These two projects, approximately 80~~March 31, 2016, 38 MWs ~~and 19~~were placed in service. The remaining 75 MWs respectively, will be constructed on separate sites in Decatur County, Georgia. Construction of the Decatur Parkway Solar Project commenced in February 2015, while construction of the Decatur County Solar Project is expected to commence in June 2015. Both projects are expected to ~~begin commercial operation~~be placed in ~~late 2015, and~~service by the entire output of each project is contracted to Georgia Power. The Decatur Parkway Solar Project is contracted under a 25-year PPA and the Decatur County Solar Project is contracted under a separate 20-year PPA. Construction costs incurred through March 31, 2015 were $32 million. The total estimated costend of the ~~facilities is expected to be between $200 million~~third quarter 2016.

(c)

Desert Stateline - On March 29, 2016, Southern Power acquired an additional 15% interest in Desert Stateline. As a result, Southern Power and the class B member are entitled to 66% and 34%, respectively, of all cash distributions from Desert Stateline. In addition, Southern Power will continue to be entitled to substantially all of the federal tax benefits with respect to the transaction. Total estimated construction costs include the acquisition price allocated to CWIP; however, the allocation of the purchase price to individual assets has not been finalized.


(d)	Southern Power owns 100% of the class A membership interests and a wholly-owned subsidiary of the seller owns 100% of the class B membership interests. Southern Power and the class B member are entitled to 51% and 49%, respectively, of all cash distributions from the project.


(e)	Total estimated construction costs include the acquisition price allocated to CWIP. During the first quarter 2016, the allocation of the purchase price to individual assets was finalized with no changes.


(f)	Total estimated construction costs include the acquisition price allocated to CWIP; however, the allocation of the purchase price to individual assets has not been finalized.

See FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and ~~$220 million, which includes the acquisition price~~Contractual Obligations" herein for ~~all of the outstanding membership interests of Decatur Parkway Solar Project, LLC and Decatur County Solar Project, LLC from TradeWind Energy, Inc.~~additional information.

~~Butler Solar Project~~

On March 12, 2015, Southern Power Company entered into a purchase agreement with CERSM, LLC and Community Energy, Inc. to acquire all of the outstanding membership interests of Butler Solar LLC as part of Southern Power's plans to build an approximately 100-MW solar photovoltaic facility in Taylor County, Georgia. Construction of the project is expected to commence in July 2015, with commercial operation expected to begin in December 2016. The entire output of the project is contracted to Georgia Power under a 30-year PPA. The total estimated cost of the facility is expected to be between $220 million and $230 million, which includes the acquisition price for all of the outstanding membership interests of Butler Solar LLC from CERSM, LLC and Community Energy, Inc. The acquisition is expected to close later in May 2015, and is subject to customary conditions to closing.

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~~Pawpaw Solar Project~~

On April 22, 2015, Southern Power Company entered into a purchase agreement with Longview Solar, LLC to acquire all of the outstanding membership interests of LS – Pawpaw, LLC as part of Southern Power's plans to build an approximately 30-MW solar photovoltaic facility in Taylor County, Georgia. Construction of the project is expected to commence in June 2015, with commercial operation expected to begin in December 2015. The entire output of the project is contracted to Georgia Power under a 30-year PPA. The total estimated cost of the facility is expected to be between $65 million and $75 million, which includes the acquisition price for all of the outstanding membership interests of LS – Pawpaw, LLC from Longview Solar, LLC. The ~~acquisition~~ ~~is expected to close later in May 2015, and is subject to customary conditions to closing.~~

~~Power Sales Agreements~~

Taking into account the PPAs and capacity from the acquisitions and construction projects discussed herein, together with various new PPAs relating to Southern Power's existing fleet, the coverage ratio of its available capacity for the next five years and the next 10 years has not changed materially as of March 31, 2015 from the period ended December 31, 2014.

~~FERC Matters~~

Southern Power has authority from the FERC to sell electricity at market-based rates. Since 2008, that authority, for certain balancing authority areas, has been conditioned on compliance with the requirements of an energy auction, which the FERC found to be tailored mitigation that addresses potential market power concerns. In accordance with FERC regulations governing such authority, the traditional operating companies and Southern Power filed a triennial market power analysis on June 30, 2014, which included continued reliance on the energy auction as tailored mitigation. On April 27, 2015, the FERC issued an order finding that the traditional operating companies' and Southern Power's existing tailored mitigation may not effectively mitigate the potential to exert market power in certain areas served by the traditional operating companies and in some adjacent areas. To retain market-based rate authority, the FERC has directed the traditional operating companies and Southern Power, within 60 days, to show why market-based rate authority should not be revoked in these areas or to provide a mitigation plan to further address market power concerns. Southern Power is evaluating the order. The ultimate outcome of this matter cannot be determined at this time.

Other Matters

Southern Power is involved in various other matters being litigated and regulatory matters that could affect future earnings. In addition, Southern Power is subject to certain claims and legal actions arising in the ordinary course of business. Southern Power's business activities are subject to extensive governmental regulation related to public health and the environment, such as regulation of air emissions and water discharges. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements, such as air quality and water standards, has occurred throughout the U.S. This litigation has included claims for damages alleged to have been caused by CO₂ and other emissions and alleged exposure to hazardous materials, and/or requests for injunctive relief in connection with such matters.

The ultimate outcome of such pending or potential litigation against Southern Power cannot be predicted at this time; however, for current proceedings not specifically reported in Note (B) to the Condensed Financial Statements herein or in Note 3 to the financial statements of Southern Power in Item 8 of the Form 10-K, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on Southern Power's financial statements.

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~~FINANCIAL CONDITION AND RESULTS OF OPERATIONS~~

ACCOUNTING POLICIES

Application of Critical Accounting Policies and Estimates

Southern Power prepares its consolidated financial statements in accordance with GAAP. Significant accounting policies are described in Note 1 to the financial statements of Southern Power in Item 8 of the Form 10-K. In the application of these policies, certain estimates are made that may have a material impact on Southern Power's results of operations and related disclosures. Different assumptions and measurements could produce estimates that are significantly different from those recorded in the financial statements. See MANAGEMENT'S DISCUSSION AND ANALYSIS – ACCOUNTING POLICIES – "Application of Critical Accounting Policies and Estimates" of Southern Power in Item 7 of the Form 10-K for a complete discussion of Southern Power's critical accounting policies and estimates related to Revenue Recognition, Impairment of ~~Long Lived~~Long-Lived Assets and Intangibles, Acquisition Accounting, Depreciation, and ITCs.

Recently Issued Accounting Standards

~~In May 2014, the Financial Accounting Standards Board (FASB) issued ASC 606,~~ ~~Revenue from Contracts with Customers. ASC 606 revises the accounting for revenue recognition.~~ On ~~April 29, 2015,~~February 25, 2016, the FASB issued ~~an exposure draft proposing~~ASU No. 2016-02, Leases(Topic 842) (ASU 2016-02). ASU 2016-02 requires lessees to recognize on the ~~standard be effective~~balance sheet a lease liability and a right-of-use asset for ~~fiscal years beginning after December 15, 2017. Southern Power continues to evaluate~~all leases. ASU 2016-02 also changes the ~~requirements~~recognition, measurement, and presentation of ~~ASC 606. The ultimate impact of the new standard has not yet been determined.~~

~~On February 18, 2015, the FASB issued Accounting Standards Update (ASU) 2015-02,~~ ~~Amendments to the Consolidation Analysis, which makes certain changes to both the variable interest model~~expense associated with leases and ~~the voting model, including changes to~~provides clarification regarding the identification of ~~variable interests, the variable interest entity characteristics for~~certain components of contracts that would represent a ~~limited partnership or similar entity, and the primary beneficiary determination. This~~lease. The accounting required by lessors is relatively unchanged. ASU 2016-02 is effective for fiscal years beginning after December 15, ~~2015.~~2018, with early adoption permitted. Southern Power is currently evaluating ~~these requirements. The ultimate impact of this ASU~~the new standard and has not yet ~~been determined.~~

~~On April 7, 2015, the FASB issued ASU No. 2015-03,~~ ~~Interest – Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs.~~ The ASU requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability and is effective for fiscal years beginning after December 15, 2015. Southern Power currently reflects unamortized debt issuance costs in other deferred charges and assets – non-affiliated ondetermined its ~~balance sheet. Upon adoption, the reclassification will not have a material impact on the results of operations, financial position, or cash flows of Southern Power.~~ultimate impact.

FINANCIAL CONDITION AND LIQUIDITY

Overview

Southern Power's financial condition remained stable at March 31, ~~2015.~~2016. Southern Power intends to continue to monitor its access to short-term and long-term capital markets as well as bank credit agreements as needed to meet future capital and liquidity needs. See "Sources of Capital" herein for additional information on lines of credit.

Net cash used for operating activities totaled $110 million for the first three months of 2016, compared to $19 million for the first three months of ~~2015, a change of $129 million as compared to $110 million of net cash provided from operating activities for the first three months of 2014.~~2015. The ~~decrease~~increase in cash ~~provided from~~used for operating activities was primarily due to an increase in unutilized federal ITCs created during the 2014 tax year that were repaid in the first three months of 2015 primarily due to bonus depreciation, as well as a reduction in accounts payable. The federal ITCs carried forward are expected to be utilized during the 2015 tax year.income taxes paid. Net cash used for investing activities totaled ~~$38~~$873 million for the first three months of ~~2015~~2016 primarily due to ~~expenditures related to~~acquisitions and the construction of ~~new solar facilities and payments pursuant to long-term service agreements.~~renewable facilities. Net cash provided from financing activities totaled $5$206 million for the first three months of ~~2015~~2016 primarily due to ~~the issuance of commercial paper, partially offset by the payment of common stock dividends.~~an increase in notes payable. Fluctuations in cash flow from financing activities vary ~~year~~from period to ~~year~~period based on capital needs and ~~the~~

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the maturity or redemption of securities.

Significant balance sheet changes for the first three months of ~~2015~~2016 include a ~~$37~~$398 million increase in CWIP due to continued construction of new solar facilities and a $412 million increase in plant in service, primarily due to ~~the construction of the Decatur County~~ solar ~~projects.~~facilities being placed in service. Other significant changes include a ~~$54~~$777 million ~~change~~decrease in ~~accumulated deferred income taxes, net of current deferred income tax items, primarily as~~cash and cash equivalents and a ~~result of the timing and amount of ITCs utilized, partially offset by property related changes. Southern Power Company's~~$276 million increase in notes payable due to funding of acquisitions and construction projects, and income taxes. See FUTURE EARNINGS POTENTIAL – "Acquisitions" herein for ~~commercial paper increased by $38 million.~~additional information.

Capital Requirements and Contractual Obligations

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" of Southern Power in Item 7 of the Form 10-K for a description of Southern Power's capital requirements for its construction program, scheduled maturities of long-term debt, as well as the related interest, leases, derivative obligations, ~~purchase commitments, and~~ unrecognized tax ~~benefits.~~benefits, and other purchase commitments. Approximately ~~$525~~$400 million will be required to ~~fund maturities of~~repay long-term debt due ~~July 15, 2015.~~September 28, 2016. There are no other scheduled maturities of long-term debt through March 31, ~~2016.~~2017. In addition, during the first quarter 2016, Southern Power entered into four new long-term service agreements (LTSA), which begin in 2020 and result in additional future commitments totaling approximately $627 million.

The ~~capital~~construction program is subject to periodic review and revision. These amounts include estimates for potential plant acquisitions and new construction. In addition, the construction ~~as well as ongoing~~program includes capital improvements and work to be performed under ~~long-term service agreements.~~LTSAs. Planned expenditures for plant acquisitions may vary materially due to market opportunities and Southern Power's ability to execute its growth strategy. Capital expenditures of Southern Power are currently estimated to be approximately $1.4 billion for 2015, which includes approximately $1.3 billion for acquisitions and/or construction of new generating facilities. See Note (I) to the Condensed Financial Statements herein for additional information. Actual capital costs may vary from these estimates because of ~~changes in~~numerous factors such as: changes in business conditions; changes in the expected environmental compliance program; changes in environmental statutes and regulations; the outcome of any legal challenges to the environmental rules; changes in FERC rules and regulations; changes in load projections; changes in legislation; the cost and efficiency of construction labor, equipment, and materials; project scope and design changes; and the cost of capital. See Note (I) to the Condensed Financial Statements herein for additional information.

Sources of Capital

Southern Power plans to obtain the funds required for construction and other purposes from sources similar to those used in the past, which were primarily from operating cash flows, short-term debt, securities issuances, term loans, and equity contributions from Southern Company. However, the amount, type, and timing of any future financings, if needed, will depend upon prevailing market conditions, regulatory approval, and other factors. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Sources of Capital" of Southern Power in Item 7 of the Form 10-K for additional information.

As of March 31, ~~2015,~~2016, Southern Power's current liabilities exceeded current assets by ~~$318~~$977 million due to ~~the~~ long-term debt maturing in ~~2015 and~~2016, the use of short-term debt as a funding source, and construction payables, as well as cash needs, which can fluctuate significantly due to the seasonality of the ~~business.~~business and the stage of its acquisitions and construction projects. In ~~2015,~~2016, Southern Power expects to utilize the capital markets, bank term loans, and commercial paper markets as the source of funds for the majority of its maturities.

~~To meet liquidity and capital resource requirements,~~As of March 31, 2016, Southern Power had ~~at March 31, 2015~~ cash and cash equivalents of approximately ~~$23 million and~~$53 million.

Other than borrowings pursuant to the Project Credit Facilities (defined below), Southern Power had no short-term borrowings during the first quarter 2016.

Company Facility

At March 31, 2016, Southern Power had a committed credit facility (Facility) of ~~$500~~$600 million ~~(Facility)~~ expiring in ~~2018,~~2020, of which ~~$488~~$560 million iswas unused. Southern Power's subsidiaries are not borrowers under the Facility.

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SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The Facility, as well as Southern Power's term loan agreement, contains a covenant that limits the ratio of debt to capitalization ~~(each as~~(as defined in the Facility) to a maximum of 65% and contains a cross default provision that is restricted only to ~~the~~ indebtedness of Southern Power. For purposes of this definition, debt excludes any project debt incurred by certain subsidiaries of Southern Power ~~Company~~to the extent such debt is non-recourse to Southern Power , and capitalization excludes the capital stock or other equity attributable to such subsidiary. Southern Power is currently in compliance with all covenants in the Facility.

Proceeds from ~~this~~the Facility may be used for working capital and general corporate purposes as well as liquidity support for Southern Power's commercial paper program. Subject to applicable market conditions, Southern Power expects to renew or replace the Facility, as needed, prior to expiration. In connection therewith, Southern Power may extend the maturity date and/or increase or decrease the lending commitment thereunder. See Note 6 to the financial statements of Southern Power under "Bank Credit Arrangements" in Item 8 of the Form 10-K and Note (E) to the Condensed Financial Statements under "Bank Credit Arrangements" herein for additional information.

Southern Power's commercial paper program is used to finance acquisition and construction costs related to electric generating facilities and for general corporate purposes, including maturing debt. Southern Power's subsidiaries are not borrowers under the commercial paper program.

Subsidiary Facilities

In connection with the construction of solar facilities by RE Tranquillity LLC, RE Roserock LLC, and RE Garland Holdings LLC, indirect subsidiaries of Southern Power, each subsidiary entered into separate credit agreements (Project Credit Facilities), which are non-recourse to Southern Power (other than the subsidiary party to the agreement). Each Project Credit Facility provides (a) a senior secured construction loan credit facility, (b) a senior secured bridge loan facility, and (c) a senior secured letter of credit facility that is secured by the membership interests of the respective project company. Proceeds from the Project Credit Facilities are being used to finance project costs related to the respective solar facilities currently under construction. Each Project Credit Facility is secured by the assets of the applicable project subsidiary and membership interests of the applicable project subsidiary. The table below summarizes each Project Credit Facility as of March 31, 2016.

~~124~~



Project	Maturity Date	Construction Loan Facility		Bridge Loan Facility		Total		Total Undrawn		Letter of Credit Facility		Total Undrawn
		(in millions)
Tranquillity	Earlier of COD or December 31, 2016	$	86	$	172	$	258	$	52	$	77	$	26
Roserock	Earlier of COD or November 30, 2016	63		180		243		121		23		16
Garland	Earlier of COD or November 30, 2016	86		308		394		309		49		32
Total		$	235	$	660	$	895	$	482	$	149	$	74

The Project Credit Facilities had total amounts outstanding as of March 31, 2016 of $413 million at a weighted average interest rate of 1.99%. For the three months ended March 31, 2016, these credit agreements had a maximum amount outstanding of $413 million, and an average amount outstanding of $260 million at a weighted average interest rate of 1.99%.

Southern Power believes the need for working capital can be adequately met by utilizing the commercial paper program, the Facility, bank term loans, and operating cash flows.

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

~~Southern Power Company's commercial paper program is used to finance acquisition and construction costs related to electric generating facilities and for general corporate purposes.~~

~~Details of short-term borrowings were as follows:~~

Commercial Paper at
the End of the Period

Commercial Paper During the Period^(*)

Amount
Outstanding

Weighted
Average
Interest
Rate

Average
Outstanding

Weighted
Average
Interest
Rate

Maximum
Amount
Outstanding
(in millions) (in millions) (in millions)
March 31, 2015: $ 233
0.6 % $ 156
0.5 % $ 234

~~(*) Average and maximum amounts are based upon daily balances during the three-month period ended March 31, 2015.~~

~~Southern Power believes the need for working capital can be adequately met by utilizing the commercial paper program, the Facility, and operating cash flows.~~

Credit Rating Risk

Southern Power does not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade.

There are certain contracts that could require collateral, but not accelerated payment, in the event of a credit rating change to BBB ~~and Baa2, or BBB-~~ and/or ~~Baa3~~Baa2, or below. These contracts are for physical electricity purchases and sales, fuel transportation and storage, ~~and~~ energy price risk ~~management.~~management, and transmission.

The maximum potential collateral requirements under these contracts at March 31, ~~2015~~2016 were as follows:


Credit Ratings	Maximum Potential Collateral Requirements		Maximum Potential Collateral Requirements
	(in millions)		(in millions)
At BBB and Baa2	$	9
At BBB and/or Baa2			$	11
At BBB- and/or Baa3	310		$	350
Below BBB- and/or Baa3	1,077		$	1,063

Included in these amounts are certain agreements that could require collateral in the event that one or more power pool participants has a credit rating change to below investment grade. Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. Additionally, ~~any~~a credit rating downgrade could impact the ability of Southern ~~Power's ability~~Power to access capital markets ~~particularly~~and would be likely to impact the ~~short-term debt market.~~cost at which it does so.

In addition, Southern Power has a PPA that could require collateral, but not accelerated payment, in the event of a downgrade of Southern ~~Power Company's~~Power's credit. The PPA requires credit assurances without stating a specific credit rating. The amount of collateral required would depend upon actual losses, if any, resulting from a credit downgrade.

Financing Activities

~~Southern Power did not issue or redeem any securities during~~During the three months ended March 31, ~~2015.~~2016, Southern Power's subsidiary repaid $3 million of long-term debt payable to TRE and borrowed $2 million due February 28, 2036 under promissory notes payable to TRE.

During the three months ended March 31, 2016, Southern Power's subsidiaries borrowed $276 million pursuant to the Project Credit Facilities at a weighted average interest rate of 1.99%. In addition, Southern Power's subsidiaries issued $8 million in letters of credit.

Subsequent to March 31, 2016, Southern Power's subsidiaries borrowed $187 million pursuant to the Project Credit Facilities at a weighted average interest rate of 1.93%.

In addition to any financings that may be necessary to meet capital requirements and contractual obligations, Southern Power ~~Company~~ plans to continue, when economically feasible, a program to retire higher-cost securities and replace these obligations with lower-cost capital if market conditions permit.

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS

FOR

THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

ALABAMA POWER COMPANY

GEORGIA POWER COMPANY

GULF POWER COMPANY

MISSISSIPPI POWER COMPANY

SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES

(UNAUDITED)

INDEX TO THE NOTES TO THE CONDENSED FINANCIAL STATEMENTS

INDEX TO APPLICABLE NOTES TO FINANCIAL STATEMENTS BY REGISTRANT

The following unaudited notes to the condensed financial statements are a combined presentation. The list below indicates the registrants to which each footnote applies.



Registrant	Applicable Notes

Southern Company	A, B, C, D, E, F, G, H, I, J

Alabama Power	A, B, C, E, F, G, H

Georgia Power	A, B, C, E, F, G, H

Gulf Power	A, B, C, E, F, G, H

Mississippi Power	A, B, C, E, F, G, H

Southern Power	A, B, C, D, E, G, H, I

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THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

ALABAMA POWER COMPANY

GEORGIA POWER COMPANY

GULF POWER COMPANY

MISSISSIPPI POWER COMPANY

SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES

NOTES TO THE CONDENSED FINANCIAL STATEMENTS:

(UNAUDITED)


(A)	INTRODUCTION

The condensed quarterly financial statements of each registrant included herein have been prepared by such registrant, without audit, pursuant to the rules and regulations of the SEC. The Condensed Balance Sheets as of December 31, ~~2014~~2015 have been derived from the audited financial statements of each registrant. In the opinion of each registrant's management, the information regarding such registrant furnished herein reflects all adjustments, which, except as otherwise disclosed, are of a normal recurring nature, necessary to present fairly the results of operations for the ~~three-month~~ periods ended March 31, ~~2015~~2016 and ~~2014.~~2015. Certain information and footnote disclosures normally included in annual financial statements prepared in accordance with GAAP have been condensed or omitted pursuant to such rules and regulations, although each registrant believes that the disclosures regarding such registrant are adequate to make the information presented not misleading. Disclosures which would substantially duplicate the disclosures in the Form 10-K and details which have not changed significantly in amount or composition since the filing of the Form 10-K are generally omitted from this Quarterly Report on Form 10-Q unless specifically required by GAAP. Therefore, these Condensed Financial Statements should be read in conjunction with the financial statements and the notes thereto included in the Form 10-K. Due to the seasonal variations in the demand for energy, operating results for the periods presented are not necessarily indicative of the operating results to be expected for the full year.

Certain prior year data presented in the financial statements have been reclassified to conform to the current year presentation. These reclassifications had no impact on the results of operations, financial position, or cash flows of any registrant.

On February 6, 2015, Gulf Power announced plans to retire its coal-fired generation at Plant Smith Units 1 and 2 (357 MWs) by March 31, 2016. In connection with this retirement, Gulf Power reclassified the net carrying value of these units from plant in service, net of depreciation, to other utility plant, net at March 31, 2015. Gulf Power expects to recover through its rates the remaining book value of the retired units and certain costs associated with the retirements; however, recovery will be considered by the Florida PSC in future rate proceedings.

Recently Issued Accounting Standards

~~In May 2014,~~On February 25, 2016, the ~~Financial Accounting Standards Board (FASB)~~FASB issued ~~ASC 606,~~ASU No. 2016-02, ~~Revenue from Contracts~~Leases(Topic 842) (ASU 2016-02). ASU 2016-02 requires lessees to recognize on the balance sheet a lease liability and a right-of-use asset for all leases. ASU 2016-02 also changes the recognition, measurement, and presentation of expense associated with ~~Customers. ASC 606 revises~~leases and provides clarification regarding the identification of certain components of contracts that would represent a lease. The accounting required by lessors is relatively unchanged and there is no change to the accounting for revenue recognition. On April 29, 2015, the FASB issued an exposure draft proposing the standard be effective for fiscal years beginning after December 15, 2017. The registrants continue to evaluate the requirements of ASC 606. The ultimate impact of the new standard has not yet been determined.

~~On February 18, 2015, the FASB issued Accounting Standards Update (ASU) 2015-02,~~ ~~Amendments to the Consolidation Analysis~~, which makes certain changes to both the variable interest model and the voting model, including changes to the identification of variable interests, the variable interest entity characteristics for a limited partnership or similar entity, and the primary beneficiary determination. Thisexisting leveraged leases. ASU 2016-02 is effective for fiscal years beginning after December 15, ~~2015. Southern Power is~~2018, with early adoption permitted. The registrants are currently evaluating ~~these requirements. The~~the new standard and have not yet determined its ultimate ~~impact~~impact; however, adoption of ~~this~~ ASU 2016-02 is expected to have a significant impact on Southern ~~Power has not yet been determined.~~Company and the traditional operating companies' balance sheets.

On March 30, 2016, the FASB issued ASU No. 2016-09, Compensation-Stock Compensation(Topic 718): Improvements to Employee Share-Based Payment Accounting (ASU 2016-09). ASU 2016-09 changes the accounting for income taxes and the cash flow presentation for share-based payment award transactions. Most significantly, entities are required to recognize all excess tax benefits and deficiencies related to the exercise or vesting of stock compensation as income tax expense or benefit in the income statement. Southern Company and the traditional operating companies currently recognize any excess tax benefits and deficiencies related to the exercise and vesting of stock compensation in additional paid-in capital. ASU 2016-09 is effective for fiscal years

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

~~On April 7, 2015, the FASB issued ASU No. 2015-03,~~ ~~Interest – Imputation of Interest (Subtopic 835-30):Simplifying the Presentation of Debt Issuance Costs~~. The ASU requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability and is effective for fiscal years beginning after December 15, 2015. Southern Company currently reflects unamortized debt issuance costs in unamortized debt issuance expense on its balance sheet. The traditional operating companies and Southern Power currently reflect unamortized debt issuance costs in other deferred charges and assets on their balance sheets. Upon2016, with early adoption ~~the reclassification will not have a material impact on the results of operations, financial position, or cash flows of any registrant.~~

~~Asset Retirement Obligations~~

See Note 1 to the financial statements of Southern Company, Alabama Power, Georgia Power, Gulf Power, and Mississippi Power under "Asset Retirement Obligations and Other Costs of Removal" in Item 8 of the Form 10-K for additional information regarding the EPA's regulation of CCR.

On April 17, 2015, the EPA published the Disposal of Coal Combustion Residuals from Electric Utilities final rule (CCR Rule) in the Federal Register, setting October 14, 2015 as the effective date of the CCR Rule. The ultimate impact of the CCR Rule cannot be determined at this time~~and will depend on the traditional operating companies' ongoing review of the CCR Rule, the results of initial and ongoing minimum criteria assessments, and the outcome of legal challenges.~~

~~In the second quarter 2015,~~permitted. Southern Company and the traditional operating companies ~~expect to record incremental asset retirement obligations (ARO) related to~~are currently evaluating the ~~CCR Rule in amounts currently estimated to fall within the following ranges:~~new standard and have not yet determined its ultimate impact.

Low High
(in millions)
Southern Company $ 525
$ 575
Alabama Power $ 330
$ 350
Georgia Power $ 10
$ 20
Gulf Power $ 70
$ 80
Mississippi Power $ 75
$ 85


(B)	CONTINGENCIES AND REGULATORY MATTERS

See Note 3 to the financial statements of the registrants in Item 8 of the Form 10-K for information relating to various lawsuits, other contingencies, and regulatory matters.

General Litigation Matters

Each registrant is subject to certain claims and legal actions arising in the ordinary course of business. In addition, business activities of Southern Company's subsidiaries are subject to extensive governmental regulation related to public health and the environment, such as regulation of air emissions and water discharges. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements such as air quality and water standards, has occurred throughout the U.S. This litigation has included claims for damages alleged to have been caused by CO₂ and other emissions, CCR, and alleged exposure to hazardous materials, and/or requests for injunctive relief in connection with such matters.

The ultimate outcome of such pending or potential litigation against each registrant and any subsidiaries cannot be predicted at this time; however, for current proceedings not specifically reported herein or in Note 3 to the financial statements of each registrant in Item 8 of the Form 10-K, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on such registrant's financial statements.

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~~NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)~~

~~(UNAUDITED)~~

~~Environmental Matters~~

~~New Source Review Actions~~

As part of a nationwide enforcement initiative against the electric utility industry which began in 1999, the EPA brought civil enforcement actions in federal district court against Alabama Power and Georgia Power alleging violations of the New Source Review (NSR) provisions of the Clean Air Act at certain coal-fired electric generating units, including units co-owned by Gulf Power and Mississippi Power. These civil actions seek penalties and injunctive relief, including orders requiring installation of the best available control technologies at the affected units. The case against Georgia Power (including claims related to a unit co-owned by Gulf Power) has been administratively closed in the U.S. District Court for the Northern District of Georgia since 2001. The case against Alabama Power (including claims involving a unit co-owned by Mississippi Power) has been actively litigated in the U.S. District Court for the Northern District of Alabama, resulting in a settlement in 2006 of the alleged NSR violations at Plant Miller; voluntary dismissal of certain claims by the EPA; and a grant of summary judgment for Alabama Power on all remaining claims and dismissal of the case with prejudice in 2011. In 2013, the U.S. Court of Appeals for the Eleventh Circuit affirmed in part and reversed in part the 2011 judgment in favor of Alabama Power, and the case has been transferred back to the U.S. District Court for the Northern District of Alabama for further proceedings.

Southern Company and each traditional operating company believe each such traditional operating company complied with applicable laws and regulations in effect at the time the work in question took place. The Clean Air Act authorizes maximum civil penalties of ~~$25,000~~ to ~~$37,500~~ per day, per violation, depending on the date of the alleged violation. An adverse outcome could require substantial capital expenditures that cannot be determined at this time and could possibly require payment of substantial penalties. Such expenditures could affect future results of operations, cash flows, and financial condition if such costs are not recovered through regulated rates. The ultimate outcome of these matters cannot be determined at this time.

Environmental Remediation

The Southern Company system must comply with environmental laws and regulations that cover the handling and disposal of waste and releases of hazardous substances. Under these various laws and regulations, the Southern Company system could incur substantial costs to clean up ~~properties.~~affected sites. The traditional operating companies have each received authority from their respective state PSCs to recover approved environmental compliance costs through regulatory mechanisms. These rates are adjusted annually or as necessary within limits approved by the state PSCs.

Georgia Power's environmental remediation liability as of March 31, ~~2015~~2016 was ~~$27~~$28 million. Georgia Power has been designated or identified as a potentially responsible party (PRP) at sites governed by the Georgia Hazardous Site Response Act and/or by the federal Comprehensive Environmental Response, Compensation, and Liability Act (CERCLA), including a site in Brunswick, Georgia on the CERCLA National Priorities List. The ~~parties~~PRPs at the Brunswick site have completed ~~the~~a removal ~~of wastes from the Brunswick site~~action as ordered by the EPA. Additional ~~cleanup and claims for recovery of natural resource damages~~response actions at this site orare anticipated. In September 2015, Georgia Power entered into an allocation agreement with another PRP, under which that PRP will be responsible (as between Georgia Power and that PRP) for paying and performing certain investigation, assessment, remediation, and other incidental activities at the ~~assessment~~Brunswick site. Assessment and potential cleanup of other sites are anticipated.

Georgia Power and numerous other entities have been designated by the EPA as PRPs at the Ward Transformer Superfund site located in Raleigh, North Carolina. In 2011, the EPA issued a Unilateral Administrative Order (UAO) to Georgia Power and 22 other parties, ordering specific remedial action of certain areas at the site. Later in 2011, Georgia Power filed a response with the EPA stating it has sufficient cause to believe it is not a liable party under CERCLA. The EPA notified Georgia Power in 2011 that it is considering enforcement options against Georgia Power and other non-complying UAO recipients. If the EPA pursues enforcement actions and the court determines that a respondent failed to comply with the UAO without sufficient cause, the EPA may also seek civil penalties of up to ~~$37,500~~ ~~per day for the violation and punitive damages of up to~~ ~~three~~ ~~times the costs incurred by the EPA as a result of the party's failure to comply with the UAO.~~

In addition to the EPA's action at this site, Georgia Power, along with many other parties, was sued in a private action by several existing PRPs for cost recovery related to the removal action. In 2013, the U.S. District Court for

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~~NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)~~

~~(UNAUDITED)~~

the Eastern District of North Carolina Western Division granted Georgia Power's summary judgment motion ruling that Georgia Power has no liability in the private action. On March 20, 2015, the U.S. Court of Appeals for the Fourth Circuit affirmed the lower court's ruling. The plaintiffs may seek review by the U.S. Supreme Court.

The ultimate outcome of these matters will depend upon the success of defenses asserted, the ultimate number of PRPs participating in the cleanup, and numerous other factors and cannot be determined at this time; however, as a result of Georgia Power's regulatory treatment for environmental remediation expenses, these matters are not expected to have a material impact on Southern Company's or Georgia Power's financial statements. ~~See Note 1 to the financial statements of Georgia Power under "Environmental Remediation Recovery" in Item 8 of the Form 10-K for additional information regarding the regulatory treatment.~~

Gulf Power's environmental remediation liability includes estimated costs of environmental remediation projects of approximately ~~$47~~$46 million as of March 31, ~~2015.~~2016. These estimated costs primarily relate to site closure criteria by the Florida Department of Environmental Protection (FDEP) for potential impacts to soil and groundwater from herbicide applications at Gulf Power substations. The schedule for completion of the remediation projects is subject to FDEP approval. The projects have been approved by the Florida PSC for recovery through Gulf Power's environmental cost recovery clause; therefore, these liabilities have no impact on net income.

In 2003, Mississippi Power and numerous other entities were designated by the Texas Commission on Environmental Quality (TCEQ) as PRPs at a site that was owned by an electric transformer company that handled Mississippi Power's transformers. The TCEQ approved the final site remediation plan in 2013 and, in March 2014, the impacted utilities, including Mississippi Power, agreed to commence remediation actions on the site. Mississippi Power's environmental remediation liability was $0.5 million as

126

Table of ~~March 31, 2015 and is expected to be recovered through the ECO Plan.~~Contents

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

The final outcome of these matters cannot be determined at this time. However, based on the currently known conditions at these sites and the nature and extent of activities relating to these sites, management of Southern Company ~~Georgia Power,~~and Gulf ~~Power, and Mississippi~~ Power does not believe that additional liabilities, if any, at these sites would be material to their respective financial statements.

~~Nuclear Fuel Disposal Cost Litigation~~

Acting through the DOE and pursuant to the Nuclear Waste Policy Act of 1982, the U.S. government entered into contracts with Alabama Power and Georgia Power that require the DOE to dispose of spent nuclear fuel and high level radioactive waste generated at Plants Hatch and Farley and Plant Vogtle Units 1 and 2 beginning no later than January 31, 1998. The DOE has yet to commence the performance of its contractual and statutory obligation to dispose of spent nuclear fuel. Consequently, Alabama Power and Georgia Power pursued and continue to pursue legal remedies against the U.S. government for its partial breach of contract.

In December 2014, the Court of Federal Claims entered a judgment in favor of Georgia Power and Alabama Power in the second spent nuclear fuel lawsuit seeking damages for the period from January 1, 2005 through December 31, 2010. Georgia Power recovered approximately $18 million, based on its ownership interests, and Alabama Power recovered approximately $26 million. The judgment amounts were paid on March 19, 2015. In March 2015, Georgia Power credited the award to accounts where the original costs were charged and reduced rate base, fuel, and cost of service for the benefit of customers. The final outcome of this matter for Alabama Power cannot be determined at this time; however, no material impact on Southern Company's or Alabama Power's net income is expected as the damage amounts collected from the government are expected to be used for the benefit of customers.

In March 2014, Alabama Power and Georgia Power filed additional lawsuits against the U.S. government for the costs of continuing to store spent nuclear fuel at Plants Farley and Hatch and Plant Vogtle Units 1 and 2 for the period from January 1, 2011 through December 31, 2013. The damage period was subsequently extended to December 31, 2014. Damages will continue to accumulate until the issue is resolved or storage is provided. No amounts have been recognized in the financial statements as of March 31, 2015 for any potential recoveries from

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~~NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)~~

~~(UNAUDITED)~~

the additional lawsuits. The final outcome of these matters cannot be determined at this time; however, no material impact on Southern Company's, Alabama Power's, or Georgia Power's net income is expected.

FERC Matters

Municipal and Rural Associations Tariff

See Note 3 to the financial statements of Mississippi Power under "FERC Matters" in Item 8 of the Form 10-K for additional information regarding a settlement agreement entered into by Mississippi Power regarding the establishment of a regulatory asset for Kemper IGCC-related costs. See Note 3 to the financial statements of Southern Company and Mississippi Power under "Integrated Coal Gasification Combined Cycle" in Item 8 of the Form 10-K and "Integrated Coal Gasification Combined Cycle" herein for information regarding Mississippi Power's construction of the Kemper IGCC.

On March 31, ~~2015,~~2016, Mississippi Power ~~reached a settlement agreement with its wholesale customers and~~ filed a request with the FERC ~~to forgo~~for an increase in wholesale base revenues as agreed upon in the settlement agreement reached with its wholesale customers under the Municipal and Rural Associations (MRA) cost-based electric tariff. The settlement agreement provides that base rates under the MRA cost-based electric tariff will increase ~~reflected~~approximately $7 million annually, with revised rates effective for services rendered beginning May 1, 2016. The increase is primarily due to the Plant Daniel Units 1 and 2 scrubbers, which were placed in service in November 2015. Additionally, under the ~~filing by, among~~settlement agreement, the tariff customers agreed in principle to similar regulatory treatment for tariff ratemaking as the treatment approved for retail ratemaking under the Mississippi PSC order (In-Service Asset Rate Order). The Kemper IGCC regulatory treatment primarily includes (i) recovery of only the Kemper IGCC assets currently operational and providing service to customers and other ~~things, increasing~~related costs and (ii) removing all of the Kemper IGCC CWIP with a corresponding increase in accrual of AFUDC ~~in lieu of including CWIP in rate base. The settlement agreement, if accepted~~effective May 1, 2016. If approved by the FERC, ~~provides that~~ the ~~additional accrual~~amount of ~~AFUDC~~base rate revenues to be recognized in 2016 is ~~effective April 1, 2015.~~expected to be approximately $5 million. The additional resulting AFUDC is ~~projected~~estimated to be approximately $12 million annually, of which $9 million relates to the Kemper IGCC. In addition, a settlement agreement entered into in 2014 and approved by the FERC allowed for an adjustment to the wholesale revenue requirement in the event the Kemper IGCC, or any substantial portion thereof, was placed in service before or after December 1, 2014. A regulatory asset account was recorded as a result of a portion of the Kemper IGCC being placed in service prior to the projected date. The March 31, 2015 settlement agreement provides that the regulatory asset will be amortized over nine months, beginning April 1, 2015.$6 million. The ultimate outcome of this matter cannot be determined at this time.

Fuel Cost Recovery

Mississippi Power has a wholesale MRA and a Market Based (MB) fuel cost recovery factor. At March 31, 2016, the amount of over-recovered wholesale MRA fuel costs included in the balance sheets was $25 million compared to $24 million at December 31, 2015. See Note 3 to the financial statements of Mississippi Power under "FERC Matters – Fuel Cost Recovery" in Item 8 of the Form 10-K for additional information.

Market-Based Rate Authority

The traditional operating companies and Southern Power have authority from the FERC to sell electricity at market-based rates. Since 2008, that authority, for certain balancing authority areas, has been conditioned on compliance with the requirements of an energy auction, which the FERC found to be tailored mitigation that addresses potential market power concerns. In accordance with FERC regulations governing such authority, the traditional operating companies and Southern Power filed a triennial market power analysis ~~on June 30,~~in 2014, which included continued reliance on the energy auction as tailored mitigation. OnIn April ~~27,~~ 2015, the FERC issued an order finding that the traditional operating companies' and Southern Power's existing tailored mitigation may not effectively mitigate the potential to exert market power in certain areas served by the traditional operating companies and in some adjacent areas. ~~To retain market-based rate authority, the~~The FERC ~~has~~ directed the traditional operating companies and Southern Power ~~within 60 days,~~ to show why market-based rate authority should not be revoked in these areas or to provide a mitigation plan to further address market power concerns. The traditional operating companies and Southern Power ~~are evaluating~~filed a request for rehearing in May 2015 and in June 2015 filed their response with the ~~order.~~FERC. The ultimate outcome of this matter cannot be determined at this time.

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

Retail Regulatory Matters

Alabama Power

See Note 3 to the financial statements of Southern Company and Alabama Power under "Retail Regulatory Matters – Alabama Power" and "Retail Regulatory Matters," respectively, in Item 8 of the Form 10-K for additional information regarding Alabama Power's recovery of retail costs through various regulatory clauses and accounting orders. The ~~recovery~~ balance of each regulatory clause recovery on the balance sheet follows:

Regulatory Clause
Balance Sheet Line Item March 31, 2015
December 31,
2014

(in millions)
Rate CNP Compliance – Under^*

Deferred under recovered regulatory clause revenues $ 25

$ 2
Under recovered regulatory clause revenues, current 16
47
Rate CNP PPA – Under
Deferred under recovered regulatory clause revenues 62

29
Under recovered regulatory clause revenues, current —
27
Retail Energy Cost Recovery – Over
Deferred over recovered regulatory clause revenues 81

47
Natural Disaster Reserve
Other regulatory liabilities, deferred 82

84

* Formerly Known As Rate CNP Environmental

~~Rate CNP~~

In March 2015, the Emerging Issues Task Force unanimously recommended to allow the normal purchases and normal sales exception for physical forward transactions in nodal energy markets. The FASB proposed new accounting guidance reflecting the recommendation on April 23, 2015. This guidance is subject to a public comment period before the FASB issues a final accounting standard. The ultimate outcome of this matter cannot be determined at this time.

~~Rate CNP Compliance(Formerly Known As Rate CNP Environmental)~~

See Note 3 to the financial statements of Southern Company under "Retail Regulatory Matters – Alabama Power – Rate CNP" and " – Non-Environmental Federal Mandated Costs Accounting Order" and of Alabama Power under "Retail Regulatory Matters – Rate CNP" and " – Non-Environmental Federal Mandated Costs Accounting Order" in Item 8 of the Form 10-K for additional information regarding Alabama Power's development of a revised cost recovery mechanism.

On March 3, 2015, the Alabama PSC approved a modification to Rate CNP Environmental to include compliance costs for both environmental and non-environmental mandates. The recoverable non-environmental compliance costs result from laws, regulations, and other mandates directed at the utility industry involving the security, reliability, safety, sustainability, or similar considerations impacting Alabama Power's facilities or operations. This modification to Rate CNP Environmental was effective March 20, 2015 with the revised rate now defined as Rate CNP Compliance. Alabama Power incurred $14 million of non-environmental compliance costs during the first quarter 2015 and will be limited to recovery of $50 million for the year. Customer rates will not be impacted before January 2016; therefore, the modification will increase the under-recovered position for Rate CNP Compliance during the year.



Regulatory Clause	Balance Sheet Line Item	March 31, 2016		December 31, 2015
		(in millions)
Rate CNP Compliance	Under recovered regulatory clause revenues, current	$	22	$	43
Rate CNP PPA	Deferred under recovered regulatory clause revenues	105		99
Retail Energy Cost Recovery	Other regulatory liabilities, current	173		238
	Deferred over recovered regulatory clause revenues	64		—
Natural Disaster Reserve	Other regulatory liabilities, deferred	74		75

Georgia Power

~~Integrated Resource Plan~~Rate Plans

See Note 3 to the financial statements of Southern Company and Georgia Power under "Retail Regulatory Matters – Georgia Power – ~~Integrated Resource~~Rate Plans" and "Retail Regulatory Matters – ~~Integrated Resource~~Rate Plans," respectively, in Item 8 of the Form 10-K for additional information.

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~~To comply with~~Georgia Power's revenues from regulated retail operations are collected through various rate mechanisms subject to the ~~April 16, 2015 effective date~~oversight of the ~~MATS rule,~~Georgia PSC. Georgia Power currently recovers its costs from the regulated retail business through the 2013 ARP, which includes traditional base tariff rates, Demand-Side Management tariffs, Environmental Compliance Cost Recovery tariffs, and Municipal Franchise Fee tariffs. In addition, financing costs related to the construction of Plant ~~Branch~~Vogtle Units 1, 3 and 4 ~~(1,266 MWs), Plant Yates Units 1~~are being collected through ~~5 (579 MWs),~~the NCCR tariff and ~~Plant McManus Units 1~~fuel costs are collected through separate fuel cost recovery tariffs. See "Fuel Cost Recovery" below and ~~2 (122 MWs) were retired~~Note 3 to the financial statements of Georgia Power under "Retail Regulatory Matters – Nuclear Construction" and Southern Company under "Retail Regulatory Matters – Georgia Power – Fuel Cost Recovery" and " – Nuclear Construction" in Item 8 of the Form 10-K for additional information regarding fuel cost recovery and the NCCR tariff, respectively.

Pursuant to the terms and conditions of a settlement agreement related to Southern Company's proposed acquisition of AGL Resources approved by the Georgia PSC on April ~~15, 2015. In addition, operations were discontinued at Plant Mitchell Unit 3 (155 MWs)~~14, 2016, Georgia Power's 2013 ARP will continue in effect until December 31, 2019, and ~~its decertification~~Georgia Power will be ~~requested~~required to file its next base rate case by July 1, 2019. Furthermore, through December 31, 2019, Georgia Power and Atlanta Gas Light Company (collectively, Utilities) will retain the merger savings, net of transition costs, as defined in ~~connection~~the settlement agreement; through December 31, 2022, net merger savings will be shared on a 60/40 basis between customers and the Utilities; thereafter, all merger savings will be retained by customers. See Note (I) under "Southern Company – Proposed Merger with AGL Resources" for additional information regarding the triennial Integrated Resource Plan in 2016. The switch to natural gas as the primary fuel is complete at Plant Yates Unit 7 and is underway at Plant Yates Unit 6. Plant Yates Unit 7 was returned to service on May 4, 2015 and Plant Yates Unit 6 is expected to return to service in mid-2015.Merger.

Fuel Cost Recovery

See Note 3 to the financial statements of Southern Company and Georgia Power under "Retail Regulatory Matters – Georgia Power – Fuel Cost Recovery" and "Retail Regulatory Matters – Fuel Cost Recovery," respectively, in Item 8 of the Form 10-K for additional information.

As of March 31, 2016 and December 31, 2015, Georgia Power's ~~under~~over recovered fuel balance totaled ~~$151~~$177 million and $116 million, respectively, and is included in current ~~assets~~liabilities and other deferred ~~charges and assets~~liabilities on Southern Company's and Georgia Power's Condensed Balance Sheets herein. AsOn April 14, 2016, Georgia Power filed a

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Table of December 31, 2014, Georgia Power's under recovered fuel balance totaled $199 million and is included in current assets and other deferred charges and assets on Southern Company's and Georgia Power's Condensed Balance Sheets herein. ~~On January 20, 2015,~~Contents

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

request with the Georgia PSC ~~approved the deferral of~~to decrease fuel rates by 15% effective June 1, 2016, which is expected to reduce annual billings by approximately $313 million. Georgia ~~Power's~~Power is currently scheduled to file its next fuel case ~~filing until~~by February 28, 2017. The ultimate outcome of this matter cannot be determined at ~~least June 30, 2015.~~this time.

Fuel cost recovery revenues ~~as recorded on the financial statements~~ are adjusted for differences in actual recoverable fuel costs and amounts billed in current regulated rates. Accordingly, changes in the billing factor will not have a significant effect on Southern Company's or Georgia Power's revenues or net income, but will affect cash flow.

Nuclear Construction

See Note 3 to the financial statements of Southern Company and Georgia Power under "Retail Regulatory Matters – Georgia Power – Nuclear Construction" and "Retail Regulatory Matters – Nuclear Construction," respectively, in Item 8 of the Form 10-K for additional information regarding Georgia Power's construction of Plant Vogtle Units 3 and 4, Vogtle Construction Monitoring (VCM) reports, the NCCR tariff, the Vogtle Construction Litigation (as defined below), and ~~pending litigation.~~the Contractor Settlement Agreement (as defined below).

In 2008, Georgia Power, acting for itself and as agent for the Vogtle Owners, entered into an agreement ~~(Vogtle 3 and 4 Agreement)~~ with the Contractor, pursuant to which the Contractor agreed to design, engineer, procure, construct, and test Plant Vogtle Units 3 and 4. 4 (Vogtle 3 and 4 Agreement).

Under the terms of the Vogtle 3 and 4 Agreement, the Vogtle Owners agreed to pay a purchase price that is subject to certain price escalations and adjustments, including fixed escalation amounts and index-based adjustments, as well as adjustments for change orders, and performance bonuses for early completion and unit performance. The Vogtle 3 and 4 Agreement also provides for liquidated damages upon the Contractor's failure to fulfill the schedule and performance ~~guarantees. The Contractor's liability to the Vogtle Owners for schedule and performance liquidated damages and warranty claims is~~guarantees, subject to a cap. In addition, the Vogtle 3 and 4 Agreement provides for limited cost sharing by the Vogtle Owners for Contractor costs under certain conditions (which have not occurred), with maximum additional capital costs under this provision attributable to Georgia Power (based on Georgia Power's ownership interest) of approximately $114 million. Each Vogtle Owner is severally (and not jointly) liable for its proportionate share, based on its ownership interest, of all amounts owed to the Contractor under the Vogtle 3 and 4 Agreement. Georgia Power's proportionate share is 45.7%.

On December 31, 2015, Westinghouse acquired Stone & Webster, Inc. from Chicago Bridge & Iron Company, N.V. (CB&I) and changed the name of Stone & Webster, Inc. to WECTEC Global Project Services Inc. (WECTEC). Certain ~~payment~~ obligations of Westinghouse and ~~CB&I Stone & Webster, Inc. (formerly known as Stone & Webster, Inc.)~~WECTEC under the Vogtle 3 and 4 Agreement ~~are~~were originally guaranteed by Toshiba Corporation (Westinghouse's parent company) and The Shaw Group Inc. (a(which is now a subsidiary of ~~Chicago Bridge & Iron Company, N.V.)~~CB&I), respectively. On March 9, 2016, in connection with Westinghouse's acquisition of WECTEC and pursuant to the settlement agreement described below, the guarantee of The Shaw Group Inc. was terminated. The guarantee of Toshiba Corporation remains in place. In the event of certain credit rating downgrades of any Vogtle Owner, such Vogtle Owner will be required to provide a letter of credit or other credit enhancement. Additionally, as a result of credit rating downgrades of Toshiba Corporation, Westinghouse provided the Vogtle Owners with letters of credit in an aggregate amount of $920 million in accordance with, and subject to adjustment under, the terms of the Vogtle 3 and 4 Agreement.

The Vogtle Owners may terminate the Vogtle 3 and 4 Agreement at any time for their convenience, provided that the Vogtle Owners will be required to pay certain termination costs. The Contractor may terminate the Vogtle 3 and 4 Agreement under certain circumstances, including certain Vogtle Owner suspension or delays of

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~~(UNAUDITED)~~

work, action by a governmental authority to permanently stop work, certain breaches of the Vogtle 3 and 4 Agreement by the Vogtle Owners, Vogtle Owner insolvency, and certain other events.

In 2009, the ~~NRC issued an Early Site Permit and Limited Work Authorization which allowed limited work~~Georgia PSC voted to ~~begin on~~certify construction of Plant Vogtle Units 3 and 4. The NRC certified the Westinghouse Design Control Document, as amended (DCD), for the AP1000 nuclear reactor design, in late 2011, and issued combined construction and operating licenses (COLs) in early 2012. Receipt of the COLs allowed full construction to begin. There have been technical and procedural challenges to the construction and licensing of Plant Vogtle Units 3 and 4, at the federal and state level, and additional challenges are expected as construction proceeds.

In 2012, the Vogtle Owners and the Contractor began negotiations regarding the costs associated with design changes to the DCD and the delays in the timing of approval of the DCD and issuance of the COLs, including the assertion by the Contractor that the Vogtle Owners are responsible for these costs under the terms of the Vogtle 3 and 4 Agreement. Also in 2012, Georgia Power and the other Vogtle Owners filed suit against the Contractor in the U.S. District Court for the Southern District of Georgia seeking a declaratory judgment that the Vogtle Owners are not responsible for these costs. In 2012, the Contractor also filed suit against Georgia Power and the other Vogtle Owners in the U.S. District Court for the District of Columbia alleging the Vogtle Owners are responsible for these costs. In 2013, the U.S. District Court for the District of Columbia dismissed the Contractor's suit, ruling that the proper venue is the U.S. District Court for the Southern District of Georgia. On March 10, 2015, the U.S. Court of Appeals for the District of Columbia Circuit affirmed the District Court's decision. The portion of additional costs claimed by the Contractor in its initial complaint that would be attributable to Georgia Power (based on Georgia Power's ownership interest) is approximately $425 million (in 2008 dollars). The Contractor also asserted it is entitled to extensions of the guaranteed substantial completion dates of April 2016 and April 2017 for Plant Vogtle Units 3 and 4, respectively. In May 2014, the Contractor filed an amended counterclaim to the suit pending in the U.S. District Court for the Southern District of Georgia alleging that (i) the design changes to the DCD imposed by the NRC delayed module production and the impacts to the Contractor are recoverable by the Contractor under the Vogtle 3 and 4 Agreement and (ii) the changes to the basemat rebar design required by the NRC caused additional costs and delays recoverable by the Contractor under the Vogtle 3 and 4 Agreement. The Contractor did not specify in its amended counterclaim the amounts relating to these new allegations; however, the Contractor has subsequently asserted related minimum damages (based on Georgia Power's ownership interest) of $113 million. The Contractor may from time to time continue to assert that it is entitled to additional payments with respect to these allegations, any of which could be substantial. Georgia Power has not agreed to the proposed cost or to any changes to the guaranteed substantial completion dates or that the Vogtle Owners have any responsibility for costs related to these issues. Litigation is ongoing and Georgia Power intends to vigorously defend the positions of the Vogtle Owners. Georgia Power also expects negotiations with the Contractor to continue with respect to cost and schedule. During such negotiations the parties may reach a mutually acceptable compromise of their positions.

Georgia Power is required to file semi-annual VCM reports with the Georgia PSC by February 28 and August 31 each year. If the projected ~~certified~~ construction capital costs to be borne by Georgia Power increase by 5% above the certified cost or the projected in-service dates are significantly extended, Georgia Power is required to seek an amendment to the Plant Vogtle Units 3 and 4 certificate from the Georgia PSC. In February 2013, Georgia ~~Power's eighth VCM report filed in 2013~~Power requested an amendment to the certificate to increase the estimated in-service capital cost of Plant Vogtle Units 3 and 4 from $4.4 billion to $4.8

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(UNAUDITED)

billion and to extend the estimated in-service dates to the fourth quarter 2017 (from April 2016) and the fourth quarter 2018 (from April 2017) for Plant Vogtle Units 3 and 4, respectively. In October 2013, the Georgia PSC approved a stipulation (2013 Stipulation) ~~entered into by~~between Georgia Power and the Georgia PSC ~~staff~~Staff (Staff) to waive the requirement to amend the Plant Vogtle Units 3 and 4 certificate until the completion of Plant Vogtle Unit 3 or earlier if deemed appropriate by the Georgia PSC and Georgia Power. ~~The~~

On April 15, 2015, the Georgia PSC ~~has approved eleven VCM reports covering the periods through June 30, 2014, including construction capital costs incurred, which through that date totaled $2.8 billion.~~

On January 29, 2015, Georgia Power announced it was notified by the Contractor of the Contractor's revised forecast for completion of Plant Vogtle Units 3 and 4, which would incrementally delay the previously disclosed estimated in-service dates by 18 months (from the fourth quarter of 2017 to the second quarter of 2019 for Unit 3 and from the fourth quarter of 2018 to the second quarter of 2020 for Unit 4).

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Georgia Power does not believe that the Contractor's revised forecast reflects all efforts that may be possible to mitigate the Contractor's delay. In addition, Georgia Power believes that, pursuant to the Vogtle 3 and 4 Agreement, the Contractor is responsible for the Contractor's costs related to the Contractor's delay (including any related construction and mitigation costs, which could be material) and that the Vogtle Owners are entitled to recover liquidated damages for the Contractor's delay beyond the guaranteed substantial completion dates of April 2016 and April 2017 for Plant Vogtle Units 3 and 4, respectively. Consistentissued a procedural order in connection with the Contractor's position in the pending litigation described above, Georgia Power expects the Contractor to contest any claims for liquidated damages and to assert that the Vogtle Owners are responsible for additional costs related to the Contractor's delay.

~~On February 27, 2015, Georgia Power filed its~~ twelfth VCM report, ~~with the Georgia PSC covering the period from July 1 through December 31, 2014,~~ which requested approval for an additional $0.2 billion of construction capital costs incurred during that period. The twelfth VCM report also reflected the Contractor's revised forecast for completion of Plant Vogtle Units 3 and 4 as well as additional estimated owner-related costs, which include approximately $10 million per month expected to result from the Contractor's proposed 18-month delay, including property taxes, oversight costs, compliance costs, and other operational readiness costs. No Contractor costs related to the Contractor's proposed 18-month delay were included in the twelfth VCM report. Additionally, while Georgia Power has not agreed to any change to the guaranteed substantial completion dates, the twelfth VCM report included a requested amendment (Requested Amendment) to the Plant Vogtle Units 3 and 4 certificate to reflect the Contractor's revised forecast for completion of Plant Vogtle Units 3 and 4 (second quarter of 2019 and second quarter of 2020, respectively) as well as additional estimated Vogtle Owner's costs, of approximately $10 million per month, including property taxes, oversight costs, compliance costs, and other operational readiness costs to include the estimated ~~owner's~~Vogtle Owner's costs associated with the proposed 18-month Contractor delay and to increase the estimated total in-service capital cost of Plant Vogtle Units 3 and 4 to $5.0 billion.

~~Georgia Power will continue~~ Pursuant to incur financing costs of approximately $30 million per month until Plant Vogtle Units 3 and 4 are placed in service. The twelfth VCM report estimated financing costs during the construction period to total approximately $2.5 billion.

~~On April 15, 2015,~~ the Georgia ~~PSC issued a~~PSC's procedural ~~order in connection with the twelfth VCM report. Pursuant to this~~ order, the Georgia PSC deemed the Requested Amendment unnecessary and withdrawn until the completion of construction of Plant Vogtle Unit 3 consistent with the 2013 Stipulation. The Georgia PSC recognized that the certified cost and the 2013 Stipulation do not constitute a cost recovery cap. In accordance with the Georgia Integrated Resource Planning Act, any costs incurred by Georgia Power in excess of the certified amount will be included in rate base, provided Georgia Power shows the costs to be reasonable and prudent. Financing costs up to the certified amount will be collected through the NCCR tariff until the units are placed in service and contemplated in a general base rate case, while financing costs on any construction-related costs in excess of the $4.4 billion certified amount are expected to be recovered through AFUDC.

On December 31, 2015, Westinghouse and the Vogtle Owners entered into a definitive settlement agreement (Contractor Settlement Agreement) to resolve disputes between the Vogtle Owners and the Contractor under the Vogtle 3 and 4 Agreement, including litigation that was pending in the U.S. District Court for the Southern District of Georgia (Vogtle Construction Litigation). Effective December 31, 2015, Georgia Power, acting for itself and as agent for the other Vogtle Owners, and the Contractor entered into an amendment to the Vogtle 3 and 4 Agreement to implement the Contractor Settlement Agreement. The Contractor Settlement Agreement and the related amendment to the Vogtle 3 and 4 Agreement (i) restrict the Contractor's ability to seek further increases in the contract price by clarifying and limiting the circumstances that constitute nuclear regulatory changes in law; (ii) provide for enhanced dispute resolution procedures; (iii) revise the guaranteed substantial completion dates to match the current estimated in-service dates of June 30, 2019 for Unit 3 and June 30, 2020 for Unit 4; (iv) provide that delay liquidated damages will commence from the current estimated nuclear fuel loading date for each unit, which is December 31, 2018 for Unit 3 and December 31, 2019 for Unit 4; and (v) provide that Georgia Power, based on its ownership interest, will pay to the Contractor and capitalize to the project cost approximately $350 million, of which approximately $241 million had been paid as of March 31, 2016. In addition, the Contractor Settlement Agreement provides for the resolution of other open existing items relating to the scope of the project under the Vogtle 3 and 4 Agreement, including cyber security, for which costs were reflected in Georgia Power's previously disclosed in-service cost estimate. Further, as part of the settlement and Westinghouse's acquisition of WECTEC: (i) Westinghouse engaged Fluor Enterprises, Inc., a subsidiary of Fluor Corporation, as a new construction subcontractor; and (ii) the Vogtle Owners, CB&I, and The Shaw Group Inc. entered into mutual releases of any and all claims arising out of events or circumstances in connection with the construction of Plant Vogtle Units 3 and 4 that occurred on or before the date of the Contractor Settlement Agreement. On January 5, 2016, the Vogtle Construction Litigation was dismissed with prejudice.

On January 21, 2016, Georgia Power submitted the Contractor Settlement Agreement and the related amendment to the Vogtle 3 and 4 Agreement to the Georgia PSC for its review. In accordance with the Georgia PSC's subsequent order, on April 5, 2016, Georgia Power filed supplemental information in support of the Contractor Settlement Agreement and Georgia Power's position that all construction costs to date have been prudently incurred and that the current estimated in-service capital cost and schedule are reasonable. The Staff will conduct a review of all costs incurred related to Plant Vogtle Units 3 and 4, the schedule for completion of Plant Vogtle Units 3 and 4, and the

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Contractor Settlement Agreement and the Staff is authorized to engage in related settlement discussions with Georgia Power and any intervenors.

The order provides that the Staff is required to report to the Georgia PSC by October 19, 2016 with respect to the status of its review and any settlement-related negotiations. If a settlement with the Staff is reached with respect to costs of Plant Vogtle Units 3 and 4, the Georgia PSC will then conduct a hearing to consider whether to approve that settlement. If a settlement with the Staff is not reached, the Georgia PSC will determine how to proceed, including (i) modifying the 2013 Stipulation, (ii) directing Georgia Power to file a request for an amendment to the certificate for Plant Vogtle Units 3 and 4, (iii) issuing a scheduling order to address remaining disputed issues, or (iv) taking any other option within its authority.

The Georgia PSC has approved thirteen VCM reports covering the periods through June 30, 2015, including construction capital costs incurred, which through that date totaled $3.1 billion. On February 26, 2016, Georgia Power filed its fourteenth VCM report with the Georgia PSC covering the period from July 1 through December 31, 2015. The fourteenth VCM report does not include a requested amendment to the certified cost of Plant Vogtle Units 3 and 4. Georgia Power is requesting approval of $160 million of construction capital costs incurred during that period. Georgia Power anticipates to incur average financing costs of approximately $27 million per month from January 2016 until Plant Vogtle Units 3 and 4 are placed in service. The updated in-service capital cost forecast is $5.44 billion and includes costs related to the Contractor Settlement Agreement. Estimated financing costs during the construction period total approximately $2.4 billion. Georgia Power's CWIP balance for Plant Vogtle Units 3 and 4 was approximately $3.7 billion as of March 31, 2016.

There have been technical and procedural challenges to the construction and licensing of Plant Vogtle Units 3 and 4, at the federal and state level, and additional challenges may arise as construction proceeds. Processes are in place that are designed to assure compliance with the requirements specified in the ~~DCD~~Westinghouse Design Control Document and the ~~COLs,~~combined construction and operating licenses, including inspections by Southern Nuclear and the NRC that occur throughout construction. As a result of such compliance processes, certain license amendment requests have been filed and approved or are pending before the NRC. Various design and other licensing-based compliance issues ~~are expected to~~may arise as construction proceeds, which may result in additional license amendments or require other resolution. If any license amendment requests or other licensing-based compliance issues are not resolved in a timely manner, there may be delays in the project schedule that could result in increased costs either to the Vogtle Owners or the Contractor or to both.

As construction continues, the risk remains that ~~ongoing~~ challenges with Contractor performance including ~~additional challenges in its~~ fabrication, assembly, delivery, and installation of the shield building and structural modules, delays in the receipt of the remaining permits necessary for the operation of Plant Vogtle Units 3 and 4, or other issues could arise and may further impact project schedule and cost. In addition, the IRS allocated production tax credits to each of Plant Vogtle Units 3 and 4, which require the applicable unit to be placed in service before 2021.

~~Additional~~Future claims by the Contractor or Georgia Power (on behalf of the Vogtle Owners) ~~are also likely to~~could arise throughout construction. These claims may be resolved through formal and informal dispute resolution procedures under the Vogtle 3 and 4 Agreement ~~but also~~and, under the enhanced dispute resolution procedures, may be resolved through ~~litigation.~~

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~~Table~~litigation after the completion of ~~Contents~~nuclear fuel load for both units.

~~NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)~~

~~(UNAUDITED)~~

The ultimate outcome of these matters cannot be determined at this time.

Gulf Power

Retail Base Rate Case

See Note 3 to the financial statements of Gulf Power under "Retail Regulatory Matters – Retail Base Rate Case" in Item 8 of the Form 10-K for additional information.

In ~~December~~ 2013, the Florida PSC approved a settlement agreement providing that ~~provides~~ Gulf Power may reduce depreciation ~~expense~~ and record a regulatory asset up to $62.5 million between January 2014 and June 2017. In any given month, such depreciation ~~expense~~ reduction may not exceed the amount necessary for the retail ROE, as reported to the Florida PSC

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monthly, to reach the midpoint of the authorized retail ROE range then in effect. ~~Gulf Power recognized a $19.6 million reduction in depreciation expense in~~For 2014, 2015, and the first three months of ~~2015.~~2016, Gulf Power recognized reductions in depreciation of $8.4 million, $20.1 million, and $5.6 million, respectively.

Cost Recovery Clauses

See Note 3 to the financial statements of Gulf Power under "Retail Regulatory Matters – Cost Recovery Clauses" in Item 8 of the Form 10-K for additional information regarding Gulf Power's recovery of retail costs through various regulatory clauses and accounting orders. Gulf Power has four regulatory clauses which are approved by the Florida PSC. The ~~recovery~~ balance of each regulatory clause recovery on the balance sheet follows:

Recovery Clause
Balance Sheet Location
March 31, 2015
December 31, 2014

(in millions)
Fuel Cost Recovery – Under
Under recovered regulatory clause revenues
$ 32

$ 40
Purchased Power Capacity Recovery – Under
Under recovered regulatory clause revenues
3

—
Environmental Cost Recovery – Under
Under recovered regulatory clause revenues
12

10
Energy Conservation Cost Recovery – Under
Under recovered regulatory clause revenues
1

3



Regulatory Clause	Balance Sheet Location	March 31, 2016		December 31, 2015
		(in millions)
Fuel Cost Recovery	Other regulatory liabilities, current	$	20	$	18
Purchased Power Capacity Recovery	Under recovered regulatory clause revenues	4		1
Environmental Cost Recovery	Under recovered regulatory clause revenues	17		19
Energy Conservation Cost Recovery	Other regulatory liabilities, current	2		4

Mississippi Power

Performance Evaluation Plan

See Note 3 to the financial statements of Mississippi Power under "Retail Regulatory Matters – Performance Evaluation Plan" in Item 8 of the Form 10-K for additional information regarding Mississippi Power's base rates.

On ~~March 17, 2015,~~April 1, 2016, Mississippi Power submitted its annual PEP lookback filing for ~~2014,~~2015, which ~~indicated no~~reflected the need for a $5 million surcharge ~~or refund. On March 26, 2015,~~to be recovered from customers. The filing has been suspended for review by the Mississippi ~~PSC suspended the filing to allow more time for review.~~

PSC. The ultimate outcome of this matter ~~cannot be determined at this time.~~

~~System Restoration Rider~~

~~See Note 1 to the financial statements of Mississippi Power under "Provision for Property Damage" in Item 8 of the Form 10-K for additional information.~~

On February 2, 2015, Mississippi Power submitted its 2015 System Restoration Rider (SRR) rate filing with the Mississippi PSC, which proposed that the 2015 SRR rate remain level at zero and Mississippi Power be allowed to accrue $3 million to the property damage reserve in 2015. On March 3, 2015, the Mississippi PSC suspended the filing to allow more time for review.

~~The ultimate outcome of this matter cannot be determined at this time.~~

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~~(UNAUDITED)~~

~~Environmental Compliance Overview Plan~~

See Note 3 to the financial statements of Mississippi Power under "Retail Regulatory Matters – Environmental Compliance Overview Plan" in Item 8 of the Form 10-K for information on Mississippi Power's annual environmental filing with the Mississippi PSC.

In 2012, the Mississippi PSC approved Mississippi Power's request for a CPCN to construct scrubbers on Plant Daniel Units 1 and 2, which are scheduled to be placed in service in September and November 2015, respectively. These units are jointly owned by Mississippi Power and Gulf Power, with 50% ownership each. The estimated total cost of the project is approximately $660 million, with Mississippi Power's portion being $330 million, excluding AFUDC. Mississippi Power's portion of the cost is expected to be recovered through the ECO Plan following the scheduled completion of the project in December 2015. As of March 31, 2015, total project expenditures were $570 million, of which Mississippi Power's portion was $290 million, excluding AFUDC of $22 million.

On February 25, 2015, Mississippi Power submitted its annual ECO filing for 2015, which indicated an annual increase in revenues of approximately $8 million. The filing is under review by the Mississippi PSC.

~~The ultimate outcome of these matters~~ cannot be determined at this time.

Fuel Cost Recovery

See Note 3 to the financial statements of Mississippi Power under "Retail Regulatory Matters – Fuel Cost Recovery" in Item 8 of the Form 10-K for information regarding Mississippi Power's retail fuel cost recovery.

At March 31, ~~2015,~~2016, the amount of over-recovered retail fuel costs included on Mississippi Power's Condensed Balance Sheet herein was ~~$15~~$80 million compared to ~~under-recovered~~over-recovered retail fuel costs of $2$71 million at December 31, ~~2014.~~2015.

~~Ad Valorem Tax Adjustment~~

~~See Note 3~~The Mississippi PSC conditionally approved a decrease of $120 million annually in fuel cost recovery rates on January 5, 2016, effective with the first billing cycle of February. As required by the order, on February 1, 2016, Mississippi Power submitted updated natural gas price forecasts and resulting fuel factors to the ~~financial statements of~~ Mississippi ~~Power under "Retail Regulatory Matters – Ad Valorem Tax Adjustment" in Item 8 of~~PSC. If approved by the ~~Form 10-K for~~Mississippi PSC, the updated forecast would decrease fuel cost recovery rates by an additional ~~information.~~

~~On April 23, 2015, Mississippi Power filed its annual ad valorem tax adjustment factor filing for 2015, which requested an annual rate decrease of 0.35%, or $2~~$36 million ~~in annual retail revenues, primarily due to a decrease in average millage rates.~~

annually. The ultimate outcome of this matter cannot be determined at this time.

Integrated Coal Gasification Combined Cycle

See Note 3 to the financial statements of Southern Company and Mississippi Power under "Integrated Coal Gasification Combined Cycle" in Item 8 of the Form 10-K for information regarding Mississippi Power's construction of the Kemper IGCC.

Kemper IGCC Overview

Construction of Mississippi Power's Kemper IGCC is nearing completion and start-up activities will continue until the Kemper IGCC is placed in service. The Kemper IGCC will utilize an IGCC technology with an output capacity

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of 582 MWs. The Kemper IGCC will be fueled by locally mined lignite (an abundant, lower heating value coal) from a mine owned by Mississippi Power and situated adjacent to the Kemper IGCC. The mine, operated by North American Coal Corporation, started commercial operation in 2013. In connection with the Kemper IGCC, Mississippi Power constructed and plans to operate approximately 61 miles of CO₂ pipeline infrastructure for the planned transport of captured CO₂ for use in enhanced oil recovery.

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~~(UNAUDITED)~~

Kemper IGCC Schedule and Cost Estimate

In 2012, the Mississippi PSC issued the 2012 MPSC CPCN Order, a detailed order confirming the CPCN originally approved by the Mississippi PSC in 2010 authorizing the acquisition, construction, and operation of the Kemper IGCC.

The certificated cost estimate of the Kemper IGCC included in the 2012 MPSC CPCN Order was $2.4 billion, net of $245 million of grants awarded to the Kemper IGCC project by the DOE under the Clean Coal Power Initiative Round 2 ~~(DOE~~(Initial DOE Grants) and excluding the cost of the lignite mine and equipment, the cost of the CO₂ pipeline facilities, and AFUDC related to the Kemper IGCC. The 2012 MPSC CPCN Order approved a construction cost cap of up to $2.88 billion, with recovery of prudently-incurred costs subject to approval by the Mississippi PSC. The Kemper IGCC was originally projected to be placed in service in May 2014. Mississippi Power placed the combined cycle and the associated common facilities portion of the Kemper IGCC in service using natural gas in August 2014 and ~~continues~~currently expects to ~~focus on completing~~place the remainder of the Kemper IGCC, including the gasifier and the gas clean-up facilities, ~~for which~~in service during the ~~in-service date is currently expected to occur in the first half~~third quarter 2016.

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(UNAUDITED)

Recovery of the ~~Kemper IGCC~~ costs subject to the cost cap and the cost of the lignite mine and equipment, the cost of the CO₂ pipeline facilities, AFUDC, and certain general exceptions, including change of law, force majeure, and beneficial capital (which exists when Mississippi Power demonstrates that the purpose and effect of the construction cost increase is to produce efficiencies that will result in a neutral or favorable effect on customers relative to the original proposal for the CPCN) (Cost Cap Exceptions) ~~remain~~remains subject to review and approval by the Mississippi PSC. Mississippi Power's Kemper IGCC 2010 project estimate, current cost estimate (which includes the impacts of the Mississippi Supreme Court's (Court) ~~decision)~~decision discussed herein under "Rate Recovery of Kemper IGCC Costs – 2013 MPSC Rate Order"), and actual costs incurred as of March 31, ~~2015, as adjusted for the Court's decision,~~2016, are as follows:

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Cost Category	2010 Project Estimate^(f)		Current Estimate		Actual Costs at March 31, 2015		2010 Project Estimate^(f)		Current Cost Estimate^(a)			Actual Costs
	(in billions)						(in billions)
Plant Subject to Cost Cap^(a)(g)	$	2.40	$	4.94	$	4.37	$	2.40	$	5.35		$	4.99
Lignite Mine and Equipment	0.21		0.23		0.23		0.21		0.23			0.23
CO₂ Pipeline Facilities	0.14		0.11		0.10		0.14		0.11			0.12
AFUDC^(b)(c)	0.17		0.64		0.48
AFUDC^(c)							0.17		0.71			0.62
Combined Cycle and Related Assets Placed in Service – Incremental^(d)(g)	—		0.02		—		—		0.02			0.01
General Exceptions	0.05		0.10		0.08		0.05		0.10			0.09
Deferred Costs^(e)(g)	—		0.18		0.14		—		0.20			0.18
Total Kemper IGCC^(a)(c)	$	2.97	$	6.22	$	5.40
Additional DOE Grants^(h)							—		(0.14		)	—
Total Kemper IGCC							$	2.97	$	6.58		$	6.24


(a)	Amounts in the Current Cost Estimate reflect estimated costs through September 30, 2016.

(b)

The 2012 MPSC CPCN Order approved a construction cost cap of up to $2.88 billion, net of the Initial DOE Grants and excluding the Cost Cap Exceptions. The Current Cost Estimate and the Actual Costs include non-incremental operating and maintenance costs related to the combined cycle and associated common facilities placed in service in August 2014 that are subject to the $2.88 billion cost cap and exclude post-in-service costs for the lignite mine. See "Rate Recovery of Kemper IGCC Costs – 2013 MPSC Rate Order" herein for additional information. The Current Cost Estimate and the Actual Costs reflect 100% of the costs of the Kemper IGCC. See note (g) for additional information.

~~(b)~~(c)

Mississippi Power's original estimate included recovery of financing costs during construction rather than the accrual of AFUDC. This approach was not approved by the Mississippi PSC in 2012 as described in "Rate Recovery of Kemper IGCC Costs." The current estimate ~~includes an approximately $9 million increase in AFUDC related to~~reflects the impact of a settlement agreement with the wholesale customers for cost-based rates under FERC's jurisdiction. See "FERC Matters" herein for additional information.


~~(c)~~	~~Amounts in the Current Estimate reflect estimated costs through March 31, 2016.~~


(d)	Incremental operating and maintenance costs related to the combined cycle and associated common facilities placed in service in August 2014, net of costs related to energy sales. See "Rate Recovery of Kemper IGCC Costs – 2013 MPSC Rate Order" herein for additional information.


(e)	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 and ~~Liabilities."~~Liabilities" herein.


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


(g)	Beginning in the third quarter 2015, certain costs, including debt carrying costs (associated with assets placed in service and other non-CWIP accounts), that previously were deferred as regulatory assets are now being recognized through income; however, such costs continue to be included in the Current Cost Estimate and the Actual Costs at March 31, 2016.


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

Of the total costs, including post-in-service costs for the lignite mine, incurred as of March 31, ~~2015, $3.27~~2016, $3.61 billion was included in property, plant, and equipment (which is net of the Initial DOE Grants and estimated probable losses of ~~$2.06~~$2.47 billion), $2$6 million in other property and investments, ~~$52~~$75 million in fossil fuel stock, ~~$35~~$45 million in materials and supplies, ~~$174~~$22 million in other regulatory assets, ~~$12~~current, $196 million in other regulatory assets, deferred, $1 million in other current assets, and $11 million in other deferred charges and assets ~~and $24 million in AROs~~ in the balance ~~sheet, with $1 million previously expensed.~~sheet.

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Mississippi Power does not intend to seek ~~any~~ rate recovery ~~or joint owner contributions~~ for any costs related to the construction of the Kemper IGCC that exceed the $2.88 billion cost cap, net of the Initial DOE Grants and excluding the Cost Cap Exceptions. Mississippi Power recorded pre-tax charges to income for revisions to the cost estimate above the cost cap of $9$53 million ($633 million after tax) in the first quarter ~~2015. This amount is~~2016. Since 2012, in ~~addition to~~the aggregate, Mississippi Power has incurred charges ~~totaling $868 million ($536 million after tax), $1.10~~of $2.47 billion ($~~681 million after tax), and $78 million ($48 million~~1.52 billion after tax) as a result of changes in ~~2014, 2013, and 2012, respectively. Southern Company recorded pre-tax charges to income for revisions to~~ the cost estimate ~~of $868 million ($536 million after tax) and $1.2 billion ($729 million after tax) in 2014 and 2013, respectively.~~above the cost cap for the Kemper IGCC through March 31, 2016. The ~~increases~~increase to the cost estimate in the first quarter ~~2015~~2016 primarily ~~reflected~~reflects costs for the extension of the Kemper IGCC's projected in-service date through September 30, 2016, and increased efforts related to ~~additional labor costs~~operational readiness and challenges in ~~support of~~ start-up and ~~operational readiness activities. The current estimate~~commissioning activities which includes ~~costs through March 31, 2016.~~the cost of repairs and modifications to the refractory lining inside the gasifiers. Any ~~further~~ extension of the in-service date beyond September 30, 2016 is currently estimated to result in additional base costs of approximately $25 million to ~~$30~~$35 million per month, which includes maintaining necessary levels of start-up labor, materials, and fuel, as well as operational resources required to execute start-up and commissioning activities. However, additional costs may be required for remediation of any further equipment and/or design issues identified. Any ~~further~~ extension of the in-service date with respect to the Kemper IGCC beyond September 30, 2016 would also increase costs for the Cost Cap Exceptions, which are not subject to the $2.88 billion cost cap established by the Mississippi PSC. These costs include AFUDC, which is currently estimated to total approximately ~~$13~~$14 million per month, as well as carrying

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~~(UNAUDITED)~~

costs and operating expenses on Kemper IGCC assets placed in service and consulting and legal fees ~~which are being deferred as regulatory assets and are estimated to total~~of approximately $6$2 million per month. For additional information, see "2015 Rate Case" herein.

~~Any further~~Mississippi Power's analysis of the time needed to complete the start-up and commissioning activities for the Kemper IGCC will continue until the remaining Kemper IGCC assets are placed in service. Further cost increases and/or extensions of the in-service date with respect to the Kemper IGCC may result from factors including, but not limited to, labor costs and productivity, adverse weather conditions, shortages and inconsistent quality of equipment, materials, and labor, contractor or supplier delay, non-performance under ~~construction~~operating or other agreements, operational readiness, including specialized operator training and required site safety programs, unforeseen engineering or design problems, start-up activities for this first-of-a-kind technology (including major equipment failure and system integration), and/or operational performance (including additional costs to satisfy any operational parameters ultimately adopted by the Mississippi PSC). In subsequent periods, any further changes in the estimated costs to complete construction and start-up of the Kemper IGCC subject to the $2.88 billion cost cap, net of the Initial DOE Grants and excluding the Cost Cap Exceptions, will be reflected in Southern Company's ~~statements of income~~ and Mississippi Power's statements of ~~operations~~income and these changes could be material.

Rate Recovery of Kemper IGCC Costs

See "FERC Matters" herein for additional information regarding Mississippi Power's MRA cost based tariff relating to recovery of a portion of the Kemper IGCC costs from Mississippi Power's wholesale customers. Rate recovery of the retail portion of the Kemper IGCC is subject to the jurisdiction of the Mississippi PSC. See Note (G) under "Unrecognized Tax Benefits – Section 174 Research and Experimental Deduction" for additional tax information related to the Kemper IGCC.

The ultimate outcome of the rate recovery matters discussed herein, including the resolution of legal challenges, determinations of prudency, and the specific manner of recovery of prudently-incurred costs, cannot be determined at this time, but could have a material impact on Southern Company's and Mississippi Power's results of operations, financial condition, and liquidity.

2012 MPSC CPCN Order

The 2012 MPSC CPCN Order included provisions relating to both Mississippi Power's recovery of financing costs during the course of construction of the Kemper IGCC and Mississippi Power's recovery of costs following the date the Kemper IGCC is placed in service. With respect to recovery of costs following the in-service date of the Kemper IGCC, the 2012 MPSC CPCN Order provided for the establishment of operational cost and revenue parameters based upon assumptions in Mississippi Power's petition for the CPCN. Mississippi Power expects the Mississippi PSC to apply operational parameters in connection with ~~the evaluation of the Rate Mitigation Plan (defined below) and any alternative~~future proceedings related to the operation of the Kemper

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(UNAUDITED)

IGCC. To the extent the Mississippi PSC determines the Kemper IGCC does not meet the operational parameters ultimately adopted by the Mississippi PSC or Mississippi Power incurs additional costs to satisfy such parameters, there could be a material adverse impact on Southern Company's or Mississippi Power's financial statements.

2013 ~~Settlement Agreement~~MPSC Rate Order

In January 2013, Mississippi Power entered into a settlement agreement with the Mississippi PSC that ~~among other things, established~~was intended to establish the process for resolving matters regarding cost recovery related to the Kemper IGCC (2013 Settlement Agreement). Under the 2013 Settlement Agreement, Mississippi Power agreed to limit the portion of prudently-incurred Kemper IGCC costs to be included in retail rate base to the $2.4 billion certificated cost estimate, plus the Cost Cap Exceptions, but excluding AFUDC, and any other costs permitted or determined to be excluded from the $2.88 billion cost cap by the Mississippi PSC. The 2013 Settlement Agreement also allowed Mississippi Power to secure alternate financing for costs not otherwise recovered in any Mississippi PSC rate proceedings contemplated by the 2013 Settlement Agreement. The Court found the 2013 Settlement Agreement unenforceable due to a lack of public notice for the related proceedings. See "2015 Mississippi Supreme Court Decision" herein for additional information.

Legislation to authorize a multi-year rate plan and legislation to provide for alternate financing through securitization of up to $1.0 billion of prudently-incurred costs was enacted into law in 2013. Mississippi Power's intent under the 2013 Settlement Agreement was to securitize (1) prudently-incurred costs in excess of the certificated cost estimate and up to the $2.88 billion cost cap, net of the DOE Grants and excluding the Cost Cap Exceptions, (2) accrued AFUDC, and (3) other prudently-incurred costs, which include carrying costs from the estimated in-service date until securitization is finalized and other costs not included in the Rate Mitigation Plan as

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~~(UNAUDITED)~~

approved by the Mississippi PSC. The Court's decision did not impact Mississippi Power's ability to utilize alternate financing through securitization, the 2012 MPSC CPCN Order, or the February 2013 legislation. See "2015 Mississippi Supreme Court Decision" herein for additional information.

~~2013 MPSC Rate Order~~

~~Consistent with the terms of the 2013 Settlement Agreement, in~~In March 2013, the Mississippi PSC issued a rate order approving retail rate increases of 15% effective March 19, 2013 and 3% effective January 1, 2014, which collectively were designed to collect $156 million annually beginning in 2014 (2013 MPSC Rate Order)~~. For the period from March 2013 through March 31, 2015, $294 million had been collected primarily~~ to be used to mitigate customer rate impacts after the Kemper IGCC is placed in ~~service.~~ service, based on a mirror CWIP methodology (Mirror CWIP rate).

Because the 2013 MPSC Rate Order did not provide for the inclusion of CWIP in rate base as permitted by the Baseload Act, Mississippi Power continues to record AFUDC on the Kemper ~~IGCC through the in-service date.~~IGCC. Mississippi Power will not record AFUDC on any additional costs of the Kemper IGCC that exceed the $2.88 billion cost cap, except for Cost Cap Exception amounts. ~~Mississippi Power will continue to record AFUDC and collect and defer the approved rates through the in-service date until directed to do otherwise by the Mississippi PSC.~~

In August 2014, Mississippi Power provided an analysis of the costs and benefits of placing the combined cycle and the associated common facilities portion of the Kemper IGCC in service, including the expected accounting treatment. Mississippi Power's analysis requested, among other things, confirmation of Mississippi Power's accounting treatment by the Mississippi PSC of the continued collection of rates as prescribed by the 2013 MPSC Rate Order, with the current recognition as revenue of the related equity return on all assets placed in service and the deferral of all remaining rate collections under the 2013 MPSC Rate Order to a regulatory liability account. See "2015 Mississippi Supreme Court Decision" for additional information regarding the decision of the Court which would discontinue the collection of, and require the refund of, all amounts previously collected under the 2013 MPSC Rate Order.

In addition, Mississippi Power's August 2014 filing with the Mississippi PSC requested confirmation of Mississippi Power's accounting treatment by the Mississippi PSC of the continued accrual of AFUDC through the in-service date of the remainder of the Kemper IGCC and the deferral of operating costs for the combined cycle as regulatory assets. Under Mississippi Power's proposal, non-incremental costs that would have been incurred whether or not the combined cycle was placed in service would be included in a regulatory asset and would continue to be subject to the $2.88 billion cost cap. Additionally, incremental costs that would not have been incurred if the combined cycle had not gone into service would be included in a regulatory asset and would not be subject to the cost cap because these costs are incurred to support operation of the combined cycle. All energy revenues associated with the combined cycle variable operating and maintenance expenses would be credited to this regulatory asset. See "Regulatory Assets and Liabilities" for additional information. Any action by the Mississippi PSC that is inconsistent with the treatment requested by Mississippi Power could have a material impact on the results of operations, financial condition, and liquidity of Southern Company and Mississippi Power.

~~2015 Mississippi Supreme Court Decision~~

On February 12, 2015, the ~~Court issued its decision in the legal challenge to the 2013 MPSC Rate Order filed by Thomas A. Blanton. The~~ Court reversed the 2013 MPSC Rate Order based on, among other things, its findings that (1) the Mirror CWIP rate treatment was not provided for under the Baseload Act and (2) the Mississippi PSC should have determined the prudence of Kemper IGCC costs before approving rate recovery through the 2013 MPSC Rate Order. The Court also found the 2013 Settlement Agreement unenforceable due to a lack of public notice for the related proceedings. ~~The Court's ruling remands the matter to~~On July 7, 2015, the Mississippi PSC ~~to (1) fix by order~~ordered that the ~~rates that were in existence prior to~~Mirror CWIP rate be terminated effective July 20, 2015 and required the ~~2013 MPSC Rate Order, (2) fix no rate increases until~~fourth quarter 2015 refund of the ~~Mississippi PSC is in compliance with the Court's ruling, and (3) enter an order refunding amounts~~$342 million collected under the 2013 MPSC Rate ~~Order. Through March 31,~~Order, along with associated carrying costs of $29 million. The Court's decision did not impact the 2012 MPSC CPCN Order or the February 2013 legislation described below.

2015 Rate Case

As a result of the 2015 Court decision, on July 10, 2015, Mississippi Power ~~had collected $294~~filed a supplemental filing including a request for interim rates (Supplemental Notice) with the Mississippi PSC which presented an alternative rate proposal (In-Service Asset Proposal) designed to recover Mississippi Power's costs associated with the Kemper IGCC assets that are commercially operational and currently providing service to customers (the transmission facilities, combined cycle, natural gas pipeline, and water pipeline) and other related costs. On August 13, 2015, the Mississippi PSC approved the implementation of the requested interim rates designed to collect approximately $159 million ~~through rates under~~annually effective with the ~~2013 MPSC~~first billing cycle in September 2015, subject to refund and certain other conditions.

On December 3, 2015, the Mississippi PSC issued the In-Service Asset Rate ~~Order. Any required refunds would also include carrying~~Order adopting in full a stipulation entered into between Mississippi Power and the Mississippi Public Utilities Staff (MPUS) regarding the In-Service Asset Proposal. The In-Service Asset Rate Order provided for retail rate recovery of an annual revenue requirement of approximately $126 million, based on Mississippi Power's actual average capital structure, with a maximum common equity percentage of 49.733%, a 9.225% return on common equity, and actual embedded interest costs. The ~~Court's decision will become legally effective upon~~In-Service Asset Rate Order also included a prudence finding of all costs in the ~~issuance~~stipulated revenue requirement calculation for the in-service assets. The stipulated revenue requirement excluded the costs of ~~a mandate~~the Kemper IGCC related to the 15% undivided interest that was previously projected to be purchased by SMEPA. Mississippi ~~PSC. Absent specific instruction from~~Power continues to evaluate its alternatives with respect to its investment and related costs associated with the ~~Court, the~~15% undivided interest.

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(UNAUDITED)

~~Mississippi PSC will determine the method and timing~~With implementation of the ~~refund. On~~new rate on December 17, 2015, the interim rates were terminated and, in March ~~12, 2015,~~2016, Mississippi Power completed customer refunds of approximately $11 million for the difference between the interim rates collected and the permanent rates.

Pursuant to the In-Service Asset Rate Order, Mississippi Power is required to file a subsequent rate request within 18 months. As part of the filing, Mississippi Power expects to request recovery of certain costs that the Mississippi PSC had excluded from the revenue requirement calculation.

On February 25, 2016, Greenleaf CO2 Solutions, LLC filed ~~motions for rehearing. If~~a notice of appeal of the In-Service Asset Rate Order with the Court. On May 5, 2016, the Court ~~denies~~dismissed the ~~motions, it would issue the mandate~~appeal.

Legislation to ~~the Mississippi PSC no later than seven days following such decision.~~

~~Rate Mitigation Plan~~

~~In 2013,~~authorize a multi-year rate plan and legislation to provide for alternate financing through securitization of up to $1.0 billion of prudently-incurred costs was enacted into law in 2013. Mississippi Power expects to securitize prudently-incurred qualifying facility costs in ~~compliance with~~excess of the certificated cost estimate of $2.4 billion. Qualifying facility costs include, but are not limited to, pre-construction costs, construction costs, regulatory costs, and accrued AFUDC. The Court's decision regarding the 2013 MPSC Rate Order ~~filed a revision~~did not impact Mississippi Power's ability to utilize alternate financing through securitization or the ~~proposed~~February 2013 legislation.

Mississippi Power expects to seek additional rate relief to address recovery ~~plan with~~of the ~~Mississippi PSC for the~~remaining Kemper IGCC for cost recovery through 2020 (Rate Mitigation Plan), which is still under review by the Mississippi PSC. The revenue requirements set forth in the Rate Mitigation Plan assume the sale of a 15% undivided interest in the Kemper IGCC to SMEPA and utilization of bonus depreciation, which currently requires that the related long-term asset be placed in service in 2015.In the Rate Mitigation Plan, Mississippi Power proposed recovery of an annual revenue requirement of approximately $156 million of Kemper IGCC-related operational costs and rate base amounts, including plant costs equal to the $2.4 billion certificated cost estimate. The 2013 MPSC Rate Order, which increased rates beginning in March 2013, was integral to the Rate Mitigation Plan, which contemplates amortization of the regulatory liability balance at the in-service date to be used to mitigate customer rate impacts through 2020, based on a fixed amortization schedule that requires approval by the Mississippi PSC. Under the Rate Mitigation Plan, Mississippi Power proposed annual rate recovery to remain the same from 2014 through 2020, with the proposed revenue requirement approximating the forecasted cost of service for the period 2014 through 2020. Under Mississippi Power's proposal, to the extent the actual annual cost of service differs from the approved forecast for certain items, the difference would be deferred as a regulatory asset or liability, subject to accrual of carrying costs, and would be included in the next year's rate recovery calculation. If any deferred balance remains at the end of 2020, the Mississippi PSC would review the amount and, if approved, determine the appropriate method and period of disposition. See "Regulatory Assets and Liabilities" herein for additional information.

To the extent that refunds of amounts collected under the 2013 MPSC Rate Order are required on a schedule different from the amortization schedule proposed in the Rate Mitigation Plan, the customer billing impacts proposed under the Rate Mitigation Plan would no longer be viable. See "2015 Mississippi Supreme Court Decision" herein for additional information.

assets. In addition to current estimated costs at March 31, ~~2015~~2016 of ~~$6.22~~$6.58 billion, Mississippi Power anticipates that it will incur additional costs after the Kemper IGCC in-service date until the Kemper IGCC cost recovery approach is finalized. These costs include, but are not limited to, regulatory costs and additional carrying costs which could be material. Recovery of these costs would be subject to approval by the Mississippi PSC.

Mississippi Power also expects to seek rate recovery through alternate means, which could include a traditional rate case. On May 1, 2015, Mississippi Power notified the Mississippi PSC of its plans to file a rate request in May 2015.

~~Prudence Reviews~~

The Mississippi PSC's review of Kemper IGCC costs is ongoing. In August 2014, the Mississippi PSC ordered that a consolidated prudence determination of all Kemper IGCC costs be completed after the entire project has been placed in service and has demonstrated availability for a reasonable period of time as determined by the Mississippi PSC and the Mississippi Public Utilities Staff (MPUS). The Mississippi PSC has encouraged the parties to work in good faith to settle contested issues and Mississippi Power is working to reach a mutually acceptable resolution. As a result of the Court's decision, Mississippi Power intends to request that the Mississippi PSC reconsider its prudence review schedule. See "2015 Mississippi Supreme Court Decision" herein for additional information.

Regulatory Assets and Liabilities

Consistent with the treatment of non-capital costs incurred during the pre-construction period, the Mississippi PSC issued an accounting order in 2011 granting Mississippi Power the authority to defer all non-capital Kemper IGCC-related costs to a regulatory asset through the in-service date, subject to review of such costs by the Mississippi PSC. Such costs include, but are not limited to, carrying costs on Kemper IGCC assets currently placed in service,

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costs associated with Mississippi PSC and MPUS consultants, prudence costs, legal fees, and operating expenses associated with assets placed in service.

In August 2014, Mississippi Power requested confirmation by the Mississippi PSC of Mississippi Power's authority to defer all operating expenses associated with the operation of the combined cycle subject to review of such costs by the Mississippi PSC. In addition, Mississippi Power is authorized to accrue carrying costs on the unamortized balance of such regulatory assets at a rate and in a manner to be determined by the Mississippi PSC in future cost recovery mechanism proceedings. Beginning in the third quarter 2015, in connection with the implementation of interim rates, Mississippi Power began expensing certain ongoing project costs and certain debt carrying costs (associated with assets placed in service and other non-CWIP accounts) that previously were deferred as regulatory assets and began amortizing certain regulatory assets associated with assets placed in service and consulting and legal fees. The amortization periods for these regulatory assets vary from two years to 10 years as set forth in the In-Service Asset Rate Order. As of March 31, ~~2015,~~2016, the ~~regulatory asset~~ balance associated with these regulatory assets was $120 million, of which $22 million is included in current assets. Other regulatory assets associated with the remainder of the Kemper IGCC ~~was $174 million. The projected balance at~~totaled $98 million as of March 31, ~~2016 is estimated to total approximately $266 million.~~2016. The amortization period for ~~any such costs approved for recovery remains subject~~these assets is expected to ~~approval~~be determined by the Mississippi ~~PSC.~~PSC in future rate proceedings following completion of construction and start-up of the Kemper IGCC and related prudence reviews.

~~The 2013~~See "2013 MPSC Rate ~~Order approved retail rate increases of 15% effective March 19, 2013 and 3% effective January 1, 2014, which collectively were designed~~Order" herein for information related to ~~collect $156 million annually beginning in 2014. On February 12,~~the July 7, 2015 ~~the Court ordered the~~ Mississippi PSC ~~to refund Mirror CWIP and to fix by~~ order ~~the rates that were in existence prior to the 2013 MPSC Rate Order. Mississippi Power is deferring the collections under the approved rates in~~terminating the Mirror CWIP ~~regulatory liability until otherwise directed by the Mississippi PSC. Mississippi Power is also accruing carrying costs on the unamortized balance~~rate and requiring refund of ~~the~~collections under Mirror ~~CWIP regulatory liability for the benefit of retail customers. As of March 31, 2015, the balance of the Mirror CWIP regulatory liability, including carrying costs, was $311 million.~~

~~See "2015 Mississippi Supreme Court Decision" herein for additional information.~~CWIP.

See Note 1 to the financial statements of Southern Company and Mississippi Power under "Regulatory Assets and Liabilities" in Item 8 of the Form 10-K for additional information.

The In-Service Asset Rate Order requires Mississippi Power to submit an annual true-up calculation of its actual cost of capital, compared to the stipulated total cost of capital, with the first occurring as of May 31, 2016. As of

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March 31, 2016, Mississippi Power recorded a related regulatory liability of approximately $3 million. See "2015 Rate Case" herein for additional information.

Lignite Mine and CO₂ Pipeline Facilities

In conjunction with the Kemper IGCC, Mississippi Power will own the lignite mine and equipment and has acquired and will continue to acquire mineral reserves located around the Kemper IGCC site. The mine started commercial operation in June 2013.

In 2010, Mississippi Power executed a 40-year management fee contract with Liberty Fuels Company, LLC (Liberty Fuels), a wholly-owned subsidiary of The North American Coal Corporation, which developed, constructed, and is operating and managing the mining operations. The contract with Liberty Fuels is effective through the end of the mine reclamation. As the mining permit holder, Liberty Fuels has a legal obligation to perform mine reclamation and Mississippi Power has a contractual obligation to fund all reclamation activities. In addition to the obligation to fund the reclamation activities, Mississippi Power currently provides working capital support to Liberty Fuels through cash advances for capital purchases, payroll, and other operating expenses. See Note 1 to the financial statements of Mississippi Power under "Asset Retirement Obligations and Other Costs of Removal" and "Variable Interest Entities" in Item 8 of the Form 10-K for additional information.

In addition, Mississippi Power has constructed and will operate the CO₂ pipeline for the planned transport of captured CO₂ for use in enhanced oil recovery. Mississippi Power has entered into agreements with Denbury Onshore (Denbury), a subsidiary of Denbury Resources Inc., and Treetop Midstream Services, LLC (Treetop), an affiliate of Tellus Operating Group, LLC and a subsidiary of Tengrys, LLC, pursuant to which Denbury will purchase 70% of the CO₂ captured from the Kemper IGCC and Treetop will purchase 30% of the CO₂ captured from the Kemper IGCC. The agreements with Denbury and Treetop provide Denbury and Treetop with termination rights ~~in the event that~~as Mississippi Power ~~does~~has not ~~satisfy~~satisfied its contractual obligation ~~with respect~~ to ~~deliveries of~~deliver captured CO₂ by May 11, 2015. ~~While~~Since May 11, 2015, Mississippi Power has ~~received no indication from either Denbury or~~been engaged in ongoing discussions with its off-takers regarding the status of the CO₂delivery schedule as well as other issues related to the CO₂ agreements. As a result of discussions with Treetop, on August 3, 2015, Mississippi Power agreed to amend certain provisions of their ~~intent to terminate their respective agreements, any~~agreement that do not affect pricing or minimum purchase quantities. Potential requirements imposed on CO₂ off-takers under the Clean Power Plan (if ultimately enacted in its current form, pending resolution of litigation) and the potential adverse financial impact of low oil prices on the off-takers increase the risk that the CO₂ contracts may be terminated or materially modified. Any termination or material modification of these agreements could result in a material reduction in ~~future chemical product sales~~Mississippi Power's revenues ~~and could have a material financial impact on Mississippi Power~~ to the extent Mississippi Power is not able to enter into other similar contractual arrangements. Additionally, if the contracts remain in place, sustained oil price reductions could result in significantly lower revenues than Mississippi Power forecasted to be available to offset customer rate impacts, which could have a material impact on Mississippi Power's financial statements.

The ultimate outcome of these matters cannot be determined at this time.

Civil Lawsuit

On April 26, 2016, a complaint against Mississippi Power was filed in Harrison County Circuit Court by Biloxi Freezing & Processing Inc., Gulfside Casino Partnership, and John Carlton Dean. The plaintiffs allege that Mississippi Power violated the Mississippi Unfair Trade Practices Act and concealed, falsely represented, and failed to fully disclose important facts concerning the cost and schedule of the Kemper IGCC and that Mississippi Power's alleged breaches interfered with and destroyed economically advantageous relationships between the plaintiffs and their current and prospective business associates. The plaintiffs seek unspecified actual damages and punitive damages as well as attorney's fees, costs, and interest. The plaintiffs also seek an injunction to prevent any Kemper IGCC costs from being charged to customers through electric rates. Mississippi Power believes this legal challenge has no merit; however, an adverse outcome in this proceeding could impact Southern Company's results of operations, financial condition, and liquidity and could have a material impact on Mississippi Power's results of operations, financial condition, and liquidity. Mississippi Power will vigorously defend the matter, and the final outcome of this matter cannot be determined at this time.

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(C)	FAIR VALUE MEASUREMENTS

As of March 31, 2016, assets and liabilities measured at fair value on a recurring basis during the period, together with their associated level of the fair value hierarchy, were as follows:



	Fair Value Measurements Using
As of March 31, 2016:	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Net Asset Value as a Practical Expedient (NAV)		Total
	(in millions)
Southern Company
Assets:
Energy-related derivatives	$	—	$	12	$	—	$	—	$	12
Interest rate derivatives	—		33		—		—		33
Nuclear decommissioning trusts^(a)	624		898		—		16		1,538
Cash equivalents	503		—		—		—		503
Other investments	9		—		1		—		10
Total	$	1,136	$	943	$	1	$	16	$	2,096
Liabilities:
Energy-related derivatives	$	—	$	201	$	—	$	—	$	201
Interest rate derivatives	—		193		—		—		193
Total	$	—	$	394	$	—	$	—	$	394

Alabama Power
Assets:
Energy-related derivatives	$	—	$	3	$	—	$	—	$	3
Nuclear decommissioning trusts^(b)
Domestic equity	365		67		—		—		432
Foreign equity	46		48		—		—		94
U.S. Treasury and government agency securities	—		25		—		—		25
Corporate bonds	11		137		—		—		148
Mortgage and asset backed securities	—		21		—		—		21
Private Equity	—		—		—		16		16
Other	—		9		—		—		9
Cash equivalents	321		—		—		—		321
Total	$	743	$	310	$	—	$	16	$	1,069
Liabilities:
Energy-related derivatives	$	—	$	49	$	—	$	—	$	49

139

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

~~Proposed Sale of Undivided Interest to SMEPA~~



	Fair Value Measurements Using
As of March 31, 2016:	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Net Asset Value as a Practical Expedient (NAV)		Total
	(in millions)
Georgia Power
Assets:
Energy-related derivatives	$	—	$	4	$	—	$	—	$	4
Interest rate derivatives	—		14		—		—		14
Nuclear decommissioning trusts^{(b) (c)}
Domestic equity	180		1		—		—		181
Foreign equity	—		115		—		—		115
U.S. Treasury and government agency securities	—		111		—		—		111
Municipal bonds	—		66		—		—		66
Corporate bonds	—		146		—		—		146
Mortgage and asset backed securities	—		145		—		—		145
Other	22		7		—		—		29
Cash equivalents	57		—		—		—		57
Total	$	259	$	609	$	—	$	—	$	868
Liabilities:
Energy-related derivatives	$	—	$	11	$	—	$	—	$	11

Gulf Power
Assets:
Cash equivalents	$	20	$	—	$	—	$	—	$	20
Liabilities:
Energy-related derivatives	$	—	$	94	$	—	$	—	$	94
Interest rate derivatives	—		5		—		—		5
Total	$	—	$	99	$	—	$	—	$	99

Mississippi Power
Assets:
Cash equivalents	$	24	$	—	$	—	$	—	$	24
Liabilities:
Energy-related derivatives	$	—	$	44	$	—	$	—	$	44

Southern Power
Assets:
Energy-related derivatives	$	—	$	5	$	—	$	—	$	5
Interest rate derivatives	—		1		—		—		1
Cash equivalents	39		—		—		—		39
Total	$	39	$	6	$	—	$	—	$	45
Liabilities:
Energy-related derivatives	$	—	$	3	$	—	$	—	$	3

~~Investment Tax Credits~~

The IRS allocated $279 million (Phase II) of Internal Revenue Code Section 48A tax credits to Mississippi Power in connection with the Kemper IGCC. Through March 31, 2015, Mississippi Power had recorded tax benefits totaling $276 million for the Phase II credits, of which approximately $207 million had been utilized through that date. These credits will be amortized as a reduction to depreciation and amortization over the life of the Kemper IGCC and are dependent upon meeting the IRS certification requirements, including an in-service date no later than April 19, 2016 and the capture and sequestration (via enhanced oil recovery) of at least 65%~~of the CO~~₂ ~~produced by the~~

~~144~~140

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

Kemper IGCC during operations in accordance with the Internal Revenue Code. Mississippi Power currently expects to place the Kemper IGCC in service in the first half of 2016. In addition, a portion of the Phase II tax credits will be subject to recapture upon completion of SMEPA's proposed purchase of an undivided interest in the Kemper IGCC as described above. The ultimate outcome of this matter cannot be determined at this time.

~~Section 174 Research and Experimental Deduction~~

Southern Company, on behalf of Mississippi Power, reflected deductions for research and experimental (R&E) expenditures related to the Kemper IGCC in its federal income tax calculations for 2013 and 2014. Due to the uncertainty related to this tax position, Southern Company and Mississippi Power had unrecognized tax benefits totaling approximately $211 million at March 31, 2015. See Note 5 to the financial statements of Southern Company and Mississippi Power under "Unrecognized Tax Benefits" in Item 8 of the Form 10-K and Note (G) herein under "Unrecognized Tax Benefits" for additional information. The ultimate outcome of this matter cannot be determined at this time.

~~145~~

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~~NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)~~

~~(UNAUDITED)~~


~~(C)~~	~~FAIR VALUE MEASUREMENTS~~

~~As of March 31, 2015, assets and liabilities measured at fair value on a recurring basis during the period, together with the level of the fair value hierarchy in which they fall, were as follows:~~

Fair Value Measurements Using
As of March 31, 2015:
Quoted Prices
in Active
Markets for
Identical
Assets
(Level 1)

Significant
Other
Observable
Inputs
(Level 2)

Significant
Unobservable
Inputs
(Level 3)
Total
(in millions)
Southern Company
Assets:
Energy-related derivatives $ —
$ 7
$ —
$ 7
Interest rate derivatives —
8
—
8
Nuclear decommissioning trusts^(a)
632
937
4
1,573
Cash equivalents 863
—
—
863
Other investments 9
—
1
10
Total $ 1,504
$ 952
$ 5
$ 2,461
Liabilities:
Energy-related derivatives $ —
$ 225
$ —
$ 225
Interest rate derivatives —
46
—
46
Total $ —
$ 271
$ —
$ 271

Alabama Power
Assets:
Energy-related derivatives $ —
$ 1
$ —
$ 1
Nuclear decommissioning trusts^(b)

Domestic equity 393
90
—
483
Foreign equity 36
65
—
101
U.S. Treasury and government agency securities —
34
—
34
Corporate bonds 10
113
—
123
Mortgage and asset backed securities —
18
—
18
Other —
6
4
10
Cash equivalents 287
—
—
287
Total $ 726
$ 327
$ 4
$ 1,057
Liabilities:
Energy-related derivatives $ —
$ 59
$ —
$ 59
Interest rate derivatives —
14
—
14
Total $ —
$ 73
$ —
$ 73

~~146~~

~~Table of Contents~~

~~NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)~~

~~(UNAUDITED)~~

Fair Value Measurements Using
As of March 31, 2015:
Quoted Prices
in Active
Markets for
Identical
Assets
(Level 1)

Significant
Other
Observable
Inputs
(Level 2)

Significant
Unobservable
Inputs
(Level 3)
Total
(in millions)
Georgia Power
Assets:
Energy-related derivatives $ —
$ 6
$ —
$ 6
Interest rate derivatives —
6
—
6
Nuclear decommissioning trusts^{(b) (c)}

Domestic equity 182
2
—
184
Foreign equity —
126
—
126
U.S. Treasury and government agency securities —
86
—
86
Municipal bonds —
92
—
92
Corporate bonds —
192
—
192
Mortgage and asset backed securities —
107
—
107
Other 11
6
—
17
Cash equivalents 406
—
—
406
Total $ 599
$ 623
$ —
$ 1,222
Liabilities:
Energy-related derivatives $ —
$ 24
$ —
$ 24
Interest rate derivatives —
31
—
31
Total $ —
$ 55
$ —
$ 55

Gulf Power
Assets:
Cash equivalents $ 18
$ —
$ —
$ 18
Liabilities:
Energy-related derivatives —
90
—
90

Mississippi Power
Assets:
Cash equivalents $ 110
$ —
$ —
$ 110
Liabilities:
Energy-related derivatives —
52
—
52

Southern Power
Assets:
Cash equivalents $ 3
$ —
$ —
$ 3


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


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


(c)	Includes the investment securities pledged to creditors and collateral received and excludes payables related to the securities lending program. As of March 31, ~~2015,~~2016, approximately ~~$50~~$58 million of the fair market value of Georgia Power's nuclear decommissioning trust funds' securities were on loan ~~and pledged~~ to creditors under the funds' managers' securities lending program.

~~147~~

~~Table~~Southern Company, Alabama Power, and Georgia Power continue to elect the option to fair value investment securities held in the nuclear decommissioning trust funds. For the three months ended March 31, 2016 and March 31, 2015, the change in fair value of ~~Contents~~the funds, including reinvested interest and dividends and excluding the funds' expenses, increased by $20 million and $33 million, respectively, at Southern Company. For the three months ended March 31, 2016 and March 31, 2015, Alabama Power recorded an increase in fair value of $11 million and $15 million, respectively, as an increase in regulatory liabilities related to its asset retirement obligations. For the three months ended March 31, 2016 and March 31, 2015, Georgia Power recorded an increase in fair value of $9 million and $18 million, respectively, as a reduction of its regulatory asset related to its asset retirement obligations.

~~NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)~~

~~(UNAUDITED)~~

Valuation Methodologies

The energy-related derivatives primarily consist of over-the-counter financial products for natural gas and physical power products, including, from time to time, basis swaps. These are standard products used within the energy industry and are valued using the market approach. The inputs used are mainly from observable market sources, such as forward natural gas prices, power prices, implied volatility, and overnight index swap interest rates. Interest rate derivatives are also standard over-the-counter ~~financial~~ products that are valued using ~~the~~observable market ~~approach. Inputs for~~data and assumptions commonly used by market participants. The fair value of interest rate derivatives reflect the net present value of expected payments and receipts under the swap agreement based on the market's expectation of future interest rates. Additional inputs to the net present value calculation may include ~~LIBOR interest rates, interest rate futures contracts,~~the contract terms, counterparty credit risk, and occasionally, implied volatility of interest rate options. The interest rate derivatives are categorized as Level 2 under Fair Value Measurements as these inputs are based on observable data and valuations of similar instruments. See Note (H) ~~herein~~ for additional information on how these derivatives are used.

The NRC requires licensees of commissioned nuclear power reactors to establish a plan for providing reasonable assurance of funds for future decommissioning. For fair value measurements of the investments within the nuclear decommissioning trusts, external pricing vendors are designated for each asset class with each security specifically assigned a primary pricing source. For investments held within commingled funds, fair value is determined at the end of each business day through the net asset value, which is established by obtaining the underlying securities' individual prices from the primary pricing source. A market price secured from the primary source vendor is then evaluated by management in its valuation of the assets within the trusts. As a general approach, fixed income market pricing vendors gather market data (including indices and market research reports) and integrate relative credit information, observed market movements, and sector news into proprietary pricing models, pricing systems, and mathematical tools. Dealer quotes and other market information, including live trading levels and pricing analysts' ~~judgment,~~judgments, are also obtained when available.

~~Investments~~ See Note 1 to the financial statements of Southern Company, Alabama Power, and Georgia Power under "Nuclear Decommissioning" in private equity and real estate within Alabama Power's nuclear decommissioning trusts are generally classified as Level 3, as the underlying assets typically do not have observable inputs. The fund manager values these assets using various inputs and techniques depending on the natureItem 8 of the ~~underlying investments. The fair value of partnerships is determined by aggregating the value of the underlying assets.~~Form 10-K for additional information.

"Other investments" include investments that are not traded in the open market. The fair value of these investments have been determined based on market factors including comparable multiples and the expectations regarding cash flows and business plan executions.

~~148~~141

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

As of March 31, ~~2015,~~2016, the fair value measurements of private equity investments held in the nuclear decommissioning trust that are calculated at net asset value per share (or its equivalent), as a practical expedient, as well as the nature and risks of those investments, were as follows:

As of March 31, 2015:
Fair
Value

Unfunded
Commitments

Redemption
Frequency

Redemption
Notice Period
(in millions)
Southern Company
Nuclear decommissioning trusts:
Foreign equity funds $ 126
None Monthly 5 days
Equity - commingled funds 65
None Daily/Monthly Daily/7 days
Debt - commingled funds 16
None Daily 5 days
Other - commingled funds 6
None Daily Not applicable
Other - money market funds 11
None Daily Not applicable
Trust-owned life insurance 118
None Daily 15 days
Cash equivalents:
Money market funds 863
None Daily Not applicable
Alabama Power
Nuclear decommissioning trusts:
Equity - commingled funds $ 65
None Daily/Monthly Daily/7 days
Debt - commingled funds 16
None Daily 5 days
Trust-owned life insurance 118
None Daily 15 days
Cash equivalents:
Money market funds 287
None Daily Not applicable
Georgia Power
Nuclear decommissioning trusts:
Foreign equity funds $ 126
None Monthly 5 days
Other - commingled funds 6
None Daily Not applicable
Other - money market funds 11
None Daily Not applicable
Cash equivalents:
Money market funds 406
None Daily Not applicable
Gulf Power
Cash equivalents:
Money market funds $ 18
None Daily Not applicable
Mississippi Power
Cash equivalents:
Money market funds $ 110
None Daily Not applicable
Southern Power
Cash equivalents:
Money market funds $ 3
None Daily Not applicable



As of March 31, 2016:	Fair Value		Unfunded Commitments		Redemption Frequency	Redemption Notice Period
	(in millions)
Southern Company	$	16	$	29	Not Applicable	Not Applicable
Alabama Power	$	16	$	29	Not Applicable	Not Applicable

~~The NRC requires licensees of commissioned nuclear power reactors to establish~~Private equity funds include a plan for providing reasonable assurance of funds for future decommissioning. Alabama Power and Georgia Power have external trust funds (the Funds) to comply with the NRC's regulations. The foreign equity fund in Georgia Power's nuclear decommissioning trusts seeks to provide long-term capital appreciation. In pursuing this investment objective, the foreign equity fund primarilyfund-of-funds that invests in high-quality private equity funds across several market sectors, a ~~diversified portfolio of equity securities of foreign companies, including those~~fund that invests in ~~emerging markets. These equity securities may include, but are not limited to, common stocks, preferred stocks,~~ real estate ~~investment trusts, convertible securities, depositary receipts (including American depositary receipts, European depositary receipts,~~assets, and ~~global depositary receipts), and rights and warrants~~a fund that acquires companies to ~~buy common stocks. Georgia Power may withdraw all or a portion of its investment on the last business day of each month subject to a minimum~~

~~149~~

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~~NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)~~

~~(UNAUDITED)~~

~~withdrawal of $1 million, provided that a minimum investment of $10 million remains. If notices of withdrawal exceed 20% of the aggregate value of the foreign~~create resale value. Private equity fund, then the foreign equity fund's board may refuse to permit the withdrawal of all such investments and may scale down the amounts to be withdrawn pro rata and may further determine that any withdrawal that has been postponed will have priority on the subsequent withdrawal date.

~~The other-commingled~~ funds and other-money market funds in Georgia Power's nuclear decommissioning trusts are invested primarily in a diversified portfolio of high-quality, short-term, liquid debt securities. The funds represent ~~cash collateral received under the Funds' managers' securities lending program and/or excess cash held within each separate investment account.~~ The primary objective of the funds is to provide a high level of current income consistent with stability of principal and liquidity. The funds invest primarily in, but not limited to, commercial paper, floating and variable rate demand notes, debt securities issued or guaranteed by the U.S. government or its agencies or instrumentalities, time deposits, repurchase agreements, municipal obligations, notes, and other high-quality short-term liquid debt securities that mature in 90 days or less. Redemptions are available on a same day basis up to the full amount of the investment in the fund. See Note 1 to the financial statements of Southern Company and Georgia Power under "Nuclear Decommissioning" in Item 8 of the Form 10-K for additional information.

Alabama Power's nuclear decommissioning trusts include investments in Trust-Owned Life Insurance (TOLI). The taxable nuclear decommissioning trusts invest in the TOLI in order to minimize the impact of taxes on the portfolios and can draw on the value of the TOLI through death proceeds, loans against the cash surrender value, and/or the cash surrender value, subject to legal restrictions. The amounts reported in the table above reflect the fair value of investments the insurer has made in relation to the TOLI agreements. The nuclear decommissioning trusts do not ~~own~~have redemption rights. Distributions from these funds will be received as the underlying investments but the fair value of the investments approximates the cash surrender value of the TOLI policies. The investments made by the insurer are in commingled funds. These commingled funds, along with other equity and debt commingled funds held in Alabama Power's nuclear decommissioning trusts, primarily include investments in domestic and international equity securities and predominantly high-quality fixed income securities. These fixed income securities may include U.S. Treasury and government agency fixed income securities, non-U.S. government and agency fixed income securities, domestic and foreign corporate fixed income securities, and mortgage and asset backed securities. The passively managed funds seek to replicate the performance of a related index. The actively managed funds seek to exceed the performance of a related index through security analysis and selection. See Note 1 to the financial statements of Southern Company and Alabama Power under "Nuclear Decommissioning" in Item 8 of the Form 10-K for additional information.

~~Southern Company, Alabama Power, and Georgia Power continue to elect the option to fair value investment securities held~~ in the nuclear decommissioning trust funds. For the three months ended March 31, 2015, the change in fair value of the funds, including reinvested interest and dividends reduced by the funds' expenses, increased by $65 million at Southern Company. For the three months ended March 31, 2015, Alabama Power recorded an increase in fair value of $47 million as an increase in regulatory liabilities. Georgia Power recorded an increase in fair value of $18 million as a reduction of its regulatory asset related to its ARO.

~~The money market~~ funds are ~~short-term investments of excess funds in~~liquidated. Liquidations are expected to occur at various ~~money market mutual funds, which are portfolios of short-term debt securities. The money market funds are regulated by~~times over the SEC and typically receive the highest rating from credit rating agencies. Regulatory and rating agency requirements for money market funds include minimum credit ratings and maximum maturities for individual securities and a maximum weighted average portfolio maturity. Redemptions are available on a same day basis up to the full amount of the investment in the money market funds.next ten years.

~~150~~

~~Table of Contents~~

~~NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)~~

~~(UNAUDITED)~~

As of March 31, ~~2015,~~2016, other financial instruments for which the carrying amount did not equal fair value were as follows:


	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	(in millions)				(in millions)
Long-term debt:
Long-term debt, including securities due within one year:
Southern Company	$	24,241	$	26,350	$	28,341	$	29,827
Alabama Power	$	6,922	$	7,696	$	7,089	$	7,688
Georgia Power	$	9,801	$	10,733	$	10,549	$	11,400
Gulf Power	$	1,370	$	1,501	$	1,303	$	1,366
Mississippi Power	$	2,251	$	2,323	$	3,209	$	2,938
Southern Power	$	1,621	$	1,789	$	3,123	$	3,171

The fair values are determined using Level 2 measurements and are based on quoted market prices for the same or similar issues or on the current rates ~~offered~~available to ~~Southern Company, Alabama Power, Georgia Power, Gulf Power, Mississippi Power, and Southern Power.~~the registrants.


(D)	STOCKHOLDERS' EQUITY

Earnings per Share

For Southern Company, the only difference in computing basic and diluted earnings per share is attributable to awards outstanding under the stock option and performance share plans. See Note 8 to the financial statements of Southern Company in Item 8 of the Form 10-K for information on the stock option and performance share plans. The effect of both stock options and performance share award units was determined using the treasury stock method. Shares used to compute diluted earnings per share were as follows:


	Three Months Ended March 31, 2015	Three Months Ended March 31, 2014	Three Months Ended March 31, 2016	Three Months Ended March 31, 2015
	(in millions)		(in millions)
As reported shares	910	890	916	910
Effect of options and performance share award units	5	3	6	5
Diluted shares	915	893	922	915

142

Table of Contents

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

Stock options and performance share award units that were not included in the diluted earnings per share calculation because they were anti-dilutive were immaterial for the three months ended March 31, ~~2015~~2016 and ~~were 17 million for the three months ended March 31, 2014.~~2015.

~~151~~

~~Table of Contents~~

~~NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)~~

~~(UNAUDITED)~~

Changes in Stockholders' Equity

The following table presents year-to-date changes in stockholders' equity of Southern Company:


	Number of Common Shares			Common Stockholders' Equity				Preferred and Preference Stock of Subsidiaries								Total Stockholders' Equity			Number of Common Shares					Common Stockholders' Equity				Preferred and Preference Stock of Subsidiaries							Total Stockholders' Equity
	Issued	Treasury					Noncontrolling Interest					Issued			Treasury							Noncontrolling Interests^(*)		Common Stockholders' Equity				Preferred and Preference Stock of Subsidiaries							Total Stockholders' Equity
	(in thousands)			Common Stockholders' Equity		(in millions)															(in thousands)					(in millions)
Balance at December 31, 2015																			915,073			(3,352	)	$	20,592			$	609		$	781			$	21,982
Consolidated net income attributable to Southern Company																			—			—		485				—			—				485
Other comprehensive income (loss)																			—			—		(114		)		—			—				(114		)
Stock issued																			6,572			—		270				—			—				270
Stock-based compensation																			—			—		60				—			—				60
Cash dividends on common stock																			—			—		(497		)		—			—				(497		)
Contributions from noncontrolling interests																			—			—		—				—			129				129
Distributions to noncontrolling interests																			—			—		—				—			(4		)		(4		)
Purchase of membership interests from noncontrolling interests																			—			—		—				—			(129		)		(129		)
Net income attributable to noncontrolling interests																			—			—		—				—			1				1
Other																			—			(35	)	1				—			—				1
Balance at March 31, 2016																			921,645			(3,387	)	$	20,797			$	609		$	778			$	22,184

Balance at December 31, 2014	908,502	(725	)	$	19,949			Preferred and Preference Stock of Subsidiaries		$	756			$	221	Total Stockholders' Equity			$	20,926		908,502		(725	)		$	19,949		$	756			$	221			$	20,926
Net income after dividends on preferred and preference stock	—	—		508				—				—				508
Consolidated net income attributable to Southern Company																			—			—		508				—			—				508
Other comprehensive income (loss)	—	—		(15		)		—				—				(15		)	—			—		(15		)		—			—				(15		)
Stock issued	3,094	—		112				—				—				112			3,094			—		112				—			—				112
Stock-based compensation	—	—		53				—				—				53			—			—		53				—			—				53
Stock repurchased, at cost	—	(2,599	)	(115		)		—				—				(115		)	—			(2,599	)	(115		)		—			—				(115		)
Cash dividends on common stock	—	—		(478		)		—				—				(478		)	—			—		(478		)		—			—				(478		)
Other	—	(11	)	3				—				—				3			—			(11	)	3				—			—				3
Balance at March 31, 2015	911,596	(3,335	)	$	20,017			$	756			$	221			$	20,994		911,596			(3,335	)	$	20,017			$	756		$	221			$	20,994

Balance at December 31, 2013	892,733	(5,647	)	$	19,008			$	756			$	—			$	19,764
Net income after dividends on preferred and preference stock	—	—		351				—				—				351
Other comprehensive income (loss)	—	—		2				—				—				2
Treasury stock re-issued	—	2,404		111				—				—				111
Stock issued	1,340	—		53				—				—				53
Stock repurchased, at cost	—	—		(4		)		—				—				(4		)
Cash dividends on common stock	—	—		(451		)		—				—				(451		)
Other	—	(18	)	—				—				—				—
Balance at March 31, 2014	894,073	(3,261	)	$	19,070			$	756			$	—			$	19,826



Commission File Number	Registrant, State of Incorporation, Address and Telephone Number		I.R.S. Employer Identification No.
1-3526	The Southern Company (A Delaware Corporation) 30 Ivan Allen Jr. Boulevard, N.W. Atlanta, Georgia 30308 (404) 506-5000		58-0690070

1-3164	Alabama Power Company (An Alabama Corporation) 600 North 18^th Street Birmingham, Alabama 35203 (205) 257-1000		63-0004250

1-6468	Georgia Power Company (A Georgia Corporation) 241 Ralph McGill Boulevard, N.E. Atlanta, Georgia 30308 (404) 506-6526	��	58-0257110

001-31737	Gulf Power Company (A Florida Corporation) One Energy Place Pensacola, Florida 32520 (850) 444-6111		59-0276810

001-11229	Mississippi Power Company (A Mississippi Corporation) 2992 West Beach Boulevard Gulfport, Mississippi 39501 (228) 864-1211		64-0205820

333-98553	Southern Power Company (A Delaware Corporation) 30 Ivan Allen Jr. Boulevard, N.W. Atlanta, Georgia 30308 (404) 506-5000		58-2598670



Registrant	Large Accelerated Filer	Accelerated Filer	Non- accelerated Filer	Smaller Reporting Company
The Southern Company	X
Alabama Power Company			X
Georgia Power Company			X
Gulf Power Company			X
Mississippi Power Company			X
Southern Power Company			X



Registrant	Description of Common Stock	Shares Outstanding at March 31, ~~2015~~2016
The Southern Company	Par Value $5 Per Share	~~908,261,371~~918,258,425
Alabama Power Company	Par Value $40 Per Share	30,537,500
Georgia Power Company	Without Par Value	9,261,500
Gulf Power Company	Without Par Value	5,642,717
Mississippi Power Company	Without Par Value	1,121,000
Southern Power Company	Par Value $0.01 Per Share	1,000



		Page Number
DEFINITIONS		5
CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION		7

	PART I—FINANCIAL INFORMATION

Item 1.	Financial Statements (Unaudited)
Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations
	The Southern Company and Subsidiary Companies
	Condensed Consolidated Statements of Income	10
	Condensed Consolidated Statements of Comprehensive Income	11
	Condensed Consolidated Statements of Cash Flows	12
	Condensed Consolidated Balance Sheets	13
	Management's Discussion and Analysis of Financial Condition and Results of Operations	15
	Alabama Power Company
	Condensed Statements of Income	3536
	Condensed Statements of Comprehensive Income	3536
	Condensed Statements of Cash Flows	3637
	Condensed Balance Sheets	3738
	Management's Discussion and Analysis of Financial Condition and Results of Operations	3940
	Georgia Power Company
	Condensed Statements of Income	51
	Condensed Statements of Comprehensive Income	51
	Condensed Statements of Cash Flows	52
	Condensed Balance Sheets	53
	Management's Discussion and Analysis of Financial Condition and Results of Operations	55
	Gulf Power Company
	Condensed Statements of Income	7069
	Condensed Statements of Comprehensive Income	7069
	Condensed Statements of Cash Flows	7170
	Condensed Balance Sheets	7271
	Management's Discussion and Analysis of Financial Condition and Results of Operations	7473
	Mississippi Power Company
	Condensed Statements of ~~Operations~~Income	8685
	Condensed Statements of Comprehensive Income ~~(Loss)~~	8685
	Condensed Statements of Cash Flows	8786
	Condensed Balance Sheets	8887
	Management's Discussion and Analysis of Financial Condition and Results of Operations	9089
	Southern Power Company and Subsidiary Companies
	Condensed Consolidated Statements of Income	~~113~~110
	Condensed Consolidated Statements of Comprehensive Income	~~113~~110
	Condensed Consolidated Statements of Cash Flows	~~114~~111
	Condensed Consolidated Balance Sheets	~~115~~112
	Management's Discussion and Analysis of Financial Condition and Results of Operations	~~117~~114
	Notes to the Condensed Financial Statements	~~126~~124
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	3334
Item 4.	Controls and Procedures	3334



		Page Number
	PART II—OTHER INFORMATION
Item 1.	Legal Proceedings	~~170~~166
Item 1A.	Risk Factors	~~170~~166
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	~~170~~ Inapplicable
Item 3.	Defaults Upon Senior Securities	Inapplicable
Item 4.	Mine Safety Disclosures	Inapplicable
Item 5.	Other Information	Inapplicable
Item 6.	Exhibits	~~171~~166
	Signatures	~~174~~169



Term	Meaning

2012 MPSC CPCN Order	A detailed order issued by the Mississippi PSC in April 2012 confirming the CPCN originally approved by the Mississippi PSC in 2010 authorizing the acquisition, construction, and operation of the Kemper IGCC
2013 ARP	Alternative Rate Plan approved by the Georgia PSC in 2013 for Georgia Power for the years 2014 through 2016 and subsequently extended through 2019
AFUDC	Allowance for funds used during construction
AGL Resources	AGL Resources Inc.
Alabama Power	Alabama Power Company
ASC	Accounting Standards Codification
ASU	Accounting Standards Update
Baseload Act	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
Bridge Agreement	Senior unsecured Bridge Credit Agreement, dated as of September 30, 2015, among Southern Company, the lenders identified therein, and Citibank, N.A.
CCR	Coal combustion residuals
Clean Air Act	Clean Air Act Amendments of 1990
~~Contractor~~	~~Westinghouse and CB&I Stone & Webster, Inc. (formerly known as Stone & Webster, Inc.), a subsidiary of The Shaw Group Inc., which was acquired by Chicago Bridge & Iron Company N.V.~~
CO₂	Carbon dioxide
COD	Commercial operation date
Contractor	Westinghouse and its affiliate, WECTEC Global Project Services Inc. (formerly known as CB&I Stone & Webster, Inc.), formerly a subsidiary of The Shaw Group Inc. and Chicago Bridge & Iron Company N.V.
CPCN	Certificate of public convenience and necessity
CWIP	Construction work in progress
DOE	U.S. Department of Energy
ECO Plan	Mississippi Power's Environmental Compliance Overview Plan
Eligible Project Costs	Certain costs of construction relating to Plant Vogtle Units 3 and 4 that are eligible for financing under the Title XVII Loan Guarantee Program
EPA	U.S. Environmental Protection Agency
FASB	Financial Accounting Standards Board
FERC	Federal Energy Regulatory Commission
FFB	Federal Financing Bank
Fitch	Fitch Ratings, Inc.
Form 10-K	Combined Annual Report on Form 10-K of Southern Company, Alabama Power, Georgia Power, Gulf Power, Mississippi Power, and Southern Power for the year ended December 31, ~~2014~~2015
GAAP	~~Generally~~U.S. generally accepted accounting principles
Georgia Power	Georgia Power Company
Gulf Power	Gulf Power Company
IGCC	Integrated coal gasification combined cycle
IIC	Intercompany interchange contract
Internal Revenue Code	Internal Revenue Code of 1986, as amended
IRS	Internal Revenue Service
ITC	Investment tax credit
Kemper IGCC	IGCC facility under construction by Mississippi Power in Kemper County, Mississippi
KWH	Kilowatt-hour
LIBOR	London Interbank Offered Rate
MATS rule	Mercury and Air Toxics Standards rule
Merger	The merger of Merger Sub with and into AGL Resources on the terms and subject to the conditions set forth in the Merger Agreement, with AGL Resources continuing as the surviving corporation and a wholly-owned, direct subsidiary of Southern Company



Term	Meaning

Merger Agreement	Agreement and Plan of Merger, dated as of August 23, 2015, among Southern Company, AGL Resources, and Merger Sub
Merger Sub	AMS Corp., a wholly-owned, direct subsidiary of Southern Company
Mirror CWIP	A regulatory liability account for use in mitigating future rate impacts for Mississippi Power customers
Mississippi Power	Mississippi Power Company
mmBtu	Million British thermal units
Moody's	Moody's Investors Service, Inc.
MW	Megawatt



~~Term~~	~~Meaning~~

NCCR	Georgia Power's Nuclear Construction Cost Recovery
NRC	U.S. Nuclear Regulatory Commission
OCI	Other comprehensive income
PEP	Mississippi Power's Performance Evaluation Plan
Plant Vogtle Units 3 and 4	Two new nuclear generating units under construction at Georgia Power's Plant Vogtle
power pool	The operating arrangement whereby the integrated generating resources of the traditional operating companies and Southern Power Company (excluding subsidiaries) are subject to joint commitment and dispatch in order to serve their combined load obligations
PPA	Power purchase agreement
PSC	Public Service Commission
PTC	Production tax credit
Rate CNP	Alabama Power's Rate Certificated New Plant
Rate CNP Compliance	Alabama Power's Rate Certificated New Plant Compliance
Rate CNP ~~Environmental~~	~~Alabama Power's Rate Certificated New Plant Environmental~~
~~Rate CNP~~ PPA	Alabama Power's Rate Certificated New Plant Power Purchase Agreement
Rate RSE	Alabama Power's Rate Stabilization and Equalization plan
registrants	Southern Company, Alabama Power, Georgia Power, Gulf Power, Mississippi Power, and Southern Power Company
ROE	Return on equity
S&P	Standard and Poor's Ratings Services, a division of The McGraw Hill Companies, Inc.
scrubber	Flue gas desulfurization system
SEC	U.S. Securities and Exchange Commission
SMEPA	South Mississippi Electric Power Association
Southern Company	The Southern Company
Southern Company system	Southern Company, the traditional operating companies, Southern Power, Southern Electric Generating Company, Southern Nuclear, Southern Company Services, Inc. (the Southern Company system service company), Southern Communications Services, Inc., and other subsidiaries
Southern Nuclear	Southern Nuclear Operating Company, Inc.
Southern Power	Southern Power Company and its subsidiaries
traditional operating companies	Alabama Power, Georgia Power, Gulf Power, and Mississippi Power
Vogtle Owners	Georgia Power, Oglethorpe Power Corporation, the Municipal Electric Authority of Georgia, and the City of Dalton, Georgia, an incorporated municipality in the State of Georgia acting by and through its Board of Water, Light, and Sinking Fund Commissioners
Westinghouse	Westinghouse Electric Company LLC


	For the Three Months Ended March 31,						For the Three Months Ended March 31,
	2015			2014			2016			2015
	(in millions)						(in millions)
Operating Revenues:
Retail revenues	$	3,542		$	3,858		$	3,377		$	3,542
Wholesale revenues	467			604			396			467
Other electric revenues	163			165			181			163
Other revenues	11			17			11			11
Total operating revenues	4,183			4,644			3,965			4,183
Operating Expenses:
Fuel	1,212			1,647			911			1,212
Purchased power	144			187			165			144
Other operations and maintenance	1,122			986			1,106			1,122
Depreciation and amortization	487			497			541			487
Taxes other than income taxes	252			247			256			252
Estimated loss on Kemper IGCC	9			380			53			9
Total operating expenses	3,226			3,944			3,032			3,226
Operating Income	957			700			933			957
Other Income and (Expense):
Allowance for equity funds used during construction	63			57			53			63
Interest expense, net of amounts capitalized	(213		)	(206		)	(246		)	(213		)
Other income (expense), net	(8		)	(7		)	(21		)	(8		)
Total other income and (expense)	(158		)	(156		)	(214		)	(158		)
Earnings Before Income Taxes	799			544			719			799
Income taxes	274			176			222			274
Consolidated Net Income	525			368			497			525
Less:
Dividends on Preferred and Preference Stock of Subsidiaries	17			17			11			17
Consolidated Net Income After Dividends on Preferred and Preference Stock of Subsidiaries	$	508		$	351
Net income attributable to noncontrolling interests							1			—
Consolidated Net Income Attributable to Southern Company							$	485		$	508
Common Stock Data:
Earnings per share (EPS) —
Basic EPS	$	0.56		$	0.39		$	0.53		$	0.56
Diluted EPS	$	0.56		$	0.39		$	0.53		$	0.56
Average number of shares of common stock outstanding (in millions)
Basic	910			890			916			910
Diluted	915			893			922			915
Cash dividends paid per share of common stock	$	0.5250		$	0.5075		$	0.5425		$	0.5250



Assets	At March 31, 2015			At December 31, 2014
	(in millions)
Current Assets:
Cash and cash equivalents	$	1,112		$	710
Receivables —
Customer accounts receivable	1,117			1,090
Unbilled revenues	374			432
Under recovered regulatory clause revenues	159			136
Other accounts and notes receivable	241			307
Accumulated provision for uncollectible accounts	(19		)	(18		)
Fossil fuel stock, at average cost	855			930
Materials and supplies, at average cost	1,050			1,039
Vacation pay	178			177
Prepaid expenses	299			665
Deferred income taxes, current	578			506
Other regulatory assets, current	363			346
Other current assets	65			50
Total current assets	6,372			6,370
Property, Plant, and Equipment:
In service	70,279			70,013
Less accumulated depreciation	24,307			24,059
Plant in service, net of depreciation	45,972			45,954
Other utility plant, net	275			211
Nuclear fuel, at amortized cost	914			911
Construction work in progress	8,314			7,792
Total property, plant, and equipment	55,475			54,868
Other Property and Investments:
Nuclear decommissioning trusts, at fair value	1,574			1,546
Leveraged leases	749			743
Miscellaneous property and investments	204			203
Total other property and investments	2,527			2,492
Deferred Charges and Other Assets:
Deferred charges related to income taxes	1,527			1,510
Unamortized debt issuance expense	200			202
Unamortized loss on reacquired debt	239			243
Other regulatory assets, deferred	4,462			4,334
Other deferred charges and assets	808			904
Total deferred charges and other assets	7,236			7,193
Total Assets	$	71,610		$	70,923



Liabilities and Stockholders' Equity	At March 31, 2015			At December 31, 2014
	(in millions)
Current Liabilities:
Securities due within one year	$	3,306		$	3,333
Interest-bearing refundable deposit	275			275
Notes payable	1,679			803
Accounts payable	1,289			1,593
Customer deposits	395			390
Accrued taxes —
Accrued income taxes	198			151
Other accrued taxes	248			487
Accrued interest	286			295
Accrued vacation pay	222			223
Accrued compensation	186			576
Mirror CWIP	311			271
Other current liabilities	790			570
Total current liabilities	9,185			8,967
Long-term Debt	21,093			20,841
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	11,706			11,568
Deferred credits related to income taxes	185			192
Accumulated deferred investment tax credits	1,198			1,208
Employee benefit obligations	2,416			2,432
Asset retirement obligations	2,151			2,168
Other cost of removal obligations	1,209			1,215
Other regulatory liabilities, deferred	439			398
Other deferred credits and liabilities	619			594
Total deferred credits and other liabilities	19,923			19,775
Total Liabilities	50,201			49,583
Redeemable Preferred Stock of Subsidiaries	375			375
Redeemable Noncontrolling Interest	40			39
Stockholders' Equity:
Common Stockholders' Equity:
Common stock, par value $5 per share —
Authorized — 1.5 billion shares
Issued — March 31, 2015: 912 million shares
— December 31, 2014: 909 million shares
Treasury — March 31, 2015: 3.3 million shares
— December 31, 2014: 0.7 million shares
Par value	4,555			4,539
Paid-in capital	6,108			5,955
Treasury, at cost	(142		)	(26		)
Retained earnings	9,639			9,609
Accumulated other comprehensive loss	(143		)	(128		)
Total Common Stockholders' Equity	20,017			19,949
Preferred and Preference Stock of Subsidiaries	756			756
Noncontrolling Interest	221			221
Total Stockholders' Equity	20,994			20,926
Total Liabilities and Stockholders' Equity	$	71,610		$	70,923



Assets	At March 31, 2016			At December 31, 2015
	(in millions)
Current Assets:
Cash and cash equivalents	$	754		$	1,404
Receivables —
Customer accounts receivable	988			1,058
Unbilled revenues	380			397
Under recovered regulatory clause revenues	43			63
Income taxes receivable, current	—			144
Other accounts and notes receivable	236			398
Accumulated provision for uncollectible accounts	(13		)	(13		)
Fossil fuel stock, at average cost	837			868
Materials and supplies, at average cost	1,085			1,061
Vacation pay	181			178
Prepaid expenses	486			495
Other regulatory assets, current	394			402
Other current assets	90			71
Total current assets	5,461			6,526
Property, Plant, and Equipment:
In service	76,553			75,118
Less accumulated depreciation	24,566			24,253
Plant in service, net of depreciation	51,987			50,865
Other utility plant, net	218			233
Nuclear fuel, at amortized cost	941			934
Construction work in progress	9,406			9,082
Total property, plant, and equipment	62,552			61,114
Other Property and Investments:
Nuclear decommissioning trusts, at fair value	1,540			1,512
Leveraged leases	761			755
Miscellaneous property and investments	488			485
Total other property and investments	2,789			2,752
Deferred Charges and Other Assets:
Deferred charges related to income taxes	1,572			1,560
Unamortized loss on reacquired debt	220			227
Other regulatory assets, deferred	4,957			4,989
Income taxes receivable, non-current	413			413
Other deferred charges and assets	771			737
Total deferred charges and other assets	7,933			7,926
Total Assets	$	78,735		$	78,318


	First Quarter 2015					First Quarter 2016
	(in millions)			(% change)		(in millions)			(% change)
Retail – prior year	$	3,858				$	3,542
Estimated change resulting from –
Rates and pricing	77			2.0		110			3.1
Sales growth	18			0.5		22			0.6
Weather	(38		)	(1.0	)	(85		)	(2.4	)
Fuel and other cost recovery	(373		)	(9.7	)	(212		)	(6.0	)
Retail – current year	$	3,542		(8.2	)%	$	3,377		(4.7	)%


	First Quarter 2015	First Quarter 2014	First Quarter 2016	First Quarter 2015
Total generation (billions of KWHs)	46	47	44	46
Total purchased power (billions of KWHs)	3	3	4	3
Sources of generation (percent) —
Coal	33	47	27	33
Nuclear	16	16	17	16
Gas	47	33	47	47
Hydro	4	4	7	3
Other Renewables			2	1
Cost of fuel, generated (cents per net KWH) —
Coal	3.70	4.19	3.24	3.70
Nuclear	0.67	0.89	0.82	0.67
Gas	2.71	4.19	2.16	2.71
Average cost of fuel, generated (cents per net KWH)	2.71	3.63	2.23	2.71
Average cost of purchased power (cents per net KWH)^(a)	7.18	8.89
Average cost of purchased power (cents per net KWH)^(*)			5.27	7.18


~~(a)~~(*)	Average cost of purchased power includes fuel purchased by the Southern Company system for tolling agreements where power is generated by the provider.


(a)	Excludes the $8.1 billion Bridge Agreement entered into in September 2015 that will be funded only to the extent necessary to provide financing for the Merger as discussed herein.


(b)	Excludes credit agreements (Project Credit Facilities) assumed with the acquisition of certain solar facilities, which are non-recourse to Southern Power Company, the proceeds of which are being used to finance project costs related to such solar facilities currently under construction. See Note (I) to the Condensed Financial Statements under "Southern Power" herein for additional information.


	Short-term Debt at March 31, 2015				Short-term Debt During the Period^(*)						Short-term Debt at March 31, 2016				Short-term Debt During the Period^(*)
	Amount Outstanding		Weighted Average Interest Rate		Average Outstanding		Weighted Average Interest Rate		Maximum Amount Outstanding		Amount Outstanding		Weighted Average Interest Rate		Average Amount Outstanding		Weighted Average Interest Rate		Maximum Amount Outstanding
	(in millions)				(in millions)				(in millions)		(in millions)				(in millions)				(in millions)
Commercial paper	$	1,399	0.3	%	$	883	0.3	%	$	1,487	$	757	0.8	%	$	853	0.8	%	$	1,233
Short-term bank debt	280		0.8	%	10		1.1	%	280		25		2.1	%	375		1.9	%	500
Total	$	1,679	0.4	%	$	893	0.3	%			$	782	0.9	%	$	1,228	1.0	%


(*)	Average and maximum amounts are based upon daily balances during the three-month period ended March 31, 2016.



Company^(a)	Senior Note Issuances		Senior Note Maturities and Redemptions		Revenue Bond Maturities, Redemptions, and Repurchases		Other Long-Term Debt Issuances			Other Long-Term Debt Redemptions and Maturities^(b)
	(in millions)
Alabama Power	$	400	$	200	$	—	$	45		$	—
Georgia Power	650		250		4		—			1
Mississippi Power	—		—		—		1,100			426
Southern Power	—		—		—		2			3
Other	—		—		—		—			4
Elimination^(c)	—		—		—		(200		)	—
Total	$	1,050	$	450	$	4	$	947		$	434


(a)	Southern Company and Gulf Power did not issue or redeem any long-term debt during the first three months of 2016.


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


(c)	Intercompany loans from Southern Company to Mississippi Power eliminated in Southern Company's Consolidated Financial Statements.



Company^(a)	Senior Note Issuances		Senior Note Redemptions		Other Long-Term Debt Redemptions and Maturities^(b)
	(in millions)
Alabama Power	$	550	$	250	$	—
Georgia Power	—		—		3
Mississippi Power	—		—		76
Other	—		—		4
Total	$	550	$	250	$	83


~~(a)~~	~~Southern Company, Gulf Power, and Southern Power did not issue or redeem any long-term debt during the first three months of 2015.~~


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


(b)	Changes in internal ~~controls.~~controls over financial reporting.



Liabilities and Stockholder's Equity	At March 31, 2015			At December 31, 2014
	(in millions)
Current Liabilities:
Securities due within one year	$	734		$	454
Accounts payable —
Affiliated	225			248
Other	273			443
Customer deposits	88			87
Accrued taxes —
Accrued income taxes	37			2
Other accrued taxes	59			37
Accrued interest	59			66
Accrued vacation pay	54			54
Accrued compensation	44			131
Other regulatory liabilities, current	2			2
Other current liabilities	114			80
Total current liabilities	1,689			1,604
Long-term Debt	6,193			6,176
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	3,890			3,874
Deferred credits related to income taxes	71			72
Accumulated deferred investment tax credits	123			125
Employee benefit obligations	322			326
Asset retirement obligations	840			829
Other cost of removal obligations	743			744
Other regulatory liabilities, deferred	242			239
Deferred over recovered regulatory clause revenues	81			47
Other deferred credits and liabilities	88			79
Total deferred credits and other liabilities	6,400			6,335
Total Liabilities	14,282			14,115
Redeemable Preferred Stock	342			342
Preference Stock	343			343
Common Stockholder's Equity:
Common stock, par value $40 per share —
Authorized — 40,000,000 shares
Outstanding — 30,537,500 shares	1,222			1,222
Paid-in capital	2,318			2,304
Retained earnings	2,281			2,255
Accumulated other comprehensive loss	(32		)	(29		)
Total common stockholder's equity	5,789			5,752
Total Liabilities and Stockholder's Equity	$	20,756		$	20,552


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



	Short-term Debt at March 31, 2015			Short-term Debt During the Period(*)
	Amount Outstanding		Weighted Average Interest Rate	Average Outstanding		Weighted Average Interest Rate	Maximum Amount Outstanding
	(in millions)			(in millions)			(in millions)
Commercial Paper	$	—	—%	$	29	0.2%	$	100



	Short-term Debt During the Period^(*)
	Average Amount Outstanding		Weighted Average Interest Rate		Maximum Amount Outstanding
	(in millions)				(in millions)
Commercial paper	$	19	0.6	%	$	100



Expires								Due Within One Year
2016		2018		Total		Unused		Term Out		No Term Out
(in millions)				(in millions)				(in millions)
$	150	$	1,600	$	1,750	$	1,736	$	—	$	150



~~First Quarter 2015 vs. First Quarter 2014~~
~~(change in millions)~~		~~(% change)~~
~~$207~~		~~N/M~~


~~(*)~~	~~Includes energy produced during the test period for the Kemper IGCC which is accounted for in accordance with FERC guidance.~~



	Commercial Paper at the End of the Period				Commercial Paper During the Period^(*)
	Amount Outstanding		Weighted Average Interest Rate		Average Outstanding		Weighted Average Interest Rate		Maximum Amount Outstanding
	(in millions)				(in millions)				(in millions)
March 31, 2015:	$	233	0.6	%	$	156	0.5	%	$	234