2.4.0.82102100 - Disclosure - Contingencies and Regulatory Matterstruefalsefalse1falsefalsefalseD2013Q2YTDhttp://www.sec.gov/CIK0000092122duration2013-01-01T00:00:002013-06-30T00:00:001true1us-gaap_CommitmentsAndContingenciesDisclosureAbstractus-gaap_truenadurationfalsefalsefalsefalsefalsefalsefalsefalse1falsefalsefalse00falsefalsefalsexbrli:stringItemTypestringfalse02false2us-gaap_LegalMattersAndContingenciesTextBlockus-gaap_truenadurationfalsefalsefalsefalsefalsefalsefalsefalseverboseLabel1falsefalsefalse00<div style="font-family:Times New Roman;font-size:10pt;"><div style="line-height:120%;text-align:left;font-size:11pt;"><font style="font-family:inherit;font-size:11pt;">CONTINGENCIES AND REGULATORY MATTERS</font></div><div style="line-height:120%;padding-top:10px;text-align:left;font-size:11pt;"><font style="font-family:inherit;font-size:11pt;">See Note 3 to the financial statements of the registrants (other than Mississippi Power) in Item 8 of the Form 10-K and Note 3 to the financial statements of Mississippi Power in Item 8 of the Form 10-K/A for information relating to various lawsuits, other contingencies, and regulatory matters.</font></div><div style="line-height:120%;padding-top:12px;font-size:11pt;"><font style="font-family:inherit;font-size:11pt;font-weight:bold;">General Litigation Matters</font></div><div style="line-height:120%;padding-top:8px;font-size:11pt;"><font style="font-family:inherit;font-size:11pt;">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 increased generally throughout the U.S. In particular, personal injury, property damage, and other claims for damages alleged to have been caused by carbon dioxide (CO</font><font style="font-family:inherit;font-size:11pt;"><sub style="vertical-align:bottom;line-height:120%;font-size:7pt">2</sub></font><font style="font-family:inherit;font-size:11pt;">) and other emissions, coal combustion byproducts, and alleged exposure to hazardous materials, and/or requests for injunctive relief in connection with such matters, have become more frequent. 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 (other than Mississippi Power) in Item 8 of the Form 10-K and Note 3 to the financial statements of Mississippi Power in Item 8 of the Form 10-K/A, 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.</font></div><div style="line-height:120%;padding-top:12px;font-size:11pt;"><font style="font-family:inherit;font-size:11pt;font-weight:bold;">Environmental Matters</font></div><div style="line-height:120%;padding-top:8px;font-size:11pt;"><font style="font-family:inherit;font-size:11pt;font-style:italic;font-weight:bold;">New Source Review Actions</font></div><div style="line-height:120%;padding-top:8px;font-size:11pt;"><font style="font-family:inherit;font-size:11pt;">In 1999, the EPA brought a civil action in the U.S. District Court for the Northern District of Georgia against certain Southern Company subsidiaries, including Alabama Power and Georgia Power, alleging that these subsidiaries had violated the NSR provisions of the Clean Air Act and related state laws at certain coal-fired generating facilities. The EPA alleged NSR violations at </font><font style="font-family:inherit;font-size:11pt;color:#000000;text-decoration:none;">five</font><font style="font-family:inherit;font-size:11pt;"> coal-fired generating facilities operated by Alabama Power, including a unit co-owned by Mississippi Power, and </font><font style="font-family:inherit;font-size:11pt;color:#000000;text-decoration:none;">three</font><font style="font-family:inherit;font-size:11pt;"> coal-fired generating facilities operated by Georgia Power, including a unit co-owned by Gulf Power. The civil action sought penalties and injunctive relief, including an order requiring installation of the best available control technology at the affected units. The case against Georgia Power (including claims related to the unit co-owned by Gulf Power) was administratively closed in 2001 and has not been reopened. After Alabama Power was dismissed from the original action, the EPA filed a separate action in 2001 against Alabama Power (including claims related to the unit co-owned by Mississippi Power) in the U.S. District Court for the Northern District of Alabama.</font></div><div style="line-height:120%;padding-top:8px;font-size:11pt;"><font style="font-family:inherit;font-size:11pt;">In 2006, the U.S. District Court for the Northern District of Alabama entered a consent decree, resolving claims relating to the alleged NSR violations at Plant Miller. In 2010, the EPA dismissed </font><font style="font-family:inherit;font-size:11pt;color:#000000;text-decoration:none;">five</font><font style="font-family:inherit;font-size:11pt;"> of its </font><font style="font-family:inherit;font-size:11pt;color:#000000;text-decoration:none;">eight</font><font style="font-family:inherit;font-size:11pt;"> remaining claims against Alabama Power, leaving only </font><font style="font-family:inherit;font-size:11pt;color:#000000;text-decoration:none;">three</font><font style="font-family:inherit;font-size:11pt;"> claims, including one relating to the unit co-owned by Mississippi Power. In 2011, the U.S. District Court for the Northern District of Alabama granted Alabama Power summary judgment on all remaining claims and dismissed the case with prejudice. That judgment is on appeal to the U.S. Court of Appeals for the Eleventh Circuit. In February 2012, the EPA filed a motion in the U.S. District Court for the Northern District of Alabama seeking vacatur of the judgment and recusal of the judge in the case involving Alabama Power.</font></div><div style="line-height:120%;padding-top:8px;font-size:11pt;"><font style="font-family:inherit;font-size:11pt;">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 </font><font style="font-family:inherit;font-size:11pt;color:#000000;text-decoration:none;">$25,000</font><font style="font-family:inherit;font-size:11pt;"> to </font><font style="font-family:inherit;font-size:11pt;color:#000000;text-decoration:none;">$37,500</font><font style="font-family:inherit;font-size:11pt;"> 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.</font></div><div style="line-height:120%;padding-top:12px;font-size:11pt;"><font style="font-family:inherit;font-size:11pt;font-style:italic;font-weight:bold;">Climate Change Litigation</font></div><div style="line-height:120%;padding-top:8px;font-size:11pt;"><font style="font-family:inherit;font-size:11pt;font-style:italic;">Kivalina Case</font></div><div style="line-height:120%;padding-top:8px;font-size:11pt;"><font style="font-family:inherit;font-size:11pt;">In 2008, the Native Village of Kivalina and the City of Kivalina filed a lawsuit in the U.S. District Court for the Northern District of California against several electric utilities (including Southern Company), several oil companies, and a coal company. The plaintiffs alleged that the village was being destroyed by erosion allegedly caused by global warming that the plaintiffs attributed to emissions of greenhouse gases by the defendants. The plaintiffs asserted claims for public and private nuisance and contended that some of the defendants (including Southern Company) acted in concert and were therefore jointly and severally liable for the plaintiffs' damages. The suit sought damages for lost property values and for the cost of relocating the village, which was alleged to be </font><font style="font-family:inherit;font-size:11pt;color:#000000;text-decoration:none;">$95 million</font><font style="font-family:inherit;font-size:11pt;"> to </font><font style="font-family:inherit;font-size:11pt;color:#000000;text-decoration:none;">$400 million</font><font style="font-family:inherit;font-size:11pt;">. In 2009, the U.S. District Court for the Northern District of California granted the defendants' motions to dismiss the case. In September 2012, the U.S. Court of Appeals for the Ninth Circuit upheld the U.S. District Court for the Northern District of California's dismissal of the case. In November 2012, the U.S. Court of Appeals for the Ninth Circuit denied the plaintiffs' request for review of the decision. On February 25, 2013, the plaintiffs filed a petition for writ of certiorari with the U.S. Supreme Court. On May 20, 2013, the U.S. Supreme Court denied the plaintiffs' petition for review. The case is now concluded.</font></div><div style="line-height:120%;padding-top:12px;font-size:11pt;"><font style="font-family:inherit;font-size:11pt;font-style:italic;">Hurricane Katrina Case</font></div><div style="line-height:120%;padding-top:8px;font-size:11pt;"><font style="font-family:inherit;font-size:11pt;">In 2005, immediately following Hurricane Katrina, a lawsuit was filed in the U.S. District Court for the Southern District of Mississippi by Ned Comer on behalf of Mississippi residents seeking recovery for property damage and personal injuries caused by Hurricane Katrina. In 2006, the plaintiffs amended the complaint to include Southern Company and many other electric utilities, oil companies, chemical companies, and coal producers. The plaintiffs allege that the defendants contributed to climate change, which contributed to the intensity of Hurricane Katrina. In 2007, the U.S. District Court for the Southern District of Mississippi dismissed the case. On appeal to the U.S. Court of Appeals for the Fifth Circuit, a three-judge panel reversed the U.S. District Court for the Southern District of Mississippi, holding that the case could proceed, but, on rehearing, the full U.S. Court of Appeals for the Fifth Circuit dismissed the plaintiffs' appeal, resulting in reinstatement of the decision of the U.S. District Court for the Southern District of Mississippi in favor of the defendants. In 2011, the plaintiffs filed an amended version of their class action complaint, arguing that the earlier dismissal was on procedural grounds and under Mississippi law the plaintiffs have a right to re-file. The amended complaint was also filed against numerous chemical, coal, oil, and utility companies, including Alabama Power, Georgia Power, Gulf Power, and Southern Power. On May 14, 2013, the U.S. Court of Appeals for the Fifth Circuit upheld the U.S. District Court for the Southern District of Mississippi's March 2012 dismissal of the case. The decision is subject to appeal. Each Southern Company entity named in the lawsuit believes that these claims are without merit. While each Southern Company entity named in the lawsuit believes the likelihood of loss is remote based on existing case law, it is not possible to predict with certainty whether any Southern Company entity named in the lawsuit will incur any liability in connection with this matter. The ultimate outcome of this matter cannot be determined at this time.</font></div><div style="line-height:120%;padding-top:12px;font-size:11pt;"><font style="font-family:inherit;font-size:11pt;font-weight:bold;">Environmental Remediation</font></div><div style="line-height:120%;padding-top:8px;font-size:11pt;"><font style="font-family:inherit;font-size:11pt;">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. 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.</font></div><div style="line-height:120%;padding-top:8px;font-size:11pt;"><font style="font-family:inherit;font-size:11pt;">Georgia Power's environmental remediation liability as of June 30, 2013 was </font><font style="font-family:inherit;font-size:11pt;color:#000000;text-decoration:none;">$18 million</font><font style="font-family:inherit;font-size:11pt;">. 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 large site in Brunswick, Georgia on the CERCLA National Priorities List (NPL). The parties have completed the removal of wastes from the Brunswick site as ordered by the EPA. Additional cleanup and claims for recovery of natural resource damages at this site or for the assessment and potential cleanup of other sites on the Georgia Hazardous Sites Inventory and the CERCLA NPL are anticipated.</font></div><div style="line-height:120%;padding-top:8px;font-size:11pt;"><font style="font-family:inherit;font-size:11pt;">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. 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 action and a court determines that a respondent failed to comply with the UAO without sufficient cause, the EPA may also seek civil penalties of up to </font><font style="font-family:inherit;font-size:11pt;color:#000000;text-decoration:none;">$37,500</font><font style="font-family:inherit;font-size:11pt;"> per day for the violation and punitive damages of up to </font><font style="font-family:inherit;font-size:11pt;color:#000000;text-decoration:none;">three</font><font style="font-family:inherit;font-size:11pt;"> times the costs incurred by the EPA as a result of the party's failure to comply with the UAO.</font></div><div style="line-height:120%;padding-top:8px;font-size:11pt;"><font style="font-family:inherit;font-size:11pt;">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. On February 1, 2013, the U.S. District Court for 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 May 10, 2013, the plaintiffs appealed the U.S. District Court for the Eastern District of North Carolina Western Division's order to the U.S. Court of Appeals for the Fourth Circuit.</font></div><div style="line-height:120%;padding-top:8px;font-size:11pt;"><font style="font-family:inherit;font-size:11pt;">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 the regulatory treatment, they 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" in Item 8 of the Form 10-K for additional information regarding the regulatory treatment.</font></div><div style="line-height:120%;padding-top:8px;font-size:11pt;"><font style="font-family:inherit;font-size:11pt;">Gulf Power's environmental remediation liability includes estimated costs of environmental remediation projects of approximately </font><font style="font-family:inherit;font-size:11pt;color:#000000;text-decoration:none;">$51 million</font><font style="font-family:inherit;font-size:11pt;"> as of June 30, 2013. 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, there was no impact on net income as a result of these estimates.</font></div><div style="line-height:120%;padding-top:8px;font-size:11pt;"><font style="font-family:inherit;font-size:11pt;">In 2003, the Texas Commission on Environmental Quality (TCEQ) designated Mississippi Power as a PRP at a site in Texas. The site was owned by an electric transformer company that handled Mississippi Power's transformers as well as those of many other entities. The site owner is bankrupt and the State of Texas has entered into an agreement with Mississippi Power and several other utilities to investigate and remediate the site. The feasibility study/presumptive remedy document was originally filed with TCEQ in 2011 and remains under consideration by the agency. Amounts expensed and accrued related to this work were not material. Hundreds of entities have received notices from the TCEQ requesting their participation in the anticipated site remediation. The final impact of this matter on Mississippi Power will depend upon further environmental assessment and the ultimate number of PRPs. The remediation expenses incurred by Mississippi Power are expected to be recovered through the ECO Plan.</font></div><div style="line-height:120%;padding-top:8px;font-size:11pt;"><font style="font-family:inherit;font-size:11pt;">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, Gulf Power, and Mississippi Power does not believe that additional liabilities, if any, at these sites would be material to their respective financial statements</font><font style="font-family:inherit;font-size:11pt;font-style:italic;">.</font></div><div style="line-height:120%;padding-top:12px;font-size:11pt;"><font style="font-family:inherit;font-size:11pt;font-weight:bold;">Nuclear Fuel Disposal Cost Litigation</font></div><div style="line-height:120%;padding-top:8px;font-size:11pt;"><font style="font-family:inherit;font-size:11pt;">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. The DOE failed to timely perform and has yet to commence the performance of its contractual and statutory obligation to dispose of spent nuclear fuel beginning no later than January 31, 1998. Consequently, Alabama Power and Georgia Power have pursued and continue to pursue legal remedies against the U.S. government for its partial breach of contract.</font></div><div style="line-height:120%;padding-top:8px;font-size:11pt;"><font style="font-family:inherit;font-size:11pt;">As a result of the first lawsuit, Georgia Power recovered approximately </font><font style="font-family:inherit;font-size:11pt;color:#000000;text-decoration:none;">$27 million</font><font style="font-family:inherit;font-size:11pt;">, based on its ownership interests, and Alabama Power recovered approximately </font><font style="font-family:inherit;font-size:11pt;color:#000000;text-decoration:none;">$17 million</font><font style="font-family:inherit;font-size:11pt;">, representing substantially all of the Southern Company system's direct costs of the expansion of spent nuclear fuel storage facilities at Plants Farley and Hatch and Plant Vogtle Units 1 and 2 from 1998 through 2004. In April 2012, Alabama Power credited the award to cost of service for the benefit of customers. In July 2012, Georgia Power credited the award to accounts where the original costs were charged and used it to reduce rate base, fuel, and cost of service for the benefit of customers.</font></div><div style="line-height:120%;padding-top:8px;font-size:11pt;"><font style="font-family:inherit;font-size:11pt;">In 2008, Alabama Power and Georgia Power filed a second lawsuit 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. Damages are being sought for the period from January 1, 2005 through December 31, 2010. Damages will continue to accumulate until the issue is resolved or storage is provided. </font><font style="font-family:inherit;font-size:11pt;color:#000000;text-decoration:none;">No</font><font style="font-family:inherit;font-size:11pt;"> amounts have been recognized in the financial statements as of June 30, 2013 for any potential recoveries from the second lawsuit. 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.</font></div><div style="line-height:120%;padding-top:8px;font-size:11pt;"><font style="font-family:inherit;font-size:11pt;">Sufficient pool storage capacity for spent fuel is available at Plant Vogtle Units 1 and 2 to maintain full-core discharge capability for both units into 2014. Construction of an on-site dry storage facility at Plant Vogtle Units 1 and 2 has begun. The facility is expected to begin operation in sufficient time to maintain full-core discharge capability, with additional on-site dry storage to be added as needed. At Plants Hatch and Farley, on-site dry spent fuel storage facilities are operational and can be expanded to accommodate spent fuel through the expected life of each plant.</font></div><div style="line-height:120%;padding-top:12px;font-size:11pt;"><font style="font-family:inherit;font-size:11pt;font-weight:bold;">FERC Matters</font></div><div style="line-height:120%;padding-top:8px;font-size:11pt;"><font style="font-family:inherit;font-size:11pt;">See Note 3 to the financial statements of Mississippi Power under "FERC Matters" in Item 8 of the Form 10-K/A for additional information regarding Mississippi Power's settlement agreement with its wholesale customers for revised rates related to the wholesale Municipal and Rural Associations (MRA) cost-based electric tariff. See Note 3 to the financial statements of Southern Company under "Integrated Coal Gasification Combined Cycle" in Item 8 of the Form 10-K, Note 3 to the financial statements of Mississippi Power under "Integrated Coal Gasification Combined Cycle" in Item 8 of the Form 10-K/A, and "Integrated Coal Gasification Combined Cycle" herein for information regarding Mississippi Power's construction of the Kemper IGCC.</font></div><div style="line-height:120%;padding-top:12px;text-align:left;font-size:11pt;"><font style="font-family:inherit;font-size:11pt;">In March 2012, Mississippi Power entered into a settlement agreement with its wholesale customers to increase wholesale base revenues under the MRA cost-based electric tariff by approximately </font><font style="font-family:inherit;font-size:11pt;color:#000000;text-decoration:none;">$22.6 million</font><font style="font-family:inherit;font-size:11pt;"> annually, and the FERC approved interim rates effective May 1, 2012. In September 2012, Mississippi Power, with its wholesale customers, filed a final settlement agreement with the FERC. On May 3, 2013, Mississippi Power received an order from the FERC accepting the settlement agreement.</font></div><div style="line-height:120%;padding-top:12px;text-align:left;font-size:11pt;"><font style="font-family:inherit;font-size:11pt;">On April 1, 2013, Mississippi Power reached a settlement agreement with its wholesale customers and filed a request with the FERC for an additional increase in the MRA cost-based electric tariff, which was accepted by the FERC on May 30, 2013. In accordance with the 2013 settlement agreement, base rates under the MRA cost-based electric tariff increased approximately </font><font style="font-family:inherit;font-size:11pt;color:#000000;text-decoration:none;">$24.2 million</font><font style="font-family:inherit;font-size:11pt;"> annually, effective April 1, 2013. The amount of base rate revenues to be received in 2013 from the agreed upon increase will be approximately </font><font style="font-family:inherit;font-size:11pt;color:#000000;text-decoration:none;">$18.0 million</font><font style="font-family:inherit;font-size:11pt;">.</font></div><div style="line-height:120%;padding-top:12px;font-size:11pt;"><font style="font-family:inherit;font-size:11pt;font-weight:bold;">Retail Regulatory Matters</font></div><div style="line-height:120%;padding-top:8px;font-size:11pt;"><font style="font-family:inherit;font-size:11pt;font-style:italic;font-weight:bold;">Alabama Power</font></div><div style="line-height:120%;padding-top:8px;font-size:11pt;"><font style="font-family:inherit;font-size:11pt;font-style:italic;">Rate CNP</font></div><div style="line-height:120%;padding-top:8px;font-size:11pt;"><font style="font-family:inherit;font-size:11pt;">See Note 3 to the financial statements of Southern Company and Alabama Power under "Retail Regulatory Matters </font><font style="font-family:inherit;font-size:11pt;font-style:italic;">–</font><font style="font-family:inherit;font-size:11pt;"> Alabama Power </font><font style="font-family:inherit;font-size:11pt;font-style:italic;">–</font><font style="font-family:inherit;font-size:11pt;"> Rate CNP" and "Retail Regulatory Matters </font><font style="font-family:inherit;font-size:11pt;font-style:italic;">–</font><font style="font-family:inherit;font-size:11pt;"> Rate CNP" in Item 8 of the Form 10-K for additional information regarding Alabama Power's recovery of retail costs through Rate Certificated New Plant Power Purchase Agreement (Rate CNP PPA) and Rate Certificated New Plant Environmental (Rate CNP Environmental). Alabama Power's under recovered Rate CNP PPA balance at June 30, 2013 and at December 31, 2012 was </font><font style="font-family:inherit;font-size:11pt;color:#000000;text-decoration:none;">$9 million</font><font style="font-family:inherit;font-size:11pt;">. This under recovered balance at June 30, 2013 is included in deferred under recovered regulatory clause revenues on Southern Company's and Alabama Power's Condensed Balance Sheets herein. For Rate CNP PPA, this classification is based on an estimate, which includes such factors as purchased power capacity and energy demand. A change in any of these factors could have a material impact on the timing of any recovery of the under recovered retail costs. Alabama Power's under recovered Rate CNP Environmental balance at June 30, 2013 and December 31, 2012 was </font><font style="font-family:inherit;font-size:11pt;color:#000000;text-decoration:none;">$21 million</font><font style="font-family:inherit;font-size:11pt;">. This under recovered balance at June 30, 2013 consists of </font><font style="font-family:inherit;font-size:11pt;color:#000000;text-decoration:none;">$8 million</font><font style="font-family:inherit;font-size:11pt;"> in under recovered regulatory clause revenues and </font><font style="font-family:inherit;font-size:11pt;color:#000000;text-decoration:none;">$13 million</font><font style="font-family:inherit;font-size:11pt;"> in deferred under recovered regulatory clause revenues on Southern Company's and Alabama Power's Condensed Balance Sheets herein. For Rate CNP Environmental, this classification is based on an estimate, which includes such factors as costs to comply with environmental mandates and energy demand. A change in any of these factors could have a material impact on the timing of any recovery of the under recovered retail costs. </font></div><div style="line-height:120%;padding-top:12px;text-align:left;font-size:11pt;"><font style="font-family:inherit;font-size:11pt;font-style:italic;">Retail Energy Cost Recovery</font></div><div style="line-height:120%;padding-top:8px;font-size:11pt;"><font style="font-family:inherit;font-size:11pt;">See Note 3 to the financial statements of Southern Company and Alabama Power under "Retail Regulatory Matters – Alabama Power – Energy Cost Recovery" and "Retail Regulatory Matters – Energy Cost Recovery," respectively, in Item 8 of the Form 10-K for additional information regarding Alabama Power's energy cost recovery. Alabama Power's over recovered fuel costs at June 30, 2013 totaled </font><font style="font-family:inherit;font-size:11pt;color:#000000;text-decoration:none;">$13 million</font><font style="font-family:inherit;font-size:11pt;"> as compared to an under recovered balance of </font><font style="font-family:inherit;font-size:11pt;color:#000000;text-decoration:none;">$4 million</font><font style="font-family:inherit;font-size:11pt;"> at December 31, 2012. The over recovered fuel costs at June 30, 2013 are included in other regulatory liabilities, current and the under recovered fuel costs at December 31, 2012 are included in deferred under recovered regulatory clause revenues on Southern Company's and Alabama Power's Condensed Balance Sheets herein. These classifications are based on estimates, which include such factors as weather, generation availability, energy demand, and the price of energy. A change in any of these factors could have a material impact on the timing of any return of the over recovered fuel costs.</font></div><div style="line-height:120%;padding-top:12px;text-align:left;font-size:11pt;"><font style="font-family:inherit;font-size:11pt;font-style:italic;">Natural Disaster Cost Recovery</font></div><div style="line-height:120%;padding-top:8px;font-size:11pt;"><font style="font-family:inherit;font-size:11pt;">See Note 3 to the financial statements of Southern Company and Alabama Power under "Retail Regulatory Matters </font><font style="font-family:inherit;font-size:11pt;font-style:italic;">– </font><font style="font-family:inherit;font-size:11pt;">Alabama Power </font><font style="font-family:inherit;font-size:11pt;font-style:italic;">– </font><font style="font-family:inherit;font-size:11pt;">Natural Disaster Reserve" and "Retail Regulatory Matters </font><font style="font-family:inherit;font-size:11pt;font-style:italic;">– </font><font style="font-family:inherit;font-size:11pt;">Natural Disaster Reserve," respectively, in Item 8 of the Form 10-K for additional information regarding natural disaster cost recovery. At June 30, 2013, the NDR had an accumulated balance of </font><font style="font-family:inherit;font-size:11pt;color:#000000;text-decoration:none;">$95 million</font><font style="font-family:inherit;font-size:11pt;"> as compared to </font><font style="font-family:inherit;font-size:11pt;color:#000000;text-decoration:none;">$103 million</font><font style="font-family:inherit;font-size:11pt;"> at December 31, 2012, which is included on Southern Company's and Alabama Power's Condensed Balance Sheets herein under other regulatory liabilities, deferred. The decrease in the NDR is a result of storm activity. The related accruals are reflected as operations and maintenance expenses on Southern Company's and Alabama Power's Condensed Statements of Income herein.</font></div><div style="line-height:120%;padding-top:12px;font-size:11pt;"><font style="font-family:inherit;font-size:11pt;font-style:italic;font-weight:bold;">Georgia Power</font></div><div style="line-height:120%;padding-top:8px;font-size:11pt;"><font style="font-family:inherit;font-size:11pt;font-style:italic;">Fuel Cost Recovery</font></div><div style="line-height:120%;padding-top:8px;font-size:11pt;"><font style="font-family:inherit;font-size:11pt;">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.</font></div><div style="line-height:120%;padding-top:8px;font-size:11pt;"><font style="font-family:inherit;font-size:11pt;">As of June 30, 2013 and December 31, 2012, Georgia Power's fuel cost over recovery balance totaled </font><font style="font-family:inherit;font-size:11pt;color:#000000;text-decoration:none;">$108 million</font><font style="font-family:inherit;font-size:11pt;"> included in current liabilities and </font><font style="font-family:inherit;font-size:11pt;color:#000000;text-decoration:none;">$230 million</font><font style="font-family:inherit;font-size:11pt;"> included in current liabilities and other deferred credits and liabilities, respectively, on Southern Company's and Georgia Power's Condensed Balance Sheets herein.</font></div><div style="line-height:120%;padding-top:8px;font-size:11pt;"><font style="font-family:inherit;font-size:11pt;">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, any 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.</font></div><div style="line-height:120%;padding-top:8px;text-align:left;font-size:11pt;"><font style="font-family:inherit;font-size:11pt;font-style:italic;">Rate Plans</font></div><div style="line-height:120%;padding-top:8px;text-align:left;font-size:11pt;"><font style="font-family:inherit;font-size:11pt;">See Note 3 to the financial statements of Southern Company and Georgia Power under "Retail Regulatory Matters –Georgia Power – Rate Plans" and "Retail Regulatory Matters – Rate Plans," respectively, in Item 8 of the Form 10-K for information regarding Georgia Power's current retail rate plan.</font></div><div style="line-height:120%;padding-top:8px;text-align:left;font-size:11pt;"><font style="font-family:inherit;font-size:11pt;">In accordance with the 2010 ARP, Georgia Power filed a base rate case with the Georgia PSC on June 28, 2013 (2013 Rate Case). The filing includes a requested rate increase totaling </font><font style="font-family:inherit;font-size:11pt;color:#000000;text-decoration:none;">$482 million</font><font style="font-family:inherit;font-size:11pt;">, or </font><font style="font-family:inherit;font-size:11pt;color:#000000;text-decoration:none;">6.1%</font><font style="font-family:inherit;font-size:11pt;"> of retail revenues, to be effective January 1, 2014 based on a proposed retail ROE of </font><font style="font-family:inherit;font-size:11pt;color:#000000;text-decoration:none;">11.50%</font><font style="font-family:inherit;font-size:11pt;">. The requested increase will be recovered through Georgia Power's existing base rate tariffs as follows: </font><font style="font-family:inherit;font-size:11pt;color:#000000;text-decoration:none;">$334 million</font><font style="font-family:inherit;font-size:11pt;"> through the traditional base rate tariffs, </font><font style="font-family:inherit;font-size:11pt;color:#000000;text-decoration:none;">$132 million</font><font style="font-family:inherit;font-size:11pt;"> through the Environmental Compliance Cost Recovery (ECCR) tariff, </font><font style="font-family:inherit;font-size:11pt;color:#000000;text-decoration:none;">$5 million</font><font style="font-family:inherit;font-size:11pt;"> through the Demand Side Management tariffs, and </font><font style="font-family:inherit;font-size:11pt;color:#000000;text-decoration:none;">$11 million</font><font style="font-family:inherit;font-size:11pt;"> through the Municipal Franchise Fee tariff. The filing reflects revenue requirements that have been levelized over the </font><font style="font-family:inherit;font-size:11pt;color:#000000;text-decoration:none;">three</font><font style="font-family:inherit;font-size:11pt;">-year period ending December 31, 2016 to provide stable rates to customers during a period of rising costs. The request is being made to allow Georgia Power to recover the costs of recent and future investments in infrastructure including environmental controls, transmission and distribution, generation, and smart grid technologies in order to maintain high levels of reliability and superior customer service.</font></div><div style="line-height:120%;padding-top:8px;text-align:left;font-size:11pt;"><font style="font-family:inherit;font-size:11pt;">The primary points of the 2013 Rate Case are:</font></div><table cellpadding="0" cellspacing="0" style="padding-top:8px;font-family:Times New Roman; font-size:10pt;"><tr><td style="width:48px;" rowspan="1" colspan="1"></td><td rowspan="1" colspan="1"></td></tr><tr><td style="vertical-align:top" rowspan="1" colspan="1"><div style="line-height:120%;font-size:11pt;padding-left:24px;"><font style="font-family:inherit;font-size:10pt;">•</font></div></td><td style="vertical-align:top;" rowspan="1" colspan="1"><div style="line-height:120%;text-align:left;font-size:11pt;"><font style="font-family:inherit;font-size:11pt;">Continuation of the traditional base rate tariffs through December 31, 2016 based on a test year ending July 31, 2014 with a modification for an appropriate </font><font style="font-family:inherit;font-size:11pt;color:#000000;text-decoration:none;">three</font><font style="font-family:inherit;font-size:11pt;">-year levelization adjustment.</font></div></td></tr></table><table cellpadding="0" cellspacing="0" style="font-family:Times New Roman; font-size:10pt;"><tr><td style="width:48px;" rowspan="1" colspan="1"></td><td rowspan="1" colspan="1"></td></tr><tr><td style="vertical-align:top" rowspan="1" colspan="1"><div style="line-height:120%;font-size:11pt;padding-left:24px;"><font style="font-family:inherit;font-size:10pt;">•</font></div></td><td style="vertical-align:top;" rowspan="1" colspan="1"><div style="line-height:120%;text-align:left;font-size:11pt;"><font style="font-family:inherit;font-size:11pt;">Continuation of the ECCR tariff through December 31, 2016 with a modification for an appropriate </font><font style="font-family:inherit;font-size:11pt;color:#000000;text-decoration:none;">three</font><font style="font-family:inherit;font-size:11pt;">-year levelization adjustment.</font></div></td></tr></table><table cellpadding="0" cellspacing="0" style="font-family:Times New Roman; font-size:10pt;"><tr><td style="width:48px;" rowspan="1" colspan="1"></td><td rowspan="1" colspan="1"></td></tr><tr><td style="vertical-align:top" rowspan="1" colspan="1"><div style="line-height:120%;font-size:11pt;padding-left:24px;"><font style="font-family:inherit;font-size:10pt;">•</font></div></td><td style="vertical-align:top;" rowspan="1" colspan="1"><div style="line-height:120%;text-align:left;font-size:11pt;"><font style="font-family:inherit;font-size:11pt;">Continuation of an allowed retail ROE range of </font><font style="font-family:inherit;font-size:11pt;color:#000000;text-decoration:none;">10.25%</font><font style="font-family:inherit;font-size:11pt;"> to </font><font style="font-family:inherit;font-size:11pt;color:#000000;text-decoration:none;">12.25%</font><font style="font-family:inherit;font-size:11pt;">.</font></div></td></tr></table><table cellpadding="0" cellspacing="0" style="font-family:Times New Roman; font-size:10pt;"><tr><td style="width:48px;" rowspan="1" colspan="1"></td><td rowspan="1" colspan="1"></td></tr><tr><td style="vertical-align:top" rowspan="1" colspan="1"><div style="line-height:120%;font-size:11pt;padding-left:24px;"><font style="font-family:inherit;font-size:10pt;">•</font></div></td><td style="vertical-align:top;" rowspan="1" colspan="1"><div style="line-height:120%;text-align:left;font-size:11pt;"><font style="font-family:inherit;font-size:11pt;">Continuation of the process whereby two-thirds of any earnings above the top of the allowed ROE range will be shared with Georgia Power's customers and the remaining one-third will be retained by Georgia Power.</font></div></td></tr></table><table cellpadding="0" cellspacing="0" style="font-family:Times New Roman; font-size:10pt;"><tr><td style="width:48px;" rowspan="1" colspan="1"></td><td rowspan="1" colspan="1"></td></tr><tr><td style="vertical-align:top" rowspan="1" colspan="1"><div style="line-height:120%;font-size:11pt;padding-left:24px;"><font style="font-family:inherit;font-size:10pt;">•</font></div></td><td style="vertical-align:top;" rowspan="1" colspan="1"><div style="line-height:120%;text-align:left;font-size:11pt;"><font style="font-family:inherit;font-size:11pt;">Continuation of the option to file an Interim Cost Recovery tariff in the event earnings are projected to fall below the bottom of the ROE range during the </font><font style="font-family:inherit;font-size:11pt;color:#000000;text-decoration:none;">three</font><font style="font-family:inherit;font-size:11pt;">-year term of the plan.</font></div></td></tr></table><div style="line-height:120%;padding-bottom:6px;padding-top:6px;text-align:left;font-size:11pt;"><font style="font-family:inherit;font-size:11pt;">The Georgia PSC is scheduled to issue a final order in this matter during December 2013. The ultimate outcome of this matter cannot be determined at this time.</font></div><div style="line-height:120%;padding-top:12px;font-size:11pt;"><font style="font-family:inherit;font-size:11pt;font-style:italic;">Integrated Resource Plans</font></div><div style="line-height:120%;padding-top:8px;font-size:11pt;"><font style="font-family:inherit;font-size:11pt;">See Note 3 to the financial statements of Southern Company under "Retail Regulatory Matters – Georgia Power – Integrated Resource Plans" and "Retail Regulatory Matters – Georgia Power – Rate Plans" and Georgia Power under "Retail Regulatory Matters – Integrated Resource Plans" and "Retail Regulatory Matters – Rate Plans" in Item 8 of the Form 10-K for additional information.</font></div><div style="line-height:120%;padding-top:8px;text-align:left;font-size:11pt;"><font style="font-family:inherit;font-size:11pt;">On April 17, 2013, the Georgia PSC approved the decertification of Plant Bowen Unit 6 (</font><font style="font-family:inherit;font-size:11pt;color:#000000;text-decoration:none;">32</font><font style="font-family:inherit;font-size:11pt;"> MWs), which was retired on April 25, 2013.</font></div><div style="line-height:120%;padding-top:8px;text-align:left;font-size:11pt;"><font style="font-family:inherit;font-size:11pt;">On July 11, 2013, the Georgia PSC approved Georgia Power's request to decertify and retire Plant Boulevard Units 2 and 3 (</font><font style="font-family:inherit;font-size:11pt;color:#000000;text-decoration:none;">28</font><font style="font-family:inherit;font-size:11pt;"> MWs) effective July 17, 2013. Plant Branch Units 3 and 4 (</font><font style="font-family:inherit;font-size:11pt;color:#000000;text-decoration:none;">1,016</font><font style="font-family:inherit;font-size:11pt;"> MWs), Plant Yates Units 1 through 5 (</font><font style="font-family:inherit;font-size:11pt;color:#000000;text-decoration:none;">579</font><font style="font-family:inherit;font-size:11pt;"> MWs), and Plant McManus Units 1 and 2 (</font><font style="font-family:inherit;font-size:11pt;color:#000000;text-decoration:none;">122</font><font style="font-family:inherit;font-size:11pt;"> MWs) will be decertified and retired by April 16, 2015, the compliance date of the MATS rule. The decertification date of Plant Branch Unit 1 was extended from December 31, 2013 as specified in the final order in the 2011 IRP to coincide with the decertification date of Plant Branch Units 3 and 4. The decertification and retirement of Plant Kraft Units 1 through 4 (</font><font style="font-family:inherit;font-size:11pt;color:#000000;text-decoration:none;">316</font><font style="font-family:inherit;font-size:11pt;"> MWs) was also approved and will be effective by April 16, 2016, assuming a </font><font style="font-family:inherit;font-size:11pt;color:#000000;text-decoration:none;">one</font><font style="font-family:inherit;font-size:11pt;">-year extension of the MATS rule compliance date is approved by the State of Georgia Environmental Protection Division to allow for necessary transmission system reliability improvements.</font></div><div style="line-height:120%;padding-top:8px;text-align:left;font-size:11pt;"><font style="font-family:inherit;font-size:11pt;">Additionally, the Georgia PSC approved Georgia Power's proposed MATS rule compliance plan for emissions controls necessary for the continued operation of Plants Bowen Units 1 through 4, Wansley Units 1 and 2, Scherer Units 1 through 3, and Hammond Units 1 through 4, the switch to natural gas as the primary fuel at Plants Yates Units 6 and 7 and SEGCO's Plant Gaston Units 1 through 4, as well as the fuel switch at Plant McIntosh Unit 1 to operate on Powder River Basin coal. See Note 1 to the financial statements of Georgia Power under "Affiliate Transactions" in Item 8 of the Form 10-K for additional information regarding the conversion of SEGCO's generating units.</font></div><div style="line-height:120%;padding-top:8px;text-align:left;font-size:11pt;"><font style="font-family:inherit;font-size:11pt;">The Georgia PSC also deferred decisions regarding the appropriate recovery periods for the net book values of Plant Branch Units 3 and 4 and Plant Boulevard Units 2 and 3, deferred environmental construction work in progress for Plant Branch Units 3 and 4 and Plant Yates Units 6 and 7, costs associated with unusable material and supplies, and any over or under recovered cost of removal balances remaining at the unit retirement dates for each retirement unit until the 2013 Rate Case. The Georgia PSC also deferred decisions regarding the recovery of any fuel related costs that could be incurred in connection with the retirement units to be addressed in future fuel cases.</font></div><div style="line-height:120%;padding-top:8px;text-align:left;font-size:11pt;"><font style="font-family:inherit;font-size:11pt;">The Georgia PSC also approved an additional </font><font style="font-family:inherit;font-size:11pt;color:#000000;text-decoration:none;">525</font><font style="font-family:inherit;font-size:11pt;"> MWs of solar generation to be purchased by Georgia Power. The </font><font style="font-family:inherit;font-size:11pt;color:#000000;text-decoration:none;">525</font><font style="font-family:inherit;font-size:11pt;"> MWs will be subdivided into </font><font style="font-family:inherit;font-size:11pt;color:#000000;text-decoration:none;">425</font><font style="font-family:inherit;font-size:11pt;"> MWs of utility scale projects and </font><font style="font-family:inherit;font-size:11pt;color:#000000;text-decoration:none;">100</font><font style="font-family:inherit;font-size:11pt;"> MWs of distributed generation. The </font><font style="font-family:inherit;font-size:11pt;color:#000000;text-decoration:none;">425</font><font style="font-family:inherit;font-size:11pt;"> MWs of the utility scale projects will be purchased through a competitive request for proposal process which will be open to all qualified market participants, including Georgia Power and its affiliates. The purchases resulting from both programs will be for energy only and recovered through Georgia Power's fuel cost recovery mechanism.</font></div><div style="line-height:120%;padding-top:8px;text-align:left;font-size:11pt;"><font style="font-family:inherit;font-size:11pt;">The decertification of these units, fuel conversions, and procurement of additional solar generation are not expected to have a material impact on Southern Company's or Georgia Power's financial statements; however, the ultimate outcome depends on the Georgia PSC's order in the 2013 Rate Case and future fuel cases and cannot be determined at this time.</font></div><div style="line-height:120%;padding-top:8px;font-size:11pt;"><font style="font-family:inherit;font-size:11pt;">On April 22, 2013, Georgia Power executed </font><font style="font-family:inherit;font-size:11pt;color:#000000;text-decoration:none;">two</font><font style="font-family:inherit;font-size:11pt;"> PPAs to purchase energy from </font><font style="font-family:inherit;font-size:11pt;color:#000000;text-decoration:none;">two</font><font style="font-family:inherit;font-size:11pt;"> wind farms in Oklahoma with capacity totaling </font><font style="font-family:inherit;font-size:11pt;color:#000000;text-decoration:none;">250</font><font style="font-family:inherit;font-size:11pt;"> MWs that will commence in 2016 and end in 2035. On April 29, 2013 and May 13, 2013, Georgia Power executed </font><font style="font-family:inherit;font-size:11pt;color:#000000;text-decoration:none;">two</font><font style="font-family:inherit;font-size:11pt;"> PPAs to purchase </font><font style="font-family:inherit;font-size:11pt;color:#000000;text-decoration:none;">50</font><font style="font-family:inherit;font-size:11pt;"> MWs and </font><font style="font-family:inherit;font-size:11pt;color:#000000;text-decoration:none;">56</font><font style="font-family:inherit;font-size:11pt;"> MWs, respectively, of biomass capacity and energy from </font><font style="font-family:inherit;font-size:11pt;color:#000000;text-decoration:none;">two</font><font style="font-family:inherit;font-size:11pt;"> facilities that will commence in 2015 and end in 2035. On May 21, 2013, the Georgia PSC approved the biomass capacity and energy PPAs. These </font><font style="font-family:inherit;font-size:11pt;color:#000000;text-decoration:none;">four</font><font style="font-family:inherit;font-size:11pt;"> PPAs result in additional contractual obligations of approximately </font><font style="font-family:inherit;font-size:11pt;color:#000000;text-decoration:none;">$13 million</font><font style="font-family:inherit;font-size:11pt;"> in 2015, </font><font style="font-family:inherit;font-size:11pt;color:#000000;text-decoration:none;">$47 million</font><font style="font-family:inherit;font-size:11pt;"> in 2016, </font><font style="font-family:inherit;font-size:11pt;color:#000000;text-decoration:none;">$49 million</font><font style="font-family:inherit;font-size:11pt;"> in 2017, and </font><font style="font-family:inherit;font-size:11pt;color:#000000;text-decoration:none;">$1.29 billion</font><font style="font-family:inherit;font-size:11pt;"> thereafter.</font></div><div style="line-height:120%;padding-top:12px;font-size:11pt;"><font style="font-family:inherit;font-size:11pt;font-style:italic;">Nuclear Construction</font></div><div style="line-height:120%;padding-top:8px;font-size:11pt;"><font style="font-family:inherit;font-size:11pt;">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, the eighth Vogtle Construction Monitoring (VCM) report, and pending litigation.</font></div><div style="line-height:120%;padding-top:8px;text-align:left;font-size:11pt;"><font style="font-family:inherit;font-size:11pt;">In 2008, Georgia Power, acting for itself and as agent for the 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. Under the terms of the Vogtle 3 and 4 Agreement, the 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. Each 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 </font><font style="font-family:inherit;font-size:11pt;color:#000000;text-decoration:none;">45.7%</font><font style="font-family:inherit;font-size:11pt;">. The Vogtle 3 and 4 Agreement provides for liquidated damages upon the Contractor's failure to fulfill the schedule and performance guarantees. The Contractor's liability to the Owners for schedule and performance liquidated damages and warranty claims is subject to a cap.</font></div><div style="line-height:120%;padding-top:8px;text-align:left;font-size:11pt;"><font style="font-family:inherit;font-size:11pt;">Certain payment obligations of Westinghouse and Stone & Webster, Inc. under the Vogtle 3 and 4 Agreement are guaranteed by Toshiba Corporation and The Shaw Group, Inc., respectively. In the event of certain credit rating downgrades of any Owner, such Owner will be required to provide a letter of credit or other credit enhancement. The Owners may terminate the Vogtle 3 and 4 Agreement at any time for their convenience, provided that the Owners will be required to pay certain termination costs. The Contractor may terminate the Vogtle 3 and 4 Agreement under certain circumstances, including certain Owner suspension or delays of work, action by a governmental authority to permanently stop work, certain breaches of the Vogtle 3 and 4 Agreement by the Owners, Owner insolvency, and certain other events.</font></div><div style="line-height:120%;padding-top:8px;text-align:left;font-size:11pt;"><font style="font-family:inherit;font-size:11pt;">In 2009, the Georgia PSC approved inclusion of the Plant Vogtle Units 3 and 4 related CWIP accounts in rate base, and the State of Georgia enacted the Georgia Nuclear Energy Financing Act, which allows Georgia Power to recover financing costs for nuclear construction projects certified by the Georgia PSC. Financing costs are recovered on all applicable certified costs through annual adjustments to an NCCR tariff by including the related CWIP accounts in rate base during the construction period. The Georgia PSC approved increases to the NCCR tariff of approximately </font><font style="font-family:inherit;font-size:11pt;color:#000000;text-decoration:none;">$223 million</font><font style="font-family:inherit;font-size:11pt;">, </font><font style="font-family:inherit;font-size:11pt;color:#000000;text-decoration:none;">$35 million</font><font style="font-family:inherit;font-size:11pt;">, and </font><font style="font-family:inherit;font-size:11pt;color:#000000;text-decoration:none;">$50 million</font><font style="font-family:inherit;font-size:11pt;">, effective January 1, 2011, 2012, and 2013, respectively. Through the NCCR tariff, Georgia Power is collecting and amortizing to earnings approximately </font><font style="font-family:inherit;font-size:11pt;color:#000000;text-decoration:none;">$91 million</font><font style="font-family:inherit;font-size:11pt;"> of financing costs, capitalized in 2009 and 2010, over the </font><font style="font-family:inherit;font-size:11pt;color:#000000;text-decoration:none;">five</font><font style="font-family:inherit;font-size:11pt;">-year period ending December 31, 2015, in addition to the ongoing financing costs. At June 30, 2013, approximately </font><font style="font-family:inherit;font-size:11pt;color:#000000;text-decoration:none;">$46 million</font><font style="font-family:inherit;font-size:11pt;"> of these 2009 and 2010 costs remained unamortized in CWIP.</font></div><div style="line-height:120%;padding-top:8px;text-align:left;font-size:11pt;"><font style="font-family:inherit;font-size:11pt;">In 2009, the NRC issued an Early Site Permit and Limited Work Authorization which allowed limited work to begin on Plant Vogtle Units 3 and 4. The NRC certified the Westinghouse Design Control Document, as amended (DCD), for the AP1000 nuclear reactor design, effective December 30, 2011, and issued combined construction and operating licenses (COLs) in February 2012. Receipt of the COLs allowed full construction to begin.</font></div><div style="line-height:120%;padding-bottom:12px;padding-top:8px;text-align:left;font-size:11pt;"><font style="font-family:inherit;font-size:11pt;">In February 2012, separate groups of petitioners filed petitions in the U.S. Court of Appeals for the District of Columbia Circuit seeking judicial review of the NRC's issuance of the COLs and certification of the DCD. These petitions were consolidated in April 2012. Also in February 2012, one of the groups of petitioners filed a motion with the NRC to stay the effectiveness of the COLs pending the outcome of the petitions pending before the U.S. District Court for the District of Columbia Circuit. The NRC denied this motion in April 2012. On May 14, 2013, the U.S. Court of Appeals for the District of Columbia Circuit ruled in favor of the NRC, upholding the COLs and allowing for the continuation of the construction. On July 23, 2013, the U.S. Court of Appeals for the District of Columbia Circuit rejected the petitioners' request for rehearing.</font></div><div style="line-height:120%;padding-bottom:13px;padding-top:8px;text-align:left;font-size:11pt;"><font style="font-family:inherit;font-size:11pt;">Georgia Power is required to file semi-annual VCM reports with the Georgia PSC by February 28 and August 31 each year. On February 19, 2013, the Georgia PSC voted to approve Georgia Power's seventh VCM report, including construction capital costs incurred through June 30, 2012 of approximately </font><font style="font-family:inherit;font-size:11pt;color:#000000;text-decoration:none;">$2.0 billion</font><font style="font-family:inherit;font-size:11pt;">. Georgia Power's eighth VCM report requests approval for an additional </font><font style="font-family:inherit;font-size:11pt;color:#000000;text-decoration:none;">$0.2 billion</font><font style="font-family:inherit;font-size:11pt;"> of construction capital costs incurred through December 31, 2012. If the projected certified construction capital costs to be borne by Georgia Power increase by </font><font style="font-family:inherit;font-size:11pt;color:#000000;text-decoration:none;">5%</font><font style="font-family:inherit;font-size:11pt;"> 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. Accordingly, the eighth VCM report also requested an amendment to the certificate to increase the estimated in-service capital cost of Plant Vogtle Units 3 and 4 to </font><font style="font-family:inherit;font-size:11pt;color:#000000;text-decoration:none;">$4.8 billion</font><font style="font-family:inherit;font-size:11pt;"> and to extend the estimated in-service dates to the fourth quarter 2017 and the fourth quarter 2018 for Plant Vogtle Units 3 and 4, respectively. Associated financing costs during the construction period are estimated to total approximately </font><font style="font-family:Times New Roman;font-size:11pt;color:#000000;font-style:normal;font-weight:normal;text-decoration:none;">$2.0 billion</font><font style="font-family:inherit;font-size:11pt;">. The Georgia PSC is scheduled to vote on the eighth VCM report in October 2013. </font></div><div style="line-height:120%;padding-bottom:12px;text-align:left;font-size:11pt;"><font style="font-family:inherit;font-size:11pt;">On July 30, 2013, Georgia Power and the Georgia PSC staff entered into a stipulation to waive the requirement to amend the Plant Vogtle Units 3 and 4 certificate, which had been requested in the eighth VCM report, until the completion of Plant Vogtle Unit 3, or earlier if deemed appropriate by the parties. In accordance with the Georgia Integrated Resource Planning Act, any costs incurred by Georgia Power in excess of the certified amount will not be included in rate base, unless shown to be reasonable and prudent; therefore, any related financing costs during construction potentially would be subject to recovery through AFUDC. The stipulation also provides that Georgia Power will combine the ninth and tenth VCM reports scheduled to be filed by August 31, 2013 and February 28, 2014, respectively, into a single report covering the period from January 1 through December 31, 2013 to be filed by February 28, 2014. Additionally, Georgia Power will file an abbreviated status update by September 3, 2013, which will include the costs incurred from January 1 through June 30, 2013. Georgia Power expects to resume filing semi-annual VCM reports in August 2014. The stipulation is subject to approval by the Georgia PSC.</font></div><div style="line-height:120%;padding-top:8px;text-align:left;font-size:11pt;"><font style="font-family:inherit;font-size:11pt;">In July 2012, the 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 Owners are responsible for these costs under the terms of the Vogtle 3 and 4 Agreement. The Contractor has claimed that its estimated adjustment attributable to Georgia Power (based on Georgia Power's ownership interest) is approximately </font><font style="font-family:inherit;font-size:11pt;color:#000000;text-decoration:none;">$425 million</font><font style="font-family:inherit;font-size:11pt;"> (in 2008 dollars) with respect to these issues. The Contractor also has asserted it is entitled to further schedule extensions. Georgia Power has not agreed with either the proposed cost or schedule adjustments or that the Owners have any responsibility for costs related to these issues. In November 2012, Georgia Power and the other Owners filed suit against the Contractor in the U.S. District Court for the Southern District of Georgia seeking a declaratory judgment that the Owners are not responsible for these costs. Also in November 2012, the Contractor filed suit against Georgia Power and the other Owners in the U.S. District Court for the District of Columbia alleging the Owners are responsible for these costs. While litigation has commenced and Georgia Power intends to vigorously defend its positions, Georgia Power expects negotiations with the Contractor to continue with respect to cost and schedule during which negotiations the parties may reach a mutually acceptable compromise of their positions.</font></div><div style="line-height:120%;padding-top:8px;text-align:left;font-size:11pt;"><font style="font-family:inherit;font-size:11pt;">In addition, processes are in place that are designed to assure compliance with the requirements specified in the DCD and the COLs, including rigorous inspections by Southern Nuclear and the NRC that occur throughout construction. During the fourth quarter 2012, certain details of the rebar design for the Plant Vogtle Unit 3 nuclear island were evaluated for consistency with the DCD and deviations were identified. On February 26, 2013 and March 1, 2013, the NRC approved the two license amendment requests required to conform the rebar design details to NRC requirements and, on March 14, 2013, the placement of basemat structural concrete for the nuclear island of Plant Vogtle Unit 3 was completed. Additional license amendment requests have been filed and approved or are pending before the NRC. Various design and other issues are expected to arise as construction proceeds, which may result in additional license amendments or require other resolution. If any license amendment requests are not resolved in a timely manner, there may be delays in the project schedule that could result in increased costs either to the Owners, the Contractor, or both.</font></div><div style="line-height:120%;padding-top:8px;text-align:left;font-size:11pt;"><font style="font-family:inherit;font-size:11pt;">As construction continues, additional delays in the fabrication and assembly of structural modules, the failure of such modules to meet applicable standards, delays in the receipt of the remaining permits necessary for the operation of Plant Vogtle Units 3 and 4, or other issues may further impact project schedule and cost. Additional claims by the Contractor or Georgia Power (on behalf of the Owners) are also likely to arise throughout construction. These claims may be resolved through formal and informal dispute resolution procedures under the Vogtle 3 and 4 Agreement, but also may be resolved through litigation.</font></div><div style="line-height:120%;padding-top:8px;text-align:left;font-size:11pt;"><font style="font-family:inherit;font-size:11pt;">The ultimate outcome of these matters cannot be determined at this time.</font></div><div style="line-height:120%;padding-top:12px;font-size:11pt;"><font style="font-family:inherit;font-size:11pt;font-style:italic;font-weight:bold;">Gulf Power</font></div><div style="line-height:120%;padding-top:8px;font-size:11pt;"><font style="font-family:inherit;font-size:11pt;font-style:italic;">Retail Base Rate Case</font></div><div style="line-height:120%;padding-top:8px;font-size:11pt;"><font style="font-family:inherit;font-size:11pt;">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.</font></div><div style="line-height:120%;padding-top:8px;text-align:left;font-size:11pt;"><font style="font-family:inherit;font-size:11pt;">On July 12, 2013, Gulf Power filed a petition with the Florida PSC requesting an increase in retail rates to the extent necessary to generate additional gross annual revenues in the amount of </font><font style="font-family:inherit;font-size:11pt;color:#000000;text-decoration:none;">$74.4 million</font><font style="font-family:inherit;font-size:11pt;"> effective in 2014. The requested increase is expected to provide a reasonable opportunity for Gulf Power to earn a retail ROE of </font><font style="font-family:inherit;font-size:11pt;color:#000000;text-decoration:none;">11.5%</font><font style="font-family:inherit;font-size:11pt;">. The Florida PSC is expected to make a decision on this matter in the first quarter 2014.</font></div><div style="line-height:120%;padding-top:8px;text-align:left;font-size:11pt;"><font style="font-family:inherit;font-size:11pt;">Gulf Power has calculated its revenue deficiency based on the projected period January 1, 2014 through December 31, 2014 which serves as the test year. The test year provides the appropriate period of utility operations to be analyzed by the Florida PSC to be able to set reasonable rates for the period the new rates will be in effect. The period January 1, 2014 through December 31, 2014 best represents expected future operations of Gulf Power as the regional economy continues to emerge from the recession. The petition also requests that the Florida PSC approve the projected January 1, 2014 through December 31, 2014 test year and consent to new rate schedules going into operation as soon as possible.</font></div><div style="line-height:120%;padding-top:8px;text-align:left;font-size:11pt;"><font style="font-family:inherit;font-size:11pt;">Additionally, Gulf Power has requested that the Florida PSC approve a step adjustment in base rates for the costs associated with certain transmission system upgrades related to Gulf Power's compliance with the MATS rule. If the Florida PSC determines that these costs are more appropriate for recovery through base rates rather than the Environmental Cost Recovery Clause, the requested step adjustment would increase retail rates to the extent necessary to generate additional gross revenues in the amount of </font><font style="font-family:inherit;font-size:11pt;color:#000000;text-decoration:none;">$16.4 million</font><font style="font-family:inherit;font-size:11pt;">, to be effective July 1, 2015.</font></div><div style="line-height:120%;padding-top:8px;text-align:left;font-size:11pt;"><font style="font-family:inherit;font-size:11pt;">The ultimate outcome of these matters cannot be determined at this time.</font></div><div style="line-height:120%;padding-top:12px;font-size:11pt;"><font style="font-family:inherit;font-size:11pt;font-style:italic;">Cost Recovery Clauses</font></div><div style="line-height:120%;padding-top:8px;font-size:11pt;"><font style="font-family:inherit;font-size:11pt;">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.</font></div><div style="line-height:120%;padding-top:12px;font-size:11pt;"><font style="font-family:inherit;font-size:11pt;text-decoration:underline;">Fuel Cost Recovery</font></div><div style="line-height:120%;padding-top:8px;font-size:11pt;"><font style="font-family:inherit;font-size:11pt;">See Notes 1 and 3 to the financial statements of Gulf Power under "Revenues" and "Retail Regulatory Matters – Cost Recovery Clauses – Fuel Cost Recovery," respectively, in Item 8 of the Form 10-K for additional information.</font></div><div style="line-height:120%;padding-top:8px;font-size:11pt;"><font style="font-family:inherit;font-size:11pt;">Under recovered fuel costs at June 30, 2013 totaled </font><font style="font-family:inherit;font-size:11pt;color:#000000;text-decoration:none;">$16.4 million</font><font style="font-family:inherit;font-size:11pt;"> which is included in under recovered regulatory clause revenues on Gulf Power's Condensed Balance Sheet herein. The under recovered fuel cost balance is expected to be offset by approximately </font><font style="font-family:inherit;font-size:11pt;color:#000000;text-decoration:none;">$26.6 million</font><font style="font-family:inherit;font-size:11pt;"> during the third quarter 2013 as a result of a payment from one of Gulf Power's fuel vendors due to the resolution of a contract dispute. At December 31, 2012, the over recovered fuel costs totaled </font><font style="font-family:inherit;font-size:11pt;color:#000000;text-decoration:none;">$17.1 million</font><font style="font-family:inherit;font-size:11pt;">, which is included in other regulatory liabilities, current on Gulf Power's Condensed Balance Sheet herein.</font></div><div style="line-height:120%;padding-top:12px;font-size:11pt;"><font style="font-family:inherit;font-size:11pt;text-decoration:underline;">Purchased Power Capacity Recovery</font></div><div style="line-height:120%;padding-top:8px;font-size:11pt;"><font style="font-family:inherit;font-size:11pt;">See Notes 1 and 3 to the financial statements of Gulf Power under "Revenues" and "Retail Regulatory Matters – Cost Recovery Clauses – Purchased Power Capacity Recovery," respectively, in Item 8 of the Form 10-K for additional information.</font></div><div style="line-height:120%;padding-top:8px;font-size:11pt;"><font style="font-family:inherit;font-size:11pt;">At June 30, 2013, the over recovered purchased power capacity costs totaled </font><font style="font-family:inherit;font-size:11pt;color:#000000;text-decoration:none;">$1.4 million</font><font style="font-family:inherit;font-size:11pt;">, which is included in other regulatory liabilities, current on Gulf Power's Condensed Balance Sheet herein. At December 31, 2012, the under recovered purchased power capacity costs totaled </font><font style="font-family:inherit;font-size:11pt;color:#000000;text-decoration:none;">$0.8 million</font><font style="font-family:inherit;font-size:11pt;">, which is included in under recovered regulatory clause revenues on Gulf Power's Condensed Balance Sheet herein.</font></div><div style="line-height:120%;padding-top:12px;font-size:11pt;"><font style="font-family:inherit;font-size:11pt;text-decoration:underline;">Environmental Cost Recovery</font></div><div style="line-height:120%;padding-top:8px;font-size:11pt;"><font style="font-family:inherit;font-size:11pt;">See Note 3 to the financial statements of Gulf Power under "Retail Regulatory Matters – Cost Recovery Clauses – Environmental Cost Recovery" in Item 8 of the Form 10-K for additional information.</font></div><div style="line-height:120%;padding-top:8px;font-size:11pt;"><font style="font-family:inherit;font-size:11pt;">Under recovered environmental costs at June 30, 2013 totaled </font><font style="font-family:inherit;font-size:11pt;color:#000000;text-decoration:none;">$11.5 million</font><font style="font-family:inherit;font-size:11pt;"> compared to </font><font style="font-family:inherit;font-size:11pt;color:#000000;text-decoration:none;">$1.9 million</font><font style="font-family:inherit;font-size:11pt;"> at December 31, 2012. These amounts are included in under recovered regulatory clause revenues on Gulf Power's Condensed Balance Sheets herein.</font></div><div style="line-height:120%;padding-top:12px;font-size:11pt;"><font style="font-family:inherit;font-size:11pt;text-decoration:underline;">Energy Conservation Cost Recovery</font></div><div style="line-height:120%;padding-top:8px;font-size:11pt;"><font style="font-family:inherit;font-size:11pt;">See Note 3 to the financial statements of Gulf Power under "Retail Regulatory Matters – Cost Recovery Clauses – Energy Conservation Cost Recovery" in Item 8 of the Form 10-K for additional information.</font></div><div style="line-height:120%;padding-top:8px;font-size:11pt;"><font style="font-family:inherit;font-size:11pt;">Under recovered energy conservation costs at June 30, 2013 totaled </font><font style="font-family:inherit;font-size:11pt;color:#000000;text-decoration:none;">$5.1 million</font><font style="font-family:inherit;font-size:11pt;"> compared to </font><font style="font-family:inherit;font-size:11pt;color:#000000;text-decoration:none;">$0.8 million</font><font style="font-family:inherit;font-size:11pt;"> at December 31, 2012. These amounts are included in under recovered regulatory clause revenues on Gulf Power's Condensed Balance Sheets herein.</font></div><div style="line-height:120%;padding-top:12px;font-size:11pt;"><font style="font-family:inherit;font-size:11pt;font-style:italic;font-weight:bold;">Mississippi Power</font></div><div style="line-height:120%;padding-top:12px;text-align:left;font-size:11pt;"><font style="font-family:inherit;font-size:11pt;font-style:italic;">Energy Efficiency</font></div><div style="line-height:120%;padding-top:12px;text-align:left;font-size:11pt;"><font style="font-family:inherit;font-size:11pt;">On July 11, 2013, the Mississippi PSC approved an energy efficiency and conservation rule requiring electric and gas utilities in Mississippi serving more than </font><font style="font-family:inherit;font-size:11pt;color:#000000;text-decoration:none;">25,000</font><font style="font-family:inherit;font-size:11pt;"> customers to implement energy efficiency programs and standards. Quick Start Plans, which include a portfolio of energy efficiency programs that are intended to provide benefits to a majority of customers, are required to be filed within </font><font style="font-family:inherit;font-size:11pt;color:#000000;text-decoration:none;">six months</font><font style="font-family:inherit;font-size:11pt;"> of the order and will be in effect for </font><font style="font-family:inherit;font-size:11pt;color:#000000;text-decoration:none;">two</font><font style="font-family:inherit;font-size:11pt;"> to </font><font style="font-family:inherit;font-size:11pt;color:#000000;text-decoration:none;">three years</font><font style="font-family:inherit;font-size:11pt;">. An annual report addressing the performance of all energy efficiency programs will be required to be filed. Mississippi Power does not currently anticipate that additional annual costs to comply with the rule will be material. The ultimate outcome of this matter cannot be determined at this time.</font></div><div style="line-height:120%;padding-top:8px;font-size:11pt;"><font style="font-family:inherit;font-size:11pt;font-style:italic;">Performance Evaluation Plan</font></div><div style="line-height:120%;padding-top:8px;font-size:11pt;"><font style="font-family:inherit;font-size:11pt;">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/A for additional information regarding Mississippi Power's base rates.</font></div><div style="line-height:120%;padding-top:8px;text-align:left;font-size:11pt;"><font style="font-family:inherit;font-size:11pt;">On January 18, 2013, Mississippi Power filed its annual PEP filing for 2013, which indicated a rate increase of </font><font style="font-family:inherit;font-size:11pt;color:#000000;text-decoration:none;">1.990%</font><font style="font-family:inherit;font-size:11pt;">, or </font><font style="font-family:inherit;font-size:11pt;color:#000000;text-decoration:none;">$15.8 million</font><font style="font-family:inherit;font-size:11pt;">, annually. On March 4, 2013, Mississippi Power and the Mississippi Public Utilities Staff (MPUS) filed a joint stipulation which revised the annual PEP filing for 2013 to reflect the removal of certain costs related to unresolved matters that are currently under review. On March 5, 2013, the revised annual PEP filing for 2013 was approved by the Mississippi PSC, which resulted in a rate increase of </font><font style="font-family:inherit;font-size:11pt;color:#000000;text-decoration:none;">1.925%</font><font style="font-family:inherit;font-size:11pt;">, or </font><font style="font-family:inherit;font-size:11pt;color:#000000;text-decoration:none;">$15.3 million</font><font style="font-family:inherit;font-size:11pt;">, annually, with the new rates effective March 19, 2013. Mississippi Power may be entitled to </font><font style="font-family:inherit;font-size:11pt;color:#000000;text-decoration:none;">$3.3 million</font><font style="font-family:inherit;font-size:11pt;"> in additional revenues in 2013 as a result of the late implementation of the 2013 PEP rate increase.</font></div><div style="line-height:120%;padding-top:8px;text-align:left;font-size:11pt;"><font style="font-family:inherit;font-size:11pt;">On March 15, 2013, Mississippi Power submitted its annual PEP lookback filing for 2012, which indicated a refund due to customers of </font><font style="font-family:inherit;font-size:11pt;color:#000000;text-decoration:none;">$4.7 million</font><font style="font-family:inherit;font-size:11pt;">, which was accrued in retail revenues. On May 1, 2013, the MPUS contested the filing.</font></div><div style="line-height:120%;padding-top:8px;text-align:left;font-size:11pt;"><font style="font-family:inherit;font-size:11pt;">The ultimate outcome of these matters cannot be determined at this time.</font></div><div style="line-height:120%;padding-top:12px;text-align:left;font-size:11pt;"><font style="font-family:inherit;font-size:11pt;font-style:italic;">System Restoration Rider</font></div><div style="line-height:120%;padding-top:8px;text-align:left;font-size:11pt;"><font style="font-family:inherit;font-size:11pt;">See Note 3 to the financial statements of Mississippi Power under "Retail Regulatory Matters – System Restoration Rider" in Item 8 of the Form 10-K/A for additional information.</font></div><div style="line-height:120%;padding-top:8px;text-align:left;font-size:11pt;"><font style="font-family:inherit;font-size:11pt;">On June 4, 2013, the Mississippi PSC approved Mississippi Power's request to continue a zero System Restoration Rider rate for 2013 and to accrue approximately </font><font style="font-family:inherit;font-size:11pt;color:#000000;text-decoration:none;">$3.2 million</font><font style="font-family:inherit;font-size:11pt;"> to the property damage reserve in 2013.</font></div><div style="line-height:120%;padding-top:12px;text-align:left;font-size:11pt;"><font style="font-family:inherit;font-size:11pt;font-style:italic;">Environmental Compliance Overview Plan</font></div><div style="line-height:120%;padding-top:8px;font-size:11pt;"><font style="font-family:inherit;font-size:11pt;">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/A for information on Mississippi Power's annual environmental filing with the Mississippi PSC.</font></div><div style="line-height:120%;padding-top:8px;font-size:11pt;"><font style="font-family:inherit;font-size:11pt;">In April 2012, the Mississippi PSC approved Mississippi Power's request for a CPCN to construct a flue gas desulfurization system (scrubber) on Plant Daniel Units 1 and 2. In May 2012, the Sierra Club filed a notice of appeal of the order with the Chancery Court of Harrison County, Mississippi (Chancery Court). These units are jointly owned by Mississippi Power and Gulf Power, with </font><font style="font-family:inherit;font-size:11pt;color:#000000;text-decoration:none;">50%</font><font style="font-family:inherit;font-size:11pt;"> ownership each. The estimated total cost of the project is approximately </font><font style="font-family:inherit;font-size:11pt;color:#000000;text-decoration:none;">$660 million</font><font style="font-family:inherit;font-size:11pt;">, with Mississippi Power's portion being </font><font style="font-family:inherit;font-size:11pt;color:#000000;text-decoration:none;">$330 million</font><font style="font-family:inherit;font-size:11pt;">, excluding AFUDC. The project is scheduled for completion in December 2015. 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 June 30, 2013, total project expenditures were </font><font style="font-family:inherit;font-size:11pt;color:#000000;text-decoration:none;">$232.9 million</font><font style="font-family:inherit;font-size:11pt;">, with Mississippi Power's portion being </font><font style="font-family:inherit;font-size:11pt;color:#000000;text-decoration:none;">$116.4 million</font><font style="font-family:inherit;font-size:11pt;">. The ultimate outcome of this matter cannot be determined at this time.</font></div><div style="line-height:120%;padding-top:12px;font-size:11pt;"><font style="font-family:inherit;font-size:11pt;font-style:italic;">Fuel Cost Recovery</font></div><div style="line-height:120%;padding-top:8px;font-size:11pt;"><font style="font-family:inherit;font-size:11pt;">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/A for information regarding Mississippi Power's fuel cost recovery.</font></div><div style="line-height:120%;padding-top:8px;text-align:left;font-size:11pt;"><font style="font-family:inherit;font-size:11pt;">On January 18, 2013, in compliance with Mississippi Power's filing requirement, Mississippi Power requested an annual adjustment of the retail fuel cost recovery factor in an amount equal to a decrease of </font><font style="font-family:inherit;font-size:11pt;color:#000000;text-decoration:none;">4.7%</font><font style="font-family:inherit;font-size:11pt;">, or </font><font style="font-family:inherit;font-size:11pt;color:#000000;text-decoration:none;">$35.5 million</font><font style="font-family:inherit;font-size:11pt;">, of total 2012 retail revenue. The Mississippi PSC approved the retail fuel cost recovery factor on March 5, 2013, with the new rates effective March 19, 2013.</font></div><div style="line-height:120%;padding-top:8px;font-size:11pt;"><font style="font-family:inherit;font-size:11pt;">At June 30, 2013, the amount of over recovered retail fuel costs included on Mississippi Power's Condensed Balance Sheets herein was </font><font style="font-family:inherit;font-size:11pt;color:#000000;text-decoration:none;">$38.0 million</font><font style="font-family:inherit;font-size:11pt;"> compared to </font><font style="font-family:inherit;font-size:11pt;color:#000000;text-decoration:none;">$56.6 million</font><font style="font-family:inherit;font-size:11pt;"> at December 31, 2012. Mississippi Power also has wholesale MRA and Market Based (MB) fuel cost recovery factors. At June 30, 2013, the amount of over recovered wholesale MRA and MB fuel costs included on Mississippi Power's Condensed Balance Sheets herein was </font><font style="font-family:inherit;font-size:11pt;color:#000000;text-decoration:none;">$11.9 million</font><font style="font-family:inherit;font-size:11pt;"> and </font><font style="font-family:inherit;font-size:11pt;color:#000000;text-decoration:none;">$0.9 million</font><font style="font-family:inherit;font-size:11pt;">, respectively, compared to </font><font style="font-family:inherit;font-size:11pt;color:#000000;text-decoration:none;">$19.0 million</font><font style="font-family:inherit;font-size:11pt;"> and </font><font style="font-family:inherit;font-size:11pt;color:#000000;text-decoration:none;">$2.1 million</font><font style="font-family:inherit;font-size:11pt;">, respectively, at December 31, 2012. In addition, at June 30, 2013, the amount of under recovered MRA emissions allowance cost included on Mississippi Power's Condensed Balance Sheets herein was </font><font style="font-family:inherit;font-size:11pt;color:#000000;text-decoration:none;">$1.4 million</font><font style="font-family:inherit;font-size:11pt;"> compared to </font><font style="font-family:inherit;font-size:11pt;color:#000000;text-decoration:none;">$0.4 million</font><font style="font-family:inherit;font-size:11pt;"> at December 31, 2012. Mississippi Power's operating revenues are adjusted for differences in actual recoverable fuel cost and amounts billed in accordance with the currently approved cost recovery rate. Accordingly, changes in the billing factor have no significant effect on Mississippi Power's revenues or net income, but will affect cash flow.</font></div><div style="line-height:120%;padding-top:8px;text-align:left;font-size:11pt;"><font style="font-family:inherit;font-size:11pt;font-style:italic;">Ad Valorem Tax Adjustment</font></div><div style="line-height:120%;padding-top:8px;text-align:left;font-size:11pt;"><font style="font-family:inherit;font-size:11pt;">On March 27, 2013, Mississippi Power filed its annual ad valorem tax adjustment factor filing for 2013, which requested an annual rate increase of </font><font style="font-family:inherit;font-size:11pt;color:#000000;text-decoration:none;">0.9%</font><font style="font-family:inherit;font-size:11pt;">, or </font><font style="font-family:inherit;font-size:11pt;color:#000000;text-decoration:none;">$7.1 million</font><font style="font-family:inherit;font-size:11pt;">, due to an increase in ad valorem taxes resulting from the expiration of a tax exemption related to Plant Daniel Units 3 and 4. On June 4, 2013, the filing was approved by the Mississippi PSC.</font></div><div style="line-height:120%;padding-top:12px;text-align:left;padding-left:2px;font-size:11pt;"><font style="font-family:inherit;font-size:11pt;font-style:italic;">Storm Damage Cost Recovery</font></div><div style="line-height:120%;padding-top:8px;text-align:left;padding-left:2px;font-size:11pt;"><font style="font-family:inherit;font-size:11pt;">See Note 3 to the financial statements of Mississippi Power under "Retail Regulatory Matters – Storm Damage Cost Recovery" in Item 8 in the Form 10-K/A for information regarding Mississippi Power's storm damage cost recovery. Mississippi Power maintains a reserve to cover the cost of damage from major storms to its transmission and distribution facilities and generally the cost of uninsured damage to its generation facilities and other property. At June 30, 2013, the balance in the storm reserve was </font><font style="font-family:inherit;font-size:11pt;color:#000000;text-decoration:none;">$58.5 million</font><font style="font-family:inherit;font-size:11pt;">.</font></div><div style="line-height:120%;padding-top:12px;text-align:left;padding-left:2px;font-size:11pt;"><font style="font-family:inherit;font-size:11pt;font-weight:bold;">Integrated Coal Gasification Combined Cycle</font></div><div style="line-height:120%;padding-top:8px;text-align:left;font-size:11pt;"><font style="font-family:inherit;font-size:11pt;">See Note 3 to the financial statements of Southern Company under "Integrated Coal Gasification Combined Cycle" in Item 8 of the Form 10-K and Note 3 to the financial statements of Mississippi Power under "Integrated Coal Gasification Combined Cycle" in Item 8 of the Form 10-K/A for information regarding Mississippi Power's construction of the Kemper IGCC.</font></div><div style="line-height:120%;padding-top:12px;text-align:left;font-size:11pt;"><font style="font-family:inherit;font-size:11pt;font-style:italic;">Kemper IGCC Project Approval</font></div><div style="line-height:120%;padding-top:8px;text-align:left;font-size:11pt;"><font style="font-family:inherit;font-size:11pt;">In 2010, the Mississippi PSC issued a CPCN authorizing the acquisition, construction, and operation of the Kemper IGCC (2010 MPSC Order) located in Kemper County, Mississippi. The Sierra Club filed an appeal of the Mississippi PSC's issuance of the CPCN and, in March 2012, the Mississippi Supreme Court reversed the decision of the Chancery Court upholding the 2010 MPSC Order and remanded the matter to the Mississippi PSC. The Mississippi Supreme Court concluded that the 2010 MPSC Order did not cite in sufficient detail substantial evidence upon which the Mississippi Supreme Court could determine the basis for the findings of the Mississippi PSC granting the CPCN. In April 2012, the Mississippi PSC issued a detailed order (2012 MPSC Order) confirming the CPCN for the Kemper IGCC, which the Sierra Club appealed to the Chancery Court. In December 2012, the Chancery Court affirmed the 2012 MPSC Order which confirmed the issuance of the CPCN for the Kemper IGCC. On January 8, 2013, the Sierra Club filed an appeal of the Chancery Court's ruling with the Mississippi Supreme Court. The ultimate outcome of the CPCN challenge cannot be determined at this time.</font></div><div style="line-height:120%;padding-top:8px;text-align:left;font-size:11pt;"><font style="font-family:inherit;font-size:11pt;">The Kemper IGCC is currently under construction and will utilize an integrated coal gasification combined cycle technology with an output capacity of </font><font style="font-family:inherit;font-size:11pt;color:#000000;text-decoration:none;">582</font><font style="font-family:inherit;font-size:11pt;"> 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 operations on June 5, 2013. In connection with the Kemper IGCC, Mississippi Power also is constructing and plans to operate approximately </font><font style="font-family:inherit;font-size:11pt;color:#000000;text-decoration:none;">61</font><font style="font-family:inherit;font-size:11pt;"> miles of CO</font><font style="font-family:inherit;font-size:11pt;"><sub style="vertical-align:bottom;line-height:120%;font-size:7pt">2</sub></font><font style="font-family:inherit;font-size:11pt;"> pipeline infrastructure. The Kemper IGCC and the CO</font><font style="font-family:inherit;font-size:11pt;"><sub style="vertical-align:bottom;line-height:120%;font-size:7pt">2</sub></font><font style="font-family:inherit;font-size:11pt;"> pipeline are scheduled to be placed in service in May 2014. See Note 3 to the financial statements of Southern Company under "Integrated Coal Gasification Combined Cycle – Lignite Mine and CO</font><font style="font-family:inherit;font-size:11pt;"><sub style="vertical-align:bottom;line-height:120%;font-size:7pt">2</sub></font><font style="font-family:inherit;font-size:11pt;"> Pipeline Facilities" in Item 8 of the Form 10-K and Note 3 to the financial statements of Mississippi Power under "Integrated Coal Gasification Combined Cycle – Lignite Mine and CO</font><font style="font-family:inherit;font-size:11pt;"><sub style="vertical-align:bottom;line-height:120%;font-size:7pt">2</sub></font><font style="font-family:inherit;font-size:11pt;"> Pipeline Facilities" in Item 8 of the Form 10-K/A for additional information regarding the lignite mine and the CO</font><font style="font-family:inherit;font-size:11pt;"><sub style="vertical-align:bottom;line-height:120%;font-size:7pt">2</sub></font><font style="font-family:inherit;font-size:11pt;"> pipeline.</font></div><div style="line-height:120%;padding-top:6px;text-align:left;font-size:11pt;"><font style="font-family:inherit;font-size:11pt;font-style:italic;">Kemper IGCC Cost Estimate</font></div><div style="line-height:120%;padding-top:8px;text-align:left;font-size:11pt;"><font style="font-family:inherit;font-size:11pt;">The certificated cost estimate of the Kemper IGCC included in the 2012 MPSC Order was </font><font style="font-family:inherit;font-size:11pt;color:#000000;text-decoration:none;">$2.4 billion</font><font style="font-family:inherit;font-size:11pt;">, net of </font><font style="font-family:inherit;font-size:11pt;color:#000000;text-decoration:none;">$245 million</font><font style="font-family:inherit;font-size:11pt;"> of grants awarded to the project by the DOE under the Clean Coal Power Initiative Round 2 (DOE Grants), the cost of the lignite mine and equipment, the cost of the CO</font><font style="font-family:inherit;font-size:11pt;"><sub style="vertical-align:bottom;line-height:120%;font-size:7pt">2</sub></font><font style="font-family:inherit;font-size:11pt;"> pipeline facilities, and AFUDC related to the Kemper IGCC. The 2012 MPSC Order approved a construction cost cap of up to </font><font style="font-family:inherit;font-size:11pt;color:#000000;text-decoration:none;">$2.88 billion</font><font style="font-family:inherit;font-size:11pt;">, with recovery of prudently-incurred costs subject to approval by the Mississippi PSC. Exceptions to the </font><font style="font-family:inherit;font-size:11pt;color:#000000;text-decoration:none;">$2.88 billion</font><font style="font-family:inherit;font-size:11pt;"> cost cap include the cost of the lignite mine and equipment, the cost of the CO</font><font style="font-family:inherit;font-size:11pt;"><sub style="vertical-align:bottom;line-height:120%;font-size:7pt">2</sub></font><font style="font-family:inherit;font-size:11pt;"> pipeline facilities, AFUDC, and certain general exceptions as contemplated in the Settlement Agreement (described below) and the 2012 MPSC Order, which includes the cost of the lignite mine and equipment, the cost of the CO</font><font style="font-family:inherit;font-size:11pt;"><sub style="vertical-align:bottom;line-height:120%;font-size:7pt">2</sub></font><font style="font-family:inherit;font-size:11pt;"> 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). Recovery of the Cost Cap Exception amounts remains subject to review and approval by the Mississippi PSC.</font></div><div style="line-height:120%;padding-top:8px;text-align:left;font-size:11pt;"><font style="font-family:inherit;font-size:11pt;"><br clear="none"/></font></div><div style="line-height:120%;padding-top:8px;text-align:left;font-size:11pt;"><font style="font-family:inherit;font-size:11pt;">On July 29, 2013, Mississippi Power further revised its cost estimate for the Kemper IGCC to approximately </font><font style="font-family:inherit;font-size:11pt;color:#000000;text-decoration:none;">$3.87 billion</font><font style="font-family:inherit;font-size:11pt;">, net of the DOE Grants and the Cost Cap Exceptions. Estimated amounts of the Cost Cap Exceptions include </font><font style="font-family:inherit;font-size:11pt;color:#000000;text-decoration:none;">$245 million</font><font style="font-family:inherit;font-size:11pt;"> for the lignite mine and equipment, </font><font style="font-family:inherit;font-size:11pt;color:#000000;text-decoration:none;">$115 million</font><font style="font-family:inherit;font-size:11pt;"> for the CO</font><font style="font-family:inherit;font-size:7pt;">2 </font><font style="font-family:inherit;font-size:11pt;">pipeline facilities, </font><font style="font-family:inherit;font-size:11pt;color:#000000;text-decoration:none;">$324 million</font><font style="font-family:inherit;font-size:11pt;"> of AFUDC, and </font><font style="font-family:inherit;font-size:11pt;color:#000000;text-decoration:none;">$101 million</font><font style="font-family:inherit;font-size:11pt;"> of other general exceptions. The revised cost estimate reflects additional cost pressures, including labor costs, piping and other material costs, engineering and support costs, start-up costs, and decreases in construction labor productivity. Mississippi Power does not intend to seek any joint owner contributions or rate recovery for any costs related to the construction of the Kemper IGCC that exceed the </font><font style="font-family:inherit;font-size:11pt;color:#000000;text-decoration:none;">$2.88 billion</font><font style="font-family:inherit;font-size:11pt;"> cost cap, excluding the Cost Cap Exceptions and net of the DOE Grants. As a result of the revisions to the cost estimate, Mississippi Power recorded pre-tax charges to income for estimated probable losses of </font><font style="font-family:inherit;font-size:11pt;color:#000000;text-decoration:none;">$78.0 million</font><font style="font-family:inherit;font-size:11pt;"> (</font><font style="font-family:inherit;font-size:11pt;color:#000000;text-decoration:none;">$48.2 million</font><font style="font-family:inherit;font-size:11pt;"> after tax) in 2012, </font><font style="font-family:inherit;font-size:11pt;color:#000000;text-decoration:none;">$462.0 million</font><font style="font-family:inherit;font-size:11pt;"> (</font><font style="font-family:inherit;font-size:11pt;color:#000000;text-decoration:none;">$285.3 million</font><font style="font-family:inherit;font-size:11pt;"> after tax) in the first quarter 2013, and </font><font style="font-family:inherit;font-size:11pt;color:#000000;text-decoration:none;">$450 million</font><font style="font-family:inherit;font-size:11pt;"> (</font><font style="font-family:inherit;font-size:11pt;color:#000000;text-decoration:none;">$277.9 million</font><font style="font-family:inherit;font-size:11pt;"> after tax) in the second quarter 2013. Southern Company evaluated the portion of the estimated probable loss related to 2012 and concluded it was not material to Southern Company. Therefore, Southern Company recorded pre-tax charges to income for estimated probable losses of </font><font style="font-family:inherit;font-size:11pt;color:#000000;text-decoration:none;">$540.0 million</font><font style="font-family:inherit;font-size:11pt;"> (</font><font style="font-family:inherit;font-size:11pt;color:#000000;text-decoration:none;">$333.5 million</font><font style="font-family:inherit;font-size:11pt;"> after tax) in the first quarter 2013 and </font><font style="font-family:inherit;font-size:11pt;color:#000000;text-decoration:none;">$450 million</font><font style="font-family:inherit;font-size:11pt;"> (</font><font style="font-family:inherit;font-size:11pt;color:#000000;text-decoration:none;">$277.9 million</font><font style="font-family:inherit;font-size:11pt;"> after tax) in the second quarter 2013.</font></div><div style="line-height:120%;padding-top:8px;text-align:left;font-size:11pt;"><font style="font-family:inherit;font-size:11pt;">Southern Company's and Mississippi Power's analysis of the estimated cost and schedule to complete the Kemper IGCC will be ongoing throughout the construction period. Mississippi Power could experience further construction cost increases and/or schedule delays with respect to the Kemper IGCC as a result of factors including, but not limited to, labor costs and productivity, adverse weather conditions, shortages and inconsistent quality of equipment, materials, and labor, or contractor or supplier delay or non-performance under construction or other agreements. Furthermore, Mississippi Power could also experience schedule delays associated with start-up activities for this "first-of-a-kind" technology, including major equipment failure, system integration, and operations and/or unforeseen engineering problems, which would result in further cost increases or require repayment of a portion of investment tax credits received. In subsequent periods, any further changes in the estimated costs to complete construction of the Kemper IGCC subject to the </font><font style="font-family:inherit;font-size:11pt;color:#000000;text-decoration:none;">$2.88 billion</font><font style="font-family:inherit;font-size:11pt;"> cost cap will be reflected in Southern Company's and Mississippi Power's statements of income and these changes could be material.</font></div><div style="line-height:120%;padding-top:8px;text-align:left;font-size:11pt;"><font style="font-family:inherit;font-size:11pt;">As of June 30, 2013, Mississippi Power had spent a total of </font><font style="font-family:inherit;font-size:11pt;color:#000000;text-decoration:none;">$3.29 billion</font><font style="font-family:inherit;font-size:11pt;"> on the Kemper IGCC. These costs include</font><font style="font-family:inherit;font-size:11pt;color:#00ffff;"> </font><font style="font-family:inherit;font-size:11pt;color:#000000;text-decoration:none;">$2.74 billion</font><font style="font-family:inherit;font-size:11pt;"> for the portion of the Kemper IGCC subject to the construction cost cap, </font><font style="font-family:inherit;font-size:11pt;color:#000000;text-decoration:none;">$210.2 million</font><font style="font-family:inherit;font-size:11pt;"> for the lignite mine and equipment, </font><font style="font-family:inherit;font-size:11pt;color:#000000;text-decoration:none;">$86.1 million</font><font style="font-family:inherit;font-size:11pt;"> for the CO</font><font style="font-family:inherit;font-size:11pt;"><sub style="vertical-align:bottom;line-height:120%;font-size:7pt">2</sub></font><font style="font-family:inherit;font-size:11pt;"> pipeline facilities, </font><font style="font-family:inherit;font-size:11pt;color:#000000;text-decoration:none;">$193.8 million</font><font style="font-family:inherit;font-size:11pt;"> of AFUDC, and </font><font style="font-family:inherit;font-size:11pt;color:#000000;text-decoration:none;">$55.2 million</font><font style="font-family:inherit;font-size:11pt;"> of other costs, including certain general exceptions and certain regulatory assets. Of this total, </font><font style="font-family:inherit;font-size:11pt;color:#000000;text-decoration:none;">$2.24 billion</font><font style="font-family:inherit;font-size:11pt;"> was included in CWIP (which is net of the DOE Grants and estimated probable losses of </font><font style="font-family:inherit;font-size:11pt;color:#000000;text-decoration:none;">$990 million</font><font style="font-family:inherit;font-size:11pt;">), </font><font style="font-family:inherit;font-size:11pt;color:#000000;text-decoration:none;">$49.7 million</font><font style="font-family:inherit;font-size:11pt;"> in other regulatory assets, </font><font style="font-family:inherit;font-size:11pt;color:#000000;text-decoration:none;">$3.9 million</font><font style="font-family:inherit;font-size:11pt;"> in other deferred charges and assets on Southern Company's and Mississippi Power's Condensed Balance Sheets herein, and </font><font style="font-family:inherit;font-size:11pt;color:#000000;text-decoration:none;">$1.0 million</font><font style="font-family:inherit;font-size:11pt;"> was previously expensed. Consistent with the treatment of non-capital costs incurred during the pre-construction period, the Mississippi PSC granted Mississippi Power the authority to defer all non-capital Kemper IGCC-related costs to a regulatory asset during the construction period. This includes deferred costs associated with the generation resource planning, evaluation, and screening activities. The amortization period for the regulatory asset will be determined by the Mississippi PSC at a later date. 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.</font></div><div style="line-height:120%;padding-top:8px;text-align:left;font-size:11pt;"><font style="font-family:inherit;font-size:11pt;">The ultimate outcome of these matters cannot be determined at this time.</font></div><div style="line-height:120%;padding-top:12px;text-align:left;font-size:11pt;"><font style="font-family:inherit;font-size:11pt;font-style:italic;">Rate Recovery of Kemper IGCC Costs</font></div><div style="line-height:120%;padding-top:8px;text-align:left;font-size:11pt;"><font style="font-family:inherit;font-size:11pt;">See "FERC Matters" 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 "Baseload Act" herein for additional information.</font></div><div style="line-height:120%;padding-top:8px;text-align:left;font-size:11pt;"><font style="font-family:inherit;font-size:11pt;">On January 24, 2013, Mississippi Power entered into a settlement agreement (Settlement Agreement) with the Mississippi PSC that, among other things, establishes the process for resolving matters regarding cost recovery related to the Kemper IGCC. Under the Settlement Agreement, Mississippi Power agreed to limit the portion of prudently-incurred Kemper IGCC costs to be included in retail rate base to the </font><font style="font-family:inherit;font-size:11pt;color:#000000;text-decoration:none;">$2.4 billion</font><font style="font-family:inherit;font-size:11pt;"> certificated cost estimate, plus the Cost Cap Exceptions as well as any other costs permitted or determined to be excluded from the </font><font style="font-family:inherit;font-size:11pt;color:#000000;text-decoration:none;">$2.88 billion</font><font style="font-family:inherit;font-size:11pt;"> cost cap by the Mississippi PSC. Mississippi Power intends to finance (1) prudently-incurred costs in excess of the certificated cost estimate and up to the </font><font style="font-family:inherit;font-size:11pt;color:#000000;text-decoration:none;">$2.88 billion</font><font style="font-family:inherit;font-size:11pt;"> cost cap, net of the DOE Grants and the Cost Cap Exceptions, (2) the accrued AFUDC, and (3) exceptions not provided for in the Seven-Year Rate Plan (discussed below) through securitization as provided in State of Mississippi legislation. The rate recovery necessary to recover the annual costs of securitization is expected to be filed and become effective after the Kemper IGCC is placed in service and following completion of the Mississippi PSC's final prudence review of costs for the Kemper IGCC.</font></div><div style="line-height:120%;padding-top:8px;text-align:left;font-size:11pt;"><font style="font-family:inherit;font-size:11pt;">Under the terms of the Settlement Agreement, Mississippi Power and the Mississippi PSC agreed to follow certain regulatory procedures and schedules for resolving the cost recovery matters related to the Kemper IGCC. These procedures and schedules include the following: (1) Mississippi Power's filing on January 25, 2013 of a new request to increase retail rates in 2013 by </font><font style="font-family:inherit;font-size:11pt;color:#000000;text-decoration:none;">$172 million</font><font style="font-family:inherit;font-size:11pt;"> annually, based on projected investment for 2013, to be recorded to a regulatory liability to be used to mitigate rate impacts when the Kemper IGCC is placed in service; (2) the Mississippi PSC's decision on that matter on March 5, 2013; (3) Mississippi Power's collaboration with the MPUS to file with the Mississippi PSC within </font><font style="font-family:inherit;font-size:11pt;color:#000000;text-decoration:none;">three months</font><font style="font-family:inherit;font-size:11pt;"> of the Settlement Agreement a rate recovery plan for the Kemper IGCC for the first </font><font style="font-family:inherit;font-size:11pt;color:#000000;text-decoration:none;">seven years</font><font style="font-family:inherit;font-size:11pt;"> of its operation, along with a proposed revenue requirement under such plan for 2014 through 2020 (Seven-Year Rate Plan) (which was made on February 26, 2013 and updated on March 22, 2013); (4) the Mississippi PSC's decision on the Seven-Year Rate Plan within </font><font style="font-family:inherit;font-size:11pt;color:#000000;text-decoration:none;">four months</font><font style="font-family:inherit;font-size:11pt;"> of that filing (which is now expected to occur in late 2013); (5) Mississippi Power's agreement to limit the portion of prudently-incurred Kemper IGCC costs to be included in rate base to the </font><font style="font-family:inherit;font-size:11pt;color:#000000;text-decoration:none;">$2.4 billion</font><font style="font-family:inherit;font-size:11pt;"> certificated cost estimate, plus the Cost Cap Exceptions, excluding AFUDC, provided that this limitation will not prevent Mississippi Power from securing alternate financing to recover any prudently-incurred Kemper IGCC costs, including plant costs above the </font><font style="font-family:inherit;font-size:11pt;color:#000000;text-decoration:none;">$2.4 billion</font><font style="font-family:inherit;font-size:11pt;"> certificated cost estimate and AFUDC, not otherwise recovered in any Mississippi PSC rate proceeding contemplated by the Settlement Agreement; and (6) the Mississippi PSC's completion of its prudence review of the Kemper IGCC costs incurred through 2012 within </font><font style="font-family:inherit;font-size:11pt;color:#000000;text-decoration:none;">six months</font><font style="font-family:inherit;font-size:11pt;"> of the Settlement Agreement (which is now expected to occur in early 2014 for costs incurred through March 31, 2013), an additional prudence review upon considering the Seven-Year Rate Plan for costs incurred through the most recent reporting period (which is now expected to be unnecessary due to the July 26, 2013 scheduling order discussed below), and a final prudence review of the remaining project costs within </font><font style="font-family:inherit;font-size:11pt;color:#000000;text-decoration:none;">six months</font><font style="font-family:inherit;font-size:11pt;"> of the Kemper IGCC's in-service date (which is now expected to include a prudence review of all costs incurred after March 31, 2013). The Settlement Agreement provides that Mississippi Power may terminate the agreement if certain conditions are not met, if Mississippi Power is unable to secure alternate financing for any prudently-incurred Kemper IGCC costs not otherwise recovered in any Mississippi PSC rate proceeding contemplated by the Settlement Agreement, or if the Mississippi PSC fails to comply with the requirements of the Settlement Agreement. Legislation to authorize a multi-year rate plan and legislation to provide for alternate financing through securitization was enacted into law on February 26, 2013. Mississippi Power is currently working with the Mississippi PSC and the MPUS to implement the procedural schedules set forth in the Settlement Agreement and additional variations to the schedule are likely.</font></div><div style="line-height:120%;padding-top:8px;text-align:left;font-size:11pt;"><font style="font-family:inherit;font-size:11pt;">On March 5, 2013, the Mississippi PSC issued an order (2013 Kemper IGCC Order) approving a </font><font style="font-family:inherit;font-size:11pt;color:#000000;text-decoration:none;">15%</font><font style="font-family:inherit;font-size:11pt;"> increase in retail rates effective on March 19, 2013, and an additional </font><font style="font-family:inherit;font-size:11pt;color:#000000;text-decoration:none;">3%</font><font style="font-family:inherit;font-size:11pt;"> increase in retail rates effective January 1, 2014, which collectively are designed to collect </font><font style="font-family:inherit;font-size:11pt;color:#000000;text-decoration:none;">$156 million</font><font style="font-family:inherit;font-size:11pt;"> annually beginning in 2014. All amounts collected through April 2014, which are expected to total </font><font style="font-family:inherit;font-size:11pt;color:#000000;text-decoration:none;">$126 million</font><font style="font-family:inherit;font-size:11pt;">, will be recorded as a regulatory liability to be used to mitigate rate impacts beginning in May 2014 when the Kemper IGCC is expected to be placed in service. As of June 30, 2013, </font><font style="font-family:inherit;font-size:11pt;color:#000000;text-decoration:none;">$27.0 million</font><font style="font-family:inherit;font-size:11pt;"> had been collected and recorded as a regulatory liability with </font><font style="font-family:inherit;font-size:11pt;color:#000000;text-decoration:none;">$3.0 million</font><font style="font-family:inherit;font-size:11pt;"> included in other regulatory liabilities, current and </font><font style="font-family:inherit;font-size:11pt;color:#000000;text-decoration:none;">$24.0 million</font><font style="font-family:inherit;font-size:11pt;"> included in other regulatory liabilities, deferred in Southern Company's and Mississippi Power's Condensed Balance Sheets herein. On March 21, 2013, a legal challenge to the 2013 Kemper IGCC Order was filed with the Mississippi Supreme Court.</font></div><div style="line-height:120%;padding-top:8px;text-align:left;font-size:11pt;"><font style="font-family:inherit;font-size:11pt;">Because the 2013 Kemper IGCC Order did not provide for the inclusion of CWIP in rate base as permitted by the Baseload Act described below, Mississippi Power continues to record AFUDC on the Kemper IGCC during the construction period. Mississippi Power will not record AFUDC on any additional costs of the Kemper IGCC that exceed the </font><font style="font-family:inherit;font-size:11pt;color:#000000;text-decoration:none;">$2.88 billion</font><font style="font-family:inherit;font-size:11pt;"> cost cap, except for Cost Cap Exception amounts. Mississippi Power's rate plans filed pursuant to the Settlement Agreement contemplate the continued accrual of AFUDC through the May 2014 expected in-service date.</font></div><div style="line-height:120%;padding-top:8px;text-align:left;font-size:11pt;"><font style="font-family:inherit;font-size:11pt;">On March 22, 2013, Mississippi Power, in compliance with the 2013 Kemper IGCC Order, filed a revision to the Seven-Year Rate Plan with the Mississippi PSC for the Kemper IGCC for 2014 through 2020, the first </font><font style="font-family:inherit;font-size:11pt;color:#000000;text-decoration:none;">seven years</font><font style="font-family:inherit;font-size:11pt;"> of operation of the Kemper IGCC. The Seven-Year Rate Plan, which contemplates Mississippi Power's sale of a </font><font style="font-family:inherit;font-size:11pt;color:#000000;text-decoration:none;">15%</font><font style="font-family:inherit;font-size:11pt;"> undivided ownership interest in the Kemper IGCC, proposes recovery of an annual revenue requirement of approximately </font><font style="font-family:inherit;font-size:11pt;color:#000000;text-decoration:none;">$156 million</font><font style="font-family:inherit;font-size:11pt;"> of Kemper IGCC-related operational costs and rate base amounts, including plant costs equal to the </font><font style="font-family:inherit;font-size:11pt;color:#000000;text-decoration:none;">$2.4 billion</font><font style="font-family:inherit;font-size:11pt;"> certificated cost estimate. Mississippi Power expects a decision from the Mississippi PSC regarding the Seven-Year Rate Plan in late 2013. The 2013 Kemper IGCC Order, which increased rates beginning on March 19, 2013, is integral to the Seven-Year Rate Plan, which contemplates amortization of the April 2014 regulatory liability balance to be used to mitigate rate impacts from the expected in-service date of May 2014 through 2020, based on a fixed amortization schedule that requires approval by the Mississippi PSC. Under the Seven-Year Rate Plan filing, Mississippi Power proposes annual rate recovery to remain the same from 2014 through 2020. While it is the intent of Mississippi Power for the actual revenue requirement to equal the proposed revenue requirement, Mississippi Power proposes that the annual differences through 2020 for certain items contemplated in the Seven-Year Rate Plan will be deferred, subject to accrual of carrying costs, and the cumulative balance will be reviewed at the end of the term of the Settlement Agreement by the Mississippi PSC to determine the disposition of any potential remaining deferred balance.</font></div><div style="line-height:120%;padding-top:8px;text-align:left;font-size:11pt;"><font style="font-family:inherit;font-size:11pt;">The revenue requirements set forth in Mississippi Power's Seven-Year Rate Plan described above assume, among other things, the Kemper IGCC will be placed in service in May 2014, the sale of a </font><font style="font-family:inherit;font-size:11pt;color:#000000;text-decoration:none;">15%</font><font style="font-family:inherit;font-size:11pt;"> undivided interest in the Kemper IGCC to SMEPA will be completed as described herein, Mississippi Power's receipt of the benefits relating to tax credits described herein, and recovery of the Cost Cap Exceptions described herein.</font></div><div style="line-height:120%;padding-top:8px;text-align:left;font-size:11pt;"><font style="font-family:inherit;font-size:11pt;">On July 26, 2013, the Mississippi PSC issued a scheduling order for the prudence review of the Kemper IGCC costs incurred through March 31, 2013. Mississippi Power expects a decision from the Mississippi PSC in early 2014.</font></div><div style="line-height:120%;padding-top:8px;text-align:left;font-size:11pt;"><font style="font-family:inherit;font-size:11pt;">The ultimate outcome of these matters, including the resolution of legal challenges, determinations of prudency and the specific manner of recovery of costs relating to the Kemper IGCC, is subject to further regulatory actions and cannot be determined at this time.</font></div><div style="line-height:120%;padding-top:12px;text-align:left;font-size:11pt;"><font style="font-family:inherit;font-size:11pt;font-style:italic;">Proposed Sale of Undivided Interest to SMEPA</font></div><div style="line-height:120%;padding-top:8px;text-align:left;font-size:11pt;"><font style="font-family:inherit;font-size:11pt;">In 2010, Mississippi Power and SMEPA entered into an asset purchase agreement whereby SMEPA agreed to purchase a </font><font style="font-family:inherit;font-size:11pt;color:#000000;text-decoration:none;">17.5%</font><font style="font-family:inherit;font-size:11pt;"> undivided interest in the Kemper IGCC. In February 2012, the Mississippi PSC approved the sale and transfer of </font><font style="font-family:inherit;font-size:11pt;color:#000000;text-decoration:none;">17.5%</font><font style="font-family:inherit;font-size:11pt;"> of the Kemper IGCC to SMEPA. In June 2012, Mississippi Power and SMEPA signed an amendment to the asset purchase agreement whereby SMEPA extended its option to purchase until December 31, 2012, and reduced its purchase commitment percentage from a </font><font style="font-family:inherit;font-size:11pt;color:#000000;text-decoration:none;">17.5%</font><font style="font-family:inherit;font-size:11pt;"> to a </font><font style="font-family:inherit;font-size:11pt;color:#000000;text-decoration:none;">15%</font><font style="font-family:inherit;font-size:11pt;"> undivided interest in the Kemper IGCC. On December 31, 2012, Mississippi Power and SMEPA agreed to extend SMEPA's option to purchase through December 31, 2013. The sale and transfer of an interest in the Kemper IGCC to SMEPA is subject to approval by the Mississippi PSC.</font></div><div style="line-height:120%;padding-top:8px;text-align:left;font-size:11pt;"><font style="font-family:inherit;font-size:11pt;">The closing of this transaction is conditioned upon execution of a joint ownership and operating agreement, receipt of all construction permits, appropriate regulatory approvals, financing, and other conditions. In September 2012, SMEPA received a conditional loan commitment from Rural Utilities Service to provide funding for SMEPA's undivided interest in the Kemper IGCC.</font></div><div style="line-height:120%;padding-top:8px;text-align:left;font-size:11pt;"><font style="font-family:inherit;font-size:11pt;">In March 2012, Mississippi Power received a </font><font style="font-family:inherit;font-size:11pt;color:#000000;text-decoration:none;">$150 million</font><font style="font-family:inherit;font-size:11pt;"> interest-bearing refundable deposit from SMEPA to be applied to the purchase. While the expectation is that the amount will be applied to the purchase price at closing, Mississippi Power would be required to refund the deposit upon the termination of the asset purchase agreement, within </font><font style="font-family:inherit;font-size:11pt;color:#000000;text-decoration:none;">60</font><font style="font-family:inherit;font-size:11pt;"> days of a request by SMEPA for a full or partial refund, or within </font><font style="font-family:inherit;font-size:11pt;color:#000000;text-decoration:none;">15 days</font><font style="font-family:inherit;font-size:11pt;"> at SMEPA's discretion in the event that Mississippi Power is assigned a senior unsecured credit rating of BBB+ or lower by S&P or Baa1 or lower by Moody's or ceases to be rated by either of these rating agencies. Given the interest-bearing nature of the deposit and SMEPA's ability to request a refund, the deposit has been presented as a current liability in Southern Company's and Mississippi Power's Condensed Balance Sheets herein and as financing proceeds in Southern Company's and Mississippi Power's Condensed Statements of Cash Flows herein. On July 18, 2013, Southern Company entered into an agreement with SMEPA under which Southern Company has agreed to guarantee the obligations of Mississippi Power with respect to any required refund of the deposit.</font></div><div style="line-height:120%;padding-top:8px;text-align:left;font-size:11pt;"><font style="font-family:inherit;font-size:11pt;">The ultimate outcome of these matters cannot be determined at this time.</font></div><div style="line-height:120%;padding-top:8px;text-align:left;font-size:11pt;"><font style="font-family:inherit;font-size:11pt;font-style:italic;">Baseload Act</font></div><div style="line-height:120%;padding-top:8px;text-align:left;font-size:11pt;"><font style="font-family:inherit;font-size:11pt;">In 2008, the Baseload Act was signed by the Governor of Mississippi and is designed to enhance the Mississippi PSC's authority to facilitate development and construction of base load generation in the State of Mississippi. The Baseload Act authorizes, but does not require, the Mississippi PSC to adopt a cost recovery mechanism that includes in retail base rates, prior to and during construction, all or a portion of the prudently-incurred pre-construction and construction costs incurred by a utility in constructing a base load electric generating plant. Prior to the passage of the Baseload Act, such costs would traditionally be recovered only after the plant was placed in service. The Baseload Act also provides for periodic prudence reviews by the Mississippi PSC and prohibits the cancellation of any such generating plant without the approval of the Mississippi PSC. In the event of cancellation of the construction of the plant without approval of the Mississippi PSC, the Baseload Act authorizes the Mississippi PSC to make a public interest determination as to whether and to what extent the utility will be afforded rate recovery for costs incurred in connection with such cancelled generating plant. There are legal challenges to the constitutionality of the Baseload Act currently pending before the Mississippi Supreme Court. The ultimate outcome of the legal challenges to this legislation cannot be determined at this time. See "Rate Recovery of Kemper IGCC Costs" herein for additional information.</font></div><div style="line-height:120%;padding-top:12px;text-align:left;font-size:11pt;"><font style="font-family:inherit;font-size:11pt;font-style:italic;">Tax Incentives</font></div><div style="line-height:120%;padding-top:8px;text-align:left;font-size:11pt;"><font style="font-family:inherit;font-size:11pt;">The IRS has allocated </font><font style="font-family:inherit;font-size:11pt;color:#000000;text-decoration:none;">$133 million</font><font style="font-family:inherit;font-size:11pt;"> (Phase I) and </font><font style="font-family:inherit;font-size:11pt;color:#000000;text-decoration:none;">$279 million</font><font style="font-family:inherit;font-size:11pt;"> (Phase II) of Internal Revenue Code Section 48A tax credits to Mississippi Power in connection with the Kemper IGCC. Mississippi Power's utilization of Phase I and Phase II credits is dependent upon meeting the IRS certification requirements, including an in-service date no later than May 11, 2014 for the Phase I credits and April 19, 2016 for the Phase II credits. In order to remain eligible for the Phase II credits, Mississippi Power plans to capture and sequester (via enhanced oil recovery) at least </font><font style="font-family:inherit;font-size:11pt;color:#000000;text-decoration:none;">65%</font><font style="font-family:inherit;font-size:11pt;font-weight:bold;"> </font><font style="font-family:inherit;font-size:11pt;">of the CO</font><font style="font-family:inherit;font-size:11pt;"><sub style="vertical-align:bottom;line-height:120%;font-size:7pt">2</sub></font><font style="font-family:inherit;font-size:11pt;"> produced by the Kemper IGCC during operations in accordance with the rules for Internal Revenue Code Section 48A investment tax credits. Through June 30, 2013, Mississippi Power had received or accrued tax benefits totaling </font><font style="font-family:inherit;font-size:11pt;color:#000000;text-decoration:none;">$412 million</font><font style="font-family:inherit;font-size:11pt;"> for these tax credits, which will be amortized as a reduction to depreciation and amortization over the life of the Kemper IGCC. As a result of bonus tax depreciation on certain assets placed, or to be placed, in service in 2013 and 2014, and the subsequent reduction in federal taxable income, Mississippi Power estimates that it will be able to utilize all of these tax credits by June 30, 2014. IRS guidelines allow these unused tax credits to be carried forward for </font><font style="font-family:inherit;font-size:11pt;color:#000000;text-decoration:none;">20 years</font><font style="font-family:inherit;font-size:11pt;"> from the date received, if not utilized before then. In October 2012, Mississippi Power filed an application with the DOE for certification of the Kemper IGCC for additional tax credits under the Internal Revenue Code Section 48A (Phase III). On May 15, 2013, the IRS notified Mississippi Power that no Phase III tax credits were allocated to the Kemper IGCC.</font></div><div style="line-height:120%;padding-top:8px;text-align:left;font-size:11pt;"><font style="font-family:inherit;font-size:11pt;">A portion of the tax credits realized by Mississippi Power will be subject to recapture upon successful completion of SMEPA's purchase of an undivided interest in the Kemper IGCC as described above. In addition, all or a portion of the tax credits will be subject to recapture if Mississippi Power fails to satisfy the in-service date requirements and CO</font><font style="font-family:inherit;font-size:11pt;"><sub style="vertical-align:bottom;line-height:120%;font-size:7pt">2</sub></font><font style="font-family:inherit;font-size:11pt;"> capture requirements described above.</font></div><div style="line-height:120%;padding-top:8px;text-align:left;font-size:11pt;"><font style="font-family:inherit;font-size:11pt;">On January 2, 2013, the American Taxpayer Relief Act of 2012 (ATRA) was signed into law. The ATRA retroactively extended several tax credits through 2013 and </font><font style="font-family:inherit;font-size:11pt;color:#000000;text-decoration:none;">50%</font><font style="font-family:inherit;font-size:11pt;"> bonus depreciation for property to be placed in service in 2013 (and for certain long-term production-period projects to be placed in service in 2014), which is expected to apply to the Kemper IGCC.</font></div><div style="line-height:120%;padding-top:8px;text-align:left;font-size:11pt;"><font style="font-family:inherit;font-size:11pt;">The ultimate outcome of these matters cannot be determined at this time.</font></div><div style="line-height:120%;padding-top:12px;font-size:11pt;"><font style="font-family:inherit;font-size:11pt;font-weight:bold;">Other Matters</font></div><div style="line-height:120%;padding-top:8px;font-size:11pt;"><font style="font-family:inherit;font-size:11pt;">On April 4, 2013, an explosion occurred at Plant Bowen Unit 2 that resulted in substantial damage to the Plant Bowen Unit 2 generator, Plant Bowen's Units 1 and 2 control room and surrounding areas, as well as Plant Bowen's switchyard. Plant Bowen Unit 1 (approximately </font><font style="font-family:inherit;font-size:11pt;color:#000000;text-decoration:none;">700</font><font style="font-family:inherit;font-size:11pt;"> MWs) was returned to service on August 3, 2013. Plant Bowen Unit 2 (approximately </font><font style="font-family:inherit;font-size:11pt;color:#000000;text-decoration:none;">700</font><font style="font-family:inherit;font-size:11pt;"> MWs) remains offline, pending completion of repairs. Georgia Power expects that any material repair costs related to the damage will be covered by property insurance. The ultimate outcome of this matter cannot be determined at this time.</font></div></div>falsefalsefalsenonnum:textBlockItemTypenaThe entire disclosure for legal proceedings, legal contingencies, litigation, regulatory and environmental matters and other contingencies.No definition available.false0falseContingencies and Regulatory MattersUnKnownUnKnownUnKnownUnKnowntruefalsefalseSheethttp://southerncompany.com/role/ContingenciesAndRegulatoryMatters12