Contingencies and Regulatory Matters

12 Months Ended

Dec. 31, 2017

General Litigation Matters

On January 20, 2017, a purported securities class action complaint was filed against Southern Company, certain of its officers, and certain former Mississippi Power officers in the U.S. District Court for the Northern District of Georgia, Atlanta Division, by Monroe County Employees' Retirement System on behalf of all persons who purchased shares of Southern Company's common stock between April 25, 2012 and October 29, 2013. The complaint alleges that Southern Company, certain of its officers, and certain former Mississippi Power officers made materially false and misleading statements regarding the Kemper County energy facility in violation of certain provisions under the Securities Exchange Act of 1934, as amended. The complaint seeks, among other things, compensatory damages and litigation costs and attorneys' fees. On June 12, 2017, the plaintiffs filed an amended complaint that provided additional detail about their claims, increased the purported class period by one day, and added certain other former Mississippi Power officers as defendants. On July 27, 2017, the defendants filed a motion to dismiss the plaintiffs' amended complaint with prejudice, to which the plaintiffs filed an opposition on September 11, 2017.

On February 27, 2017, Jean Vineyard filed a shareholder derivative lawsuit in the U.S. District Court for the Northern District of Georgia that names as defendants Southern Company, certain of its directors, certain of its officers, and certain former Mississippi Power officers. The complaint alleges that the defendants caused Southern Company to make false or misleading statements regarding the Kemper County energy facility cost and schedule. Further, the complaint alleges that the defendants were unjustly enriched and caused the waste of corporate assets. The plaintiff seeks to recover, on behalf of Southern Company, unspecified actual damages and, on her own behalf, attorneys' fees and costs in bringing the lawsuit. The plaintiff also seeks certain changes to Southern Company's corporate governance and internal processes. On March 27, 2017, the court deferred this lawsuit until 30 days after certain further action in the purported securities class action complaint discussed above.

On May 15, 2017, Helen E. Piper Survivor's Trust filed a shareholder derivative lawsuit in the Superior Court of Gwinnett County, State of Georgia and, on May 31, 2017, Judy Mesirov filed a shareholder derivative lawsuit in the U.S. District Court for the Northern District of Georgia. Each of these lawsuits names as defendants Southern Company, certain of its directors, certain of its officers, and certain former Mississippi Power officers. Each complaint alleges that the individual defendants, among other things, breached their fiduciary duties in connection with schedule delays and cost overruns associated with the construction of the Kemper County energy facility. Each complaint further alleges that the individual defendants authorized or failed to correct false and misleading statements regarding the Kemper County energy facility schedule and cost and failed to implement necessary internal controls to prevent harm to Southern Company. Each plaintiff seeks to recover, on behalf of Southern Company, unspecified actual damages and disgorgement of profits and, on its behalf, attorneys' fees and costs in bringing the lawsuit. Each plaintiff also seeks certain unspecified changes to Southern Company's corporate governance and internal processes. On August 15, 2017, these two shareholder derivative lawsuits were consolidated in the U.S. District Court for the Northern District of Georgia and the court deferred the consolidated case until 30 days after certain further action in the purported securities class action complaint discussed above.

Southern Company believes these legal challenges have no merit; however, an adverse outcome in any of these proceedings could have an impact on Southern Company's results of operations, financial condition, and liquidity. Southern Company will vigorously defend itself in these matters, the ultimate outcome of which cannot be determined at this time.

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 standards for air, water, land, and protection of other natural resources, 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.

Environmental Matters

Environmental Remediation

The Southern Company system must comply with environmental laws and regulations governing 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 electric operating companies and the natural gas distribution utilities conduct studies to determine the extent of any required cleanup and have recognized the estimated costs to clean up known impacted sites in the financial statements. A liability for environmental remediation costs is recognized only when a loss is determined to be probable and reasonably estimable. The traditional electric operating companies and the natural gas distribution utilities in Illinois, New Jersey, Georgia, and Florida have all received authority from their respective state PSCs or other applicable state regulatory agencies to recover approved environmental compliance costs through regulatory mechanisms. These regulatory mechanisms are adjusted annually or as necessary within limits approved by the state PSCs or other applicable state regulatory agencies.

Georgia Power's environmental remediation liability as of December 31, 2017 and 2016 was $22 million and $17 million, respectively. Georgia Power has been designated or identified as a potentially responsible party at sites governed by the Georgia Hazardous Site Response Act and/or by the federal Comprehensive Environmental Response, Compensation, and Liability Act, and assessment and potential cleanup of such sites is expected.

Gulf Power's environmental remediation liability includes estimated costs of environmental remediation projects of approximately $52 million and $44 million as of December 31, 2017 and 2016, respectively. 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'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 Gulf Power's environmental cost recovery clause; therefore, these liabilities have no impact on net income.

Southern Company Gas' environmental remediation liability as of December 31, 2017 and 2016 was $388 million and $426 million, respectively, based on the estimated cost of environmental investigation and remediation associated with known current and former manufactured gas plant operating sites. These environmental remediation expenditures are recoverable from customers through rate mechanisms approved by the applicable state regulatory agencies of the natural gas distribution utilities, with the exception of one site representing $2 million of the total accrued remediation costs.

The ultimate outcome of these matters cannot be determined at this time; however, as a result of the regulatory treatment for environmental remediation expenses described above, the final disposition of these matters is not expected to have a material impact on Southern 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 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 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. In 2015, Georgia Power recovered approximately $18 million, based on its ownership interests, which was credited to accounts where the original costs were charged, and used to reduce rate base, fuel, and cost of service for the benefit of customers. Also in 2015, Alabama Power recovered approximately $26 million, which was applied to reduce the cost of service for the benefit of customers.

In 2014, Alabama Power and Georgia Power filed 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. On October 10, 2017, Alabama Power and Georgia Power filed additional lawsuits against the U.S. government in the Court of Federal Claims 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, 2015 through December 31, 2017. 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, 2017 for any potential recoveries from the pending lawsuits. The final outcome of these matters cannot be determined at this time. However, Alabama Power and Georgia Power expect to credit any recoveries back for the benefit of customers in accordance with direction from their respective PSC and, therefore, 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

Market-Based Rate Authority

The traditional electric 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 electric operating companies and Southern Power filed a triennial market power analysis in 2014, which included continued reliance on the energy auction as tailored mitigation. In 2015, the FERC issued an order finding that the traditional electric 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 electric operating companies and in some adjacent areas. The FERC directed the traditional electric 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 electric operating companies and Southern Power filed a request for rehearing and filed their response with the FERC in 2015.

In December 2016, the traditional electric operating companies and Southern Power filed an amendment to their market-based rate tariff that proposed certain changes to the energy auction, as well as several non-tariff changes. On February 2, 2017, the FERC issued an order accepting all such changes subject to an additional condition of cost-based price caps for certain sales outside of the energy auction, finding that all of these changes would provide adequate alternative mitigation for the traditional electric operating companies' and Southern Power's potential to exert market power in certain areas served by the traditional electric operating companies and in some adjacent areas. On May 17, 2017, the FERC accepted the traditional electric operating companies' and Southern Power's compliance filing accepting the terms of the order. While the FERC's February 2, 2017 order references the market power proceeding discussed above, it remains a separate, ongoing matter.

On October 25, 2017, the FERC issued an order in response to the traditional electric operating companies' and Southern Power's June 29, 2017 triennial updated market power analysis. The FERC directed the traditional electric operating companies and Southern Power to show cause within 60 days why market-based rate authority should not be revoked in certain areas adjacent to the area presently under mitigation in accordance with the February 2, 2017 order or to provide a mitigation plan to further address market power concerns. On November 10, 2017, the traditional electric operating companies and Southern Power responded to the FERC and proposed to resolve matters by applying the alternative mitigation authorized by the February 2, 2017 order to the adjacent areas made the subject of the October 25, 2017 order.

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

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% with an adjusting point of 5.98% and 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. 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, the excess will be refunded to customers unless otherwise directed by the Alabama PSC; however, there is no provision for additional customer billings should the actual retail return fall below the WCE range.

At December 31, 2016, Alabama Power's retail return exceeded the allowed WCE range which resulted in Alabama Power establishing a $73 million Rate RSE refund liability. In accordance with an Alabama PSC order issued on February 14, 2017, Alabama Power applied the full amount of the refund to reduce the under recovered balance of Rate CNP PPA as discussed further below.

Effective in January 2017, Rate RSE increased 4.48%, or $245 million annually. At December 31, 2017, Alabama Power's actual retail return was within the allowed WCE range. On December 1, 2017, Alabama Power made its required annual Rate RSE submission to the Alabama PSC of projected data for calendar year 2018. Projected earnings were within the specified range; therefore, retail rates under Rate RSE remained unchanged for 2018.

In conjunction with Rate RSE, Alabama Power has an established retail tariff that provides for an adjustment to customer billings to recognize the impact of a change in the statutory income tax rate. As a result of Tax Reform Legislation, the application of this tariff would reduce annual retail revenue by approximately $250 million over the remainder of 2018. The ultimate outcome of this matter cannot be determined at this time.

Rate CNP PPA

Alabama Power's retail rates, approved by the Alabama PSC, provide for adjustments under Rate CNP to recognize the placing of new generating facilities into retail service. Alabama Power may also recover retail costs associated with certificated PPAs under Rate CNP PPA. On March 7, 2017, 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, 2017 through March 31, 2018. No adjustment to Rate CNP PPA is expected in 2018. As of December 31, 2017 and 2016, Alabama Power had an under recovered Rate CNP PPA balance of $12 million and $142 million, respectively, which is included in deferred under recovered regulatory clause revenues in the balance sheet.

In accordance with an accounting order issued on February 17, 2017 by the Alabama PSC, Alabama Power eliminated the under recovered balance in Rate CNP PPA at December 31, 2016, which totaled approximately $142 million. As discussed herein under "Rate RSE," Alabama Power utilized the full amount of its $73 million Rate RSE refund liability to reduce the amount of the Rate CNP PPA under recovery and reclassified the remaining $69 million to a separate regulatory asset. The amortization of the new regulatory asset through Rate RSE will begin concurrently with the effective date of Alabama Power's next depreciation study, which is expected to occur within the next two to four years. Alabama Power's current depreciation study became effective January 1, 2017.

Rate CNP Compliance

Rate CNP Compliance allows for the recovery of Alabama Power's retail costs associated with laws, regulations, and other such mandates directed at the utility industry involving the environment, security, reliability, safety, sustainability, or similar considerations impacting Alabama Power's facilities or operations. 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. Revenues for Rate CNP Compliance, 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 will have no significant effect on revenues or net income, but will affect annual cash flow. Changes in Rate CNP Compliance-related operations and maintenance expenses and depreciation generally will have no effect on net income.

In accordance with an accounting order issued on February 17, 2017 by the Alabama PSC, Alabama Power reclassified $36 million of its under recovered balance in Rate CNP Compliance to a separate regulatory asset. The amortization of the new regulatory asset through Rate RSE will begin concurrently with the effective date of Alabama Power's next depreciation study, which is expected to occur within the next two to four years. Alabama Power's current depreciation study became effective January 1, 2017.

On December 5, 2017, the Alabama PSC issued a consent order that Alabama Power leave in effect for 2018 the factors associated with Alabama Power's compliance costs for the year 2017, with any under-collected amount for prior years deemed recovered before any current year amounts. Any under recovered amounts associated with 2018 will be reflected in the 2019 filing. As of December 31, 2017 and 2016, Alabama Power had a deferred under recovered regulatory clause revenues balance of $17 million and $9 million, respectively.

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 accordance with an accounting order issued on February 17, 2017 by the Alabama PSC, Alabama Power reclassified $36 million of its under recovered balance in Rate ECR to a separate regulatory asset. The amortization of the new regulatory asset through Rate RSE will begin concurrently with the effective date of Alabama Power's next depreciation study, which is expected to occur within the next two to four years. Alabama Power's current depreciation study became effective January 1, 2017.

On December 5, 2017, the Alabama PSC issued a consent order that Alabama Power leave in effect for 2018 the energy cost recovery rates which began in 2017. Therefore, the Rate ECR factor as of January 1, 2018 remained at 2.015 cents per KWH. The rate will return to 5.910 cents per KWH in 2019, absent a further order from the Alabama PSC.

At December 31, 2017, Alabama Power's under recovered fuel costs totaled $25 million, which is included in other regulatory assets, current. At December 31, 2016, Alabama Power had an over recovered fuel balance of $76 million, which was included in other regulatory liabilities, current. 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. When the reserve balance falls below $50 million, a reserve establishment charge will be activated (and the on-going reserve maintenance charge concurrently suspended) until the reserve balance reaches $75 million. 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. No such accruals were recorded or designated in any period presented.

In December 2017, the reserve maintenance charge was suspended and the reserve establishment charge was activated as a result of the NDR balance falling below $50 million. Alabama Power expects to collect approximately $16 million annually until the reserve balance is restored to $75 million. The NDR balance at December 31, 2017 was $38 million.

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. The regulatory asset will be amortized and recovered over the affected unit's remaining useful life, as established prior to the decision regarding early retirement through Rate CNP Compliance.

Alabama Power retired Plant Gorgas Units 6 and 7 (200 MWs) and Plant Barry Unit 3 (225 MWs) in 2015. Additionally, Alabama Power ceased using coal at Plant Barry Units 1 and 2 (250 MWs) in 2015, but such units remain available on a limited basis with natural gas as the fuel source. In April 2016, Alabama Power also ceased using coal at Plant Greene County Units 1 and 2 (300 MWs representing Alabama Power's ownership interest) and began operating Units 1 and 2 solely on natural gas in June 2016 and July 2016, respectively.

In accordance with this accounting order from the Alabama PSC, Alabama Power transferred the unrecovered plant asset balances to regulatory assets at their respective retirement dates. These regulatory assets are being amortized and recovered through Rate CNP Compliance over the units' remaining useful lives, as established prior to the decision for retirement; therefore, these decisions associated with coal operations had no significant impact on Southern Company's financial statements.

Georgia Power

Rate Plans

Pursuant to the terms and conditions of a settlement agreement related to Southern Company's acquisition of Southern Company Gas approved by the Georgia PSC in April 2016, the 2013 ARP will continue in effect until December 31, 2019, and Georgia Power will be required to file its next base rate case by July 1, 2019. Furthermore, through December 31, 2019, Georgia Power and Atlanta Gas Light Company each will retain their respective merger savings, net of transition costs, as defined in the settlement agreement; through December 31, 2022, such net merger savings applicable to each will be shared on a 60/40 basis with their respective customers; thereafter, all merger savings will be retained by customers.

In accordance with the 2013 ARP, the Georgia PSC approved increases to tariffs effective January 1, 2016 as follows: (1) traditional base tariff rates by approximately $49 million; (2) Environmental Compliance Cost Recovery tariff by approximately $75 million; (3) Demand-Side Management tariffs by approximately $3 million; and (4) Municipal Franchise Fee tariff by approximately $13 million, for a total increase in base revenues of approximately $140 million. There were no changes to these tariffs in 2017.

Under the 2013 ARP, Georgia Power'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 Georgia Power. There will be no recovery of any earnings shortfall below 10.00% on an actual basis. In 2015, Georgia Power's retail ROE was within the allowed retail ROE range. In 2016, Georgia Power's retail ROE exceeded 12.00%, and Georgia Power will refund to retail customers approximately $44 million in 2018, as approved by the Georgia PSC on January 16, 2018. In 2017, Georgia Power's retail ROE was within the allowed retail ROE range, subject to review and approval by the Georgia PSC.

On January 19, 2018, the Georgia PSC issued an order on the Tax Reform Legislation, which was amended on February 16, 2018 (Tax Order). In accordance with the Tax Order, Georgia Power is required to submit its analysis of the Tax Reform Legislation and related recommendations to address the related impacts on Georgia Power's cost of service and annual revenue requirements by March 6, 2018. The ultimate outcome of this matter cannot be determined at this time.

Integrated Resource Plan

In July 2016, the Georgia PSC approved Georgia Power's triennial Integrated Resource Plan (2016 IRP) including the decertification and retirement of Plant Mitchell Units 3, 4A, and 4B (217 MWs) and Plant Kraft Unit 1 (17 MWs), as well as the decertification of the Intercession City unit (143 MWs total capacity). In August 2016, the Plant Mitchell and Plant Kraft units were retired and Georgia Power sold its 33% ownership interest in the Intercession City unit to Duke Energy Florida, LLC.

Additionally, the Georgia PSC approved Georgia Power's environmental compliance strategy and related expenditures proposed in the 2016 IRP, including measures taken to comply with existing government-imposed environmental mandates, subject to limits on expenditures for Plant McIntosh Unit 1 and Plant Hammond Units 1 through 4.

The Georgia PSC approved the reclassification of the remaining net book value of Plant Mitchell Unit 3 and costs associated with materials and supplies remaining at the unit retirement date to a regulatory asset. Recovery of the unit's net book value will continue through December 31, 2019, as provided in the 2013 ARP. The timing of the recovery of the remaining balance of the unit's net book value as of December 31, 2019 and costs associated with materials and supplies remaining at the unit retirement date was deferred for consideration in Georgia Power's 2019 base rate case.

The Georgia PSC also approved the Renewable Energy Development Initiative (REDI) to procure an additional 1,200 MWs of renewable resources primarily utilizing market-based prices established through a competitive bidding process with expected in-service dates between 2018 and 2021. Additionally, 200 MWs of self-build capacity for use by Georgia Power was approved, as well as consideration for no more than 200 MWs of capacity as part of a renewable commercial and industrial program.

In 2017, Georgia Power filed for and received certification for 510 MWs of REDI utility-scale PPAs for solar generation resources, which are expected to be in operation by the end of 2019. Georgia Power also filed for and received approval to develop several solar generation projects to fulfill the approved self-build capacity.

In the 2016 IRP, the Georgia PSC also approved recovery of costs up to $99 million through June 30, 2019 to preserve nuclear generation as an option at a future generation site in Stewart County, Georgia. On March 7, 2017, the Georgia PSC approved Georgia Power's decision to suspend work at the site due to changing economics, including lower load forecasts and fuel costs. The timing of recovery for costs incurred of approximately $50 million is expected to be determined by the Georgia PSC in a future Georgia Power rate case.

Fuel Cost Recovery

Georgia Power has established fuel cost recovery rates approved by the Georgia PSC. In 2015, the Georgia PSC approved Georgia Power's request to lower annual billings by approximately $350 million effective January 1, 2016. In May 2016, the Georgia PSC approved Georgia Power's request to further lower annual billings under an interim fuel rider by approximately $313 million effective June 1, 2016, which expired on December 31, 2017. The Georgia PSC will review Georgia Power's cumulative over or under recovered fuel balance no later than September 1, 2018 and evaluate the need to file a fuel case unless Georgia Power deems it necessary to file a fuel case at an earlier time. Georgia Power continues to be allowed to adjust its fuel cost recovery rates under an interim fuel rider prior to the next fuel case if the under recovered fuel balance exceeds $200 million.

Georgia Power's fuel cost recovery mechanism includes costs associated with a natural gas hedging program, as revised and approved by the Georgia PSC, allowing the use of an array of derivative instruments within a 48-month time horizon.

Georgia Power's under recovered fuel balance totaled $165 million at December 31, 2017 and is included in current assets. At December 31, 2016, Georgia Power's over recovered fuel balance totaled $84 million and is included in other regulatory liabilities, current.

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 is accruing $30 million annually through December 31, 2019, as provided in the 2013 ARP, for incremental operating and maintenance costs of damage from major storms to its transmission and distribution facilities. Hurricanes Irma and Matthew caused significant damage to Georgia Power's transmission and distribution facilities during September 2017 and October 2016, respectively. The incremental restoration costs related to these hurricanes deferred in Georgia Power's regulatory asset for storm damage totaled approximately $260 million. The rate of storm damage cost recovery is expected to be adjusted as part of Georgia Power's next base rate case required to be filed by July 1, 2019. As a result of this regulatory treatment, costs related to storms are not expected to have a material impact on Southern Company's financial statements.

At December 31, 2017 and December 31, 2016, the total balance in Georgia Power's regulatory asset related to storm damage was $333 million and $206 million, respectively, with approximately $30 million included in other regulatory assets, current for both years and approximately $303 million and $176 million included in other regulatory assets, deferred, respectively.

Gulf Power

Retail Base Rate Cases

In 2013, the Florida PSC approved a settlement agreement related to Gulf Power's 2013 retail base rate case that authorized Gulf Power to reduce depreciation and record a regulatory asset up to $62.5 million from January 2014 through June 2017. In any given month, such depreciation reduction was not to 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. For 2014 and 2015, Gulf Power recognized reductions in depreciation of $8.4 million and $20.1 million, respectively. No net reduction in depreciation was recorded in 2016. In 2017, Gulf Power recognized the remaining $34.0 million reduction in depreciation.

On April 4, 2017, the Florida PSC approved a settlement agreement (2017 Rate Case Settlement Agreement) among Gulf Power and three intervenors with respect to Gulf Power's request in 2016 to increase retail base rates. Among the terms of the 2017 Rate Case Settlement Agreement, Gulf Power increased rates effective with the first billing cycle in July 2017 to provide an annual overall net customer impact of approximately $54.3 million. The net customer impact consisted of a $62.0 million increase in annual base revenues, less an annual purchased power capacity cost recovery clause credit for certain wholesale revenues of approximately $8 million through December 2019. In addition, Gulf Power continued its authorized retail ROE midpoint (10.25%) and range (9.25% to 11.25%) and is deemed to have a maximum equity ratio of 52.5% for all retail regulatory purposes. Gulf Power also began amortizing the regulatory asset associated with the investment balances remaining after the retirement of Plant Smith Units 1 and 2 (357 MWs) over 15 years effective January 1, 2018 and implemented new depreciation rates effective January 1, 2018. The 2017 Rate Case Settlement Agreement also resulted in a $32.5 million write-down of Gulf Power's ownership of Plant Scherer Unit 3 (205 MWs), which was recorded in the first quarter 2017. The remaining issues related to the inclusion of Gulf Power's investment in Plant Scherer Unit 3 in retail rates have been resolved as a result of the 2017 Rate Case Settlement Agreement, including recoverability of certain costs associated with the ongoing ownership and operation of the unit through the environmental cost recovery clause.

The 2017 Rate Case Settlement Agreement set forth a process for addressing the revenue requirement effects of the Tax Reform Legislation through a prospective change to Gulf Power's base rates. Under the terms of the 2017 Rate Case Settlement Agreement, by March 1, 2018, Gulf Power must identify the revenue requirements impacts and defer them to a regulatory asset or regulatory liability to be considered for prospective application in a change to base rates in a limited scope proceeding before the Florida PSC. In lieu of this approach, on February 14, 2018, the parties to the 2017 Rate Case Settlement Agreement filed a new stipulation and settlement agreement (2018 Tax Reform Settlement Agreement) with the Florida PSC. If approved, the 2018 Tax Reform Settlement Agreement will result in annual reductions of $18.2 million to Gulf Power's base rates and $15.6 million to Gulf Power's environmental cost recovery rates effective beginning the first calendar month following approval.

The 2018 Tax Reform Settlement Agreement also provides for a one-time refund of $69.4 million for the retail portion of unprotected (not subject to normalization) deferred tax liabilities through Gulf Power's fuel cost recovery rate over the remainder of 2018. In addition, a limited scope proceeding to address the flow back of protected deferred tax liabilities will be initiated by May 1, 2018 and Gulf Power will record a regulatory liability for the related 2018 amounts eligible to be returned to customers consistent with IRS normalization principles. Unless otherwise agreed to by the parties to the 2018 Tax Reform Settlement Agreement, amounts recorded in this regulatory liability will be refunded to retail customers in 2019 through Gulf Power's fuel cost recovery rate.

If the 2018 Tax Reform Settlement Agreement is approved, the 2017 Rate Case Settlement Agreement will be amended to increase Gulf Power's maximum equity ratio from 52.5% to 53.5% for regulatory purposes.

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

Mississippi Power

On February 7, 2018, Mississippi Power revised its annual projected Performance Evaluation Plan (PEP) filing for 2018 to reflect the impacts of the Tax Reform Legislation. The revised filing requests an increase of $26 million in annual revenues, based on a performance adjusted ROE of 9.33% and an increased equity ratio of 55%. The ultimate outcome of this matter cannot be determined at this time.

Southern Company Gas

The natural gas distribution utilities are subject to regulation and oversight by their respective state regulatory agencies for the rates charged to their customers and other matters. These agencies approve rates designed to provide the opportunity to generate revenues to recover all prudently-incurred costs, including a return on rate base sufficient to pay interest on debt and provide a reasonable ROE.

The natural gas market for Atlanta Gas Light was deregulated in 1997. Accordingly, marketers, rather than a traditional utility, sell natural gas to end-use customers in Georgia and handle customer billing functions. Atlanta Gas Light earns revenue for its distribution services by charging rates to its customers based primarily on monthly fixed charges that are set by the Georgia PSC and adjusted periodically.

With the exception of Atlanta Gas Light, the natural gas distribution utilities are authorized by the relevant regulatory agencies in the states in which they serve to use natural gas cost recovery mechanisms that adjust rates to reflect changes in the wholesale cost of natural gas and ensure recovery of all costs prudently incurred in purchasing natural gas for customers. Natural gas cost recovery revenues are adjusted for differences in actual recoverable natural gas costs and amounts billed in current regulated rates. Changes in the billing factor will not have a significant effect on revenues or net income, but will affect cash flows. In addition to natural gas cost recovery mechanisms, there are other cost recovery mechanisms, such as regulatory riders, which vary by utility but allow recovery of certain costs, such as those related to infrastructure replacement programs, as well as environmental remediation and energy efficiency plans. See Note 1 under "Cost of Natural Gas" for additional information.

Regulatory Infrastructure Programs

Certain of Southern Company Gas' natural gas distribution utilities are involved in ongoing capital projects associated with infrastructure improvement programs that have been previously approved by their applicable state regulatory agencies and provide an appropriate return on invested capital. These infrastructure improvement programs are designed to update or expand the natural gas distribution systems of the natural gas distribution utilities to improve reliability and meet operational flexibility and growth. Initial program lengths range from nine to 10 years, with completion dates ranging from 2020 through 2025.

On February 21, 2017, the Georgia PSC approved a rate adjustment mechanism for Atlanta Gas Light that included the 2017 capital investment associated with a four-year extension of one of its existing infrastructure programs, with a total additional investment of $177 million through 2020.

Base Rate Cases

On January 31, 2018, the Illinois Commerce Commission approved a $137 million increase in Nicor Gas' annual base rate revenues, including $93 million related to the recovery of investments under Nicor Gas' infrastructure program, effective February 8, 2018, based on a ROE of 9.8%.

The Illinois Commerce Commission issued an order effective January 25, 2018 that requires utilities in the state to record the impacts of the Tax Reform Legislation, including the reduction in the corporate income tax rate to 21% and the impact of excess deferred income taxes, as a regulatory liability. On February 20, 2018, the Illinois Commerce Commission granted Nicor Gas' application for rehearing to file revised base rates and tariffs, which Nicor Gas expects to file by the end of the second quarter 2018.

On December 1, 2017, Atlanta Gas Light filed its 2018 annual rate adjustment with the Georgia PSC. If approved, Atlanta Gas Light's annual base rate revenues will increase by $22 million, effective June 1, 2018. Atlanta Gas Light will file a revised rate adjustment to incorporate the effects of the Tax Reform Legislation in the first quarter 2018. The Georgia PSC is expected to rule on the revised requested increase in the second quarter 2018.

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

Kemper County Energy Facility

Overview

The Kemper County energy facility was designed to utilize IGCC technology with an expected output capacity of 582 MWs and to 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 County energy facility. The mine, operated by North American Coal Corporation, started commercial operation in 2013. In connection with the Kemper County energy facility construction, Mississippi Power constructed approximately 61 miles of CO₂ pipeline infrastructure for the transport of captured CO₂ for use in enhanced oil recovery.

Schedule and Cost Estimate

In 2012, the Mississippi PSC issued the 2012 MPSC CPCN Order, confirming the CPCN originally approved by the Mississippi PSC in 2010 authorizing the acquisition, construction, and operation of the Kemper County energy facility. The certificated cost estimate of the Kemper County energy facility included in the 2012 MPSC CPCN Order was $2.4 billion, net of approximately $0.57 billion for the cost of the lignite mine and equipment, the cost of the CO₂ pipeline facilities, AFUDC, and certain general exceptions (Cost Cap Exceptions). 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 County energy facility 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 County energy facility in service in August 2014.

The initial production of syngas began on July 14, 2016 for gasifier "B" and on September 13, 2016 for gasifier "A." Mississippi Power achieved integrated operation of both gasifiers on January 29, 2017, including the production of electricity from syngas in both combustion turbines. During testing, the plant produced and captured CO₂, and produced sulfuric acid and ammonia, each of acceptable quality under the related off-take agreements. However, Mississippi Power experienced numerous challenges during the extended start-up process to achieve integrated operation of the gasifiers on a sustained basis. In May 2017, after achieving these milestones, Mississippi Power determined that a critical system component, the syngas coolers, would need replacement sooner than originally planned, which would require significant lead time and significant cost. In addition, the long-term natural gas price forecast had decreased significantly and the estimated cost of operating and maintaining the facility during the first five full years of operations had increased significantly since certification.

On June 21, 2017, the Mississippi PSC stated its intent to issue an order (which occurred on July 6, 2017) directing Mississippi Power to pursue a settlement under which the Kemper County energy facility would be operated as a natural gas plant, rather than an IGCC plant, and address all issues associated with the Kemper County energy facility (Kemper Settlement Order). The Kemper Settlement Order established a new docket for the purposes of pursuing a global settlement of the related costs (Kemper Settlement Docket). On June 28, 2017, Mississippi Power notified the Mississippi PSC that it would begin a process to suspend operations and start-up activities on the gasifier portion of the Kemper County energy facility, given the uncertainty as to its future. On February 6, 2018, the Mississippi PSC voted to approve a settlement agreement related to cost recovery for the Kemper County energy facility among Mississippi Power, the MPUS, and certain intervenors (Kemper Settlement Agreement).

At the time of project suspension in June 2017, the total cost estimate for the Kemper County energy facility was approximately $7.38 billion, including approximately $5.95 billion of costs subject to the construction cost cap, and was net of the $137 million in additional grants from the DOE for the Kemper County energy facility. In the aggregate, Mississippi Power had recorded charges to income of $3.07 billion ($1.89 billion after tax) as a result of changes in the cost estimate above the cost cap for the Kemper IGCC through May 31, 2017.

Given the Mississippi PSC's stated intent regarding no further rate increase for the Kemper County energy facility and the subsequent suspension, cost recovery of the gasifier portions became no longer probable; therefore, Mississippi Power recorded an additional charge to income in June 2017 of $2.8 billion ($2.0 billion after tax), which included estimated costs associated with the gasifier portions of the plant and lignite mine. During the third and fourth quarters of 2017, Mississippi Power recorded charges to income of $242 million ($206 million after tax), including $164 million for ongoing project costs, estimated mine and gasifier-related costs, and certain termination costs during the suspension period prior to conclusion of the Kemper Settlement Docket, as well as the charge associated with the Kemper Settlement Agreement discussed below. Additional pre-tax cancellation costs, including mine and plant closure and contract termination costs, currently estimated at approximately $50 million to $100 million (excluding salvage), are expected to be incurred in 2018. Mississippi Power has begun efforts to dispose of or abandon the mine and gasifier-related assets.

Rate Recovery

Kemper Settlement Agreement

On February 6, 2018, the Mississippi PSC voted to approve the Kemper Settlement Agreement. The Kemper Settlement Agreement provides for an annual revenue requirement of approximately $99.3 million for costs related to the Kemper County energy facility, which includes the impact of Tax Reform Legislation. The revenue requirement is based on (i) a fixed ROE for 2018 of 8.6% excluding any performance adjustment, (ii) a ROE for 2019 calculated in accordance with PEP, excluding the performance adjustment, (iii) for future years, a performance-based ROE calculated pursuant to PEP, and (iv) amortization periods for the related regulatory assets and liabilities of eight years and six years, respectively. The revenue requirement also reflects a disallowance related to a portion of Mississippi Power's investment in the Kemper County energy facility requested for inclusion in rate base, which was recorded in the fourth quarter 2017 as an additional charge to income of approximately $78 million ($85 million net of accumulated depreciation of $7 million) pre-tax ($48 million after tax).

Under the Kemper Settlement Agreement, retail customer rates will reflect a reduction of approximately $26.8 million annually and include no recovery for costs associated with the gasifier portion of the Kemper County energy facility in 2018 or at any future date. On February 12, 2018, Mississippi Power made the required compliance filing with the Mississippi PSC. The Kemper Settlement Agreement also requires (i) the CPCN for the Kemper County energy facility to be modified to limit it to natural gas combined cycle operation and (ii) Mississippi Power to file a reserve margin plan with the Mississippi PSC by August 2018.

As of December 31, 2017, the balances associated with the Kemper County energy facility regulatory assets and liabilities were $114 million and $26 million, respectively.

As a result of the Mississippi PSC order on February 6, 2018, rate recovery for the Kemper County energy facility is resolved, subject to any future legal challenges.

2015 Rate Case

On December 3, 2015, the Mississippi PSC issued the In-Service Asset Rate Order regarding the Kemper County energy facility assets that were commercially operational and currently providing service to customers (the transmission facilities, combined cycle, natural gas pipeline, and water pipeline) and other related costs. The In-Service Asset Rate Order provided for retail rate recovery of an annual revenue requirement of approximately $126 million, based on Mississippi Power's actual average capital structure, with a maximum common equity percentage of 49.733%, a 9.225% return on common equity, and actual embedded interest costs. The In-Service Asset Rate Order also included a prudence finding of all costs in the stipulated revenue requirement calculation for the in-service assets.

In connection with the implementation of the In-Service Asset Rate Order and wholesale rates, Mississippi Power began expensing certain ongoing project costs and certain retail debt carrying costs that previously were deferred and began amortizing certain regulatory assets associated with assets placed in service and consulting and legal fees over periods ranging from two years to 10 years. On July 6, 2017, the Mississippi PSC issued an order requiring Mississippi Power to establish a regulatory liability account to maintain current rates related to the Kemper County energy facility following the July 2017 completion of the amortization period for certain of these regulatory assets.

Lignite Mine and CO₂ Pipeline Facilities

Mississippi Power owns the lignite mine and equipment and mineral reserves located around the Kemper County energy facility 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 responsible for the mining operations 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. Mississippi Power expects mine reclamation to begin in 2018. In addition to the obligation to fund the reclamation activities, Mississippi Power provided working capital support to Liberty Fuels through cash advances for capital purchases, payroll, and other operating expenses.

In addition, Mississippi Power constructed the CO₂ pipeline for the planned transport of captured CO₂ for use in enhanced oil recovery and entered into an agreement with Denbury Onshore (Denbury) to purchase the captured CO₂. Denbury has the right to terminate the contract at any time because Mississippi Power did not place the Kemper IGCC in service by July 1, 2017.

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

Litigation

On April 26, 2016, a complaint against Mississippi Power was filed in Harrison County Circuit Court (Circuit Court) by Biloxi Freezing & Processing Inc., Gulfside Casino Partnership, and John Carlton Dean, which was amended and refiled on July 11, 2016 to include, among other things, Southern Company as a defendant. The individual plaintiff alleges that Mississippi Power and Southern Company violated the Mississippi Unfair Trade Practices Act. All plaintiffs have alleged that Mississippi Power and Southern Company concealed, falsely represented, and failed to fully disclose important facts concerning the cost and schedule of the Kemper County energy facility and that these alleged breaches have unjustly enriched Mississippi Power and Southern Company. The plaintiffs seek unspecified actual damages and punitive damages; ask the Circuit Court to appoint a receiver to oversee, operate, manage, and otherwise control all affairs relating to the Kemper County energy facility; ask the Circuit Court to revoke any licenses or certificates authorizing Mississippi Power or Southern Company to engage in any business related to the Kemper County energy facility in Mississippi; and seek attorney's fees, costs, and interest. The plaintiffs also seek an injunction to prevent any Kemper County energy facility costs from being charged to customers through electric rates. On June 23, 2017, the Circuit Court ruled in favor of motions by Southern Company and Mississippi Power and dismissed the case. On July 7, 2017, the plaintiffs filed notice of an appeal. Southern Company believes this legal challenge has no merit; however, an adverse outcome in this proceeding could have a material impact on Southern Company's results of operations, financial condition, and liquidity. Southern Company intends to vigorously defend itself in this matter and the ultimate outcome of this matter cannot be determined at this time.

On June 9, 2016, Treetop, Greenleaf CO₂ Solutions, LLC (Greenleaf), Tenrgys, LLC, Tellus Energy, LLC, WCOA, LLC, and Tellus Operating Group filed a complaint against Mississippi Power, Southern Company, and SCS in the state court in Gwinnett County, Georgia. The complaint related to the cancelled CO₂ contract with Treetop and alleged fraudulent misrepresentation, fraudulent concealment, civil conspiracy, and breach of contract on the part of Mississippi Power, Southern Company, and SCS and sought compensatory damages of $100 million, as well as unspecified punitive damages. Southern Company, Mississippi Power, and SCS moved to compel arbitration pursuant to the terms of the CO₂ contract, which the court granted on May 4, 2017. On June 28, 2017, Treetop, Greenleaf, Tenrgys, LLC, Tellus Energy, LLC, WCOA, LLC, and Tellus Operating Group filed a claim for arbitration requesting $500 million in damages. On December 28, 2017, Mississippi Power reached a settlement agreement with Treetop, Greenleaf, Tenrgys, LLC, Tellus Energy, LLC, WCOA, LLC, and Tellus Operating Group and the arbitration was dismissed.

Nuclear Construction

Project Status

In 2009, the Georgia PSC certified construction of Plant Vogtle Units 3 and 4. In 2012, the NRC issued the related combined construction and operating licenses, which allowed full construction of the two AP1000 nuclear units (with electric generating capacity of approximately 1,100 MWs each) and related facilities to begin. Until March 2017, construction on Plant Vogtle Units 3 and 4 continued under the Vogtle 3 and 4 Agreement, which was a substantially fixed price agreement. On March 29, 2017, the EPC Contractor filed for bankruptcy protection under Chapter 11 of the U.S. Bankruptcy Code.

In connection with the EPC Contractor's bankruptcy filing, Georgia Power, acting for itself and as agent for the Vogtle Owners, entered into the Interim Assessment Agreement with the EPC Contractor to allow construction to continue. The Interim Assessment Agreement expired on July 27, 2017 when the Vogtle Services Agreement became effective. In August 2017, following completion of comprehensive cost to complete and cancellation cost assessments, Georgia Power filed its seventeenth VCM report with the Georgia PSC, which included a recommendation to continue construction of Plant Vogtle Units 3 and 4, with Southern Nuclear serving as project manager and Bechtel serving as the primary construction contractor. On December 21, 2017, the Georgia PSC approved Georgia Power's recommendation to continue construction.

Georgia Power expects Plant Vogtle Units 3 and 4 to be placed in service by November 2021 and November 2022, respectively. Georgia Power's revised capital cost forecast for its 45.7% proportionate share of Plant Vogtle Units 3 and 4 is $8.8 billion ($7.3 billion after reflecting the impact of payments received under the Guarantee Settlement Agreement and the Customer Refunds, each as defined herein). Georgia Power's CWIP balance for Plant Vogtle Units 3 and 4 was $3.3 billion at December 31, 2017, which is net of the Guarantee Settlement Agreement payments less the Customer Refunds. Georgia Power estimates that its financing costs for construction of Plant Vogtle Units 3 and 4 will total approximately $3.1 billion, of which $1.6 billion had been incurred through December 31, 2017.

Vogtle 3 and 4 Agreement and EPC Contractor Bankruptcy

In 2008, Georgia Power, acting for itself and as agent for the Vogtle Owners, entered into the Vogtle 3 and 4 Agreement. Under the terms of the Vogtle 3 and 4 Agreement, the Vogtle Owners agreed to pay a purchase price 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. Under the Toshiba Guarantee, Toshiba guaranteed certain payment obligations of the EPC Contractor, including any liability of the EPC Contractor for abandonment of work. In the first quarter 2016, Westinghouse delivered to the Vogtle Owners a total of $920 million of letters of credit from financial institutions (Westinghouse Letters of Credit) to secure a portion of the EPC Contractor's potential obligations under the Vogtle 3 and 4 Agreement.

Subsequent to the EPC Contractor bankruptcy filing, a number of subcontractors to the EPC Contractor alleged non-payment by the EPC Contractor for amounts owed for work performed on Plant Vogtle Units 3 and 4. Georgia Power, acting for itself and as agent for the Vogtle Owners, has taken actions to remove liens filed by these subcontractors through the posting of surety bonds. Related to such liens, certain subcontractors have filed, and additional subcontractors may file, actions against the EPC Contractor and the Vogtle Owners to preserve their payment rights with respect to such claims. All amounts associated with the removal of subcontractor liens and other EPC Contractor pre-petition accounts payable have been paid or accrued as of December 31, 2017.

On June 9, 2017, Georgia Power and the other Vogtle Owners and Toshiba entered into a settlement agreement regarding the Toshiba Guarantee (Guarantee Settlement Agreement). Pursuant to the Guarantee Settlement Agreement, Toshiba acknowledged the amount of its obligation was $3.68 billion (Guarantee Obligations), of which Georgia Power's proportionate share was approximately $1.7 billion. The Guarantee Settlement Agreement provided for a schedule of payments for the Guarantee Obligations beginning in October 2017 and continuing through January 2021. Toshiba made the first three payments as scheduled. On December 8, 2017, Georgia Power, the other Vogtle Owners, certain affiliates of the Municipal Electric Authority of Georgia (MEAG Power), and Toshiba entered into Amendment No. 1 to the Guarantee Settlement Agreement (Guarantee Settlement Agreement Amendment). The Guarantee Settlement Agreement Amendment provided that Toshiba's remaining payment obligations under the Guarantee Settlement Agreement were due and payable in full on December 15, 2017, which Toshiba satisfied on December 14, 2017. Pursuant to the Guarantee Settlement Agreement Amendment, Toshiba was deemed to be the owner of certain pre-petition bankruptcy claims of Georgia Power, the other Vogtle Owners, and certain affiliates of MEAG Power against Westinghouse, and Georgia Power and the other Vogtle Owners surrendered the Westinghouse Letters of Credit.

Additionally, on June 9, 2017, Georgia Power, acting for itself and as agent for the other Vogtle Owners, and the EPC Contractor entered into the Vogtle Services Agreement, which was amended and restated on July 20, 2017. On July 20, 2017, the bankruptcy court approved the EPC Contractor's motion seeking authorization to (i) enter into the Vogtle Services Agreement, (ii) assume and assign to the Vogtle Owners certain project-related contracts, (iii) join the Vogtle Owners as counterparties to certain assumed project-related contracts, and (iv) reject the Vogtle 3 and 4 Agreement. The Vogtle Services Agreement, and the EPC Contractor's rejection of the Vogtle 3 and 4 Agreement, became effective upon approval by the DOE on July 27, 2017. The Vogtle Services Agreement will continue until the start-up and testing of Plant Vogtle Units 3 and 4 are complete and electricity is generated and sold from both units. The Vogtle Services Agreement is terminable by the Vogtle Owners upon 30 days' written notice.

Effective October 23, 2017, Georgia Power, acting for itself and as agent for the other Vogtle Owners, entered into a construction completion agreement with Bechtel, whereby Bechtel will serve as the primary contractor for the remaining construction activities for Plant Vogtle Units 3 and 4 (Bechtel Agreement). Facility design and engineering remains the responsibility of the EPC Contractor under the Vogtle Services Agreement. The Bechtel Agreement is a cost reimbursable plus fee arrangement, whereby Bechtel will be reimbursed for actual costs plus a base fee and an at-risk fee, which is subject to adjustment based on Bechtel's performance against cost and schedule targets. Each Vogtle Owner is severally (not jointly) liable for its proportionate share, based on its ownership interest, of all amounts owed to Bechtel under the Bechtel Agreement. The Vogtle Owners may terminate the Bechtel Agreement at any time for their convenience, provided that the Vogtle Owners will be required to pay amounts related to work performed prior to the termination (including the applicable portion of the base fee), certain termination-related costs, and, at certain stages of the work, the applicable portion of the at-risk fee. Bechtel may terminate the Bechtel Agreement under certain circumstances, including certain Vogtle Owner suspensions of work, certain breaches of the Bechtel Agreement by the Vogtle Owners, Vogtle Owner insolvency, and certain other events. Pursuant to the Loan Guarantee Agreement between Georgia Power and the DOE, Georgia Power is required to obtain the DOE's approval of the Bechtel Agreement prior to obtaining any further advances under the Loan Guarantee Agreement.

On November 2, 2017, the Vogtle Owners entered into an amendment to their joint ownership agreements for Plant Vogtle Units 3 and 4 (as amended, Vogtle Joint Ownership Agreements) to provide for, among other conditions, additional Vogtle Owner approval requirements. Pursuant to the Vogtle Joint Ownership Agreements, the holders of at least 90% of the ownership interests in Plant Vogtle Units 3 and 4 must vote to continue construction if certain adverse events occur, including (i) the bankruptcy of Toshiba; (ii) termination or rejection in bankruptcy of certain agreements, including the Vogtle Services Agreement or the Bechtel Agreement; (iii) the Georgia PSC or Georgia Power determines that any of Georgia Power's costs relating to the construction of Plant Vogtle Units 3 and 4 will not be recovered in retail rates because such costs are deemed unreasonable or imprudent; or (iv) an increase in the construction budget contained in the seventeenth VCM report of more than $1 billion or extension of the project schedule contained in the seventeenth VCM report of more than one year. In addition, pursuant to the Vogtle Joint Ownership Agreements, the required approval of holders of ownership interests in Plant Vogtle Units 3 and 4 is at least (i) 90% for a change of the primary construction contractor and (ii) 67% for material amendments to the Vogtle Services Agreement or agreements with Southern Nuclear or the primary construction contractor, including the Bechtel Agreement. The Vogtle Joint Ownership Agreements also confirm that the Vogtle Owners' sole recourse against Georgia Power or Southern Nuclear for any action or inaction in connection with their performance as agent for the Vogtle Owners is limited to removal of Georgia Power and/or Southern Nuclear as agent, except in cases of willful misconduct.

Regulatory Matters

In 2009, the Georgia PSC voted to certify construction of Plant Vogtle Units 3 and 4 with a certified capital cost of $4.418 billion. 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 up to the certified capital cost of $4.418 billion. As of December 31, 2017, Georgia Power had recovered approximately $1.6 billion of financing costs. On January 30, 2018, Georgia Power filed to decrease the NCCR tariff by approximately $50 million, effective April 1, 2018, pending Georgia PSC approval. The decrease reflects the payments received under the Guarantee Settlement Agreement, refunds to customers ordered by the Georgia PSC aggregating approximately $188 million (Customer Refunds), and the estimated effects of Tax Reform Legislation. The Customer Refunds were recognized as a regulatory liability as of December 31, 2017 and will be paid in three installments of $25 to each retail customer no later than the third quarter 2018.

Georgia Power is required to file semi-annual VCM reports with the Georgia PSC by February 28 and August 31 each year. In October 2013, in connection with the eighth VCM report, the Georgia PSC approved a stipulation (2013 Stipulation) between Georgia Power and the staff of the Georgia PSC to waive the requirement to amend the Plant Vogtle Units 3 and 4 certificate in accordance with the 2009 certification order until the completion of Plant Vogtle Unit 3, or earlier if deemed appropriate by the Georgia PSC and Georgia Power.

On December 20, 2016, the Georgia PSC voted to approve a settlement agreement (Vogtle Cost Settlement Agreement) resolving certain prudency matters in connection with the fifteenth VCM report. On December 21, 2017, the Georgia PSC voted to approve (and issued its related order on January 11, 2018) certain recommendations made by Georgia Power in the seventeenth VCM report and modifying the Vogtle Cost Settlement Agreement. The Vogtle Cost Settlement Agreement, as modified by the January 11, 2018 order, resolved the following regulatory matters related to Plant Vogtle Units 3 and 4: (i) none of the $3.3 billion of costs incurred through December 31, 2015 and reflected in the fourteenth VCM report should be disallowed from rate base on the basis of imprudence; (ii) the Contractor Settlement Agreement was reasonable and prudent and none of the amounts paid pursuant to the Contractor Settlement Agreement should be disallowed from rate base on the basis of imprudence; (iii) (a) capital costs incurred up to $5.680 billion would be presumed to be reasonable and prudent with the burden of proof on any party challenging such costs, (b) Georgia Power would have the burden to show that any capital costs above $5.680 billion were prudent, and (c) a revised capital cost forecast of $7.3 billion (after reflecting the impact of payments received under the Guarantee Settlement Agreement and Customer Refunds) is found reasonable; (iv) construction of Plant Vogtle Units 3 and 4 should be completed, with Southern Nuclear serving as project manager and Bechtel as primary contractor; (v) approved and deemed reasonable Georgia Power's revised schedule placing Plant Vogtle Units 3 and 4 in service in November 2021 and November 2022, respectively; (vi) confirmed that the revised cost forecast does not represent a cost cap and that prudence decisions on cost recovery will be made at a later date, consistent with applicable Georgia law; (vii) reduced the ROE used to calculate the NCCR tariff (a) from 10.95% (the ROE rate setting point authorized by the Georgia PSC in the 2013 ARP) to 10.00% effective January 1, 2016, (b) from 10.00% to 8.30%, effective January 1, 2020, and (c) from 8.30% to 5.30%, effective January 1, 2021 (provided that the ROE in no case will be less than Georgia Power's average cost of long-term debt); (viii) reduced the ROE used for AFUDC equity for Plant Vogtle Units 3 and 4 from 10.00% to Georgia Power's average cost of long-term debt, effective January 1, 2018; and (ix) agreed that upon Unit 3 reaching commercial operation, retail base rates would be adjusted to include carrying costs on those capital costs deemed prudent in the Vogtle Cost Settlement Agreement. The January 11, 2018 order also stated that if Plant Vogtle Units 3 and 4 are not commercially operational by June 1, 2021 and June 1, 2022, respectively, the ROE used to calculate the NCCR tariff will be further reduced by 10 basis points each month (but not lower than Georgia Power's average cost of long-term debt) until the respective unit is commercially operational. The ROE reductions negatively impacted earnings by approximately $20 million in 2016 and $25 million in 2017 and are estimated to have negative earnings impacts of approximately $120 million in 2018 and an aggregate of $585 million from 2019 to 2022. In its January 11, 2018 order, the Georgia PSC stated if other certain conditions and assumptions upon which Georgia Power's seventeenth VCM report are based do not materialize, both Georgia Power and the Georgia PSC reserve the right to reconsider the decision to continue construction.

On February 12, 2018, Georgia Interfaith Power & Light, Inc. and Partnership for Southern Equity, Inc. filed a petition appealing the Georgia PSC's January 11, 2018 order with the Fulton County Superior Court. Georgia 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, financial condition, and liquidity.

The IRS allocated PTCs to each of Plant Vogtle Units 3 and 4, which originally required the applicable unit to be placed in service before 2021. Under the Bipartisan Budget Act of 2018, Plant Vogtle Units 3 and 4 continue to qualify for PTCs. The nominal value of Georgia Power's portion of the PTCs is approximately $500 million per unit.

In its January 11, 2018 order, the Georgia PSC also approved $542 million of capital costs incurred during the seventeenth VCM reporting period (January 1, 2017 to June 30, 2017). The Georgia PSC has approved seventeen VCM reports covering the periods through June 30, 2017, including total construction capital costs incurred through that date of $4.4 billion. Georgia Power expects to file its eighteenth VCM report on February 28, 2018 requesting approval of approximately $450 million of construction capital costs (before payments received under the Guarantee Settlement Agreement and the Customer Refunds) incurred from July 1, 2017 through December 31, 2017. Georgia Power's CWIP balance for Plant Vogtle Units 3 and 4 was approximately $4.8 billion as of December 31, 2017, or $3.3 billion net of payments received under the Guarantee Settlement Agreement and the Customer Refunds.

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

Cost and Schedule

Georgia Power's approximate proportionate share of the remaining estimated capital cost to complete Plant Vogtle Units 3 and 4 with in service dates of November 2021 and November 2022, respectively, is as follows:



	(in billions)
Project capital cost forecast	$	7.3
Net investment as of December 31, 2017	(3.4		)
Remaining estimate to complete	$	3.9

Note: Excludes financing costs capitalized through AFUDC and is net of payments received under the Guarantee Settlement Agreement and the Customer Refunds.

Georgia Power estimates that its financing costs for construction of Plant Vogtle Units 3 and 4 will total approximately $3.1 billion, of which $1.6 billion had been incurred through December 31, 2017.

As construction continues, challenges with management of contractors, subcontractors, and vendors, labor productivity and availability, fabrication, delivery, assembly, and installation of plant systems, structures, and components (some of which are based on new technology and have not yet operated in the global nuclear industry at this scale), or other issues could arise and change the projected schedule and estimated cost.

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. Processes are in place that are designed to assure compliance with the requirements specified in the Westinghouse Design Control Document and the combined construction and operating licenses, including inspections by Southern Nuclear and the NRC that occur throughout construction. As a result of such compliance processes, certain license amendment requests have been filed and approved or are pending before the NRC. Various design and other licensing-based compliance matters, including the timely resolution of Inspections, Tests, Analyses, and Acceptance Criteria and the related approvals by the NRC, may arise, 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.

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

Other Matters

As of December 31, 2017, Georgia Power had borrowed $2.6 billion related to Plant Vogtle Units 3 and 4 costs through the Loan Guarantee Agreement and a multi-advance credit facility among Georgia Power, the DOE, and the FFB, which provides for borrowings of up to $3.46 billion, subject to the satisfaction of certain conditions. On September 28, 2017, the DOE issued a conditional commitment to Georgia Power for up to approximately $1.67 billion in additional guaranteed loans under the Loan Guarantee Agreement. This conditional commitment expires on June 30, 2018, subject to any further extension approved by the DOE. Final approval and issuance of these additional loan guarantees by the DOE cannot be assured and are subject to the negotiation of definitive agreements, completion of due diligence by the DOE, receipt of any necessary regulatory approvals, and satisfaction of other conditions. See Note 6 under "DOE Loan Guarantee Borrowings" for additional information, including applicable covenants, events of default, mandatory prepayment events, and conditions to borrowing.

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

Other Matters

A wholly-owned subsidiary of Southern Company Gas owns and operates a natural gas storage facility consisting of two salt dome caverns in Louisiana. Periodic integrity tests are required in accordance with rules of the Louisiana Department of Natural Resources (DNR). In August 2017, in connection with an ongoing integrity project, updated seismic mapping indicated the proximity of one of the caverns to the edge of the salt dome may be less than the required minimum and could result in Southern Company Gas retiring the cavern early. At December 31, 2017, the facility's property, plant, and equipment had a net book value of $112 million, of which the cavern itself represents approximately 20%. A potential early retirement of this cavern is dependent upon several factors including compliance with an order from the Louisiana DNR detailing the requirements to place the cavern back in service, which includes, among other things, obtaining core samples to determine the composition of the sheath surrounding the edge of the salt dome.

The cavern continues to maintain its pressures and overall structural integrity. These events were considered in connection with Southern Company Gas' annual long-lived asset impairment analysis, which determined there was no impairment as of December 31, 2017. Any changes in results of monitoring activities, rates at which expiring capacity contracts are re-contracted, timing of placing the cavern back in service, or Louisiana DNR requirements could trigger impairment. Further, early retirement of the cavern could trigger impairment of other long-lived assets associated with the natural gas storage facility. The ultimate outcome of this matter cannot be determined at this time, but could have a significant impact on Southern Company's financial statements.

ALABAMA POWER CO

Loss Contingencies [Line Items]

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 standards for air, water, land, and protection of other natural resources, 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 estimated 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. The Company recognizes a liability for environmental remediation costs only when it determines a loss is probable and reasonably estimable.

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 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. In 2015, the Company recovered approximately $26 million, which was applied to reduce the cost of service for the benefit of customers.

In 2014, the Company filed a 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. On October 10, 2017, the Company filed an additional lawsuit against the U.S. government in the Court of Federal Claims for the costs of continuing to store spent nuclear fuel at Plant Farley for the period from January 1, 2015 through December 31, 2017. 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, 2017 for any potential recoveries from the pending lawsuits. The final outcome of these matters cannot be determined at this time. However, the Company expects to credit any recovery back for the benefit of customers in accordance with direction from the Alabama PSC and, therefore, 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 electric operating companies (including the Company) and Southern Power filed a triennial market power analysis in 2014, which included continued reliance on the energy auction as tailored mitigation. In 2015, the FERC issued an order finding that the traditional electric 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 electric operating companies and in some adjacent areas. The FERC directed the traditional electric 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 electric operating companies (including the Company) and Southern Power filed a request for rehearing and filed their response with the FERC in 2015.

In December 2016, the traditional electric operating companies (including the Company) and Southern Power filed an amendment to their market-based rate tariff that proposed certain changes to the energy auction, as well as several non-tariff changes. On February 2, 2017, the FERC issued an order accepting all such changes subject to an additional condition of cost-based price caps for certain sales outside of the energy auction, finding that all of these changes would provide adequate alternative mitigation for the traditional electric operating companies' (including the Company's) and Southern Power's potential to exert market power in certain areas served by the traditional electric operating companies (including the Company) and in some adjacent areas. On May 17, 2017, the FERC accepted the traditional electric operating companies' (including the Company's) and Southern Power's compliance filing accepting the terms of the order. While the FERC's February 2, 2017 order references the market power proceeding discussed above, it remains a separate, ongoing matter.

On October 25, 2017, the FERC issued an order in response to the traditional electric operating companies' (including the Company's) and Southern Power's June 29, 2017 triennial updated market power analysis. The FERC directed the traditional electric operating companies (including the Company) and Southern Power to show cause within 60 days why market-based rate authority should not be revoked in certain areas adjacent to the area presently under mitigation in accordance with the February 2, 2017 order or to provide a mitigation plan to further address market power concerns. On November 10, 2017, the traditional electric operating companies (including the Company) and Southern Power responded to the FERC and proposed to resolve matters by applying the alternative mitigation authorized by the February 2, 2017 order to the adjacent areas made the subject of the October 25, 2017 order.

The ultimate outcome of these matters 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% with an adjusting point of 5.98% and 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. 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, the excess will be refunded to customers unless otherwise directed by the Alabama PSC; however, there is no provision for additional customer billings should the actual retail return fall below the WCE range.

At December 31, 2016, the Company's retail return exceeded the allowed WCE range which resulted in the Company establishing a $73 million Rate RSE refund liability. In accordance with an Alabama PSC order issued on February 14, 2017, the Company applied the full amount of the refund to reduce the under recovered balance of Rate CNP PPA as discussed further below.

Effective in January 2017, Rate RSE increased 4.48%, or $245 million annually. At December 31, 2017, the Company's actual retail return was within the allowed WCE range. On December 1, 2017, the Company made its required annual Rate RSE submission to the Alabama PSC of projected data for calendar year 2018. Projected earnings were within the specified range; therefore, retail rates under Rate RSE remained unchanged for 2018.

In conjunction with Rate RSE, the Company has an established retail tariff that provides for an adjustment to customer billings to recognize the impact of a change in the statutory income tax rate. As a result of Tax Reform Legislation, the application of this tariff would reduce annual retail revenue by approximately $250 million over the remainder of 2018. The ultimate outcome of this matter cannot be determined at this time.

Rate CNP PPA

The Company's retail rates, approved by the Alabama PSC, provide for adjustments under Rate CNP to recognize the placing of new generating facilities into retail service. The Company may also recover retail costs associated with certificated PPAs under Rate CNP PPA. On March 7, 2017, 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, 2017 through March 31, 2018. No adjustment to Rate CNP PPA is expected in 2018. As of December 31, 2017 and 2016, the Company had an under recovered Rate CNP PPA balance of $12 million and $142 million, respectively, which is included in deferred under recovered regulatory clause revenues in the balance sheet.

In accordance with an accounting order issued on February 17, 2017 by the Alabama PSC, the Company eliminated the under recovered balance in Rate CNP PPA at December 31, 2016, which totaled approximately $142 million. As discussed herein under "Rate RSE," the Company utilized the full amount of its $73 million Rate RSE refund liability to reduce the amount of the Rate CNP PPA under recovery and reclassified the remaining $69 million to a separate regulatory asset. The amortization of the new regulatory asset through Rate RSE will begin concurrently with the effective date of the Company's next depreciation study, which is expected to occur within the next two to four years. The Company's current depreciation study became effective January 1, 2017.

Rate CNP Compliance

Rate CNP Compliance allows for the recovery of the Company's retail costs associated with laws, regulations, and other such mandates directed at the utility industry involving the environment, security, reliability, safety, sustainability, or similar considerations impacting the Company's facilities or operations. 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. Revenues for Rate CNP Compliance, 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 will have no significant effect on the Company's revenues or net income, but will affect annual cash flow. Changes in Rate CNP Compliance-related operations and maintenance expenses and depreciation generally will have no effect on net income.

In accordance with an accounting order issued on February 17, 2017 by the Alabama PSC, the Company reclassified $36 million of its under recovered balance in Rate CNP Compliance to a separate regulatory asset. The amortization of the new regulatory asset through Rate RSE will begin concurrently with the effective date of the Company's next depreciation study, which is expected to occur within the next two to four years. The Company's current depreciation study became effective January 1, 2017.

On December 5, 2017, the Alabama PSC issued a consent order that the Company leave in effect for 2018 the factors associated with the Company's compliance costs for the year 2017, with any under-collected amount for prior years deemed recovered before any current year amounts. Any under recovered amounts associated with 2018 will be reflected in the 2019 filing. As of December 31, 2017 and 2016, the Company had a deferred under recovered regulatory clause revenues balance of $17 million and $9 million, respectively.

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 accordance with an accounting order issued on February 17, 2017 by the Alabama PSC, the Company reclassified $36 million of its under recovered balance in Rate ECR to a separate regulatory asset. The amortization of the new regulatory asset through Rate RSE will begin concurrently with the effective date of the Company's next depreciation study, which is expected to occur within the next two to four years. The Company's current depreciation study became effective January 1, 2017.

On December 5, 2017, the Alabama PSC issued a consent order that the Company leave in effect for 2018 the energy cost recovery rates which began in 2017. Therefore, the Rate ECR factor as of January 1, 2018 remained at 2.015 cents per KWH. The rate will return to 5.910 cents per KWH in 2019, absent a further order from the Alabama PSC.

At December 31, 2017, the Company's under recovered fuel costs totaled $25 million, which is included in deferred under recovered regulatory clause revenues. At December 31, 2016, the Company had an over recovered fuel balance of $76 million, which was included in other regulatory liabilities, current. 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. When the reserve balance falls below $50 million, a reserve establishment charge will be activated (and the on-going reserve maintenance charge concurrently suspended) until the reserve balance reaches $75 million. 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. No such accruals were recorded or designated in any period presented.

In December 2017, the reserve maintenance charge was suspended and the reserve establishment charge was activated as a result of the NDR balance falling below $50 million. The Company expects to collect approximately $16 million annually until the reserve balance is restored to $75 million. The NDR balance at December 31, 2017 was $38 million.

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. The regulatory asset will be amortized and recovered over the affected unit's remaining useful life, as established prior to the decision regarding early retirement through Rate CNP Compliance.

The Company retired Plant Gorgas Units 6 and 7 (200 MWs) and Plant Barry Unit 3 (225 MWs) in 2015. Additionally, the Company ceased using coal at Plant Barry Units 1 and 2 (250 MWs) in 2015, but such units remain available on a limited basis with natural gas as the fuel source. In April 2016, the Company also ceased using coal at Plant Greene County Units 1 and 2 (300 MWs representing the Company's ownership interest) and began operating Units 1 and 2 solely on natural gas in June 2016 and July 2016, respectively.

In accordance with this accounting order from the Alabama PSC, the Company transferred the unrecovered plant asset balances to regulatory assets at their respective retirement dates. These regulatory assets are being amortized and recovered through Rate CNP Compliance over the units' remaining useful lives, as established prior to the decision for retirement; therefore, these decisions associated with coal operations had no significant impact on the Company's financial statements.

GEORGIA POWER CO

Loss Contingencies [Line Items]

CONTINGENCIES AND REGULATORY MATTERS

General Litigation Matters

In 2011, plaintiffs filed a putative class action against the Company in the Superior Court of Fulton County, Georgia alleging that the Company's collection in rates of municipal franchise fees (all of which are remitted to municipalities) exceeded the amounts allowed in orders of the Georgia PSC and alleging certain state tort law claims. In November 2016, the Georgia Court of Appeals reversed the trial court's previous dismissal of the case and remanded the case to the trial court for further proceedings. The Company filed a petition for writ of certiorari with the Georgia Supreme Court, which was granted on August 28, 2017. A decision from the Georgia Supreme Court is expected in late 2018. The Company believes the plaintiffs' claims have no merit and intends to vigorously defend itself in this matter. The ultimate outcome of this matter cannot be determined at this time.

The Company is also 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 standards for air, water, land, and protection of other natural resources, 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 recognizes a liability for environmental remediation costs only when it determines a loss is probable and reasonably estimable. The Company's environmental remediation liability as of December 31, 2017 and 2016 was $22 million and $17 million, respectively. The Company has been designated or identified as a potentially responsible party at sites governed by the Georgia Hazardous Site Response Act and/or by the federal Comprehensive Environmental Response, Compensation, and Liability Act, and assessment and potential cleanup of such sites is expected.

The ultimate outcome of these matters 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 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. In 2015, the Company recovered approximately $18 million, based on its ownership interests, which was credited to accounts where the original costs were charged, and used to reduce rate base, fuel, and cost of service for the benefit of customers.

In 2014, the Company filed 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. On October 10, 2017, the Company filed additional lawsuits against the U.S. government in the Court of Federal Claims 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, 2015 through December 31, 2017. 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, 2017 for any potential recoveries from the pending lawsuits. The final outcome of these matters cannot be determined at this time. However, the Company expects to credit any recovery back for the benefit of customers in accordance with direction from the Georgia PSC and, therefore, 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 ultimate outcome of these matters cannot be determined at this time.

Retail Regulatory Matters

Rate Plans

Pursuant to the terms and conditions of a settlement agreement related to Southern Company's acquisition of Southern Company Gas approved by the Georgia PSC in April 2016, the 2013 ARP will continue in effect until December 31, 2019, and the Company will be required to file its next base rate case by July 1, 2019. Furthermore, through December 31, 2019, the Company and Atlanta Gas Light Company each will retain their respective merger savings, net of transition costs, as defined in the settlement agreement; through December 31, 2022, such net merger savings applicable to each will be shared on a 60/40 basis with their respective customers; thereafter, all merger savings will be retained by customers.

In accordance with the 2013 ARP, the Georgia PSC approved increases 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) Demand-Side Management tariffs by approximately $3 million; and (4) Municipal Franchise Fee tariff by approximately $13 million, for a total increase in base revenues of approximately $140 million. There were no changes to these tariffs in 2017.

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 2015, the Company's retail ROE was within the allowed retail ROE range. In 2016, the Company's retail ROE exceeded 12.00%, and the Company will refund to retail customers approximately $44 million in 2018, as approved by the Georgia PSC on January 16, 2018. In 2017, the Company's retail ROE was within the allowed retail ROE range, subject to review and approval by the Georgia PSC.

On January 19, 2018, the Georgia PSC issued an order on the Tax Reform Legislation, which was amended on February 16, 2018 (Tax Order). In accordance with the Tax Order, the Company is required to submit its analysis of the Tax Reform Legislation and related recommendations to address the related impacts on the Company's cost of service and annual revenue requirements by March 6, 2018. The ultimate outcome of this matter cannot be determined at this time.

Integrated Resource Plan

In July 2016, the Georgia PSC approved the Company's triennial Integrated Resource Plan (2016 IRP) including the decertification and retirement of Plant Mitchell Units 3, 4A, and 4B (217 MWs) and Plant Kraft Unit 1 (17 MWs), as well as the decertification of the Intercession City unit (143 MWs total capacity). In August 2016, the Plant Mitchell and Plant Kraft units were retired and the Company sold its 33% ownership interest in the Intercession City unit to Duke Energy Florida, LLC.

Additionally, the Georgia PSC approved the Company's environmental compliance strategy and related expenditures proposed in the 2016 IRP, including measures taken to comply with existing government-imposed environmental mandates, subject to limits on expenditures for Plant McIntosh Unit 1 and Plant Hammond Units 1 through 4.

The Georgia PSC also approved the Renewable Energy Development Initiative (REDI) to procure an additional 1,200 MWs of renewable resources primarily utilizing market-based prices established through a competitive bidding process with expected in-service dates between 2018 and 2021. Additionally, 200 MWs of self-build capacity for use by the Company was approved, as well as consideration for no more than 200 MWs of capacity as part of a renewable commercial and industrial program.

In 2017, the Company filed for and received certification for 510 MWs of REDI utility-scale PPAs for solar generation resources, which are expected to be in operation by the end of 2019. The Company also filed for and received approval to develop several solar generation projects to fulfill the approved self-build capacity.

In the 2016 IRP, the Georgia PSC also approved recovery of costs up to $99 million through June 30, 2019 to preserve nuclear generation as an option at a future generation site in Stewart County, Georgia. On March 7, 2017, the Georgia PSC approved the Company's decision to suspend work at the site due to changing economics, including lower load forecasts and fuel costs. The timing of recovery for costs incurred of approximately $50 million is expected to be determined by the Georgia PSC in a future rate case.

Fuel Cost Recovery

The Company has established fuel cost recovery rates approved by the Georgia PSC. In 2015, the Georgia PSC approved the Company's request to lower annual billings by approximately $350 million effective January 1, 2016. In May 2016, the Georgia PSC approved the Company's request to further lower annual billings under an interim fuel rider by approximately $313 million effective June 1, 2016, which expired on December 31, 2017. The Georgia PSC will review the Company's cumulative over or under recovered fuel balance no later than September 1, 2018 and evaluate the need to file a fuel case unless the Company deems it necessary to file a fuel case at an earlier time. The Company continues to be allowed to adjust its fuel cost recovery rates under an interim fuel rider prior to the next fuel case if the under recovered fuel balance exceeds $200 million.

The Company's fuel cost recovery mechanism includes costs associated with a natural gas hedging program, as revised and approved by the Georgia PSC, allowing the use of an array of derivative instruments within a 48-month time horizon.

The Company's under recovered fuel balance totaled $165 million at December 31, 2017 and is included in current assets. At December 31, 2016, the Company's over recovered fuel balance totaled $84 million and is included in over recovered fuel clause revenues, current.

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.

Storm Damage Recovery

The Company is accruing $30 million annually through December 31, 2019, as provided in the 2013 ARP, for incremental operating and maintenance costs of damage from major storms to its transmission and distribution facilities. Hurricanes Irma and Matthew caused significant damage to the Company's transmission and distribution facilities during September 2017 and October 2016, respectively. The incremental restoration costs related to these hurricanes deferred in the regulatory asset for storm damage totaled approximately $260 million. At December 31, 2017, the total balance in the regulatory asset related to storm damage was $333 million. The rate of storm damage cost recovery is expected to be adjusted as part of the Company's next base rate case required to be filed by July 1, 2019. As a result of this regulatory treatment, costs related to storms are not expected to have a material impact on the Company's financial statements. See Note 1 under "Storm Damage Recovery" for additional information regarding the Company's storm damage reserve.

GULF POWER CO

Loss Contingencies [Line Items]

CONTINGENCIES AND REGULATORY MATTERS

Nuclear Construction

Project Status

In connection with the EPC Contractor's bankruptcy filing, the Company, acting for itself and as agent for the Vogtle Owners, entered into the Interim Assessment Agreement with the EPC Contractor to allow construction to continue. The Interim Assessment Agreement expired on July 27, 2017 when the Vogtle Services Agreement became effective. In August 2017, following completion of comprehensive cost to complete and cancellation cost assessments, the Company filed its seventeenth VCM report with the Georgia PSC, which included a recommendation to continue construction of Plant Vogtle Units 3 and 4, with Southern Nuclear serving as project manager and Bechtel serving as the primary construction contractor. On December 21, 2017, the Georgia PSC approved the Company's recommendation to continue construction.

The Company expects Plant Vogtle Units 3 and 4 to be placed in service by November 2021 and November 2022, respectively. The Company's revised capital cost forecast for its 45.7% proportionate share of Plant Vogtle Units 3 and 4 is $8.8 billion ($7.3 billion after reflecting the impact of payments received under the Guarantee Settlement Agreement and the Customer Refunds, each as defined herein). The Company's CWIP balance for Plant Vogtle Units 3 and 4 was $3.3 billion at December 31, 2017, which is net of the Guarantee Settlement Agreement payments less the Customer Refunds. The Company estimates that its financing costs for construction of Plant Vogtle Units 3 and 4 will total approximately $3.1 billion, of which $1.6 billion had been incurred through December 31, 2017.

Vogtle 3 and 4 Agreement and EPC Contractor Bankruptcy

In 2008, the Company, acting for itself and as agent for the Vogtle Owners, entered into the Vogtle 3 and 4 Agreement. Under the terms of the Vogtle 3 and 4 Agreement, the Vogtle Owners agreed to pay a purchase price 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. Under the Toshiba Guarantee, Toshiba guaranteed certain payment obligations of the EPC Contractor, including any liability of the EPC Contractor for abandonment of work. In the first quarter 2016, Westinghouse delivered to the Vogtle Owners a total of $920 million of letters of credit from financial institutions (Westinghouse Letters of Credit) to secure a portion of the EPC Contractor's potential obligations under the Vogtle 3 and 4 Agreement.

Subsequent to the EPC Contractor bankruptcy filing, a number of subcontractors to the EPC Contractor alleged non-payment by the EPC Contractor for amounts owed for work performed on Plant Vogtle Units 3 and 4. The Company, acting for itself and as agent for the Vogtle Owners, has taken actions to remove liens filed by these subcontractors through the posting of surety bonds. Related to such liens, certain subcontractors have filed, and additional subcontractors may file, actions against the EPC Contractor and the Vogtle Owners to preserve their payment rights with respect to such claims. All amounts associated with the removal of subcontractor liens and other EPC Contractor pre-petition accounts payable have been paid or accrued as of December 31, 2017.

On June 9, 2017, the Company and the other Vogtle Owners and Toshiba entered into a settlement agreement regarding the Toshiba Guarantee (Guarantee Settlement Agreement). Pursuant to the Guarantee Settlement Agreement, Toshiba acknowledged the amount of its obligation was $3.68 billion (Guarantee Obligations), of which the Company's proportionate share was approximately $1.7 billion. The Guarantee Settlement Agreement provided for a schedule of payments for the Guarantee Obligations beginning in October 2017 and continuing through January 2021. Toshiba made the first three payments as scheduled. On December 8, 2017, the Company, the other Vogtle Owners, certain affiliates of the Municipal Electric Authority of Georgia (MEAG Power), and Toshiba entered into Amendment No. 1 to the Guarantee Settlement Agreement (Guarantee Settlement Agreement Amendment). The Guarantee Settlement Agreement Amendment provided that Toshiba's remaining payment obligations under the Guarantee Settlement Agreement were due and payable in full on December 15, 2017, which Toshiba satisfied on December 14, 2017. Pursuant to the Guarantee Settlement Agreement Amendment, Toshiba was deemed to be the owner of certain pre-petition bankruptcy claims of the Company, the other Vogtle Owners, and certain affiliates of MEAG Power against Westinghouse, and the Company and the other Vogtle Owners surrendered the Westinghouse Letters of Credit.

Additionally, on June 9, 2017, the Company, acting for itself and as agent for the other Vogtle Owners, and the EPC Contractor entered into the Vogtle Services Agreement, which was amended and restated on July 20, 2017. On July 20, 2017, the bankruptcy court approved the EPC Contractor's motion seeking authorization to (i) enter into the Vogtle Services Agreement, (ii) assume and assign to the Vogtle Owners certain project-related contracts, (iii) join the Vogtle Owners as counterparties to certain assumed project-related contracts, and (iv) reject the Vogtle 3 and 4 Agreement. The Vogtle Services Agreement, and the EPC Contractor's rejection of the Vogtle 3 and 4 Agreement, became effective upon approval by the DOE on July 27, 2017. The Vogtle Services Agreement will continue until the start-up and testing of Plant Vogtle Units 3 and 4 are complete and electricity is generated and sold from both units. The Vogtle Services Agreement is terminable by the Vogtle Owners upon 30 days' written notice.

Effective October 23, 2017, the Company, acting for itself and as agent for the other Vogtle Owners, entered into a construction completion agreement with Bechtel, whereby Bechtel will serve as the primary contractor for the remaining construction activities for Plant Vogtle Units 3 and 4 (Bechtel Agreement). Facility design and engineering remains the responsibility of the EPC Contractor under the Vogtle Services Agreement. The Bechtel Agreement is a cost reimbursable plus fee arrangement, whereby Bechtel will be reimbursed for actual costs plus a base fee and an at-risk fee, which is subject to adjustment based on Bechtel's performance against cost and schedule targets. Each Vogtle Owner is severally (not jointly) liable for its proportionate share, based on its ownership interest, of all amounts owed to Bechtel under the Bechtel Agreement. The Vogtle Owners may terminate the Bechtel Agreement at any time for their convenience, provided that the Vogtle Owners will be required to pay amounts related to work performed prior to the termination (including the applicable portion of the base fee), certain termination-related costs, and, at certain stages of the work, the applicable portion of the at-risk fee. Bechtel may terminate the Bechtel Agreement under certain circumstances, including certain Vogtle Owner suspensions of work, certain breaches of the Bechtel Agreement by the Vogtle Owners, Vogtle Owner insolvency, and certain other events. Pursuant to the Loan Guarantee Agreement between the Company and the DOE, the Company is required to obtain the DOE's approval of the Bechtel Agreement prior to obtaining any further advances under the Loan Guarantee Agreement.

On November 2, 2017, the Vogtle Owners entered into an amendment to their joint ownership agreements for Plant Vogtle Units 3 and 4 (as amended, Vogtle Joint Ownership Agreements) to provide for, among other conditions, additional Vogtle Owner approval requirements. Pursuant to the Vogtle Joint Ownership Agreements, the holders of at least 90% of the ownership interests in Plant Vogtle Units 3 and 4 must vote to continue construction if certain adverse events occur, including (i) the bankruptcy of Toshiba; (ii) termination or rejection in bankruptcy of certain agreements, including the Vogtle Services Agreement or the Bechtel Agreement; (iii) the Georgia PSC or the Company determines that any of the Company's costs relating to the construction of Plant Vogtle Units 3 and 4 will not be recovered in retail rates because such costs are deemed unreasonable or imprudent; or (iv) an increase in the construction budget contained in the seventeenth VCM report of more than $1 billion or extension of the project schedule contained in the seventeenth VCM report of more than one year. In addition, pursuant to the Vogtle Joint Ownership Agreements, the required approval of holders of ownership interests in Plant Vogtle Units 3 and 4 is at least (i) 90% for a change of the primary construction contractor and (ii) 67% for material amendments to the Vogtle Services Agreement or agreements with Southern Nuclear or the primary construction contractor, including the Bechtel Agreement. The Vogtle Joint Ownership Agreements also confirm that the Vogtle Owners' sole recourse against the Company or Southern Nuclear for any action or inaction in connection with their performance as agent for the Vogtle Owners is limited to removal of the Company and/or Southern Nuclear as agent, except in cases of willful misconduct.

Regulatory Matters

In 2009, the Georgia PSC voted to certify construction of Plant Vogtle Units 3 and 4 with a certified capital cost of $4.418 billion. 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 up to the certified capital cost of $4.418 billion. As of December 31, 2017, the Company had recovered approximately $1.6 billion of financing costs. On January 30, 2018, the Company filed to decrease the NCCR tariff by approximately $50 million, effective April 1, 2018, pending Georgia PSC approval. The decrease reflects the payments received under the Guarantee Settlement Agreement, refunds to customers ordered by the Georgia PSC aggregating approximately $188 million (Customer Refunds), and the estimated effects of Tax Reform Legislation. The Customer Refunds were recognized as a regulatory liability as of December 31, 2017 and will be paid in three installments of $25 to each retail customer no later than the third quarter 2018.

The Company is required to file semi-annual VCM reports with the Georgia PSC by February 28 and August 31 each year. In October 2013, in connection with the eighth VCM report, the Georgia PSC approved a stipulation (2013 Stipulation) between the Company and the staff of the Georgia PSC to waive the requirement to amend the Plant Vogtle Units 3 and 4 certificate in accordance with the 2009 certification order until the completion of Plant Vogtle Unit 3, or earlier if deemed appropriate by the Georgia PSC and the Company.

On December 20, 2016, the Georgia PSC voted to approve a settlement agreement (Vogtle Cost Settlement Agreement) resolving certain prudency matters in connection with the fifteenth VCM report. On December 21, 2017, the Georgia PSC voted to approve (and issued its related order on January 11, 2018) certain recommendations made by the Company in the seventeenth VCM report and modifying the Vogtle Cost Settlement Agreement. The Vogtle Cost Settlement Agreement, as modified by the January 11, 2018 order, resolved the following regulatory matters related to Plant Vogtle Units 3 and 4: (i) none of the $3.3 billion of costs incurred through December 31, 2015 and reflected in the fourteenth VCM report should be disallowed from rate base on the basis of imprudence; (ii) the Contractor Settlement Agreement was reasonable and prudent and none of the amounts paid pursuant to the Contractor Settlement Agreement should be disallowed from rate base on the basis of imprudence; (iii) (a) capital costs incurred up to $5.680 billion would be presumed to be reasonable and prudent with the burden of proof on any party challenging such costs, (b) the Company would have the burden to show that any capital costs above $5.680 billion were prudent, and (c) a revised capital cost forecast of $7.3 billion (after reflecting the impact of payments received under the Guarantee Settlement Agreement and Customer Refunds) is found reasonable; (iv) construction of Plant Vogtle Units 3 and 4 should be completed, with Southern Nuclear serving as project manager and Bechtel as primary contractor; (v) approved and deemed reasonable the Company's revised schedule placing Plant Vogtle Units 3 and 4 in service in November 2021 and November 2022, respectively; (vi) confirmed that the revised cost forecast does not represent a cost cap and that prudence decisions on cost recovery will be made at a later date, consistent with applicable Georgia law; (vii) reduced the ROE used to calculate the NCCR tariff (a) from 10.95% (the ROE rate setting point authorized by the Georgia PSC in the 2013 ARP) to 10.00% effective January 1, 2016, (b) from 10.00% to 8.30%, effective January 1, 2020, and (c) from 8.30% to 5.30%, effective January 1, 2021 (provided that the ROE in no case will be less than the Company's average cost of long-term debt); (viii) reduced the ROE used for AFUDC equity for Plant Vogtle Units 3 and 4 from 10.00% to the Company's average cost of long-term debt, effective January 1, 2018; and (ix) agreed that upon Unit 3 reaching commercial operation, retail base rates would be adjusted to include carrying costs on those capital costs deemed prudent in the Vogtle Cost Settlement Agreement. The January 11, 2018 order also stated that if Plant Vogtle Units 3 and 4 are not commercially operational by June 1, 2021 and June 1, 2022, respectively, the ROE used to calculate the NCCR tariff will be further reduced by 10 basis points each month (but not lower than the Company's average cost of long-term debt) until the respective unit is commercially operational. The ROE reductions negatively impacted earnings by approximately $20 million in 2016 and $25 million in 2017 and are estimated to have negative earnings impacts of approximately $120 million in 2018 and an aggregate of $585 million from 2019 to 2022. In its January 11, 2018 order, the Georgia PSC stated if other certain conditions and assumptions upon which the Company's seventeenth VCM report are based do not materialize, both the Company and the Georgia PSC reserve the right to reconsider the decision to continue construction.

On February 12, 2018, Georgia Interfaith Power & Light, Inc. and Partnership for Southern Equity, Inc. filed a petition appealing the Georgia PSC's January 11, 2018 order with the Fulton County Superior 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 IRS allocated PTCs to each of Plant Vogtle Units 3 and 4, which originally required the applicable unit to be placed in service before 2021. Under the Bipartisan Budget Act of 2018, Plant Vogtle Units 3 and 4 continue to qualify for PTCs. The nominal value of the Company's portion of the PTCs is approximately $500 million per unit.

In its January 11, 2018 order, the Georgia PSC also approved $542 million of capital costs incurred during the seventeenth VCM reporting period (January 1, 2017 to June 30, 2017). The Georgia PSC has approved seventeen VCM reports covering the periods through June 30, 2017, including total construction capital costs incurred through that date of $4.4 billion. The Company expects to file its eighteenth VCM report on February 28, 2018 requesting approval of approximately $450 million of construction capital costs (before payments received under the Guarantee Settlement Agreement and the Customer Refunds) incurred from July 1, 2017 through December 31, 2017. The Company's CWIP balance for Plant Vogtle Units 3 and 4 was approximately $4.8 billion as of December 31, 2017, or $3.3 billion net of payments received under the Guarantee Settlement Agreement and the Customer Refunds.

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

Cost and Schedule

The Company's approximate proportionate share of the remaining estimated capital cost to complete Plant Vogtle Units 3 and 4 with in service dates of November 2021 and November 2022, respectively, is as follows:



	(in billions)
Project capital cost forecast	$	7.3
Net investment as of December 31, 2017	(3.4		)
Remaining estimate to complete	$	3.9

Note: Excludes financing costs capitalized through AFUDC and is net of payments received under the Guarantee Settlement Agreement and the Customer Refunds.

The Company estimates that its financing costs for construction of Plant Vogtle Units 3 and 4 will total approximately $3.1 billion, of which $1.6 billion had been incurred through December 31, 2017.

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

Other Matters

As of December 31, 2017, the Company had borrowed $2.6 billion related to Plant Vogtle Units 3 and 4 costs through the Loan Guarantee Agreement and a multi-advance credit facility among the Company, the DOE, and the FFB, which provides for borrowings of up to $3.46 billion, subject to the satisfaction of certain conditions. On September 28, 2017, the DOE issued a conditional commitment to the Company for up to approximately $1.67 billion in additional guaranteed loans under the Loan Guarantee Agreement. This conditional commitment expires on June 30, 2018, subject to any further extension approved by the DOE. Final approval and issuance of these additional loan guarantees by the DOE cannot be assured and are subject to the negotiation of definitive agreements, completion of due diligence by the DOE, receipt of any necessary regulatory approvals, and satisfaction of other conditions. See Note 6 under "DOE Loan Guarantee Borrowings" for additional information, including applicable covenants, events of default, mandatory prepayment events, and conditions to borrowing.

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

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 standards for air, water, land, and protection of natural resources 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 governing 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 and reasonably estimable. At December 31, 2017 and 2016, the Company's environmental remediation liability included estimated costs of environmental remediation projects of approximately $52 million and $44 million, respectively, of which approximately $5 million and $4 million, respectively, is included in under recovered regulatory clause revenues and other current liabilities and approximately $47 million and $40 million, respectively, is included in other regulatory assets, deferred and other deferred credits and liabilities. 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 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, the final disposition of these matters is not expected to have a material impact on the Company's financial statements.

FERC Matters

The ultimate outcome of these matters 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 Cases

In the 2013 Rate Case Settlement Agreement, the Florida PSC authorized the Company to reduce depreciation and record a regulatory asset up to $62.5 million from January 2014 through June 2017. In any given month, such depreciation reduction was not to 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. For 2014 and 2015, the Company recognized reductions in depreciation of $8.4 million and $20.1 million, respectively. No net reduction in depreciation was recorded in 2016. In 2017, the Company recognized the remaining $34.0 million reduction in depreciation.

On April 4, 2017, the Florida PSC approved the 2017 Rate Case Settlement Agreement among the Company and three intervenors with respect to the Company's request in 2016 to increase retail base rates. Among the terms of the 2017 Rate Case Settlement Agreement, the Company increased rates effective with the first billing cycle in July 2017 to provide an annual overall net customer impact of approximately $54.3 million. The net customer impact consisted of a $62.0 million increase in annual base revenues, less an annual purchased power capacity cost recovery clause credit for certain wholesale revenues of approximately $8 million through December 2019. In addition, the Company continued its authorized retail ROE midpoint (10.25%) and range (9.25% to 11.25%), is deemed to have a maximum equity ratio of 52.5% for all retail regulatory purposes, and implemented new dismantlement accruals effective July 1, 2017. The Company also began amortizing the regulatory asset associated with the investment balances remaining after the retirement of Plant Smith Units 1 and 2 (357 MWs) over 15 years effective January 1, 2018 and implemented new depreciation rates effective January 1, 2018. The 2017 Rate Case Settlement Agreement also resulted in a $32.5 million write-down of the Company's ownership of Plant Scherer Unit 3 (205 MWs), which was recorded in the first quarter 2017. The remaining issues related to the inclusion of the Company's investment in Plant Scherer Unit 3 in retail rates have been resolved as a result of the 2017 Rate Case Settlement Agreement, including recoverability of certain costs associated with the ongoing ownership and operation of the unit through the environmental cost recovery clause.

The 2017 Rate Case Settlement Agreement set forth a process for addressing the revenue requirement effects of the Tax Reform Legislation through a prospective change to the Company's base rates. Under the terms of the 2017 Rate Case Settlement Agreement, by March 1, 2018, the Company must identify the revenue requirements impacts and defer them to a regulatory asset or regulatory liability to be considered for prospective application in a change to base rates in a limited scope proceeding before the Florida PSC. In lieu of this approach, on February 14, 2018, the parties to the 2017 Rate Case Settlement Agreement filed a new stipulation and settlement agreement (2018 Tax Reform Settlement Agreement) with the Florida PSC. If approved, the 2018 Tax Reform Settlement Agreement will result in annual reductions of $18.2 million to the Company's base rates and $15.6 million to the Company's environmental cost recovery rates effective beginning the first calendar month following approval.

The 2018 Tax Reform Settlement Agreement also provides for a one-time refund of $69.4 million for the retail portion of unprotected (not subject to normalization) deferred tax liabilities through the Company's fuel cost recovery rate over the remainder of 2018. In addition, a limited scope proceeding to address the flow back of protected deferred tax liabilities will be initiated by May 1, 2018 and the Company will record a regulatory liability for the related 2018 amounts eligible to be returned to customers consistent with IRS normalization principles. Unless otherwise agreed to by the parties to the 2018 Tax Reform Settlement Agreement, amounts recorded in this regulatory liability will be refunded to retail customers in 2019 through the Company's fuel cost recovery rate.

If the 2018 Tax Reform Settlement Agreement is approved, the 2017 Rate Case Settlement Agreement will be amended to increase the Company's maximum equity ratio from 52.5% to 53.5% for regulatory purposes.

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

Cost Recovery Clauses

As discussed previously, the 2017 Rate Case Settlement Agreement resolved the remaining issues related to the Company's inclusion of certain costs associated with the ongoing ownership and operation of Plant Scherer Unit 3 in the environmental cost recovery clause and no adjustment to the environmental cost recovery clause rate approved by the Florida PSC in November 2016 was made.

On October 25, 2017, the Florida PSC approved the Company's annual clause rate request for its fuel, purchased power capacity, environmental, and energy conservation cost recovery factors for 2018. The net effect of the approved changes is a $63 million increase in annual revenues effective in January 2018, the majority of which will be offset by related expense increases.

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, 2017, the under recovered fuel balance was approximately $22 million, which is included in under recovered regulatory clause revenues on the balance sheet. At December 31, 2016, the over recovered fuel balance was approximately $15 million, which is included in other regulatory liabilities, current on the balance sheet.

Purchased Power Capacity Recovery

The Company has established purchased power capacity cost recovery 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, 2017, the under recovered purchased power capacity balance was $2 million, which is included in under recovered regulatory clause revenues on the balance sheet. At December 31, 2016, the 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.

Annually, the Company seeks recovery of projected costs including any true-up amounts from prior periods. At December 31, 2017 and 2016, the over recovered environmental balance of approximately $11 million and $8 million, respectively, along with the current portion of projected environmental expenditures, was included in under recovered regulatory clause revenues on the balance sheets.

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, 2017, the under recovered ECCR balance was immaterial. At December 31, 2016, the balance was approximately $4 million, which is included in under recovered regulatory clause revenues on the balance sheet.

Other Matters

As a result of the cost to comply with environmental regulations imposed by the EPA, the Company retired its coal-fired generation at Plant Smith Units 1 and 2 in March 2016. In August 2016, the Florida PSC approved the Company's request to reclassify the remaining net book value of Plant Smith Units 1 and 2 and the remaining materials and supplies associated with these units as of the retirement date, totaling approximately $63 million, to a regulatory asset. The Company began amortizing the investment balances over 15 years effective January 1, 2018 in accordance with the 2017 Rate Case Settlement Agreement.

MISSISSIPPI POWER CO

Loss Contingencies [Line Items]

CONTINGENCIES AND REGULATORY MATTERS

General Litigation Matters

Environmental Matters

Environmental Remediation

The Company must comply with environmental laws and regulations governing 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 established regulatory mechanisms. The Company recognizes a liability for environmental remediation costs only when it determines a loss is probable and reasonably estimable.

FERC Matters

Municipal and Rural Associations Tariff

The Company provides wholesale electric service to Cooperative Energy, East Mississippi Electric Power Association, and the City of Collins, all located in southeastern Mississippi, under a long-term cost-based, FERC regulated MRA tariff.

In March 2016, the Company reached a settlement agreement with its wholesale customers, which was subsequently approved by the FERC, for an increase in wholesale base revenues under the MRA cost-based electric tariff, primarily as a result of placing scrubbers for Plant Daniel Units 1 and 2 in service in 2015. The settlement agreement became effective for services rendered beginning May 1, 2016, resulting in an estimated annual revenue increase of $7 million under the MRA cost-based electric tariff. Additionally, under the settlement agreement, the tariff customers agreed to similar regulatory treatment for MRA tariff ratemaking as the treatment approved for retail ratemaking through an order issued by the Mississippi PSC in December 2015 (In-Service Asset Rate Order). This regulatory treatment primarily includes (i) recovery of the operational Kemper County energy facility assets providing service to customers and other related costs, (ii) amortization of the Kemper County energy facility-related regulatory assets included in rates under the settlement agreement over the 36 months ending April 30, 2019, (iii) Kemper County energy facility-related expenses included in rates under the settlement agreement no longer being deferred and charged to expense, and (iv) removing all of the Kemper County energy facility CWIP from rate base with a corresponding increase in accrual of AFUDC. The additional resulting AFUDC totaled approximately $22 million through the suspension of Kemper IGCC start-up activities and has been recorded as a charge to income.

On September 18, 2017, the Company and Cooperative Energy executed a Shared Service Agreement (SSA), as part of the MRA tariff, under which the Company and Cooperative Energy will share in providing electricity to all Cooperative Energy delivery points, in lieu of the current arrangement under which each delivery point is specifically assigned to either entity. The SSA accepted by the FERC on October 31, 2017 became effective on January 1, 2018 and may be cancelled by Cooperative Energy with 10 years notice after December 31, 2020. The SSA provides Cooperative Energy the option to decrease its use of the Company's generation services under the MRA tariff, subject to annual and cumulative caps and a one-year notice requirement. In the event Cooperative Energy elects to reduce these services, the related reduction in the Company's revenues is not expected to be significant through 2020.

Fuel Cost Recovery

The Company has a wholesale MRA and a Market Based (MB) fuel cost recovery factor. At December 31, 2017, over-recovered wholesale MRA fuel costs were immaterial and at December 31, 2016 were approximately $13 million, and is included in over-recovered regulatory clause liabilities, current in the balance sheet. Effective January 1, 2018, the wholesale MRA fuel rate increased $11 million annually.

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

Cooperative Energy Power Supply Agreement

In 2008, the Company entered into a 10-year Power Supply Agreement (PSA) with Cooperative Energy for approximately 152 MWs, which became effective in 2011. Following certain plant retirements, the PSA capacity was reduced to 86 MWs. On February 5, 2018, the Company and Cooperative Energy executed an amendment to extend the PSA through March 31, 2021, effective April 1, 2018, with increased total capacity of 286 MWs.

Cooperative Energy also has a 10-year Network Integration Transmission Service Agreement (NITSA) with SCS for transmission service to certain delivery points on the Company's transmission system that became effective in 2011. As a result of the PSA amendments, Cooperative Energy and SCS amended the terms of the NITSA on January 12, 2018 to provide for the purchase of incremental transmission capacity for service beginning April 1, 2018 through March 31, 2021. This NITSA amendment remains subject to acceptance by the FERC. The ultimate outcome of these matters 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.

In 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.

On January 26, 2018, the Mississippi PSC issued an order directing utilities to file within 30 days information regarding the impact on rates resulting from Tax Reform Legislation. The Company's Kemper County energy facility rates, approved on February 6, 2018, include the effects of Tax Reform Legislation. The Company's 2018 ECO, revised 2018 PEP, and 2018 SRR rate filings, all submitted in February 2018, include the effects of Tax Reform Legislation and are subject to approval by the Mississippi PSC.

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

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 a projected revenue requirement, and the PEP lookback filing, which is filed after the end of the year and allows for review of the actual revenue requirement compared to the projected filing.

In 2011, the Company submitted its annual PEP lookback filing for 2010, which recommended no surcharge or refund. Later in 2011, the MPUS disputed 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 the 2010 PEP lookback filing, which remain 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 2014, 2015, 2016, and 2017, the Company submitted its annual PEP lookback filings for the prior years, which for 2013 and 2014 each indicated no surcharge or refund and for each of 2015 and 2016 indicated a $5 million surcharge. Additionally, in July 2016, in November 2016, and on November 15, 2017, the Company submitted its annual projected PEP filings for 2016, 2017, and 2018, respectively, which for 2016 and 2017 indicated no change in rates and for 2018 indicated a rate increase of 4%, or $38 million in annual revenues. The Mississippi PSC suspended each of these filings to allow more time for review.

On February 7, 2018, the Company revised its annual projected PEP filing for 2018 to reflect the impacts of Tax Reform Legislation. The revised filing requests an increase of $26 million in annual revenues, based on a performance adjusted ROE of 9.33% and an increased equity ratio of 55%. See Note 5 for additional information.

The ultimate outcome of these matters 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 extended by an order issued by the Mississippi PSC in July 2016, until the time the Mississippi PSC approves a comprehensive portfolio plan program. The ultimate outcome of this matter cannot be determined at this time.

On July 6, 2017, the Mississippi PSC issued an order approving the Company's Energy Efficiency Cost Rider 2017 compliance filing, which increased annual retail revenues by approximately $2 million effective with the first billing cycle for August 2017.

On November 30, 2017, the Company submitted its Energy Efficiency Cost Rider 2018 compliance filing which included a small decrease in annual retail revenues. The ultimate outcome of this matter 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 2015. These units are jointly owned by the Company and Gulf Power, with 50% ownership each. In 2014, the Company entered into a settlement agreement with the Sierra Club under which, among other things, 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 (and the units were retired in July 2016). 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 in April 2015) and cease burning coal and other solid fuel at Plant Greene County Units 1 and 2 (200 MWs) no later than April 2016 (which occurred in February and March 2016, respectively) and begin operating those units solely on natural gas (which occurred in June and July 2016, respectively).

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. The Mississippi PSC approved $41 million and $17 million of costs that were reclassified to regulatory assets associated with Plant Watson and Plant Greene County, respectively, for amortization over five-year periods that began in July 2016 and July 2017, respectively. As a result, these decisions are not expected to have a material impact on the Company's financial statements.

In August 2016, the Mississippi PSC approved the Company's revised ECO plan filing for 2016, which requested the maximum 2% annual increase in revenues, or approximately $18 million, primarily related to the Plant Daniel Units 1 and 2 scrubbers placed in service in 2015. The revised rates became effective with the first billing cycle for September 2016. Approximately $22 million of related revenue requirements in excess of the 2% maximum was deferred for inclusion in the 2017 filing, along with related carrying costs.

On May 4, 2017, the Mississippi PSC approved the Company's ECO plan filing for 2017, which requested the maximum 2% annual increase in revenues, or approximately $18 million, primarily related to the carryforward from the prior year. The rates became effective with the first billing cycle for June 2017. Approximately $26 million of related revenue requirements in excess of the 2% maximum was deferred for inclusion in the 2018 filing, along with related carrying costs.

On February 14, 2018, the Company submitted its ECO plan filing for 2018, including the effects of Tax Reform Legislation, which requested the maximum 2% annual increase in revenues, or approximately $17 million, primarily related to the carryforward from the prior year. Approximately $13 million of related revenue requirements in excess of the 2% maximum, along with related carrying costs, remains deferred for inclusion in the 2019 filing. The ultimate outcome of this matter cannot be determined at this time.

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. On January 12, 2017, the Mississippi PSC approved the 2017 retail fuel cost recovery factor, effective February 2017 through January 2018, which resulted in an annual revenue increase of approximately $55 million. On November 15, 2017, the Company filed its annual rate adjustment under the retail fuel cost recovery clause, requesting an additional increase of $39 million annually, which the Mississippi PSC approved on January 16, 2018 effective February 2018 through January 2019. At December 31, 2017, the amount of under-recovered retail fuel costs included in the balance sheet in customer accounts receivable was approximately $6 million compared to $37 million over recovered at December 31, 2016.

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 July 6, 2017, the Mississippi PSC approved the Company's annual ad valorem tax adjustment factor filing for 2017, which included an annual rate increase of 0.85%, or $8 million in annual retail revenues, primarily due to increased assessments.

System Restoration Rider

In February 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 of $3 million annually. On February 3, 2017, the Company submitted its 2017 SRR rate filing, which proposed an increase in the property damage reserve accrual of $1 million. These filings were suspended by the Mississippi PSC for review.

On January 21, 2017, a tornado caused extensive damage to the Company's transmission and distribution infrastructure. Storm damage repairs were approximately $9 million. A portion of these costs was charged to the retail property damage reserve and was addressed in the 2018 SRR rate filing.

On February 1, 2018, the Company submitted its 2018 SRR rate filing, including the effects of Tax Reform Legislation, which proposed that the SRR rate remain at zero and the annual accrual for the property damage reserve be reduced to $2 million in 2018.

The ultimate outcome of these matters cannot be determined at this time. See Note 1 under "Provision for Property Damage" for additional information.

Storm Damage Cost Recovery

In connection with the damage associated with Hurricane Katrina, the Mississippi PSC authorized the issuance of system restoration bonds in 2006. In accordance with a Mississippi PSC order on January 24, 2017, the Company eliminated the applicable Storm Restoration Charge because the bond sinking fund managed by the Mississippi State Bond Commission is substantially funded.

Kemper County Energy Facility

Overview

The Kemper County energy facility was designed to utilize IGCC technology with an expected output capacity of 582 MWs and to 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 County energy facility. The mine, operated by North American Coal Corporation, started commercial operation in 2013. In connection with the Kemper County energy facility construction, the Company constructed approximately 61 miles of CO₂ pipeline infrastructure for the transport of captured CO₂ for use in enhanced oil recovery.

Schedule and Cost Estimate

In 2012, the Mississippi PSC issued the 2012 MPSC CPCN Order, confirming the CPCN originally approved by the Mississippi PSC in 2010 authorizing the acquisition, construction, and operation of the Kemper County energy facility. The certificated cost estimate of the Kemper County energy facility included in the 2012 MPSC CPCN Order was $2.4 billion, net of approximately $0.57 billion for the cost of the lignite mine and equipment, the cost of the CO₂ pipeline facilities, AFUDC, and certain general exceptions (Cost Cap Exceptions). 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 County energy facility 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 County energy facility in service in August 2014.

The initial production of syngas began on July 14, 2016 for gasifier "B" and on September 13, 2016 for gasifier "A." The Company achieved integrated operation of both gasifiers on January 29, 2017, including the production of electricity from syngas in both combustion turbines. During testing, the plant produced and captured CO₂, and produced sulfuric acid and ammonia, each of acceptable quality under the related off-take agreements. However, the Company experienced numerous challenges during the extended start-up process to achieve integrated operation of the gasifiers on a sustained basis. In May 2017, after achieving these milestones, the Company determined that a critical system component, the syngas coolers, would need replacement sooner than originally planned, which would require significant lead time and significant cost. In addition, the long-term natural gas price forecast had decreased significantly and the estimated cost of operating and maintaining the facility during the first five full years of operations had increased significantly since certification.

On June 21, 2017, the Mississippi PSC stated its intent to issue an order (which occurred on July 6, 2017) directing the Company to pursue a settlement under which the Kemper County energy facility would be operated as a natural gas plant, rather than an IGCC plant, and address all issues associated with the Kemper County energy facility (Kemper Settlement Order). The Kemper Settlement Order established a new docket for the purposes of pursuing a global settlement of the related costs (Kemper Settlement Docket). On June 28, 2017, the Company notified the Mississippi PSC that it would begin a process to suspend operations and start-up activities on the gasifier portion of the Kemper County energy facility, given the uncertainty as to its future. On February 6, 2018, the Mississippi PSC voted to approve a settlement agreement related to cost recovery for the Kemper County energy facility among the Company, the MPUS, and certain intervenors (Kemper Settlement Agreement).

At the time of project suspension in June 2017, the total cost estimate for the Kemper County energy facility was approximately $7.38 billion, including approximately $5.95 billion of costs subject to the construction cost cap, and was net of the $137 million in Additional DOE Grants. In the aggregate, the Company had recorded charges to income of $3.07 billion ($1.89 billion after tax) as a result of changes in the cost estimate above the cost cap for the Kemper IGCC through May 31, 2017.

Given the Mississippi PSC's stated intent regarding no further rate increase for the Kemper County energy facility and the subsequent suspension, cost recovery of the gasifier portions became no longer probable; therefore, the Company recorded an additional charge to income in June 2017 of $2.8 billion ($2.0 billion after tax), which included estimated costs associated with the gasifier portions of the plant and lignite mine. During the third and fourth quarters of 2017, the Company recorded charges to income of $242 million ($206 million after tax), including $164 million for ongoing project costs, estimated mine and gasifier-related costs, and certain termination costs during the suspension period prior to conclusion of the Kemper Settlement Docket, as well as the charge associated with the Kemper Settlement Agreement discussed below. Additional pre-tax cancellation costs, including mine and plant closure and contract termination costs, currently estimated at approximately $50 million to $100 million (excluding salvage), are expected to be incurred in 2018. The Company has begun efforts to dispose of or abandon the mine and gasifier-related assets.

Rate Recovery

Kemper Settlement Agreement

On February 6, 2018, the Mississippi PSC voted to approve the Kemper Settlement Agreement. The Kemper Settlement Agreement provides for an annual revenue requirement of approximately $99.3 million for costs related to the Kemper County energy facility, which includes the impact of Tax Reform Legislation. The revenue requirement is based on (i) a fixed ROE for 2018 of 8.6% excluding any performance adjustment, (ii) a ROE for 2019 calculated in accordance with PEP, excluding the performance adjustment, (iii) for future years, a performance-based ROE calculated pursuant to PEP, and (iv) amortization periods for the related regulatory assets and liabilities of eight years and six years, respectively. The revenue requirement also reflects a disallowance related to a portion of the Company's investment in the Kemper County energy facility requested for inclusion in rate base, which was recorded in the fourth quarter 2017 as an additional charge to income of approximately $78 million ($85 million net of accumulated depreciation of $7 million) pre-tax ($48 million after tax).

Under the Kemper Settlement Agreement, retail customer rates will reflect a reduction of approximately $26.8 million annually and include no recovery for costs associated with the gasifier portion of the Kemper County energy facility in 2018 or at any future date. On February 12, 2018, the Company made the required compliance filing with the Mississippi PSC. The Kemper Settlement Agreement also requires (i) the CPCN for the Kemper County energy facility to be modified to limit it to natural gas combined cycle operation and (ii) the Company to file a reserve margin plan with the Mississippi PSC by August 2018.

As of December 31, 2017, the balances associated with the Kemper County energy facility regulatory assets and liabilities were $114 million and $26 million, respectively.

As a result of the Mississippi PSC order on February 6, 2018, rate recovery for the Kemper County energy facility is resolved, subject to any future legal challenges.

2015 Rate Case

On December 3, 2015, the Mississippi PSC issued the In-Service Asset Rate Order regarding the Kemper County energy facility assets that were commercially operational and currently providing service to customers (the transmission facilities, combined cycle, natural gas pipeline, and water pipeline) and other related costs. The In-Service Asset Rate Order provided 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. The In-Service Asset Rate Order also included a prudence finding of all costs in the stipulated revenue requirement calculation for the in-service assets.

In connection with the implementation of the In-Service Asset Rate Order and wholesale rates, the Company began expensing certain ongoing project costs and certain retail debt carrying costs that previously were deferred and began amortizing certain regulatory assets associated with assets placed in service and consulting and legal fees over periods ranging from two years to 10 years. On July 6, 2017, the Mississippi PSC issued an order requiring the Company to establish a regulatory liability account to maintain current rates related to the Kemper County energy facility following the July 2017 completion of the amortization period for certain of these regulatory assets. See "FERC Matters" herein for additional information related to the 2016 settlement agreement with wholesale customers.

Lignite Mine and CO₂ Pipeline Facilities

The Company owns the lignite mine and equipment and mineral reserves located around the Kemper County energy facility site. The mine started commercial operation in June 2013.

In 2010, the Company 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 responsible for the mining operations 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. The Company expects mine reclamation to begin in 2018. In addition to the obligation to fund the reclamation activities, the Company provided working capital support to Liberty Fuels through cash advances for capital purchases, payroll, and other operating expenses. See Note 1 under "Asset Retirement Obligations and Other Costs of Removal" and "Variable Interest Entities" for additional information.

In addition, the Company constructed the CO₂ pipeline for the planned transport of captured CO₂ for use in enhanced oil recovery and entered into an agreement with Denbury Onshore (Denbury) to purchase the captured CO₂. Denbury has the right to terminate the contract at any time because the Company did not place the Kemper IGCC in service by July 1, 2017.

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

Litigation

On April 26, 2016, a complaint against the Company was filed in Harrison County Circuit Court (Circuit Court) by Biloxi Freezing & Processing Inc., Gulfside Casino Partnership, and John Carlton Dean, which was amended and refiled on July 11, 2016 to include, among other things, Southern Company as a defendant. The individual plaintiff alleges that the Company and Southern Company violated the Mississippi Unfair Trade Practices Act. All plaintiffs have alleged that the Company and Southern Company concealed, falsely represented, and failed to fully disclose important facts concerning the cost and schedule of the Kemper County energy facility and that these alleged breaches have unjustly enriched the Company and Southern Company. The plaintiffs seek unspecified actual damages and punitive damages; ask the Circuit Court to appoint a receiver to oversee, operate, manage, and otherwise control all affairs relating to the Kemper County energy facility; ask the Circuit Court to revoke any licenses or certificates authorizing the Company or Southern Company to engage in any business related to the Kemper County energy facility in Mississippi; and seek attorney's fees, costs, and interest. The plaintiffs also seek an injunction to prevent any Kemper County energy facility costs from being charged to customers through electric rates. On June 23, 2017, the Circuit Court ruled in favor of motions by Southern Company and the Company and dismissed the case. On July 7, 2017, the plaintiffs filed notice of an appeal. The Company believes this legal challenge has no merit; however, an adverse outcome in this proceeding could have a material impact on the Company's results of operations, financial condition, and liquidity. The Company intends to vigorously defend itself in this matter and the ultimate outcome of this matter cannot be determined at this time.

On June 9, 2016, Treetop, Greenleaf CO₂Solutions, LLC (Greenleaf), Tenrgys, LLC, Tellus Energy, LLC, WCOA, LLC, and Tellus Operating Group filed a complaint against the Company, Southern Company, and SCS in the state court in Gwinnett County, Georgia. The complaint related to the cancelled CO₂ contract with Treetop and alleged fraudulent misrepresentation, fraudulent concealment, civil conspiracy, and breach of contract on the part of the Company, Southern Company, and SCS and sought compensatory damages of $100 million, as well as unspecified punitive damages. Southern Company, the Company, and SCS moved to compel arbitration pursuant to the terms of the CO₂ contract, which the court granted on May 4, 2017. On June 28, 2017, Treetop, Greenleaf, Tenrgys, LLC, Tellus Energy, LLC, WCOA, LLC, and Tellus Operating Group filed a claim for arbitration requesting $500 million in damages. On December 28, 2017, the Company reached a settlement agreement with Treetop, Greenleaf, Tenrgys, LLC, Tellus Energy, LLC, WCOA, LLC, and Tellus Operating Group and the arbitration was dismissed.

SOUTHERN POWER CO

Loss Contingencies [Line Items]

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 standards for air, water, land, and protection of other natural resources, 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.

During 2015, the Company indirectly acquired a 51% membership interest in RE Roserock LLC (Roserock), the owner of the Roserock facility in Pecos County, Texas, which was under construction by Recurrent Energy, LLC and was subsequently placed in service in November 2016. Prior to placing the facility in service, certain solar panels were damaged during installation. While the facility currently is generating energy consistent with operational expectations and PPA obligations, the Company is pursuing remedies under its insurance policies and other contracts to repair or replace these solar panels. In connection therewith, the Company is withholding payments of approximately $26 million from the construction contractor, who has placed a lien on the Roserock facility for the same amount. The amounts withheld are included in other accounts payable and other current liabilities on the Company's consolidated balance sheets. On May 18, 2017, Roserock filed a lawsuit in the state district court in Pecos County, Texas, against XL Insurance America, Inc. (XL) and North American Elite Insurance Company (North American Elite) seeking recovery from an insurance policy for damages resulting from a hail storm and certain installation practices by the construction contractor, McCarthy Building Companies, Inc. (McCarthy). On May 19, 2017, Roserock filed a separate lawsuit against McCarthy in the state district court in Travis County, Texas alleging breach of contract and breach of warranty for the damages sustained at the Roserock facility, which has since been moved to the U.S. District Court for the Western District of Texas. On May 22, 2017, McCarthy filed a counter lawsuit against Roserock, Array Technologies, Inc., Canadian Solar (USA), Inc., XL, and North American Elite in the U.S. District Court for the Western District of Texas alleging, among other things, breach of contract, and requesting foreclosure of mechanic's liens against Roserock. On July 18, 2017, the U.S. District Court for the Western District of Texas consolidated the two pending lawsuits. On December 11, 2017, the U.S. District Court for the Western District of Texas dismissed McCarthy's claims against Canadian Solar (USA), Inc. and dismissed cross-claims that XL and North American Elite had sought to bring against Roserock. The Company intends to vigorously pursue and defend these matters, the ultimate outcome of which cannot be determined at this time.

FERC Matters

The Company and certain of its generation subsidiaries are subject to regulation by the FERC. 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 electric operating companies and the Company filed a triennial market power analysis in 2014, which included continued reliance on the energy auction as tailored mitigation. In 2015, the FERC issued an order finding that the traditional electric 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 electric operating companies and in some adjacent areas. The FERC directed the traditional electric 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 electric operating companies and the Company filed a request for rehearing and filed their response with the FERC in 2015.

In December 2016, the traditional electric operating companies and the Company filed an amendment to their market-based rate tariff that proposed certain changes to the energy auction, as well as several non-tariff changes. On February 2, 2017, the FERC issued an order accepting all such changes subject to an additional condition of cost-based price caps for certain sales outside of the energy auction, finding that all of these changes would provide adequate alternative mitigation for the traditional electric operating companies' and the Company's potential to exert market power in certain areas served by the traditional electric operating companies and in some adjacent areas. On May 17, 2017, the FERC accepted the traditional electric operating companies' and the Company's compliance filing accepting the terms of the order. While the FERC's February 2, 2017 order references the market power proceeding discussed above, it remains a separate, ongoing matter.

On October 25, 2017, the FERC issued an order in response to the traditional electric operating companies' and the Company's June 29, 2017 triennial updated market power analysis. The FERC directed the traditional electric operating companies and the Company to show cause within 60 days why market-based rate authority should not be revoked in certain areas adjacent to the area presently under mitigation in accordance with the February 2, 2017 order or to provide a mitigation plan to further address market power concerns. On November 10, 2017, the traditional electric operating companies and the Company responded to the FERC and proposed to resolve matters by applying the alternative mitigation authorized by the February 2, 2017 order to the adjacent areas made the subject of the October 25, 2017 order.

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

SOUTHERN Co GAS

Loss Contingencies [Line Items]

CONTINGENCIES AND REGULATORY MATTERS

General Litigation Matters

Nicor Gas and Nicor Energy Services Company, wholly-owned subsidiaries of the Company, and Nicor Inc. were defendants in a putative class action initially filed in 2011 in the state court in Cook County, Illinois. The plaintiffs purported to represent a class of the customers who purchased the Gas Line Comfort Guard product from Nicor Energy Services Company and variously alleged that the marketing, sale, and billing of the Gas Line Comfort Guard product violated the Illinois Consumer Fraud and Deceptive Business Practices Act, constituting common law fraud and resulting in unjust enrichment of these entities. The plaintiffs sought, on behalf of the classes they purported to represent, actual and punitive damages, interest, costs, attorney fees, and injunctive relief. On February 8, 2017, the judge denied the plaintiffs' motion for class certification and the Company's motion for summary judgment. On March 7, 2017, the parties reached a settlement, which was finalized and effective on April 3, 2017. The settlement did not have a material impact on the Company's financial statements.

The Company is assessing its alleged involvement in an incident that occurred in one of its service territories that resulted in several deaths, injuries, and property damage. One of the Company's utilities has been named as one of the defendants in several lawsuits related to this incident. The Company has insurance that provides full coverage of any financial exposure in excess of $11 million that is related to this incident. During the successor period ended December 31, 2016 and the predecessor period ended December 31, 2015, the Company recorded reserves for substantially all of its potential exposure from these cases. The ultimate outcome of this matter cannot be determined at this time.

The Company is subject to certain claims and legal actions arising in the ordinary course of business. The ultimate outcome of these matters and such pending or potential litigation against the Company cannot be determined 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

The Company's operations are regulated by state and federal environmental agencies through a variety of laws and regulations governing air, water, land, and protection of other natural resources. The Company maintains a comprehensive environmental compliance strategy to assess upcoming requirements and compliance costs associated with these environmental laws and regulations. The costs, including capital expenditures and operations and maintenance costs, required to comply with environmental laws and regulations impact future results of operations, cash flows, and financial condition. Compliance costs may result from the installation of additional environmental controls. Compliance with these environmental requirements involves significant capital and operating costs to clean up affected sites. The Company conducts studies to determine the extent of any required clean up and has recognized in its financial statements the costs to clean up known impacted sites. The natural gas distribution utilities in Illinois, New Jersey, Georgia, and Florida have each received authority from their applicable state regulatory agencies to recover approved environmental compliance costs through regulatory mechanisms.

The Company is subject to environmental remediation liabilities associated with 46 former MGP sites in five different states. Accrued environmental remediation costs of $388 million and $426 million have been recorded in the balance sheets as of December 31, 2017 and 2016, respectively. These environmental remediation expenditures are recoverable from customers through rate mechanisms approved by the applicable state regulatory agencies, with the exception of one site representing $2 million of the accrued remediation costs.

In 2015, the EPA filed an administrative complaint and notice of opportunity for hearing against Nicor Gas. The complaint alleged violation of the regulatory requirements applicable to polychlorinated biphenyls in the Nicor Gas distribution system and the EPA sought a total civil penalty of $0.3 million. On January 26, 2017, the EPA notified Nicor Gas that it agreed to voluntarily dismiss its administrative complaint with prejudice and without payment of a civil penalty or other further obligation on the part of Nicor Gas.

The Company's ultimate environmental compliance strategy and future environmental capital expenditures will be affected by the final requirements of new or revised environmental regulations and the outcome of any legal challenges to the environmental rules. The ultimate outcome of these matters cannot be determined at this time.

FERC Matters

At December 31, 2017, gas midstream operations was involved in two gas pipeline construction projects. These projects, along with the Company's existing pipelines, are intended to provide diverse sources of natural gas supplies to customers, resolve current and long-term supply planning for new capacity, enhance system reliability, and generate economic development in the areas served. On October 13, 2017, the Atlantic Coast Pipeline project received FERC approval. On January 19, 2018, the PennEast Pipeline project received FERC approval.

Additionally, on August 1, 2017, the Dalton Pipeline was placed in service as authorized by the FERC and transportation service for customers commenced. See Note 4 for additional information.

Regulatory Matters

Regulatory Infrastructure Programs

The Company has infrastructure improvement programs at several of its utilities. Descriptions of these programs are as follows:

Nicor Gas

In 2013, Illinois enacted legislation that allows Nicor Gas to provide more widespread safety and reliability enhancements to its distribution system. The legislation stipulates that rate increases to customers as a result of any infrastructure investments shall not exceed a cumulative annual average of 4.0% or, in any given year, 5.5%, of base rate revenues. In 2014, the Illinois Commission approved the nine-year regulatory infrastructure program, Investing in Illinois, under which Nicor Gas implemented rates that became effective in March 2015.

Investing in Illinois is subject to annual review by the Illinois Commission. In conjunction with the base rate case order issued by the Illinois Commission on January 31, 2018, Nicor Gas is recovering the portion of these program costs incurred prior to December 31, 2017 through base rates. See "Base Rate Cases" herein for additional information.

Atlanta Gas Light

Atlanta Gas Light's STRIDE program, which was initially approved by the Georgia PSC in 2009, is comprised of the Integrated System Reinforcement Program (i-SRP), the Integrated Customer Growth Program (i-CGP), and the Integrated Vintage Plastic Replacement Program (i-VPR) and consists of infrastructure development, enhancement, and replacement programs that are used to update and expand distribution systems and LNG facilities, improve system reliability, and meet operational flexibility and growth. For 2017 and subsequent years, the recovery of and return on current and future capital investments under the STRIDE program are included in the annual base rate revenue adjustment under GRAM.

The i-CGP program authorized Atlanta Gas Light to spend $91 million through 2017 on projects to extend its pipeline facilities to serve customers in areas without pipeline access and create new economic development opportunities in Georgia. This program ended in 2017 and was replaced with a tariff to provide up to $15 million annually for Atlanta Gas Light to commit to strategic economic development projects.

The i-SRP program authorized $445 million of capital spending through 2017 for projects to upgrade Atlanta Gas Light's distribution system and LNG facilities in Georgia, improve its peak-day system reliability and operational flexibility, and create a platform to meet long-term forecasted growth. In August 2016, Atlanta Gas Light filed a petition with the Georgia PSC for approval of a four-year extension of its i-SRP seeking approval to invest an additional $177 million to improve and upgrade its core gas distribution system in years 2017 through 2020.

The i-VPR program authorized Atlanta Gas Light to spend $275 million through 2017 to replace 756 miles of aging plastic pipe that was installed primarily in the mid-1960s to the early 1980s. Atlanta Gas Light has identified approximately 3,300 miles of vintage plastic mains in its system that should be considered for potential replacement.

See "Base Rate Cases" herein for additional information.

The orders for the STRIDE programs provide for recovery of all prudent costs incurred in the performance of the program. Atlanta Gas Light will recover from end-use customers, through billings to Marketers, the costs related to the programs net of any cost savings from the programs. The regulatory asset represents recoverable incurred costs related to the programs that will be collected in future rates charged to customers through the rate riders. The future expected costs to be recovered through rates related to allowed, but not incurred costs, are recognized in an unrecognized ratemaking amount that is not reflected on the balance sheets. This allowed cost is primarily the equity return on the capital investment under the program. See "Unrecognized Ratemaking Amounts" herein for additional information.

Atlanta Gas Light capitalizes and depreciates the capital expenditure costs incurred from the STRIDE programs over the life of the assets. Operations and maintenance costs are expensed as incurred. Recoveries, which are recorded as revenue, are based on a formula that allows Atlanta Gas Light to recover operations and maintenance costs in excess of those included in its current base rates, depreciation, and an allowed rate of return on capital expenditures. However, Atlanta Gas Light is allowed the recovery of carrying costs on the under recovered balance resulting from the timing difference.

Elizabethtown Gas

Elizabethtown Gas' 2013 extension of the Aging Infrastructure Replacement (AIR) enhanced infrastructure program allowed for infrastructure investment of $115 million over four years and was focused on the replacement of aging cast iron in its pipeline system. Carrying charges on the additional capital spend are being accrued and deferred for regulatory purposes at a weighted average cost of capital of 6.65%. Effective July 1, 2017, investments under this program, which ended September 30, 2017, are being recovered through base rate revenues. See "Base Rate Cases" herein for additional information.

In 2015, Elizabethtown Gas filed the Safety, Modernization and Reliability Tariff plan with the New Jersey BPU seeking approval to invest more than $1.1 billion to replace 630 miles of vintage cast iron, steel, and copper pipeline, as well as 240 regulator stations. During the first quarter 2018, Elizabethtown Gas withdrew this filing in response to a proposed rule by the New Jersey BPU to incentivize utilities to accelerate investment in infrastructure replacement programs that enhance reliability, resiliency, and/or safety of the distribution system. The ultimate outcome of this matter cannot be determined at this time.

Virginia Natural Gas

In 2012, the Virginia Commission approved the Steps to Advance Virginia's Energy (SAVE) program, an accelerated infrastructure replacement program, to be completed over a five-year period. This program included a maximum allowance for capital expenditures of $25 million per year, not to exceed $105 million in total.

In March 2016, the Virginia Commission approved an extension to the SAVE program for Virginia Natural Gas to replace more than 200 miles of aging pipeline infrastructure and invest up to $30 million in 2016 and up to $35 million annually through 2021.

The SAVE program is subject to annual review by the Virginia Commission. In conjunction with the base rate case order issued by the Virginia Commission on December 21, 2017, Virginia Natural Gas is recovering the portion of these program costs incurred prior to September 1, 2017 through base rates. See "Base Rate Cases" herein for additional information.

Florida City Gas

In 2015, the Florida PSC approved Florida City Gas' Safety, Access, and Facility Enhancement program, under which costs incurred for replacing aging pipes are recovered through a rate rider with annual adjustments and true-ups. Under the program, Florida City Gas is authorized to spend $105 million over a 10-year period on infrastructure relocation and enhancement projects.

PRP Settlement

In 2015, Atlanta Gas Light received a final order from the Georgia PSC for a rate true-up of allowed unrecovered revenue through 2014 related to its PRP. This order allows Atlanta Gas Light to recover $144 million of the $178 million previously unrecovered program revenue. The remaining $34 million requested related primarily to previously unrecognized ratemaking amounts and did not have a material impact on the Company's financial statements. The Company also recognized $1 million of interest expense and $5 million in operations and maintenance expense related to the PRP on the Company's statements of income for the predecessor year ended December 31, 2015. See "Unrecognized Ratemaking Amounts" herein for additional information.

As a result of the PRP settlement, Atlanta Gas Light began recovering incremental PRP surcharge amounts through three phased in increases in addition to its previously existing PRP surcharge amount, which was established to address recovery of the unrecovered PRP balance of $144 million in 2015 and the estimated amounts to be earned under the program through 2025. The initial incremental surcharge of approximately $15 million annually was effective in October 2015, with additional annual increases of approximately $15 million in each of October 2016 and 2017. The final increase scheduled for October 2017 was included in the implementation of GRAM in March 2017. The under recovered balance is the result of the continued revenue requirement earned under the program offset by the existing and incremental PRP surcharges. The unrecovered balance at December 31, 2017 was $187 million, including $104 million of unrecognized equity return. The PRP surcharge will remain in effect until the earlier of the full recovery of the under recovered amount or December 31, 2025. See "Base Rate Cases" herein for additional information on GRAM.

One of the capital projects under the PRP experienced construction issues and Atlanta Gas Light was required to complete mitigation work prior to placing it in service. These mitigation costs will be included in future base rates in 2018. Provisions in the order resulted in the recognition of $5 million in operations and maintenance expense for the predecessor year ended December 31, 2015 on the Company's statements of income. In 2017, Atlanta Gas Light recovered $20 million from the settlement of contractor litigation claims and continues to pursue contractual and legal claims against a third-party contractor. Mitigation costs recovered through the legal process are retained by Atlanta Gas Light. The ultimate outcome of this matter cannot be determined at this time.

Base Rate Cases

Settled Base Rate Cases

On February 21, 2017, the Georgia PSC approved GRAM and a $20 million increase in annual base rate revenues for Atlanta Gas Light, effective March 1, 2017. GRAM adjusts base rates annually, up or down, using an earnings band based on the previously approved ROE of 10.75% and does not collect revenue through special riders and surcharges. Atlanta Gas Light adjusts rates up to

the lower end of the band of 10.55% and adjusts rates down to the higher end of the band of 10.95%. Various infrastructure programs previously authorized by the Georgia PSC under Atlanta Gas Light's STRIDE program, which include the i-VPR and i-SRP, will continue under GRAM and the recovery of and return on the infrastructure program investments will be included in annual base rate adjustments. The Georgia PSC will review Atlanta Gas Light's performance annually under GRAM.

Pursuant to the GRAM approval, Atlanta Gas Light and the staff of the Georgia PSC agreed to a variation to the i-CGP that was formerly part of Atlanta Gas Light's STRIDE program. As a result, a new tariff was created, effective October 10, 2017, to provide up to $15 million annually for Atlanta Gas Light to commit to strategic economic development projects. Projects under this tariff must be approved by the Georgia PSC.

Beginning with the next rate adjustment in June 2018, Atlanta Gas Light's recovery of the previously unrecovered Pipeline Replacement Program revenue through 2014, as well as the mitigation costs associated with the Pipeline Replacement Program that were not previously included in its rates, will also be included in GRAM. In connection with the GRAM approval, the last monthly Pipeline Replacement Program surcharge increase became effective March 1, 2017.

On June 30, 2017, the New Jersey BPU approved a settlement that provides for a $13 million increase in annual base rate revenues, effective July 1, 2017, based on a ROE of 9.6%. Also included in the settlement was a new composite depreciation rate that is expected to result in a $3 million annual reduction of depreciation. See Note 11 under "Proposed Sale of Elizabethtown Gas and Elkton Gas" for information on the proposed sale of Elizabethtown Gas.

On December 21, 2017, the Virginia Commission approved a settlement for a $34 million increase in annual base rate revenues, effective September 1, 2017, including $13 million related to the recovery of investments under the SAVE program. See "Regulatory Infrastructure Programs" herein for additional information. An authorized ROE range of 9.0% to 10.0% with a midpoint of 9.5% will be used to determine the revenue requirement in any filing, other than for a change in base rates.

On January 31, 2018, the Illinois Commission approved a $137 million increase in annual base rate revenues, including $93 million related to the recovery of investments under the Investing in Illinois program, effective February 8, 2018, based on a ROE of 9.8%.

Pending Base Rate Cases

On October 23, 2017, Florida City Gas filed a general base rate case with the Florida PSC requesting a $19 million increase in annual base rate revenues. On January 29, 2018, Florida City Gas filed an update to incorporate the effects of the Tax Reform Legislation that, if approved, would reduce the requested base rate revenues by $4 million. The requested increase is based on a 2018 projected test year and a ROE of 11.25%. The requested increase includes $3 million related to the recovery of investments under SAFE that are currently being recovered through a surcharge. Additionally, Florida City Gas requested an interim rate increase of $5 million annually that was approved and became effective January 12, 2018, subject to refund. The Florida PSC is expected to rule on the requested increase in mid-2018.

On December 1, 2017, Atlanta Gas Light filed its 2018 annual rate adjustment with the Georgia PSC. If approved, annual base rate revenues will increase by $22 million, effective June 1, 2018. Atlanta Gas Light will file a revised rate adjustment to incorporate the effects of the Tax Reform Legislation in the first quarter 2018. The Georgia PSC is expected to rule on the revised requested increase in the second quarter 2018.

On February 15, 2018, Chattanooga Gas filed a general base rate case with the Tennessee Public Utility Commission requesting a $7 million increase in annual base rate revenues. The requested increase, which incorporated the effects of the Tax Reform Legislation, was based on a projected test year ending June 30, 2019 and a ROE of 11.25%. The Tennessee Public Utility Commission is expected to rule on the requested increase in the third quarter 2018.

The ultimate outcome of these pending base rate cases cannot be determined at this time.

Other

The New Jersey BPU, Virginia Commission, Tennessee Public Utility Commission, and Maryland PSC each issued an order effective January 1, 2018 that requires utilities in their respective states to track as a regulatory liability the impact of the Tax Reform Legislation, including the reduction in the corporate income tax rate to 21% and the impact of excess deferred income taxes. The New Jersey BPU's order requires Elizabethtown Gas to file by March 2, 2018 proposed revised base rates with an April 1, 2018 interim effective date and a July 1, 2018 final effective date. Virginia Natural Gas will address the Virginia Commission's order in its Annual Information Filing, which will be filed by July 1, 2018. The Tennessee Public Utility Commission's order required Chattanooga Gas to file proposals to reduce rates or make other ratemaking adjustments to account for the impact of the Tax Reform Legislation. Chattanooga Gas made the required filing as part of its February 15, 2018 general base rate case filing. The Maryland PSC's order required Elkton Gas to file an explanation of the impact of the Tax Reform Legislation on its expenses and revenues, as well as when and how it expects to pass through to its customers those effects. Elkton Gas made the required filing on February 15, 2018 and will reduce annual base rates by $0.1 million effective April 1, 2018. Credits will be issued to customers for the impact of the Tax Reform Legislation from January 2018 through March 2018.

The Illinois Commission issued an order effective January 25, 2018 that requires utilities in the state to record the impacts of the Tax Reform Legislation, including the reduction in the corporate income tax rate to 21% and the impact of excess deferred income taxes, as a regulatory liability. On February 20, 2018, the Illinois Commission granted Nicor Gas' application for rehearing to file revised base rates and tariffs, which Nicor Gas expects to file by the end of the second quarter 2018.

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

energySMART

In 2014, the Illinois Commission approved Nicor Gas' energySMART through 2017, which outlined energy efficiency program offerings and therm reduction goals, and subsequently extended the program to 2021. Through December 31, 2017, Nicor Gas spent $107 million of the initial authorized expenditure of $113 million. A new four-year program began on January 1, 2018, with an additional authorized expenditure of $160 million.

Unrecognized Ratemaking Amounts

The following table illustrates the Company's authorized ratemaking amounts that are not recognized on its balance sheets. These amounts are primarily composed of an allowed equity rate of return on assets associated with certain of the Company's regulatory infrastructure programs. These amounts will be recognized as revenues in the Company's financial statements in the periods they are billable to customers, the majority of which will be recovered by 2025.



	December 31, 2017		December 31, 2016
	(in millions)
Atlanta Gas Light	$	104	$	110
Virginia Natural Gas	11		11
Elizabethtown Gas^(*)	8		6
Nicor Gas	2		2
Total	$	125	$	129

(*) See Note 11 under "Proposed Sale of Elizabethtown Gas and Elkton Gas" for information on the pending asset sale.

Other Matters

A wholly-owned subsidiary of the Company owns and operates a natural gas storage facility consisting of two salt dome caverns in Louisiana. Periodic integrity tests are required in accordance with rules of the Louisiana Department of Natural Resources (DNR). In August 2017, in connection with an ongoing integrity project, updated seismic mapping indicated the proximity of one of the caverns to the edge of the salt dome may be less than the required minimum and could result in the Company retiring the cavern early. At December 31, 2017, the facility's property, plant, and equipment had a net book value of $112 million, of which the cavern itself represents approximately 20%. A potential early retirement of this cavern is dependent upon several factors including compliance with an order from the Louisiana DNR detailing the requirements to place the cavern back in service, which includes, among other things, obtaining core samples to determine the composition of the sheath surrounding the edge of the salt dome.

The cavern continues to maintain its pressures and overall structural integrity. These events were considered in connection with the Company's annual long-lived asset impairment analysis, which determined there was no impairment as of December 31, 2017. Any changes in results of monitoring activities, rates at which expiring capacity contracts are re-contracted, timing of placing the cavern back in service, or Louisiana DNR requirements could trigger impairment. Further, early retirement of the cavern could trigger impairment of other long-lived assets associated with the natural gas storage facility. The ultimate outcome of this matter cannot be determined at this time, but could have a material impact on the Company's financial statements.