SOUTHERN : MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (form 10-K)

February 20, 2020 at 06:08 am EST

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Combined Management's Discussion and Analysis of Financial Condition
and Results of Operations
  Overview                                                               II-16
  Results of Operations                                                  II-20
  Southern Company                                                       II-20
  Alabama Power                                                          II-30
  Georgia Power                                                          II-34
  Mississippi Power                                                      II-39
  Southern Power                                                         II-43
  Southern Company Gas                                                   II-47
  Future Earnings Potential                                              II-57
  Accounting Policies                                                    II-90
  Financial Condition and Liquidity

II-100




This section generally discusses 2019 and 2018 items and year-to-year
comparisons between 2019 and 2018. Discussions of 2017 items and year-to-year
comparisons between 2018 and 2017 that are not included in this Annual Report on
Form 10-K can be found in Item 7 of each Registrant's Annual Report on Form 10-K
for the year ended December 31, 2018, which was filed with the SEC on February
19, 2019. The following Management's Discussion and Analysis of Financial
Condition and Results of Operations is a combined presentation; however,
information contained herein relating to any individual Registrant is filed by
such Registrant on its own behalf and each Registrant makes no representation as
to information related to the other Registrants.
Item 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK


See MANAGEMENT'S DISCUSSION AND ANALYSIS - FINANCIAL CONDITION AND LIQUIDITY -
"Market Price Risk" in Item 7 herein and Note 1 to the financial statements
under "Financial Instruments" in Item 8 herein. Also see Notes 13 and 14 to the
financial statements in Item 8 herein.

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COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS
Southern Company and Subsidiary Companies 2019 Annual Report

OVERVIEW


Business Activities
Southern Company is a holding company that owns all of the common stock of three
traditional electric operating companies, as well as the parent entities of
Southern Power and Southern Company Gas, and owns other direct and indirect
subsidiaries. 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. Southern
Company's reportable 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.
•      The traditional electric operating companies - Alabama Power, Georgia
       Power, and Mississippi Power - are vertically integrated utilities
       providing electric service to retail customers in three Southeastern
       states in addition to wholesale customers in the Southeast.


•      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, IPPs, 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.

• Southern Company Gas is an energy services holding company whose primary

business is the distribution of natural gas. Southern Company Gas owns

natural gas distribution utilities in four states - Illinois, Georgia,

Virginia, and Tennessee - and is also involved in several other

complementary businesses. Southern Company Gas manages its business

through four reportable segments - gas distribution operations, gas

pipeline investments, wholesale gas services, which includes Sequent, a

natural gas asset optimization company, and gas marketing services, which

includes SouthStar, a provider of energy-related products and services to


       natural gas markets - and one non-reportable segment, all other. See Notes
       7 and 16 to the financial statements for additional information.


Many factors affect the opportunities, challenges, and risks of the Southern
Company system's electric service and natural gas businesses. These factors
include the ability to maintain constructive regulatory environments, to
maintain and grow sales and customers, and to effectively manage and secure
timely recovery of prudently-incurred costs. These costs include those related
to projected long-term demand growth; stringent environmental standards,
including CCR rules; safety; system reliability and resilience; fuel; natural
gas; restoration following major storms; and capital expenditures, including
constructing new electric generating plants and expanding and improving the
electric transmission and electric and natural gas distribution systems.
The traditional electric operating companies and natural gas distribution
utilities have various regulatory mechanisms that 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 the Southern Company system for the foreseeable future.
See Note 2 to the financial statements for additional information.
Southern Power's future earnings will depend upon the parameters of the
wholesale market and the efficient operation of its wholesale generating assets,
as well as Southern Power's ability to execute its growth strategy and to
develop and construct generating facilities. In addition, Southern Power's
future earnings will depend upon the availability of federal and state ITCs and
PTCs on its renewable energy projects, which could be impacted by future tax
legislation. See FUTURE EARNINGS POTENTIAL - "Acquisitions and Dispositions,"
"Construction Programs," and "Income Tax Matters" herein and Notes 10 and 15 to
the financial statements for additional information.
Southern Company's other business activities include providing energy solutions
to electric utilities and their customers in the areas of distributed
generation, energy storage and renewables, and energy efficiency. Other business
activities also include investments in telecommunications, leveraged lease
projects, and gas storage facilities. Management continues to evaluate the
contribution of each of these activities to total shareholder return and may
pursue acquisitions, dispositions, and other strategic ventures or investments
accordingly.

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COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Southern Company and Subsidiary Companies 2019 Annual Report



Recent Developments
Southern Company
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), including the final working capital
adjustments. The gain associated with the sale of Gulf Power totaled $2.6
billion pre-tax ($1.4 billion after tax).
Alabama Power
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 and long-term contracts
for the purchase of power from others, as well as the acquisition of an existing
combined cycle facility for a total capital investment of approximately $1.1
billion. The related costs would be recovered through existing rate mechanisms.
In addition, Alabama Power will pursue approximately 200 MWs of certain demand
side management and distributed energy resource programs. See FUTURE EARNINGS
POTENTIAL - "Regulatory Matters - Alabama Power" herein for additional
information.
Georgia Power
Rate Case
On December 17, 2019, the Georgia PSC voted to approve the 2019 ARP, including
estimated rate increases totaling $342 million, $181 million, and $386 million
effective January 1, 2020, January 1, 2021, and January 1, 2022, respectively.
See FUTURE EARNINGS POTENTIAL - "Regulatory Matters - Georgia Power - Rate Plans
- 2019 ARP" herein for additional information.
Plant Vogtle Units 3 and 4 Status
In 2009, the Georgia PSC certified construction of Plant Vogtle Units 3 and 4
(with electric generating capacity of approximately 1,100 MWs each). Georgia
Power holds a 45.7% ownership interest in Plant Vogtle Units 3 and 4. In March
2017, the EPC Contractor filed for bankruptcy protection under Chapter 11 of the
U.S. Bankruptcy Code. In December 2017, the Georgia PSC approved Georgia Power's
recommendation to continue construction. The current expected in-service dates
remain November 2021 for Unit 3 and November 2022 for Unit 4.
In the second quarter 2018, Georgia Power revised its total project capital cost
forecast to complete construction and start-up of Plant Vogtle Units 3 and 4 to
$8.4 billion (net of $1.7 billion received under the Guarantee Settlement
Agreement and approximately $188 million in related customer refunds), with
respect to Georgia Power's ownership interest. As of December 31, 2019,
approximately $140 million of the $366 million construction contingency estimate
established in the second quarter 2018 was allocated to the base capital cost
forecast.
As a result of the increase in the total project capital cost forecast and
Georgia Power's decision not to seek rate recovery of the increase in the base
capital costs, the holders of at least 90% of the ownership interests in Plant
Vogtle Units 3 and 4 were required to vote to continue construction. In
September 2018, the Vogtle Owners unanimously voted to continue construction of
Plant Vogtle Units 3 and 4. Following the vote to continue construction, Georgia
Power entered into agreements to take certain actions which partially mitigate
potential financial exposure for the other Vogtle Owners and to provide funding
with respect to a MEAG Power wholly-owned subsidiary's ownership interest in
Plant Vogtle Units 3 and 4 under certain circumstances.
As part of its ongoing processes, Southern Nuclear continues to evaluate cost
and schedule forecasts on a regular basis to incorporate current information
available, particularly in the areas of commodity installation, system
turnovers, and workforce statistics. In February 2020, Southern Nuclear updated
its cost and schedule forecast, which did not change the projected overall
capital cost forecast and confirmed the expected in-service dates of November
2021 for Unit 3 and November 2022 for Unit 4.
In March 2019, Georgia Power entered into the Amended and Restated Loan
Guarantee Agreement with the DOE, 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, up to
approximately $5.130 billion. At December 31, 2019, Georgia Power had a total of
$3.8 billion of borrowings outstanding under the related multi-advance credit
facilities.
The ultimate outcome of these matters cannot be determined at this time.
See FUTURE EARNINGS POTENTIAL - "Construction Programs - Nuclear Construction"
herein and Note 8 to the financial statements under "Long-term Debt - DOE Loan
Guarantee Borrowings" for additional information.

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COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Southern Company and Subsidiary Companies 2019 Annual Report

Mississippi Power
In 2019, Mississippi Power recorded pre-tax and after-tax charges to income of
$24 million related to the Kemper County energy facility, which was suspended in
2017, primarily associated with the expected close out of a DOE contract related
to the Kemper County energy facility, as well as other abandonment and related
closure costs and ongoing period costs, net of salvage proceeds, for the mine
and gasifier-related assets. The after-tax amount for 2019 includes an
adjustment related to the tax abandonment of the Kemper IGCC following the
filing of the 2018 tax return. In December 2019, Mississippi Power transferred
ownership of the CO2 pipeline to an unrelated gas pipeline company, with no
resulting impact on income. Mine reclamation activities are expected to be
substantially completed in 2020 and dismantlement of the abandoned
gasifier-related assets and site restoration activities are expected to be
completed in 2024. The additional pre-tax period costs associated with
dismantlement and site restoration activities, including related costs for
compliance and safety, ARO accretion, and property taxes, are estimated to total
$17 million in 2020, $15 million to $16 million annually in 2021 through 2023,
and $5 million in 2024. See Note 2 to the financial statements under
"Mississippi Power - Kemper County Energy Facility" and Note 3 to the financial
statements for additional information, including remaining contingencies related
to the Kemper IGCC.
On November 26, 2019, Mississippi Power filed a base rate case (Mississippi
Power 2019 Base Rate Case) with the Mississippi PSC. The filing includes a
requested annual decrease in Mississippi Power's retail rates of $5.8 million,
or 0.6%, which is driven primarily by changes in the amortization rates of
certain regulatory assets and liabilities and cost reductions, partially offset
by an increase in Mississippi Power's requested return on investment and
depreciation associated with the filing of an updated depreciation study. The
revenue requirements included in the filing are based on a 53% average equity
ratio and a 7.728% return on investment. On December 10, 2019, the Mississippi
PSC suspended the base rate case filing through no later than March 25, 2020. If
no further action is taken by the Mississippi PSC, the proposed rates may be
effective beginning on March 26, 2020. The ultimate outcome of this matter
cannot be determined at this time. See Note 2 to the financial statements under
"Mississippi Power - 2019 Base Rate Case" for additional information.
Southern Power
During 2019, Southern Power completed construction and achieved commercial
operation of the 100-MW Wildhorse Mountain wind facility, acquired and continued
construction of the 136-MW Skookumchuck wind facility, and continued
construction of the 200-MW Reading wind facility. In addition, Southern Power
acquired 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 $167 million.
On June 13, 2019, Southern Power completed the sale of its equity interests in
Plant Nacogdoches, a 115-MW biomass facility located in Nacogdoches County,
Texas, to Austin Energy, for a purchase price of approximately $461 million,
including working capital adjustments.
On January 17, 2020, Southern Power completed the sale of its equity interests
in Plant Mankato (including the 385-MW expansion unit completed in May 2019) to
a subsidiary of Xcel for a purchase price of approximately $663 million,
including estimated working capital adjustments.
Southern Power calculates an investment coverage ratio for its generating
assets, including those owned with various partners, 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. With the inclusion of investments
associated with the wind facilities currently under construction, as well as
other capacity and energy contracts, and excluding Plant Mankato, which was sold
on January 17, 2020, Southern Power's average investment coverage ratio at
December 31, 2019 was 93% through 2024 and 90% through 2029, with an average
remaining contract duration of approximately 14 years.
See FUTURE EARNINGS POTENTIAL - "Acquisitions and Dispositions - Southern Power"
and Construction Programs - Southern Power" herein for additional information.

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COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Southern Company and Subsidiary Companies 2019 Annual Report

Southern Company Gas
During 2019, the natural gas distribution utilities have been involved in the
following regulatory proceedings:
•      On September 25, 2019, the Virginia Commission approved Virginia Natural

Gas' Steps to Advance Virginia's Energy (SAVE) program request to amend

and extend the program through 2024 with estimated capital spend totaling

approximately $365 million.

• On October 2, 2019, the Illinois Commission approved a $168 million annual

base rate increase for Nicor Gas, including $65 million related to the

recovery of investments under the Investing in Illinois program, which

became effective October 8, 2019.

• On December 19, 2019, the Georgia PSC approved a $65 million annual base

rate increase for Atlanta Gas Light, effective January 1, 2020.




See FUTURE EARNINGS POTENTIAL - "Regulatory Matters - Southern Company Gas -
Rate Proceedings" herein and Note 2 to the financial statements under "Southern
Company Gas - Rate Proceedings" for additional information.
Also during 2019, Southern Company Gas recorded a pre-tax impairment charge of
$91 million ($69 million after tax) related to a natural gas storage facility in
Louisiana. See Note 3 to the financial statements under "Other Matters -
Southern Company Gas" for additional information.
On February 7, 2020, Southern Company Gas entered into agreements with Dominion
Modular LNG Holdings, Inc. and Dominion Atlantic Coast Pipeline, LLC for the
sale of its interests in Pivotal LNG and Atlantic Coast Pipeline, respectively,
for an aggregate purchase price of $165 million, including estimated working
capital and timing adjustments. Southern Company Gas may also receive two
payments of $5 million each, contingent upon certain milestones related to
Pivotal LNG being met by Dominion Modular LNG Holdings, Inc. after the
completion of the sale. Based on the terms of these pending transactions,
Southern Company Gas recorded an asset impairment charge, exclusive of the
contingent payments, for Pivotal LNG of approximately $24 million ($17 million
after tax) as of December 31, 2019. The completion of each transaction is
subject to the satisfaction or waiver of certain conditions, including, among
other customary closing conditions, the completion of the other transaction and,
for the sale of the interest in Atlantic Coast Pipeline, the expiration or
termination of any applicable waiting period under the Hart-Scott-Rodino
Antitrust Improvements Act of 1976. The transactions are expected to be
completed in the first half of 2020; however, the ultimate outcome cannot be
determined at this time. The assets and liabilities of Pivotal LNG and the
interest in Atlantic Coast Pipeline are classified as held for sale as of
December 31, 2019. See Notes 3, 7, and 15 to the financial statements under
"Southern Company Gas - Gas Pipeline Projects," "Southern Company Gas - Equity
Method Investments," and "Southern Company Gas - Proposed Sale of Pivotal LNG
and Atlantic Coast Pipeline," respectively, for additional information.
See FUTURE EARNINGS POTENTIAL - "Acquisitions and Dispositions - Southern
Company Gas" herein for information regarding Southern Company Gas' 2018
disposition activity.
Key Performance Indicators
In striving to achieve attractive risk-adjusted returns while providing
cost-effective energy to more than eight million electric and gas utility
customers collectively, the traditional electric operating companies and
Southern Company Gas continue 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, and execution of
major construction projects. In addition, Southern Company and the Subsidiary
Registrants focus on earnings per share (EPS) and net income, respectively, as a
key performance indicator. See RESULTS OF OPERATIONS herein for information on
the Registrants' financial performance. See RESULTS OF OPERATIONS - "Southern
Company Gas - Operating Metrics" for additional information on Southern Company
Gas' operating metrics, including Heating Degree Days, customer count, and
volumes of natural gas sold.
The financial success of the traditional electric operating companies and
Southern Company Gas is directly tied to customer satisfaction. Key elements of
ensuring customer satisfaction include outstanding service, high reliability,
and competitive prices. The traditional electric operating companies use
customer satisfaction surveys to evaluate their results and generally target the
top quartile of these surveys in measuring performance. Reliability indicators
are also used to evaluate results. See FUTURE EARNINGS POTENTIAL - "Regulatory
Matters - Alabama Power - Rate RSE" and " - Mississippi Power - Performance
Evaluation Plan" herein for additional information on Alabama Power's Rate RSE
and Mississippi Power's PEP rate plan, respectively, both of which contain
mechanisms that directly tie customer service indicators to the allowed equity
return.
Southern Power continues to focus on several key performance indicators,
including, but not limited to, the equivalent forced outage rate and contract
availability to evaluate operating results and help ensure its ability to meet
its contractual commitments to customers.

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COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Southern Company and Subsidiary Companies 2019 Annual Report



RESULTS OF OPERATIONS
Southern Company
Consolidated net income attributable to Southern Company was $4.7 billion in
2019, an increase of $2.5 billion, or 112.9%, from the prior year. The increase
was primarily due to the $2.6 billion ($1.4 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 "Electricity Business -
Estimated Loss on Plants Under Construction" herein and Notes 2 and 15 to the
financial statements under "Georgia Power - Nuclear Construction" and "Southern
Company," respectively, for additional information.
Basic EPS was $4.53 in 2019 and $2.18 in 2018. Diluted EPS, which factors in
additional shares related to stock-based compensation, was $4.50 in 2019 and
$2.17 in 2018. EPS for 2019 and 2018 was negatively impacted by $0.11 and $0.04
per share, respectively, as a result of increases in the average shares
outstanding. See Note 8 to the financial statements under "Outstanding Classes
of Capital Stock - Southern Company" for additional information.
Southern Company has paid dividends on its common stock since 1948. Dividends
paid per share of common stock were $2.46 in 2019 and $2.38 in 2018. In January
2020, Southern Company declared a quarterly dividend of 62 cents per share. For
2019, the dividend payout ratio was 54% compared to 109% for 2018. The decrease
was due to the increase in earnings in 2019.
Discussion of Southern Company's results of operations is divided into three
parts - the Southern Company system's primary business of electricity sales, its
gas business, and its other business activities.
                            2019       2018
                             (in millions)
Electricity business      $ 3,268    $ 2,304
Gas business                  585        372
Other business activities     886       (450 )
Net Income                $ 4,739    $ 2,226


Electricity Business
Southern Company's electric utilities generate and sell electricity to retail
and wholesale customers. The results of operations discussed below include the
results of Gulf Power through December 31, 2018. See Note 15 to the financial
statements under "Southern Company" for additional information.

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COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Southern Company and Subsidiary Companies 2019 Annual Report

A condensed statement of income for the electricity business follows:


                                                                           Increase
                                                                          (Decrease)
                                                               2019        from 2018
                                                                  (in millions)
Electric operating revenues                                 $ 17,095     $    (1,476 )
Fuel                                                           3,622          (1,015 )
Purchased power                                                  816            (155 )
Cost of other sales                                               76              10
Other operations and maintenance                               4,479            (156 )
Depreciation and amortization                                  2,472             (93 )
Taxes other than income taxes                                  1,011             (87 )
Estimated loss on plants under construction                       24          (1,073 )
Impairment charges                                                 3            (153 )
(Gain) loss on dispositions, net                                 (21 )           (21 )
Total electric operating expenses                             12,482          (2,743 )
Operating income                                               4,613

1,267


Allowance for equity funds used during construction              121             (10 )
Interest expense, net of amounts capitalized                     987             (48 )
Other income (expense), net                                      234              90
Income taxes                                                     708             501
Net income                                                     3,273             894
Less:

Dividends on preferred and preference stock of subsidiaries 15

       (1 )
Net income (loss) attributable to noncontrolling interests       (10 )           (69 )
Net Income Attributable to Southern Company                 $  3,268     $

964

Electric Operating Revenues Electric operating revenues for 2019 were $17.1 billion, reflecting a $1.5 billion decrease from 2018. Details of electric operating revenues were as follows:


                                     2019          2018
                                       (in millions)
Retail electric - prior year      $ 15,222
Estimated change resulting from -
Rates and pricing                      581
Sales decline                         (143 )
Weather                                 29
Fuel and other cost recovery          (392 )
Gulf Power disposition              (1,213 )
Retail electric - current year      14,084      $ 15,222
Wholesale electric revenues          2,152         2,516
Other electric revenues                636           664
Other revenues                         223           169
Electric operating revenues       $ 17,095      $ 18,571
Percent change                        (7.9 )%        0.2 %



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COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Southern Company and Subsidiary Companies 2019 Annual Report



Retail electric revenues decreased $1.1 billion, or 7.5%, in 2019 as compared to
the prior year. The significant factors driving this change are shown in the
preceding table. The increase in rates and pricing in 2019 was 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
Rate CNP Compliance, and lower Rate RSE customer refund in 2019 as compared to
the prior year; Georgia Power's higher contributions from commercial and
industrial customers with variable demand-driven pricing, NCCR rate increase
effective January 1, 2019, and pricing effects associated with a milder winter
in 2019 compared to 2018; and Mississippi Power's PEP and ECO Plan rate
increases effective for the first billing cycle of September 2018.
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, including 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.
See Note 2 to the financial statements under "Alabama Power," "Georgia Power,"
and "Mississippi Power" for additional information. Also see "Energy Sales"
below for a discussion of changes in the volume of energy sold, including
changes related to sales growth (decline) and weather.
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 MRA
sales 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.
Wholesale electric revenues from power sales were as follows:
                     2019       2018
                      (in millions)
Capacity and other $   529    $   620
Energy               1,623      1,896
Total              $ 2,152    $ 2,516


In 2019, wholesale revenues decreased $364 million, or 14.5%, as compared to the
prior year due to decreases of $273 million in energy revenues and $91 million
in capacity revenues. Excluding the $28 million decrease associated with the
sale of Gulf Power, energy revenues decreased $165 million at Southern Power and
$80 million at the traditional electric operating companies. The decrease at
Southern Power related to a $113 million decrease primarily in non-PPA
short-term sales and a decrease in the market price of energy, as well as a $51
million decrease primarily in sales under PPAs from natural gas facilities. The
decrease at the traditional electric operating companies was primarily due to
lower natural gas prices. Excluding the $26 million decrease associated with the
sale of Gulf Power, the decrease in capacity revenues was primarily related to
the sales of Southern Power's Plant Oleander and Plant Stanton Unit A (together,
the Florida Plants) in December 2018 and Southern Power's Plant Nacogdoches in
June 2019. See Note 15 to the financial statements for additional information.
Other Electric Revenues
Other electric revenues decreased $28 million, or 4.2%, in 2019 as compared to
the prior year. The decrease was primarily due to a decrease of $66 million
related to the sale of Gulf Power, partially offset by increases at Georgia
Power of $13 million in regulated power delivery construction and maintenance
contracts and $11 million from outdoor lighting LED conversions and sales, as
well as an increase at Alabama Power of $9 million from pole attachment
agreements.

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COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Southern Company and Subsidiary Companies 2019 Annual Report



Energy Sales
Changes in revenues are influenced heavily by the change in the volume of energy
sold from year to year. KWH sales for 2019 and the percent change from the prior
year were as follows:
                                                               2019
                                                                                         Adjusted(b)
                                                                               Total KWH
                        Total           Total KWH       Weather-Adjusted        Percent       Weather-Adjusted
                        KWHs         Percent Change     Percent Change(a)       Change        Percent Change(a)
                    (in billions)
Residential                 48.5          (11.1 )%             (10.7 )%            (1.1 )%           (0.8 )%
Commercial                  49.1           (8.1 )               (8.6 )             (1.1 )            (1.6 )
Industrial                  50.1           (6.1 )               (6.1 )             (2.9 )            (2.9 )
Other                        0.8           (9.1 )               (9.0 )             (5.8 )            (5.7 )
Total retail               148.5           (8.5 )               (8.4 )%            (1.7 )            (1.8 )%
Wholesale                   48.0           (3.9 )                                  (2.6 )
Total energy sales         196.5           (7.4 )%                                 (1.9 )%

(a) Weather-adjusted KWH sales are estimated by removing from KWH sales the

effect of deviations from normal temperature conditions, based on statistical

models of the historical relationship between temperatures and energy sales.

Normal temperature conditions are defined as those experienced in the

applicable service territory over a specified historical period. This metric

is useful because it allows trends in historical operations to be evaluated

apart from the influence of weather conditions. Management also considers

this metric in developing long-term capital and financial plans.

(b) Kilowatt-hour sales comparisons to the prior year were significantly impacted

by the disposition of Gulf Power on January 1, 2019. These changes exclude

Gulf Power.




Changes in retail energy sales are generally the result of changes in
electricity usage by customers, changes in weather, and changes in the number of
customers. Excluding the impact of the Gulf Power disposition on January 1,
2019, weather-adjusted retail energy sales decreased 2.7 billion KWHs in 2019 as
compared to the prior year primarily due to lower customer usage.
Weather-adjusted residential usage decreases are primarily attributable to an
increase in energy-efficient residential appliances and energy saving
initiatives, partially offset by customer growth. Weather-adjusted commercial
usage decreases are primarily attributable to an increase in energy saving
initiatives and an ongoing migration to the electronic commerce business model.
Industrial usage decreases are a result of changes in production levels
primarily in the primary metals, paper, chemicals, and textiles sectors.
See "Electric Operating Revenues" above for a discussion of significant changes
in wholesale revenues related to changes in price and KWH sales.
Other Revenues
Other revenues increased $54 million, or 32.0%, in 2019 as compared to the prior
year. The increase was primarily due to increases at Georgia Power of $20
million from unregulated sales associated with new energy conservation projects
and $14 million from unregulated power delivery construction and maintenance
contracts, as well as an increase at Alabama Power of $11 million in unregulated
sales of products and services.
Fuel and Purchased Power Expenses
The mix of fuel sources for the generation of electricity is determined
primarily by demand, the unit cost of fuel consumed, and the availability of
generating units. Additionally, the electric utilities purchase a portion of
their electricity needs from the wholesale market.

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Details of the Southern Company system's generation and purchased power were as follows:


                                                          2019    2018(a)
Total generation (in billions of KWHs)                     187        191
Total purchased power (in billions of KWHs)                 18         14
Sources of generation (percent) -
Gas                                                         52         48
Coal                                                        22         27
Nuclear                                                     16         16
Hydro                                                        3          3
Other                                                        7          6
Cost of fuel, generated (in cents per net KWH) -
Gas                                                       2.36       2.76
Coal                                                      2.87       2.93
Nuclear                                                   0.79       0.80

Average cost of fuel, generated (in cents per net KWH) 2.20 2.46 Average cost of purchased power (in cents per net KWH)(b) 5.01 5.94

(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.




In 2019, total fuel and purchased power expenses were $4.4 billion, a decrease
of $1.2 billion, or 20.9%, as compared to the prior year. Excluding
approximately $511 million associated with the sale of Gulf Power, the decrease
was primarily the result of a $575 million decrease in the average cost of fuel
and purchased power and an $84 million net decrease in the volume of KWHs
generated and purchased.
Fuel and purchased power energy transactions at the traditional electric
operating companies are generally offset by fuel revenues and do not have a
significant impact on net income. See FUTURE EARNINGS POTENTIAL - "Regulatory
Matters" herein for additional information. Fuel expenses incurred under
Southern Power's PPAs are generally the responsibility of the counterparties and
do not significantly impact net income.
Fuel
In 2019, fuel expense was $3.6 billion, a decrease of $1.0 billion, or 21.9%, as
compared to the prior year. Excluding approximately $309 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 14.5% decrease in the average cost of natural gas
per KWH generated, and a 2.1% decrease in the average cost of coal per KWH
generated, partially offset by a 5.0% increase in the volume of KWHs generated
by natural gas.
Purchased Power
In 2019, purchased power expense was $816 million, a decrease of $155 million,
or 16.0%, as compared to the prior year. Excluding approximately $202 million
associated with the sale of Gulf Power, the change was primarily due to a 9.6%
increase in the volume of KWHs purchased, partially offset by a 15.7% decrease
in the average cost of KWH purchased.
Energy purchases will vary depending on demand for energy within the Southern
Company system's electric service territory, the market prices of wholesale
energy as compared to the cost of the Southern Company system's generation, and
the availability of the Southern Company system's generation.
Other Operations and Maintenance Expenses
Other operations and maintenance expenses decreased $156 million, or 3.4%, in
2019 as compared to the prior year. The decrease reflects approximately $356
million related to Gulf Power in 2018 and $17 million related to the
dispositions of Southern Power's Florida Plants and Plant Nacogdoches, partially
offset by additional accruals of $123 million to the NDR at Alabama Power, $21
million of increased transmission and distribution expenses primarily due to
overhead line maintenance and vegetation management at the traditional electric
operating companies, $18 million from costs associated with unregulated sales at
Georgia Power primarily associated with new energy conservation projects and
power delivery construction and maintenance contracts, and $16 million related
to an adjustment for FERC fees at Georgia Power following the conclusion of a
multi-year audit of

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headwater benefits associated with hydro facilities. See Notes 2 and 15 to the
financial statements under "Alabama Power - Rate NDR" and "Southern Power -
Sales of Natural Gas and Biomass Plants," respectively, for additional
information.
Depreciation and Amortization
Depreciation and amortization decreased $93 million, or 3.6%, in 2019 as
compared to the prior year. The decrease was primarily due to a decrease of $191
million related to Gulf Power in 2018, partially offset by an increase in
depreciation of $62 million primarily resulting from additional plant in service
and an increase in the amortization of regulatory assets of $47 million
primarily at Mississippi Power and Georgia Power. See Note 2 to the financial
statements under "Southern Company - Regulatory Assets and Liabilities" and Note
5 to the financial statements under "Depreciation and Amortization" for
additional information.
Taxes Other Than Income Taxes
Taxes other than income taxes decreased $87 million, or 7.9%, in 2019 as
compared to the prior year primarily due to a decrease of $118 million related
to the sale of Gulf Power, partially offset by higher property taxes of $30
million primarily at Georgia Power.
Estimated Loss on Plants Under Construction
The $1.1 billion charge in 2018 reflects Georgia Power's revised estimate to
complete construction and start-up of Plant Vogtle Units 3 and 4. The 2019
charges of $24 million were associated with abandonment and closure activities
for the mine and gasifier-related assets of the Kemper IGCC at Mississippi
Power, net of sales proceeds. See Note 2 to the financial statements under
"Georgia Power - Nuclear Construction" and "Mississippi Power - Kemper County
Energy Facility" for additional information.
Impairment Charges
In the second quarter 2018, Southern Power recorded a $119 million asset
impairment charge related to the sale of the Florida Plants and in the third
quarter 2018 recorded a $36 million asset impairment charge on wind turbine
equipment held for development projects. Asset impairment charges recorded in
2019 were immaterial. See Note 15 to the financial statements under "Southern
Power - Sales of Natural Gas and Biomass Plants" and " - Development Projects"
for additional information.
(Gain) Loss on Dispositions, Net
Gain on dispositions, net increased $21 million in 2019 as compared to the prior
year primarily due to Southern Power's sale of Plant Nacogdoches in the second
quarter 2019. See Note 15 to the financial statements under "Southern Power -
Sales of Natural Gas and Biomass Plants" for additional information.
Interest Expense, Net of Amounts Capitalized
Interest expense, net of amounts capitalized decreased $48 million, or 4.6%, in
2019 as compared to the prior year primarily related to the sale of Gulf Power.
Other Income (Expense), Net
Other income (expense), net increased $90 million, or 62.5%, in 2019 as compared
to the prior year primarily due to a $36 million gain arising from the Roserock
solar facility litigation settlement at Southern Power in 2019, $37 million from
decreased charitable donations in 2019 at the traditional electric operating
companies, $23 million of increased non-service cost-related retirement benefits
income, and $16 million of increased interest income primarily associated with a
new tolling arrangement accounted for as a sales-type lease at Mississippi Power
as well as temporary cash investments, primarily at Alabama Power. These
increases were partially offset by $24 million related to the settlement of
Mississippi Power's Deepwater Horizon claim in 2018 and a $14 million gain from
a joint-development wind project at Southern Power in 2018 attributable to its
partner in the project. See Note 3 to the financial statements under "General
Litigation Matters - Southern Power" and "Other Matters - Mississippi Power" and
Note 11 to the financial statements under "Pension Plans" for additional
information.
Income Taxes
Income taxes increased $501 million, or 242.0%, in 2019 as compared to the prior
year. Excluding an income tax benefit of approximately $20 million related to
Gulf Power in 2018, income taxes increased $481 million. The increase was
primarily due to increases in pre-tax earnings, including the $1.1 billion
charge in 2018 associated with Plant Vogtle Units 3 and 4 construction at
Georgia Power. See Notes 10 and 15 to the financial statements for additional
information.

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Net Income Attributable to Noncontrolling Interests
Substantially all noncontrolling interests relate to renewable projects at
Southern Power. Net income attributable to noncontrolling interests decreased
$69 million, or 116.9%, in 2019, as compared to the prior year. The decrease was
primarily due to $92 million of losses attributable to noncontrolling interests
related to the tax equity partnerships entered into in 2018 and $14 million
attributable to a joint-development wind project 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 Note 3
to the financial statements under "General Litigation Matters - Southern Power"
and Note 7 to the financial statements under "Southern Power" for additional
information regarding the litigation settlement and tax equity partnerships,
respectively.
Gas Business
Southern Company Gas distributes natural gas through utilities in four states
and is involved in several other complementary businesses including gas pipeline
investments, wholesale gas services, and gas marketing services.
A condensed statement of income for the gas business follows:
                                                          Increase
                                                         (Decrease)
                                               2019      from 2018
                                                  (in millions)
Operating revenues                           $ 3,792    $     (117 )
Cost of natural gas                            1,319          (220 )
Cost of other sales                                -           (12 )
Other operations and maintenance                 888           (93 )
Depreciation and amortization                    487           (13 )
Taxes other than income taxes                    213             2
Impairment charges                               115            73
(Gain) loss on dispositions, net                   -           291
Total operating expenses                       3,022            28
Operating income                                 770          (145 )
Earnings from equity method investments          157             9
Interest expense, net of amounts capitalized     232             4
Other income (expense), net                       20            19
Income taxes                                     130          (334 )
Net income                                   $   585    $      213


The Southern Company Gas Dispositions were completed by July 29, 2018 and
represent the primary variance driver for 2019 compared to 2018. Detailed
variance explanations are provided herein. See Note 15 to the financial
statements under "Southern Company Gas" for additional information on the
Southern Company Gas Dispositions.
Seasonality of Results
During the period from November through March when natural gas usage and
operating revenues are generally higher (Heating Season), more customers are
connected to Southern Company Gas' distribution systems and natural gas usage is
higher in periods of colder weather. Occasionally in the summer, operating
revenues are impacted due to peak usage by power generators in response to
summer energy demands. Southern Company Gas' base operating expenses, excluding
cost of natural gas, bad debt expense, and certain incentive compensation costs,
are incurred relatively equally over any given year. Thus, operating results can
vary significantly from quarter to quarter as a result of seasonality. For 2019,
the percentage of operating revenues and net income generated during the Heating
Season (January through March and November through December) were 68.7% and
86.8%, respectively. For 2018, the percentage of operating revenues and net
income generated during the Heating Season were 68.7% and 96.0%, respectively.

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Operating Revenues
Operating revenues in 2019 were $3.8 billion, a $117 million decrease compared
to 2018. Details of operating revenues were as follows:
                                                               2019
                                                           (in millions)
Operating revenues - prior year                           $      3,909
Estimated change resulting from -
Infrastructure replacement programs and base rate changes           96
Gas costs and other cost recovery                                  (89 )
Wholesale gas services                                             150
Southern Company Gas Dispositions(*)                              (300 )
Other                                                               26
Operating revenues - current year                         $      3,792
Percent change                                                    (3.0 )%

(*) Includes a $245 million decrease related to natural gas revenues, including

alternative revenue programs, and a $55 million decrease related to other

revenues. See Note 15 to the financial statements under "Southern Company

Gas" for additional information.




Revenues from infrastructure replacement programs and base rate changes
increased in 2019 compared to the prior year primarily due to increases of $74
million at Nicor Gas and $16 million at Atlanta Gas Light. These amounts include
the natural gas distribution utilities' continued investments recovered through
infrastructure replacement programs and base rate increases as well as customer
refunds in 2018 as a result of the Tax Reform Legislation. See Note 2 to the
financial statements under "Southern Company Gas" for additional information.
Revenues attributable to gas costs and other cost recovery decreased in 2019
compared to the prior year primarily due to lower natural gas prices and
decreased volumes of natural gas sold. Natural gas distribution rates include
provisions to adjust billings for fluctuations in natural gas costs. Therefore,
gas costs recovered through natural gas revenues generally equal the amount
expensed in cost of natural gas and do not affect net income from the natural
gas distribution utilities.
Revenues from wholesale gas services increased in 2019 primarily due to
derivative gains, partially offset by decreased commercial activity.
Other natural gas revenues increased in 2019 primarily due to increases in
customers at the natural gas distribution utilities and recovery of prior period
hedge losses at gas marketing services.
Cost of Natural Gas
Excluding Atlanta Gas Light, which does not sell natural gas to end-use
customers, the natural gas distribution utilities charge their utility customers
for natural gas consumed using natural gas cost recovery mechanisms set by the
applicable state regulatory agencies. Under these mechanisms, all
prudently-incurred natural gas costs are passed through to customers without
markup, subject to regulatory review. The natural gas distribution utilities
defer or accrue the difference between the actual cost of natural gas and the
amount of commodity revenue earned in a given period. The deferred or accrued
amount is either billed or refunded to customers prospectively through
adjustments to the commodity rate. Deferred natural gas costs are reflected as
regulatory assets and accrued natural gas costs are reflected as regulatory
liabilities. Therefore, gas costs recovered through natural gas revenues
generally equal the amount expensed in cost of natural gas and do not affect net
income from the natural gas distribution utilities. Cost of natural gas at the
natural gas distribution utilities represented 84.5% of the total cost of
natural gas for 2019.
Gas marketing services customers are charged for actual and estimated natural
gas consumed. Cost of natural gas includes the cost of fuel and associated
transportation costs, lost and unaccounted for gas, adjustments to reduce the
value of inventories to market value, if applicable, and gains and losses
associated with certain derivatives.
In 2019, cost of natural gas was $1.3 billion, a decrease of $220 million, or
14.3%, compared to the prior year. Excluding a $106 million decrease related to
the Southern Company Gas Dispositions, cost of natural gas decreased by $114
million, which reflects a 14.8% decrease in natural gas prices compared to 2018.

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Cost of Other Sales
Cost of other sales related to Pivotal Home Solutions, which was sold on June 4,
2018. See Note 15 to the financial statements under "Southern Company Gas - Sale
of Pivotal Home Solutions" for additional information.
Other Operations and Maintenance Expenses
Other operations and maintenance expenses decreased $93 million, or 9.5%, in
2019 compared to the prior year. Excluding a $65 million decrease related to the
Southern Company Gas Dispositions, other operations and maintenance expenses
decreased $28 million. This decrease was primarily due to $28 million of
disposition-related costs incurred during 2018, a $12 million adjustment in 2018
for the adoption of a new paid time off policy, an $11 million expense for a
litigation settlement to facilitate the sale of Pivotal Home Solutions in 2018,
and a $7 million decrease in compensation and benefits costs, partially offset
by a $22 million increase in rider expenses, primarily at Nicor Gas, passed
through directly to customers. See FUTURE EARNINGS POTENTIAL - "Southern Company
Gas - Utility Regulation and Rate Design" herein for additional information.
Depreciation and Amortization
Depreciation and amortization decreased $13 million, or 2.6%, in 2019 compared
to the prior year. Excluding a $27 million decrease related to the Southern
Company Gas Dispositions, depreciation and amortization increased $14 million.
This increase was primarily due to continued infrastructure investments at the
natural gas distribution utilities, partially offset by accelerated depreciation
related to assets retired in 2018. See Note 2 to the financial statements under
"Southern Company Gas - Infrastructure Replacement Programs and Capital
Projects" for additional information.
Impairment Charges
In 2019, Southern Company Gas recorded impairment charges of $91 million related
to a natural gas storage facility in Louisiana and $24 million in contemplation
of the sale of its interests in Pivotal LNG and Atlantic Coast Pipeline. In
2018, a goodwill impairment charge of $42 million was recorded in contemplation
of the sale of Pivotal Home Solutions. See Notes 1, 3, and 15 to the financial
statements under "Goodwill and Other Intangible Assets and Liabilities," "Other
Matters - Southern Company Gas," and "Southern Company Gas," respectively, for
additional information.
(Gain) Loss on Dispositions, Net
Gain on dispositions, net was $291 million in 2018 and was associated with the
Southern Company Gas Dispositions. The income tax expense on these gains
included income tax expense on goodwill not deductible for tax purposes and for
which a deferred tax liability had not been recorded previously.
Earnings from Equity Method Investments
Earnings from equity method investments increased $9 million, or 6.1%, in 2019
compared to the prior year and reflect higher earnings from SNG as a result of
rate increases that became effective September 2018, partially offset by a $6
million pre-tax loss on the sale of Triton in May 2019. See Note 7 to the
financial statements under "Southern Company Gas" for additional information.
Other Income (Expense), Net
Other income (expense), net increased $19 million in 2019 compared to the prior
year. This increase primarily resulted from a $23 million decrease in charitable
donations in 2019.
Income Taxes
Income taxes decreased $334 million, or 72.0%, in 2019 compared to the prior
year. This decrease primarily reflects a reduction of $348 million related to
the Southern Company Gas Dispositions, as well as $29 million in benefits
associated with impairment charges in 2019 and additional benefits from the
flowback of excess deferred income taxes in 2019 primarily at Atlanta Gas Light
as previously authorized by the Georgia PSC, partially offset by $48 million of
additional taxes associated with increased pre-tax earnings at wholesale gas
services.
See FUTURE EARNINGS POTENTIAL - "Income Tax Matters" herein and Note 10 to the
financial statements for additional information. Also see Notes 2, 3, and 15 to
the financial statements under "Southern Company Gas," "Other Matters - Southern
Company Gas," and "Southern Company Gas - Proposed Sale of Pivotal LNG and
Atlantic Coast Pipeline," respectively, for additional information on Atlanta
Gas Light's regulatory treatment of the impacts of the Tax Reform Legislation
and the impairment charges.

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Other Business Activities
Southern Company's other business activities primarily include the parent
company (which does not allocate operating expenses to business units);
PowerSecure, a provider of energy solutions to electric utilities and their
customers in the areas of distributed generation, energy storage and renewables,
and energy efficiency; Southern Holdings, which invests in various projects,
including leveraged lease projects; and Southern Linc, which provides digital
wireless communications for use by the Southern Company system and also markets
these services to the public and provides fiber optics services within the
Southeast.
A condensed statement of income for Southern Company's other business activities
follows:
                                                Increase
                                               (Decrease)
                                    2019        from 2018
                                       (in millions)
Operating revenues               $    532     $      (483 )
Cost of other sales                   359            (369 )
Other operations and maintenance      233             (40 )
Depreciation and amortization          79              13
Taxes other than income taxes           6               -
Impairment charges                     50              38
(Gain) loss on dispositions, net   (2,548 )        (2,548 )
Total operating expenses           (1,821 )        (2,906 )
Operating income (loss)             2,353           2,423
Interest expense                      517             (62 )
Other income (expense), net            10              33
Income taxes (benefit)                960           1,182
Net income (loss)                $    886     $     1,336


Operating Revenues
Southern Company's operating revenues for these other business activities
decreased $483 million, or 47.6%, in 2019 as compared to the prior year
primarily related to PowerSecure's 2018 storm restoration services in Puerto
Rico and the sale of PowerSecure's utility infrastructure services business in
June 2019.
Cost of Other Sales
Cost of other sales for these other business activities decreased $369 million,
or 50.7%, in 2019 as compared to the prior year primarily related to
PowerSecure's 2018 storm restoration services in Puerto Rico and the sale of
PowerSecure's utility infrastructure services business in June 2019.
Other Operations and Maintenance Expenses
Other operations and maintenance expenses for these other business activities
decreased $40 million, or 14.7%, in 2019 as compared to the prior year. The
decrease was primarily due to PowerSecure's lower employee compensation and
benefits in 2019 and 2018 storm restoration services in Puerto Rico.
Impairment Charges
In 2019, goodwill and asset impairment charges totaling $50 million were
recorded related to the sale of PowerSecure's utility infrastructure services
and lighting businesses. In 2018, asset impairment charges of $12 million
associated with Southern Linc's tower leases were recorded in contemplation of
the sale of Gulf Power.
(Gain) Loss on Dispositions, Net
The 2019 gain on dispositions, net primarily relates to the gain of $2.6 billion
($1.4 billion after tax) on the sale of Gulf Power. See Note 15 to the financial
statements under "Southern Company" for additional information.

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Interest Expense
Interest expense for these other business activities decreased $62 million, or
10.7%, in 2019 as compared to the prior year primarily due to a decrease in
average outstanding long-term debt at the parent company. See Note 8 to the
financial statements for additional information.
Other Income (Expense), Net
Other income (expense), net for these other business activities increased $33
million in 2019 as compared to the prior year primarily due to a $43 million
decrease in charitable donations at the parent company, partially offset by a
$17 million impairment charge associated with a leveraged lease at Southern
Holdings in 2019. See Notes 1 and 3 to the financial statements under "Leveraged
Leases" and "Other Matters - Southern Company," respectively, for additional
information.
Income Taxes (Benefit)
The income tax for these other business activities increased $1.2 billion in
2019 as compared to the prior year primarily due to the tax impacts related to
the sale of Gulf Power. See Note 10 to the financial statements and Note 15 to
the financial statements under "Southern Company" for additional information.
Alabama Power
Alabama Power's 2019 net income after dividends on preferred and preference
stock was $1.07 billion, representing a $140 million, or 15.1%, increase over
the previous year. The increase was primarily due to an increase in retail
revenues associated with the impacts of customer bill credits issued in 2018
related to the Tax Reform Legislation and a lower Rate RSE customer refund in
2019 as compared to the prior year, as well as additional capital investments
recovered through Rate CNP Compliance. The increase in revenue is partially
offset by increases in operations and maintenance and depreciation expenses and
lower customer usage. See FUTURE EARNINGS POTENTIAL - "Regulatory Matters -
Alabama Power - Rate RSE" and " - Rate CNP Compliance" herein for additional
information.
A condensed income statement for Alabama Power follows:
                                                                          Increase
                                                                         (Decrease)
                                                               2019      from 2018
                                                                  (in millions)
Operating revenues                                           $ 6,125    $      93
Fuel                                                           1,112         (189 )
Purchased power                                                  403          (29 )
Other operations and maintenance                               1,821          152
Depreciation and amortization                                    793           29
Taxes other than income taxes                                    403           14
Total operating expenses                                       4,532          (23 )
Operating income                                               1,593          116
Allowance for equity funds used during construction               52          (10 )
Interest expense, net of amounts capitalized                     336           13
Other income (expense), net                                       46           26
Income taxes                                                     270          (21 )
Net income                                                     1,085          140
Dividends on preferred and preference stock                       15

Net income after dividends on preferred and preference stock $ 1,070 $


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Operating Revenues Operating revenues for 2019 were $6.1 billion, reflecting a $0.1 billion increase from 2018. Details of operating revenues were as follows:


                                    2019         2018
                                      (in millions)
Retail - prior year               $ 5,367
Estimated change resulting from -
Rates and pricing                     347
Sales decline                         (79 )
Weather                                (3 )
Fuel and other cost recovery         (131 )
Retail - current year               5,501     $ 5,367
Wholesale revenues -
Non-affiliates                        258         279
Affiliates                             81         119
Total wholesale revenues              339         398
Other operating revenues              285         267
Total operating revenues          $ 6,125     $ 6,032
Percent change                        1.5 %      (0.1 )%


Retail revenues in 2019 were $5.5 billion. These revenues increased $134
million, or 2.5%, in 2019 as compared to the prior year. The increase in 2019
was primarily due to increases in rates and pricing associated with the impact
of customer bill credits issued in 2018 related to the Tax Reform Legislation
and additional capital investments recovered through Rate CNP Compliance, as
well as a lower Rate RSE customer refund in 2019 as compared to the prior year,
partially offset by decreases in fuel revenues and customer usage, as well as
milder weather in 2019 as compared to 2018.
See Note 2 to the financial statements under "Alabama Power - Rate RSE" and " -
Rate CNP Compliance" for additional information. See "Energy Sales" herein for a
discussion of changes in the volume of energy sold, including changes related to
sales decline and weather.
Electric rates include provisions to recognize the recovery of fuel costs,
purchased power costs, PPAs certificated by the Alabama PSC, and costs
associated with the natural disaster reserve. Under these provisions, fuel and
other cost recovery revenues generally equal fuel and other cost recovery
expenses and do not affect net income. See FUTURE EARNINGS POTENTIAL -
"Regulatory Matters - Alabama Power - Rate ECR" herein for additional
information.
Wholesale revenues from power sales to non-affiliated utilities were as follows:
                         2019         2018
                         (in millions)
Capacity and other   $    102        $ 101
Energy                    156          178

Total non-affiliated $ 258 $ 279




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 electric service territory, and 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.

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In 2019, wholesale revenues from sales to non-affiliates decreased $21 million,
or 7.5%, as compared to the prior year primarily as a result of an 8.2% decrease
in energy prices due to lower natural gas prices, partially offset by a 1%
increase in the amount of KWHs sold.
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 and purchases 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 2019, wholesale revenues from sales to affiliates decreased $38 million, or
31.9%, as compared to the prior year. In 2019, KWH sales decreased 22.7% due to
the decreased availability of coal generation associated with the retirement of
Plant Gorgas Units 8, 9, and 10, and the price of energy decreased 11.8% as a
result of lower natural gas prices.
In 2019, other operating revenues increased $18 million, or 6.7%, as compared to
the prior year primarily due to an increase in unregulated sales of products and
services and pole attachment agreements.
Energy Sales
Changes in revenues are influenced heavily by the change in the volume of energy
sold from year to year. KWH sales for 2019 and the percent change from the prior
year were as follows:
                                           2019
                       Total           Total KWH       Weather-Adjusted
                        KWHs        Percent Change      Percent Change
                   (in billions)
Residential                 18.3          (1.9 )%            (1.5 )%
Commercial                  13.6          (2.2 )             (2.2 )
Industrial                  22.1          (3.7 )             (3.7 )
Other                        0.2          (7.3 )             (7.3 )
Total retail                54.2          (2.8 )             (2.6 )%
Wholesale
Non-affiliates               5.1           1.2
Affiliates                   3.5         (22.7 )
Total wholesale              8.6         (10.1 )
Total energy sales          62.8          (3.8 )%


Changes in retail energy sales are generally the result of changes in
electricity usage by customers, changes in weather, and changes in the number of
customers. Retail energy sales in 2019 decreased 2.8% primarily due to lower
customer usage and milder weather in 2019 compared to 2018. Weather-adjusted
residential sales were 1.5% lower in 2019 primarily due to lower customer usage
resulting from an increase in penetration of energy-efficient residential
appliances, partially offset by customer growth. Weather-adjusted commercial
sales were 2.2% lower in 2019 primarily due to lower customer usage resulting
from customer initiatives in energy savings and an ongoing migration to the
electronic commerce business model, partially offset by customer growth.
Industrial sales decreased 3.7% in 2019 as compared to 2018 primarily as a
result of changes in production levels in the primary metals and chemicals
sectors.
See "Operating Revenues" above for a discussion of significant changes in
wholesale revenues from sales to non-affiliates and wholesale revenues from
sales to affiliated companies related to changes in price and KWH sales.
Fuel and Purchased Power Expenses
The mix of fuel sources for generation of electricity is determined primarily by
the unit cost of fuel consumed, demand, and the availability of generating
units. Additionally, Alabama Power purchases a portion of its electricity needs
from the wholesale market.

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


                                                             2019    2018
Total generation (in billions of KWHs)                       56.9    60.5
Total purchased power (in billions of KWHs)                   9.4     8.1
Sources of generation (percent) -
Coal                                                           45      50
Nuclear                                                        25      23
Gas                                                            21      19
Hydro                                                           9       8
Cost of fuel, generated (in cents per net KWH) -
Coal                                                         2.69    2.73
Nuclear                                                      0.77    0.77
Gas                                                          2.47    2.84

Average cost of fuel, generated (in cents per net KWH)(a)(b) 2.11 2.26 Average cost of purchased power (in cents per net KWH)(c) 4.39 5.47

(a) For 2018, cost of fuel, generated and average cost of fuel, generated

excludes a $30 million adjustment associated with a May 2018 Alabama PSC

accounting order related to excess deferred income taxes. See FUTURE EARNINGS

POTENTIAL - "Regulatory Matters - Alabama Power - Tax Reform Accounting

Order" herein for additional information.

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

generated.

purchased by Alabama Power for tolling agreements where power is generated by

the provider.




Fuel and purchased power expenses were $1.5 billion in 2019, a decrease of $218
million, or 12.6%, compared to 2018. The decrease was primarily due to a $102
million decrease in the average cost of purchased power, a $56 million decrease
in the average cost of fuel, a $30 million net decrease related to the volume of
KWHs purchased and generated, and a $30 million decrease in fuel expense
associated with the May 2018 Alabama PSC accounting order.
Fuel and purchased power energy transactions do not have a significant impact on
earnings, since energy expenses are generally offset by energy revenues through
Alabama Power's energy cost recovery clause. Alabama Power, along with the
Alabama PSC, continuously monitors the under/over recovered balance to determine
whether adjustments to billing rates are required. See Note 2 to the financial
statements under "Alabama Power - Rate ECR" for additional information.
Fuel
Fuel expenses were $1.1 billion in 2019, a decrease of $189 million, or 14.5%,
compared to 2018. The decrease was primarily due to a 13% decrease in the
average cost of KWHs generated by natural gas, which excludes tolling
agreements, a 14.4% decrease in the volume of KWHs generated by coal, and a 5.2%
increase in the volume of KWHs generated by hydro, as well as a $30 million
decrease in fuel expense associated with the May 2018 Alabama PSC accounting
order.
Purchased Power - Non-Affiliates
Purchased power expense from non-affiliates was $203 million in 2019, a decrease
of $13 million, or 6.0%, compared to 2018. This decrease was primarily due to a
12.6% decrease in the average cost per KWH purchased due to lower natural gas
prices. The decrease was partially offset by a 9.1% increase in the amount of
energy purchased as a result of decreased coal generation due to the retirement
of Plant Gorgas Units 8, 9, and 10.
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 service
territory, and the availability of the Southern Company system's generation.
Purchased Power - Affiliates
Purchased power expense from affiliates was $200 million in 2019, a decrease of
$16 million, or 7.4%, compared to 2018. This decrease was primarily due to a
25.2% decrease in the average cost per KWH purchased due to lower natural gas
prices. The decrease was partially offset by a 24.1% increase in the amount of
energy purchased primarily due to the availability of lower-cost

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generation compared to Alabama Power's owned generation and a decrease in coal
generation due to the retirement of Plant Gorgas Units 8, 9, and 10.
Energy purchases from affiliates will vary depending on demand for energy 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, as approved by the FERC.
Other Operations and Maintenance Expenses
In 2019, other operations and maintenance expenses increased $152 million, or
9.1%, as compared to the prior year primarily due to additional accruals of $123
million to the NDR as well as $11 million in Rate CNP Compliance-related
expenses. See Note 2 to the financial statements under "Alabama Power - Rate
NDR" and " - Rate CNP Compliance" for additional information.
Depreciation and Amortization
Depreciation and amortization increased $29 million, or 3.8%, in 2019 as
compared to the prior year primarily due to additional plant in service. See
Note 5 to the financial statements under "Depreciation and Amortization" for
additional information.
Other Income (Expense), Net
Other income (expense), net increased $26 million, or 130.0%, in 2019 as
compared to the prior year primarily due to a decrease of $17 million in
charitable donations and an increase of $9 million in interest income from
temporary cash investments.
Income Taxes
Income taxes decreased $21 million, or 7.2%, in 2019 as compared to the prior
year primarily due to additional benefits from the flowback of excess deferred
income taxes in accordance with an Alabama PSC accounting order, partially
offset by an increase in pre-tax net income. See Note 2 to the financial
statements under "Alabama Power - Tax Reform Accounting Order" for additional
information.
Georgia Power
Georgia Power's 2019 net income was $1.7 billion, representing a $927 million,
or 116.9%, increase from the previous year. 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 base revenues associated with higher
contributions from commercial and industrial customers with variable
demand-driven pricing, 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.
A condensed income statement for Georgia Power follows:
                                                          Increase
                                                         (Decrease)
                                               2019      from 2018
                                                  (in millions)
Operating revenues                           $ 8,408    $     (12 )
Fuel                                           1,444         (254 )
Purchased power                                1,096          (57 )
Other operations and maintenance               1,972          112
Depreciation and amortization                    981           58
Taxes other than income taxes                    454           17

Estimated loss on Plant Vogtle Units 3 and 4 - (1,060 ) Total operating expenses

                       5,947       (1,184 )
Operating income                               2,461        1,172
Interest expense, net of amounts capitalized     409           12
Other income (expense), net                      140           25
Income taxes                                     472          258
Net income                                   $ 1,720    $     927



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Operating Revenues
Operating revenues for 2019 were $8.4 billion, a $12 million decrease from 2018.
Details of operating revenues were as follows:
                                     2019        2018
                                      (in millions)
Retail - prior year               $ 7,752
Estimated change resulting from -
Rates and pricing                     202
Sales decline                         (66 )
Weather                                39
Fuel cost recovery                   (220 )
Retail - current year               7,707      $ 7,752
Wholesale revenues -
Non-affiliates                        129          163
Affiliates                             11           24
Total wholesale revenues              140          187
Other operating revenues              561          481
Total operating revenues          $ 8,408      $ 8,420
Percent change                       (0.1 )%       1.3 %


Retail revenues of $7.7 billion in 2019 decreased $45 million, or 0.6%, compared
to 2018. The significant factors driving this change are shown in the preceding
table. The increase in rates and pricing was primarily due to higher
contributions from commercial and industrial customers with variable
demand-driven pricing, an increase in the NCCR tariff effective January 1, 2019,
and pricing effects associated with a milder winter in 2019 compared to 2018.
See Note 2 to the financial statements under "Georgia Power - Nuclear
Construction" for additional information related to the NCCR tariff.
See "Energy Sales" below for a discussion of changes in the volume of energy
sold, including changes related to the sales decline in 2019.
Electric rates include provisions to 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 FUTURE EARNINGS POTENTIAL - "Regulatory Matters - Georgia
Power - Fuel Cost Recovery" herein for additional information.
Wholesale revenues from power sales to non-affiliated utilities were as follows:
                         2019         2018
                         (in millions)
Capacity and other   $     55        $  54
Energy                     74          109
Total non-affiliated $    129        $ 163


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.
Wholesale revenues from non-affiliated sales decreased $34 million, or 20.9%, in
2019 as compared to 2018 primarily due to lower energy prices and lower demand.

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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. In 2019, wholesale revenues from
sales to affiliates decreased $13 million, or 54.2%, as compared to 2018
primarily due to a 36.3% decrease in KWH sales as a result of the lower market
cost of available energy compared to the cost of Georgia Power-owned generation.
Other operating revenues increased $80 million, or 16.6%, in 2019 from the prior
year primarily due to revenue increases of $27 million from power delivery
construction and maintenance contracts, $20 million from unregulated sales
associated with new energy conservation projects, $11 million from outdoor
lighting LED conversions and sales, $7 million from OATT sales, and $6 million
in wholesale operating fees associated with contractual targets.
Energy Sales
Changes in revenues are influenced heavily by the change in the volume of energy
sold from year to year. KWH sales for 2019 and the percent change from the prior
year were as follows:
                                           2019
                       Total           Total KWH       Weather-Adjusted
                        KWHs        Percent Change      Percent Change
                   (in billions)
Residential                 28.2          (0.5 )%            (0.4 )%
Commercial                  32.8          (0.4 )             (1.3 )
Industrial                  23.2          (2.1 )             (2.2 )
Other                        0.5          (5.6 )             (5.5 )
Total retail                84.7          (0.9 )             (1.2 )%
Wholesale
Non-affiliates               2.7         (15.8 )
Affiliates                   0.3         (36.3 )
Total wholesale              3.0         (18.7 )
Total energy sales          87.7          (1.7 )%


Changes in retail energy sales are generally the result of changes in
electricity usage by customers, changes in weather, and changes in the number of
customers.
In 2019, weather-adjusted residential and commercial KWH sales decreased 0.4%
and 1.3%, respectively, compared to 2018 primarily due to a decline in average
customer usage resulting from an increase in energy saving initiatives. The
decreases in weather-adjusted residential and commercial KWH sales were largely
and partially, respectively, offset by customer growth. Weather-adjusted
industrial KWH sales decreased 2.2% primarily due to decreases in the paper,
textile, stone, clay, and glass, and lumber sectors, partially offset by an
increase in the pipeline sector.
See "Operating Revenues" above for a discussion of significant changes in
wholesale sales to non-affiliates and affiliated companies.
Fuel and Purchased Power Expenses
Fuel costs constitute one of the largest expenses for Georgia Power. The mix of
fuel sources for the generation of electricity is determined primarily by
demand, the unit cost of fuel consumed, and the availability of generating
units. Additionally, Georgia Power purchases a portion of its electricity needs
from the wholesale market.

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


                                                          2019    2018
Total generation (in billions of KWHs)                    62.6    65.2
Total purchased power (in billions of KWHs)               29.1    27.9
Sources of generation (percent) -
Gas                                                         47      42
Nuclear                                                     26      25
Coal                                                        24      30
Hydro                                                        3       3
Cost of fuel, generated (in cents per net KWH) -
Gas                                                       2.42    2.75
Nuclear                                                   0.81    0.82
Coal                                                      3.09    3.21

Average cost of fuel, generated (in cents per net KWH) 2.16 2.40 Average cost of purchased power (in cents per net KWH)(*) 4.21 4.79




(*) Average cost of purchased power includes fuel purchased by Georgia Power for
tolling agreements where power is generated by the provider.
Fuel and purchased power expenses were $2.5 billion in 2019, a decrease of $311
million, or 10.9%, compared to 2018. The decrease was primarily due to a $289
million decrease related to the average cost of fuel and purchased power.
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 FUTURE EARNINGS POTENTIAL -
"Regulatory Matters - Georgia Power - Fuel Cost Recovery" herein for additional
information.
Fuel
Fuel expense was $1.4 billion in 2019, a decrease of $254 million, or 15.0%,
compared to 2018. The decrease was primarily due to a 10% decrease in the
average cost of fuel, primarily related to lower natural gas prices, and a 3.9%
decrease in the volume of KWHs generated, primarily due to the lower market cost
of energy compared to available Georgia Power resources.
Purchased Power - Non-Affiliates
Purchased power expense from non-affiliates was $521 million in 2019, an
increase of $91 million, or 21.2%, compared to 2018. The increase was primarily
due to a 53.1% increase in the volume of KWHs purchased primarily due to the
lower market cost of energy compared to available Southern Company system
resources and warmer weather in the third quarter 2019 resulting in higher
customer demand, partially offset by a 22.1% decrease in the average cost per
KWH purchased primarily due to lower energy prices.
The volume increase also reflects purchases from Gulf Power which were
classified as affiliate prior to January 1, 2019. See Note 15 to the financial
statements 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.
Purchased Power - Affiliates
Purchased power expense from affiliates was $575 million in 2019, a decrease of
$148 million, or 20.5%, compared to 2018. The decrease was primarily due to an
11.1% decrease in the volume of KWHs purchased as Georgia Power units generally
dispatched at a lower cost than other Southern Company system resources and a
13.0% decrease in the average cost per KWH purchased resulting from lower energy
prices.
The decrease in purchased power expense from affiliates also reflects a change
in the classification of capacity expenses of $24 million 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 decrease in the volume of KWHs purchased also includes the effect of
classifying purchases from Gulf Power as

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non-affiliate beginning January 1, 2019. See Notes 9 and 15 to the financial
statements for additional information regarding ASC 842 and the sale of Gulf
Power, respectively.
Energy purchases from affiliates will vary depending on the 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.
Other Operations and Maintenance Expenses
In 2019, other operations and maintenance expenses increased $112 million, or
6.0%, compared to 2018. The increase reflects increases in expenses of $30
million from unregulated sales primarily associated with new energy conservation
projects and power delivery construction and maintenance contracts, $26 million
related to scheduled generation outages, $16 million related to an adjustment
for FERC fees following the conclusion of a multi-year audit of headwater
benefits associated with hydro facilities, $12 million primarily due to the
timing of vegetation management and other transmission-related expenses, and $10
million associated with generation maintenance.
Depreciation and Amortization
Depreciation and amortization increased $58 million, or 6.3%, in 2019 compared
to 2018. The increase was primarily due to a $31 million increase in
depreciation associated with additional plant in service and a $19 million
increase in the amortization of regulatory assets related to the retirement of
certain generating units. See FUTURE EARNINGS POTENTIAL - "Regulatory Matters -
Georgia Power - Integrated Resource Plan" herein for additional information on
unit retirements.
The increase also reflects the classification of approximately $9 million
related to PPAs with Southern Power accounted for as finance leases following
the adoption of ASC 842. In prior periods, the expenses related to these PPAs
were included in purchased power, affiliates. See Note 9 to the financial
statements for additional information regarding ASC 842.
See Note 5 to the financial statements under "Depreciation and Amortization" for
additional information.
Taxes Other Than Income Taxes
In 2019, taxes other than income taxes increased $17 million, or 3.9%, compared
to 2018 primarily due to higher property taxes of $25 million as a result of
increases in the assessed value of property, partially offset by a decrease of
$11 million in municipal franchise fees, largely due to adjustments associated
with the Georgia Power Tax Reform Settlement Agreement. See FUTURE EARNINGS
POTENTIAL - "Regulatory Matters - Georgia Power - Rate Plans - Tax Reform
Settlement Agreement" herein for additional information.
Estimated Loss on Plant Vogtle Units 3 and 4
In the second quarter 2018, an estimated probable loss of $1.1 billion was
recorded to reflect Georgia Power's revised estimate to complete construction
and start-up of Plant Vogtle Units 3 and 4. See ACCOUNTING POLICIES - "Estimated
Cost, Schedule, and Rate Recovery for the Construction of Plant Vogtle Units 3
and 4" herein and Note 2 to the financial statements under "Georgia Power -
Nuclear Construction" for additional information.
Interest Expense, Net of Amounts Capitalized
In 2019, interest expense, net of amounts capitalized increased $12 million, or
3.0%, compared to 2018. The increase was primarily due to the reclassification
of $15 million related to PPAs with Southern Power accounted for as finance
leases following the adoption of ASC 842 and a $6 million increase in interest
expense associated with an increase in outstanding short-term borrowings,
partially offset by a $9 million increase in amounts capitalized largely
associated with Plant Vogtle Units 3 and 4.
In prior periods, the expenses related to the PPAs with Southern Power were
included in purchased power, affiliates. See FINANCIAL CONDITION AND LIQUIDITY -
"Sources of Capital" and "Financing Activities" herein for additional
information on borrowings, Note 9 to the financial statements for additional
information regarding ASC 842, and Note 2 to the financial statements under
"Georgia Power - Nuclear Construction" for additional information regarding
Plant Vogtle Units 3 and 4.
Other Income (Expense), Net
In 2019, other income (expense), net increased $25 million compared to the prior
year primarily due to a $16 million increase in non-service cost-related
retirement benefits income and a $13 million decrease in charitable donations,
partially offset by a $4 million decrease in interest income from temporary cash
investments. See Note 11 to the financial statements for additional information
on Georgia Power's net periodic pension and other postretirement benefit costs.

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Income Taxes
Income taxes increased $258 million, or 120.6%, in 2019 compared to the prior
year primarily as a result of higher pre-tax earnings largely due to the 2018
charge associated with Plant Vogtle Units 3 and 4 construction. This increase
was partially offset by additional state ITCs recognized in 2019 and the
recognition of a valuation allowance in 2018. See Note 10 to the financial
statements for additional information.
Mississippi Power
Mississippi Power's net income after dividends on preferred stock was $139
million in 2019 compared to $235 million in 2018. The change was primarily the
result of higher income tax expense following the 2018 partial reversal of a
valuation allowance.
A condensed statement of operations follows:
                                                                 Increase
                                                                (Decrease)
                                                      2019      from 2018
                                                         (in millions)
Operating revenues                                  $ 1,264    $      (1 )
Fuel                                                    407            2
Purchased power                                          20          (21 )
Other operations and maintenance                        283          (30 )
Depreciation and amortization                           192           23
Taxes other than income taxes                           113            6
Estimated loss on Kemper IGCC                            24          (13 )
Total operating expenses                              1,039          (33 )
Operating income                                        225           32
Allowance for equity funds used during construction       1            1
Interest expense, net of amounts capitalized             69           (7 )
Other income (expense), net                              12           (5 )
Income taxes (benefit)                                   30          132
Net income                                              139          (97 )
Dividends on preferred stock                              -           (1 )

Net income after dividends on preferred stock $ 139 $ (96 )


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Operating Revenues Operating revenues for 2019 were approximately $1.3 billion, a $1 million decrease from 2018. Details of operating revenues were as follows:


                                     2019        2018
                                      (in millions)
Retail - prior year               $   889
Estimated change resulting from -
Rates and pricing                      31
Weather                                (2 )
Fuel and other cost recovery          (41 )
Retail - current year                 877      $   889
Wholesale revenues -
Non-affiliates                        237          263
Affiliates                            132           91
Total wholesale revenues              369          354
Other operating revenues               18           22
Total operating revenues          $ 1,264      $ 1,265
Percent change                       (0.1 )%       6.6 %


Total retail revenues for 2019 decreased $12 million, or 1.3%, compared to 2018
primarily due to a fuel rate decrease that became effective for the first
billing cycle of February 2019. This decrease was largely offset by an increase
in rates and pricing, primarily related to PEP and ECO Plan rate changes that
became effective for the first billing cycle of September 2018, net of a new
tolling arrangement accounted for as a sales-type lease effective January 2019.
See Note 2 to the financial statements under "Mississippi Power - Environmental
Compliance Overview Plan" and " - Performance Evaluation Plan" and Note 9 to the
financial statements under "Lessor" for additional information.
See "Energy Sales" below for a discussion of changes in the volume of energy
sold, including changes related to sales and weather.
Electric rates for Mississippi Power 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,
including the energy component of purchased power costs, and do not affect net
income. Recoverable fuel costs include fuel and purchased power expenses reduced
by the fuel and emissions portion of wholesale revenues from energy sold to
customers outside Mississippi Power's service territory. See FUTURE EARNINGS
POTENTIAL - "Regulatory Matters - Mississippi Power - Fuel Cost Recovery" herein
for additional information.
Wholesale revenues from power sales to non-affiliated utilities, including
FERC-regulated MRA sales as well as market-based sales, were as follows:
                         2019         2018
                         (in millions)
Capacity and other   $      3        $   6
Energy                    234          257

Total non-affiliated $ 237 $ 263




Wholesale revenues from sales to non-affiliates will vary depending on fuel
prices, the market prices of wholesale energy compared to the cost of
Mississippi 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. In addition, Mississippi Power provides service under long-term
contracts with rural electric cooperative associations and municipalities
located in southeastern Mississippi under cost-based electric tariffs which are
subject to regulation by the FERC. The contracts with these wholesale customers
represented 15.7% of Mississippi Power's total

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operating revenues in 2019 and are generally subject to 10-year rolling
cancellation notices. Historically, these wholesale customers have acted as a
group and any changes in contractual relationships for one customer are likely
to be followed by the other wholesale customers. Short-term opportunity energy
sales are also included in sales for resale to non-affiliates. These opportunity
sales are made at market-based rates that generally provide a margin above
Mississippi Power's variable cost to produce the energy.
Wholesale revenues from sales to non-affiliates decreased $26 million, or 9.9%,
compared to 2018. This decrease primarily reflects decreases of $14 million from
lower fuel prices, $6 million from decreased customer usage, and $8 million from
lower PPA capacity and energy sales.
Wholesale revenues from sales to affiliates 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.
Wholesale revenues from sales to affiliates increased $41 million, or 45.1%, in
2019 compared to 2018. This increase was primarily due to a $76 million increase
associated with higher KWH sales due to the dispatch of Mississippi Power's
lower cost generation resources to serve the Southern Company system's
territorial load, partially offset by a $35 million decrease associated with
lower natural gas prices.
Energy Sales
Changes in revenues are influenced heavily by the change in the volume of energy
sold from year to year. KWH sales for 2019 and the percent change from the prior
year were as follows:
                                                                     2019
                                             Total             Total KWH           Weather-Adjusted
                                             KWHs           Percent Change          Percent Change
                                         (in millions)
Residential                                     2,062             (2.4 )%              (0.8 )%
Commercial                                      2,715             (2.9 )               (2.7 )
Industrial                                      4,795             (2.6 )               (2.6 )
Other                                              36             (1.9 )               (1.9 )
Total retail                                    9,608             (2.7 )               (2.2 )%
Wholesale
Non-affiliated                                  3,966             (0.3 )
Affiliated                                      4,758             84.1
Total wholesale                                 8,724             32.9
Total energy sales                             18,332             11.5  %


Changes in retail energy sales are generally the result of changes in
electricity usage by customers, changes in weather, and changes in the number of
customers. Retail energy sales decreased 2.7% in 2019 as compared to the prior
year, primarily due to decreased demand by several large industrial customers.
Weather-adjusted residential and commercial KWH sales decreased 0.8% and 2.7%,
respectively, in 2019 primarily due to decreased customer usage as a result of
an increase in energy saving initiatives, slightly offset by customer growth.
See "Operating Revenues" above for a discussion of significant changes in
wholesale revenues to affiliated companies.
Fuel and Purchased Power Expenses
The mix of fuel sources for generation of electricity is determined primarily by
demand, the unit cost of fuel consumed, and the availability of generating
units. Additionally, Mississippi Power purchases a portion of its electricity
needs from the wholesale market.

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


                                                        2019      2018
Total generation (in millions of KWHs)                 18,269    15,966
Total purchased power (in millions of KWHs)               529       960
Sources of generation (percent) -
Gas                                                        94        93
Coal                                                        6         7
Cost of fuel, generated (in cents per net KWH) -
Gas                                                      2.26      2.65
Coal                                                     4.05      3.50

Average cost of fuel, generated (in cents per net KWH) 2.37 2.72 Average cost of purchased power (in cents per net KWH) 3.71 4.27




Fuel and purchased power expenses were $427 million in 2019, a decrease of $19
million, or 4.3%, as compared to the prior year. The decrease was primarily due
to a $60 million decrease related to the average cost of fuel and purchased
power primarily due to the lower average cost of natural gas, partially offset
by a $41 million net increase associated with the volume of KWHs generated and
purchased primarily due to the availability of Mississippi Power's lower-cost
generation resources.
Fuel and purchased power energy transactions do not have a significant impact on
earnings, since energy expenses are generally offset by energy revenues through
Mississippi Power's fuel cost recovery clauses. See FUTURE EARNINGS POTENTIAL -
"Regulatory Matters - Mississippi Power - Fuel Cost Recovery" herein and Note 1
to the financial statements under "Fuel Costs" for additional information.
Fuel
Fuel expense increased $2 million, or 0.5%, in 2019 compared to 2018 primarily
due to a 15% increase in the volume of KWHs generated, partially offset by a 13%
net decrease in the average cost of fuel per KWH generated.
Purchased Power
Purchased power expense decreased $21 million, or 51.2%, in 2019 compared to
2018. The decrease was primarily the result of a 45% decrease in the volume of
KWHs purchased due to the availability of Mississippi Power's lower-cost
generation resources and a 13% decrease in the average cost per KWH purchased.
Energy purchases 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 service territory, and the
availability of the Southern Company system's generation. These purchases are
made in accordance with the IIC or other contractual agreements, as approved by
the FERC.
Other Operations and Maintenance Expenses
Other operations and maintenance expenses decreased $30 million, or 9.6%, in
2019 compared to the prior year. The decrease was primarily due to decreases of
$21 million in compensation and benefit expenses primarily due to an employee
attrition plan implemented in the third quarter 2018, $5 million in amortization
of previously deferred Plant Ratcliffe expenses as a result of a settlement
agreement reached with wholesale customers (MRA Settlement Agreement), $5
million in planned generation outage costs, and $4 million in Plant Ratcliffe
waste water treatment expenses. These decreases were partially offset by a $9
million increase in overhead line maintenance and vegetation management
expenses. See Note 2 to the financial statements under "Mississippi Power -
Municipal and Rural Associations Tariff" for additional information.
Depreciation and Amortization
Depreciation and amortization increased $23 million, or 13.6%, in 2019 compared
to 2018 primarily related to increases in amortization associated with ECO Plan
regulatory assets. See Note 2 to the financial statements under "Mississippi
Power - Environmental Compliance Overview Plan" for additional information.

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Taxes Other Than Income Taxes
Taxes other than income taxes increased $6 million, or 5.6%, in 2019 compared to
2018 primarily due to increases of $4 million in ad valorem taxes and $2 million
in franchise taxes.
Estimated Loss on Kemper IGCC
In 2019 and 2018, charges of $24 million and $37 million, respectively, were
recorded associated with the abandonment and closure activities and period
costs, net of sales proceeds for the mine and gasifier-related assets. The 2019
charge primarily related to the expected close out of a DOE contract related to
the Kemper County energy facility. See Note 2 to the financial statements under
"Kemper County Energy Facility" for additional information.
Interest Expense, Net of Amounts Capitalized
Interest expense, net of amounts capitalized decreased $7 million, or 9.2%, in
2019 compared to 2018, primarily as the result of a decrease in outstanding
long-term borrowings. See Note 8 to the financial statements for additional
information.
Other Income (Expense), Net
Other income (expense), net decreased $5 million in 2019 compared to 2018. The
decrease was primarily due to the $24 million settlement of Mississippi Power's
Deepwater Horizon claim in 2018, partially offset by a $9 million increase in
interest income associated with a new tolling arrangement accounted for as a
sales-type lease and a $7 million decrease in charitable donations. See Notes 3
and 9 to the financial statements under "Other Matters - Mississippi Power" and
"Lessor," respectively, for additional information.
Income Taxes (Benefit)
Income tax expense increased $132 million, or 129.4%, in 2019 compared to 2018
primarily due to a $92 million increase related to the 2018 reduction of a
valuation allowance for a state income tax net operating loss (NOL)
carryforward, a $42 million increase associated with the revaluation of deferred
tax assets related to the Kemper IGCC recorded in 2018 in accordance with the
Tax Reform Legislation, and a $9 million increase due to higher pre-tax earnings
in 2019. These increases were partially offset by $15 million associated with
the flowback of excess deferred income taxes resulting from the MRA Settlement
Agreement and a new tolling arrangement accounted for as a sales-type lease. See
FUTURE EARNINGS POTENTIAL - "Income Tax Matters" herein and Note 10 to the
financial statements for additional information.
Southern Power
Net income attributable to Southern Power for 2019 was $339 million, a $152
million increase from 2018, primarily due to net impacts totaling approximately
$141 million from the dispositions of the Florida Plants in 2018 and Plant
Nacogdoches in the second quarter 2019, which include an asset impairment charge
in 2018, a gain on sale in 2019 (including the recognition of deferred ITCs),
and a decrease in operations and maintenance expense, partially offset by PPA
capacity revenue decreases in 2019. The increase in net income also reflects $79
million in tax expense recognized in 2018 related to the Tax Reform Legislation,
a $27 million wind turbine equipment impairment charge in 2018, and net gains in
2019 of $25 million from the Roserock solar facility litigation settlement 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 and reductions in net income of approximately
$60 million related to the SP Wind tax equity partnership entered into in 2018.
See Note 15 to the financial statements under "Southern Power - Sales of Natural
Gas and Biomass Plants" and " - Development Projects" for additional information
on the Florida Plants and Plant Nacogdoches dispositions and sales of wind
turbine equipment. See Notes 7 and 10 to the financial statements under
"Southern Power" and "Legal Entity Reorganizations" for additional information
on the tax equity partnerships and the legal entity reorganization,
respectively. Also see Note 3 to the financial statements under "General
Litigation - Southern Power" for additional information on the Roserock solar
facility litigation settlement.

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A condensed statement of income follows:


                                                                         Increase
                                                                        (Decrease)
                                                             2019       from 2018
                                                                (in millions)
Operating revenues                                         $ 1,938     $     (267 )
Fuel                                                           577           (122 )
Purchased power                                                108            (68 )
Other operations and maintenance                               359            (36 )
Depreciation and amortization                                  479            (14 )
Taxes other than income taxes                                   40             (6 )
Asset impairment                                                 3           (153 )
Gain on disposition                                            (23 )          (21 )
Total operating expenses                                     1,543           (420 )
Operating income                                               395            153
Interest expense, net of amounts capitalized                   169            (14 )
Other income (expense), net                                     47             24
Income taxes (benefit)                                         (56 )          108
Net income                                                     329             83

Net income (loss) attributable to noncontrolling interests (10 )

   (69 )
Net income attributable to Southern Power                  $   339     $

152




Operating Revenues
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 the second quarter 2019 sale of Plant
Nacogdoches), and PPA energy revenues from Southern Power's generation
facilities. To the extent Southern Power has capacity not contracted 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 Southern Company 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.
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 - "Southern Power's Power Sales Agreements" herein
for additional information regarding Southern Power's PPAs.

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Operating Revenues Details
Details of Southern Power's operating revenues were as follows:
                           2019       2018
                            (in millions)
PPA capacity revenues    $   482    $   580
PPA energy revenues        1,081      1,140
Total PPA revenues         1,563      1,720
Non-PPA revenues             363        472
Other revenues                12         13

Total operating revenues $ 1,938 $ 2,205




Operating revenues for 2019 were $1.9 billion, a $267 million, or 12%, decrease
from 2018. The decrease in operating revenues was primarily due to the
following:
•  PPA capacity revenues decreased $98 million, or 17%, 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 $34 million from the

expiration of an affiliate natural gas PPA, offset by a $36 million increase

in new PPA capacity revenues from existing natural gas facilities, of which

$13 million related to the expansion unit at Plant Mankato.

• PPA energy revenues decreased $59 million, or 5%, primarily due to a $67

million decrease in sales from natural gas facilities primarily driven by a

$103 million decrease in the average cost of fuel and purchased power,

partially offset by a $36 million increase in the volume of KWHs sold due to

increased customer load.

• Non-PPA revenues decreased $109 million, or 23%, primarily due to a $72

million decrease in the volume of KWHs sold through short-term sales and a $37

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:
                                                      Total   Total KWH   Total
                                                      KWHs    % Change    KWHs
                                                      2019                2018
                                                        (in billions of KWHs)
Generation                                             47                  46
Purchased power                                         3                   4
Total generation and purchased power                   50        -%


Total generation and purchased power, excluding
solar, wind, and tolling agreements                    29        -%

Southern Power's PPAs for natural gas 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
Southern Company 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 Southern Company
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.

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Details of Southern Power's fuel and purchased power expenses were as follows:
                                            2019         2018
                                            (in millions)
Fuel                                    $    577        $ 699
Purchased power                              108          176

Total fuel and purchased power expenses $ 685 $ 875




In 2019, total fuel and purchased power expenses decreased $190 million, or 22%,
compared to 2018. Fuel expense decreased $122 million, or 17%, due to a $137
million decrease in the average cost of fuel per KWH generated, partially offset
by a $15 million increase associated with the volume of KWHs generated.
Purchased power expense decreased $68 million, or 39%, due to a $37 million
decrease associated with the average cost of purchased power and a $31 million
decrease associated with the volume of KWHs purchased.
Other Operations and Maintenance Expenses
In 2019, other operations and maintenance expenses decreased $36 million, or 9%,
compared to 2018. The decrease was due to gains totaling $17 million on the sale
of wind turbine equipment, decreased expense of $17 million related to the
dispositions of the Florida Plants and Plant Nacogdoches, and the recovery of $5
million in legal costs related to the Roserock solar facility litigation
settlement in the first quarter 2019. See Note 15 to the financial statements
under "Southern Power - Development Projects" and " - Sales of Natural Gas and
Biomass Plants" for additional information on the sale of wind turbine equipment
and the dispositions, respectively. Also see Note 3 to the financial statements
under "General Litigation Matters - Southern Power" for additional information
on the litigation settlement.
Asset Impairment
Asset impairment charges totaling $156 million were recorded in 2018, including
$119 million related to the sale of the Florida Plants and $36 million related
to wind turbine equipment held for development projects. Asset impairment
charges in 2019 were immaterial. See Note 15 to the financial statements under
"Southern Power - Sales of Natural Gas and Biomass Plants" and " - Development
Projects" for additional information.
Gain on Dispositions, Net
The sale of Plant Nacogdoches in 2019 resulted in a $23 million gain. See Note
15 to the financial statements under "Southern Power - Sales of Natural Gas and
Biomass Plants" for additional information.
Interest Expense, Net of Amounts Capitalized
In 2019, interest expense, net of amounts capitalized decreased $14 million, or
8%, compared to 2018, primarily due to a decrease in the amount of outstanding
debt.
Other Income (Expense), Net
In 2019, other income (expense), net increased $24 million, or 104%, compared to
2018 primarily due to a $36 million gain arising from the Roserock solar
facility litigation settlement in 2019, partially offset by a $14 million gain
from a joint-development wind project in 2018 attributable to Southern Power's
partner in the project, which was offset by a $14 million loss within
noncontrolling interests. See Note 3 to the financial statements under "Southern
Power" for additional information regarding the litigation settlement.
Income Taxes (Benefit)
In 2019, income tax benefit was $56 million compared to $164 million for 2018, a
decrease of $108 million, primarily attributable to reductions in tax benefits
of $127 million from wind PTCs primarily following the 2018 sale of a
noncontrolling tax equity interest in SP Wind and $65 million from changes in
state apportionment rates following the 2018 reorganizations of certain legal
entities, as well as a $64 million increase in income tax expense as a result of
higher pre-tax earnings, partially offset by $79 million in tax expense
recognized in 2018 related to the Tax Reform Legislation and a $75 million tax
benefit resulting from the recognition of deferred ITCs remaining from the
original construction recognized in connection with the sale of Plant
Nacogdoches.

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See FUTURE EARNINGS POTENTIAL - "Income Tax Matters - Federal Tax Reform
Legislation" herein and Notes 1, 10, and 15 to the financial statements under
"Income Taxes," "Effective Tax Rate," and "Southern Power," respectively, for
additional information.
Net Income Attributable to Noncontrolling Interests
In 2019, net income attributable to noncontrolling interests decreased $69
million, or 117%, compared to 2018. The decrease was primarily due to $92
million of losses attributable to noncontrolling interests related to the tax
equity partnerships entered into in 2018 and $14 million attributable to a
joint-development wind project 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 Note 3 to the
financial statements under "General Litigation Matters - Southern Power" and
Note 7 to the financial statements under "Southern Power" for additional
information regarding the litigation settlement and tax equity partnerships,
respectively.
Southern Company Gas
Operating Metrics
Southern Company Gas continues to focus on several operating metrics, including
Heating Degree Days, customer count, and volumes of natural gas sold.
Southern Company Gas measures weather and the effect on its business using
Heating Degree Days. Generally, increased Heating Degree Days result in higher
demand for natural gas on Southern Company Gas' distribution system. Southern
Company Gas has various regulatory mechanisms, such as weather and revenue
normalization and straight-fixed-variable rate design, which limit its exposure
to weather changes within typical ranges in each of its utility's respective
service territory, including Nicor Gas following the approval of a revenue
decoupling mechanism for residential customers in its recent rate case. Southern
Company Gas also utilizes weather hedges to limit the negative income impacts in
the event of warmer-than-normal weather.
The number of customers served by gas distribution operations and gas marketing
services can be impacted by natural gas prices, economic conditions, and
competition from alternative fuels. Gas distribution operations and gas
marketing services' customers are primarily located in Georgia and Illinois.
Southern Company Gas' natural gas volume metrics for gas distribution operations
and gas marketing services illustrate the effects of weather and customer demand
for natural gas. Wholesale gas services' physical sales volumes represent the
daily average natural gas volumes sold to its customers.
Seasonality of Results
During the Heating Season, natural gas usage and operating revenues are
generally higher as more customers are connected to the gas distribution systems
and natural gas usage is higher in periods of colder weather. Occasionally in
the summer, wholesale gas services' operating revenues are impacted due to peak
usage by power generators in response to summer energy demands. Southern Company
Gas' base operating expenses, excluding cost of natural gas, bad debt expense,
and certain incentive compensation costs, are incurred relatively evenly
throughout the year. Seasonality also affects the comparison of certain balance
sheet items across quarters, including receivables, unbilled revenues, natural
gas for sale, and notes payable. However, these items are comparable when
reviewing Southern Company Gas' annual results. Thus, Southern Company Gas'
operating results can vary significantly from quarter to quarter as a result of
seasonality, which is illustrated in the table below.
             Percent Generated During
                  Heating Season
                                    Net
        Operating Revenues        Income
2019             68.7 %              86.8 %
2018             68.7 %              96.0 %


Net Income
Net income attributable to Southern Company Gas in 2019 was $585 million, an
increase of $213 million, or 57.3%, compared to the prior year. The change in
net income includes a $125 million increase at wholesale gas services, an
increase of $57 million in continued investment in infrastructure replacement
programs and base rate changes at gas distribution operations, net of
depreciation, a $34 million decrease in income taxes primarily at Atlanta Gas
Light due to increased flowback of excess deferred income taxes in lieu of a
rate increase as previously authorized by the Georgia PSC, and an $11 million
increase in earnings from equity method investments in 2019. This increase also
includes a $51 million net loss in 2018 from the Southern Company Gas

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Dispositions (including the goodwill impairment charge) and $21 million in
disposition-related costs in 2018, partially offset by $86 million in after-tax
impairment charges in 2019. See Notes 3 and 15 to the financial statements under
"Other Matters - Southern Company Gas" and "Southern Company Gas - Proposed Sale
of Pivotal LNG and Atlantic Coast Pipeline," respectively, for additional
information on the impairment charges. See Note 2 to the financial statements
under "Southern Company Gas - Rate Proceedings - Nicor Gas" and " - Atlanta Gas
Light" for additional information on the impacts of the Tax Reform Legislation.
Also see FUTURE EARNINGS POTENTIAL - "Income Tax Matters" herein and Notes 10
and 15 to the financial statements for additional information.
A condensed income statement for Southern Company Gas follows:
                                                                          Increase (Decrease)
                                                               2019            from 2018
                                                                      (in millions)
Operating revenues                                         $    3,792     $         (117 )
Cost of natural gas                                             1,319               (220 )
Cost of other sales                                                 -                (12 )
Other operations and maintenance                                  888                (93 )
Depreciation and amortization                                     487                (13 )
Taxes other than income taxes                                     213                  2
Impairment charges                                                115                 73
(Gain) loss on dispositions, net                                    -                291
Total operating expenses                                        3,022                 28
Operating income                                                  770               (145 )
Earnings from equity method investments                           157                  9
Interest expense, net of amounts capitalized                      232                  4
Other income (expense), net                                        20                 19
Earnings before income taxes                                      715               (121 )
Income taxes                                                      130               (334 )
Net Income                                                 $      585     $          213

The Southern Company Gas Dispositions were completed by July 29, 2018 and represent the primary variance driver for 2019 compared to 2018. Detailed variance explanations are provided herein. See Note 15 to the financial statements under "Southern Company Gas" for additional information on the Southern Company Gas Dispositions.


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Operating Revenues
Operating revenues in 2019 were $3.8 billion, a $117 million decrease, compared
to 2018. Details of operating revenues were as follows:
                                                               2019
                                                           (in millions)
Operating revenues - prior year                           $      3,909
Estimated change resulting from -
Infrastructure replacement programs and base rate changes           96
Gas costs and other cost recovery                                  (89 )
Wholesale gas services                                             150
Southern Company Gas Dispositions(*)                              (300 )
Other                                                               26
Operating revenues - current year                         $      3,792
Percent change                                                    (3.0 )%

(*) Includes a $245 million decrease related to natural gas revenues, including

alternative revenue programs, and a $55 million decrease related to other

revenues. See Note 15 to the financial statements under "Southern Company

Gas" for additional information.




Revenues from infrastructure replacement programs and base rate changes
increased in 2019 compared to the prior year primarily due to increases of $74
million at Nicor Gas and $16 million at Atlanta Gas Light. These amounts include
gas distribution operations' continued investments recovered through
infrastructure replacement programs and base rate increases as well as customer
refunds in 2018 as a result of the Tax Reform Legislation. See Note 2 to the
financial statements under "Southern Company Gas" for additional information.
Revenues associated with gas costs and other cost recovery decreased in 2019
compared to the prior year primarily due to lower natural gas prices and
decreased volumes of natural gas sold. Natural gas distribution rates include
provisions to adjust billings for fluctuations in natural gas costs. Therefore,
gas costs recovered through natural gas revenues generally equal the amount
expensed in cost of natural gas and do not affect net income from gas
distribution operations. See "Cost of Natural Gas" herein for additional
information.
Revenues from wholesale gas services increased in 2019 primarily due to
derivative gains, partially offset by decreased commercial activity. See
"Segment Information - Wholesale Gas Services" herein for additional
information.
Other revenues increased in 2019 primarily due to increases in customers at gas
distribution operations and recovery of prior period hedge losses at gas
marketing services.
Heating Degree Days
During Heating Season, natural gas usage and operating revenues are generally
higher. Weather typically does not have a significant net income impact other
than during the Heating Season. The following table presents the Heating Degree
Days information for Illinois and Georgia, the primary locations where Southern
Company Gas' operations are impacted by weather.
                   Years Ended December 31,         2019 vs. normal     2019 vs. 2018
                 Normal(a)        2019     2018     colder (warmer)    colder (warmer)
                        (in thousands)
Illinois(b)      5,782           6,136    6,101            6.1  %              0.6  %
Georgia          2,529           2,157    2,588          (14.7 )%            (16.7 )%

(a) Normal represents the 10-year average from January 1, 2009 through December

31, 2018 for Illinois at Chicago Midway International Airport and for Georgia

at Atlanta Hartsfield-Jackson International Airport, based on information

obtained from the National Oceanic and Atmospheric Administration, National

Climatic Data Center.

(b) Heating Degree Days in Illinois are expected to have a limited financial

impact in future years. On October 2, 2019, Nicor Gas received approval for a

volume balancing adjustment, a revenue decoupling mechanism for residential

customers that provides a monthly benchmark level of revenue per rate class


    for recovery.



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Southern Company Gas hedged its exposure to warmer-than-normal weather in
Illinois for gas distribution operations and in Illinois and Georgia for gas
marketing services. The remaining impacts of weather on earnings were
immaterial.
Customer Count
The following table provides the number of customers served by Southern Company
Gas at December 31, 2019 and 2018:
                                                                2019                   2018
                                                           (in thousands, except market share %)
Gas distribution operations                                        4,277                   4,248
Gas marketing services
Energy customers(*)                                                  631                     697
Market share of energy customers in Georgia                         28.9 %                  29.0 %

(*) Gas marketing services' customers are primarily located in Georgia and

Illinois. Also included as of December 31, 2018 were approximately 70,000

customers in Ohio contracted through an annual auction process to serve for

12 months beginning April 1, 2018.

Southern Company Gas anticipates overall customer growth trends in gas
distribution operations to continue as it expects continued improvement in the
new housing market and low natural gas prices. Southern Company Gas uses a
variety of targeted marketing programs to attract new customers and to retain
existing customers.
Cost of Natural Gas
Excluding Atlanta Gas Light, which does not sell natural gas to end-use
customers, gas distribution operations charges its utility customers for natural
gas consumed using natural gas cost recovery mechanisms set by the applicable
state regulatory agencies. Under these mechanisms, all prudently-incurred
natural gas costs are passed through to customers without markup, subject to
regulatory review. Gas distribution operations defers or accrues the difference
between the actual cost of natural gas and the amount of commodity revenue
earned in a given period. The deferred or accrued amount is either billed or
refunded to customers prospectively through adjustments to the commodity rate.
Deferred natural gas costs are reflected as regulatory assets and accrued
natural gas costs are reflected as regulatory liabilities. Therefore, gas costs
recovered through natural gas revenues generally equal the amount expensed in
cost of natural gas and do not affect net income from gas distribution
operations. Cost of natural gas at gas distribution operations represented 84.5%
of the total cost of natural gas for 2019.
Gas marketing services customers are charged for actual and estimated natural
gas consumed. Cost of natural gas includes the cost of fuel and associated
transportation costs, lost and unaccounted for gas, adjustments to reduce the
value of inventories to market value, if applicable, and gains and losses
associated with certain derivatives.
In 2019, cost of natural gas was $1.3 billion, a decrease of $220 million, or
14.3%, compared to the prior year. Excluding a $106 million decrease related to
the Southern Company Gas Dispositions, cost of natural gas decreased by $114
million, which reflects a 14.8% decrease in natural gas prices compared to 2018.

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Volumes of Natural Gas Sold
The following table details the volumes of natural gas sold during all periods
presented.
                                                                 2019 vs. 2018
                                                2019    2018       % Change
Gas distribution operations (mmBtu in millions)
Firm                                             677     721          (6.1 )%
Interruptible                                     92      95          (3.2 )%
Total(*)                                         769     816          (5.8 )%
Wholesale gas services (mmBtu in millions/day)
Daily physical sales                             6.4     6.7          (4.5


Gas marketing services (mmBtu in millions)
Firm:
Georgia                                           33      37         (10.8 )%
Illinois                                          12      13          (7.7 )%
Other                                             15      20         (25.0 )%
Interruptible large commercial and industrial     14      14             -  %
Total                                             74      84         (11.9 )%

(*) Includes total volumes of natural gas sold of 38 mmBtu for 2018 related to

Elizabethtown Gas, Elkton Gas, and Florida City Gas, which were sold in July

2018. See Note 15 to the financial statements under "Southern Company Gas -

Sale of Elizabethtown Gas and Elkton Gas" and " - Sale of Florida City Gas"

for additional information.




Cost of Other Sales
Cost of other sales related to Pivotal Home Solutions, which was sold on June 4,
2018. See Note 15 to the financial statements under "Southern Company Gas - Sale
of Pivotal Home Solutions" for additional information.
Other Operations and Maintenance Expenses
In 2019, other operations and maintenance expenses decreased $93 million, or
9.5%, compared to the prior year. Excluding a $65 million decrease related to
the Southern Company Gas Dispositions, other operations and maintenance expenses
decreased $28 million. This decrease was primarily due to $28 million of
disposition-related costs incurred during 2018, a $12 million adjustment in 2018
for the adoption of a new paid time off policy, an $11 million expense for a
litigation settlement to facilitate the sale of Pivotal Home Solutions in 2018,
and a $7 million decrease in compensation and benefits costs, partially offset
by a $22 million increase in rider expenses, primarily at Nicor Gas, passed
through directly to customers. See FUTURE EARNINGS POTENTIAL - "Southern Company
Gas - Utility Regulation and Rate Design" herein for additional information.
Depreciation and Amortization
In 2019, depreciation and amortization decreased $13 million, or 2.6%, compared
to the prior year. Excluding a $27 million decrease related to the Southern
Company Gas Dispositions, depreciation and amortization increased $14 million.
This increase was primarily due to continued infrastructure investments at gas
distribution operations, partially offset by accelerated depreciation related to
assets retired in 2018. See Note 2 to the financial statements under "Southern
Company Gas - Infrastructure Replacement Programs and Capital Projects" for
additional information.
Impairment Charges
In 2019, Southern Company Gas recorded impairment charges of $91 million related
to a natural gas storage facility in Louisiana and $24 million in contemplation
of the sale of its interests in Pivotal LNG and Atlantic Coast Pipeline. In
2018, a goodwill impairment charge of $42 million was recorded in contemplation
of the sale of Pivotal Home Solutions. See Notes 1, 3, and 15 to the financial
statements under "Goodwill and Other Intangible Assets and Liabilities," "Other
Matters - Southern Company Gas," and "Southern Company Gas," respectively, for
additional information.

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(Gain) Loss on Dispositions, Net
In 2018, gain on dispositions, net was $291 million and was associated with the
Southern Company Gas Dispositions. The income tax expense on these gains
included income tax expense on goodwill not deductible for tax purposes and for
which a deferred tax liability had not been recorded previously.
Earnings from Equity Method Investments
In 2019, earnings from equity method investments increased $9 million, or 6.1%,
compared to the prior year and reflect higher earnings from SNG as a result of
rate increases that became effective September 2018, partially offset by a $6
million pre-tax loss on the sale of Triton in May 2019. See Note 7 to the
financial statements under "Southern Company Gas" for additional information.
Other Income (Expense), Net
In 2019, other income (expense), net increased $19 million compared to the prior
year. This increase primarily resulted from a $23 million decrease in charitable
donations in 2019.
Income Taxes
In 2019, income taxes decreased $334 million, or 72.0%, compared to the prior
year. This decrease primarily reflects a reduction of $348 million related to
the Southern Company Gas Dispositions, as well as $29 million in benefits
associated with impairment charges in 2019 and additional benefits from the
flowback of excess deferred income taxes in 2019 primarily at Atlanta Gas Light
as previously authorized by the Georgia PSC, partially offset by $48 million of
additional taxes associated with increased pre-tax earnings at wholesale gas
services.
See FUTURE EARNINGS POTENTIAL - "Income Tax Matters" herein and Note 10 to the
financial statements for additional information. Also see Notes 2, 3, and 15 to
the financial statements under "Southern Company Gas," "Other Matters - Southern
Company Gas," and "Southern Company Gas - Proposed Sale of Pivotal LNG and
Atlantic Coast Pipeline," respectively, for additional information on Atlanta
Gas Light's regulatory treatment of the impacts of the Tax Reform Legislation
and the impairment charges.
Performance and Non-GAAP Measures
Adjusted operating margin is a non-GAAP measure that is calculated as operating
revenues less cost of natural gas, cost of other sales, and revenue tax expense.
Adjusted operating margin excludes other operations and maintenance expenses,
depreciation and amortization, taxes other than income taxes, impairment
charges, and gain (loss) on dispositions, net, which are included in the
calculation of operating income as calculated in accordance with GAAP and
reflected in the statements of income. The presentation of adjusted operating
margin is believed to provide useful information regarding the contribution
resulting from base rate changes, infrastructure replacement programs and
capital projects, and customer growth at gas distribution operations since the
cost of natural gas and revenue tax expense can vary significantly and are
generally billed directly to customers. Southern Company Gas further believes
that utilizing adjusted operating margin at gas pipeline investments, wholesale
gas services, and gas marketing services allows it to focus on a direct measure
of performance before overhead costs. The applicable reconciliation of operating
income to adjusted operating margin is provided herein.
Adjusted operating margin should not be considered an alternative to, or a more
meaningful indicator of, Southern Company Gas' operating performance than
operating income as determined in accordance with GAAP. In addition, Southern
Company Gas' adjusted operating margin may not be comparable to similarly titled
measures of other companies.
Detailed variance explanations of Southern Company Gas' financial performance
are provided herein.

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Reconciliations of operating income to adjusted operating margin are as follows:


                              2019        2018
                                (in millions)
Operating Income            $   770     $   915
Other operating expenses(a)   1,703       1,443
Revenue taxes(b)               (114 )      (111 )

Adjusted Operating Margin $ 2,359 $ 2,247

(a) Includes other operations and maintenance, depreciation and amortization,

taxes other than income taxes, impairment charges, and gain (loss) on

dispositions, net.

(b) Nicor Gas' revenue tax expenses, which are passed through directly to


    customers.


Segment Information
                                                     2019                                                              2018
                        Adjusted Operating       Operating                                Adjusted Operating   Operating Expenses
                            Margin(a)           Expenses(a)        Net Income (Loss)          Margin(a)              (a)(b)          Net Income (Loss)(b)
                                                (in millions)                                                      (in millions)
Gas distribution
operations             $        1,799         $      1,226       $            337        $       1,794         $         890        $             334
Gas pipeline
investments                        32                   12                     94                   32                    12                      103
Wholesale gas
services                          273                   54                    163                  134                    64                       38
Gas marketing
services                          234                  122                     83                  263                   244                      (40 )
All other                          28                  182                    (92 )                 33                   131                      (63 )
Intercompany
eliminations                       (7 )                 (7 )                    -                   (9 )                  (9 )                      -
Consolidated           $        2,359         $      1,589       $            585        $       2,247         $       1,332        $             372

(a) Adjusted operating margin and operating expenses are adjusted for Nicor Gas'

revenue tax expenses, which are passed through directly to customers.

(b) Operating expenses for gas distribution operations and gas marketing services

include the gain on dispositions, net. Net income for gas distribution

operations and gas marketing services includes the gain on dispositions, net

and the associated income tax expense. See Note 15 to the financial

statements under "Southern Company Gas" for additional information.




Gas Distribution Operations
Gas distribution operations is the largest component of Southern Company Gas'
business and is subject to regulation and oversight by agencies in each of the
states it serves. These agencies approve natural gas rates designed to provide
Southern Company Gas with the opportunity to generate revenues to recover the
cost of natural gas delivered to its customers and its fixed and variable costs,
including depreciation, interest expense, operations and maintenance, taxes, and
overhead costs, and to earn a reasonable return on its investments.
With the exception of Atlanta Gas Light, Southern Company Gas' second largest
utility that operates in a deregulated natural gas market and has a
straight-fixed-variable rate design that minimizes the variability of its
revenues based on consumption, the earnings of the natural gas distribution
utilities can be affected by customer consumption patterns that are a function
of weather conditions, price levels for natural gas, and general economic
conditions that may impact customers' ability to pay for natural gas consumed.
Southern Company Gas has various weather mechanisms, such as weather
normalization mechanisms and weather derivative instruments, that limit its
exposure to weather changes within typical ranges in its natural gas
distribution utilities' service territories.
In July 2018, a Southern Company Gas subsidiary, Pivotal Utility Holdings,
completed the sales of the assets of two of its natural gas distribution
utilities, Elizabethtown Gas and Elkton Gas, to South Jersey Industries, Inc.
Also in July 2018, Southern Company Gas and its wholly-owned direct subsidiary,
NUI Corporation, completed the sale of Pivotal Utility Holdings, which primarily
consisted of Florida City Gas, to NextEra Energy. See Note 15 to the financial
statements under "Southern Company Gas" for additional information.

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The following table details the results of gas distribution operations including and excluding the impact of the utilities sold in 2018.


                                                                                            Variance
                                                                      Impacts of            Excluding
                                                                   Utilities Sold in    Utilities Sold in
Favorable(unfavorable)                          2019 vs 2018             2018                 2018
                                                                     (in millions)
Adjusted Operating Margin                     $          5        $             138     $           143
Operating expenses                                    (336 )                    246                 (90 )
Other income (expense), net                             (3 )                      -                  (3 )
Interest expenses                                       (9 )                    (13 )               (22 )
Income tax expense                                     346                     (315 )                31
Net income                                    $          3        $              56     $            59


Excluding the impact of the utilities sold in 2018, net income in 2019 increased
$59 million, or 21.2%, compared to the prior year. The $143 million increase in
adjusted operating margin reflects additional revenue from base rate increases
and continued investment recovered through infrastructure replacement programs,
a decrease in refunds associated with bad debt riders, and the customer refunds
in 2018 as a result of the Tax Reform Legislation. The $90 million increase in
operating expenses includes increases in compensation and benefit costs and
rider expenses passed through directly to customers, as well as additional
depreciation primarily due to additional assets placed in service. The $3
million decrease in other income (expense), net is primarily due to a contractor
litigation settlement in 2018. The $22 million increase in interest expense is
primarily from the issuance of first mortgage bonds at Nicor Gas. The $31
million decrease in income tax expense is primarily due to an increase in the
flowback of excess deferred income taxes in 2019 primarily at Atlanta Gas Light.
See Note 2 to the financial statements under "Southern Company Gas - Rate
Proceedings - Atlanta Gas Light" and " - Infrastructure Replacement Programs and
Capital Projects - Atlanta Gas Light - PRP" herein for additional information on
Atlanta Gas Light's stipulation reflecting the impacts of the Tax Reform
Legislation and the contractor litigation settlement, respectively.
Gas Pipeline Investments
Gas pipeline investments consists primarily of joint ventures in natural gas
pipeline investments including SNG, Atlantic Coast Pipeline, PennEast Pipeline,
and Dalton Pipeline. See Note 7 to the financial statements under "Southern
Company Gas" for additional information.
Net income in 2019 decreased $9 million, or 8.7%, compared to the prior year.
This decrease primarily relates to an increase in tax expense due to changes in
state apportionment rates, partially offset by higher earnings from SNG.
Wholesale Gas Services
Wholesale gas services is involved in asset management and optimization,
storage, transportation, producer and peaking services, natural gas supply,
natural gas services, and wholesale gas marketing. Southern Company Gas has
positioned the business to generate positive economic earnings on an annual
basis even under low volatility market conditions that can result from a number
of factors. When market price volatility increases, wholesale gas services is
well positioned to capture significant value and generate stronger results.
Operating expenses primarily reflect employee compensation and benefits.
Net income in 2019 increased $125 million, or 328.9%, compared to the prior
year. This increase primarily relates to a $139 million increase in adjusted
operating margin, a $10 million decrease in operating expenses, and a $20
million increase in other income (expense), partially offset by a $48 million
increase in income taxes.

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Details of adjusted operating margin are provided in the table below.

2018

(in

millions)


Commercial activity recognized                             $        54     $      254
Gain on storage derivatives                                         40

Gain (loss) on transportation and forward commodity derivatives

                                                        186           (119 )
LOCOM adjustments, net of current period recoveries                (16 )           (7 )
Purchase accounting adjustments to fair value inventory
and contracts                                                        9             (3 )
Adjusted operating margin                                  $       273     $      134


Change in Commercial Activity
The commercial activity at wholesale gas services includes recognition of
storage and transportation values that were generated in prior periods, which
reflect the impact of prior period hedge gains and losses as associated physical
transactions occur. The decrease in commercial activity in 2019 compared to the
prior year was primarily due to significant natural gas price volatility that
resulted from prolonged cold weather during 2018 coupled with low natural gas
supply.
Change in Storage and Transportation Derivatives
Volatility in the natural gas market arises from a number of factors, such as
weather fluctuations or changes in supply or demand for natural gas in different
regions of the U.S. The volatility of natural gas commodity prices has a
significant impact on Southern Company Gas' customer rates, long-term
competitive position against other energy sources, and the ability of wholesale
gas services to capture value from locational and seasonal spreads. Forward
storage or time spreads applicable to the locations of wholesale gas services'
specific storage positions in 2019 resulted in storage derivative gains.
Transportation and forward commodity derivative gains in 2019 are primarily the
result of narrowing transportation spreads due to supply constraints and
increases in natural gas supply, which impacted forward prices at natural gas
receipt and delivery points, primarily in the Northeast and Midwest regions.
The natural gas that wholesale gas services purchases and injects into storage
is accounted for at the LOCOM value utilizing gas daily or spot prices at the
end of the year. See Note 1 to the financial statements under "Natural Gas for
Sale" for additional information.
Withdrawal Schedule and Physical Transportation Transactions
The expected natural gas withdrawals from storage and expected offset to prior
hedge losses/gains associated with the transportation portfolio of wholesale gas
services are presented in the following table, along with the net operating
revenues expected at the time of withdrawal from storage and the physical flow
of natural gas between contracted transportation receipt and delivery points.
Wholesale gas services' expected net operating revenues exclude storage and
transportation demand charges, as well as other variable fuel, withdrawal,
receipt, and delivery charges, and exclude estimated profit sharing under asset
management agreements. Further, the amounts that are realizable in future
periods are based on the inventory withdrawal schedule, planned physical flow of
natural gas between the transportation receipt and delivery points, and forward
natural gas prices at December 31, 2019. A portion of wholesale gas services'
storage inventory and transportation capacity is economically hedged with
futures contracts, which results in the realization of substantially fixed net
operating revenues.

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                                        Storage Withdrawal
                                                                               Physical Transportation
                                                 Expected net operating      Transactions - Expected Net
                            Total storage(a)           losses(b)                  Operating Gains(c)
                              (in mmBtu in
                               millions)             (in millions)                  (in millions)
2020                                 61         $                    6     $                         (119 )
2021 and thereafter                   -                              -                                (67 )
Total at December 31, 2019           61         $                    6     $                         (186 )

(a) At December 31, 2019, the WACOG of wholesale gas services' expected natural

gas withdrawals from storage was $1.87 per mmBtu.

(b) Represents expected operating losses from planned storage withdrawals

associated with existing inventory positions and could change as wholesale

gas services adjusts its daily injection and withdrawal plans in response to

changes in future market conditions and forward NYMEX price fluctuations.

will be settled and the physical transportation transactions will occur that

offset the derivative gains and losses previously recognized.




Gas Marketing Services
Gas marketing services provides energy-related products and services to natural
gas markets and participants in customer choice programs that were approved in
various states to increase competition. These programs allow customers to choose
their natural gas supplier while the local distribution utility continues to
provide distribution and transportation services. Gas marketing services is
weather sensitive and uses a variety of hedging strategies, such as weather
derivative instruments and other risk management tools, to partially mitigate
potential weather impacts.
On June 4, 2018, Southern Company Gas completed the sale of Pivotal Home
Solutions to American Water Enterprises LLC. See Note 15 under "Southern Company
Gas - Sale of Pivotal Home Solutions" for additional information.
Net income increased $123 million in 2019 compared to the prior year. This
increase primarily relates to a $122 million decrease in operating expenses and
a $27 million decrease in income tax expense, partially offset by a $29 million
decrease in adjusted operating margin.
Excluding a $43 million decrease attributable to the 2018 disposition of Pivotal
Home Solutions, adjusted operating margin increased $14 million, which primarily
reflects favorable margins and recovery of prior period hedge losses. Excluding
a $116 million decrease attributable to the 2018 disposition of Pivotal Home
Solutions that includes the related goodwill impairment charge, operating
expense decreased $6 million due to lower amortization of intangible assets.
Excluding a $33 million decrease attributable to the 2018 disposition of Pivotal
Home Solutions, income tax expense increased $6 million primarily due to higher
pre-tax earnings.
All Other
All other includes Southern Company Gas' storage and fuels operations and its
investment in Triton through completion of its sale on May 29, 2019, AGL
Services Company, and Southern Company Gas Capital, as well as various corporate
operating expenses that are not allocated to the reportable segments and
interest income (expense) associated with affiliate financing arrangements.
Net loss increased $29 million, or 46.0%, in 2019 compared to the prior year.
This increase primarily reflects a $51 million increase in operating expenses,
partially offset by a $39 million decrease in income taxes. The increase in
operating expenses primarily reflects a $91 million impairment charge related to
a natural gas storage facility in Louisiana and a $24 million impairment charge
in contemplation of the sale of Southern Company Gas' interests in Pivotal LNG
and Atlantic Coast Pipeline, partially offset by a $12 million one-time
adjustment in the first quarter 2018 for the adoption of a new paid time off
policy, $28 million of disposition-related costs incurred during 2018, and a $14
million decrease in depreciation and amortization. The decrease in income taxes
reflects a $29 million benefit due to the impairment charge, a $13 million
benefit related to the reversal of a federal income tax valuation allowance in
connection with the sale of Triton, the impact of deferred tax expenses related
to the enactment of the State of Illinois income tax legislation in 2018, and
changes in state income tax apportionment factors in several states during 2019.
See Note 3 to the financial statements under "Other Matters - Southern Company
Gas," Note 10 to the financial statements, and Note 15 to the financial
statements under "Southern Company Gas - Proposed Sale of Pivotal LNG and
Atlantic Coast Pipeline" for additional information.
Segment Reconciliations
Reconciliations of operating income to adjusted operating margin for 2019 and
2018 are provided in the following tables. See Note 16 to the financial
statements under "Southern Company Gas" for additional segment information.

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                                                                                         2019
                             Gas Distribution      Gas Pipeline      Wholesale Gas    Gas Marketing
                                Operations          Investments         Services         Services      All Other   Intercompany Elimination   Consolidated
                                                                                     (in millions)
Operating Income (Loss)     $          573      $              20   $          219   $          112   $    (154 ) $                 -        $

770


Other operating expenses(a)          1,340                     12               54              122         182                    (7 )             1,703
Revenue tax expense(b)                (114 )                    -                -                -           -                     -                (114 )
Adjusted Operating Margin   $        1,799      $              32   $          273   $          234   $      28   $                (7 )      $      2,359


                                                                                         2018
                             Gas Distribution      Gas Pipeline      Wholesale Gas    Gas Marketing
                                Operations          Investments         Services         Services      All Other   Intercompany Elimination   Consolidated
                                                                                     (in millions)
Operating Income (Loss)     $          904      $              20   $           70   $           19   $     (98 ) $                 -        $

915


Other operating expenses(a)          1,001                     12               64              244         131                    (9 )             1,443
Revenue tax expense(b)                (111 )                    -                -                -           -                     -                (111 )
Adjusted Operating Margin   $        1,794      $              32   $          134   $          263   $      33   $                (9 )      $

2,247

(a) Includes other operations and maintenance, depreciation and amortization,

taxes other than income taxes, impairment charges, and (gain) loss on

dispositions, net.

(b) Nicor Gas' revenue tax expenses, which are passed through directly to

customers.




Effects of Inflation
The traditional electric operating companies and the natural gas distribution
utilities are subject to rate regulation that is generally based on the recovery
of historical and projected costs. The effects of inflation can create an
economic loss since the recovery of costs could be in dollars that have less
purchasing power. Southern Power is party to long-term contracts reflecting
market-based rates, including inflation expectations. Any adverse effect of
inflation on the Registrants' results of operations has not been substantial in
recent years. See Note 2 to the financial statements for additional information
on rate regulation.
FUTURE EARNINGS POTENTIAL
General
Prices for electric service provided by the traditional electric operating
companies and natural gas distributed by the natural gas distribution utilities
to retail customers are set by state PSCs or other applicable state regulatory
agencies under cost-based regulatory principles. Retail rates and earnings are
reviewed and may be adjusted periodically within certain limitations. Prices for
wholesale electricity sales, interconnecting transmission lines, and the
exchange of electric power are regulated by the FERC. Southern Power continues
to focus on long-term PPAs. See ACCOUNTING POLICIES - "Application of Critical
Accounting Policies and Estimates - Utility Regulation" herein and Note 2 to the
financial statements for additional information about regulatory matters.
Each Registrant's results of operations are not necessarily indicative of its
future earnings potential. Recent disposition activities described under
"Acquisitions and Dispositions" herein and in Note 15 to the financial
statements will impact future earnings for the applicable Registrants. The level
of the Registrants' future earnings depends on numerous factors that affect the
opportunities, challenges, and risks of the Registrants' primary businesses of
selling electricity and/or distributing natural gas, as described further
herein.
For the traditional electric operating companies, these factors include the
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 the trend of reduced electricity usage per
customer, especially in residential and commercial markets. Other major factors
include Plant Vogtle Units 3 and 4 construction and rate recovery related
thereto for Georgia Power and the ability to prevail against legal challenges
associated with the Kemper County energy facility for Mississippi Power.

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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, for Georgia Power, more multi-family home
construction, all of which could contribute to a net reduction in customer
usage.
The level of future earnings for Southern Power's competitive wholesale electric
business depends on numerous factors including Southern Power's ability to
execute its growth strategy through the development or acquisition of renewable
facilities and other energy projects while containing costs, as well as
regulatory matters, creditworthiness of customers, total electric generating
capacity available in Southern Power's market areas, and Southern Power's
ability to successfully remarket capacity as current contracts expire. In
addition, renewable portfolio standards, transmission constraints, cost of
generation from units within the Southern Company power pool, and operational
limitations could influence Southern Power's future earnings.
The level of future earnings for Southern Company Gas' primary business of
distributing natural gas and its complementary businesses in the gas pipeline
investments, wholesale gas services, and gas marketing services sectors depends
on numerous factors. These factors include the natural gas distribution
utilities' ability to maintain constructive regulatory environments that allow
for the timely recovery of prudently-incurred costs, the completion and
subsequent operation of ongoing infrastructure and other construction projects,
creditworthiness of customers, and Southern Company Gas' ability to optimize its
transportation and storage positions and to re-contract storage rates at
favorable prices. The volatility of natural gas prices has an impact on Southern
Company Gas' customer rates, its 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 portion of
Southern Company Gas' operations to earnings variability. Over the longer term,
volatility is expected to be low to moderate and locational and/or
transportation spreads are expected to decrease as new pipelines are built to
reduce the existing supply constraints in the shale areas of the Northeast U.S.
To the extent these pipelines are further delayed or not built, volatility could
increase. See "Construction Programs" herein for additional information on
permitting challenges experienced by the Atlantic Coast Pipeline and the
PennEast Pipeline. Additional economic factors may contribute to this
environment, including a significant drop in oil and natural gas prices, which
could lead to consolidation of natural gas producers or reduced levels of
natural gas production. Further, if economic conditions continue to improve, the
demand for natural gas may increase, which may cause natural gas prices to rise
and drive higher volatility in the natural gas markets on a longer-term basis.
Earnings for both the electricity and natural gas businesses 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 wholesale customers, energy conservation practiced by customers, the use of
alternative energy sources by customers, the prices of electricity and natural
gas, and the price elasticity of demand. Demand for electricity and natural gas
in the Registrants' service territories is primarily driven by the pace of
economic growth or decline that may be affected by changes in regional and
global economic conditions, which may impact future earnings.
Mississippi Power provides service under long-term contracts with rural electric
cooperative associations and municipalities located in southeastern Mississippi
under cost-based electric tariffs which are subject to regulation by the FERC.
The contracts with these wholesale customers represented 15.7% of Mississippi
Power's total operating revenues in 2019 and are generally subject to 10-year
rolling cancellation notices. Historically, these wholesale customers have acted
as a group and any changes in contractual relationships for one customer are
likely to be followed by the other wholesale customers.
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. In addition, Southern Power and Southern Company
Gas regularly consider and evaluate joint development arrangements as well as
acquisitions and dispositions of businesses and assets as part of their business
strategies. See "Acquisitions and Dispositions" herein and Note 15 to the
financial statements for additional information.

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Acquisitions and Dispositions
See Note 15 to the financial statements for additional information.
Southern Company
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), including the final working capital
adjustments. The gain associated with the sale of Gulf Power totaled $2.6
billion pre-tax ($1.4 billion after tax). In 2018, net income attributable to
Gulf Power was $160 million.
Alabama Power
On September 6, 2019, Alabama Power entered into a purchase and sale agreement
(Autauga Combined Cycle Acquisition) to acquire all of the equity interests in
Tenaska Alabama II Partners, L.P. 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 completion of the Autauga Combined Cycle Acquisition is subject to the
satisfaction or waiver of certain conditions, including, among other customary
conditions, approval by the Alabama PSC and the FERC. Alabama Power expects to
obtain all regulatory approvals by the end of the third quarter 2020.
The ultimate outcome of this matter cannot be determined at this time.
Southern Power
Acquisitions
During 2019, Southern Power acquired a controlling interest in the fuel cell
generation facility listed below and acquired the Skookumchuck wind facility
discussed under "Construction Programs - Southern Power" herein.
Acquisition-related costs were expensed as incurred and were not material.
                   Approximate                Southern
                    Nameplate                  Power                               PPA
Project              Capacity                Ownership                 PPA      Remaining
Facility Resource      (MW)      Location    Percentage     COD    Counterparty  Period
                                                                     Delmarva
                                              100% of                Power &
DSGP(a)  Fuel Cell      28       Delaware     Class B     N/A(b)      Light     15 years

(a) During 2019, Southern Power made a total investment of approximately $167

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) Southern Power's 18-MW share of the facility was repowered between June and

August 2019. In December 2019, a Class C member joined the existing

partnership between the Class A member and Southern Power and made an

investment to repower the remaining 10 MWs. In connection with the Class C

member joining the partnership, the original fuel cells (before repower),

which had a carrying value of approximately $55 million, were distributed to

the Class A member in a non-cash transaction that was excluded from the

statements of cash flows.




Development Projects
Southern Power continues to evaluate and refine the deployment of the remaining
wind turbine equipment purchased in 2016 and 2017 to development and
construction projects. Wind projects utilizing equipment purchased in 2016 and
2017, and reaching commercial operation by the end of 2020 and 2021, are
expected to qualify for 100% and 80% PTCs, respectively. The significant
majority of this equipment either has been deployed to completed projects,
projects under construction, or projects that are probable of being completed or
has been sold to third parties. Sales during 2019 resulted in gains totaling
approximately $17 million.
Sales of Renewable Facility Interests
In May 2018, Southern Power completed the sale of a noncontrolling 33% equity
interest in SP Solar, a limited partnership indirectly owning substantially all
of Southern Power's solar facilities, to Global Atlantic for approximately $1.2
billion. Since Southern Power retained control of the limited partnership
through its wholly-owned general partner, the sale was recorded as an

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equity transaction. Cash distributions from SP Solar are allocated 67% to
Southern Power and 33% to Global Atlantic in accordance with their partnership
ownership interests.
In December 2018, Southern Power completed the sale of a noncontrolling tax
equity interest in SP Wind, which owns a portfolio of eight operating wind
facilities, to three financial investors for approximately $1.2 billion. The tax
equity investors together will generally receive 40% of the cash distributions
from available cash and will receive 99% of the tax attributes, including future
PTCs.
Southern Power consolidates each entity, as the primary beneficiary of the VIE,
since it controls the most significant activities, including operating and
maintaining the assets.
Sales of Natural Gas and Biomass Plants
In December 2018, Southern Power completed the sale of all of its equity
interests in the Florida Plants to NextEra Energy for $203 million, including
working capital adjustments. In contemplation of this sale transaction, Southern
Power recorded an asset impairment charge of approximately $119 million ($89
million after tax) in May 2018. Pre-tax net income for the Florida Plants was
$49 million for the period from January 1, 2018 to December 4, 2018.
On June 13, 2019, Southern Power completed the sale of its equity interests in
Plant Nacogdoches, a 115-MW biomass facility located in Nacogdoches County,
Texas, to Austin Energy, for a purchase price of approximately $461 million,
including working capital adjustments. Southern Power recorded a gain of $23
million ($88 million after tax) on the sale. The pre-tax net income for Plant
Nacogdoches was $13 million and $27 million for the period from January 1, 2019
to June 13, 2019 and for the year ended 2018, respectively.
On January 17, 2020, Southern Power completed the sale of its equity interests
in Plant Mankato (including the 385-MW expansion unit completed in May 2019) to
a subsidiary of Xcel for a purchase price of approximately $663 million,
including estimated working capital adjustments. The sale resulted in a gain of
approximately $39 million ($23 million after tax) in 2020. Pre-tax net income
for Plant Mankato was $29 million and immaterial for the years ended December
31, 2019 and 2018, respectively. The assets and liabilities of Plant Mankato are
classified as held for sale as of December 31, 2019 and 2018.
Southern Company Gas
In June 2018, Southern Company Gas completed the stock sale of Pivotal Home
Solutions to American Water Enterprises LLC. Southern Company Gas and American
Water Enterprises LLC entered into a transition services agreement whereby
Southern Company Gas provided certain administrative and operational services
through November 4, 2018.
In July 2018, a Southern Company Gas subsidiary, Pivotal Utility Holdings,
completed the sales of the assets of two of its natural gas distribution
utilities, Elizabethtown Gas and Elkton Gas, to South Jersey Industries, Inc.
Southern Company Gas and South Jersey Industries, Inc. entered into transition
services agreements whereby Southern Company Gas will provide certain
administrative and operational services through no later than July 31, 2020.
In July 2018, Southern Company Gas and its wholly-owned direct subsidiary, NUI
Corporation, completed the stock sale of Pivotal Utility Holdings, which
primarily consisted of Florida City Gas, to NextEra Energy. Southern Company Gas
and NextEra Energy entered into a transition services agreement whereby Southern
Company Gas will provide certain administrative and operational services through
no later than July 29, 2020.
The Southern Company Gas Dispositions resulted in a net loss of $51 million in
2018, which includes $342 million of tax expense. The after-tax impacts of these
dispositions included income tax expense on goodwill not deductible for tax
purposes and for which a deferred tax liability had not been recorded
previously. In addition, a goodwill impairment charge of $42 million was
recorded during 2018 in contemplation of the sale of Pivotal Home Solutions.
The Southern Company Gas Dispositions materially decreased Southern Company Gas'
subsequent earnings and cash flows. For the year ended December 31, 2018,
pre-tax earnings attributable to these dispositions were $297 million, which
includes a $291 million gain on dispositions, net and a $42 million goodwill
impairment. Due to the seasonal nature of the natural gas business and other
factors including, but not limited to, weather, regulation, competition,
customer demand, and general economic conditions, these results are not
necessarily indicative of the results to be expected for any other period.
On May 29, 2019, Southern Company Gas sold its investment in Triton, a cargo
container leasing company. This disposition resulted in a pre-tax loss of $6
million and a net after-tax gain of $7 million as a result of reversing a $13
million federal income tax valuation allowance.
On February 7, 2020, Southern Company Gas entered into agreements with Dominion
Modular LNG Holdings, Inc. and Dominion Atlantic Coast Pipeline, LLC for the
sale of its interests in Pivotal LNG and Atlantic Coast Pipeline, respectively,
for an

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aggregate purchase price of $165 million, including estimated working capital
and timing adjustments. Southern Company Gas may also receive two payments of $5
million each, contingent upon certain milestones related to Pivotal LNG being
met by Dominion Modular LNG Holdings, Inc. after the completion of the sale.
Based on the terms of these pending transactions, Southern Company Gas recorded
an asset impairment charge, exclusive of the contingent payments, for Pivotal
LNG of approximately $24 million ($17 million after tax) as of December 31,
2019. The completion of each transaction is subject to the satisfaction or
waiver of certain conditions, including, among other customary closing
conditions, the completion of the other transaction and, for the sale of the
interest in Atlantic Coast Pipeline, the expiration or termination of any
applicable waiting period under the Hart-Scott-Rodino Antitrust Improvements Act
of 1976. The transactions are expected to be completed in the first half of
2020; however, the ultimate outcome cannot be determined at this time. The
assets and liabilities of Pivotal LNG and the interest in Atlantic Coast
Pipeline are classified as held for sale as of December 31, 2019. See Notes 3,
7, and 15 to the financial statements under "Southern Company Gas - Gas Pipeline
Projects," "Southern Company Gas - Equity Method Investments," and "Southern
Company Gas - Proposed Sale of Pivotal LNG and Atlantic Coast Pipeline,"
respectively, for additional information.
Environmental Matters
The Southern Company system's operations are regulated by state and federal
environmental agencies through a variety of laws and regulations governing air,
water, land, and other natural resources. The Southern Company system maintains
comprehensive environmental compliance and GHG strategies to assess both current
and upcoming requirements and compliance costs associated with these
environmental laws and regulations. The costs required to comply with
environmental laws and regulations and to achieve stated goals, including
capital expenditures, operations and maintenance costs, and costs reflected in
ARO liabilities, may impact future electric generating unit retirement and
replacement decisions, results of operations, cash flows, and/or financial
condition. Related costs may result from the installation of additional
environmental controls, closure and monitoring of CCR facilities, unit
retirements, or changing fuel sources for certain existing units, as well as
related upgrades to the Southern Company system's transmission and distribution
(electric and natural gas) systems. A major portion of these costs is expected
to be recovered through retail and wholesale rates, including existing
ratemaking and billing provisions. The ultimate impact of environmental laws and
regulations and the GHG goals discussed herein will depend on various factors,
such as state adoption and implementation of requirements, the availability and
cost of any deployed technology, fuel prices, and the outcome of pending and/or
future legal challenges.
New or revised environmental laws and regulations could affect many areas of
operations for the Subsidiary Registrants. 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 on a timely basis in rates 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.
Alabama Power and Mississippi Power recover environmental compliance costs
through separate mechanisms, Rate CNP Compliance and the ECO Plan, respectively.
Georgia Power's base rates include an Environmental Compliance Cost Recovery
(ECCR) tariff that allows for the recovery of environmental compliance costs.
The natural gas distribution utilities of Southern Company Gas generally recover
environmental remediation expenditures through rate mechanisms approved by their
applicable state regulatory agencies. See Notes 2 and 3 to the financial
statements for additional information.
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. Since Southern Power's units are newer
natural gas and renewable generating facilities, costs associated with
environmental compliance for these facilities have been less significant than
for similarly situated coal or older natural gas generating facilities.
Environmental, natural resource, and land use concerns, including the
applicability of air quality limitations, the potential presence of wetlands or
threatened and endangered species, the availability of water withdrawal rights,
uncertainties regarding impacts such as increased light or noise, and concerns
about potential adverse health impacts can, however, increase the cost of siting
and operating any type of future electric generating facility. The impact of
such laws, regulations, and other considerations on Southern Power and
subsequent recovery through PPA provisions cannot be determined at this time.
Further, increased costs that are recovered through regulated rates could
contribute to reduced demand for electricity 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 affect their demand for electricity and natural gas.
Although the timing, requirements, and estimated costs could change as
environmental laws and regulations are adopted or modified, as compliance plans
are revised or updated, and as legal challenges to rules are initiated or
completed, estimated capital

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expenditures through 2024 based on the current environmental compliance strategy
for the Southern Company system and the traditional electric operating companies
are as follows:
                   2020   2021   2022   2023   2024   Total
                                 (in millions)

Southern Company $ 223 $ 250 $ 244 $ 214 $ 131 $ 1,062 Alabama Power 80 77 82 97 103 439 Georgia Power 115 156 152 105 23 551 Mississippi Power 28 17 10 12 5 72




These estimates do not include any costs associated with potential regulation of
GHG emissions. See "Global Climate Issues" herein for additional information.
The Southern Company system also anticipates substantial expenditures associated
with ash pond closure and ground water monitoring under the CCR Rule and related
state rules, which are reflected in the applicable Registrants' ARO liabilities.
See FINANCIAL CONDITION AND LIQUIDITY - "Capital Requirements" herein and Note 6
to the financial statements for additional information.
Environmental Laws and Regulations
Air Quality
The Southern Company system reduced SO2 and NOX air emissions by 98% and 88%,
respectively, from 1990 to 2018. The Southern Company system reduced mercury air
emissions by over 96% from 2005 to 2018.
The EPA finalized regional haze regulations in 2005 and 2017. These regulations
require states, tribal governments, and various federal agencies to develop and
implement plans to reduce pollutants that impair visibility and demonstrate
reasonable progress toward the goal of restoring natural visibility conditions
in certain areas, including national parks and wilderness areas. States are
required to submit state implementation plans for the second ten-year planning
period (2018 through 2028) by July 31, 2021. These plans could require further
reductions in particulate matter, SO2, and/or NOX, which could result in
increased compliance costs at affected electric generating units.
Water Quality
In 2014, the EPA finalized requirements under Section 316(b) of the Clean Water
Act (CWA) to regulate cooling water intake structures (CWIS) to minimize their
effects on fish and other aquatic life at existing power plants. The regulation
requires plant-specific studies to determine applicable CWIS changes to protect
organisms. The Southern Company system is conducting these studies and currently
anticipates applicable CWIS changes may include fish-friendly CWIS screens with
fish return systems and minor additions of monitoring equipment at certain
plants. The impact of this rule will depend on the outcome of these
plant-specific studies, any additional protective measures required to be
incorporated into each plant's National Pollutant Discharge Elimination System
(NPDES) permit based on site-specific factors, and the outcome of any legal
challenges.
In 2015, the EPA finalized the steam electric effluent limitations guidelines
(ELG) rule (2015 ELG Rule) that set national standards for wastewater discharges
from new and existing steam electric generating units generating greater than 50
MWs. The 2015 ELG Rule prohibits effluent discharges of certain waste streams
and imposes stringent limits on flue gas desulfurization (scrubber) wastewater
discharges. The 2015 technology-based limits and the CCR Rule require extensive
changes to existing ash and wastewater management systems or the installation
and operation of new ash and wastewater management systems. Compliance with the
2015 ELG Rule is expected to require capital expenditures and increased
operational costs for the traditional electric operating companies' coal-fired
electric generation. State environmental agencies will incorporate specific
compliance applicability dates in the NPDES permitting process for each ELG
waste stream. On November 22, 2019, the EPA published a proposed rule that
changes certain requirements in the 2015 ELG Rule, including adjusting
compliance limits and providing certain exemptions for boilers that are expected
to be retired by December 31, 2028 and for low utilization boilers (876,000
MWh/year or less). The proposal also extends the latest applicability date for
flue gas desulfurization wastewater to December 31, 2025 but retains the latest
applicability date of December 31, 2023 for bottom ash transport water. The
impact of any changes to the 2015 ELG Rule will depend on the content of a new
final rule, which the EPA plans to finalize by August 2020, and the outcome of
any legal challenges.
Coal Combustion Residuals
In 2015, the EPA finalized non-hazardous solid waste regulations for the
disposal of CCR, including coal ash and gypsum, in landfills and surface
impoundments (ash ponds) at active electric generating power plants. The CCR
Rule requires landfills and

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ash ponds to be evaluated against a set of performance criteria and potentially
closed if certain criteria are not met. Closure of existing landfills and ash
ponds requires installation of equipment and infrastructure to manage CCR in
accordance with the CCR Rule. In addition to the CCR Rule, the States of Alabama
and Georgia finalized state regulations regarding the handling of CCR within
their respective states. The State of Georgia received approval from the EPA on
its partial permit program implementing the state CCR permit program in lieu of
the federal self-implementing rule in accordance with the Water Infrastructure
Improvements for the Nation Act. The State of Alabama also submitted its state
CCR program for the EPA's review and approval. The State of Mississippi has not
yet developed a state CCR permit program.
The EPA is in the process of amending portions of the CCR Rule. Most recently,
on December 2, 2019, the EPA published a proposed rule that would require
facilities to cease placement of both CCR and non-CCR waste in unlined surface
impoundments as soon as technically feasible, no later than August 31, 2020.
This proposed rule also includes extensions beyond August 31, 2020, provided
that certain conditions are met. Impacts of the proposed rule to the Southern
Company system are expected to be limited, as the traditional electric operating
companies and SEGCO stopped sending coal ash from most of the generating units
to unlined ponds in April 2019 and expect to stop sending coal ash from the
remaining generating units within the timeframes and associated extensions
allowed in the proposed rule.
Based on cost estimates for closure and monitoring of landfills and ash ponds
pursuant to the CCR Rule, the Southern Company system recorded/revised AROs for
each CCR unit in 2015 and has continued to update these cost estimates and ARO
liabilities in subsequent years. The traditional electric operating companies
expect to continue updating these estimates periodically as additional
information related to ash pond closure methodologies, schedules, and/or costs
becomes available. Alabama Power anticipates increasing the ARO for one of its
ash ponds within the next nine months upon completion of a feasibility study and
the related cost estimate, and the increase could be material. 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, results of operations, cash flows, and financial
condition for Southern Company and the traditional electric operating companies
could be materially impacted. See FINANCIAL CONDITION AND LIQUIDITY - "Capital
Requirements" and FUTURE EARNINGS POTENTIAL - "Regulatory Matters - Georgia
Power - Integrated Resource Plan" herein and Note 6 to the financial statements
for additional information.
The ultimate outcome of these matters cannot be determined at this time.
Environmental Remediation
The Southern Company system must comply with environmental laws and regulations
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 Southern Company Gas conduct studies to
determine the extent of any required cleanup and have recognized the estimated
costs to clean up known impacted sites in their financial statements. Amounts
for cleanup and ongoing monitoring costs were not material for any year
presented. The traditional electric operating companies and the natural gas
distribution utilities in Illinois and Georgia (which represent substantially
all of Southern Company Gas' accrued remediation costs) have all received
authority from their respective state PSCs or other applicable state regulatory
agencies to recover approved environmental compliance costs through regulatory
mechanisms. These regulatory mechanisms are adjusted annually or as necessary
within limits approved by the state PSCs or other applicable state regulatory
agencies. The traditional electric operating companies and Southern Company Gas
may be liable for some or all required cleanup costs for additional sites that
may require environmental remediation. See Note 3 to the financial statements
under "Environmental Remediation" for additional information.
Global Climate Issues
On July 8, 2019, the EPA published the final Affordable Clean Energy rule (ACE
Rule) to repeal and replace the CPP. The ACE Rule requires states to develop
unit-specific CO2 emission rate standards for existing coal-fired units based on
heat-rate efficiency improvements. The ACE Rule is being challenged in the D.C.
Circuit Court of Appeals and Georgia Power is an intervenor in the litigation in
support of the rule, as are other industry parties. The ultimate impact of the
ACE Rule 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.
Additional GHG policies, including legislation, may emerge in the future
requiring the United States to transition to a lower GHG emitting economy;
however, associated impacts are currently unknown. The Southern Company system
has transitioned from an electric generating mix of 70% coal and 15% natural gas
in 2007 to a mix of 22% coal and 52% natural gas in 2019, along with over 8,300
MWs of renewable resources. This transition has been supported in part by the
Southern Company system retiring over 5,600 MWs of coal- and oil-fired
generating capacity since 2010 and converting over 3,400 MWs of generating
capacity from coal to natural gas since 2015. In addition, Southern Company Gas
has replaced approximately 5,600 miles of bare steel and

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cast-iron pipe, resulting in removal of approximately 2.5 million metric tons of GHG from its natural gas distribution system since 1998. The following table provides the Registrants' 2018 and preliminary 2019 GHG emissions based on ownership or financial control of facilities:


                                      2018               Preliminary 2019
                            (in million metric tons of CO2 equivalent)
Southern Company(a)(b)        102                                      88
Alabama Power                  36                                      32
Georgia Power                  30                                      27
Mississippi Power               8                                       9
Southern Power(b)              14                                      13
Southern Company Gas(b)         1                                       1

(a) Includes non-registrant subsidiaries.

(b) The 2018 and preliminary 2019 amounts include GHG emissions attributable to

disposed assets through the date of the applicable disposition. See Note 15

to the financial statements for additional information regarding disposition

activities.




Based on the preliminary 2019 amount above, the Southern Company system has
achieved an estimated GHG emission reduction of 44% since 2007. In April 2018,
Southern Company established an intermediate goal of a 50% reduction in carbon
emissions from 2007 levels by 2030 and a long-term goal of low- to no-carbon
operations by 2050. The Southern Company system's ability to achieve these goals
depends on many external factors, including supportive national energy policies,
low natural gas prices, and the development, deployment, and advancement of
relevant energy technologies. The Southern Company system expects to continue
cost-effectively growing its renewable energy portfolio, optimizing technology
advancements to modernize its transmission and distribution systems, increasing
the use of natural gas for generation, completing Plant Vogtle Units 3 and 4,
investing in energy efficiency, and continuing research and development efforts
focused on technologies to lower GHG emissions. The Southern Company system is
also evaluating methods of removing carbon from the atmosphere.
Regulatory Matters
Alabama Power
Alabama Power's revenues from regulated retail operations are collected through
various rate mechanisms subject to the oversight of the Alabama PSC. Alabama
Power currently recovers its costs from the regulated retail business primarily
through Rate RSE, Rate CNP, Rate ECR, and Rate NDR. In addition, the Alabama PSC
issues accounting orders to address current events impacting Alabama Power. See
Note 2 to the financial statements under "Alabama Power" for additional
information regarding Alabama Power's rate mechanisms and accounting orders.
Petition for Certificate of Convenience and Necessity
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 and long-term contracts
for the purchase of power from others, both as more fully described below, as
well as the Autauga Combined Cycle Acquisition. 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. See Note 15 to the financial statements under "Alabama
Power" for additional information regarding the Autauga Combined Cycle
Acquisition.
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 is also
subject to approval by the FERC. Alabama Power expects to obtain all regulatory
approvals 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.

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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.
Alabama Power entered into additional long-term PPAs totaling approximately 640
MWs of generating capacity consisting of approximately 240 MWs of combined cycle
generation expected to begin later in 2020 and approximately 400 MWs of solar
generation coupled with battery energy storage systems (solar/battery systems)
expected to begin in 2022 through 2024. The terms of the agreements for the
solar/battery systems permit Alabama Power to use the energy and retire the
associated renewable energy credits (REC) in service of customers or to sell
RECs, separately or bundled with energy.
Upon certification, Alabama Power expects to recover costs associated with Plant
Barry Unit 8 pursuant to its Rate CNP New Plant. Additionally, Alabama Power
expects to recover costs associated with the Autauga Combined Cycle Acquisition
through the inclusion in Rate RSE of revenues from the existing power sales
agreement and, on expiration of that agreement, pursuant to 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.
The ultimate outcome of these matters cannot be determined at this time.
Construction Work in Progress Accounting Order
On October 1, 2019, the Alabama PSC acknowledged that Alabama Power would begin
certain limited preparatory activities associated with Plant Barry Unit 8
construction to meet the target in-service date by authorizing Alabama Power to
record the related costs as CWIP prior to the issuance of an order on the CCN
petition. Should a CCN not be granted and Alabama Power does not proceed with
the related construction of Plant Barry Unit 8, Alabama Power may transfer those
costs and any costs that directly result from the non-issuance of the CCN to a
regulatory asset which would be amortized over a five-year period. If the
balance of incurred costs reaches 5% of the estimated in-service cost of the
total project prior to issuance of an order on the CCN petition, Alabama Power
will confer with the Alabama PSC regarding the appropriateness of additional
authorization. The Sierra Club subsequently filed a petition for reconsideration
of the accounting order. The Alabama PSC voted to deny the petition for
reconsideration on January 7, 2020.
Rate RSE
The Alabama PSC has adopted Rate RSE that provides for periodic annual
adjustments based upon Alabama Power's projected weighted common equity return
(WCER) compared to an allowable range. Rate RSE adjustments are based on
forward-looking information for the applicable upcoming calendar year. Rate RSE
adjustments for any two-year period, when averaged together, cannot exceed 4.0%
and any annual adjustment is limited to 5.0%. When the projected WCER is under
the allowed range, there is an adjusting point of 5.98% and eligibility for a
performance-based adder of seven basis points, or 0.07%, to the WCER adjusting
point if Alabama Power (i) has an "A" credit rating equivalent with at least one
of the recognized rating agencies or (ii) is in the top one-third of a
designated customer value benchmark survey. If Alabama Power's actual retail
return is above the allowed WCER range, the excess will be refunded to customers
unless otherwise directed by the Alabama PSC; however, there is no provision for
additional customer billings should the actual retail return fall below the WCER
range. Prior to January 2019, retail rates remained unchanged when the WCER
range was between 5.75% and 6.21%.
In May 2018, the Alabama PSC approved modifications to Rate RSE and other
commitments designed to position Alabama Power to address the growing pressure
on its credit quality resulting from the Tax Reform Legislation, without
increasing retail rates under Rate RSE in the near term. Alabama Power plans to
reduce growth in total debt by increasing equity, with corresponding reductions
in debt issuances, thereby de-leveraging its capital structure. Alabama Power's
goal is to achieve an equity ratio of approximately 55% by the end of 2025. At
December 31, 2019, Alabama Power's equity ratio was approximately 50%.
The approved modifications to Rate RSE began for billings in January 2019. The
modifications include reducing the top of the allowed WCER range from 6.21% to
6.15% and modifications to the refund mechanism applicable to prior year actual
results. The modifications to the refund mechanism allow Alabama Power to retain
a portion of the revenue that causes the actual WCER for a given year to exceed
the allowed range.
Generally, during a year without a Rate RSE upward adjustment, if Alabama
Power's actual WCER is between 6.15% and 7.65%, customers will receive 25% of
the amount between 6.15% and 6.65%, 40% of the amount between 6.65% and 7.15%,
and 75% of the amount between 7.15% and 7.65%. Customers will receive all
amounts in excess of an actual WCER of 7.65%. During a year

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with a Rate RSE upward adjustment, if Alabama Power's actual WCER exceeds 6.15%,
customers receive 50% of the amount between 6.15% and 6.90% and all amounts in
excess of an actual WCER of 6.90%.
In conjunction with these modifications to Rate RSE, in May 2018, Alabama Power
consented to a moratorium on any upward adjustments under Rate RSE for 2019 and
2020 and to return $50 million to customers through bill credits in 2019.
On November 27, 2019, Alabama Power made its required annual Rate RSE submission
to the Alabama PSC of projected data for calendar year 2020. Projected earnings
were within the specified range; therefore, retail rates under Rate RSE remain
unchanged for 2020.
During 2019, Alabama Power provided to the Alabama PSC and the Alabama Office of
the Attorney General information related to the operation and utilization of
Rate RSE, in accordance with the rules governing the operation of Rate RSE. The
ultimate outcome of this matter cannot be determined at this time.
At December 31, 2019, Alabama Power's WCER exceeded 6.15%, resulting in Alabama
Power establishing a current regulatory liability of $53 million for Rate RSE
refunds, which will be refunded to customers through bill credits in April 2020.
Rate CNP New Plant
Rate CNP New Plant allows for recovery of Alabama Power's retail costs
associated with newly developed or acquired certificated generating facilities
placed into retail service. No adjustments to Rate CNP New Plant occurred during
the period 2017 through 2019. See Note 2 to the financial statements under
"Alabama Power - Petition for Certificate of Convenience and Necessity" for
additional information.
Rate CNP PPA
Rate CNP PPA allows for the recovery of Alabama Power's retail costs associated
with certificated PPAs. No adjustments to Rate CNP PPA occurred during the
period 2017 through 2019 and no adjustment is expected for 2020.
Rate CNP Compliance
Rate CNP Compliance allows for the recovery of Alabama Power's retail costs
associated with laws, regulations, and other such mandates directed at the
utility industry involving the environment, security, reliability, safety,
sustainability, or similar considerations impacting Alabama Power's facilities
or operations. Rate CNP Compliance is based on forward-looking information and
provides for the recovery of these costs pursuant to factors that are calculated
and submitted to the Alabama PSC by December 1 with rates effective for the
following calendar year. Compliance costs to be recovered include operations and
maintenance expenses, depreciation, and a return on certain invested capital.
Revenues for Rate CNP Compliance, as recorded on the financial statements, are
adjusted for differences in actual recoverable costs and amounts billed in
current regulated rates. Accordingly, changes in the billing factor will have no
significant effect on Southern Company's or Alabama Power's revenues or net
income, but will affect annual cash flow. Changes in Rate CNP Compliance-related
operations and maintenance expenses and depreciation generally will have no
effect on net income.
On November 27, 2019, Alabama Power submitted calculations associated with its
cost of complying with governmental mandates, as provided under Rate CNP
Compliance. The filing reflected a projected over recovered retail revenue
requirement for governmental mandates, which resulted in a rate decrease of
approximately $68 million that became effective for the billing month of January
2020.
Rate ECR
Rate ECR recovers Alabama Power's retail energy costs based on an estimate of
future energy costs and the current over or under recovered balance. Revenues
recognized under Rate ECR and recorded on the financial statements are adjusted
for the difference in actual recoverable fuel costs and amounts billed in
current regulated rates. The difference in the recoverable fuel costs and
amounts billed gives rise to the over or under recovered amounts recorded as
regulatory assets or liabilities. Alabama Power, along with the Alabama PSC,
continually monitors the over or under recovered cost balance to determine
whether an adjustment to billing rates is required. Changes in the Rate ECR
factor have no significant effect on Southern Company's or Alabama Power's net
income but will impact operating cash flows. The Alabama PSC may approve billing
rates under Rate ECR of up to 5.910 cents per KWH.
On December 3, 2019, the Alabama PSC approved a decrease to Rate ECR from 2.353
to 2.160 cents per KWH, equal to 1.82%, or approximately $102 million annually,
effective January 1, 2020. The rate will adjust to 5.910 cents per KWH in
January 2021 absent a further order from the Alabama PSC.

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Tax Reform Accounting Order
In May 2018, the Alabama PSC approved an accounting order that authorized
Alabama Power to defer the benefits of federal excess deferred income taxes
associated with the Tax Reform Legislation for the year ended December 31, 2018
as a regulatory liability and to use up to $30 million of such deferrals to
offset under recovered amounts under Rate ECR. The final excess deferred tax
liability for the year ended December 31, 2018 totaled approximately $69
million, of which $30 million was used to offset the Rate ECR under recovered
balance. On December 3, 2019, the Alabama PSC issued an order authorizing
Alabama Power to apply the remaining deferred balance of approximately $39
million to increase the balance in the NDR. See "Rate NDR" herein and Note 10 to
the financial statements under "Current and Deferred Income Taxes" for
additional information.
Plant Greene County
Alabama Power jointly owns Plant Greene County with an affiliate, Mississippi
Power. See Note 5 to the financial statements under "Joint Ownership Agreements"
for additional information regarding the joint ownership agreement. On December
31, 2019, Mississippi Power updated its proposed Reserve Margin Plan (RMP),
originally filed in August 2018 with the Mississippi PSC. The RMP proposed a
four-year acceleration of the retirement of Plant Greene County Units 1 and 2 to
the third quarter 2021 and the third quarter 2022, respectively. Mississippi
Power's proposed Plant Greene County unit retirements would require the
completion of proposed transmission and system reliability improvements, as well
as agreement by Alabama Power. Alabama Power will continue to monitor the status
of Mississippi Power's proposed RMP and associated regulatory process as well as
the proposed transmission and system reliability improvements. Alabama Power
will review all the facts and circumstances and will evaluate all its
alternatives prior to reaching a final determination on the ongoing operations
of Plant Greene County. The ultimate outcome of this matter cannot be determined
at this time.
Rate NDR
Based on an order from the Alabama PSC, Alabama Power maintains a reserve for
operations and maintenance expenses to cover the cost of damages from major
storms to its transmission and distribution facilities. The order approves a
separate monthly Rate NDR charge to customers consisting of two components. The
first component is intended to establish and maintain a reserve balance for
future storms and is an on-going part of customer billing. When the reserve
balance falls below $50 million, a reserve establishment charge will be
activated (and the on-going reserve maintenance charge concurrently suspended)
until the reserve balance reaches $75 million.
The second component of the Rate NDR charge is intended to allow recovery of any
existing deferred storm-related operations and maintenance costs and any future
reserve deficits over a 24-month period. The Alabama PSC order gives Alabama
Power authority to record a deficit balance in the NDR when costs of storm
damage exceed any established reserve balance. Absent further Alabama PSC
approval, the maximum total Rate NDR charge consisting of both components is $10
per month per non-residential customer account and $5 per month per residential
customer account. Alabama Power has the authority, based on an order from the
Alabama PSC, to accrue certain additional amounts as circumstances warrant. The
order allows for reliability-related expenditures to be charged against the
additional accruals when the NDR balance exceeds $75 million. Alabama Power may
designate a portion of the NDR to reliability-related expenditures as a part of
an annual budget process for the following year or during the current year for
identified unbudgeted reliability-related expenditures that are incurred.
Accruals that have not been designated can be used to offset storm charges.
Additional accruals to the NDR enhance Alabama Power's ability to mitigate the
financial effects of future natural disasters, promote system reliability, and
offset costs retail customers would otherwise bear.
As discussed herein under "Tax Reform Accounting Order," in accordance with an
Alabama PSC order issued on December 3, 2019, Alabama Power applied the
remaining excess deferred income tax regulatory liability balance of
approximately $39 million to increase the balance in the NDR. Alabama Power also
accrued an additional $84 million to the NDR in December 2019 resulting in an
accumulated balance of $150 million at December 31, 2019. Of this amount,
Alabama Power designated $37 million to be applied to budgeted
reliability-related expenditures for 2020, which is included in other regulatory
liabilities, current. The remaining NDR balance of $113 million is included in
other regulatory liabilities, deferred on the balance sheet.
In December 2017, the reserve maintenance charge was suspended and the reserve
establishment charge was activated and collected approximately $16 million
annually through 2019. Effective with the March 2020 billings, the reserve
establishment charge will be suspended and the reserve maintenance charge will
be activated as a result of the NDR balance exceeding $75 million. Alabama Power
expects to collect approximately $5 million in 2020 and $3 million annually
thereafter unless the NDR balance falls below $50 million.
As revenue from the Rate NDR charge is recognized, an equal amount of operations
and maintenance expenses related to the NDR will also be recognized. As a
result, the Rate NDR charge will not have an effect on net income but will
impact operating cash flows.

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Environmental Accounting Order
Based on an order from the Alabama PSC (Environmental Accounting Order), Alabama
Power is allowed to establish a regulatory asset to record the unrecovered
investment costs, including the unrecovered plant asset balance and the
unrecovered costs associated with site removal and closure associated with
future unit retirements caused by environmental regulations. The regulatory
asset is being amortized and recovered over the affected unit's remaining useful
life, as established prior to the decision regarding early retirement through
Rate CNP Compliance.
On April 15, 2019, Alabama Power retired Plant Gorgas Units 8, 9, and 10 and
reclassified approximately $654 million of the unrecovered asset balances to
regulatory assets, which are being recovered over the units' remaining useful
lives, the latest being through 2037, as established prior to the decision to
retire. At December 31, 2019, the related regulatory assets totaled $649
million. Additionally, approximately $700 million of net capitalized asset
retirement costs were reclassified to a regulatory asset in accordance with
accounting guidance provided by the Alabama PSC. The asset retirement costs are
being recovered through 2055. See Note 2 to the financial statements under
"Alabama Power" and Note 6 to the financial statements for additional
information.
Georgia Power
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 an
alternate rate plan, which includes traditional base tariffs, Demand-Side
Management (DSM) tariffs, the ECCR tariff, and Municipal Franchise Fee (MFF)
tariffs. In addition, financing costs on 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 - Rate Plans," " - Fuel Cost
Recovery," and " - Nuclear Construction" for additional information.
Rate Plans
2019 ARP
On December 17, 2019, the Georgia PSC voted to approve the 2019 ARP, under which
Georgia Power increased its rates on January 1, 2020 and will increase rates
annually for 2021 and 2022 as detailed below based on compliance filings to be
made at least 90 days prior to the effective date. Georgia Power will recover
estimated increases through its existing tariffs as follows:
Tariff            2020    2021   2022
                     (in millions)
Traditional base $    -  $ 120  $ 192
ECCR(a)             318     55    184
DSM                  12      1      1
MFF                  12      4      9
Total(b)         $  342  $ 181  $ 386

(a) Effective January 1, 2020, CCR AROs will be recovered through the ECCR

tariff. See "Integrated Resource Plan" herein for additional information on

recovery of compliance costs for CCR AROs.

(b) Totals may not add due to rounding.




Further, under the 2019 ARP, Georgia Power's retail ROE is set at 10.50%, and
earnings will be evaluated against a retail ROE range of 9.50% to 12.00%. The
Georgia PSC also approved an increase in the retail equity ratio to 56% from
55%. Any retail earnings above 12.00% will be shared, with 40% being applied to
reduce regulatory assets, 40% directly refunded to customers, and the remaining
20% retained by Georgia Power. There will be no recovery of any earnings
shortfall below 9.50% on an actual basis. However, if at any time during the
term of the 2019 ARP, Georgia Power projects that its retail earnings will be
below 9.50% for any calendar year, it could petition the Georgia PSC for
implementation of the Interim Cost Recovery (ICR) tariff to adjust Georgia
Power's retail rates to achieve a 9.50% ROE. The Georgia PSC would have 90 days
to rule on Georgia Power's request. The ICR tariff would expire at the earlier
of January 1, 2023 or the end of the calendar year in which the ICR tariff
becomes effective. In lieu of requesting implementation of an ICR tariff, or if
the Georgia PSC chooses not to implement the ICR tariff, Georgia Power may file
a full rate case.
Additionally, under the 2019 ARP and pursuant to the sharing mechanism approved
in the 2013 ARP whereby two-thirds of any earnings above the top of the allowed
ROE range are shared with Georgia Power's customers, (i) Georgia Power used 50%
(approximately $50 million) of the customer share of earnings above the band in
2018 to reduce regulatory assets and 50%

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(approximately $50 million) will be refunded to customers in 2020 and (ii)
Georgia Power will forgo its share of 2019 earnings in excess of the earnings
band so that 50% (approximately $60 million) of all earnings over the 2019 band
will be refunded to customers and 50% (approximately $60 million) were used to
reduce regulatory assets.
Except as provided above, Georgia Power will not file for a general base rate
increase while the 2019 ARP is in effect. Georgia Power is required to file a
general base rate case by July 1, 2022, in response to which the Georgia PSC
would be expected to determine whether the 2019 ARP should be continued,
modified, or discontinued.
2013 ARP
Pursuant to the terms and conditions of a settlement agreement related to
Southern Company's acquisition of Southern Company Gas approved by the Georgia
PSC in 2016, the 2013 ARP continued in effect until December 31, 2019.
Furthermore, through December 31, 2019, Georgia Power retained its merger
savings, net of transition costs, as defined in the settlement agreement;
through December 31, 2022, such net merger savings will be shared on a 60/40
basis with customers; thereafter, all merger savings will be retained by
customers.
There were no changes to Georgia Power's traditional base tariffs, ECCR tariff,
DSM tariffs, or MFF tariffs in 2017, 2018, or 2019.
Under the 2013 ARP, Georgia Power's retail ROE was set at 10.95% and earnings
were evaluated against a retail ROE range of 10.00% to 12.00%. Two-thirds of any
earnings above 12.00% were to be directly refunded to customers, with the
remaining one-third retained by Georgia Power. On February 5, 2019, the Georgia
PSC approved a settlement between Georgia Power and the staff of the Georgia PSC
under which Georgia Power's retail ROE for 2017 was stipulated to exceed 12.00%
and Georgia Power reduced certain regulatory assets by approximately $4 million
in lieu of providing refunds to retail customers. In 2019 and 2018, Georgia
Power's retail ROE exceeded 12.00% and, under the modified sharing mechanism
pursuant to the 2019 ARP, Georgia Power has reduced regulatory assets by a total
of approximately $110 million and expects to refund a total of approximately
$110 million to customers, subject to review and approval by the Georgia PSC.
See "2019 ARP" and "Integrated Resource Plan" herein for additional information.
Tax Reform Settlement Agreement
In April 2018, the Georgia PSC approved the Georgia Power Tax Reform Settlement
Agreement. To reflect the federal income tax rate reduction impact of the Tax
Reform Legislation, Georgia Power issued bill credits of approximately $95
million and $130 million in 2019 and 2018, respectively, and is issuing bill
credits of approximately $105 million in February 2020, for a total of $330
million. In addition, Georgia Power deferred as a regulatory liability (i) the
revenue equivalent of the tax expense reduction resulting from legislation
lowering the Georgia state income tax rate from 6.00% to 5.75% in 2019 and (ii)
the entire benefit of federal and state excess accumulated deferred income
taxes. At December 31, 2019, the related regulatory liability balance totaled
$659 million, which is being amortized over a three-year period ending December
31, 2022 in accordance with the 2019 ARP.
To address some of the negative cash flow and credit quality impacts of the Tax
Reform Legislation, the Georgia PSC also approved an increase in Georgia Power's
retail equity ratio to the lower of (i) Georgia Power's actual common equity
weight in its capital structure or (ii) 55%, until the Georgia PSC approved the
2019 ARP. Benefits from reduced federal income tax rates in excess of the
amounts refunded to customers were retained by Georgia Power to cover the
carrying costs of the incremental equity in 2018 and 2019.
See "2019 ARP" herein for additional information.
Integrated Resource Plan
See "Environmental Matters" herein for additional information regarding proposed
and final EPA rules and regulations, including revisions to ELG for steam
electric power plants and additional regulations of CCR and CO2.
On July 16, 2019, the Georgia PSC voted to approve Georgia Power's modified
triennial IRP (Georgia Power 2019 IRP). 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. In accordance with the 2019 ARP, the remaining net book values at December
31, 2019 of $488 million for the Plant Hammond units are being recovered over a
period equal to the respective unit's remaining useful life, which varies
between 2024 and 2035, and $30 million for Plant McIntosh Unit 1 is being
recovered over a three-year period ending December 31, 2022. In addition,
approximately $20 million of related unusable materials and supplies inventory
balances and approximately $295 million of net capitalized asset retirement
costs were reclassified to a regulatory asset. In accordance with the
modifications to the earnings sharing mechanism approved in the 2019 ARP,
Georgia Power fully amortized the regulatory assets associated with these
unusable materials and supplies inventory

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balances as well as a regulatory asset of approximately $50 million related to
costs for a future generation site in Stewart County, Georgia. See "Rate Plans -
2019 ARP" herein for additional information.
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 2019 ARP, the Georgia PSC approved recovery of the
estimated under recovered balance of these compliance costs at December 31, 2019
over a three-year period ending December 31, 2022 and recovery of estimated
compliance costs for 2020, 2021, and 2022 over three-year periods ending
December 31, 2022, 2023, and 2024, respectively, with recovery of construction
contingency beginning in the year following actual expenditure. The under
recovered balance at December 31, 2019 was $175 million and the estimated
compliance costs expected to be incurred in 2020, 2021, and 2022 are $265
million, $290 million, and $390 million, respectively. The ECCR tariff is
expected to be revised for actual expenditures and updated estimates through
future annual compliance filings. See "Environmental Matters - Environmental
Laws and Regulations - Coal Combustion Residuals" and FINANCIAL CONDITION AND
LIQUIDITY - "Capital Requirements" and "Contractual Obligations" herein and Note
6 to the financial statements for additional information regarding Georgia
Power's AROs.
On February 4, 2020, the Georgia PSC voted to deny a motion for reconsideration
filed by the Sierra Club regarding the Georgia PSC's decision in the 2019 ARP
allowing Georgia Power to recover compliance costs for CCR 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 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.
Fuel Cost Recovery
Georgia Power has established fuel cost recovery rates approved by the Georgia
PSC. Georgia Power is scheduled to file its next fuel case no later than March
16, 2020, with new rates, if any, to be effective June 1, 2020. Georgia Power
continues to be allowed to adjust its fuel cost recovery rates under an interim
fuel rider prior to the next fuel case if the under or over recovered fuel
balance exceeds $200 million. At December 31, 2019, Georgia Power's over
recovered fuel balance was $73 million.
Georgia Power's fuel cost recovery mechanism includes costs associated with a
natural gas hedging program, as revised and approved by the Georgia PSC,
allowing the use of an array of derivative instruments within a 48-month time
horizon.
Fuel cost recovery revenues as recorded on the financial statements are adjusted
for differences in actual recoverable fuel costs and amounts billed in current
regulated rates. Accordingly, changes in the billing factor will not have a
significant effect on Southern Company's or Georgia Power's revenues or net
income but will affect operating cash flows.
Storm Damage Recovery
Beginning January 1, 2020, Georgia Power is recovering $213 million annually
through December 31, 2022, as provided in the 2019 ARP, for incremental
operations and maintenance costs of damage from major storms to its transmission
and distribution facilities. At December 31, 2019, the balance in the regulatory
asset related to storm damage was $410 million. The rate of storm damage cost
recovery is expected to be adjusted in future regulatory proceedings as
necessary. As a result of this regulatory treatment, costs related to storms are
not expected to have a material impact on Southern Company's or Georgia Power's
financial statements. See Note 2 to the financial statements under "Georgia
Power - Storm Damage Recovery" for additional information regarding Georgia
Power's storm damage reserve.
Mississippi Power
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 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. See
Note 2 to the financial statements under "Mississippi Power" for additional
information.

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2019 Base Rate Case
On November 26, 2019, Mississippi Power filed the Mississippi Power 2019 Base
Rate Case with the Mississippi PSC. The filing includes a requested annual
decrease in Mississippi Power's retail rates of $5.8 million, or 0.6%, which is
driven primarily by changes in the amortization rates of certain regulatory
assets and liabilities and cost reductions, partially offset by an increase in
Mississippi Power's requested return on investment and depreciation associated
with the filing of an updated depreciation study. The revenue requirements
included in the filing are based on a projected test year period of January 1,
2020 through December 31, 2020, a 53% average equity ratio, and a 7.728% return
on investment. The filing reflects the elimination of separate rates for costs
associated with the Kemper County energy facility and energy efficiency
initiatives; those costs are proposed to be included in the PEP, ECO Plan, and
ad valorem tax adjustment factor, as applicable. On December 10, 2019, the
Mississippi PSC suspended the base rate case filing through no later than March
25, 2020. If no further action is taken by the Mississippi PSC, the proposed
rates may be effective beginning on March 26, 2020. The ultimate outcome of this
matter cannot be determined at this time.
Operations Review
In August 2018, the Mississippi PSC began an operations review of Mississippi
Power, for which the final report is expected prior to the conclusion of the
Mississippi Power 2019 Base Rate Case. The review includes, but is not limited
to, a comparative analysis of its costs, its cost recovery framework, and ways
in which it may streamline management operations for the reasonable benefit of
ratepayers. The ultimate outcome of this matter cannot be determined at this
time.
Reserve Margin Plan
On December 31, 2019, Mississippi Power updated its proposed RMP, originally
filed in August 2018, as required by the Mississippi PSC. In 2018, Mississippi
Power had proposed alternatives to reduce its reserve margin and lower or avoid
operating costs, with the most economic alternatives being the two-year and
seven-year acceleration of the retirement of Plant Watson Units 4 and 5,
respectively, to the first quarter 2022 and the four-year acceleration of the
retirement of Plant Greene County Units 1 and 2 to the third quarter 2021 and
the third quarter 2022, respectively. The December 2019 update noted that Plant
Daniel Units 1 and 2 currently have long-term economics similar to Plant Watson
Unit 5. The Plant Greene County unit retirements would require the completion by
Alabama Power of proposed transmission and system reliability improvements, as
well as agreement by Alabama Power. The RMP filing also states that, in the
event the Mississippi PSC ultimately approves an alternative that includes an
accelerated retirement, Mississippi Power would require authorization to defer
in a regulatory asset for future recovery the remaining net book value of the
units at the time of retirement. A decision by the Mississippi PSC that does not
include recovery of the remaining book value of any generating units retired
could have a material impact on Southern Company's and Mississippi Power's
financial statements. The ultimate outcome of this matter cannot be determined
at this time. See Note 3 to the financial statements under "Other Matters -
Mississippi Power" for additional information on Plant Daniel Units 1 and 2.
Performance Evaluation Plan
Mississippi Power's retail base rates generally are set under the PEP, a rate
plan approved by the Mississippi PSC. In recognition that Mississippi Power's
long-term financial success is dependent upon how well it satisfies its
customers' needs, PEP includes performance indicators that directly tie customer
service indicators to Mississippi Power's allowed ROE. PEP measures Mississippi
Power's performance on a 10-point scale as a weighted average of results in
three areas: average customer price, as compared to prices of other regional
utilities (weighted at 40%); service reliability, measured in percentage of time
customers had electric service (40%); and customer satisfaction, measured in a
survey of residential customers (20%). Typically, two PEP filings are made for
each calendar year: the PEP projected filing, which is typically filed prior to
the beginning of the year based on a projected revenue requirement, and the PEP
lookback filing, which is filed after the end of the year and allows for review
of the actual revenue requirement compared to the projected filing.
In February 2018, Mississippi Power revised its annual projected PEP filing for
2018 to reflect the impacts of the Tax Reform Legislation. The revised filing
requested an increase of $26 million in annual revenues, based on a performance
adjusted ROE of 9.33% and an increased equity ratio of 55%. In July 2018,
Mississippi Power and the MPUS entered into a settlement agreement, which was
approved by the Mississippi PSC in August 2018 (PEP Settlement Agreement). Rates
under the PEP Settlement Agreement became effective with the first billing cycle
of September 2018. The PEP Settlement Agreement provided for an increase of
approximately $21.6 million in annual base retail revenues, which excluded
certain compensation costs contested by the MPUS, as well as approximately $2
million subsequently approved for recovery through the 2018 Energy Efficiency
Cost Rider. Under the PEP Settlement Agreement, Mississippi Power deferred a
portion of the contested compensation costs for 2018 and 2019 as a regulatory
asset, which totaled $4 million as of December 31, 2019 and is included in other
regulatory assets,

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deferred on the balance sheet. The Mississippi PSC is expected to rule on the
appropriate treatment for such costs in connection with the Mississippi Power
2019 Base Rate Case. The ultimate outcome of this matter cannot be determined at
this time.
Pursuant to the PEP Settlement Agreement, Mississippi Power's
performance-adjusted allowed ROE is 9.31% and its allowed equity ratio is capped
at 51%, pending further review by the Mississippi PSC. In lieu of the requested
equity ratio increase, Mississippi Power retained $44 million of excess
accumulated deferred income taxes resulting from the Tax Reform Legislation
until the conclusion of the Mississippi Power 2019 Base Rate Case. Further,
Mississippi Power agreed to seek equity contributions sufficient to restore its
equity ratio to 50% by December 31, 2018. Since Mississippi Power's actual
average equity ratio for 2018 was more than 1% lower than the 50% target,
Mississippi Power deferred the corresponding difference in its revenue
requirement of approximately $4 million as a regulatory liability for resolution
in the Mississippi Power 2019 Base Rate Case. Pursuant to the PEP Settlement
Agreement, PEP proceedings are suspended until after the conclusion of the
Mississippi Power 2019 Base Rate Case and Mississippi Power was not required to
make any PEP filings for regulatory years 2018, 2019, and 2020.
Energy Efficiency
On February 5, 2019, the Mississippi PSC issued an order approving Mississippi
Power's Energy Efficiency Cost Rider 2019 compliance filing, which included a
slight decrease in annual retail revenues, effective with the first billing
cycle in March 2019.
As part of the Mississippi Power 2019 Base Rate Case, Mississippi Power has
proposed that the Energy Efficiency Cost Rider be eliminated and those costs be
included in the PEP. The ultimate outcome of this matter cannot be determined at
this time.
Environmental Compliance Overview Plan
In accordance with a 2011 accounting order from the Mississippi PSC, Mississippi
Power has the authority to defer in a regulatory asset for future recovery all
plant retirement- or partial retirement-related costs resulting from
environmental regulations. The Mississippi PSC approved $41 million and $17
million of costs that were reclassified to regulatory assets associated with the
fuel conversion of Plant Watson and Plant Greene County, respectively, for
amortization over five-year periods ending in July 2021 and July 2022,
respectively.
In August 2018, the Mississippi PSC approved an annual increase in revenues
related to the ECO Plan of approximately $17 million, effective with the first
billing cycle for September 2018. This increase represented the maximum 2%
annual increase in revenues and primarily related to the carryforward from the
prior year.
The increase was the result of Mississippi PSC approval of an agreement between
Mississippi Power and the MPUS to settle the 2018 ECO Plan filing (ECO
Settlement Agreement) and was sufficient to recover costs through 2019,
including remaining amounts deferred from prior years along with the related
carrying costs. In accordance with the ECO Settlement Agreement, ECO Plan
proceedings are suspended until after the conclusion of the Mississippi Power
2019 Base Rate Case and Mississippi Power was not required to make any ECO Plan
filings for 2018, 2019, and 2020, with any necessary adjustments reflected in
the Mississippi Power 2019 Base Rate Case. The ECO Settlement Agreement contains
the same terms as the PEP Settlement Agreement described herein with respect to
allowed ROE and equity ratio. At December 31, 2019, Mississippi Power has
recorded $2 million in other regulatory liabilities, deferred on the balance
sheet related to the actual December 31, 2018 average equity ratio differential
from target applicable to the ECO Plan.
On October 24, 2019, the Mississippi PSC approved Mississippi Power's July 9,
2019 request for a CPCN 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 6 to the financial statements for additional information
on AROs and Note 3 to the financial statements under "Other Matters -
Mississippi Power" for additional information on Gulf Power's ownership in Plant
Daniel.
Fuel Cost Recovery
Mississippi Power annually establishes and is required to file for an adjustment
to the retail fuel cost recovery factor that is approved by the Mississippi PSC.
The Mississippi PSC approved decreases of $35 million and $24 million, effective
in February 2019 and 2020, respectively. At December 31, 2019 and 2018, over
recovered retail fuel costs included in other current liabilities on Southern
Company's balance sheets and over recovered regulatory clause liabilities on
Mississippi Power's balance sheets were approximately $23 million and $8
million, respectively.

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Mississippi Power has wholesale MRA and Market Based (MB) fuel cost recovery
factors. Effective with the first billing cycle for January 2019, the wholesale
MRA fuel rate increased $16 million annually and the wholesale MB fuel rate
decreased by an immaterial amount. Effective January 1, 2020, the wholesale MRA
fuel rate increased $1 million annually and the wholesale MB fuel rate decreased
by an immaterial amount. At December 31, 2019 and 2018, over recovered wholesale
MRA fuel costs included in other current liabilities on Southern Company's
balance sheets and over recovered regulatory clause liabilities on Mississippi
Power's balance sheets were approximately $6 million. At December 31, 2019 and
2018, over/under recovered wholesale MB fuel costs included in the balance
sheets were immaterial.
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 operating cash flows.
Kemper County Energy Facility
Overview
The Kemper County energy facility was designed to utilize IGCC technology with
an expected output capacity of 582 MWs and to be fueled by locally mined lignite
(an abundant, lower heating value coal) from a mine owned by Mississippi Power
and situated adjacent to the Kemper County energy facility.
Schedule and Cost Estimate
In 2012, the Mississippi PSC issued an order confirming the CPCN originally
approved by the Mississippi PSC in 2010 authorizing the acquisition,
construction, and operation of the Kemper County energy facility. The order
approved a construction cost cap of up to $2.88 billion, with recovery of
prudently-incurred costs subject to approval by the Mississippi PSC. The Kemper
County energy facility was originally projected to be placed in service in May
2014. Mississippi Power placed the combined cycle and the associated common
facilities portion of the Kemper County energy facility in service in August
2014. The combined cycle and associated common facilities portions of the Kemper
County energy facility were dedicated as Plant Ratcliffe in April 2018.
In June 2017, the Mississippi PSC stated its intent to issue an order, which
occurred in July 2017, directing Mississippi Power to pursue a settlement under
which the Kemper County energy facility would be operated as a natural gas
plant, rather than an IGCC plant, and address all issues associated with the
Kemper County energy facility. The order established a new docket for the
purpose of pursuing a global settlement of the related costs (Kemper Settlement
Docket). In June 2017, Mississippi Power notified the Mississippi PSC that it
would begin a process to suspend operations and start-up activities on the
gasifier portion of the Kemper County energy facility, given the uncertainty as
to its future.
At the time of project suspension in June 2017, the total cost estimate for the
Kemper County energy facility was approximately $7.38 billion, including
approximately $5.95 billion of costs subject to the construction cost cap, net
of $137 million in additional grants from the DOE received in April 2016. In the
aggregate, Mississippi Power had recorded charges to income of $3.07 billion
($1.89 billion after tax) as a result of changes in the cost estimate above the
cost cap for the Kemper IGCC through May 2017.
Given the Mississippi PSC's stated intent regarding no further rate increase for
the Kemper County energy facility and the subsequent suspension, cost recovery
of the gasifier portions became no longer probable; therefore, Mississippi Power
recorded an additional charge to income in June 2017 of $2.8 billion ($2.0
billion after tax), which included estimated costs associated with the
gasification portions of the plant and lignite mine. During the third and fourth
quarters of 2017, Mississippi Power recorded charges to income of $242 million
($206 million after tax), including $164 million for ongoing project costs,
estimated mine and gasifier-related costs, and certain termination costs during
the suspension period prior to conclusion of the Kemper Settlement Docket, as
well as the charge associated with the Kemper Settlement Agreement discussed
below.
In 2019, Mississippi Power recorded pre-tax and after-tax charges to income of
$24 million, primarily associated with the expected close out of a related DOE
contract, as well as other abandonment and related closure costs and ongoing
period costs, net of salvage proceeds, for the mine and gasifier-related assets.
The after-tax amount for 2019 includes an adjustment related to the tax
abandonment of the Kemper IGCC following the filing of the 2018 tax return. In
2018, Mississippi Power recorded pre-tax charges to income of $37 million ($68
million benefit after tax), primarily associated with abandonment and related
closure costs and ongoing period costs, net of salvage proceeds, for the mine
and gasifier-related assets, as well as the impact of a change in the valuation
allowance for the related state income tax NOL carryforward.
Mississippi Power expects to substantially complete mine reclamation activities
in 2020 and dismantlement of the abandoned gasifier-related assets and site
restoration activities are expected to be completed in 2024. The additional
pre-tax period costs associated with dismantlement and site restoration
activities, including related costs for compliance and safety, ARO accretion,

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and property taxes, are estimated to total $17 million in 2020, $15 million to
$16 million annually in 2021 through 2023, and $5 million in 2024.
See Note 10 to the financial statements for additional information.
Rate Recovery
In February 2018, the Mississippi PSC voted to approve a settlement agreement
related to cost recovery for the Kemper County energy facility among Mississippi
Power, the MPUS, and certain intervenors (Kemper Settlement Agreement), which
resolved all cost recovery issues, modified the CPCN to limit the Kemper County
energy facility to natural gas combined cycle operation, and provided for an
annual revenue requirement of approximately $99.3 million for costs related to
the Kemper County energy facility, which included the impact of the Tax Reform
Legislation. The revenue requirement was based on (i) a fixed ROE for 2018 of
8.6% excluding any performance adjustment, (ii) a ROE for 2019 calculated in
accordance with PEP, excluding the performance adjustment, (iii) for future
years, a performance-based ROE calculated pursuant to PEP, and (iv) amortization
periods for the related regulatory assets and liabilities of eight years and six
years, respectively. The revenue requirement also reflects a disallowance
related to a portion of Mississippi Power's investment in the Kemper County
energy facility requested for inclusion in rate base, which was recorded in the
fourth quarter 2017 as an additional charge to income of approximately $78
million ($85 million net of accumulated depreciation of $7 million) pre-tax ($48
million after tax).
Under the Kemper Settlement Agreement, retail customer rates were reduced by
approximately $26.8 million annually, effective with the first billing cycle of
April 2018, and include no recovery for costs associated with the gasifier
portion of the Kemper County energy facility in 2018 or at any future date.
On November 26, 2019, Mississippi Power filed the Mississippi Power 2019 Base
Rate Case, which reflects the elimination of separate rates for costs associated
with the Kemper County energy facility; these costs are proposed to be included
in rates for PEP, ECO Plan, and ad valorem tax adjustment factor, as applicable.
The ultimate outcome of this matter cannot be determined at this time.
Lignite Mine and CO2 Pipeline Facilities
Mississippi Power owns the lignite mine and equipment and mineral reserves
located around the Kemper County energy facility site. The mine started
commercial operation in June 2013. In connection with the Kemper County energy
facility construction, Mississippi Power also constructed a pipeline for the
transport of captured CO2.
In 2010, Mississippi Power executed a management fee contract with Liberty Fuels
Company, LLC (Liberty Fuels), a wholly-owned subsidiary of The North American
Coal Corporation, which developed, constructed, and is responsible for the
mining operations through the end of the mine reclamation. As the mining permit
holder, Liberty Fuels has a legal obligation to perform mine reclamation and
Mississippi Power has a contractual obligation to fund all reclamation
activities. As a result of the abandonment of the Kemper IGCC, final mine
reclamation began in 2018 and is expected to be substantially completed in 2020,
with monitoring expected to continue through 2027. See Note 6 to the financial
statements for additional information.
On December 31, 2019, Mississippi Power transferred ownership of the CO2
pipeline to an unrelated gas pipeline company, with no resulting impact on
income. In conjunction with the transfer of the CO2 pipeline, the parties agreed
to enter into a 15-year firm transportation agreement, which is expected to be
signed by March 2020, providing for the conversion by the pipeline company of
the CO2 pipeline to a natural gas pipeline to be used for the delivery of
natural gas to Plant Ratcliffe. The agreement will be treated as a finance lease
for accounting purposes upon commencement, which is expected to occur by August
2020. See Note 9 to the financial statements for additional information.
Government Grants
In 2010, the DOE, through a cooperative agreement with SCS, agreed to fund $270
million of the Kemper County energy facility through the grants awarded to the
project by the DOE under the Clean Coal Power Initiative Round 2. In 2016,
additional DOE grants in the amount of $137 million were awarded to the Kemper
County energy facility. Through December 31, 2018, Mississippi Power received
total DOE grants of $387 million, of which $382 million reduced the construction
costs of the Kemper County energy facility and $5 million reimbursed Mississippi
Power for expenses associated with DOE reporting. 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
expects to close out the DOE contract related to the Kemper County energy
facility in 2020. 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. The ultimate outcome of this matter cannot be determined at this time;
however, it could have a material impact on Southern Company's and Mississippi
Power's financial statements.

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Municipal and Rural Associations Tariff
Mississippi Power provides wholesale electric service to Cooperative Energy,
East Mississippi Electric Power Association, and the City of Collins, all
located in southeastern Mississippi, under a long-term, cost-based,
FERC-regulated MRA tariff.
In 2017, Mississippi Power and Cooperative Energy executed, and the FERC
accepted, a Shared Service Agreement (SSA), as part of the MRA tariff, under
which Mississippi Power and Cooperative Energy will share in providing
electricity to the Cooperative Energy delivery points under the tariff,
effective January 1, 2018. The SSA may be cancelled by Cooperative Energy with
10 years notice after December 31, 2020. As of December 31, 2019, Cooperative
Energy has the option to decrease its use of Mississippi Power's generation
services under the MRA tariff up to 2.5% annually, with required notice, up to a
maximum total reduction of 11%, or approximately $9 million in cumulative annual
base revenues.
On May 7, 2019, the FERC accepted Mississippi Power's requested $3.7 million
annual decrease in MRA base rates effective January 1, 2019, as agreed upon in
the MRA Settlement Agreement, resolving all matters related to the Kemper County
energy facility, similar to the retail rate settlement agreement approved by the
Mississippi PSC in February 2018, and reflecting the impacts of the Tax Reform
Legislation.
Cooperative Energy Power Supply Agreement
Effective April 1, 2018, Mississippi Power and Cooperative Energy amended and
extended a previous power supply agreement through March 31, 2021, which was
subsequently extended through May 31, 2021. The amendment increased the total
capacity from 86 MWs to 286 MWs.
Cooperative Energy also has a 10-year network integration transmission service
agreement (NITSA) with SCS for transmission service to certain delivery points
on Mississippi Power's transmission system through March 31, 2021. As a result
of the PSA amendment, Cooperative Energy and SCS also amended the terms of the
NITSA, which the FERC approved, to provide for the purchase of incremental
transmission capacity from April 1, 2018 through March 31, 2021.
Southern Company Gas
Utility Regulation and Rate Design
The natural gas distribution utilities are subject to regulations and oversight
by their respective state regulatory agencies. Rates charged to customers vary
according to customer class (residential, commercial, or industrial) and rate
jurisdiction. These agencies approve rates designed to provide the opportunity
to generate revenues to recover all prudently-incurred costs, including a return
on rate base sufficient to pay interest on debt and provide a reasonable ROE.
Rate base generally consists of the original cost of the utility plant in
service, working capital, and certain other assets, less accumulated
depreciation on the utility plant in service and net deferred income tax
liabilities, and may include certain other additions or deductions.
The natural gas market for Atlanta Gas Light was deregulated in 1997.
Accordingly, Marketers, rather than a traditional utility, sell natural gas to
end-use customers in Georgia and handle customer billing functions. The
Marketers file their rates monthly with the Georgia PSC. As a result of
operating in a deregulated environment, Atlanta Gas Light's role includes:
• distributing natural gas for Marketers;

• constructing, operating, and maintaining the gas system infrastructure,

including responding to customer service calls and leaks;

• reading meters and maintaining underlying customer premise information for


       Marketers; and


•      planning and contracting for capacity on interstate transportation and
       storage systems.


Atlanta Gas Light earns revenue by charging rates to its customers based
primarily on monthly fixed charges that are set by the Georgia PSC and adjusted
periodically. The Marketers add these fixed charges when billing customers. This
mechanism, called a straight-fixed-variable rate design, minimizes the
seasonality of Atlanta Gas Light's revenues since the monthly fixed charge is
not volumetric or directly weather dependent. See "GRAM" and "PRP" herein for
additional information.
With the exception of Atlanta Gas Light, the earnings of the natural gas
distribution utilities can be affected by customer consumption patterns that are
largely a function of weather conditions and price levels for natural gas.
Specifically, customer demand substantially increases during the Heating Season
when natural gas is used for heating purposes. Southern Company Gas has various
mechanisms, such as weather and revenue normalization mechanisms and weather
derivative instruments, that limit exposure to weather changes within typical
ranges in these utilities' respective service territories.
With the exception of Atlanta Gas Light, the natural gas distribution utilities
are authorized by the relevant regulatory agencies in the states in which they
serve to use natural gas cost recovery mechanisms that adjust rates to reflect
changes in the wholesale

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cost of natural gas and ensure recovery of all costs prudently incurred in
purchasing natural gas for customers. Natural gas cost recovery revenues are
adjusted for differences in actual recoverable natural gas costs and amounts
billed in current regulated rates. Changes in the billing factor will not have a
significant effect on Southern Company Gas' revenues or net income, but will
affect cash flows. Since Atlanta Gas Light does not sell natural gas directly to
its end-use customers, it does not utilize a traditional natural gas cost
recovery mechanism. However, Atlanta Gas Light does maintain natural gas
inventory for the Marketers in Georgia and recovers the cost through recovery
mechanisms approved by the Georgia PSC specific to Georgia's deregulated market.
In addition to natural gas recovery mechanisms, there are other cost recovery
mechanisms, such as regulatory riders, which vary by utility but allow recovery
of certain costs, such as those related to infrastructure replacement programs
as well as environmental remediation and energy efficiency plans. In traditional
rate designs, utilities recover a significant portion of the fixed customer
service and pipeline infrastructure costs based on assumed natural gas volumes
used by customers. The utilities, including Nicor Gas beginning in November
2019, have decoupled regulatory mechanisms that Southern Company Gas believes
encourage conservation by separating the recoverable amount of these fixed costs
from the amounts of natural gas used by customers. See Note 2 to the financial
statements under "Southern Company Gas - Rate Proceedings" for additional
information. Also see "Construction Programs - Southern Company Gas -
Infrastructure Replacement Programs and Capital Projects" for additional
information regarding infrastructure replacement programs at certain of the
natural gas distribution utilities.
The following table provides regulatory information for Southern Company Gas'
natural gas distribution utilities:
                                                                      Virginia
                                    Nicor Gas   Atlanta Gas Light   Natural Gas    Chattanooga Gas
Authorized ROE(a)                     9.73%          10.25%            9.50%            9.80%
                                                                      9.00% -
Authorized ROE range(a)                N/A       10.05% - 10.45%       10.00%            N/A
Weather normalization mechanisms(b)                                      ü                ü
Decoupled, including
straight-fixed-variable rates(c)        ü               ü


Regulatory infrastructure program
rates(d)                                ü                                ü
Bad debt rider(e)                       ü                                ü                ü
Energy efficiency plan(f)               ü                                ü
Annual base rate adjustment
mechanism(g)                                            ü                                 ü
Year of last rate decision            2019            2019              2018            2018

(a) Atlanta Gas Light's authorized ROE and ROE range became effective on January

1, 2020. Atlanta Gas Light's ROE for 2019 was 10.75%.

(b) Regulatory mechanisms that allow recovery of costs in the event of unseasonal

weather, but are not direct offsets to the potential impacts on earnings of

weather and customer consumption. These mechanisms are designed to help

stabilize operating results by increasing base rate amounts charged to

customers when weather is warmer than normal and decreasing amounts charged

when weather is colder than normal.

natural gas volumes used by customers. On October 2, 2019, Nicor Gas received

approval for a volume balancing adjustment, a revenue decoupling mechanism

for residential customers that provides a monthly benchmark level of revenue

per rate class for recovery.

(d) Programs that update or expand distribution systems and LNG facilities.

(e) The recovery (refund) of bad debt expense over (under) an established


    benchmark expense. Nicor Gas, Virginia Natural Gas, and Chattanooga Gas
    recover the gas portion of bad debt expense through their purchased gas
    adjustment mechanisms.

(f) Recovery of costs associated with plans to achieve specified energy savings

goals.

(g) Regulatory mechanism allowing annual adjustments to base rates up or down

based on authorized ROE and/or ROE range.

GRAM


In December 2019, the Georgia PSC approved the continuation of GRAM as part of
Atlanta Gas Light's 2019 rate case order. Various infrastructure programs
previously authorized by the Georgia PSC, including the Integrated Vintage
Plastic Replacement Program (i-VPR) to replace aging plastic pipe and the
Integrated System Reinforcement Program (i-SRP) to upgrade Atlanta Gas Light's
distribution system and LNG facilities in Georgia, continue under GRAM and the
recovery of and return on the infrastructure program investments are included in
annual base rate adjustments. The future expected costs to be recovered through
rates related to allowed, but not incurred, costs are recognized in an
unrecognized ratemaking amount that is not reflected on the balance sheets. This
allowed cost is primarily the equity return on the capital investment under the
infrastructure programs in place prior to GRAM. See "Unrecognized Ratemaking
Amounts" herein for additional information. The Georgia PSC reviews Atlanta Gas
Light's performance annually under GRAM. See "Rate Proceedings" herein for
additional information.

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Pursuant to the GRAM approval, Atlanta Gas Light and the staff of the Georgia
PSC agreed to a variation of the Integrated Customer Growth Program to extend
pipeline facilities to serve customers in areas without pipeline access and
create new economic development opportunities in Georgia. As a result, a new
tariff was created, effective October 10, 2017, to provide up to $15 million
annually for Atlanta Gas Light to commit to strategic economic development
projects. Projects under this tariff must be approved by the Georgia PSC.
PRP
Atlanta Gas Light previously recovered PRP costs through a PRP surcharge
established in 2015 to address recovery of the under recovered PRP balance and
the related carrying costs. Effective January 2018, PRP costs are being
recovered through GRAM and base rates until the earlier of the full recovery of
the under recovered amount or December 31, 2025. The under recovered balance at
December 31, 2019 was $135 million, including $70 million of unrecognized equity
return. See "Rate Proceedings" and "Unrecognized Ratemaking Amounts" herein for
additional information.
Rate Proceedings
Nicor Gas
In January 2018, the Illinois Commission approved a $137 million increase in
annual base rate revenues, including $93 million related to the recovery of
investments under the Investing in Illinois program, effective in February 2018,
based on a ROE of 9.8%. In May 2018, the Illinois Commission approved Nicor Gas'
rehearing request for revised base rates to incorporate the reduction in the
federal income tax rate as a result of the Tax Reform Legislation. The resulting
decrease of approximately $44 million in annual base rate revenues became
effective May 5, 2018. The benefits of the Tax Reform Legislation from January
25, 2018 through May 4, 2018 were refunded to customers via bill credits and
concluded in the second quarter 2019.
In November 2018, Nicor Gas filed a general base rate case with the Illinois
Commission. On October 2, 2019, the Illinois Commission approved a $168 million
annual base rate increase effective October 8, 2019. The base rate increase
included $65 million related to the recovery of program costs under the
Investing in Illinois program and was based on a ROE of 9.73% and an equity
ratio of 54.2%. Additionally, the Illinois Commission approved a volume
balancing adjustment, a revenue decoupling mechanism for residential customers
that provides a monthly benchmark level of revenue per rate class for recovery.
Atlanta Gas Light
On June 3, 2019, Atlanta Gas Light filed a general base rate case with the
Georgia PSC. On December 19, 2019, the Georgia PSC approved a $65 million annual
base rate increase, effective January 1, 2020, based on a ROE of 10.25% and an
equity ratio of 56%. Earnings will be evaluated against a ROE range of 10.05% to
10.45%, with disposition of any earnings above 10.45% to be determined by the
Georgia PSC. Additionally, the Georgia PSC approved continuation of the
previously authorized inclusion in base rates of the recovery of and return on
the infrastructure program investments, including, but not limited to, GRAM
adjustments, and a reauthorization and continuation of GRAM until terminated by
the Georgia PSC. GRAM filing rate adjustments will be based on the authorized
ROE of 10.25%. GRAM adjustments for 2021 may not exceed 5% of 2020 base rates.
The 5% limitation does not set a precedent in any future rate proceedings by
Atlanta Gas Light.
On January 31, 2020, in accordance with the Georgia PSC's order for the 2019
rate case, Atlanta Gas Light filed a recommended notice of proposed rulemaking
for a long-range planning tool. The proposal provides for participating natural
gas utilities to file a comprehensive capacity supply and related infrastructure
delivery plan for a 10-year period, including capital and related operations and
maintenance expense budgets. Participating natural gas utilities would file an
updated 10-year plan at least once every third year under the proposal. Related
costs of implementing an approved comprehensive plan would be included in the
utility's next rate case or GRAM filing. The rulemaking process is expected to
be completed during 2020.
Virginia Natural Gas
In December 2018, the Virginia Commission approved Virginia Natural Gas' annual
information form filing, which reduced annual base rates by $14 million
effective January 1, 2019 due to lower tax expense as a result of the Tax Reform
Legislation, along with customer refunds, via bill credits, for $14 million
related to 2018 tax benefits deferred as a regulatory liability at December 31,
2018. These customer refunds were completed in the first quarter 2019.
On February 3, 2020, Virginia Natural Gas filed a notice of intent with the
Virginia Commission as required prior to the filing of a base rate case, which
will occur between April 3, 2020 and April 30, 2020. The ultimate outcome of
this matter cannot be determined at this time.
See Note 2 to the financial statements under "Southern Company Gas - Rate
Proceedings" for additional information.

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Affiliate Asset Management Agreements
With the exception of Nicor Gas, the natural gas distribution utilities use
asset management agreements with an affiliate, Sequent, for the primary purpose
of reducing utility customers' gas cost recovery rates through payments to the
utilities by Sequent. For Atlanta Gas Light, these payments are controlled by
the Georgia PSC and are utilized for infrastructure improvements and to fund
heating assistance programs, rather than as a reduction to gas cost recovery
rates. Under these asset management agreements, Sequent supplies natural gas to
the utility and markets available pipeline and storage capacity to improve the
overall cost of supplying gas to the utility customers. Currently, the natural
gas distribution utilities primarily purchase their gas from Sequent. The
purchase agreements require Sequent to provide firm gas to the natural gas
distribution utilities, but these natural gas distribution utilities maintain
the right and ability to make their own long-term supply arrangements if they
believe it is in the best interest of their customers.
Each agreement provides for Sequent to make payments to the natural gas
distribution utility through either an annual minimum guarantee within a profit
sharing structure, a profit sharing structure without an annual minimum
guarantee, or a fixed fee.
Unrecognized Ratemaking Amounts
The following table illustrates Southern Company Gas' authorized ratemaking
amounts that are not recognized on its balance sheets. These amounts are
primarily composed of an allowed equity rate of return on assets associated with
certain regulatory infrastructure programs. These amounts will be recognized as
revenues in Southern Company Gas' financial statements in the periods they are
billable to customers, the majority of which will be recovered by 2025.
                      December 31, 2019      December 31, 2018
                                    (in millions)
Atlanta Gas Light    $                70    $                95
Virginia Natural Gas                  10                     11
Nicor Gas                              2                      4
Total                $                82    $               110


Construction Programs
The Registrants 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, expanding and improving the electric
transmission and electric and natural gas distribution systems, and undertaking
projects to comply with environmental laws and regulations.
For the traditional electric operating companies, major generation construction
projects are subject to state PSC approval in order to be included in retail
rates. The largest construction project currently underway in the Southern
Company system is Plant Vogtle Units 3 and 4. See "Nuclear Construction" herein
for additional information. Also see "Regulatory Matters - Alabama Power" herein
for information regarding Alabama Power's construction of Plant Barry Unit 8.
While Southern Power generally constructs and acquires generation assets covered
by long-term PPAs, any uncontracted capacity could negatively affect future
earnings. See "Southern Power" herein, "Acquisitions and Dispositions - Southern
Power" herein, and Note 15 to the financial statements under "Southern Power"
for additional information about costs relating to Southern Power's acquisitions
that involve construction of renewable energy facilities.
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 "Southern Company Gas" herein for additional
information regarding infrastructure improvement programs at the natural gas
distribution utilities and certain pipeline construction projects.
See FINANCIAL CONDITION AND LIQUIDITY - "Capital Requirements" herein for
additional information regarding the Registrants' capital requirements for their
construction programs, including estimated totals for each of the next five
years.
Nuclear Construction
In 2009, the Georgia PSC certified construction of Plant Vogtle Units 3 and 4.
Georgia Power holds a 45.7% ownership interest in Plant Vogtle Units 3 and 4. In
2012, the NRC issued the related combined construction and operating licenses,
which allowed full construction of the two AP1000 nuclear units (with electric
generating capacity of approximately 1,100 MWs each) and related facilities to
begin. Until March 2017, construction on Plant Vogtle Units 3 and 4 continued
under the Vogtle 3 and 4 Agreement,

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which was a substantially fixed price agreement. In March 2017, the EPC
Contractor filed for bankruptcy protection under Chapter 11 of the U.S.
Bankruptcy Code.
In connection with the EPC Contractor's bankruptcy filing, Georgia Power, acting
for itself and as agent for the other Vogtle Owners, entered into several
transitional arrangements to allow construction to continue. In July 2017,
Georgia Power, acting for itself and as agent for the other Vogtle Owners,
entered into the Vogtle Services Agreement, whereby Westinghouse provides
facility design and engineering services, procurement and technical support, and
staff augmentation on a time and materials cost basis. The Vogtle Services
Agreement provides that it will continue until the start-up and testing of Plant
Vogtle Units 3 and 4 are complete and electricity is generated and sold from
both units. The Vogtle Services Agreement is terminable by the Vogtle Owners
upon 30 days' written notice.
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.
See Note 8 to the financial statements under "Long-term Debt - DOE Loan
Guarantee Borrowings" for information on the Amended and Restated Loan Guarantee
Agreement, including applicable covenants, events of default, mandatory
prepayment events, and conditions to borrowing.
Cost and Schedule
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:
                                           (in billions)

Base project capital cost forecast(a)(b) $ 8.2 Construction contingency estimate

0.2

Total project capital cost forecast(a)(b) 8.4 Net investment as of December 31, 2019(b) (5.9 ) Remaining estimate to complete(a) $ 2.5

(a) Excludes financing costs expected to be capitalized through AFUDC of

approximately $300 million, of which $23 million had been accrued through

December 31, 2019.

(b) Net of $1.7 billion received from Toshiba under the Guarantee Settlement

Agreement and approximately $188 million in related customer refunds.




As of December 31, 2019, approximately $140 million of the $366 million
construction contingency estimate established in the second quarter 2018 was
allocated to the base capital cost forecast for cost risks including, among
other factors, construction productivity; craft labor incentives; adding
resources for supervision, field support, project management, initial test
program, start-up, and operations and engineering support; subcontracts; 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 $2.2
billion had been incurred through December 31, 2019.
As part of its ongoing processes, Southern Nuclear continues to evaluate cost
and schedule forecasts on a regular basis to incorporate current information
available, particularly in the areas of commodity installation, system
turnovers, and workforce statistics.
In April 2019, Southern Nuclear 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. The project has
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. However,

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Southern Nuclear and Georgia Power believe that existing productivity levels and
pace of activity completion are sufficient to meet the regulatory-approved
in-service dates.
In February 2020, Southern Nuclear updated its cost and schedule forecast, which
did not change the projected overall capital cost forecast and confirmed the
expected in-service dates of November 2021 for Unit 3 and November 2022 for Unit
4. This update included initiatives to improve productivity while refining and
extending system turnover plans and certain near-term milestone dates. Other
milestone dates did not change. Achievement of the aggressive site work plan
relies on meeting increased monthly production and activity target values during
2020. To meet these 2020 targets, existing craft, including subcontractors,
construction productivity must improve and be sustained above historical average
levels, appropriate levels of craft laborers, particularly electrical and
pipefitter craft labor, must be maintained, and additional supervision and other
field support resources must be retained. Southern Nuclear and Georgia Power
continue to believe that pursuit of an aggressive site work plan is an
appropriate strategy to achieve completion of the units by their
regulatory-approved in-service dates.
As construction, including subcontract work, continues and testing and system
turnover activities increase, challenges with management of contractors and
vendors; subcontractor performance; 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,
installation, system turnover, and the initial testing and start-up, including
any required engineering changes or any remediation related thereto, of plant
systems, structures, or components (some of which are based on new technology
that only within the last few years 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.
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. As part of the aggressive site work plan, in January 2020,
Southern Nuclear notified the NRC of its intent to load fuel in 2020. 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 $12 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.
Joint Owner Contracts
In November 2017, the Vogtle Owners entered into an amendment to their joint
ownership agreements for Plant Vogtle Units 3 and 4 to provide for, among other
conditions, additional Vogtle Owner approval requirements. Effective in August
2018, the Vogtle Owners further amended the joint ownership agreements to
clarify and provide procedures for certain provisions of the joint ownership
agreements related to adverse events that require the vote of the holders of at
least 90% of the ownership interests in Plant Vogtle Units 3 and 4 to continue
construction (as amended, and together with the November 2017 amendment, the
Vogtle Joint Ownership Agreements). The Vogtle Joint Ownership Agreements also
confirm that the Vogtle Owners' sole recourse against Georgia Power or Southern
Nuclear for any action or inaction in connection with their performance as agent
for the Vogtle Owners is limited to removal of Georgia Power and/or Southern
Nuclear as agent, except in cases of willful misconduct.
As a result of an increase in the total project capital cost forecast and
Georgia Power's decision not to seek rate recovery of the increase in the base
capital costs in conjunction with the nineteenth VCM report in 2018, the holders
of at least 90% of the ownership interests in Plant Vogtle Units 3 and 4 were
required to vote to continue construction. In September 2018, the Vogtle Owners
unanimously voted to continue construction of Plant Vogtle Units 3 and 4.

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Amendments to the Vogtle Joint Ownership Agreements
In connection with the vote to continue construction, Georgia Power entered into
(i) a binding term sheet (Vogtle Owner Term Sheet) with the other Vogtle Owners
and MEAG Power's wholly-owned subsidiaries MEAG Power SPVJ, LLC (MEAG SPVJ),
MEAG Power SPVM, LLC (MEAG SPVM), and MEAG Power SPVP, LLC (MEAG SPVP) to take
certain actions which partially mitigate potential financial exposure for the
other Vogtle Owners, including additional amendments to the Vogtle Joint
Ownership Agreements and the purchase of PTCs from the other Vogtle Owners at
pre-established prices, and (ii) a term sheet (MEAG Term Sheet) with MEAG Power
and MEAG SPVJ to provide funding with respect to MEAG SPVJ's ownership interest
in Plant Vogtle Units 3 and 4 under certain circumstances. On January 14, 2019,
Georgia Power, MEAG Power, and MEAG SPVJ entered into an agreement to implement
the provisions of the MEAG Term Sheet. On February 18, 2019, Georgia Power, the
other Vogtle Owners, and MEAG Power's wholly-owned subsidiaries MEAG SPVJ, MEAG
SPVM, and MEAG SPVP entered into certain amendments to the Vogtle Joint
Ownership Agreements to implement the provisions of the Vogtle Owner Term Sheet.
The ultimate outcome of these matters cannot be determined at this time.
Regulatory Matters
In 2009, the Georgia PSC voted to certify construction of Plant Vogtle Units 3
and 4 with a certified capital cost of $4.418 billion. In addition, in 2009 the
Georgia PSC approved inclusion of the Plant Vogtle Units 3 and 4 related CWIP
accounts in rate base, and the State of Georgia enacted the Georgia Nuclear
Energy Financing Act, which allows Georgia Power to recover financing costs for
Plant Vogtle Units 3 and 4. Financing costs are recovered on all applicable
certified costs through annual adjustments to the NCCR tariff up to the
certified capital cost of $4.418 billion. At December 31, 2019, Georgia Power
had recovered approximately $2.2 billion of financing costs. Financing costs
related to capital costs above $4.418 billion are being recognized through AFUDC
and are expected to be recovered through retail rates over the life of Plant
Vogtle Units 3 and 4; however, Georgia Power will not record AFUDC related to
any capital costs in excess of the total deemed reasonable by the Georgia PSC
(currently $7.3 billion) and not requested for rate recovery. On December 17,
2019, the Georgia PSC approved Georgia Power's request to decrease the NCCR
tariff by $62 million annually, effective January 1, 2020.
Georgia Power is required to file semi-annual VCM reports with the Georgia PSC
by February 28 and August 31 of each year. In 2013, in connection with the
eighth VCM report, the Georgia PSC approved a stipulation between Georgia Power
and the staff of the Georgia PSC to waive the requirement to amend the Plant
Vogtle Units 3 and 4 certificate in accordance with the 2009 certification order
until the completion of Plant Vogtle Unit 3, or earlier if deemed appropriate by
the Georgia PSC and Georgia Power.
In 2016, the Georgia PSC voted to approve a settlement agreement (Vogtle Cost
Settlement Agreement) resolving certain prudency matters in connection with the
fifteenth VCM report. In December 2017, the Georgia PSC voted to approve (and
issued its related order on January 11, 2018) Georgia Power's seventeenth VCM
report and modified the Vogtle Cost Settlement Agreement. The Vogtle Cost
Settlement Agreement, as modified by the January 11, 2018 order, resolved the
following regulatory matters related to Plant Vogtle Units 3 and 4: (i) none of
the $3.3 billion of costs incurred through December 31, 2015 and reflected in
the fourteenth VCM report should be disallowed from rate base on the basis of
imprudence; (ii) the Contractor Settlement Agreement was reasonable and prudent
and none of the amounts paid pursuant to the Contractor Settlement Agreement
should be disallowed from rate base on the basis of imprudence; (iii) (a)
capital costs incurred up to $5.68 billion would be presumed to be reasonable
and prudent with the burden of proof on any party challenging such costs, (b)
Georgia Power would have the burden to show that any capital costs above $5.68
billion were prudent, and (c) a revised capital cost forecast of $7.3 billion
(after reflecting the impact of payments received under the Guarantee Settlement
Agreement and related customer refunds) was found reasonable; (iv) construction
of Plant Vogtle Units 3 and 4 should be completed, with Southern Nuclear serving
as project manager and Bechtel as primary contractor; (v) approved and deemed
reasonable Georgia Power's revised schedule placing Plant Vogtle Units 3 and 4
in service in November 2021 and November 2022, respectively; (vi) confirmed that
the revised cost forecast does not represent a cost cap and that prudence
decisions on cost recovery will be made at a later date, consistent with
applicable Georgia law; (vii) reduced the ROE used to calculate the NCCR tariff
(a) from 10.95% (the ROE rate setting point authorized by the Georgia PSC in the
2013 ARP) to 10.00% effective January 1, 2016, (b) from 10.00% to 8.30%,
effective January 1, 2020, and (c) from 8.30% to 5.30%, effective January 1,
2021 (provided that the ROE in no case will be less than Georgia Power's average
cost of long-term debt); (viii) reduced the ROE used for AFUDC equity for Plant
Vogtle Units 3 and 4 from 10.00% to Georgia Power's average cost of long-term
debt, effective January 1, 2018; and (ix) agreed that upon Unit 3 reaching
commercial operation, retail base rates would be adjusted to include carrying
costs on those capital costs deemed prudent in the Vogtle Cost Settlement
Agreement. The January 11, 2018 order also stated that if Plant Vogtle Units 3
and 4 are not commercially operational by June 1, 2021 and June 1, 2022,
respectively, the ROE used to calculate the NCCR tariff will be further reduced
by 10 basis points each month (but not lower than Georgia Power's average cost
of long-term debt) until the respective Unit is commercially operational. The
ROE reductions negatively impacted earnings by approximately $75 million,

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$100 million, and $25 million in 2019, 2018, and 2017, respectively, and are
estimated to have negative earnings impacts of approximately $140 million, $240
million, and $190 million in 2020, 2021, and 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.
In February 2018, Georgia Interfaith Power & Light, Inc. (GIPL) and Partnership
for Southern Equity, Inc. (PSE) filed a petition appealing the Georgia PSC's
January 11, 2018 order with the Fulton County Superior Court. In March 2018,
Georgia Watch filed a similar appeal to the Fulton County Superior Court for
judicial review of the Georgia PSC's decision and denial of Georgia Watch's
motion for reconsideration. In December 2018, the Fulton County Superior Court
granted Georgia Power's motion to dismiss the two appeals. On January 9, 2019,
GIPL, PSE, and Georgia Watch filed an appeal of this decision with the Georgia
Court of Appeals. On 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. 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.
On February 18, 2020, the Georgia PSC approved Georgia Power's twentieth VCM
report and its concurrently-filed twenty-first VCM report, including approval of
(i) $1.2 billion of construction capital costs incurred from July 1, 2018
through June 30, 2019 and (ii) $21.5 million of expenditures related to Georgia
Power's portion of an administrative claim filed in the Westinghouse bankruptcy
proceedings (which expenditures had previously been deferred by the Georgia PSC
for later approval). Through the twenty-first VCM, the Georgia PSC has approved
total construction capital costs incurred through June 30, 2019 of $6.7 billion
(before $1.7 billion of payments received under the Guarantee Settlement
Agreement and approximately $188 million in related customer refunds). On
February 19, 2020, Georgia Power filed its twenty-second VCM report with the
Georgia PSC covering the period from July 1, 2019 through December 31, 2019,
requesting approval of $674 million of construction capital costs incurred
during that period.
The ultimate outcome of these matters cannot be determined at this time.
Southern Power
During 2019, Southern Power completed construction of and placed in service the
385-MW Plant Mankato expansion and the Wildhorse Mountain facility, acquired and
continued construction of the Skookumchuck facility, and continued construction
of the Reading facility.
                            Approximate
                             Nameplate                                                     PPA
    Project                  Capacity                   Actual/Expected        PPA       Contract
   Facility      Resource      (MW)       Location            COD

Counterparties Period Projects Completed During the Year Ended December 31, 2019 Mankato Natural Gas 385 Mankato, MN May 2019


 Northern    20 years
expansion(a)                                                               States Power
                                                                             Company
Wildhorse          Wind         100      Pushmataha      December 2019       Arkansas    20 years
Mountain (b)                             County, OK                          Electric
                                                                           Cooperative
                                                                           Corporation
Projects Under Construction at December 31, 2019
Reading(c)         Wind         200       Osage and   Second quarter 2020     Royal      12 years
                                            Lyon                            Caribbean
                                        Counties, KS                       Cruises LTD
Skookumchuck(d)    Wind         136       Lewis and   Second quarter 2020  Puget Sound   20 years
                                          Thurston                            Energy
                                        Counties, WA

(a) Southern Power completed the sale of its equity interests in Plant Mankato,

including the expansion, to a subsidiary of Xcel on January 17, 2020. The

expansion unit started providing energy under a PPA with Northern States

Power on June 1, 2019. See "Acquisitions and Dispositions - Southern Power -

Sales of Natural Gas and Biomass Plants" herein and Note 15 to the financial

statements under "Southern Power" and "Assets Held for Sale" for additional

information.

(b) In May 2018, Southern Power purchased 100% of the membership interests of the

Wildhorse Mountain facility. In December 2019, Southern Power entered into a

tax equity partnership and, as a result, owns 100% of the Class B membership

interests.

the Reading facility pursuant to a joint development arrangement. Southern

Power may enter into a tax equity partnership, in which case it would then

own 100% of the Class B membership interests. The ultimate outcome of this


    matter cannot be determined at this time.



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(d) In October 2019, Southern Power purchased 100% of the membership interests of

the Skookumchuck facility pursuant to a joint development arrangement. In

December 2019, Southern Power entered into a tax equity agreement as the

Class B member with funding of the tax equity amounts expected to occur upon

commercial operation. Shortly after commercial operation, Southern Power may

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.




Total aggregate construction costs for the two projects under construction at
December 31, 2019, excluding acquisition costs, are expected to be between $490
million and $535 million. At December 31, 2019, total costs of construction
incurred for these projects were $417 million and are included in CWIP. The
ultimate outcome of these matters cannot be determined at this time.
Southern Company Gas
Infrastructure Replacement Programs and Capital Projects
Southern Company Gas continues to focus on capital discipline and cost control
while pursuing projects and initiatives that are expected to have current and
future benefits to customers, provide an appropriate return on invested capital,
and help ensure the safety and reliability of the utility infrastructure. 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 timely recovery of capital expenditures for
specific infrastructure replacement programs. Total capital expenditures
incurred during 2019 for gas distribution operations were $1.4 billion.
The following table and discussions provide updates on the infrastructure
replacement programs and capital projects at the natural gas distribution
utilities at December 31, 2019. These programs are risk-based and designed to
update and replace cast iron, bare steel, and mid-vintage plastic materials or
expand Southern Company Gas' distribution systems to improve reliability and
meet operational flexibility and growth. The anticipated expenditures for these
programs in 2020 are quantified in the discussion below.
                                                                                         Pipe
                                                                                       Installed
                                                                                         Since                                 Last
                                             Expenditures in    Expenditures Since      Project      Scope of     Program     Year of


 Utility         Program         Recovery         2019           Project Inception     Inception     Program      Duration    Program
                                                         (in millions)                  (miles)      (miles)      (years)
Nicor Gas      Investing in
               Illinois(*)        Rider     $           396     $           1,712           843        1,450            9      2023
Virginia     Steps to Advance
 Natural    Virginia's Energy
   Gas      (SAVE and SAVE II)    Rider                  45                   244           363          770           13      2024
  Total                                     $           441     $           1,956         1,206        2,220

(*) Includes replacement of pipes, compressors, and transmission mains along with

other improvements such as new meters. Scope of program miles is an estimate


    and subject to change.


Nicor Gas
In 2013, Illinois enacted legislation that allows Nicor Gas to provide more
widespread safety and reliability enhancements to its distribution system. The
legislation stipulates that rate increases to customers as a result of any
infrastructure investments shall not exceed a cumulative annual average of 4.0%
or, in any given year, 5.5% of base rate revenues. In 2014, the Illinois
Commission approved the nine-year regulatory infrastructure program, Investing
in Illinois, subject to annual review. Nicor Gas expects to place into service
$400 million of qualifying projects under Investing in Illinois in 2020.
In conjunction with the base rate case order issued by the Illinois Commission
in January 2018, Nicor Gas is recovering program costs incurred prior to
December 31, 2017 through base rates. Additionally, the Illinois Commission's
approval of Nicor Gas' rate case on October 2, 2019 included $65 million in
annual revenues related to the recovery of program costs from January 1, 2018
through September 30, 2019 under the Investing in Illinois program. See
"Regulatory Matters - Southern Company Gas - Rate Proceedings" herein for
additional information.
Virginia Natural Gas
In 2012, the Virginia Commission approved the SAVE program, an accelerated
infrastructure replacement program. In 2016 and on September 25, 2019, the
Virginia Commission approved amendments and extensions to the SAVE program. The
latest extension allows Virginia Natural Gas to continue replacing aging
pipeline infrastructure through 2024 and increases 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 total potential

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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. Virginia
Natural Gas expects to invest $50 million under this program in 2020.
The SAVE program is subject to annual review by the Virginia Commission. In
accordance with the base rate case order issued by the Virginia Commission in
2017, Virginia Natural Gas is recovering program costs incurred prior to
September 1, 2017 through base rates. Program costs incurred subsequent to
September 1, 2017 are currently recovered through a separate rider and are
subject to future base rate case proceedings.
On December 6, 2019, Virginia Natural Gas filed an application with the Virginia
Commission for a 24.1-mile header improvement project to improve resiliency and
increase the supply of natural gas delivered to energy suppliers, including
Virginia Natural Gas. The cost of the project is expected to total $346 million.
The Virginia Commission is expected to rule on this application in the second
quarter 2020. Construction is expected to begin in June 2021 and the project is
expected to be placed in service in the fourth quarter 2022. The ultimate
outcome of this matter cannot be determined at this time.
Atlanta Gas Light
As discussed under "Regulatory Matters - Southern Company Gas - Utility
Regulation and Rate Design" herein, i-SRP and i-VPR will continue under GRAM and
the recovery of and return on current and future infrastructure program capital
investments will be included in base rates.
Pipeline Construction Projects
Southern Company Gas is involved in two significant pipeline construction
projects within its gas pipeline investments segment. These projects, along with
Southern Company Gas' existing pipelines, are intended to provide diverse
sources of natural gas supplies to customers, resolve current and long-term
supply planning for new capacity, enhance system reliability, and generate
economic development in the areas served.
In 2014, Southern Company Gas entered into a joint venture, whereby it holds a
5% ownership interest in the Atlantic Coast Pipeline, an interstate pipeline
company formed to develop and operate an approximate 605-mile natural gas
pipeline in North Carolina, Virginia, and West Virginia with expected initial
transportation capacity of 1.5 Bcf per day. The proposed pipeline project is
expected to transport natural gas to customers in Virginia. In 2017, the
Atlantic Coast Pipeline received FERC approval.
The Atlantic Coast Pipeline has experienced challenges to its permits since
construction began in 2018. During the third and fourth quarters 2018, a FERC
stop work order, together with delays in obtaining permits necessary for
construction and construction delays due to judicial actions, impacted the cost
and schedule for the project. Project cost estimates are approximately $8.0
billion ($400 million for Southern Company Gas), excluding financing costs. 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. On
January 7, 2020, the U.S. Court of Appeals for the Fourth Circuit vacated
another key permit. 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 February 7, 2020, Southern Company Gas entered into an agreement with
Dominion Atlantic Coast Pipeline, LLC for the sale of its interest in Atlantic
Coast Pipeline. The transaction is expected to be completed in the first half of
2020; however, the ultimate outcome cannot be determined at this time. See Note
15 to the financial statements under "Southern Company Gas - Proposed Sale of
Pivotal LNG and Atlantic Coast Pipeline" for additional information.
Also in 2014, Southern Company Gas entered into a partnership in which it holds
a 20% ownership interest in the PennEast Pipeline, an interstate pipeline
company formed to develop and operate an approximate 118-mile natural gas
pipeline between New Jersey and Pennsylvania. The expected initial
transportation capacity of 1.0 Bcf per day is under long-term contracts, mainly
with public utilities and other market-serving entities, such as electric
generation companies, in New Jersey, Pennsylvania, and New York. Southern
Company Gas believes this pipeline will alleviate takeaway constraints in the
Marcellus region and help mitigate some of the price volatility experienced
during recent winters.
Expected project costs related to the PennEast Pipeline for Southern Company Gas
total approximately $300 million, excluding financing costs. In January 2018,
the PennEast Pipeline received initial FERC approval. Work continues with state
and federal agencies to obtain the required permits to begin construction. On
September 10, 2019, an appellate court ruled that the PennEast Pipeline does not
have federal eminent domain authority over lands in which a state has property
rights interests. On February 18, 2020, PennEast Pipeline filed a petition for a
writ of certiorari to seek U.S. Supreme Court review of the appellate court
decision. On December 30, 2019, PennEast Pipeline filed a two-year extension
request with the FERC to complete the project by January 19, 2022.

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Additionally, on January 30, 2020, PennEast Pipeline filed an amendment with the
FERC to construct the pipeline project in two phases. The first phase would
consist of 68 miles of pipe, constructed entirely within Pennsylvania, which is
expected to be completed by November 2021. The second phase would include the
remaining route in Pennsylvania and New Jersey and is targeted for completion in
2023. FERC approval of the amended plan is required prior to beginning the first
phase.
The ultimate outcome of these matters cannot be determined at this time;
however, any work delays, whether caused by judicial or regulatory action,
abnormal weather, or other conditions, may result in additional cost or schedule
modifications or, ultimately, in project cancellation, any of which could result
in an impairment of one or both of Southern Company Gas' investments and could
have a material impact on Southern Company's and Southern Company Gas' financial
statements. Southern Company Gas evaluated its investments and determined there
was no impairment as of December 31, 2019.
See Notes 3 and 7 to the financial statements under "Guarantees" and "Southern
Company Gas - Equity Method Investments," respectively, for additional
information on these pipeline projects.
Southern Power's Power Sales Agreements
General
Southern Power has PPAs with some of the traditional electric operating
companies, other investor-owned utilities, IPPs, municipalities, and other
load-serving entities, as well as commercial and industrial customers. The PPAs
are expected to provide Southern Power with a stable source of revenue during
their respective terms.
Many of Southern Power's PPAs have provisions that require Southern Power or the
counterparty to post collateral or an acceptable substitute guarantee in the
event that S&P or Moody's downgrades the credit ratings of the respective
company to an unacceptable credit rating or if the counterparty is not rated or
fails to maintain a minimum coverage ratio.
On January 29, 2019, Pacific Gas & Electric Company (PG&E) filed petitions to
reorganize under Chapter 11 of the U.S. Bankruptcy Code. Southern Power,
together with its noncontrolling partners, owns four solar facilities where PG&E
is the energy off-taker for approximately 207 MWs of capacity under long-term
PPAs. PG&E is also the transmission provider for these four facilities and two
of Southern Power's other solar facilities. At December 31, 2019, Southern Power
had outstanding accounts receivables due from PG&E of $2 million related to the
PPAs and $33 million related to the transmission interconnections (of which $27
million is classified in receivables - other and $6 million is classified in
other deferred charges and assets). Subsequent to December 31, 2019, Southern
Power received $15 million in accordance with a November 2019 bankruptcy court
order granting payment of transmission interconnections for amounts due and
owing. Southern Power continues to evaluate the recoverability of its
investments in these solar facilities under various scenarios, including selling
the related energy into the competitive markets, and has concluded that these
solar facilities are not impaired. PG&E has continued to perform under the terms
of the PPAs. Southern Power does not expect a material impact to its financial
statements if, as a result of the bankruptcy proceedings, PG&E does not perform
in accordance with the PPAs or the terms of the PPAs are renegotiated; however,
the ultimate outcome of this matter cannot be determined at this time.
Southern Power is working to maintain and expand its share of the wholesale
markets. During 2019, Southern Power saw an increase in the demand for energy
and capacity that can be served from natural gas generating facilities,
especially in the Southeast, and expects that this increase in demand will
continue in the near term (2020-2022), with timing varying depending on the
market. During 2019, Southern Power successfully remarketed approximately 190 to
650 MWs of annual natural gas generation capacity to load-serving entities
through several PPAs extending over the next nine years. Southern Power
calculates an investment coverage ratio for its generating assets, including
those owned with various partners, 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. With the inclusion of investments associated with the
wind facilities currently under construction, as well as other capacity and
energy contracts, and excluding Plant Mankato, which was sold on January 17,
2020, Southern Power's average investment coverage ratio at December 31, 2019
was 93% through 2024 and 90% through 2029, with an average remaining contract
duration of approximately 14 years. See "Acquisitions and Dispositions -
Southern Power" and "Construction Programs - Southern Power" herein for
additional information.
Natural Gas
Southern Power's electricity sales from natural gas facilities are primarily
through long-term PPAs that consist of two types of agreements. The first type,
referred to as a unit or block sale, is a customer purchase from a dedicated
generating unit where all or a portion of the generation from that unit is
reserved for that customer. Southern Power typically has the ability to serve
the unit or block sale customer from an alternate resource. The second type,
referred to as requirements service, provides that Southern Power serve the
customer's capacity and energy requirements from a combination of the customer's
own generating units and

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from Southern Power resources not dedicated to serve unit or block sales.
Southern Power has rights to purchase power provided by the requirements
customers' resources when economically viable.
As a general matter, substantially all of the PPAs 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 or
purchased power relating to the energy delivered under such PPAs. To the extent
a particular generating facility does not meet the operational requirements
contemplated in the PPAs, Southern Power may be responsible for excess fuel
costs. With respect to fuel transportation risk, most of Southern Power's PPAs
provide that the counterparties are responsible for the availability of fuel
transportation to the particular generating facility.
Capacity charges that form part of the PPA payments are designed to recover
fixed and variable operation and maintenance costs based on dollars-per-kilowatt
year. In general, to reduce Southern Power's exposure to certain operation and
maintenance costs, Southern Power has LTSAs. See Note 1 to the financial
statements under "Long-Term Service Agreements" for additional information.
Solar and Wind
Southern Power's electricity sales from solar and wind (renewable) generating
facilities are also primarily through long-term PPAs; however, these 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 provide
Southern Power a certain fixed price for the electricity 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. Generally, under the renewable
generation PPAs, the purchasing party retains the right to keep or resell the
renewable energy credits.
Income Tax Matters
Consolidated Income Taxes
On behalf of the Registrants, Southern Company files a consolidated federal
income tax return and various state income tax returns, some of which are
combined or unitary. Under a joint consolidated income tax allocation agreement,
each Southern Company subsidiary's current and deferred tax expense is computed
on a stand-alone basis and no subsidiary is allocated more current expense than
would be paid if it filed a separate income tax return. In accordance with IRS
regulations, each company is jointly and severally liable for the federal tax
liability.
The impact of certain tax events at Southern Company and/or its other
subsidiaries can, and does, affect each Registrant's ability to utilize certain
tax credits. See "Tax Credits" and ACCOUNTING POLICIES - "Application of
Critical Accounting Policies and Estimates" herein and Note 10 to the financial
statements for additional information.
Federal Tax Reform Legislation
In 2017, the Tax Reform Legislation was signed into law and became effective on
January 1, 2018. The Tax Reform Legislation, among other things, reduced the
federal corporate income tax rate to 21%, retained normalization provisions for
public utility property and existing renewable energy incentives, and repealed
the corporate alternative minimum tax. In addition, under the Tax Reform
Legislation, NOLs generated after December 31, 2017 can no longer be carried
back to previous tax years but can be carried forward indefinitely, with
utilization limited to 80% of taxable income of the subsequent tax year. The
projected reduction of Southern Company's consolidated income tax liability
resulting from the tax rate reduction also delays the expected utilization of
existing tax credit carryforwards. See "Consolidated Income Taxes" herein and
Note 10 to the financial statements for information on Southern Company's joint
consolidated income tax allocation agreement.

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Bonus Depreciation
Under the Tax Reform Legislation, projects with binding contracts prior to
September 28, 2017 and placed in service after September 27, 2017 remain
eligible for 50% bonus depreciation for 2015 through 2017, 40% bonus
depreciation for 2018, and 30% bonus depreciation for 2019 and certain
long-lived assets placed in service in 2020. Based on provisional estimates,
bonus depreciation is expected to result in positive cash flows for the
Registrants as follows:
                      2019 Tax Year      2020 Tax Year
                                (in millions)
Southern Company     $           989    $           382
Alabama Power                    180                 68
Georgia Power                    314                 56
Mississippi Power                  7                  2
Southern Power(*)                 87                 95
Southern Company Gas             190                 58

(*) Cash flows resulting from bonus depreciation for Southern Power would also be

impacted by Southern Power's use of tax equity partnerships.




See Note 10 to the financial statements under "Current and Deferred Income
Taxes" for additional information. The ultimate outcome of this matter cannot be
determined at this time.
Tax Credits
The Tax Reform Legislation retained solar energy incentives of 30% ITC for
projects that commenced construction by December 31, 2019; 26% ITC for projects
that commence construction in 2020; 22% ITC for projects that commence
construction in 2021; and a permanent 10% ITC for projects that commence
construction on or after January 1, 2022. In addition, the Tax Reform
Legislation retained wind energy incentives of 100% PTC for projects that
commenced construction in 2016; 80% PTC for projects that commenced construction
in 2017; 60% PTC for projects that commenced construction in 2018; and 40% PTC
for projects that commenced construction in 2019. As a result of a tax extenders
bill passed in December 2019, projects that begin construction in 2020 will be
entitled to 60% PTC. Projects commencing construction after 2020 will not be
entitled to any PTCs. Southern Company has received ITCs and PTCs in connection
with investments in solar, wind, and biomass facilities primarily at Southern
Power and Georgia Power.
Southern Power's ITCs relate to its investment in new solar facilities acquired
or constructed and its PTCs relate to the first 10 years of energy production
from its wind facilities, which have had, and may continue to have, a material
impact on Southern Power's cash flows and net income. At December 31, 2019,
Southern Company and Southern Power had approximately $1.8 billion and $1.4
billion, respectively, of unutilized ITCs and PTCs, which are currently expected
to be fully utilized by 2024, but could be further delayed. Since 2018, Southern
Power has been utilizing tax equity partnerships for wind and solar projects,
where the tax partner takes significantly all of the respective federal tax
benefits. These tax equity partnerships are consolidated in Southern Company's
and Southern Power's financial statements using the HLBV methodology to allocate
partnership gains and losses. See Note 1 to the financial statements under
"General" for additional information on the HLBV methodology and Note 1 to the
financial statements under "Income Taxes" and Note 10 to the financial
statements under "Deferred Tax Assets and Liabilities - Tax Credit
Carryforwards" and "Effective Tax Rate" for additional information regarding
utilization and amortization of credits and the tax benefit related to
associated basis differences.
General Litigation Matters
The Registrants are involved in various other matters being litigated and
regulatory matters that could affect future earnings. 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 herein or in Notes 2 and 3 to the
financial statements, management does not anticipate that the ultimate
liabilities, if any, arising from such current proceedings would have a material
effect on such Registrant's financial statements. See Notes 2 and 3 to the
financial statements for a discussion of various other contingencies, regulatory
matters, and other matters being litigated which may affect future earnings
potential.
The Registrants believe the pending legal challenges discussed below have no
merit; however, the ultimate outcome of these matters cannot be determined at
this time.

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Southern Company
In January 2017, a securities class action complaint was filed against Southern
Company, certain of its officers, and certain former Mississippi Power officers
in the U.S. District Court for the Northern District of Georgia by Monroe County
Employees' Retirement System on behalf of all persons who purchased shares of
Southern Company's common stock between April 25, 2012 and October 29, 2013. The
complaint alleges that Southern Company, certain of its officers, and certain
former Mississippi Power officers made materially false and misleading
statements regarding the Kemper County energy facility in violation of certain
provisions under the Securities Exchange Act of 1934, as amended. The complaint
seeks, among other things, compensatory damages and litigation costs and
attorneys' fees. 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 certain claims against
certain officers of Southern Company and Mississippi Power and dismissed 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 motion for reconsideration
and denied a motion to certify the issue for interlocutory appeal. On August 22,
2019, the court certified the plaintiffs' proposed class. On September 5, 2019,
the defendants filed a petition for interlocutory appeal of the class
certification order with the U.S. Court of Appeals for the Eleventh Circuit. On
December 19, 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 expires on March 31, 2020.
In February 2017, Jean Vineyard and Judy Mesirov each filed a shareholder
derivative lawsuit in the U.S. District Court for the Northern District of
Georgia. Each of these lawsuits names as defendants Southern Company, certain of
its directors, certain of its officers, and certain former Mississippi Power
officers. In 2017, these two shareholder derivative lawsuits were consolidated
in the U.S. District Court for the Northern District of Georgia. The complaints
allege that the defendants caused Southern Company to make false or misleading
statements regarding the Kemper County energy facility cost and schedule.
Further, the complaints allege that the defendants were unjustly enriched and
caused the waste of corporate assets and also allege that the individual
defendants violated their fiduciary duties. Each plaintiff seeks to recover, on
behalf of Southern Company, unspecified actual damages and, on each plaintiff's
own behalf, attorneys' fees and costs in bringing the lawsuit. Each plaintiff
also seeks certain changes to Southern Company's corporate governance and
internal processes. In April 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.
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.
Georgia Power
In 2011, plaintiffs filed a putative class action against Georgia Power in the
Superior Court of Fulton County, Georgia alleging that Georgia Power's
collection in rates of amounts for municipal franchise fees (which fees are paid
to municipalities) exceeded the amounts allowed in orders of the Georgia PSC and
alleging certain state tort law claims. In 2016, the Georgia Court of Appeals
reversed the trial court's previous dismissal of the case and remanded the case
to the trial court. Georgia Power filed a petition for writ of certiorari with
the Georgia Supreme Court, which was granted in 2017. In June 2018, the Georgia
Supreme Court affirmed the judgment of the Georgia Court of Appeals and remanded
the case to the trial court for further proceedings. Following a motion by
Georgia Power, on February 13, 2019, the Superior Court of Fulton County ordered
the parties to submit petitions to the Georgia PSC for a declaratory ruling to
address certain terms the court previously held were ambiguous as used in the
Georgia PSC's orders. The order entered by the Superior Court of Fulton County
also conditionally certified the proposed class. In March 2019, Georgia Power
and the plaintiffs filed petitions with the Georgia PSC seeking confirmation of
the proper

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application of the municipal franchise fee schedule pursuant to the Georgia
PSC's orders. On October 23, 2019, the Georgia PSC issued an order that found
and concluded that Georgia Power has appropriately implemented the municipal
franchise fee schedule. On March 6, 2019, Georgia Power filed a notice of appeal
with the Georgia Court of Appeals regarding the Superior Court of Fulton
County's February 2019 order. The amount of any possible losses cannot be
calculated at this time because, among other factors, it is unknown whether
conditional class certification will be upheld and the ultimate composition of
any class and whether any losses would be subject to recovery from any
municipalities.
Mississippi Power
In May 2018, Southern Company and Mississippi Power received a notice of dispute
and arbitration demand filed by Martin Product Sales, LLC (Martin) based on two
agreements, both related to Kemper IGCC byproducts for which Mississippi Power
provided termination notices in 2017. Martin alleges breach of contract, breach
of good faith and fair dealing, fraud and misrepresentation, and civil
conspiracy and makes a claim for damages in the amount of approximately $143
million, as well as additional unspecified damages, attorney's fees, costs, and
interest. A portion of the claim for damages was on behalf of Martin Transport,
Inc. (Martin Transport), an affiliate of Martin. In the first quarter 2019,
Mississippi Power and Southern Company filed motions to dismiss, which were
denied by the arbitration panel on May 10, 2019. On September 27, 2019, Martin
Transport filed a separate complaint against Mississippi Power in the Circuit
Court of Kemper County, Mississippi alleging claims of fraud, negligent
misrepresentation, promissory estoppel, and equitable estoppel, each arising out
of the same alleged facts and circumstances that underlie Martin's arbitration
demand. Martin Transport seeks compensatory damages of $5 million and punitive
damages of $50 million. In November 2019, Martin Transport's claim was combined
with the Martin arbitration case and the separate court case was dismissed. On
December 16, 2019, Southern Company and Mississippi Power each filed motions for
summary judgment on all claims. On February 17, 2020, the arbitration panel
granted Southern Company's motion and dismissed Southern Company from the
arbitration. An adverse outcome in this proceeding could have a material impact
on Southern Company's and Mississippi Power's financial statements.
In November 2018, Ray C. Turnage and 10 other individual plaintiffs filed a
putative class action complaint against Mississippi Power and three members of
the Mississippi PSC in the U.S. District Court for the Southern District of
Mississippi. Mississippi Power received Mississippi PSC approval in 2013 to
charge a mirror CWIP rate premised upon including in its rate base
pre-construction and construction costs for the Kemper IGCC prior to placing the
Kemper IGCC into service. The Mississippi Supreme Court reversed that approval
and ordered Mississippi Power to refund the amounts paid by customers under the
previously-approved mirror CWIP rate. The plaintiffs allege that the initial
approval process, and the amount approved, were improper. They also allege that
Mississippi Power underpaid customers by up to $23.5 million in the refund
process by applying an incorrect interest rate. The plaintiffs seek to recover,
on behalf of themselves and their putative class, actual damages, punitive
damages, pre-judgment interest, post-judgment interest, attorney's fees, and
costs. In response to Mississippi Power and the Mississippi PSC each filing a
motion to dismiss, the plaintiffs filed an amended complaint on March 14, 2019.
The amended complaint included four additional plaintiffs and additional claims
for gross negligence, reckless conduct, and intentional wrongdoing. Mississippi
Power and the Mississippi PSC have each filed a motion to dismiss the amended
complaint. An adverse outcome in this proceeding could have a material impact on
Mississippi Power's financial statements.
See Note 2 to the financial statements under "Kemper County Energy Facility" for
additional information.
Other Matters
Southern Company
A subsidiary of Southern Holdings has several leveraged lease agreements, with
original terms ranging up to 45 years, which relate to international and
domestic energy generation, distribution, and transportation assets. Southern
Company receives federal income tax deductions for depreciation and
amortization, as well as interest on long-term debt related to these
investments. Southern Company reviews all important lease assumptions at least
annually, or more frequently if events or changes in circumstances indicate that
a change in assumptions has occurred or may occur. These assumptions include the
effective tax rate, the residual value, the credit quality of the lessees, and
the timing of expected tax cash flows. See Note 1 to the financial statements
under "Leveraged Leases" for additional information.
The ability of the lessees to make required payments to the Southern Holdings
subsidiary is dependent on the operational performance of the assets. In 2017,
the financial and operational performance of one of the lessees and the
associated generation assets raised significant concerns about the short-term
ability of the generation assets to produce cash flows sufficient to support
ongoing operations and the lessee's contractual obligations and its ability to
make the remaining semi-annual lease payments through the end of the lease term
in 2047. In addition, following the expiration of the existing power offtake
agreement in 2032, the lessee also is exposed to remarketing risk, which
encompasses the price and availability of alternative sources of generation.

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While all lease payments through December 31, 2019 have been paid in full due to
recent operational improvements, operational and remarketing risks and the
resulting cash liquidity challenges persist, and significant concerns continue
regarding the lessee's ability to make the remaining semi-annual lease payments.
These challenges may also impact the expected residual value of the generation
assets. Southern Company has evaluated the recoverability of the lease
receivable and the expected residual value of the generation assets under
various scenarios. Based on current forecasts of energy prices in the years
following the expiration of the existing PPA, Southern Company concluded that it
is no longer probable that all of the associated rental payments will be
received over the term of the lease. As a result, during the fourth quarter
2019, Southern Company revised the estimate of cash flows to be received under
the leveraged lease, which resulted in an impairment charge of $17 million ($13
million after tax). If any future lease payment is not paid in full, the
Southern Holdings subsidiary may be unable to make its corresponding payment to
the holders of the underlying non-recourse debt related to the generation
assets. Failure to make the required payment to the debtholders could represent
an event of default that would give the debtholders the right to foreclose on,
and take ownership of, the generation assets from the Southern Holdings
subsidiary, in effect terminating the lease and resulting in the write-off of
the related lease receivable, which totaled approximately $76 million at
December 31, 2019. Southern Company will continue to monitor the operational
performance of the underlying assets and evaluate the ability of the lessee to
continue to make the required lease payments. The ultimate outcome of this
matter cannot be determined at this time.
Mississippi Power
In conjunction with Southern Company's sale of Gulf Power, NextEra Energy held
back $75 million of the purchase price pending Mississippi Power and Gulf Power
negotiating a mutually acceptable revised operating agreement for Plant Daniel.
In addition, Mississippi Power and Gulf Power committed to seek a restructuring
of their 50% undivided ownership interests in Plant Daniel such that each of
them would, after the restructuring, own 100% of a generating unit. On January
15, 2019, Gulf Power provided notice to Mississippi Power that Gulf Power will
retire its share of the generating capacity of Plant Daniel on January 15, 2024.
Mississippi Power has the option to purchase Gulf Power's ownership interest for
$1 on January 15, 2024, provided that Mississippi Power exercises the option no
later than 120 days prior to that date. Mississippi Power is assessing the
potential operational and economic effects of Gulf Power's notice. The ultimate
outcome of these matters remains subject to completion of Mississippi Power's
evaluations and applicable regulatory approvals, including by the FERC and the
Mississippi PSC, and cannot be determined at this time. See Note 15 to the
financial statements under "Southern Company" for information regarding the sale
of Gulf Power.
Southern Company Gas
A wholly-owned subsidiary of Southern Company Gas owns and operates a natural
gas storage facility consisting of two salt dome caverns in Louisiana. Periodic
integrity tests are required in accordance with rules of the Louisiana
Department of Natural Resources (DNR). In 2017, in connection with an ongoing
integrity project, updated seismic mapping indicated the proximity of one of the
caverns to the edge of the salt dome may be less than the required minimum and
could result in Southern Company Gas retiring the cavern early.
In the third quarter 2019, management determined that it no longer planned to
obtain the core samples during 2020 that are necessary to determine the
composition of the sheath surrounding the edge of the salt dome. Core sampling
is a requirement of the Louisiana DNR to put the cavern back in service; as a
result, the cavern will not return to service by 2021. This change in plan,
which affects the future operation of the entire storage facility, resulted in a
pre-tax impairment charge of $91 million ($69 million after-tax) recorded by
Southern Company Gas in 2019. Southern Company Gas continues to monitor the
pressure and overall structural integrity of the entire facility pending any
future decisions regarding decommissioning.
Southern Company Gas has two other natural gas storage facilities located in
California and Texas, which could be impacted by ongoing changes in the U.S.
natural gas storage market. Recent sales of natural gas storage facilities have
resulted in losses for the sellers and may imply an impact on future rates
and/or asset values. Sustained diminished natural gas storage values could
trigger impairment of either or both of these natural gas storage facilities,
which have a combined net book value of $326 million at December 31, 2019.
The ultimate outcome of these matters cannot be determined at this time, but
could have a material impact on the financial statements of Southern Company and
Southern Company Gas.
ACCOUNTING POLICIES
Application of Critical Accounting Policies and Estimates
The Registrants prepare their financial statements in accordance with GAAP.
Significant accounting policies are described in the notes to the financial
statements. In the application of these policies, certain estimates are made
that may have a material impact

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on the results of operations and related disclosures of the applicable
Registrants (as indicated in the section descriptions herein). Different
assumptions and measurements could produce estimates that are significantly
different from those recorded in the financial statements. Senior management has
reviewed and discussed the following critical accounting policies and estimates
with the Audit Committee of Southern Company's Board of Directors.
Utility Regulation (Southern Company, Alabama Power, Georgia Power, Mississippi
Power, and Southern Company Gas)
The traditional electric operating companies and the natural gas distribution
utilities are subject to retail regulation by their respective state PSCs or
other applicable state regulatory agencies and wholesale regulation by the FERC.
These regulatory agencies set the rates the traditional electric operating
companies and the natural gas distribution utilities are permitted to charge
customers based on allowable costs, including a reasonable ROE. As a result, the
traditional electric operating companies and the natural gas distribution
utilities apply accounting standards which require the financial statements to
reflect the effects of rate regulation. Through the ratemaking process, the
regulators may require the inclusion of costs or revenues in periods different
than when they would be recognized by a non-regulated company. This treatment
may result in the deferral of expenses and the recording of related regulatory
assets based on anticipated future recovery through rates or the deferral of
gains or creation of liabilities and the recording of related regulatory
liabilities. The application of the accounting standards for rate regulated
entities also impacts their financial statements as a result of the estimates of
allowable costs used in the ratemaking process. These estimates may differ from
those actually incurred by the traditional electric operating companies and the
natural gas distribution utilities; therefore, the accounting estimates inherent
in specific costs such as depreciation, AROs, and pension and other
postretirement benefits have less of a direct impact on the results of
operations and financial condition of the applicable Registrants than they would
on a non-regulated company.
Revenues related to regulated utility operations as a percentage of total
operating revenues in 2019 for the applicable Registrants were as follows: 87%
for Southern Company, 99% for Alabama Power, 97% for Georgia Power, 100% for
Mississippi Power, and 80% for Southern Company Gas.
As reflected in Note 2 to the financial statements, significant regulatory
assets and liabilities have been recorded. Management reviews the ultimate
recoverability of these regulatory assets and any requirement to refund these
regulatory liabilities based on applicable regulatory guidelines and GAAP.
However, adverse legislative, judicial, or regulatory actions could materially
impact the amounts of such regulatory assets and liabilities and could adversely
impact the financial statements of the applicable Registrants.
Estimated Cost, Schedule, and Rate Recovery for the Construction of Plant Vogtle
Units 3 and 4
(Southern Company and Georgia Power)
In 2016, the Georgia PSC approved the Vogtle Cost Settlement Agreement, which
resolved certain prudency matters in connection with Georgia Power's fifteenth
VCM report. In 2017, the Georgia PSC approved Georgia Power's seventeenth VCM
report, which included a recommendation to continue construction of Plant Vogtle
Units 3 and 4, with Southern Nuclear serving as project manager and Bechtel
serving as the primary construction contractor, as well as a modification of the
Vogtle Cost Settlement Agreement. The Georgia PSC's related order stated that
under the modified Vogtle Cost Settlement Agreement, (i) none of the $3.3
billion of costs incurred through December 31, 2015 should be disallowed as
imprudent; (ii) capital costs incurred up to $5.68 billion would be presumed to
be reasonable and prudent with the burden of proof on any party challenging such
costs; (iii) Georgia Power would have the burden of proof to show that any
capital costs above $5.68 billion were prudent; (iv) Georgia Power's total
project capital cost forecast of $7.3 billion (net of $1.7 billion received
under the Guarantee Settlement Agreement and approximately $188 million in
related customer refunds) was found reasonable and did not represent a cost cap;
and (v) prudence decisions would be made subsequent to achieving fuel load for
Unit 4.
In its 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.
In the second quarter 2018, Georgia Power revised its base cost forecast and
estimated contingency to complete construction and start-up of Plant Vogtle
Units 3 and 4 to $8.0 billion and $0.4 billion, respectively, for a total
project capital cost forecast of $8.4 billion (net of $1.7 billion received
under the Guarantee Settlement Agreement and approximately $188 million in
related customer refunds). Although Georgia Power believes these incremental
costs are reasonable and necessary to complete the project and the Georgia PSC's
order in the seventeenth VCM proceeding specifically states that the
construction of Plant Vogtle Units 3 and 4 is not subject to a cost cap, Georgia
Power did not seek rate recovery for the $0.7 billion increase in costs included
in the base capital cost forecast in the nineteenth VCM report. After
considering the significant level of uncertainty that exists regarding the
future recoverability of costs included in the construction contingency estimate
since the ultimate outcome of these matters is subject to the outcome of future
assessments by management, as well as Georgia PSC decisions in these future
regulatory

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proceedings, Georgia Power recorded a total pre-tax charge to income of $1.1
billion ($0.8 billion after tax) in the second quarter 2018.
Georgia Power's revised cost estimate reflects an expected in-service date of
November 2021 for Unit 3 and November 2022 for Unit 4.
As of December 31, 2019, approximately $140 million of the $366 million
construction contingency estimate established in the second quarter 2018 was
allocated to the base capital cost forecast for cost risks including, among
other factors, construction productivity; craft labor incentives; adding
resources for supervision, field support, project management, initial test
program, start-up, and operations and engineering support; subcontracts; and
procurement. As and when construction contingency is spent, Georgia Power may
request the Georgia PSC to evaluate those expenditures for rate recovery.
As part of its ongoing processes, Southern Nuclear continues to evaluate cost
and schedule forecasts on a regular basis to incorporate current information
available, particularly in the areas of commodity installation, system
turnovers, and workforce statistics.
In April 2019, Southern Nuclear 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. The project has
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. However, Southern
Nuclear and Georgia Power believe that existing productivity levels and pace of
activity completion are sufficient to meet the regulatory-approved in-service
dates.
In February 2020, Southern Nuclear updated its cost and schedule forecast, which
did not change the projected overall capital cost forecast and confirmed the
expected in-service dates of November 2021 for Unit 3 and November 2022 for Unit
4. This update included initiatives to improve productivity while refining and
extending system turnover plans and certain near-term milestone dates. Other
milestone dates did not change. Achievement of the aggressive site work plan
relies on meeting increased monthly production and activity target values during
2020. To meet these 2020 targets, existing craft, including subcontractors,
construction productivity must improve and be sustained above historical average
levels, appropriate levels of craft laborers, particularly electrical and
pipefitter craft labor, must be maintained, and additional supervision and other
field support resources must be retained. Southern Nuclear and Georgia Power
continue to believe that pursuit of an aggressive site work plan is an
appropriate strategy to achieve completion of the units by their
regulatory-approved in-service dates.
As construction, including subcontract work, continues and testing and system
turnover activities increase, challenges with management of contractors and
vendors; subcontractor performance; 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,
installation, system turnover, and the initial testing and start-up, including
any required engineering changes or any remediation related thereto, of plant
systems, structures, or components (some of which are based on new technology
that only within the last few years 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.
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. As part of the aggressive site work plan, in January 2020,
Southern Nuclear notified the NRC of its intent to load fuel in 2020. 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 $12 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

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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.
Given the significant complexity involved in estimating the future costs to
complete construction and start-up of Plant Vogtle Units 3 and 4 and the
significant management judgment necessary to assess the related uncertainties
surrounding future rate recovery of any projected cost increases, as well as the
potential impact on results of operations and cash flows, Southern Company and
Georgia Power consider these items to be critical accounting estimates. See Note
2 to the financial statements under "Georgia Power - Nuclear Construction" for
additional information.
Accounting for Income Taxes (Southern Company, Mississippi Power, Southern
Power, and Southern Company Gas)
The consolidated income tax provision and deferred income tax assets and
liabilities, as well as any unrecognized tax benefits and valuation allowances,
require significant judgment and estimates. These estimates are supported by
historical tax return data, reasonable projections of taxable income, and
interpretations of applicable tax laws and regulations across multiple taxing
jurisdictions. The effective tax rate reflects the statutory tax rates and
calculated apportionments for the various states in which the Southern Company
system operates.
On behalf of its subsidiaries, Southern Company files a consolidated federal
income tax return and various state income tax returns, some of which are
combined or unitary. Under a joint consolidated income tax allocation agreement,
each Southern Company subsidiary's current and deferred tax expense is computed
on a stand-alone basis and no subsidiary is allocated more current expense than
would be paid if it filed a separate income tax return. Certain deductions and
credits can be limited or utilized at the consolidated or combined level
resulting in NOL and tax credit carryforwards that would not otherwise result on
a stand-alone basis. Utilization of NOL and tax credit carryforwards and the
assessment of valuation allowances are based on significant judgment and
extensive analysis of Southern Company's and its subsidiaries' current financial
position and results of operations, including currently available information
about future years, to estimate when future taxable income will be realized.
Current and deferred state income tax liabilities and assets are estimated based
on laws of multiple states that determine the income to be apportioned to their
jurisdictions. States utilize various formulas to calculate the apportionment of
taxable income, primarily using sales, assets, or payroll within the
jurisdiction compared to the consolidated totals. In addition, each state varies
as to whether a stand-alone, combined, or unitary filing methodology is
required. The calculation of deferred state taxes considers apportionment
factors and filing methodologies that are expected to apply in future years. The
apportionments and methodologies which are ultimately finalized in a manner
inconsistent with expectations could have a material effect on the financial
statements of the applicable Registrants.
Given the significant judgment involved in estimating NOL and tax credit
carryforwards and multi-state apportionments for all subsidiaries, the
applicable Registrants consider deferred income tax liabilities and assets to be
critical accounting estimates.
Asset Retirement Obligations (Southern Company, Alabama Power, Georgia Power,
Mississippi Power, and Southern Company Gas)
AROs are computed as the present value of the estimated costs for an asset's
future retirement and are recorded in the period in which the liability is
incurred. The estimated costs are capitalized as part of the related long-lived
asset and depreciated over the asset's useful life. In the absence of quoted
market prices, AROs are estimated using present value techniques in which
estimates of future cash outlays associated with the asset retirements are
discounted using a credit-adjusted risk-free rate. Estimates of the timing and
amounts of future cash outlays are based on projections of when and how the
assets will be retired and the cost of future removal activities.
The ARO liabilities for the traditional electric operating companies primarily
relate to facilities that are subject to the CCR Rule and the related state
rules, principally ash ponds. In addition, Alabama Power and Georgia Power have
retirement obligations related to the decommissioning of nuclear facilities
(Alabama Power's Plant Farley and Georgia Power's ownership interests in Plant
Hatch and Plant Vogtle Units 1 and 2). The traditional electric operating
companies also have AROs related to various landfill sites, asbestos removal,
and underground storage tanks, as well as, for Alabama Power, disposal of
polychlorinated biphenyls in certain transformers and sulfur hexafluoride gas in
certain substation breakers, for Georgia Power, gypsum cells and restoration of
land at the end of long-term land leases for solar facilities, and for
Mississippi Power, mine reclamation and water wells.
The traditional electric operating companies and Southern Company Gas also have
identified other retirement obligations, such as obligations related to certain
electric transmission and distribution facilities, certain asbestos-containing
material within long-term assets not subject to ongoing repair and maintenance
activities, certain wireless communication towers, the disposal of
polychlorinated biphenyls in certain transformers, leasehold improvements,
equipment on customer property, and property associated with the Southern
Company system's rail lines and natural gas pipelines. However, liabilities for
the removal of these

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assets have not been recorded because the settlement timing for certain
retirement obligations related to these assets is indeterminable and, therefore,
the fair value of the retirement obligations cannot be reasonably estimated. A
liability for these retirement obligations will be recognized when sufficient
information becomes available to support a reasonable estimation of the ARO.
The cost estimates for AROs related to the disposal of CCR are based on
information using various assumptions related to closure and post-closure costs,
timing of future cash outlays, inflation and discount rates, and the potential
methods for complying with the CCR Rule and the related state rules. The
traditional electric operating companies expect to update their ARO cost
estimates periodically as additional information related to these assumptions
becomes available. See Note 6 to the financial statements for additional
information, including increases to AROs related to ash ponds recorded during
2019 by certain Registrants.
Given the significant judgment involved in estimating AROs, the applicable
Registrants consider the liabilities for AROs to be critical accounting
estimates.
Pension and Other Postretirement Benefits (Southern Company, Alabama Power,
Georgia Power, Mississippi Power, and Southern Company Gas)
The applicable Registrants' calculations of pension and other postretirement
benefits expense are dependent on a number of assumptions. These assumptions
include discount rates, healthcare cost trend rates, expected long-term rate of
return (LRR) on plan assets, mortality rates, expected salary and wage
increases, and other factors. Components of pension and other postretirement
benefits expense include interest and service cost on the pension and other
postretirement benefit plans, expected return on plan assets, and amortization
of certain unrecognized costs and obligations. Actual results that differ from
the assumptions utilized are accumulated and amortized over future periods and,
therefore, generally affect recognized expense and the recorded obligation in
future periods. While the applicable Registrants believe the assumptions used
are appropriate, differences in actual experience or significant changes in
assumptions would affect their pension and other postretirement benefit costs
and obligations.
Key elements in determining the applicable Registrants' pension and other
postretirement benefit expense are the LRR and the discount rate used to measure
the benefit plan obligations and the periodic benefit plan expense for future
periods. For purposes of determining the applicable Registrants' liabilities
related to the pension and other postretirement benefit plans, Southern Company
discounts the future related cash flows using a single-point discount rate for
each plan developed from the weighted average of market-observed yields for high
quality fixed income securities with maturities that correspond to expected
benefit payments. The discount rate assumption impacts both the service cost and
non-service costs components of net periodic benefit costs as well as the
projected benefit obligations.
The LRR on pension and other postretirement benefit plan assets is based on
Southern Company's investment strategy, historical experience, and expectations
that consider external actuarial advice, and represents the average rate of
earnings expected over the long term on the assets invested to provide for
anticipated future benefit payments. Southern Company determines the amount of
the expected return on plan assets component of non-service costs by applying
the LRR of various asset classes to Southern Company's target asset allocation.
The LRR only impacts the non-service costs component of net periodic benefit
costs for the following year and is set annually at the beginning of the year.
For 2019, the LRR assumption for qualified pension plan assets was reduced from
7.95% to 7.75% for purposes of determining net periodic pension expense as a
result of changes in the economic outlook used in estimating the expected
returns as of December 31, 2018. As a result of the decrease in the LRR, the
non-service costs component of net periodic pension expense increased by $24
million for the Southern Company system in 2019. See the table below for the
impact on each Registrant.

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For 2020, net periodic pension expense will be impacted by two factors: a change
in the approach used to determine the LRR assumption and cash contributions
totaling $1.1 billion to the qualified pension plan made in December 2019.
Historically, Southern Company has set the LRR assumption using asset return
modeling based on geometric returns that reflect the compound average returns
for dependent annual periods. Beginning in 2020, Southern Company will set the
LRR assumption using an arithmetic mean which represents the expected simple
average return to be earned by the pension plan assets over any one year.
Southern Company believes the use of the arithmetic mean is more compatible with
the LRR's function of estimating a single year's investment return. Excluding
the additional pension contribution in December 2019, the change in the LRR
assumption will reduce the non-service costs component of net periodic pension
expense by $78 million for the Southern Company system in 2020. See the table
below for the impact on each Registrant. The contributions in 2019 will further
reduce expense by $88 million for the Southern Company system in 2020.
                                                         Alabama          Georgia
                              Southern Company            Power            Power         Mississippi Power      Southern Company Gas
                                                                         (in millions)
Increase (decrease) in pension expense:
                    2019 $                24        $             5   $           8   $              1        $               2
                    2020                 (78 )                  (18 )           (25 )               (4 )                     (7 )


The following table illustrates the sensitivity to changes in the applicable
Registrants' long-term assumptions with respect to the discount rate, salary
increases, and the long-term rate of return on plan assets:
                                                 Increase/(Decrease) in
                                                                          Projected
                                                                        Obligation for
                                                       Projected            Other
                                                     Obligation for     Postretirement
                                                    Pension Plan at    Benefit Plans at
                                  Total Benefit       December 31,       December 31,
25 Basis Point Change in:        Expense for 2020         2019               2019
                                                     (in millions)
Discount rate:
Southern Company                    $41/$(39)         $549/$(518)         $57/$(54)
Alabama Power                       $10/$(10)         $131/$(123)         $14/$(13)
Georgia Power                       $12/$(11)         $166/$(156)         $21/$(20)
Mississippi Power                    $2/$(2)           $25/$(23)           $2/$(2)
Southern Company Gas                 $1/$(1)           $38/$(36)           $6/$(6)
Salaries:
Southern Company                    $23/$(22)         $118/$(113)           $-/$-
Alabama Power                        $6/$(6)           $33/$(32)            $-/$-
Georgia Power                        $6/$(6)           $34/$(33)            $-/$-
Mississippi Power                    $1/$(1)            $5/$(5)             $-/$-
Southern Company Gas                 $1/$(1)            $3/$(3)             $-/$-
Long-term return on plan assets:
Southern Company                    $35/$(35)             N/A                N/A
Alabama Power                        $9/$(9)              N/A                N/A
Georgia Power                       $11/$(11)             N/A                N/A
Mississippi Power                    $2/$(2)              N/A                N/A
Southern Company Gas                 $3/$(3)              N/A                N/A

See Note 11 to the financial statements for additional information regarding pension and other postretirement benefits.


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Asset Impairment (Southern Company, Southern Power, and Southern Company Gas)
Goodwill (Southern Company and Southern Company Gas)
The acquisition method of accounting requires the assets acquired and
liabilities assumed to be recorded at the date of acquisition at their
respective estimated fair values. The applicable Registrants have recognized
goodwill as of the date of their acquisitions, as a residual over the fair
values of the identifiable net assets acquired. Goodwill is tested for
impairment at the reporting unit level on an annual basis in the fourth quarter
of the year as well as on an interim basis as events and changes in
circumstances occur, including, but not limited to, a significant change in
operating performance, the business climate, legal or regulatory factors, or a
planned sale or disposition of a significant portion of the business. A
reporting unit is the operating segment, or a business one level below the
operating segment (a component), if discrete financial information is prepared
and regularly reviewed by management. Components are aggregated if they have
similar economic characteristics.
As part of the impairment tests, the applicable Registrant may perform an
initial qualitative assessment to determine whether it is more likely than not
that the fair value of each reporting unit is less than its carrying amount
before applying the quantitative goodwill impairment test. If the applicable
Registrant elects to perform the qualitative assessment, it evaluates relevant
events and circumstances, including but not limited to, macroeconomic
conditions, industry and market conditions, cost factors, financial performance,
entity specific events, and events specific to each reporting unit. If the
applicable Registrant determines that it is more likely than not that the fair
value of a reporting unit is less than its carrying amount, or it elects not to
perform a qualitative assessment, it compares the fair value of the reporting
unit to its carrying value to determine if the fair value is greater than its
carrying value.
Goodwill for Southern Company and Southern Company Gas was $5.3 billion and $5.0
billion, respectively, at December 31, 2019. For its 2019 and 2018 annual
impairment tests, Southern Company Gas performed the qualitative assessment and
determined that it was more likely than not that the fair value of all of its
reporting units with goodwill exceeded their carrying amounts, and therefore no
quantitative analysis was required. For its 2017 annual impairment test,
Southern Company Gas performed the quantitative assessment, which resulted in
the fair value of all of its reporting units that have goodwill exceeding their
carrying value. For its annual impairment tests for PowerSecure, Southern
Company performed the quantitative assessment, which resulted in the fair value
of goodwill at PowerSecure exceeding its carrying value in all years presented.
However, Southern Company recorded goodwill impairment charges totaling $34
million in 2019 as a result of its decision to sell certain PowerSecure business
units. See Note 15 to the financial statements under "Southern Company" for
additional information.
The judgments made in determining the estimated fair value assigned to each
class of assets acquired and liabilities assumed, as well as asset lives, can
significantly impact the applicable Registrant's results of operations. Fair
values and useful lives are determined based on, among other factors, the
expected future period of benefit of the asset, the various characteristics of
the asset, and projected cash flows. As the determination of an asset's fair
value and useful life involves management making certain estimates and because
these estimates form the basis for the determination of whether or not an
impairment charge should be recorded, the applicable Registrants consider these
estimates to be critical accounting estimates.
See Note 1 to the financial statements under "Goodwill and Other Intangible
Assets and Liabilities" for additional information regarding the applicable
Registrants' goodwill.
Long-Lived Assets (Southern Company, Southern Power, and Southern Company Gas)
Impairments of long-lived assets of the traditional electric utilities and
natural gas distribution utilities are generally related to specific regulatory
disallowances. The applicable Registrants assess their other long-lived assets
for impairment whenever events or changes in circumstances indicate that an
asset's carrying amount may not be recoverable. If an indicator exists, the
asset is tested for recoverability by comparing the asset carrying value to the
sum of the undiscounted expected future cash flows directly attributable to the
asset's use and eventual disposition. If the estimate of undiscounted future
cash flows is less than the carrying value of the asset, the fair value of the
asset is determined and a loss is recorded equal to the difference between the
carrying value and the fair value of the asset. In addition, when assets are
identified as held for sale, an impairment loss is recognized to the extent the
carrying value of the assets or asset group exceeds their fair value less cost
to sell. A high degree of judgment is required in developing estimates related
to these evaluations, which are based on projections of various factors, some of
which have been quite volatile in recent years.
Southern Power's investments in long-lived assets are primarily generation
assets, whether in service or under construction. Excluding the natural gas
distribution utilities, Southern Company Gas' investments in long-lived assets
are primarily natural gas transportation and storage facility assets, whether in
service or under construction. In addition, exclusive of the traditional
electric operating companies and natural gas distribution utilities, Southern
Company's investments in long-lived assets also include investments in leveraged
leases.

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For Southern Power, examples of impairment indicators could include significant
changes in construction schedules, current period losses combined with a history
of losses or a projection of continuing losses, a significant decrease in market
prices, the inability to remarket generating capacity for an extended period,
the unplanned termination of a customer contract or the inability of a customer
to perform under the terms of the contract, or the inability to deploy wind
turbine equipment to a development project. For Southern Company Gas, examples
of impairment indicators could include, but are not limited to, significant
changes in the U.S. natural gas storage market, construction schedules, current
period losses combined with a history of losses or a projection of continuing
losses, a significant decrease in market prices, the inability to renew or
extend customer contracts or the inability of a customer to perform under the
terms of the contract, attrition rates, or the inability to deploy a development
project. For Southern Company's investments in leveraged leases, impairment
indicators include changes in estimates of future rental payments to be received
under the lease as well as the residual value of the leased asset at the end of
the lease.
As the determination of the expected future cash flows generated from an asset,
an asset's fair value, and useful life involves management making certain
estimates and because these estimates form the basis for the determination of
whether or not an impairment charge should be recorded, the applicable
Registrants consider these estimates to be critical accounting estimates.
See Note 3 to the financial statements under "Other Matters" and Note 15 to the
financial statements for information on certain assets recently evaluated for
impairment.
Derivatives and Hedging Activities (Southern Company and Southern Company Gas)
Determining whether a contract meets the definition of a derivative instrument,
contains an embedded derivative requiring bifurcation, or qualifies for hedge
accounting treatment is complex. The treatment of a single contract may vary
from period to period depending upon accounting elections, changes in the
applicable Registrant's assessment of the likelihood of future hedged
transactions, or new interpretations of accounting guidance. As a result,
judgment is required in determining the appropriate accounting treatment. In
addition, the estimated fair value of derivative instruments may change
significantly from period to period depending upon market conditions, and
changes in hedge effectiveness may impact the accounting treatment.
Derivative instruments (including certain derivative instruments embedded in
other contracts) are recorded on the balance sheets as either assets or
liabilities measured at their fair value. If the transaction qualifies for, and
is designated as, a normal purchase or normal sale, it is exempt from fair value
accounting treatment and is, instead, subject to traditional accrual accounting.
The applicable Registrant utilizes market data or assumptions that market
participants would use in pricing the derivative asset or liability, including
assumptions about risk and the risks inherent in the inputs of the valuation
technique.
Changes in the derivatives' fair value are recognized concurrently in earnings
unless specific hedge accounting criteria are met. If the derivatives meet those
criteria, derivative gains and losses offset related results of the hedged item
in the income statement in the case of a fair value hedge, or gains and losses
are deferred in OCI on the balance sheets until the hedged transaction affects
earnings in the case of a cash flow hedge. Additionally, a company is required
to formally designate a derivative as a hedge as well as document and assess the
effectiveness of derivatives associated with transactions that receive hedge
accounting treatment.
Southern Company Gas uses derivative instruments primarily to reduce the impact
to its results of operations due to the risk of changes in the price of natural
gas and, to a lesser extent, Southern Company Gas hedges against
warmer-than-normal weather and interest rates. The fair value of natural gas
derivative instruments used to manage exposure to changing natural gas prices
reflects the estimated amounts that Southern Company Gas would receive or pay to
terminate or close the contracts at the reporting date, taking into account the
current unrealized gains or losses on open contracts. For derivatives utilized
at gas marketing services and wholesale gas services that are not designated as
accounting hedges, changes in fair value are reported as gains or losses in
results of operations in the period of change. Gas marketing services records
derivative gains or losses arising from cash flow hedges in OCI and reclassifies
them into earnings in the same period that the underlying hedged item is
recognized in earnings.
Derivative assets and liabilities are classified based on the lowest level of
input that is significant to the fair value measurement. The assessment of the
significance of a particular input to the fair value measurement requires
judgment and may affect the valuation of fair value assets and liabilities and
their placement within the fair value hierarchy. The determination of the fair
value of the derivative instruments incorporates various required factors. These
factors include:
•      the creditworthiness of the counterparties involved and the impact of
       credit enhancements (such as cash deposits and letters of credit);

• events specific to a given counterparty; and

• the impact of nonperformance risk on liabilities.

A significant change in the underlying market prices or pricing assumptions used in pricing derivative assets or liabilities may result in a significant financial statement impact.


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Given the assumptions used in pricing the derivative asset or liability,
Southern Company and Southern Company Gas consider the valuation of derivative
assets and liabilities a critical accounting estimate. See FINANCIAL CONDITION
AND LIQUIDITY - "Market Price Risk" herein and Note 14 to the financial
statements for more information.
Revenue Recognition (Southern Power)
Southern Power's power sale transactions, which include PPAs, are classified in
one of four general categories: leases, non-derivatives or normal sale
derivatives, derivatives designated as cash flow hedges, and derivatives not
designated as hedges, as described further below. For more information on
derivative transactions, see FINANCIAL CONDITION AND LIQUIDITY - "Market Price
Risk" herein and Notes 1 and 14 to the financial statements. Southern Power's
revenues are dependent upon significant judgments used to determine the
appropriate transaction classification, which must be documented upon the
inception of each contract.
Lease Transactions
Southern Power considers the following factors to determine whether the sales
contract is a lease:
•   Assessing whether specific property is explicitly or implicitly identified in

the agreement;

• Determining whether the fulfillment of the arrangement is dependent on the

use of the identified property; and

• Assessing whether the arrangement conveys to the counterparty substantially

all of the economic benefits and the right to direct the use of the asset.




If the contract meets the above criteria for a lease, Southern Power performs
further analysis as to whether the lease is classified as operating, financing,
or sales-type. All of Southern Power's power sales contracts that are determined
to be leases are accounted for as operating leases and the capacity revenue is
recognized on a straight-line basis over the term of the contract and is
included in Southern Power's operating revenues. Energy revenues and other
contingent revenues are recognized in the period the energy is delivered or the
service is rendered. See Note 9 to the financial statements for additional
information.
Non-Derivative and Normal Sale Derivative Transactions
If the power sales contract is not classified as a lease, Southern Power further
considers the following factors to determine proper classification:
• Assessing whether the contract meets the definition of a derivative;

• Assessing whether the contract meets the definition of a capacity contract;

• Assessing the probability at inception and throughout the term of the

individual contract that the contract will result in physical delivery; and

• Ensuring that the contract quantities do not exceed available generating

capacity (including purchased capacity).




Contracts that do not meet the definition of a derivative or are designated as
normal sales (i.e. capacity contracts which provide for the sale of electricity
that involve physical delivery in quantities within Southern Power's available
generating capacity) are accounted for as executory contracts. For contracts
that have a capacity charge, the revenue is generally recognized in the period
that it becomes billable. Revenues related to energy and ancillary services are
recognized in the period the energy is delivered or the service is rendered. See
Note 4 to the financial statements for additional information.
Cash Flow Hedge Transactions
Southern Power further considers the following in designating other derivative
contracts for the sale of electricity as cash flow hedges of anticipated sale
transactions:
•   Identifying the hedging instrument, the forecasted hedged transaction, and

the nature of the risk being hedged; and

• Assessing hedge effectiveness at inception and throughout the contract term.




These contracts are accounted for on a fair value basis and are recorded in AOCI
over the life of the contract. Realized gains and losses are then recognized in
operating revenues as incurred.
Derivative (Non-Hedge) Transactions
Contracts for sales of electricity, which meet the definition of a derivative
and that either do not qualify or are not designated as normal sales or as cash
flow hedges, are accounted for on a fair value basis and are recorded in
operating revenues.

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Acquisition Accounting (Southern Power)
Southern Power may acquire generation assets as part of its overall growth
strategy. At the time of an acquisition, Southern Power will assess if these
assets and activities meet the definition of a business. For acquisitions that
meet the definition of a business, the purchase price, including any contingent
consideration, is allocated based on the fair value of the identifiable assets
acquired and liabilities assumed (including any intangible assets, primarily
related to acquired PPAs). Assets acquired that do not meet the definition of a
business are accounted for as an asset acquisition. The purchase price of each
asset acquisition is allocated based on the relative fair value of assets
acquired.
Determining the fair value of assets acquired and liabilities assumed requires
management judgment and Southern Power may engage independent valuation experts
to assist in this process. Fair values are determined by using market
participant assumptions, and typically include the timing and amounts of future
cash flows, incurred construction costs, the nature of acquired contracts,
discount rates, power market prices, and expected asset lives. Any due diligence
or transition costs incurred by Southern Power for potential or successful
acquisitions are expensed as incurred.
Contingent consideration primarily relates to fixed amounts due to the seller
once the facility is placed in service. For contingent consideration with
variable payments, Southern Power fair values the arrangement with any changes
recorded in the consolidated statements of income. See Note 13 to the financial
statements for additional fair value information and Note 15 to the financial
statements for additional information on recent acquisitions.
Variable Interest Entities (Southern Power)
Southern Power enters into partnerships with varying ownership structures. Upon
entering into such arrangements, membership interests and other variable
interests are evaluated to determine if the legal entity is a VIE. If the legal
entity is a VIE, Southern Power will assess if it has both the power to direct
the activities of the VIE that most significantly impact the VIE's economic
performance and the obligation to absorb losses or the right to receive benefits
from the VIE that could potentially be significant to the VIE, making it the
primary beneficiary. Making this determination may require significant
management judgment.
If Southern Power is the primary beneficiary, the assets, liabilities, and
results of operations of the entity are consolidated. If Southern Power is not
the primary beneficiary, the legal entity is generally accounted for under the
equity method of accounting. Southern Power reconsiders its conclusions as to
whether the legal entity is a VIE and whether it is the primary beneficiary for
events that impact the rights of variable interests, such as ownership changes
in membership interests.
Southern Power has partial ownership in certain legal entities for which the
contractual provisions represent profit-sharing arrangements because the
allocations of cash distributions and tax benefits are not based on fixed
ownership percentages. For these arrangements, the noncontrolling interest is
accounted for under a balance sheet approach utilizing the HLBV method. The HLBV
method calculates each partner's share of income based on the change in net
equity the partner can legally claim in a HLBV at the end of the period compared
to the beginning of the period.
Contingent Obligations (All Registrants)
The Registrants are subject to a number of federal and state laws and
regulations, as well as other factors and conditions that subject them to
environmental, litigation, and other risks. See FUTURE EARNINGS POTENTIAL herein
and Notes 2 and 3 to the financial statements for more information regarding
certain of these contingencies. The Registrants periodically evaluate their
exposure to such risks and record reserves for those matters where a
non-tax-related loss is considered probable and reasonably estimable. The
adequacy of reserves can be significantly affected by external events or
conditions that can be unpredictable; thus, the ultimate outcome of such matters
could materially affect the results of operations, cash flows, or financial
condition of the Registrants.
Recently Issued Accounting Standards
See Note 1 to the financial statements under "Recently Adopted Accounting
Standards" for additional information.
In 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842) (ASU 2016-02). ASU
2016-02 requires lessees to recognize on the balance sheet a lease liability and
a right-of-use asset for all leases. ASU 2016-02 also changes the recognition,
measurement, and presentation of expense associated with leases and provides
clarification regarding the identification of certain components of contracts
that would represent a lease. The accounting required by lessors is relatively
unchanged and there is no change to the accounting for existing leveraged
leases. The Registrants adopted the new standard effective January 1, 2019. See
Note 9 to the financial statements for additional information and related
disclosures.

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FINANCIAL CONDITION AND LIQUIDITY
Overview
The financial condition of each Registrant remained stable at December 31, 2019.
The Registrants' cash requirements primarily consist of funding ongoing
operations, including unconsolidated subsidiaries, as well as common stock
dividends, capital expenditures, and debt maturities. Southern Power's cash
requirements also include distributions to noncontrolling interests. Capital
expenditures and other investing activities for the traditional electric
operating companies include investments to meet projected long-term demand
requirements, including to build new generation facilities, to maintain existing
generation facilities, to comply with environmental regulations including adding
environmental modifications to certain existing generating units and closures of
ash ponds, to expand and improve transmission and distribution facilities, and
for restoration following major storms. Southern Power's capital expenditures
and other investing activities may include acquisitions or new construction
associated with its overall growth strategy and to maintain its existing
generation fleet's performance. Southern Company Gas' capital expenditures and
other investing activities include investments to meet projected long-term
demand requirements, to maintain existing natural gas distribution systems as
well as to update and expand these systems, and to comply with environmental
regulations.
Operating cash flows provide a substantial portion of the Registrants' cash
needs. During 2019, Southern Power utilized tax credits, which provided $734
million in operating cash flows. For the three-year period from 2020 through
2022, each Registrant's projected stock dividends, capital expenditures, and
debt maturities, as well as distributions to noncontrolling interests for
Southern Power, are expected to exceed its operating cash flows. Southern
Company plans to finance future cash needs in excess of its operating cash flows
primarily by accessing borrowings from financial institutions and issuing debt
and hybrid securities in the capital markets. Each Subsidiary Registrant plans
to finance its future cash needs in excess of its operating cash flows primarily
through external securities issuances, borrowings from financial institutions,
and equity contributions from Southern Company. In addition, Georgia Power plans
to utilize borrowings through the FFB and Southern Power plans to utilize tax
equity partnership contributions. The Registrants plan to use commercial paper
to manage seasonal variations in operating cash flows and for other working
capital needs and continue to monitor their access to short-term and long-term
capital markets as well as their bank credit arrangements to meet future capital
and liquidity needs. See "Sources of Capital," "Financing Activities," "Capital
Requirements," and "Contractual Obligations" herein for additional information.
The Registrants' investments in their qualified pension plans and Alabama
Power's and Georgia Power's investments in their nuclear decommissioning trust
funds increased in value at December 31, 2019 as compared to December 31, 2018.
In December 2019, the Registrants voluntarily contributed the following amounts
to the qualified pension plan:
                         Southern                                                                                 Southern Company
                         Company       Alabama Power     Georgia Power     Mississippi Power     Southern Power         Gas
                                                                     (in millions)
Contributions to
qualified pension
plan                  $      1,136   $           362   $           200   $                54   $             24   $          145


No mandatory contributions to the qualified pension plans are anticipated during
2020. See "Contractual Obligations" herein and Notes 6 and 11 to the financial
statements under "Nuclear Decommissioning" and "Pension Plans," respectively,
for additional information.
At the end of 2019, the market price of Southern Company's common stock was
$63.70 per share (based on the closing price as reported on the NYSE) and the
book value was $26.11 per share, representing a market-to-book value ratio of
244%, compared to $43.92, $23.91, and 184%, respectively, at the end of 2018.

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Analysis of Cash Flows Net cash flows provided from (used for) operating, investing, and financing activities in 2019 and 2018 are presented in the following table: Net cash provided from

                                           Georgia                                             Southern
(used for):                  Southern Company   Alabama Power     Power      Mississippi Power    Southern Power    Company Gas
                                                                        (in millions)
2019
Operating activities        $          5,781   $       1,779   $   2,907   $            339      $       1,385    $     1,067
Investing activities                  (3,392 )        (1,963 )    (3,885 )             (263 )             (167 )       (1,386 )
Financing activities                  (1,930 )           765         918                (83 )           (1,120 )          298

2018
Operating activities        $          6,945   $       1,881   $   2,769   $            804      $         631    $       764
Investing activities                  (5,760 )        (2,289 )    (3,109 )             (232 )             (227 )          998
Financing activities                  (1,813 )           177        (400 )             (527 )             (363 )       (1,770 )


Fluctuations in cash flows from financing activities vary from year to year
based on capital needs and the maturity or redemption of securities.
Southern Company
Net cash provided from operating activities decreased $1.2 billion in 2019 as
compared to 2018 primarily due to the voluntary contribution to the qualified
pension plan and the timing of vendor payments.
The net cash used for investing activities in 2019 and 2018 was primarily due to
the traditional electric operating companies' construction of electric
generation, transmission, and distribution facilities, including installation of
equipment to comply with environmental standards, and capital expenditures for
Southern Company Gas' infrastructure replacement programs, partially offset by
proceeds from the sale transactions described in Note 15 to the financial
statements, which totaled $5.1 billion and $3.0 billion in 2019 and 2018,
respectively.
The net cash used for financing activities in 2019 was primarily due to common
stock dividend payments and net repayments of short-term bank debt and
commercial paper, partially offset by net issuances of long-term debt and the
issuance of common stock. The net cash used for financing activities in 2018 was
primarily due to net redemptions and repurchases of long-term debt, common stock
dividend payments, and a decrease in commercial paper borrowings, partially
offset by net issuances of short-term bank debt, proceeds from Southern Power's
sales of non-controlling equity interests in entities indirectly owning
substantially all of its solar facilities and eight of its wind facilities, and
the issuance of common stock.
Alabama Power
Net cash provided from operating activities decreased $102 million in 2019 as
compared to 2018 primarily due to the voluntary contribution to the qualified
pension plan, partially offset by the impacts of customer bill credits issued in
2018 related to the Tax Reform Legislation and increased fuel cost recovery.
The net cash used for investing activities in 2019 and 2018 was primarily due to
gross property additions.
The net cash provided from financing activities in 2019 was primarily due to
capital contributions from Southern Company and a long-term debt issuance,
partially offset by payments of common stock dividends and a maturity of
long-term debt. The net cash provided from financing activities in 2018 was
primarily due to issuances of long-term debt and additional capital
contributions from Southern Company, partially offset by the payment of common
stock dividends and a maturity of long-term debt.
Georgia Power
Net cash provided from operating activities increased $138 million in 2019 as
compared to 2018 primarily due to lower customer refunds and increased fuel cost
recovery, partially offset by the voluntary contribution to the qualified
pension plan.

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The net cash used for investing activities in 2019 and 2018 was primarily due to
gross property additions, including a total of $2.5 billion related to the
construction of Plant Vogtle Units 3 and 4. See FUTURE EARNINGS POTENTIAL -
"Construction Programs - Nuclear Construction" herein for additional information
on construction of Plant Vogtle Units 3 and 4.
The net cash provided from financing activities in 2019 was primarily due to
borrowings from the FFB for construction of Plant Vogtle Units 3 and 4,
issuances of senior notes, capital contributions from Southern Company, and
pollution control revenue bonds reoffered to the public, partially offset by
payment of common stock dividends and the maturity of senior notes. The net cash
used for financing activities in 2018 was primarily due to the redemption and
repurchase of senior notes, payment of common stock dividends, and pollution
control revenue bond repurchases, partially offset by capital contributions from
Southern Company.
Mississippi Power
Net cash provided from operating activities decreased $465 million in 2019 as
compared to 2018 primarily due to higher income tax refunds in 2018 as a result
of the tax impact of the abandonment of the Kemper IGCC and the voluntary
contribution to the qualified pension plan in 2019.
The net cash used for investing activities in 2019 and 2018 was primarily due to
gross property additions.
The net cash used for financing activities in 2019 was primarily due to a return
of capital to Southern Company and the redemption of senior notes, partially
offset by capital contributions from Southern Company and pollution control
revenue bonds reoffered to the public. The net cash used for financing
activities in 2018 was primarily due to the redemption of preferred stock,
long-term bank debt, short-term borrowings, and senior notes, partially offset
by the issuance of senior notes and short-term borrowings.
Southern Power
Net cash provided from operating activities increased $754 million in 2019 as
compared to 2018 primarily due to the utilization of federal ITCs totaling $734
million in 2019. At December 31, 2019, Southern Power had $1.4 billion of
unutilized ITCs and PTCs which are expected to be fully utilized by 2024. See
FUTURE EARNINGS POTENTIAL - "Income Tax Matters - Tax Credits" herein for
additional information.
The net cash used for investing activities in 2019 was primarily due to Southern
Power's investment in DSGP and ongoing construction activities, largely offset
by proceeds from the sales of Plant Nacogdoches and certain wind turbine
equipment. The net cash used for investing activities in 2018 was primarily due
to the construction of generating facilities and payments for renewable
acquisitions, partially offset by proceeds from the disposition of the Florida
Plants. See FUTURE EARNINGS POTENTIAL - "Acquisitions and Dispositions" and
"Construction Programs" herein and Note 15 to the financial statements for
additional information.
The net cash used for financing activities in 2019 was primarily due to returns
of capital to Southern Company, the repayment at maturity of senior notes,
payments of common stock dividends, and distributions to noncontrolling
interests, partially offset by proceeds from net issuances of commercial paper.
The net cash used for financing activities in 2018 was primarily due to returns
of capital to Southern Company, payments of common stock dividends, and
distributions to noncontrolling interests, partially offset by capital
contributions from noncontrolling interests.
Southern Company Gas
Net cash provided from operating activities increased $303 million in 2019 as
compared to 2018 primarily due to the timing of collection of customer
receivables and lower income tax payments, partially offset by the timing of
vendor payments and the voluntary contribution to the qualified pension plan.
The net cash used for investing activities in 2019 was primarily due to gross
property additions related to utility capital expenditures and infrastructure
investments recovered through replacement programs at gas distribution
operations and capital contributed to equity method pipeline investments,
partially offset by proceeds from the sale of Triton and capital distributions
in excess of earnings from equity method pipeline investments. The net cash
provided from investing activities in 2018 was primarily due to proceeds from
the Southern Company Gas Dispositions, partially offset by gross property
additions primarily related to utility capital expenditures and pre-approved
rider and infrastructure investments recovered through replacement programs at
gas distribution operations as well as net capital contributions to equity
method pipeline investments.
The net cash provided from financing activities in 2019 was primarily due to
capital contributions from Southern Company and proceeds from the issuance of
first mortgage bonds, partially offset by the redemption of long-term debt and
payments of common stock dividends. The net cash used for financing activities
in 2018 was primarily due to payments of common stock dividends to

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Southern Company, return of capital to Southern Company, redemptions of gas
facility revenue bonds and senior notes, and repayments of commercial paper
borrowings and long-term debt, partially offset by debt issuances and capital
contributions from Southern Company.
Significant Balance Sheet Changes
Southern Company
Significant balance sheet changes in 2019 for Southern Company included:
•   decreases in assets and liabilities held for sale of $5.0 billion and $3.3

billion, respectively, and an increase of $2.7 billion in total stockholders'

equity primarily related to the sale of Gulf Power;

• an increase of $2.3 billion in total property, plant, and equipment primarily

related to the traditional electric operating companies' construction of

electric generation, transmission, and distribution facilities, including

installation of equipment to comply with environmental standards, net of $1.2


    billion and $1.0 billion reclassified to other regulatory assets and
    regulatory assets associated with AROs, respectively, as a result of
    generating unit retirements at Alabama Power and Georgia Power;

• an increase in other regulatory assets of $1.8 billion primarily related to

the $1.2 billion reclassification from property, plant, and equipment

discussed above and a $0.8 billion increase in regulatory assets associated

with retiree benefit plans primarily resulting from a decrease in the overall

discount rate used to calculate benefit obligations;

• increases in operating lease right-of-use assets, net of amortization and

operating lease obligations, each totaling $1.8 billion, recorded upon the

adoption of ASC 842;

• an increase of $1.4 billion in regulatory assets associated with AROs

primarily related to the $1.0 billion reclassification from property, plant,

and equipment discussed above and ARO revisions at Alabama Power and

Mississippi Power related to the CCR Rule;

• an increase of $1.3 billion in accumulated deferred income taxes primarily

related to the expected utilization of tax credit carryforwards in the 2019

tax year as a result of increased taxable income from the sale of Gulf Power;

and

• a decrease of $0.9 billion in notes payable related to net repayments of

short-term bank debt and commercial paper.




See Notes 2, 5, 6, 8, 9, 10, 11, and 15 to the financial statements for
additional information.
Alabama Power
Significant balance sheet changes in 2019 for Alabama Power included:
•   an increase of $1.5 billion in total common stockholder's equity primarily

due to a $1.2 billion capital contribution from Southern Company;

• increases of $0.9 billion in regulatory assets associated with AROs and $0.7

billion in other regulatory assets, deferred primarily due to the impacts of

retiring and reclassifying Plant Gorgas Units 8, 9, and 10;

• an increase of $0.6 billion in cash and cash equivalents; and

• an increase of $0.3 billion in AROs, deferred primarily due to an increase in

the ARO estimate related to ash pond facilities.

See Notes 2 and 6 to the financial statements for additional information.


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Georgia Power Significant balance sheet changes in 2019 for Georgia Power included: • an increase of $1.8 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 pollution control

revenue bonds being reoffered to the public;

• an increase of $1.6 billion in property, plant, and equipment to comply with

environmental standards and the construction of generation, transmission, and

distribution facilities, net of approximately $0.8 billion reclassified to

regulatory assets due to the retirement of certain generating units as

approved in the Georgia Power 2019 IRP;

• increases in operating lease right-of-use assets, net of amortization and

operating lease obligations, each totaling $1.4 billion, recorded upon the

adoption of ASC 842;

• an increase of $1.2 billion in regulatory assets primarily due to the $0.8

billion reclassification from property, plant, and equipment discussed above

and $0.2 billion associated with retiree benefit plans primarily as a result

of a decrease in the overall discount rate used to calculate benefit

obligations; and

• an increase of $742 million in total common stockholder's equity primarily

due to capital contributions from Southern Company.




See Notes 2, 8, 9, and 11 to the financial statements for additional
information.
Mississippi Power
Significant balance sheet changes in 2019 for Mississippi Power included:
•   a decrease of $231 million in long-term debt, primarily due to the

reclassification of $249 million of senior notes to securities due within one

year and the redemption of $25 million of senior notes, partially offset by

$43 million in pollution control revenue bonds reoffered to the public;

• an increase of $107 million in other property and investments primarily due

to a new tolling arrangement accounted for as a sales-type lease;

• increases of $67 million in regulatory assets associated with AROs and $31

million in AROs, deferred primarily due to ARO revisions; and

• a net change of $57 million in accumulated deferred income tax assets and

liabilities primarily due to the recognition of a tax loss on the CO2

pipeline transfer and the alternative minimum tax carryforward from prior

years.




See Notes 2, 6, 8, 9, and 10 to the financial statements for additional
information.
Southern Power
Significant balance sheet changes in 2019 for Southern Power included:
•   a $662 million decrease in stockholders' equity due to returns of capital to

Southern Company;

• a $635 million decrease in accumulated deferred income tax assets primarily

related to the utilization of tax credits for the 2019 tax year;

• a $619 million decrease in long-term debt (including securities due within

one year) related to the maturity of $600 million in senior notes;

• a $449 million increase in notes payable due to net issuances of commercial

paper; and

• increases in operating lease right-of-use assets, net of amortization and

operating lease obligations totaling $369 million and $376 million,

respectively, recorded upon the adoption of ASC 842.




See Notes 8, 9, and 10 to the financial statements for additional information.
Southern Company Gas
Significant balance sheet changes in 2019 for Southern Company Gas included:
•   an increase of $950 million in property, plant, and equipment primarily due

to utility capital expenditures and infrastructure investments recovered

through replacement programs, partially offset by $115 million of asset

impairment charges;

• additional paid-in-capital of $841 million primarily related to capital

contributions from Southern Company;

• decreases of $373 million and $414 million in energy marketing receivables


    and payables, respectively, due to lower natural gas prices and volumes of
    natural gas sold;



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• a $287 million decrease in equity investments in unconsolidated subsidiaries

primarily due to $151 million associated with Pivotal LNG and Atlantic Coast

Pipeline reclassified to assets held for sale, as well as distributions from

SNG and the sale of Triton;

• a $203 million increase in accumulated deferred income taxes primarily due to

accelerated tax depreciation and other timing differences;

• reclassification of $171 million in total assets held for sale associated

with Pivotal LNG and Atlantic Coast Pipeline;

• a $95 million decrease in long-term debt primarily due to the redemption of

$300 million in senior notes and the repayment of $50 million in first

mortgage bonds, partially offset by the issuance of $300 million in first

mortgage bonds; and

• increases of $93 million in operating right-of-use assets and $92 million in

operating lease obligations, respectively, related to the adoption of ASC

842.




See Notes 3, 7, 8, 9, 10, and 15 to the financial statements for additional
information.
Sources of Capital
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.
Southern Company does not expect to issue any equity in the capital markets
through 2024.
The Subsidiary Registrants plan to obtain the funds to meet their future capital
needs from sources similar to those they used in the past, which were primarily
from operating cash flows, external securities issuances, borrowings from
financial institutions, and equity contributions from Southern Company. In
addition, Georgia Power plans to utilize borrowings from the FFB, as discussed
further in Note 8 to the financial statements under "Long-term Debt - DOE Loan
Guarantee Borrowings," Southern Power plans to utilize tax equity partnership
contributions, as discussed further herein, and Southern Company Gas plans to
utilize proceeds from the pending sale of its interests in Pivotal LNG and
Atlantic Coast Pipeline, as discussed further in Note 15 to the financial
statements under "Southern Company Gas - Proposed Sale of Pivotal LNG and
Atlantic Coast Pipeline."
The amount, type, and timing of any financings in 2020, as well as in subsequent
years, will be contingent on investment opportunities and the Registrants'
capital requirements and will depend upon prevailing market conditions,
regulatory approvals (for the Subsidiary Registrants), and other factors. See
"Capital Requirements" herein for additional information.
Southern Power utilizes tax equity partnerships as one of its financing sources,
where the tax partner takes significantly all of the federal tax benefits. These
tax equity partnerships are consolidated in Southern Power's financial
statements and are accounted for using HLBV methodology to allocate partnership
gains and losses. During 2019, Southern Power obtained tax equity funding for
the Wildhorse Mountain wind project and received proceeds of $97 million. See
Notes 1 and 15 to the financial statements under "General" and "Southern Power,"
respectively, for additional information.
The issuance of securities by the traditional electric operating companies and
Nicor Gas is generally subject to the approval of the applicable state PSC or
other applicable state regulatory agency. The issuance of all securities by
Mississippi Power and short-term securities by Georgia Power is generally
subject to regulatory approval by the FERC. Additionally, with respect to the
public offering of securities, Southern Company, the traditional electric
operating companies, and Southern Power (excluding its subsidiaries), Southern
Company Gas Capital, and Southern Company Gas (excluding its other subsidiaries)
file registration statements with the SEC under the Securities Act of 1933, as
amended (1933 Act). The amounts of securities authorized by the appropriate
regulatory authorities, as well as the securities registered under the 1933 Act,
are closely monitored and appropriate filings are made to ensure flexibility in
the capital markets.
The Registrants generally obtain financing separately without credit support
from any affiliate. See Note 8 to the financial statements under "Bank Credit
Arrangements" for additional information. The Southern Company system does not
maintain a centralized cash or money pool. Therefore, funds of each company are
not commingled with funds of any other company in the Southern Company system,
except in the case of Southern Company Gas, as described below.
The traditional electric operating companies and SEGCO may utilize a Southern
Company subsidiary organized to issue and sell commercial paper at their request
and for their benefit. Proceeds from such issuances for the benefit of an
individual company are loaned directly to that company. The obligations of each
traditional electric operating company and SEGCO under these arrangements are
several and there is no cross-affiliate credit support. Alabama Power also
maintains its own separate commercial paper program.
Southern Company Gas Capital obtains external financing for Southern Company Gas
and its subsidiaries, other than Nicor Gas, which obtains financing separately
without credit support from any affiliates. Southern Company Gas maintains
commercial

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paper programs at Southern Company Gas Capital and Nicor Gas. Nicor Gas'
commercial paper program supports its working capital needs as Nicor Gas is not
permitted to make money pool loans to affiliates. All of the other Southern
Company Gas subsidiaries benefit from Southern Company Gas Capital's commercial
paper program.
By regulation, Nicor Gas is restricted, to the extent of its retained earnings
balance, in the amount it can dividend or loan to affiliates and is not
permitted to make money pool loans to affiliates. At December 31, 2019, the
amount of subsidiary retained earnings restricted to dividend totaled $951
million. This restriction did not impact Southern Company Gas' ability to meet
its cash obligations, nor does management expect such restriction to materially
impact Southern Company Gas' ability to meet its currently anticipated cash
obligations.
The Registrants' current liabilities frequently exceed their 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.
See Note 8 to the financial statements for additional information. Also see
"Financing Activities" herein for information on issuances of long-term debt
subsequent to December 31, 2019. At December 31, 2019, the following
Registrants' current liabilities exceeded their current assets, primarily as a
result of securities due within one year and notes payable, as shown in the
table below:
                                           Southern        Georgia
At December 31, 2019                      Company(*)        Power

Mississippi Power Southern Power

(in

millions)


      Current liabilities in excess of
                        current assets $        2,729   $     1,902   $               125   $            945
        Securities due within one year          2,989         1,025                   281                824
                         Notes payable          2,055           365                     -                549

(*) Includes $600 million and $465 million of securities due within one year and

notes payable, respectively, at the parent company.




The Registrants believe the need for working capital can be adequately met by
utilizing operating cash flows, as well as commercial paper, lines of credit,
and short-term bank notes, as market conditions permit. In addition, under
certain circumstances, the Subsidiary Registrants may utilize equity
contributions and/or loans from Southern Company.
Bank Credit Arrangements
At December 31, 2019, the Registrants' unused committed credit arrangements with
banks were as follows:
                    Southern
At December 31,     Company      Alabama    Georgia                           Southern       Southern                Southern
2019                 parent       Power      Power      Mississippi Power      Power(a)   Company Gas(b)   SEGCO      Company
                                                                  (in millions)

Unused committed


           credit $    1,999   $   1,328   $  1,733   $               150

$ 591 $ 1,745 $ 30 $ 7,576

(a) At December 31, 2019, Southern Power also had a continuing letter of credit

facility for standby letters of credit, of which $23 million was unused.

Subsequent to December 31, 2019, Southern Power entered into an additional

$60 million continuing letter of credit facility for standby letters of

credit. Southern Power's subsidiaries are not parties to its bank credit

arrangement or to the letter of credit facilities.

(b) Includes $1.245 billion and $500 million at Southern Company Gas Capital and

Nicor Gas, respectively.




Subject to applicable market conditions, the Registrants, Nicor Gas, and SEGCO
expect to renew or replace their bank credit arrangements as needed, prior to
expiration. In connection therewith, the Registrants, Nicor Gas, and SEGCO 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 the revenue bonds of the traditional electric operating
companies and the commercial paper programs of the Registrants, Nicor Gas, and
SEGCO. See Note 8 to the financial statements under "Bank Credit Arrangements"
for additional information.
Short-term Borrowings
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. Southern Power's
subsidiaries are not issuers or obligors under its commercial paper program.
Commercial paper and short-term bank term loans are included in notes payable in
the balance sheets. Details of the Registrants' short-term borrowings were as
follows:

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                                        Short-term Debt at the End of the Period
                                             Amount                     Weighted Average
                                          Outstanding                     Interest Rate
                                          December 31,                    December 31,
                                     2019           2018     2017      2019    2018   2017
                                         (in millions)
Southern Company             $    2,055           $ 2,915  $ 2,439     2.1 %   3.1 %  1.9 %
Alabama Power                         -                 -        3       -       -    3.7
Georgia Power                       365               294      150     2.2     3.1    2.2
Mississippi Power                     -                 -        4       -       -    3.8
Southern Power                      549               100      105     2.2     3.1    2.0
Southern Company Gas:
Southern Company Gas Capital $      372           $   403  $ 1,243     2.1 %   3.1 %  1.7 %
Nicor Gas                           278               247      275     1.8     3.0    1.8
Southern Company Gas Total   $      650           $   650  $ 1,518     2.0 %   3.0 %  1.8 %


                                                   Short-term Debt During the Period(*)
                                                             Weighted Average
                        Average Amount Outstanding             Interest Rate            Maximum Amount Outstanding
                         2019        2018      2017        2019     2018    2017         2019        2018      2017
                               (in millions)                                                   (in millions)

Southern Company $ 1,240 $ 3,377 $ 2,672 2.6 % 2.6 %

  1.5 %   $     2,914   $ 5,447   $ 3,668
Alabama Power                 17        27        25       2.6      2.3      1.3             190       258       223
Georgia Power                371       139       427       2.7      2.5      1.8             935       710     1,460
Mississippi Power              -        68        18         -      2.0      3.0               -       300        36
Southern Power                76       188       232       2.7      2.5      1.4             578       385       419
Southern Company
Gas:
Southern Company Gas
Capital              $       302   $   520   $   723       2.6 %    2.3 %    1.4 %   $       490   $ 1,361   $ 1,243
Nicor Gas                     91       123       176       2.3      2.2      1.1             278       275       525
Southern Company Gas
Total                $       393   $   643   $   899       2.5 %    2.3 %    1.4 %

(*) Average and maximum amounts are based upon daily balances during the 12-month


    periods ended December 31, 2019, 2018, and 2017.



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Financing Activities The following table outlines the Registrants' long-term debt financing activities for the year ended December 31, 2019:


                                                                    Revenue                                                    Other
                                                                     Bond               Revenue                              Long-Term
                                            Senior Note          Issuances and            Bond              Other              Debt
                           Senior           Maturities,           Reofferings         Maturities,         Long-Term         Redemptions
                            Note          Redemptions, and       of Purchased         Redemptions,          Debt                and
Company                   Issuances         Repurchases              Bonds

and Repurchases Issuances Maturities(a)


                                                                           (in millions)
Southern Company parent $         -     $            2,400     $             -     $              -     $     1,725     $            -
Alabama Power                   600                    200                   -                    -               -                  1
Georgia Power                   750                    500                 584                  223           1,218                 13
Mississippi Power                 -                     25                  43                    -               -                  -
Southern Power                    -                    600                   -                    -               -                  -
Southern Company Gas              -                    300                   -                    -             300                 50
Other                             -                      -                   -                   25               -                 17
Elimination(b)                    -                      -                   -                    -               -                 (7 )
Southern Company        $     1,350     $            4,025     $           627     $            248     $     3,243     $           74

(a) Includes reductions in finance lease obligations resulting from cash payments

under finance leases.

(b) Represents reductions in affiliate finance lease obligations at Georgia

Power, which are eliminated in Southern Company's consolidated financial

statements.




Except as otherwise described herein, the Registrants used the proceeds of debt
issuances for their redemptions and maturities shown in the table above, to
repay short-term indebtedness, and for general corporate purposes, including
working capital. The Subsidiary Registrants also used the proceeds for their
construction programs.
In addition to any financings that may be necessary to meet capital requirements
and contractual obligations, the Registrants 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.
Southern Company
During 2019, Southern Company issued approximately 19.5 million shares of common
stock through employee equity compensation plans and received proceeds of
approximately $844 million.
In addition, in August 2019, Southern Company issued 34.5 million 2019 Series A
Equity Units (Equity Units), initially in the form of corporate units (Corporate
Units), at a stated amount of $50 per Corporate Unit, for a total stated amount
of $1.725 billion. Net proceeds from the issuance were approximately $1.682
billion. Each Corporate Unit is comprised of (i) a 1/40 undivided beneficial
ownership interest in $1,000 principal amount of Southern Company's Series 2019A
Remarketable Junior Subordinated Notes due 2024, (ii) a 1/40 undivided
beneficial ownership interest in $1,000 principal amount of Southern Company's
Series 2019B Remarketable Junior Subordinated Notes due 2027, and (iii) a stock
purchase contract, which obligates the holder to purchase from Southern Company,
no later than August 1, 2022, a certain number of shares of Southern Company's
common stock for $50 in cash. See Note 8 to the financial statements under
"Equity Units" for additional information.
In January 2019, Southern Company repaid a $250 million short-term uncommitted
bank credit arrangement and a $1.5 billion short-term floating rate bank loan.
In 2019, Southern Company, through repurchases and redemptions, retired all $1.0
billion aggregate principal amount of its 1.85% Senior Notes due July 1, 2019,
$350 million aggregate principal amount of its Series 2014B 2.15% Senior Notes
due September 1, 2019, $750 million aggregate principal amount of its Series
2018A Floating Rate Notes due February 14, 2020, and $300 million aggregate
principal amount of its Series 2017A Floating Rate Senior Notes due September
30, 2020.
Subsequent to December 31, 2019, Southern Company issued $1.0 billion aggregate
principal amount of Series 2020A 4.95% Junior Subordinated Notes due January 30,
2080.
Alabama Power
In February 2019, Alabama Power repaid at maturity $200 million aggregate
principal amount of Series Z 5.125% Senior Notes due February 15, 2019.

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In September 2019, Alabama Power issued $600 million aggregate principal amount
of Series 2019A 3.45% Senior Notes due October 1, 2049.
Subsequent to December 31, 2019, Alabama Power received a capital contribution
totaling $610 million from Southern Company.
Georgia Power
In March and December 2019, Georgia Power made borrowings under the
multi-advance credit facilities related to the Amended and Restated Loan
Guarantee Agreement in an aggregate principal amount of $835 million and $383
million, respectively, with applicable interest rates of 3.213% and 2.537%,
respectively, both for an interest period that extends to 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. See Note 8 to the financial statements under "Long-term Debt - DOE Loan
Guarantee Borrowings" for additional information.
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 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.
Subsequent to December 31, 2019, Georgia Power issued $700 million aggregate
principal amount of Series 2020A 2.10% Senior Notes due July 30, 2023, $500
million aggregate principal amount of Series 2020B 3.70% Senior Notes due
January 30, 2050, and an additional $300 million aggregate principal amount of
Series 2019B 2.65% Senior Notes due September 15, 2029.
During 2019, Georgia Power reoffered to the public the following pollution
control revenue bonds that previously had been purchased and were held by
Georgia Power at December 31, 2018:
•      $173 million aggregate principal amount of Development Authority of Bartow

County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company

Plant Bowen Project), First Series 2009;

• approximately $105 million aggregate principal amount of Development


       Authority of Burke County (Georgia) Pollution Control Revenue Bonds
       (Georgia Power Company Plant Vogtle Project), First Series 2013;


•      $65 million aggregate principal amount of Development Authority of Burke

County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company


       Plant Vogtle Project), Second Series 2008;


•      $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; and

• 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.




During 2019, Georgia Power purchased, held, and subsequently reoffered to the
public an additional $115 million of pollution control revenue bonds.
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 December 2019, Georgia Power repaid at maturity $500 million aggregate
principal amount of its Series 2009B 4.25% Senior Notes.
Subsequent to December 31, 2019, Georgia Power received a capital contribution
totaling $500 million from Southern Company and announced the redemption of all
$500 million aggregate principal amount of its Series 2017C 2.00% Senior Notes
due September 8, 2020.
Mississippi Power
In March 2019, Mississippi Power reoffered to the public approximately $43
million of Mississippi Business Finance Corporation Pollution Control Revenue
Refunding Bonds, Series 2002, which previously had been purchased and held by
Mississippi Power.
In December 2019, Mississippi Power redeemed $25 million aggregate principal
amount of its Series 2018A Floating Rate Senior Notes due March 27, 2020.
Southern Power
In May 2019, Southern Power repaid at maturity a $100 million short-term
floating rate bank loan.

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In December 2019, Southern Power repaid at maturity $600 million aggregate
principal amount of its Series 2016D 1.95% Senior Notes.
Also in December 2019, Southern Power entered into a short-term floating rate
bank loan in the aggregate principal amount of $100 million, bearing interest
based on one-month LIBOR. Subsequent to December 31, 2019, Southern Power repaid
the bank loan.
Southern Company Gas
In July 2019, Nicor Gas repaid at maturity $50 million aggregate principal
amount of its 4.7% first mortgage bonds.
In August 2019, Southern Company Gas Capital repaid at maturity $300 million
aggregate principal amount of its 5.25% Senior Notes.
In August and October 2019, Nicor Gas issued $200 million and $100 million,
respectively, aggregate principal amount of first mortgage bonds in a private
placement.
Credit Rating Risk
At December 31, 2019, the 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.
There are certain contracts that could require collateral, but not accelerated
payment, in the event of a credit rating change of certain Registrants to BBB
and/or Baa2 or below. These contracts are primarily for physical electricity and
natural gas purchases and sales, fuel purchases, fuel transportation and
storage, energy price risk management, transmission, interest rate management,
and, for Georgia Power, construction of new generation at Plant Vogtle Units 3
and 4.
The maximum potential collateral requirements under these contracts at
December 31, 2019 were as follows:
                                                                                                         Southern    Southern Company
Credit Ratings      Southern Company(*)     Alabama Power      Georgia Power      Mississippi Power      Power(*)           Gas
                                                                     (in millions)
At BBB and/or
Baa2              $                  36   $              1   $              -   $                 -   $         35   $             -
At BBB- and/or
Baa3                                472                  1                 86                     -            385                 -
At BB+ and/or Ba1
or below                          2,040                322              1,020                   267          1,174                18

(*) Excludes amounts related to Plant Mankato, which was sold on January 17,

2020. Southern Power has PPAs that could require collateral, but not

accelerated payment, in the event of a downgrade of Southern Power's credit.

The PPAs require credit assurances without stating a specific credit rating.

The amount of collateral required would depend upon actual losses resulting

from a credit downgrade. Southern Power had $104 million of cash collateral

posted related to PPA requirements at December 31, 2019.




The potential collateral requirement amounts in the previous table for the
traditional electric operating companies and Southern Power include certain
agreements that could require collateral in the event that either Alabama Power
or 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 the Registrants to access capital markets and would be likely to
impact the cost at which they do so.
Mississippi Power and its largest retail customer, Chevron, have agreements
under which Mississippi Power continues to provide retail service to the Chevron
refinery in Pascagoula, Mississippi through 2038. The agreements grant Chevron a
security interest in the co-generation assets located at the refinery that is
exercisable upon the occurrence of (i) certain bankruptcy events or (ii) other
events of default coupled with specific reductions in steam output at the
facility and a downgrade of Mississippi Power's credit rating to below
investment grade by two of the three rating agencies.
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.
On September 12, 2019, S&P upgraded the senior unsecured long-term debt rating
of Alabama Power to A from A-, the long-term issuer rating of Nicor Gas to A
from A-, and the senior secured debt rating of Nicor Gas to A+ from A. The
ratings outlooks remained negative.

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Market Price Risk
The Registrants 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, the
applicable company nets the exposures, where possible, to take advantage of
natural offsets and enters into various derivative transactions for the
remaining exposures pursuant to the applicable company's policies in areas such
as counterparty exposure and risk management practices. Southern Company Gas'
wholesale gas operations uses 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.
Due to cost-based rate regulation and other various cost recovery mechanisms,
the traditional electric operating companies and the natural gas distribution
utilities that sell natural gas directly to end-use customers continue to have
limited exposure to market volatility in interest rates, foreign currency
exchange rates, commodity fuel prices, and prices of electricity. The
traditional electric operating companies and certain of the natural gas
distribution utilities manage fuel-hedging programs implemented per the
guidelines of their respective state PSCs or other applicable state regulatory
agencies to hedge the impact of market fluctuations in natural gas prices for
customers. Mississippi Power also manages wholesale fuel-hedging programs under
agreements with its wholesale customers. Because energy from Southern Power's
facilities is primarily sold under long-term PPAs with tolling agreements and
provisions shifting substantially all of the responsibility for fuel cost to the
counterparties, Southern Power's exposure to market volatility in commodity fuel
prices and prices of electricity is generally limited. However, Southern Power
has been and may continue to be exposed to market volatility in energy-related
commodity prices as a result of uncontracted generating capacity. To mitigate
residual risks relative to movements in electricity prices, the traditional
electric operating companies and Southern Power may enter into physical
fixed-price contracts for the purchase and sale of electricity through the
wholesale electricity market and, to a lesser extent, financial hedge contracts
for natural gas purchases; however, a significant portion of contracts are
priced at market.
Certain of Southern Company Gas' 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 OTC energy contracts, such as forward
contracts, futures contracts, options contracts, and swap agreements. Southern
Company Gas' gas marketing services and wholesale gas services businesses also
actively manage storage positions through a variety of hedging transactions for
the purpose of managing exposures arising from changing natural gas
prices. These hedging instruments are used to substantially protect economic
margins (as spreads between wholesale and retail natural gas prices widen
between periods) and thereby minimize exposure to declining operating margins.
Some of these economic hedge activities may not qualify, or may not be
designated, for hedge accounting treatment.
The Registrants had no material change in market risk exposure for the year
ended December 31, 2019 when compared to the year ended December 31, 2018. See
Note 1 to the financial statements under "Financial Instruments" and Note 14 to
the financial statements for additional information.
The Registrants may enter into interest rate derivatives designated as hedges,
which are intended to mitigate interest rate volatility related to forecasted
debt financings and existing fixed and floating rate obligations. Outstanding
interest rate derivatives at December 31, 2019 are as follows:
                                                  Georgia    Southern

Company


At December 31, 2019       Southern Company(*)     Power           Gas
                                             (in millions)
Hedges of forecasted debt $                 700  $     500  $             200
Hedges of existing debt                   1,800          -                  -
Total                     $               2,500  $     500  $             200

(*) Includes $1.8 billion of hedges of existing debt at the Southern Company


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The following table provides information related to variable interest rate exposure on long-term debt (including amounts due within one year) at December 31, 2019 for the applicable Registrants:


                                    Southern       Alabama       Georgia     Mississippi     Southern
At December 31, 2019               Company(*)       Power         Power         Power          Power
                                                   (in millions, except percentages)
Long-term variable interest
rate exposure                   $      4,063     $    1,079   $       550   $        308   $       525
Weighted average interest rate
on long-term variable interest
rate exposure                           2.38 %         2.35 %        1.74 %         2.51 %        2.46 %
Impact on annualized interest
expense of 100 basis point
change in interest rates        $         41     $       11   $         6   $          3   $         5

(*) Includes $1.5 billion of long-term variable interest rate exposure at the

Southern Company parent entity.




Southern Power Company had foreign currency denominated debt of €1.1 billion at
December 31, 2019. Southern Power Company has mitigated its exposure to foreign
currency exchange rate risk through the use of foreign currency swaps converting
all interest and principal payments to fixed-rate U.S. dollars.
The changes in fair value of energy-related derivative contracts for Southern
Company and Southern Company Gas for the years ended December 31, 2019 and 2018
are provided in the table below. The fair value of energy-related derivative
contracts was not material for the other Registrants.
                                                         Southern

Company(a) Southern Company Gas(a)


                                                                         (in millions)
Contracts outstanding at December 31, 2017, assets
(liabilities), net                                     $             (163 )    $                (106 )
Contracts realized or settled                                          93                         66
Current period changes(b)                                            (131 )                     (127 )
Contracts outstanding at December 31, 2018, assets
(liabilities), net                                     $             (201 )    $                (167 )
Contracts realized or settled                                          69                         26
Current period changes(b)                                             105                        213
Disposition                                                             6                          -

Contracts outstanding at December 31, 2019, assets (liabilities), net

                                     $              (21 )    $                  72

(a) Excludes cash collateral held on deposit in broker margin accounts of $99

million, $277 million, and $193 million at December 31, 2019, 2018, and 2017,

respectively, and premium and intrinsic value associated with weather

derivatives of $4 million, $8 million, and $11 million at December 31, 2019,

2018, and 2017, respectively.

(b) The changes in fair value of energy-related derivative contracts are

substantially attributable to both the volume and the price of natural gas.

Current period changes also include the changes in fair value of new

contracts entered into during the period, if any.




The net hedge volumes of energy-related derivative contracts for natural gas
purchased (sold) at December 31, 2019 and 2018 for Southern Company and Southern
Company Gas were as follows:
                                Southern Company  Southern Company Gas
                                      mmBtu Volume (in millions)
At December 31, 2019:
Commodity - Natural gas swaps                327                     -
Commodity - Natural gas options              262                   218
Total hedge volume                           589                   218

At December 31, 2018:
Commodity - Natural gas swaps                287                     -
Commodity - Natural gas options              144                   120
Total hedge volume                           431                   120



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Southern Company Gas' derivative contracts are comprised of 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. The volumes presented
above for Southern Company Gas represent the net of long natural gas positions
of 4.10 billion mmBtu and short natural gas positions of 3.88 billion mmBtu at
December 31, 2019 and the net of long natural gas positions of 4.16 billion
mmBtu and short natural gas positions of 4.04 billion mmBtu at December 31,
2018.
For the Southern Company system, the weighted average swap contract cost above
market prices was approximately $0.28 and $0.12 per mmBtu at December 31, 2019
and 2018, respectively. The change in option fair value is primarily
attributable to the volatility of the market and the underlying change in the
natural gas price. Substantially all of the traditional electric operating
companies' natural gas hedge gains and losses are recovered through their
respective fuel cost recovery clauses.
At December 31, 2019 and 2018, substantially all of the traditional electric
operating companies' and certain of the natural gas distribution utilities'
energy-related derivative contracts were designated as regulatory hedges and
were related to the applicable company's fuel-hedging program. Gains and losses
associated with regulatory hedges are initially recorded as regulatory
liabilities and assets, respectively, and then are included in fuel expense/cost
of natural gas as they are recovered through their respective cost recovery
clause. Gains and losses on energy-related derivatives designated as cash flow
hedges, which are used to hedge anticipated purchases and sales, are initially
deferred in AOCI before being recognized in income in the same period as the
hedged transaction. 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. See Note 14 to the financial statements for additional
information.
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.
The Registrants use over-the-counter contracts that are not exchange traded but
are fair valued using prices which are market observable, and thus fall into
Level 2 of the fair value hierarchy. In addition, Southern Company Gas uses
exchange-traded market-observable contracts, which are categorized as Level 1,
and contracts that include a combination of observable and unobservable
components, which are categorized as Level 3. See Note 13 to the financial
statements for further discussion of fair value measurements. The maturities of
the energy-related derivative contracts for Southern Company and Southern
Company Gas at December 31, 2019 were as follows:
                                        Fair Value Measurements of Contracts at
                                                   December 31, 2019
                                 Total                         Maturity
                               Fair Value        Year 1        Years 2&3       Years 4&5
                                                     (in millions)
Southern Company
Level 1(a)                    $     (53 )     $     (19 )     $     (37 )     $        3
Level 2(b)                           18              42             (25 )              1
Level 3                              14              10               1                3
Southern Company total(c)     $     (21 )     $      33       $     (61 )     $        7

Southern Company Gas
Level 1(a)                    $     (53 )     $     (19 )     $     (37 )     $        3
Level 2(b)                          111              98              11                2
Level 3                              14              10               1                3

Southern Company Gas total(c) $ 72 $ 89 $ (25 )

$ 8

(a) Valued using NYMEX futures prices.

(b) Level 2 amounts for Southern Company Gas are valued using basis transactions

that represent the cost to transport natural gas from a NYMEX delivery point


    to the contract delivery point. These transactions are based on quotes
    obtained either through electronic trading platforms or directly from
    brokers.

intrinsic value associated with weather derivatives of $4 million at

December 31, 2019.

The Registrants are exposed to risk in the event of nonperformance by counterparties to energy-related and interest rate derivative contracts, as applicable. The Registrants only enter into agreements and material transactions with counterparties that have


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investment grade credit ratings by Moody's and S&P, or with counterparties who
have posted collateral to cover potential credit exposure. Therefore, the
Registrants do not anticipate market risk exposure from nonperformance by the
counterparties. For additional information, see Note 1 to the financial
statements under "Financial Instruments" and Note 14 to the financial
statements.
Southern Company performs periodic reviews of its leveraged lease transactions,
both domestic and international, and the creditworthiness of the lessees,
including a review of the value of the underlying leased assets and the credit
ratings of the lessees. Southern Company's domestic lease transactions generally
do not have any credit enhancement mechanisms; however, the lessees in its
international lease transactions have pledged various deposits as additional
security to secure the obligations. The lessees in Southern Company's
international lease transactions are also required to provide additional
collateral in the event of a credit downgrade below a certain level. See Notes 1
and 3 to the financial statements under "Leveraged Leases" and "Other Matters -
Southern Company," respectively, for additional information.
Southern Company Gas Value at Risk (VaR)
VaR is the maximum potential loss in portfolio value over a specified time
period that is not expected to be exceeded within a given degree of probability.
Southern Company Gas' VaR may not be comparable to that of other companies due
to differences in the factors used to calculate VaR. Southern Company Gas' VaR
is determined on a 95% confidence interval and a one-day holding period, which
means that 95% of the time, the risk of loss in a day from a portfolio of
positions is expected to be less than or equal to the amount of VaR calculated.
The open exposure of Southern Company Gas is managed in accordance with
established policies that limit market risk and require daily reporting of
potential financial exposure to senior management. Because Southern Company Gas
generally manages physical gas assets and economically protects its positions by
hedging in the futures markets, Southern Company Gas' open exposure is generally
mitigated. Southern Company Gas employs daily risk testing, using both VaR and
stress testing, to evaluate the risk of its positions.
Southern Company Gas actively monitors open commodity positions and the
resulting VaR and maintains a relatively small risk exposure as total buy volume
is close to sell volume, with minimal open natural gas price risk. Based on a
95% confidence interval and employing a one-day holding period, SouthStar's
portfolio of positions for all periods presented was immaterial.
Southern Company Gas' wholesale gas services segment had the following VaRs at
December 31:
               2019    2018   2017
                  (in millions)
Period end(*) $  2.6  $ 6.4  $ 4.8
Average          3.4    3.7    2.0
High(*)          7.0   11.7    4.8
Low              2.1    1.2    1.0

(*) The increase in VaR at December 31, 2018 reflects significant natural gas

price increases in Sequent's key markets driven by an industry-wide

lower-than-normal natural gas storage inventory position and

colder-than-normal weather in the middle of fourth quarter 2018. As weather

and natural gas prices moderated subsequent to December 31, 2018, VaR

reduced.




Credit Risk
Southern Company (except as discussed herein), the traditional electric
operating companies, and Southern Power are not exposed to any concentrations of
credit risk. Southern Company Gas' exposure to concentrations of credit risk is
discussed herein.
Southern Company Gas
Gas Distribution Operations
Concentration of credit risk occurs at Atlanta Gas Light for amounts billed for
services and other costs to its customers, which consist of 16 Marketers in
Georgia. The credit risk exposure to Marketers varies seasonally, with the
lowest exposure in the non-peak summer months and the highest exposure in the
peak winter months. Marketers are responsible for the retail sale of natural gas
to end-use customers in Georgia. The provisions of Atlanta Gas Light's tariff
allow Atlanta Gas Light to obtain credit security support in an amount equal to
a minimum of two times a Marketer's highest month's estimated bill from Atlanta
Gas Light. For 2019, the four largest Marketers based on customer count, which
includes SouthStar, accounted for 21% of Southern Company Gas' adjusted
operating margin and 27% of adjusted operating margin for Southern Company Gas'
gas distribution operations segment.

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Several factors are designed to mitigate Southern Company Gas' risks from the
increased concentration of credit that has resulted from deregulation. In
addition to the security support described above, Atlanta Gas Light bills
intrastate delivery service to Marketers in advance rather than in arrears.
Atlanta Gas Light accepts credit support in the form of cash deposits, letters
of credit/surety bonds from acceptable issuers, and corporate guarantees from
investment-grade entities. Southern Company Gas reviews the adequacy of credit
support coverage, credit rating profiles of credit support providers, and
payment status of each Marketer. Southern Company Gas believes that adequate
policies and procedures are in place to properly quantify, manage, and report on
Atlanta Gas Light's credit risk exposure to Marketers.
Atlanta Gas Light also faces potential credit risk in connection with
assignments of interstate pipeline transportation and storage capacity to
Marketers. Although Atlanta Gas Light assigns this capacity to Marketers, in the
event that a Marketer fails to pay the interstate pipelines for the capacity,
the interstate pipelines would likely seek repayment from Atlanta Gas Light.
Wholesale Gas Services
Southern Company Gas has established credit policies to determine and monitor
the creditworthiness of counterparties, as well as the quality of pledged
collateral. Southern Company Gas also utilizes netting agreements whenever
possible to mitigate exposure to counterparty credit risk. When Southern Company
Gas is engaged in more than one outstanding derivative transaction with the same
counterparty and 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. 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 netting and cash
collateral agreements include such provisions.
Southern Company Gas may require counterparties to pledge additional collateral
when deemed necessary. Southern Company Gas conducts credit evaluations and
obtains appropriate internal approvals for a 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.
Certain of Southern Company Gas' derivative instruments contain
credit-risk-related or other contingent features that could increase the
payments for collateral it posts in the normal course of business when its
financial instruments are in net liability positions. At December 31, 2019, for
agreements with such features, Southern Company Gas' derivative instruments with
liability fair values were immaterial and Southern Company Gas had no collateral
posted with derivatives counterparties to satisfy these arrangements.
Southern Company Gas has a concentration of credit risk as measured by its
30-day receivable exposure plus forward exposure. At December 31, 2019, the top
20 counterparties of Southern Company Gas' wholesale gas services segment
represented approximately 59%, or $218 million, of its total counterparty
exposure and had a weighted average S&P equivalent credit rating of A-, all of
which is consistent with the prior year. The S&P equivalent credit rating is
determined by a process of converting the lower of the S&P or Moody's ratings to
an internal rating ranging from 9 to 1, with 9 being equivalent to AAA/Aaa by
S&P and Moody's, respectively, and 1 being D / Default by S&P and Moody's,
respectively. A counterparty that does not have an external rating is assigned
an internal rating based on the strength of the financial ratios of that
counterparty. To arrive at the weighted average credit rating, each counterparty
is assigned an internal ratio, which is multiplied by their credit exposure and
summed for all counterparties. The sum is divided by the aggregate total
counterparties' exposures, and this numeric value is then converted to a S&P
equivalent.

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The following table provides credit risk information related to Southern Company
Gas' third-party natural gas contracts receivable and payable positions at
December 31:
                                          Gross Receivables            Gross Payables
                                            2019           2018         2019         2018
                                            (in millions)               (in millions)
Netting agreements in place:
Counterparty is investment grade     $     238            $ 461    $    127         $ 255
Counterparty is non-investment grade         1                5          43            95
Counterparty has no external rating        175              314         272

505


No netting agreements in place:
Counterparty is investment grade            14               19           -             1
Counterparty has no external rating          -                2           -             -
Amount recorded in balance sheets    $     428            $ 801    $    442

$ 856




Gas Marketing Services
Southern Company Gas obtains credit scores for its firm residential and small
commercial customers using a national credit reporting agency, enrolling only
those customers that meet or exceed Southern Company Gas' credit threshold.
Southern Company Gas considers potential interruptible and large commercial
customers based on reviews of publicly available financial statements and
commercially available credit reports. Prior to entering into a physical
transaction, Southern Company Gas also assigns physical wholesale counterparties
an internal credit rating and credit limit based on the counterparties' Moody's,
S&P, and Fitch ratings, commercially available credit reports, and audited
financial statements.
Capital Requirements
Total estimated capital expenditures for the Registrants through 2024 based on
their current construction programs are as follows:
                              2020   2021   2022   2023   2024
                                       (in billions)
Southern Company(a)(b)(c)(d) $ 8.7  $ 7.3  $ 6.8  $ 6.8  $ 6.2
Alabama Power(b)               2.1    1.8    1.8    1.8    1.6
Georgia Power(c)               4.1    3.4    3.0    2.8    2.7
Mississippi Power              0.3    0.2    0.2    0.3    0.2
Southern Power(d)              0.3    0.2    0.1    0.1    0.1
Southern Company Gas           1.8    1.6    1.6    1.7    1.6

(a) Includes the Subsidiary Registrants, as well the other subsidiaries.

(b) Includes amounts contingent upon approval by the Alabama PSC related to

Alabama Power's September 6, 2019 CCN filing totaling $0.5 billion for 2020,

$0.2 billion for 2021, $0.3 billion for 2022, and $0.1 billion for 2023. See

FUTURE EARNINGS POTENTIAL - "Regulatory Matters - Alabama Power - Petition

for Certificate of Convenience and Necessity" herein for additional

information.

billion, and $0.3 billion for the construction of Plant Vogtle Units 3 and 4

in 2020, 2021, and 2022, respectively.

(d) These amounts do not include approximately $0.5 billion per year for 2020

through 2024 for Southern Power's planned expenditures for plant acquisitions

and placeholder growth, which may vary materially due to market opportunities

and Southern Power's ability to execute its growth strategy.




These amounts include estimated capital expenditures to comply with
environmental laws and regulations, but do not include any potential compliance
costs associated with pending regulation of CO2 emissions from fossil fuel-fired
electric generating units. See FUTURE EARNINGS POTENTIAL - "Environmental
Matters" herein for additional information. These amounts also include capital
expenditures related to contractual purchase commitments for nuclear fuel (for
Southern Company, Alabama Power, and Georgia Power) and capital expenditures
covered under LTSAs.
The traditional electric operating companies also anticipate costs associated
with closure and monitoring of ash ponds and landfills in accordance with the
CCR Rule and the related state rules, which are reflected in the applicable
Registrants' ARO liabilities. Alabama Power's cost estimates are based on
closure-in-place for all of its ash ponds. The cost estimates for Georgia

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Power and Mississippi Power are based on a combination of closure-in-place for
some ash ponds and closure by removal for others. These anticipated costs are
likely to change, and could change materially, as assumptions and details
pertaining to closure are refined and compliance activities continue. See FUTURE
EARNINGS POTENTIAL - "Environmental Matters - Environmental Laws and Regulations
- Coal Combustion Residuals" herein and Note 6 to the financial statements for
additional information. The current estimates of these costs through 2024 are as
follows:
                   2020   2021   2022   2023   2024
                            (in millions)

Southern Company $ 498 $ 551 $ 742 $ 916 $ 967 Alabama Power 200 217 284 363 386 Georgia Power 265 289 391 475 530 Mississippi Power 23 29 24 23 20




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; abnormal weather; 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, Southern Power's 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" for additional information regarding Southern Power's plant
acquisitions and construction projects.
The construction program of Georgia Power also includes Plant Vogtle Units 3 and
4, which includes components based on new technology that only within the last
few years began initial operation in the global nuclear industry at this scale
and which may be subject to additional revised cost estimates during
construction. See Note 2 to the financial statements under "Georgia Power -
Nuclear Construction" for information regarding Plant Vogtle Units 3 and 4 and
additional factors that may impact construction expenditures.
See FUTURE EARNINGS POTENTIAL - "Construction Programs" herein for additional
information. Also see "Contractual Obligations" herein for information regarding
other future funding requirements of the Registrants.

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Contractual Obligations
The following tables present the Registrants' contractual obligations at
December 31, 2019. Additional information about these funding requirements is
provided herein.
Southern Company                     2020        2021-2022       2023-2024       After 2024        Total
                                                                (in millions)
Long-term debt -
Principal                         $  2,971     $     5,189     $     2,890     $     33,489     $  44,539
Interest                             1,677           3,109           2,809           25,986        33,581
Financial derivative obligations       450             204              65                -           719
Operating leases                       294             543             386            1,609         2,832
Finance leases                          31              47              33              246           357
Pipeline charges, storage
capacity, and gas supply               725           1,085             784            1,677         4,271
Purchase commitments -
Capital                              7,758          12,981          11,989                         32,728
Fuel                                 2,787           3,491           1,527            4,546        12,351
Purchased power                        150             270             237            1,725         2,382
Other                                  406             618             530            2,174         3,728
ARO settlements                        498           1,293           1,883                          3,674
Other(*)                               163             310              38               65           576
Southern Company system total     $ 17,910     $    29,140     $    23,171     $     71,517     $ 141,738

(*) Includes funding requirements related to pension and other postretirement

benefit plans, nuclear decommissioning trusts of Georgia Power, and preferred

stock dividends of Alabama Power.




Alabama Power                        2020        2021-2022       2023-2024       After 2024       Total
                                                               (in millions)
Long-term debt -
Principal                         $    250     $     1,060     $       321     $      6,956     $  8,587
Interest                               338             649             578            4,985        6,550
Preferred stock dividends               15              29              29                -           73
Financial derivative obligations        14              10               -                -           24
Operating leases                        54             105               5                1          165
Finance leases                           1               2               1                -            4
Purchase commitments -
Capital                              1,502           2,891           2,927                         7,320
Fuel                                   959           1,226             465              808        3,458
Purchased power                         35              75              77              446          633
Other                                   39              81              62              243          425
ARO settlements                        200             501             749                         1,450
Pension and other postretirement
benefit plans                           14              28                                            42
Alabama Power total               $  3,421     $     6,657     $     5,214     $     13,439     $ 28,731



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Georgia Power                        2020        2021-2022       2023-2024       After 2024       Total
                                                               (in millions)
Long-term debt -
Principal                         $  1,014     $       906     $       628     $      9,236     $ 11,784
Interest                               384             715             668            5,070        6,837
Financial derivative obligations        49              21               -                -           70
Operating leases                       205             395             359              831        1,790
Finance leases                          28              49              50              134          261
Purchase commitments -
Capital                              3,805           6,080           4,966                        14,851
Fuel                                 1,091           1,401             629            3,610        6,731
Purchased power                         56             117             123              862        1,158
Other                                  117             121             133              205          576
ARO settlements                        265             680           1,006                         1,951
Nuclear decommissioning trust            5               9               9               65           88
Pension and other postretirement
benefit plans                           50              93                                           143
Georgia Power total               $  7,069     $    10,587     $     8,571     $     20,013     $ 46,240


Mississippi Power                    2020        2021-2022       2023-2024       After 2024       Total
                                                               (in millions)
Long-term debt -
Principal                         $    282     $       270     $         -     $      1,026     $  1,578
Interest                                68             102              83              542          795
Financial derivative obligations        15              11               1                -           27
Operating leases                         2               2               1                2            7
Purchase commitments -
Capital                                255             397             402                         1,054
Fuel                                   313             312             169              108          902
Purchased power                         17              36              37              417          507
Other                                   28              58              69              230          385
ARO settlements                         23              53              44                           120
Pension and other postretirement
benefits plans                           7              14                                            21
Mississippi Power total           $  1,010     $     1,255     $       806     $      2,325     $  5,396


Southern Power                       2020        2021-2022       2023-2024       After 2024       Total
                                                               (in millions)
Long-term debt -
Principal                         $    825     $       977     $       290     $      2,339     $  4,431
Interest                               163             278             222            1,302        1,965
Financial derivative obligations         3               -               -                -            3
Operating leases                        29              50              52              888        1,019
Purchase commitments -
Capital                                251             306             294                           851
Fuel                                   424             552             265               20        1,261
Purchased power                         42              42               -                -           84
Other                                  159             296             239            1,481        2,175
Southern Power total              $  1,896     $     2,501     $     1,362     $      6,030     $ 11,789



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Southern Company Gas                 2020        2021-2022       2023-2024       After 2024       Total
                                                               (in millions)
Long-term debt -
Principal                         $      -     $       376     $       400     $      4,659     $  5,435
Interest                               235             458             425            3,213        4,331
Financial derivative obligations       369             161              66                -          596
Operating leases                        18              31              21               44          114
Pipeline charges, storage
capacity, and gas supply               725           1,085             784            1,677        4,271
Purchase commitments -
Capital                              1,775           3,191           3,335                         8,301
Other                                   31              14               1                -           46
Pension and other postretirement
benefit plans                           16              29                                            45
Southern Company Gas total        $  3,169     $     5,345     $     5,032     $      9,593     $ 23,139

Additional information about these funding requirements is provided below: • Long-term debt - Represents scheduled maturities of long-term debt, as well

as the related interest. All amounts are reflected based on final maturity

dates except for amounts related to Georgia Power's FFB borrowings. The final

maturity date for Georgia Power's FFB borrowings is February 20, 2044;

however, principal amortization is reflected beginning in February 2020. The

interest amounts also include the effects of interest rate derivatives

employed to manage interest rate risk and effects of foreign currency swaps

employed to manage foreign currency exchange rate risk, as applicable. For

Southern Company and Southern Power, debt principal includes a $5 million

loss related to Southern Power's foreign currency hedge of €1.1 billion. The

Registrants plan to continue, when economically feasible, to retire

higher-cost securities and replace these obligations with lower-cost capital

if market conditions permit. Variable rate interest obligations are estimated

based on rates at December 31, 2019, as reflected in the statements of

capitalization for each Registrant. Long-term debt excludes finance lease

amounts, which are shown separately. See Note 8 to the financial statements

for additional information.

• Financial derivative obligations - See Note 14 to the financial statements

for additional information.

• Operating and finance leases - See Note 9 to the financial statements for

additional information. Operating lease commitments may include certain land

leases for facilities that may be subject to annual price escalation based on

indices. Estimated lease payments for Southern Company and Alabama Power

exclude amounts contingent upon approval by the Alabama PSC related to

Alabama Power's September 6, 2019 CCN filing totaling $1 million for 2021, $2

million for 2022, $3 million for 2023, $4 million for 2024, and $85 million

for after 2024. See Note 2 to the financial statements under "Alabama Power -

Petition for Certificate of Convenience and Necessity" for additional

information.

• Purchase commitments - Capital - Estimated capital expenditures are provided

for a five-year period, including capital expenditures associated with

environmental regulations. These amounts exclude contractual purchase

commitments for nuclear fuel, capital expenditures covered under LTSAs, and

estimated capital expenditures for AROs, which are reflected in the "fuel,"

"other," and "ARO settlements" categories, respectively, where applicable.

Estimated capital expenditures for Southern Company and Alabama Power exclude

amounts contingent upon approval by the Alabama PSC related to Alabama

Power's September 6, 2019 CCN filing totaling $0.5 billion for 2020, $0.2

billion for 2021, $0.3 billion for 2022, and $0.1 billion for 2023. See Note

2 to the financial statements under "Alabama Power - Petition for Certificate

of Convenience and Necessity" for additional information. Estimated capital

expenditures for Southern Company and Southern Power exclude approximately

$0.5 billion per year for 2020 through 2024 for Southern Power's planned

expenditures for plant acquisitions and placeholder growth. At December 31,

2019, significant purchase commitments were outstanding in connection with


    the Registrants' construction programs. See FUTURE EARNINGS POTENTIAL -
    "Environmental Matters" and "Construction Programs" herein and "Capital
    Requirements" herein for additional information.

• Purchase commitments - Fuel - Primarily includes commitments to purchase coal

(for the traditional electric operating companies), natural gas (for the

traditional electric operating companies and Southern Power), and nuclear

fuel (for Alabama Power and Georgia Power), as well as the related

transportation and storage. In most cases, these contracts contain provisions

for price escalation, minimum purchase levels, and other financial

commitments. Natural gas purchase commitments are based on various indices at

the time of delivery. Amounts reflected for natural gas purchase commitments

have been estimated based on the NYMEX future prices at December 31, 2019.

• Purchase commitments - Purchased power - Represents estimated minimum

obligations for various PPAs for the purchase of capacity and energy, as well

as, for Georgia Power, capacity payments related to Plant Vogtle Units 1 and

2. Amounts exclude PPAs accounted for as leases, which are reflected in the


    "operating leases" and "finance leases" categories, where applicable.



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Estimated capacity payments for Southern Company and Alabama Power exclude
amounts contingent upon approval by the Alabama PSC related to Alabama Power's
September 6, 2019 CCN filing totaling $4 million for 2020, $7 million for 2021,
$7 million for 2022, $8 million for 2023, $8 million for 2024, and $107 million
for after 2024. See Note 2 to the financial statements under "Alabama Power -
Petition for Certificate of Convenience and Necessity" for additional
information. Mississippi Power's long-term PPAs are associated with solar
facilities and only include an energy component. Southern Power's purchased
power commitments will be resold under a third-party agreement at cost. See Note
3 to the financial statements under "Guarantees" for additional information.
•   Purchase commitments - Other - Includes LTSAs (for all Registrants),

contracts for the procurement of limestone (for Alabama Power and Georgia

Power), contractual environmental remediation liabilities (for Southern

Company Gas), operation and maintenance agreements (for Southern Power), and

transmission agreements (for Southern Power). LTSAs include price escalation

based on inflation indices. Southern Power's transmission commitments are

based on the Southern Company system's current tariff rate for point-to-point

transmission.

• Pension and other postretirement benefit plans - The Southern Company system

provides postretirement benefits to the majority of its employees and funds

trusts to the extent required by PSCs, other applicable state regulatory

agencies, or the FERC. The Registrants forecast contributions to their

pension and other postretirement benefit plans over a three-year period. The

Registrants anticipate no mandatory contributions to the qualified pension

plan during the next three years. Amounts presented represent estimated

benefit payments for the nonqualified pension plans, estimated non-trust

benefit payments for the other postretirement benefit plans, and estimated

contributions to the other postretirement benefit plan trusts, all of which

will be made from corporate assets of the applicable subsidiaries. See Note

11 to the financial statements for additional information related to the

pension and other postretirement benefit plans, including estimated benefit

payments. Certain benefit payments will be made through the related benefit

plans. Other benefit payments will be made from corporate assets of the

applicable subsidiaries.

• ARO settlements - Represents estimated costs for a five-year period

associated with closing and monitoring ash ponds at the traditional electric

operating companies in accordance with the CCR Rule and the related state

rules, which are reflected in the applicable Registrants' ARO liabilities.

Material expenditures in future years for ARO settlements also will be

required for ash ponds, nuclear decommissioning (for Alabama Power and

Georgia Power), and other liabilities reflected in the applicable

Registrants' AROs. See Note 6 to the financial statements for additional

information.

• Preferred stock dividends - Represents preferred stock of Alabama Power.

Preferred stock does not mature; therefore, amounts are provided for the next

five years only.

• Nuclear decommissioning trusts - As a result of NRC requirements, Alabama

Power and Georgia Power have external trust funds for nuclear decommissioning

costs. Based on its most recent site study completed in 2018, Alabama Power

currently has no additional funding requirements. Alabama Power's next site

study is expected to be conducted by 2023. Georgia Power's projections of

nuclear decommissioning trust fund contributions for Plant Hatch and Plant

Vogtle Units 1 and 2 are based on the 2019 ARP. See Note 6 to the financial

statements under "Nuclear Decommissioning" for additional information.

• Pipeline charges, storage capacity, and gas supply - Includes charges at

Southern Company Gas recoverable through a natural gas cost recovery

mechanism, or alternatively billed to Marketers selling retail natural gas,

and demand charges associated with Sequent. The gas supply balance includes

amounts for Nicor Gas and SouthStar gas commodity purchase commitments of 45

million mmBtu at floating gas prices calculated using forward natural gas

prices at December 31, 2019 and valued at $84 million. Southern Company Gas

provides guarantees to certain gas suppliers for certain of its subsidiaries,


    including SouthStar, in support of payment obligations.



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Market Closed - Nyse Other stock markets 04:01:20 2024-04-24 pm EDT			5-day change	1st Jan Change
73.91 ^USD	+0.90%		+5.89%	+5.41%

Apr. 22	Sector Update: Energy Stocks Advance in Late Monday Afternoon Trading	MT
Apr. 22	Sector Update: Energy	MT

Sector Update: Energy Stocks Advance in Late Monday Afternoon Trading	Apr. 22	MT
Sector Update: Energy	Apr. 22	MT
Southern Increases Quarterly Dividend by $0.02 to $0.72 Per Share, Payable on June 6 to Shareholders of Record on May 20	Apr. 22	MT
Southern Co. Raises Quarterly Dividend by 2.9%	Apr. 22	DJ
The Southern Company Announces Regular Quarterly Dividend, Payable on June 6, 2024	Apr. 22	CI
BMO Capital Adjusts Southern Company Price Target to $77 From $76	Apr. 22	MT
Scotiabank Adjusts Southern Co.'s Price Target to $77 From $80	Apr. 22	MT
Mercy Investment Services Submits a Shareholder Proposal to The Southern Company	Apr. 12	CI
John Chevedden Submits a Shareholder Proposal to The Southern Company	Apr. 12	CI
Barclays Adjusts Southern's Price Target to $66 From $65	Apr. 12	MT
US electric utilities brace for surge in power demand from data centers	Apr. 10	RE
North American Morning Briefing : Investors on -2-	Apr. 05	DJ
UBS Downgrades Southern to Neutral From Buy, Cuts Price Target to $76 From $78	Apr. 04	MT
Mizuho Securities Raises Southern's Price Target to $76 From $73, Keeps Buy Rating	Apr. 02	MT
The Southern Company Receives a Shareholder Proposal from Mercy Investment Services, Inc	Apr. 01	CI
The Southern Company Receives a Shareholder Proposal from John Chevedden	Apr. 01	CI
BMO Capital Raises Price Target on Southern to $76 From $72, Maintains Outperform Rating	Apr. 01	MT
Southern Insider Sold Shares Worth $344,600, According to a Recent SEC Filing	Mar. 12	MT
Public Service Enterprise beats Q4 profit estimates on lower operating expenses	Feb. 26	RE
Southern Insider Sold Shares Worth $931,855, According to a Recent SEC Filing	Feb. 16	MT
Sector Update: Energy Stocks Rise Late Afternoon	Feb. 16	MT
Southern Files Mixed Shelf	Feb. 16	MT
Alliant Energy reports Q4 profit miss on lower retail electric, gas sales	Feb. 15	RE
Con Edison beats fourth-quarter profit estimates on lower operating expenses	Feb. 15	RE
Sector Update: Energy Stocks Jump in Late Afternoon	Feb. 15	MT

	1st Jan change	Capi.
SOUTHERN COMPANY	+5.41%	80.83B
NEXTERA ENERGY	+9.58%	137B
IBERDROLA, S.A.	-2.65%	77.52B
DUKE ENERGY CORPORATION	+1.98%	76.34B
ENEL S.P.A.	-10.10%	66.08B
CONSTELLATION ENERGY CORPORATION	+59.26%	58.66B
AMERICAN ELECTRIC POWER COMPANY, INC.	+6.34%	45.48B
DOMINION ENERGY, INC.	+9.00%	42.91B
GE VERNOVA INC.	0.00%	39.77B
EXELON CORPORATION	+5.21%	37.76B

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