On January 1, 2019, Southern Company completed the sale of Gulf Power to NextEra Energy for an aggregate cash purchase price of approximately $5.8 billion (less $1.3 billion of indebtedness assumed), subject to customary working capital adjustments. The preliminary gain associated with the sale of Gulf Power totaled $2.5 billion pre-tax ($1.3 billion after tax). See Note (K) to the10-K are generally omitted from this Quarterly Report on Form 10-Q unless specifically required by GAAP. Therefore, these Condensed Financial Statements ~~under "Southern Company" herein for additional information.~~

~~Georgia Power and Atlanta Gas Light each filed base rate cases~~should be read in conjunction with the ~~Georgia PSC~~financial statements and the notes thereto included in ~~June 2019. Georgia Power's filing,~~the Form 10-K. Due to the seasonal variations in the demand for energy, operating results for the periods presented are not necessarily indicative of the operating results to be expected for the full year.

Southern Company continues to focus on several key performance indicators. These indicators include, but are not limited to, customer satisfaction, plant availability, electric and natural gas system reliability, execution of major construction projects, and earnings per share.

Third Quarter 2019 vs. Third Quarter 2018 Year-to-Date 2019 vs. Year-to-Date 2018
(change in millions) (% change) (change in millions) (% change)
$152 13.1 $2,350 120.6

Consolidated net income attributable to Southern Company was $1.3 billion ($1.26 per share) for the third quarter 2019 compared to $1.2 billion ($1.14 per share) for the corresponding period in 2018. The increase was primarily due to increased retail revenues at Alabama Power primarily due to the impact of customer bill credits issued in 2018 related to the Tax Reform Legislation and at Georgia Power primarily due to higher contributions from commercial and industrial customers with variable demand-driven pricing as well as warmer weather in the third quarter 2019 when compared to the corresponding period in 2018, partially offset by a reduction in customer usage at Alabama Power and Georgia Power. The increase in net income was also partially offset by increased impairment charges primarily related to a third quarter 2019 charge recorded at Southern Company Gas related to a natural gas storage facility.

Consolidated net income attributable to Southern Company was $4.3 billion ($4.12 per share) for year-to-date 2019 compared to $1.9 billion ($1.92 per share) for the corresponding period in 2018. The increase was primarily due to the $2.5 billion ($1.3 billion after tax) gain on the sale of Gulf Power in 2019 and a $1.1 billion ($0.8 billion after tax) charge in the second quarter 2018 for an estimated probable loss related to Georgia Power's construction of Plant Vogtle Units 3 and 4. See Note (K) to the Condensed Financial Statements under "~~Southern Company" herein and Note 2 to the financial statements under "Georgia Power – Nuclear Construction" in Item 8 of the Form 10-K for additional information.~~

Third Quarter 2019 vs. Third Quarter 2018 Year-to-Date 2019 vs. Year-to-Date 2018
(change in millions) (% change) (change in millions) (% change)
$(93) (2.0) $(777) (6.5)

In the third quarter 2019, retail electric revenues were $4.5 billion compared to $4.6 billion for the corresponding period in 2018. For year-to-date 2019, retail electric revenues were $11.1 billion compared to $11.9 billion for the corresponding period in 2018.

~~Details of the changes in retail electric revenues were as follows:~~

Third Quarter 2019 Year-to-Date 2019
(in millions) (% change) (in millions) (% change)
Retail electric – prior year $ 4,605
$ 11,913

Estimated change resulting from –
Rates and pricing 242
5.3 % 425
3.6 %
Sales decline (71 ) (1.6 ) (111 ) (0.9 )
Weather 125
2.7
68
0.5
Fuel and other cost recovery (48 ) (1.0 ) (227 ) (1.9 )
Gulf Power disposition (341 ) (7.4 ) (932 ) (7.8 )
Retail electric – current year $ 4,512
(2.0 )% $ 11,136
(6.5 )%

Revenues associated with changes in rates and pricing increased in the third quarter and year-to-date 2019 when compared to the corresponding periods in 2018 primarily due to the impacts of Alabama Power's customer bill credits issued in 2018 related to the Tax Reform Legislation, additional capital investments recovered through Alabama Power's Rate CNP Compliance, higher contributions from Georgia Power's commercial and industrial customers with variable demand-driven pricing, an increase in Georgia Power's NCCR tariff effective January 1, 2019, and increases in Mississippi Power's PEP and ECO Plan rates that became effective for the first billing cycle of September 2018.

See Note 2 to the financial statements under "Alabama Power," "Georgia Power," and "Mississippi Power" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements herein for additional information.

Revenues attributable to changes in sales decreased in the third quarter and year-to-date 2019 when compared to the corresponding periods in 2018. Weather-adjusted residential KWH sales decreased 1.9% and 0.9% in the third quarter and year-to-date 2019, respectively, when compared to the corresponding periods in 2018 primarily due to decreased customer usage at Alabama Power and Georgia Power primarily resulting from an increase in energy efficient residential appliances and energy saving initiatives, partially offset by customer growth. Weather-adjusted commercial KWH sales decreased 2.1% and 1.7% in the third quarter and year-to-date 2019, respectively, when compared to the corresponding periods in 2018 primarily due to decreased customer usage resulting from an increase in energy saving initiatives. Industrial KWH sales decreased 3.3% and 2.5% in the third quarter and year-to-date 2019, respectively, when compared to the corresponding periods in 2018 as a result of a decrease in demand

~~resulting from changes in production levels primarily in the primary metals, textile, stone, clay, and glass, paper, and chemicals sectors.~~

Fuel and other cost recovery revenues decreased $48 million and $227 million in the third quarter and year-to-date 2019, respectively, compared to the corresponding periods in 2018. For year-to-date 2019, the decrease was primarily due to lower generation costs at Alabama Power and Georgia Power and lower recoverable fuel costs at Mississippi Power. Electric rates for the traditional electric operating companies include ~~provisions to adjust billings for fluctuations in fuel costs, including the energy component of purchased power costs. Under these provisions, fuel revenues generally equal fuel expenses, includi~~ng the energy component of PPA costs, and do not affect net income. The traditional electric operating companies each have one or more regulatory mechanisms to recover other costs such as environmental and other compliance costs, storm damage, new plants, and PPA capacity costs.

Third Quarter 2019 vs. Third Quarter 2018 Year-to-Date 2019 vs. Year-to-Date 2018
(change in millions) (% change) (change in millions) (% change)
$(73) (10.5) $(270) (13.9)

Wholesale electric revenues consist of PPAs and short-term opportunity sales. Wholesale electric revenues from PPAs (other than solar and wind PPAs) have both capacity and energy components. Capacity revenues generally represent the greatest contribution to net income and are designed to provide recovery of fixed costs plus a return on investment. Energy revenues will vary depending on fuel prices, the market prices of wholesale energy compared to the Southern Company system's generation, demand for energy within the Southern Company system's electric service territory, and the availability of the Southern Company system's generation. Increases and decreases in energy revenues that are driven by fuel prices are accompanied by an increase or decrease in fuel costs and do not have a significant impact on net income. Energy sales from solar and wind PPAs do not have a capacity charge and customers either purchase the energy output of a dedicated renewable facility through an energy charge or through a fixed price related to the energy. As a result, the ability to recover fixed and variable operations and maintenance expenses is dependent upon the level of energy generated from these facilities, which can be impacted by weather conditions, equipment performance, transmission constraints, and other factors. Wholesale electric revenues at Mississippi Power include FERC-regulated municipal and rural association sales under cost-based tariffs as well as market-based sales. Short-term opportunity sales are made at market-based rates that generally provide a margin above the Southern Company system's variable cost to produce the energy.

In the third quarter 2019, wholesale electric revenues were $625 million compared to $698 million for the corresponding period in 2018. For year-to-date 2019, wholesale electric revenues were $1.7 billion compared to $1.9 billion for the corresponding period in 2018. The third quarter 2019 decrease was related to a $44 million decrease in energy revenues and a $29 million decrease in capacity revenues. The year-to-date 2019 decrease was related to a $204 million decrease in energy revenues and a $66 million decrease in capacity revenues. Excluding decreases of $8 million and $21 million of energy revenues for the third quarter and year-to-date 2019, respectively, related to the sale of Gulf Power, the decreases in energy revenues primarily related to Southern Power and included a decrease in non-PPA revenues due to a decrease in the volume of KWHs sold through short-term sales and a decrease in the market price of energy. These decreases were also due to lower natural gas prices. The decreases in capacity revenues primarily related to the sales of Gulf Power and Southern Power's Plant Oleander and Plant Stanton Unit A in December 2018 and Southern Power's Plant Nacogdoches in June 2019. See Note (K) to the Condensed Financial Statements under "~~Southern Company" and "Southern Power" herein and Note 15 to the financial statements under "Southern Power – Sales of Natural Gas Plants" in Item 8 of the Form 10-K for additional information.~~

In the third quarter 2019, natural gas revenues were $498 million compared to $492 million for the corresponding period in 2018. For year-to-date 2019, natural gas revenues were $2.7 billion compared to $2.8 billion for the corresponding period in 2018.

Third Quarter 2019 vs. Third Quarter 2018 Year-to-Date 2019 vs. Year-to-Date 2018
(change in millions) (% change) (change in millions) (% change)
$(2) (1.0) $(458) (45.5)

For year-to-date 2019, other revenues were $549 million compared to $1.0 billion for the corresponding period in 2018. This decrease was primarily related to PowerSecure's 2018 storm restoration services in Puerto Rico.

Third Quarter 2019
vs.
Third Quarter 2018 Year-to-Date 2019
vs.
Year-to-Date 2018
(change in millions) (% change) (change in millions) (% change)
Fuel $ (238 ) (18.2) $ (678 ) (19.3)
Purchased power (3 ) (1.2) (135 ) (17.8)
Total fuel and purchased power expenses $ (241 ) $ (813 )

In the third quarter 2019, total fuel and purchased power expenses were $1.33 billion compared to $1.57 billion for the corresponding period in 2018. Excluding approximately $148 million associated with the sale of Gulf Power, the decrease was primarily the result of a $158 million decrease in the average cost of fuel and purchased power, partially offset by a $65 million net increase in the aggregate volume of KWHs generated and purchased.

For year-to-date 2019, total fuel and purchased power expenses were $3.5 billion compared to $4.3 billion for the corresponding period in 2018. Excluding approximately $373 million associated with the sale of Gulf Power, the decrease was primarily the result of a $345 million decrease in the average cost of fuel and purchased power and a $95 million net decrease in the aggregate volume of KWHs generated and purchased.

Third Quarter 2019
Third Quarter 2018^(a)
Year-to-Date 2019
Year-to-Date 2018^(a)
Total generation (in billions of KWHs)
54 53 143 146
Total purchased power (in billions of KWHs)
6 4 14 11
Sources of generation (percent) —

Gas 54 50 51 48
Coal 24 28 23 27
Nuclear 15 15 16 15
Hydro 1 2 4 3
Other 6 5 6 7
Cost of fuel, generated (in cents per net KWH)—

Gas 2.25 2.62 2.39 2.65
Coal 2.85 2.92 2.93 2.96
Nuclear 0.79 0.81 0.79 0.80
Average cost of fuel, generated (in cents per net KWH)
2.18 2.42 2.24 2.43
Average cost of purchased power (in cents per net KWH)^(b)
5.22 6.18 5.11 6.14

In the third quarter 2019, fuel expense was $1.1 billion compared to $1.3 billion for the corresponding period in 2018. Excluding approximately $96 million related to Gulf Power in 2018, the decrease was primarily due to a 14.1% decrease in the average cost of natural gas per KWH generated, a 9.9% decrease in the volume of KWHs generated by coal, and a 2.4% decrease in the average cost of coal per KWH generated, partially offset by a 6.7% increase in the volume of KWHs generated by natural gas.

For year-to-date 2019, fuel expense was $2.8 billion compared to $3.5 billion for the corresponding period in 2018. Excluding approximately $223 million related to Gulf Power in 2018, the decrease was primarily due to an 18.1% decrease in the volume of KWHs generated by coal, a 9.8% decrease in the average cost of natural gas per KWH generated, and a 1.0% decrease in the average cost of coal per KWH generated, partially offset by a 4.1% increase in the volume of KWHs generated by natural gas.

In the third quarter 2019, purchased power expense was $254 million compared to $257 million for the corresponding period in 2018. Excluding approximately $53 million associated with Gulf Power, the change was primarily due to a 28.6% increase in the volume of KWHs purchased, partially offset by a 15.5% decrease in the average cost per KWH purchased.

For year-to-date 2019, purchased power expense was $625 million compared to $760 million for the corresponding period in 2018. Excluding approximately $150 million associated with Gulf Power, the change was primarily due to an 8.3% increase in the volume of KWHs purchased, partially offset by a 16.8% decrease in the average cost per KWH purchased.

~~See Note (K) to the Condensed Financial Statements under "Southern Company" herein for information regarding the sale of Gulf Power.~~

For year-to-date 2019, cost of other sales was $316 million compared to $688 million for the corresponding period in 2018. This decrease was primarily related to PowerSecure's 2018 storm restoration services in Puerto Rico.

Third Quarter 2019 vs. Third Quarter 2018 Year-to-Date 2019 vs. Year-to-Date 2018
(change in millions) (% change) (change in millions) (% change)
$(112) (8.0) $(329) (7.8)

Third Quarter 2019 vs. Third Quarter 2018 Year-to-Date 2019 vs. Year-to-Date 2018
(change in millions) (% change) (change in millions) (% change)
$(27) (3.4) $(71) (3.0)

In the third quarter 2019, depreciation and amortization was $760 million compared to $787 million for the corresponding period in 2018. For year-to-date 2019, depreciation and amortization was $2.27 billion compared to $2.34 billion for the corresponding period in 2018. The third quarter and year-to-date 2019 decreases were primarily due to decreases of $48 million and $142 million, respectively, related to the sale of Gulf Power and decreases of $1 million and $27 million, respectively, related to the Southern Company Gas Dispositions, partially offset by increases of $19 million and $81 million, respectively, related to additional plant in service. The year-to-date 2019 decrease was also partially offset by increased amortization of $18 million associated with ECO Plan regulatory assets at Mississippi Power.

Third Quarter 2019 vs. Third Quarter 2018 Year-to-Date 2019 vs. Year-to-Date 2018
(change in millions) (% change) (change in millions) (% change)
$(16) (5.0) $(59) (6.0)

In the third quarter 2019, taxes other than income taxes were $303 million compared to $319 million for the corresponding period in 2018. For year-to-date 2019, taxes other than income taxes were $931 million compared to $990 million for the corresponding period in 2018. These decreases primarily relate to the sale of Gulf Power, partially offset by an increase in the assessed value of property at Georgia Power. The year-to-date 2019 decrease was also partially offset by increases in invested capital tax at Southern Company Gas as a result of increased infrastructure investments and increased revenue tax expenses.

Third Quarter 2019 vs. Third Quarter 2018 Year-to-Date 2019 vs. Year-to-Date 2018
(change in millions) (% change) (change in millions) (% change)
$3 N/M $(1,095) (99.1)

~~See Note 2 to the financial statements in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements herein under "Georgia Power~~ – ~~Nuclear Construction" for additional information.~~

Third Quarter 2019 vs. Third Quarter 2018 Year-to-Date 2019 vs. Year-to-Date 2018
(change in millions) (% change) (change in millions) (% change)
$(24) (5.2) $(92) (6.6)

Third Quarter 2019 vs. Third Quarter 2018 Year-to-Date 2019 vs. Year-to-Date 2018
(change in millions) (% change) (change in millions) (% change)
$4 7.0 $44 22.6

For year-to-date 2019, other income (expense), net was $239 million compared to $195 million for the corresponding period in 2018. This increase was primarily due to a $36 million gain arising from the settlement of litigation related to the Roserock solar facility at Southern Power in the second quarter 2019, $23 million of increased non-service cost-related pension income, and $10 million of increased interest income from temporary cash investments at the parent company. These increases were partially offset by $24 million related to the settlement of Mississippi Power's Deepwater Horizon claim in May 2018 and a $14 million gain from a joint-development wind project at Southern Power in 2018, which was attributable to its partner in the project and fully offset within noncontrolling interests. See Note (C) to the Condensed Financial Statements under "General Litigation Matters – Southern Power" herein, Note (H) to the Condensed Financial Statements herein, and Note 3 to the financial statements under "Other Matters – Mississippi Power," in Item 8 of the Form 10-K for additional information.

Third Quarter 2019 vs. Third Quarter 2018 Year-to-Date 2019 vs. Year-to-Date 2018
(change in millions) (% change) (change in millions) (% change)
$(256) (41.1) $1,274 N/M

In the third quarter 2019, income taxes were $367 million compared to $623 million for the corresponding period in 2018. Excluding a $312 million decrease related to the Southern Company Gas Dispositions, income taxes increased $56 million primarily due to higher pre-tax earnings.

For year-to-date 2019, income taxes were $1.9 billion compared to $598 million for the corresponding period in 2018. Excluding a $363 million decrease related to the Southern Company Gas Dispositions, income taxes increased $1.6 billion primarily due to the tax impacts related to the sale of Gulf Power and other increases in pre-tax earnings, including the $1.1 billion charge in the second quarter 2018 associated with Plant Vogtle Units 3 and 4 construction, as well as a $105 million reduction in tax benefits associated with wind PTCs following Southern Power's 2018 sale of a noncontrolling tax equity interest in its wind projects.

~~See Notes (G) and (K) to the Condensed Financial Statements herein for additional information.~~

For year-to-date 2019, net income attributable to noncontrolling interests was $26 million compared to $71 million for the corresponding period in 2018. The decrease was primarily due to $70 million of losses attributable to noncontrolling interests related to the tax equity partnerships entered into in 2018, partially offset by an allocation of approximately $29 million of income to the noncontrolling interest partner related to the Roserock solar facility litigation settlement.

The results of operations discussed above are not necessarily indicative of Southern Company's future earnings potential. Future earnings will be impacted by the recently completed and additional pending disposition activities described herein, in Note (K) to the Condensed Financial Statements herein, and in Note 15 to the financial statements in Item 8 of the Form 10-K. The level of Southern Company's future earnings depends on numerous factors that affect the opportunities, challenges, and risks of the Southern Company system's primary businesses of selling electricity and distributing natural gas. These factors include the traditional electric operating companies' and the natural gas distribution utilities' ability to maintain constructive regulatory environments that allow for the timely recovery of prudently-incurred costs during a time of increasing costs, continued customer growth, and, for the traditional electric operating companies, the weak pace of growth in electricity use per customer, especially in residential and commercial markets. Plant Vogtle Units 3 and 4 construction and rate recovery and the profitability of Southern Power's competitive wholesale business are also major factors.

Earnings in the electricity business will also depend upon maintaining and growing sales, considering, among other things, the adoption and/or penetration rates of increasingly energy-efficient technologies, increasing volumes of electronic commerce transactions, and more multi-family home construction, all of which could contribute to a net reduction in customer usage. Earnings for both the electricity and natural gas businesses are subject to a variety of other factors. These factors include weather, competition, new energy contracts with other utilities and other wholesale customers, energy conservation practiced by customers, the use of alternative energy sources by customers, the prices of electricity and natural gas, the price elasticity of demand, and the rate of economic growth or decline in the service territory. In addition, the level of future earnings for the wholesale electric business also depends on numerous factors including regulatory matters, creditworthiness of customers, total electric generating capacity available and related costs, the development or acquisition of renewable facilities and other energy projects, and the successful remarketing of capacity as current contracts expire. Demand for electricity and natural gas is primarily driven by the pace of economic growth that may be affected by changes in regional and global economic conditions, which may impact future earnings. In addition, the volatility of natural gas prices has a significant impact on the natural gas distribution utilities' customer rates, long-term competitive position against other energy sources, and the ability of Southern Company Gas' gas marketing services and wholesale gas services businesses to capture value from locational and seasonal spreads. Additionally, changes in commodity prices subject a significant portion of Southern Company Gas' operations to earnings variability.

As part of its ongoing effort to adapt to changing market conditions, Southern Company continues to evaluate and consider a wide array of potential business strategies. These strategies may include business combinations, partnerships, and acquisitions involving other utility or non-utility businesses or properties, disposition of certain assets or businesses, internal restructuring, or some combination thereof. Furthermore, Southern Company may engage in new business ventures that arise from competitive and regulatory changes in the utility industry. Pursuit of any of the above strategies, or any combination thereof, may significantly affect the business operations, risks, and financial condition of Southern Company.

On June 13, 2019, Southern Power completed the sale of its equity interests in Nacogdoches Power, LLC, the owner of an approximately 115-MW biomass facility located in Nacogdoches County, Texas, to Austin Energy, for a cash purchase price of approximately $461 million.

In November 2018, Southern Power entered into an agreement with Northern States Power (a subsidiary of Xcel) to sell all of its equity interests in Plant Mankato for an aggregate purchase price of approximately $650 million, subject to certain state commission approvals. On September 27, 2019, the Minnesota Public Utilities Commission

denied approval of the transaction. A newly-formed subsidiary of Xcel has agreed to purchase all of the equity interests in Plant Mankato subject to FERC approval and other customary conditions to closing. The transaction is expected to close by January 20, 2020. If the transaction does not close by this date, either party may terminate the transaction, which would result in the payment of a termination fee to Southern Power of up to $25 million. The ultimate outcome of this matter cannot be determined at this time.

~~See "Regulatory Matters~~ ~~– Alabama Power" herein for information regarding Alabama Power's proposed acquisition of an existing combined cycle facility.~~

~~For additional~~ information relating to ~~these issues, see RISK FACTORS and MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL of Southern Company in Item 7 of the Form 10-K.~~

New or revised environmental laws and regulations could affect many areas of the traditional electric operating companies', Southern Power's, and the natural gas distribution utilities' operations. The impact of any such changes cannot be determined at this time. Environmental compliance costs could affect earnings if such costs cannot continue to be recovered in rates on a timely basis for the traditional electric operating companies and the natural gas distribution utilities or through long-term wholesale agreements for the traditional electric operating companies and Southern ~~Power. Further, increased costs that are recovered through regulated rates could contribute to reduced demand for electricity~~Company Gas at March 31, 2020 and natural gas, which could negatively affect results of operations, cash flows, and/or financial condition. Additionally, many commercial and industrial customers may also be affected by existing and future environmental requirements, which for some may have the potential to ultimately affect their demand for electricity and natural gas. See MANAGEMENT'S DISCUSSION AND ANALYSIS December 31, 2019 were as follows:

On September 13, 2019, the D.C. Circuit Court of Appeals dismissed most challenges brought against the 2016 Cross-State Air Pollution Rule update (2016 CSAPR Update), including the application of the EPA's new emissions allowance budget methodology to the State of Mississippi, which had been challenged by Mississippi Power. However, the court agreed that the 2016 CSAPR Update was unlawful because it allows upwind states to continue their significant contributions to downwind air quality problems beyond statutory deadlines. Accordingly, the court remanded the 2016 CSAPR Update to the EPA. The 2016 CSAPR Update allowance budgets remain in place while the EPA considers how to address the court's remand. The ultimate outcome of this matter cannot be determined at this time.

On October 22, 2019, the EPA and the U.S. Army Corps of Engineers jointly published a final rule that repealed the 2015 Waters of the United States (WOTUS) rule. This final rule will be effective December 23, 2019 and will bring all states back under the pre-2015 regulations until a new WOTUS rule is finalized. A revised definition of WOTUS is anticipated to be finalized by the end of 2019. The impact of the WOTUS rule will depend on the content of the final~~rule redefining WOTUS and the outcome of any associated legal challenges and cannot be determined at this time.~~

As further analysis is performed and additional details are developed with respect to ash pond closures, the traditional electric operating companies expect to periodically update their ARO cost estimates. Additionally, the closure designs and plans in the States of Alabama and Georgia are subject to approval by environmental regulatory agencies. Absent continued recovery of ARO costs through regulated rates, Southern Company's results of operations, cash flows, and financial condition could be materially impacted. The ultimate outcome of these matters cannot be determined at this time. See Note 6 to the financial statements in Item 8 of the Form 10-K and Note (A) to the Condensed Financial Statements under "Asset Retirement Obligations" herein for additional information.

On July 8, 2019, the EPA published the final Affordable Clean Energy rule (ACE Rule) to repeal and replace the CPP. On September 17, 2019, the D.C. Circuit Court of Appeals dismissed litigation related to the CPP as moot. The ACE Rule requires states to develop unit-specific CO₂ emission rate standards for existing coal-fired units based on heat-rate efficiency improvements. Combustion turbines, including natural gas combined cycles, are not included as affected sources in the ACE Rule. The Southern Company system has ownership interests in 19 coal-fired units (approximately 10,300 MWs) to which the ACE Rule is applicable. The ACE Rule is being challenged in the D.C. Circuit Court of Appeals and Georgia Power has filed a motion to intervene in the litigation in support of the rule, as have others. The ultimate impact of the ACE Rule, including the repeal and replacement of the CPP, to the Southern Company system will depend on state implementation plan requirements and the outcome of associated legal challenges and cannot be determined at this time.

The traditional electric operating companies each have established fuel cost recovery rates approved by their respective state PSCs. Fuel cost recovery revenues 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. The traditional electric operating companies continuously monitor their under or over recovered fuel cost balances and make appropriate filings with their state PSCs to adjust fuel cost recovery rates as necessary.

~~The procurement of these resources is~~CCN petition, remain subject to ~~the satisfaction or waiver of certain conditions, including, among other customary conditions,~~ approval by the Alabama PSC. The completion of the Autauga Combined Cycle Acquisition (defined below) is also subject to (i) the expiration or termination of the waiting period under the Hart-Scott-Rodino Antitrust Improvements Act and (ii) approval by the FERC. All regulatory approvals are expected to be obtained by the end of the third quarter 2020.

On May 8, 2019, Alabama Power entered into an Agreement for Engineering, Procurement, and Construction with Mitsubishi Hitachi Power Systems Americas, Inc. and Black & Veatch Construction, Inc. to construct an approximately 720-MW combined cycle facility at Plant Barry (Plant Barry Unit 8), which is expected to be placed in service by the end of 2023.

On September 6, 2019, Alabama Power entered into a purchase and sale agreement to acquire all of the equity interests in Tenaska Alabama II Partners, L.P. (Autauga Combined Cycle Acquisition). Tenaska Alabama II Partners, L.P. owns and operates an approximately 885-MW combined cycle generation facility in Autauga County, Alabama. The transaction is expected to close by September 1, 2020. As part of the Autauga Combined Cycle Acquisition, Alabama Power will assume an existing power sales agreement under which the full output of the generating facility remains committed to another third party for its remaining term of approximately three years. The estimated revenues from the power sales agreement are expected to offset the associated costs of operation during the remaining term.

~~The capital investment associated with the construction of Plant Barry Unit 8 and the Autauga Combined Cycle Acquisition is currently estimated to total approximately $1.1 billion.~~

Upon certification, Alabama Power expects to recover costs associated with Plant Barry Unit 8 through its Rate CNP New Plant. Additionally, Alabama Power expects to recover costs associated with the Autauga Combined Cycle Acquisition through Rate RSE during the term of the existing power sales agreement and, on expiration of the agreement, through Rate CNP New Plant. The recovery of costs associated with laws, regulations, and other such mandates directed at the utility industry are expected to be recovered through Rate CNP Compliance. Alabama Power expects to recover the capacity-related costs associated with the PPAs through its Rate CNP PPA. In addition, fuel and energy-related costs are expected to be recovered through Rate ECR. Any remaining costs associated with the Autauga Combined Cycle Acquisition and Plant Barry Unit 8 will be incorporated through the annual filing of

~~Rate RSE. See Note 2 to the financial statements under "Alabama Power" in Item 8 of the Form 10-K for additional information.~~

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

On June 28, 2019, Georgia Power filed a base rate case (Georgia Power 2019 Base Rate Case) with the Georgia PSC. The filing, as modified on September 24, 2019, includes a three-year Alternate Rate Plan with requested rate increases totaling $560 million, $144 million, and $233 million effective January 1, 2020, January 1, 2021, and January 1, 2022, respectively. These increases are based on a proposed retail ROE of 10.90% and a proposed equity ratio of 56% and reflect levelized revenue requirements during the three-year period, with the exception of incremental compliance costs related to CCR AROs, Demand-Side Management programs, and adjustments to the Municipal Franchise Fee tariff.

~~Georgia Power has requested recovery of the proposed increases through its existing base rate tariffs as follows:~~

Georgia Power's filing primarily reflects requests to (i) address the impacts of the Tax Reform Legislation, (ii) recover the costs of recent and future capital investments in infrastructure designed to maintain high levels of reliability and superior customer service with updated depreciation rates, (iii) recover substantial storm damage expenses incurred and deferred since 2013 along with a reasonable level of storm damage expenses expected to be incurred during the three years ending December 31, 2022, and (iv) recover the costs necessary to comply with federal and state regulations for CCR AROs. In addition, the filing includes the following provisions:

~~Georgia Power expects the Georgia PSC to issue a final order in this matter on December 17, 2019.~~ The ultimate outcome of this matter cannot be determined at this time.

~~On July 16,~~decision in the 2019 ~~the Georgia PSC voted to approve Georgia Power's triennial IRP (Georgia Power 2019 IRP) as modified by a stipulated agreement among~~ARP allowing Georgia Power ~~the staff of the Georgia PSC, and certain intervenors and further modified by the Georgia PSC.~~

In the Georgia Power 2019 IRP, the Georgia PSC approved the decertification and retirement of Plant Hammond Units 1 through 4 (840 MWs) and Plant McIntosh Unit 1 (142.5 MWs) effective July 29, 2019. The Georgia PSC also approved the reclassification of the remaining net book values of the Plant Hammond and Plant McIntosh units (approximately $500 million and $40 million, respectively), as well as any unusable materials and supplies inventory balances, upon retirement to a regulatory asset. Recovery of each unit's net book value will continue through December 31, 2019 as provided in the 2013 ARP. Additionally, approximately $295 million of net capitalized asset retirement costs were reclassified to a regulatory asset.

For the regulatory asset balances remaining at December 31, 2019, Georgia Power requested recovery in the Georgia Power 2019 Base Rate Case as follows: (i) the net book values of Plant Mitchell Unit 3 (approximately $8 million at September 30, 2019) and Plant McIntosh Unit 1, any unusable materials and supplies inventory, and the future generation site in Stewart County, Georgia over a three-year period ending December 31, 2022 and (ii) the

net book values of Plant Hammond Units 1 through 4 over a period equal to the applicable unit's remaining useful life through 2035. The timing of recovery of the related ARO costs will be determined in the Georgia Power 2019 Base Rate Case. The ultimate outcome of these matters cannot be determined at this time.

Also in the Georgia Power 2019 IRP, the Georgia PSC approved Georgia Power's proposed environmental compliance strategy associated with ash pond and certain landfill closures and post-closure care in compliance with the CCR Rule and the related state rule. In the Georgia Power 2019 Base Rate Case, Georgia Power requested recovery of the under recovered balance of theserecover compliance costs ~~at December 31, 2019 (approximately $157 million at September 30, 2019) over a three-year period ending December 31, 2022 and recovery of estimated compliance costs of $277 million~~ for ~~2020, $395 million for 2021, and $655 million for 2022 over three-year periods ending December 31, 2022, 2023, and 2024, respectively.~~CCR AROs. The ultimate outcome of this matter cannot be determined at this time. ~~See Note 6 to the financial statements in Item 8 of the Form 10-K for additional information regarding Georgia Power's AROs.~~

The Georgia PSC also approved Georgia Power to (i) issue requests for proposals (RFP) for capacity beginning in 2022 or 2023 and in 2026, 2027, or 2028; (ii) procure up to an additional 2,210 MWs of renewable resources through competitive RFPs; and (iii) invest in a portfolio of up to 80 MWs of battery energy storage technologies.

~~See "Rate Plans" herein for additional information regarding the Georgia Power 2019 Base Rate Case.~~

During the third quarter and year-to-date 2019, Mississippi Power recorded pre-tax charges to income of $4 million ($3 million after tax) and $10 million ($7 million after tax), respectively, primarily resulting from the abandonment and related closure activities and ongoing period costs, net of sales proceeds, for the mine and gasifier-related assets at the Kemper County energy facility. Additional closure costs for the mine and gasifier-related assets, currently estimated at up to $10 million pre-tax (excluding dismantlement costs, net of salvage), may be incurred through the first half of 2020. In addition, period costs, including, but not limited to, costs for compliance and safety, ARO accretion, and property taxes for the mine and gasifier-related assets, are estimated at $3 million for the remainder of 2019 and $2 million to $7 million annually in 2020 through 2023.

~~In addition, Mississippi Power constructed the CO~~₂ ~~pipeline for the planned transport of captured CO~~₂ ~~for use in enhanced oil recovery and is currently evaluating its options regarding the final disposition of the CO~~₂ ~~pipeline, including removal of the pipeline. This evaluation is expected to be complete by year-end 2019. If Mississippi Power ultimately decides to remove the CO~~₂ ~~pipeline, the cost of removal~~ ~~could have a material impact on Southern Company's financial statements.~~

The subsidiary companies of Southern Company are engaged in continuous construction programs to accommodate existing and estimated future loads on their respective systems. The Southern Company system intends to continue its strategy of developing and constructing new electric generating facilities, adding environmental modifications to certain existing units, expanding and improving the electric transmission and distribution systems, and updating and expanding the natural gas distribution systems. For the traditional electric operating companies, major generation construction projects are subject to state PSC approval in order to be included in retail rates. While Southern Power generally constructs and acquires generation assets covered by long-term PPAs, any uncontracted capacity could

negatively affect future earnings. Southern Company Gas is engaged in various infrastructure improvement programs 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. The natural gas distribution utilities recover their investment and a return associated with these infrastructure programs through their regulated rates. See Notes 2 and 15 to the financial statements under "Southern Company Gas – Infrastructure Replacement Programs and Capital Projects" and "Southern Power," respectively, in Item 8 of the Form 10-K and Note (K) to the Condensed Financial Statements under "~~Southern Power" herein for additional information.~~

The largest construction project currently underway in the Southern Company system is Plant Vogtle Units 3 and 4 (45.7% ownership interest by Georgia Power in the two units, each with approximately 1,100 MWs). See Note 2 to the financial statements under "Georgia Power – Nuclear Construction" in Item 8 of the Form 10-K and "~~Nuclear Construction" herein for additional information.~~

~~Also see FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" herein for additional information regarding Southern Company's capital requirements for its subsidiaries' construction programs.~~

See Note 2 to the financial statements under "Georgia Power – Nuclear Construction" in Item 8 of the Form 10-K for additional information regarding the construction of Plant Vogtle Units 3 and 4, the joint ownership agreements and related funding agreement, VCM reports, and the NCCR tariff.

In April 2019, Southern Nuclear ~~completed~~established aggressive target values for monthly construction production and system turnover activities as part of a strategy to maintain and, where possible, build margin to the regulatory-approved in-service dates of November 2021 for Unit 3 and November 2022 for Unit 4. Through early 2020, the project faced challenges with the April 2019 aggressive strategy targets including, but not limited to, electrical and pipefitting labor productivity and closure rates for work packages, which resulted in a backlog of activities and completion percentages below the April 2019 aggressive strategy targets.

approved or are pending before the NRC. Various design and other licensing-based compliance matters, including the timely submittal by Southern Nuclear of the ITAAC documentation for each unit and the related reviews and approvals by the NRC necessary to support NRC authorization to load fuel, may arise, which may result in additional license amendments or require other resolution. As part of the aggressive site work plan, in January 2020,

See RISK FACTORS of Southern Company in the Form 10-K for a discussion of certain risks associated with the licensing, construction, and operation of nuclear generating units, including potential impactsduring that ~~could result from a major incident at a nuclear facility anywhere in the world.~~

At September 30, 2019, Georgia Power had borrowed $3.46 billion related to Plant Vogtle Units 3 and 4 costs as provided through the Amended and Restated Loan Guarantee Agreement and related multi-advance credit facilities among Georgia Power, the DOE, and the FFB, which provide for borrowings of up to approximately $5.130 billion, subject to the satisfaction of certain conditions. See Note 8 to the financial statements under "Long-term Debt – DOE Loan Guarantee Borrowings" in Item 8 of the Form 10-K and Note (F) to the Condensed Financial Statements under "~~DOE Loan Guarantee Borrowings" herein for additional information, including applicable covenants, events of default, mandatory prepayment events, and conditions to borrowing.~~period.

~~The Atlantic Coast Pipeline has experienced challenges~~information relating to its permits since construction began in 2018. On October 4, 2019, the U.S. Supreme Court agreed to hear Atlantic Coast Pipeline's appeal of a lower court ruling that overturned a key permit for the project. The delays resulting from the permitting issues have impacted the cost and schedule for the project. As a result, total current project cost estimates have increased from between $7.0 billion

and $7.8 billion ($350 million and $390 million for Southern Company Gas) to between $7.3 billion and $7.8 billion ($365 million and $390 million for Southern Company Gas), excluding financing costs. The operator of the joint venture has indicated that it currently expects to complete construction by the end of 2021 and place the project in service shortly thereafter.

On September 10, 2019, an appellate court ruled that the PennEast Pipeline does not have federal court eminent domain authority over lands in which a state has property rights interests. The joint venture is pursuing appellate and other options and is evaluating further next steps.

~~Southern Company and its subsidiaries~~The Registrants are involved in various other matters ~~that could affect future earnings, including matters~~ being litigated ~~as well as other~~and regulatory matters and matters that could result in asset impairments. In addition, Southern Company and its subsidiaries are subject to certain claims and legal actions arising in the ordinary course of business. The business activities of Southern Company's subsidiaries are subject to extensive governmental regulation related to public health and the environment, such as laws and regulations governing air, water, land, and protection of other natural resources. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental laws and regulations, 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 or regulatory matters ~~or potential asset impairments~~against each Registrant and any subsidiaries cannot be determined at this time; however, for current proceedings not specifically reported ~~in Notes (B) and (C) to the Condensed Financial Statements~~ 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~~such Registrant's financial statements. ~~See Notes (B) and (C) to~~

In May 2017, Helen E. Piper Survivor's Trust filed a shareholder derivative lawsuit in the Superior Court of Gwinnett County, 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 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. The 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. The 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. The plaintiff also seeks certain unspecified changes to Southern Company's corporate governance and internal processes. In May 2018, the court entered an order staying this lawsuit until 30 days after the resolution of any dispositive motions or any settlement, whichever is earlier, in the securities class action. On August 5, 2019, the court granted a motion filed by the plaintiff on July 17, 2019 to substitute a new named plaintiff, Martin J. Kobuck, in place of Helen E. Piper Survivor's Trust.

Southern Company prepares its consolidated financial statements in accordance with GAAP. Significant accounting policies are described in Notes 1, 5, and 6 to the financial statements in Item 8 of the Form 10-K. In the application of these policies, certain estimates are made that may have a material impact on Southern Company's results of operations and related disclosures. Different assumptions and measurements could produce estimates that are significantly different from those recorded in the financial statements. See MANAGEMENT'S DISCUSSION AND ANALYSIS – ACCOUNTING POLICIES – "Application of Critical Accounting Policies and Estimates" of Southern Company in Item 7 of the Form 10-K for a complete discussion of Southern Company's critical accounting policies and estimates.

~~See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY~~ – "Overview" of Southern Company in Item 7 of the Form 10-K for additional information. Southern Company's financial condition remained stable at September 30, 2019. Southern Company intends to continue to monitor its access to short-term and long-term capital markets as well as bank credit agreements to meet future capital and liquidity needs. See "~~Capital Requirements and Contractual Obligations," "Sources of Capital," and "Financing Activities" herein for additional information.~~

Net cash provided from operating activities totaled $4.9 billion for the first nine months of 2019, a decrease of $0.7 billion from the corresponding period in 2018. The decrease in net cash provided from operating activities was primarily due to the timing of vendor payments and the impacts of the Gulf Power disposition and the Southern Company Gas Dispositions. Net cash used for investing activities totaled $1.1 billion for the first nine months of 2019 primarily due to the traditional electric operating companies' installation of equipment to comply with environmental standards and construction of electric generation, transmission, and distribution facilities and capital expenditures for Southern Company Gas' infrastructure replacement programs, largely offset by the proceeds from the sale of Gulf Power. Net cash used for financing activities totaled $2.4 billion for the first nine months of 2019 primarily due to net repayments of short-term bank debt and commercial paper and common stock dividend payments, partially offset by net issuances of long-term debt. Cash flows from financing activities vary from period to period based on capital needs and the maturity or redemption of securities. See Notes (F) and (K) to the Condensed Financial Statements herein for additional information.

~~Significant balance sheet changes for the first nine months of 2019 include:~~

~~See Notes (A), (B), (F), (G), (K), and (L) to the Condensed Financial Statements herein for additional information.~~

At the end of the third quarter 2019, the market price of Southern Company's common stock was $61.77 per share (based on the closing price as reported on the NYSE) and the book value was $26.23 per share, representing a market-to-book ratio of 235%, compared to $43.92, $23.91, and 184%, respectively, at the end of 2018. Southern Company's common stock dividend for the third quarter 2019 was $0.62 per share compared to $0.60 per share in the third quarter 2018.

~~See MANAGEMENT'S DISCUSSION AND ANALYSIS~~ – ~~FINANCIAL CONDITION AND LIQUIDITY~~ – "Capital Requirements and Contractual Obligations" of Southern Company in Item 7 of the Form 10-K for a description of Southern Company's capital requirements and contractual obligations. Approximately $3.3 billion will be required through September 30, 2020 to fund maturities of long-term debt. See "~~Sources of Capital" herein for additional information.~~

The construction programs are subject to periodic review and revision, and actual construction costs may vary from these estimates because of numerous factors. These factors include: changes in business conditions; changes in load projections; changes in environmental laws and regulations; the outcome of any legal challenges to environmental rules; changes in electric generating plants, including unit retirements and replacements and adding or changing fuel sources at existing electric generating units, to meet regulatory requirements; changes in FERC rules and regulations; state regulatory agency approvals; changes in the expected environmental compliance program; changes in legislation; the cost and efficiency of construction labor, equipment, and materials; project scope and design changes; delays in construction due to judicial or regulatory action; storm impacts; and the cost of capital. In addition, there can be no assurance that costs related to capital expenditures will be fully recovered. Additionally, planned expenditures for plant acquisitions may vary due to market opportunities and Southern Power's ability to

~~execute its growth strategy. See Note 15 to the financial statements under "Southern Power" in Item 8 of the Form 10-K and Note (K) to the Condensed Financial Statements under "Southern Power" herein for additional information regarding Southern Power's plant acquisitions and construction projects.~~

Southern Company intends to meet its future capital needs through operating cash flows, borrowings from financial institutions, and debt and equity issuances in the capital markets. Equity capital can be provided from any combination of Southern Company's stock plans, private placements, or public offerings. The amount and timing of additional equity and debt issuances in 2019, as well as in subsequent years, will be contingent on Southern Company's investment opportunities and the Southern Company system's capital requirements and will depend upon prevailing market conditions and other factors. See "~~Capital Requirements and Contractual Obligations" herein for additional information.~~

Except as described herein, the traditional electric operating companies, Southern Power, and Southern Company Gas plan to obtain the funds required for construction and other purposes from operating cash flows, external security issuances, borrowings from financial institutions, and equity contributions or loans from Southern Company. Southern Power also plans to utilize tax equity partnership contributions, as well as funds resulting from its pending asset sale. However, the amount, type, and timing of any future financings, if needed, will depend upon prevailing market conditions, regulatory approval, and other factors. See MANAGEMENT'S DISCUSSION AND ANALYSIS – ~~FINANCIAL CONDITION AND LIQUIDITY~~ – ~~"Sources of Capital" of Southern Company in Item 7 of the Form 10-K for additional information. Also see Note (K) to the Condensed Financial Statements under "Southern Power" herein for additional information regarding the pending sale of Plant Mankato.~~

Southern Company's current liabilities frequently exceed current assets because of scheduled maturities of long-term debt and the periodic use of short-term debt as a funding source, as well as significant seasonal fluctuations in

cash needs. As of September 30, 2019, Southern Company's current liabilities exceeded current assets by $0.6 billion, primarily due to long-term debt that is due within one year and notes payable totaling $3.9 billion (including approximately $0.6 billion at the parent company, $1.8 billion at Georgia Power, $0.3 billion at Mississippi Power, $0.9 billion at Southern Power, and $0.3 billion at Southern Company Gas), partially offset by $2.9 billion of cash and cash equivalents. To meet short-term cash needs and contingencies, the Southern Company system has substantial cash flow from operating activities and access to capital markets and financial institutions. Southern Company, the traditional electric operating companies, Southern Power, and Southern Company Gas intend to utilize operating cash flows, as well as commercial paper, lines of credit, bank notes, and securities issuances, as market conditions permit, as well as, under certain circumstances for the traditional electric operating companies, Southern Power, and Southern Company Gas, equity contributions and/or loans from Southern Company to meet their short-term capital needs.

~~Committed credit arrangements with banks at September 30, 2019 were as follows:~~

~~See Note 8 to the financial statements under "Bank Credit Arrangements" in Item 8 of the Form 10-K and Note (F) to the Condensed Financial Statements under "Bank Credit Arrangements" herein for additional information.~~

A portion of the unused credit with banks is allocated to provide liquidity support to the revenue bonds of the traditional electric operating companies and the commercial paper programs of Southern Company, the traditional electric operating companies, Southern Power Company, Southern Company Gas, Nicor Gas, and SEGCO. The amount of variable rate revenue bonds of the traditional electric operating companies outstanding requiring liquidity support as of September 30, 2019 was approximately $1.4 billion. In addition, at September 30, 2019, Alabama Power had approximately $87 million of revenue bonds outstanding that are required to be remarketed within the next 12 months.

The registrants, Nicor Gas, and SEGCO make short-term borrowings primarily through commercial paper programs that have the liquidity support of the committed bank credit arrangements described above. Short-term borrowings are included in notes payable in the balance sheets.

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

Short-term Debt at
September 30, 2019

Short-term Debt During the Period^(*)

Amount
Outstanding

Weighted
Average
Interest
Rate

Average
Amount
Outstanding

Weighted
Average
Interest
Rate

Maximum
Amount
Outstanding
(in millions) (in millions) (in millions)
Commercial paper $ 292
2.2 % $ 976
2.5 % $ 1,509
Short-term bank debt 250
2.5 % 250
2.7 % 250
Total $ 542
2.4 % $ 1,226
2.6 %

~~Southern Company believes the need for working capital can be adequately met by utilizing commercial paper programs, lines of credit, bank term loans, and operating cash flows.~~

At September 30, 2019, Southern Company and its subsidiaries did not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade.

There are certain contracts that could require collateral, but not accelerated payment, in the event of a credit rating change of certain subsidiaries to BBB and/or Baa2 or below. These contracts are for physical electricity and natural gas purchases and sales, fuel purchases, fuel transportation and storage, energy price risk management, transmission, interest rate management, and construction of new generation at Plant Vogtle Units 3 and 4.

~~The maximum potential collateral requirements under these contracts at September 30, 2019 were as follows:~~

Credit Ratings Maximum Potential
Collateral
Requirements
(in millions)
At BBB and/or Baa2 $ 32
At BBB- and/or Baa3 $ 433
At BB+ and/or Ba1^(*)
$ 1,894

Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. Additionally, a credit rating downgrade could impact the ability of Southern Company and its subsidiaries to access capital markets, and would be likely to impact the cost at which they do so.

During the first nine months of 2019, Southern Company issued approximately 15.0 million shares of common stock primarily through employee equity compensation plans and received proceeds of approximately $623 million.

~~The following table outlines the long-term debt financing activities for Southern Company and its subsidiaries for the first nine months of 2019:~~

~~In September 2019, Southern Company redeemed all $300 million aggregate principal amount of its Series 2017A Floating Rate Senior Notes due September 30, 2020.~~

As reflected in the table above, in March 2019, Georgia Power made additional borrowings under the FFB Credit Facilities in an aggregate principal amount of $835 million at an interest rate of 3.213% through the final maturity date of February 20, 2044. The proceeds were used to reimburse Georgia Power for Eligible Project Costs relating to the construction of Plant Vogtle Units 3 and 4.

~~In June 2019, Georgia Power entered into two short-term floating rate bank loans in aggregate principal amounts of $125 million each, both of which bear interest based on one-month LIBOR.~~

~~In May 2019, Southern Power repaid at maturity a $100 million aggregate principal amount short-term bank loan.~~

In August 2019, Nicor Gas issued $200 million aggregate principal amount of first mortgage bonds in a private placement. Nicor Gas entered into an agreement to issue an additional $100 million aggregate principal amount of first mortgage bonds on October 30, 2019.

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

During the nine months ended September 30, 2019, there were no material changes to Southern Company's, Alabama Power's, Georgia Power's, Mississippi Power's, and Southern Power's disclosures about market risk. For additional market risk disclosures relating to Southern Company Gas, see MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Market Price Risk" of Southern Company Gas herein. For an in-depth discussion of each registrant's market risks, see MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Market Price Risk" of each registrant in Item 7 of the Form 10-K and Note 1 to the financial statements under "Financial Instruments" and Notes 13 and 14 to the financial statements in Item 8 of the Form 10-K. Also see Notes (I) and (J) to the Condensed Financial Statements herein for information relating to ~~derivative instruments.~~various lawsuits and other contingencies.

There have been no changes in Southern Company's, Alabama Power's, Georgia Power's, Mississippi Power's, Southern Power's, or Southern Company Gas' internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934, as amended) during the third quarter 2019 that have materially affected or are reasonably likely to materially affect Southern Company's, Alabama Power's, Georgia Power's, Mississippi Power's, Southern Power's, or Southern Company Gas' internal control over financial reporting.

Alabama Power operates as a vertically integrated utility providing electric service to retail and wholesale customers within its traditional service territory located in the State of Alabama in addition to wholesale customers in the Southeast.

Many factors affect the opportunities, challenges, and risks of Alabama Power's business of providing electric service. These factors include the ability to maintain a constructive regulatory environment, to maintain and grow energy sales and customers, and to effectively manage and secure timely recovery of costs. These costs include those related to projected long-term demand growth, stringent environmental standards, including CCR rules, reliability, fuel, capital expenditures, including improving the electric transmission and distribution systems, and restoration following major storms. Alabama Power has various regulatory mechanisms that operate to address cost recovery. Effectively operating pursuant to these regulatory mechanisms and appropriately balancing required costs and capital expenditures with customer prices will continue to challenge Alabama Power for the foreseeable future.

Alabama Power continues to focus on several key performance indicators including, but not limited to, customer satisfaction, plant availability, system reliability, and net income after dividends on preferred stock.

Third Quarter 2019 vs. Third Quarter 2018 Year-to-Date 2019 vs. Year-to-Date 2018
(change in millions)
(% change)
(change in millions)
(% change)
$96 25.7 $125 14.6

Third Quarter 2019 vs. Third Quarter 2018 Year-to-Date 2019 vs. Year-to-Date 2018
(change in millions) (% change) (change in millions) (% change)
$110 6.9 $78 1.9

~~Details of the changes in retail revenues were as follows:~~

Third Quarter 2019
Year-to-Date 2019
(in millions)
(% change)
(in millions)
(% change)
Retail – prior year $ 1,584
$ 4,208

Estimated change resulting from –
Rates and pricing 119
7.4 % 214
5.1 %
Sales decline (29 ) (1.8 ) (60 ) (1.4 )
Weather 33
2.1
15
0.4
Fuel and other cost recovery (13 ) (0.8 ) (91 ) (2.2 )
Retail – current year $ 1,694
6.9 % $ 4,286
1.9 %

~~Revenues increased in the third quarter and year-to-date 2019 due to warmer weather in the third quarter 2019 when compared to the corresponding period in 2018.~~

Third Quarter 2019 vs. Third Quarter 2018 Year-to-Date 2019 vs. Year-to-Date 2018
(change in millions) (% change) (change in millions) (% change)
$(3) (4.1) $(19) (8.9)

Wholesale revenues from sales to non-affiliates will vary depending on fuel prices, the market prices of wholesale energy compared to the cost of Alabama Power's and the Southern Company system's generation, demand for energy within the Southern Company system's service territory, and the availability of the Southern Company system's generation. Increases and decreases in energy revenues that are driven by fuel prices are accompanied by an increase or decrease in fuel costs and do not affect net income. Short-term opportunity energy sales are also included in wholesale energy sales to non-affiliates. These opportunity sales are made at market-based rates that generally provide a margin above Alabama Power's variable cost to produce the energy.

For year-to-date 2019, wholesale revenues from sales to non-affiliates were $194 million compared to $213 million for the corresponding period in 2018. The decrease was primarily due to a 4.9% decrease in KWH sales as a result of lower demand and a 4.5% decrease in the price of energy due to lower natural gas prices in 2019 compared to the corresponding period in 2018.

~~Wholesale Revenues~~ – ~~Affiliates~~

Third Quarter 2019 vs. Third Quarter 2018 Year-to-Date 2019 vs. Year-to-Date 2018
(change in millions) (% change) (change in millions) (% change)
$(12) (85.7) $(30) (31.3)

Wholesale revenues from sales to affiliated companies will vary depending on demand and the availability and cost of generating resources at each company. These affiliate sales are made in accordance with the IIC, as approved by the FERC. These transactions do not have a significant impact on earnings since this energy is generally sold at marginal cost and energy purchases are generally offset by energy revenues through Alabama Power's energy cost recovery clause.

In the third quarter 2019, wholesale revenues from sales to affiliates were $2 million compared to $14 million for the corresponding period in 2018. For year-to-date 2019, wholesale revenues from sales to affiliates were $66 million compared to $96 million for the corresponding period in 2018. These decreases were primarily due to reductions in KWH sales as a result of decreased availability of coal generation associated with the retirement of Plant Gorgas Units 8, 9, and 10 and a decrease in the price of energy as a result of lower natural gas prices.

Third Quarter 2019 vs. Third Quarter 2018
Year-to-Date 2019 vs.
Year-to-Date 2018
(change in millions)
(% change) (change in millions) (% change)
Fuel $ (46 ) (12.9) $ (164 ) (16.0 )
Purchased power – non-affiliates 13
20.3 (16 ) (9.1 )
Purchased power – affiliates 4
5.8 15
10.1
Total fuel and purchased power expenses $ (29 ) $ (165 )

In addition, fuel expense increased $30 million for year-to-date 2018 in accordance with an Alabama PSC accounting order authorizing the use of excess deferred income taxes to offset under recovered fuel costs (Tax Reform Accounting Order). See Note 2 to the financial statements under "Alabama Power – Tax Reform Accounting Order" in Item 8 of the Form 10-K for additional information.

~~Details of Alabama Power's generation and purchased power were as follows:~~

Third Quarter 2019 Third Quarter 2018 Year-to-Date 2019
Year-to-Date 2018
Total generation (in billions of KWHs)
15 16 43 47
Total purchased power (in billions of KWHs)
4 3 8 6
Sources of generation (percent) —

Coal 48 54 45 52
Nuclear 26 24 25 22
Gas 24 18 21 19
Hydro 2 4 9 7
Cost of fuel, generated (in cents per net KWH) — ^(a)

Coal 2.67 2.74 2.76 2.74
Nuclear 0.75 0.78 0.77 0.77
Gas 2.40 2.80 2.48 2.72
Average cost of fuel, generated (in cents per net KWH)^(a)(b)
2.10 2.27 2.15 2.27
Average cost of purchased power (in cents per net KWH)^(c)
4.35 5.43 4.40 5.59

For year-to-date 2019, fuel expense was $0.86 billion compared to $1.03 billion for the corresponding period in 2018. The decrease was primarily due to a 26.4% increase in the volume of KWHs generated by hydro, a 20.6% decrease in the volume of KWHs generated by coal, and an 8.8% decrease in the average cost of natural gas per KWH generated, which excludes fuel associated with tolling agreements, partially offset by a 7.0% increase in the volume of KWHs generated by natural gas.

In addition, fuel expense increased $30 million for year-to-date 2018 in accordance with the Tax Reform Accounting Order. See Note 2 to the financial statements under "Alabama Power – Tax Reform Accounting Order" in Item 8 of the Form 10-K for additional information.

In the third quarter 2019, purchased power expense from non-affiliates was $77 million compared to $64 million for the corresponding period in 2018. The increase was primarily related to a 42% increase in the volume of KWHs purchased primarily due to warmer weather in the third quarter 2019 compared to the corresponding period in 2018, partially offset by a 15.5% decrease in the average cost per KWH purchased due to lower natural gas prices.

For year-to-date 2019, purchased power expense from non-affiliates was $160 million compared to $176 million for the corresponding period in 2018. The decrease was primarily related to a 12.6% decrease in the average cost per KWH purchased due to lower natural gas prices, partially offset by a 6% increase in the volume of KWHs purchased primarily as a result of the retirement of Plant Gorgas Units 8, 9, and 10.

Third Quarter 2019 vs. Third Quarter 2018 Year-to-Date 2019 vs. Year-to-Date 2018
(change in millions) (% change) (change in millions) (% change)
$8 2.0 $30 2.5

For year-to-date 2019, other operations and maintenance expenses were $1.22 billion compared to $1.19 billion for the corresponding period in 2018. This increase was primarily due to increases of $20 million in Rate CNP Compliance-related expenses, $18 million related to affiliate billing credits received in 2018, and $3 million in employee benefit expenses. These increases were partially offset by a $20 million decrease in overhead line maintenance expenses due to the timing and availability of contract labor. Operations and maintenance expenses associated with Rate CNP compliance do not have a significant impact on earnings since they are generally offset by Rate CNP revenues. See Note 2 to the financial statements under "Alabama Power – Rate CNP Compliance" in Item 8 of the Form 10-K for additional information.

Third Quarter 2019 vs. Third Quarter 2018 Year-to-Date 2019 vs. Year-to-Date 2018
(change in millions) (% change) (change in millions) (% change)
$3 1.6 $23 4.0

Third Quarter 2019 vs. Third Quarter 2018 Year-to-Date 2019 vs. Year-to-Date 2018
(change in millions) (% change) (change in millions) (% change)
$2 22.2 $12 50.0

For year-to-date 2019, other income (expense), net was $36 million compared to $24 million for the corresponding period in 2018. This increase was primarily due to increases in interest income from temporary cash investments and non-service cost-related pension income. See Note (H) to the Condensed Financial Statements herein for additional information.

Third Quarter 2019 vs. Third Quarter 2018 Year-to-Date 2019 vs. Year-to-Date 2018
(change in millions) (% change) (change in millions) (% change)
$17 13.4 $23 8.5

In the third quarter 2019, income taxes were $144 million compared to $127 million for the corresponding period in 2018. For year-to-date 2019, income taxes were $295 million compared to $272 million for the corresponding period in 2018. These increases were primarily due to higher pre-tax earnings in the third quarter 2019 compared to the corresponding period in 2018 and the application of the Tax Reform Accounting Order in 2018. See Note 2 to the financial statements under "Alabama Power – Tax Reform Accounting Order" in Item 8 of the Form 10-K for additional information.

The results of operations discussed above are not necessarily indicative of Alabama Power's future earnings potential. The level of Alabama Power's future earnings depends on numerous factors that affect the opportunities, challenges, and risks of Alabama Power's primary business of providing electric service. These factors include Alabama Power's ability to maintain a constructive regulatory environment that continues to allow for the timely recovery of prudently-incurred costs, including the procurement of resources outlined in the September 6, 2019 petition for a CCN filed with the Alabama PSC and recovery of related costs, during a time of increasing costs and the weak pace of growth in new customers and electricity use per customer, especially in residential and commercial markets. Earnings will also depend upon maintaining and growing sales, considering, among other things, the adoption and/or penetration rates of increasingly energy-efficient technologies and increasing volumes of electronic commerce transactions, both of which could contribute to a net reduction in customer usage. Earnings are subject to a variety of other factors. These factors include weather, competition, new energy contracts with other utilities, energy conservation practiced by customers, the use of alternative energy sources by customers, the price of electricity, the price elasticity of demand, and the rate of economic growth or decline in Alabama Power's service territory. Demand for electricity is primarily driven by the pace of economic growth that may be affected by changes in regional and global economic conditions, which may impact future earnings. For additional information relating to these issues, see RISK FACTORS in Item 1A and MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL of Alabama Power in Item 7 of the Form 10-K.

New or revised environmental laws and regulations could affect many areas of Alabama Power's operations. The impact of any such changes cannot be determined at this time. Environmental compliance costs could affect earnings if such costs cannot continue to be recovered in rates on a timely basis. Environmental compliance costs are recovered through Rate CNP Compliance. Further, increased costs that are recovered through regulated rates could contribute to reduced demand for electricity, which could negatively affect results of operations, cash flows, and/or financial condition. Additionally, many commercial and industrial customers may also be affected by existing and future environmental requirements, which for some may have the potential to ultimately affect their demand for electricity. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters" of Alabama Power in Item 7 of the Form 10-K and Note 2 to the financial statements under "Alabama Power – Rate CNP Compliance" and Note 3 to the financial statements under "Environmental Remediation" in Item 8 of the Form 10-K for additional information.

On October 22, 2019, the EPA and the U.S. Army Corps of Engineers jointly published a final rule that repealed the 2015 Waters of the United States (WOTUS) rule. This final rule will be effective December 23, 2019 and will bring all states back under the pre-2015 regulations until a new WOTUS rule is finalized. A revised definition of WOTUS is anticipated to be finalized by the end of 2019. The impact of the WOTUS rule will depend on the content of the final~~rule redefining WOTUS and the outcome of any associated legal challenges and cannot be determined at this time.~~

On July 8, 2019, the EPA published the final Affordable Clean Energy rule (ACE Rule) to repeal and replace the CPP. On September 17, 2019, the D.C. Circuit Court of Appeals dismissed litigation related to the CPP as moot. The ACE Rule requires states to develop unit-specific CO₂ emission rate standards for existing coal-fired units based on heat-rate efficiency improvements. Combustion turbines, including natural gas combined cycles, are not included as affected sources in the ACE Rule. Alabama Power has ownership interests in seven coal-fired units (approximately 4,500 MWs) to which the ACE Rule is applicable. The ACE Rule is being challenged in the D.C. Circuit Court of Appeals. The ultimate impact of the ACE Rule, including the repeal and replacement of the CPP, to Alabama Power

~~will depend on state implementation plan requirements and the outcome of associated legal challenges and cannot be determined at this time.~~

On September 6, 2019, Alabama Power filed a petition for a CCN with the Alabama PSC for authorization to procure additional generating capacity through the turnkey construction of a new combined cycle facility, the acquisition of an existing combined cycle facility, and long-term contracts for the purchase of power from others, as more fully described below. In addition, Alabama Power will pursue approximately 200 MWs of certain demand side management and distributed energy resource programs. This filing was predicated on the results of Alabama Power's 2019 IRP provided to the Alabama PSC, which identified an approximately 2,400-MW resource need for Alabama Power, driven by the need for additional winter reserve capacity.

The procurement of these resources is subject to the satisfaction or waiver of certain conditions, including, among other customary conditions, approval by the Alabama PSC. The completion of the Autauga Combined Cycle Acquisition (defined below) is also subject to (i) the expiration or termination of the waiting period under the Hart-Scott-Rodino Antitrust Improvements Act and (ii) approval by the FERC. All regulatory approvals are expected to be obtained by the end of the third quarter 2020.

On May 8, 2019, Alabama Power entered into an Agreement for Engineering, Procurement, and Construction with Mitsubishi Hitachi Power Systems Americas, Inc. and Black & Veatch Construction, Inc. to construct an approximately 720-MW combined cycle facility at Plant Barry (Plant Barry Unit 8), which is expected to be placed in service by the end of 2023.

On September 6, 2019, Alabama Power entered into a purchase and sale agreement to acquire all of the equity interests in Tenaska Alabama II Partners, L.P. (Autauga Combined Cycle Acquisition). Tenaska Alabama II Partners, L.P. owns and operates an approximately 885-MW combined cycle generation facility in Autauga County, Alabama. The transaction is expected to close by September 1, 2020. As part of the Autauga Combined Cycle Acquisition, Alabama Power will assume an existing power sales agreement under which the full output of the generating facility remains committed to another third party for its remaining term of approximately three years. The estimated revenues from the power sales agreement are expected to offset the associated costs of operation during the remaining term.

~~The capital investment associated with the construction of Plant Barry Unit 8 and the Autauga Combined Cycle Acquisition is currently estimated to total approximately $1.1 billion.~~

Upon certification, Alabama Power expects to recover costs associated with Plant Barry Unit 8 through its Rate CNP New Plant. Additionally, Alabama Power expects to recover costs associated with the Autauga Combined Cycle Acquisition through Rate RSE during the term of the existing power sales agreement and, on expiration of the agreement, through Rate CNP New Plant. The recovery of costs associated with laws, regulations, and other such mandates directed at the utility industry are expected to be recovered through Rate CNP Compliance. Alabama Power expects to recover the capacity-related costs associated with the PPAs through its Rate CNP PPA. In addition, fuel and energy-related costs are expected to be recovered through Rate ECR. Any remaining costs associated with the Autauga Combined Cycle Acquisition and Plant Barry Unit 8 will be incorporated through the annual filing of Rate RSE. See Note 2 to the financial statements under "Alabama Power" in Item 8 of the Form 10-K for additional information.

~~Alabama Power is~~ involved in various other ~~matters that could affect future earnings, including~~ matters being litigated and regulatory matters. ~~In addition, Alabama Power is subject to certain claims and legal actions arising in the ordinary course of business. Alabama Power's business activities~~ are subject to extensive governmental regulation related to public health and the environment, such as laws and regulations governing air, water, land, and protection of other natural resources. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental laws and regulations, 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 or regulatory matters against each Registrant and any subsidiaries cannot be determined at this time; however, for current proceedings not specifically reported ~~in Notes (B) and (C) to the Condensed Financial~~

~~Statements~~ herein, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on Alabama Power's financial statements. See Notes (B) and (C) to the Condensed Financial Statements herein for a discussion of various other contingencies, regulatory matters, and other matters being litigated which may affect future earnings potential.

In response to changing customer expectations, payment patterns, and ongoing efforts to increase overall operating efficiencies, Alabama Power has closed 40 of its 86 payment offices as of September 30, 2019. Charges associated with these activities are not expected to have a material impact on Alabama Power'ssuch Registrant's financial statements.

~~Alabama Power prepares its financial statements in accordance with GAAP. Significant accounting policies are described in Notes 1, 5, and 6 to~~The Registrants believe the financial statements in Item 8 of the Form 10-K. In the application of these policies, certain estimates are made that may have a material impact on Alabama Power's results of operations and related disclosures. Different assumptions and measurements could produce estimates that are significantly different from those recorded in the financial statements. See MANAGEMENT'S DISCUSSION AND ANALYSIS – ACCOUNTING POLICIES – "Application of Critical Accounting Policies and Estimates" of Alabama Power in Item 7 of the Form 10-K for a complete discussion of Alabama Power's critical accounting policies and estimates.

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Overview" of Alabama Power in Item 7 of the Form 10-K for additional information. Alabama Power's financial condition remained stable at September 30, 2019. Alabama Power intends to continue to monitor its access to short-term and long-term capital markets as well as its bank credit arrangements to meet future capital and liquidity needs. See "~~Capital Requirements and Contractual Obligations," "Sources of Capital," and "Financing Activities" herein for additional information.~~

Significant balance sheet changes for the first nine months of 2019 include increases of $1.6 billion in total common stockholder's equity primarily due to a $1.2 billion capital contribution from Southern Company, $1.0 billion in cash and cash equivalents, and $0.6 billion in long-term debt due to a senior note issuance in the third quarter 2019. See "Financing Activities" herein for additional information. Other significant changes include increases of $0.9 billion in regulatory assets associated with AROs and $0.5 billion in other regulatory assets, deferred and a decrease of $0.5 billion in property, plant, and equipment. These changes were primarily due to the impacts of retiring and reclassifying Plant Gorgas Units 8, 9, and 10. See Note 2 to the financial statements in Item 8 of the Form 10-K and

~~Note (B) to the Condensed Financial Statements herein under "Alabama Power – Environmental Accounting Order" for additional information.~~

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" of Alabama Power in Item 7 of the Form 10-K for a description of Alabama Power's capital requirements and contractual obligations. There are no scheduled maturities of long-term debt through September 30, 2020.

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters" of Alabama Power in Item 7 of the Form 10-K for additional information on Alabama Power's environmental compliance strategy.

Alabama Power anticipates costs associated with closure-in-place and monitoring of ash ponds in accordance with the CCR Rule, which are reflected in Alabama Power's ARO liabilities. These costs, which are expected to change, could change materially as Alabama Power continues to refine its assumptions underlying the cost estimates and evaluate the method and timing of compliance activities. These costs are currently estimated to be approximately $200 million for 2020, $217 million for 2021, $284 million for 2022, $363 million for 2023, and $386 million for 2024. See FUTURE EARNINGS POTENTIAL – "Environmental Matters– Environmental Laws and Regulations – Coal Combustion Residuals" herein, Note (A) to the Condensed Financial Statements under "Asset Retirement Obligations" herein, and Note 6 to the financial statements in Item 8 of the Form 10-K for additional information.

The construction program is subject to periodic review and revision, and actual construction costs may vary from these estimates because of numerous factors. These factors include: changes in business conditions; changes in load projections; changes in environmental laws and regulations; the outcome of any legal challenges to environmental rules; changes in generating plants, including unit retirements and replacements and adding or changing fuel sources at existing generating units, to meet regulatory requirements; changes indiscussed below have no merit; however, the expected environmental compliance program; changes in FERC rules and regulations; Alabama PSC approvals; changes in legislation; the cost and efficiency of construction labor, equipment, and materials; project scope and design changes; storm impacts; and the cost of capital. In addition, there can be no assurance that costs related to capital expenditures will be fully recovered.

Alabama Power plans to obtain the funds to meet its future capital needs from sources similar to those used in the past, which were primarily from operating cash flows, external security issuances, borrowings from financial institutions, and equity contributions from Southern Company. However, the amount, type, and timing of any future financings, if needed, will depend upon prevailing market conditions, regulatory approval, and other factors. In January 2019, Alabama Power received a capital contribution totaling $1.225 billion from Southern Company. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Sources of Capital" of Alabama Power in Item 7 of the Form 10-K for additional information.

Alabama Power's current liabilities sometimes exceed current assets because of long-term debt maturities and the periodic use of short-term debt as a funding source, as well as significant seasonal fluctuations in cash needs.

~~At September 30, 2019, Alabama Power had approximately $1.34 billion of cash and cash equivalents. Committed credit arrangements with banks at September 30, 2019 were as follows:~~

As reflected in the table above, in May 2019 and September 2019, Alabama Power amended its $800 million and $500 million multi-year credit arrangements, which, among other things, extended the maturity dates from 2022 to 2024 and 2020 to 2022, respectively. In addition, Alabama Power increased the borrowing capacity of its $500 million credit arrangement to $525 million.

Most of these bank credit arrangements, as well as Alabama Power's term loan arrangements, contain covenants that limit debt levels and contain cross-acceleration provisions to other indebtedness (including guarantee obligations) of Alabama Power. Such cross-acceleration provisions to other indebtedness would trigger an event of default if Alabama Power defaulted on indebtedness, the payment of which was then accelerated. At September 30, 2019, Alabama Power was in compliance with all such covenants. None of the bank credit arrangements contain material adverse change clauses at the time of borrowings.

Subject to applicable market conditions, Alabama Power expects to renew or replace its bank credit arrangements as needed prior to expiration. In connection therewith, Alabama Power may extend the maturity dates and/or increase or decrease the lending commitments thereunder.

A portion of the unused credit with banks is allocated to provide liquidity support to Alabama Power's pollution control revenue bonds and commercial paper programs. The amount of variable rate pollution control revenue bonds outstanding requiring liquidity support was approximately $854 million as of September 30, 2019. At September 30, 2019, Alabama Power also had $87 million of fixed rate pollution control revenue bonds outstanding that were required to be reoffered within the next 12 months.

Alabama Power also has substantial cash flow from operating activities and access to the capital markets, including a commercial paper program, to meet liquidity needs. Alabama Power may meet short-term cash needs through its commercial paper program. Alabama Power may also meet short-term cash needs through a Southern Company subsidiary organized to issue and sell commercial paper at the request and for the benefit of Alabama Power and the other traditional electric operating companies. Proceeds from such issuances for the benefit of Alabama Power are loaned directly to Alabama Power. The obligations of each traditional electric operating company under these arrangements are several and there is no cross-affiliate credit support. Short-term borrowings are included in notes payable in the balance sheets.

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

~~Alabama Power believes the need for working capital can be adequately met by utilizing commercial paper programs, lines of credit, and operating cash flows.~~

~~At September 30, 2019, Alabama Power did not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade.~~

There are certain contracts that could require collateral, but not accelerated payment, in the event of a credit rating change to BBB and/or Baa2 or below. These contracts are primarily for physical electricity purchases, fuel purchases, fuel transportation and storage, energy price risk management, and transmission. At September 30, 2019, the maximum potential collateral requirements at a rating below BBB- and/or Baa3 totaled approximately $342 million.

Included in these amounts are certain agreements that could require collateral in the event that either Alabama Power or Georgia Power (an affiliate of Alabama Power) has a credit rating change to below investment grade. Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. Additionally, a credit rating downgrade could impact the ability of Alabama Power to access capital markets and would be likely to impact the cost at which it does so.

~~In February 2019, Alabama Power repaid at maturity $200 million aggregate principal amount of Series Z 5.125% Senior Notes due February 15, 2019.~~

In September 2019, Alabama Power issued $600 million aggregate principal amount of Series 2019A 3.45% Senior Notes due October 1, 2049. The proceeds will be used for general corporate purposes, including Alabama Power's continuous construction program.

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

Georgia Power operates as a vertically integrated utility providing electric service to retail customers within its traditional service territory located within the State of Georgia and to wholesale customers in the Southeast.

Many factors affect the opportunities, challenges, and risks of Georgia Power's business of providing electric service. These factors include the ability to maintain a constructive regulatory environment, to maintain and grow energy sales and customers, and to effectively manage and secure timely recovery of costs. These costs include those related to projected long-term demand growth, stringent environmental standards, including CCR rules, reliability, fuel, capital expenditures, including new generating facilities and expanding and improving transmission and distribution facilities, and restoration following major storms. Georgia Power has various regulatory mechanisms that operate to address cost recovery. Effectively operating pursuant to these regulatory mechanisms and appropriately balancing required costs and capital expenditures with customer prices will continue to challenge Georgia Power for the foreseeable future.

On June 28, 2019, Georgia Power filed a base rate case with the Georgia PSC. The filing, as modified on September 24, 2019, includes a three-year Alternate Rate Plan with requested rate increases totaling $560 million, $144 million, and $233 million effective January 1, 2020, January 1, 2021, and January 1, 2022, respectively. The ultimate outcome of this matter cannot be determined at this time. See FUTURE EARNINGS POTENTIAL – "~~Retail Regulatory Matters~~ – ~~Rate Plans" herein for additional information.~~

Georgia Power continues to focus on several key performance indicators, including, but not limited to, customer satisfaction, plant availability, system reliability, the execution of major construction projects, and net income.

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

~~See FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters~~ – ~~Nuclear Construction" and Note (F) to the Condensed Financial Statements under "DOE Loan Guarantee Borrowings" herein for additional information.~~

Third Quarter 2019 vs. Third Quarter 2018 Year-to-Date 2019 vs. Year-to-Date 2018
(change in millions) (% change) (change in millions) (% change)
$175 26.4 $977 157.3

Georgia Power's net income for the third quarter 2019 was $839 million compared to $664 million for the corresponding period in 2018. The increase was primarily due to an increase in retail revenues associated with higher contributions from commercial and industrial customers with variable demand-driven pricing and warmer weather in the third quarter 2019 compared to the corresponding period in 2018.

For year-to-date 2019, net income was $1.60 billion compared to $621 million for the corresponding period in 2018. The increase was primarily due to a $1.1 billion ($0.8 billion after tax) charge in the second quarter 2018 for an estimated probable loss related to Georgia Power's construction of Plant Vogtle Units 3 and 4, an increase in retail revenues associated with higher contributions from commercial and industrial customers with variable demand-driven pricing, warmer weather in the third quarter 2019 compared to the corresponding period in 2018, and an increase in other revenues primarily related to unregulated sales. Partially offsetting the increase were higher non-fuel operations and maintenance expenses and depreciation and amortization.

Third Quarter 2019 vs. Third Quarter 2018 Year-to-Date 2019 vs. Year-to-Date 2018
(change in millions) (% change) (change in millions) (% change)
$142 5.9 $69 1.1

In the third quarter 2019, retail revenues were $2.57 billion compared to $2.43 billion for the corresponding period in 2018. For year-to-date 2019, retail revenues were $6.18 billion compared to $6.11 billion for the corresponding period in 2018.

~~Details of the changes in retail revenues were as follows:~~

Third Quarter 2019 Year-to-Date 2019
(in millions) (% change) (in millions) (% change)
Retail – prior year $ 2,425
$ 6,112

Estimated change resulting from –
Rates and pricing 116
4.8 % 177
2.9 %
Sales decline (41 ) (1.7 ) (52 ) (0.9 )
Weather 89
3.7
61
1.0
Fuel cost recovery (22 ) (0.9 ) (117 ) (1.9 )
Retail – current year $ 2,567
5.9 % $ 6,181
1.1 %

Revenues attributable to changes in sales decreased in the third quarter and year-to-date 2019 when compared to the corresponding periods in 2018. Weather-adjusted residential KWH sales decreased 1.9% and 0.3% and weather-adjusted commercial KWH sales decreased 2.0% and 1.4% in the third quarter and year-to-date 2019, respectively, primarily due to a decline in average customer usage resulting from an increase in energy saving initiatives, partially offset by customer growth. Weather-adjusted industrial KWH sales decreased 3.7% in the third quarter 2019 primarily due to decreases in the paper, textile, and chemical sectors. Weather-adjusted industrial KWH sales decreased 1.8% for year-to-date 2019 primarily due to decreases in the textile, stone, clay, and glass, and paper sectors. The decreases in weather-adjusted industrial KWH sales in the third quarter and year-to-date 2019 were partially offset by an increase in the pipeline sector.

Fuel revenues and costs are allocated between retail and wholesale jurisdictions. Retail fuel cost recovery revenues decreased in the third quarter and year-to-date 2019 when compared to the corresponding periods in 2018. For year-to-date 2019, the decrease was primarily due to lower generation costs. Electric rates include provisions to periodically adjust billings for fluctuations in fuel costs, including the energy component of purchased power costs. Under these fuel cost recovery provisions, fuel revenues generally equal fuel expenses and do not affect net income. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Fuel Cost Recovery" of Georgia Power in Item 7 of the Form 10-K for additional information.

Third Quarter 2019 vs. Third Quarter 2018 Year-to-Date 2019 vs. Year-to-Date 2018
(change in millions) (% change) (change in millions) (% change)
$(7) (16.3) $(25) (20.3)

Wholesale revenues from sales to non-affiliates consist of PPAs and short-term opportunity sales. Wholesale revenues from PPAs have both capacity and energy components. Wholesale capacity revenues from PPAs are recognized either on a levelized basis over the appropriate contract period or the amounts billable under the contract terms and provide for recovery of fixed costs and a return on investment. Wholesale revenues from sales to non-affiliates will vary depending on fuel prices, the market prices of wholesale energy compared to the cost of Georgia Power's and the Southern Company system's generation, demand for energy within the Southern Company system's electric service territory, and the availability of the Southern Company system's generation. Increases and decreases in energy revenues that are driven by fuel prices are accompanied by an increase or decrease in fuel costs and do not have a significant impact on net income. Short-term opportunity sales are made at market-based rates that generally provide a margin above Georgia Power's variable cost of energy.

Third Quarter 2019 vs. Third Quarter 2018 Year-to-Date 2019 vs. Year-to-Date 2018
(change in millions) (% change) (change in millions) (% change)
$28 23.1 $69 19.8

Third Quarter 2019
vs.
Third Quarter 2018
Year-to-Date 2019
vs.
Year-to-Date 2018
(change in millions) (% change) (change in millions) (% change)
Fuel $ (37 ) (7.7 ) $ (137 ) (10.8 )
Purchased power – non-affiliates 45
42.5
55
16.3
Purchased power – affiliates (56 ) (27.2 ) (95 ) (17.1 )
Total fuel and purchased power expenses $ (48 ) $ (177 )

In the third quarter 2019, total fuel and purchased power expenses were $744 million compared to $792 million in the corresponding period in 2018. The decrease was primarily due to a $58 million decrease related to the average cost of fuel and purchased power primarily related to lower fuel and energy prices, partially offset by a net increase of $10 million related to the volume of KWHs generated and purchased.

For year-to-date 2019, total fuel and purchased power expenses were $1.99 billion compared to $2.16 billion in the corresponding period in 2018. The decrease was primarily due to a $171 million decrease related to the average cost of fuel and purchased power primarily related to lower fuel and energy prices.

Fuel and purchased power energy transactions do not have a significant impact on earnings since these fuel expenses are generally offset by fuel revenues through Georgia Power's fuel cost recovery mechanism. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Fuel Cost Recovery" of Georgia Power in Item 7 of the Form 10-K for additional information.

~~Details of Georgia Power's generation and purchased power were as follows:~~

Third Quarter 2019 Third Quarter 2018 Year-to-Date 2019 Year-to-Date 2018
Total generation (in billions of KWHs)
19 18 48 49
Total purchased power (in billions of KWHs)
8 8 23 22
Sources of generation (percent) —

Gas 46 44 47 43
Coal 31 32 26 30
Nuclear 22 22 24 25
Hydro 1 2 3 2
Cost of fuel, generated (in cents per net KWH) —

Gas 2.33 2.58 2.45 2.64
Coal 3.00 3.14 3.10 3.25
Nuclear 0.82 0.83 0.81 0.83
Average cost of fuel, generated (in cents per net KWH)
2.20 2.36 2.21 2.36
Average cost of purchased power (in cents per net KWH)^(*)
4.20 4.52 4.22 4.70

In the third quarter 2019, fuel expense was $443 million compared to $480 million in the corresponding period in 2018. The decrease was primarily due to a 6.8% decrease in the average cost of fuel, primarily related to lower natural gas and coal prices, partially offset by a 3.5% increase in the volume of KWHs generated, primarily due to warmer weather in the third quarter 2019 compared to the corresponding period in 2018.

For year-to-date 2019, fuel expense was $1.13 billion compared to $1.27 billion in the corresponding period in 2018. The decrease was primarily due to a 6.4% decrease in the average cost of fuel, primarily related to lower natural gas and coal prices, and a 3.0% decrease in the volume of KWHs generated, primarily due to scheduled generation outages, as well as milder weather in the first quarter 2019 compared to the corresponding period in 2018.

In the third quarter 2019, purchased power expense from non-affiliates was $151 million compared to $106 million in the corresponding period in 2018. For year-to-date 2019, purchased power expense from non-affiliates was $393 million compared to $338 million in the corresponding period in 2018. The increases were primarily due to 86.9% and 45.2% increases in the volume of KWHs purchased in the third quarter and year-to-date 2019, respectively, primarily due to warmer weather in the third quarter 2019 resulting in higher customer demand and scheduled generation outages at Georgia Power-owned generating units, partially offset by 23.2% and 21.0% decreases in the average cost per KWH purchased in the third quarter and year-to-date 2019, respectively, primarily due to lower energy prices.

~~The volume increases also reflect purchases from Gulf Power which were classified as affiliate prior to January 1, 2019. See Note (K) to the Condensed Financial Statements under "Southern Company" herein for information regarding the sale of Gulf Power.~~

Energy purchases from non-affiliates will vary depending on the market prices of wholesale energy as compared to the cost of the Southern Company system's generation, demand for energy within the Southern Company system's electric service territory, and the availability of the Southern Company system's generation.

In the third quarter 2019, purchased power expense from affiliates was $150 million compared to $206 million in the corresponding period in 2018. For year-to-date 2019, purchased power expense from affiliates was $460 million compared to $555 million in the corresponding period in 2018. The decreases were primarily due to 25.5% and 9.7% decreases in the volume of KWHs purchased in the third quarter and year-to-date 2019, respectively, as Georgia Power units generally dispatched at a lower cost than other Southern Company system resources and 8.3% and 9.9% decreases in the average cost per KWH purchased in the third quarter and year-to-date 2019, respectively, resulting from lower energy prices.

The decreases in purchased power expense from affiliates also reflect the classification of capacity expenses of $6 million and $18 million in the third quarter and year-to-date 2019, respectively, related to PPAs with Southern Power accounted for as finance leases following the adoption of FASB ASC Topic 842, ~~Leases~~ (ASC 842). In 2019, these expenses are included in depreciation and amortization and interest expense, net of amounts capitalized. The decreases in the volume of KWHs purchased also include the effect of classifying purchases from Gulf Power as non-affiliate beginning January 1, 2019. See Notes (L) and (K) to the Condensed Financial Statements herein for additional information regarding Georgia Power's adoption of ASC 842 and the sale of Gulf Power, respectively.

Energy purchases from affiliates will vary depending on demand and the availability and cost of generating resources at each company within the Southern Company system. These purchases are made in accordance with the IIC or other contractual agreements, all as approved by the FERC.

Third Quarter 2019 vs. Third Quarter 2018 Year-to-Date 2019 vs. Year-to-Date 2018
(change in millions) (% change) (change in millions) (% change)
$8 8.4 $1 0.3

The results of operations discussed above are not necessarily indicative of Georgia Power's future earnings potential. The level of Georgia Power's future earnings depends on numerous factors that affect the opportunities, challenges, and risks of Georgia Power's business of providing electric service. These factors include Georgia Power's ability to maintain a constructive regulatory environment that continues to allow for the timely recovery of prudently-incurred costs during a time of increasing costs, continued customer growth, and the weak pace of growth in electricity use per customer, especially in residential and commercial markets. Plant Vogtle Units 3 and 4 construction and rate recovery are also major factors. Earnings will also depend upon maintaining and growing sales, considering, among other things, the adoption and/or penetration rates of increasingly energy-efficient technologies, increasing volumes of electronic commerce transactions, and more multi-family home construction, all of which could contribute to a net reduction in customer usage. Earnings are subject to a variety of other factors. These factors include weather, competition, new energy contracts with other utilities, energy conservation practiced by customers, the use of alternative energy sources by customers, the price of electricity, the price elasticity of demand, and the rate of economic growth or decline in Georgia Power's service territory. Demand for electricity is primarily driven by the pace of economic growth that may be affected by changes in regional and global economic conditions, which may impact future earnings.

~~For additional information relating to these issues, see RISK FACTORS in Item 1A and MANAGEMENT'S DISCUSSION AND ANALYSIS~~ – ~~FUTURE EARNINGS POTENTIAL of Georgia Power in Item 7 of the Form 10-K.~~

On October 22, 2019, the EPA and the U.S. Army Corps of Engineers jointly published a final rule that repealed the 2015 Waters of the United States (WOTUS) rule. This final rule will be effective December 23, 2019 and will bring all states back under the pre-2015 regulations until a new WOTUS rule is finalized. A revised definition of WOTUS is anticipated to be finalized by the end of 2019. The impact of the WOTUS rule will depend on the content of the final~~rule redefining WOTUS and the outcome of any associated legal challenges and cannot be determined at this time.~~

On July 8, 2019, the EPA published the final Affordable Clean Energy rule (ACE Rule) to repeal and replace the CPP. On September 17, 2019, the D.C. Circuit Court of Appeals dismissed litigation related to the CPP as moot. The ACE Rule requires states to develop unit-specific CO₂ emission rate standards for existing coal-fired units based on heat-rate efficiency improvements. Combustion turbines, including natural gas combined cycles, are not included as affected sources in the ACE Rule. Georgia Power has ownership interests in nine coal-fired units (approximately 4,800 MWs) to which the ACE Rule is applicable. The ACE Rule is being challenged in the D.C. Circuit Court of Appeals and Georgia Power has filed a motion to intervene in the litigation in support of the rule, as have others. The ultimate impact of the ACE Rule, including the repeal and replacement of the CPP, to Georgia Power will depend on state implementation plan requirements and the outcome of associated legal challenges and cannot be determined at this time.

Georgia Power's revenues from regulated retail operations are collected through various rate mechanisms subject to the oversight of the Georgia PSC. Georgia Power currently recovers its costs from the regulated retail business through the 2013 ARP, which includes traditional base tariff rates, Demand-Side Management tariffs, ECCR tariffs, and Municipal Franchise Fee tariffs. In addition, financing costs related to certified construction costs of Plant Vogtle Units 3 and 4 are being collected through the NCCR tariff and fuel costs are collected through a separate fuel cost recovery tariff. See Note 2 to the financial statements under "Georgia Power" in Item 8 of the Form 10-K for additional information regarding regulatory matters.

On June 28, 2019, Georgia Power filed a base rate case (Georgia Power 2019 Base Rate Case) with the Georgia PSC. The filing, as modified on September 24, 2019, includes a three-year Alternate Rate Plan with requested rate increases totaling $560 million, $144 million, and $233 million effective January 1, 2020, January 1, 2021, and January 1, 2022, respectively. These increases are based on a proposed retail ROE of 10.90% and a proposed equity ratio of 56% and reflect levelized revenue requirements during the three-year period, with the exception of incremental compliance costs related to CCR AROs, Demand-Side Management programs, and adjustments to the Municipal Franchise Fee tariff.

~~Georgia Power has requested recovery of the proposed increases through its existing base rate tariffs as follows:~~

Georgia Power's filing primarily reflects requests to (i) address the impacts of the Tax Reform Legislation, (ii) recover the costs of recent and future capital investments in infrastructure designed to maintain high levels of reliability and superior customer service with updated depreciation rates, (iii) recover substantial storm damage expenses incurred and deferred since 2013 along with a reasonable level of storm damage expenses expected to be incurred during the three years ending December 31, 2022, and (iv) recover the costs necessary to comply with federal and state regulations for CCR AROs. In addition, the filing includes the following provisions:

~~Georgia Power expects the Georgia PSC to issue a final order in this matter on December 17, 2019. The ultimate outcome of this matter cannot be determined at this time.~~

In 2016, the Georgia PSC approved Georgia Power's triennial IRP, including 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. In 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. In accordance with the Georgia PSC's order, costs incurred of approximately $50 million have been recorded as a regulatory asset.

On July 16, 2019, the Georgia PSC voted to approve Georgia Power's triennial IRP (Georgia Power 2019 IRP) as modified by a stipulated agreement among Georgia Power, the staff of the Georgia PSC, and certain intervenors and further modified by the Georgia PSC.

In the Georgia Power 2019 IRP, the Georgia PSC approved the decertification and retirement of Plant Hammond Units 1 through 4 (840 MWs) and Plant McIntosh Unit 1 (142.5 MWs) effective July 29, 2019. The Georgia PSC also approved the reclassification of the remaining net book values of the Plant Hammond and Plant McIntosh units (approximately $500 million and $40 million, respectively), as well as any unusable materials and supplies inventory balances, upon retirement to a regulatory asset. Recovery of each unit's net book value will continue through December 31, 2019 as provided in the 2013 ARP. Additionally, approximately $295 million of net capitalized asset retirement costs were reclassified to a regulatory asset.

For the regulatory asset balances remaining at December 31, 2019, Georgia Power requested recovery in the Georgia Power 2019 Base Rate Case as follows: (i) the net book values of Plant Mitchell Unit 3 (approximately $8 million at September 30, 2019) and Plant McIntosh Unit 1, any unusable materials and supplies inventory, and the future generation site in Stewart County, Georgia over a three-year period ending December 31, 2022 and (ii) the net book values of Plant Hammond Units 1 through 4 over a period equal to the applicable unit's remaining useful life through 2035. The timing of recovery of the related ARO costs will be determined in the Georgia Power 2019 Base Rate Case. The ultimate outcome of these matters cannot be determined at this time.

Also in the Georgia Power 2019 IRP, the Georgia PSC approved Georgia Power's proposed environmental compliance strategy associated with ash pond and certain landfill closures and post-closure care in compliance with the CCR Rule and the related state rule. In the Georgia Power 2019 Base Rate Case, Georgia Power requested recovery of the under recovered balance of these compliance costs at December 31, 2019 (approximately $157 million at September 30, 2019) over a three-year period ending December 31, 2022 and recovery of estimated compliance costs of $277 million for 2020, $395 million for 2021, and $655 million for 2022 over three-year periods ending December 31, 2022, 2023, and 2024, respectively. The ultimate outcome of this matter cannot be determined at this time. See Note 6 to the financial statements in Item 8 of the Form 10-K for additional information regarding Georgia Power's AROs.

Additionally, the Georgia PSC rejected a request to certify approximately 25 MWs of capacity at Plant Scherer Unit 3 for the retail jurisdiction beginning January 1, 2020 following the expiration of a wholesale PPA. Georgia Power may offer such capacity in the wholesale market or to the retail jurisdiction in a future IRP. The ultimate outcome of this matter cannot be determined at this time but is not expected to have a material impact on Georgia Power's financial statements.

The Georgia PSC also approved Georgia Power to (i) issue requests for proposals (RFP) for capacity beginning in 2022 or 2023 and in 2026, 2027, or 2028; (ii) procure up to an additional 2,210 MWs of renewable resources through competitive RFPs; and (iii) invest in a portfolio of up to 80 MWs of battery energy storage technologies.

~~See "Rate Plans" herein for additional information regarding the Georgia Power 2019 Base Rate Case.~~

See Note 2 to the financial statements under "Georgia Power – Nuclear Construction" in Item 8 of the Form 10-K for additional information regarding the construction of Plant Vogtle Units 3 and 4, the joint ownership agreements and related funding agreement, VCM reports, and the NCCR tariff.

In October 2017, Georgia Power, acting for itself and as agent for the other Vogtle Owners, executed the Bechtel Agreement, a cost reimbursable plus fee arrangement, whereby Bechtel is 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.

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

As of September 30, 2019, approximately $30 million of the construction contingency estimate was allocated to the base capital cost forecast for cost risks including, among other factors, attracting and retaining craft labor; adding resources for supervision, field support, project management, initial test program, and start-up; and procurement. As and when construction contingency is spent, Georgia Power may request the Georgia PSC to evaluate those expenditures for rate recovery.

Georgia Power estimates that its financing costs for construction of Plant Vogtle Units 3 and 4 will total approximately $3.1 billion, of which $2.1 billion had been incurred through September 30, 2019.

In April 2019, Southern Nuclear completed a cost and schedule validation process to verify and update quantities of commodities remaining to install, labor hours to install remaining quantities and related productivity, testing and system turnover requirements, and forecasted staffing needs and related costs. This process confirmed the estimated total project capital cost forecast for Plant Vogtle Units 3 and 4. The expected in-service dates of November 2021 for Unit 3 and November 2022 for Unit 4, as previously approved by the Georgia PSC, remain unchanged. On April 30, 2019, as requested by the staff of the Georgia PSC, Georgia Power reported the results of the cost and schedule validation process to the Georgia PSC.

As construction continues and testing and system turnover activities increase, challenges with management of contractors, subcontractors, and vendors; supervision of craft labor and related craft labor productivity, particularly in the installation of electrical and mechanical commodities, ability to attract and retain craft labor, and/or related cost escalation; procurement, fabrication, delivery, assembly, and/or installation and the initial testing and start-up, including any required engineering changes, of plant systems, structures, or components (some of which are based on new technology that only recently began initial operation in the global nuclear industry at this scale), or regional transmission upgrades, any of which may require additional labor and/or materials; or other issues could arise and change the projected schedule and estimated cost.

The April 2019 cost and schedule validation process established target values for monthly construction production and system turnover activities as part of a strategy to maintain and, where possible, build margin to the approved in-service dates. To support that strategy, monthly production and activity target values will continue to increase significantly throughout the remainder of 2019 and into 2020. To meet these increasing monthly targets, existing craft construction productivity must improve and additional craft laborers (particularly electrical and pipefitter craft labor), as well as additional supervision and other field support resources, must be retained and deployed.

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 submittal by Southern Nuclear of the ITAAC documentation for each unit and the related reviews and approvals by the NRC necessary to support NRC authorization to load fuel, 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. However, any extension of the regulatory-approved project schedule is currently estimated to result in additional base capital costs of approximately $50 million per month, based on Georgia Power's ownership interests, and AFUDC of approximately $11 million per month. While Georgia Power is not precluded from seeking recovery of any future capital cost forecast increase, management will ultimately determine whether or not to seek recovery. Any further changes to the capital cost forecast that are not expected to be recoverable through regulated rates will be required to be charged to income and such charges could be material.

and Georgia Watch filed an appeal of this decision with the Georgia Court of Appeals. OnIn October ~~29,~~ 2019, the Georgia Court of Appeals issued an opinion affirming the Fulton County Superior Court's ruling that the Georgia PSC's January 11, 2018 order was not a final, appealable decision. In addition, the Georgia Court of Appeals remanded the case to the Fulton County Superior Court to clarify its ruling as to whether the petitioners showed that review of the Georgia PSC's final order would not provide them an adequate remedy. On April 21, 2020, the Fulton County Superior Court entered an appealable order granting Georgia Power's motion to dismiss the two appeals. Georgia Power believes the petitions have no merit; however, an adverse outcome in the litigation combined with subsequent adverse action by the Georgia PSC could have a material impact on Southern Company's and Georgia Power's results of operations, financial condition, and liquidity.

In the nineteenth VCM, the Georgia PSC deferred approval of $51.6 million of expenditures related to Georgia Power's portion of an administrative claim filed in the Westinghouse bankruptcy proceedings. On June 20, 2019, Georgia Power, acting for itself and as agent for the other Vogtle Owners, entered into a settlement agreement related to the administrative claim filed in the Westinghouse bankruptcy proceedings. Accordingly, in the twentieth/twenty-first VCM report, Georgia Power also requested approval of $21.5 million of associated expenditures previously deferred for approval by the Georgia PSC. The remaining $30.1 million deferred for approval was refunded to Georgia Power and credited to the total construction capital costs.during that period.

At September 30, 2019, Georgia Power had borrowed $3.46 billion related to Plant Vogtle Units 3 and 4 costs as provided through the Amended and Restated Loan Guarantee Agreement and related multi-advance credit facilities among Georgia Power, the DOE,PEP and the ~~FFB, which provide~~ECO Plan for ~~borrowings~~2018 through 2020, Mississippi Power plans to resume PEP proceedings and ECO Plan filings for 2021.

~~Georgia Power is~~Registrants are involved in various other ~~matters that could affect future earnings, including~~ matters being litigated and regulatory matters. ~~In addition, Georgia Power is subject to certain claims and legal actions arising in the ordinary course of business. Georgia Power's business activities~~ are subject to extensive governmental regulation related to public health and the environment, such as laws and regulations governing air, water, land, and protection of other natural resources. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental laws and regulations, 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 or regulatory matters against each Registrant and any subsidiaries cannot be determined at this time; however, for current proceedings not specifically reported ~~in Notes (B) and (C) to the Condensed Financial~~

~~Statements~~ herein, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on ~~Georgia Power's~~such Registrant's financial statements. ~~See Notes (B)~~

Georgia Power prepares its financial statements in accordance with GAAP. Significant accounting policies are described in Notes 1, 5, and 6 to the financial statements in Item 8 of the Form 10-K. In the application of these policies, certain estimates are made that may have a material impact on Georgia Power's results of operations and related disclosures. Different assumptions and measurements could produce estimates that are significantly different from those recorded in the financial statements. See MANAGEMENT'S DISCUSSION AND ANALYSIS – ACCOUNTING POLICIES – "Application of Critical Accounting Policies and Estimates" of Georgia Power in Item 7 of the Form 10-K for a complete discussion of Georgia Power's critical accounting policies and estimates.

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Overview" of Georgia Power in Item 7 of the Form 10-K for additional information. Georgia Power's financial condition remained stable at September 30, 2019. Georgia Power intends to continue to monitor its access to short-term and long-term capital markets as well as bank credit agreements to meet future capital and liquidity needs. See "~~Capital Requirements and Contractual Obligations," "Sources of Capital," and "Financing Activities" herein for additional information.~~

Net cash provided from operating activities totaled $2.4 billion for the first nine months of 2019 compared to $2.2 billion for the corresponding period in 2018. The increase was primarily due to lower customer refunds and increased fuel cost recovery, partially offset by the timing of vendor payments. Net cash used for investing activities totaled $2.8 billion for the first nine months of 2019 primarily related to installation of equipment to comply with environmental standards and construction of generation, transmission, and distribution facilities, including approximately $1.0 billion related to the construction of Plant Vogtle Units 3 and 4. Net cash provided from financing activities totaled $765 million for the first nine months of 2019 primarily due to borrowings from the FFB for construction of Plant Vogtle Units 3 and 4, issuances of senior notes, and the reoffering of pollution control revenue bonds, partially offset by payment of common stock dividends and the redemption and repurchase of pollution control revenue bonds. Cash flows from financing activities vary from period to period based on capital needs and the maturity or redemption of securities.

Significant balance sheet changes for the first nine months of 2019 include an increase of $2.0 billion in long-term debt (including securities due within one year) primarily due to borrowings from the FFB for construction of Plant Vogtle Units 3 and 4, issuances of senior notes, and the reoffering of pollution control revenue bonds previously purchased and held by Georgia Power; recording $1.5 billion in operating lease right-of-use assets, net of amortization and $1.4 billion in operating lease obligations related to the adoption of ASC 842; an increase of $1.1 billion in regulatory assets primarily due to the retirement of certain generating units as approved in the Georgia Power 2019 IRP; and an increase of $1.0 billion in property, plant, and equipment to comply with environmental standards and the construction of generation, transmission, and distribution facilities, net of $835 million reclassified to regulatory assets due to unit retirements. See Notes (B) and (F) to the Condensed Financial Statements under "~~Georgia Power~~ – ~~Nuclear Construction" and "DOE Loan Guarantee Borrowings~~," respectively, herein for additional information regarding Plant Vogtle Units 3 and 4 and the related Amended and Restated Loan Guarantee Agreement. Also see Note (B) to the Condensed Financial Statements under "~~Georgia Power~~ – ~~Integrated Resource Plan" and Note (L) to the Condensed Financial Statements herein for additional information on the Georgia Power 2019 IRP and the adoption of ASC 842, respectively.~~

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" of Georgia Power in Item 7 of the Form 10-K for a description of Georgia Power's capital requirements and contractual obligations. Approximately $1.5 billion will be required through September 30, 2020 to fund maturities of long-term debt. See "~~Sources of Capital" herein for additional information. Also see FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters~~ – ~~Nuclear Construction" for additional information regarding Plant Vogtle Units 3 and 4.~~

The construction program is subject to periodic review and revision, and actual construction costs may vary from these estimates because of numerous factors. These factors include: changes in business conditions; changes in load projections; changes in environmental laws and regulations; the outcome of any legal challenges to environmental rules; changes in generating plants, including unit retirements and replacements and adding or changing fuel sources at existing generating units, to meet regulatory requirements; changes in FERC rules and regulations; Georgia PSC approvals; changes in the expected environmental compliance program; changes in legislation; the cost and efficiency of construction labor, equipment, and materials; project scope and design changes; storm impacts; and the cost of capital. In addition, there can be no assurance that costs related to capital expenditures will be fully recovered. The construction program also includes Plant Vogtle Units 3 and 4, which includes components based on new technology that only recently began initial operation in the global nuclear industry at this scale and which may be subject to additional revised cost estimates during construction. The ability to control costs and avoid cost and schedule overruns during the development, construction, and operation of new facilities is subject to a number of factors, including, but not limited to, changes in labor costs, availability, and productivity; challenges with management of contractors, subcontractors, or vendors; adverse weather conditions; shortages, delays, increased costs, or inconsistent quality of equipment, materials, and labor; contractor or supplier delay; nonperformance under construction, operating, or other agreements; operational readiness, including specialized operator training and required site safety programs; engineering or design problems; design and other licensing-based compliance

matters, including the timely submittal by Southern Nuclear of the ITAAC documentation for each unit and the related reviews and approvals by the NRC necessary to support NRC authorization to load fuel; challenges with start-up activities, including major equipment failure, system integration, or regional transmission upgrades; and/or operational performance. See Note 2 to the financial statements under "Georgia Power – Nuclear Construction" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "~~Georgia Power~~ – ~~Nuclear Construction" herein for information regarding additional factors that may impact construction expenditures.~~

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

In 2014, Georgia Power entered into a loan guarantee agreement with the DOE and, in March 2019, entered into the Amended and Restated Loan Guarantee Agreement, under which the proceeds of borrowings may be used to reimburse Georgia Power for Eligible Project Costs incurred in connection with its construction of Plant Vogtle Units 3 and 4.

Under the Amended and Restated Loan Guarantee Agreement, the DOE has agreed to guarantee the obligations of Georgia Power under note purchase agreements among the DOE, Georgia Power, and the FFB and related promissory notes which provide for two multi-advance term loan facilities (FFB Credit Facilities). Under the FFB Credit Facilities, Georgia Power may make term loan borrowings through the FFB in an amount up to approximately $5.130 billion, provided that total aggregate borrowings under the FFB Credit Facilities may not exceed 70% of (i) Eligible Project Costs minus (ii) approximately $1.492 billion (reflecting the amounts received by Georgia Power under the Guarantee Settlement Agreement less the Customer Refunds). At September 30, 2019, Georgia Power had borrowed $3.46 billion under the FFB Credit Facilities.

~~See Note (F) to the Condensed Financial Statements under "DOE Loan Guarantee Borrowings~~" herein for additional information regarding the Amended and Restated Loan Guarantee Agreement, including applicable covenants, events of default, mandatory prepayment events, and additional conditions to borrowing. Also see Note (B) to the Condensed Financial Statements under "~~Georgia Power~~ – ~~Nuclear Construction" herein for additional information regarding Plant Vogtle Units 3 and 4.~~

Georgia Power's current liabilities frequently exceed current assets because of scheduled maturities of long-term debt and the periodic use of short-term debt as a funding source, as well as significant seasonal fluctuations in cash needs. At September 30, 2019, Georgia Power's current liabilities exceeded current assets by $1.9 billion primarily due to long-term debt that is due within one year of $1.5 billion and notes payable of $250 million.

At September 30, 2019, Georgia Power had approximately $449 million of cash and cash equivalents and a multi-year committed credit arrangement with banks totaling $1.75 billion, of which $1.73 billion was unused. In May 2019, Georgia Power amended its bank credit arrangement which, among other things, extended the maturity date from 2022 to 2024. This credit arrangement, as well as Georgia Power's term loan arrangements, contain a covenant that limits debt levels and contain a cross-acceleration provision to other indebtedness (including guarantee obligations) of Georgia Power. Such cross-acceleration provisions to other indebtedness would trigger an event of default if Georgia Power defaulted on indebtedness, the payment of which was then accelerated. At September 30, 2019, Georgia Power was in compliance with this covenant. The bank credit arrangement does not contain a material adverse change clause at the time of borrowing.

Subject to applicable market conditions, Georgia Power expects to renew or replace this credit arrangement as needed prior to expiration. In connection therewith, Georgia Power may extend the maturity date and/or increase or decrease the lending commitments thereunder.

~~See Note 8 to the financial statements under "Bank Credit Arrangements" in Item 8 of the Form 10-K and Note (F) to the Condensed Financial Statements under "Bank Credit Arrangements" herein for additional information.~~

A portion of the $1.73 billion unused bank credit arrangement is allocated to provide liquidity support to Georgia Power's pollution control revenue bonds and commercial paper program. The amount of variable rate pollution control revenue bonds outstanding requiring liquidity support as of September 30, 2019 was approximately $550 million.

Georgia Power may also meet short-term cash needs through a Southern Company subsidiary organized to issue and sell commercial paper at the request and for the benefit of Georgia Power and the other traditional electric operating companies. Proceeds from such issuances for the benefit of Georgia Power are loaned directly to Georgia Power. The obligations of each traditional electric operating company under these arrangements are several and there is no cross-affiliate credit support. Short-term borrowings are included in notes payable in the balance sheets.

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

~~Georgia Power believes the need for working capital can be adequately met by utilizing the commercial paper program, lines of credit, short-term bank notes, and operating cash flows.~~

~~At September 30, 2019, Georgia Power did not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade.~~

There are certain contracts that could require collateral, but not accelerated payment, in the event of a credit rating change to BBB- and/or Baa3 or below. These contracts are for physical electricity purchases and sales, fuel purchases, fuel transportation and storage, energy price risk management, transmission, and construction of new generation at Plant Vogtle Units 3 and 4.

~~The maximum potential collateral requirements under these contracts at September 30, 2019 were as follows:~~

Included in these amounts are certain agreements that could require collateral in the event that Georgia Power or Alabama Power (an affiliate of Georgia Power) has a credit rating change to below investment grade. Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. Additionally, a credit rating downgrade could impact the ability of Georgia Power to access capital markets and would be likely to impact the cost at which it does so.

In January 2019, Georgia Power redeemed approximately $13 million, $20 million, and $75 million aggregate principal amount of Development Authority of Burke County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Vogtle Project), First Series 1992, Eighth Series 1994, and Second Series 1995, respectively.

In March 2019, Georgia Power made additional borrowings under the FFB Credit Facilities in an aggregate principal amount of $835 million at an interest rate of 3.213% through the final maturity date of February 20, 2044. The proceeds were used to reimburse Georgia Power for Eligible Project Costs relating to the construction of Plant Vogtle Units 3 and 4.

~~Also in March 2019, Georgia Power reoffered to the public the following pollution control revenue bonds that previously had been purchased and held by Georgia Power:~~

~~In April 2019, Georgia Power purchased and held the following pollution control revenue bonds. In May 2019, Georgia Power reoffered these pollution control revenue bonds to the public.~~

In June 2019, Georgia Power reoffered to the public $55 million aggregate principal amount of Development Authority of Burke County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Vogtle Project), Fifth Series 1994, which previously had been purchased and held by Georgia Power.

Also in June 2019, Georgia Power entered into two short-term floating rate bank loans in aggregate principal amounts of $125 million each, both of which bear interest based on one-month LIBOR. The proceeds from these bank loans were used to repay a portion of Georgia Power's existing indebtedness and for working capital and other general corporate purposes.

In August 2019, Georgia Power reoffered to the public approximately $72 million aggregate principal amount of Development Authority of Bartow County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Bowen Project), First Series 2013, which previously had been purchased and held by Georgia Power.

In September 2019, Georgia Power issued $400 million aggregate principal amount of Series 2019A 2.20% Senior Notes due September 15, 2024 and $350 million aggregate principal amount of Series 2019B 2.65% Senior Notes due September 15, 2029. The proceeds were used to repay a portion of Georgia Power's short-term indebtedness and for general corporate purposes.

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

Mississippi Power operates as a vertically integrated utility providing electric service to retail customers within its traditional service territory located within the State of Mississippi and to wholesale customers in the Southeast.

Many factors affect the opportunities, challenges, and risks of Mississippi Power's business of providing electric service. These factors include Mississippi Power's ability to maintain and grow energy sales and number of customers and to operate in a constructive regulatory environment that provides timely recovery of prudently-incurred costs. These costs include those related to projected long-term demand growth, stringent environmental standards, including CCR rules, reliability, fuel, capital and operations and maintenance expenditures, including expanding and improving transmission and distribution facilities, and restoration following major storms. Appropriately balancing required costs and capital expenditures with customer prices will continue to challenge Mississippi Power for the foreseeable future. Mississippi Power is scheduled to file a base rate case by the end of 2019 (Mississippi Power 2019 Base Rate Case).

Mississippi Power continues to focus on several key performance indicators. In recognition that Mississippi Power's long-term financial success is dependent upon how well it satisfies its customers' needs, Mississippi Power's retail base rate mechanism, PEP, includes performance indicators that directly tie customer service indicators to Mississippi Power's allowed ROE. Mississippi Power also focuses on broader measures of customer satisfaction, plant availability, system reliability, and net income.

~~Mississippi Power also continues to focus on resolution of matters related to the abandonment of the Kemper IGCC, including final disposition of the CO~~₂ ~~pipeline and outstanding legal proceedings and investigations.~~

Third Quarter 2019 vs. Third Quarter 2018 Year-to-Date 2019 vs. Year-to-Date 2018
(change in millions) (% change) (change in millions) (% change)
$18 38.3 $53 61.6

Mississippi Power's net income for the third quarter 2019 was $65 million compared to $47 million for the corresponding period in 2018. This increase was primarily due to a decrease in employee compensation and benefit expenses due to an employee attrition plan implemented in the third quarter 2018 and an increase in base rates that became effective for the first billing cycle of September 2018.

For year-to-date 2019, net income was $139 million compared to $86 million for the corresponding period in 2018. This increase was primarily due to lower charges associated with the Kemper IGCC in 2019, an increase in base rates that became effective for the first billing cycle of September 2018, and a decrease in employee compensation

~~and benefits due to an employee attrition plan implemented in the third quarter 2018, partially offset by the settlement of Mississippi Power's Deepwater Horizon claim in May 2018.~~

Third Quarter 2019 vs. Third Quarter 2018 Year-to-Date 2019 vs. Year-to-Date 2018
(change in millions) (% change) (change in millions) (% change)
$(3) (1.2) $9 1.4

Third Quarter 2019 Year-to-Date 2019
(in millions) (% change) (in millions) (% change)
Retail – prior year $ 254
$ 660

Estimated change resulting from –
Rates and pricing 8
3.1 % 34
5.2 %
Sales decline —
—
—
—
Weather 2
0.8
(7 ) (1.1 )
Fuel and other cost recovery (13 ) (5.1 ) (18 ) (2.7 )
Retail – current year $ 251
(1.2 )% $ 669
1.4 %

Third Quarter 2019 vs. Third Quarter 2018 Year-to-Date 2019 vs. Year-to-Date 2018
(change in millions) (% change) (change in millions) (% change)
$(6) (8.6) $(19) (9.6)

For year-to-date 2019, wholesale revenues from sales to non-affiliates were $178 million compared to $197 million for the corresponding period in 2018. This decrease primarily resulted from a $7 million decrease in energy prices related to lower natural gas prices, a $7 million decrease in cost-based electric tariff revenues resulting from decreased customer usage and a decrease in rates due to the MRA Settlement Agreement, and a $6 million decrease due to lower PPA capacity and energy sales. See Note (B) to the Condensed Financial Statements under "Mississippi Power – Municipal and Rural Association Tariff" herein for additional information.

Third Quarter 2019 vs. Third Quarter 2018 Year-to-Date 2019 vs. Year-to-Date 2018
(change in millions) (% change) (change in millions) (% change)
$23 82.1 $28 34.6

For year-to-date 2019, total fuel and purchased power expenses were $334 million compared to $339 million for the corresponding period in 2018. The decrease was primarily due to a $29 million decrease related to the average cost of fuel and purchased power primarily due to a lower average cost of natural gas, partially offset by a $24 million net increase associated with the volume of KWHs generated and purchased.

~~Details of Mississippi Power's generation and purchased power were as follows:~~

Third Quarter 2019 Third Quarter 2018 Year-to-Date 2019 Year-to-Date 2018
Total generation (in millions of KWHs)
5,554 4,581 14,125 12,665
Total purchased power (in millions of KWHs)
99 234 238 441
Sources of generation (percent) –

Coal 8 8 7 7
Gas 92 92 93 93
Cost of fuel, generated (in cents per net KWH) –

Coal 3.88 3.51 3.98 3.50
Gas 2.16 2.58 2.29 2.57
Average cost of fuel, generated (in cents per net KWH)
2.30 2.66 2.41 2.63
Average cost of purchased power (in cents per net KWH)
6.42 4.72 6.50 6.15

In the third quarter 2019, purchased power expense was $6 million compared to $11 million for the corresponding period in 2018. For year-to-date 2019, purchased power expense was $15 million compared to ~~$27 million~~ for the corresponding period in 2018. These decreases were primarily due to a 58% and 46% decrease in the volume of KWHs purchased due to the availability of Mississippi Power's lower-cost generation resources in the third quarter

~~and year-to-date 2019, respectively, partially offset by a 36% and 6% increase in the average cost per KWH purchased in the third quarter and year-to-date 2019, respectively.~~

In the third quarter 2019, other operations and maintenance expenses were $68 million compared to $80 million for the corresponding period in 2018. The decrease was primarily due to decreases of $15 million in employee compensation and benefit expenses due to an employee attrition plan implemented in the third quarter 2018.

For year-to-date 2019, other operations and maintenance expenses were $194 million compared to $222 million for the corresponding period in 2018. The decrease was primarily due to decreases of $20 million in employee compensation and benefit expenses primarily due to an employee attrition plan implemented in the third quarter 2018, $6 million related to Plant Ratcliffe waste water treatment, and $4 million related to lower amortization of previously deferred Plant Ratcliffe expenses as a result of the MRA Settlement Agreement. These decreases were partially offset by a $6 million increase related to additional overhead line maintenance and vegetation management. See Note (B) to the Condensed Financial Statements under "Mississippi Power – Municipal and Rural Association Tariff" herein for additional information.

Third Quarter 2019 vs. Third Quarter 2018 Year-to-Date 2019 vs. Year-to-Date 2018
(change in millions) (% change) (change in millions) (% change)
$3 N/M $(35) (77.8)

Third Quarter 2019 vs. Third Quarter 2018 Year-to-Date 2019 vs. Year-to-Date 2018
(change in millions) (% change) (change in millions) (% change)
$4 N/M $(13) (46.4)

For year-to-date 2019, other income (expense), net was $15 million compared to $28 million for the corresponding period in 2018. This decrease was primarily due to a $24 million decrease related to the settlement of Mississippi Power's Deepwater Horizon claim recorded in May 2018, partially offset by an increase of $9 million primarily due to higher interest income associated with a new tolling arrangement accounted for as a sales-type lease. See Note (L) to the Condensed Financial Statements herein and Note 3 to the financial statements under "Other Matters – Mississippi Power" in Item 8 of the Form 10-K for additional information.

Third Quarter 2019 vs. Third Quarter 2018 Year-to-Date 2019 vs. Year-to-Date 2018
(change in millions) (% change) (change in millions) (% change)
$1 7.1 $4 17.4

In the third quarter 2019, income taxes were $15 million compared to $14 million for the corresponding period in 2018. For year-to-date 2019, income taxes were $27 million compared to $23 million for the corresponding period in 2018. These increases were primarily due to higher pre-tax earnings, partially offset by an increase in the flowback of excess deferred income taxes as a result of both the MRA Settlement Agreement and a new tolling arrangement accounted for as a sales-type lease.

~~See Note (B) to the Condensed Financial Statements under "Mississippi Power" herein for additional information.~~

The results of operations discussed above are not necessarily indicative of Mississippi Power's future earnings potential. The level of Mississippi Power's future earnings depends on numerous factors that affect the opportunities, challenges, and risks of Mississippi Power's business of providing electric service. These factors include Mississippi Power's ability to recover its prudently-incurred costs in a timely manner during a time of increasing costs and its ability to prevail against legal challenges associated with the Kemper County energy facility. Future earnings will be driven primarily by continued customer growth and the weak pace of growth in electricity use per customer, especially in residential and commercial markets. Earnings will also depend upon maintaining and growing sales, considering, among other things, the adoption and/or penetration rates of increasingly energy-efficient technologies and increasing volumes of electronic commerce transactions, both of which could contribute to a net reduction in customer usage. Earnings are subject to a variety of other factors. These factors include weather, competition, developing new and maintaining existing energy contracts and associated load requirements with other utilities and other wholesale customers, energy conservation practiced by customers, the use of alternative energy sources by customers, the price of electricity, the price elasticity of demand, and the rate of

economic growth or decline in Mississippi Power's service territory. Demand for electricity is primarily driven by the pace of economic growth that may be affected by changes in regional and global economic conditions, which may impact future earnings. Mississippi Power is scheduled to file a base rate case by the end of 2019.

~~For additional information relating to these issues, see RISK FACTORS in Item 1A and MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL of Mississippi Power in Item 7 of the Form 10-K.~~

New or revised environmental laws and regulations could affect many areas of Mississippi Power's operations. The impact of any such changes cannot be determined at this time. Environmental compliance costs could affect earnings if such costs cannot continue to be recovered in rates on a timely basis or through long-term wholesale agreements. Further, increased costs that are recovered through regulated rates could contribute to reduced demand for electricity, which could negatively affect results of operations, cash flows, and/or financial condition. Additionally, many commercial and industrial customers may also be affected by existing and future environmental requirements, which for some may have the potential to ultimately affect their demand for electricity. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters" of Mississippi Power in Item 7 and Note 3 to the financial statements under "Environmental Matters" in Item 8 of the Form 10-K for additional information.

On September 13, 2019, the D.C. Circuit Court of Appeals dismissed most challenges brought against the 2016 Cross-State Air Pollution Rule update (2016 CSAPR Update), including the application of the EPA's new emissions allowance budget methodology to the State of Mississippi, which had been challenged by Mississippi Power. However, the court agreed that the 2016 CSAPR Update was unlawful because it allows upwind states to continue their significant contributions to downwind air quality problems beyond statutory deadlines. Accordingly, the court remanded the 2016 CSAPR Update to the EPA. The 2016 CSAPR Update allowance budgets remain in place while the EPA considers how to address the court's remand. The ultimate outcome of this matter cannot be determined at this time.

On October 22, 2019, the EPA and the U.S. Army Corps of Engineers jointly published a final rule that repealed the 2015 Waters of the United States (WOTUS) rule. This final rule will be effective December 23, 2019 and will bring all states back under the pre-2015 regulations until a new WOTUS rule is finalized. A revised definition of WOTUS is anticipated to be finalized by the end of 2019. The impact of the WOTUS rule will depend on the content of the final~~rule redefining WOTUS and the outcome of any associated legal challenges and cannot be determined at this time.~~

In the second quarter 2019, Mississippi Power recorded an increase of approximately $58 million to its AROs for higher expected compliance costs related to the CCR Rule (and the related State of Alabama rule, as applicable). Approximately $49 million of the revised cost estimates are associated with an ash pond at Plant Greene County, which is jointly owned with Alabama Power. The additional estimated costs to close this ash pond under the planned closure-in-place methodology primarily relate to cost inputs from contractor bids, internal drainage and dewatering system designs, and an increase in the estimated ash volume.

As further analysis is performed and additional details are developed with respect to ash pond closures, Mississippi Power expects to periodically update its ARO cost estimates. Additionally, the closure designs and plans in the State of Alabama are subject to approval by environmental regulatory agencies. Absent continued recovery of ARO costs through regulated rates, Mississippi Power's results of operations, cash flows, and financial condition could be materially impacted. The ultimate outcome of this matter cannot be determined at this time. See Note 6 to the financial statements in Item 8 of the Form 10-K and Note (A) to the Condensed Financial Statements under "Asset Retirement Obligations" herein for additional information.

On July 8, 2019, the EPA published the final Affordable Clean Energy rule (ACE Rule) to repeal and replace the CPP. On September 17, 2019, the D.C. Circuit Court of Appeals dismissed litigation related to the CPP as moot. The ACE Rule requires states to develop unit-specific CO₂ emission rate standards for existing coal-fired units based on heat-rate efficiency improvements. Combustion turbines, including natural gas combined cycles, are not included as affected sources in the ACE Rule. Mississippi Power has ownership interests in two coal-fired units (approximately 500 MWs) to which the ACE Rule is applicable. The ACE Rule is being challenged in the D.C. Circuit Court of Appeals. The ultimate impact of the ACE Rule, including the repeal and replacement of the CPP, to Mississippi Power will depend on state implementation plan requirements and the outcome of associated legal challenges and cannot be determined at this time.

Mississippi Power's rates and charges for service to retail customers are subject to the regulatory oversight of the Mississippi PSC. Mississippi Power's rates are a combination of base rates under PEP and several separate cost recovery clauses for specific categories of costs. These separate cost recovery clauses address such items as fuel and purchased power, energy efficiency programs, ad valorem taxes, property damage, and the costs of compliance with environmental laws and regulations. Costs not addressed through one of the specific cost recovery clauses are

~~expected to be recovered through Mississippi Power's base rates. Mississippi Power is scheduled to file a base rate case by the end of 2019.~~

~~See Note 2 to the financial statements under "Mississippi Power" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Mississippi Power" herein for additional information.~~

On October 24, 2019, the Mississippi PSC approved Mississippi Power's July 9, 2019 request for a Certificate of Public Convenience and Necessity to complete certain environmental compliance projects, primarily associated with the Plant Daniel coal units co-owned 50% with Gulf Power. The total estimated cost is approximately $125 million, with Mississippi Power's share of approximately $66 million being proposed for recovery through its ECO Plan. Approximately $17 million of Mississippi Power's share is associated with ash pond closure and is reflected in Mississippi Power's ARO liabilities. See Note (A) to the Condensed Financial Statements under "Asset Retirement Obligations" herein for additional information on AROs and Note (C) to the Condensed Financial Statements under "Other Matters – Mississippi Power" herein for additional information on Gulf Power's ownership in Plant Daniel.

At September 30, 2019 and December 31, 2018, approximately $18 million and $8 million, respectively, of over-recovered fuel costs was included in over recovered regulatory clause liabilities on Mississippi Power's condensed balance sheet.

Mississippi Power's operating revenues are adjusted for differences in actual recoverable fuel cost and amounts billed in accordance with the currently approved cost recovery rate. Accordingly, changes in the billing factor should have no significant effect on Mississippi Power's revenues or net income, but will affect cash flow.

During the third quarter and year-to-date 2019, Mississippi Power recorded pre-tax charges to income of $4 million ($3 million after tax) and $10 million ($7 million after tax), respectively, primarily resulting from the abandonment and related closure activities and ongoing period costs, net of sales proceeds, for the mine and gasifier-related assets at the Kemper County energy facility. Additional closure costs for the mine and gasifier-related assets, currently estimated at up to $10 million pre-tax (excluding dismantlement costs, net of salvage), may be incurred through the first half of 2020. In addition, period costs, including, but not limited to, costs for compliance and safety, ARO accretion, and property taxes for the mine and gasifier-related assets, are estimated at $3 million for the remainder of 2019 and $2 million to $7 million annually in 2020 through 2023.

~~In addition, Mississippi Power constructed the CO~~₂ ~~pipeline for the planned transport of captured CO~~₂ ~~for use in enhanced oil recovery and is currently evaluating its options regarding the final disposition of the CO~~₂ ~~pipeline, including removal of the pipeline. This evaluation is expected to be complete by year-end 2019. If Mississippi Power ultimately decides to remove the CO~~₂ ~~pipeline, the cost of removal~~ ~~would have a material impact on Mississippi Power's financial statements.~~

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

~~See Note 2 to the financial statements under "Mississippi Power – Kemper County Energy Facility" in Item 8 of the Form 10-K for additional information.~~

On March 27, 2020, the Mississippi PSC's motion to dismiss was granted. Also on March 27, 2020, the plaintiffs filed a motion seeking to name the new members of the Mississippi PSC, the Mississippi Development Authority, and Southern Company as additional defendants and add a cause of action against all defendants under a cause of action based on a dormant commerce clause theory under the U.S. Constitution. On April 9, 2020 and April 10, 2020, Mississippi Power ~~believes these legal challenges have no merit; however, an~~and the Mississippi PSC, respectively, filed responses opposing the motion for leave to file a second amended complaint. Mississippi Power's motion to dismiss the first amended complaint filed in 2019 remains pending before the court. An adverse outcome in ~~either of these proceedings~~this proceeding could have a material impact on Mississippi Power's ~~results~~financial statements.

As of September 30, 2019, Mississippi Power's current liabilities exceeded current assets by approximately $73 million primarily as a result of $300 million of long-term debt that is due within one year.

~~All of these~~


(a)	Does not include Southern Power Company's $120 million and $60 million continuing letter of credit facilities for standby letters of credit expiring in 2021 and 2023, respectively, of which $25 million and $60 million, respectively, was unused at March 31, 2020. Southern Power's subsidiaries are not parties to its bank credit arrangements or letter of credit facilities.

(b)

Southern Company Gas, as the parent entity, guarantees the obligations of Southern Company Gas Capital, which is the borrower of $1.25 billion of this arrangement. Southern Company Gas' committed credit arrangement also includes $500 million for which Nicor Gas is the borrower and which is restricted for working capital needs of Nicor Gas. Pursuant to this multi-year credit arrangement, the allocations between Southern Company Gas Capital and Nicor Gas may be adjusted.

As reflected in the table above, in March 2020, Mississippi Power entered into a $125 million revolving credit facility that matures in March 2023.

Subject to applicable market conditions, Southern Company and its subsidiaries expect to renew or replace their bank credit arrangements as needed, prior to expiration. In connection therewith, Southern Company and its subsidiaries may extend the maturity dates and/or increase or decrease the lending commitments thereunder.

These bank credit arrangements, as well as the term loan arrangements of the Registrants and SEGCO, contain covenants that limit debt levels and ~~typically~~ contain cross-acceleration or, in the case of Southern Power, cross-default provisions to other indebtedness (including guarantee obligations) that are restricted only to the indebtedness of ~~Mississippi Power.~~the individual company. Such cross-default provisions to other indebtedness would trigger an event of default if Southern Power defaulted on indebtedness or guarantee obligations over a specified threshold. Such cross-acceleration provisions to other indebtedness would trigger an event of default if ~~Mississippi Power~~the applicable borrower defaulted on

~~119~~

~~Table of Contents~~

~~MISSISSIPPI POWER COMPANY~~

~~MANAGEMENT'S DISCUSSION AND ANALYSIS OF~~

~~FINANCIAL CONDITION AND RESULTS OF OPERATIONS~~

indebtedness, the payment of which was then accelerated. At ~~September 30, 2019, Mississippi Power was~~March 31, 2020, the Registrants, Nicor Gas, and SEGCO were in compliance with all such covenants. None of the bank credit arrangements contain material adverse change clauses at the time of ~~borrowing.~~borrowings.

~~Subject~~A portion of the unused credit with banks is allocated to ~~applicable market conditions, Mississippi Power expects~~provide liquidity support to ~~renew or replace its credit arrangements as needed, prior to expiration. In connection therewith, Mississippi Power may extend~~ the ~~maturity dates and/or increase or decrease~~revenue bonds of the ~~lending commitments thereunder.~~

Mississippi Power may also meet short-term cash needs through a Southern Company subsidiary organized to issue and sell commercial paper at the request and for the benefit of Mississippi Power and the other traditional electric operating ~~companies. Proceeds from such issuances for~~companies and the ~~benefit~~commercial paper programs of ~~Mississippi Power are loaned directly to Mississippi Power.~~the Registrants, Nicor Gas, and SEGCO. The ~~obligations~~amount of ~~each~~variable rate revenue bonds of the traditional electric operating ~~company~~companies outstanding requiring liquidity support at March 31, 2020 was approximately $1.4 billion (comprised of approximately $854 million at Alabama Power, $550 million at Georgia Power, and $40 million at Mississippi Power). Subsequent to March 31, 2020, Mississippi Power purchased and held or redeemed all $40 million of its variable rate revenue bonds. In addition, at March 31, 2020, Georgia Power had approximately $188 million of fixed rate revenue bonds outstanding that are required to be remarketed within the next 12 months.

Earnings per Share

For Southern Company, the only differences in computing basic and diluted earnings per share are attributable to awards outstanding under ~~these arrangements are several~~stock-based compensation plans and, ~~there~~as a result of stock price volatility in the first quarter 2020, the equity units issued in August 2019. Earnings per share dilution resulting from stock-based compensation

Table of ContentsIndex to Financial Statements

NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

plans and the equity units issuance is ~~no cross-affiliate credit support. Short-term borrowings are~~determined using the treasury stock method. See Note 8 to the financial statements under "Equity Units" in Item 8 of the Form 10-K for information on the August 2019 equity units issuance and Note 12 to the financial statements in Item 8 of the Form 10-K for information on stock-based compensation plans. Shares used to compute diluted earnings per share were as follows:



	Three Months Ended March 31, 2020	Three Months Ended March 31, 2019
	(in millions)
As reported shares	1,057	1,038
Effect of stock-based compensation	7	7
Effect of equity units	3	—
Diluted shares	1,067	1,045

An immaterial number of stock-based compensation awards was not included in ~~notes payable~~the diluted earnings per share calculation because the awards were anti-dilutive for the three months ended March 31, 2020. There were 0 such amounts for the three months ended March 31, 2019.

(G) INCOME TAXES

See Note 10 to the financial statements in Item 8 of the Form 10-K for additional tax information.

Current and Deferred Income Taxes

Tax Credit and Net Operating Loss Carryforwards

The utilization of each Registrants' estimated tax credit and net operating loss carryforwards and related valuation allowances could be impacted by numerous factors, including the acquisition of additional renewable projects, the purchase of rights to additional PTCs of Plant Vogtle Units 3 and 4 pursuant to certain joint ownership agreements, potential impacts of the COVID-19 pandemic, and changes in taxable income projections. See Note (B) and Note 2 to the financial statements in Item 8 of the Form 10-K under "Georgia Power – Nuclear Construction" for additional information on Plant Vogtle Units 3 and 4.

Effective Tax Rate

Details of significant changes in the ~~balance sheets.~~effective tax rate for the applicable Registrants are provided herein.

~~Short-term debt, including~~Southern Company

Southern Company's effective tax rate is typically lower than the ~~average amount~~statutory rate due to employee stock plans' dividend deduction, non-taxable AFUDC equity at the traditional electric operating companies, flowback of excess deferred income taxes at the regulated utilities, and ~~maximum amount outstanding,~~federal income tax benefits from ITCs and PTCs primarily at Southern Power.

Southern Company's effective tax rate was ~~immaterial at September 30, 2019 and during~~14.7% for the ~~three-month~~three months ended March 31, 2020 compared to 39.8% for the corresponding period ~~ended September 30,~~in 2019.

~~Mississippi Power believes~~ The effective tax rate decrease was primarily due to the ~~need for working capital can be adequately met by utilizing lines~~tax impact from the sale of ~~credit, short-term bank notes, the commercial paper program, operating cash flows, and other cash.~~

~~Credit Rating Risk~~

~~See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Credit Rating Risk" of Mississippi~~Gulf Power in 2019. See Note 15 to the financial statements under "Southern Company" in Item 78 of the Form 10-K for additional information.

Georgia Power

Georgia Power's effective tax rate was 4.6% for the three months ended March 31, 2020 compared to 20.8% for the corresponding period in 2019. The effective tax rate decrease was primarily due to an increase in the flowback of excess deferred income taxes in 2020 as authorized in the 2019 ARP. See Note 2 to the financial statements under "Georgia Power" in Item 8 of the Form 10-K for additional information.

Table of ContentsIndex to Financial Statements

NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

Southern Power

Southern Power's effective tax rate was 13.5% for the three months ended March 31, 2020 compared to a benefit rate of (49.8)% for the corresponding period in 2019. The effective tax rate increase was primarily due to the tax impact from the sale of Plant Mankato in 2020. See Note (K) under "Southern Power" for additional information.

(H) RETIREMENT BENEFITS

The Southern Company system has a qualified defined benefit, trusteed, pension plan covering substantially all employees, with the exception of employees at PowerSecure. The qualified pension plan is funded in accordance with requirements of the Employee Retirement Income Security Act of 1974, as amended (ERISA). NaN mandatory contributions to the qualified pension plan are anticipated for the year ending December 31, 2020. The Southern Company system also provides certain non-qualified defined benefits for a select group of management and highly compensated employees, which are funded on a cash basis. In addition, the Southern Company system provides certain medical care and life insurance benefits for retired employees through other postretirement benefit plans. The traditional electric operating companies fund other postretirement trusts to the extent required by their respective regulatory commissions. Southern Company Gas has a separate unfunded supplemental retirement health care plan that provides medical care and life insurance benefits to employees of discontinued businesses.

See Note 11 to the financial statements in Item 8 of the Form 10-K for additional information.

Effective January 1, 2020, Southern Company adopted a change in method of calculating the market-related value of the liability-hedging securities included in its pension plan assets. The market-related value is used to determine the expected return on plan assets component of net periodic pension cost. Southern Company previously used the calculated value approach for all plan assets, which smoothed asset returns and deferred gains and losses by amortizing them into the calculation of the market-related value over five years. Southern Company changed to the fair value approach for liability-hedging securities, which includes measuring the market-related value of that portion of the plan assets at fair value for purposes of determining the expected return on plan assets. The remaining asset classes of plan assets will continue to use the calculated value approach in determining the market-related value. Southern Company considers the fair value approach to be preferable because it results in a current reflection of changes in the value of plan assets in the measurement of net periodic pension cost. Southern Company evaluated the effect of this change in accounting method and deemed it immaterial to the historical and current financial statements of all Registrants and therefore did not account for the change retrospectively. The change in accounting principle was recorded through earnings as a prior period adjustment for the amounts related to the unregulated businesses of Southern Company and Southern Power. Amounts related to the traditional electric operating companies and the natural gas distribution utilities have been reflected as adjustments to regulatory assets as appropriate, consistent with the expected regulatory treatment.

Table of ContentsIndex to Financial Statements

NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

On each Registrant's condensed statements of income, the service cost component of net periodic benefit costs is included in other operations and maintenance expenses and all other components of net periodic benefit costs are included in other income (expense), net. Components of the net periodic benefit costs for the three months ended March 31, 2020 and 2019 are presented in the following tables.



Three Months Ended March 31, 2020	Southern Company			Alabama Power			Georgia Power			Mississippi Power			Southern Power			Southern Company Gas
	(in millions)
Pension Plans
Service cost	$	94		$	22		$	24		$	4		$	2		$	8
Interest cost	108			25			33			5			1			8
Expected return on plan assets	(275		)	(66		)	(87		)	(13		)	(3		)	(19		)
Amortization:
Prior service costs	1			—			—			—			—			(1		)
Regulatory asset	—			—			—			—			—			4
Net (gain)/loss	67			18			22			3			1			2
Net periodic pension cost (income)	$	(5	)	$	(1	)	$	(8	)	$	(1	)	$	1		$	2
Postretirement Benefits
Service cost	$	5		$	2		$	1		$	—		$	—		$	—
Interest cost	13			3			5			—			—			2
Expected return on plan assets	(18		)	(7		)	(7		)	—			—			(2		)
Amortization:
Regulatory asset	—			—			—			—			—			2
Net (gain)/loss	1			—			1			—			—			(1		)
Net periodic postretirement benefit cost	$	1		$	(2	)	$	—		$	—		$	—		$	1

Table of ContentsIndex to Financial Statements

NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)



Three Months Ended March 31, 2019	Southern Company			Alabama Power			Georgia Power			Mississippi Power			Southern Power			Southern Company Gas
	(in millions)
Pension Plans
Service cost	$	73		$	17		$	19		$	3		$	2		$	6
Interest cost	123			28			39			6			1			9
Expected return on plan assets	(221		)	(51		)	(73		)	(10		)	(2		)	(15		)
Amortization:
Prior service costs	—			—			—			—			—			(1		)
Regulatory asset	—			—			—			—			—			3
Net (gain)/loss	30			9			11			1			—			1
Net periodic pension cost (income)	$	5		$	3		$	(4	)	$	—		$	1		$	3
Postretirement Benefits
Service cost	$	5		$	1		$	1		$	—		$	—		$	1
Interest cost	17			4			7			1			—			2
Expected return on plan assets	(16		)	(6		)	(6		)	—			—			(2		)
Amortization:
Prior service costs	1			1			—			—			—			—
Regulatory asset	—			—			—			—			—			2
Net (gain)/loss	(1		)	—			—			—			—			(1		)
Net periodic postretirement benefit cost	$	6		$	—		$	2		$	1		$	—		$	2

Table of ContentsIndex to Financial Statements

NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

(I) FAIR VALUE MEASUREMENTS

As of March 31, 2020, assets and liabilities measured at fair value on a recurring basis during the period, together with their associated level of the fair value hierarchy, were as follows:



	Fair Value Measurements Using:
As of March 31, 2020:	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Net Asset Value as a Practical Expedient (NAV)		Total
	(in millions)
Southern Company
Assets:
Energy-related derivatives^(a)	$	328	$	164	$	87	$	—	$	579
Interest rate derivatives	—		22		—		—		22
Investments in trusts:^(b)(c)
Domestic equity	578		108		—		—		686
Foreign equity	52		171		—		—		223
U.S. Treasury and government agency securities	—		289		—		—		289
Municipal bonds	—		103		—		—		103
Pooled funds – fixed income	—		16		—		—		16
Corporate bonds	23		297		—		—		320
Mortgage and asset backed securities	—		85		—		—		85
Private equity	—		—		—		60		60
Other	24		5		—		—		29
Cash equivalents	1,686		11		—		—		1,697
Other investments	9		29		—		—		38
Total	$	2,700	$	1,300	$	87	$	60	$	4,147
Liabilities:
Energy-related derivatives^(a)	$	426	$	212	$	11	$	—	$	649
Interest rate derivatives	—		22		—		—		22
Foreign currency derivatives	—		90		—		—		90
Contingent consideration	—		—		19		—		19
Total	$	426	$	324	$	30	$	—	$	780

Table of ContentsIndex to Financial Statements

NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)



	Fair Value Measurements Using:
As of March 31, 2020:	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Net Asset Value as a Practical Expedient (NAV)		Total
	(in millions)
Alabama Power
Assets:
Energy-related derivatives	$	—	$	5	$	—	$	—	$	5
Nuclear decommissioning trusts:^(b)
Domestic equity	368		99		—		—		467
Foreign equity	52		50		—		—		102
U.S. Treasury and government agency securities	—		22		—		—		22
Municipal bonds	—		1		—		—		1
Corporate bonds	23		141		—		—		164
Mortgage and asset backed securities	—		30		—		—		30
Private equity	—		—		—		60		60
Other	7		—		—		—		7
Cash equivalents	694		11		—		—		705
Other investments	—		29		—		—		29
Total	$	1,144	$	388	$	—	$	60	$	1,592
Liabilities:
Energy-related derivatives	$	—	$	27	$	—	$	—	$	27

Georgia Power
Assets:
Energy-related derivatives	$	—	$	6	$	—	$	—	$	6
Nuclear decommissioning trusts:^(b)(c)
Domestic equity	210		1		—		—		211
Foreign equity	—		119		—		—		119
U.S. Treasury and government agency securities	—		267		—		—		267
Municipal bonds	—		102		—		—		102
Corporate bonds	—		156		—		—		156
Mortgage and asset backed securities	—		56		—		—		56
Other	16		5		—		—		21
Cash equivalents	212		—		—		—		212
Total	$	438	$	712	$	—	$	—	$	1,150
Liabilities:
Energy-related derivatives	$	—	$	61	$	—	$	—	$	61

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(UNAUDITED)



	Fair Value Measurements Using:
As of March 31, 2020:	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Net Asset Value as a Practical Expedient (NAV)		Total
	(in millions)
Mississippi Power
Assets:
Energy-related derivatives	$	—	$	3	$	—	$	—	$	3
Cash equivalents	79		—		—		—		79
Total	$	79	$	3	$	—	$	—	$	82
Liabilities:
Energy-related derivatives	$	—	$	33	$	—	$	—	$	33

Southern Power
Assets:
Energy-related derivatives	$	—	$	2	$	—	$	—	$	2
Cash equivalents	166		—		—		—		166
Total	$	166	$	2	$	—	$	—	$	168
Liabilities:
Energy-related derivatives	$	—	$	3	$	—	$	—	$	3
Foreign currency derivatives	—		90		—		—		90
Contingent consideration	—		—		19		—		19
Total	$	—	$	93	$	19	$	—	$	112

Southern Company Gas
Assets:
Energy-related derivatives^(a)	$	328	$	148	$	87	$	—	$	563
Non-qualified deferred compensation trusts:
Domestic equity	—		9		—		—		9
Foreign equity	—		3		—		—		3
Pooled funds – fixed income	—		16		—		—		16
Cash equivalents and restricted cash	270		—		—		—		270
Total	$	598	$	176	$	87	$	—	$	861
Liabilities:
Energy-related derivatives^(a)	$	426	$	88	$	11	$	—	$	525
Interest rate derivatives	—		21		—		—		21
Total	$	426	$	109	$	11	$	—	$	546


(a)	Energy-related derivatives exclude cash collateral of $128 million and $16 million associated with premiums and certain weather derivatives accounted for based on intrinsic value rather than fair value.


(b)	Excludes receivables related to investment income, pending investment sales, payables related to pending investment purchases, and currencies. See Note 6 to the financial statements in Item 8 of the Form 10-K for additional information.

(c)

Includes investment securities pledged to creditors and collateral received and excludes payables related to the securities lending program. As of March 31, 2020, approximately $31 million of the fair market value of Georgia Power's nuclear decommissioning trust funds' securities were on loan to creditors under the funds' managers' securities lending program. See Note 6 to the financial statements in Item 8 of the Form 10-K for additional information.

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Southern Company, Alabama Power, and Georgia Power continue to elect the option to fair value investment securities held in the nuclear decommissioning trust funds. The fair value of the funds, including reinvested interest and dividends and excluding the funds' expenses, increased (decreased) by the amounts shown in the table below for the three months ended March 31, 2020 and 2019. The changes were recorded as a change to the regulatory assets and liabilities related to AROs for Georgia Power and Alabama Power, respectively.



Fair value increases (decreases)	Three Months Ended March 31, 2020			Three Months Ended March 31, 2019
	(in millions)
Southern Company	$	(247	)	$	152
Alabama Power	(167		)	87
Georgia Power	(80		)	65

Valuation Methodologies

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

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

The NRC requires licensees of commissioned nuclear power reactors to establish a plan for providing reasonable assurance of funds for future decommissioning. See Note 6 to the financial statements under "Nuclear Decommissioning" in Item 8 of the Form 10-K for additional information.

Southern Power has contingent payment obligations related to certain acquisitions whereby Southern Power is primarily obligated to make generation-based payments to the seller, which commenced at the commercial operation of the respective facility and continue through 2026. The obligation is categorized as Level 3 under Fair Value Measurements as the fair value is determined using significant unobservable inputs for the forecasted facility generation in MW-hours, as well as other inputs such as a fixed dollar amount per MW-hour, and a discount rate. The fair value of contingent consideration reflects the net present value of expected payments and any periodic change arising from forecasted generation is expected to be immaterial.

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"Other investments" include investments traded in the open market that have maturities greater than 90 days, which are categorized as Level 2 under Fair Value Measurements and are comprised of corporate bonds, bank certificates of deposit, treasury bonds, and/or agency bonds.

As of March 31, 2020, the fair value measurements of private equity investments held in Alabama Power's nuclear decommissioning trusts that are calculated at net asset value per share (or its equivalent) as a practical expedient totaled $60 million and unfunded commitments related to the private equity investments totaled $73 million. Private equity investments include high-quality private equity funds across several market sectors and funds that invest in real estate assets. Private equity funds do not have redemption rights. Distributions from these funds will be received as the underlying investments in the funds are liquidated.

As of March 31, 2020, other financial instruments for which the carrying amount did not equal fair value were as follows:



	Southern Company		Alabama Power		Georgia Power		Mississippi Power		Southern Power		Southern Company Gas^(*)
	(in millions)
Long-term debt, including securities due within one year:
Carrying amount	$	45,820	$	8,432	$	12,217	$	1,413	$	4,369	$	5,836
Fair value	49,126		9,239		14,020		1,433		4,376		6,416


(*)	The long-term debt of Southern Company Gas is recorded at amortized cost, including the fair value adjustments at the effective date of the 2016 merger with Southern Company. Southern Company Gas amortizes the fair value adjustments over the lives of the respective bonds.

The fair values are determined using Level 2 measurements and are based on quoted market prices for the same or similar issues or on the current rates available to the Registrants.

Commodity Contracts with Level 3 Valuation Inputs

As of March 31, 2020, the fair value of Southern Company Gas' Level 3 physical natural gas forward contracts was $76 million. Since commodity contracts classified as Level 3 typically include a combination of observable and unobservable components, the changes in fair value may include amounts due in part to observable market factors, or changes to assumptions on the unobservable components. The following table includes transfers to Level 3, which represent the fair value of Southern Company Gas' commodity derivative contracts that include a significant unobservable component for the first time during the period.



	Three Months Ended March 31, 2020
	(in millions)
Beginning balance	$	14
Transfers to Level 3	70
Transfers from Level 3	(3		)
Instruments realized or otherwise settled during period	(1		)
Changes in fair value	(4		)
Ending balance	$	76

Changes in fair value of Level 3 instruments represent changes in gains and losses for the periods that are reported on Southern Company Gas' statements of income in natural gas revenues.

The valuation of certain commodity contracts requires the use of certain unobservable inputs. All forward pricing used in the valuation of such contracts is directly based on third-party market data, such as broker quotes and exchange settlements, when that data is available. If third-party market data is not available, then industry standard methodologies are used to develop inputs that maximize the use of relevant observable inputs and minimize the use

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of unobservable inputs. Observable inputs, including some forward prices used for determining fair value, reflect the best available market information. Unobservable inputs are updated using industry standard techniques such as extrapolation, combining observable forward inputs supplemented by historical market and other relevant data. Level 3 physical natural gas forward contracts include unobservable forward price inputs (ranging from $(0.84) to $0.21 per mmBtu). Forward price increases (decreases) as of March 31, 2020 would have resulted in higher (lower) values on a net basis.

(J) DERIVATIVES

Southern Company, the traditional electric operating companies, Southern Power, and Southern Company Gas are exposed to market risks, including commodity price risk, interest rate risk, weather risk, and occasionally foreign currency exchange rate risk. To manage the volatility attributable to these exposures, each company nets its exposures, where possible, to take advantage of natural offsets and enters into various derivative transactions for the remaining exposures pursuant to each company's policies in areas such as counterparty exposure and risk management practices. Southern Company Gas' wholesale gas operations use various contracts in its commercial activities that generally meet the definition of derivatives. For the traditional electric operating companies, Southern Power, and Southern Company Gas' other businesses, each company's policy is that derivatives are to be used primarily for hedging purposes and mandates strict adherence to all applicable risk management policies. Derivative positions are monitored using techniques including, but not limited to, market valuation, value at risk, stress testing, and sensitivity analysis. Derivative instruments are recognized at fair value in the balance sheets as either assets or liabilities and are presented on a net basis. See Note (I) for additional fair value information. In the statements of cash flows, any cash impacts of settled energy-related and interest rate derivatives are recorded as operating activities. Any cash impacts of settled foreign currency derivatives are classified as operating or financing activities to correspond with classification of the hedged interest or principal, respectively. See Note 1 to the financial statements under "Financial Instruments" in Item 8 of the Form 10-K for additional information.

Energy-Related Derivatives

The traditional electric operating companies, Southern Power, and Southern Company Gas enter into energy-related derivatives to hedge exposures to electricity, natural gas, and other fuel price changes. However, due to cost-based rate regulations and other various cost recovery mechanisms, the traditional electric operating companies and the natural gas distribution utilities have limited exposure to market volatility in energy-related commodity prices. Each of the traditional electric operating companies and certain of the natural gas distribution utilities of Southern Company Gas manage fuel-hedging programs, implemented per the guidelines of their respective state PSCs or other applicable state regulatory agencies, through the use of financial derivative contracts, which are expected to continue to mitigate price volatility. The traditional electric operating companies (with respect to wholesale generating capacity) and Southern Power have limited exposure to market volatility in energy-related commodity prices because their long-term sales contracts shift substantially all fuel cost responsibility to the purchaser. However, the traditional electric operating companies and Southern Power may be exposed to market volatility in energy-related commodity prices to the extent any uncontracted capacity is used to sell electricity. Southern Company Gas retains exposure to price changes that can, in a volatile energy market, be material and can adversely affect its results of operations.

Southern Company Gas also enters into weather derivative contracts as economic hedges of operating margins in the event of warmer-than-normal weather. Exchange-traded options are carried at fair value, with changes reflected in operating revenues. Non-exchange-traded options are accounted for using the intrinsic value method. Changes in the intrinsic value for non-exchange-traded contracts are reflected in operating revenues.

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Energy-related derivative contracts are accounted for under one of three methods:

•

Regulatory Hedges — Energy-related derivative contracts designated as regulatory hedges relate primarily to the traditional electric operating companies' and the natural gas distribution utilities' fuel-hedging programs, where gains and losses are initially recorded as regulatory liabilities and assets, respectively, and then are included in fuel expense as the underlying fuel is used in operations and ultimately recovered through the respective fuel cost recovery clauses.


•	Cash Flow Hedges — Gains and losses on energy-related derivatives designated as cash flow hedges (which are mainly used to hedge anticipated purchases and sales) are initially deferred in accumulated OCI before being recognized in the statements of income in the same period and in the same income statement line item as the earnings effect of the hedged transactions.


•	Not Designated — Gains and losses on energy-related derivative contracts that are not designated or fail to qualify as hedges are recognized in the statements of income as incurred.

Some energy-related derivative contracts require physical delivery as opposed to financial settlement, and this type of derivative is both common and prevalent within the electric and natural gas industries. When an energy-related derivative contract is settled physically, any cumulative unrealized gain or loss is reversed and the contract price is recognized in the respective line item representing the actual price of the underlying goods being delivered.

At ~~September 30, 2019,~~March 31, 2020, the net volume of energy-related derivative contracts for natural gas positions, together with the longest hedge date over which the respective entity is hedging its exposure to the variability in future cash flows for forecasted transactions and the longest non-hedge date for derivatives not designated as hedges, were as follows:



	Net Purchased mmBtu	Longest Hedge Date	Longest Non-Hedge Date
	(in millions)
Southern Company^(*)	945	2023	2031
Alabama Power	88	2023	—
Georgia Power	168	2023	—
Mississippi Power	100	2023	—
Southern Power	4	2020	2020
Southern Company Gas^(*)	585	2022	2031

(*)

Southern Company Gas' derivative instruments include both long and short natural gas positions. A long position is a contract to purchase natural gas and a short position is a contract to sell natural gas. Southern Company Gas' volume represents the net of long natural gas positions of 4.6 billion mmBtu and short natural gas positions of 4.0 billion mmBtu as of March 31, 2020, which is also included in Southern Company's total volume.

At March 31, 2020, the net volume of Southern Power's energy-related derivative contracts for power to be sold was 1 million MWHs, all of which expire in 2020.

In addition to the volumes discussed above, the traditional electric operating companies and Southern Power enter into physical natural gas supply contracts that provide the option to sell back excess natural gas due to operational constraints. The maximum expected volume of natural gas subject to such a feature is 23 million mmBtu for Southern Company, which includes 6 million mmBtu for Alabama Power, 7 million mmBtu for Georgia Power, 3 million mmBtu for Mississippi Power, ~~did~~and 7 million mmBtu for Southern Power.

For cash flow hedges of energy-related derivatives, the estimated pre-tax gains (losses) expected to be reclassified from accumulated OCI to earnings for the 12-month period ending March 31, 2021 are immaterial for all Registrants.

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Interest Rate Derivatives

Southern Company and certain subsidiaries may enter into interest rate derivatives to hedge exposure to changes in interest rates. The derivatives employed as hedging instruments are structured to minimize ineffectiveness. Derivatives related to existing variable rate securities or forecasted transactions are accounted for as cash flow hedges where the derivatives' fair value gains or losses are recorded in OCI and are reclassified into earnings at the same time and presented on the same income statement line item as the earnings effect of the hedged transactions. Derivatives related to existing fixed rate securities are accounted for as fair value hedges, where the derivatives' fair value gains or losses and hedged items' fair value gains or losses are both recorded directly to earnings on the same income statement line item. Fair value gains or losses on derivatives that are not designated or fail to qualify as hedges are recognized in the statements of income as incurred.

At March 31, 2020, the following interest rate derivatives were outstanding:



	Notional Amount		Interest Rate Received	Weighted Average Interest Rate Paid	Hedge Maturity Date	Fair Value Gain (Loss) at March 31, 2020
	(in millions)					(in millions)
Cash Flow Hedges of Forecasted Debt			��
Southern Company Gas	$	200	3-month LIBOR	1.81%	September 2030	$	(21	)
Cash Flow Hedges of Existing Debt
Mississippi Power	60		1-month LIBOR	0.58%	December 2021	—
Fair Value Hedges of Existing Debt
Southern Company parent	300		2.75%	3-month LIBOR + 0.92%	June 2020	1
Southern Company parent	1,500		2.35%	1-month LIBOR + 0.87%	July 2021	21
Southern Company	$	2,060				$	1

The estimated pre-tax gains (losses) related to interest rate derivatives expected to be reclassified from accumulated OCI to interest expense for the 12-month period ending March 31, 2021 total $(25) million for Southern Company and are immaterial for all other Registrants. Deferred gains and losses related to interest rate derivatives are expected to be amortized into earnings through 2046 for the Southern Company parent entity, 2035 for Alabama Power, 2044 for Georgia Power, 2028 for Mississippi Power, and 2046 for Southern Company Gas.

Foreign Currency Derivatives

Southern Company and certain subsidiaries, including Southern Power, may enter into foreign currency derivatives to hedge exposure to changes in foreign currency exchange rates, such as that arising from the issuance of debt denominated in a currency other than U.S. dollars. Derivatives related to forecasted transactions are accounted for as cash flow hedges where the derivatives' fair value gains or losses are recorded in OCI and are reclassified into earnings at the same time and on the same income statement line as the earnings effect of the hedged transactions, including foreign currency gains or losses arising from changes in the U.S. currency exchange rates. The derivatives employed as hedging instruments are structured to minimize ineffectiveness.

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(UNAUDITED)

At March 31, 2020, the following foreign currency derivatives were outstanding:



	Pay Notional		Pay Rate	Receive Notional		Receive Rate	Hedge Maturity Date	Fair Value Gain (Loss) at March 31, 2020
	(in millions)			(in millions)				(in millions)
Cash Flow Hedges of Existing Debt
Southern Power	$	677	2.95%	€	600	1.00%	June 2022	$	(39	)
Southern Power	564		3.78%	500		1.85%	June 2026	(51		)
Total	$	1,241		€	1,100			$	(90	)

The estimated pre-tax gains (losses) related to Southern Power's foreign currency derivatives expected to be reclassified from accumulated OCI to earnings for the 12-month period ending March 31, 2021 are $(24) million.

Derivative Financial Statement Presentation and Amounts

Southern Company, the traditional electric operating companies, Southern Power, and Southern Company Gas enter into derivative contracts that may contain certain provisions that permit intra-contract netting of derivative receivables and payables for routine billing and offsets related to events of default and settlements. Southern Company and certain subsidiaries also utilize master netting agreements to mitigate exposure to counterparty credit risk. These agreements may contain provisions that permit netting across product lines and against cash collateral. The fair value amounts of derivative assets and liabilities on the balance sheet are presented net to the extent that there are netting arrangements or similar agreements with the counterparties.

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The fair value of energy-related derivatives, interest rate derivatives, and foreign currency derivatives was reflected in the balance sheets as follows:



	As of March 31, 2020						As of December 31, 2019
Derivative Category and Balance Sheet Location	Assets			Liabilities			Assets			Liabilities
	(in millions)						(in millions)
Southern Company
Derivatives designated as hedging instruments for regulatory purposes
Energy-related derivatives:
Other current assets/Other current liabilities	$	7		$	100		$	3		$	70
Other deferred charges and assets/Other deferred credits and liabilities	8			40			6			44
Total derivatives designated as hedging instruments for regulatory purposes	$	15		$	140		$	9		$	114
Derivatives designated as hedging instruments in cash flow and fair value hedges
Energy-related derivatives:
Other current assets/Other current liabilities	$	3		$	6		$	1		$	6
Interest rate derivatives:
Other current assets/Other current liabilities	12			21			2			23
Other deferred charges and assets/Other deferred credits and liabilities	10			—			—			1
Foreign currency derivatives:
Other current assets/Other current liabilities	—			24			—			24
Other deferred charges and assets/Other deferred credits and liabilities	—			66			16			—
Total derivatives designated as hedging instruments in cash flow and fair value hedges	$	25		$	117		$	19		$	54
Derivatives not designated as hedging instruments
Energy-related derivatives:
Other current assets/Other current liabilities	$	300		$	297		$	461		$	358
Other deferred charges and assets/Other deferred credits and liabilities	261			206			207			225
Total derivatives not designated as hedging instruments	$	561		$	503		$	668		$	583
Gross amounts recognized	$	601		$	760		$	696		$	751
Gross amounts offset^(a)	(383		)	(511		)	(463		)	(562		)
Net amounts recognized in the Balance Sheets^(b)	$	218		$	249		$	233		$	189

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(UNAUDITED)



	As of March 31, 2020						As of December 31, 2019
Derivative Category and Balance Sheet Location	Assets			Liabilities			Assets			Liabilities
	(in millions)						(in millions)
Alabama Power
Derivatives designated as hedging instruments for regulatory purposes
Energy-related derivatives:
Other current assets/Other current liabilities	$	3		$	18		$	2		$	14
Other deferred charges and assets/Other deferred credits and liabilities	2			9			2			10
Total derivatives designated as hedging instruments for regulatory purposes	$	5		$	27		$	4		$	24
Gross amounts recognized	$	5		$	27		$	4		$	24
Gross amounts offset	(4		)	(4		)	(2		)	(2		)
Net amounts recognized in the Balance Sheets	$	1		$	23		$	2		$	22

Georgia Power
Derivatives designated as hedging instruments for regulatory purposes
Energy-related derivatives:
Other current assets/Other current liabilities	$	3		$	42		$	1		$	32
Other deferred charges and assets/Other deferred credits and liabilities	3			19			3			21
Total derivatives designated as hedging instruments for regulatory purposes	$	6		$	61		$	4		$	53
Derivatives designated as hedging instruments in cash flow and fair value hedges
Interest rate derivatives:
Other current assets/Other current liabilities	$	—		$	—		$	—		$	17
Total derivatives designated as hedging instruments in cash flow and fair value hedges	$	—		$	—		$	—		$	17
Gross amounts recognized	$	6		$	61		$	4		$	70
Gross amounts offset	(6		)	(6		)	(3		)	(3		)
Net amounts recognized in the Balance Sheets	$	—		$	55		$	1		$	67

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(UNAUDITED)



	As of March 31, 2020						As of December 31, 2019
Derivative Category and Balance Sheet Location	Assets			Liabilities			Assets			Liabilities
	(in millions)						(in millions)
Mississippi Power
Derivatives designated as hedging instruments for regulatory purposes
Energy-related derivatives:
Other current assets/Other current liabilities	$	1		$	21		$	—		$	15
Other deferred charges and assets/Other deferred credits and liabilities	2			12			1			12
Total derivatives designated as hedging instruments for regulatory purposes	$	3		$	33		$	1		$	27
Gross amounts recognized	$	3		$	33		$	1		$	27
Gross amounts offset	(3		)	(3		)	(1		)	(1		)
Net amounts recognized in the Balance Sheets	$	—		$	30		$	—		$	26

Southern Power
Derivatives designated as hedging instruments in cash flow and fair value hedges
Energy-related derivatives:
Other current assets/Other current liabilities	$	2		$	2		$	1		$	2
Foreign currency derivatives:
Other current assets/Other current liabilities	—			24			—			24
Other deferred charges and assets/Other deferred credits and liabilities	—			66			16			—
Total derivatives designated as hedging instruments in cash flow and fair value hedges	$	2		$	92		$	17		$	26
Derivatives not designated as hedging instruments
Energy-related derivatives:
Other current assets/Other current liabilities	$	—		$	1		$	2		$	1
Total derivatives not designated as hedging instruments	$	—		$	1		$	2		$	1
Gross amounts recognized	$	2		$	93		$	19		$	27
Gross amounts offset	—			—			—			—
Net amounts recognized in the Balance Sheets	$	2		$	93		$	19		$	27

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(UNAUDITED)



	As of March 31, 2020						As of December 31, 2019
Derivative Category and Balance Sheet Location	Assets			Liabilities			Assets			Liabilities
	(in millions)						(in millions)
Southern Company Gas
Derivatives designated as hedging instruments for regulatory purposes
Energy-related derivatives:
Assets from risk management activities/Liabilities from risk management activities-current	$	—		$	19		$	—		$	9
Other deferred charges and assets/Other deferred credits and liabilities	1			—			—			1
Total derivatives designated as hedging instruments for regulatory purposes	$	1		$	19		$	—		$	10
Derivatives designated as hedging instruments in cash flow and fair value hedges
Energy-related derivatives:
Assets from risk management activities/Liabilities from risk management activities-current	$	1		$	4		$	—		$	4
Interest rate derivatives:
Assets from risk management activities/Liabilities from risk management activities-current	—			21			2			—
Total derivatives designated as hedging instruments in cash flow and fair value hedges	$	1		$	25		$	2		$	4
Derivatives not designated as hedging instruments
Energy-related derivatives:
Assets from risk management activities/Liabilities from risk management activities-current	$	300		$	296		$	459		$	357
Other deferred charges and assets/Other deferred credits and liabilities	261			206			207			225
Total derivatives not designated as hedging instruments	$	561		$	502		$	666		$	582
Gross amounts of recognized	$	563		$	546		$	668		$	596
Gross amounts offset^(a)	(370		)	(498		)	(456		)	(555		)
Net amounts recognized in the Balance Sheets^(b)	$	193		$	48		$	212		$	41


(a)	Gross amounts offset include cash collateral held on deposit in broker margin accounts of $128 million and $99 million as of March 31, 2020 and December 31, 2019, respectively.


(b)	Net amounts of derivative instruments outstanding exclude premium and intrinsic value associated with weather derivatives of $16 million and $4 million as of March 31, 2020 and December 31, 2019, respectively.

Energy-related derivatives not designated as hedging instruments were immaterial for the traditional electric operating companies at March 31, 2020 and December 31, 2019.

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(UNAUDITED)

At March 31, 2020 and December 31, 2019, the pre-tax effects of unrealized derivative gains (losses) arising from energy-related derivative instruments designated as regulatory hedging instruments and deferred were as follows:



Regulatory Hedge Unrealized Gain (Loss) Recognized in the Balance Sheet at March 31, 2020
Derivative Category and Balance Sheet Location	Southern Company^(*)			Alabama Power			Georgia Power			Mississippi Power			Southern Company Gas^(*)
	(in millions)
Energy-related derivatives:
Other regulatory assets, current	$	(79	)	$	(17	)	$	(39	)	$	(19	)	$	(4	)
Other regulatory assets, deferred	(33		)	(7		)	(16		)	(10		)	—
Other regulatory liabilities, current	5			1			—			—			4
Total energy-related derivative gains (losses)	$	(107	)	$	(23	)	$	(55	)	$	(29	)	$	—


(*)	Fair value gains and losses recorded in regulatory assets and liabilities include cash collateral held on deposit in broker margin accounts of $19 million at March 31, 2020.



Regulatory Hedge Unrealized Gain (Loss) Recognized in the Balance Sheet at December 31, 2019
Derivative Category and Balance Sheet Location	Southern Company^(*)			Alabama Power			Georgia Power			Mississippi Power			Southern Company Gas^(*)
	(in millions)
Energy-related derivatives:
Other regulatory assets, current	$	(63	)	$	(14	)	$	(31	)	$	(15	)	$	(3	)
Other regulatory assets, deferred	(37		)	(8		)	(18		)	(11		)	—
Other regulatory liabilities, current	6			2			—			—			4
Total energy-related derivative gains (losses)	$	(94	)	$	(20	)	$	(49	)	$	(26	)	$	1


(*)	Fair value gains and losses recorded in regulatory assets and liabilities include cash collateral held on deposit in broker margin accounts of $11 million at December 31, 2019.

For the three months ended March 31, 2020 and 2019, the pre-tax effects of cash flow hedge accounting on accumulated OCI were as follows:



Gain (Loss) Recognized in OCI on Derivative	For the Three Months Ended March 31,
Gain (Loss) Recognized in OCI on Derivative	2020			2019
	(in millions)
Southern Company
Energy-related derivatives	$	(4	)	$	—
Interest rate derivatives	(26		)	—
Foreign currency derivatives	(83		)	(39		)
Total	$	(113	)	$	(39	)
Southern Power
Foreign currency derivatives	$	(83	)	$	(39	)
Southern Company Gas
Energy-related derivatives	$	(4	)	$	—
Interest rate derivatives	(23		)	—
Total	$	(27	)	$	—

Table of ContentsIndex to Financial Statements

NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

For the three months ended March 31, 2020 and 2019, the pre-tax effects of energy-related derivatives and interest rate derivatives designated as cash flow hedging instruments on accumulated OCI were immaterial for the other Registrants.

For the three months ended March 31, 2020 and 2019, the pre-tax effects of cash flow and fair value hedge accounting on income were as follows:



Location and Amount of Gain (Loss) Recognized in Income on Cash Flow and Fair Value Hedging Relationships	For the Three Months Ended March 31,
	For the Three Months Ended March 31,
	2020			2019
	(in millions)
Southern Company
Total cost of natural gas	$	439		$	686
Gain (loss) on energy-related cash flow hedges^(a)	(7		)	1
Total depreciation and amortization	857			751
Gain (loss) on energy-related cash flow hedges^(a)	(1		)	(3		)
Total interest expense, net of amounts capitalized	(456		)	(430		)
Gain (loss) on interest rate cash flow hedges^(a)	(6		)	(5		)
Gain (loss) on foreign currency cash flow hedges^(a)	(6		)	(6		)
Gain (loss) on interest rate fair value hedges^(b)	29			14
Total other income (expense), net	103			78
Gain (loss) on foreign currency cash flow hedges^(a)(c)	(31		)	(24		)
Southern Power
Total depreciation and amortization	$	117		$	119
Gain (loss) on energy-related cash flow hedges^(a)	(1		)	(3		)
Total interest expense, net of amounts capitalized	(39		)	(44		)
Gain (loss) on foreign currency cash flow hedges^(a)	(6		)	(6		)
Total other income (expense), net	2			2
Gain (loss) on foreign currency cash flow hedges^(a)(c)	(31		)	(24		)


(a)	Reclassified from accumulated OCI into earnings.


(b)	For fair value hedges, changes in the fair value of the derivative contracts are generally equal to changes in the fair value of the underlying debt and have no material impact on income.


(c)	The reclassification from accumulated OCI into other income (expense), net completely offsets currency gains and losses arising from changes in the U.S. currency exchange rates used to record the euro-denominated notes.

For the three months ended March 31, 2020 and 2019, the pre-tax effects of cash flow and fair value hedge accounting on income for energy-related derivatives and interest rate derivatives were immaterial for the traditional electric operating companies and Southern Company Gas.

As of March 31, 2020 and December 31, 2019, the following amounts were recorded on the balance sheets related to cumulative basis adjustments for fair value hedges:



	Carrying Amount of the Hedged Item						Cumulative Amount of Fair Value Hedging Adjustment included in Carrying Amount of the Hedged Item
Balance Sheet Location of Hedged Items	As of March 31, 2020			As of December 31, 2019			As of March 31, 2020			As of December 31, 2019
	(in millions)						(in millions)
Southern Company
Securities due within one year	$	(600	)	$	(599	)	$	(1	)	$	—
Long-term debt	(1,519		)	(1,494		)	(22		)	3

Table of ContentsIndex to Financial Statements

NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

For the three months ended March 31, 2020 and 2019, the pre-tax effects of energy-related derivatives not designated as hedging instruments on the statements of income of Southern Company and Southern Company Gas were as follows:



		Gain (Loss)
		Three Months Ended March 31,
Derivatives in Non-Designated Hedging Relationships	Statements of Income Location	2020		2019
		(in millions)
Energy-related derivatives:	Natural gas revenues^(*)	$	70	$	33
	Cost of natural gas	7		8
Total derivatives in non-designated hedging relationships		$	77	$	41


(*)	Excludes immaterial gains (losses) recorded in natural gas revenues associated with weather derivatives for all periods presented.

For the three months ended March 31, 2020 and 2019, the pre-tax effects of energy-related derivatives and interest rate derivatives not designated as hedging instruments were immaterial for all other Registrants.

Contingent Features

Southern Company, the traditional electric operating companies, Southern Power, and Southern Company Gas do not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade.

There are certain ~~contracts~~derivatives that ~~have required or~~ could require collateral, but not accelerated payment, in the event of avarious credit rating ~~change~~changes of certain Southern Company subsidiaries. At March 31, 2020, the Registrants had 0 collateral posted with derivative counterparties to ~~BBB and/or Baa2 or below. These contracts are for physical electricity purchases~~satisfy these arrangements.

For the Registrants with interest rate derivatives at March 31, 2020, the fair value of interest rate derivative liabilities with contingent features and ~~sales, fuel transportation and storage, energy price risk management, and transmission. At September 30, 2019,~~ the maximum potential collateral requirements arising from the credit-risk-related contingent features, at a rating below BBB- and/or Baa3, ~~equaled approximately $269 million.~~

~~Included in these amounts are~~was immaterial. At March 31, 2020, the fair value of energy-related derivative liabilities with contingent features and the maximum potential collateral requirements arising from the credit-risk-related contingent features, at a rating below BBB- and/or Baa3, were immaterial for all Registrants. The maximum potential collateral requirements arising from the credit-risk-related contingent features for the traditional electric operating companies and Southern Power include certain agreements that could require collateral in the event that ~~either Alabama Power~~one or ~~Georgia Power (affiliate companies of Mississippi Power)~~more Southern Company power pool participants has a credit rating change to below investment grade. Following the sale of Gulf Power to NextEra Energy, Gulf Power is continuing to participate in the Southern Company power pool for a defined transition period that, subject to certain potential adjustments, is scheduled to end on January 1, 2024.

Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. ~~Additionally, a credit rating downgrade could impact~~If collateral is required, fair value amounts recognized for the ~~ability of Mississippi~~right to reclaim cash collateral or the obligation to return cash collateral are not offset against fair value amounts recognized for derivatives executed with the same counterparty.

Alabama Power and Southern Power maintain accounts with certain regional transmission organizations to ~~access capital markets and would be likely to impact~~facilitate financial derivative transactions. Based on the ~~cost at which it does so.~~

~~On August 1, 2019, Moody's upgraded Mississippi Power's senior unsecured long-term debt rating to Baa2 from Baa3 and maintained the positive rating outlook.~~

~~As a result~~value of the ~~Tax Reform Legislation, certain financial metrics, such as~~positions in these accounts and the ~~funds from operations to debt percentage, used by the credit rating agencies to assess~~associated margin requirements, Alabama Power and Southern ~~Company and its subsidiaries, including Mississippi~~ Power may be ~~negatively impacted. The settlement agreement approved by~~required to post collateral. At March 31, 2020, cash collateral posted in these accounts was immaterial. Southern Company Gas maintains accounts with brokers or the ~~Mississippi PSC in August 2018 with respect~~clearing houses of certain exchanges to facilitate financial derivative transactions. Based on the 2018 PEP filings and all unresolved PEP filings for prior years is expected to help mitigate these potential adverse impacts by allowing Mississippi Power to retain the excess deferred taxes resulting from the Tax Reform Legislation until the conclusionvalue of the ~~Mississippi Power 2019 Base Rate Case. See Note 2~~positions in these accounts and the associated margin requirements, Southern Company Gas may be required to deposit cash into these accounts. At March 31, 2020, cash collateral held on deposit in broker margin accounts was $128 million.

The Registrants are exposed to losses related to financial instruments in the ~~financial statements under "Mississippi Power" in Item 8~~event of ~~the Form 10-K~~counterparties' nonperformance. The Registrants only enter into agreements and ~~Note (B) to the Condensed Financial Statements under "Mississippi Power" herein for additional information.~~

material transactions with counterparties that have

~~120~~

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~~MISSISSIPPI POWER COMPANY~~

~~MANAGEMENT'S DISCUSSION AND ANALYSIS OF~~NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)

~~FINANCIAL CONDITION AND RESULTS OF OPERATIONS~~(UNAUDITED)

~~Financing Activities~~

~~In March 2019, Mississippi Power reoffered~~investment grade credit ratings by Moody's and S&P or with counterparties who have posted collateral to cover potential credit exposure. The Registrants have also established risk management policies and controls to determine and monitor the ~~public $43 million~~creditworthiness of ~~Mississippi Business Finance Corporation Pollution Control Revenue Refunding Bonds, Series 2002, which previously had been purchased~~counterparties in order to mitigate their exposure to counterparty credit risk. Prior to entering into a physical transaction, Southern Company Gas assigns physical wholesale counterparties an internal credit rating and ~~held by Mississippi Power.~~credit limit based on the counterparties' Moody's, S&P, and Fitch ratings, commercially available credit reports, and audited financial statements. Southern Company Gas may require counterparties to pledge additional collateral when deemed necessary.

In addition, Southern Company Gas conducts credit evaluations and obtains appropriate internal approvals for the counterparty's line of credit before any transaction with the counterparty is executed. In most cases, the counterparty must have an investment grade rating, which includes a minimum long-term debt rating of Baa3 from Moody's and BBB- from S&P. Generally, Southern Company Gas requires credit enhancements by way of a guaranty, cash deposit, or letter of credit for transaction counterparties that do not have investment grade ratings.

Southern Company Gas also utilizes master netting agreements whenever possible to ~~any financings~~mitigate exposure to counterparty credit risk. When Southern Company Gas is engaged in more than one outstanding derivative transaction with the same counterparty and it also has a legally enforceable netting agreement with that counterparty, the "net" mark-to-market exposure represents the netting of the positive and negative exposures with that counterparty and a reasonable measure of Southern Company Gas' credit risk. Southern Company Gas also uses other netting agreements with certain counterparties with whom it conducts significant transactions. Master netting agreements enable Southern Company Gas to net certain assets and liabilities by counterparty. Southern Company Gas also nets across product lines and against cash collateral provided the master netting and cash collateral agreements include such provisions. Southern Company Gas may ~~be necessary~~require counterparties to ~~meet capital requirements and contractual obligations, Mississippi Power plans,~~pledge additional collateral when ~~economically feasible, to retire higher-cost securities and replace these obligations with lower-cost capital if market conditions permit.~~deemed necessary.

~~121~~

~~Table~~The Registrants do not anticipate a material adverse effect on their respective financial statements as a result of ~~Contents~~

~~SOUTHERN POWER COMPANY~~

~~AND SUBSIDIARY COMPANIES~~

~~122~~

~~Table of Contents~~

~~SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES~~

~~CONDENSED CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)~~

For the Three Months Ended September 30, For the Nine Months Ended September 30,
2019 2018 2019 2018
(in millions) (in millions)
Operating Revenues:
Wholesale revenues, non-affiliates $ 455
$ 496
$ 1,197
$ 1,363
Wholesale revenues, affiliates 116
134
320
326
Other revenues 3
5
10
10
Total operating revenues 574
635
1,527
1,699
Operating Expenses:
Fuel 166
190
449
511
Purchased power 26
37
82
137
Other operations and maintenance 85
94
250
278
Depreciation and amortization 120
130
357
370
Taxes other than income taxes 10
12
32
36
Asset impairment —
36
—
155
Gain on dispositions, net —
—
(23 ) —
Total operating expenses 407
499
1,147
1,487
Operating Income 167
136
380
212
Other Income and (Expense):
Interest expense, net of amounts capitalized (43 ) (45 ) (127 ) (138 )
Other income (expense), net 6
17
48
22
Total other income and (expense) (37 ) (28 ) (79 ) (116 )
Earnings Before Income Taxes 130
108
301
96
Income taxes (benefit) 19
(38 ) (41 ) (210 )
Net Income 111
146
342
306
Net income attributable to noncontrolling interests 25
54
26
71
Net Income Attributable to Southern Power $ 86
$ 92
$ 316
$ 235
counterparty nonperformance.

~~CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)~~

For the Three Months Ended September 30, For the Nine Months Ended September 30,
2019 2018 2019 2018
(in millions) (in millions)
Net Income $ 111
$ 146
$ 342
$ 306
Other comprehensive income (loss):
Qualifying hedges:
Changes in fair value, net of tax of
$(18), $(4), $(28), and $(7), respectively (53 ) (11 ) (84 ) (19 )
Reclassification adjustment for amounts included in net income,
net of tax of $15, $4, $21, and $16, respectively 45
11
64
46
Pension and other postretirement benefit plans:
Reclassification adjustment for amounts included in net income,
net of tax of $-, $-, $-, and $-, respectively —
—
—
1
Total other comprehensive income (loss) (8 ) —
(20 ) 28
Comprehensive Income 103
146
322
334
Comprehensive income attributable to noncontrolling interests 25
54
26
71
Comprehensive Income Attributable to Southern Power $ 78
$ 92
$ 296
$ 263

~~The accompanying notes as they relate to Southern Power are an integral part of these condensed consolidated financial statements.~~

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~~SOUTHERN POWER COMPANY~~(K) ACQUISITIONS AND ~~SUBSIDIARY COMPANIES~~

~~CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)~~

For the Nine Months Ended September 30,
2019 2018
(in millions)
Operating Activities:
Net income $ 342
$ 306
Adjustments to reconcile net income to net cash provided from operating activities —
Depreciation and amortization, total 377
394
Deferred income taxes (122 ) (337 )
Utilization of federal investment tax credits 705
—
Amortization of investment tax credits (136 ) (43 )
Asset impairment —
155
Other, net (43 ) (2 )
Changes in certain current assets and liabilities —
-Receivables 15
(41 )
-Prepaid income taxes 33
5
-Other current assets (3 ) 1
-Accounts payable (5 ) (27 )
-Accrued taxes 66
256
-Other current liabilities (8 ) (1 )
Net cash provided from operating activities 1,221
666
Investing Activities:
Business acquisitions, net of cash acquired (50 ) (64 )
Property additions (284 ) (226 )
Proceeds from dispositions and asset sales 572
—
Change in construction payables (11 ) 3
Investment in unconsolidated subsidiaries (116 ) —
Payments pursuant to LTSAs (85 ) (57 )
Other investing activities 10
20
Net cash provided from (used for) investing activities 36
(324 )
Financing Activities:
Decrease in notes payable, net —
(68 )
Proceeds —
Short-term borrowings —
200
Capital contributions from parent company 59
—
Redemptions —
Short-term borrowings (100 ) —
Senior notes —
(350 )
Other long-term debt —
(420 )
Return of capital (755 ) (650 )
Distributions to noncontrolling interests (125 ) (86 )
Capital contributions from noncontrolling interests 11
1,333
Payment of common stock dividends (154 ) (234 )
Other financing activities (6 ) (15 )
Net cash used for financing activities (1,070 ) (290 )
Net Change in Cash, Cash Equivalents, and Restricted Cash 187
52
Cash, Cash Equivalents, and Restricted Cash at Beginning of Period 181
140
Cash, Cash Equivalents, and Restricted Cash at End of Period $ 368
$ 192
Supplemental Cash Flow Information:
Cash paid (received) during the period for —
Interest (net of $11 and $14 capitalized for 2019 and 2018, respectively) $ 133
$ 138
Income taxes, net (612 ) (102 )
Noncash transactions — Accrued property additions at end of period 41
37

~~The accompanying notes as they relate to Southern Power are an integral part of these condensed consolidated financial statements.~~

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~~SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES~~

~~CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)~~

Assets At September 30, 2019 At December 31, 2018
(in millions)
Current Assets:
Cash and cash equivalents $ 368
$ 181
Receivables —
Customer accounts receivable 152
111
Affiliated 49
55
Other 41
116
Materials and supplies 190
220
Prepaid income taxes 296
25
Other current assets 38
37
Total current assets 1,134
745
Property, Plant, and Equipment:
In service 13,072
13,271
Less: Accumulated provision for depreciation 2,374
2,171
Plant in service, net of depreciation 10,698
11,100
Construction work in progress 541
430
Total property, plant, and equipment 11,239
11,530
Other Property and Investments:
Intangible assets, net of amortization of $64 and $61
at September 30, 2019 and December 31, 2018, respectively 326
345
Other investments 28
—
Total other property and investments 354
345
Deferred Charges and Other Assets:
Operating lease right-of-use assets, net of amortization 368
—
Prepaid LTSAs 145
98
Accumulated deferred income taxes 318
1,186
Income taxes receivable, non-current 32
30
Assets held for sale 600
576
Other deferred charges and assets 207
373
Total deferred charges and other assets 1,670
2,263
Total Assets $ 14,397
$ 14,883

~~The accompanying notes as they relate to Southern Power are an integral part of these condensed consolidated financial statements.~~

~~125~~

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~~SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES~~

~~CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)~~

Liabilities and Stockholders' Equity At September 30, 2019 At December 31, 2018
(in millions)
Current Liabilities:
Securities due within one year $ 900
$ 599
Notes payable —
100
Accounts payable —
Affiliated 79
92
Other 74
77
Accrued taxes 21
6
Accrued interest 31
36
Other current liabilities 133
121
Total current liabilities 1,238
1,031
Long-term Debt 4,060
4,418
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes 117
105
Accumulated deferred ITCs 1,745
1,832
Operating lease obligations 373
—
Other deferred credits and liabilities 171
213
Total deferred credits and other liabilities 2,406
2,150
Total Liabilities 7,704
7,599
Total Stockholders' Equity (See accompanying statements)
6,693
7,284
Total Liabilities and Stockholders' Equity $ 14,397
$ 14,883

~~The accompanying notes as they relate to Southern Power are an integral part of these condensed consolidated financial statements.~~

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~~SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES~~

~~CONDENSED CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY (UNAUDITED)~~

Paid-In
Capital Retained
Earnings Accumulated
Other
Comprehensive
Income (Loss) Total Common
Stockholders' Equity Noncontrolling Interests Total
(in millions)
Balance at December 31, 2017 $ 3,662
$ 1,478
$ (2 ) $ 5,138
$ 1,360
$ 6,498
Net income attributable to Southern Power —
121
—
121
—
121
Capital contributions from parent company 1
—
—
1
—
1
Other comprehensive income (loss) —
—
24
24
—
24
Cash dividends on common stock —
(78 ) —
(78 ) —
(78 )
Capital contributions from
noncontrolling interests —
—
—
—
9
9
Distributions to noncontrolling interests —
—
—
—
(13 ) (13 )
Net income (loss) attributable
to noncontrolling interests —
—
—
—
(6 ) (6 )
Other —
(2 ) 5
3
(1 ) 2
Balance at March 31, 2018 3,663
1,519
27
5,209
1,349
6,558
Net income attributable to Southern Power —
22
—
22
—
22
Return of capital to parent company (250 ) —
—
(250 ) —
(250 )
Capital contributions from parent company 17
—
—
17
—
17
Other comprehensive income (loss) —
—
4
4
—
4
Cash dividends on common stock —
(78 ) —
(78 ) —
(78 )
Capital contributions from
noncontrolling interests —
—
—
—
22
22
Distributions to noncontrolling interests —
—
—
—
(29 ) (29 )
Net income attributable
to noncontrolling interests —
—
—
—
23
23
Sale of noncontrolling interests (407 ) —
—
(407 ) 1,690
1,283
Other —
1
—
1
1
2
Balance at June 30, 2018 3,023
1,464
31
4,518
3,056
7,574
Net income attributable to Southern Power —
92
—
92
—
92
Return of capital to parent company (415 ) —
—
(415 ) —
(415 )
Cash dividends on common stock —
(78 ) —
(78 ) —
(78 )
Capital contributions from
noncontrolling interests —
—
—
—
123
123
Distributions to noncontrolling interests —
—
—
—
(45 ) (45 )
Net income attributable
to noncontrolling interests —
—
—
—
54
54
Sale of noncontrolling interests (4 ) —
—
(4 ) —
(4 )
Balance at September 30, 2018 $ 2,604
$ 1,478
$ 31
$ 4,113
$ 3,188
$ 7,301

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~~SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES~~

~~CONDENSED CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY (UNAUDITED)~~

Paid-In
Capital Retained
Earnings Accumulated
Other
Comprehensive
Income (Loss) Total Common
Stockholders' Equity Noncontrolling Interests Total
(in millions)
Balance at December 31, 2018 $ 1,600
$ 1,352
$ 16
$ 2,968
$ 4,316
$ 7,284
Net income attributable to Southern Power —
56
—
56
—
56
Capital contributions from parent company 1
—
—
1
—
1
Other comprehensive income (loss) —
—
(4 ) (4 ) —
(4 )
Cash dividends on common stock —
(51 ) —
(51 ) —
(51 )
Capital contributions from
noncontrolling interests —
—
—
—
3
3
Distributions to noncontrolling interests —
—
—
—
(41 ) (41 )
Net income (loss) attributable
to noncontrolling interests —
—
—
—
(29 ) (29 )
Other (1 ) (1 ) —
(2 ) 1
(1 )
Balance at March 31, 2019 1,600
1,356
12
2,968
4,250
7,218
Net income attributable to Southern Power —
174
—
174
—
174
Return of capital to parent company (505 ) —
—
(505 ) —
(505 )
Capital contributions from parent company 7
—
—
7
—
7
Other comprehensive income (loss) —
—
(8 ) (8 ) —
(8 )
Cash dividends on common stock —
(52 ) —
(52 ) —
(52 )
Capital contributions from
noncontrolling interests —
—
—
—
2
2
Distributions to noncontrolling interests —
—
—
—
(47 ) (47 )
Net income attributable
to noncontrolling interests —
—
—
—
29
29
Other —
1
—
1
(1 ) —
Balance at June 30, 2019 1,102
1,479
4
2,585
4,233
6,818
Net income attributable to Southern Power —
86
—
86
—
86
Return of capital to parent company (250 ) —
—
(250 ) —
(250 )
Capital contributions from parent company 53
—
—
53
—
53
Other comprehensive income (loss) —
—
(8 ) (8 ) —
(8 )
Cash dividends on common stock —
(51 ) —
(51 ) —
(51 )
Capital contributions from
noncontrolling interests —
—
—
—
63
63
Distributions to noncontrolling interests —
—
—
—
(43 ) (43 )
Net income attributable
to noncontrolling interests —
—
—
—
25
25
Balance at September 30, 2019 $ 905
$ 1,514
$ (4 ) $ 2,415
$ 4,278
$ 6,693

~~The accompanying notes as they relate to Southern Power are an integral part of these condensed consolidated financial statements.~~

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~~SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES~~

~~MANAGEMENT'S DISCUSSION AND ANALYSIS OF~~

~~FINANCIAL CONDITION AND RESULTS OF OPERATIONS~~

~~THIRD QUARTER 2019 vs. THIRD QUARTER 2018~~

~~AND~~

~~YEAR-TO-DATE 2019 vs. YEAR-TO-DATE 2018~~

~~OVERVIEW~~

Southern Power develops, constructs, acquires, owns, and manages power generation assets, including renewable energy projects, and sells electricity at market-based rates in the wholesale market. Southern Power continually seeks opportunities to execute its strategy to create value through various transactions including acquisitions, dispositions, and sales of partnership interests, development and construction of new generating facilities, and entry into PPAs primarily with investor-owned utilities, independent power producers, municipalities, electric cooperatives, and other load-serving entities, as well as commercial and industrial customers. In general, Southern Power commits to the construction or acquisition of new generating capacity only after entering into or assuming long-term PPAs for the new facilities.

In the second quarter 2019, Southern Power completed the sale of its equity interests in Nacogdoches Power, LLC, the owner of an approximately 115-MW biomass facility located in Nacogdoches County, Texas, to Austin Energy, for a cash purchase price of approximately $461 million.

In the third quarter 2019, Southern Power completed a transaction to acquire a majority interest in DSGP, an affiliate of Bloom Energy that owns and operates fuel cell generation facilities, for a total purchase price of approximately $166 million.

In November 2018, Southern Power entered into an agreement with Northern States Power (a subsidiary of Xcel) to sell all of its equity interests in Plant Mankato for an aggregate purchase price of approximately $650 million, subject to certain state commission approvals. On September 27, 2019, the Minnesota Public Utilities Commission denied approval of the transaction. A newly-formed subsidiary of Xcel has agreed to purchase all of the equity interests in Plant Mankato subject to FERC approval and other customary conditions to closing. The transaction is expected to close by January 20, 2020. If the transaction does not close by this date, either party may terminate the transaction, which would result in the payment of a termination fee to Southern Power of up to $25 million. The ultimate outcome of this matter cannot be determined at this time.

During the nine months ended September 30, 2019, Southern Power continued construction of the 100-MW Wildhorse Mountain and the 200-MW Reading wind facilities. Subsequent to September 30, 2019, Southern Power acquired the 136-MW Skookumchuck wind facility and is continuing construction. See FUTURE EARNINGS POTENTIAL – "~~Construction Projects" herein for additional information.~~

At September 30, 2019, Southern Power's average investment coverage ratio for its generating assets (including Plant Mankato), based on the ratio of investment under contract to total investment using the respective generation facilities' net book value (or expected in-service value for facilities under construction) as the investment amount, was 93% through 2023 and 91% through 2028, with an average remaining contract duration of approximately 15 years.

~~Southern Power continues to focus on several key performance indicators, including, but not limited to, peak season equivalent forced outage rate, contract availability, and net income.~~

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~~SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES~~

~~MANAGEMENT'S DISCUSSION AND ANALYSIS OF~~

~~FINANCIAL CONDITION AND RESULTS OF OPERATIONS~~

~~RESULTS OF OPERATIONS~~

~~Net Income Attributable to Southern Power~~

Third Quarter 2019 vs. Third Quarter 2018 Year-to-Date 2019 vs. Year-to-Date 2018
(change in millions) (% change) (change in millions) (% change)
$(6) (6.5) $81 34.5

Net income attributable to Southern Power for the third quarter 2019 was $86 million compared to $92 million for the corresponding period in 2018. The decrease is primarily due to PPA capacity revenue decreases from the dispositions of Plant Oleander and Plant Stanton Unit A (together, the Florida Plants) in 2018 and Plant Nacogdoches in the second quarter 2019 totaling approximately $20 million and reductions in net income of approximately $10 million, net, related to the SP Wind tax equity partnership entered into in 2018, partially offset by a $27 million wind turbine equipment impairment charge in 2018.

Net income attributable to Southern Power for year-to-date 2019 was $316 million compared to $235 million for the corresponding period in 2018. The increase is primarily due to net impacts from the dispositions of the Florida Plants in 2018 and Plant Nacogdoches in the second quarter 2019 (including an asset impairment charge in 2018 and gains on sale in 2019, partially offset by PPA capacity revenue decreases in 2019) totaling approximately $142 million, a $27 million wind turbine equipment impairment charge in 2018, and net gains totaling $25 million from a litigation settlement relating to the Roserock solar facility and sales of wind equipment. These increases were partially offset by $65 million in state income tax benefits recorded in 2018 arising from the reorganization of Southern Power's legal entities that own and operate certain solar facilities and reductions in net income of approximately $54 million related to the SP Wind tax equity partnership entered into in 2018.DISPOSITIONS

See ~~Notes 7, 10, and~~Note 15 to the financial statements in Item 8 of the Form 10-K for additional information, ~~on the tax equity partnerships, the legal entity reorganization,~~including details of assets and ~~the Florida Plants dispositions, respectively. Also see Note (C) to the Condensed Financial Statements herein~~liabilities held for ~~additional information on the Roserock solar facility litigation settlement~~sale at December 31, 2019 for Southern Company, Southern Power, and ~~Note (K) to the Condensed Financial Statements herein~~Southern Company Gas. No Registrant had assets or liabilities held for ~~additional information on the disposition of Plant Nacogdoches and sales of wind equipment.~~sale at March 31, 2020.

~~Operating Revenues~~Alabama Power

Third Quarter 2019 vs. Third Quarter 2018 Year-to-Date 2019 vs. Year-to-Date 2018
(change in millions) (% change) (change in millions) (% change)
$(61) (9.6) $(172) (10.1)

~~Total operating revenues include PPA capacity revenues, which are derived primarily from long-term contracts involving natural gas facilities and a biomass generating facility (through~~On April 22, 2020, the ~~second quarter 2019 sale of Plant Nacogdoches), and PPA energy revenues from Southern Power's generation facilities. To~~FERC approved the ~~extent Southern Power has capacity not contracted~~Autauga Combined Cycle Acquisition. The Autauga Combined Cycle Acquisition remains subject to approval by the Alabama PSC. See Note (B) under ~~a PPA, it may sell power into an accessible wholesale market, or, to the extent those generation assets are part of the FERC-approved IIC, it may sell power into the power pool.~~

~~Natural Gas and Biomass Capacity and Energy Revenue~~

~~Capacity revenues generally represent the greatest contribution to operating income and are designed to provide recovery of fixed costs plus a return on investment.~~

Energy is generally sold at variable cost or is indexed to published natural gas indices. Energy revenues will vary depending on the energy demand of Southern Power's customers and their generation capacity, as well as the market prices of wholesale energy compared to the cost of Southern Power's energy. Energy revenues also include fees for support services, fuel storage, and unit start charges. Increases and decreases in energy revenues under PPAs that are driven by fuel or purchased power prices are accompanied by an increase or decrease in fuel and purchased power costs and do not have a significant impact on net income.

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~~Solar and Wind Energy Revenue~~

Southern Power's energy sales from solar and wind generating facilities are predominantly through long-term PPAs that do not have capacity revenue. Customers either purchase the energy output of a dedicated renewable facility through an energy charge or pay a fixed price related to the energy generated from the respective facility and sold to the grid. As a result, Southern Power's ability to recover fixed and variable operations and maintenance expenses is dependent upon the level of energy generated from these facilities, which can be impacted by weather conditions, equipment performance, transmission constraints, and other factors.

~~See FUTURE EARNINGS POTENTIAL – "Power Sales Agreements" herein~~"Alabama Power" for additional ~~information regarding Southern Power's PPAs.~~

~~Details of Southern Power's operating revenues were as follows:~~

Third Quarter 2019 Third Quarter 2018 Year-to-Date 2019 Year-to-Date 2018
(in millions)
PPA capacity revenues $ 131
$ 168
$ 384
$ 450
PPA energy revenues 339
336
857
892
Total PPA revenues 470
504
1,241
1,342
Non-PPA revenues 101
126
276
347
Other revenues 3
5
10
10
Total operating revenues $ 574
$ 635
$ 1,527
$ 1,699

In the third quarter 2019, total operating revenues were $574 million, reflecting a $61 million, or 10%, decrease from the corresponding period in 2018. The decrease in operating revenues was primarily due to the following:

PPA capacity revenues decreased $37 million, or 22%, primarily due to the sales of the Florida Plants in December 2018 and Plant Nacogdoches in June 2019. In addition, the change reflects a reduction of $15 million from the contractual expiration of an affiliate natural gas PPA, partially offset by a $13 million increase in new PPA capacity revenues from existing gas facilities.

PPA energy revenues increased $3 million, or 1%, due to a $15 million increase in sales primarily driven by the volume of KWHs generated by solar and wind facilities, partially offset by a $12 million decrease in sales from natural gas facilities primarily driven by a decrease in the average cost of fuel and purchased power.

~~Non-PPA revenues decreased $25 million, or 20%, due to a $15 million decrease in the volume of KWHs sold through short-term sales and a $10 million decrease in the market price of energy.~~

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For year-to-date 2019, total operating revenues were $1.5 billion, reflecting a $172 million, or 10%, decrease from the corresponding period in 2018. The decrease in operating revenues was primarily due to the following:

PPA capacity revenues decreased $66 million, or 15%, primarily due to the sales of the Florida Plants in December 2018 and Plant Nacogdoches in June 2019. In addition, the change reflects a reduction of $20 million from the contractual expiration of an affiliate natural gas PPA, offset by a $26 million increase in new PPA capacity revenues from existing natural gas facilities.

PPA energy revenues decreased $35 million, or 4%, primarily due to a $42 million decrease in sales from natural gas facilities primarily driven by a $66 million decrease in the average cost of fuel and purchased power, partially offset by a $24 million increase in the volume of KWHs sold due to increased customer load.

~~Non-PPA revenues decreased $71 million, or 20%, primarily due to a $52 million decrease in the volume of KWHs sold through short-term sales and an $18 million decrease in the market price of energy.~~

~~Fuel and Purchased Power Expenses~~

~~Details of Southern Power's generation and purchased power were as follows:~~

Third Quarter 2019 Third Quarter 2018 Year-to-Date 2019 Year-to-Date 2018
(in billions of KWHs)
Generation 13.8 13.3 35.7 35.3
Purchased power 0.8 0.9 2.5 3.1
Total generation and purchased power 14.6 14.2 38.2 38.4

Total generation and purchased power, excluding solar, wind, and tolling agreements 8.6 8.2 22.3 22.2

Southern Power's PPAs for natural gas and biomass generation generally provide that the purchasers are responsible for either procuring the fuel (tolling agreements) or reimbursing Southern Power for substantially all of the cost of fuel relating to the energy delivered under such PPAs. Consequently, changes in such fuel costs are generally accompanied by a corresponding change in related fuel revenues and do not have a significant impact on net income. Southern Power is responsible for the cost of fuel for generating units that are not covered under PPAs. Power from these generating units is sold into the wholesale market or into the power pool for capacity owned directly by Southern Power.

Purchased power expenses will vary depending on demand, availability, and the cost of generating resources throughout the Southern Company system and other contract resources. Load requirements are submitted to the power pool on an hourly basis and are fulfilled with the lowest cost alternative, whether that is generation owned by Southern Power, an affiliate company, or external parties. Such purchased power costs are generally recovered through PPA revenues.

~~Details of Southern Power's fuel and purchased power expenses were as follows:~~

Third Quarter 2019 vs. Third Quarter 2018 Year-to-Date 2019 vs. Year-to-Date 2018
(change in millions) (% change) (change in millions) (% change)
Fuel $ (24 ) (12.6) $ (62 ) (12.1)
Purchased power (11 ) (29.7) (55 ) (40.1)
Total fuel and purchased power expenses $ (35 ) $ (117 )

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In the third quarter 2019, total fuel and purchased power expenses decreased $35 million, or 15%, compared to the corresponding period in 2018. Fuel expense decreased $24 million due to a $38 million decrease in the average cost of fuel per KWH generated, partially offset by a $14 million increase associated with the volume of KWHs generated. Purchased power expense decreased $11 million due to an $8 million decrease associated with the volume of KWHs purchased and a $3 million decrease associated with the average cost of purchased power.

For year-to-date 2019, total fuel and purchased power expenses decreased $117 million, or 18%, compared to the corresponding period in 2018. Fuel expense decreased $62 million due to a $78 million decrease in the average cost of fuel per KWH generated, partially offset by a $16 million increase associated with the volume of KWHs generated. Purchased power expense decreased $55 million due to a $28 million decrease associated with the average cost of purchased power and a $27 million decrease associated with the volume of KWHs purchased.

~~Other Operations and Maintenance Expenses~~

Third Quarter 2019 vs. Third Quarter 2018 Year-to-Date 2019 vs. Year-to-Date 2018
(change in millions) (% change) (change in millions) (% change)
$(9) (9.6) $(28) (10.1)

In the third quarter 2019, other operations and maintenance expenses were $85 million compared to $94 million for the corresponding period in 2018. The decrease was primarily due to lower scheduled outage and maintenance expenses and a gain on the sale of wind turbine equipment.

For year-to-date 2019, other operations and maintenance expenses were $250 million compared to $278 million for the corresponding period in 2018. The decrease was primarily due to gains totaling $17 million on the sale of wind turbine equipment, lower scheduled outage and maintenance expenses, and the recovery of legal costs related to the Roserock litigation settlement in the first quarter 2019.

See Note (K) to the Condensed Financial Statements under "Southern Power – Development Projects" herein for additional information on the sale of wind turbine equipment. Also see Note (C) to the Condensed Financial Statements under "General Litigation Matters – Southern Power" herein for additional information on the Roserock solar facility litigation settlement.

~~Asset Impairment~~

Third Quarter 2019 vs. Third Quarter 2018 Year-to-Date 2019 vs. Year-to-Date 2018
(change in millions) (% change) (change in millions) (% change)
$(36) (100.0) $(155) (100.0)

In the second quarter 2018, a $119 million asset impairment charge was recorded in anticipation of the sale of the Florida Plants. In addition, in the third quarter 2018, a $36 million asset impairment charge was recorded on wind turbine equipment held for development projects. See Note 15 to the financial statements in Item 8 of the Form 10-K under "Southern Power – Sale of Natural Gas Plants" and Note (K) to the Condensed Financial Statements under "Southern Power – Development Projects" herein for additional information.

~~Gain on Dispositions, net~~

~~In the second quarter 2019, the sale of Plant Nacogdoches resulted in a $23 million gain. See Note (K) to the Condensed Financial Statements under "Southern Power" herein for additional information.~~

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~~Other Income (Expense), net~~

Third Quarter 2019 vs. Third Quarter 2018 Year-to-Date 2019 vs. Year-to-Date 2018
(change in millions) (% change) (change in millions) (% change)
$(11) N/M $26 N/M

~~N/M - Not meaningful~~

In the third quarter 2019, other income (expense), net was $6 million compared to $17 million for the corresponding period in 2018. The decrease was primarily due to a $14 million gain from a joint-development wind project in 2018, which was attributable to Southern Power's partner in the project and fully offset within noncontrolling interests.

For year-to-date 2019, other income (expense), net was $48 million compared to $22 million for the corresponding period in 2018. The increase was primarily due to a $36 million gain arising from the settlement of litigation related to the Roserock solar facility in the second quarter 2019, partially offset by a $14 million gain from a joint-development wind project in 2018, which was attributable to Southern Power's partner in the project and fully offset within noncontrolling interests. See Note (C) to the Condensed Financial Statements under "General Litigation Matters – Southern Power" herein for additional information regarding the litigation settlement.

~~Income Taxes (Benefit)~~

Third Quarter 2019 vs. Third Quarter 2018 Year-to-Date 2019 vs. Year-to-Date 2018
(change in millions) (% change) (change in millions) (% change)
$57 150.0 $169 80.5

In the third quarter 2019, income tax expense was $19 million compared to a $38 million benefit for the corresponding period in 2018. This change was primarily due to a $25 million reduction of tax benefits from wind PTCs primarily as a result of the 2018 sale of a noncontrolling tax equity interest in SP Wind, a $13 million increase in income tax expense as a result of higher pre-tax earnings, and $11 million in tax benefits recorded in 2018 related to changes in state apportionment rates following the reorganization of Southern Power's legal entities that own and operate certain wind facilities.

For year-to-date 2019, income tax benefit was $41 million compared to $210 million for the corresponding period in 2018. This change was primarily due to a $105 million reduction of tax benefits from wind PTCs primarily following the sale of a noncontrolling tax equity interest in SP Wind, $65 million in tax benefits related to changes in state apportionment rates following the 2018 reorganizations of certain legal entities, and a $63 million increase in income tax expense as a result of higher pre-tax earnings, partially offset by a $75 million tax benefit resulting from the recognition of deferred ITCs remaining from the original construction of Plant Nacogdoches.

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

~~Net Income Attributable to Noncontrolling Interests~~

Third Quarter 2019 vs. Third Quarter 2018 Year-to-Date 2019 vs. Year-to-Date 2018
(change in millions) (% change) (change in millions) (% change)
$(29) (53.7) $(45) (63.4)

In the third quarter 2019, net income attributable to noncontrolling interests was $25 million compared to $54 million for the corresponding period in 2018. The decrease was primarily due to an allocation of approximately $22 million of losses attributable to noncontrolling interests related to the tax equity partnerships entered into in 2018.

For year-to-date 2019, net income attributable to noncontrolling interests was $26 million compared to $71 million for the corresponding period in 2018. The decrease was primarily due to $70 million of losses attributable to

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~~FINANCIAL CONDITION AND RESULTS OF OPERATIONS~~

noncontrolling interests related to the tax equity partnerships entered into in 2018, partially offset by an allocation of approximately $29 million of income to the noncontrolling interest partner related to the Roserock solar facility litigation settlement.

See Notes 1 and 7 to the financial statements in Item 8 of the Form 10-K under "General" and "Southern Power," respectively, and Note (E) to the Condensed Financial Statements under "Southern Power – Consolidated Variable Interest Entities" herein for additional information regarding the tax equity partnerships. See Note (C) to the Condensed Financial Statements under "General Litigation Matters – Southern Power" herein for additional information regarding the Roserock solar facility litigation settlement.

~~FUTURE EARNINGS POTENTIAL~~

The results of operations discussed above are not necessarily indicative of Southern Power's future earnings potential. Future earnings potential will be impacted by the sales of noncontrolling interests in renewable facilities and the Florida Plants in 2018, the sale of Plant Nacogdoches in the second quarter 2019, and the pending sale of Plant Mankato expected to close by January 20, 2020. The level of Southern Power's future earnings depends on numerous factors that affect the opportunities, challenges, and risks of Southern Power's competitive wholesale business. These factors include: Southern Power's ability to achieve sales growth while containing costs; regulatory matters; creditworthiness of customers; total generating capacity available in Southern Power's market areas; the successful remarketing of capacity as current contracts expire; and Southern Power's ability to execute its growth strategy through the development or acquisition of renewable facilities and other energy projects.

In the second quarter 2019, Southern Power completed the sale of its equity interests in Nacogdoches Power, LLC, the owner of an approximately 115-MW biomass facility located in Nacogdoches County, Texas, to Austin Energy, for a cash purchase price of approximately $461 million. The pre-tax income related to Plant Nacogdoches was $16 million and $20 million for the nine months ended September 30, 2019 and 2018, respectively.

In the third quarter 2019, Southern Power completed a transaction to acquire a majority interest in DSGP, an affiliate of Bloom Energy that owns and operates fuel cell generation facilities, for a total purchase price of approximately $166 million. Pre-tax income for this project was immaterial for the three months ended September 30, 2019. See Notes (E) and (K) to the Condensed Financial Statements under "Southern Power" and "Southern Power – Development Projects," respectively, herein for additional information.

In November 2018, Southern Power entered into an agreement with Northern States Power (a subsidiary of Xcel) to sell all of its equity interests in Plant Mankato for an aggregate purchase price of approximately $650 million, subject to certain state commission approvals. On September 27, 2019, the Minnesota Public Utilities Commission denied approval of the transaction. A newly-formed subsidiary of Xcel has agreed to purchase all of the equity interests in Plant Mankato subject to FERC approval and other customary conditions to closing. The transaction is expected to close by January 20, 2020. If the transaction does not close by this date, either party may terminate the transaction, which would result in the payment of a termination fee to Southern Power of up to $25 million. The ultimate outcome of this matter cannot be determined at this time. ~~Pre-tax income for Plant Mankato was immaterial for both the nine months ended September 30, 2019 and 2018.~~

Demand for electricity is primarily driven by the pace of economic growth that may be affected by changes in regional and global economic conditions, as well as renewable portfolio standards, which may impact future earnings. Other factors that could influence future earnings include weather, transmission constraints, cost of generation from units within the power pool, and operational limitations. For additional information relating to these factors, see RISK FACTORS in Item 1A and MANAGEMENT'S DISCUSSION AND ANALYSIS – ~~FUTURE EARNINGS POTENTIAL of Southern Power in Item 7 of the Form 10-K.~~

Southern Power

Acquisitions

In March 2020, Southern Power ~~Sales Agreements~~

~~See BUSINESS – "The Southern Company System – Southern Power"~~entered into an agreement to acquire a controlling membership interest in ~~Item 1~~an approximately 300-MW wind facility located in South Dakota. The acquisition is subject to FERC approval and certain other customary conditions to closing, including commercial operation of the ~~Form 10-K for additional information regarding Southern Power's~~facility, which is expected to occur in the fourth quarter 2020. The facility's output is contracted under 2 long-term PPAs. ~~Generally, under the solar and wind generation PPAs, the purchasing party retains the right to keep or resell the renewable energy credits.~~

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~~SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES~~

~~MANAGEMENT'S DISCUSSION AND ANALYSIS OF~~

~~FINANCIAL CONDITION AND RESULTS OF OPERATIONS~~

~~Environmental Matters~~

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

~~Environmental Laws and Regulations~~Construction Projects

~~Water Quality~~

~~On October 22, 2019,~~During the ~~EPA and the U.S. Army Corps of Engineers jointly published a final rule that repealed the 2015 Waters~~three months ended March 31, 2020, Southern Power continued construction of the ~~United States (WOTUS) rule. This final rule will be effective December 23, 2019~~Reading and ~~will bring all states back under the pre-2015 regulations until a new WOTUS rule is finalized. A revised definition of WOTUS is anticipated~~Skookumchuck wind facilities. Total aggregate construction costs, excluding acquisition costs, are expected to be ~~finalized by~~between $490 million and $535 million for the ~~end~~two facilities under construction. At March 31, 2020, total costs of ~~2019. The impact of the WOTUS rule will depend on the content of the final~~

~~rule redefining WOTUS~~Table of ContentsIndex to Financial Statements

NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

construction incurred for these projects were $447 million and ~~the~~are included in CWIP. The ultimate outcome of ~~any associated legal challenges and~~these matters cannot be determined at this time.

~~Acquisitions~~

During the third quarter 2019, Southern Power acquired a controlling interest in the fuel cell generation facility listed below. Acquisition-related costs were expensed as incurred and were not material.



Project Facility	Resource	Approximate Nameplate Capacity (MW)	Location	~~Southern Power Percentage Ownership~~	~~COD~~	~~PPA Counterparty~~	~~PPA Remaining Period~~
~~DSGP~~^(a)	~~Fuel Cell~~	28	~~Delaware~~	~~100% of Class B~~	~~N/A~~^(b)	~~Delmarva Power & Light~~	~~15 years~~


~~(a)~~	During the second and third quarters 2019, Southern Power made a total investment of approximately $166 million in DSGP and now holds a controlling interest and consolidates 100% of DSGP's operating results. Southern Power records net income attributable to noncontrolling interests for approximately 10 MWs of the facility.


~~(b)~~	~~Approximately 18 MWs of the 28-MW facility was repowered between June and August 2019.~~

~~Construction Projects~~

~~See MANAGEMENT'S DISCUSSION AND ANALYSIS~~ – ~~FUTURE EARNINGS POTENTIAL~~ – ~~"Acquisitions" and "Construction Projects" of Southern Power in Item 7 of the Form 10-K and FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" herein for additional information.~~

During the nine months ended September 30, 2019, Southern Power completed construction of and placed in service the 385-MW Plant Mankato expansion and continued construction of the Wildhorse Mountain and Reading facilities. Total aggregate construction costs, excluding acquisition costs, are expected to be between $405 million and $450 million for the two facilities under construction. At September 30, 2019, total costs of construction incurred for these projects were $337 million and are included in CWIP. The ultimate outcome of these matters cannot be determined at this time.

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~~Project Facility~~	~~Resource~~	~~Approximate Nameplate Capacity (~~MW)	~~Location~~	Actual/Expected COD	~~PPA Counterparties~~	PPA Contract Period
~~Projects Completed During the Nine Months Ended September 30, 2019~~
~~Mankato expansion~~^(a)	~~Natural Gas~~	~~385~~	~~Mankato, MN~~	~~May 2019~~	~~Northern States Power Company~~	~~20 years~~
Projects Under Construction as of ~~September 30, 2019~~
~~Wildhorse Mountain~~^(b)	~~Wind~~	~~100~~	~~Pushmataha County, OK~~	~~Fourth quarter 2019~~	~~Arkansas Electric Cooperative~~	~~20 years~~March 31, 2020
Reading^(c)(a)	Wind	200	Osage and Lyon Counties, KS	~~Second quarter~~May 2020	~~Royal Caribbean Cruises LTD~~	12 years
Skookumchuck^(b)	Wind	136	Lewis and Thurston Counties, WA	Second half of 2020	20 years

Subsequent to September 30, 2019, Southern Power purchased 100% of the membership interests of the 136-MW Skookumchuck wind facility located in Lewis and Thurston Counties, Washington from the joint development arrangement with Renewable Energy Systems Americas, Inc. and is continuing construction. The facility's output is contracted under a 20-year PPA with Puget Sound Energy, Inc. Upon commercial operation, which is expected to occur in the first quarter 2020, Southern Power may enter into a tax equity partnership as the Class B member and, shortly thereafter, sell a noncontrolling interest in these Class B membership interests to another partner. The ultimate outcome of this matter cannot be determined at this time.

~~Southern Power is involved in various other matters that could affect~~Company Gas may also receive 2 future ~~earnings, including matters being litigated, as well as other regulatory and business matters. In addition,~~ ~~Southern Power is subject to~~payments of $5 million each, contingent upon certain ~~claims and legal actions arising in the ordinary course of business. Southern Power's business activities~~ ~~are subject to extensive governmental regulation~~milestones related to public health and the environment, such as laws and regulations governing air, water, land, and protection of other natural resources. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental laws and regulations, has occurred throughout the U.S. This litigation has included claims for damages alleged to have been causedPivotal LNG being met 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, regulatory matters, or other business matters cannot be determined at this time; however, for current proceedings not specifically reported in Notes (B) and (C) to the

Southern Power prepares its consolidated financial statements in accordance with GAAP. Significant accounting policies are described in Notes 1, 4, and 10 to the financial statements in Item 8 of the Form 10-K. In the application of these policies, certain estimates are made that may have a material impact on Southern Power's results of operations and related disclosures. Different assumptions and measurements could produce estimates that are significantly different from those recorded in the financial statements. See MANAGEMENT'S DISCUSSION AND ANALYSIS7 under "Other Matters – ACCOUNTING POLICIES – "Application of Critical Accounting Policies and Estimates" of Southern Power in Item 7 of the Form 10-K for a complete discussion of Southern Power's critical accounting policies and estimates.

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Overview" of Southern Power in Item 7 of the Form 10-K for additional information. Southern Power's financial condition remained stable at September 30, 2019. Southern Power intends to continue to monitor its access to short-term and long-term capital markets as well as bank credit agreements as needed to meet future capital and liquidity needs. See "~~Sources of Capital" herein for additional information on lines of credit.~~

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" of Southern Power in Item 7 of the Form 10-K for a description of Southern Power's capital requirements and contractual obligations. Approximately $900 million will be required through September 30, 2020 to fund maturities of long-term debt. See "Sources of Capital" herein for additional information.

Southern Power's construction program includes estimates for potential plant acquisitions and placeholder growth, new construction and development, capital improvements, and work to be performed under LTSAs and is subject to periodic review and revision. Actual construction costs, including acquisitions, may vary from these estimates because of numerous factors such as: changes in business conditions; changes in the expected environmental compliance program; changes in environmental laws and regulations; the outcome of any legal challenges to environmental rules; changes in FERC rules and regulations; changes in load projections; changes in legislation; the cost and efficiency of construction labor, equipment, and materials; project scope and design changes; and the cost of capital. See FUTURE EARNINGS POTENTIAL – "~~Construction Projects" herein for additional information.~~

Southern Power plans to obtain the funds required for acquisitions, construction, development, debt maturities, and other purposes from operating cash flows, external securities issuances, borrowings from financial institutions, tax equity partnership contributions, divestitures, and equity contributions from Southern Company. However, the amount, type, and timing of any future financings, if needed, will depend upon prevailing market conditions, regulatory approval, and other factors. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Sources of Capital" of Southern Power in Item 7 of the Form 10-K for additional information.

Southern Power's current liabilities sometimes exceed current assets due to the use of short-term debt as a funding source and construction payables, as well as fluctuations in cash needs due to seasonality. Southern Power believes the need for working capital can be adequately met by utilizing the commercial paper program, the Facility (as

~~defined below), borrowings from financial institutions, equity contributions from Southern Company, external securities issuances, and operating cash flows.~~

~~As of September 30, 2019, Southern Power had cash and cash equivalents of approximately $368 million.~~

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

In May 2019, Southern Power amended and restated its committed credit facility (Facility) to extend the maturity date to 2024 and decrease the borrowing capacity from $750 million to $600 million. At September 30, 2019, $9 million of the Facility had been used for letters of credit and $591 million remains unused. Proceeds from the Facility may be used for working capital and general corporate purposes as well as liquidity support for Southern Power's commercial paper program. Subject to applicable market conditions, Southern Power expects to renew or replace the Facility, as needed, prior to expiration. In connection therewith, Southern Power may extend the maturity date and/or increase or decrease the lending commitment thereunder. See Note 8 to the financial statements under "Bank Credit Arrangements"respectively, in Item 8 of the Form 10-K and ~~Note (F) to the Condensed Financial Statements~~Notes (C) and (E) under "~~Bank Credit Arrangements~~Other Matters – Southern Company Gas" and "Southern Company Gas," ~~herein for additional information.~~respectively.

~~Southern Power also has a $120 million continuing letter of credit facility expiring~~distributed generation, energy storage and renewables, and energy efficiency, as well as investments in ~~2021 for standby letters of credit. At September 30, 2019, $90 million has been used for letters of credit, primarily as credit support for PPA requirements,~~telecommunications and ~~$30 million remains unused.~~

~~Southern Power's subsidiaries do not borrow under the commercial paper program and~~leveraged lease projects. All other inter-segment revenues are not ~~parties to, and do not borrow under, the Facility or the continuing letter of credit facility.~~

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

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

Included in these amounts are certain agreements that could require collateral in the event that either Alabama Power or Georgia Power (affiliate companies of Southern Power) has a credit rating change to below investment grade. Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. Additionally, a credit rating downgrade could impact the ability of Southern Power to access capital markets and would be likely to impact the cost at which it does so.

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

~~In May 2019, Southern Power repaid at maturity a $100 million short-term floating rate bank loan.~~

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

For year-to-date 2019, cost of natural gas was $956 million compared to $1.05 billion for the corresponding period in 2018. Excluding a $106 million decrease related to the Southern Company Gas Dispositions, cost of natural gas increased $9 million. This increase reflects a 4.9% increase in natural gas prices in the first quarter 2019, partially offset by a decrease in the volume of natural gas sold year-to-date 2019 compared to the corresponding period in 2018.

~~For year-to-date 2019, income taxes were $61 million compared to $475 million for the corresponding period in 2018. Excluding~~ a ~~$363~~$24 million decrease ~~related to the Southern Company Gas Dispositions and a $27 million decrease for an impairment charge related to a natural~~at wholesale gas ~~storage facility in Louisiana, income taxes decreased $24 million. This decrease was~~services primarily due to an increase in the flowback of excess deferred income taxes in 2019 primarily at Atlanta Gas Light as previously authorized by the Georgia PSC and the reversal of a $13 million federal income tax valuation allowance in connection with the sale of Triton in May 2019.

~~See Note (E)~~reduced natural gas price volatility compared to the Condensed Financial Statements under "Southern Company Gas" herein for additional information on the sale of Triton, Note (C) to the Condensed Financial Statements under "Other Matters – Southern Company Gas" herein for additional information on the natural gas storage facility andprior year. See Note 2 to the financial statements under "Southern Company Gas" in Item 8 of the Form 10-K for additional ~~information on~~information.

In the ~~third~~first quarter ~~and year-to-date 2019,~~2020, there were no material changes in net income ~~decreased $14 million, or 70.0%, and $5 million, or 7.4%, respectively,~~ compared to the corresponding ~~periods~~period in ~~2018. These decreases primarily relate to an increase in tax expense due to changes in state apportionment rates, partially offset by higher earnings from SNG.~~2019.

~~For year-to-date 2019, net income increased $125 million compared to the corresponding period in 2018. This increase primarily relates to a $119~~$1 million decrease in operating expenses and a ~~$35~~$3 million decrease in income tax ~~expense, partially offset by a $31 million~~expense. The decrease in adjusted operating ~~margin.~~

On October 22, 2019, the EPA and the U.S. Army Corps of Engineers jointly published a final rule that repealed the 2015 Waters of the United States (WOTUS) rule. This final rule will be effective December 23, 2019 and will bring all states back under the pre-2015 regulations until a new WOTUS rule is finalized. A revised definition of WOTUS is anticipated to be finalized by the end of 2019. The impact of the WOTUS rule will depend on the content of the final~~rule redefining WOTUS and the outcome of any associated legal challenges and cannot be determined at this time.~~

In addition to capital expenditures recovered through base rates by each of the natural gas distribution utilities, Nicor Gas and Virginia Natural Gas have separate rate riders that provide for timely recovery of capital expenditures for specific infrastructure replacement programs. Infrastructure expenditures incurred under these programs in the first nine months of 2019 were as follows:

On April 8, 2019, Virginia Natural Gas filed an application with the Virginia Commission to amend and extend its SAVE program, which was approved by the Virginia Commission on September 25, 2019. The extension allows Virginia Natural Gas to continue replacing aging pipeline infrastructure through 2024 and increase its authorized investment under the previously-approved plan from $35 million to $40 million in 2019 with additional annual investments of $50 million in 2020, $60 million in 2021, $70 million in each year from 2022 through 2024, and a potential variance of up to $5 million allowed for the program, for a maximum total investment over the six-year term (2019 through 2024) of $365 million.

~~See MANAGEMENT'S DISCUSSION AND ANALYSIS~~ – ~~FUTURE EARNINGS POTENTIAL~~ – ~~"Regulatory Matters~~ – ~~Infrastructure Replacement Programs and Capital Projects" of Southern Company Gas in Item 7 and Note 2 to the financial statements under "Southern Company Gas~~ – ~~Infrastructure Replacement Programs and Capital Projects" in Item 8 of the Form 10-K for additional information.~~

Southern Company Gas is involved in various other matters that could affect future earnings, including matters being litigated, as well as other regulatory matters and matters that could result in asset impairments. In addition, Southern Company Gas is subject to certain claims and legal actions arising in the ordinary course of business. The ultimate outcome of such pending or potential litigation, regulatory matters, or potential asset impairments cannot be determined at this time; however, for current proceedings not specifically reported in Notes (B) and (C) to the Condensed Financial Statements herein, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on Southern Company Gas' financial statements. See Notes (B) and (C) to the Condensed Financial Statements herein for a discussion of various other contingencies, regulatory matters, and other matters being litigated which may affect future earnings potential.

The Atlantic Coast Pipeline has experienced challenges to its permits since construction began in 2018. On October 4, 2019, the U.S. Supreme Court agreed to hear Atlantic Coast Pipeline's appeal of a lower court ruling that overturned a key permit for the project. The delays resulting from the permitting issues have impacted the cost and schedule for the project. As a result, total current project cost estimates have increased from between $7.0 billion and $7.8 billion ($350 million and $390 million for Southern Company Gas) to between $7.3 billion and $7.8 billion ($365 million and $390 million for Southern Company Gas), excluding financing costs. The operator of the joint venture has indicated that it currently expects to complete construction by the end of 2021 and place the project in service shortly thereafter.

On September 10, 2019, an appellate court ruled that the PennEast Pipeline does not have federal court eminent domain authority over lands in which a state has property rights interests. The joint venture is pursuing appellate and other options and is evaluating further next steps.

The long-term debt on Southern Company Gas' balance sheets includes both principal and non-principal components. As of September 30, 2019, the non-principal components totaled $420 million, which consisted of the unamortized portions of the fair value adjustment recorded in purchase accounting, debt premiums, debt discounts, and debt issuance costs.

~~In July 2019, Nicor Gas repaid at maturity $50 million aggregate principal amount of 4.7% first mortgage bonds.~~

~~In August 2019, Southern Company Gas Capital repaid at maturity $300 million aggregate principal amount of 5.25% Senior Notes due 2019.~~

In August 2019, Nicor Gas issued $200 million aggregate principal amount of first mortgage bonds in a private placement. The proceeds will be used for the repayment of short-term debt, capital expenditures, and other corporate purposes. Nicor Gas entered into an agreement to issue an additional $100 million aggregate principal amount of first mortgage bonds on October 30, 2019.

The condensed quarterly financial statements of each registrant included herein have been prepared by such registrant, without audit, pursuant to the rules and regulations of the SEC. The Condensed Balance Sheets as of December 31, 2018 have been derived from the audited financial statements of each registrant. In the opinion of each registrant's management, the information regarding such registrant furnished herein reflects all adjustments, which, except as otherwise disclosed, are of a normal recurring nature, necessary to present fairly the results of operations for the periods ended September 30, 2019 and 2018. Certain information and footnote disclosures normally included in annual financial statements prepared in accordance with GAAP have been condensed or omitted pursuant to such rules and regulations, although each registrant believes that the disclosures regarding such registrant are adequate to make the information presented not misleading. Disclosures which would substantially duplicate the disclosures in the Form 10-K and details which have not changed significantly in amount or composition since the filing of the Form 10-K are generally omitted from this Quarterly Report on Form 10-Q unless specifically required by GAAP. Therefore, these Condensed Financial Statements should be read in conjunction with the financial statements and the notes thereto included in the Form 10-K. Due to the seasonal variations in the demand for energy, operating results for the periods presented are not necessarily indicative of the operating results to be expected for the full year.

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

Nicor Gas' natural gas inventory is carried at cost on a LIFO basis. Inventory decrements occurring during the year that are restored prior to year end are charged to cost of natural gas at the estimated annual replacement cost. Inventory decrements that are not restored prior to year end are charged to cost of natural gas at the actual LIFO cost of the inventory layers liquidated. Nicor Gas had 0 inventory decrement at September 30, 2019.

~~See Note 6 to the financial statements in Item 8 of the Form 10-K for additional information regarding AROs.~~

Southern Company Alabama Power Mississippi Power
(in millions)
Balance at December 31, 2018 $ 9,394
$ 3,210
$ 160
Liabilities incurred 35
—
1
Liabilities settled (223 ) (76 ) (28 )
Accretion 299
107
5
Cash flow revisions 455
312
57
Balance at September 30, 2019 $ 9,960
$ 3,553
$ 195

As further analysis is performed and additional details are developed with respect to ash pond closures, the traditional electric operating companies expect to periodically update their ARO cost estimates. Additionally, the closure designs and plans in the States of Alabama and Georgia are subject to approval by environmental regulatory agencies. Absent continued recovery of ARO costs through regulated rates, Southern Company's and the traditional electric operating companies' results of operations, cash flows, and financial condition could be materially impacted. The ultimate outcome of these matters cannot be determined at this time.

On April 22, 2020, the FERC approved the Autauga Combined Cycle Acquisition. The Autauga Combined Cycle Acquisition, as well as procurement of ~~these~~the other resources isidentified in Alabama Power's CCN petition, remain subject to ~~the satisfaction or waiver of certain conditions, including, among other customary conditions,~~ approval by the Alabama PSC. The ~~completion~~ultimate outcome of this matter cannot be determined at this time.

~~The capital investment associated with the construction of Plant Barry Unit 8~~purchased power, ad valorem taxes, property damage, and the ~~Autauga Combined Cycle Acquisition is currently estimated to total approximately $1.1 billion.~~

Upon certification, Alabama Power expects to recover costs associated with Plant Barry Unit 8 through its Rate CNP New Plant. Additionally, Alabama Power expects to recover costs associated with the Autauga Combined Cycle Acquisition through Rate RSE during the term of the existing power sales agreement and, on expiration of the agreement, through Rate CNP New Plant. Thespecific cost recovery ~~of costs associated with laws, regulations, and other such mandates directed at the utility industry~~clauses are expected to be recovered through Mississippi Power's base rates.

On June 28, 2019, Georgia Power filed a base rate case (Georgia Power 2019 Base Rate Case) with the Georgia PSC. The filing, as modified on September 24, 2019, includes a three-year Alternate Rate Plan with requested rate increases totaling $560 million, $144 million, and $233 million effective January 1, 2020, January 1, 2021, and

January 1, 2022, respectively. These increases are based on a proposed retail ROE of 10.90% and a proposed equity ratio of 56% and reflect levelized revenue requirements during the three-year period, with the exception of incremental compliance costs related to CCR AROs, Demand-Side Management programs, and adjustments to the Municipal Franchise Fee tariff.

~~Georgia Power has requested recovery of the proposed increases through its existing base rate tariffs as follows:~~

Georgia Power's filing primarily reflects requests to (i) address the impacts of the Tax Reform Legislation, (ii) recover the costs of recent and future capital investments in infrastructure designed to maintain high levels of reliability and superior customer service with updated depreciation rates, (iii) recover substantial storm damage expenses incurred and deferred since 2013 along with a reasonable level of storm damage expenses expected to be incurred during the three years ending December 31, 2022, and (iv) recover the costs necessary to comply with federal and state regulations for CCR AROs. In addition, the filing includes the following provisions:

~~Georgia Power expects the Georgia PSC to issue a final order in this matter on December 17, 2019. The ultimate outcome of this matter cannot be determined at this time.~~

In 2016, the Georgia PSC approved Georgia Power's triennial IRP, including 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. In 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. In accordance with the Georgia PSC's order, costs incurred of approximately $50 million have been recorded as a regulatory asset.

On July 16, 2019, the Georgia PSC voted to approve Georgia Power's triennial IRP (Georgia Power 2019 IRP) as modified by a stipulated agreement among Georgia Power, the staff of the Georgia PSC, and certain intervenors and further modified by the Georgia PSC.

In the Georgia Power 2019 IRP, the Georgia PSC approved the decertification and retirement of Plant Hammond Units 1 through 4 (840 MWs) and Plant McIntosh Unit 1 (142.5 MWs) effective July 29, 2019. The Georgia PSC also approved the reclassification of the remaining net book values of the Plant Hammond and Plant McIntosh units (approximately $500 million and $40 million, respectively), as well as any unusable materials and supplies inventory balances, upon retirement to a regulatory asset. Recovery of each unit's net book value will continue through December 31, 2019 as provided in the 2013 ARP. Additionally, approximately $295 million of net capitalized asset retirement costs were reclassified to a regulatory asset.

For the regulatory asset balances remaining at December 31, 2019, Georgia Power requested recovery in the Georgia Power 2019 Base Rate Case as follows: (i) the net book values of Plant Mitchell Unit 3 (approximately $8 million at September 30, 2019) and Plant McIntosh Unit 1, any unusable materials and supplies inventory, and the future generation site in Stewart County, Georgia over a three-year period ending December 31, 2022 and (ii) the net book values of Plant Hammond Units 1 through 4 over a period equal to the applicable unit's remaining useful life through 2035. The timing of recovery of the related ARO costs will be determined in the Georgia Power 2019 Base Rate Case. The ultimate outcome of these matters cannot be determined at this time.

Also in the Georgia Power 2019 IRP, the Georgia PSC approved Georgia Power's proposed environmental compliance strategy associated with ash pond and certain landfill closures and post-closure care in compliance with the CCR Rule and the related state rule. In the Georgia Power 2019 Base Rate Case, Georgia Power requested recovery of the under recovered balance of these compliance costs at December 31, 2019 (approximately $157 million at September 30, 2019) over a three-year period ending December 31, 2022 and recovery of estimated compliance costs of $277 million for 2020, $395 million for 2021, and $655 million for 2022 over three-year periods ending December 31, 2022, 2023, and 2024, respectively. The ultimate outcome of this matter cannot be determined at this time. See Note 6 to the financial statements"Southern Power" in Item 8 of the Form 10-K, for additional information ~~regarding Georgia~~about costs relating to Southern Power's ~~AROs.~~

Additionally, the Georgia PSC rejected a request to certify approximately 25 MWs of capacity at Plant Scherer Unit 3 for the retail jurisdiction beginning January 1, 2020 following the expiration of a wholesale PPA. Georgia Power may offer such capacity in the wholesale market or to the retail jurisdiction in a future IRP. The ultimate outcome of this matter cannot be determined at this time but is not expected to have a material impact on Georgia Power's or Southern Company's financial statements.

~~The Georgia PSC also approved Georgia Power to (i) issue requests for proposals (RFP) for capacity beginning in 2022 or 2023 and in 2026, 2027, or 2028; (ii) procure up to an additional 2,210 MWs~~acquisitions that involve construction of renewable ~~resources~~energy facilities.

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.

In April 2019, Southern Nuclear ~~completed~~established aggressive target values for monthly construction production and system turnover activities as part of a strategy to maintain and, where possible, build margin to the regulatory-approved in-service dates of November 2021 for Unit 3 and November 2022 for Unit 4. Through early 2020, the project faced challenges with the April 2019 aggressive strategy targets including, but not limited to, electrical and pipefitting labor productivity and closure rates for work packages, which resulted in a backlog of activities and completion percentages below the April 2019 aggressive strategy targets.

craft construction productivity must improve and additional craft laborers (particularly electrical and pipefitter craft labor), as well as additional supervision and other field support resources, must4 cannot be ~~retained and deployed.~~determined at this time.

2022, respectively. In its January 11, 2018 order, the Georgia PSC also stated if other conditions change and assumptions upon which Georgia Power's seventeenth VCM report are based do not materialize, the Georgia PSC reserved the right to reconsider the decision to continue construction.

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

At September 30, 2019, Georgia Power had borrowed $3.46 billion related to Plant Vogtle Units 3 and 4 costs as provided through the Amended and Restated Loan Guarantee Agreement and related multi-advance credit facilities among Georgia Power, the DOE, and the FFB, which provide for borrowings of up to approximately $5.130 billion, subject to the satisfaction of certain conditions. See ~~Note 8 to the financial statements under "Long-term Debt – DOE Loan Guarantee Borrowings"~~RISK FACTORS in Item ~~8 of~~1A herein and in the Form 10-K for a discussion of certain risks associated with the licensing, construction, and ~~Note (F) under "DOE Loan Guarantee Borrowings" for additional information,~~operation of nuclear generating units, including ~~applicable covenants, events of default, mandatory prepayment events, and conditions to borrowing.~~potential impacts that could result from a major incident at a nuclear facility anywhere in the world.

~~On October 24, 2019, the Mississippi PSC approved Mississippi Power's July 9, 2019 request for a Certificate of Public Convenience~~Reading and Necessity to complete certain environmental compliance projects, primarily associated with the Plant Daniel coal units co-owned 50% with Gulf Power. The total estimated cost is approximately $125 million, with Mississippi Power's share of approximately $66 million being proposed for recovery through its ECO Plan. Approximately $17 million of Mississippi Power's share is associated with ash pond closure and is reflected in Mississippi Power's ARO liabilities. See Note 2 to the financial statements under "Mississippi Power – Environmental Compliance Overview Plan" in Item 8 of the Form 10-K for additional information on Mississippi Power's ECO Plan. See Note (A) under "Asset Retirement Obligations" for additional information on AROs and Note (C) under "Other Matters – Mississippi Power" for additional information on Gulf Power's ownership in Plant Daniel.

~~During the third quarter~~between $490 million and year-to-date 2019, Mississippi Power recorded pre-tax charges to income of $4 million ($3 million after tax) and $10 million ($7 million after tax), respectively, primarily resulting from the abandonment and related closure activities and ongoing period costs, net of sales proceeds, for the mine and gasifier-related assets at the Kemper County energy facility. Additional closure costs for the mine and gasifier-related assets, currently estimated at up to $10 million pre-tax (excluding dismantlement costs, net of salvage), may be incurred through the first half of 2020. In addition, period costs, including, but not limited to, costs for compliance and safety, ARO accretion, and property taxes for the mine and gasifier-related assets, are estimated at $3$535 million for the ~~remainder~~two facilities under construction. At March 31, 2020, total costs of ~~2019~~construction incurred for these projects were $447 million and ~~$2 million to $7 million annually~~are included in ~~2020 through 2023.~~

~~In addition, Mississippi Power constructed the CO~~₂ ~~pipeline for the planned transport of captured CO~~₂ ~~for use in enhanced oil recovery and is currently evaluating its options regarding the final disposition of the CO~~₂ ~~pipeline, including removal of the pipeline. This evaluation is expected to be complete by year-end 2019. If Mississippi Power ultimately decides to remove the CO~~₂ ~~pipeline, the cost of removal~~ ~~would have a material impact on Mississippi Power's financial statements and could have a material impact on Southern Company's financial statements.~~

In December 2018, Mississippi Power filed with the DOE its request for property closeout certification under the contract related to the $387 million of grants received. Mississippi Power and the DOE are currently in discussions regarding the requested closeout and property disposition, which may require payment to the DOE for a portion of certain property that is to be retained by Mississippi Power. In connection with the DOE closeout discussions, on April 29, 2019, the Civil Division of the Department of Justice informed Southern Company and Mississippi Power of an investigation related to the Kemper County energy facility.CWIP. The ultimate outcome of these matters cannot be determined at this ~~time; however, they could have a material impact on Mississippi Power's and Southern Company's financial statements.~~

Southern Company Gas is engaged in various infrastructure programs that update or expand its gas distribution systems to improve reliability and help ensure the safety of its utility infrastructure, and recovers in rates its investment and a return associated with these infrastructure programs. In addition to capital expenditures recovered through base rates by each of the natural gas distribution utilities, Nicor Gas and Virginia Natural Gas have separate rate riders that provide ~~for~~ timely recovery of capital expenditures for specific infrastructure replacement programs.

~~On April 8, 2019, Virginia Natural Gas filed an application with~~ Infrastructure expenditures incurred under these programs in the Virginia Commission to amend and extend its Steps to Advance Virginia's Energy program, which was approved by the Virginia Commission on September 25, 2019. The extension allows Virginia Natural Gas to continue replacing aging pipeline infrastructure through 2024

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. In 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. Also in 2017, the defendants filed a motion to dismiss the plaintiffs' amended complaint with prejudice, to which the plaintiffs filed an opposition. In ~~March~~ 2018, the court issued an order ~~granting, in part, the defendants' motion to dismiss. The court dismissed~~dismissing certain claims against certain officers of Southern Company and Mississippi Power and ~~dismissed~~dismissing the allegations related to a number of the statements that plaintiffs challenged as being false or misleading. In ~~April 2018, the defendants filed a motion for reconsideration of the court's order, seeking dismissal of the remaining claims in the lawsuit. In August~~ 2018, the court denied the defendants' motion for reconsideration and also denied a motion to certify the issue for interlocutory appeal. ~~On August 22,~~In the third quarter 2019, the court certified the plaintiffs' proposed ~~class. On September 5, 2019,~~class and the defendants filed a petition for interlocutory appeal of the class certification order with the U.S. Court of Appeals for the Eleventh Circuit. In December 2019, the U.S. District Court for the Northern District of Georgia entered an order staying all deadlines in the case pending mediation. The stay automatically expired on March 31, 2020; however, in light of the COVID-19 pandemic, the U.S. District Court for the Northern District of Georgia vacated all existing discovery deadlines until at least June 15, 2020.

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 in Illinois and Georgia have each 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 was $16 million and $23 million as of September 30, 2019 and December 31, 2018, 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.

Southern Company Gas' environmental remediation liability was $278 million and $294 million as of September 30, 2019 and December 31, 2018, 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~~it could have a material impact on ~~the financial statements of Southern Company, Georgia Power, or Southern Company Gas.~~

On May 17, 2019, the Alabama Department of Environmental Management (ADEM) issued a proposed administrative order assessing a penalty of $250,000 to Alabama Power for unpermitted discharge of fluids and/or pollutants to groundwater and/or soils at Plant Gadsden. The order was finalized and Alabama Power paid the penalty on September 16, 2019.

On October 16, 2019, Alabama Power agreed to a consent order regarding a fish kill investigation. The consent order requires Alabama Power to pay approximately $50,000 to ADEM in civil penalties and approximately $172,000 to the Alabama Department of Conservation and Natural Resources in fish restocking costs. The ultimate outcome of this matter cannot be determined at this time.

The Atlantic Coast Pipeline has experienced challenges to its permits since construction began in 2018. On October 4, 2019, the U.S. Supreme Court agreed to hear Atlantic Coast Pipeline's appeal of a lower court ruling that overturned a key permit for the project. The delays resulting from the permitting issues have impacted the cost and schedule for the project. As a result, total current project cost estimates have increased from between $7.0 billion and $7.8 billion ($350 million and $390 million for Southern Company Gas) to between $7.3 billion and $7.8 billion ($365 million and $390 million for Southern Company Gas), excluding financing costs. The operatorA portion of the ~~joint venture has indicated that it currently expects~~unused credit with banks is allocated to ~~complete construction by the end of 2021 and place the project in service shortly thereafter.~~

On September 10, 2019, an appellate court ruled that the PennEast Pipeline does not have federal court eminent domain authority over lands in which a state has property rights interests. The joint venture is pursuing appellate and other options and is evaluating further next steps.

~~Bank credit arrangements~~ provide liquidity support to the ~~registrants' commercial paper borrowings and~~revenue bonds of the traditional electric operating ~~companies' revenue bonds.~~companies and the commercial paper programs of the Registrants, Nicor Gas, and SEGCO. The amount of variable rate revenue bonds of the traditional electric operating companies outstanding requiring liquidity support ~~as of September 30, 2019~~at March 31, 2020 was approximately $1.4 billion (comprised of approximately $854 million at Alabama Power, $550 million at Georgia Power, and $40 million at Mississippi Power). Subsequent to March 31, 2020, Mississippi Power purchased and held or redeemed all $40 million of its variable rate revenue bonds. In addition, at ~~September 30, 2019, Alabama~~March 31, 2020, Georgia Power had approximately ~~$87~~$188 million of fixed rate revenue bonds outstanding that ~~were~~are required to be remarketed within the next 12 months.

Also in January 2019, through cash tender offers, Southern Company repurchased and retired approximately $522 million of the $1.0 billion aggregate principal amount outstanding of its 1.85% Senior Notes due July 1, 2019 (1.85% Notes), approximately $180 million of the $350 million aggregate principal amount outstanding of its Series 2014B 2.15% Senior Notes due September 1, 2019 (Series 2014B Notes), and approximately $504 million of the $750 million aggregate principal amount outstanding of its Series 2018A Floating Rate Notes due February 14, 2020 (Series 2018A Notes),called for an aggregate purchase price, excluding accrued and unpaid interest, of approximately $1.2 billion. In addition, following the completion of the cash tender offers, in February 2019, Southern Company completed the redemption of all ~~of the Series 2018A Notes, 1.85% Notes, and Series 2014B Notes remaining outstanding.~~

~~In September 2019, Southern Company redeemed all $300~~$600 million aggregate principal amount of its Series ~~2017A Floating Rate~~2015A 2.750% Senior Notes due ~~September 30,~~June 15, 2020.

In January ~~2019, Georgia Power redeemed approximately $13~~30, 2050, and an additional $300 million $20 million, and $75 million aggregate principal amount of Development Authority of Burke County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Vogtle Project), First Series 1992, Eighth Series 1994, and Second Series 1995, respectively.

~~In March 2019, Georgia Power reoffered to the public the following pollution control revenue bonds that previously had been purchased and held by Georgia Power:~~

~~In April 2019, Georgia Power purchased and held the following pollution control revenue bonds. In May 2019, Georgia Power reoffered these pollution control revenue bonds to the public.~~

In June 2019, Georgia Power reoffered to the public $55 million aggregate principal amount of Development Authority of Burke County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Vogtle Project), Fifth Series 1994, which previously had been purchased and held by Georgia Power.

~~Also in June 2019, Georgia Power entered into 2 short-term floating rate bank loans in aggregate principal amounts of $125 million each, both of which bear interest based on one-month LIBOR.~~

In August 2019, Georgia Power reoffered to the public approximately $72 million aggregate principal amount of Development Authority of Bartow County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Bowen Project), First Series 2013, which previously had been purchased and held by Georgia Power.

~~In September 2019, Georgia Power issued $400 million aggregate principal amount of Series 2019A 2.20% Senior Notes due September 15, 2024 and $350 million~~ aggregate principal amount of Series 2019B 2.65% Senior Notes due September 15, 2029.

~~In May 2019, Southern Power repaid at maturity a $100 million aggregate principal amount short-term bank loan.~~

~~In August 2019, Nicor Gas issued $200~~redeemed all $500 million aggregate principal amount of ~~first mortgage bonds~~its Series 2017C 2.00% Senior Notes due September 8, 2020.

For Southern Company, the only difference in computing basic and diluted earnings per share is attributable to awards outstanding under stock-based compensation plans and the Equity Units. Earnings per share dilution resulting from stock-based compensation plans and the Equity Units issuance is determined under the treasury stock method. See "~~Equity Units~~" herein for additional information and Note 12 to the financial statements in Item 8 of the Form 10-K for information on stock-based compensation plans. Shares used to compute diluted earnings per share were as follows:

The Equity Units issued in August 2019 were excluded from the calculation of diluted earnings per share for the three and nine months ended September 30, 2019 as the dilutive stock price threshold was not met.

Southern Company's effective tax rate is typically lower than the statutory rate due to employee stock plans' dividend deduction, non-taxable AFUDC equity and flowback of excess deferred income taxes at the regulated utilities, and federal income tax benefits from ITCs and PTCs, primarily at Southern Power.

Southern Company's effective tax rate was 30.2% for the nine months ended September 30, 2019 compared to 22.7% for the corresponding period in 2018. The effective tax rate increase was primarily due to the tax impact

from the sale of Gulf Power in 2019 and the reductions of tax benefits associated with wind PTCs following Southern Power's 2018 sale of a noncontrolling tax equity interest in its wind projects. The effective tax rate increase was partially offset by the tax impacts related to the Southern Company Gas Dispositions in 2018. See Note (K) for additional information.

Georgia Power's effective tax rate was 22.6% for the nine months ended September 30, 2019 compared to 25.5% for the corresponding period in 2018. The effective tax rate decrease was primarily due to an increase in state ITCs in 2019 related to the construction of Plant Vogtle Units 3 and 4 and the impact of recording a valuation allowance on certain state tax credit carryforwards in 2018, partially offset by additional benefits recorded in 2018 as a result of the Tax Reform Legislation.

Mississippi Power's effective tax rate was 16.3% for the nine months ended September 30, 2019 compared to 20.8% for the corresponding period in 2018. The effective tax rate decrease was primarily due to an increase in the flowback of excess deferred income taxes as a result of both a settlement agreement reached with wholesale customers under the MRA tariff and a new tolling arrangement accounted for as a sales-type lease. See Note (B) under "Mississippi Power" for additional information on the settlement agreement.

Southern Power's effective tax benefit rate was (13.6)% for the nine months ended September 30, 2019 compared to (220.3)% for the corresponding period in 2018. The effective tax benefit rate decrease primarily resulted from lower wind PTCs following the 2018 sale of a noncontrolling tax equity interest in SP Wind and changes in state apportionment rates following the 2018 reorganization of certain legal entities, partially offset by the net tax benefits from the sale of Plant Nacogdoches in 2019. See Note (K) and Note 15 to the financial statements in Item 8 of the Form 10-K under "Southern Power" for additional information.

Southern Company Gas' effective tax rate was 15.0% for the nine months ended September 30, 2019 compared to 61.8% for the corresponding period in 2018. This decrease was primarily related to an increase in the flowback of excess deferred income taxes in 2019, primarily at Atlanta Gas Light as previously authorized by the Georgia PSC, and the reversal of a federal tax valuation allowance in connection with Southern Company Gas' sale of Triton in 2019, as well as the tax impacts of the Southern Company Gas Dispositions in 2018. See Note (E) under "Southern Company Gas" and Notes 2 and 15 to the financial statements under ~~"Southern Company Gas"~~"Long-Term Debt – DOE Loan Guarantee Borrowings" in Item 8 of the Form 10-K for additional information.

The Southern Company system has a qualified defined benefit, trusteed, pension plan covering substantially all employees, with the exception of employees at PowerSecure. The qualified pension plan is fundedAlso in ~~accordance with requirements of the Employee Retirement Income Security Act of 1974, as amended (ERISA). NaN mandatory contributions~~March 2020, Georgia Power purchased and subsequently reoffered to the ~~qualified pension plan are anticipated for~~public approximately $53 million of pollution control revenue bonds.

On each registrant's condensed statements of income, the service cost component of net periodic benefit costs is included in other operations and maintenance expenses and all other components of net periodic benefit costs are included in other income (expense), net. Components of the net periodic benefit costs for the three and nine months ended September 30, 2019 and 2018 are presented in the following tables.

Three Months Ended
September 30, 2019
Southern
Company

Alabama
Power

Georgia
Power

Mississippi
Power
Southern Power Southern Company Gas
(in millions)
Pension Plans
Service cost $ 73
$ 17
$ 19
$ 3
$ 2
$ 7
Interest cost 123
28
38
6
1
9
Expected return on plan assets (222 ) (51 ) (73 ) (10 ) (2 ) (15 )
Amortization:
Prior service costs 1
—
—
—
—
(1 )
Regulatory asset —
—
—
—
—
3
Net (gain)/loss 30
9
11
1
—
1
Net periodic pension cost (income) $ 5
$ 3
$ (5 ) $ —
$ 1
$ 4
Postretirement Benefits
Service cost $ 5
$ 1
$ 2
$ 1
$ —
$ —
Interest cost 18
4
6
—
—
2
Expected return on plan assets (16 ) (6 ) (7 ) —
—
(1 )
Amortization:
Prior service costs —
1
—
—
—
—
Regulatory asset —
—
—
—
—
1
Net (gain)/loss (1 ) —
1
—
—
—
Net periodic postretirement benefit cost $ 6
$ —
$ 2
$ 1
$ —
$ 2

Three Months Ended
September 30, 2018
Southern
Company

Alabama
Power

Georgia
Power

Mississippi
Power
Southern Power Southern Company Gas
(in millions)
Pension Plans
Service cost $ 90

$ 19

$ 22

$ 5

$ 3

$ 8
Interest cost 116

26

34

5

1

10
Expected return on plan assets (236 )
(51 )
(74 )
(11 )
(3 )
(18 )
Amortization:
Prior service costs 1

—

1

—

—

(1 )
Regulatory asset —
—
—
—
—
4
Net (gain)/loss 53

13

18

3

—

3
Net periodic pension cost (income) $ 24

$ 7

$ 1

$ 2

$ 1

$ 6
Postretirement Benefits
Service cost $ 6
$ 1
$ 2
$ —
$ 1
$ —
Interest cost 19
5
7
—
—
2
Expected return on plan assets (17 ) (7 ) (6 ) —
—
(1 )
Amortization:
Prior service costs 2
1
—
—
—
—
Regulatory asset —
—
—
—
—
2
Net (gain)/loss 3
—
2
—
—
—
Net periodic postretirement benefit cost $ 13
$ —
$ 5
$ —
$ 1
$ 3

Nine Months Ended
September 30, 2018
Southern
Company

Alabama
Power

Georgia
Power

Mississippi
Power
Southern Power Southern Company Gas
(in millions)
Pension Plans
Service cost $ 269
$ 58
$ 65
$ 13
$ 7
$ 24
Interest cost 348
76
104
15
4
29
Expected return on plan assets (707 ) (155 ) (222 ) (31 ) (8 ) (53 )
Amortization:
Prior service costs 3
1
2
—
—
(2 )
Regulatory asset —
—
—
—
—
11
Net (gain)/loss 160
40
52
8
1
9
Net periodic pension cost (income) $ 73
$ 20
$ 1
$ 5
$ 4
$ 18
Postretirement Benefits
Service cost $ 18
$ 4
$ 5
$ 1
$ 1
$ 1
Interest cost 56
13
21
2
—
7
Expected return on plan assets (51 ) (20 ) (19 ) (1 ) —
(5 )
Amortization: ��
Prior service costs 5
3
1
—
—
—
Regulatory asset —
—
—
—
—
5
Net (gain)/loss 10
1
6
—
—
—
Net periodic postretirement benefit cost $ 38
$ 1
$ 14
$ 2
$ 1
$ 8

~~As of September 30, 2019, assets and liabilities measured at fair value on a recurring basis during the period, together with their associated level of the fair value hierarchy, were as follows:~~

Southern Company, Alabama Power, and Georgia Power continue to elect the option to fair value investment securities held in the nuclear decommissioning trust funds. The fair value of the funds, including reinvested interest and dividends and excluding the funds' expenses, increased (decreased) by the amounts shown in the table below for the three and nine months ended September 30, 2019 and 2018. The changes were recorded as a change to the regulatory assets and liabilities related to AROs for Georgia Power and Alabama Power, respectively.

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

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

The NRC requires licensees of commissioned nuclear power reactors to establish a plan for providing reasonable assurance of funds for future decommissioning. See Note 6 to the financial statements under "Nuclear Decommissioning" in Item 8 of the Form 10-K for additional information.

Southern Power has contingent payment obligations related to certain acquisitions whereby Southern Power is primarily obligated to make generation-based payments to the seller, which commenced at the commercial operation of the respective facility and continue through 2026. The obligation is categorized as Level 3 under Fair Value Measurements as the fair value is determined using significant unobservable inputs for the forecasted facility generation in MW-hours, as well as other inputs such as a fixed dollar amount per MW-hour, and a discount rate.

~~The fair value of contingent consideration reflects the net present value of expected payments and any periodic change arising from forecasted generation is expected to be immaterial.~~

As of September 30, 2019, the fair value measurements of private equity investments held in Alabama Power's nuclear decommissioning trusts that are calculated at net asset value per share (or its equivalent) as a practical expedient totaled $53 million and unfunded commitments related to the private equity investments totaled $54 million. Private equity funds include funds-of-funds that invest in high-quality private equity funds across several market sectors, funds that invest in real estate assets, and a fund that acquires companies to create resale value. Private equity funds do not have redemption rights. Distributions from these funds will be received as the underlying investments in the funds are liquidated.

~~The fair values are determined using Level 2 measurements and are based on quoted market prices for the same or similar issues or on the current rates available to Southern Company, Alabama Power,~~March 31, 2020, Georgia Power ~~Mississippi Power, Southern Power, and Southern Company Gas.~~borrowed the remaining $50 million pursuant to this bank credit arrangement.

~~The traditional electric operating companies, Southern Power, and~~March 2020, Southern Company Gas ~~enter into energy-related derivatives~~Capital borrowed approximately $95 million pursuant to hedge exposures to electricity, natural gas, and other fuel price changes. However, due to cost-based rate regulations and other various cost recovery mechanisms, the traditional electric operating companies and the natural gas distribution utilities have limited exposure to market volatility in energy-related commodity prices. Each of the traditional electric operating companies and certain of the natural gas distribution utilities ofa short-term uncommitted bank credit arrangement, guaranteed by Southern Company Gas, manage fuel-hedging programs, implemented per the guidelines of their respective state PSCs or other applicable state regulatory agencies, through the use of financial derivative contracts, which are expected to continue to mitigate price volatility. The traditional electric operating companies (with respect to wholesale generating capacity) and Southern Power have limited exposure to market volatility in energy-related commodity prices because their long-term sales contracts shift substantially all fuel cost responsibility to the purchaser. However, the traditional electric operating companies and Southern Power may be exposed to market volatility in energy-related commodity prices to the extent any uncontracted capacity is used to sell electricity.bearing interest at a rate agreed upon by Southern Company Gas ~~retains exposure to price changes that can, in a volatile energy market, be material and can adversely affect its results of operations.~~

Southern Company Gas also enters into weather derivative contracts as economic hedges of operating margins in the event of warmer-than-normal weather. Exchange-traded options are carried at fair value, with changes reflected in operating revenues. Non-exchange-traded options are accounted for using the intrinsic value method. Changes in the intrinsic value for non-exchange-traded contracts are reflected in operating revenues.

~~Energy-related derivative contracts are accounted for under one of three methods:~~

Some energy-related derivative contracts require physical delivery as opposed to financial settlement, and this type of derivative is both common and prevalent within the electric and natural gas industries. When an energy-related derivative contract is settled physically, any cumulative unrealized gain or loss is reversedCapital and the ~~contract price is recognized in~~bank from time to time and payable on demand, following specified notice by the ~~respective line item representing the actual price of the underlying goods being delivered.~~bank.

In addition to the volumes discussed above, the traditional electric operating companies and Southern Power enter into physical natural gas supply contracts that provide the option to sell back excess natural gas due to operational constraints. The maximum expected volume of natural gas subject to such a feature is 25 million mmBtu for Southern Company, which includes 4 million mmBtu for Alabama Power, 8 million mmBtu for Georgia Power, 4 million mmBtu for Mississippi Power, and 9 million mmBtu for Southern Power.

For cash flow hedges of energy-related derivatives, the estimated pre-tax gains (losses) expected to be reclassified from accumulated OCI to earnings for the 12-month period ending September 30, 2020 are immaterial for all registrants.

Southern Company and certain subsidiaries may enter into interest rate derivatives to hedge exposure to changes in interest rates. The derivatives employed as hedging instruments are structured to minimize ineffectiveness. Derivatives related to existing variable rate securities or forecasted transactions are accounted for as cash flow

hedges where the derivatives' fair value gains or losses are recorded in OCI and are reclassified into earnings at the same time and presented on the same income statement line item as the earnings effect of the hedged transactions. Derivatives related to existing fixed rate securities are accounted for as fair value hedges, where the derivatives' fair value gains or losses and hedged items' fair value gains or losses are both recorded directly to earnings on the same income statement line item. Fair value gains or losses on derivatives that are not designated or fail to qualify as hedges are recognized in the statements of income as incurred.

~~At September 30, 2019, the following interest rate derivatives were outstanding:~~

The estimated pre-tax gains (losses) related to interest rate derivatives expected to be reclassified from accumulated OCI to interest expense for the 12-month period ending September 30, 2020 total $(21) million for Southern Company and are immaterial for all other registrants. Deferred gains and losses related to interest rate derivatives are expected to be amortized into earnings through 2046 for the Southern Company parent entity, 2035 for Alabama Power, 2044 for Georgia Power, 2028 for Mississippi Power, and 2046 for Southern Company Gas.

~~The fair value of energy-related derivatives, interest rate derivatives, and foreign currency derivatives was reflected in the balance sheets as follows:~~

At September 30, 2019 and December 31, 2018, the pre-tax effects of unrealized derivative gains (losses) arising from energy-related derivative instruments designated as regulatory hedging instruments and deferred were as follows:

Regulatory Hedge Unrealized Gain (Loss) Recognized in the Balance Sheet at September 30, 2019
Derivative Category and Balance Sheet
Location
Southern
Company^(*)
Alabama
Power
Georgia
Power
Mississippi
Power
Southern Company Gas^(*)
(in millions)
Energy-related derivatives:
Other regulatory assets, current $ (55 ) $ (11 ) $ (27 ) $ (12 ) $ (5 )
Other regulatory assets, deferred (37 ) (8 ) (19 ) (10 ) —
Other regulatory liabilities, current 6
3
—
—
3
Total energy-related derivative gains (losses) $ (86 ) $ (16 ) $ (46 ) $ (22 ) $ (2 )

Regulatory Hedge Unrealized Gain (Loss) Recognized in the Balance Sheet at December 31, 2018
Derivative Category and Balance Sheet
Location
Southern
Company
Alabama
Power
Georgia
Power
Mississippi
Power
Southern Company Gas
(in millions)
Energy-related derivatives:
Other regulatory assets, current $ (19 ) $ (3 ) $ (6 ) $ (2 ) $ (8 )
Other regulatory assets, deferred (16 ) (3 ) (9 ) (4 ) —
Assets held for sale, current (6 ) —
—
—
—
Other regulatory liabilities, current 1
—
—
—
1
Total energy-related derivative gains (losses) $ (40 ) $ (6 ) $ (15 ) $ (6 ) $ (7 )

For the three and nine months ended September 30, 2019 and 2018, the pre-tax effects of energy-related derivatives and interest rate derivatives designated as cash flow hedging instruments on accumulated OCI were immaterial for the other registrants.

~~For the three and nine months ended September 30, 2019 and 2018, the pre-tax effects of cash flow and fair value hedge accounting on income were as follows:~~

Location and Amount of Gain (Loss) Recognized in Income on Cash Flow and Fair Value Hedging Relationships For the Three Months Ended September 30, For the Nine Months Ended September 30,

2019 2018 2019 2018
(in millions) (in millions)
Southern Company
Total depreciation and amortization $ 760
$ 787
$ 2,267
$ 2,338

Gain (loss) on energy-related cash flow hedges^(a)
(1 ) —
(5 ) 2
Total interest expense, net of amounts capitalized (434 ) (458 ) (1,294 ) (1,386 )

Gain (loss) on interest rate cash flow hedges^(a)
(5 ) (5 ) (14 ) (16 )

Gain (loss) on foreign currency cash flow hedges^(a)
(6 ) (6 ) (18 ) (18 )

Gain (loss) on interest rate fair value hedges^(b)
10
(4 ) 43
(35 )
Total other income (expense), net 61
57
239
195

Gain (loss) on foreign currency cash flow hedges^(a)(c)
(54 ) (9 ) (62 ) (46 )
Southern Power
Total depreciation and amortization $ 120
$ 130
$ 357
$ 370

Gain (loss) on energy-related cash flow hedges^(a)
(1 ) —
(5 ) 2
Total interest expense, net of amounts capitalized (43 ) (45 ) (127 ) (138 )

Gain (loss) on foreign currency cash flow hedges^(a)
(6 ) (6 ) (18 ) (18 )
Total other income (expense), net 6
17
48
22

Gain (loss) on foreign currency cash flow hedges^(a)(c)
(54 ) (9 ) (62 ) (46 )

For the three and nine months ended September 30, 2019 and 2018, the pre-tax effects of cash flow and fair value hedge accounting on income for energy-related derivatives and interest rate derivatives were immaterial for the traditional electric operating companies and Southern Company Gas.

~~As of September 30, 2019 and December 31, 2018, the following amounts were recorded on the balance sheets related to cumulative basis adjustments for fair value hedges:~~

Carrying Amount of the Hedged Item Cumulative Amount of Fair Value Hedging Adjustment included in Carrying Amount of the Hedged Item
Balance Sheet Location of Hedged Items As of September 30, 2019 As of December 31, 2018
As of September 30, 2019 As of December 31, 2018

(in millions) (in millions)
Southern Company
Securities due within one year $ (500 ) $ (498 ) $ —
$ 2
Long-term debt (2,093 ) (2,052 ) (2 ) 41

Georgia Power
Securities due within one year $ (500 ) $ (498 ) $ —
$ 2

For the three and nine months ended September 30, 2019 and 2018, the pre-tax effects of energy-related derivatives not designated as hedging instruments on the statements of income of Southern Company and Southern Company Gas were as follows:

For the three and nine months ended September 30, 2019 and 2018, the pre-tax effects of energy-related derivatives and interest rate derivatives not designated as hedging instruments were immaterial for the traditional electric operating companies and Southern Power.

~~Southern Company, the traditional electric operating companies, Southern Power, and Southern Company Gas do~~Registrants did not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade.

~~For the registrants with~~BBB and/or Baa2 or below. These contracts are for physical electricity and natural gas purchases and sales, fuel purchases, fuel transportation and storage, energy price risk management, transmission, interest rate ~~derivatives~~management, and, for Georgia Power, construction of new generation at ~~September 30, 2019, the fair value~~Plant Vogtle Units 3 and 4.

rating change to below investment grade. Following the sale of Gulf Power to NextEra Energy, Gulf Power is continuing to participate in the Southern Company power pool for a defined transition period that, subject to certain potential adjustments, is scheduled to end on January 1, 2024.

Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. ~~If collateral is required, fair value amounts recognized for~~Additionally, a credit rating downgrade could impact the ~~right to reclaim cash collateral or the obligation to return cash collateral are not offset against fair value amounts recognized for derivatives executed with the same counterparty.~~

~~Alabama Power and Southern Power maintain accounts with certain regional transmission organizations to facilitate financial derivative transactions. Based on the value~~ability of the ~~positions in these accounts~~Registrants to access capital markets and would be likely to impact the ~~associated margin requirements, Alabama Power and Southern Power may be required to post collateral. At September 30, 2019, cash collateral posted in these accounts was immaterial.~~cost at which they do so.

~~The registrants are exposed to losses related to financial instruments~~recent volatility in the ~~event of counterparties' nonperformance. The registrants only enter into agreements~~financial markets resulting from the COVID-19 pandemic and ~~material transactions with counterparties that have investment grade credit ratings by Moody's~~Notes (I) and ~~S&P or with counterparties who have posted collateral~~(J) to ~~cover potential credit exposure. The registrants have also established risk management policies and controls~~the Condensed Financial Statements herein for information relating to determine and monitor the creditworthiness of counterparties in order to mitigate their exposure to counterparty credit risk. Prior to entering into a physical transaction, Southern Company Gas assigns physical wholesale counterparties an internal credit rating and credit limit based on the counterparties' Moody's, S&P, and Fitch Ratings Inc. ratings, commercially available credit reports, and audited financial statements. Southern Company Gas may require counterparties to pledge additional collateral when deemed necessary.

In addition, Southern Company Gas conducts credit evaluations and obtains appropriate internal approvals for the counterparty's line of credit before any transaction with the counterparty is executed. In most cases, the counterparty must have an investment grade rating, which includes a minimum long-term debt rating of Baa3 from Moody's and BBB- from S&P. Generally, Southern Company Gas requires credit enhancements by way of a guaranty, cash deposit, or letter of credit for transaction counterparties that do not have investment grade ratings.derivative instruments.

~~The registrants do not anticipate a material adverse effect on~~ their respective ~~financial statements~~state regulatory agencies to hedge the impact of market fluctuations in natural gas prices for customers. In addition, certain non-regulated operations routinely utilize various types of derivative instruments to economically hedge certain commodity price and weather risks inherent in the natural gas industry. These instruments include a variety of exchange-traded and over-the-counter energy contracts, such as ~~a result~~forward contracts, futures contracts, options contracts, and swap agreements. Some of ~~counterparty nonperformance.~~

During the third quarter 2019, Southern Power acquired a controlling interest in the fuel cell generation facility listed below. Acquisition-related costs were expensed as incurred and were not material.

Southern Power continues to evaluate and refine the deployment of wind turbine equipment purchased in 2016 and 2017 to potential joint development and construction projects as well as the amount of MW capacity to be constructed. During 2019, certain wind turbine equipment was sold, resulting in gains totaling approximately $17 million.

~~On June 13, 2019, Southern Power completed the sale of its equity interests in Nacogdoches Power, LLC, the owner of an approximately 115-MW biomass facility located in Nacogdoches County, Texas,~~Index to ~~Austin Energy, for a cash purchase price of approximately $461 million. This sale resulted in an $88 million after-tax gain.~~

In November 2018, Southern Power entered into an agreement with Northern States Power (a subsidiary of Xcel) to sell all of its equity interests in Plant Mankato for an aggregate purchase price of approximately $650 million, subject to certain state commission approvals. On September 27, 2019, the Minnesota Public Utilities Commission denied approval of the transaction. A newly-formed subsidiary of Xcel has agreed to purchase all of the equity interests in Plant Mankato subject to FERC approval and other customary conditions to closing. The transaction is expected to close by January 20, 2020. If the transaction does not close by this date, either party may terminate the transaction, which would result in the payment of a termination fee to Southern Power of up to $25 million. The ultimate outcome of this matter cannot be determined at this time. The assets and liabilities of Plant Mankato are classified as assets held for sale and liabilities held for sale on Southern Company's and Southern Power's balance sheets as of September 30, 2019 and December 31, 2018. See "~~Assets Held for Sale" herein for additional information.~~

~~Under the terms of the PPAs for Plant Mankato, approximately $545 million of assets, primarily related to property, plant, and equipment, are subject to lien at September 30, 2019.~~

~~On January 1, 2019, the registrants adopted the provisions of FASB ASC Topic 842 (as amended),~~ ~~Leases~~ (ASC 842), which require lessees to recognize leases with a term of greater than 12 months on the balance sheet as lease obligations, representing the discounted future fixed payments due, along with right-of-use (ROU) assets that will be amortized over the term of each lease.

The registrants elected the transition methodology provided by ASC 842, whereby the applicable requirements are applied on a prospective basis as of the adoption date of January 1, 2019, without restating prior periods. The registrants also elected the package of practical expedients provided by ASC 842 that allows prior determinations of whether existing contracts are, or contain, leases and the classification of existing leases to continue without reassessment. Additionally, the registrants applied the use-of-hindsight practical expedient in determining lease terms as of the date of adoption and elected the practical expedient that allows existing land easements not previously accounted for as leases not to be reassessed.

As lessee, the registrants lease certain electric generating units (including renewable energy facilities), real estate/land, communication towers, railcars, and other equipment and vehicles. The major categories of lease obligations are as follows:

Real estate/land leases primarily consist of commercial real estate leases at Southern Company, Georgia Power, and Southern Company Gas and various land leases primarily associated with renewable energy facilities at Southern

~~Power. The commercial real estate leases have remaining terms of up to 25 years while the land leases have remaining terms of up to 47 years, including renewal periods.~~

Communication towers are leased for the installation of equipment to provide cellular phone service to customers and to support the automated meter infrastructure programs at the traditional electric operating companies. Communication tower leases have terms of up to 10 years with options to renew for periods up to 20 years.

While renewal options exist in many of the leases, other than for land leases associated with renewable energy facilities, the expected term used in calculating the lease obligation generally reflects only the noncancelable period of the lease as it is not considered reasonably certain that the lease will be extended. The expected term of land leases associated with renewable energy facilities includes renewal periods reasonably certain of exercise resulting in an expected lease term at least equal to the expected life of the renewable energy facilities.

While not specifically structured as a lease, some of the PPAs at Alabama Power and Georgia Power are deemed to represent a lease of the underlying electric generating units when the terms of the PPA convey the right to control the use of the underlying assets. Amounts recorded for leases of electric generating units are generally based on the amount of scheduled capacity payments due over the remaining term of the affiliate PPA, which varies between three and 18 years. Georgia Power has several PPAs with Southern Power that Georgia Power accounts for as leases with a lease obligation of approximately $625 million at September 30, 2019. The amount paid for energy under these affiliate PPAs reflects a price that would be paid in an arm's-length transaction as those amounts have been reviewed and approved by the Georgia PSC.

During the third quarter 2019, Alabama Power entered into additional long-term PPAs totaling approximately 640 MWs of additional generating capacity consisting of combined cycle generation expected to commence in 2020 and solar generation coupled with battery energy storage systems expected to commence in 2022 through 2024. Both the combined cycle PPA and the battery storage system portion of the solar generation PPAs are deemed operating leases. The estimated minimum lease payments for these agreements total $95 million. See Note (B) under "~~Alabama Power" for additional information.~~

~~Leases with an initial term of 12 months or less are not recorded on the balance sheet; the registrants generally recognize lease expense for these leases on a straight-line basis over the lease term.~~

Residual value guarantees exist primarily in railcar leases at Alabama Power and Georgia Power and the amounts probable of being paid under those guarantees are included in the lease payments. All such amounts are immaterial as of September 30, 2019.

For all asset categories, with the exception of electric generating units, gas pipelines, and real estate leases, the registrants combine lease payments and any nonlease components, such as asset maintenance, for purposes of calculating the lease obligation and the right-of-use asset.

~~Balance sheet amounts recorded for operating and finance leases are as follows:~~

Lease costs for the three and nine months ended September 30, 2019, which includes both amounts recognized as operations and maintenance expense and amounts capitalized as part of the cost of another asset, are as follows:

~~Georgia Power has variable lease payments that are based on the amount of energy produced by certain renewable generating facilities subject to PPAs.~~

~~Other information with respect to cash and noncash activities related to leases, as well as weighted-average lease terms and discount rates, is as follows:~~

~~Maturities of lease liabilities are as follows:~~

Payments made under PPAs at Georgia Power for energy generated from certain renewable energy facilities accounted for as operating and finance leases are considered variable lease costs and are therefore not reflected in the above maturity analysis.

~~As of September 30, 2019, Alabama Power and Southern Power have additional operating leases that have not yet commenced, as detailed in the following table:~~

~~For additional information on each registrant's operating lease obligations at December 31, 2018, see Note 9 to the financial statements in Item 8 of the Form 10-K.~~

With the exception of Southern Company Gas, the registrants are each considered lessors in various arrangements that have been determined to contain a lease due to the customer's ability to control the use of the underlying asset

owned by the applicable registrant. For the traditional electric operating companies, these arrangements consist of outdoor lighting contracts accounted for as operating leases with initial terms of up to seven years, after which the contracts renew on a month-to-month basis at the customer's option. For Mississippi Power, these arrangements also include tolling arrangements related to electric generating units accounted for as sales-type leases with terms of up to 20 years. For Southern Power, these arrangements consist of PPAs related to electric generating units, including renewable energy facilities, accounted for as operating leases with terms of up to 28 years. For Southern Company, these arrangements also include PPAs related to fuel cells accounted for as operating leases with terms of up to 15 years. Southern Company Gas is the lessor in operating leases related to gas pipelines with remaining terms of up to 24 years.

~~Lease income for the three and nine months ended September 30, 2019 is as follows:~~

~~No profit or loss was recognized by Mississippi Power upon commencement of a sales-type lease during the first quarter 2019.~~

Lease income for Southern Power is included in wholesale revenues. Lease payments received under tolling arrangements and PPAs consist of either scheduled payments or variable payments based on the amount of energy produced by the underlying electric generating units. Scheduled payments to be received under outdoor lighting contracts, tolling arrangements, and PPAs accounted for as leases are presented in the following maturity analyses.

~~The undiscounted cash flows to be received under tolling arrangements accounted for as sales-type leases are as follows:~~

~~The undiscounted cash flows to be received under operating leases and contracts accounted for as operating leases (adjusted for intercompany eliminations) are as follows:~~

The primary businesses of the Southern Company system are electricity sales by the traditional electric operating companies and Southern Power and the distribution of natural gas by Southern Company Gas. The traditional electric operating companies – Alabama Power, Georgia Power, and Mississippi Power – are vertically integrated utilities providing electric service in 3 Southeastern states. Southern Power develops, constructs, acquires, owns, and manages power generation assets, including renewable energy projects, and sells electricity at market-based rates in the wholesale market. Southern Company Gas distributes natural gas through its natural gas distribution utilities and is involved in several other complementary businesses including gas pipeline investments, wholesale gas services, and gas marketing services.

Southern Company's reportable business segments are the sale of electricity by the traditional electric operating companies, the sale of electricity in the competitive wholesale market by Southern Power, and the sale of natural gas and other complementary products and services by Southern Company Gas. Revenues from sales by Southern Power to the traditional electric operating companies were $116 million and $320 million for the three and nine months ended September 30, 2019, respectively, and $134 million and $326 million for the three and nine months ended September 30, 2018, respectively. Revenues from sales of natural gas from Southern Company Gas to the traditional electric operating companies were $9 million and $13 million for the three and nine months ended September 30, 2019, respectively, and $14 million and $22 million for the three and nine months ended September 30, 2018, respectively. Revenues from sales of natural gas from Southern Company Gas to Southern Power were $20 million and $53 million for the three and nine months ended September 30, 2019, respectively, and $38 million and $96 million for the three and nine months ended September 30, 2018, respectively. The "All Other" column includes the Southern Company parent entity, which does not allocate operating expenses to business segments. Also, this category includes segments below the quantitative threshold for separate disclosure. These segments include providing energy solutions, such as distributed energy infrastructure and energy efficiency products and services, to customers, as well as investments in telecommunications and leveraged lease projects. All other inter-segment revenues are not material.

Financial ~~data for business segments and products and services for the three and nine months ended September 30, 2019 and 2018 was as follows:~~



Registrant	Title of Each Class	Trading Symbol(s)	Name of Each Exchange on Which Registered
The Southern Company	Common Stock, par value $5 per share	SO	New York Stock Exchange
The Southern Company	Common Stock, par value $5 per share	SO	(NYSE)
The Southern Company	Series 2015A 6.25% Junior Subordinated Notes due 2075	SOJA	NYSE
The Southern Company	Series 2016A 5.25% Junior Subordinated Notes due 2076	SOJB	NYSE
The Southern Company	Series 2017B 5.25% Junior Subordinated Notes due 2077	SOJC	NYSE
The Southern Company	2019 Series A Corporate Units	SOLN	NYSE
The Southern Company	Series 2020A 4.95% Junior Subordinated Notes due 2080	SOJD	NYSE
Alabama Power Company	5.00% Series Class A Preferred Stock	ALP PR Q	NYSE
Georgia Power Company	Series 2017A 5.00% Junior Subordinated Notes due 2077	GPJA	NYSE
Southern Power Company	Series 2016A 1.000% Senior Notes due 2022	SO/22B	NYSE
Southern Power Company	Series 2016B 1.850% Senior Notes due 2026	SO/26A	NYSE



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



Registrant	Description of Common Stock	Shares Outstanding at ~~September 30, 2019~~March 31, 2020
The Southern Company	Par Value $5 Per Share	~~1,048,733,989~~1,055,955,711
Alabama Power Company	Par Value $40 Per Share	30,537,500
Georgia Power Company	Without Par Value	9,261,500
Mississippi Power Company	Without Par Value	1,121,000
Southern Power Company	Par Value $0.01 Per Share	1,000
Southern Company Gas	Par Value $0.01 Per Share	100



		Page ~~Number~~

	~~DEFINITIONS~~Definitions	54
	~~CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION~~Cautionary Statement Regarding Forward-Looking Information	98

	PART I—FINANCIAL INFORMATION
~~Item 1.~~	~~Financial Statements (Unaudited)~~
Item 2.	~~Management's Discussion and Analysis of Financial Condition and Results of Operations~~
1.	~~The Southern Company and Subsidiary Companies~~
	~~Condensed Consolidated~~Financial Statements ~~of Income~~(Unaudited)	1210
	~~Condensed Consolidated Statements of Comprehensive Income~~	13
	~~Condensed Consolidated Statements of Cash Flows~~	14
	~~Condensed Consolidated Balance Sheets~~	15
	~~Condensed Consolidated Statements of Stockholders' Equity~~	17
Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	19
	~~Alabama Power Company~~
	~~Condensed Statements of Income~~	56
	~~Condensed Statements of Comprehensive Income~~	56
	~~Condensed Statements of Cash Flows~~	57
	~~Condensed Balance Sheets~~	58
	~~Condensed Statements of Common Stockholder's Equity~~	60
	~~Management's Discussion and Analysis of Financial Condition and Results of Operations~~	61
	~~Georgia Power Company~~
	~~Condensed Statements of Income~~	75
	~~Condensed Statements of Comprehensive Income~~	75
	~~Condensed Statements of Cash Flows~~	76
	~~Condensed Balance Sheets~~	77
	~~Condensed Statements of Common Stockholder's Equity~~	79
	~~Management's Discussion and Analysis of Financial Condition and Results of Operations~~	80
	~~Mississippi Power Company~~
	~~Condensed Statements of Income~~	~~103~~
	~~Condensed Statements of Comprehensive Income~~	~~103~~
	~~Condensed Statements of Cash Flows~~	~~104~~
	~~Condensed Balance Sheets~~	~~105~~
	~~Condensed Statements of Common Stockholder's Equity~~	~~107~~
	~~Management's Discussion and Analysis of Financial Condition and Results of Operations~~	~~108~~
	~~Southern Power Company and Subsidiary Companies~~
	~~Condensed Consolidated Statements of Income~~	~~123~~
	~~Condensed Consolidated Statements of Comprehensive Income~~	~~123~~
	~~Condensed Consolidated Statements of Cash Flows~~	~~124~~
	~~Condensed Consolidated Balance Sheets~~	~~125~~
	~~Condensed Consolidated Statements of Stockholders' Equity~~	~~127~~
	~~Management's Discussion and Analysis of Financial Condition and Results of Operations~~	~~129~~



		Page Number
	~~PART I—FINANCIAL INFORMATION (CONTINUED)~~
	~~Southern Company Gas and Subsidiary Companies~~
	~~Condensed Consolidated Statements of Income~~	~~143~~
	~~Condensed Consolidated Statements of Comprehensive Income~~	~~143~~
	~~Condensed Consolidated Statements of Cash Flows~~	~~144~~
	~~Condensed Consolidated Balance Sheets~~	~~145~~
	~~Condensed Consolidated Statements of Stockholder's Equity~~	~~147~~
	~~Management's Discussion and Analysis of Financial Condition and Results of Operations~~	~~148~~
	~~Notes to the Condensed Financial Statements~~	~~173~~91
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	54151
Item 4.	Controls and Procedures	54151

	PART II—OTHER INFORMATION

Item 1.	Legal Proceedings	~~249~~152
Item 1A.	Risk Factors	~~249~~152
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	Inapplicable
Item 3.	Defaults Upon Senior Securities	Inapplicable
Item 4.	Mine Safety Disclosures	Inapplicable
Item 5.	Other Information	Inapplicable
Item 6.	Exhibits	~~249~~153

	Signatures	~~252~~156



Commission File Number	Registrant, State of Incorporation, Address and Telephone Number	I.R.S. Employer Identification No.



Term	Meaning
2013 ARP	~~Alternative~~Alternate Rate Plan approved by the Georgia PSC in 2013 for Georgia Power for the years 2014 through 2016 and subsequently extended through 2019
2019 ARP	Alternate Rate Plan approved by the Georgia PSC in 2019 for Georgia Power for the years 2020 through 2022
AFUDC	Allowance for funds used during construction
Alabama Power	Alabama Power Company
Amended and Restated Loan Guarantee Agreement	Loan guarantee agreement entered into by Georgia Power with the DOE in 2014, as amended and restated onin March ~~22,~~ 2019, under which the proceeds of borrowings may be used to reimburse Georgia Power for Eligible Project Costs incurred in connection with its construction of Plant Vogtle Units 3 and 4
ARO	Asset retirement obligation
~~ASC~~	~~Accounting Standards Codification~~
ASU	Accounting Standards Update
Atlanta Gas Light	Atlanta Gas Light Company, a wholly-owned subsidiary of Southern Company Gas
Atlantic Coast Pipeline	Atlantic Coast Pipeline, LLC, a joint venture to construct and operate a natural gas pipeline in which Southern Company Gas ~~has~~held a 5% ~~ownership~~ interest through March 24, 2020
Autauga Combined Cycle Acquisition	The purchase and sale agreement entered into in September 2019 by Alabama Power to acquire all of the equity interest in Tenaska Alabama Partners, L.P., the owner and operator of an approximately 885-MW combined cycle generation facility in Autauga County, Alabama
Bechtel	Bechtel Power Corporation, the primary contractor for the remaining construction activities for Plant Vogtle Units 3 and 4
Bechtel Agreement	The October 23, 2017 construction completion agreement between the Vogtle Owners and Bechtel
~~CCN~~	~~Certificate of convenience and necessity~~
CCR	Coal combustion residuals
CCR Rule	Disposal of Coal Combustion Residuals from Electric Utilities final rule published by the EPA in 2015
Chattanooga Gas	Chattanooga Gas Company, a wholly-owned subsidiary of Southern Company Gas
CO₂	~~Carbon dioxide~~
COD	Commercial operation date
Contractor Settlement Agreement	The December 31, 2015 agreement between Westinghouse and the Vogtle Owners resolving disputes between the Vogtle Owners and the EPC Contractor under the Vogtle 3 and 4 Agreement
~~Cooperative Energy~~COVID-19	~~Electric cooperative in Mississippi~~
~~CPP~~	~~Clean Power Plan, the final action published~~The novel coronavirus disease declared a pandemic by the ~~EPA~~World Health Organization and the Centers for Disease Control and Prevention in ~~2015 that established guidelines for states to develop plans to meet EPA-mandated CO~~₂ ~~emission rates or emission reduction goals for existing electric generating units~~
~~Customer Refunds~~	~~Refunds issued to Georgia Power customers in 2018 as ordered by the Georgia PSC related to the Guarantee Settlement Agreement~~March 2020
CWIP	Construction work in progress
Dalton	City of Dalton, Georgia, an incorporated municipality in the State of Georgia, acting by and through its Board of Water, Light, and Sinking Fund Commissioners
Dalton Pipeline	A pipeline facility in Georgia in which Southern Company Gas has a 50% undivided ownership interest
DOE	U.S. Department of Energy
~~DSGP~~	~~Diamond State Generation Partners~~
ECO Plan	Mississippi Power's environmental compliance overview plan
Eligible Project Costs	Certain costs of construction relating to Plant Vogtle Units 3 and 4 that are eligible for financing under the loan guarantee program established under Title XVII of the Energy Policy Act of 2005
EPA	U.S. Environmental Protection Agency
EPC Contractor	Westinghouse and its affiliate, WECTEC Global Project Services Inc.; the former engineering, procurement, and construction contractor for Plant Vogtle Units 3 and 4
FASB	Financial Accounting Standards Board
FERC	Federal Energy Regulatory Commission
FFB	Federal Financing Bank
FFB Credit Facilities	Note purchase agreements among the DOE, Georgia Power, and the FFB and related promissory notes which provide for two multi-advance term loan facilities



Term	Meaning
~~FFB~~	~~Federal Financing Bank~~
Fitch	Fitch Ratings, Inc.
Form 10-K	Annual Report on Form 10-K of Southern Company, Alabama Power, Georgia Power, Mississippi Power, Southern Power, and Southern Company Gas for the year ended December 31, ~~2018,~~2019, as applicable
GAAP	U.S. generally accepted accounting principles
Georgia Power	Georgia Power Company
~~GHG~~Georgia Power 2019 IRP	~~Greenhouse gas~~Georgia Power's modified triennial integrated resource plan approved by the Georgia PSC in July 2019
Guarantee Settlement Agreement	The June 9, 2017 settlement agreement between the Vogtle Owners and Toshiba related to certain payment obligations of the EPC Contractor guaranteed by Toshiba
Gulf Power	Gulf Power Company, until January 1, 2019 a wholly-owned subsidiary of Southern Company
Heating Degree Days	A measure of weather, calculated when the average daily temperatures are less than 65 degrees Fahrenheit
Heating Season	The period from November through March when Southern Company Gas' natural gas usage and operating revenues are generally higher
HLBV	Hypothetical liquidation at book value
IGCC	Integrated coal gasification combined cycle, the technology originally approved for Mississippi Power's Kemper County energy facility (Plant Ratcliffe)
IIC	Intercompany Interchange Contract
~~Illinois Commission~~	~~Illinois Commerce Commission~~
~~IRP~~	~~Integrated resource plan~~
ITAAC	Inspections, Tests, Analyses, and Acceptance Criteria, standards established by the NRC
ITC	Investment tax credit
JEA	Jacksonville Electric Authority
KWH	Kilowatt-hour
LIBOR	London Interbank Offered Rate
LIFO	Last-in, first-out
LOCOM	Lower of weighted average cost or current market price
LTSA	Long-term service agreement
Marketers	Marketers selling retail natural gas in Georgia and certificated by the Georgia PSC
MEAG Power	Municipal Electric Authority of Georgia
Mississippi Power	Mississippi Power Company
mmBtu	Million British thermal units
Moody's	Moody's Investors Service, Inc.
MRA	Municipal and Rural Associations
MW	Megawatt
natural gas distribution utilities	Southern Company Gas' natural gas distribution utilities (Nicor Gas, Atlanta Gas Light, Virginia Natural Gas, ~~Elizabethtown Gas, Florida City Gas, Chattanooga Gas, and Elkton Gas as of June 30, 2018) (Nicor Gas, Atlanta Gas Light, Virginia Natural Gas,~~ and Chattanooga ~~Gas as of July 29, 2018)~~Gas)
NCCR	Georgia Power's Nuclear Construction Cost Recovery
NDR	Alabama Power's Natural Disaster Reserve
NextEra Energy	NextEra Energy, Inc.
Nicor Gas	Northern Illinois Gas Company, a wholly-owned subsidiary of Southern Company Gas
NRC	U.S. Nuclear Regulatory Commission
NYMEX	New York Mercantile Exchange, Inc.
~~OATT~~	~~Open access transmission tariff~~
OCI	Other comprehensive income
PennEast Pipeline	PennEast Pipeline Company, LLC, a joint venture to construct and operate a natural gas pipeline in which Southern Company Gas has a 20% ownership interest
PEP	Mississippi Power's Performance Evaluation Plan



Term	Meaning
~~PEP~~Pivotal LNG	~~Mississippi Power's Performance Evaluation Plan~~
Pivotal ~~Home Solutions~~	~~Nicor Energy Services Company, until June 4, 2018~~LNG, Inc., through March 24, 2020 a wholly-owned subsidiary of Southern Company Gas ~~doing business as Pivotal Home Solutions~~
~~Pivotal Utility Holdings~~PowerSecure	~~Pivotal Utility Holdings,~~PowerSecure, Inc., ~~until July 29, 2018~~ a wholly-owned subsidiary of Southern Company ~~Gas, doing business as Elizabethtown Gas (until July 1, 2018), Elkton Gas (until July 1, 2018), and Florida City Gas~~
~~PowerSecure~~	~~PowerSecure, Inc.~~
~~power pool~~	The operating arrangement whereby the integrated generating resources of the traditional electric operating companies and Southern Power (excluding subsidiaries) are subject to joint commitment and dispatch in order to serve their combined load obligations
PPA	Power purchase agreements, as well as, for Southern Power, contracts for differences that provide the owner of a renewable facility a certain fixed price for the electricity sold to the grid
PSC	Public Service Commission
PTC	Production tax credit
Rate CNP	Alabama Power's Rate Certificated New Plant, consisting of Rate CNP New Plant, Rate CNP Compliance, and Rate CNP PPA
Rate ECR	Alabama Power's Rate Energy Cost Recovery
Rate NDR	Alabama Power's Rate Natural Disaster Reserve
Rate RSE	Alabama Power's Rate Stabilization and Equalization
~~registrants~~Registrants	Southern Company, Alabama Power, Georgia Power, Mississippi Power, Southern Power Company, and Southern Company Gas
~~revenue from contracts with customers~~	~~Revenue from contracts accounted for under the guidance of ASC 606, Revenue from Contracts with Customers~~
ROE	Return on equity
S&P	S&P Global Ratings, a division of S&P Global Inc.
SCS	Southern Company Services, Inc. ~~(the~~, the Southern Company system service ~~company)~~company and a wholly-owned subsidiary of Southern Company
SEC	U.S. Securities and Exchange Commission
SNG	Southern Natural Gas Company, L.L.C., a pipeline system in which Southern Company Gas has a 50% ownership interest
Southern Company	The Southern Company
Southern Company Gas	Southern Company Gas and its subsidiaries
Southern Company Gas Capital	Southern Company Gas Capital Corporation, a 100%-owned subsidiary of Southern Company Gas
Southern Company ~~Gas Dispositions~~power pool	The operating arrangement whereby the integrated generating resources of the traditional electric operating companies and Southern ~~Company Gas' disposition of Pivotal Home Solutions, Pivotal Utility Holdings' disposition of Elizabethtown Gas~~Power (excluding subsidiaries) are subject to joint commitment and ~~Elkton Gas, and NUI Corporation's disposition of Pivotal Utility Holdings, which primarily consisted of Florida City Gas~~dispatch in order to serve their combined load obligations
Southern Company system	Southern Company, the traditional electric operating companies, Southern Power, Southern Company Gas, Southern Electric Generating Company, Southern Nuclear, SCS, Southern Communications Services, Inc., PowerSecure, and other subsidiaries
Southern Nuclear	Southern Nuclear Operating Company, Inc., a wholly-owned subsidiary of Southern Company
Southern Power	Southern Power Company and its subsidiaries
SP Solar	SP Solar Holdings I, LP, a limited partnership indirectly owning substantially all of Southern Power's solar facilities, in which Southern Power has a 67% ownership interest
SP Wind	SP Wind Holdings II, LLC, a holding company owning a portfolio of eight operating wind facilities, in which Southern Power is the controlling partner in a tax equity arrangement
Subsidiary Registrants	Alabama Power, Georgia Power, Mississippi Power, Southern Power, and Southern Company Gas
Tax Reform ~~Legislation~~	The impact of the Tax Cuts and Jobs Act, which became effective on January 1, 2018
Toshiba	Toshiba Corporation, the parent company of Westinghouse
traditional electric operating companies	Alabama Power, Georgia Power, ~~Gulf Power,~~ and Mississippi Power ~~through December 31, 2018; Alabama Power, Georgia Power, and Mississippi Power as of January 1, 2019~~
Triton	Triton Container Investments, LLC, an investment of Southern Company Gas through May 29, 2019
VCM	Vogtle Construction Monitoring
VIE	Variable interest entity



~~Term~~	~~Meaning~~
Virginia Commission	Virginia State Corporation Commission
Virginia Natural Gas	Virginia Natural Gas, Inc., a wholly-owned subsidiary of Southern Company Gas



Term	Meaning
Vogtle 3 and 4 Agreement	Agreement entered into with the EPC Contractor in 2008 by Georgia Power, acting for itself and as agent for the Vogtle Owners, and rejected in bankruptcy in July 2017, pursuant to which the EPC Contractor agreed to design, engineer, procure, construct, and test Plant Vogtle Units 3 and 4
Vogtle Owners	Georgia Power, Oglethorpe Power Corporation, MEAG Power, and Dalton
Vogtle Services Agreement	The June 9, 2017 services agreement between the Vogtle Owners and the EPC Contractor, as amended and restated onin July ~~20,~~ 2017, for the EPC Contractor to transition construction management of Plant Vogtle Units 3 and 4 to Southern Nuclear and to provide ongoing design, engineering, and procurement services to Southern Nuclear
WACOG	Weighted average cost of gas
Westinghouse	Westinghouse Electric Company LLC
Xcel	Xcel Energy Inc.


•	the ability to overcome or mitigate the current challenges at Plant Vogtle Units 3 and 4, including, but not limited to, those related to COVID-19, as described in Note (B) to the Condensed Financial Statements under "Georgia Power – Nuclear Construction" in Item 1 herein, that could impact the cost and schedule for the project;



	Page
The Southern Company and Subsidiary Companies:
Condensed Consolidated Statements of Income	11
Condensed Consolidated Statements of Comprehensive Income	12
Condensed Consolidated Statements of Cash Flows	13
Condensed Consolidated Balance Sheets	14
Condensed Consolidated Statements of Stockholders' Equity	16

Alabama Power Company:
Condensed Statements of Income	17
Condensed Statements of Comprehensive Income	17
Condensed Statements of Cash Flows	18
Condensed Balance Sheets	19
Condensed Statements of Common Stockholder's Equity	21

Georgia Power Company:
Condensed Statements of Income	22
Condensed Statements of Comprehensive Income	22
Condensed Statements of Cash Flows	23
Condensed Balance Sheets	24
Condensed Statements of Common Stockholder's Equity	26

Mississippi Power Company:
Condensed Statements of Income	27
Condensed Statements of Comprehensive Income	27
Condensed Statements of Cash Flows	28
Condensed Balance Sheets	29
Condensed Statements of Common Stockholder's Equity	31

Southern Power Company and Subsidiary Companies:
Condensed Consolidated Statements of Income	32
Condensed Consolidated Statements of Comprehensive Income	32
Condensed Consolidated Statements of Cash Flows	33
Condensed Consolidated Balance Sheets	34
Condensed Consolidated Statements of Stockholders' Equity	36

Southern Company Gas and Subsidiary Companies:
Condensed Consolidated Statements of Income	37
Condensed Consolidated Statements of Comprehensive Income	37
Condensed Consolidated Statements of Cash Flows	38
Condensed Consolidated Balance Sheets	39
Condensed Consolidated Statements of Stockholder's Equity	41

Combined Notes to the Condensed Financial Statements	42


	For the Three Months Ended September 30,						For the Nine Months Ended September 30,						For the Three Months Ended March 31,
	2019			2018			2019			2018			2020			2019
	(in millions)						(in millions)						(in millions)
Operating Revenues:
Retail electric revenues	$	4,512		$	4,605		$	11,136		$	11,913		$	3,078		$	3,084
Wholesale electric revenues	625			698			1,667			1,937			418			499
Other electric revenues	163			165			492			495			151			168
Natural gas revenues (includes alternative revenue programs of $-, $5, $-, and $(23), respectively)	498			492			2,661			2,806
Natural gas revenues (includes alternative revenue programs of $9 and $(2), respectively)													1,249			1,474
Other revenues	197			199			549			1,007			122			187
Total operating revenues	5,995			6,159			16,505			18,158			5,018			5,412
Operating Expenses:
Fuel	1,072			1,310			2,836			3,514			636			850
Purchased power	254			257			625			760			181			170
Cost of natural gas	79			104			956			1,053			439			686
Cost of other sales	114			120			316			688			55			118
Other operations and maintenance	1,292			1,404			3,888			4,217			1,296			1,314
Depreciation and amortization	760			787			2,267			2,338			857			751
Taxes other than income taxes	303			319			931			990			330			329
Estimated loss on plants under construction	4			1			10			1,105
Impairment charges	110			36			142			197
(Gain) loss on dispositions, net	(6		)	(353		)	(2,512		)	(317		)	(39		)	(2,497		)
Total operating expenses	3,982			3,985			9,459			14,545			3,755			1,721
Operating Income	2,013			2,174			7,046			3,613			1,263			3,691
Other Income and (Expense):
Allowance for equity funds used during construction	33			36			96			99			34			32
Earnings from equity method investments	39			36			120			108			42			48
Interest expense, net of amounts capitalized	(434		)	(458		)	(1,294		)	(1,386		)	(456		)	(430		)
Other income (expense), net	61			57			239			195			103			78
Total other income and (expense)	(301		)	(329		)	(839		)	(984		)	(277		)	(272		)
Earnings Before Income Taxes	1,712			1,845			6,207			2,629			986			3,419
Income taxes	367			623			1,872			598			145			1,360
Consolidated Net Income	1,345			1,222			4,335			2,031			841			2,059
Dividends on preferred stock of subsidiaries	4			4			11			12			4			4
Net income attributable to noncontrolling interests	25			54			26			71
Net loss attributable to noncontrolling interests													(31		)	(29		)
Consolidated Net Income Attributable to Southern Company	$	1,316		$	1,164		$	4,298		$	1,948		$	868		$	2,084
Common Stock Data:
Earnings per share -
Basic	$	1.26		$	1.14		$	4.12		$	1.92		$	0.82		$	2.01
Diluted	$	1.25		$	1.13		$	4.09		$	1.91		$	0.81		$	1.99
Average number of shares of common stock outstanding (in millions)
Basic	1,048			1,023			1,043			1,016			1,057			1,038
Diluted	1,057			1,029			1,051			1,021			1,067			1,045



Assets	At March 31, 2020			At December 31, 2019
	(in millions)
Current Assets:
Cash and cash equivalents	$	2,164		$	1,975
Receivables —
Customer accounts receivable	1,603			1,614
Energy marketing receivables	291			428
Unbilled revenues	522			599
Other accounts and notes receivable	560			817
Accumulated provision for uncollectible accounts	(53		)	(49		)
Materials and supplies	1,405			1,388
Fossil fuel for generation	577			521
Natural gas for sale	233			479
Prepaid expenses	667			314
Assets from risk management activities, net of collateral	134			183
Regulatory assets – asset retirement obligations	272			287
Other regulatory assets	876			885
Assets held for sale	—			188
Other current assets	179			188
Total current assets	9,430			9,817
Property, Plant, and Equipment:
In service	105,931			105,114
Less: Accumulated depreciation	31,180			30,765
Plant in service, net of depreciation	74,751			74,349
Nuclear fuel, at amortized cost	854			851
Construction work in progress	8,360			7,880
Total property, plant, and equipment	83,965			83,080
Other Property and Investments:
Goodwill	5,280			5,280
Equity investments in unconsolidated subsidiaries	1,386			1,303
Other intangible assets, net of amortization of $292 and $280 at March 31, 2020 and December 31, 2019, respectively	523			536
Nuclear decommissioning trusts, at fair value	1,787			2,036
Leveraged leases	795			788
Miscellaneous property and investments	407			391
Total other property and investments	10,178			10,334
Deferred Charges and Other Assets:
Operating lease right-of-use assets, net of amortization	1,770			1,800
Deferred charges related to income taxes	798			798
Unamortized loss on reacquired debt	297			300
Regulatory assets – asset retirement obligations, deferred	4,384			4,094
Other regulatory assets, deferred	6,763			6,805
Assets held for sale, deferred	—			601
Other deferred charges and assets	1,267			1,071
Total deferred charges and other assets	15,279			15,469
Total Assets	$	118,852		$	118,700



Liabilities and Stockholders' Equity	At March 31, 2020		At December 31, 2019
	(in millions)
Current Liabilities:
Securities due within one year	$	1,809	$	2,989
Notes payable	1,710		2,055
Energy marketing trade payables	298		442
Accounts payable	1,653		2,115
Customer deposits	491		496
Accrued taxes —
Accrued income taxes	25		—
Other accrued taxes	338		659
Accrued interest	414		474
Accrued compensation	502		992
Asset retirement obligations	514		504
Other regulatory liabilities	701		756
Liabilities held for sale	—		5
Operating lease obligations	230		229
Other current liabilities	868		830
Total current liabilities	9,553		12,546
Long-term Debt	44,235		41,798
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	8,398		7,888
Deferred credits related to income taxes	5,954		6,078
Accumulated deferred ITCs	2,271		2,291
Employee benefit obligations	1,778		1,814
Operating lease obligations, deferred	1,610		1,615
Asset retirement obligations, deferred	9,296		9,282
Accrued environmental remediation	230		234
Other cost of removal obligations	2,251		2,239
Other regulatory liabilities, deferred	368		256
Other deferred credits and liabilities	701		609
Total deferred credits and other liabilities	32,857		32,306
Total Liabilities	86,645		86,650
Redeemable Preferred Stock of Subsidiaries	291		291
Total Stockholders' Equity (See accompanying statements)	31,916		31,759
Total Liabilities and Stockholders' Equity	$	118,852	$	118,700



	Southern Company Common Stockholders' Equity
	Number of Common Shares			Common Stock										Accumulated Other Comprehensive Income (Loss)
	Issued	Treasury		Par Value		Paid-In Capital		Treasury			Retained Earnings			Accumulated Other Comprehensive Income (Loss)			Noncontrolling Interests			Total
	(in millions)
Balance at December 31, 2018	1,035	(1	)	$	5,164	$	11,094	$	(38	)	$	8,706		$	(203	)	$	4,316		$	29,039
Consolidated net income attributable to Southern Company	—	—		—		—		—			2,084			—			—			2,084
Stock issued	6	—		28		196		—			—			—			—			224
Stock-based compensation	—	—		—		24		—			—			—			—			24
Cash dividends of $0.60 per share	—	—		—		—		—			(622		)	—			—			(622		)
Contributions from noncontrolling interests	—	—		—		—		—			—			—			3			3
Distributions to noncontrolling interests	—	—		—		—		—			—			—			(41		)	(41		)
Net income (loss) attributable to noncontrolling interests	—	—		—		—		—			—			—			(29		)	(29		)
Other	—	—		—		7		(2		)	(1		)	—			1			5
Balance at March 31, 2019	1,041	(1	)	$	5,192	$	11,321	$	(40	)	$	10,167		$	(203	)	$	4,250		$	30,687



Balance at December 31, 2019	1,054	(1	)	$	5,257	$	11,734	$	(42	)	$	10,877		$	(321	)	$	4,254		$	31,759
Consolidated net income attributable to Southern Company	—	—		—		—		—			868			—			—			868
Other comprehensive income (loss)	—	—		—		—		—			—			(47		)	—			(47		)
Stock issued	3	—		9		43		—			—			—			—			52
Stock-based compensation	—	—		—		5		—			—			—			—			5
Cash dividends of $0.62 per share	—	—		—		—		—			(655		)	—			—			(655		)
Contributions from noncontrolling interests	—	—		—		—		—			—			—			16			16
Distributions to noncontrolling interests	—	—		—		—		—			—			—			(48		)	(48		)
Net income (loss) attributable to noncontrolling interests	—	—		—		—		—			—			—			(31		)	(31		)
Other	—	—		—		—		(2		)	(2		)	1			—			(3		)
Balance at March 31, 2020	1,057	(1	)	$	5,266	$	11,782	$	(44	)	$	11,088		$	(367	)	$	4,191		$	31,916



Liabilities and Stockholder's Equity	At March 31, 2020		At December 31, 2019
	(in millions)
Current Liabilities:
Securities due within one year	$	296	$	251
Accounts payable —
Affiliated	212		316
Other	271		514
Customer deposits	101		100
Accrued taxes	168		78
Accrued interest	82		92
Accrued compensation	105		216
Asset retirement obligations	201		195
Other regulatory liabilities	155		193
Other current liabilities	109		105
Total current liabilities	1,700		2,060
Long-term Debt	8,141		8,270
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	3,283		3,260
Deferred credits related to income taxes	1,946		1,960
Accumulated deferred ITCs	99		100
Employee benefit obligations	198		206
Operating lease obligations	103		107
Asset retirement obligations, deferred	3,330		3,345
Other cost of removal obligations	402		412
Other regulatory liabilities, deferred	225		146
Other deferred credits and liabilities	41		40
Total deferred credits and other liabilities	9,627		9,576
Total Liabilities	19,468		19,906
Redeemable Preferred Stock	291		291
Common Stockholder's Equity (See accompanying statements)	9,609		8,955
Total Liabilities and Stockholder's Equity	$	29,368	$	29,152



	Number of Common Shares Issued	Common Stock		Paid-In Capital		Retained Earnings			Accumulated Other Comprehensive Income (Loss)			Total
	(in millions)
Balance at December 31, 2018	31	$	1,222	$	3,508	$	2,775		$	(28	)	$	7,477
Net income after dividends on preferred stock	—	—		—		217			—			217
Capital contributions from parent company	—	—		1,236		—			—			1,236
Other comprehensive income	—	—		—		—			1			1
Cash dividends on common stock	—	—		—		(211		)	—			(211		)
Balance at March 31, 2019	31	$	1,222	$	4,744	$	2,781		$	(27	)	$	8,720

Balance at December 31, 2019	31	$	1,222	$	4,755	$	3,001		$	(23	)	$	8,955
Net income after dividends on preferred stock	—	—		—		280			—			280
Capital contributions from parent company	—	—		612		—			—			612
Other comprehensive income	—	—		—		—			1			1
Cash dividends on common stock	—	—		—		(239		)	—			(239		)
Balance at March 31, 2020	31	$	1,222	$	5,367	$	3,042		$	(22	)	$	9,609


Assets	At September 30, 2019			At December 31, 2018			At March 31, 2020		At December 31, 2019
	(in millions)						(in millions)
Current Assets:
Cash and cash equivalents	$	2,931		$	1,396		$	330	$	279
Receivables —
Customer accounts receivable	1,812			1,726			109		107
Energy marketing receivables	336			801
Unbilled revenues	591			654
Under recovered fuel clause revenues	—			115
Other accounts and notes receivable	693			813
Accumulated provision for uncollectible accounts	(47		)	(50		)
Affiliated							26		30
Other							54		73
Materials and supplies	1,412			1,465			198		191
Fossil fuel for generation	437			405
Natural gas for sale	475			524
Prepaid expenses	279			432
Assets from risk management activities, net of collateral	116			222
Other regulatory assets	657			525
Assets held for sale	17			393
Prepaid income taxes							452		36
Other current assets	208			162			24		43
Total current assets	9,917			9,583			1,193		759
Property, Plant, and Equipment:
In service	103,529			103,706			13,282		13,270
Less: Accumulated depreciation	30,469			31,038
Less: Accumulated provision for depreciation							2,580		2,464
Plant in service, net of depreciation	73,060			72,668			10,702		10,806
Nuclear fuel, at amortized cost	849			875
Construction work in progress	7,804			7,254			534		515
Total property, plant, and equipment	81,713			80,797			11,236		11,321
Other Property and Investments:
Goodwill	5,280			5,315
Intangible assets, net of amortization of $74 and $69 at March 31, 2020 and December 31, 2019, respectively							317		322
Equity investments in unconsolidated subsidiaries	1,540			1,580			45		28
Other intangible assets, net of amortization of $265 and $235 at September 30, 2019 and December 31, 2018, respectively	550			613
Nuclear decommissioning trusts, at fair value	1,965			1,721
Leveraged leases	799			798
Miscellaneous property and investments	394			269
Total other property and investments	10,528			10,296			362		350
Deferred Charges and Other Assets:
Operating lease right-of-use assets, net of amortization	1,818			—			368		369
Deferred charges related to income taxes	796			794
Unamortized loss on reacquired debt	307			323
Regulatory assets – asset retirement obligations	4,436			2,933
Other regulatory assets, deferred	6,289			5,375
Assets held for sale, deferred	631			5,350
Prepaid LTSAs							134		128
Accumulated deferred income taxes							129		551
Income taxes receivable, non-current							8		5
Assets held for sale							—		601
Other deferred charges and assets	1,156			1,463			216		216
Total deferred charges and other assets	15,433			16,238			855		1,870
Total Assets	$	117,591		$	116,914		$	13,646	$	14,300



Balance at December 31, 2019	$	909	$	1,485		$	(26	)	$	2,368		$	4,254		$	6,622
Net income attributable to Southern Power	—		75			—			75			—			75
Other comprehensive income (loss)	—		—			(33		)	(33		)	—			(33		)
Cash dividends on common stock	—		(50		)	—			(50		)	—			(50		)
Capital contributions from noncontrolling interests	—		—			—			—			16			16
Distributions to noncontrolling interests	—		—			—			—			(48		)	(48		)
Net income (loss) attributable to noncontrolling interests	—		—			—			—			(31		)	(31		)
Balance at March 31, 2020	$	909	$	1,510		$	(59	)	$	2,360		$	4,191		$	6,551



	Paid-In Capital			Retained Earnings (Accumulated Deficit)			Accumulated Other Comprehensive Income (Loss)			Total
	(in millions)
Balance at December 31, 2018	$	8,856		$	(312	)	$	26		$	8,570
Net income	—			270			—			270
Capital contributions from parent company	17			—			—			17
Other comprehensive income (loss)	—			—			(1		)	(1		)
Cash dividends on common stock	—			(118		)	—			(118		)
Balance at March 31, 2019	$	8,873		$	(160	)	$	25		$	8,738

Balance at December 31, 2019	$	9,697		$	(198	)	$	7		$	9,506
Net income	—			275			—			275
Return of capital to parent company	(2		)	—			—			(2		)
Other comprehensive income (loss)	—			—			(15		)	(15		)
Cash dividends on common stock	—			(133		)	—			(133		)
Balance at March 31, 2020	$	9,695		$	(56	)	$	(8	)	$	9,631



Note		Page
A	Introduction	43
B	Regulatory Matters	46
C	Contingencies	54
D	Revenue from Contracts with Customers and Lease Income	58
E	Consolidated Entities and Equity Method Investments	62
F	Financing	64
G	Income Taxes	66
H	Retirement Benefits	67
I	Fair Value Measurements	70
J	Derivatives	75
K	Acquisitions and Dispositions	86
L	Segment and Related Information	88



Registrant	Applicable Notes
Southern Company	A, B, C, D, E, F, G, H, I, J, K, L
Alabama Power	A, B, C, D, F, G, H, I, J, K
Georgia Power	A, B, C, D, F, G, H, I, J
Mississippi Power	A, B, C, D, F, G, H, I, J
Southern Power	A, C, D, E, F, G, H, I, J, K
Southern Company Gas	A, B, C, D, E, F, G, H, I, J, K, L



	At March 31, 2020							At December 31, 2019
	Gross Carrying Amount		Accumulated Amortization			Other Intangible Assets, Net		Gross Carrying Amount		Accumulated Amortization			Other Intangible Assets, Net
	(in millions)							(in millions)
Southern Company
Other intangible assets subject to amortization:
Customer relationships	$	212	$	(121	)	$	91	$	212	$	(116	)	$	96
Trade names	64		(26		)	38		64		(25		)	39
Storage and transportation contracts	64		(63		)	1		64		(62		)	2
PPA fair value adjustments	390		(74		)	316		390		(69		)	321
Other	10		(8		)	2		11		(8		)	3
Total other intangible assets subject to amortization	$	740	$	(292	)	$	448	$	741	$	(280	)	$	461
Other intangible assets not subject to amortization:
Federal Communications Commission licenses	75		—			75		75		—			75
Total other intangible assets	$	815	$	(292	)	$	523	$	816	$	(280	)	$	536

Southern Power
Other intangible assets subject to amortization:
PPA fair value adjustments	$	390	$	(74	)	$	316	$	390	$	(69	)	$	321

Southern Company Gas
Other intangible assets subject to amortization:
Gas marketing services
Customer relationships	$	156	$	(108	)	$	48	$	156	$	(104	)	$	52
Trade names	26		(10		)	16		26		(10		)	16
Wholesale gas services
Storage and transportation contracts	64		(63		)	1		64		(62		)	2
Total other intangible assets subject to amortization	$	246	$	(181	)	$	65	$	246	$	(176	)	$	70



	Three Months Ended
	March 31, 2020
	(in millions)
Southern Company^(a)	$	12
Southern Power^(b)	$	5
Southern Company Gas
Gas marketing services	$	4
Wholesale gas services^(b)	1
Southern Company Gas total	$	5


(a)	Includes $6 million for the three months ended March 31, 2020, recorded as a reduction to operating revenues.


(a)	Represents restricted cash held by Southern Company Gas as collateral for workers' compensation, life insurance, and long-term disability insurance.



	Third Quarter 2019					Year-to-Date 2019
	(in millions)			(% change)		(in millions)			(% change)
Retail electric – prior year	$	4,605				$	11,913
Estimated change resulting from –
Rates and pricing	242			5.3	%	425			3.6	%
Sales decline	(71		)	(1.6	)	(111		)	(0.9	)
Weather	125			2.7		68			0.5
Fuel and other cost recovery	(48		)	(1.0	)	(227		)	(1.9	)
Gulf Power disposition	(341		)	(7.4	)	(932		)	(7.8	)
Retail electric – current year	$	4,512		(2.0	)%	$	11,136		(6.5	)%



	Third Quarter 2019 vs. Third Quarter 2018				Year-to-Date 2019 vs. Year-to-Date 2018
	(change in millions)			(% change)	(change in millions)			(% change)
Fuel	$	(238	)	(18.2)	$	(678	)	(19.3)
Purchased power	(3		)	(1.2)	(135		)	(17.8)
Total fuel and purchased power expenses	$	(241	)		$	(813	)



	Third Quarter 2019	Third Quarter 2018^(a)	Year-to-Date 2019	Year-to-Date 2018^(a)
Total generation (in billions of KWHs)	54	53	143	146
Total purchased power (in billions of KWHs)	6	4	14	11
Sources of generation (percent) —
Gas	54	50	51	48
Coal	24	28	23	27
Nuclear	15	15	16	15
Hydro	1	2	4	3
Other	6	5	6	7
Cost of fuel, generated (in cents per net KWH)—
Gas	2.25	2.62	2.39	2.65
Coal	2.85	2.92	2.93	2.96
Nuclear	0.79	0.81	0.79	0.80
Average cost of fuel, generated (in cents per net KWH)	2.18	2.42	2.24	2.43
Average cost of purchased power (in cents per net KWH)^(b)	5.22	6.18	5.11	6.14


~~(a)~~	~~Excludes Gulf Power, which was sold on January 1, 2019.~~


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

Third Quarter 2019 vs. Third Quarter 2018

Year-to-Date 2019 vs. Year-to-Date 2018

(change in millions)

(% change)

(change in millions)

(% change)