Contingencies and Regulatory Matters

12 Months Ended

Dec. 31, 2015

Loss Contingencies [Line Items]

CONTINGENCIES AND REGULATORY MATTERS

CONTINGENCIES AND REGULATORY MATTERS

General Litigation Matters

Southern Company and its subsidiaries are subject to certain claims and legal actions arising in the ordinary course of business. In addition, the business activities of Southern Company's subsidiaries are subject to extensive governmental regulation related to public health and the environment, such as regulation of air emissions and water discharges. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements such as air quality and water standards, has occurred throughout the U.S. This litigation has included claims for damages alleged to have been caused by CO₂ and other emissions, CCR, and alleged exposure to hazardous materials, and/or requests for injunctive relief in connection with such matters. The ultimate outcome of such pending or potential litigation against Southern Company and its subsidiaries cannot be predicted at this time; however, for current proceedings not specifically reported herein, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on Southern Company's financial statements.

AGL Resources Merger Litigation

AGL Resources and each member of the AGL Resources board of directors were named as defendants in four purported shareholder class action lawsuits filed in the United States District Court for the Northern District of Georgia in September and October 2015. These actions were filed on behalf of named plaintiffs and other AGL Resources shareholders challenging the Merger and seeking, among other things, preliminary and permanent injunctive relief enjoining the Merger, and, in certain circumstances, damages. Southern Company and Merger Sub were also named as defendants in two of these lawsuits. On October 23, 2015, the court consolidated the four lawsuits into a single action. On January 4, 2016, the parties filed a proposed stipulated order of dismissal, asking the court to dismiss the consolidated amended complaint without prejudice, which the court approved on January 5, 2016. See Note 12 under "Southern Company – Proposed Merger with AGL Resources" for additional information regarding the Merger.

Environmental Matters

Environmental Remediation

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

Georgia Power's environmental remediation liability as of December 31, 2015 was $29 million. Georgia Power has been designated or identified as a potentially responsible party (PRP) at sites governed by the Georgia Hazardous Site Response Act and/or by the federal Comprehensive Environmental Response, Compensation, and Liability Act (CERCLA), including a site in Brunswick, Georgia on the CERCLA National Priorities List. The PRPs at the Brunswick site have completed a removal action as ordered by the EPA. Additional response actions at this site are anticipated. In September 2015, Georgia Power entered into an allocation agreement with another PRP, under which that PRP will be responsible (as between Georgia Power and that PRP) for paying and performing certain investigation, assessment, remediation, and other incidental activities at the Brunswick site. Assessment and potential cleanup of other sites are anticipated.

The ultimate outcome of these matters will depend upon the success of defenses asserted, the ultimate number of PRPs participating in the cleanup, and numerous other factors and cannot be determined at this time; however, as a result of Georgia Power's regulatory treatment for environmental remediation expenses, these matters are not expected to have a material impact on Southern Company's financial statements.

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

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 does not believe that additional liabilities, if any, at these sites would be material to the financial statements.

Nuclear Fuel Disposal Costs

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

In December 2014, the Court of Federal Claims entered a judgment in favor of Georgia Power and Alabama Power in their spent nuclear fuel lawsuit seeking damages for the period from January 1, 2005 through December 31, 2010. On March 19, 2015, Georgia Power recovered approximately $18 million, based on its ownership interests, and Alabama Power recovered approximately $26 million. In March 2015, Georgia Power credited the award to accounts where the original costs were charged and reduced rate base, fuel, and cost of service for the benefit of customers. In November 2015, Alabama Power applied the retail-related proceeds to offset the nuclear fuel expense under Rate ECR. See "Retail Regulatory Matters – Alabama Power – Nuclear Waste Fund Accounting Order" herein for additional information. In December 2015, Alabama Power credited the wholesale-related proceeds to each wholesale customer.

In March 2014, Alabama Power and Georgia Power filed additional lawsuits against the U.S. government for the costs of continuing to store spent nuclear fuel at Plants Farley and Hatch and Plant Vogtle Units 1 and 2 for the period from January 1, 2011 through December 31, 2013. The damage period was subsequently extended to December 31, 2014. Damages will continue to accumulate until the issue is resolved or storage is provided. No amounts have been recognized in the financial statements as of December 31, 2015 for any potential recoveries from the additional lawsuits. The final outcome of these matters cannot be determined at this time; however, no material impact on Southern Company's net income is expected.

On-site dry spent fuel storage facilities are operational at all three plants and can be expanded to accommodate spent fuel through the expected life of each plant.

FERC Matters

The traditional operating companies and Southern Power have authority from the FERC to sell electricity at market-based rates. Since 2008, that authority, for certain balancing authority areas, has been conditioned on compliance with the requirements of an energy auction, which the FERC found to be tailored mitigation that addresses potential market power concerns. In accordance with FERC regulations governing such authority, the traditional operating companies and Southern Power filed a triennial market power analysis in June 2014, which included continued reliance on the energy auction as tailored mitigation. On April 27, 2015, the FERC issued an order finding that the traditional operating companies' and Southern Power's existing tailored mitigation may not effectively mitigate the potential to exert market power in certain areas served by the traditional operating companies and in some adjacent areas. The FERC directed the traditional operating companies and Southern Power to show why market-based rate authority should not be revoked in these areas or to provide a mitigation plan to further address market power concerns. The traditional operating companies and Southern Power filed a request for rehearing on May 27, 2015 and on June 26, 2015 filed their response with the FERC. The ultimate outcome of this matter cannot be determined at this time.

Retail Regulatory Matters

Alabama Power

Rate RSE

The Alabama PSC has adopted Rate RSE that provides for periodic annual adjustments based upon Alabama Power's projected weighted cost of equity (WCE) compared to an allowable range. Rate RSE adjustments are based on forward-looking information for the applicable upcoming calendar year. Retail rates remain unchanged when the WCE ranges between 5.75% and 6.21%. Rate RSE adjustments for any two-year period, when averaged together, cannot exceed 4.0% and any annual adjustment is limited to 5.0%. If Alabama Power's actual retail return is above the allowed WCE range, customer refunds will be required; however, there is no provision for additional customer billings should the actual retail return fall below the WCE range.

In 2013, the Alabama PSC approved a revision to Rate RSE, effective for calendar year 2014. This revision established the WCE range of 5.75% to 6.21% with an adjusting point of 5.98% and provided eligibility for a performance-based adder of seven basis points, or 0.07%, to the WCE adjusting point if Alabama Power (i) has an "A" credit rating equivalent with at least one of the recognized rating agencies or (ii) is in the top one-third of a designated customer value benchmark survey.

The Rate RSE increase for 2015 was 3.49% or $181 million annually, and was effective January 1, 2015. On November 30, 2015, Alabama Power made its annual Rate RSE submission to the Alabama PSC of projected data for calendar year 2016. Projected earnings were within the specified WCE range; therefore, retail rates under Rate RSE remained unchanged for 2016.

Rate CNP

Alabama Power's retail rates, approved by the Alabama PSC, provide for adjustments to recognize the placing of new generating facilities into retail service under Rate CNP. Alabama Power may also recover retail costs associated with certificated PPAs under Rate CNP PPA. On March 3, 2015, the Alabama PSC issued a consent order that Alabama Power leave in effect the current Rate CNP PPA factor for billings for the period April 1, 2015 through March 31, 2016. No adjustment to Rate CNP PPA is expected in 2016. As ofDecember 31, 2015, Alabama Power had an under recovered certificated PPA balance of$99 millionwhichis included in deferred under recovered regulatory clause revenues in the balance sheet.

Rate CNP Environmental allowed for the recovery of Alabama Power's retail costs associated with environmental laws, regulations, and other such mandates. On March 3, 2015, the Alabama PSC approved a modification to Rate CNP Environmental to include compliance costs for both environmental and non-environmental mandates. The recoverable non-environmental compliance costs result from laws, regulations, and other mandates directed at the utility industry involving the security, reliability, safety, sustainability, or similar considerations impacting Alabama Power's facilities or operations. This modification to Rate CNP Environmental was effective March 20, 2015 with the revised rate now defined as Rate CNP Compliance. Alabama Power was limited to recover $50 million of non-environmental compliance costs for the year 2015. Additional non-environmental compliance costs were recovered through Rate RSE. Customer rates were not impacted by this order in 2015; therefore, the modification increased the under recovered position for Rate CNP Compliance during 2015. Rate CNP Compliance is based on forward-looking information and provides for the recovery of these costs pursuant to a factor that is calculated annually. Compliance costs to be recovered include operations and maintenance expenses, depreciation, and a return on certain invested capital.

Rate CNP Compliance increased 1.5%, or $75 million annually, effective January 1, 2015. As of December 31, 2015, Alabama Power had an under recovered compliance clause balance of $43 million, which is included in under recovered regulatory clause revenues in the balance sheet.

Rate ECR

Alabama Power has established energy cost recovery rates under Alabama Power's Rate ECR as approved by the Alabama PSC. Rates are based on an estimate of future energy costs and the current over or under recovered balance. Revenues recognized under Rate ECR and recorded on the financial statements are adjusted for the difference in actual recoverable fuel costs and amounts billed in current regulated rates. The difference in the recoverable fuel costs and amounts billed give rise to the over or under recovered amounts recorded as regulatory assets or liabilities. Alabama Power, along with the Alabama PSC, continually monitors the over or under recovered cost balance to determine whether an adjustment to billing rates is required. Changes in the Rate ECR factor have no significant effect on Southern Company's net income, but will impact operating cash flows. Currently, the Alabama PSC may approve billing rates under Rate ECR of up to 5.910 cents per KWH. In December 2014, the Alabama PSC issued a consent order that Alabama Power leave in effect for 2015 the Rate ECR factor of 2.681 cents per KWH.

On December 1, 2015, the Alabama PSC approved a decrease in Alabama Power’s Rate ECR factor from 2.681 to 2.030 cents per KWH, 6.7%, or $370 million annually, based upon projected billings, effective January 1, 2016. The approved decrease in the Rate ECR factor will have no significant effect on Southern Company's net income, but will decrease operating cash flows related to fuel cost recovery in 2016 when compared to 2015. The rate will return to 2.681 cents per KWH in 2017 and 5.910 cents per KWH in 2018, absent a further order from the Alabama PSC.

Alabama Power's over recovered fuel costs at December 31, 2015 totaled $238 million as compared to $47 million at December 31, 2014. At December 31, 2015, $238 million is included in other regulatory liabilities, current. The over recovered fuel costs at December 31, 2014 are included in deferred over recovered regulatory clause revenues. 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 recovery or return of fuel costs.

Rate NDR

Based on an order from the Alabama PSC, Alabama Power maintains a reserve for operations and maintenance expenses to cover the cost of damages from major storms to its transmission and distribution facilities. The order approves a separate monthly Rate NDR charge to customers consisting of two components. The first component is intended to establish and maintain a reserve balance for future storms and is an on-going part of customer billing. The second component of the Rate NDR charge is intended to allow recovery of any existing deferred storm-related operations and maintenance costs and any future reserve deficits over a 24-month period. The Alabama PSC order gives Alabama Power authority to record a deficit balance in the NDR when costs of storm damage exceed any established reserve balance. Absent further Alabama PSC approval, the maximum total Rate NDR charge consisting of both components is $10 per month per non-residential customer account and $5 per month per residential customer account. Alabama Power has the authority, based on an order from the Alabama PSC, to accrue certain additional amounts as circumstances warrant. The order allows for reliability-related expenditures to be charged against the additional accruals when the NDR balance exceeds $75 million. Alabama Power may designate a portion of the NDR to reliability-related expenditures as a part of an annual budget process for the following year or during the current year for identified unbudgeted reliability-related expenditures that are incurred. Accruals that have not been designated can be used to offset storm charges. Additional accruals to the NDR will enhance Alabama Power's ability to deal with the financial effects of future natural disasters, promote system reliability, and offset costs retail customers would otherwise bear.

As revenue from the Rate NDR charge is recognized, an equal amount of operations and maintenance expenses related to the NDR will also be recognized. As a result, the Rate NDR charge will not have an effect on net income but will impact operating cash flows.

Environmental Accounting Order

Based on an order from the Alabama PSC, Alabama Power is allowed to establish a regulatory asset to record the unrecovered investment costs, including the unrecovered plant asset balance and the unrecovered costs, associated with site removal and closure associated with future unit retirements caused by environmental regulations. These costs are being amortized and recovered over the affected unit's remaining useful life, as established prior to the decision regarding early retirement through Rate CNP Compliance.

In April 2015, as part of its environmental compliance strategy, Alabama Power retired Plant Gorgas Units 6 and 7 (200 MWs). Additionally, in April 2015, Alabama Power ceased using coal at Plant Barry Units 1 and 2 (250 MWs), but such units will remain available on a limited basis with natural gas as the fuel source. In accordance with the joint stipulation entered in connection with a civil enforcement action by the EPA, Alabama Power retired Plant Barry Unit 3 (225 MWs) in August 2015 and it is no longer available for generation. Alabama Power expects to cease using coal at Plant Greene County Units 1 and 2 (300 MWs) and begin operating those units solely on natural gas by April 2016.

In accordance with this accounting order from the Alabama PSC, Alabama Power transferred the unrecovered plant asset balances to a regulatory asset at their respective retirement dates. The regulatory asset will be amortized and recovered through Rate CNP Compliance over the remaining useful lives, as established prior to the decision for retirement. As a result, these decisions will not have a significant impact on Southern Company's financial statements.

Nuclear Waste Fund Accounting Order

In 2013, the U.S. District Court for the District of Columbia ordered the DOE to cease collecting spent fuel depositary fees from nuclear power plant operators until such time as the DOE either complies with the Nuclear Waste Policy Act of 1982 or until the U.S. Congress enacts an alternative waste management plan. The DOE formally set the fee to zero effective May 16, 2014.

In August 2014, the Alabama PSC issued an order to provide for the continued recovery from customers of amounts associated with the permanent disposal of nuclear waste from the operation of Plant Farley. In accordance with the order, effective May 16, 2014, Alabama Power was authorized to recover from customers an amount equal to the prior fee and to record the amounts in a regulatory liability account (approximately $14 million annually). On December 1, 2015, the Alabama PSC issued an order for Alabama Power to discontinue recording the amounts recovered from customers in a regulatory liability account and transfer amounts recorded in the regulatory liability to Rate ECR. On December 1, 2015, Alabama Power transferred $20 million from the regulatory liability to Rate ECR to offset fuel expense.

Cost of Removal Accounting Order

In accordance with an accounting order issued in November 2014 by the Alabama PSC, in December 2014, Alabama Power fully amortized the balance of $123 million in certain regulatory asset accounts and offset this amortization expense with the amortization of $120 million of the regulatory liability for other cost of removal obligations. The regulatory asset accounts fully amortized and terminated as of December 31, 2014 represented costs previously deferred under a compliance and pension cost accounting order as well as a non-nuclear outage accounting order, which were approved by the Alabama PSC in 2012 and 2013, respectively. Approximately $95 million of non-nuclear outage costs and $28 million of compliance and pension costs were fully amortized in December 2014.

Georgia Power

Rate Plans

In 2013, the Georgia PSC voted to approve the 2013 ARP. The 2013 ARP reflects the settlement agreement among Georgia Power, the Georgia PSC's Public Interest Advocacy Staff, and11 of the 13intervenors.

In January 2014, in accordance with the 2013 ARP, Georgia Power increased its tariffs as follows: (1) traditional base tariff rates by approximately$80 million; (2) Environmental Compliance Cost Recovery (ECCR) tariff by approximately $25 million; (3) Demand-Side Management (DSM) tariffs by approximately $1 million; and (4) Municipal Franchise Fee (MFF) tariff by approximately $4 million, for a total increase in base revenues of approximately$110 million.

On February 19, 2015, in accordance with the 2013 ARP, the Georgia PSC approved an increase to tariffs effective January 1, 2015 as follows: (1) traditional base tariff rates by approximately $107 million; (2) ECCR tariff by approximately $23 million; (3) DSM tariffs by approximately $3 million; and (4) MFF tariff by approximately $3 million, for a total increase in base revenues of approximately $136 million.

On December 16, 2015, in accordance with the 2013 ARP, the Georgia PSC approved an increase to tariffs effective January 1, 2016 as follows: (1) traditional base tariff rates by approximately $49 million; (2) ECCR tariff by approximately $75 million; (3) DSM tariffs by approximately $3 million; and (4) MFF tariff by approximately $13 million, for a total increase in base revenues of approximately $140 million.

Under the 2013 ARP, Georgia Power's retail ROE is set at 10.95% and earnings are evaluated against a retail ROE range of10.00% to 12.00%. Two-thirds of any earnings above 12.00% will be directly refunded to customers, with the remaining one-third retained by Georgia Power. There will be no recovery of any earnings shortfall below 10.00% on an actual basis. In 2014, Georgia Power's retail ROE exceeded 12.00%, and Georgia Power will refund to retail customers approximately $11 million in 2016, as approved by the Georgia PSC on February 18, 2016. In 2015, Georgia Power's retail ROE was within the allowed retail ROE range.

Georgia Power is required to file a general base rate case by July 1, 2016, in response to which the Georgia PSC would be expected to determine whether the 2013 ARP should be continued, modified, or discontinued.

Integrated Resource Plan

To comply with the April 16, 2015 effective date of the MATS rule, Plant Branch Units 1, 3, and 4 (1,266 MWs), Plant Yates Units 1 through 5 (579 MWs), and Plant McManus Units 1 and 2 (122 MWs) were retired and operations were discontinued at Plant Mitchell Unit 3 (155 MWs) by April 15, 2015, and Plant Kraft Units 1 through 4 (316 MWs) were retired on October 13, 2015. The switch to natural gas as the primary fuel was completed at Plant Yates Units 6 and 7 by June 2015 and at Plant Gaston Units 1 through 4 by December 2015.

In the 2013 ARP, the Georgia PSC approved the amortization of the CWIP balances related to environmental projects that will not be completed at Plant Branch Units 1 through 4 and Plant Yates Units 6 and 7 over nine years ending December 2022 and the amortization of the remaining net book values of Plant Branch Unit 2 from October 2013 to December 2022, Plant Branch Unit 1 from May 2015 to December 2020, Plant Branch Unit 3 from May 2015 to December 2023, and Plant Branch Unit 4 from May 2015 to December 2024.

On January 29, 2016, Georgia Power filed its triennial IRP (2016 IRP). The filing included a request to decertify Plant Mitchell Units 3, 4A, and 4B (217 MWs) and Plant Kraft Unit 1 (17 MWs) upon approval of the 2016 IRP. The 2016 IRP also reflects that Georgia Power exercised its contractual option to sell its 33% ownership interest in the Intercession City unit (143 MWs total capacity) to Duke Energy Florida, Inc. See Note 4 for additional information.

In the 2016 IRP, Georgia Power requested reclassification of the remaining net book value of Plant Mitchell Unit 3, as of its retirement date, to a regulatory asset to be amortized over a period equal to the unit's remaining useful life. Georgia Power also requested that the Georgia PSC approve the deferral of the cost associated with materials and supplies remaining at the unit retirement dates to a regulatory asset, to be amortized over a period deemed appropriate by the Georgia PSC.

The decertification and retirement of these units are not expected to have a material impact on Southern Company's financial statements; however, the ultimate outcome depends on the Georgia PSC's orders in the 2016 IRP and next general base rate case.

Additionally, the 2016 IRP included a Renewable Energy Development Initiative requesting to procure up to 525 MWs of renewable resources utilizing market-based prices established through a competitive bidding process to expand Georgia Power's existing renewable initiatives, including the Advanced Solar Initiative.

A decision from the Georgia PSC on the 2016 IRP is expected in the third quarter 2016. The ultimate outcome of these matters cannot be determined at this time.

Fuel Cost Recovery

Georgia Power has established fuel cost recovery rates approved by the Georgia PSC. The Georgia PSC approved a reduction in Georgia Power's total annual billings of approximately $567 million effective June 1, 2012, with an additional $122 million reduction effective January 1, 2013 through June 1, 2014. Under an Interim Fuel Rider, Georgia Power continues to be allowed to adjust its fuel cost recovery rates prior to the next fuel case if the under or over recovered fuel balance exceeds $200 million. Georgia Power's fuel cost recovery includes costs associated with a natural gas hedging program, as approved by the Georgia PSC in 2015, allowing it to use an array of derivative instruments within a 48-month time horizon effective January 1, 2016. See Note 11 under "Energy-Related Derivatives" for additional information. On December 15, 2015, the Georgia PSC approved Georgia Power's request to lower annual billings by approximately $350 million effective January 1, 2016.

Georgia Power's over recovered fuel balance totaled approximately $116 million at December 31, 2015 and is included in current liabilities and other deferred liabilities. At December 31, 2014, Georgia Power's under recovered fuel balance totaled approximately $199 million and was included in current assets and other deferred charges and assets.

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

Storm Damage Recovery

Georgia Power defers and recovers certain costs related to damages from major storms as mandated by the Georgia PSC. Beginning January 1, 2014, Georgia Power is accruing $30 million annually under the 2013 ARP that is recoverable through base rates. As of December 31, 2015 and December 31, 2014, the balance in the regulatory asset related to storm damage was $92 million and $98 million, respectively, with approximately $30 million included in other regulatory assets, current for both years and approximately $62 million and $68 million included in other regulatory assets, deferred, respectively. Georgia Power expects the Georgia PSC to periodically review and adjust, if necessary, the amounts collected in rates for storm damage costs. As a result of the regulatory treatment, costs related to storms are generally not expected to have a material impact on Southern Company's financial statements.

Nuclear Construction

In 2008, Georgia Power, acting for itself and as agent for Oglethorpe Power Corporation (OPC), the Municipal Electric Authority of Georgia (MEAG Power), and the City of Dalton, Georgia (Dalton), acting by and through its Board of Water, Light, and Sinking Fund Commissioners, doing business as Dalton Utilities (collectively, Vogtle Owners), entered into an agreement with a consortium consisting of Westinghouse Electric Company LLC (Westinghouse) and Stone & Webster, Inc., a subsidiary of The Shaw Group Inc., which was acquired by Chicago Bridge & Iron Company N.V. (CB&I) (Westinghouse and Stone & Webster, Inc., collectively, Contractor), pursuant to which the Contractor agreed to design, engineer, procure, construct, and test two AP1000 nuclear units (with electric generating capacity of approximately 1,100 MWs each) and related facilities at Plant Vogtle (Vogtle 3 and 4 Agreement).

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

On December 31, 2015, Westinghouse acquired Stone & Webster, Inc. from CB&I (Acquisition). In connection with the Acquisition, Stone & Webster, Inc. changed its name to WECTEC Global Project Services Inc. (WECTEC). Certain obligations of Westinghouse and Stone & Webster, Inc. have been guaranteed by Toshiba Corporation, Westinghouse's parent company, and CB&I's The Shaw Group Inc., respectively. Subject to the consent of the DOE, in connection with the Acquisition and pursuant to the settlement agreement described below, the guarantee of The Shaw Group Inc. will be terminated. The guarantee of Toshiba Corporation remains in place. In the event of certain credit rating downgrades of any Vogtle Owner, such Vogtle Owner will be required to provide a letter of credit or other credit enhancement. Additionally, on January 13, 2016, as a result of recent credit rating downgrades of Toshiba Corporation, Westinghouse provided the Vogtle Owners with letters of credit in an aggregate amount of $900 million in accordance with, and subject to adjustment under, the terms of the Vogtle 3 and 4 Agreement.

The Vogtle Owners may terminate the Vogtle 3 and 4 Agreement at any time for their convenience, provided that the Vogtle Owners will be required to pay certain termination costs. The Contractor may terminate the Vogtle 3 and 4 Agreement under certain circumstances, including certain Vogtle Owner suspension or delays of work, action by a governmental authority to permanently stop work, certain breaches of the Vogtle 3 and 4 Agreement by the Vogtle Owners, Vogtle Owner insolvency, and certain other events.

In 2009, the NRC issued an Early Site Permit and Limited Work Authorization which allowed limited work 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, in late 2011, and issued combined construction and operating licenses (COLs) in early 2012. Receipt of the COLs allowed full construction to begin. There have been technical and procedural challenges to the construction and licensing of Plant Vogtle Units 3 and 4, at the federal and state level, and additional challenges may arise as construction proceeds.

In 2009, the Georgia PSC voted to certify construction of Plant Vogtle Units 3 and 4. In addition, 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 the NCCR tariff by including the related CWIP accounts in rate base during the construction period. The Georgia PSC approved an initial NCCR tariff of approximately $223 million effective January 1, 2011, as well as increases to the NCCR tariff of approximately $35 million, $50 million, $60 million, $27 million, and $19 million effective January 1, 2012, 2013, 2014, 2015, and 2016, respectively.

Georgia Power is required to file semi-annual Vogtle Construction Monitoring (VCM) reports with the Georgia PSC by February 28 and August 31 each year. If the projected construction capital costs to be borne by Georgia Power increase by 5% above the certified cost or the projected in-service dates are significantly extended, Georgia Power is required to seek an amendment to the Plant Vogtle Units 3 and 4 certificate from the Georgia PSC. In February 2013, Georgia Power requested an amendment to the certificate to increase the estimated in-service capital cost of Plant Vogtle Units 3 and 4 from $4.4 billion to $4.8 billion and to extend the estimated in-service dates to the fourth quarter 2017 (from April 2016) and the fourth quarter 2018 (from April 2017) for Plant Vogtle Units 3 and 4, respectively. In October 2013, the Georgia PSC approved a stipulation (2013 Stipulation) between Georgia Power and the Georgia PSC Staff (Staff) to waive the requirement to amend the Plant Vogtle Units 3 and 4 certificate until the completion of Plant Vogtle Unit 3 or earlier if deemed appropriate by the Georgia PSC and Georgia Power.

On April 15, 2015, the Georgia PSC issued a procedural order in connection with the twelfth VCM report, which included a requested amendment (Requested Amendment) to the Plant Vogtle Units 3 and 4 certificate to reflect the Contractor's revised forecast for completion of Plant Vogtle Units 3 and 4 (second quarter of 2019 and second quarter of 2020, respectively) as well as additional estimated Vogtle Owner's costs, of approximately $10 million per month, including property taxes, oversight costs, compliance costs, and other operational readiness costs to include the estimated Vogtle Owner's costs associated with the proposed 18-month Contractor delay and to increase the estimated total in-service capital cost of Plant Vogtle Units 3 and 4 to $5.0 billion. Pursuant to the Georgia PSC's procedural order, the Georgia PSC deemed the Requested Amendment unnecessary and withdrawn until the completion of construction of Plant Vogtle Unit 3 consistent with the 2013 Stipulation. The Georgia PSC recognized that the certified cost and the 2013 Stipulation do not constitute a cost recovery cap. In accordance with the Georgia Integrated Resource Planning Act, any costs incurred by Georgia Power in excess of the certified amount will be included in rate base, provided Georgia Power shows the costs to be reasonable and prudent. Financing costs up to the certified amount will be collected through the NCCR tariff until the units are placed in service and contemplated in a general base rate case, while financing costs on any construction-related costs in excess of the $4.4 billion certified amount are expected to be recovered through AFUDC.

In 2012, the Vogtle Owners and the Contractor commenced litigation regarding the costs associated with design changes to the DCD and the delays in the timing of approval of the DCD and issuance of the COLs, including the assertion by the Contractor that the Vogtle Owners are responsible for these costs under the terms of the Vogtle 3 and 4 Agreement. The Contractor also asserted that it was entitled to extensions of the guaranteed substantial completion dates of April 2016 and April 2017 for Plant Vogtle Units 3 and 4, respectively. In May 2014, the Contractor filed an amended claim alleging that (i) the design changes to the DCD imposed by the NRC delayed module production and the impacts to the Contractor are recoverable by the Contractor under the Vogtle 3 and 4 Agreement and (ii) the changes to the basemat rebar design required by the NRC caused additional costs and delays recoverable by the Contractor under the Vogtle 3 and 4 Agreement. In June 2015, the Contractor updated its estimated damages to an aggregate (based on Georgia Power's ownership interest) of approximately $714 million (in 2015 dollars). The case was pending in the U.S. District Court for the Southern District of Georgia (Vogtle Construction Litigation).

On December 31, 2015, Westinghouse and the Vogtle Owners entered into a definitive settlement agreement (Contractor Settlement Agreement) to resolve disputes between the Vogtle Owners and the Contractor under the Vogtle 3 and 4 Agreement, including the Vogtle Construction Litigation. Effective December 31, 2015, Georgia Power, acting for itself and as agent for the other Vogtle Owners, and the Contractor entered into an amendment to the Vogtle 3 and 4 Agreement to implement the Contractor Settlement Agreement. The Contractor Settlement Agreement and the related amendment to the Vogtle 3 and 4 Agreement (i) restrict the Contractor's ability to seek further increases in the contract price by clarifying and limiting the circumstances that constitute nuclear regulatory changes in law; (ii) provide for enhanced dispute resolution procedures; (iii) revise the guaranteed substantial completion dates to match the current estimated in-service dates of June 30, 2019 for Unit 3 and June 30, 2020 for Unit 4; (iv) provide that delay liquidated damages will now commence from the current estimated nuclear fuel loading date for each unit, which is December 31, 2018 for Unit 3 and December 31, 2019 for Unit 4, rather than the original guaranteed substantial completion dates under the Vogtle 3 and 4 Agreement; and (v) provide that Georgia Power, based on its ownership interest, will pay to the Contractor and capitalize to the project cost approximately $350 million, of which approximately $120 million has been paid previously under the dispute resolution procedures of the Vogtle 3 and 4 Agreement. Further, subsequent to December 31, 2015, Georgia Power paid approximately $121 million under the terms of the Contractor Settlement Agreement. In addition, the Contractor Settlement Agreement provides for the resolution of other open existing items relating to the scope of the project under the Vogtle 3 and 4 Agreement, including cyber security, for which costs were reflected in Georgia Power's previously disclosed in-service cost estimate. Further, as part of the settlement and in connection with the Acquisition: (i) Westinghouse has engaged Fluor Enterprises, Inc., a subsidiary of Fluor Corporation, as a new construction subcontractor; and (ii) the Vogtle Owners, CB&I, and The Shaw Group Inc. have entered into mutual releases of any and all claims arising out of events or circumstances in connection with the construction of Plant Vogtle Units 3 and 4 that occurred on or before the date of the Contractor Settlement Agreement. On January 5, 2016, the Vogtle Construction Litigation was dismissed with prejudice.

On January 21, 2016, Georgia Power submitted the Contractor Settlement Agreement and the related amendment to the Vogtle 3 and 4 Agreement to the Georgia PSC for its review. On February 2, 2016, the Georgia PSC ordered Georgia Power to file supplemental information by April 5, 2016 in support of the Contractor Settlement Agreement and Georgia Power's position that all construction costs to date have been prudently incurred and that the current estimated in-service capital cost and schedule are reasonable. Following Georgia Power's filing under the order, the Staff will conduct a review of all costs incurred related to Plant Vogtle Units 3 and 4, the schedule for completion of Plant Vogtle Units 3 and 4, and the Contractor Settlement Agreement and the Staff is authorized to engage in related settlement discussions with Georgia Power and any intervenors.

The order provides that the Staff is required to report to the Georgia PSC by October 5, 2016 with respect to the status of its review and any settlement-related negotiations. If a settlement with the Staff is reached with respect to costs of Plant Vogtle Units 3 and 4, the Georgia PSC will then conduct a hearing to consider whether to approve that settlement. If a settlement with the Staff is not reached, the Georgia PSC will determine how to proceed, including (i) modifying the 2013 Stipulation, (ii) directing Georgia Power to file a request for an amendment to the certificate for Plant Vogtle Units 3 and 4, (iii) issuing a scheduling order to address remaining disputed issues, or (iv) taking any other option within its authority.

The Georgia PSC has approved thirteen VCM reports covering the periods through June 30, 2015, including construction capital costs incurred, which through that date totaled $3.1 billion. On February 26, 2016, Georgia Power filed its fourteenth VCM report with the Georgia PSC covering the period from July 1 through December 31, 2015. The fourteenth VCM report does not include a requested amendment to the certified cost of Plant Vogtle Units 3 and 4. Georgia Power is requesting approval of $160 million of construction capital costs incurred during that period. Georgia Power anticipates to incur average financing costs of approximately $27 million per month from January 2016 until Plant Vogtle Units 3 and 4 are placed in service. The updated in-service capital cost forecast is $5.44 billion and includes costs related to the Contractor Settlement Agreement. Estimated financing costs during the construction period total approximately $2.4 billion. Georgia Power's CWIP balance for Plant Vogtle Units 3 and 4 was approximately $3.6 billion as of December 31, 2015.

Processes are in place that are designed to assure compliance with the requirements specified in the DCD and the COLs, including inspections by Southern Nuclear and the NRC that occur throughout construction. As a result of such compliance processes, certain license amendment requests have been filed and approved or are pending before the NRC. Various design and other licensing-based compliance issues may arise as construction proceeds, which may result in additional license amendments or require other resolution. If any license amendment requests or other licensing-based compliance issues are not resolved in a timely manner, there may be delays in the project schedule that could result in increased costs either to the Vogtle Owners or the Contractor or to both.

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

Future claims by the Contractor or Georgia Power (on behalf of the Vogtle Owners) could arise throughout construction. These claims may be resolved through formal and informal dispute resolution procedures under the Vogtle 3 and 4 Agreement and, under the enhanced dispute resolution procedures, may be resolved through litigation after the completion of nuclear fuel load for both units.

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

Gulf Power

Retail Base Rate Case

In 2013, the Florida PSC voted to approve a settlement agreement among Gulf Power and all of the intervenors to Gulf Power's retail base rate case (Gulf Power Settlement Agreement). Under the terms of the Gulf Power Settlement Agreement, Gulf Power (1) increased base rates approximately $35 million annually effective January 2014 and subsequently increased base rates approximately $20 million annually effective January 2015; (2) continued its current authorized retail ROE midpoint (10.25%) and range (9.25% – 11.25%); and (3) is accruing a return similar to AFUDC on certain transmission system upgrades placed into service after January 2014 until Gulf Power's next base rate adjustment date or January 1, 2017, whichever comes first.

The Gulf Power Settlement Agreement also includes a self-executing adjustment mechanism that will increase the authorized retail ROE midpoint and range by 25 basis points in the event the 30-year treasury yield rate increases by an average of at least 75 basis points above 3.7947% for a consecutive six-month period.

The Gulf Power Settlement Agreement also provides that Gulf Power may reduce depreciation expense and record a regulatory asset that will be included as an offset to the other cost of removal regulatory liability in an aggregate amount up to $62.5 million between January 2014 and June 2017. In any given month, such depreciation expense reduction may not exceed the amount necessary for the retail ROE, as reported to the Florida PSC monthly, to reach the midpoint of the authorized retail ROE range then in effect. Recovery of the regulatory asset will occur over a period to be determined by the Florida PSC in Gulf Power's next base rate case or next depreciation and dismantlement study proceeding, whichever comes first. For 2015 and 2014, Gulf Power recognized reductions in depreciation expense of $20.1 million and $8.4 million, respectively.

Pursuant to the Gulf Power Settlement Agreement, Gulf Power may not request an increase in its retail base rates to be effective until after June 2017, unless Gulf Power's actual retail ROE falls below the authorized ROE range.

Integrated Coal Gasification Combined Cycle

Kemper IGCC Overview

Construction of Mississippi Power's Kemper IGCC is nearing completion and start-up activities will continue until the Kemper IGCC is placed in service. The Kemper IGCC will utilize an IGCC technology with an output capacity of 582 MWs. The Kemper IGCC will be fueled by locally mined lignite (an abundant, lower heating value coal) from a mine owned by Mississippi Power and situated adjacent to the Kemper IGCC. The mine, operated by North American Coal Corporation, started commercial operation in 2013. In connection with the Kemper IGCC, Mississippi Power constructed and plans to operate approximately 61 miles of CO₂ pipeline infrastructure for the planned transport of captured CO₂ for use in enhanced oil recovery.

Kemper IGCC Schedule and Cost Estimate

In 2012, the Mississippi PSC issued the 2012 MPSC CPCN Order, a detailed order confirming the CPCN originally approved by the Mississippi PSC in 2010 authorizing the acquisition, construction, and operation of the Kemper IGCC. The certificated cost estimate of the Kemper IGCC included in the 2012 MPSC CPCN Order was $2.4 billion, net of $245 million of grants awarded to the Kemper IGCC project by the DOE under the Clean Coal Power Initiative Round 2 (DOE Grants) and excluding the cost of the lignite mine and equipment, the cost of the CO₂ pipeline facilities, and AFUDC related to the Kemper IGCC. The 2012 MPSC CPCN Order approved a construction cost cap of up to $2.88 billion, with recovery of prudently-incurred costs subject to approval by the Mississippi PSC. The Kemper IGCC was originally projected to be placed in service in May 2014. Mississippi Power placed the combined cycle and the associated common facilities portion of the Kemper IGCC in service using natural gas in August 2014 and currently expects to place the remainder of the Kemper IGCC, including the gasifier and the gas clean-up facilities, in service during the third quarter 2016.

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

Cost Category	2010 Project Estimate(f)		Current Cost Estimate(a)		Actual Costs
	(in billions)
Plant Subject to Cost Cap(b)(g)	$	2.40	$	5.29	$	4.83
Lignite Mine and Equipment	0.21		0.23		0.23
CO2 Pipeline Facilities	0.14		0.11		0.11
AFUDC(c)	0.17		0.69		0.59
Combined Cycle and Related Assets Placed in Service – Incremental(d)(g)	—		0.01		0.01
General Exceptions	0.05		0.10		0.09
Deferred Costs(e)(g)	—		0.20		0.17
Total Kemper IGCC	$	2.97	$	6.63	$	6.03

(a) Amounts in the Current Cost Estimate reflect estimated costs through August 31, 2016.

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

(c) Mississippi Power's original estimate included recovery of financing costs during construction rather than the accrual of AFUDC. This approach was not approved by the Mississippi PSC in 2012 as described in "Rate Recovery of Kemper IGCC Costs." The current estimate reflects the impact of a settlement agreement with the wholesale customers for cost-based rates under FERC's jurisdiction.

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

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

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

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

Of the total costs, including post-in-service costs for the lignite mine, incurred as of December 31, 2015, $3.47 billion was included in property, plant, and equipment (which is net of the DOE Grants and estimated probable losses of $2.41 billion), $2 millionin other property and investments,$69 million in fossil fuel stock, $45 millionin materials and supplies,$21 million in other regulatory assets, current, $195 million in other regulatory assets, deferred, and $11 million in other deferred charges and assets in the balance sheet.

Mississippi Power does not intend to seek rate recovery for any costs related to the construction of the Kemper IGCC that exceed the $2.88 billion cost cap, net of the DOE Grants and excluding the Cost Cap Exceptions. Southern Company recorded pre-tax charges to income for revisions to the cost estimate above the cost cap of $365 million ($226 million after tax), $868 million ($536 million after tax), and $1.2 billion ($729 million after tax) in 2015, 2014, and 2013, respectively. The increases to the cost estimate in 2015 primarily reflect costs for the extension of the Kemper IGCC's projected in-service date through August 31, 2016, increased efforts related to scope modifications, additional labor costs in support of start-up and operational readiness activities, and system repairs and modifications after startup testing and commissioning activities identified necessary remediation of equipment installation, fabrication, and design issues, including the refractory lining inside the gasifiers; the lignite feed and dryer systems; and the syngas cooler vessels. Any extension of the in-service date beyond August 31, 2016 is currently estimated to result in additional base costs of approximately $25 million to $35 millionper month, which includes maintaining necessary levels of start-up labor, materials, and fuel, as well as operational resources required to execute start-up and commissioning activities. However, additional costs may be required for remediation of any further equipment and/or design issues identified. Any extension of the in-service date with respect to the Kemper IGCC beyond August 31, 2016 would also increase costs for the Cost Cap Exceptions, which are not subject to the$2.88 billioncost cap established by the Mississippi PSC. These costs include AFUDC, which is currently estimated to total approximately$13 million per month, as well as carrying costs and operating expenses on Kemper IGCC assets placed in service and consulting and legal fees of approximately $2 millionper month. For additional information, see "2015 Rate Case" herein.

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

Rate Recovery of Kemper IGCC Costs

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

2012 MPSC CPCN Order

The 2012 MPSC CPCN Order included provisions relating to both Mississippi Power's recovery of financing costs during the course of construction of the Kemper IGCC and Mississippi Power's recovery of costs following the date the Kemper IGCC is placed in service. With respect to recovery of costs following the in-service date of the Kemper IGCC, the 2012 MPSC CPCN Order provided for the establishment of operational cost and revenue parameters based upon assumptions in Mississippi Power's petition for the CPCN. Mississippi Power expects the Mississippi PSC to apply operational parameters in connection with future proceedings related to the operation of the Kemper IGCC. To the extent the Mississippi PSC determines the Kemper IGCC does not meet the operational parameters ultimately adopted by the Mississippi PSC or Mississippi Power incurs additional costs to satisfy such parameters, there could be a material adverse impact on the financial statements.

2013 MPSC Rate Order

In January 2013, Mississippi Power entered into a settlement agreement with the Mississippi PSC that was intended to establish the process for resolving matters regarding cost recovery related to the Kemper IGCC (2013 Settlement Agreement). Under the 2013 Settlement Agreement, Mississippi Power agreed to limit the portion of prudently-incurred Kemper IGCC costs to be included in retail rate base to the $2.4 billion certificated cost estimate, plus the Cost Cap Exceptions, but excluding AFUDC, and any other costs permitted or determined to be excluded from the $2.88 billion cost cap by the Mississippi PSC. In March 2013, the Mississippi PSC issued a rate order approving retail rate increases of 15% effective March 19, 2013 and 3% effective January 1, 2014, which collectively were designed to collect $156 million annually beginning in 2014 (2013 MPSC Rate Order) to be used to mitigate customer rate impacts after the Kemper IGCC is placed in service.

Because the 2013 MPSC Rate Order did not provide for the inclusion of CWIP in rate base as permitted by the Baseload Act, Mississippi Power continues to record AFUDC on the Kemper IGCC. Mississippi Power will not record AFUDC on any additional costs of the Kemper IGCC that exceed the $2.88 billion cost cap, except for Cost Cap Exception amounts.

On February 12, 2015, the Court issued its decision in the legal challenge to the 2013 MPSC Rate Order. The Court reversed the 2013 MPSC Rate Order based on, among other things, its findings that (1) the Mirror CWIP rate treatment was not provided for under the Baseload Act and (2) the Mississippi PSC should have determined the prudence of Kemper IGCC costs before approving rate recovery through the 2013 MPSC Rate Order. The Court also found the 2013 Settlement Agreement unenforceable due to a lack of public notice for the related proceedings. On July 7, 2015, the Mississippi PSC ordered that the Mirror CWIP rate be terminated effective July 20, 2015 and required the fourth quarter 2015 refund of the $342 million collected under the 2013 MPSC Rate Order, along with associated carrying costs of $29 million. The Court's decision did not impact the 2012 MPSC CPCN Order or the February 2013 legislation discussed below.

2015 Rate Case

As a result of the 2015 Court decision, on July 10, 2015, Mississippi Power filed a supplemental filing including a request for interim rates (Supplemental Notice) with the Mississippi PSC which presented an alternative rate proposal (In-Service Asset Proposal) for consideration by the Mississippi PSC. The In-Service Asset Proposal was based upon the test period of June 2015 to May 2016, was designed to recover Mississippi Power's costs associated with the Kemper IGCC assets that are commercially operational and currently providing service to customers (the transmission facilities, combined cycle, natural gas pipeline, and water pipeline) and other related costs, and was designed to collect approximately $159 million annually. On August 13, 2015, the Mississippi PSC approved the implementation of interim rates that became effective with the first billing cycle in September, subject to refund and certain other conditions.

On December 3, 2015, the Mississippi PSC issued an order (In-Service Asset Rate Order) adopting in full a stipulation (the 2015 Stipulation) entered into between Mississippi Power and the MPUS regarding the In-Service Asset Proposal. Consistent with the 2015 Stipulation, the In-Service Asset Rate Order provides for retail rate recovery of an annual revenue requirement of approximately $126 million, based on Mississippi Power's actual average capital structure, with a maximum common equity percentage of 49.733%, a 9.225% return on common equity, and actual embedded interest costs during the test period. The In-Service Asset Rate Order also includes a prudence finding of all costs in the stipulated revenue requirement calculation for the in-service assets. The stipulated revenue requirement excludes the costs of the Kemper IGCC related to the 15% undivided interest that was previously projected to be purchased by SMEPA. See "Termination of Proposed Sale of Undivided Interest to SMEPA" herein for additional information.

With implementation of the new rate on December 17, 2015, the interim rates were terminated and Mississippi Power recorded a customer refund of approximately $11 million in December 2015 for the difference between the interim rates collected and the permanent rates. The refund is required to be completed by March 16, 2016.

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

On February 25, 2016, Greenleaf CO2 Solutions, LLC filed a notice of appeal of the In-Service Asset Rate Order with the Court. Mississippi Power believes the appeal has no merit; however, an adverse outcome in this appeal could have a material impact on Southern Company's results of operations. The ultimate outcome of this matter cannot be determined at this time.

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

Mississippi Power expects to seek additional rate relief to address recovery of the remaining Kemper IGCC assets. In addition to current estimated costs at December 31, 2015 of $6.63 billion, Mississippi Power anticipates that it will incur additional costs after the Kemper IGCC in-service date until the Kemper IGCC cost recovery approach is finalized. These costs include, but are not limited to, regulatory costs and additional carrying costs which could be material. Recovery of these costs would be subject to approval by the Mississippi PSC.

Mississippi Power expects the Kemper IGCC to qualify for additional DOE grants included in the recently passed Consolidated Appropriations Act of 2015, which are expected to be used to reduce future rate impacts for customers. The ultimate outcome of this matter cannot be determined at this time.

Regulatory Assets and Liabilities

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

In August 2014, Mississippi Power requested confirmation by the Mississippi PSC of Mississippi Power's authority to defer all operating expenses associated with the operation of the combined cycle subject to review of such costs by the Mississippi PSC. In addition, Mississippi Power is authorized to accrue carrying costs on the unamortized balance of such regulatory assets at a rate and in a manner to be determined by the Mississippi PSC in future cost recovery mechanism proceedings. Beginning in the third quarter 2015, in connection with the implementation of interim rates, Mississippi Power began expensing certain ongoing project costs and certain debt carrying costs (associated with assets placed in service and other non-CWIP accounts) that previously were deferred as regulatory assets and began amortizing certain regulatory assets associated with assets placed in service and consulting and legal fees. The amortization periods for these regulatory assets vary from two years to 10 years as set forth in the In-Service Asset Rate Order. As of December 31, 2015, the balance associated with these regulatory assets was $120 million. Other regulatory assets associated with the remainder of the Kemper IGCC totaled $96 million as of December 31, 2015. The amortization period for these assets is expected to be determined by the Mississippi PSC in future rate proceedings following completion of construction and start-up of the Kemper IGCC and related prudence reviews.

See "2013 MPSC Rate Order" herein for information related to the July 7, 2015 Mississippi PSC order terminating the Mirror CWIP rate and requiring refund of collections under Mirror CWIP.

The In-Service Asset Rate Order requires Mississippi Power to submit an annual true-up calculation of its actual cost of capital, compared to the stipulated total cost of capital, with the first occurring as of May 31, 2016. As of December 31, 2015, Mississippi Power recorded a related regulatory liability of approximately $2 million. See "2015 Rate Case" herein for additional information.

Lignite Mine and CO₂ Pipeline Facilities

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

In 2010, Mississippi Power executed a 40-year management fee contract with Liberty Fuels Company, LLC (Liberty Fuels), a wholly-owned subsidiary of The North American Coal Corporation, which developed, constructed, and is operating and managing the mining operations. The contract with Liberty Fuels is effective through the end of the mine reclamation. As the mining permit holder, Liberty Fuels has a legal obligation to perform mine reclamation and Mississippi Power has a contractual obligation to fund all reclamation activities. In addition to the obligation to fund the reclamation activities, Mississippi Power currently provides working capital support to Liberty Fuels through cash advances for capital purchases, payroll, and other operating expenses.

In addition, Mississippi Power has constructed and will operate the CO₂ pipeline for the planned transport of captured CO₂ for use in enhanced oil recovery. Mississippi Power has entered into agreements with Denbury Onshore (Denbury), a subsidiary of Denbury Resources Inc., and Treetop Midstream Services, LLC (Treetop), an affiliate of Tellus Operating Group, LLC and a subsidiary of Tengrys, LLC, pursuant to which Denbury will purchase 70% of the CO₂ captured from the Kemper IGCC and Treetop will purchase 30% of the CO₂ captured from the Kemper IGCC. The agreements with Denbury and Treetop provide Denbury and Treetop with termination rights as Mississippi Power has not satisfied its contractual obligation to deliver captured CO₂ by May 11, 2015. Since May 11, 2015, Mississippi Power has been engaged in ongoing discussions with its off-takers regarding the status of the CO₂ delivery schedule as well as other issues related to the CO₂ agreements. As a result of discussions with Treetop, on August 3, 2015, Mississippi Power agreed to amend certain provisions of their agreement that do not affect pricing or minimum purchase quantities. Potential requirements imposed on CO₂ off-takers under the Clean Power Plan (if ultimately enacted in its current form, pending resolution of litigation) and the potential adverse financial impact of low oil prices on the off-takers increase the risk that the CO₂ contracts may be terminated or materially modified. Any termination or material modification of these agreements is not expected to have a material impact on Southern Company's revenues. Additionally, if the contracts remain in place, sustained oil price reductions could result in significantly lower revenues than Mississippi Power forecasted to be available to offset customer rate impacts.

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

Termination of Proposed Sale of Undivided Interest to SMEPA

In 2010 and as amended in 2012, Mississippi Power and SMEPA entered into an agreement whereby SMEPA agreed to purchase a 15% undivided interest in the Kemper IGCC. On May 20, 2015, SMEPA notified Mississippi Power that it was terminating the agreement. Mississippi Power had previously received a total of $275 million of deposits from SMEPA that were returned to SMEPA, with interest of approximately $26 million, on June 3, 2015, as a result of the termination by Southern Company, pursuant to its guarantee obligation. Subsequently, Mississippi Power issued a promissory note in the aggregate principal amount of approximately $301 million to Southern Company, which matures December 1, 2017.

The In-Service Asset Proposal and the related rates approved by the Mississippi PSC excluded any costs associated with the 15% undivided interest. Mississippi Power continues to evaluate its alternatives with respect to its investment and the related costs associated with the 15% undivided interest.

Bonus Depreciation

On December 18, 2015, the Protecting Americans from Tax Hikes (PATH) Act was signed into law. Bonus depreciation was extended for qualified property placed in service over the next five years. The PATH Act allows for 50% bonus depreciation for 2015, 2016, and 2017; 40% bonus depreciation for 2018; and 30% bonus depreciation for 2019 and certain long-lived assets placed in service in 2020. The extension of 50% bonus depreciation is expected to result in approximately $3 million of positive cash flows related to the combined cycle and associated common facilities portion of the Kemper IGCC for the 2015 tax year and approximately $360 million for the 2016 tax year, which may not all be realized in 2016 due to a projected NOL on the Company's 2016 income tax return, and is dependent upon placing the remainder of the Kemper IGCC in service in 2016. See "Kemper IGCC Schedule and Cost Estimate" herein for additional information. The ultimate outcome of this matter cannot be determined at this time.

Investment Tax Credits

The IRS allocated $279 million (Phase II) of Internal Revenue Code Section 48A tax credits to Mississippi Power in connection with the Kemper IGCC. These tax credits were dependent upon meeting the IRS certification requirements, including an in-service date no later than April 19, 2016 and the capture and sequestration (via enhanced oil recovery) of at least 65% of the CO₂ produced by the Kemper IGCC during operations in accordance with the Internal Revenue Code. As a result of the schedule extension for the Kemper IGCC, the Phase II tax credits have been recaptured.

Section 174 Research and Experimental Deduction

Southern Company reflected deductions for research and experimental (R&E) expenditures related to the Kemper IGCC in its federal income tax calculations for 2013, 2014, and 2015. In May 2015, Southern Company amended its 2008 through 2013 federal income tax returns to include deductions for Kemper IGCC-related R&E expenditures. Due to the uncertainty related to this tax position, Southern Company had unrecognized tax benefits associated with these R&E deductions totaling approximately $423 million as of December 31, 2015. See "Bonus Depreciation" herein and Note 5 under "Unrecognized Tax Benefits" for additional information. The ultimate outcome of this matter cannot be determined at this time.

Alabama Power [Member]

Loss Contingencies [Line Items]

CONTINGENCIES AND REGULATORY MATTERS

CONTINGENCIES AND REGULATORY MATTERS

General Litigation Matters

The Company is subject to certain claims and legal actions arising in the ordinary course of business. In addition, the Company's business activities are subject to extensive governmental regulation related to public health and the environment, such as regulation of air emissions and water discharges. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements such as air quality and water standards, has occurred throughout the U.S. This litigation has included claims for damages alleged to have been caused by CO₂ and other emissions, CCR, and alleged exposure to hazardous materials, and/or requests for injunctive relief in connection with such matters. The ultimate outcome of such pending or potential litigation against the Company cannot be predicted at this time; however, for current proceedings not specifically reported herein, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on the Company's financial statements.

Environmental Matters

Environmental Remediation

The Company 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 Company could incur substantial costs to clean up affected sites. The Company conducts studies to determine the extent of any required cleanup and has recognized in its financial statements the costs to clean up known sites. Amounts for cleanup and ongoing monitoring costs were not material for any year presented. The Company may be liable for some or all required cleanup costs for additional sites that may require environmental remediation.

Nuclear Fuel Disposal Costs

Acting through the DOE and pursuant to the Nuclear Waste Policy Act of 1982, the U.S. government entered into a contract with the Company that requires the DOE to dispose of spent nuclear fuel and high level radioactive waste generated at Plant Farley beginning no later than January 31, 1998. The DOE has yet to commence the performance of its contractual and statutory obligation to dispose of spent nuclear fuel. Consequently, the Company has pursued and continues to pursue legal remedies against the U.S. government for its partial breach of contract.

In December 2014, the Court of Federal Claims entered a judgment in favor of the Company in its spent nuclear fuel lawsuit seeking damages for the period from January 1, 2005 through December 31, 2010. On March 19, 2015, the Company recovered approximately $26 million. In November 2015, the Company applied the retail-related proceeds to offset the nuclear fuel expense under Rate ECR. See "Retail Regulatory Matters – Nuclear Waste Fund Accounting Order" herein for additional information. In December 2015, the Company credited the wholesale-related proceeds to each wholesale customer.

In March 2014, the Company filed an additional lawsuit against the U.S. government for the costs of continuing to store spent nuclear fuel at Plant Farley for the period from January 1, 2011 through December 31, 2013. The damage period was subsequently extended to December 31, 2014. Damages will continue to accumulate until the issue is resolved or storage is provided. No amounts have been recognized in the financial statements as of December 31, 2015 for any potential recoveries from this lawsuit. The final outcome of this matter cannot be determined at this time; however, no material impact on the Company's net income is expected.

At Plant Farley, on-site dry spent fuel storage facilities are operational and can be expanded to accommodate spent fuel through the expected life of the plant.

FERC Matters

The Company has authority from the FERC to sell electricity at market-based rates. Since 2008, that authority, for certain balancing authority areas, has been conditioned on compliance with the requirements of an energy auction, which the FERC found to be tailored mitigation that addresses potential market power concerns. In accordance with FERC regulations governing such authority, the traditional operating companies (including the Company) and Southern Power filed a triennial market power analysis in June 2014, which included continued reliance on the energy auction as tailored mitigation. On April 27, 2015, the FERC issued an order finding that the traditional operating companies' (including the Company's) and Southern Power's existing tailored mitigation may not effectively mitigate the potential to exert market power in certain areas served by the traditional operating companies and in some adjacent areas. The FERC directed the traditional operating companies (including the Company) and Southern Power to show why market-based rate authority should not be revoked in these areas or to provide a mitigation plan to further address market power concerns. The traditional operating companies (including the Company) and Southern Power filed a request for rehearing on May 27, 2015 and on June 26, 2015 filed their response with the FERC. The ultimate outcome of this matter cannot be determined at this time.

Retail Regulatory Matters

Rate RSE

The Alabama PSC has adopted Rate RSE that provides for periodic annual adjustments based upon the Company's projected weighted cost of equity (WCE) compared to an allowable range. Rate RSE adjustments are based on forward-looking information for the applicable upcoming calendar year. Retail rates remain unchanged when the WCE ranges between 5.75% and 6.21%. Rate RSE adjustments for any two-year period, when averaged together, cannot exceed 4.0% and any annual adjustment is limited to 5.0%. If the Company's actual retail return is above the allowed WCE range, customer refunds will be required; however, there is no provision for additional customer billings should the actual retail return fall below the WCE range.

In 2013, the Alabama PSC approved a revision to Rate RSE, effective for calendar year 2014. This revision established the WCE range of 5.75% to 6.21% with an adjusting point of 5.98% and provided eligibility for a performance-based adder of seven basis points, or 0.07%, to the WCE adjusting point if the Company (i) has an "A" credit rating equivalent with at least one of the recognized rating agencies or (ii) is in the top one-third of a designated customer value benchmark survey.

The Rate RSE increase for 2015 was 3.49% or $181 million annually, and was effective January 1, 2015. On November 30, 2015, the Company made its annual Rate RSE submission to the Alabama PSC of projected data for calendar year 2016. Projected earnings were within the specified WCE range; therefore, retail rates under Rate RSE remained unchanged for 2016.

Rate CNP

The Company's retail rates, approved by the Alabama PSC, provide for adjustments to recognize the placing of new generating facilities into retail service under Rate CNP. The Company may also recover retail costs associated with certificated PPAs under Rate CNP PPA. On March 3, 2015, the Alabama PSC issued a consent order that the Company leave in effect the current Rate CNP PPA factor for billings for the period April 1, 2015 through March 31, 2016. No adjustment to Rate CNP PPA is expected in 2016. As ofDecember 31, 2015, the Company had an under recovered certificated PPA balance of$99 millionwhichis included in deferred under recovered regulatory clause revenues in the balance sheet.

Rate CNP Environmental allowed for the recovery of the Company's retail costs associated with environmental laws, regulations, and other such mandates. On March 3, 2015, the Alabama PSC approved a modification to Rate CNP Environmental to include compliance costs for both environmental and non-environmental mandates. The recoverable non-environmental compliance costs result from laws, regulations, and other mandates directed at the utility industry involving the security, reliability, safety, sustainability, or similar considerations impacting the Company's facilities or operations. This modification to Rate CNP Environmental was effective March 20, 2015 with the revised rate now defined as Rate CNP Compliance. The Company was limited to recover $50 million of non-environmental compliance costs for the year 2015. Additional non-environmental compliance costs were recovered through Rate RSE. Customer rates were not impacted by this order in 2015; therefore, the modification increased the under recovered position for Rate CNP Compliance during 2015. Rate CNP Compliance is based on forward-looking information and provides for the recovery of these costs pursuant to a factor that is calculated annually. Compliance costs to be recovered include operations and maintenance expenses, depreciation, and a return on certain invested capital.

Rate CNP Compliance increased 1.5%, or $75 million annually, effective January 1, 2015. As of December 31, 2015, the Company had an under recovered compliance clause balance of $43 million, which is included in under recovered regulatory clause revenues in the balance sheet.

Rate ECR

The Company has established energy cost recovery rates under the Company's Rate ECR as approved by the Alabama PSC. Rates are based on an estimate of future energy costs and the current over or under recovered balance. Revenues recognized under Rate ECR and recorded on the financial statements are adjusted for the difference in actual recoverable fuel costs and amounts billed in current regulated rates. The difference in the recoverable fuel costs and amounts billed give rise to the over or under recovered amounts recorded as regulatory assets or liabilities. The Company, along with the Alabama PSC, continually monitors the over or under recovered cost balance to determine whether an adjustment to billing rates is required. Changes in the Rate ECR factor have no significant effect on the Company's net income, but will impact operating cash flows. Currently, the Alabama PSC may approve billing rates under Rate ECR of up to 5.910 cents per KWH. In December 2014, the Alabama PSC issued a consent order that the Company leave in effect for 2015 the Rate ECR factor of 2.681 cents per KWH.

On December 1, 2015, the Alabama PSC approved a decrease in the Company’s Rate ECR factor from 2.681 to 2.030 cents per KWH, 6.7%, or $370 million annually, based upon projected billings, effective January 1, 2016. The approved decrease in the Rate ECR factor will have no significant effect on the Company's net income, but will decrease operating cash flows related to fuel cost recovery in 2016 when compared to 2015. The rate will return to 2.681 cents per KWH in 2017 and 5.910 cents per KWH in 2018, absent a further order from the Alabama PSC.

The Company's over recovered fuel costs at December 31, 2015 totaled $238 million as compared to $47 million at December 31, 2014. At December 31, 2015, $238 million is included in other regulatory liabilities, current. The over recovered fuel costs at December 31, 2014 are included in deferred over recovered regulatory clause revenues. 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 recovery or return of fuel costs.

Rate NDR

Based on an order from the Alabama PSC, the Company maintains a reserve for operations and maintenance expenses to cover the cost of damages from major storms to its transmission and distribution facilities. The order approves a separate monthly Rate NDR charge to customers consisting of two components. The first component is intended to establish and maintain a reserve balance for future storms and is an on-going part of customer billing. The second component of the Rate NDR charge is intended to allow recovery of any existing deferred storm-related operations and maintenance costs and any future reserve deficits over a 24-month period. The Alabama PSC order gives the Company authority to record a deficit balance in the NDR when costs of storm damage exceed any established reserve balance. Absent further Alabama PSC approval, the maximum total Rate NDR charge consisting of both components is $10 per month per non-residential customer account and $5 per month per residential customer account. The Company has the authority, based on an order from the Alabama PSC, to accrue certain additional amounts as circumstances warrant. The order allows for reliability-related expenditures to be charged against the additional accruals when the NDR balance exceeds $75 million. The Company may designate a portion of the NDR to reliability-related expenditures as a part of an annual budget process for the following year or during the current year for identified unbudgeted reliability-related expenditures that are incurred. Accruals that have not been designated can be used to offset storm charges. Additional accruals to the NDR will enhance the Company's ability to deal with the financial effects of future natural disasters, promote system reliability, and offset costs retail customers would otherwise bear.

As revenue from the Rate NDR charge is recognized, an equal amount of operations and maintenance expenses related to the NDR will also be recognized. As a result, the Rate NDR charge will not have an effect on net income but will impact operating cash flows.

Environmental Accounting Order

Based on an order from the Alabama PSC, the Company is allowed to establish a regulatory asset to record the unrecovered investment costs, including the unrecovered plant asset balance and the unrecovered costs, associated with site removal and closure associated with future unit retirements caused by environmental regulations. These costs are being amortized and recovered over the affected unit's remaining useful life, as established prior to the decision regarding early retirement through Rate CNP Compliance.

In April 2015, as part of its environmental compliance strategy, the Company retired Plant Gorgas Units 6 and 7 (200 MWs). Additionally, in April 2015, the Company ceased using coal at Plant Barry Units 1 and 2 (250 MWs), but such units will remain available on a limited basis with natural gas as the fuel source. In accordance with the joint stipulation entered in connection with a civil enforcement action by the EPA, the Company retired Plant Barry Unit 3 (225 MWs) in August 2015 and it is no longer available for generation. The Company expects to cease using coal at Plant Greene County Units 1 and 2 (300 MWs) and begin operating those units solely on natural gas by April 2016.

In accordance with this accounting order from the Alabama PSC, the Company transferred the unrecovered plant asset balances to a regulatory asset at their respective retirement dates. The regulatory asset will be amortized and recovered through Rate CNP Compliance over the remaining useful lives, as established prior to the decision for retirement. As a result, these decisions will not have a significant impact on the Company's financial statements.

Nuclear Waste Fund Accounting Order

In 2013, the U.S. District Court for the District of Columbia ordered the DOE to cease collecting spent fuel depositary fees from nuclear power plant operators until such time as the DOE either complies with the Nuclear Waste Policy Act of 1982 or until the U.S. Congress enacts an alternative waste management plan. The DOE formally set the fee to zero effective May 16, 2014.

In August 2014, the Alabama PSC issued an order to provide for the continued recovery from customers of amounts associated with the permanent disposal of nuclear waste from the operation of Plant Farley. In accordance with the order, effective May 16, 2014, the Company was authorized to recover from customers an amount equal to the prior fee and to record the amounts in a regulatory liability account (approximately $14 million annually). On December 1, 2015, the Alabama PSC issued an order for the Company to discontinue recording the amounts recovered from customers in a regulatory liability account and transfer amounts recorded in the regulatory liability to Rate ECR. On December 1, 2015, the Company transferred $20 million from the regulatory liability to Rate ECR to offset fuel expense.

Cost of Removal Accounting Order

In accordance with an accounting order issued in November 2014 by the Alabama PSC, in December 2014, the Company fully amortized the balance of $123 million in certain regulatory asset accounts and offset this amortization expense with the amortization of $120 million of the regulatory liability for other cost of removal obligations. The regulatory asset accounts fully amortized and terminated as of December 31, 2014 represented costs previously deferred under a compliance and pension cost accounting order as well as a non-nuclear outage accounting order, which were approved by the Alabama PSC in 2012 and 2013, respectively. Approximately $95 million of non-nuclear outage costs and $28 million of compliance and pension costs were fully amortized in December 2014.

Georgia Power [Member]

Loss Contingencies [Line Items]

CONTINGENCIES AND REGULATORY MATTERS

CONTINGENCIES AND REGULATORY MATTERS

General Litigation Matters

The Company is subject to certain claims and legal actions arising in the ordinary course of business. In addition, the Company's business activities are subject to extensive governmental regulation related to public health and the environment, such as regulation of air emissions and water discharges. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements such as air quality and water standards, has occurred throughout the U.S. This litigation has included claims for damages alleged to have been caused by CO₂ and other emissions, CCR, and alleged exposure to hazardous materials, and/or requests for injunctive relief in connection with such matters. The ultimate outcome of such pending or potential litigation against the Company cannot be predicted at this time; however, for current proceedings not specifically reported herein, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on the Company's financial statements.

Environmental Matters

Environmental Remediation

The Company 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 Company may also incur substantial costs to clean up affected sites. See Note 1 under "Environmental Remediation Recovery" for additional information.

The Company has been designated or identified as a potentially responsible party (PRP) at sites governed by the Georgia Hazardous Site Response Act and/or by the federal Comprehensive Environmental Response, Compensation, and Liability Act (CERCLA), including a site in Brunswick, Georgia on the CERCLA National Priorities List. The PRPs at the Brunswick site have completed a removal action as ordered by the EPA. Additional response actions at this site are anticipated. In September 2015, the Company entered into an allocation agreement with another PRP, under which that PRP will be responsible (as between the Company and that PRP) for paying and performing certain investigation, assessment, remediation, and other incidental activities at the Brunswick site. Assessment and potential cleanup of other sites are anticipated.

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 Company's regulatory treatment for environmental remediation expenses described in Note 1 under "Environmental Remediation Recovery," these matters are not expected to have a material impact on the Company's financial statements.

Nuclear Fuel Disposal Costs

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

In December 2014, the Court of Federal Claims entered a judgment in favor of the Company in its spent nuclear fuel lawsuit seeking damages for the period from January 1, 2005 through December 31, 2010. On March 19, 2015, the Company recovered approximately $18 million, based on its ownership interests. In March 2015, the Company credited the award to accounts where the original costs were charged and reduced rate base, fuel, and cost of service for the benefit of customers.

In March 2014, the Company filed additional lawsuits against the U.S. government for the costs of continuing to store spent nuclear fuel at Plant Hatch and Plant Vogtle Units 1 and 2 for the period from January 1, 2011 through December 31, 2013. The damage period was subsequently extended to December 31, 2014. Damages will continue to accumulate until the issue is resolved or storage is provided. No amounts have been recognized in the financial statements as of December 31, 2015 for any potential recoveries from the additional lawsuits. The final outcome of these matters cannot be determined at this time; however, no material impact on the Company's net income is expected.

On-site dry spent fuel storage facilities are operational at Plant Vogtle Units 1 and 2 and Plant Hatch. Facilities can be expanded to accommodate spent fuel through the expected life of each plant.

FERC Matters

The Company has authority from the FERC to sell electricity at market-based rates. Since 2008, that authority, for certain balancing authority areas, has been conditioned on compliance with the requirements of an energy auction, which the FERC found to be tailored mitigation that addresses potential market power concerns. In accordance with FERC regulations governing such authority, the traditional operating companies (including the Company) and Southern Power filed a triennial market power analysis in June 2014, which included continued reliance on the energy auction as tailored mitigation. On April 27, 2015, the FERC issued an order finding that the traditional operating companies' (including the Company's) and Southern Power's existing tailored mitigation may not effectively mitigate the potential to exert market power in certain areas served by the traditional operating companies and in some adjacent areas. The FERC directed the traditional operating companies (including the Company) and Southern Power to show why market-based rate authority should not be revoked in these areas or to provide a mitigation plan to further address market power concerns. The traditional operating companies (including the Company) and Southern Power filed a request for rehearing on May 27, 2015 and on June 26, 2015 filed their response with the FERC. The ultimate outcome of this matter cannot be determined at this time.

Retail Regulatory Matters

Rate Plans

In 2013, the Georgia PSC voted to approve the 2013 ARP. The 2013 ARP reflects the settlement agreement among the Company, the Georgia PSC's Public Interest Advocacy Staff, and11 of the 13intervenors.

In January 2014, in accordance with the 2013 ARP, the Company increased its tariffs as follows: (1) traditional base tariff rates by approximately$80 million; (2) ECCR tariff by approximately$25 million; (3) Demand-Side Management (DSM) tariffs by approximately $1 million; and (4) Municipal Franchise Fee (MFF) tariff by approximately$4 million, for a total increase in base revenues of approximately$110 million.

On February 19, 2015, in accordance with the 2013 ARP,the Georgia PSC approved an increase to tariffs effective January 1, 2015as follows: (1) traditional base tariff rates by approximately$107 million; (2) ECCR tariff by approximately $23 million; (3) DSM tariffs by approximately$3 million; and (4) MFF tariff by approximately$3 million, for a total increase in base revenues of approximately$136 million.

On December 16, 2015, in accordance with the 2013 ARP, the Georgia PSC approved an increase to tariffs effective January 1, 2016 as follows: (1) traditional base tariff rates by approximately$49 million; (2) ECCR tariff by approximately$75 million; (3) DSM tariffs by approximately$3 million; and (4) MFF tariff by approximately$13 million, for a total increase in base revenues of approximately $140 million.

Under the 2013 ARP, the Company's retail ROE is set at 10.95% and earnings are evaluated against a retail ROE range of 10.00% to 12.00%. Two-thirds of any earnings above 12.00% will be directly refunded to customers, with the remaining one-third retained by the Company. There will be no recovery of any earnings shortfall below 10.00% on an actual basis. In 2014, the Company's retail ROE exceeded 12.00%, and the Company will refund to retail customers approximately $11 million in 2016, as approved by the Georgia PSC on February 18, 2016. In 2015, the Company's retail ROE was within the allowed retail ROE range.

The Company is required to file a general base rate case by July 1, 2016, in response to which the Georgia PSC would be expected to determine whether the 2013 ARP should be continued, modified, or discontinued.

Integrated Resource Plan

To comply with the April 16, 2015 effective date of the MATS rule, Plant Branch Units 1, 3, and 4 (1,266 MWs), Plant Yates Units 1 through 5 (579 MWs), and Plant McManus Units 1 and 2 (122 MWs) were retired and operations were discontinued at Plant Mitchell Unit 3 (155 MWs) by April 15, 2015, and Plant Kraft Units 1 through 4 (316 MWs) were retired on October 13, 2015. The switch to natural gas as the primary fuel was completed at Plant Yates Units 6 and 7 by June 2015 and at Plant Gaston Units 1 through 4 by December 2015.

In the 2013 ARP, the Georgia PSC approved the amortization of the CWIP balances related to environmental projects that will not be completed at Plant Branch Units 1 through 4 and Plant Yates Units 6 and 7 overnine yearsending December 2022 and the amortization of the remaining net book values of Plant Branch Unit 2 from October 2013 to December 2022, Plant Branch Unit 1 from May 2015 to December 2020, Plant Branch Unit 3 from May 2015 to December 2023, and Plant Branch Unit 4 from May 2015 to December 2024.

On January 29, 2016, the Company filed its triennial IRP (2016 IRP). The filing included a request to decertify Plant Mitchell Units 3, 4A, and 4B (217 MWs) and Plant Kraft Unit 1 (17 MWs) upon approval of the 2016 IRP. The 2016 IRP also reflects that the Company exercised its contractual option to sell its33% ownership interest in the Intercession City unit (143 MWs total capacity) to Duke Energy Florida, Inc. See Note 4 for additional information.

In the 2016 IRP, the Company requested reclassification of the remaining net book value of Plant Mitchell Unit 3, as of its retirement date, to a regulatory asset to be amortized over a period equal to the unit's remaining useful life. The Company also requested that the Georgia PSC approve the deferral of the cost associated with materials and supplies remaining at the unit retirement dates to a regulatory asset, to be amortized over a period deemed appropriate by the Georgia PSC.

The decertification and retirement of these units are not expected to have a material impact on the Company's financial statements; however, the ultimate outcome depends on the Georgia PSC's orders in the 2016 IRP and next general base rate case.

Additionally, the 2016 IRP included a Renewable Energy Development Initiative requesting to procure up to525 MWs of renewable resources utilizing market-based prices established through a competitive bidding process to expand the Company’s existing renewable initiatives, including the Advanced Solar Initiative.

A decision from the Georgia PSC on the 2016 IRP is expected in the third quarter 2016. The ultimate outcome of these matters cannot be determined at this time.

Fuel Cost Recovery

The Company has established fuel cost recovery rates approved by the Georgia PSC. The Georgia PSC approved a reduction in the Company's total annual billings of approximately $567 million effective June 1, 2012, with an additional $122 million reduction effective January 1, 2013 through June 1, 2014. Under an Interim Fuel Rider, the Company continues to be allowed to adjust its fuel cost recovery rates prior to the next fuel case if the under or over recovered fuel balance exceeds $200 million. The Company's fuel cost recovery includes costs associated with a natural gas hedging program, as approved by the Georgia PSC in 2015, allowing it to use an array of derivative instruments within a 48-month time horizon effective January 1, 2016. See Note 11 under "Energy-Related Derivatives" for additional information. On December 15, 2015, the Georgia PSC approved the Company's request to lower annual billings by approximately $350 million effective January 1, 2016.

The Company's over recovered fuel balance totaled approximately $116 million at December 31, 2015 and is included in current liabilities and other deferred liabilities. At December 31, 2014, the Company's under recovered fuel balance totaled approximately $199 million and was included in current assets and other deferred charges and assets.

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

Nuclear Construction

In 2008, the Company, acting for itself and as agent for Oglethorpe Power Corporation (OPC), the Municipal Electric Authority of Georgia (MEAG Power), and the City of Dalton, Georgia (Dalton), acting by and through its Board of Water, Light, and Sinking Fund Commissioners, doing business as Dalton Utilities (collectively, Vogtle Owners), entered into an agreement with a consortium consisting of Westinghouse Electric Company LLC (Westinghouse) and Stone & Webster, Inc., a subsidiary of The Shaw Group Inc., which was acquired by Chicago Bridge & Iron Company N.V. (CB&I) (Westinghouse and Stone & Webster, Inc., collectively, Contractor), pursuant to which the Contractor agreed to design, engineer, procure, construct, and test two AP1000 nuclear units (with electric generating capacity of approximately1,100MWs each) and related facilities at Plant Vogtle (Vogtle 3 and 4 Agreement).

Under the terms of the Vogtle 3 and 4 Agreement, the Vogtle Owners agreed to pay a purchase price that is subject to certain price escalations and adjustments, including fixed escalation amounts and index-based adjustments, as well as adjustments for change orders, and performance bonuses for early completion and unit performance. The Vogtle 3 and 4 Agreement also provides for liquidated damages upon the Contractor's failure to fulfill the schedule and performance guarantees, subject to a cap. In addition, the Vogtle 3 and 4 Agreement provides for limited cost sharing by the Vogtle Owners for Contractor costs under certain conditions (which have not occurred), with maximum additional capital costs under this provision attributable to the Company (based on the Company's ownership interest) of approximately$114 million. Each Vogtle Owner is severally (and not jointly) liable for its proportionate share, based on its ownership interest, of all amounts owed to the Contractor under the Vogtle 3 and 4 Agreement. The Company's proportionate share is45.7%.

On December 31, 2015, Westinghouse acquired Stone & Webster, Inc. from CB&I (Acquisition). In connection with the Acquisition, Stone & Webster, Inc. changed its name to WECTEC Global Project Services Inc. (WECTEC). Certain obligations of Westinghouse and Stone & Webster, Inc. have been guaranteed by Toshiba Corporation, Westinghouse's parent company, and CB&I's The Shaw Group Inc., respectively. Subject to the consent of the DOE, in connection with the Acquisition and pursuant to the settlement agreement described below, the guarantee of The Shaw Group Inc. will be terminated. The guarantee of Toshiba Corporation remains in place. In the event of certain credit rating downgrades of any Vogtle Owner, such Vogtle Owner will be required to provide a letter of credit or other credit enhancement. Additionally, on January 13, 2016, as a result of recent credit rating downgrades of Toshiba Corporation, Westinghouse provided the Vogtle Owners with letters of credit in an aggregate amount of$900 millionin accordance with, and subject to adjustment under, the terms of the Vogtle 3 and 4 Agreement.

The Vogtle Owners may terminate the Vogtle 3 and 4 Agreement at any time for their convenience, provided that the Vogtle Owners will be required to pay certain termination costs. The Contractor may terminate the Vogtle 3 and 4 Agreement under certain circumstances, including certain Vogtle Owner suspension or delays of work, action by a governmental authority to permanently stop work, certain breaches of the Vogtle 3 and 4 Agreement by the Vogtle Owners, Vogtle Owner insolvency, and certain other events.

In 2009, the NRC issued an Early Site Permit and Limited Work Authorization which allowed limited work 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, in late 2011, and issued combined construction and operating licenses (COLs) in early 2012. Receipt of the COLs allowed full construction to begin. There have been technical and procedural challenges to the construction and licensing of Plant Vogtle Units 3 and 4, at the federal and state level, and additional challenges may arise as construction proceeds.

In 2009, the Georgia PSC voted to certify construction of Plant Vogtle Units 3 and 4. In addition, 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 the Company 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 the NCCR tariff by including the related CWIP accounts in rate base during the construction period. The Georgia PSC approved an initial NCCR tariff of approximately $223 millioneffective January 1, 2011, as well as increases to the NCCR tariff of approximately$35 million, $50 million, $60 million, $27 million, and $19 millioneffective January 1, 2012, 2013, 2014, 2015, and 2016, respectively.

The Company is required to file semi-annual Vogtle Construction Monitoring (VCM) reports with the Georgia PSC by February 28 and August 31 each year. If the projected construction capital costs to be borne by the Company increase by5%above the certified cost or the projected in-service dates are significantly extended, the Company is required to seek an amendment to the Plant Vogtle Units 3 and 4 certificate from the Georgia PSC. In February 2013, the Company requested an amendment to the certificate to increase the estimated in-service capital cost of Plant Vogtle Units 3 and 4 from$4.4 billion to$4.8 billionand to extend the estimated in-service dates to the fourth quarter 2017 (from April 2016) and the fourth quarter 2018 (from April 2017) for Plant Vogtle Units 3 and 4, respectively. In October 2013, the Georgia PSC approved a stipulation (2013 Stipulation) between the Company and the Georgia PSC Staff (Staff) to waive the requirement to amend the Plant Vogtle Units 3 and 4 certificate until the completion of Plant Vogtle Unit 3 or earlier if deemed appropriate by the Georgia PSC and the Company.

On April 15, 2015, the Georgia PSC issued a procedural order in connection with the twelfth VCM report, which included a requested amendment (Requested Amendment) to the Plant Vogtle Units 3 and 4 certificate to reflect the Contractor's revised forecast for completion of Plant Vogtle Units 3 and 4 (second quarter of 2019 and second quarter of 2020, respectively) as well as additional estimated Vogtle Owner's costs, of approximately$10 million per month, including property taxes, oversight costs, compliance costs, and other operational readiness costs to include the estimated Vogtle Owner's costs associated with the proposed 18-month Contractor delay and to increase the estimated total in-service capital cost of Plant Vogtle Units 3 and 4 to $5.0 billion. Pursuant to the Georgia PSC's procedural order, the Georgia PSC deemed the Requested Amendment unnecessary and withdrawn until the completion of construction of Plant Vogtle Unit 3 consistent with the 2013 Stipulation. The Georgia PSC recognized that the certified cost and the 2013 Stipulation do not constitute a cost recovery cap. In accordance with the Georgia Integrated Resource Planning Act, any costs incurred by the Company in excess of the certified amount will be included in rate base, provided the Company shows the costs to be reasonable and prudent. Financing costs up to the certified amount will be collected through the NCCR tariff until the units are placed in service and contemplated in a general base rate case, while financing costs on any construction-related costs in excess of the$4.4 billioncertified amount are expected to be recovered through AFUDC.

In 2012, the Vogtle Owners and the Contractor commenced litigation regarding the costs associated with design changes to the DCD and the delays in the timing of approval of the DCD and issuance of the COLs, including the assertion by the Contractor that the Vogtle Owners are responsible for these costs under the terms of the Vogtle 3 and 4 Agreement. The Contractor also asserted that it was entitled to extensions of the guaranteed substantial completion dates of April 2016 and April 2017 for Plant Vogtle Units 3 and 4, respectively. In May 2014, the Contractor filed an amended claim alleging that (i) the design changes to the DCD imposed by the NRC delayed module production and the impacts to the Contractor are recoverable by the Contractor under the Vogtle 3 and 4 Agreement and (ii) the changes to the basemat rebar design required by the NRC caused additional costs and delays recoverable by the Contractor under the Vogtle 3 and 4 Agreement. In June 2015, the Contractor updated its estimated damages to an aggregate (based on the Company's ownership interest) of approximately$714 million(in 2015 dollars). The case was pending in the U.S. District Court for the Southern District of Georgia (Vogtle Construction Litigation).

On December 31, 2015, Westinghouse and the Vogtle Owners entered into a definitive settlement agreement (Contractor Settlement Agreement) to resolve disputes between the Vogtle Owners and the Contractor under the Vogtle 3 and 4 Agreement, including the Vogtle Construction Litigation. Effective December 31, 2015, the Company, acting for itself and as agent for the other Vogtle Owners, and the Contractor entered into an amendment to the Vogtle 3 and 4 Agreement to implement the Contractor Settlement Agreement. The Contractor Settlement Agreement and the related amendment to the Vogtle 3 and 4 Agreement (i) restrict the Contractor's ability to seek further increases in the contract price by clarifying and limiting the circumstances that constitute nuclear regulatory changes in law; (ii) provide for enhanced dispute resolution procedures; (iii) revise the guaranteed substantial completion dates to match the current estimated in-service dates of June 30, 2019 for Unit 3 and June 30, 2020 for Unit 4; (iv) provide that delay liquidated damages will now commence from the current estimated nuclear fuel loading date for each unit, which is December 31, 2018 for Unit 3 and December 31, 2019 for Unit 4, rather than the original guaranteed substantial completion dates under the Vogtle 3 and 4 Agreement; and (v) provide that the Company, based on its ownership interest, will pay to the Contractor and capitalize to the project cost approximately$350 million, of which approximately$120 millionhas been paid previously under the dispute resolution procedures of the Vogtle 3 and 4 Agreement. Further, subsequent to December 31, 2015, the Company paid approximately$121 millionunder the terms of the Contractor Settlement Agreement. In addition, the Contractor Settlement Agreement provides for the resolution of other open existing items relating to the scope of the project under the Vogtle 3 and 4 Agreement, including cyber security,for which costs were reflected in the Company's previously disclosed in-service cost estimate. Further, as part of the settlement and in connection with the Acquisition: (i) Westinghouse has engaged Fluor Enterprises, Inc., a subsidiary of Fluor Corporation, as a new construction subcontractor; and (ii) the Vogtle Owners, CB&I, and The Shaw Group Inc. have entered into mutual releases of any and all claims arising out of events or circumstances in connection with the construction of Plant Vogtle Units 3 and 4 that occurred on or before the date of the Contractor Settlement Agreement. On January 5, 2016, the Vogtle Construction Litigation was dismissed with prejudice.

On January 21, 2016, the Company submitted the Contractor Settlement Agreement and the related amendment to the Vogtle 3 and 4 Agreement to the Georgia PSC for its review. On February 2, 2016, the Georgia PSC ordered the Company to file supplemental information by April 5, 2016 in support of the Contractor Settlement Agreement and the Company's position that all construction costs to date have been prudently incurred and that the current estimated in-service capital cost and schedule are reasonable. Following the Company's filing under the order, the Staff will conduct a review of all costs incurred related to Plant Vogtle Units 3 and 4, the schedule for completion of Plant Vogtle Units 3 and 4, and the Contractor Settlement Agreement and the Staff is authorized to engage in related settlement discussions with the Company and any intervenors.

The order provides that the Staff is required to report to the Georgia PSC by October 5, 2016 with respect to the status of its review and any settlement-related negotiations. If a settlement with the Staff is reached with respect to costs of Plant Vogtle Units 3 and 4, the Georgia PSC will then conduct a hearing to consider whether to approve that settlement. If a settlement with the Staff is not reached, the Georgia PSC will determine how to proceed, including (i) modifying the 2013 Stipulation, (ii) directing the Company to file a request for an amendment to the certificate for Plant Vogtle Units 3 and 4, (iii) issuing a scheduling order to address remaining disputed issues, or (iv) taking any other option within its authority.

The Georgia PSC has approved thirteen VCM reports covering the periods through June 30, 2015, including construction capital costs incurred, which through that date totaled$3.1 billion. On February 26, 2016, the Company filed its fourteenth VCM report with the Georgia PSC covering the period from July 1 through December 31, 2015.The fourteenth VCM report does not include a requested amendment to the certified cost of Plant Vogtle Units 3 and 4. The Company is requesting approval of$160 million of construction capital costs incurred during that period. The Company anticipates to incur average financing costs of approximately$27 millionper month from January 2016 until Plant Vogtle Units 3 and 4 are placed in service. The updated in-service capital cost forecast is $5.44 billion and includes costs related to the Contractor Settlement Agreement. Estimated financing costs during the construction period total approximately $2.4 billion. The Company's CWIP balance for Plant Vogtle Units 3 and 4 was approximately $3.6 billion as of December 31, 2015.

Processes are in place that are designed to assure compliance with the requirements specified in the DCD and the COLs, including inspections by Southern Nuclear and the NRC that occur throughout construction. As a result of such compliance processes, certain license amendment requests have been filed and approved or are pending before the NRC. Various design and other licensing-based compliance issues may arise as construction proceeds, which may result in additional license amendments or require other resolution. If any license amendment requests or other licensing-based compliance issues are not resolved in a timely manner, there may be delays in the project schedule that could result in increased costs either to the Vogtle Owners or the Contractor or to both.

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

Future claims by the Contractor or the Company (on behalf of the Vogtle Owners) could arise throughout construction. These claims may be resolved through formal and informal dispute resolution procedures under the Vogtle 3 and 4 Agreement and, under the enhanced dispute resolution procedures, may be resolved through litigation after the completion of nuclear fuel load for both units.

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

Gulf Power [Member]

Loss Contingencies [Line Items]

CONTINGENCIES AND REGULATORY MATTERS

CONTINGENCIES AND REGULATORY MATTERS

General Litigation Matters

The Company is subject to certain claims and legal actions arising in the ordinary course of business. In addition, the Company's business activities are subject to extensive governmental regulation related to public health and the environment, such as regulation of air emissions and water discharges. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements such as air quality and water standards, has occurred throughout the U.S. This litigation has included claims for damages alleged to have been caused by CO₂ and other emissions, CCR, and alleged exposure to hazardous materials, and/or requests for injunctive relief in connection with such matters. The ultimate outcome of such pending or potential litigation against the Company cannot be predicted at this time; however, for current proceedings not specifically reported herein, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on the Company's financial statements.

Environmental Matters

Environmental Remediation

The Company 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 Company may also incur substantial costs to clean up affected sites. The Company received authority from the Florida PSC to recover approved environmental compliance costs through the environmental cost recovery clause. The Florida PSC reviews costs and adjusts rates up or down annually.

The Company recognizes a liability for environmental remediation costs only when it determines a loss is probable. At December 31, 2015, the Company's environmental remediation liability included estimated costs of environmental remediation projects of approximately $46 million, of which approximately $4 million is included in under recovered regulatory clause revenues and other current liabilities and approximately $42 million is included in other regulatory assets, deferred and other deferred credits and liabilities. These estimated costs relate to site closure criteria by the Florida Department of Environmental Protection (FDEP) for potential impacts to soil and groundwater from herbicide applications at the Company's 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 the Company's environmental cost recovery clause; therefore, these liabilities have no impact on net income.

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, the Company does not believe that additional liabilities, if any, at these sites would be material to the Company's financial statements.

FERC Matters

The Company has authority from the FERC to sell electricity at market-based rates. Since 2008, that authority, for certain balancing authority areas, has been conditioned on compliance with the requirements of an energy auction, which the FERC found to be tailored mitigation that addresses potential market power concerns. In accordance with FERC regulations governing such authority, the traditional operating companies (including the Company) and Southern Power filed a triennial market power analysis in June 2014, which included continued reliance on the energy auction as tailored mitigation. On April 27, 2015, the FERC issued an order finding that the traditional operating companies' (including the Company's) and Southern Power's existing tailored mitigation may not effectively mitigate the potential to exert market power in certain areas served by the traditional operating companies and in some adjacent areas. The FERC directed the traditional operating companies (including the Company) and Southern Power to show why market-based rate authority should not be revoked in these areas or to provide a mitigation plan to further address market power concerns. The traditional operating companies (including the Company) and Southern Power filed a request for rehearing on May 27, 2015 and on June 26, 2015 filed their response with the FERC. The ultimate outcome of this matter cannot be determined at this time.

Retail Regulatory Matters

The Company's rates and charges for service to retail customers are subject to the regulatory oversight of the Florida PSC. The Company's rates are a combination of base rates and several separate cost recovery clauses for specific categories of costs. These separate cost recovery clauses address such items as fuel and purchased energy costs, purchased power capacity costs, energy conservation and demand side management programs, and the costs of compliance with environmental laws and regulations. Costs not addressed through one of the specific cost recovery clauses are recovered through the Company's base rates.

Retail Base Rate Case

In 2013, the Florida PSC voted to approve the 2013 Rate Case Settlement Agreement among the Company and all of the intervenors to the Company's retail base rate case. Under the terms of the 2013 Rate Case Settlement Agreement, the Company (1) increased base rates approximately $35 million annually effective January 2014 and subsequently increased base rates approximately $20 million annually effective January 2015; (2) continued its current authorized retail ROE midpoint (10.25%) and range (9.25% – 11.25%); and (3) is accruing a return similar to AFUDC on certain transmission system upgrades placed into service after January 2014 until the next base rate adjustment date or January 1, 2017, whichever comes first.

The 2013 Rate Case Settlement Agreement also includes a self-executing adjustment mechanism that will increase the authorized retail ROE midpoint and range by 25 basis points in the event the 30-year treasury yield rate increases by an average of at least 75 basis points above 3.7947% for a consecutive six-month period.

The 2013 Rate Case Settlement Agreement also provides that the Company may reduce depreciation expense and record a regulatory asset that will be included as an offset to the other cost of removal regulatory liability in an aggregate amount up to $62.5 million between January 2014 and June 2017. In any given month, such depreciation expense reduction may not exceed the amount necessary for the retail ROE, as reported to the Florida PSC monthly, to reach the midpoint of the authorized retail ROE range then in effect. Recovery of the regulatory asset will occur over a period to be determined by the Florida PSC in the Company's next base rate case or next depreciation and dismantlement study proceeding, whichever comes first. For 2015 and 2014, the Company recognized reductions in depreciation expense of $20.1 million and $8.4 million, respectively.

Pursuant to the 2013 Rate Case Settlement Agreement, the Company may not request an increase in its retail base rates to be effective until after June 2017, unless the Company's actual retail ROE falls below the authorized ROE range.

Cost Recovery Clauses

On November 2, 2015, the Florida PSC approved the Company's annual rate clause request for its fuel, purchased power capacity, environmental, and energy conservation cost recovery factors for 2016. The net effect of the approved changes is an expected $49 million decrease in annual revenue for 2016. The decreased revenues will not have a significant impact on net income since most of the revenues will be offset by lower expenses.

Revenues for all cost recovery clauses, as recorded on the financial statements, are adjusted for differences in actual recoverable costs and amounts billed in current regulated rates. Accordingly, changes in the billing factor for fuel and purchased power will have no significant effect on the Company's revenues or net income, but will affect annual cash flow. The recovery provisions for environmental compliance and energy conservation include related expenses and a return on net average investment.

Retail Fuel Cost Recovery

The Company has established fuel cost recovery rates as approved by the Florida PSC. If, at any time during the year, the projected year-end fuel cost over or under recovery balance exceeds 10% of the projected fuel revenue applicable for the period, the Company is required to notify the Florida PSC and indicate if an adjustment to the fuel cost recovery factor is being requested.

At December 31, 2015, the over recovered fuel balance was approximately $18 million, which is included in other regulatory liabilities, current in the balance sheets. At December 31, 2014, the under recovered fuel balance was approximately $40 million, which is included in under recovered regulatory clause revenues in the balance sheets.

Purchased Power Capacity Recovery

The Company has established purchased power capacity recovery cost rates as approved by the Florida PSC. If the projected year-end purchased power capacity cost over or under recovery balance exceeds 10% of the projected purchased power capacity revenue applicable for the period, the Company is required to notify the Florida PSC and indicate if an adjustment to the purchased power capacity cost recovery factor is being requested.

At December 31, 2015 and 2014, the under recovered purchased power capacity balance was immaterial.

Environmental Cost Recovery

The Florida Legislature adopted legislation for an environmental cost recovery clause, which allows an electric utility to petition the Florida PSC for recovery of prudent environmental compliance costs that are not being recovered through base rates or any other recovery mechanism. Such environmental costs include operations and maintenance expenses, emissions allowance expense, depreciation, and a return on net average investment. This legislation also allows recovery of costs incurred as a result of an agreement between the Company and the FDEP for the purpose of ensuring compliance with ozone ambient air quality standards adopted by the EPA.

In 2007, the Florida PSC voted to approve a stipulation among the Company, the Office of Public Counsel, and the Florida Industrial Power Users Group regarding the Company's plan for complying with certain federal and state regulations addressing air quality. The Company's environmental compliance plan as filed in 2007 contemplated implementation of specific projects identified in the plan from 2007 through 2018. The Florida PSC's approval of the stipulation also required the Company to file annual updates to the plan and outlined a process for approval of additional elements in the plan when they became committed projects. In the 2010 update filing, the Company identified several elements of the updated plan that the Company had decided to implement. Following the process outlined in the original approved stipulation, these additional projects were approved by the Florida PSC later in 2010. The Florida PSC acknowledged that the costs of the approved projects associated with the Company's Clean Air Interstate Rule and Clean Air Visibility Rule compliance plans are eligible for recovery through the environmental cost recovery clause.

Annually, the Company seeks recovery of projected costs including any true-up amounts from prior periods. At December 31, 2015, the under recovered environmental balance was immaterial. At December 31, 2014, the under recovered environmental balance was approximately $10 million, which is included in under recovered regulatory clause revenues in the balance sheets.

In 2012, the Mississippi PSC approved Mississippi Power's request for a certificate of public convenience and necessity to construct scrubbers on Plant Daniel Units 1 and 2, which were placed in service in November 2015. These units are jointly owned by Mississippi Power and the Company, with 50% ownership each. The total cost of the project was approximately $653 million, with the Company's portion being approximately $316 million, excluding AFUDC. The Company's portion of the cost is being recovered through the environmental cost recovery clause.

Energy Conservation Cost Recovery

Every five years, the Florida PSC establishes new numeric conservation goals covering a 10-year period for utilities to reduce annual energy and seasonal peak demand using demand-side management (DSM) programs. After the goals are established, utilities develop plans and programs to meet the approved goals. The costs for these programs are recovered through rates established annually in the energy conservation cost recovery (ECCR) clause.

At December 31, 2015, the over recovered ECCR balance was approximately $4 million, which is included in other regulatory liabilities, current in the balance sheet. At December 31, 2014, the under recovered ECCR balance was approximately $3 million, which is included in under recovered regulatory clause revenues in the balance sheet.

Mississippi Power [Member]

Loss Contingencies [Line Items]

CONTINGENCIES AND REGULATORY MATTERS

CONTINGENCIES AND REGULATORY MATTERS

General Litigation Matters

The Company is subject to certain claims and legal actions arising in the ordinary course of business. In addition, the Company's business activities are subject to extensive governmental regulation related to public health and the environment, such as regulation of air emissions and water discharges. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements such as air quality and water standards, has occurred throughout the U.S. This litigation has included claims for damages alleged to have been caused by CO₂ and other emissions, CCR, and alleged exposure to hazardous materials, and/or requests for injunctive relief in connection with such matters. The ultimate outcome of such pending or potential litigation against the Company cannot be predicted at this time; however, for current proceedings not specifically reported herein, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on the Company's financial statements.

Environmental Matters

Environmental Remediation

The Company 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 Company may also incur substantial costs to clean up affected sites. The Company has authority from the Mississippi PSC to recover approved environmental compliance costs through regulatory mechanisms.

FERC Matters

Municipal and Rural Associations Tariff

In 2012, the Company entered into a settlement agreement with its wholesale customers with respect to the Company's request for revised rates under the wholesale cost-based electric tariff. The settlement agreement provided that base rates under the cost-based electric tariff increase by approximately $23 million over a 12-month period with revised rates effective April 1, 2012. A significant portion of the difference between the requested base rate increase and the agreed upon rate increase was due to a change in the recovery methodology for the return on the Kemper IGCC CWIP. Under the settlement agreement, a portion of CWIP will continue to accrue AFUDC. The tariff customers specifically agreed to the same regulatory treatment for tariff ratemaking as the treatment approved for retail ratemaking by the Mississippi PSC with respect to (i) the accounting for Kemper IGCC-related costs that cannot be capitalized, (ii) the accounting for the lease termination and purchase of Plant Daniel Units 3 and 4, and (iii) the establishment of a regulatory asset for certain potential plant retirement costs.

Also in 2012, the FERC approved a motion to place interim rates into effect beginning in May 2012. Later in 2012, the Company, with its wholesale customers, filed a final settlement agreement with the FERC. In 2013, the Company received an order from the FERC accepting the settlement agreement.

In 2013, the Company 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 in 2013. The 2013 settlement agreement provided that base rates under the MRA cost-based electric tariff will increase by approximately $24 million annually, effective April 1, 2013.

In March 2014, the Company reached a settlement agreement with its wholesale customers and filed a request with the FERC for an increase in the MRA cost-based electric tariff. The settlement agreement, accepted by the FERC in May 2014, provided that base rates under the MRA cost-based electric tariff increased approximately $10 million annually, effective May 1, 2014.

Included in this settlement agreement, an adjustment to the Company's wholesale revenue requirement in a subsequent rate proceeding was allowed in the event the Kemper IGCC, or any substantial portion thereof, was placed in service before or after December 1, 2014. Therefore, the Company recorded a regulatory asset as a result of a portion of the Kemper IGCC being placed in service prior to the projected date, which was fully amortized as of December 31, 2015.

On May 13, 2015, the FERC accepted a further settlement agreement between the Company and its wholesale customers to forgo a MRA cost-based electric tariff increase by, among other things, increasing the accrual of AFUDC and lowering the portion of CWIP in rate base, effective April 1, 2015. The additional resulting AFUDC is estimated to be approximately $14 million annually, of which $11 million relates to the Kemper IGCC.

Fuel Cost Recovery

The Company has a wholesale MRA and a Market Based (MB) fuel cost recovery factor. Effective January 1, 2016, the wholesale MRA fuel rate decreased $47 million annually. Effective February 1, 2016, the wholesale MB fuel rate decreased $2 million annually. At December 31, 2015, the amount of over-recovered wholesale MRA fuel costs included in the balance sheets was $24 million compared to an immaterial balance at December 31, 2014.

The Company'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 should have no significant effect on the Company's revenues or net income, but will affect cash flow.

Market-Based Rate Authority

The Company has authority from the FERC to sell electricity at market-based rates. Since 2008, that authority, for certain balancing authority areas, has been conditioned on compliance with the requirements of an energy auction, which the FERC found to be tailored mitigation that addresses potential market power concerns. In accordance with FERC regulations governing such authority, the traditional operating companies (including the Company) and Southern Power filed a triennial market power analysis in June 2014, which included continued reliance on the energy auction as tailored mitigation. On April 27, 2015, the FERC issued an order finding that the traditional operating companies' (including the Company's) and Southern Power's existing tailored mitigation may not effectively mitigate the potential to exert market power in certain areas served by the traditional operating companies and in some adjacent areas. The FERC directed the traditional operating companies (including the Company) and Southern Power to show why market-based rate authority should not be revoked in these areas or to provide a mitigation plan to further address market power concerns. The traditional operating companies (including the Company) and Southern Power filed a request for rehearing on May 27, 2015 and on June 26, 2015 filed their response with the FERC. The ultimate outcome of this matter cannot be determined at this time.

Retail Regulatory Matters

General

In 2012, the Mississippi PSC issued an order for the purpose of investigating and reviewing, for informational purposes only, the ROE formulas used by the Company and all other regulated electric utilities in Mississippi. In 2013, the MPUS filed with the Mississippi PSC its report on the ROE formulas used by the Company and all other regulated electric utilities in Mississippi. The ultimate outcome of this matter cannot be determined at this time.

Energy Efficiency

In 2013, the Mississippi PSC approved an energy efficiency and conservation rule requiring electric and gas utilities in Mississippi serving more than 25,000 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, were required to be filed within six months of the order and will be in effect for two to three years. An annual report addressing the performance of all energy efficiency programs is required.

In June 2014, the Mississippi PSC approved the Company's 2014 Energy Efficiency Quick Start Plan filing, which includes a portfolio of energy efficiency programs. In November 2014, the Mississippi PSC approved the Company's revised compliance filing, which included an increase of $7 million in retail revenues for the period December 2014 through December 2015.

Performance Evaluation Plan

The Company’s retail base rates are set under the PEP, a rate plan approved by the Mississippi PSC. Two filings are made for each calendar year: the PEP projected filing, which is typically filed prior to the beginning of the year based on projected revenue requirement, and the PEP lookback filing, which is filed after the year and allows for review of the actual revenue requirement compared to the projected filing. PEP was designed with the objective to reduce the impact of rate changes on the customer and provide incentives for the Company to keep customer prices low and customer satisfaction and reliability high. PEP is a mechanism for rate adjustments based on three indicators: price, customer satisfaction, and service reliability.

In 2011, the Company submitted its annual PEP lookback filing for 2010, which recommended no surcharge or refund. Later in 2011, the Company received a letter from the MPUS disputing certain items in the 2010 PEP lookback filing. In 2012, the Mississippi PSC issued an order canceling the Company's PEP lookback filing for 2011. In 2013, the MPUS contested the Company's PEP lookback filing for 2012, which indicated a refund due to customers of $5 million. Unresolved matters related to certain costs included in the 2010 PEP lookback filing, which are currently under review, also impact the 2012 PEP lookback filing.

In 2013, the Mississippi PSC approved the projected PEP filing for 2013, which resulted in a rate increase of 1.9%, or $15 million, annually, effective March 19, 2013. The Company may be entitled to $3 million in additional revenues related to 2013 as a result of the late implementation of the 2013 PEP rate increase.

In March 2014 and 2015, the Company submitted its annual PEP lookback filings for 2013 and 2014, respectively, which each indicated no surcharge or refund. The Mississippi PSC suspended each of the filings to allow more time for review.

In June 2014, the Mississippi PSC issued an order for the purpose of investigating and reviewing the adoption of a uniform formula rate plan for the Company and other regulated electric utilities in Mississippi.

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

Environmental Compliance Overview Plan

In 2012, the Mississippi PSC approved the Company's request for a CPCN to construct scrubbers on Plant Daniel Units 1 and 2, which were placed in service in November 2015. These units are jointly owned by the Company and Gulf Power, with 50% ownership each. The Company's portion of the cost is expected to be recovered through the ECO Plan following the scheduled completion of the project. As of December 31, 2015, total project expenditures were $637 million, of which the Company's portion was $325 million, excluding AFUDC of $36 million.

In 2013, the Mississippi PSC approved the Company’s 2013 ECO Plan filing which proposed no change in rates.

In August 2014, the Company entered into a settlement agreement with the Sierra Club that, among other things, required the Sierra Club to dismiss or withdraw all pending legal and regulatory challenges to the issuance of the CPCN to construct scrubbers on Plant Daniel Units 1 and 2, which also occurred in August 2014. In addition, and consistent with the Company's ongoing evaluation of recent environmental rules and regulations, the Company agreed to retire, repower with natural gas, or convert to an alternative non-fossil fuel source Plant Sweatt Units 1 and 2 (80 MWs) no later than December 2018. The Company also agreed that it would cease burning coal and other solid fuel at Plant Watson Units 4 and 5 (750 MWs) and begin operating those units solely on natural gas no later than April 2015 (which occurred on April 16, 2015), and cease burning coal and other solid fuel at Plant Greene County Units 1 and 2 (200 MWs) and begin operating those units solely on natural gas no later than April 2016.

In accordance with a 2011 accounting order from the Mississippi PSC, the Company has the authority to defer in a regulatory asset for future recovery all plant retirement- or partial retirement-related costs resulting from environmental regulations. This request was made to minimize the potential rate impact to customers arising from pending and final environmental regulations which may require the premature retirement of some generating units. As of December 31, 2015, $5 million of Plant Greene County costs and $36 million of costs related to Plant Watson have been reclassified as regulatory assets. These costs are expected to be recovered through the ECO plan and other existing cost recovery mechanisms. Additional costs associated with the remaining net book value of coal-related equipment will be reclassified to a regulatory asset at the time of retirement for Plants Watson and Greene County in 2016. Approved regulatory asset costs will be amortized over a period to be determined by the Mississippi PSC. As a result, these decisions are not expected to have a material impact on the Company's financial statements.

On December 3, 2015, the Mississippi PSC approved the Company's revised ECO filing for 2015, which indicated no change in revenue.

Fuel Cost Recovery

The Company establishes, annually, a retail fuel cost recovery factor that is approved by the Mississippi PSC. The Company is required to file for an adjustment to the retail fuel cost recovery factor annually. The Mississippi PSC approved the 2016 retail fuel cost recovery factor, effective January 21, 2016, which will result in an annual revenue decrease of approximately $120 million. At December 31, 2015, the amount of over-recovered retail fuel costs included in the balance sheets was $71 million compared to a $3 million under-recovered balance at December 31, 2014.

The Company'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 should have no significant effect on the Company's revenues or net income, but will affect cash flow.

Ad Valorem Tax Adjustment

The Company establishes, annually, an ad valorem tax adjustment factor that is approved by the Mississippi PSC to collect the ad valorem taxes paid by the Company. On September 1, 2015, the Mississippi PSC approved the Company's annual ad valorem tax adjustment factor filing effective September 18, 2015, which included an annual rate decrease of 0.35%, or $2 million in annual retail revenues, primarily due to average millage rates.

System Restoration Rider

On October 6, 2015, the Mississippi PSC approved the Company's 2015 SRR rate filing, which proposed that the SRR rate remain level at zero and the Company continue to accrue $3 million annually to the property damage reserve.

On February 1, 2016, the Company submitted its 2016 SRR rate filing which proposed no changes to either the SRR rate or the annual property damage reserve accrual. The ultimate outcome of this matter cannot be determined at this time.

See Note 1 under "Provision for Property Damage" for additional information.

Integrated Coal Gasification Combined Cycle

Kemper IGCC Overview

Construction of the Kemper IGCC is nearing completion and start-up activities will continue until the Kemper IGCC is placed in service. The Kemper IGCC will utilize an IGCC technology with an output capacity of582MWs. The Kemper IGCC will be fueled by locally mined lignite (an abundant, lower heating value coal) from a mine owned by the Company and situated adjacent to the Kemper IGCC. The mine, operated by North American Coal Corporation, started commercial operation in 2013. In connection with the Kemper IGCC, the Company constructed and plans to operate approximately61 miles of CO₂ pipeline infrastructure for the planned transport of captured CO₂ for use in enhanced oil recovery.

Kemper IGCC Schedule and Cost Estimate

In 2012, the Mississippi PSC issued the 2012 MPSC CPCN Order, a detailed order confirming the CPCN originally approved by the Mississippi PSC in 2010 authorizing the acquisition, construction, and operation of the Kemper IGCC. The certificated cost estimate of the Kemper IGCC included in the 2012 MPSC CPCN Order was$2.4 billion, net of $245 million of DOE Grants and excluding the cost of the lignite mine and equipment, the cost of the CO₂pipeline facilities, and AFUDC related to the Kemper IGCC. The 2012 MPSC CPCN Order approved a construction cost cap of up to$2.88 billion, with recovery of prudently-incurred costs subject to approval by the Mississippi PSC.The Kemper IGCC was originally projected to be placed in service in May 2014. The Company placed the combined cycle and the associated common facilities portion of the Kemper IGCC in service using natural gas in August 2014 and currently expects to place the remainder of the Kemper IGCC, including the gasifier and the gas clean-up facilities, in service during the third quarter 2016.

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

Cost Category	2010 Project Estimate(f)		Current Cost Estimate(a)		Actual Costs
	(in billions)
Plant Subject to Cost Cap(b)(g)	$	2.40	$	5.29	$	4.83
Lignite Mine and Equipment	0.21		0.23		0.23
CO2 Pipeline Facilities	0.14		0.11		0.11
AFUDC(c)	0.17		0.69		0.59
Combined Cycle and Related Assets Placed in Service – Incremental(d)(g)	—		0.01		0.01
General Exceptions	0.05		0.10		0.09
Deferred Costs(e)(g)	—		0.20		0.17
Total Kemper IGCC	$	2.97	$	6.63	$	6.03

(a) Amounts in the Current Cost Estimate reflect estimated costs through August 31, 2016.

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

(c) The Company's original estimate included recovery of financing costs during construction rather than the accrual of AFUDC. This approach was not approved by the Mississippi PSC in 2012 as described in "Rate Recovery of Kemper IGCC Costs." The current estimate reflects the impact of a settlement agreement with the wholesale customers for cost-based rates under FERC's jurisdiction. See "FERC Matters" herein for additional information.

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

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

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

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

Of the total costs, including post-in-service costs for the lignite mine, incurred as ofDecember 31, 2015, $3.47 billionwas included in property, plant, and equipment (which is net of the DOE Grants and estimated probable losses of$2.41 billion), $2 millionin other property and investments,$69 million in fossil fuel stock, $45 millionin materials and supplies,$21 millionin other regulatory assets, current,$195 millionin other regulatory assets, deferred, and$11 millionin other deferred charges and assets in the balance sheet.

The Company does not intend to seek rate recovery for any costs related to the construction of the Kemper IGCC that exceed the$2.88 billioncost cap, net of the DOE Grants and excluding the Cost Cap Exceptions. The Company recorded pre-tax charges to income for revisions to the cost estimate above the cost cap of$365 million ($226 million after tax), $868 million ($536 million after tax), and $1.1 billion ($681 millionafter tax) in 2015, 2014, and 2013, respectively. The increases to the cost estimate in 2015 primarily reflect costs for the extension of the Kemper IGCC's projected in-service date through August 31, 2016, increased efforts related to scope modifications, additional labor costs in support of start-up and operational readiness activities, and system repairs and modifications after startup testing and commissioning activities identified necessary remediation of equipment installation, fabrication, and design issues, including the refractory lining inside the gasifiers; the lignite feed and dryer systems; and the syngas cooler vessels. Any extension of the in-service date beyond August 31, 2016 is currently estimated to result in additional base costs of approximately$25 million to $35 millionper month, which includes maintaining necessary levels of start-up labor, materials, and fuel, as well as operational resources required to execute start-up and commissioning activities. However, additional costs may be required for remediation of any further equipment and/or design issues identified. Any extension of the in-service date with respect to the Kemper IGCC beyond August 31, 2016 would also increase costs for the Cost Cap Exceptions, which are not subject to the$2.88 billioncost cap established by the Mississippi PSC. These costs include AFUDC, which is currently estimated to total approximately$13 million per month, as well as carrying costs and operating expenses on Kemper IGCC assets placed in service and consulting and legal fees of approximately $2 million per month. For additional information, see "2015 Rate Case" herein.

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

Rate Recovery of Kemper IGCC Costs

See "FERC Matters" herein for additional information regarding the Company's MRA cost-based tariff relating to recovery of a portion of the Kemper IGCC costs from the Company's wholesale customers. Rate recovery of the retail portion of the Kemper IGCC is subject to the jurisdiction of the Mississippi PSC. See "Income Tax Matters" herein for additional tax information related to the Kemper IGCC.

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

2012 MPSC CPCN Order

The 2012 MPSC CPCN Order included provisions relating to both the Company's recovery of financing costs during the course of construction of the Kemper IGCC and the Company's recovery of costs following the date the Kemper IGCC is placed in service. With respect to recovery of costs following the in-service date of the Kemper IGCC, the 2012 MPSC CPCN Order provided for the establishment of operational cost and revenue parameters based upon assumptions in the Company's petition for the CPCN. The Company expects the Mississippi PSC to apply operational parameters in connection with future proceedings related to the operation of the Kemper IGCC. To the extent the Mississippi PSC determines the Kemper IGCC does not meet the operational parameters ultimately adopted by the Mississippi PSC or the Company incurs additional costs to satisfy such parameters, there could be a material adverse impact on the Company's financial statements.

2013 MPSC Rate Order

In January 2013, the Company entered into a settlement agreement with the Mississippi PSC that was intended to establish the process for resolving matters regarding cost recovery related to the Kemper IGCC (2013 Settlement Agreement). Under the 2013 Settlement Agreement, the Company agreed to limit the portion of prudently-incurred Kemper IGCC costs to be included in retail rate base to the$2.4 billioncertificated cost estimate, plus the Cost Cap Exceptions, but excluding AFUDC, and any other costs permitted or determined to be excluded from the$2.88 billioncost cap by the Mississippi PSC. In March 2013, the Mississippi PSC issued a rate order approving retail rate increases of 15%effective March 19, 2013 and3%effective January 1, 2014, which collectively were designed to collect$156 millionannually beginning in 2014 (2013 MPSC Rate Order) to be used to mitigate customer rate impacts after the Kemper IGCC is placed in service.

Because the 2013 MPSC Rate Order did not provide for the inclusion of CWIP in rate base as permitted by the Baseload Act, the Company continues to record AFUDC on the Kemper IGCC. The Company will not record AFUDC on any additional costs of the Kemper IGCC that exceed the$2.88 billioncost cap, except for Cost Cap Exception amounts.

On February 12, 2015, the Court issued its decision in the legal challenge to the 2013 MPSC Rate Order. The Court reversed the 2013 MPSC Rate Order based on, among other things, its findings that (1) the Mirror CWIP rate treatment was not provided for under the Baseload Act and (2) the Mississippi PSC should have determined the prudence of Kemper IGCC costs before approving rate recovery through the 2013 MPSC Rate Order. The Court also found the 2013 Settlement Agreement unenforceable due to a lack of public notice for the related proceedings. On July 7, 2015, the Mississippi PSC ordered that the Mirror CWIP rate be terminated effective July 20, 2015 and required the fourth quarter 2015 refund of the $342 million collected under the 2013 MPSC Rate Order, along with associated carrying costs of $29 million. The Court's decision did not impact the 2012 MPSC CPCN Order or the February 2013 legislation discussed below.

2015 Rate Case

As a result of the 2015 Court decision, on July 10, 2015, the Company filed a supplemental filing including a request for interim rates (Supplemental Notice) with the Mississippi PSC which presented an alternative rate proposal (In-Service Asset Proposal) for consideration by the Mississippi PSC. The In-Service Asset Proposal was based upon the test period of June 2015 to May 2016, was designed to recover the Company's costs associated with the Kemper IGCC assets that are commercially operational and currently providing service to customers (the transmission facilities, combined cycle, natural gas pipeline, and water pipeline) and other related costs, and was designed to collect approximately $159 millionannually. On August 13, 2015, the Mississippi PSC approved the implementation of interim rates that became effective with the first billing cycle in September, subject to refund and certain other conditions.

On December 3, 2015, the Mississippi PSC issued an order (In-Service Asset Rate Order) adopting in full a stipulation (the 2015 Stipulation) entered into between the Company and the MPUS regarding the In-Service Asset Proposal. Consistent with the 2015 Stipulation, the In-Service Asset Rate Order provides for retail rate recovery of an annual revenue requirement of approximately$126 million, based on the Company’s actual average capital structure, with a maximum common equity percentage of 49.733%, a 9.225% return on common equity, and actual embedded interest costs during the test period. The In-Service Asset Rate Order also includes a prudence finding of all costs in the stipulated revenue requirement calculation for the in-service assets. The stipulated revenue requirement excludes the costs of the Kemper IGCC related to the 15% undivided interest that was previously projected to be purchased by SMEPA. See "Termination of Proposed Sale of Undivided Interest to SMEPA" herein for additional information.

With implementation of the new rate on December 17, 2015, the interim rates were terminated and the Company recorded a customer refund of approximately$11 millionin December 2015 for the difference between the interim rates collected and the permanent rates. The refund is required to be completed by March 16, 2016.

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

On February 25, 2016, Greenleaf CO2 Solutions, LLC filed a notice of appeal of the In-Service Asset Rate Order with the Court. The Company believes the appeal has no merit; however, an adverse outcome in this appeal could have a material impact on the Company's results of operations, financial condition, and liquidity. The ultimate outcome of this matter cannot be determined at this time.

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

The Company expects to seek additional rate relief to address recovery of the remaining Kemper IGCC assets. In addition to current estimated costs at December 31, 2015of$6.63 billion, the Company anticipates that it will incur additional costs after the Kemper IGCC in-service date until the Kemper IGCC cost recovery approach is finalized. These costs include, but are not limited to, regulatory costs and additional carrying costs which could be material. Recovery of these costs would be subject to approval by the Mississippi PSC.

The Company expects the Kemper IGCC to qualify for additional DOE grants included in the recently passed Consolidated Appropriations Act of 2015, which are expected to be used to reduce future rate impacts for customers. The ultimate outcome of this matter cannot be determined at this time.

Regulatory Assets and Liabilities

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

In August 2014, the Company requested confirmation by the Mississippi PSC of the Company's authority to defer all operating expenses associated with the operation of the combined cycle subject to review of such costs by the Mississippi PSC. In addition, the Company is authorized to accrue carrying costs on the unamortized balance of such regulatory assets at a rate and in a manner to be determined by the Mississippi PSC in future cost recovery mechanism proceedings. Beginning in the third quarter 2015, in connection with the implementation of interim rates, the Company began expensing certain ongoing project costs and certain debt carrying costs (associated with assets placed in service and other non-CWIP accounts) that previously were deferred as regulatory assets and began amortizing certain regulatory assets associated with assets placed in service and consulting and legal fees. The amortization periods for these regulatory assets vary fromtwo yearsto 10 yearsas set forth in the In-Service Asset Rate Order. As of December 31, 2015, the balance associated with these regulatory assets was$120 million. Other regulatory assets associated with the remainder of the Kemper IGCC totaled$96 millionas ofDecember 31, 2015. The amortization period for these assets is expected to be determined by the Mississippi PSC in future rate proceedings following completion of construction and start-up of the Kemper IGCC and related prudence reviews.

See "2013 MPSC Rate Order" herein for information related to the July 7, 2015 Mississippi PSC order terminating the Mirror CWIP rate and requiring refund of collections under Mirror CWIP.

The In-Service Asset Rate Order requires the Company to submit an annual true-up calculation of its actual cost of capital, compared to the stipulated total cost of capital, with the first occurring as of May 31, 2016. As of December 31, 2015, the Company recorded a related regulatory liability of approximately$2 million. See "2015 Rate Case" herein for additional information.

Lignite Mine and CO₂ Pipeline Facilities

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

In 2010, the Company executed a40-year management fee contract with Liberty Fuels Company, LLC (Liberty Fuels), a wholly-owned subsidiary of The North American Coal Corporation, which developed, constructed, and is operating and managing the mining operations. The contract with Liberty Fuels is effective through the end of the mine reclamation. As the mining permit holder, Liberty Fuels has a legal obligation to perform mine reclamation and the Company has a contractual obligation to fund all reclamation activities. In addition to the obligation to fund the reclamation activities, the Company currently provides working capital support to Liberty Fuels through cash advances for capital purchases, payroll, and other operating expenses. See Note 1 to the financial statements under "Asset Retirement Obligations and Other Costs of Removal" and "Variable Interest Entities" for additional information.

In addition, the Company has constructed and will operate the CO₂pipeline for the planned transport of captured CO₂for use in enhanced oil recovery. The Company has entered into agreements with Denbury Onshore (Denbury), a subsidiary of Denbury Resources Inc., and Treetop Midstream Services, LLC (Treetop), an affiliate of Tellus Operating Group, LLC and a subsidiary of Tengrys, LLC, pursuant to which Denbury will purchase70% of the CO₂captured from the Kemper IGCC and Treetop will purchase30% of the CO₂captured from the Kemper IGCC. The agreements with Denbury and Treetop provide Denbury and Treetop with termination rights as the Company has not satisfied its contractual obligation to deliver captured CO₂by May 11, 2015. Since May 11, 2015, the Company has been engaged in ongoing discussions with its off-takers regarding the status of the CO₂ delivery schedule as well as other issues related to the CO₂ agreements. As a result of discussions with Treetop, on August 3, 2015, the Company agreed to amend certain provisions of their agreement that do not affect pricing or minimum purchase quantities. Potential requirements imposed on CO₂ off-takers under the Clean Power Plan (if ultimately enacted in its current form, pending resolution of litigation) and the potential adverse financial impact of low oil prices on the off-takers increase the risk that the CO₂ contracts may be terminated or materially modified. Any termination or material modification of these agreements could result in a material reduction in the Company's revenues to the extent the Company is not able to enter into other similar contractual arrangements. Additionally, if the contracts remain in place, sustained oil price reductions could result in significantly lower revenues than the Company forecasted to be available to offset customer rate impacts, which could have a material impact on the Company's financial statements.

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

Termination of Proposed Sale of Undivided Interest to SMEPA

In 2010 and as amended in 2012, the Company and SMEPA entered into an agreement whereby SMEPA agreed to purchase a15%undivided interest in the Kemper IGCC. On May 20, 2015, SMEPA notified the Company that it was terminating the agreement. The Company had previously received a total of $275 million of deposits from SMEPA that were returned by Southern Company to SMEPA, with interest of approximately $26 million, on June 3, 2015, as a result of the termination, pursuant to its guarantee obligation. Subsequently, the Company issued a promissory note in the aggregate principal amount of approximately$301 million to Southern Company, which matures December 1, 2017.

The In-Service Asset Proposal and the related rates approved by the Mississippi PSC excluded any costs associated with the 15%undivided interest. The Company continues to evaluate its alternatives with respect to its investment and the related costs associated with the15% undivided interest.

Bonus Depreciation

On December 18, 2015, the Protecting Americans from Tax Hikes (PATH) Act was signed into law. Bonus depreciation was extended for qualified property placed in service over the nextfive years. The PATH Act allows for 50%bonus depreciation for 2015, 2016, and 2017;40%bonus depreciation for 2018; and30% bonus depreciation for 2019 and certain long-lived assets placed in service in 2020. The extension of 50%bonus depreciation is expected to result in approximately$3 million of positive cash flows related to the combined cycle and associated common facilities portion of the Kemper IGCC for the 2015 tax year and approximately $360 million for the 2016 tax year, which may not all be realized in 2016 due to a projected net operating loss (NOL) on Southern Company's 2016 consolidated income tax return, and is dependent upon placing the remainder of the Kemper IGCC in service in 2016. See "Kemper IGCC Schedule and Cost Estimate" herein for additional information. The ultimate outcome of this matter cannot be determined at this time.

Investment Tax Credits

The IRS allocated$279 million(Phase II) of Internal Revenue Code Section 48A tax credits to the Company in connection with the Kemper IGCC. These tax credits were dependent upon meeting the IRS certification requirements, including an in-service date no later than April 19, 2016 and the capture and sequestration (via enhanced oil recovery) of at least 65%of the CO₂produced by the Kemper IGCC during operations in accordance with the Internal Revenue Code. As a result of the schedule extension for the Kemper IGCC, the Phase II tax credits have been recaptured.

Section 174 Research and Experimental Deduction

Southern Company, on behalf of the Company, reflected deductions for research and experimental (R&E) expenditures related to the Kemper IGCC in its federal income tax calculations for 2013, 2014, and 2015. In May 2015, Southern Company amended its 2008 through 2013 federal income tax returns to include deductions for Kemper IGCC-related R&E expenditures. Due to the uncertainty related to this tax position, the Company had unrecognized tax benefits associated with these R&E deductions totaling approximately $423 million as of December 31, 2015. See "Bonus Depreciation" herein and Note 5 under "Unrecognized Tax Benefits" for additional information. The ultimate outcome of this matter cannot be determined at this time.

Southern Power [Member]

Loss Contingencies [Line Items]

CONTINGENCIES AND REGULATORY MATTERS

CONTINGENCIES AND REGULATORY MATTERS

General Litigation Matters

The Company is subject to certain claims and legal actions arising in the ordinary course of business. In addition, the Company's business activities are subject to extensive governmental regulation related to public health and the environment. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements such as air quality and water standards, has occurred throughout the U.S. This litigation has included claims for damages alleged to have been caused by CO₂ and other emissions and alleged exposure to hazardous materials, and/or requests for injunctive relief in connection with such matters. The ultimate outcome of such pending or potential litigation against the Company and its subsidiaries cannot be predicted at this time; however, for current proceedings not specifically reported herein, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on the Company's financial statements.

FERC Matters

The Company has authority from the FERC to sell electricity at market-based rates. Since 2008, that authority, for certain balancing authority areas, has been conditioned on compliance with the requirements of an energy auction, which the FERC found to be tailored mitigation that addresses potential market power concerns. In accordance with FERC regulations governing such authority, the traditional operating companies and the Company filed a triennial market power analysis in June 2014, which included continued reliance on the energy auction as tailored mitigation. On April 27, 2015, the FERC issued an order finding that the traditional operating companies' and the Company's existing tailored mitigation may not effectively mitigate the potential to exert market power in certain areas served by the traditional operating companies and in some adjacent areas. The FERC directed the traditional operating companies and the Company to show why market-based rate authority should not be revoked in these areas or to provide a mitigation plan to further address market power concerns. The traditional operating companies and the Company filed a request for rehearing on May 27, 2015 and on June 26, 2015 filed their response with the FERC. The ultimate outcome of this matter cannot be determined at this time.