Third Quarter 2017 vs. Third Quarter 2016 Year-to-Date 2017 vs. Year-to-Date 2016
(change in millions) (% change) (change in millions) (% change)
$14 53.8 $(2,073) N/M

~~N/M - Not meaningful~~

Mississippi Power's net income after dividends on preferred stock for the third quarter 2017 was $40 million compared to $26 million for the corresponding period in 2016. The increase was due to lower pre-tax charges associated with the Kemper IGCC and a decrease in interest expense, net of amounts capitalized, partially offset by an increase in income taxes and decreases in retail revenues and AFUDC equity.

Mississippi Power's net loss after dividends on preferred stock for year-to-date 2017 was $2.03 billion compared to net income of $39 million for the corresponding period in 2016. The decrease in net income was related to higher pre-tax charges associated with the Kemper IGCC.

~~See Note 3 to the financial statements of Mississippi Power under "Integrated Coal Gasification Combined Cycle" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" herein for additional information.~~

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~~MISSISSIPPI POWER COMPANY~~

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

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

issue of class certification as moot. Also in December 2021, the plaintiffs filed a petition for writ of certiorari to the Georgia Supreme Court, which was denied on January 27, 2023. On February 6, 2023, the plaintiffs filed a motion for reconsideration with the Georgia Supreme Court, which was denied on February 16, 2023. This matter is now concluded.

~~Retail Revenues~~

Third Quarter 2017 vs. Third Quarter 2016 Year-to-Date 2017 vs. Year-to-Date 2016
(change in millions) (% change) (change in millions) (% change)
$(20) (7.6) $13 2.0
Plant Scherer

In July 2020, a group of individual plaintiffs filed a complaint, which was amended in December 2022, in the ~~third quarter 2017, retail revenues~~Superior Court of Fulton County, Georgia against Georgia Power alleging that the construction and operation of Plant Scherer has impacted groundwater and air, resulting in alleged personal injuries and property damage. The plaintiffs seek an unspecified amount of monetary damages including punitive damages, a medical monitoring fund, and injunctive relief. In December 2022, the Superior Court of Fulton County, Georgia granted Georgia Power's motion to transfer the case to the Superior Court of Monroe County, Georgia. On May 9, 2023, the Superior Court of Monroe County, Georgia denied Georgia Power's motion to dismiss the case for lack of subject matter jurisdiction. On July 27, 2023, the Superior Court of Monroe County, Georgia denied the remaining motions to dismiss certain claims and plaintiffs that Georgia Power filed at the outset of the case.

In October 2021, February 2022, and January 2023, a total of eight additional complaints were ~~$243 million compared~~filed in the Superior Court of Monroe County, Georgia against Georgia Power alleging that releases from Plant Scherer have impacted groundwater and air, resulting in alleged personal injuries and property damage. The plaintiffs sought an unspecified amount of monetary damages including punitive damages. After Georgia Power removed these cases to ~~$263 million~~the U.S. District Court for the ~~corresponding period~~Middle District of Georgia, the plaintiffs voluntarily dismissed their complaints without prejudice in ~~2016. For year-to-date 2017, retail revenues were $665 million compared~~November 2022 and January 2023. On May 12, 2023, the plaintiffs in the cases originally filed in October 2021, February 2022, and January 2023 refiled their eight complaints in the Superior Court of Monroe County, Georgia. Also on May 12, 2023, a new complaint was filed in the Superior Court of Monroe County, Georgia against Georgia Power alleging that the construction and operation of Plant Scherer have impacted groundwater and air, resulting in alleged personal injuries. The plaintiff seeks an unspecified amount of monetary damages, including punitive damages. On May 18, 2023, Georgia Power removed all of these cases to ~~$652 million~~the U.S. District Court for the ~~corresponding period in 2016.~~

~~Details~~Middle District of Georgia. The plaintiffs are requesting the ~~changes in retail revenues were as follows:~~

Third Quarter 2017 Year-to-Date 2017
(in millions) (% change) (in millions) (% change)
Retail – prior year $ 263
$ 652

Estimated change resulting from –
Rates and pricing (10 ) (3.8 ) 9
1.4
Sales growth 1
0.4
4
0.6
Weather (9 ) (3.4 ) (16 ) (2.5 )
Fuel and other cost recovery (2 ) (0.8 ) 16
2.5
Retail – current year $ 243
(7.6 )% $ 665
2.0 %

~~Revenues associated with changes in rates and pricing decreased in~~court remand the ~~third quarter 2017 when compared~~cases back to the ~~corresponding period in 2016 primarily due to recognition~~Superior Court of Monroe County, Georgia.

The amount of possible loss, if any, from these matters cannot be estimated at this time.

Mississippi Power

In 2018, Ray C. Turnage and 10 other individual plaintiffs filed a ~~regulatory liability as directed by~~putative class action complaint against Mississippi Power and the three then-serving members of the Mississippi PSC in the U.S. District Court for the Southern District of Mississippi, which was amended in March 2019 to include four additional plaintiffs. Mississippi Power received Mississippi PSC approval in 2013 to charge a ~~July 6, 2017 order following full amortization of certain regulatory assets~~mirror CWIP rate premised upon including in its rate base pre-construction and ~~an ECO Plan rate decrease implemented~~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 and make claims for gross negligence, reckless conduct, and intentional wrongdoing. They also allege that Mississippi Power underpaid customers by up to $23.5 million in the ~~second quarter 2017.~~

~~Revenues associated with changes~~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. The district court dismissed the amended complaint; however, in ~~rates and pricing increased in year-to-date 2017 when compared~~March 2020, the plaintiffs filed a motion seeking to name the ~~corresponding period in 2016 primarily due to an ECO Plan rate increase implemented in the third quarter 2016, partially offset by the recognition~~new members of ~~a regulatory liability as directed by~~ the Mississippi PSC, inthe Mississippi Development Authority, and Southern Company as additional defendants and add a cause of action against all defendants based on a dormant commerce clause theory under the U.S. Constitution. In July ~~6, 2017 order following full amortization of certain regulatory assets and an ECO Plan rate decrease implemented in~~2020, the plaintiffs filed a motion for leave to file a third amended complaint, which included the same federal claims as the proposed second ~~quarter 2017.~~

~~See Note (B) to~~amended complaint, as well as several additional state law claims based on the ~~Condensed Financial Statements under "Regulatory Matters –~~allegation that Mississippi Power ~~– Environmental Compliance Overview Plan" and "Integrated Coal Gasification Combined Cycle" herein for additional information.~~

~~Revenues attributable~~failed to ~~changes in sales increased slightly for~~disclose the ~~third quarter 2017 when compared~~annual percentage rate of interest applicable to refunds. In November 2020, the corresponding period in 2016. Weather-adjusted KWH sales to residential customers increased 2.9% due to higher customer usage. Weather-adjusted KWH sales to commercial customers decreased 1.2% due to lower customer usage, partially offset by customer growth. KWH sales to industrial customers decreased 2.4% primarily due to an unplanned outage by a large customer in 2017,district court denied each of the ~~impacts of Hurricane Harvey on petroleum pipeline customers, and a decrease in the number of mid-size customers.~~

Revenues attributable to changes in sales increased slightly for year-to-date 2017 when compared to the corresponding period in 2016. Weather-adjusted KWH sales to residential customers increased 0.8% due to higher customer usage. Weather-adjusted KWH sales to commercial customers decreased 0.7% due to lower customer usage, partially offset by customer growth. KWH sales to industrial customers decreased 1.1% primarily due to unplanned outages by a large customer in 2017, the impacts of Hurricane Harvey on petroleum pipeline customers, and a decrease in the number of mid-size customers.

Fuel and other cost recovery revenues decreased in the third quarter 2017 when compared to the corresponding period in 2016 primarily as a result of lower recoverable fuel costs. Fuel and other cost recovery revenues increased

plaintiffs' pending

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

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

~~for year-to-date 2017 when compared to~~motions and entered final judgment in favor of Mississippi Power. In January 2021, the ~~corresponding period in 2016 primarily as a result of higher recoverable fuel costs. See "Fuel and Purchased Power Expenses" herein for additional information. Recoverable fuel costs include fuel and purchased power expenses reduced~~district court denied further motions by the ~~fuel portion~~plaintiffs to vacate the judgment and to file a revised second amended complaint. In February 2021, the plaintiffs filed a notice of wholesale revenues from energy sold to customers outside Mississippi Power's service territory. Electric rates 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.

~~Wholesale Revenues – Affiliates~~

Third Quarter 2017 vs. Third Quarter 2016 Year-to-Date 2017 vs. Year-to-Date 2016
(change in millions) (% change) (change in millions) (% change)
$14 N/M $17 73.9

~~N/M - Not meaningful~~

~~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~~appeal 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 the third quarter 2017, wholesale revenues from sales to affiliates were $21 million compared to $7 million~~U.S. Court of Appeals for the ~~corresponding period in 2016. The increase was due to a $13 million increase in KWH sales as a result~~Fifth Circuit. In March 2022, the U.S. Court of ~~supporting Southern Company system transmission reliability and a $1 million increase primarily due to higher natural gas prices.~~

~~For year-to-date 2017, wholesale revenues from sales to affiliates were $40 million compared to $23 million~~Appeals for the ~~corresponding period in 2016. The increase was primarily due to higher KWH sales as a result of supporting Southern Company system transmission reliability and higher natural gas prices.~~

~~Fuel and Purchased Power Expenses~~

Third Quarter 2017
vs.
Third Quarter 2016 Year-to-Date 2017
vs.
Year-to-Date 2016
(change in millions) (% change) (change in millions) (% change)
Fuel $ 8
7.1 $ 33
12.3
Purchased power – non-affiliates 1
33.3 3
75.0
Purchased power – affiliates (3 ) (60.0) (1 ) (7.1)
Total fuel and purchased power expenses $ 6
$ 35

InFifth Circuit issued an opinion affirming the third quarter 2017, total fuel and purchased power expenses were $126 million compared to $120 million for the corresponding period in 2016. The increase was due to a $6 million increase in the volume of KWHs generated and purchased.

For year-to-date 2017, total fuel and purchased power expenses were $321 million compared to $286 million for the corresponding period in 2016. The increase was primarily due to a $42 million increase in the average cost of natural gas and purchased power, partially offset by a $4 million decrease in coal prices and a $3 million decrease in the volume of KWHs generated and purchased.

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 clause.

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~~FINANCIAL CONDITION AND RESULTS OF OPERATIONS~~

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

Third Quarter 2017 Third Quarter 2016 Year-to-Date 2017 Year-to-Date 2016
Total generation (in millions of KWHs)
4,453 4,255 11,542 11,570
Total purchased power (in millions of KWHs)^(*)
164 288 527 877
Sources of generation (percent) –

Coal 8 10 8 9
Gas 92 90 92 91
Cost of fuel, generated (in cents per net KWH) –

Coal 3.80 4.02 3.60 4.09
Gas 2.77 2.64 2.72 2.34
Average cost of fuel, generated (in cents per net KWH)
2.86 2.79 2.80 2.50
Average cost of purchased power (in cents per net KWH)^(*)
3.74 2.59 3.78 2.04


~~(*)~~	~~Includes energy produced during the test period for the Kemper IGCC, which is accounted for in accordance with FERC guidance.~~

~~Fuel~~

In the third quarter 2017, total fuel expense was $120 million compared to $112 million for the corresponding period in 2016. The increase was due to a 2.5% increase in the average cost of fuel per KWH generated, primarily due to a 4.5% higher cost of natural gas, and a 5.4% increase in the volume of KWHs generated.

For year-to-date 2017, total fuel expense was $301 million compared to $268 million for the corresponding period in 2016. The increase was due to a 12.0% increase in the average cost of fuel per KWH generated primarily due to a 16.2% higher cost of natural gas.

~~Purchased Power~~

~~Energy purchases will vary depending on the market prices of wholesale energy as compared to the cost~~dismissal 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. Energy purchases from affiliates are made in accordance with the IIC, as approved by the FERC.

~~Other Operations and Maintenance Expenses~~

Third Quarter 2017 vs. Third Quarter 2016 Year-to-Date 2017 vs. Year-to-Date 2016
(change in millions) (% change) (change in millions) (% change)
$(8) (10.8) $(5) (2.4)

In the third quarter 2017, other operations and maintenance expenses were $66 million compared to $74 million for the corresponding period in 2016. The decrease was primarily due to a $5 million decrease in transmission and distribution expenses related to overhead line maintenance and a $4 million decrease related to decreases in employee compensation and benefits and corporate advertising.

For year-to-date 2017, other operations and maintenance expenses were $206 million compared to $211 million for the corresponding period in 2016. The decrease was primarily due to a $6 million decrease in transmission and distribution expenses related to overhead line maintenance and a $5 million decrease related to decreases in employee compensation and benefits and corporate advertising, partially offset by a $5 million increase associated with the Kemper IGCC in-service assets.

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~~See FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined Cycle~~ – ~~Rate Recovery of Kemper IGCC Costs~~ – ~~2015 Rate Case" herein for additional information.~~

~~Depreciation and Amortization~~

Third Quarter 2017 vs. Third Quarter 2016 Year-to-Date 2017 vs. Year-to-Date 2016
(change in millions) (% change) (change in millions) (% change)
$9 30.0 $6 5.3

In the third quarter 2017, depreciation and amortization was $39 million compared to $30 million for the corresponding period in 2016. The increase was primarily related to $6 million in amortization and deferrals associated with regulatory assets and liabilities and $3 million in depreciation related to additional plant in service.

~~For year-to-date 2017~~, depreciation and amortization was $120 million compared to $114 million for the corresponding period in 2016. The increase was primarily related to $5 million in depreciation related to additional plant in service.

~~See Note 1 to the financial statements of Mississippi Power under "Depreciation, Depletion, and Amortization" in Item 8 of the Form 10-K.~~

~~Taxes Other Than Income Taxes~~

Third Quarter 2017 vs. Third Quarter 2016 Year-to-Date 2017 vs. Year-to-Date 2016
(change in millions) (% change) (change in millions) (% change)
$(6) (19.4) $(4) (4.9)

In the third quarter 2017, taxes other than income taxes were $25 million compared to $31 million for the corresponding period in 2016. For year-to-date 2017, taxes other than income taxes were $77 million compared to $81 million for the corresponding period in 2016. These decreases were primarily due to a decrease in franchise taxes of $5 million and $4 million for the third quarter and year-to-date 2017, respectively, as well as a decrease in payroll taxes of $1 million for the third quarter 2017.

~~Estimated Loss on Kemper IGCC~~

Third Quarter 2017 vs. Third Quarter 2016 Year-to-Date 2017 vs. Year-to-Date 2016
(change in millions) (% change) (change in millions) (% change)
$(54) (61.4) $2,933 N/M

~~N/M - Not meaningful~~

Estimated probable losses on the Kemper IGCC of $34 million and $3.2 billion were recorded in the third quarter and year-to-date 2017, respectively, compared to $88 million and $222 million in the third quarter and year-to-date 2016, respectively. While the ultimate disposition of the gasification portions of the Kemper IGCC remains subject to the Mississippi PSC's jurisdiction, including the potential resolution of the matters addressed in the Kemper IGCC Settlement Docket, given the Mississippi PSC's stated intent regarding no further rate increase for the Kemper County energy facility, cost recovery of the gasification portions is no longer probable. As a result, Mississippi Power suspended the project on June 28, 2017, and recorded $34 million and $2.9 billion of additional charges to income in the third quarter and year-to-date 2017, respectively, for the estimated costs associated with the gasification portions of the plant and lignite mine.

Prior to the project's suspension, Mississippi Power recorded losses for revisions of estimated costs expected to be incurred on construction of the Kemper IGCC in excess of the $2.88 billion cost cap established byclaims against the Mississippi PSC ~~net~~defendants but reversing the dismissal of the ~~Initial DOE Grants~~claims against Mississippi Power. In May 2022, the U.S. Court of Appeals for the Fifth Circuit denied a petition by Mississippi Power for a rehearing en banc and ~~excluding~~remanded the ~~Cost Cap Exceptions.~~

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~~FINANCIAL CONDITION AND RESULTS OF OPERATIONS~~

~~See Note 3~~case to the ~~financial statements~~U.S. District Court for the Southern District of Mississippi for further proceedings. In June 2022, Mississippi Power ~~under "Integrated Coal Gasification Combined Cycle" in Item 8~~filed with the trial court a motion to dismiss the complaint with prejudice, which was granted on March 15, 2023. On March 28, 2023, the plaintiffs filed a notice of appeal with the ~~Form 10-K and FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined Cycle" and Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" herein for additional information.~~

~~Allowance for Equity Funds Used During Construction~~

Third Quarter 2017 vs. Third Quarter 2016 Year-to-Date 2017 vs. Year-to-Date 2016
(change in millions) (% change) (change in millions) (% change)
$(30) (96.8) $(18) (20.0)

~~In the third quarter 2017, AFUDC equity was $1 million compared to $31 million~~U.S. Court of Appeals for the ~~corresponding period~~Fifth Circuit. An adverse outcome in ~~2016. For year-to-date 2017, AFUDC equity was $72 million compared to $90 million for the corresponding period in 2016. The decreases resulted from the Kemper IGCC project suspension in June 2017.~~

~~See Note 3 to the financial statements of Mississippi Power under "FERC Matters" and "Integrated Coal Gasification Combined Cycle" in Item 8 of the Form 10-K and FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined Cycle" and Note (B) to the Condensed Financial Statements under "FERC Matters" and "Integrated Coal Gasification Combined Cycle" herein for additional information regarding the Kemper IGCC.~~

~~Interest Expense, Net of Amounts Capitalized~~

Third Quarter 2017 vs. Third Quarter 2016 Year-to-Date 2017 vs. Year-to-Date 2016
(change in millions) (% change) (change in millions) (% change)
$(28) N/M $(23) 50.0

~~N/M - Not meaningful~~

In the third quarter 2017, interest expense, net of amounts capitalized was $(13) million compared to $15 million for the corresponding period in 2016. The decrease was primarily associated with a $33 million net reduction in interest following a settlement with the IRS related to research and experimental (R&E) deductions. Also contributing to the decrease was a $4 million decrease in interest related to long-term debt. These decreases were partially offset by an $11 million reduction in interest capitalized following suspension of the Kemper IGCC construction.

For year-to-date 2017, interest expense, net of amounts capitalized was $23 million compared to $46 million for the corresponding period in 2016. The decrease was primarily associated with a $33 million net reduction in interest following a settlement with the IRS related to R&E deductions. Also contributing to the decrease was a $2 million decrease in interest related to short-term debt and a $1 million decrease in interest related to long-term debt. These decreases were partially offset by an $8 million reduction in interest capitalized following suspension of the Kemper IGCC construction and the amortization of $7 million in interest deferrals in accordance with the In-Service Asset Rate Order.

~~Income Taxes (Benefit)~~

Third Quarter 2017 vs. Third Quarter 2016 Year-to-Date 2017 vs. Year-to-Date 2016
(change in millions) (% change) (change in millions) (% change)
$26 N/M $(856) N/M

~~N/M - Not meaningful~~

In the third quarter 2017, income taxes were $24 million compared to an income tax benefit of $2 million for the corresponding period in 2016. For year-to-date 2017, income tax benefit was $885 million compared to $29 million

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~~FINANCIAL CONDITION AND RESULTS OF OPERATIONS~~

for the corresponding period in 2016. The changes were primarily due to the estimated probable losses on the Kemper IGCC, net of the non-deductible AFUDC equity portion and the related state valuation allowances.

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

~~FUTURE EARNINGS POTENTIAL~~

The results of operations discussed above are not necessarily indicative of Mississippi Power's future earnings potential. The level of Mississippi Power's future earnings depends on numerous factors that affect the opportunities, challenges, and risks of Mississippi Power's business of providing electric service. These factors include Mississippi Power's ability to recover its prudently-incurred costs, including those related to the remainder of the Kemper County energy facility not included in current rates, in a timely manner during a time of increasing costs and its ability to prevail against legal challenges associated with the Kemper County energy facility. Future earnings will be driven primarily by customer growth. Earnings will also depend upon maintaining and growing sales, considering, among other things, the adoption and/or penetration rates of increasingly energy-efficient technologies and increasing volumes of electronic commerce transactions. Earnings are subject to a variety of other factors. These factors include weather, competition, developing new and maintaining existing energy contracts and associated load requirements with other utilities and other wholesale customers, energy conservation practiced by customers, the use of alternative energy sources by customers, the price of electricity, the price elasticity of demand, and the rate of economic growth or decline in Mississippi Power's service territory. Demand for electricity is primarily driven by the pace of economic growth that may be affected by changes in regional and global economic conditions, which may impact future earnings.

On October 4, 2017, Mississippi Power executed agreements with its largest retail customer, Chevron Products Company (Chevron), to continue providing retail service to the Chevron refinery in Pascagoula, Mississippi through 2038, subject to the approval of the Mississippi PSC. The new agreements are not expected tothis proceeding could have a material impact on Mississippi Power's ~~earnings; however, the co-generation assets located at the refinery are expected to be accounted for as a sales-type lease in accordance~~financial statements.

Southern Power

In July 2021, Southern Power and certain of its subsidiaries filed an arbitration demand with the ~~new lease accounting rules that become effective~~American Arbitration Association against First Solar for defective design of actuators on trackers and inverters installed by First Solar under the engineering, procurement, and construction agreements associated with five solar projects owned by Southern Power and partners and managed by Southern Power. In February 2023, arbitration hearings concluded. In July 2023, an interim award of approximately $36 million was entered in ~~2019. These assets~~favor of Southern Power and was subsequently received in September 2023. The interim award included $18 million representing recovery of losses associated with replacement costs, penalty payments, and lost revenues previously incurred. This recovery is reflected in Southern Power's third quarter and year-to-date 2023 statements of income as an $11 million reduction to other operations and maintenance expense and a $7 million increase in other revenues, with $6 million allocated through noncontrolling interests to Southern Power's partners. The remaining $18 million in award proceeds received in excess of the losses incurred is recognized on the balance sheet at September 30, 2023 as restricted cash and a liability to fund future replacement costs. The parties are ~~also subject to~~awaiting issuance of a ~~security interest granted to Chevron. See FINANCIAL CONDITION AND LIQUIDITY – "Credit Rating Risk" herein for additional information.~~final award. The ultimate outcome of this matter cannot be determined at this time.

~~Current proposals related~~

Environmental Remediation

The Southern Company system must comply with environmental laws and regulations governing the handling and disposal of waste and releases of hazardous substances. Under these various laws and regulations, the Southern Company system could incur substantial costs to clean up affected sites. The traditional electric operating companies and the natural gas distribution utilities in Illinois and Georgia have each received authority from their respective state PSCs or other applicable state regulatory agencies to recover approved environmental remediation costs through regulatory mechanisms. These regulatory mechanisms are adjusted annually or as necessary within limits approved by the state PSCs or other applicable state regulatory agencies.

Georgia Power's environmental remediation liability was $14 million and $15 million at September 30, 2023 and December 31, 2022, respectively. Georgia Power has been designated or identified as a potentially responsible party at sites governed by the Georgia Hazardous Site Response Act and/or by the federal Comprehensive Environmental Response, Compensation, and Liability Act, and assessment and potential ~~federal tax reform legislation are primarily focused on reducing the corporate income tax rate, allowing 100%~~cleanup of ~~capital expenditures to be deducted,~~such sites is expected.

Southern Company Gas' environmental remediation liability was $234 million and ~~eliminating the interest deduction. The ultimate impact of any tax reform proposals is dependent~~$256 million at September 30, 2023 and December 31, 2022, respectively, based on the ~~final form~~estimated cost of ~~any legislation enacted~~environmental investigation and ~~the related transition rules and cannot be determined at this time, but could have a material impact on Mississippi Power's financial statements.~~

For additional information relating to these issues, see RISK FACTORS in Item 1A and MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL of Mississippi Power in Item 7 of the Form 10-K and Note (B) to the Condensed Financial Statements under "~~Integrated Coal Gasification Combined Cycle" herein for additional information.~~

~~Environmental Matters~~

Compliance costs related to federal and state environmental statutes and regulations could affect earnings if such costs cannot continue to be fully recovered in rates on a timely basis or through long-term wholesale agreements. Environmental compliance spending over the next several years may differ materially from the amounts estimated. The timing, specific requirements, and estimated costs could change as environmental statutes and regulations are adopted or modified, as compliance plans are revised or updated, and as legal challenges to rules are completed. Further, higher costs that are recovered through regulated rates could contribute to reduced demand for electricity, which could negatively affect results of operations, cash flows, and financial condition. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters" of Mississippi

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~~FINANCIAL CONDITION AND RESULTS OF OPERATIONS~~

~~Power in Item 7 and Note 3 to the financial statements of Mississippi Power under "Environmental Matters" in Item 8 of the Form 10-K for additional information.~~

~~Environmental Statutes and Regulations~~

~~Water Quality~~

~~See MANAGEMENT'S DISCUSSION AND ANALYSIS~~ – ~~FUTURE EARNINGS POTENTIAL~~ – ~~"Environmental Matters~~ – ~~Environmental Statutes and Regulations~~ – Water Quality" of Mississippi Power in Item 7 of the Form 10-K for additional information regarding the final effluent guidelines rule and the final rule revising the regulatory definition of waters of the U.S. for all Clean Water Act (CWA) programs.

On April 25, 2017, the EPA published a notice announcing it would reconsider the effluent guidelines rule, which had been finalized in November 2015. On September 18, 2017, the EPA published a final rule establishing a stay of the compliance deadlines for certain effluent limitations and pretreatment standards under the rule.

On June 27, 2017, the EPA and the U.S. Army Corps of Engineers proposed to rescind the final rule that revised the regulatory definition of waters of the U.S. for all CWA programs. The final rule has been stayed since October 2015 by the U.S. Court of Appeals for the Sixth Circuit.remediation associated with known former manufactured gas plant operating sites.

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

~~Global Climate Issues~~

~~See MANAGEMENT'S DISCUSSION AND ANALYSIS~~ – ~~FUTURE EARNINGS POTENTIAL~~ – ~~"Environmental Matters~~ – ~~Global Climate Issues" of Mississippi Power in Item 7~~time; however, as a result of the ~~Form 10-K~~regulatory treatment for ~~additional information.~~

~~On March 28, 2017,~~environmental remediation expenses described above, the U.S. President signed an executive order directing agencies to review actions that potentially burden the development or use of domestically produced energy resources. The executive order specifically directs the EPA to review the Clean Power Plan and final greenhouse gas emission standards for new, modified, and reconstructed electric generating units and, if appropriate, take action to suspend, revise, or rescind those rules. On October 16, 2017, the EPA published a proposed rule to repeal the Clean Power Plan. The EPA has not determined whether or when it will promulgate a replacement rule.

~~On June 1, 2017, the U.S. President announced that the United States will withdraw from the non-binding Paris Agreement and begin renegotiation of its terms.~~

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

~~FERC Matters~~

~~Municipal and Rural Associations Tariff~~

~~See Note 3~~is not expected to have a material impact on the financial statements of ~~Mississippi Power under "FERC Matters" in Item 8 of~~ the Form 10-K for additional information regarding a settlement agreement entered into by Mississippi Power regarding the establishment of a regulatory asset for Kemper IGCC-related costs. See Note 3 to the financial statements of Mississippi Power under "Integrated Coal Gasification Combined Cycle" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "~~Integrated Coal Gasification Combined Cycle" herein for information regarding the Kemper IGCC.~~

In March 2016, Mississippi Power reached a settlement agreement with its wholesale customers, which was subsequently approved by the FERC, for an increase in wholesale base revenues under the MRA cost-based electric tariff, primarily as a result of placing scrubbers for Plant Daniel Units 1 and 2 in service in 2015. The settlement agreement became effective for services rendered beginning May 1, 2016, resulting in an estimated annual revenue increase of $7 million under the MRA cost-based electric tariff. Additionally, under the settlement agreement, the tariff customers agreed to similar regulatory treatment for MRA tariff ratemaking as the treatment approved for retail ratemaking under the In-Service Asset Rate Order. This regulatory treatment primarily includes (i) recovery of the Kemper IGCC assets currently operational and providing service to customers and other related costs, (ii)

applicable Registrants.

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~~MANAGEMENT'S DISCUSSION AND ANALYSIS OF~~

~~FINANCIAL CONDITION AND RESULTS OF OPERATIONS~~

amortization of the Kemper IGCC-related regulatory assets included in rates under the settlement agreement over the 36 months ending April 30, 2019, (iii) Kemper IGCC-related expenses included in rates under the settlement agreement no longer being deferred and chargedIndex to expense, and (iv) removing all of the Kemper IGCC CWIP from rate base with a corresponding increase in accrual of AFUDC. The additional resulting AFUDC totaled approximately $22 million through the suspension of Kemper IGCC start-up activities.

~~See Note (B) to the Condensed~~ Financial Statements ~~under "Integrated Coal Gasification Combined Cycle" herein for additional information.~~

~~Fuel Cost Recovery~~

Mississippi Power has a wholesale MRA and a Market Based (MB) fuel cost recovery factor. At September 30, 2017, the amount of over-recovered wholesale MRA fuel costs included in the balance sheets was $3 million compared to $13 million at December 31, 2016. Over-recovered wholesale MB fuel costs included in the balance sheets were immaterial at September 30, 2017 and December 31, 2016.NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)

~~See Note 3 to the financial statements of Mississippi Power under "FERC Matters – Fuel Cost Recovery" in Item 8 of the Form 10-K for additional information.~~

~~Market-Based Rate Authority~~

~~See MANAGEMENT'S DISCUSSION AND ANALYSIS~~ – ~~FUTURE EARNINGS POTENTIAL~~ – ~~"FERC Matters~~ – Market-Based Rate Authority" of Mississippi Power in Item 7 of the Form 10-K for additional information regarding the traditional electric operating companies' and Southern Power's market power proceeding and amendment to their market-rate tariff.

On May 17, 2017, the FERC accepted the traditional electric operating companies' (including Mississippi Power's) and Southern Power's compliance filing accepting the terms of the FERC's February 2, 2017 order regarding an amendment by the traditional electric operating companies (including Mississippi Power) and Southern Power to their market-based rate tariff. While the FERC's order references the traditional electric operating companies' (including Mississippi Power's) and Southern Power's market power proceeding related to their 2014 triennial updated market power analysis, that proceeding remains a separate, ongoing matter.

On October 25, 2017, the FERC issued an order in response to the traditional electric operating companies' (including Mississippi Power's) and Southern Power's June 30, 2017 triennial updated market power analysis. The FERC directed the traditional electric operating companies (including Mississippi Power) and Southern Power to show cause within 60 days why market-based rate authority should not be revoked in certain areas adjacent to the area presently under mitigation in accordance with the February 2, 2017 order, or to provide a mitigation plan to further address market power concerns. The traditional electric operating companies (including Mississippi Power) and Southern Power expect to make a filing within the specified 60 days responding to the FERC's order.

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

~~Cooperative Energy Shared Service Agreement and PPA~~

Mississippi Power provides electricity to a municipality and various rural electric cooperative associations located in southeastern Mississippi, including Cooperative Energy. These generation services are provided under long-term contracts subject to a cost-based, FERC regulated MRA electric tariff and a long-term market-based wholesale contract.

On September 18, 2017, Mississippi Power and Cooperative Energy executed a Shared Service Agreement (SSA), as part of the MRA tariff, under which Mississippi Power and Cooperative Energy will share in providing electricity to all Cooperative Energy delivery points, in lieu of the current arrangement under which each delivery point is specifically assigned to either entity. The SSA becomes effective on January 1, 2018, subject to the FERC's acceptance, and may be cancelled by Cooperative Energy with 10 years notice after December 31, 2021.

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The SSA provides Cooperative Energy the option to decrease its use of Mississippi Power's generation services under the MRA tariff, subject to annual and cumulative caps and a one-year notice requirement. In the event Cooperative Energy elects to reduce these services, the related reduction in Mississippi Power's revenues is not expected to be significant through 2020.

In 2008, Mississippi Power entered into a 10-year Power Supply Agreement (PSA) with Cooperative Energy for approximately 152 MWs, which became effective in 2011. Following certain plant retirements, the current PSA capacity is 86 MWs. On September 28, 2017, Mississippi Power and Cooperative Energy executed an amendment to the PSA effective October 1, 2017, increasing the capacity to 286 MWs under the PSA.

Cooperative Energy also has a 10-year Network Integration Transmission Service Agreement (NITSA) with SCS for transmission service to certain delivery points on the Mississippi Power transmission system that became effective in 2011. As a result of the PSA amendments, Cooperative Energy and SCS are amending the terms of the NITSA to provide for the purchase of incremental transmission capacity for service beginning April 1, 2018. This NITSA amendment remains subject to execution and acceptance by the FERC.

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

~~Retail Regulatory Matters~~

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 3 to the financial statements of Mississippi Power under "Retail Regulatory Matters" and "Integrated Coal Gasification Combined Cycle" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "~~Regulatory Matters~~ – ~~Mississippi Power" and "Integrated Coal Gasification Combined Cycle" herein for additional information.~~

~~Renewables~~

Mississippi Power placed in service three solar projects in January, June, and October 2017. Mississippi Power may retire the renewable energy credits (REC) generated on behalf of its customers or sell the RECs, separately or bundled with energy, to third parties.

On August 17, 2017, the Mississippi PSC approved Mississippi Power's CPCN for the construction, operation, and maintenance of a 52.5-MW solar energy generating facility, which is expected to be placed in service by January 2020. The ultimate outcome of this matter cannot be determined at this time.

Performance Evaluation Plan

On ~~March 15, 2017,~~June 13, 2023, the Mississippi PSC approved Mississippi Power's annual retail PEP filing for 2023 indicating no change in retail rates.

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

Ad Valorem Tax Adjustment

On May 2, 2023, the Mississippi PSC approved Mississippi Power's annual ad valorem tax adjustment filing for 2023, resulting in a $7 million annual decrease in revenues effective with the first billing cycle of June 2023.

Mississippi Power's operating revenues are adjusted for differences in actual recoverable ad valorem taxes 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.

Environmental Compliance Overview Plan

On April 4, 2023, the Mississippi PSC approved Mississippi Power's annual ECO Plan filing for 2023, resulting in a $3 million annual increase in revenues effective with the first billing cycle of May 2023.

System Restoration Rider

On April 4, 2023, the Mississippi PSC approved Mississippi Power's annual SRR filing, which indicated no change in retail rates. Mississippi Power's minimum annual SRR accrual was increased from $8 million to $12 million.

Municipal and Rural Associations Tariff

On October 27, 2023, the FERC approved a settlement agreement filed by Mississippi Power ~~submitted its annual PEP lookback filing for 2016, which reflected the need~~and Cooperative Energy on July 31, 2023 related to Mississippi Power's July 2022 request for a $5$23 million ~~surcharge~~increase in annual wholesale base revenues under the MRA tariff. The settlement agreement provides for a $16 million increase in annual wholesale base revenues, effective September 14, 2022, and a refund to ~~be recovered from customers. The filing has been suspended~~customers of approximately $6 million primarily related to the difference between the approved rates and interim rates.

Integrated Resource Plans

In October 2023, Mississippi Power signed an affiliate PPA with Georgia Power for ~~review by~~750 MWs of capacity and energy starting January 2024 through December 2028. In order to fulfill this agreement and serve the interests of customers, Mississippi ~~PSC.~~

~~On November 15, 2017,~~Power will need to delay the anticipated retirement of certain electric generating units, as identified in its 2021 IRP. Mississippi Power is expected to ~~make~~file its ~~annual PEP filing~~next IRP in April 2024 in accordance with the rules and orders of the Mississippi PSC.

Southern Company Gas

Infrastructure Replacement Programs and Capital Projects

Capital expenditures incurred under specific infrastructure replacement programs and capital projects during the first nine months of 2023 were as follows:


Utility	Program	Nine Months Ended September 30, 2023
		(in millions)
Nicor Gas	Investing in Illinois	$	320
Virginia Natural Gas	SAVE	56
Atlanta Gas Light	System Reinforcement Rider	84
Chattanooga Gas	Pipeline Replacement Program	7
Total		$	467

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(UNAUDITED)

Nicor Gas

On June 15, 2023, the Illinois Commission concluded its review of the Qualifying Infrastructure Plant (QIP) capital investments by Nicor Gas for ~~2018. Retail rate adjustments~~calendar year 2019 under ~~PEP are limited~~the QIP Rider, also referred to 4%as Investing in Illinois, program. The Illinois Commission disallowed $32 million of ~~annual retail revenue~~the $415 million of capital investments commissioned in 2019, together with the related return on investment. Nicor Gas recorded a pre-tax charge to income in the second quarter 2023 of $38 million ($28 million after tax) associated with the disallowance of capital investments. The disallowance is reflected on the statement of income as an $8 million reduction to revenues and ~~are subject to Mississippi PSC approval.~~

a $30 million increase in operating expenses. On August 3, 2023, the Illinois Commission denied a rehearing request filed by Nicor Gas. On August 24, 2023, Nicor Gas filed a notice of appeal with the Illinois Appellate Court. Nicor Gas defends these investments in infrastructure as prudently incurred. The Illinois Commission has not yet conducted its review for calendar years 2020 through 2022 or the nine months ended September 30, 2023. Any further disallowance by the Illinois Commission could be material. The ultimate outcome of these matters cannot be determined at this time.

~~Energy Efficiency~~Rate Proceedings

Atlanta Gas Light

On July ~~6, 2017, the Mississippi PSC issued an order approving Mississippi Power's Energy Efficiency Cost Rider compliance filing, which increased~~14, 2023, Atlanta Gas Light filed its annual ~~retail revenues by approximately $2 million effective~~GRAM update with the ~~first billing cycle for August 2017.~~

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~~Environmental Compliance Overview Plan~~

~~On May 4, 2017,~~$53 million based on the Mississippi PSC approved Mississippi Power's ECO Plan filing for 2017, which requested the maximum 2% annual increase in revenues, approximately $18 million, primarily related to the Plant Daniel Unitsprojected 12-month period beginning January 1, ~~and 2 scrubbers placed in service in 2015. The rates became effective with the first billing cycle for June 2017. Approximately $26 million of related revenue requirements in excess~~2024. Resolution of the ~~2% maximum was deferred for inclusion in the 2018 filing.~~

~~Fuel Cost Recovery~~

~~At September 30, 2017, the amount of over-recovered retail fuel costs included on the condensed balance sheet was $2 million compared to $37 million at~~GRAM filing is expected by December 31, ~~2016.~~

~~On November 15, 2017, Mississippi Power is expected to file its annual rate adjustment under the retail fuel cost recovery clause.~~2023, with new rates effective January 1, 2024. The ultimate outcome of this matter cannot be determined at this time.

~~Ad Valorem Tax Adjustment~~Virginia Natural Gas

On ~~July 6, 2017,~~August 28, 2023, the ~~Mississippi PSC~~Virginia Commission approved ~~Mississippi Power's~~a stipulation agreement related to Virginia Natural Gas' August 2022 general base rate case filing. The approved agreement provides for a $48 million increase in annual ~~ad valorem tax adjustment factor filing for 2017, which included~~base rate revenues, including the recovery of investments under the SAVE program, an ~~annual rate~~ROE of 9.70%, and an equity ratio of 49.06%. Interim rates became effective January 1, 2023, subject to refund, based on Virginia Natural Gas' original requested increase of ~~0.85%, or $8 million in annual retail revenues, primarily due~~approximately $69 million. Refunds to ~~increased assessments.~~

~~Provision for Property Damage~~

On October 8, 2017, Hurricane Nate hit the Gulf Coast of Mississippi causing minor damage to Mississippi Power's distribution infrastructure. Preliminary storm damage repair costs have been estimated to be immaterial. These costs may be chargedcustomers related to the ~~retail property damage reserve~~difference between the approved rates effective September 1, 2023 and ~~addressed~~the interim rates will be completed later in ~~a subsequent System Restoration Rider rate filing. The ultimate outcome of this matter cannot be determined at this time.~~the fourth quarter 2023.

~~Integrated Coal Gasification Combined Cycle~~(C) CONTINGENCIES

See Note 3 to the financial statements ~~of Mississippi Power under "Integrated Coal Gasification Combined Cycle"~~ in Item 8 of the Form 10-K for information ~~regarding Mississippi Power's construction of the Kemper IGCC.~~relating to various lawsuits and other contingencies.

~~Kemper IGCC Overview~~

The Kemper IGCC 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 IGCC. The mine, operated by North American Coal Corporation, started commercial operation in 2013. In connection with the Kemper IGCC, Mississippi Power constructed approximately 61 miles of CO₂ ~~pipeline infrastructure for the transport of captured CO~~₂ ~~for use in enhanced oil recovery.~~

~~Kemper IGCC Schedule and Cost Estimate~~

In 2012, the Mississippi PSC issued the 2012 MPSC CPCN Order, a detailed order confirming the CPCN originally approved by the Mississippi PSC in 2010 authorizing the acquisition, construction, and operation of the Kemper IGCC. The certificated cost estimate of the Kemper IGCC included in the 2012 MPSC CPCN Order was $2.4 billion, net of $245 million of Initial DOE Grants and excluding the cost of the lignite mine and equipment, the cost of the CO₂ pipeline facilities, and AFUDC related to the Kemper IGCC. The 2012 MPSC CPCN Order approved a construction cost cap of up to $2.88 billion, with recovery of prudently-incurred costs subject to approval by the Mississippi PSC. The Kemper IGCC was originally projected to be placed in service in May 2014. Mississippi Power placed the combined cycle and the associated common facilities portion of the Kemper IGCC in service in August 2014.General Litigation Matters

The initial production of syngas began on July 14, 2016 for gasifier "B" and on September 13, 2016 for gasifier "A." Mississippi Power achieved integrated operation of both gasifiers on January 29, 2017, including the production of electricity from syngas in both combustion turbines. During testing, the plant produced and captured

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CO₂, and produced sulfuric acid and ammonia, each of acceptable quality under the related off-take agreements. However, Mississippi Power experienced numerous challenges during the extended start-up process to achieve integrated operation of the gasifiers on a sustained basis. In May 2017, after achieving these milestones, Mississippi Power determined that a critical system component, the syngas coolers, would need replacement sooner than originally planned, which would require significant lead time and significant cost. In addition, the long-term natural gas price forecast has decreased significantly and the estimated cost of operating and maintaining the facility during the first five full years of operations has increased significantly since certification.

On June 21, 2017, the Mississippi PSC stated its intent to issue an order (which occurred on July 6, 2017) directing Mississippi Power to pursue a settlement under which the Kemper County energy facility would be operated as a natural gas plant, rather than an IGCC plant, and address all issues associated with the Kemper IGCC. On June 28, 2017, Mississippi Power notified the Mississippi PSC that it would begin a process to suspend operations and start-up activities on the gasifier portion of the Kemper IGCC, given the uncertainty as to the future of the gasifier portion of the Kemper IGCC. Mississippi Power expects to continue to operate the combined cycle portion of the Kemper IGCC as it has done since August 2014.

Mississippi Power's Kemper IGCC 2010 project estimate totaled $2.97 billion, which included capped costs of $2.4 billion. At the time of project suspension in June 2017, the total cost estimate for the Kemper IGCC was approximately $7.38 billion, including approximately $5.95 billion of costs subject to the construction cost cap, and was net of the $137 million in Additional DOE Grants.

Mississippi Power recorded pre-tax charges to income for revisions to the cost estimate above the cost cap for the Kemper IGCC of $196 million ($121 million after tax) in the second quarter through May 31, 2017 and a total of $305 million ($188 million after tax) for year-to-date through May 31, 2017. In the aggregate, Mississippi Power incurred charges of $3.07 billion ($1.89 billion after tax) as a result of changes in the cost estimate above the cost cap for the Kemper IGCC through May 31, 2017. The May 31, 2017 cost estimate included approximately $175 million of estimated costs to be incurred beyond the then-estimated in-service date of June 30, 2017 that were expected to be subject to the $2.88 billion cost cap.

While the ultimate disposition of the gasification portions of the Kemper IGCC remains subject to the Mississippi PSC's jurisdiction, including the potential resolution of the matters addressed in the Kemper IGCC Settlement Docket, given the Mississippi PSC's stated intent regarding no further rate increase for the Kemper County energy facility, cost recovery of the gasification portions is 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 includes estimated costs associated with the gasification portions of the plant and lignite mine. In the third quarter 2017, Mississippi Power recorded an additional charge of $34 million ($21 million after tax) for ongoing project costs during suspension, which includes estimated gasifier-related costs through December 31, 2017 to reflect the Mississippi PSC's schedule for the Kemper IGCC Settlement Docket, as well as mine-related costs and other suspension costs through September 30, 2017. Any extension of the suspension period beyond December 31, 2017 is currently estimated to result in additional suspension costs of approximately $5 million per month. In the event the gasification portions of the projectRegistrants are ultimately canceled, additional pre-tax costs, which include mine and Kemper IGCC plant closure costs and contract termination costs, currently estimated at approximately $100 million to $200 million are expected to be incurred. In the aggregate, Mississippi Power recorded total pre-tax charges to income for the estimated probable losses on the Kemper IGCC totaling $34 million ($21 million after tax) for the third quarter 2017 and $3.2 billion ($2.2 billion after tax) for the nine months ended September 30, 2017.

As of September 30, 2017, Mississippi Power has recorded a total of approximately $1.3 billion in costs associated with the combined cycle portion of the Kemper IGCC. The Kemper combined cycle balances as presented in the condensed balance sheet at September 30, 2017 include $1.1 billion in property, plant, and equipment, net of $80 million in accumulated depreciation; $15 million in materials and supplies; $10 million in other deferred charges and assets; and $113 million in regulatory assets, net of accumulated amortization of $63 million, of which $21 million is included in other regulatory assets, current and $92 million in other regulatory assets, deferred.

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~~Rate Recovery of Kemper IGCC Costs~~

Given the variety of potential scenarios and the uncertainty of the outcome of future regulatory proceedings with the Mississippi PSC (and any subsequent related legal challenges), the ultimate outcome of the rate recovery matters discussed herein, including the resolution of legal challenges, cannot now be determined but could result in further material charges that could have a material impact on Mississippi Power's results of operations, financial condition, and liquidity.

~~Kemper IGCC Settlement Docket~~

On June 21, 2017, the Mississippi PSC stated its intent to issue an order (which occurred on July 6, 2017) directing Mississippi Power to pursue a settlement under which the Kemper County energy facility would be operated as a natural gas plant, rather than an IGCC plant, and address all issues associated with the Kemper IGCC. The Kemper Settlement Order established the Kemper IGCC Settlement Docket. The Mississippi PSC requested any such proposed settlement agreement reflect: (i) at a minimum, no rate increase to Mississippi Power customers (with a rate reduction focused on residential customers encouraged); (ii) removal of all cost risk to customers associated with the Kemper IGCC gasifier and related assets; and (iii) modification or amendment of the CPCN for the Kemper IGCC to allow only for ownership and operation of a natural gas facility.

On June 28, 2017, Mississippi Power notified the Mississippi PSC that it would begin a process to suspend operations and start-up activities on the gasifier portion of the Kemper IGCC, given the uncertainty as to the future of the gasifier portion of the Kemper IGCC. Mississippi Power expects to continue to operate the combined cycle portion of the Kemper IGCC as it has done since August 2014. At the time of project suspension, the total cost estimate for the Kemper IGCC was approximately $7.38 billion, including approximately $5.95 billion of costs subject to the construction cost cap, and was net of the $137 million in Additional DOE Grants.

Mississippi Power reached and filed a settlement agreement on August 21, 2017 with certain parties (not including the MPUS), which it believes met the conditions of the Kemper Settlement Order. The settlement agreement provides for an annual revenue requirement of $126 million for Kemper IGCC-related costs, which would (i) be effective January 1, 2018, (ii) represent no rate increase for customers, and (iii) include no recovery for the costs associated with the gasifier portion of the Kemper IGCC in 2018 or at any future date. In addition, under the settlement agreement, the CPCN for the Kemper IGCC would be modified to limit the Kemper County energy facility to natural gas combined cycle operation and Mississippi Power would, in the future, file a reserve margin plan with the Mississippi PSC. The Mississippi PSC issued a scheduling order, as amended on October 5, 2017, noting Mississippi Power and the MPUS had failed to reach a joint stipulation and ordering a full hearing. The Mississippi PSC is expected to rule on an order resolving this matter in January 2018.

While the ultimate disposition of the gasification portions of the Kemper IGCC remains subject to the Mississippi PSC's jurisdiction, including the potential resolution of the matters addressed in the Kemper IGCC Settlement Docket, given the Mississippi PSC's stated intent regarding no further rate increase for the Kemper County energy facility, cost recovery of the gasification portions is 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 includes estimated costs associated with the gasification portions of the plant and lignite mine. In the third quarter 2017, Mississippi Power recorded an additional charge of $34 million ($21 million after tax) for ongoing project costs during suspension, which includes estimated gasifier-related costs through December 31, 2017 to reflect the Mississippi PSC's schedule for the Kemper IGCC Settlement Docket, as well as mine-related costs and other suspension costs through September 30, 2017. Any extension of the suspension period beyond December 31, 2017 is currently estimated to result in additional suspension costs of approximately $5 million per month. In the event the gasification portions of the project are ultimately canceled, additional pre-tax costs, which include mine and Kemper IGCC plant closure costs and contract termination costs, currently estimated at approximately $100 million to $200 million are expected to be incurred.

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$0.8 billion is included in retail and wholesale rates. The $0.5 billion not included in current rates includes costs in excess of the original 2010 estimate for the combined cycle portion of the facility, as well as the 15% that was previously contracted to Cooperative Energy. Mississippi Power has calculated the revenue requirements resulting from these remaining costs, using reasonable assumptions for amortization periods, and expects them to be recovered through rates consistent with the Mississippi PSC's requested settlement conditions. The ultimate outcome will be determined by the Mississippi PSC in the Kemper IGCC Settlement Docket proceedings.

~~Prudence~~

On August 17, 2016, the Mississippi PSC issued an order establishing a discovery docket to manage all filings related to the prudence of the Kemper IGCC. On October 3, 2016, Mississippi Power made a required compliance filing, which included a review and explanation of differences between the Kemper IGCC project estimate set forth in the 2010 CPCN proceedings and the most recent Kemper IGCC project estimate, as well as comparisons of current cost estimates and current expected plant operational parameters to the estimates presented in the 2010 CPCN proceedings for the first five years after the Kemper IGCC was to be placed in service. Compared to amounts presented in the 2010 CPCN proceedings, operations and maintenance expenses have increased an average of $105 million annually and maintenance capital has increased an average of $44 million annually for the first full five years of operations for the Kemper IGCC. Additionally, while the current estimated operational availability estimates reflect ultimate results similar to those presented in the 2010 CPCN proceedings, the ramp up period for the current estimates reflects a lower starting point and a slower escalation rate. On November 17, 2016, Mississippi Power submitted a supplemental filing to the October 3, 2016 compliance filing to present revised non-fuel operations and maintenance expense projections for the first year after the Kemper IGCC was to be placed in service. This supplemental filing included approximately $68 million in additional estimated operations and maintenance costs expected to be required to support the operations of the Kemper IGCC during that period.

Mississippi Power responded to numerous requests for information from interested parties in the discovery docket, which is now complete. Mississippi Power expects the Mississippi PSC to utilize this information in connection with the ultimate resolution of Kemper IGCC cost recovery.

~~Economic Viability Analysis~~

In the fourth quarter 2016, as a part of its Integrated Resource Plan process, the Southern Company system completed its regular annual updated fuel forecast, the 2017 Annual Fuel Forecast. This updated fuel forecast reflected significantly lower long-term estimated costs for natural gas than were previously projected. As a result of the updated long-term natural gas forecast, as well as the revised operating expense projections reflected in the discovery docket filings discussed above, on February 21, 2017, Mississippi Power filed an updated project economic viability analysis of the Kemper IGCC as required under the 2012 MPSC CPCN Order confirming authorization of the Kemper IGCC. The project economic viability analysis measures the life cycle economics of the Kemper IGCC compared to feasible alternatives, natural gas combined cycle generating units, under a variety of scenarios and considering fuel, operating and capital costs, and operating characteristics, as well as federal and state taxes and incentives. The reduction in the projected long-term natural gas prices in the 2017 Annual Fuel Forecast and, to a lesser extent, the increase in the estimated Kemper IGCC operating costs, negatively impact the updated project economic viability analysis.

~~Mississippi Power expects the Mississippi PSC to address this matter in connection with the Kemper IGCC Settlement Docket.~~

~~2015 Rate Case~~

On December 3, 2015, the Mississippi PSC issued the In-Service Asset Rate Order adopting in full the 2015 Stipulation entered into between Mississippi Power and the MPUS regarding the Kemper IGCC assets that were commercially operational and currently providing service to customers (the transmission facilities, combined cycle, natural gas pipeline, and water pipeline) and other related costs. The In-Service Asset Rate Order provided for retail rate recovery of an annual revenue requirement of approximately $126 million, based on Mississippi Power's actual

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average capital structure, with a maximum common equity percentage of 49.733%, a 9.225% return on common equity, and actual embedded interest costs. The In-Service Asset Rate Order also included a prudence finding of all costs in the stipulated revenue requirement calculation for the in-service assets. The stipulated revenue requirement excluded the costs of the Kemper IGCC related to the 15% undivided interest that was previously projected to be purchased by Cooperative Energy but reserved Mississippi Power's right to seek recovery in a future proceeding. See "~~Termination of Proposed Sale of Undivided Interest" herein for additional information.~~

In 2011, the Mississippi PSC authorized Mississippi Power to defer all non-capital Kemper IGCC-related costs to a regulatory asset through the in-service date. In connection with the implementation of the In-Service Asset Order and wholesale rates, Mississippi Power began expensing certain ongoing project costs and certain retail debt carrying costs that previously were deferred and began amortizing certain regulatory assets associated with assets placed in service and consulting and legal fees. The amortization periods for these regulatory assets vary from two years to 10 years as set forth in the In-Service Asset Rate Order and the settlement agreement with wholesale customers. As of September 30, 2017, the balance associated with these regulatory assets was $113 million, of which $21 million is included in current assets. See "~~FERC Matters" herein for additional information related to the 2016 settlement agreement with wholesale customers.~~

The In-Service Asset Rate Order requires Mississippi Power to submit an annual true-up calculation of its actual cost of capital, compared to the stipulated total cost of capital, for the May 31, 2016 and 2017 calculations. At September 30, 2017, Mississippi Power's related regulatory liability totaled approximately $10 million.

As required by the In-Service Asset Rate Order, on June 5, 2017, Mississippi Power made a rate filing requesting to adjust the amortization schedules of the regulatory assets reviewed and determined prudent in the In-Service Asset Order in a manner that would not change customer rates or annual revenues. On June 28, 2017, the Mississippi PSC suspended this filing. On July 6, 2017, the Mississippi PSC issued an order requiring Mississippi Power to establish a regulatory liability account to maintain current rates related to the Kemper IGCC following the July 2017 completion of the amortization period for certain regulatory assets approved in the In-Service Asset Rate Order that would allow for subsequent refund if the Mississippi PSC deems the rates unjust and unreasonable. At September 30, 2017, the related regulatory liability totaled $7 million.

~~2013 MPSC Rate Order~~

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

On February 12, 2015, the Mississippi Supreme Court reversed the 2013 MPSC Rate Order and, on July 7, 2015, the Mississippi PSC ordered that the Mirror CWIP rate be terminated effective July 20, 2015 and required the fourth quarter 2015 refund of the $342 million previously collected, along with associated carrying costs of $29 million.

Because the 2013 MPSC Rate Order did not provide for the inclusion of CWIP in rate base as permitted by the Baseload Act, Mississippi Power continued to record AFUDC on the Kemper IGCC. Between the original May 2014 estimated in-service date and the June 2017 project suspension date, Mississippi Power recorded $494 million of AFUDC on the Kemper IGCC subject to the $2.88 billion cost cap and Cost Cap Exception amounts, of which $460 million related to the gasification portions of the Kemper IGCC.

~~Mississippi Power expects the Mississippi PSC to address this matter in connection with the Kemper IGCC Settlement Docket.~~

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~~Lignite Mine and CO~~₂ ~~Pipeline Facilities~~

~~In conjunction with the Kemper IGCC, Mississippi Power owns the lignite mine and equipment and mineral reserves located around the Kemper IGCC site. The mine started commercial operation in June 2013.~~

In 2010, Mississippi Power executed a 40-year management fee contract with Liberty Fuels Company, LLC (Liberty Fuels), a wholly-owned subsidiary of The North American Coal Corporation, which developed, constructed, and is 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. In addition to the obligation to fund the reclamation activities, Mississippi Power provides working capital support to Liberty Fuels through cash advances for capital purchases, payroll, and other operating expenses. During the suspension period, these costs are approximately $2 million per month and are being recognized in income as incurred. See Note 1 to the financial statements of Mississippi Power under "Asset Retirement Obligations and Other Costs of Removal" and "Variable Interest Entities" in Item 8 of the Form 10-K for additional information.

~~In addition, Mississippi Power constructed the CO~~₂ ~~pipeline for the planned transport of captured CO~~₂ for use in enhanced oil recovery. Mississippi Power entered into agreements with Denbury Onshore (Denbury) and Treetop Midstream Services, LLC (Treetop), pursuant to which Denbury would purchase 70% of the CO₂ ~~captured from the Kemper IGCC and Treetop would purchase 30% of the CO~~₂ captured from the Kemper IGCC. On June 3, 2016, Mississippi Power cancelled its contract with Treetop and amended its contract with Denbury to reflect, among other things, Denbury's agreement to purchase 100% of the CO₂ captured from the Kemper IGCC and an initial contract term of 16 years. Denbury has the right to terminate the contract at any time because Mississippi Power did not place the Kemper IGCC in service by July 1, 2017.

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

~~Termination of Proposed Sale of Undivided Interest~~

In 2010 and as amended in 2012, Mississippi Power and Cooperative Energy (formerly known as SMEPA) entered into an agreement whereby Cooperative Energy agreed to purchase a 15% undivided interest in the Kemper IGCC. On May 20, 2015, Cooperative Energy notified Mississippi Power of its termination of the agreement. Mississippi Power previously received a total of $275 million of deposits from Cooperative Energy that were required to be returned to Cooperative Energy with interest. On June 3, 2015, Southern Company, pursuant to its guarantee obligation, returned approximately $301 million to Cooperative Energy. Subsequently, Mississippi Power issued a promissory note in the aggregate principal amount of approximately $301 million to Southern Company, which was repaid in June 2017.

~~Litigation~~

On April 26, 2016, a complaint against Mississippi Power was filed in Harrison County Circuit Court (Circuit Court) by Biloxi Freezing & Processing Inc., Gulfside Casino Partnership, and John Carlton Dean, which was amended and refiled on July 11, 2016 to include, among other things, Southern Company as a defendant. The individual plaintiff alleges that Mississippi Power and Southern Company violated the Mississippi Unfair Trade Practices Act. All plaintiffs have alleged that Mississippi Power and Southern Company concealed, falsely represented, and failed to fully disclose important facts concerning the cost and schedule of the Kemper IGCC and that these alleged breaches have unjustly enriched Mississippi Power and Southern Company. The plaintiffs seek unspecified actual damages and punitive damages; ask the Circuit Court to appoint a receiver to oversee, operate, manage, and otherwise control all affairs relating to the Kemper IGCC; ask the Circuit Court to revoke any licenses or certificates authorizing Mississippi Power or Southern Company to engage in any business related to the Kemper IGCC in Mississippi; and seek attorney's fees, costs, and interest. The plaintiffs also seek an injunction to prevent any Kemper IGCC costs from being charged to customers through electric rates. On June 23, 2017, the Circuit Court ruled in favor of motions by Southern Company and Mississippi Power and dismissed the case. On July 7, 2017, the plaintiffs filed notice of an appeal.

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~~On June 9, 2016, Treetop, Greenleaf CO~~₂ Solutions, LLC (Greenleaf), Tenrgys, LLC, Tellus Energy, LLC, WCOA, LLC, and Tellus Operating Group filed a complaint against Mississippi Power, Southern Company, and SCS in the state court in Gwinnett County, Georgia. The complaint relates to the cancelled CO₂contract with Treetop and alleges fraudulent misrepresentation, fraudulent concealment, civil conspiracy, and breach of contract on the part of Mississippi Power, Southern Company, and SCS and seeks compensatory damages of $100 million, as well as unspecified punitive damages. Southern Company, Mississippi Power, and SCS moved to compel arbitration pursuant to the terms of the CO₂ contract, which the court granted on May 4, 2017. On June 28, 2017, Treetop, Greenleaf, Tenrgys, LLC, Tellus Energy, LLC, WCOA, LLC, and Tellus Operating Group filed a claim for arbitration requesting $500 million in damages.

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

~~Baseload Act~~

In 2008, the Baseload Act was signed by the Governor of Mississippi. The Baseload Act authorizes, but does not require, the Mississippi PSC to adopt a cost recovery mechanism that includes in retail base rates, prior to and during construction, all or a portion of the prudently-incurred pre-construction and construction costs incurred by a utility in constructing a base load electric generating plant. Prior to the passage of the Baseload Act, such costs would traditionally be recovered only after the plant was placed in service. The Baseload Act also provides for periodic prudence reviews by the Mississippi PSC and prohibits the cancellation of any such generating plant without the approval of the Mississippi PSC. In the event of cancellation of the construction of the plant without approval of the Mississippi PSC, the Baseload Act authorizes the Mississippi PSC to make a public interest determination as to whether and to what extent the utility will be afforded rate recovery or implement credits, refunds, or rebates to customers for costs incurred in connection with such cancelled generating plant.

~~Income Tax Matters~~

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Income Tax Matters" of Mississippi Power in Item 7 of the Form 10-K and Note (G) to the Condensed Financial Statements under "~~Section 174 Research and Experimental Deduction" herein for additional information on bonus depreciation, investment tax credits, and the Section 174 research and experimental deduction.~~

~~Bonus Depreciation~~

All projected tax benefits previously received for bonus depreciation related to the Kemper IGCC were repaid in connection with third quarter 2017 estimated tax payments. If the suspension of the Kemper IGCC start-up activities ultimately results in an abandonment for income tax purposes, the related deduction would be claimed in the year of the abandonment. See Note (B) to the Condensed Financial Statements under "~~Integrated Coal Gasification Combined Cycle" herein and Note (G) to the Condensed Financial Statements herein for additional information. The ultimate outcome of this matter cannot be determined at this time.~~

~~Section 174 Research and Experimental Deduction~~

Southern Company, on behalf of Mississippi Power, has reflected deductions for R&E expenditures related to the Kemper IGCC in its federal income tax calculations since 2013 and filed amended federal income tax returns for 2008 through 2013 to also include such deductions. In December 2016, Southern Company and the IRS reached a proposed settlement, which was approved on September 8, 2017 by the U.S. Congress Joint Committee on Taxation (JCT), resolving a methodology for these deductions. As a result of the JCT approval, Mississippi Power recognized $176 million of previously unrecognized tax benefits and reversed $36 million of associated accrued interest. See Notes (B) and (G) to the Condensed Financial Statements under "~~Integrated Coal Gasification Combined Cycle" and "Section 174 Research and Experimental Deduction," respectively, herein for additional information.~~

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~~Other Matters~~

~~Mississippi Power is~~ involved in various ~~other~~ matters being litigated and regulatory matters that could affect future earnings. In addition, Mississippi Power is subject to certain claims and legal actions arising in the ordinary course of business. Mississippi Power's business activities are subject to extensive governmental regulation related to public health and the environment, such as regulation of air emissions and water discharges. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements, such as air quality and water standards, has occurred throughout the U.S. This litigation has included claims for damages alleged to have been caused by CO₂ ~~and other emissions, CCR, and alleged exposure to hazardous materials, and/or requests for injunctive relief in connection with such~~ matters.

The ultimate outcome of such pending or potential litigation or regulatory matters against each Registrant and any subsidiaries cannot be ~~predicted~~determined at this time; however, for current proceedings not specifically reported ~~in Note (B) to the Condensed Financial Statements~~ herein, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on such Registrant's financial statements.

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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(UNAUDITED)

Southern Company and Mississippi Power

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. In 2018, Mississippi Power filed with the DOE its request for property closeout certification under the contract related to the $387 million of total grants received. In 2020, Mississippi Power and Southern Company executed an agreement with the DOE completing Mississippi Power's ~~financial statements. See Note (B)~~request, which enabled Mississippi Power to proceed with full dismantlement of the ~~Condensed Financial Statements herein for a discussion~~abandoned gasifier-related assets and site restoration activities. In connection with the DOE closeout discussions, in 2019, the Civil Division of ~~various other contingencies, regulatory matters, and other matters being litigated which may affect future earnings potential.~~

~~The SEC is conducting a formal investigation~~the Department of Justice informed Southern Company and Mississippi Power ~~concerning~~of a civil investigation related to the ~~estimated costs and expected in-service date~~DOE grants. On August 4, 2023, the U.S. District Court for the Northern District of ~~the Kemper IGCC.~~Georgia unsealed a civil action in which defendants Southern Company, SCS, and Mississippi Power ~~believe~~are alleged to have violated certain provisions of the ~~investigation is focused primarily on periods subsequent~~False Claims Act by fraudulently inducing the DOE to ~~2010~~disburse funds pursuant to the grants. The federal government declined to intervene in the action. On October 30, 2023, the plaintiff, a former SCS employee, filed an amended complaint, again alleging certain violations of the False Claims Act. The plaintiff seeks to recover all damages incurred personally and on ~~accounting matters, disclosure controls~~behalf of the government caused by the defendants' alleged violations, as well as treble damages and ~~procedures, and internal controls over financial reporting associated with the Kemper IGCC. See ACCOUNTING POLICIES – "Application of Critical Accounting Policies and Estimates" herein for additional information on the Kemper IGCC.~~attorneys' fees, among other relief. The ultimate outcome of this matter cannot be determined at this time; however, an adverse outcome could have a material impact on Southern Company's and Mississippi Power's financial statements.

Alabama Power

In September 2022, Mobile Baykeeper filed a citizen suit in the U.S. District Court for the Southern District of Alabama alleging that Alabama Power's plan to close the Plant Barry ash pond utilizing a closure-in-place methodology violates the Resource Conservation and Recovery Act (RCRA) and regulations governing CCR. Among other relief requested, Mobile Baykeeper seeks a declaratory judgment that the RCRA and regulations governing CCR are being violated, preliminary and injunctive relief to prevent implementation of Alabama Power's closure plan and the development of a closure plan that satisfies regulations governing CCR requirements. On December 19, 2022, Alabama Power filed a motion to dismiss the case. On September 30, 2023, the magistrate judge issued a report and recommendation to deny Alabama Power's motion to dismiss, to which Alabama Power has filed objections.

On January 31, 2023, the EPA issued a Notice of Potential Violations associated with Alabama Power's plan to close the Plant Barry ash pond. Alabama Power has affirmed to the EPA its position that it is in compliance with CCR requirements.

The ultimate outcome of these matters cannot be determined at this time but could have a material impact on Alabama Power's ARO estimates and cash flows. See Note 6 to the financial statements in Item 8 of the Form 10-K for a discussion of Alabama Power's ARO liabilities.

Georgia Power

Municipal Franchise Fees

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 law claims. This case has been ruled upon and appealed numerous times over the last several years. In 2019, the Georgia PSC issued an order that found Georgia Power has appropriately implemented the municipal franchise fee schedule. In March 2021, the Superior Court of Fulton County granted class certification and Georgia Power's motion for summary judgment and the plaintiffs filed a notice of appeal. In April 2021, Georgia Power filed a notice of cross appeal on the issue of class certification. In December 2021, the Georgia Court of Appeals affirmed the Superior Court's ruling that granted summary judgment to Georgia Power and dismissed Georgia Power's cross appeal on the

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Plant Scherer

In July 2020, a group of individual plaintiffs filed a complaint, which was amended in December 2022, in the Superior Court of Fulton County, Georgia against Georgia Power alleging that the construction and operation of Plant Scherer has impacted groundwater and air, resulting in alleged personal injuries and property damage. The plaintiffs seek an unspecified amount of monetary damages including punitive damages, a medical monitoring fund, and injunctive relief. In December 2022, the Superior Court of Fulton County, Georgia granted Georgia Power's motion to transfer the case to the Superior Court of Monroe County, Georgia. On May 9, 2023, the Superior Court of Monroe County, Georgia denied Georgia Power's motion to dismiss the case for lack of subject matter jurisdiction. On July 27, 2023, the Superior Court of Monroe County, Georgia denied the remaining motions to dismiss certain claims and plaintiffs that Georgia Power filed at the outset of the case.

In October 2021, February 2022, and January 2023, a total of eight additional complaints were filed in the Superior Court of Monroe County, Georgia against Georgia Power alleging that releases from Plant Scherer have impacted groundwater and air, resulting in alleged personal injuries and property damage. The plaintiffs sought an unspecified amount of monetary damages including punitive damages. After Georgia Power removed these cases to the U.S. District Court for the Middle District of Georgia, the plaintiffs voluntarily dismissed their complaints without prejudice in November 2022 and January 2023. On May 12, 2023, the plaintiffs in the cases originally filed in October 2021, February 2022, and January 2023 refiled their eight complaints in the Superior Court of Monroe County, Georgia. Also on May 12, 2023, a new complaint was filed in the Superior Court of Monroe County, Georgia against Georgia Power alleging that the construction and operation of Plant Scherer have impacted groundwater and air, resulting in alleged personal injuries. The plaintiff seeks an unspecified amount of monetary damages, including punitive damages. On May 18, 2023, Georgia Power removed all of these cases to the U.S. District Court for the Middle District of Georgia. The plaintiffs are requesting the court remand the cases back to the Superior Court of Monroe County, Georgia.

The amount of possible loss, if any, from these matters cannot be estimated at this time.

Mississippi Power

In 2018, Ray C. Turnage and 10 other individual plaintiffs filed a putative class action complaint against Mississippi Power and the three then-serving members of the Mississippi PSC in the U.S. District Court for the Southern District of Mississippi, which was amended in March 2019 to include four additional plaintiffs. 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 and make claims for gross negligence, reckless conduct, and intentional wrongdoing. 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. The district court dismissed the amended complaint; however, in March 2020, the plaintiffs filed a motion seeking to name the new members of the Mississippi PSC, the Mississippi Development Authority, and Southern Company as additional defendants and add a cause of action against all defendants based on a dormant commerce clause theory under the U.S. Constitution. In July 2020, the plaintiffs filed a motion for leave to file a third amended complaint, which included the same federal claims as the proposed second amended complaint, as well as several additional state law claims based on the allegation that Mississippi Power failed to disclose the annual percentage rate of interest applicable to refunds. In November 2020, the district court denied each of the plaintiffs' pending

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(UNAUDITED)

motions and entered final judgment in favor of Mississippi Power. In January 2021, the district court denied further motions by the plaintiffs to vacate the judgment and to file a revised second amended complaint. In February 2021, the plaintiffs filed a notice of appeal with the U.S. Court of Appeals for the Fifth Circuit. In March 2022, the U.S. Court of Appeals for the Fifth Circuit issued an opinion affirming the dismissal of the claims against the Mississippi PSC defendants but reversing the dismissal of the claims against Mississippi Power. In May 2022, the U.S. Court of Appeals for the Fifth Circuit denied a petition by Mississippi Power for a rehearing en banc and remanded the case to the U.S. District Court for the Southern District of Mississippi for further proceedings. In June 2022, Mississippi Power filed with the trial court a motion to dismiss the complaint with prejudice, which was granted on March 15, 2023. On March 28, 2023, the plaintiffs filed a notice of appeal with the U.S. Court of Appeals for the Fifth Circuit. An adverse outcome in this proceeding could have a material impact on Mississippi Power's financial statements.

Southern Power

In July 2021, Southern Power and certain of its subsidiaries filed an arbitration demand with the American Arbitration Association against First Solar for defective design of actuators on trackers and inverters installed by First Solar under the engineering, procurement, and construction agreements associated with five solar projects owned by Southern Power and partners and managed by Southern Power. In February 2023, arbitration hearings concluded. In July 2023, an interim award of approximately $36 million was entered in favor of Southern Power and was subsequently received in September 2023. The interim award included $18 million representing recovery of losses associated with replacement costs, penalty payments, and lost revenues previously incurred. This recovery is reflected in Southern Power's third quarter and year-to-date 2023 statements of income as an $11 million reduction to other operations and maintenance expense and a $7 million increase in other revenues, with $6 million allocated through noncontrolling interests to Southern Power's partners. The remaining $18 million in award proceeds received in excess of the losses incurred is recognized on the balance sheet at September 30, 2023 as restricted cash and a liability to fund future replacement costs. The parties are awaiting issuance of a final award. The ultimate outcome of this matter cannot be determined at this time.

Environmental Remediation

Southern Company Gas' environmental remediation liability was $234 million and $256 million at September 30, 2023 and December 31, 2022, respectively, based on the estimated cost of environmental investigation and remediation associated with known former manufactured gas plant operating sites.

The ultimate outcome of these matters cannot be determined at this time; however, as a result of the regulatory treatment for environmental remediation expenses described above, the final disposition of these matters is not expected to have a material impact on the financial statements of the applicable Registrants.

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(UNAUDITED)

Other Matters

Traditional Electric Operating Companies

In April 2019, Bellsouth Telecommunications d/b/a AT&T Alabama (AT&T) filed a complaint against Alabama Power with the FCC alleging that the pole rental rate AT&T is required to pay pursuant to the parties' joint use agreement is unjust and unreasonable under federal law. The complaint sought a new rate and approximately $87 million in refunds of alleged overpayments for the preceding six years. In August 2019, the FCC stayed the case in favor of arbitration, which AT&T has not pursued. The ultimate outcome of this matter cannot be determined at this time, but an adverse outcome could have a material impact on the financial statements of Southern Company and Alabama Power. Georgia Power and Mississippi ~~Power.~~

~~ACCOUNTING POLICIES~~

~~Application of Critical Accounting Policies and Estimates~~Power have joint use agreements with other AT&T affiliates.

Mississippi Power ~~prepares its financial statements~~

In August 2022, the Mississippi Department of Revenue (Mississippi DOR) completed an audit of sales and use taxes paid by Mississippi Power from 2016 to 2019 and entered a final assessment, indicating a total amount due of $28 million, including associated penalties and interest. In October 2022, Mississippi Power filed an administrative appeal with the Mississippi DOR contesting the assessment. On October 2, 2023, Mississippi Power and the Mississippi DOR reached a settlement agreement on an assessment of approximately $11 million including associated penalties and interest, $7 million of which was previously paid by Mississippi Power. On October 5, 2023, Mississippi Power made a final $4 million payment and considers this matter closed.

Pursuant to an accounting order approved by the Mississippi PSC in ~~accordance~~December 2022, Mississippi Power deferred $3 million of the agreed upon assessment related to taxes and associated interest to a regulatory asset for disposition in a future rate proceeding.

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(D) REVENUE FROM CONTRACTS WITH CUSTOMERS AND LEASE INCOME

Revenue from Contracts with ~~GAAP. Significant accounting policies~~Customers

The Registrants generate revenues from a variety of sources, some of which are ~~described in~~not accounted for as revenue from contracts with customers, such as leases, derivatives, and certain cost recovery mechanisms. See Note 1 to the financial statements of Mississippi Power in Item 8 of the Form 10-K. In the application of these policies, certain estimates are made that may have a material impact on Mississippi Power's results of operations and related disclosures. Different assumptions and measurements could produce estimates that are significantly different from those recorded in the financial statements. See MANAGEMENT'S DISCUSSION AND ANALYSIS – ACCOUNTING POLICIES – "Application of Critical Accounting Policies and Estimates" of Mississippi Power in Item 7 of the Form 10-K for a complete discussion of Mississippi Power's critical accounting policies and estimates related to Utility Regulation, Asset Retirement Obligations, Pension and Other Postretirement Benefits, AFUDC, Unbilled Revenues, and Contingent Obligations.

~~Kemper IGCC Rate Recovery~~

For periods prior to the second quarter 2017, significant accounting estimates included Kemper IGCC estimated construction costs, project completion date, and rate recovery. See MANAGEMENT'S DISCUSSION AND ANALYSIS – ACCOUNTING POLICIES – "Kemper IGCC Estimated Construction Costs, Project Completion Date, and Rate Recovery" of Mississippi Power in Item 7 of the Form 10-K for additional information. Mississippi Power recorded total pre-tax charges to income related to the Kemper IGCC of $428 million ($264 million after tax) in 2016, $365 million ($226 million after tax) in 2015, $868 million ($536 million after tax) in 2014, and $1.2 billion ($729 million after tax) in prior years.

~~As a result of the Mississippi PSC's June 21, 2017 stated intent to issue an order (which occurred on July 6, 2017) directing Mississippi Power to pursue a settlement~~ under which the Kemper County energy facility would be operated as a natural gas plant rather than an IGCC plant, as well as Mississippi Power's June 28, 2017 suspension of the operation and start-up of the gasifier portion of the Kemper IGCC, the estimated construction costs and

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project completion date are no longer considered significant accounting estimates. Significant accounting estimates for the September 30, 2017 financial statements presented herein include the overall assessment of rate recovery for the Kemper County energy facility and the estimated costs for the potential cancellation of the Kemper IGCC.

While the ultimate disposition of the gasification portions of the Kemper IGCC remains subject to the Mississippi PSC's jurisdiction, including the potential resolution of the matters addressed in the Kemper IGCC Settlement Docket, given the Mississippi PSC's stated intent regarding no further rate increase for the Kemper County energy facility, cost recovery of the gasification portions is 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 includes estimated costs associated with the gasification portions of the plant and lignite mine. In the third quarter 2017, Mississippi Power recorded an additional charge of $34 million ($21 million after tax) for ongoing project costs during suspension, which includes estimated gasifier-related costs through December 31, 2017 to reflect the Mississippi PSC's schedule for the Kemper IGCC Settlement Docket, as well as mine-related costs and other suspension costs through September 30, 2017. Any extension of the suspension period beyond December 31, 2017 is currently estimated to result in additional suspension costs of approximately $5 million per month. In the event the gasification portions of the project are ultimately canceled, additional pre-tax costs, which include mine and Kemper IGCC plant closure costs and contract termination costs, currently estimated at approximately $100 million to $200 million are expected to be incurred.

As of September 30, 2017, Mississippi Power has recorded a total of approximately $1.3 billion in costs associated with the combined cycle portion of the Kemper IGCC including transmission and related regulatory assets, of which $0.8 billion is included in retail and wholesale rates. The $0.5 billion not included in current rates includes costs in excess of the original 2010 estimate for the combined cycle portion of the facility, as well as the 15% that was previously contracted to Cooperative Energy. Mississippi Power has calculated the revenue requirements resulting from these remaining costs, using reasonable assumptions for amortization periods, and expects them to be recovered through rates consistent with the Mississippi PSC's requested settlement conditions. The ultimate outcome will be determined by the Mississippi PSC in the Kemper IGCC Settlement Docket proceedings.

In the aggregate, since the Kemper IGCC project started, Mississippi Power has incurred charges of $6.00 billion ($3.96 billion after tax) through September 30, 2017. Mississippi Power recorded total pre-tax charges to income for the estimated probable losses on the Kemper IGCC of $34 million ($21 million after tax) and $88 million ($54 million after tax) in the third quarter 2017 and the third quarter 2016, respectively, and total pre-tax charges of $3.2 billion ($2.2 billion after tax) and $222 million ($137 million after tax) year-to-date in 2017 and 2016, respectively.

Given the significant judgment involved in estimating the costs to cancel the gasifier portion of the Kemper IGCC, the ultimate rate recovery for the Kemper IGCC, including the $0.5 billion of combined cycle-related costs not yet in rates, and the impact on Mississippi Power's results of operations, Mississippi Power considers these items to be critical accounting estimates. See Note 3 to the financial statements of Mississippi Power under "Integrated Coal Gasification Combined Cycle""Revenues" in Item 8 of the Form 10-K for additional information on the revenue policies of the Registrants. See "Lease Income" herein and Note ~~(B)~~(J) for additional information on revenue accounted for under lease and derivative accounting guidance, respectively.

The following table disaggregates revenue from contracts with customers for the three and nine months ended September 30, 2023 and 2022:


	Southern Company		Alabama Power		Georgia Power		Mississippi Power		Southern Power		Southern Company Gas
	(in millions)
Three Months Ended September 30, 2023
Operating revenues
Retail electric revenues
Residential	$	2,543	$	969	$	1,473	$	101	$	—	$	—
Commercial	1,845		599		1,151		95		—		—
Industrial	1,116		498		528		90		—		—
Other	30		3		25		2		—		—
Total retail electric revenues	5,534		2,069		3,177		288		—		—
Natural gas distribution revenues
Residential	217		—		—		—		—		217
Commercial	56		—		—		—		—		56
Transportation	275		—		—		—		—		275
Industrial	4		—		—		—		—		4
Other	60		—		—		—		—		60
Total natural gas distribution revenues	612		—		—		—		—		612
Wholesale electric revenues
PPA energy revenues	317		66		31		2		226		—
PPA capacity revenues	151		26		13		3		110		—
Non-PPA revenues	101		15		21		137		126		—
Total wholesale electric revenues	569		107		65		142		462		—
Other natural gas revenues
Gas marketing services	54		—		—		—		—		54
Other natural gas revenues	8		—		—		—		—		8
Total natural gas revenues	62		—		—		—		—		62
Other revenues	330		54		146		10		18		—
Total revenue from contracts with customers	7,107		2,230		3,388		440		480		674
Other revenue sources(*)	(127)		(147)		(151)		(4)		173		15

Total operating revenues	$	6,980	$	2,083	$	3,237	$	436	$	653	$	689

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	Southern Company		Alabama Power		Georgia Power		Mississippi Power		Southern Power		Southern Company Gas
	(in millions)
Nine Months Ended September 30, 2023
Operating revenues
Retail electric revenues
Residential	$	5,717	$	2,277	$	3,202	$	238	$	—	$	—
Commercial	4,464		1,493		2,733		238		—		—
Industrial	2,770		1,324		1,195		251		—		—
Other	84		10		68		6		—		—
Total retail electric revenues	13,035		5,104		7,198		733		—		—
Natural gas distribution revenues
Residential	1,443		—		—		—		—		1,443
Commercial	370		—		—		—		—		370
Transportation	878		—		—		—		—		878
Industrial	33		—		—		—		—		33
Other	228		—		—		—		—		228
Total natural gas distribution revenues	2,952		—		—		—		—		2,952
Wholesale electric revenues
PPA energy revenues	853		196		66		8		601		—
PPA capacity revenues	490		130		38		36		289		—
Non-PPA revenues	199		49		30		315		312		—
Total wholesale electric revenues	1,542		375		134		359		1,202		—
Other natural gas revenues

Gas marketing services	358		—		—		—		—		358
Other natural gas revenues	28		—		—		—		—		28
Total natural gas revenues	386		—		—		—		—		386
Other revenues	971		159		422		31		46		—
Total revenue from contracts with customers	18,886		5,638		7,754		1,123		1,248		3,338
Other revenue sources(*)	322		(218)		51		14		438		79

Total operating revenues	$	19,208	$	5,420	$	7,805	$	1,137	$	1,686	$	3,417

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(UNAUDITED)


	Southern Company		Alabama Power		Georgia Power		Mississippi Power		Southern Power		Southern Company Gas
	(in millions)
Three Months Ended September 30, 2022
Operating revenues
Retail electric revenues
Residential	$	2,104	$	799	$	1,212	$	93	$	—	$	—
Commercial	1,637		499		1,051		87		—		—
Industrial	1,183		452		642		89		—		—
Other	27		3		22		2		—		—
Total retail electric revenues	4,951		1,753		2,927		271		—		—
Natural gas distribution revenues
Residential	331		—		—		—		—		331
Commercial	93		—		—		—		—		93
Transportation	259		—		—		—		—		259
Industrial	12		—		—		—		—		12
Other	49		—		—		—		—		49
Total natural gas distribution revenues	744		—		—		—		—		744
Wholesale electric revenues
PPA energy revenues	812		187		40		4		591		—
PPA capacity revenues	175		56		12		1		107		—
Non-PPA revenues	58		67		4		242		303		—
Total wholesale electric revenues	1,045		310		56		247		1,001		—
Other natural gas revenues
Gas marketing services	84		—		—		—		—		84
Other natural gas revenues	15		—		—		—		—		15
Total natural gas revenues	99		—		—		—		—		99
Other revenues	277		65		110		13		9		—
Total revenue from contracts with customers	7,116		2,128		3,093		531		1,010		843
Other revenue sources(*)	1,262		316		796		(21)		170		14

Total operating revenues	$	8,378	$	2,444	$	3,889	$	510	$	1,180	$	857

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)


	Southern Company		Alabama Power		Georgia Power		Mississippi Power		Southern Power		Southern Company Gas
	(in millions)
Nine Months Ended September 30, 2022
Operating revenues
Retail electric revenues
Residential	$	5,282	$	2,049	$	2,995	$	238	$	—	$	—
Commercial	4,202		1,285		2,688		229		—		—
Industrial	2,914		1,143		1,529		242		—		—
Other	79		10		62		7		—		—
Total retail electric revenues	12,477		4,487		7,274		716		—		—
Natural gas distribution revenues
Residential	1,821		—		—		—		—		1,821
Commercial	493		—		—		—		—		493
Transportation	872		—		—		—		—		872
Industrial	60		—		—		—		—		60
Other	244		—		—		—		—		244
Total natural gas distribution revenues	3,490		—		—		—		—		3,490
Wholesale electric revenues
PPA energy revenues	1,739		354		112		11		1,285		—
PPA capacity revenues	443		135		35		4		273		—
Non-PPA revenues	182		166		19		511		572		—
Total wholesale electric revenues	2,364		655		166		526		2,130		—
Other natural gas revenues

Gas marketing services	417		—		—		—		—		417
Other natural gas revenues	41		—		—		—		—		41
Total natural gas revenues	458		—		—		—		—		458
Other revenues	810		173		327		34		27		—
Total revenue from contracts with customers	19,599		5,315		7,767		1,276		2,157		3,948
Other revenue sources(*)	2,633		708		1,451		3		461		50

Total operating revenues	$	22,232	$	6,023	$	9,218	$	1,279	$	2,618	$	3,998

(*)Other revenue sources relate to revenues from customers accounted for as derivatives and leases, alternative revenue programs at Southern Company Gas, and cost recovery mechanisms and revenues (including those related to fuel costs) that meet other scope exceptions for revenues from contracts with customers at the traditional electric operating companies.

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

Contract Balances

The following table reflects the closing balances of receivables, contract assets, and contract liabilities related to revenues from contracts with customers at September 30, 2023 and December 31, 2022:


	Southern Company		Alabama Power		Georgia Power		Mississippi Power		Southern Power		Southern Company Gas
	(in millions)
Accounts Receivable
At September 30, 2023	$	2,680	$	858	$	1,175	$	106	$	138	$	331
At December 31, 2022	3,123		696		922		92		237		1,107
Contract Assets
At September 30, 2023	$	267	$	6	$	146	$	—	$	—	$	41
At December 31, 2022	156		2		89		—		—		—
Contract Liabilities
At September 30, 2023	$	62	$	—	$	8	$	2	$	8	$	—
At December 31, 2022	45		4		9		—		1		—

Contract assets for Georgia Power primarily relate to retail customer fixed bill programs, where the payment is contingent upon Georgia Power's continued performance and the customer's continued participation in the program over a one-year contract term, and unregulated service agreements, where payment is contingent on project completion. Contract liabilities for Georgia Power primarily relate to cash collections recognized in advance of revenue for unregulated service agreements. At September 30, 2023, Southern Company Gas' contract assets relate to work performed on an energy efficiency enhancement and upgrade contract with the U.S. General Services Administration. Southern Company Gas receives cash advances from a third-party financial institution to fund work performed, of which approximately $51 million had been received at September 30, 2023. These advances have been accounted for as long-term debt on the balance sheets. See Note 1 to the ~~Condensed~~financial statements under "Affiliate Transactions" in Item 8 of the Form 10-K for additional information regarding the construction contract. At September 30, 2023 and December 31, 2022, Southern Company's unregulated distributed generation business had contract assets of $75 million and $65 million, respectively, and contract liabilities of $47 million and $32 million, respectively, for outstanding performance obligations.

Revenues recognized in the three and nine months ended September 30, 2023, which were included in contract liabilities at December 31, 2022, were immaterial for the applicable Registrants. Contract liabilities are primarily classified as current on the balance sheets as the corresponding revenues are generally expected to be recognized within one year.

Remaining Performance Obligations

The Subsidiary Registrants may enter into long-term contracts with customers in which revenues are recognized as performance obligations are satisfied over the contract term. For Alabama Power, Georgia Power, and Southern Power, these contracts primarily relate to PPAs whereby electricity and generation capacity are provided to a customer. The revenue recognized for the delivery of electricity is variable; however, certain PPAs include a fixed payment for fixed generation capacity over the term of the contract. For Southern Company Gas, these contracts primarily relate to the U.S. General Services Administration contract described above. Southern Company's unregulated distributed generation business also has partially satisfied performance obligations related to certain

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

fixed price contracts. Revenues from contracts with customers related to these performance obligations remaining at September 30, 2023 are expected to be recognized as follows:


	2023 (remaining)		2024		2025		2026		2027		Thereafter
	(in millions)
Southern Company	$	166	$	599	$	359	$	318	$	319	$	2,245
Alabama Power	10		24		8		—		—		—
Georgia Power	23		66		34		14		14		23

Southern Power	84		356		302		303		310		2,233
Southern Company Gas	4		29		—		—		—		—

Lease Income

Lease income for the three and nine months ended September 30, 2023 and 2022 is as follows:


	Southern Company		Alabama Power		Georgia Power		Mississippi Power		Southern Power		Southern Company Gas
	(in millions)
For the Three Months Ended September 30, 2023
Lease income - interest income on sales-type leases	$	6	$	—	$	—	$	4	$	2	$	—
Lease income - operating leases	36		3		7		—		21		9
Variable lease income	134		—		—		—		144		—
Total lease income	$	176	$	3	$	7	$	4	$	167	$	9

For the Nine Months Ended September 30, 2023
Lease income - interest income on sales-type leases	$	18	$	—	$	—	$	11	$	7	$	—
Lease income - operating leases	129		32		22		2		64		27
Variable lease income	327		1		—		—		351		—
Total lease income	$	474	$	33	$	22	$	13	$	422	$	27

For the Three Months Ended September 30, 2022
Lease income - interest income on sales-type leases	$	7	$	—	$	—	$	4	$	3	$	—
Lease income - operating leases	50		19		8		1		21		9
Variable lease income	139		—		—		—		145		—
Total lease income	$	196	$	19	$	8	$	5	$	169	$	9

For the Nine Months Ended September 30, 2022
Lease income - interest income on sales-type leases	$	19	$	—	$	—	$	11	$	8	$	—
Lease income - operating leases	149		58		24		1		64		27
Variable lease income	355		1		—		—		372		—
Total lease income	$	523	$	59	$	24	$	12	$	444	$	27

Lease payments received under "~~Integrated Coal Gasification Combined Cycle" herein~~tolling arrangements and PPAs consist of either scheduled payments or variable payments based on the amount of energy produced by the underlying electric generating units. Lease income for ~~additional information.~~Alabama Power and Southern Power is included in wholesale revenues.

~~Recently Issued Accounting Standards~~

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

(E) CONSOLIDATED ENTITIES AND EQUITY METHOD INVESTMENTS

See ~~MANAGEMENT'S DISCUSSION AND ANALYSIS – ACCOUNTING POLICIES – "Recently Issued Accounting Standards" of Mississippi Power~~Note 7 to the financial statements in Item 78 of the Form 10-K for additional information.

~~In 2014,~~

Southern Company

At September 30, 2023 and December 31, 2022, Southern Holdings had equity method investments totaling $126 million and $112 million, respectively, primarily related to investments in venture capital funds focused on energy and utility investments. Earnings from these investments were immaterial for all periods presented.

Southern Power

Variable Interest Entities

Southern Power has certain subsidiaries that are determined to be VIEs. Southern Power is considered the ~~FASB issued ASC 606,~~ ~~Revenue from Contracts with Customers~~ ~~(ASC 606), replacing~~primary beneficiary of these VIEs because it controls the ~~existing accounting standard and industry specific guidance for revenue recognition with a five-step model for recognizing and measuring revenue from contracts with customers. The underlying principle~~most significant activities of the ~~standard~~VIEs, including operating and maintaining the respective assets, and has the obligation to absorb expected losses of these VIEs to the extent of its equity interests.

SP Solar and SP Wind

At September 30, 2023 and December 31, 2022, SP Solar had total assets of $5.8 billion and $5.9 billion, respectively, total liabilities of $0.4 billion, and noncontrolling interests of $1.1 billion. Cash distributions from SP Solar are allocated 67% to Southern Power and 33% to the limited partner in accordance with their partnership interest percentage. Under the terms of the limited partnership agreement, distributions without limited partner consent are limited to available cash and SP Solar is obligated to ~~recognize revenue~~distribute all such available cash to ~~depict~~its partners each quarter. Available cash includes all cash generated in the ~~transfer~~quarter subject to the maintenance of ~~goods or services~~appropriate operating reserves.

At September 30, 2023 and December 31, 2022, SP Wind had total assets of $2.2 billion, total liabilities of $184 million and $169 million, respectively, and noncontrolling interests of $38 million and $39 million, respectively. Under the terms of the limited liability agreement, distributions without Class A member consent are limited to ~~customers at~~available cash and SP Wind is obligated to distribute all such available cash to its members each quarter. Available cash includes all cash generated in the ~~amount expected~~quarter subject to ~~be collected. The new standard also requires enhanced disclosures regarding~~ the ~~nature, amount, timing,~~maintenance of appropriate operating reserves. Cash distributions from SP Wind are generally allocated 60% to Southern Power and ~~uncertainty~~40% to the three financial investors in accordance with the limited liability agreement.

Southern Power consolidates both SP Solar and SP Wind, as the primary beneficiary, since it controls the most significant activities of ~~revenue~~each entity, including operating and maintaining their assets. Certain transfers and sales of the assets in the VIEs are subject to partner consent and the ~~related cash flows arising~~liabilities are non-recourse to the general credit of Southern Power. Liabilities consist of customary working capital items and do not include any long-term debt.

Other Variable Interest Entities

Southern Power has other consolidated VIEs that relate to certain subsidiaries that have either sold noncontrolling interests to tax equity investors or acquired less than a 100% interest from ~~contracts with customers.~~facility developers. These entities are considered VIEs because the arrangements are structured similar to a limited partnership and the noncontrolling members do not have substantive kick-out rights.

~~While Mississippi Power expects most~~At September 30, 2023 and December 31, 2022, the other VIEs had total assets of ~~its revenue to be included in~~$1.7 billion and $1.8 billion, respectively, total liabilities of $0.2 billion, and noncontrolling interests of $0.8 billion. Under the ~~scope~~terms of ~~ASC 606, it has not fully completed its evaluation~~the partnership agreements, distributions of all ~~revenue arrangements. The majority of Mississippi Power's revenue, including~~

available cash are required each month or quarter and additional distributions require partner consent.

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~~MISSISSIPPI POWER COMPANY~~

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

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

Equity Method Investments

At December 31, 2022, Southern Power had equity method investments in wind and battery energy ~~provided to customers, is from tariff offerings that provide electricity without a defined contractual term, as well as longer-term contractual commitments, including PPAs. Mississippi~~storage projects totaling $49 million. During the first quarter 2023, Southern Power ~~expects that the revenue from contracts with these customers will not result in a significant shift~~sold its remaining equity method investments in the ~~timing~~projects and received proceeds of ~~revenue recognition~~$50 million. Earnings (loss) from these investments, including the gains associated with the sales, were immaterial for ~~such sales.~~all periods presented.

~~Mississippi Power's ongoing evaluation~~

Southern Company Gas

Equity Method Investments

The carrying amounts of ~~other revenue streams~~Southern Company Gas' equity method investments at September 30, 2023 and December 31, 2022 and related ~~contracts includes unregulated sales to customers. Some revenue arrangements, such as alternative revenue programs, are excluded~~earnings from the scope of ASC 606 and, therefore, will be accounted for and disclosed or presented separately from revenues under ASC 606 on Mississippi Power's financial statements, if material. In addition, the power and utilities industry continues to evaluate other specific industry issues, including the applicability of ASC 606 to contributions in aid of construction (CIAC). Although final implementation guidance has not been issued, Mississippi Power expects CIAC to be out of the scope of ASC 606.

The new standard is effective for interim and annual reporting periods beginning after December 15, 2017. Mississippi Power intends to use the modified retrospective method of adoption effective January 1, 2018. Mississippi Power has also elected to utilize practical expedients which allow it to apply the standard to open contracts at the date of adoption and to reflect the aggregate effect of all modifications when identifying performance obligations and allocating the transaction price for contracts modified before the effective date. Under the modified retrospective method of adoption, prior year reported results are not restated; however, a cumulative-effect adjustment to retained earnings at January 1, 2018 is recorded. In addition, disclosures will include comparative information on 2018 financial statement line items under current guidance. While the adoption of ASC 606, including the cumulative-effect adjustment, is not expected to have a material impact on either the timing or amount of revenues recognized in Mississippi Power's financial statements, Mississippi Power will continue to evaluate the requirements, as well as any additional clarifying guidance that may be issued.

~~On March 10, 2017, the FASB issued ASU No. 2017-07,~~ ~~Compensation – Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost~~ (ASU 2017-07). ASU 2017-07 requires that an employer report the service cost component in the same line item or items as other compensation costs and requires the other components of net periodic pension and postretirement benefit costs to be separately presented in the income statement outside income from operations. Additionally, only the service cost component is eligible for capitalization, when applicable. However, all cost components remain eligible for capitalization under FERC regulations. ASU 2017-07 will be applied retrospectivelythose investments for the ~~presentation of the service cost component~~three and the other components of net periodic pension and postretirement benefit costs in the income statement. The capitalization of the service cost component of net periodic pension and postretirement benefit costs in assets will be applied on a prospective basis. ASU 2017-07 is effective for annual periods beginning after December 15, 2017, including interim periods within those annual periods. The presentation changes required for net periodic pension and postretirement benefit costs will result in a decrease in Mississippi Power's operating income and an increase in other income for 2016 and 2017 and are expected to result in a decrease in operating income and an increase in other income for 2018. The adoption of ASU 2017-07 is not expected to have a material impact on Mississippi Power's financial statements.

~~On August 28, 2017, the FASB issued ASU No. 2017-12,~~ ~~Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities~~ (ASU 2017-12), amending the hedge accounting recognition and presentation requirements. ASU 2017-12 makes more financial and non-financial hedging strategies eligible for hedge accounting, amends the related presentation and disclosure requirements, and simplifies hedge effectiveness assessment requirements. ASU 2017-12 is effective for fiscal years beginning after December 15, 2018 and interim periods within those fiscal years, with early adoption permitted. Mississippi Power is evaluating the standard and expects to early adopt ASU 2017-12 effective January 1, 2018. The adoption of ASU 2017-12 is not expected to have a material impact on Mississippi Power's financial statements.

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~~MISSISSIPPI POWER COMPANY~~

~~MANAGEMENT'S DISCUSSION AND ANALYSIS OF~~

~~FINANCIAL CONDITION AND RESULTS OF OPERATIONS~~

~~FINANCIAL CONDITION AND LIQUIDITY~~

~~Overview~~

~~See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Overview" of Mississippi Power in Item 7 of the Form 10-K and FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined Cycle" herein for additional information. Earnings for the~~ nine months ended September 30, ~~2017~~2023 and 2022 were ~~negatively affected by revisions to the cost estimate for the Kemper IGCC.~~as follows:

Mississippi Power's capital expenditures and debt maturities are expected to materially exceed operating cash flows through 2022. Projected capital expenditures in that period include investments to maintain existing generation facilities, to add environmental modifications to existing generating units, and to expand and improve transmission and distribution facilities.


Investment Balance	September 30, 2023		December 31, 2022
	(in millions)
SNG	$	1,210	$	1,243
Other	33		33
Total	$	1,243	$	1,276

In the second quarter 2017, Mississippi Power borrowed an additional $40 million under a promissory note issued to Southern Company. In June 2017, Southern Company made equity contributions totaling $1.0 billion to Mississippi Power. Mississippi Power used a portion of the proceeds to prepay $901 million of outstanding debt.

As of September 30, 2017, Mississippi Power's current liabilities exceeded current assets by approximately $769 million primarily due to $935 million in long-term debt that matures within the next 12 months and $94 million of short-term debt. Mississippi Power intends to utilize operating cash flows, lines of credit, and bank term loans, as market conditions permit, as well as, under certain circumstances, commercial paper and/or equity contributions and/or loans from Southern Company to fund Mississippi Power's short-term capital needs.

Net cash provided from operating activities totaled $361 million for the first nine months of 2017, a decrease of $12 million as compared to the corresponding period in 2016. The decrease in cash provided from operating activities is primarily due to deferred income taxes related to the Kemper IGCC, partially offset by the timing of payments received from affiliates and customers and the completion of Mirror CWIP refunds in 2016. See Notes (B) and (G) to the Condensed Financial Statements under "~~Integrated Coal Gasification Combined Cycle~~ – ~~Rate Recovery of Kemper IGCC Costs" and "Unrecognized Tax Benefits~~ – ~~Section 174 Research and Experimental Deduction~~" herein for additional information. Net cash used for investing activities totaled $483 million for the first nine months of 2017 primarily due to gross property additions related to the Kemper IGCC. Net cash provided from financing activities totaled $129 million for the first nine months of 2017 primarily due to capital contributions from Southern Company, partially offset by redemptions of long-term debt and short-term borrowings. Cash flows from financing activities vary from period to period based on capital needs and the maturity or redemption of securities.

Significant balance sheet changes for the first nine months of 2017 include an increase in paid-in capital of $1.0 billion due to capital contributions from Southern Company, a portion of which was used to repay $300 million of securities due within one year, $591 million of long-term debt, and $10 million of short-term debt. Securities due within one year decreased $551 million due to the repayment of promissory notes to Southern Company. Long-term debt decreased primarily due to the reclassification of $1.2 billion in unsecured term loans to securities due within one year. Other significant changes include decreases of $2.5 billion in CWIP, $756 million in accumulated deferred income taxes, and $299 million in deferred charges related to income taxes. All of these changes primarily resulted from the Kemper IGCC suspension and related estimated loss. Income taxes receivable and unrecognized tax benefits also decreased due to tax refunds associated with the IRS Section 174 R&E settlement. See FUTURE EARNINGS POTENTIAL – "~~Integrated Coal Gasification Combined Cycle" and Notes (B) and (G) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" and "Section 174 Research and Experimental Deduction," respectively, herein for additional information.~~

~~Capital Requirements and Contractual Obligations~~

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" of Mississippi Power in Item 7 of the Form 10-K for a description of Mississippi Power's capital requirements for its construction program, including estimated capital expenditures for new generating resources and to comply with existing environmental statutes and regulations,


	Three Months Ended September 30,				Nine Months Ended September 30,
Earnings from Equity Method Investments	2023		2022		2023		2022
	(in millions)
SNG	$	32	$	34	$	104	$	104
Other	—		—		—		1
Total	$	32	$	34	$	104	$	105

~~146~~

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~~MISSISSIPPI POWER COMPANY~~

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

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

(F) FINANCING AND LEASES

scheduled maturities of long-term debt, as well as related interest, leases, purchase commitments, derivative obligations, preferred stock dividends, trust funding requirements, and unrecognized tax benefits. Approximately $935 million will be required through September 30, 2018 to fund maturities of long-term debt and $4 million will be required to fund maturities of short-term debt. In addition, Mississippi Power has $40 million of tax-exempt variable rate demand obligations that are supported by short-term credit facilities and $50 million of fixed rate pollution control revenue bonds that are required to be remarketed over the next 12 months. See "~~Sources of Capital" and FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined Cycle" herein for additional information.~~Bank Credit Arrangements

The construction program of Mississippi Power is currently estimated to be $582 million for 2017, $203 million for 2018, $177 million for 2019, $204 million for 2020, $199 million for 2021, and $240 million for 2022. These estimated expenditures do not include potential compliance costs that may arise from the EPA's final rules and guidelines or future state plans that would limit CO₂ ~~emissions from existing, new, modified, or reconstructed fossil-fuel-fired electric generating units.~~

The construction program is subject to periodic review and revision, and actual construction costs may vary from these estimates because of numerous factors. These factors include: changes in business conditions; changes in load projections; storm impacts; changes in environmental statutes and regulations; the outcome of any legal challenges to the environmental rules; changes in generating plants, including unit retirements and replacements and adding or changing fuel sources at existing units, to meet regulatory requirements; changes in FERC rules and regulations; Mississippi PSC approvals; changes in the expected environmental compliance program; changes in legislation; the cost and efficiency of construction labor, equipment, and materials; project scope and design changes; and the cost of capital.

~~Sources of Capital~~

Mississippi Power plans to obtain the funds required for construction and other purposes from operating cash flows, external security issuances, term loans, and/or short-term debt, as well as, under certain circumstances, equity contributions and/or loans from Southern Company. The amount, type, and timing of future financings will depend upon regulatory approval, prevailing market conditions, and other factors, which includes resolution of the Kemper County energy facility cost recovery. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" and – FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined Cycle – Rate Recovery of Kemper IGCC Costs" of Mississippi Power in Item 7 of the Form 10-K for additional information.

On February 28, 2017, the maturity dates for $551 million in promissory notes to Southern Company were extended to July 31, 2018. In the second quarter 2017, Mississippi Power borrowed an additional $40 million under a promissory note issued to Southern Company. In June 2017, Southern Company made equity contributions totaling $1.0 billion to Mississippi Power. Mississippi Power used a portion of the proceeds to (i) prepay $300 million of the outstanding principal amount under its $1.2 billion unsecured term loan; (ii) repay all of the $591 million outstanding principal amount of promissory notes to Southern Company; and (iii) repay $10 million of the outstanding principal amount of bank loans.

In September 2017, Mississippi Power issued a floating rate promissory note to Southern Company in an aggregate principal amount of up to $150 million bearing interest based on one-month LIBOR. Mississippi Power borrowed $109 million under this promissory note primarily to satisfy its federal income tax obligations for the quarter ending September 30, 2017 and subsequently repaid the promissory note upon receipt of its income tax refund from the U.S. federal government related to the settlement concerning deductible R&E expenditures. See Note ~~(G) to the Condensed Financial Statements under "Section 174 Research and Experimental Deduction" herein for additional information.~~

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~~MISSISSIPPI POWER COMPANY~~

~~MANAGEMENT'S DISCUSSION AND ANALYSIS OF~~

~~FINANCIAL CONDITION AND RESULTS OF OPERATIONS~~

market conditions permit, as well as, under certain circumstances, commercial paper and/or equity contributions and/or loans from Southern Company to fund Mississippi Power's short-term capital needs. Specifically, Mississippi Power has been informed by Southern Company that in the event sufficient funds are not available from external sources, Southern Company intends to provide Mississippi Power with loans and/or equity contributions sufficient to fund the remaining indebtedness scheduled to mature and other cash needs over the next 12 months. Therefore, Mississippi Power's financial statement presentation contemplates continuation of Mississippi Power as a going concern as a result of Southern Company's anticipated ongoing financial support of Mississippi Power. For additional information, see Notes 1 and 68 to the financial statements ~~of Mississippi Power under "Recently Issued Accounting Standards" and "Going Concern," respectively, in Item 8 of the Form 10-K and Note (E) to the Condensed Financial Statements under "Going Concern" herein.~~

~~At September 30, 2017, Mississippi Power had approximately $231 million of cash and cash equivalents. Committed credit arrangements with banks at September 30, 2017 were as follows:~~

Expires
Executable Term
Loans

Expires Within One
Year
2017 Total Unused
One
Year

Two
Years

Term
Out

No Term
Out
(in millions)
$ 100
$ 100
$ 100
$ —
$ —
$ —
$ 100

~~See Note 6 to the financial statements of Mississippi Power~~ under "Bank Credit Arrangements" in Item 8 of the Form 10-K for additional information.

At September 30, 2023, committed credit arrangements with banks were as follows:


	Expires
Company	2024		2025		2026		2028		Total		Unused		Expires within One Year
	(in millions)
Southern Company parent(a)	$	150	$	—	$	—	$	1,850	$	2,000	$	1,998	$	150
Alabama Power	—		—		650		700		1,350		1,350		—
Georgia Power	—		—		—		1,750		1,750		1,726		—
Mississippi Power	—		125		150		—		275		275		—
Southern Power(a)(b)	—		—		—		600		600		589		—
Southern Company Gas(c)	100		—		—		1,500		1,600		1,598		100
SEGCO	30		—		—		—		30		30		30
Southern Company	$	280	$	125	$	800	$	6,400	$	7,605	$	7,566	$	280

(a)Arrangement expiring in 2028 represents a $2.45 billion combined arrangement for Southern Company and ~~Note (E)~~Southern Power as borrowers. Pursuant to the ~~Condensed~~combined facility, the allocations between Southern Company and Southern Power may be adjusted.

(b)Does not include Southern Power Company's $75 million and $100 million continuing letter of credit facilities for standby letters of credit, expiring in 2025 and 2026, respectively, of which $9 million and $16 million, respectively, was unused at September 30, 2023. In March 2023, Southern Power amended the $100 million letter of credit facility, which, among other things, extended the expiration date from 2025 to 2026 and increased the amount from $75 million. Southern Power's subsidiaries are not parties to its bank credit arrangements or letter of credit facilities.

(c)Southern Company Gas, as the parent entity, guarantees the obligations of Southern Company Gas Capital, which is the borrower of $800 million of the credit arrangement expiring in 2028. Southern Company Gas' committed credit arrangement expiring in 2028 also includes $700 million for which Nicor Gas is the borrower and which is restricted for working capital needs of Nicor Gas. Pursuant to the multi-year credit arrangement expiring in 2028, the allocations between Southern Company Gas Capital and Nicor Gas may be adjusted. Nicor Gas is also the borrower under a $100 million credit arrangement expiring in 2024.

As reflected in the table above, in May 2023, Southern Company and Southern Power combined and extended their multi-year credit arrangements previously maturing in 2026, resulting in a single aggregate $2.45 billion facility (currently allocated $1.85 billion for Southern Company and $600 million for Southern Power) maturing in 2028. Pursuant to the combined facility, the allocations between Southern Company and Southern Power may be adjusted. Alabama Power, Georgia Power, and Southern Company Gas Capital, along with Nicor Gas, amended and restated certain of their multi-year credit arrangements, which, among other things, extended the maturity dates from 2026 to 2028. Mississippi Power amended and restated certain of its multi-year credit arrangements aggregating $150 million, which, among other things, extended the maturity dates from 2024 to 2026. Nicor Gas also entered into a $100 million credit arrangement maturing in 2024 to replace its $250 million credit arrangement that expired in 2023. In June 2023, Southern Company also entered into a new $150 million credit arrangement maturing in 2024. In August 2023, Alabama Power amended and restated one of its multi-year credit arrangements, which, among other things, extended the maturity date from 2024 to 2026 and increased the borrowing capacity from $550 million to $650 million.

Table of ContentsIndex to Financial Statements ~~under "Bank Credit Arrangements" herein for additional information.~~

~~Most of these~~

NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

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

These bank credit arrangements, as well as ~~Mississippi Power's~~the term loan ~~agreement,~~arrangements of the Registrants, Nicor Gas, and SEGCO, contain covenants that limit debt levels and ~~typically~~ contain ~~cross acceleration~~cross-acceleration provisions to other indebtedness (including guarantee obligations) that are restricted only to the indebtedness of ~~Mississippi Power. Such~~the individual company. The cross-acceleration provisions to other indebtedness would trigger an event of default if ~~Mississippi Power~~the applicable borrower defaulted on indebtedness, the payment of which was then accelerated. At September 30, ~~2017, Mississippi Power was~~2023, the Registrants, Nicor Gas, and SEGCO were in compliance with all such covenants. None of the bank credit arrangements contain material adverse change clauses at the time of ~~borrowing.~~

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

A portion of the ~~$100 million~~ unused credit ~~arrangements~~ with banks is allocated to provide liquidity support to ~~Mississippi Power's pollution control~~certain revenue ~~bonds. The amount~~bonds of the traditional electric operating companies and the commercial paper programs of the Registrants, Nicor Gas, and SEGCO. At September 30, 2023, outstanding variable rate ~~pollution control~~demand revenue bonds ~~outstanding requiring~~of the traditional electric operating companies with allocated liquidity support astotaled approximately $1.7 billion (comprised of ~~September 30, 2017 was~~ approximately ~~$40 million.~~$818 million at Alabama Power, $819 million at Georgia Power, and $69 million at Mississippi Power). In addition, at September 30, ~~2017, Mississippi~~2023, Alabama Power and Georgia Power had approximately ~~$50~~$120 million and $325 million, respectively, of fixed rate ~~pollution control~~revenue bonds outstanding that ~~were~~are required to be remarketed within the next 12 months. The variable rate demand revenue bonds and fixed rate revenue bonds required to be remarketed within the next 12 months are classified as long-term debt on the balance sheets as a result of available long-term committed credit.

~~Short-term borrowings~~

Convertible Senior Notes

In February 2023, Southern Company issued $1.5 billion aggregate principal amount of Series 2023A 3.875% Convertible Senior Notes due December 15, 2025 (Series 2023A Convertible Senior Notes). In March 2023, Southern Company issued an additional $225 million aggregate principal amount of the Series 2023A Convertible Senior Notes upon the exercise by the initial purchasers of their over-allotment option.

Interest on the Series 2023A Convertible Senior Notes is payable semiannually, which began on June 15, 2023. The Series 2023A Convertible Senior Notes will mature on December 15, 2025, unless earlier converted or repurchased, but are not redeemable at the option of Southern Company. The Series 2023A Convertible Senior Notes are direct, unsecured, and unsubordinated obligations of Southern Company, ranking equally with all of Southern Company's other unsecured and unsubordinated indebtedness from time to time outstanding, and are effectively subordinated to all secured indebtedness of Southern Company.

Holders may convert their Series 2023A Convertible Senior Notes at their option prior to the close of business on the business day preceding September 15, 2025, but only under the following circumstances:

•during any calendar quarter (and only during such calendar quarter), if the last reported sale price of Southern Company's common stock for at least 20 trading days (whether or not consecutive) during the period of 30 consecutive trading days ending on, and including, the last trading day of the immediately preceding calendar quarter is greater than or equal to 130% of the conversion price on each applicable trading day as determined by Southern Company;

•during the five business day period after any 10 consecutive trading day period (Measurement Period) in which the trading price per $1,000 principal amount of Series 2023A Convertible Senior Notes for each trading day of the Measurement Period was less than 98% of the product of the last reported sale price of the common stock and the conversion rate on each such trading day; or

•upon the occurrence of certain corporate events specified in the indenture governing the Series 2023A Convertible Senior Notes.

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

On or after September 15, 2025, a holder may convert all or any portion of its Series 2023A Convertible Senior Notes at any time prior to the close of business on the second scheduled trading day immediately preceding the maturity date regardless of the foregoing conditions.

Southern Company will settle conversions of the Series 2023A Convertible Senior Notes by paying cash up to the aggregate principal amount of the Series 2023A Convertible Senior Notes to be converted and paying or delivering, as the case may be, cash, shares of common stock or a combination of cash and shares of common stock, at Southern Company's election, in respect of the remainder, if any, of Southern Company's conversion obligation in excess of the aggregate principal amount of the Series 2023A Convertible Senior Notes being converted. The Series 2023A Convertible Senior Notes are initially convertible at a rate of 11.8818 shares of common stock per $1,000 principal amount converted, which is approximately equal to $84.16 per share of common stock. The conversion rate will be subject to adjustment upon the occurrence of certain specified events but will not be adjusted for accrued and unpaid interest. In addition, upon the occurrence of a make-whole fundamental change (as defined in the indenture governing the Series 2023A Convertible Senior Notes), Southern Company will, in certain circumstances, increase the conversion rate by a number of additional shares of common stock for conversions in connection with the make-whole fundamental change.

Upon the occurrence of a fundamental change (as defined in the indenture governing the Series 2023A Convertible Senior Notes), holders of the Series 2023A Convertible Senior Notes may require Southern Company to purchase all or a portion of their Series 2023A Convertible Senior Notes, in principal amounts equal to $1,000 or an integral multiple thereof, for cash at a price equal to 100% of the principal amount of the Series 2023A Convertible Senior Notes to be purchased plus any accrued and unpaid interest.

Earnings per Share

For Southern Company, the only difference in computing basic and diluted earnings per share (EPS) is attributable to awards outstanding under stock-based compensation plans and the Series 2023A Convertible Senior Notes. EPS dilution resulting from stock-based compensation plans is determined using the treasury stock method and EPS dilution resulting from the Series 2023A Convertible Senior Notes is determined using the net share settlement method. See Note 12 to the financial statements in Item 8 of the Form 10-K and "Convertible Senior Notes" herein for additional information. Shares used to compute diluted EPS were as follows:


	Three Months Ended September 30,		Nine Months Ended September 30,
	2023	2022	2023	2022
	(in millions)
As reported shares	1,092	1,082	1,092	1,070
Effect of stock-based compensation	7	6	6	6
Diluted shares	1,099	1,088	1,098	1,076

For all periods presented, an immaterial number of stock-based compensation awards was excluded from the diluted EPS calculation because the awards were anti-dilutive.

For all periods presented, there was no dilution resulting from the Series 2023A Convertible Senior Notes.

Southern Company Leveraged Lease

See Note 9 to the financial statements in Item 8 of the Form 10-K for information on a leveraged lease agreement related to energy generation. In June 2022, the Southern Holdings subsidiary operating the generating plant for the lessee provided notice to the lessee to terminate the related operating and maintenance agreement effective June 30, 2023. Subsequently, the lessee failed to make the semi-annual lease payment due in December 2022. As a result, the Southern Holdings subsidiary was unable to make its corresponding payment to the holders of the underlying non-recourse debt related to the generation assets. The parties to the lease entered into forbearance agreements which suspended the related contractual rights of the parties while they continued restructuring negotiations, during which

Table of ContentsIndex to Financial Statements

NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

the termination date for the operating and maintenance agreement was delayed until July 31, 2023. The negotiations were completed on July 14, 2023, resulting in the Southern Holdings subsidiary agreeing to continue operating the plant for the lessee until the lessee's associated power off-take agreement ends in 2032, subject to certain terms and conditions. The restructuring had no material impact on Southern Company's financial statements. Southern Company will continue to monitor the operational performance of the underlying assets and evaluate the ability of the lessee to continue to meet its obligations, including those associated with a future closure or retirement of the generation assets and associated properties, including the dry ash landfill.

(G) INCOME TAXES

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

Current and Deferred Income Taxes

Tax Credit and Net Operating Loss Carryforwards

Southern Company had federal ITC and PTC carryforwards (primarily related to Southern Power) totaling $1.0 billion and $1.1 billion at September 30, 2023 and December 31, 2022, respectively.

Southern Company's federal PTC and ITC carryforwards begin expiring in 2031, but are expected to be fully utilized by 2028. The utilization of each Registrant's estimated tax credit and state net operating loss carryforwards and related valuation allowances could be impacted by numerous factors, including the acquisition of additional renewable projects, changes in taxable income projections, transfer of eligible credits, and potential income tax rate changes. In the third quarter 2023, Georgia Power started generating advanced nuclear PTCs for Plant Vogtle Unit 3 beginning on the in-service date of July 31, 2023. In addition, pursuant to the Global Amendments to the Vogtle Joint Ownership Agreements (as defined in Note (B) under "Georgia Power – Nuclear Construction – Joint Owner Contracts"), Georgia Power is purchasing advanced nuclear PTCs for Plant Vogtle Unit 3 from certain other Vogtle Owners. See Note (B) and Note 2 to the financial statements in Item 8 of the Form 10-K under "Georgia Power – Nuclear Construction" for additional information on Plant Vogtle Units 3 and 4.

Effective Tax Rate

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

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

Southern Company

Southern Company's effective tax rate was 13.9% for the nine months ended September 30, 2023 compared to 20.0% for the corresponding period in 2022. The effective tax rate decrease was primarily due to an increase in the flowback of certain excess deferred income taxes at Alabama Power in 2023, lower pre-tax earnings in 2023, and an adjustment related to state tax credit carryforwards and the related valuation allowance at Georgia Power in 2022 and 2023, partially offset by the flowback of certain excess deferred income taxes ending in 2022 at Georgia Power.

Alabama Power

Alabama Power's effective tax rate was 8.3% for the nine months ended September 30, 2023 compared to 23.7% for the corresponding period in 2022. The effective tax rate decrease was primarily due to an increase in the flowback of certain excess deferred income taxes in 2023. See Note 2 to the financial statements under "Alabama Power – Excess Accumulated Deferred Income Tax Accounting Order" in Item 8 of the Form 10-K for additional information.

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

Georgia Power

Georgia Power's effective tax rate was 18.2% for the nine months ended September 30, 2023 compared to 18.5% for the corresponding period in 2022. The effective tax rate decrease was primarily due to an adjustment related to state tax credit carryforwards in 2022, a decrease in a valuation allowance on certain state tax credit carryforwards in 2023, and lower pre-tax earnings in 2023, largely offset by the flowback of certain excess deferred income taxes ending in 2022.

Mississippi Power

Mississippi Power's effective tax rate was 16.9% for the nine months ended September 30, 2023 compared to 20.1% for the corresponding period in 2022. The effective tax rate decrease was primarily due to an increase in the flowback of certain excess deferred income taxes in 2023.

Southern Power

Southern Power's effective tax rate was 14.8% for the nine months ended September 30, 2023 compared to 18.8% for the corresponding period in 2022. The effective tax rate decrease was primarily due to changes in state apportionment methodology resulting from tax legislation enacted by the State of Tennessee in May 2023.

Unrecognized Tax Benefits

Southern Company's and Georgia Power's unrecognized tax positions balances at September 30, 2023 were $167 million and $86 million, respectively, compared to $80 million for Southern Company at December 31, 2022. The increases from prior periods are primarily related to the amendment of certain 2019 through 2021 state tax filing positions related to tax credit utilization. If effective settlement of the positions is favorable, these positions would decrease Southern Company's and Georgia Power's effective tax rates. The ultimate outcome of this unrecognized tax benefit, of which a portion is expected to be resolved within the next 12 months, is dependent on acceptance by the state or expiration of related statute of limitations.

Subsequent to September 30, 2023, a statute of limitations expired related to a 2019 state tax filing position to exclude certain gains from 2019 dispositions from taxation in a certain unitary state. This $44 million tax position and related interest will be recognized in the fourth quarter 2023 and will decrease Southern Company's annual effective tax rate.

(H) RETIREMENT BENEFITS

The Southern Company system has a qualified defined benefit, trusteed, pension plan covering substantially all employees, with the exception of employees at PowerSecure. The qualified pension plan is funded in accordance with requirements of the Employee Retirement Income Security Act of 1974, as amended (ERISA). No mandatory contributions to the qualified pension plan are anticipated for the year ending December 31, 2023. The Southern Company system also provides certain non-qualified defined benefits for a select group of management and highly compensated employees, which are funded on a cash basis. In addition, the Southern Company system provides certain medical care and life insurance benefits for retired employees through other postretirement benefit plans. The traditional electric operating companies fund other postretirement trusts to the extent required by their respective regulatory commissions. Southern Company Gas has a separate unfunded supplemental retirement health care plan that provides medical care and life insurance benefits to employees of discontinued businesses.

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

On each Registrant's condensed statements of income, the service cost component of net periodic benefit costs is included in other operations and maintenance expenses and all other components of net periodic benefit costs are included in ~~notes payable~~other income (expense), net. Components of the net periodic benefit costs for the three and nine months ended September 30, 2023 and 2022 are presented in the ~~balance sheets. Details of short-term borrowings were as follows:~~following tables.

Short-term Debt at September 30, 2017
Short-term Debt During the Period^(*)

Amount
Outstanding

Weighted
Average
Interest
Rate

Average
Amount
Outstanding

Weighted
Average
Interest
Rate

Maximum
Amount
Outstanding
(in millions) (in millions) (in millions)
Short-term bank debt $ 4
3.8% $ 28
2.8% $ 126


~~(*)~~	~~Average and maximum amounts are based upon daily balances during the three-month period ended September 30, 2017.~~

~~148~~

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~~MISSISSIPPI POWER COMPANY~~

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

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


	Southern Company		Alabama Power		Georgia Power		Mississippi Power		Southern Power		Southern Company Gas
	(in millions)
Three Months Ended September 30, 2023
Pension Plans
Service cost	$	69	$	16	$	17	$	2	$	2	$	6
Interest cost	156		37		48		7		2		11
Expected return on plan assets	(307)		(75)		(97)		(13)		(4)		(22)
Amortization:
Prior service costs	—		—		—		—		—		(1)
Regulatory asset	—		—		—		—		—		4
Net (gain) loss	8		2		4		1		—		(1)
Net periodic pension income	$	(74)	$	(20)	$	(28)	$	(3)	$	—	$	(3)

Postretirement Benefits
Service cost	$	4	$	1	$	1	$	—	$	—	$	—
Interest cost	18		5		6		1		—		2
Expected return on plan assets	(21)		(9)		(7)		(1)		—		(2)
Amortization:
Prior service costs	—		—		1		—		—		—
Regulatory asset	—		—		—		—		—		2
Net gain	(4)		(1)		(1)		—		—		(1)
Net periodic postretirement benefit cost (income)	$	(3)	$	(4)	$	—	$	—	$	—	$	1

Nine Months Ended September 30, 2023
Pension Plans
Service cost	$	207	$	48	$	51	$	8	$	5	$	18
Interest cost	469		109		143		21		6		32
Expected return on plan assets	(922)		(223)		(289)		(41)		(12)		(65)
Amortization:
Prior service costs	—		—		1		—		—		(2)
Regulatory asset	—		—		—		—		—		11
Net (gain) loss	24		7		10		1		—		(3)
Net periodic pension income	$	(222)	$	(59)	$	(84)	$	(11)	$	(1)	$	(9)

Postretirement Benefits
Service cost	$	11	$	3	$	3	$	—	$	—	$	1
Interest cost	53		13		19		2		—		6
Expected return on plan assets	(62)		(26)		(22)		(1)		—		(5)
Amortization:
Prior service costs	1		—		1		—		—		—
Regulatory asset	—		—		—		—		—		5
Net gain	(10)		(2)		(3)		—		—		(3)
Net periodic postretirement benefit cost (income)	$	(7)	$	(12)	$	(2)	$	1	$	—	$	4

~~Credit Rating Risk~~

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)


	Southern Company		Alabama Power		Georgia Power		Mississippi Power		Southern Power		Southern Company Gas
	(in millions)
Three Months Ended September 30, 2022
Pension Plans
Service cost	$	103	$	25	$	26	$	5	$	2	$	9
Interest cost	102		24		31		5		2		7
Expected return on plan assets	(316)		(77)		(99)		(15)		(4)		(22)
Amortization:
Prior service costs	—		—		—		—		—		(1)
Regulatory asset	—		—		—		—		—		3
Net loss	60		16		18		2		1		2
Net periodic pension cost (income)	$	(51)	$	(12)	$	(24)	$	(3)	$	1	$	(2)

Postretirement Benefits
Service cost	$	6	$	2	$	2	$	1	$	1	$	—
Interest cost	10		3		4		—		—		1
Expected return on plan assets	(20)		(9)		(8)		—		—		(2)
Amortization:
Prior service costs	(1)		—		—		—		—		—
Regulatory asset	—		—		—		—		—		2
Net (gain)/loss	1		—		—		—		—		(1)
Net periodic postretirement benefit cost (income)	$	(4)	$	(4)	$	(2)	$	1	$	1	$	—

Nine Months Ended September 30, 2022
Pension Plans
Service cost	$	309	$	74	$	78	$	13	$	7	$	26
Interest cost	306		72		92		14		5		21
Expected return on plan assets	(949)		(229)		(298)		(44)		(12)		(68)
Amortization:
Prior service costs	—		—		1		—		—		(2)
Regulatory asset	—		—		—		—		—		11
Net loss	180		47		55		9		2		5
Net periodic pension cost (income)	$	(154)	$	(36)	$	(72)	$	(8)	$	2	$	(7)

Postretirement Benefits
Service cost	$	17	$	5	$	5	$	1	$	1	$	1
Interest cost	31		8		11		1		—		4
Expected return on plan assets	(60)		(25)		(21)		(1)		—		(6)
Amortization:
Prior service costs	(1)		—		—		—		—		—
Regulatory asset	—		—		—		—		—		5
Net (gain) loss	1		—		1		—		—		(2)
Net periodic postretirement benefit cost (income)	$	(12)	$	(12)	$	(4)	$	1	$	1	$	2

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

(I) FAIR VALUE MEASUREMENTS

At September 30, ~~2017,~~2023, assets and liabilities measured at fair value on a recurring basis during the period, together with their associated level of the fair value hierarchy, were as follows:


	Fair Value Measurements Using:
At September 30, 2023	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Net Asset Value as a Practical Expedient (NAV)		Total
	(in millions)
Southern Company
Assets:
Energy-related derivatives(a)	$	7	$	73	$	—	$	—	$	80


Investments in trusts:(b)
Domestic equity	692		196		—		—		888
Foreign equity	131		154		—		—		285
U.S. Treasury and government agency securities	—		337		—		—		337
Municipal bonds	—		42		—		—		42
Pooled funds – fixed income	—		6		—		—		6
Corporate bonds	—		368		—		—		368
Mortgage and asset backed securities	—		85		—		—		85
Private equity	—		—		—		169		169
Cash and cash equivalents	3		—		—		—		3
Other	33		3		—		8		44
Cash equivalents and restricted cash	919		11		—		—		930
Other investments	9		34		8		—		51
Total	$	1,794	$	1,309	$	8	$	177	$	3,288
Liabilities:
Energy-related derivatives(a)	$	34	$	217	$	—	$	—	$	251
Interest rate derivatives	—		351		—		—		351
Foreign currency derivatives	—		192		—		—		192
Contingent consideration	5		—		19		—		24
Other	—		13		—		—		13
Total	$	39	$	773	$	19	$	—	$	831

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)


	Fair Value Measurements Using:
At September 30, 2023	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Net Asset Value as a Practical Expedient (NAV)		Total
	(in millions)
Alabama Power
Assets:
Energy-related derivatives	$	—	$	26	$	—	$	—	$	26

Nuclear decommissioning trusts:(b)
Domestic equity	404		188		—		—		592
Foreign equity	131		—		—		—		131
U.S. Treasury and government agency securities	—		20		—		—		20
Municipal bonds	—		1		—		—		1
Corporate bonds	—		215		—		—		215
Mortgage and asset backed securities	—		22		—		—		22
Private equity	—		—		—		169		169
Other	10		—		—		8		18
Cash equivalents and restricted cash	489		11		—		—		500
Other investments	—		34		—		—		34
Total	$	1,034	$	517	$	—	$	177	$	1,728
Liabilities:
Energy-related derivatives	$	—	$	75	$	—	$	—	$	75



Georgia Power
Assets:
Energy-related derivatives	$	—	$	14	$	—	$	—	$	14

Nuclear decommissioning trusts:(b)
Domestic equity	288		1		—		—		289
Foreign equity	—		153		—		—		153
U.S. Treasury and government agency securities	—		317		—		—		317
Municipal bonds	—		41		—		—		41
Corporate bonds	—		153		—		—		153
Mortgage and asset backed securities	—		63		—		—		63
Other	23		3		—		—		26

Total	$	311	$	745	$	—	$	—	$	1,056
Liabilities:
Energy-related derivatives	$	—	$	83	$	—	$	—	$	83

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)


	Fair Value Measurements Using:
At September 30, 2023	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Net Asset Value as a Practical Expedient (NAV)		Total
	(in millions)
Mississippi Power
Assets:
Energy-related derivatives	$	—	$	24	$	—	$	—	$	24

Cash equivalents	3		—		—		—		3
Total	$	3	$	24	$	—	$	—	$	27
Liabilities:
Energy-related derivatives	$	—	$	44	$	—	$	—	$	44



Southern Power
Assets:
Energy-related derivatives	$	—	$	5	$	—	$	—	$	5

Cash equivalents	23		—		—		—		23
Total	$	23	$	5	$	—	$	—	$	28
Liabilities:
Energy-related derivatives	$	—	$	6	$	—	$	—	$	6
Foreign currency derivatives	—		42		—		—		42
Contingent consideration	5		—		19		—		24
Other	—		13		—		—		13
Total	$	5	$	61	$	19	$	—	$	85

Southern Company Gas
Assets:
Energy-related derivatives(a)	$	7	$	4	$	—	$	—	$	11

Non-qualified deferred compensation trusts:
Domestic equity	—		7		—		—		7
Foreign equity	—		1		—		—		1
Pooled funds – fixed income	—		6		—		—		6
Cash equivalents	3		—		—		—		3
Cash equivalents	294		—		—		—		294

Total	$	304	$	18	$	—	$	—	$	322
Liabilities:
Energy-related derivatives(a)	$	34	$	9	$	—	$	—	$	43
Interest rate derivatives	—		99		—		—		99

Total	$	34	$	108	$	—	$	—	$	142

(a)Excludes cash collateral of $49 million.

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

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

Southern Company, Alabama Power, and Georgia Power continue to elect the option to fair value investment securities held in the nuclear decommissioning trust funds. The fair value of the funds, including reinvested interest and dividends and excluding the funds' expenses, increased (decreased) by the amounts shown in the table below for the three and nine months ended September 30, 2023 and 2022. The changes were recorded as a change to the regulatory assets and liabilities related to AROs for Georgia Power and Alabama Power, respectively.


	Three Months Ended				Nine Months Ended
Fair value increases (decreases)	September 30, 2023		September 30, 2022		September 30, 2023		September 30, 2022
	(in millions)
Southern Company	$	(4)	$	(106)	$	211	$	(486)
Alabama Power	(36)		(53)		54		(245)
Georgia Power	32		(53)		157		(241)

Valuation Methodologies

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

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

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

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

Southern Power has contingent payment obligations related to two of its acquisitions whereby it is primarily obligated to make generation-based payments to the seller, commencing at the commercial operation of each facility and continuing through 2026 and 2035, respectively. The obligations are primarily categorized as Level 3 under Fair Value Measurements as the fair value is determined using significant unobservable inputs for the forecasted facility's generation in MW-hours, as well as other inputs such as a fixed dollar amount per MW-hour, and a discount rate. The fair value of contingent consideration reflects the net present value of expected payments and any periodic change arising from forecasted generation is expected to be immaterial.

Southern Power also has payment obligations through 2040 whereby it must reimburse the transmission owners for interconnection facilities and network upgrades constructed to support connection of a Southern Power generating facility to the transmission system. The obligations are categorized as Level 2 under Fair Value Measurements as the fair value is determined using observable inputs for the contracted amounts and reimbursement period, as well as a discount rate. The fair value of the obligations reflects the net present value of expected payments.

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

At September 30, 2023, the fair value measurements of private market investments held in Alabama Power's nuclear decommissioning trusts that are calculated at net asset value per share (or its equivalent) as a practical expedient totaled $177 million and unfunded commitments related to the private market investments totaled $72 million. Private market investments include high-quality private equity funds across several market sectors, funds that invest in real estate assets, and a private credit fund. Private market funds do not have redemption rights. Distributions from these funds will be received as the underlying investments in the funds are liquidated.

At September 30, 2023, other financial instruments for which the carrying amount did not equal fair value were as follows:


	Southern Company(*)		Alabama Power		Georgia Power		Mississippi Power		Southern Power		Southern Company Gas(*)
	(in billions)
Long-term debt, including securities due within one year:
Carrying amount	$	58.8	$	11.2	$	15.8	$	1.6	$	2.7	$	8.1
Fair value	50.8		9.4		13.4		1.3		2.4		6.5

(*)The carrying amount of Southern Company Gas' long-term debt includes fair value adjustments from the effective date of the 2016 merger with Southern Company. Southern Company Gas amortizes the fair value adjustments over the remaining lives of the respective bonds, the latest being through 2043.

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

(J) DERIVATIVES

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, each company nets its exposures, where possible, to take advantage of natural offsets and enters into various derivative transactions for the remaining exposures pursuant to each company's policies in areas such as counterparty exposure and risk management practices. For the traditional electric operating companies, Southern Power, and Southern Company Gas' other businesses, each company's policy is that derivatives are to be used primarily for hedging purposes and mandates strict adherence to all applicable risk management policies. Derivative positions are monitored using techniques including, but not limited to, market valuation, value at risk, stress testing, and sensitivity analysis. Derivative instruments are recognized at fair value in the balance sheets as either assets or liabilities and are presented on a net basis. See Note (I) for additional fair value information. In the statements of cash flows, any cash impacts of settled energy-related and interest rate derivatives are recorded as operating activities. Any cash impacts of settled foreign currency derivatives are classified as operating or financing activities

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

to correspond with the classification of the hedged interest or principal, respectively. See Note 1 to the financial statements under "Financial Instruments" in Item 8 of the Form 10-K for additional information.

Energy-Related Derivatives

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

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

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

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

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

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

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

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

At September 30, 2023, the net volume of energy-related derivative contracts for natural gas positions, together with the longest hedge date over which the respective entity is hedging its exposure to the variability in future cash flows for forecasted transactions and the longest non-hedge date for derivatives not designated as hedges, were as follows:


	Net Purchased mmBtu	Longest Hedge Date	Longest Non-Hedge Date
	(in millions)
Southern Company(*)	422	2030	2028
Alabama Power	109	2026	—
Georgia Power	104	2026	—
Mississippi Power	80	2027	—
Southern Power	8	2030	2024
Southern Company Gas(*)	121	2027	2028

(*)Southern Company Gas' derivative instruments include both long and short natural gas positions. A long position is a contract to purchase natural gas and a short position is a contract to sell natural gas. Southern Company Gas' volume represents the net of 135.5 million mmBtu long natural gas positions and 14.2 million mmBtu short natural gas positions at September 30, 2023, which is also included in Southern Company's total volume.

In addition to the volumes discussed above, the traditional electric operating companies and Southern Power enter into physical natural gas supply contracts that provide the option to sell back excess natural gas due to operational constraints. The maximum expected volume of natural gas subject to such a feature is 14 million mmBtu for Southern Company, which includes 4 million mmBtu for Alabama Power, 5 million mmBtu for Georgia Power, 2 million mmBtu for Mississippi Power, ~~does~~and 3 million mmBtu for Southern Power.

For cash flow hedges of energy-related derivatives, the estimated pre-tax losses expected to be reclassified from accumulated OCI to earnings for the 12-month period ending September 30, 2024 are $30 million for Southern Company, $25 million for Southern Company Gas, and immaterial for Southern Power.

Interest Rate Derivatives

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

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

At September 30, 2023, the following interest rate derivatives were outstanding:


	Notional Amount		Weighted Average Interest Rate Paid	Interest Rate Received	Hedge Maturity Date	Fair Value Gain (Loss) at September 30, 2023
	(in millions)					(in millions)


Fair Value Hedges of Existing Debt
Southern Company parent	$	400	1-month SOFR + 0.80%	1.75%	March 2028	$	(56)
Southern Company parent	1,000		1-month SOFR + 2.48%	3.70%	April 2030	(196)
Southern Company Gas	500		1-month SOFR + 0.49%	1.75%	January 2031	(99)
Southern Company	$	1,900				$	(351)

For cash flow hedges of interest rate derivatives, the estimated pre-tax losses expected to be reclassified from accumulated OCI to interest expense for the 12-month period ending September 30, 2024 are $19 million for Southern Company and immaterial for the traditional electric operating companies and Southern Company Gas. Deferred gains and losses related to interest rate derivatives are expected to be amortized into earnings through 2052 for Southern Company, Alabama Power, and Georgia Power, 2028 for Mississippi Power, and 2046 for Southern Company Gas.

Foreign Currency Derivatives

Southern Company and certain subsidiaries, including Southern Power, may enter into foreign currency derivatives to hedge exposure to changes in foreign currency exchange rates, such as that arising from the issuance of debt denominated in a currency other than U.S. dollars. Derivatives related to forecasted transactions are accounted for as cash flow hedges where the derivatives' fair value gains or losses are recorded in OCI and are reclassified into earnings at the same time and on the same income statement line as the earnings effect of the hedged transactions, including foreign currency gains or losses arising from changes in the U.S. currency exchange rates. Derivatives related to existing fixed rate securities are accounted for as fair value hedges, where the derivatives' fair value gains or losses and hedged items' fair value gains or losses are both recorded directly to earnings on the same income statement line item, including foreign currency gains or losses arising from changes in the U.S. currency exchange rates. Southern Company has elected to exclude the cross-currency basis spread from the assessment of effectiveness in the fair value hedges of its foreign currency risk and record any difference between the change in the fair value of the excluded components and the amounts recognized in earnings as a component of OCI.

At September 30, 2023, the following foreign currency derivatives were outstanding:


	Pay Notional		Pay Rate	Receive Notional		Receive Rate	Hedge Maturity Date	Fair Value Gain (Loss) at September 30, 2023
	(in millions)			(in millions)				(in millions)
Cash Flow Hedges of Existing Debt
Southern Power	$	564	3.78%	€	500	1.85%	June 2026	$	(42)

Fair Value Hedges of Existing Debt

Southern Company parent	1,476		3.39%	1,250		1.88%	September 2027	(150)


Southern Company	$	2,040		€	1,750			$	(192)

For cash flow hedges of foreign currency derivatives, the estimated pre-tax losses expected to be reclassified from accumulated OCI to earnings for the 12-month period ending September 30, 2024 are $10 million for Southern Power.

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

Derivative Financial Statement Presentation and Amounts

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

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


	At September 30, 2023				At December 31, 2022
Derivative Category and Balance Sheet Location	Assets		Liabilities		Assets		Liabilities
	(in millions)				(in millions)
Southern Company
Energy-related derivatives designated as hedging instruments for regulatory purposes

Assets from risk management activities/Liabilities from risk management activities	$	34	$	134	$	123	$	121
Other deferred charges and assets/Other deferred credits and liabilities	36		77		52		44


Total derivatives designated as hedging instruments for regulatory purposes	70		211		175		165
Derivatives designated as hedging instruments in cash flow and fair value hedges
Energy-related derivatives:
Assets from risk management activities/Liabilities from risk management activities	—		28		3		27
Other deferred charges and assets/Other deferred credits and liabilities	4		2		6		4
Interest rate derivatives:
Assets from risk management activities/Liabilities from risk management activities	—		80		12		62
Other deferred charges and assets/Other deferred credits and liabilities	—		271		—		240
Foreign currency derivatives:
Assets from risk management activities/Liabilities from risk management activities	—		35		—		34
Other deferred charges and assets/Other deferred credits and liabilities	—		157		—		182
Total derivatives designated as hedging instruments in cash flow and fair value hedges	4		573		21		549
Energy-related derivatives not designated as hedging instruments

Assets from risk management activities/Liabilities from risk management activities	5		8		13		13
Other deferred charges and assets/Other deferred credits and liabilities	1		2		2		1

Total derivatives not designated as hedging instruments	6		10		15		14
Gross amounts recognized	80		794		211		728
Gross amounts offset(a)	(37)		(86)		(70)		(111)
Net amounts recognized in the Balance Sheets(b)	$	43	$	708	$	141	$	617

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)


	At September 30, 2023				At December 31, 2022
Derivative Category and Balance Sheet Location	Assets		Liabilities		Assets		Liabilities
	(in millions)				(in millions)
Alabama Power(c)
Energy-related derivatives designated as hedging instruments for regulatory purposes

Other current assets/Other current liabilities	$	15	$	46	$	42	$	21
Other deferred charges and assets/Other deferred credits and liabilities	11		29		20		18
Total derivatives designated as hedging instruments for regulatory purposes	26		75		62		39






Gross amounts offset	(17)		(17)		(24)		(24)
Net amounts recognized in the Balance Sheets	$	9	$	58	$	38	$	15

Georgia Power
Energy-related derivatives designated as hedging instruments for regulatory purposes

Other current assets/Other current liabilities	$	4	$	57	$	36	$	43
Other deferred charges and assets/Other deferred credits and liabilities	10		26		6		18
Total derivatives designated as hedging instruments for regulatory purposes	14		83		42		61





Energy-related derivatives not designated as hedging instruments

Other current assets/Other current liabilities	—		—		—		1

Gross amounts recognized	14		83		42		62
Gross amounts offset	(11)		(11)		(21)		(21)
Net amounts recognized in the Balance Sheets	$	3	$	72	$	21	$	41

Mississippi Power(c)
Energy-related derivatives designated as hedging instruments for regulatory purposes

Other current assets/Other current liabilities	$	9	$	22	$	33	$	24
Other deferred charges and assets/Other deferred credits and liabilities	15		22		26		8
Total derivatives designated as hedging instruments for regulatory purposes	24		44		59		32






Gross amounts offset	(17)		(17)		(17)		(17)
Net amounts recognized in the Balance Sheets	$	7	$	27	$	42	$	15

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)


	At September 30, 2023				At December 31, 2022
Derivative Category and Balance Sheet Location	Assets		Liabilities		Assets		Liabilities
	(in millions)				(in millions)
Southern Power
Derivatives designated as hedging instruments in cash flow and fair value hedges
Energy-related derivatives:
Other current assets/Other current liabilities	$	—	$	5	$	—	$	12
Other deferred charges and assets/Other deferred credits and liabilities	4		—		5		—
Foreign currency derivatives:
Other current assets/Other current liabilities	—		11		—		11
Other deferred charges and assets/Other deferred credits and liabilities	—		31		—		36
Total derivatives designated as hedging instruments in cash flow and fair value hedges	4		47		5		59
Energy-related derivatives not designated as hedging instruments

Other current assets/Other current liabilities	1		1		2		—
Other deferred charges and assets/Other deferred credits and liabilities	—		—		1		—
Total derivatives not designated as hedging instruments	1		1		3		—
Gross amounts recognized	5		48		8		59
Gross amounts offset	(1)		(1)		—		—
Net amounts recognized in the Balance Sheets	$	4	$	47	$	8	$	59

Southern Company Gas
Energy-related derivatives designated as hedging instruments for regulatory purposes

Other current assets/Other current liabilities	$	6	$	9	$	12	$	33


Derivatives designated as hedging instruments in cash flow and fair value hedges
Energy-related derivatives:
Other current assets/Other current liabilities	—		23		3		15
Other deferred charges and assets/Other deferred credits and liabilities	—		2		1		4
Interest rate derivatives:
Other current assets/Other current liabilities	—		21		—		14
Other deferred charges and assets/Other deferred credits and liabilities	—		78		—		72
Total derivatives designated as hedging instruments in cash flow and fair value hedges	—		124		4		105
Energy-related derivatives not designated as hedging instruments

Other current assets/Other current liabilities	4		7		11		12
Other deferred charges and assets/Other deferred credits and liabilities	1		2		1		1

Total derivatives not designated as hedging instruments	5		9		12		13
Gross amounts recognized	11		142		28		151
Gross amounts offset(a)	9		(40)		—		(41)
Net amounts recognized in the Balance Sheets(b)	$	20	$	102	$	28	$	110

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

(a)Gross amounts offset includes cash collateral held on deposit in broker margin accounts of $49 million and $41 million at September 30, 2023 and December 31, 2022, respectively.

(b)Net amounts of derivative instruments outstanding exclude immaterial premium and intrinsic value associated with weather derivatives for both periods presented.

(c)Energy-related derivatives not designated as hedging instruments were immaterial for Alabama Power and Mississippi Power at December 31, 2022. There were no such instruments for Alabama Power and Mississippi Power at September 30, 2023.

At September 30, 2023 and December 31, 2022, the pre-tax effects of unrealized derivative gains (losses) arising from energy-related derivative instruments designated as regulatory hedging instruments and deferred were as follows:


Regulatory Hedge Unrealized Gain (Loss) Recognized in the Balance Sheet
Derivative Category and Balance Sheet Location	Southern Company		Alabama Power		Georgia Power		Mississippi Power		Southern Company Gas
	(in millions)
At September 30, 2023:
Energy-related derivatives:
Other regulatory assets, current	$	(113)	$	(39)	$	(54)	$	(16)	$	(4)
Other regulatory assets, deferred	(48)		(19)		(18)		(11)		—


Other regulatory liabilities, current	23		8		1		4		10
Other regulatory liabilities, deferred	6		1		2		3		—
Total energy-related derivative gains (losses)	$	(132)	$	(49)	$	(69)	$	(20)	$	6

At December 31, 2022:
Energy-related derivatives:
Other regulatory assets, current	$	(71)	$	(8)	$	(26)	$	(13)	$	(24)
Other regulatory assets, deferred	(23)		(7)		(14)		(2)		—
Other regulatory liabilities, current	72		29		19		22		2
Other regulatory liabilities, deferred	31		9		2		20		—
Total energy-related derivative gains (losses)	$	9	$	23	$	(19)	$	27	$	(22)

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

For the three and nine months ended September 30, 2023 and 2022, the pre-tax effects of cash flow and fair value hedge accounting on accumulated OCI for the applicable Registrants were as follows:


Gain (Loss) Recognized in OCI on Derivatives	For the Three Months Ended September 30,				For the Nine Months Ended September 30,
	2023		2022		2023		2022
	(in millions)				(in millions)
Southern Company
Cash flow hedges:
Energy-related derivatives	$	(4)	$	11	$	(55)	$	51
Interest rate derivatives	(3)		6		(12)		36
Foreign currency derivatives	(15)		(35)		(6)		(137)
Fair value hedges(*):
Foreign currency derivatives	27		20		28		18
Total	$	5	$	2	$	(45)	$	(32)


Georgia Power
Cash flow hedges:
Interest rate derivatives	$	—	$	—	$	(3)	$	31



Southern Power
Cash flow hedges:
Energy-related derivatives	$	—	$	(11)	$	(14)	$	(4)

Foreign currency derivatives	(15)		(35)		(6)		(137)
Total	$	(15)	$	(46)	$	(20)	$	(141)
Southern Company Gas
Cash flow hedges:
Energy-related derivatives	$	(4)	$	22	$	(41)	$	55
Interest rate derivatives	(4)		5		—		—
Total	$	(8)	$	27	$	(41)	$	55

(*)Represents amounts excluded from the assessment of effectiveness for which the difference between changes in fair value and periodic amortization is recorded in OCI.

For the three and nine months ended September 30, 2022, the pre-tax effects of interest rate derivatives designated as cash flow hedging instruments on accumulated OCI were immaterial for Alabama Power and there were no such effects in 2023.

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

For the three and nine months ended September 30, 2023 and 2022, the pre-tax effects of cash flow and fair value hedge accounting on income were as follows:


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

	2023		2022		2023		2022
	(in millions)				(in millions)
Southern Company
Total cost of natural gas	$	102	$	294	$	1,199	$	1,840
Gain (loss) on energy-related cash flow hedges(a)	(4)		9		(32)		28
Total other operations and maintenance	1,424		1,527		4,352		4,568
Gain (loss) on energy-related cash flow hedges(a)	(1)		—		(2)		—
Total depreciation and amortization	1,143		922		3,365		2,728
Gain (loss) on energy-related cash flow hedges(a)	(5)		(1)		(18)		5
Total interest expense, net of amounts capitalized	(620)		(511)		(1,812)		(1,461)
Gain (loss) on interest rate cash flow hedges(a)	(22)		(7)		(31)		(19)
Gain (loss) on foreign currency cash flow hedges(a)	(3)		(3)		(8)		(16)
Gain (loss) on interest rate fair value hedges(b)	(47)		(102)		(50)		(300)
Total other income (expense), net	141		132		428		414
Gain (loss) on foreign currency cash flow hedges(a)(c)	(14)		(32)		(4)		(129)
Gain (loss) on foreign currency fair value hedges	(7)		(59)		19		(180)
Amount excluded from effectiveness testing recognized in earnings	(27)		(21)		(28)		(17)










Southern Power
Total depreciation and amortization	$	130	$	133	$	380	$	384
Gain (loss) on energy-related cash flow hedges(a)	(5)		(1)		(18)		5
Total interest expense, net of amounts capitalized	(32)		(32)		(98)		(105)
Gain (loss) on foreign currency cash flow hedges(a)	(3)		(3)		(8)		(16)
Total other income (expense), net	4		3		8		5
Gain (loss) on foreign currency cash flow hedges(a)(c)	(14)		(32)		(4)		(129)
Southern Company Gas
Total cost of natural gas	$	102	$	294	$	1,199	$	1,840
Gain (loss) on energy-related cash flow hedges(a)	(4)		9		(32)		28
Total other operations and maintenance	264		252		879		824
Gain (loss) on energy-related cash flow hedges(a)	(1)		—		(2)		—
Total interest expense, net of amounts capitalized	(77)		(65)		(226)		(187)
Gain (loss) on interest rate cash flow hedges(a)	(18)		(2)		(18)		(3)
Gain (loss) on interest rate fair value hedges(b)	(11)		(30)		(14)		(87)

(a)Reclassified from accumulated OCI into earnings.

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

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

The pre-tax effects of cash flow and fair value hedge accounting on income for interest rate derivatives were immaterial for the traditional electric operating companies for all periods presented.

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

At September 30, 2023 and December 31, 2022, the following amounts were recorded on the balance sheets related to cumulative basis adjustments for fair value hedges:


	Carrying Amount of the Hedged Item				Cumulative Amount of Fair Value Hedging Adjustment included in Carrying Amount of the Hedged Item
Balance Sheet Location of Hedged Items	At September 30, 2023		At December 31, 2022		At September 30, 2023		At December 31, 2022
	(in millions)				(in millions)
Southern Company

Long-term debt	$	(2,873)	$	(2,927)	$	328	$	282

Southern Company Gas

Long-term debt	$	(402)	$	(415)	$	95	$	81

For the three and nine months ended September 30, 2023 and 2022, the pre-tax effects of energy-related derivatives not designated as hedging instruments on the statements of income of Southern Company and Southern Company Gas were as follows:


		Gain (Loss)
		Three Months Ended September 30,				Nine Months Ended September 30,
Derivatives in Non-Designated Hedging Relationships	Statements of Income Location	2023		2022		2023		2022
		(in millions)				(in millions)

Energy-related derivatives:	Natural gas revenues(*)	$	—	$	3	$	—	$	(10)
	Cost of natural gas	7		(2)		36		(7)

Total derivatives in non-designated hedging relationships		$	7	$	1	$	36	$	(17)

(*)Excludes $14 million of gains for the nine months ended September 30, 2023, and immaterial amounts for all other periods presented, recorded in natural gas revenues associated with weather derivatives.

For the three and nine months ended September 30, 2023 and 2022, the pre-tax effects of energy-related derivatives not designated as hedging instruments were immaterial for the other Registrants.

Contingent Features

The Registrants do not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade.

On October 4, 2017, Mississippi Power executed agreements with its largest retail customer, Chevron, to continue providing 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.

There are certain ~~contracts~~derivatives that ~~have required or~~ could require collateral, but not accelerated payment, in the event of avarious credit rating change to BBB and/or Baa2 or below. These contracts are for physical electricity purchases and sales, fuel transportation and storage, energy price risk management, and transmission. At September 30, 2017, the maximum potential collateral requirements at a rating below BBB- and/or Baa3 equaled approximately $255 million.

~~Included in these amounts are~~changes of certain ~~agreements that could require collateral in the event that Alabama Power or Georgia Power has a credit rating change to below investment grade.~~Southern Company subsidiaries. Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. ~~Additionally,~~At September 30, 2023, the Registrants had no collateral posted with derivative counterparties to satisfy these arrangements.

For Southern Company, the fair value of foreign currency derivative liabilities and interest rate derivative liabilities with contingent features, and the maximum potential collateral requirements arising from the credit-risk-related contingent features at a rating below BBB- and/or Baa3, was $78 million at September 30, 2023. For Southern Power, the fair value of foreign currency derivative liabilities with contingent features, and the maximum potential collateral requirements arising from the credit-risk-related contingent features at a rating below BBB- and/or Baa3, was $20 million at September 30, 2023. For the traditional electric operating companies and Southern Power, energy-related derivative liabilities with contingent features and the maximum potential collateral requirements arising from the credit-risk-related contingent features, at a rating below BBB- and/or Baa3, were immaterial at September 30, 2023. The maximum potential collateral requirements arising from the credit-risk-related contingent features for the traditional electric operating companies and Southern Power include certain agreements that could

Table of ContentsIndex to Financial Statements

NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

require collateral in the event that one or more Southern Company power pool participants has a credit rating ~~downgrade could impact~~change to below investment grade.

Alabama Power and Southern Power maintain accounts with certain regional transmission organizations to facilitate financial derivative transactions and they may be required to post collateral based on the ~~ability~~value of ~~Mississippi~~the positions in these accounts and the associated margin requirements. At September 30, 2023, cash collateral posted in these accounts was $18 million for Southern Power and immaterial for Alabama Power. Southern Company Gas maintains accounts with brokers or the clearing houses of certain exchanges to ~~access capital markets,~~facilitate financial derivative transactions. Based on the value of the positions in these accounts and ~~would~~the associated margin requirements, Southern Company Gas may be ~~likely~~required to ~~impact~~deposit cash into these accounts. At September 30, 2023, cash collateral held on deposit in broker margin accounts was $49 million.

The Registrants are exposed to losses related to financial instruments in the ~~cost at which it does so.~~

~~On March 1, 2017,~~event of counterparties' nonperformance. The Registrants only enter into agreements and material transactions with counterparties that have investment grade credit ratings by Moody's ~~downgraded the senior unsecured debt rating of Mississippi Power to Ba1 from Baa3.~~

~~On March 24, 2017,~~and S&P ~~revised~~or with counterparties who have posted collateral to cover potential credit exposure. The Registrants have also established risk management policies and controls to determine and monitor the creditworthiness of counterparties in order to mitigate their exposure to counterparty credit risk.

Southern Company Gas uses established credit policies to determine and monitor the creditworthiness of counterparties, including requirements to post collateral or other credit security, as well as the quality of pledged collateral. Collateral or credit security is most often in the form of cash or letters of credit from an investment-grade financial institution, but may also include cash or U.S. government securities held by a trustee. Prior to entering a physical transaction, Southern Company Gas assigns its ~~consolidated~~counterparties an internal credit rating ~~outlook for~~and credit limit based on the counterparties' Moody's, S&P, and Fitch ratings, commercially available credit reports, and audited financial statements. Southern Company ~~and its subsidiaries (including Mississippi Power) from stable~~Gas may require counterparties to ~~negative.~~pledge additional collateral when deemed necessary.

~~On March 30, 2017, Fitch placed the ratings of Mississippi Power on rating watch negative.~~

~~On June 22, 2017, Moody's placed the ratings of Mississippi Power on review for downgrade. On September 21, 2017, Moody's revised its rating outlook for Mississippi Power from under review to stable.~~

~~Financing Activities~~

~~In March 2017, Mississippi Power issued a $9 million short-term bank note bearing interest at 5% per annum, which was repaid in April 2017.~~

~~In February 2017, Mississippi Power amended $551 million in promissory notes to~~ Southern Company ~~extending~~Gas utilizes netting agreements whenever possible to mitigate exposure to counterparty credit risk. Netting agreements enable Southern Company Gas to net certain assets and liabilities by counterparty across product lines and against cash collateral, provided the ~~maturity dates~~netting and cash collateral agreements include such provisions. While the amounts due from, or owed to, counterparties are settled net, they are recorded on a gross basis on the balance sheet as energy marketing receivables and energy marketing payables.

The Registrants do not anticipate a material adverse effect on their respective financial statements as a result of counterparty nonperformance.

Table of ContentsIndex to Financial Statements

NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

(K) ACQUISITIONS AND DISPOSITIONS

See Note 15 to the financial statements in Item 8 of the ~~notes from December 1, 2017 to July 31, 2018. In the second quarter 2017, Mississippi Power borrowed an additional $40 million under a promissory note issued to Southern Company.~~

In June 2017, Southern Company made equity contributions totaling $1.0 billion to Mississippi Power. Mississippi Power used a portion of the proceeds to (i) prepay $300 million of the outstanding principal amount under its $1.2 billion unsecured term loan, which matures on March 30, 2018; (ii) repay all of the $591 million outstanding principal amount of promissory notes to Southern Company; and (iii) repay a $10 million short-term bank loan.

~~In August 2017, Mississippi Power repaid a $12.5 million short-term bank note.~~

In September 2017, Mississippi Power issued a floating rate promissory note to Southern Company in an aggregate principal amount of up to $150 million bearing interest based on one-month LIBOR. Mississippi Power borrowed $109 million under this promissory note primarily to satisfy its federal income tax obligations for the quarter ending September 30, 2017 and subsequently repaid the promissory note upon receipt of its income tax refund from the U.S. federal government related to the settlement concerning deductible R&E expenditures. See Note (G) to the Condensed Financial Statements under "Section 174 Research and Experimental Deduction" hereinForm 10-K for additional information.

~~149~~

~~Table of Contents~~

~~MISSISSIPPI POWER COMPANY~~

~~MANAGEMENT'S DISCUSSION AND ANALYSIS OF~~

~~FINANCIAL CONDITION AND RESULTS OF OPERATIONS~~

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

~~SOUTHERN POWER COMPANY~~

~~AND SUBSIDIARY COMPANIES~~

~~SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES~~

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

For the Three Months Ended September 30, For the Nine Months Ended September 30,
2017 2016 2017 2016
(in millions) (in millions)
Operating Revenues:
Wholesale revenues, non-affiliates $ 510
$ 387
$ 1,293
$ 866
Wholesale revenues, affiliates 105
110
295
313
Other revenues 3
3
9
10
Total operating revenues 618
500
1,597
1,189
Operating Expenses:
Fuel 189
154
460
341
Purchased power, non-affiliates 36
25
90
60
Purchased power, affiliates 7
8
23
16
Other operations and maintenance 83
81
272
246
Depreciation and amortization 131
93
379
247
Taxes other than income taxes 13
5
37
17
Total operating expenses 459

366
1,261
927
Operating Income 159
134
336
262
Other Income and (Expense):
Interest expense, net of amounts capitalized (47 ) (35 ) (144 ) (78 )
Other income (expense), net 3
2
3
3
Total other income and (expense) (44 ) (33 ) (141 ) (75 )
Earnings Before Income Taxes 115
101
195
187
Income taxes (benefit) (39 ) (102 ) (129 ) (167 )
Net Income 154
203
324
354
Less: Net income attributable to noncontrolling interests 30
27
48
39
Net Income Attributable to Southern Power $ 124
$ 176
$ 276
$ 315

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

For the Three Months Ended September 30, For the Nine Months Ended September 30,
2017 2016 2017 2016
(in millions) (in millions)
Net Income $ 154
$ 203
$ 324
$ 354
Other comprehensive income (loss):
Qualifying hedges:
Changes in fair value, net of tax of
$15, $14, $35, and $(1), respectively 25
23
58
(1 )
Reclassification adjustment for amounts included in net income,
net of tax of $(12), $(1), $(42), and $7, respectively (20 ) (1 ) (68 ) 13
Total other comprehensive income (loss) 5
22
(10 ) 12
Comprehensive Income 159
225
314
366
Less: Comprehensive income attributable to noncontrolling interests 30
27
48
39
Comprehensive Income Attributable to Southern Power $ 129
$ 198
$ 266
$ 327

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

~~SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES~~

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

For the Nine Months Ended September 30,
2017 2016
(in millions)
Operating Activities:
Net income $ 324
$ 354
Adjustments to reconcile net income to net cash provided from operating activities —
Depreciation and amortization, total 404
262
Deferred income taxes 240
(668 )
Amortization of investment tax credits (42 ) (25 )
Collateral deposits (1 ) (80 )
Income taxes receivable, non-current (42 ) —
Other, net (2 ) 19
Changes in certain current assets and liabilities —
-Receivables (77 ) (82 )
-Other current assets 38
(15 )
-Accounts payable (31 ) 7
-Accrued taxes 79
483
-Other current liabilities 5
14
Net cash provided from operating activities 895
269
Investing Activities:
Business acquisitions (1,032 ) (1,134 )
Property additions (218 ) (1,702 )
Change in construction payables (166 ) (69 )
Payments pursuant to LTSAs (99 ) (58 )
Investment in restricted cash (16 ) (750 )
Distribution of restricted cash 33
746
Other investing activities 7
(41 )
Net cash used for investing activities (1,491 ) (3,008 )
Financing Activities:
Increase (decrease) in notes payable, net (89 ) 692
Proceeds —
Senior notes —
1,531
Capital contributions from parent company —
800
Other long-term debt 43
63
Redemptions — Other long-term debt (4 ) (84 )
Distributions to noncontrolling interests (89 ) (22 )
Capital contributions from noncontrolling interests 79
367
Purchase of membership interests from noncontrolling interests —
(129 )
Payment of common stock dividends (238 ) (204 )
Other financing activities (27 ) (14 )
Net cash provided from (used for) financing activities (325 ) 3,000
Net Change in Cash and Cash Equivalents (921 ) 261
Cash and Cash Equivalents at Beginning of Period 1,099
830
Cash and Cash Equivalents at End of Period $ 178
$ 1,091
Supplemental Cash Flow Information:
Cash paid (received) during the period for —
Interest (net of $7 and $32 capitalized for 2017 and 2016, respectively) $ 144
$ 49
Income taxes, net (343 ) 71
Noncash transactions — Accrued property additions at end of period 16
210

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

~~SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES~~

~~CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)~~

Assets At September 30, 2017 At December 31, 2016
(in millions)
Current Assets:
Cash and cash equivalents $ 178
$ 1,099
Receivables —
Customer accounts receivable 148
102
Other 61
34
Affiliated 74
57
Fossil fuel stock 15
15
Materials and supplies 351
337
Prepaid income taxes 51
74
Other current assets 26
39
Total current assets 904
1,757
Property, Plant, and Equipment:
In service 13,734
12,728
Less: Accumulated provision for depreciation 1,823
1,484
Plant in service, net of depreciation 11,911
11,244
Construction work in progress 425
398
Total property, plant, and equipment 12,336
11,642
Other Property and Investments:
Intangible assets, net of amortization of $41 and $22
at September 30, 2017 and December 31, 2016, respectively 417
436
Total other property and investments 417
436
Deferred Charges and Other Assets:
Prepaid LTSAs 77
101
Accumulated deferred income taxes 400
594
Income taxes receivable, non-current 53
11
Other deferred charges and assets — affiliated 6
13
Other deferred charges and assets — non-affiliated 455
615
Total deferred charges and other assets 991
1,334
Total Assets $ 14,648
$ 15,169

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

~~SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES~~

~~CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)~~

Liabilities and Stockholders' Equity At September 30, 2017 At December 31, 2016
(in millions)
Current Liabilities:
Securities due within one year $ 864
$ 560
Notes payable 120
209
Accounts payable —
Affiliated 93
88
Other 84
278
Accrued taxes —
Accrued income taxes 101
148
Other accrued taxes 30
7
Accrued interest 36
36
Acquisitions payable —
461
Contingent consideration 15
46
Other current liabilities 58
70
Total current liabilities 1,401
1,903
Long-term Debt 4,946
5,068
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes 191
152
Accumulated deferred ITCs 1,900
1,839
Asset retirement obligations 76
64
Other deferred credits and liabilities 232
304
Total deferred credits and other liabilities 2,399
2,359
Total Liabilities 8,746
9,330
Redeemable Noncontrolling Interests 59
164
Common Stockholder's Equity:
Common stock, par value $.01 per share —
Authorized — 1,000,000 shares
Outstanding — 1,000 shares —
—
Paid-in capital 3,661
3,671
Retained earnings 762
724
Accumulated other comprehensive income 25
35
Total common stockholder's equity 4,448
4,430
Noncontrolling interests 1,395
1,245
Total stockholders' equity 5,843
5,675
Total Liabilities and Stockholders' Equity $ 14,648
$ 15,169

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

~~155~~

~~Table of Contents~~

~~SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES~~

~~MANAGEMENT'S DISCUSSION AND ANALYSIS OF~~

~~FINANCIAL CONDITION AND RESULTS OF OPERATIONS~~

~~THIRD QUARTER 2017 vs. THIRD QUARTER 2016~~

~~AND~~

~~YEAR-TO-DATE 2017 vs. YEAR-TO-DATE 2016~~

~~OVERVIEW~~

Southern Power

Asset Acquisitions

Southern Power's asset acquisitions during the nine months ended September 30, 2023 are detailed in the following table:

Project Facility

Resource

Seller

Approximate Nameplate Capacity (MW)

Location

Southern Power Ownership Percentage

Expected COD

PPA Contract Period

Millers Branch(*)

Solar

EDF Renewables, Inc.

200

Haskell County, TX

100%

Fourth quarter 2025

20 years

South Cheyenne

Solar

Hanwha Q Cells USA Corp.

150

Laramie County, WY

100%

First quarter 2024

20 years

(*)The project includes an option to expand capacity up to an additional 300 MWs.

The aggregate purchase price for the two projects was $193 million, which is primarily recorded within construction work in progress on the balance sheet.

Southern Company Gas

On September 22, 2023, Southern Company Gas completed the sale of its California natural gas storage facility, resulting in an immaterial loss.

(L) SEGMENT AND RELATED INFORMATION

Southern Company

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

Southern Company's reportable business segments are the sale of electricity by the traditional electric operating companies, the sale of electricity in the competitive wholesale market by Southern Power, ~~continually seeks opportunities~~and the sale of natural gas and other complementary products and services by Southern Company Gas. Revenues from sales by Southern Power to ~~execute its strategy to create value through various transactions including acquisitions~~the traditional electric operating companies were $156 million and $406 million for the three and nine months ended September 30, 2023, respectively, and $336 million and $673 million for the three and nine months ended September 30, 2022, respectively. Revenues from sales of ~~assets, construction~~natural gas from Southern Company Gas to the traditional electric operating companies and ~~development of new generating facilities,~~Southern Power were immaterial for all periods presented. The "All Other" column includes the Southern Company parent entity, which does not allocate operating expenses to business segments. Also, this category includes segments below the quantitative threshold for separate disclosure. These segments include providing distributed energy and ~~entry into PPAs primarily with investor-owned utilities, independent power producers, municipalities,~~resilience solutions and ~~other load-serving entities,~~deploying microgrids for commercial, industrial, governmental, and utility customers, as well as ~~commercial~~investments in telecommunications. All other inter-segment revenues are not material.

Table of ContentsIndex to Financial Statements

NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

Financial data for business segments and ~~industrial customers. In general,~~products and services for the three and nine months ended September 30, 2023 and 2022 was as follows:


	Electric Utilities
	Traditional Electric Operating Companies		Southern Power		Eliminations		Total		Southern Company Gas		All Other		Eliminations		Consolidated
	(in millions)
Three Months Ended September 30, 2023
Operating revenues	$	5,674	$	653	$	(160)	$	6,167	$	689	$	154	$	(30)	$	6,980
Segment net income (loss)(a)(b)(c)	1,419		100		—		1,519		82		(179)		—		1,422
Nine Months Ended September 30, 2023
Operating revenues	$	14,145	$	1,686	$	(417)	$	15,414	$	3,417	$	499	$	(122)	$	19,208
Segment net income (loss)(a)(b)(c)(d)	2,852		288		—		3,140		475		(490)		(4)		3,121
At September 30, 2023
Goodwill	$	—	$	2	$	—	$	2	$	5,015	$	144	$	—	$	5,161
Total assets	99,464		13,090		(568)		111,986		24,823		2,370		(858)		138,321
Three Months Ended September 30, 2022
Operating revenues	$	6,938	$	1,180	$	(691)	$	7,427	$	857	$	135	$	(41)	$	8,378
Segment net income (loss)(a)(b)	1,445		95		—		1,540		83		(152)		1		1,472
Nine Months Ended September 30, 2022
Operating revenues	$	16,716	$	2,618	$	(1,391)	$	17,943	$	3,998	$	418	$	(127)	$	22,232
Segment net income (loss)(a)(b)	3,256		265		—		3,521		516		(415)		(11)		3,611
At December 31, 2022
Goodwill	$	—	$	2	$	—	$	2	$	5,015	$	144	$	—	$	5,161
Total assets	95,861		13,081		(659)		108,283		24,621		2,665		(678)		134,891

(a)Attributable to Southern Company.

(b)For the traditional electric operating companies, includes pre-tax charges (credits) to income at Georgia Power for the estimated probable loss associated with the construction of Plant Vogtle Units 3 and 4 of $160 million ($120 million after tax) for the three and nine months ended September 30, 2023 and $(70) million ($(52) million after tax) and $(18) million ($(13) million after tax) for the three and nine months ended September 30, 2022, respectively. See Note (B) and Note 2 to the financial statements in Item 8 of the Form 10-K under "Georgia Power – Nuclear Construction" for additional information.

(c)For Southern Power, ~~has constructed or acquired new generating capacity only~~includes an $18 million pre-tax loss recovery ($9 million after ~~entering into or assuming long-term PPAs~~tax and partnership allocations) for the ~~new facilities.~~

~~During~~three and nine months ended September 30, 2023 related to an arbitration interim award and a $16 million pre-tax gain ($12 million after tax) on the sale of spare parts for the nine months ended September 30, ~~2017,~~2023. See Note (C) under "General Litigation Matters – Southern Power acquired or completed the construction of, and placed in service, approximately 498 MWs of solar and wind facilities. In addition, Southern Power began construction at the recently acquired Cactus Flats wind facility, continued development of its portfolio of wind projects, and continued expansion of the Mankato natural gas facility by 345 MWs of capacity. See FUTURE EARNINGS POTENTIAL – "~~Acquisitions" and "Construction Projects" herein~~Power" for additional information.

(d)For Southern ~~Power is considering the sale of up to~~Company Gas, includes a ~~one-third equity interest in its solar asset portfolio. The ultimate outcome of this matter cannot be determined at this time.~~

~~At September 30, 2017, Southern Power had an average investment coverage ratio of 91% through 2021 and 90% through 2026, with an average remaining contract duration~~pre-tax charge of approximately ~~16 years. These ratios include the PPAs and capacity~~$38 million ($28 million after tax) associated with ~~facilities currently~~the disallowance of certain capital expenditures at Nicor Gas. See Note (B) under ~~construction and acquisitions discussed herein. See FUTURE EARNINGS POTENTIAL~~ – "~~Power Sales Agreements" herein~~"Southern Company Gas" for additional information.

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

~~RESULTS OF OPERATIONS~~

~~Net Income~~

Third Quarter 2017 vs. Third Quarter 2016 Year-to-Date 2017 vs. Year-to-Date 2016
(change in millions) (% change) (change in millions) (% change)
$(52) (29.5) $(39) (12.4)

Net income attributable to Southern Power for the third quarter 2017 was $124 million compared to $176 million for the corresponding period in 2016. The decrease was primarily due to decreased income tax benefits from solar ITCs and increased interest expense primarily due to a decrease in capitalized interest associated with completing construction of and placing in service solar facilities, partially offset by additional operating income related to new generating facilities.

Net income attributable to Southern Power for year-to-date 2017 was $276 million compared to $315 million for the corresponding period in 2016. The decrease was primarily due to decreased income tax benefits resulting from a reduction in solar ITCs, partially offset by an increase in wind PTCs, and increased interest expense from debt issuances to fund Southern Power's growth strategy and continuous construction program, partially offset by additional operating income from new generating facilities.

~~For additional information on new generating facilities placed in service during 2016 and 2017, see MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Acquisitions" and~~

~~156~~

Table of ContentsIndex to Financial Statements

~~SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES~~

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

~~FINANCIAL CONDITION AND RESULTS OF OPERATIONS~~

(UNAUDITED)

Products and Services

~~"Construction Projects" of Southern Power in Item 7 of the Form 10-K and FUTURE EARNINGS POTENTIAL – "Acquisitions" and "Construction Projects" herein.~~


	Electric Utilities' Revenues
	Retail		Wholesale		Other		Total
	(in millions)
Three Months Ended September 30, 2023	$	5,139	$	727	$	301	$	6,167
Three Months Ended September 30, 2022	5,961		1,197		269		7,427
Nine Months Ended September 30, 2023	$	12,597	$	1,930	$	887	$	15,414
Nine Months Ended September 30, 2022	14,363		2,798		782		17,943

~~Operating Revenues~~


	Southern Company Gas' Revenues
	Gas Distribution Operations		Gas Marketing Services		Other		Total
	(in millions)
Three Months Ended September 30, 2023	$	617	$	56	$	16	$	689
Three Months Ended September 30, 2022	748		85		24		857
Nine Months Ended September 30, 2023	$	2,989	$	376	$	52	$	3,417
Nine Months Ended September 30, 2022	3,513		420		65		3,998

Third Quarter 2017 vs. Third Quarter 2016 Year-to-Date 2017 vs. Year-to-Date 2016
(change in millions) (% change) (change in millions) (% change)
$118 23.6 $408 34.3

Total operating revenues include PPA capacity revenues, which are derived primarily from long-term contracts involving natural gas and biomass generating facilities, and PPA energy revenues, which include sales from Southern Power's natural gas, biomass, solar, and wind facilities. To the extent Southern Power has capacity not contracted under a PPA, it may sell power into the wholesale market and, to the extent the generation assets are part of the IIC, as approved by the FERC, it may sell power into the power pool.

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

~~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 is generally sold at variable cost or is indexed to published 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 a capacity charge. Customers either purchase the energy output of a dedicated renewable facility through an energy charge or pay a fixed price related to the energy 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, and other factors.

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

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

Third Quarter 2017 Third Quarter 2016 Year-to-Date 2017 Year-to-Date 2016
(in millions)
PPA capacity revenues $ 169
$ 149
$ 466
$ 406
PPA energy revenues 299
247
765
532
Total PPA revenues 468
396
1,231
938
Non-PPA revenues 147
101
357
241
Other revenues 3
3
9
10
Total operating revenues $ 618
$ 500
$ 1,597
$ 1,189

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

~~FINANCIAL CONDITION AND RESULTS OF OPERATIONS~~

(UNAUDITED)

Southern Company Gas

InSouthern Company Gas manages its business through three reportable segments – gas distribution operations, gas pipeline investments, and gas marketing services. The non-reportable segments are combined and presented as all other.

Gas distribution operations is the ~~third quarter 2017, total operating revenues were $618 million, reflecting~~largest component of Southern Company Gas' business and includes natural gas local distribution utilities that construct, manage, and maintain intrastate natural gas pipelines and gas distribution facilities in four states.

Gas pipeline investments consists of joint ventures in natural gas pipeline investments including a ~~$118 million, or 24%, increase from the corresponding period~~50% interest in ~~2016. The increase in operating revenues was primarily due to the following:~~

~~PPA capacity revenues increased $20 million, or 13%, primarily due to additional customer capacity requirements~~SNG and a ~~new PPA related to~~50% joint ownership interest in the Dalton Pipeline. These natural gas ~~facilities.~~

PPA energy revenues increased $52 million, or 21%, primarily due to a $55 million increase in sales from new solar and wind facilities, partially offset by a $3 million decrease in sales from natural gas PPAs due to a $24 million decrease in volume primarily due topipelines enable the ~~expiration~~provision of ~~a PPA and reduced customer load, partially offset by a $21 million increase in the average cost of fuel.~~

Non-PPA revenues increased $46 million, or 46%, due to a $58 million increase in the volume of KWHs sold primarily from uncovered natural gas capacity through short-term opportunity sales, offset by a $12 million decrease in the price of energy in the wholesale markets.

For year-to-date 2017, total operating revenues were $1.6 billion, reflecting a $408 million, or 34%, increase from the corresponding period in 2016. The increase in operating revenues was primarily due to the following:

~~PPA capacity revenues increased $60 million, or 15%, primarily due to additional customer capacity requirements and a new PPA related to natural gas facilities.~~

PPA energy revenues increased $233 million, or 44%, primarily due to a $188 million increase in sales from new solar and wind facilities and a $35 million increase in sales from natural gas PPAs primarily due to a $69 million increase in the average cost of fuel, partially offset by a $34 million decrease in volume primarily due to the expiration of a PPA and reduced customer load.

Non-PPA revenues increased $116 million, or 48%, due to a $104 million increase in the volume of KWHs sold primarily from uncovered natural gas capacity through short-term opportunity sales, as well as a $12 million increase in the price of energy in the wholesale markets.

~~Fuel and Purchased Power Expenses~~

Fuel costs constitute the single largest expense for Southern Power. In addition, Southern Power purchases a portion of its electricity needs from the wholesale market. Details of Southern Power's generation and purchased power were as follows:

Third Quarter 2017 Third Quarter 2016 Year-to-Date 2017 Year-to-Date 2016
(in billions of KWHs)
Generation 12.5 11.1 33.2 27.9
Purchased power 1.2 0.9 3.4 2.5
Total generation and purchased power 13.7 12.0 36.6 30.4

Total generation and purchased power, excluding solar, wind, and tolling agreements 7.2 6.7 17.8 17.7

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

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

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

Third Quarter 2017
vs.
Third Quarter 2016 Year-to-Date 2017
vs.
Year-to-Date 2016
(change in millions) (% change) (change in millions) (% change)
Fuel $ 35
22.7 $ 119
34.9
Purchased power 10
30.3 37
48.7
Total fuel and purchased power expenses $ 45
$ 156

In the third quarter 2017, total fuel and purchased power expenses increased $45 million, or 24.1%, compared to the corresponding period in 2016. Fuel expense increased $35 million primarily due to a $29 million increase in the average costdiverse sources of natural gas per KWH generated and an $8 million increase in the volume of KWHs generated, excluding solar, wind, and tolling agreements. Purchased power expense increased $10 million primarily due to an increase in the volume of KWHs purchased.

~~For year-to-date 2017, total fuel and purchased power expenses increased $156 million, or 37.4%, compared~~supplies to the corresponding period in 2016. Fuel expense increased $119 million primarily due to a $139 million increase in the average cost of natural gas per KWH generated, partially offset by a $19 million decrease in the volume of KWHs generated, excluding solar, wind, and tolling agreements. Purchased power expense increased $37 million due to a $28 million increase in the volume of KWHs purchased and a $9 million increase associated with the average cost of purchased power.

~~Other Operations and Maintenance Expenses~~

Third Quarter 2017 vs. Third Quarter 2016 Year-to-Date 2017 vs. Year-to-Date 2016
(change in millions) (% change) (change in millions) (% change)
$2 2.5 $26 10.6

In the third quarter 2017, other operations and maintenance expenses were $83 million compared to $81 million for the corresponding period in 2016. The increase was primarily due to a $13 million increase associated with new solar, wind, and gas facilities, partially offset by a $5 million decrease in scheduled outage maintenance expenses and a $5 million decrease in non-outage operations and maintenance expenses.

For year-to-date 2017, other operations and maintenance expenses were $272 million compared to $246 million for the corresponding period in 2016. The increase was primarily due to a $48 million increase associated with new solar, wind, and gas facilities and an $8 million increase associated with employee compensation and expenses in supportcustomers of Southern ~~Power's overall growth strategy, partially offset by a $22 million decrease in scheduled outage maintenance expenses and an $8 million decrease in non-outage operations and maintenance expenses.~~

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~~Depreciation and Amortization~~

Third Quarter 2017 vs. Third Quarter 2016 Year-to-Date 2017 vs. Year-to-Date 2016
(change in millions) (% change) (change in millions) (% change)
$38 40.9 $132 53.4

In the third quarter 2017, depreciation and amortization was $131 million compared to $93 million for the corresponding period in 2016. For year-to-date 2017, depreciation and amortization was $379 million compared to $247 million for the corresponding period in 2016. The increases were primarily due to new solar, wind, and gas facilities placed in service.

~~Taxes Other Than Income Taxes~~

Third Quarter 2017 vs. Third Quarter 2016 Year-to-Date 2017 vs. Year-to-Date 2016
(change in millions) (% change) (change in millions) (% change)
$8 160.0 $20 117.6

In the third quarter 2017, taxes other than income taxes were $13 million compared to $5 million for the corresponding period in 2016. For year-to-date 2017, taxes other than income taxes were $37 million compared to $17 million for the corresponding period in 2016. These increases were primarily due to additional property taxes due to new solar, wind, and gas facilities.

~~Interest Expense, net of Amounts Capitalized~~

Third Quarter 2017 vs. Third Quarter 2016 Year-to-Date 2017 vs. Year-to-Date 2016
(change in millions) (% change) (change in millions) (% change)
$12 34.3 $66 84.6

In the third quarter 2017, interest expense, net of amounts capitalized was $47 million compared to $35 million for the corresponding period in 2016. The increase was primarily due to an $8 million decrease in capitalized interest associated with completing construction of and placing in service solar facilities and an increase of $3 million in interest expense due to an increase in average outstanding long-term debt, primarily to fund Southern Power's growth strategy and continuous construction program.

For year-to-date 2017, interest expense, net of amounts capitalized was $144 million compared to $78 million for the corresponding period in 2016. The increase was primarily due to an increase of $39 million in interest expense due to an increase in average outstanding long-term debt, primarily to fund Southern Power's growth strategy and continuous construction program, as well as a $25 million decrease in capitalized interest associated with completing construction of and placing in service solar facilities.

~~Other Income (Expense), Net~~

Third Quarter 2017 vs. Third Quarter 2016 Year-to-Date 2017 vs. Year-to-Date 2016
(change in millions) (% change) (change in millions) (% change)
$1 50.0 $— —

In the third quarter 2017, other income (expense), net was $3 million compared to $2 million for the corresponding period in 2016. Other income (expense), net was $3 million for both year-to-date 2017 and 2016. The changes include increases of $36 million and $152 million from currency losses arising from translation of €1.1 billion euro-denominated fixed-rate notes into U.S. dollars for the third quarter and year-to-date 2017, respectively, fully offset by an equal change in gains on the foreign currency hedges that were reclassified from accumulated OCI into earnings.Company Gas. See Note ~~(H) to the Condensed Financial Statements herein for additional information.~~

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~~Income Taxes (Benefit)~~

Third Quarter 2017 vs. Third Quarter 2016 Year-to-Date 2017 vs. Year-to-Date 2016
(change in millions) (% change) (change in millions) (% change)
$63 61.8 $38 22.8

In the third quarter 2017, income tax benefit was $39 million compared to $102 million for the corresponding period in 2016. The decrease was primarily due to a $61 million decrease in income tax benefits from solar ITCs.

For year-to-date 2017, income tax benefit was $129 million compared to $167 million for the corresponding period in 2016. The decrease was primarily due to a $102 million decrease in income tax benefits from solar ITCs, partially offset by a $58 million increase in wind PTCs and a $4 million increase resulting from state apportionment rate changes.

~~See Note (G) to the Condensed Financial Statements herein for additional information on income taxes and Note 1~~7 to the financial statements ~~of Southern Power~~ under ~~"Income and Other Taxes"~~"Southern Company Gas" in Item 8 of the Form 10-K for additional ~~information on ITCs~~information.

Gas marketing services provides natural gas marketing to end-use customers primarily in Georgia and ~~PTCs.~~

~~FUTURE EARNINGS POTENTIAL~~Illinois through SouthStar.

The ~~results of operations discussed above are not necessarily indicative of Southern Power's future earnings potential.~~all other column includes segments and subsidiaries that fall below the quantitative threshold for separate disclosure, including storage and fuels operations. The level of Southern Power's future earnings depends on numerous factors that affect the opportunities, challenges, and risks of Southern Power's competitive wholesale business. These factors include: Southern Power's ability to achieve sales growth while containing costs; regulatory matters; creditworthiness of customers; total generating capacity availableall other column included a natural gas storage facility in ~~Southern Power's market areas; the successful remarketing of capacity as current contracts expire; Southern Power's ability to execute~~Texas through its growth strategy, including successful additional investments in renewable and other energy projects, and to develop and construct generating facilities. Current proposals related to potential federal tax reform legislation are primarily focused on reducing the corporate income tax rate, allowing 100% of capital expenditures to be deducted, and eliminating the interest deduction. The ultimate impact of any tax reform proposals, including any potential changes to the availability or realizability of ITCs and PTCs, is dependent on the final form of any legislation enacted and the related transition rules, and cannot be determined at this time, but could have a material impact on Southern Power's consolidated financial statements.

~~Southern Power is considering the~~ sale ~~of up to a one-third equity interest in its solar asset portfolio. The ultimate outcome of this matter cannot be determined at this time.~~

Demand for electricity is primarily driven by the pace of economic growth that may be affected by changes in regional and global economic conditions, as well as renewable portfolio standards, which may impact future earnings.

Other factors that could influence future earnings include weather, demand, cost of generation from facilities within the power pool, and operational limitations. For additional information relating to these factors, see RISK FACTORS in Item 1A and MANAGEMENT'S DISCUSSION AND ANALYSIS – ~~FUTURE EARNINGS POTENTIAL of Southern Power in Item 7 of the Form 10-K.~~

~~Power Sales Agreements~~

See BUSINESS – "The Southern Company System – Southern Power" in Item 1 of the Form 10-K for additional information regarding Southern Power's PPAs. Generally, under the solar and wind generation PPAs, the purchasing party retains the right to keep or resell the renewable energy credits.

At September 30, 2017, Southern Power's average investment coverage ratio for its generating assets, based on the ratio of investment under contract to total investment using the respective generation facilities' net book value (or expected in-service value for facilities under construction) as the investment amount, was 91% through 2021 and 90% through 2026, with an average remaining contract duration of approximately 16 years.

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~~Environmental Matters~~

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

~~Environmental Statutes and Regulations~~

~~Water Quality~~

~~See MANAGEMENT'S DISCUSSION AND ANALYSIS~~ – ~~FUTURE EARNINGS POTENTIAL~~ – ~~"Environmental Matters~~ – ~~Environmental Statutes and Regulations~~ – ~~Water Quality" of Southern Power in Item 7 of the Form 10-K for additional information regarding the final effluent guidelines rule.~~

~~On April 25, 2017, the EPA published a notice announcing it would reconsider the effluent guidelines rule, which had been finalized~~ in November ~~2015. On~~2022 and a natural gas storage facility in California through its sale in September ~~18, 2017, the EPA published a final rule establishing a stay of the compliance deadlines for certain effluent limitations and pretreatment standards under the rule.~~

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

~~Global Climate Issues~~

~~See MANAGEMENT'S DISCUSSION AND ANALYSIS~~ – ~~FUTURE EARNINGS POTENTIAL~~ – ~~"Environmental Matters~~ – ~~Global Climate Issues" of Southern Power in Item 7 of the Form 10-K for additional information.~~

On March 28, 2017, the U.S. President signed an executive order directing agencies to review actions that potentially burden the development or use of domestically produced energy resources. The executive order specifically directs the EPA to review the Clean Power Plan and final greenhouse gas emission standards for new, modified, and reconstructed electric generating units and, if appropriate, take action to suspend, revise, or rescind those rules. On October 16, 2017, the EPA published a proposed rule to repeal the Clean Power Plan. The EPA has not determined whether or when it will promulgate a replacement rule.

~~On June 1, 2017, the U.S. President announced that the United States will withdraw from the non-binding Paris Agreement and begin renegotiation of its terms.~~

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

~~FERC Matters~~

~~See MANAGEMENT'S DISCUSSION AND ANALYSIS~~ – ~~FUTURE EARNINGS POTENTIAL~~ – "FERC Matters" of Southern Power in Item 7 of the Form 10-K for additional information regarding the traditional electric operating companies' and Southern Power's market power proceeding and amendment to their market-rate tariff.

On May 17, 2017, the FERC accepted the traditional electric operating companies' and Southern Power's compliance filing accepting the terms of the FERC's February 2, 2017 order regarding an amendment by the traditional electric operating companies and Southern Power to their market-based rate tariff. While the FERC's order references the traditional electric operating companies' and Southern Power's market power proceeding related to their 2014 triennial updated market power analysis, that proceeding remains a separate, ongoing matter.

On October 25, 2017, the FERC issued an order in response to the traditional electric operating companies' and Southern Power's June 30, 2017 triennial updated market power analysis. The FERC directed the traditional electric operating companies and Southern Power to show cause within 60 days why market-based rate authority should not be revoked in certain areas adjacent to the area presently under mitigation in accordance with the February 2, 2017

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order, or to provide a mitigation plan to further address market power concerns. The traditional electric operating companies and Southern Power expect to make a filing within the specified 60 days responding to the FERC's order.

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

~~Acquisitions~~

During the nine months ended September 30, 2017, in accordance with Southern Power's overall growth strategy, one of Southern Power's wholly-owned subsidiaries acquired the project discussed below. Acquisition-related costs were expensed as incurred and were not material.2023. See Note ~~(I) to the Condensed Financial Statements under "Southern Power~~" herein and MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" of Southern Power in Item 7 of the Form 10-K for additional information.

Project Facility Resource
Approximate Nameplate Capacity (MW)
Location Percentage Ownership Actual COD PPA Counterparties PPA Contract Period
Bethel Wind 276 Castro County, TX 100 % January 2017 Google Energy, LLC 12 years

The aggregate amounts of revenue and net income recognized by Southern Power related to the Bethel facility included in Southern Power's condensed consolidated statements of income for year-to-date 2017 were immaterial. The Bethel facility did not have operating revenues or activities prior to completion of construction and the assets being placed in service; therefore, supplemental pro forma information as though the acquisition occurred as of the beginning of 2017 and for the comparable 2016 period is not meaningful and has been omitted.

Subsequent to September 30, 2017, Southern Power purchased all of the redeemable noncontrolling interests, representing 10% of the membership interests, in Southern Turner Renewable Energy, LLC and repaid $14 million of notes payable to Turner Renewable Energy, LLC.

~~Construction Projects~~

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

~~Construction Projects Completed and in Progress~~

During the nine months ended September 30, 2017, in accordance with its overall growth strategy, Southern Power completed construction of and placed in service, or continued construction of, the projects set forth in the following table. Through September 30, 2017, total costs of construction incurred for these projects were $494 million, of which $122 million remained in CWIP. Total aggregate construction costs, excluding the acquisition costs, are expected to be between $360 million and $415 million for the Mankato and Cactus Flats facilities. The ultimate outcome of these matters cannot be determined at this time.

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~~Project Facility~~	~~Resource~~	~~Approximate Nameplate Capacity (~~MW)	~~Location~~	~~Actual/Expected COD~~	~~PPA Counterparties~~	~~PPA Contract Period~~
~~Projects Completed During the Nine Months Ended September 30, 2017~~
~~East Pecos~~	~~Solar~~	~~120~~	~~Pecos County, TX~~	~~March 2017~~	~~Austin Energy~~	15 ~~years~~
~~Lamesa~~	~~Solar~~	~~102~~	~~Dawson County, TX~~	~~April 2017~~	~~City of Garland, Texas~~	~~15 years~~

~~Projects Under Construction as of September 30, 2017~~
~~Cactus Flats~~^(*)	~~Wind~~	~~148~~	~~Concho County, TX~~	~~Third quarter 2018~~	~~General Motors, LLC~~ ~~and~~ ~~General Mills Operations, LLC~~	~~12 years~~ ~~and~~ ~~15 years~~
~~Mankato~~	~~Natural Gas~~	~~345~~	~~Mankato, MN~~	~~Second quarter 2019~~	~~Northern States Power Company~~	~~20 years~~


~~(*)~~	~~On July 31, 2017, Southern Power acquired a 100% ownership interest in the Cactus Flats facility, which is in the early stages of construction, from RES America Developments, Inc.~~

~~Development Projects~~

In December 2016, as part of Southern Power's renewable development strategy, one of Southern Power's wholly-owned subsidiaries entered into a joint development agreement with Renewable Energy Systems Americas, Inc. to develop and construct approximately 3,000 MWs of wind projects. Also in December 2016, Southern Power signed agreements and made payments to purchase wind turbine equipment from Siemens Wind Power, Inc. and Vestas-American Wind Technology, Inc. to be used for construction of the facilities. All of the wind turbine equipment was delivered by April 2017, which allows the projects to qualify for 100% PTCs for 10 years following their expected commercial operation dates between 2018 and 2020. The ultimate outcome of these matters cannot be determined at this time.

~~Income Tax Matters~~

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Income Tax Matters" of Southern Power in Item 7 of the Form 10-K and Note (G) to the Condensed Financial Statements herein for additional information.

During the third quarter 2017, Southern Power began a legal entity reorganization of various direct and indirect subsidiaries that own and operate solar facilities, including certain subsidiaries owned in partnership with various third parties. Southern Power's ownership interests in the various solar entities and facilities will not be affected by the reorganization. The reorganization is expected to result in estimated tax benefits totaling approximately $40 million that will be recorded in the fourth quarter 2017 related to certain changes in state apportionment rates and net operating loss carryforward utilization. The ultimate outcome of this matter cannot be determined at this time.

~~Other Matters~~

Southern Power is involved in various other matters being litigated and regulatory matters that could affect future earnings. In addition, Southern Power is subject to certain claims and legal actions arising in the ordinary course of business. Southern Power's business activities are subject to extensive governmental regulation related to public health and the environment, such as regulation of air emissions and water discharges. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements, such as air quality and water standards, has occurred throughout the U.S. This litigation has included claims for damages alleged to have been caused by CO₂ ~~and other emissions and alleged exposure to hazardous materials, and/or requests for injunctive relief in connection with such matters.~~

The ultimate outcome of such pending or potential litigation or regulatory matters cannot be predicted at this time; however, for current proceedings not specifically reported in Note (B) to the Condensed Financial Statements

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~~herein, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on Southern Power's financial statements.~~

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

~~ACCOUNTING POLICIES~~

~~Application of Critical Accounting Policies and Estimates~~

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

~~Recently Issued Accounting Standards~~

~~See MANAGEMENT'S DISCUSSION AND ANALYSIS – ACCOUNTING POLICIES – "Recently Issued Accounting Standards" of Southern Power in Item 7 of the Form 10-K for additional information.~~

~~In 2014, the FASB issued ASC 606,~~ ~~Revenue from Contracts with Customers~~ (ASC 606), replacing the existing accounting standard and industry specific guidance for revenue recognition with a five-step model for recognizing and measuring revenue from contracts with customers. The underlying principle of the standard is to recognize revenue to depict the transfer of goods or services to customers at the amount expected to be collected. The new standard also requires enhanced disclosures regarding the nature, amount, timing, and uncertainty of revenue and the related cash flows arising from contracts with customers.

While Southern Power expects most of its revenue to be included in the scope of ASC 606, it has not fully completed its evaluation of all revenue arrangements. However, given Southern Power's core activities of selling generation capacity and energy to high credit rated customers, Southern Power currently does not expect the new standard to have a significant impact to net income. Southern Power's ongoing evaluation of revenue streams and

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related contracts includes the evaluation of identified revenue streams tied to longer-term contractual arrangements, such as certain capacity and energy payments under PPAs that are expected to be excluded from the scope of ASC 606 and included in the scope of the current leasing guidance (ASC 840).

The new standard is effective for interim and annual reporting periods beginning after December 15, 2017. Southern Power intends to use the modified retrospective method of adoption effective January 1, 2018. Southern Power has also elected to utilize practical expedients which allow it to apply the standard to open contracts at the date of adoption and to reflect the aggregate effect of all modifications when identifying performance obligations and allocating the transaction price for contracts modified before the effective date. Under the modified retrospective method of adoption, prior year reported results are not restated; however, a cumulative-effect adjustment to retained earnings at January 1, 2018 is recorded. In addition, disclosures will include comparative information on 2018 financial statement line items under current guidance. While the adoption of ASC 606, including the cumulative-effect adjustment, is not expected to have a material impact on either the timing or amount of revenues recognized in Southern Power's financial statements, Southern Power will continue to evaluate the requirements, as well as any additional clarifying guidance that may be issued.

~~On August 28, 2017, the FASB issued ASU No. 2017-12,~~ ~~Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities~~ (ASU 2017-12), amending the hedge accounting recognition and presentation requirements. ASU 2017-12 makes more financial and non-financial hedging strategies eligible for hedge accounting, amends the related presentation and disclosure requirements, and simplifies hedge effectiveness assessment requirements. ASU 2017-12 is effective for fiscal years beginning after December 15, 2018 and interim periods within those fiscal years, with early adoption permitted. Southern Power is evaluating the standard and expects to early adopt ASU 2017-12 effective January 1, 2018. The adoption of ASU 2017-12 is not expected to have a material impact on Southern Power's financial statements.

~~FINANCIAL CONDITION AND LIQUIDITY~~

~~Overview~~

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Overview" of Southern Power in Item 7 of the Form 10-K for additional information. Southern Power's financial condition remained stable at September 30, 2017. Southern Power intends to continue to monitor its access to short-term and long-term capital markets as well as bank credit agreements as needed to meet future capital and liquidity needs. See "~~Sources of Capital" herein for additional information on lines of credit.~~

Southern Power anticipates utilizing third-party tax equity as one of the financing sources to fund its renewable growth strategy; however, the use of third-party tax equity structures is not expected to have a material impact on future earnings. Subsequent to September 30, 2017, Southern Power secured third-party tax equity funding for the recently acquired Cactus Flats project subject to achieving commercial operation and various other customary conditions to closing. The ultimate outcome of this matter cannot be determined at this time.

Net cash provided from operating activities totaled $895 million for the first nine months of 2017 compared to $269 million for the first nine months of 2016. The increase in net cash provided from operating activities was primarily due to income tax refunds received and an increase in energy sales arising from new solar and wind facilities, partially offset by an increase in interest paid. See FUTURE EARNINGS POTENTIAL – "Income Tax Matters – Bonus Depreciation" of Southern Power in Item 7 of the Form 10-K for additional information. Net cash used for investing activities totaled $1.5 billion for the first nine months of 2017 primarily due to payments for renewable acquisitions and the construction of generating facilities. Net cash used for financing activities totaled $325 million for the first nine months of 2017 primarily due to common stock dividend payments, a decrease in notes payable, and distributions to noncontrolling interests, partially offset by capital contributions from noncontrolling interests. Cash flows from financing activities may vary from period to period based on capital needs and the maturity or redemption of securities.

~~Significant balance sheet changes for the first nine months of 2017 include a $1.0 billion increase in property, plant,~~

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~~SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES~~

~~MANAGEMENT'S DISCUSSION AND ANALYSIS OF~~

~~FINANCIAL CONDITION AND RESULTS OF OPERATIONS~~

and equipment in-service primarily related to acquisitions and completing construction of and placing in service solar facilities, a $921 million decrease in cash and cash equivalents, and a $461 million decrease in acquisitions payable.

~~See FUTURE EARNINGS POTENTIAL~~ – "~~Acquisitions" and "Construction Projects" herein for additional information.~~

~~Capital Requirements and Contractual Obligations~~

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" of Southern Power in Item 7 of the Form 10-K for a description of Southern Power's capital requirements for its construction program, scheduled maturities of long-term debt, as well as the related interest, derivative obligations, leases, unrecognized tax benefits, and other purchase commitments. Approximately $864 million will be required to repay maturities of long-term debt through September 30, 2018.

Southern Power's construction program includes estimates for potential plant acquisitions, new construction and development, capital improvements, and work to be performed under LTSAs and is subject to periodic review and revision. Planned expenditures for plant acquisitions may vary materially due to market opportunities and Southern Power's ability to execute its growth strategy. Actual capital costs may vary from these estimates because of numerous factors such as: changes in business conditions; changes in the expected environmental compliance program; changes in environmental statutes and regulations; the outcome of any legal challenges to the environmental rules; changes in FERC rules and regulations; changes in load projections; changes in legislation; the cost and efficiency of construction labor, equipment, and materials; project scope and design changes; and the cost of capital. See Note (I) to the Condensed Financial Statements herein for additional information.

~~Sources of Capital~~

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

As of September 30, 2017, Southern Power's current liabilities exceeded current assets by $497 million due to long-term debt maturing in the next 12 months, the use of short-term debt as a funding source, and fluctuations in cash needs, due to both seasonality and the stage of acquisitions and construction projects. Southern Power believes the need for working capital can be adequately met by utilizing the commercial paper program, the Facility (as defined below), bank term loans, the debt capital markets, and operating cash flows.

~~As of September 30, 2017, Southern Power had cash and cash equivalents of approximately $178 million.~~

Southern Power's commercial paper program is used to finance acquisition and construction costs related to electric generating facilities, for general corporate purposes, and to finance maturing debt. Commercial paper is included in notes payable on the condensed consolidated balance sheet at September 30, 2017.

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~~SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES~~

~~MANAGEMENT'S DISCUSSION AND ANALYSIS OF~~

~~FINANCIAL CONDITION AND RESULTS OF OPERATIONS~~

~~Details of commercial paper were as follows:~~

Short-term Debt at September 30, 2017
Short-term Debt During the Period ^(*)
Amount Outstanding Weighted Average Interest Rate Average Amount Outstanding Weighted Average Interest Rate
Maximum
Amount
Outstanding
(in millions) (in millions) (in millions)
Commercial paper $ 120
1.5 % $ 322
1.5 % $ 416


~~(*)~~	~~Average and maximum amounts are based upon daily balances during the three-month period ended September 30, 2017.~~

At September 30, 2017, Southern Power had a committed credit facility (Facility) of $750 million, of which $22 million has been used for letters of credit and $728 million remains unused. In May 2017, Southern Power amended the Facility, which, among other things, extended the maturity date from 2020 to 2022 and increased Southern Power's borrowing ability under this Facility to $750 million from $600 million. Proceeds from the Facility may be used for working capital and general corporate purposes as well as liquidity support for Southern Power's commercial paper program. Subject to applicable market conditions, Southern Power expects to renew or replace the Facility, as needed, prior to expiration. In connection therewith, Southern Power may extend the maturity date and/or increase or decrease the lending commitment thereunder. See Note 6 to the financial statements of Southern Power under "Bank Credit Arrangements" in Item 8 of the Form 10-K and Note ~~(E) to the Condensed Financial Statements~~(K) under "~~Bank Credit Arrangements" herein~~"Southern Company Gas" for additional information.

~~The Facility, as well as Southern Power's term loan agreement, contains a covenant that limits~~Business segment financial data for the ratio of debt to capitalization (as defined in the Facility) to a maximum of 65% and contains a cross-default provision that is restricted only to indebtedness of Southern Power. For purposes of this definition, debt excludes any project debt incurred by certain subsidiaries of Southern Power to the extent such debt is non-recourse to Southern Power, and capitalization excludes the capital stock or other equity attributable to such subsidiary. Southern Power is currently in compliance with all covenants in the Facility.

~~Southern Power also has a $120 million continuing letter of credit facility for standby letters of credit expiring in 2019. At~~three months ended September 30, ~~2017, $111~~2023 and 2022 was as follows:


	Gas Distribution Operations		Gas Pipeline Investments		Gas Marketing Services		Total		All Other		Eliminations		Consolidated
	(in millions)
Three Months Ended September 30, 2023
Operating revenues	$	619	$	8	$	56	$	683	$	8	$	(2)	$	689
Segment net income (loss)	70		24		2		96		(14)		—		82
Nine Months Ended September 30, 2023
Operating revenues	$	3,002	$	24	$	376	$	3,402	$	30	$	(15)	$	3,417
Segment net income(*)	352		73		59		484		(9)		—		475
Total assets at September 30, 2023	22,625		1,542		1,519		25,686		9,795		(10,658)		24,823
Three Months Ended September 30, 2022
Operating revenues	$	751	$	8	$	85	$	844	$	16	$	(3)	$	857
Segment net income (loss)	59		24		(2)		81		2		—		83
Nine Months Ended September 30, 2022
Operating revenues	$	3,533	$	24	$	420	$	3,977	$	43	$	(22)	$	3,998
Segment net income	365		76		65		506		10		—		516
Total assets at December 31, 2022	22,040		1,577		1,616		25,233		8,943		(9,555)		24,621

(*)For gas distribution operations, includes a pre-tax charge of approximately $38 million ~~has been used~~($28 million after tax) associated with the disallowance of certain capital expenditures at Nicor Gas. See Note (B) under "Southern Company Gas" for ~~letters of credit and $9 million remains unused.~~

~~Southern Power's subsidiaries do not borrow under the commercial paper program and are not parties to, and do not borrow under, the Facility or the continuing letter of credit facility.~~

~~Credit Rating Risk~~

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

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

additional information.

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~~SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES~~Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations.


			Page
Combined Management's Discussion and Analysis of Financial Condition and Results of Operations
Overview			101
Results of Operations			106
Southern Company			106
Alabama Power			115
Georgia Power			121
Mississippi Power			127
Southern Power			132
Southern Company Gas			136
Future Earnings Potential			142
Accounting Policies			147
Financial Condition and Liquidity			148

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.

100

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION

AND RESULTS OF OPERATIONS

~~The maximum potential collateral requirements under these contracts at September 30, 2017 were as follows:~~

Credit Ratings Maximum Potential
Collateral
Requirements
(in millions)
At BBB and/or Baa2 $ 37
At BBB- and/or Baa3 $ 398
At BB+ and/or Ba1^(*)
$ 1,124


~~(*)~~	~~Any additional credit rating downgrades at or below BB- and/or Ba3 could increase collateral requirements up to an additional $38 million.~~

Included in these amounts are certain agreements that could require collateral in the event that 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 Southern Power to access capital markets and would be likely to impact the cost at which it does so.

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

~~On March 24, 2017, S&P revised its consolidated credit rating outlook for Southern Company and its subsidiaries (including Southern Power) from stable to negative.~~

~~Financing Activities~~

In September 2017, Southern Power amended its $60 million aggregate principal amount floating rate bank loan to, among other things, increase the aggregate principal amount to $100 million and extend the maturity date from September 2017 to October 2018. The additional $40 million of proceeds were used to repay existing indebtedness and for other general corporate purposes.

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

~~SOUTHERN COMPANY GAS~~

~~AND SUBSIDIARY COMPANIES~~

~~SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES~~

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

Successor Predecessor
For the Three Months Ended September 30, For the Three Months Ended September 30, For the Nine Months Ended September 30, July 1, 2016 through September 30, January 1, 2016 through
June 30,
2017 2016 2017 2016 2016
(in millions) (in millions)
Operating Revenues:
Natural gas revenues (includes revenue
taxes of $9, $9, $75, $9, and $57 for the
periods presented, respectively) $ 532
$ 518
$ 2,746
$ 518
$ 1,841
Other revenues 33
25
95
25
64
Total operating revenues 565
543
2,841
543
1,905
Operating Expenses:
Cost of natural gas 134
133
1,085
133
755
Cost of other sales 7
2
20
2
14
Other operations and maintenance 205
216
671
216
454
Depreciation and amortization 125
116
370
116
206
Taxes other than income taxes 26
29
140
29
99
Merger-related expenses —
35
—
35
56
Total operating expenses 497
531
2,286
531
1,584
Operating Income 68
12
555
12
321
Other Income and (Expense):
Earnings from equity method investments 32
29
100
29
2
Interest expense, net of amounts capitalized (51 ) (39 ) (145 ) (39 ) (96 )
Other income (expense), net 18
9
26
9
5
Total other income and (expense) (1 ) (1 ) (19 ) (1 ) (89 )
Earnings Before Income Taxes 67
11
536
11
232
Income taxes 52
7
233
7
87
Net Income 15
4
303
4
145
Less: Net income attributable to
noncontrolling interest —
—
—
—
14
Net Income Attributable to
Southern Company Gas $ 15
$ 4
$ 303
$ 4
$ 131

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

~~SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES~~

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

Successor Predecessor
For the Three Months Ended September 30, For the Three Months Ended September 30, For the Nine Months Ended September 30, July 1, 2016 through September 30, January 1, 2016 through
June 30,
2017 2016 2017 2016 2016
(in millions) (in millions)
Net Income $ 15
$ 4
$ 303
$ 4
$ 145
Other comprehensive income (loss):
Qualifying hedges:
Changes in fair value, net of tax of
$-, $(2), $(2), $(2), and $(23),
respectively —
(3 ) (3 ) (3 ) (41 )
Reclassification adjustment for
amounts included in net income,
net of tax of $-, $-, $-, $-, and $-,
respectively —
—
—
—
1
Pension and other postretirement
benefit plans:
Reclassification adjustment for
amounts included in net income,
net of tax of $-, $-, $(1), $-, and $4,
respectively —
—
—
—
5
Total other comprehensive income (loss) —
(3 ) (3 ) (3 ) (35 )
Comprehensive Income 15
1
300
1
110
Less: Comprehensive income attributable to
noncontrolling interest —
—
—
—
14
Comprehensive Income Attributable to
Southern Company Gas $ 15
$ 1
$ 300
$ 1
$ 96

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

~~SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES~~

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

Successor Predecessor
For the Nine Months Ended September 30, July 1, 2016 through September 30, January 1, 2016 through
June 30,
2017 2016 2016
(in millions) (in millions)
Operating Activities:
Net income $ 303
$ 4
$ 145
Adjustments to reconcile net income
to net cash provided from operating activities —
Depreciation and amortization, total 370
116
206
Deferred income taxes 265
(30 ) 8
Pension, postretirement, and other employee benefits (4 ) (123 ) 5
Stock based compensation expense 25
11
20
Hedge settlements —
(35 ) (26 )
Mark-to-market adjustments (32 ) 17
162
Other, net (67 ) (47 ) (82 )
Changes in certain current assets and liabilities —
-Receivables 534
(18 ) 181
-Natural gas for sale, net of temporary LIFO liquidation —
(222 ) 273
-Prepaid income taxes (7 ) 1
151
-Other current assets (42 ) (36 ) 37
-Accounts payable (169 ) 78
43
-Accrued taxes (24 ) (11 ) 41
-Accrued compensation (11 ) (36 ) (21 )
-Other current liabilities 8
(11 ) (30 )
Net cash provided from (used for) operating activities 1,149
(342 ) 1,113
Investing Activities:
Property additions (1,093 ) (287 ) (509 )
Cost of removal, net of salvage (45 ) (21 ) (32 )
Change in construction payables, net 49
9
(7 )
Investment in unconsolidated subsidiaries (128 ) (1,421 ) (14 )
Returned investment in unconsolidated subsidiaries 22
2
3
Other investing activities 3
3
—
Net cash used for investing activities (1,192 ) (1,715 ) (559 )
Financing Activities:
Increase (decrease) in notes payable, net (323 ) 472
(896 )
Proceeds —
First mortgage bonds 200
—
250
Capital contributions from parent company 79
1,089
—
Senior notes 450
900
350
Redemptions and repurchases —
Medium-term notes (22 ) —
—
First mortgage bonds —
—
(125 )
Senior notes —
(300 ) —
Distributions to noncontrolling interest —
—
(19 )
Payment of common stock dividends (332 ) (63 ) (128 )
Other financing activities (7 ) (8 ) 10
Net cash provided from (used for) financing activities 45
2,090
(558 )
Net Change in Cash and Cash Equivalents 2
33
(4 )
Cash and Cash Equivalents at Beginning of Period 19
15
19
Cash and Cash Equivalents at End of Period $ 21
$ 48
$ 15
Supplemental Cash Flow Information:
Cash paid (received) during the period for —
Interest (net of $9, $2, and $3 capitalized, respectively) $ 146
$ 86
$ 119
Income taxes, net 17
54
(100 )
Noncash transactions —
Accrued property additions at end of period 112
50
41

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

~~SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES~~

~~CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)~~

Assets At September 30, 2017 At December 31, 2016
(in millions)
Current Assets:
Cash and cash equivalents $ 21
$ 19
Receivables —
Energy marketing receivables 427
623
Customer accounts receivable 221
364
Unbilled revenues 61
239
Other accounts and notes receivable 61
76
Accumulated provision for uncollectible accounts (26 ) (27 )
Materials and supplies 24
26
Natural gas for sale 631
631
Prepaid expenses 103
80
Assets from risk management activities, net of collateral 103
128
Other regulatory assets, current 96
81
Other current assets 25
10
Total current assets 1,747
2,250
Property, Plant, and Equipment:
In service 15,383
14,508
Less: Accumulated depreciation 4,567
4,439
Plant in service, net of depreciation 10,816
10,069
Construction work in progress 596
496
Total property, plant, and equipment 11,412
10,565
Other Property and Investments:
Goodwill 5,967
5,967
Equity investments in unconsolidated subsidiaries 1,609
1,541
Other intangible assets, net of amortization of $100 and $34
at September 30, 2017 and December 31, 2016, respectively 300
366
Miscellaneous property and investments 21
21
Total other property and investments 7,897
7,895
Deferred Charges and Other Assets:
Other regulatory assets, deferred 944
973
Other deferred charges and assets 190
170
Total deferred charges and other assets 1,134
1,143
Total Assets $ 22,190
$ 21,853

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

~~SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES~~

~~CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)~~

Liabilities and Stockholder's Equity At September 30, 2017 At December 31, 2016
(in millions)
Current Liabilities:
Securities due within one year $ —
$ 22
Notes payable 934
1,257
Energy marketing trade payables 451
597
Accounts payable 368
348
Customer deposits 137
153
Accrued taxes —
Accrued income taxes —
26
Other accrued taxes 70
68
Accrued interest 66
48
Accrued compensation 46
58
Liabilities from risk management activities, net of collateral 28
62
Other regulatory liabilities, current 126
102
Accrued environmental remediation, current 54
69
Other current liabilities 112
108
Total current liabilities 2,392
2,918
Long-term Debt 5,862
5,259
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes 2,214
1,975
Employee benefit obligations 431
441
Other cost of removal obligations 1,656
1,616
Accrued environmental remediation, deferred 345
357
Other regulatory liabilities, deferred 35
51
Other deferred credits and liabilities 88
127
Total deferred credits and other liabilities 4,769
4,567
Total Liabilities 13,023
12,744
Common Stockholder's Equity:
Common stock, par value $0.01 per share —
Authorized — 100 million shares
Outstanding — 100 shares —
—
Paid in capital 9,185
9,095
Accumulated deficit (41 ) (12 )
Accumulated other comprehensive income 23
26
Total common stockholder's equity 9,167
9,109
Total Liabilities and Stockholder's Equity $ 22,190
$ 21,853

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

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~~SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES~~

~~MANAGEMENT'S DISCUSSION AND ANALYSIS OF~~

~~FINANCIAL CONDITION AND RESULTS OF OPERATIONS~~

OVERVIEW

Southern Company ~~Gas~~ is ~~an energy services~~a holding company ~~whose~~that owns all of the common stock of three traditional electric operating companies (Alabama Power, Georgia Power, and Mississippi Power), Southern Power, and Southern Company Gas and owns other direct and indirect subsidiaries. The primary ~~business is~~businesses of the Southern Company system are electricity sales by the traditional electric operating companies and Southern Power and the distribution of natural gas ~~through utilities in seven states – Illinois, Georgia, Virginia, New Jersey, Florida, Tennessee, and Maryland.~~by Southern Company ~~Gas~~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 ~~its subsidiaries are also involved in several~~the sale of natural gas and other complementary ~~businesses.~~

products and services by Southern Company ~~Gas has four~~Gas. Southern Company Gas' reportable segments –are gas distribution operations, gas ~~marketing services, wholesale gas services,~~pipeline investments, and gas midstream operations – and one non-reportable segment – all other. For additional information on these segments, see Note (K) to the Condensed Financial Statements herein and "BUSINESS – Southern Company Gas" in Item 1 of the Form 10-K.

Many factors affect the opportunities, challenges, and risks of Southern Company Gas' business. These factors include the ability to maintain constructive regulatory environments, to maintain and grow natural gas sales, and to effectively manage and secure timely recovery of costs. Southern Company Gas has various regulatory mechanisms that operate to address cost recovery. Effectively operating pursuant to these regulatory mechanisms and appropriately balancing required costs and capital expenditures with customer prices will continue to challenge Southern Company Gas for the foreseeable future.

~~Merger, Acquisition, and Disposition Activities~~

On July 1, 2016, Southern Company Gas completed the Merger, which was accounted for by Southern Company using the acquisition method of accounting whereby the assets acquired and liabilities assumed were recognized at fair value as of the acquisition date. Pushdown accounting was applied to create a new cost basis for Southern Company Gas assets, liabilities, and equity as of the acquisition date. Accordingly, the successor financial statements reflect a new basis of accounting and successor and predecessor period financial results (separated by a heavy black line) are presented, but are not comparable. As a result of the application of acquisition accounting, certain discussions herein include disclosure of the predecessor and successor periods.marketing services. See Note ~~(I)~~(L) to the Condensed Financial Statements herein for additional information on segment reporting. Alabama Power, Georgia Power, and Mississippi Power each operate with one reportable business segment, since substantially all of their business is providing electric service to customers. Southern Power also operates its business with one reportable business segment, the sale of electricity in the competitive wholesale market. For additional information on the Registrants' primary business activities, see BUSINESS – "The Southern Company System" in Item 1 of the Form 10-K.

The Registrants continue to focus on several key performance indicators. For the traditional electric operating companies and Southern Company Gas, these indicators include, but are not limited to, customer satisfaction, plant availability, electric and natural gas system reliability, and execution of major construction projects. For Southern Power, these indicators include, but are 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. In addition, Southern Company and the Subsidiary Registrants focus on earnings per share and net income, respectively, as a key performance indicator.

Recent Developments

Alabama Power

On March 24, 2023, Alabama Power filed Rate CNP New Plant with the Alabama PSC to recover costs associated with the acquisition of the Central Alabama Generating Station. The filing reflected an annual increase in retail revenues of $78 million effective with June 2023 billings. Through May 2023, Alabama Power recovered substantially all costs associated with the Central Alabama Generating Station through Rate RSE, offset by revenues from a power sales agreement. On May 24, 2023, the Central Alabama Generating Station was placed into retail service.

On June 14, 2023, the Alabama PSC issued an order approving modifications to Alabama Power's Renewable Generation Certificate. The modifications authorized Alabama Power to procure an additional 2,400 MWs of renewable capacity and energy by June 14, 2029 and to market the related energy and environmental attributes to customers and other third parties. The modifications also increased the size of allowable renewable projects from 80 MWs to 200 MWs and increased the annual approval limit from 160 MWs to 400 MWs.

On July 11, 2023, the Alabama PSC issued an order authorizing Alabama Power to expand the existing authority of its reliability reserve to include certain production-related expenses that are intended to maintain reliability in periods between scheduled generating unit outages.

On August 18, 2023, Alabama Power notified the Alabama PSC of its intent to use a portion of its $166 million reliability reserve balance during 2023. The ultimate outcome of this matter cannot be determined at this time.

On October 3, 2023, the Alabama PSC issued an order modifying its December 2022 order and authorizing Alabama Power to (i) flow back in 2023 approximately $24 million of certain federal excess accumulated deferred income taxes resulting from the Tax Cuts and Jobs Act of 2017 and (ii) make available any remaining balance of excess accumulated deferred income taxes at the end of 2023 for the benefit of customers in 2024 and/or 2025. The ultimate outcome of this matter cannot be determined at this time.

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION

AND RESULTS OF OPERATIONS (Continued)

On November 1, 2023, Alabama Power placed Plant Barry Unit 8 in service. At September 30, 2023, project expenditures associated with Plant Barry Unit 8 totaled approximately $583 million.

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

Georgia Power

Plant Vogtle Units 3 and 4 Construction and Start-Up Status

Georgia Power placed Plant Vogtle Unit 3 in service on July 31, 2023 and continues construction on Plant Vogtle Unit 4 (each with electric generating capacity of approximately 1,100 MWs), in which it holds a 45.7% ownership interest. Georgia Power's share of the total project capital cost forecast to complete Plant Vogtle Units 3 and 4, including contingency, through July 2023 and March 2024, respectively, is $10.8 billion.

Hot functional testing for Unit 4 was completed on May 1, 2023. On July 20, 2023, Southern Nuclear announced that all Unit 4 ITAACs had been submitted to the NRC, and, on July 28, 2023, the NRC published its 103(g) finding that the accepted criteria in the combined license for Unit 4 had been met, which allowed nuclear fuel to be loaded and start-up testing to begin. Fuel load for Unit 4 was completed on August 19, 2023. On October 6, 2023, Georgia Power announced that during the start-up and pre-operational testing for Plant Vogtle Unit 4, Southern Nuclear identified a motor fault in one of four reactor coolant pumps (RCPs) and has started the process to replace this RCP with an on-site spare RCP from inventory. Considering this remediation and the remaining pre-operational testing, Unit 4 is projected to be placed in service during the first quarter 2024. The projected schedule for Unit 4 significantly depends on the pace and success of replacing the RCP, which involves removing and re-installing commodities around the RCP. In addition, any findings related to the root cause of the motor fault on the single Unit 4 RCP could require engineering changes or remediation related to the other seven Unit 3 and Unit 4 RCPs. Any further delays could result in a later in-service date and cost increases.

During the first nine months of 2023, established construction contingency totaling $43 million was assigned to the base capital cost forecast for costs primarily associated with the Unit 3 schedule extension and completion of start-up and pre-operational testing, including continued need of support resources for Unit 3 testing, as well as additional craft and support resources and subcontract work for Unit 4.

Georgia Power and the other Vogtle Owners did not agree on the starting dollar amount for the determination of cost increases subject to the cost-sharing and tender provisions of the Global Amendments (as defined in Note (B) to the Condensed Financial Statements under "Georgia Power – Nuclear Construction – Joint Owner Contracts" herein). The other Vogtle Owners notified Georgia Power that they believed the project capital cost forecast approved by the Vogtle Owners in February 2022 triggered the tender provisions.

In June 2022 and July 2022, OPC and Dalton, respectively, notified Georgia Power of their purported exercises of their tender options. Georgia Power did not accept these purported tender exercises. In June 2022, OPC and MEAG Power each filed a separate lawsuit against Georgia Power in the Superior Court of Fulton County, Georgia seeking a declaratory judgment that the starting dollar amount is $17.1 billion and that the cost-sharing and tender provisions had been triggered. In July 2022, Georgia Power filed its answers in the lawsuits filed by MEAG Power and OPC and included counterclaims seeking a declaratory judgment that the starting dollar amount is $18.38 billion and that costs related to force majeure events are excluded prior to calculating the cost-sharing and tender provisions and when calculating Georgia Power's related financial obligations. In September 2022, Dalton filed complaints in each of these lawsuits.

Also in September 2022, Georgia Power and MEAG Power reached an agreement to resolve their dispute regarding the proper interpretation of the cost-sharing and tender provisions of the Global Amendments. Under the terms of the agreement, among other items, (i) MEAG Power will not exercise its tender option and will retain its full ownership interest in Plant Vogtle Units 3 and 4; (ii) Georgia Power will reimburse a portion of MEAG Power's costs of construction for Plant Vogtle Units 3 and 4 as such costs are incurred and with no further adjustment for force majeure costs, which payments will total approximately $92 million based on the current project capital cost forecast; and (iii) Georgia Power will reimburse 20% of MEAG Power's costs of construction with respect to any

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amounts over the current project capital cost forecast, with no further adjustment for force majeure costs. In October 2022, MEAG Power and Georgia Power filed a notice of settlement and voluntary dismissal of the pending litigation described above, including Georgia Power's counterclaim, and Dalton dismissed its related complaint.

On October 5, 2023 and October 17, 2023, Georgia Power reached agreements with OPC and Dalton, respectively, to resolve its respective dispute with each of OPC and Dalton regarding the proper interpretation of the cost-sharing and tender provisions of the joint ownership agreements relating to the ~~Merger.~~Global Amendments. Under the terms of the agreements with OPC and Dalton, among other items, (i) each of OPC and Dalton retracted its exercise of the tender option and will retain its full ownership interest in Plant Vogtle Units 3 and 4, (ii) Georgia Power made payments immediately after execution of the agreements of $308 million and $17 million to OPC and Dalton, respectively, representing payment for a portion of each of OPC's and Dalton's costs of construction for Plant Vogtle Units 3 and 4 previously incurred, (iii) Georgia Power will pay a portion of each of OPC's and Dalton's further costs of construction for Plant Vogtle Units 3 and 4 as such costs are incurred and with no further adjustment for force majeure costs, which payments will be in an aggregate amount of approximately $105 million and $6 million for OPC and Dalton, respectively, based on the current project capital cost forecast, and (iv) Georgia Power will pay 66% of each of OPC's and Dalton's costs of construction with respect to any amounts above the current project capital cost forecast, with no further adjustment for force majeure costs. On October 23, 2023, OPC, Dalton, and Georgia Power filed a stipulation of dismissal with prejudice of their litigation described above, including Georgia Power's counterclaims.

Georgia Power recorded pre-tax charges to income through the fourth quarter 2022 of $407 million ($304 million after tax) associated with the cost-sharing provisions of the Global Amendments, including the settlement with MEAG Power. Based on the current project capital cost forecast and the settlements with OPC and Dalton described above, Georgia Power recorded a pre-tax charge to income of approximately $160 million ($120 million after tax) in the third quarter 2023. These charges are included in the total project capital cost forecast and will not be recovered from retail customers.

The ultimate impact of these matters on the construction schedule and project capital cost forecast and related cost recovery for Plant Vogtle Units 3 and 4 cannot be determined at this time. See Note (B) to the Condensed Financial Statements under "Georgia Power – Nuclear Construction" herein for additional information.

Plant Vogtle Unit 3 and Common Facilities Rate Proceeding

In compliance with a Georgia PSC order approved in November 2021, Georgia Power increased annual retail base rates by $318 million effective August 1, 2023 based on the in-service date of July 31, 2023 for Plant Vogtle Unit 3. See Note (B) to the Condensed Financial Statements under "Georgia Power – Nuclear Construction" herein for additional information on Plant Vogtle Units 3 and 4.

Plant Vogtle Units 3 and 4 Prudency Proceeding

On August 30, 2023, as provided for in the December 2017 Georgia PSC approval of the seventeenth VCM report, Georgia Power filed with the Georgia PSC an application to adjust rates to include reasonable and prudent Plant Vogtle Units 3 and 4 costs (Application). The Application provides the necessary support to justify the reasonableness, prudence, and recovery of $8.826 billion in total construction and capital costs, $1.07 billion in associated retail rate base items, and the operating costs related to the full operation and output of Plant Vogtle Units 3 and 4.

Also on August 30, 2023, the staff of the Georgia PSC filed a stipulated agreement (Prudency Stipulation) among Georgia Power, the staff of the Georgia PSC, and certain intervenors. If the Prudency Stipulation is approved, Georgia Power will recover $7.562 billion in total construction and capital costs and associated retail rate base items of $1.02 billion, which includes AFUDC financing costs above $4.418 billion (the Georgia PSC-certified amount) up to $7.562 billion.

The Prudency Stipulation also provides for the recovery of projected operations and maintenance expenses, depreciation expense, nuclear decommissioning accruals, and property taxes, net of projected production tax credits.

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After considering construction and capital costs already in retail base rates of $2.1 billion and $362 million of associated retail rate base items (approved by the Georgia PSC in November 2021), and upon achieving commercial operation of Unit 4, Georgia Power will include in retail rate base the remaining $5.462 billion of construction and capital costs as well as $656 million of associated retail rate base items.

If the Prudency Stipulation is approved by the Georgia PSC, annual retail base revenues will increase approximately $729 million and the average retail base rates will be adjusted by approximately 5% effective the first day of the month after Unit 4 achieves commercial operation.

Georgia Power expects the Georgia PSC to render a final decision on these matters on December 19, 2023. The ultimate outcome of these matters cannot be determined at this time. See Note (B) to the Condensed Financial Statements under "Georgia Power – Plant Vogtle Units 3 and 4 Prudency Proceeding" herein for additional information.

Rate Plans

In accordance with the terms of the 2022 ARP, on October 2, 2023, Georgia Power filed tariff adjustments to become effective January 1, 2024 that would result in a net increase in rates of $191 million pending approval by the Georgia PSC. The ultimate outcome of this matter cannot be determined at this time. See Note (B) to the Condensed Financial Statements under "Georgia Power – Rate Plans" herein for additional information.

Fuel Cost Recovery

On May 16, 2023, the Georgia PSC approved a stipulation agreement between Georgia Power and the staff of the Georgia PSC to increase annual fuel billings by 54%, or approximately $1.1 billion,effective June 1, 2023. The increase reflects a three-year recovery period for $2.2 billion of Georgia Power's under recovered fuel balance at May 31, 2023. Changes in fuel rates have no significant effect on Southern Company's or Georgia Power's net income but do impact the related operating cash flows. See Note (B) to the Condensed Financial Statements under "Georgia Power – Fuel Cost Recovery" herein for additional information.

Integrated Resource Plan

On October 27, 2023, Georgia Power filed an updated IRP (2023 IRP Update) with the Georgia PSC, which sets forth a plan to support the recent increase in the state of Georgia's projected energy needs since the 2022 IRP. The schedule for the Georgia PSC to consider the 2023 IRP Update has not been determined. Georgia Power has requested that the Georgia PSC evaluate the 2023 IRP Update by the end of April 2024. The ultimate outcome of this matter cannot be determined at this time. See Note (B) to the Condensed Financial Statements under "Georgia Power – Integrated Resource Plans" herein for additional information.

Mississippi Power

On October 27, 2023, the FERC approved a settlement agreement filed by Mississippi Power and Cooperative Energy on July 31, 2023 related to Mississippi Power's July 2022 request for a $23 million increase in annual wholesale base revenues under the MRA tariff. The settlement agreement provides for a $16 million increase in annual wholesale base revenues, effective September ~~2016,~~ 14, 2022, and a refund to customers of approximately $6 million primarily related to the difference between the approved rates and interim rates.

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Southern Power

On September 20, 2023, Southern Power acquired 100% of the membership interests in the 200-MW Millers Branch solar project located in Haskell County, Texas from EDF Renewables Development, Inc. and is continuing development and construction. The facility's output is contracted under a 20-year PPA and commercial operation is expected to occur in the fourth quarter 2025. The project includes an option to expand capacity up to an additional 300 MWs.

On September 22, 2023, Southern Power acquired 100% of the membership interests in the 150-MW South Cheyenne solar project located in Laramie County, Wyoming from Hanwha Q Cells USA Corp. and is continuing construction. The facility's output is contracted under a 20-year PPA and commercial operation is expected to occur in the first quarter 2024.

The ultimate outcome of these matters cannot be determined at this time. See Note (K) to the Condensed Financial Statements under "Southern Power" herein for additional information.

At September 30, 2023, Southern Power's average 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 facilities' net book value (or expected in-service value for facilities under construction) as the investment amount was 97% through 2027 and 91% through 2032, with an average remaining contract duration of approximately 13 years.

Southern Company Gas ~~paid~~

On July 14, 2023, Atlanta Gas Light filed its annual GRAM update with the Georgia PSC. The filing requests an annual base rate increase of $53 million based on the projected 12-month period beginning January 1, 2024. Resolution of the GRAM filing is expected by December 31, 2023, with new rates effective January 1, 2024.

On August 28, 2023, the Virginia Commission approved a stipulation agreement related to Virginia Natural Gas' August 2022 general base rate case filing. The approved agreement provides for a $48 million increase in annual base rate revenues, including the recovery of investments under the SAVE program, an ROE of 9.70%, and an equity ratio of 49.06%. Interim rates became effective January 1, 2023, subject to refund, based on Virginia Natural Gas' original requested increase of approximately $69 million. Refunds to customers related to the difference between the approved rates effective September 1, 2023 and the interim rates will be completed later in the fourth quarter 2023.

On June 15, 2023, the Illinois Commission concluded its review of the Qualifying Infrastructure Plant (QIP) capital investments by Nicor Gas for calendar year 2019 under the QIP Rider, also referred to as Investing in Illinois, program. The Illinois Commission disallowed $32 million of the $415 million of capital investments commissioned in 2019, together with the related return on investment. Nicor Gas recorded a pre-tax charge to income in the second quarter 2023 of $38 million ($28 million after tax) associated with the disallowance of capital investments. The disallowance is reflected on the statement of income as an $8 million reduction to revenues and a $30 million increase in operating expenses. On August 3, 2023, the Illinois Commission denied a rehearing request filed by Nicor Gas. On August 24, 2023, Nicor Gas filed a notice of appeal with the Illinois Appellate Court. Nicor Gas defends these investments in infrastructure as prudently incurred. The Illinois Commission has not yet conducted its review for calendar years 2020 through 2022 or the nine months ended September 30, 2023. Any further disallowance by the Illinois Commission could be material.

The ultimate outcome of these matters cannot be determined at this time. See Note (B) to the Condensed Financial Statements under "Southern Company Gas" herein for additional information.

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RESULTS OF OPERATIONS

Southern Company

Net Income


Third Quarter 2023 vs. Third Quarter 2022		Year-To-Date 2023 vs. Year-To-Date 2022
(change in millions)	(% change)	(change in millions)	(% change)
$(50)	(3.4)	$(490)	(13.6)

Consolidated net income attributable to Southern Company in the third quarter 2023 was $1.4 billion ($1.30 per share) compared to ~~acquire~~$1.5 billion ($1.36 per share) for the corresponding period in 2022. The decrease was primarily due to an increase of $172 million in after-tax charges related to the construction of Plant Vogtle Units 3 and 4, higher depreciation and amortization, and higher interest expense, partially offset by an increase in retail electric revenues associated with warmer weather and rates and pricing, lower non-fuel operations and maintenance costs, a ~~50% equity interest~~decrease in ~~SNG. On March 31, 2017,~~income tax expense, and an increase in other revenues.

Consolidated net income attributable to Southern Company ~~Gas made~~for year-to-date 2023 was $3.1 billion ($2.86 per share) compared to $3.6 billion ($3.38 per share) for the corresponding period in 2022. The decrease was primarily due to an ~~additional $50~~increase of $133 million ~~contribution~~in after-tax charges related to ~~maintain its 50% equity~~the construction of Plant Vogtle Units 3 and 4, higher depreciation and amortization, higher interest expense, and a decrease in ~~SNG. Southern Company Gas recorded equity investment income of $28 million and $86 million from this investment~~retail electric revenues associated with milder weather in the ~~successor third quarter~~first and ~~year-to-date 2017, respectively,~~second quarters of 2023 compared to the corresponding periods in 2022, partially offset by lower non-fuel operations and ~~$27 million~~maintenance costs, an increase in ~~September 2016.~~ other revenues, an increase in natural gas revenues from rate increases and continued infrastructure replacement, and a decrease in income tax expense.

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

Retail Electric Revenues

In the third quarter 2023, retail electric revenues were $5.1 billion compared to $6.0 billion for the corresponding period in 2022. For year-to-date 2023, retail electric revenues were $12.6 billion compared to $14.4 billion for the corresponding period in 2022. Details of the changes in retail electric revenues were as follows:


	Third Quarter 2023 vs. Third Quarter 2022				Year-To-Date 2023 vs. Year-To-Date 2022
	(change in millions)		(% change)		(change in millions)		(% change)
Rates and pricing	$	76	1.3	%	$	63	0.4	%
Sales decline	(28)		(0.5)		(48)		(0.3)
Weather	132		2.2		(194)		(1.4)
Fuel and other cost recovery	(1,002)		(16.8)		(1,587)		(11.0)
Retail electric revenues	$	(822)	(13.8)	%	$	(1,766)	(12.3)	%

Revenues associated with changes in rates and ~~Notes 4~~pricing increased in the third quarter and 11year-to-date 2023 when compared to the corresponding periods in 2022 primarily due to base tariff increases in accordance with Georgia Power's 2022 ARP and an increase in Rate CNP Compliance revenues at Alabama Power, partially offset by lower contributions from commercial and industrial customers with variable demand-driven pricing and a decrease in the revenues recognized under the NCCR tariff, both at Georgia Power. In addition, in the third quarter and year-to-date 2023, revenues associated with Rate CNP Depreciation increased $94 million and $234 million, respectively, and were fully offset by customer bill credits related to the flowback of excess accumulated deferred income taxes at Alabama Power. See Note 2 to the financial statements under "Alabama Power" and "Georgia Power" in Item 8 of the Form 10-K for additional information.

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Revenues attributable to changes in sales decreased in the third quarter and year-to-date 2023 when compared to the corresponding periods in 2022. Weather-adjusted residential KWH sales decreased 1.8% and 0.4% in the third quarter and year-to-date 2023, respectively, when compared to the corresponding periods in 2022 primarily due to decreased customer usage, partially offset by customer growth. Weather-adjusted commercial KWH sales increased 1.3% in both the third quarter and year-to-date 2023 when compared to the corresponding periods in 2022 primarily due to increased customer usage and customer growth. Industrial KWH sales decreased 2.3% and 2.1% in the third quarter and year-to-date 2023, respectively, when compared to the corresponding periods in 2022 primarily due to a decrease in the chemicals and forest products sectors. Also contributing to the year-to-date 2023 industrial KWH sales decrease was a decrease in the textiles sector.

Fuel and other cost recovery revenues decreased $1.0 billion and $1.6 billion in the third quarter and year-to-date 2023, respectively, compared to the corresponding periods in 2022 primarily due to lower fuel and purchased power costs. 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 in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements herein for additional information.

Wholesale Electric Revenues


Third Quarter 2023 vs. Third Quarter 2022		Year-To-Date 2023 vs. Year-To-Date 2022
(change in millions)	(% change)	(change in millions)	(% change)
$(470)	(39.3)	$(868)	(31.0)

In the third quarter 2023, wholesale electric revenues were $0.7 billion compared to $1.2 billion for the corresponding period in 2022. The decrease was primarily due to a decrease of $452 million in energy revenues as a result of fuel and purchased power price decreases when compared to the corresponding period in 2022 and a net decrease in the volume of KWHs sold primarily associated with natural gas PPAs at Southern Power. In addition, a decrease in capacity revenues of $18 million primarily resulted from power sales agreements that ended in May 2023 at Alabama Power, partially offset by an increase related to new capacity contracts at Georgia Power.

For year-to-date 2023, wholesale electric revenues were $1.9 billion compared to $2.8 billion for the corresponding period in 2022. The decrease was primarily due to a decrease of $892 million in energy revenues as a result of fuel and purchased power price decreases when compared to the corresponding period in 2022 and a net decrease in the volume of KWHs sold primarily associated with natural gas PPAs at Southern Power. The decrease in energy revenues was partially offset by an increase in capacity revenues of $24 million primarily resulting from a net increase in capacity sales from natural gas PPAs at Southern Power and an increase related to new capacity contracts at Georgia Power.

Wholesale electric revenues consist of revenues from 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.

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Wholesale electric revenues at Mississippi Power include FERC-regulated municipal and rural association sales under cost-based tariffs as well as market-based sales. Short-term opportunity sales are made at market-based rates that generally provide a margin above the Southern Company system's variable cost to produce the energy.

Other Electric Revenues


Third Quarter 2023 vs. Third Quarter 2022		Year-To-Date 2023 vs. Year-To-Date 2022
(change in millions)	(% change)	(change in millions)	(% change)
$18	9.7	$48	8.7

In the third quarter 2023, other electric revenues were $203 million compared to $185 million for the corresponding period in 2022. The increase was primarily due to increases of $10 million resulting from receipts of liquidated damages associated with generation facility production guarantees and an arbitration interim award at Southern Power, $10 million in retail solar program fees at Georgia Power, and $9 million in transmission revenues primarily associated with open access transmission tariff sales, partially offset by a decrease of $11 million in cogeneration steam revenue primarily associated with lower natural gas prices at Alabama Power.

For year-to-date 2023, other electric revenues were $602 million compared to $554 million for the corresponding period in 2022. The increase was primarily due to increases of $19 million resulting from receipts of liquidated damages associated with generation facility production guarantees and an arbitration interim award at Southern Power, $18 million in transmission revenues primarily associated with open access transmission tariff sales, $18 million in realized gains associated with price stability products for retail customers on variable demand-driven pricing tariffs at Georgia Power, and $18 million in outdoor lighting sales at Georgia Power, partially offset by a decrease of $23 million in cogeneration steam revenue primarily associated with lower natural gas prices at Alabama Power.

See Note (C) to the Condensed Financial Statements under "General Litigation Matters – Southern Power" herein for additional information.

Natural Gas Revenues

In the third quarter 2023, natural gas revenues were $0.7 billion compared to $0.9 billion for the corresponding period in 2022. For year-to-date 2023, natural gas revenues were $3.4 billion compared to $4.0 billion for the corresponding period in 2022. Details of the changes in natural gas revenues were as follows:


	Third Quarter 2023 vs. Third Quarter 2022				Year-To-Date 2023 vs. Year-To-Date 2022
	(change in millions)		(% change)		(change in millions)		(% change)
Infrastructure replacement programs and rate changes	$	9	1.1	%	$	97	2.4	%
Gas costs and other cost recovery	(181)		(21.1)		(645)		(16.1)
Gas marketing services	(22)		(2.6)		(44)		(1.1)
Other	26		3.0		11		0.3
Natural gas revenues	$	(168)	(19.6)	%	$	(581)	(14.5)	%

Revenues from infrastructure replacement programs and rate changes at the natural gas distribution utilities increased in the third quarter and year-to-date 2023 compared to the corresponding periods in 2022 primarily due to rate increases at the natural gas distribution utilities and continued investment in infrastructure replacement. The year-to-date 2023 increase was partially offset by a regulatory disallowance at Nicor Gas. See Note 2 to the financial statements under "Southern Company Gas – Rate Proceedings" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Southern Company Gas – Infrastructure Replacement Programs and Capital Projects" herein for additional information.

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Revenues from gas costs and other cost recovery decreased in the third quarter and year-to-date 2023 compared to the corresponding periods in 2022 primarily due to lower natural gas cost recovery associated with lower natural gas prices, the timing of natural gas purchases, and the recovery of those costs from customers. 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 gas marketing services decreased in the third quarter and year-to-date 2023 compared to the corresponding periods in 2022 primarily due to lower natural gas prices and lower variable price spreads.

Other Revenues


Third Quarter 2023 vs. Third Quarter 2022		Year-To-Date 2023 vs. Year-To-Date 2022
(change in millions)	(% change)	(change in millions)	(% change)
$44	24.7	$143	27.6

In the third quarter 2023, other revenues were $222 million compared to $178 million for the corresponding period in 2022. For year-to-date 2023, other revenues were $662 million compared to $519 million for the corresponding period in 2022. The increases in the third quarter and year-to-date 2023 were primarily due to increases of $9 million and $41 million, respectively, in power delivery construction and maintenance projects at Georgia Power, $12 million and $40 million, respectively, related to distributed infrastructure projects at PowerSecure, $9 million and $26 million, respectively, primarily related to sales associated with commercial customers at Southern Linc, $4 million and $20 million, respectively, in unregulated sales of products and services at Alabama Power, and $11 million and $16 million, respectively, associated with energy conservation projects at Georgia Power.

Fuel and Purchased Power Expenses


	Third Quarter 2023 vs. Third Quarter 2022			Year-To-Date 2023 vs. Year-To-Date 2022
	(change in millions)		(% change)	(change in millions)		(% change)
Fuel	$	(1,056)	(43.6)	$	(1,873)	(35.7)
Purchased power	(438)		(67.9)	(605)		(47.1)
Total fuel and purchased power expenses	$	(1,494)		$	(2,478)

In the third quarter 2023, total fuel and purchased power expenses were $1.6 billion compared to $3.1 billion for the corresponding period in 2022. The decrease was due to a $1.2 billion decrease in the average cost of fuel and purchased power and a $262 million net decrease in the volume of KWHs generated and purchased.

For year-to-date 2023, total fuel and purchased power expenses were $4.1 billion compared to $6.5 billion for the corresponding period in 2022. The decrease was due to a $2.1 billion decrease in the average cost of fuel and purchased power and a $349 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 Note 2 to the financial statements in Item 8 of the Form 10-K 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.

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


	Third Quarter 2023	Third Quarter 2022	Year-To-Date 2023	Year-To-Date 2022
Total generation (in billions of KWHs)(a)(b)	53	50	141	141
Total purchased power (in billions of KWHs)	5	9	14	20
Sources of generation (percent)(a) —
Gas	54	54	54	50
Coal	21	21	18	22
Nuclear(b)	16	16	17	16
Hydro	2	2	3	4
Wind, Solar, and Other	7	7	8	8
Cost of fuel, generated (in cents per net KWH)—
Gas(a)	2.80	6.75	2.78	5.42
Coal	4.52	4.12	4.40	3.58
Nuclear(b)	0.79	0.71	0.74	0.72
Average cost of fuel, generated (in cents per net KWH)(a)(b)	2.84	5.05	2.71	4.07
Average cost of purchased power (in cents per net KWH)(c)	4.80	8.94	5.08	7.84

(a)Excludes Central Alabama Generating Station KWHs and associated cost of fuel through July 12, 2022 as its fuel was previously provided by the purchaser under a power sales agreement. See Note 15 to the financial statements under "Alabama Power" in Item 8 of the Form 10-K for additional information.

(b)Excludes KWHs generated from test period energy at Plant Vogtle Unit 3 prior to its in-service date. The related fuel costs are charged to CWIP in accordance with FERC guidance. See Note (B) to the Condensed Financial Statements under "Georgia Power – Nuclear Construction" herein for additional information on Plant Vogtle Units 3 and 4.

(c)Average cost of purchased power includes fuel purchased by the Southern Company system for tolling agreements where power is generated by the provider.

Fuel

In the third quarter 2023, fuel expense was $1.4 billion compared to $2.4 billion for the corresponding period in 2022. The decrease was primarily due to a 58.5% decrease in the average cost of natural gas per KWH generated, partially offset by a 10.0% increase in the volume of KWHs generated by nuclear, a 9.7% increase in the average cost of coal per KWH generated, a 6.4% increase in the volume of KWHs generated by coal, and a 6.0% increase in the volume of KWHs generated by natural gas.

For year-to-date 2023, fuel expense was $3.4 billion compared to $5.2 billion for the corresponding period in 2022. The decrease was primarily due to a 48.7% decrease in the average cost of natural gas per KWH generated and a 20.4% decrease in the volume of KWHs generated by coal, partially offset by a 22.9% increase in the average cost of coal per KWH generated, an 11.0% decrease in the volume of KWHs generated by hydro, and a 9.0% increase in the volume of KWHs generated by natural gas.

Purchased Power

In the third quarter 2023, purchased power expense was $207 million compared to $645 million for the corresponding period in 2022. For year-to-date 2023, purchased power expense was $0.7 billion compared to $1.3 billion for the corresponding period in 2022. The decreases for the third quarter and year-to-date 2023 were primarily due to decreases of 46.3% and 35.2%, respectively, in the average cost per KWH purchased primarily due to a decrease in natural gas prices and decreases of 48.1% and 29.0%, respectively, in the volume of KWHs purchased.

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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.

Cost of Natural Gas


Third Quarter 2023 vs. Third Quarter 2022		Year-To-Date 2023 vs. Year-To-Date 2022
(change in millions)	(% change)	(change in millions)	(% change)
$(192)	(65.3)	$(641)	(34.8)

Excluding Atlanta Gas Light, which does not sell natural gas to end-use customers, 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. Cost of natural gas at the natural gas distribution utilities represented 76% and 84% of the total cost of natural gas in the third quarter and year-to-date 2023, respectively.

In the third quarter 2023, cost of natural gas was $102 million compared to $294 million for the corresponding period in 2022. For year-to-date 2023, cost of natural gas was $1.2 billion compared to $1.8 billion for the corresponding period in 2022. The decreases reflect lower gas cost recovery as a result of decreases of 69% and 60% in natural gas prices in the third quarter and year-to-date 2023, respectively, compared to the corresponding periods in 2022.

Cost of Other Sales


Third Quarter 2023 vs. Third Quarter 2022		Year-To-Date 2023 vs. Year-To-Date 2022
(change in millions)	(% change)	(change in millions)	(% change)
$34	37.0	$106	38.5

In the third quarter 2023, cost of other sales was $126 million compared to $92 million for the corresponding period in 2022. The increase was primarily due to increases of $12 million from unregulated power delivery construction and maintenance projects at Georgia Power, $7 million at Southern Linc primarily related to sales associated with commercial customers, $6 million related to distributed infrastructure projects at PowerSecure, and $5 million related to energy service contracts at Southern Company Gas.

For year-to-date 2023, cost of other sales was $381 million compared to $275 million for the corresponding period in 2022. The increase was primarily due to increases of $35 million from unregulated power delivery construction and maintenance projects at Georgia Power, $23 million at Southern Linc primarily related to sales associated with commercial customers, $21 million related to distributed infrastructure projects at PowerSecure, $20 million related to energy service contracts at Southern Company Gas, and $10 million in expenses related to unregulated products and services at Alabama Power.

Other Operations and Maintenance Expenses


Third Quarter 2023 vs. Third Quarter 2022		Year-To-Date 2023 vs. Year-To-Date 2022
(change in millions)	(% change)	(change in millions)	(% change)
$(103)	(6.7)	$(216)	(4.7)

In the third quarter 2023, other operations and maintenance expenses were $1.4 billion compared to $1.5 billion for the corresponding period in 2022. The decrease was primarily due to decreases of $88 million in transmission and distribution expenses primarily related to line maintenance, $45 million in storm damage recovery as authorized in Georgia Power's 2022 ARP, $22 million in technology infrastructure and application production costs, and $14 million in generation non-outage maintenance expenses and planned outages, partially offset by a $23 million

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AND RESULTS OF OPERATIONS (Continued)

increase in generation environmental projects primarily at Georgia Power and a $14 million gain recorded in the third quarter 2022 as a result of the early termination of the transition services agreement related to the 2019 sale of Gulf Power.

For year-to-date 2023, other operations and maintenance expenses were $4.4 billion compared to $4.6 billion for the corresponding period in 2022. The decrease was primarily due to decreases of $147 million in transmission and distribution expenses primarily related to line maintenance, $136 million in storm damage recovery as authorized in Georgia Power's 2022 ARP, $91 million in generation non-outage maintenance expenses and planned outages, and $32 million in expenses passed through to customers primarily related to bad debt and energy efficiency programs at Southern Company Gas, partially offset by a $47 million increase in technology infrastructure and application production costs, a $43 million increase in generation environmental projects primarily at Georgia Power, $30 million related to a regulatory disallowance at Nicor Gas, a $25 million decrease in nuclear property insurance refunds at Georgia Power and Alabama Power, a $16 million increase in employee compensation and benefits, and a $14 million gain recorded in the third quarter 2022 as a result of the early termination of the transition services agreement related to the 2019 sale of Gulf Power.

See Note (B) to the Condensed Financial Statements under ~~"Equity Method Investments~~"Southern Company Gas – ~~SNG"~~Infrastructure Replacement Programs and ~~"Investment~~Capital Projects" herein for additional information on the regulatory disallowance at Nicor Gas and Note 2 to the financial statements under "Georgia Power – Storm Damage Recovery" in ~~SNG,~~Item 8 of the Form 10-K for additional information.

Depreciation and Amortization


Third Quarter 2023 vs. Third Quarter 2022		Year-To-Date 2023 vs. Year-To-Date 2022
(change in millions)	(% change)	(change in millions)	(% change)
$221	24.0	$637	23.4

In the third quarter 2023, depreciation and amortization was $1.1 billion compared to $0.9 billion for the corresponding period in 2022. For year-to-date 2023, depreciation and amortization was $3.4 billion compared to $2.7 billion for the corresponding period in 2022. The increases in the third quarter and year-to-date 2023 were primarily due to increases of $181 million and $544 million, respectively, resulting from higher depreciation rates at Alabama Power and Georgia Power and increases of $28 million and $74 million, respectively, from additional plant in service. See Notes 2 and 5 to the financial statements under "Alabama Power" and "Depreciation and Amortization," respectively, in Item 8 of the Form 10-K for additional information.

Taxes Other Than Income Taxes


Third Quarter 2023 vs. Third Quarter 2022		Year-To-Date 2023 vs. Year-To-Date 2022
(change in millions)	(% change)	(change in millions)	(% change)
$(11)	(3.1)	$3	0.3

In ~~October 2016,~~the third quarter 2023, taxes other than income taxes were $341 million compared to $352 million for the corresponding period in 2022. The decrease was primarily due to decreases of $15 million in municipal franchise fees resulting from lower retail revenues at Georgia Power, partially offset by an increase of $4 million in property taxes primarily at Georgia Power resulting from an increase in the assessed value of property.

For year-to-date 2023, taxes other than income taxes were $1.08 billion compared to $1.07 billion for the corresponding period in 2022. The increase was primarily due to increases of $26 million in property taxes primarily at Georgia Power resulting from an increase in the assessed value of property, $18 million in utility license taxes at Alabama Power, and $8 million in payroll taxes primarily at Southern Company Gas, ~~completed its purchase~~largely offset by decreases of ~~Piedmont's 15% interest~~$33 million in ~~SouthStar, which eliminated~~municipal franchise fees resulting from lower retail revenues at Georgia Power and $15 million in revenue tax expenses at Southern Company Gas.

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Estimated Loss on Plant Vogtle Units 3 and 4

Third Quarter 2023 vs. Third Quarter 2022

Year-To-Date 2023 vs. Year-To-Date 2022

(change in millions)

(% change)

(change in millions)

(% change)

$230

N/M

$178

N/M

Georgia Power recorded pre-tax charges (credits) to income for the ~~noncontrolling interest associated with SouthStar.~~estimated probable loss on Plant Vogtle Units 3 and 4 totaling $160 million and $(70) million in the third quarter 2023 and 2022, respectively, and $160 million and $(18) million for year-to-date 2023 and 2022, respectively. The charges (credits) reflected revisions to the total project capital cost forecast to complete construction and start-up of Plant Vogtle Units 3 and 4. See Note 4(B) to the Condensed Financial Statements herein and Note 2 to the financial statements in Item 8 of the Form 10-K under "Georgia Power – Nuclear Construction" for additional information.

Allowance for Equity Funds Used During Construction


Third Quarter 2023 vs. Third Quarter 2022		Year-To-Date 2023 vs. Year-To-Date 2022
(change in millions)	(% change)	(change in millions)	(% change)
$7	11.9	$37	22.7

In the third quarter 2023, allowance for equity funds used during construction was $66 million compared to $59 million for the corresponding period in 2022. For year-to-date 2023, allowance for equity funds used during construction was $200 million compared to $163 million for the corresponding period in 2022. The increases were primarily associated with an increase in capital expenditures related to Plant Barry Unit 8 construction, as well as an increase in capital expenditures related to hydro production, both at Alabama Power. Also contributing to the increase for year-to-date 2023 was an increase in capital expenditures subject to AFUDC at Georgia Power. See Note 2 to the financial statements in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements herein under "Alabama Power – Certificates of Convenience and Necessity" for additional information.

Interest Expense, Net of Amounts Capitalized


Third Quarter 2023 vs. Third Quarter 2022		Year-To-Date 2023 vs. Year-To-Date 2022
(change in millions)	(% change)	(change in millions)	(% change)
$109	21.3	$351	24.0

In the third quarter 2023, interest expense, net of amounts capitalized was $620 million compared to $511 million for the corresponding period in 2022. For year-to-date 2023, interest expense, net of amounts capitalized was $1.8 billion compared to $1.5 billion for the corresponding period in 2022. The increases in the third quarter and year-to-date 2023 primarily reflect approximately $63 million and $222 million, respectively, related to higher interest rates and $48 million and $134 million, respectively, related to higher average outstanding borrowings. See FINANCIAL CONDITION AND LIQUIDITY – "Sources of Capital" and "Financing Activities" herein for additional information on borrowings.

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Other Income (Expense), Net


Third Quarter 2023 vs. Third Quarter 2022		Year-To-Date 2023 vs. Year-To-Date 2022
(change in millions)	(% change)	(change in millions)	(% change)
$9	6.8	$14	3.4

For year-to-date 2023, other income (expense), net was $428 million compared to $414 million for the corresponding period in 2022. The increase was primarily due to a $29 million increase in interest income, a $13 million decrease in non-operating benefit-related expenses at Alabama Power, an $8 million gain on investments at Southern ~~Company Gas~~Holdings, and a $6 million decrease in non-operating marketing expenses at Georgia Power, partially offset by decreases of $30 million in non-service cost-related retirement benefits income and $13 million in customer charges related to contributions in aid of construction at Georgia Power. See Note (H) to the Condensed Financial Statements herein for additional information.

Income Taxes


Third Quarter 2023 vs. Third Quarter 2022		Year-To-Date 2023 vs. Year-To-Date 2022
(change in millions)	(% change)	(change in millions)	(% change)
$(117)	(28.3)	$(399)	(44.8)

In the third quarter 2023, income taxes were $297 million compared to $414 million for the corresponding period in 2022. For year-to-date 2023, income taxes were $492 million compared to $891 million for the corresponding period in 2022. The decreases were primarily due to lower pre-tax earnings, an increase in the flowback of certain excess deferred income taxes at Alabama Power, and a decrease in a valuation allowance on certain state tax credit carryforwards at Georgia Power in 2023, partially offset by a decrease in the flowback of certain excess deferred income taxes at Georgia Power that ended in 2022. Also contributing to the year-to-date 2023 decrease was an adjustment in the second quarter 2022 related to a prior year state tax credit carryforward at Georgia Power. See Note (G) to the Condensed Financial Statements herein for additional information.

Net Income (Loss) Attributable to Noncontrolling Interests


Third Quarter 2023 vs. Third Quarter 2022		Year-To-Date 2023 vs. Year-To-Date 2022
(change in millions)	(% change)	(change in millions)	(% change)
$(2)	(16.7)	$(13)	(23.6)

Substantially all noncontrolling interests relate to renewable projects at Southern Power. In the third quarter 2023, net income attributable to noncontrolling interests was $10 million compared to $12 million for the corresponding period in 2022. The decrease was primarily due to $7 million in higher HLBV loss allocations to Southern Power's wind tax equity partners, largely offset by an allocation of $6 million to Southern Power's equity partners related to an arbitration interim award.

For year-to-date 2023, net loss attributable to noncontrolling interests was $68 million compared to $55 million for the corresponding period in 2022. The increase was primarily due to $16 million in higher HLBV loss allocations to Southern Power's wind tax equity partners and $12 million in lower income allocations to Southern Power's equity partners, partially offset by $15 million in lower loss allocations to Southern Power's battery energy storage partners.

See Note (C) to the Condensed Financial Statements under ~~"Variable Interest Entities"~~"General Litigation Matters – Southern Power" herein for additional information.

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Alabama Power

Net Income


Third Quarter 2023 vs. Third Quarter 2022		Year-To-Date 2023 vs. Year-To-Date 2022
(change in millions)	(% change)	(change in millions)	(% change)
$40	7.6	$(124)	(9.9)

Alabama Power's net income after dividends on preferred stock in the third quarter 2023 was $565 million compared to $525 million for the corresponding period in 2022. The increase was primarily due to a decrease in income tax expense and an increase in retail revenues associated with Rate CNP Compliance and warmer weather in Alabama Power's service territory in the third quarter 2023 compared to the corresponding period in 2022. These increases to income were partially offset by an increase in depreciation and amortization associated with a change in depreciation rates effective January 2023.

Alabama Power's net income after dividends on preferred stock for year-to-date 2023 was $1.13 billion compared to $1.26 billion for the corresponding period in 2022. The decrease was primarily due to an increase in depreciation rates effective January 2023, a decrease in retail revenues associated with milder weather in Alabama Power's service territory in the first and second quarters of 2023 compared to the corresponding periods in 2022, and an increase in capacity-related expenses. These decreases to income were partially offset by a decrease in income tax expense and an increase in Rate CNP Compliance revenues.

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

Retail Revenues

In the third quarter 2023, retail revenues were $1.86 billion compared to $2.01 billion for the corresponding period in 2022. For year-to-date 2023, retail revenues were $4.71 billion compared to $5.02 billion for the corresponding period in 2022. Details of the changes in retail revenues were as follows:


	Third Quarter 2023 vs. Third Quarter 2022				Year-To-Date 2023 vs. Year-To-Date 2022
	(change in millions)		(% change)		(change in millions)		(% change)
Rates and pricing	$	62	3.1	%	$	178	3.5	%
Sales decline	(2)		(0.1)		(36)		(0.7)
Weather	35		1.7		(84)		(1.7)
Fuel and other cost recovery	(243)		(12.1)		(365)		(7.3)
Retail revenues	$	(148)	(7.4)	%	$	(307)	(6.2)	%

Revenues associated with changes in rates and pricing increased in the third quarter and year-to-date 2023 when compared to the corresponding periods in 2022 primarily due to an increase in Rate CNP Compliance revenues. In addition, in the third quarter and year-to-date 2023, revenues associated with Rate CNP Depreciation increased $94 million and $234 million, respectively, and were fully offset by customer bill credits related to the flowback of excess accumulated deferred income taxes. See Note 2 to the financial statements under "Alabama Power" in Item 8 of the Form 10-K for additional information.

On October 15, 2017, Southern Company Gas subsidiary, Pivotal Utility Holdings, entered into agreements for the sale of the assets of two of its natural gas distribution utilities, Elizabethtown Gas and Elkton Gas,Revenues attributable to ~~South Jersey Industries, Inc. for a total cash purchase price of $1.7 billion. As of September 30, 2017, the net book value of the assets to be disposed of~~changes in the sale was approximately $1.5 billion, which includes approximately $0.5 billion of goodwill. The goodwill is not deductible for tax purposes and as a result, a deferred tax liability has not yet been provided for goodwill. Through the completion of the sale, Southern Company Gas intends to invest approximately $0.1 billionsales decreased in capital expenditures which are required for ordinary business operations. The completion of each sale is subject to the satisfaction or waiver of certain closing conditions, including, among others, (i) the expiration or termination of the waiting period under the Hart-Scott-Rodino Antitrust Improvements Act; (ii) the receipt of required regulatory approvals, including the FERC, the Federal Communications Commission, the New Jersey BPU, and, with respect to the sale of Elkton Gas, the Maryland PSC; and (iii) other customary closing conditions. The sales are expected to be completed by the end of the third quarter ~~2018.~~

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

and year-to-date 2023 when compared to the corresponding periods in 2022. Weather-adjusted residential KWH sales decreased 0.8% in the third quarter 2023 compared to the corresponding period in 2022 primarily due to decreased customer usage and remained flat for year-to-date 2023 when compared to the corresponding period in 2022. Weather-adjusted commercial KWH sales increased 1.1% and 0.8% in the third quarter and year-to-date 2023, respectively, when compared to the corresponding periods in 2022 primarily due to increases in customer usage and customer growth. Industrial KWH sales decreased 4.8% and 3.9% in the third quarter and year-to-date 2023, respectively, primarily due to decreases in

~~176~~

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~~SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES~~

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION

AND RESULTS OF OPERATIONS

(Continued)

the chemicals and forest products sectors. Also contributing to the industrial KWH sales decrease in the third quarter 2023 was a decrease in the primary metals sector.

Fuel and other cost recovery revenues decreased in the third quarter and year-to-date 2023 when compared to the corresponding periods in 2022 primarily as a result of lower fuel and purchased power costs.

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 NDR. Under these provisions, fuel and other cost recovery revenues generally equal fuel and other cost recovery expenses and do not affect net income. See Note 2 to the financial statements under "Alabama Power" in Item 8 of the Form 10-K for additional information.

Wholesale Revenues – Non-Affiliates


Third Quarter 2023 vs. Third Quarter 2022		Year-To-Date 2023 vs. Year-To-Date 2022
(change in millions)	(% change)	(change in millions)	(% change)
$(144)	(57.6)	$(164)	(31.4)

In the third quarter 2023, wholesale revenues from sales to non-affiliates were $106 million compared to $250 million for the corresponding period in 2022. The decrease was primarily due to a 47.0% decrease in the volume of KWHs sold as a result of power sales agreements that ended in May 2023 and a 19.8% decrease in the price of energy primarily as a result of lower natural gas prices in the third quarter 2023 compared to the corresponding period in 2022.

For year-to-date 2023, wholesale revenues from sales to non-affiliates were $358 million compared to $522 million for the corresponding period in 2022. The decrease was primarily due to a 20.4% decrease in the price of energy primarily as a result of lower natural gas prices and a 13.8% decrease in the volume of KWHs sold due to lower customer demand as a result of milder weather in 2023 compared to the corresponding period in 2022.

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

Wholesale Revenues – Affiliates


Third Quarter 2023 vs. Third Quarter 2022		Year-To-Date 2023 vs. Year-To-Date 2022
(change in millions)	(% change)	(change in millions)	(% change)
$(56)	(80.0)	$(127)	(74.7)

In the third quarter 2023, wholesale revenues from sales to affiliates were $14 million compared to $70 million for the corresponding period in 2022. For year-to-date 2023, wholesale revenues from sales to affiliates were $43 million compared to $170 million for the corresponding period in 2022. The decreases for the third quarter and year-to-date 2023 were primarily due to decreases of 60.6% and 45.6%, respectively, in the price of energy due to lower natural gas prices and 51.2% and 53.5%, respectively, in the volume of KWH sales due to lower customer demand as a result of milder weather in 2023 compared to the corresponding periods in 2022.

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. Energy revenues related to 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.

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Other Revenues


Third Quarter 2023 vs. Third Quarter 2022		Year-To-Date 2023 vs. Year-To-Date 2022
(change in millions)	(% change)	(change in millions)	(% change)
$(13)	(11.2)	$(5)	(1.6)

In the third quarter 2023, other revenues were $103 million compared to $116 million for the corresponding period in 2022. For year-to-date 2023, other revenues were $311 million compared to $316 million for the corresponding period in 2022. The decreases for the third quarter and year-to-date 2023 were primarily due to decreases of $11 million and $23 million, respectively, in cogeneration steam revenue primarily associated with lower natural gas prices. The decrease for year-to-date 2023 was largely offset by a $20 million increase in unregulated sales of products and services.

Fuel and Purchased Power Expenses


	Third Quarter 2023 vs. Third Quarter 2022			Year-To-Date 2023 vs. Year-To-Date 2022
	(change in millions)		(% change)	(change in millions)		(% change)
Fuel	$	(264)	(39.6)	$	(386)	(27.6)
Purchased power – non-affiliates	(143)		(77.3)	(150)		(43.2)
Purchased power – affiliates	(33)		(29.2)	(67)		(25.8)
Total fuel and purchased power expenses	$	(440)		$	(603)

In the third quarter 2023, total fuel and purchased power expenses were $524 million compared to $964 million for the corresponding period in 2022. For year-to-date 2023, total fuel and purchased power expenses were $1.40 billion compared to $2.01 billion for the corresponding period in 2022. The decreases for the third quarter and year-to-date 2023 were due to decreases of $301 million and $540 million, respectively, in the average cost of fuel and purchased power and decreases of $139 million and $63 million, respectively, related to the volume of KWHs generated and purchased.

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

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


	Third Quarter 2023	Third Quarter 2022	Year-To-Date 2023	Year-To-Date 2022
Total generation (in billions of KWHs)(a)	15	16	43	45
Total purchased power (in billions of KWHs)	3	4	8	9
Sources of generation (percent)(a) —
Coal	40	47	35	45
Gas	31	28	30	23
Nuclear	26	22	27	24
Hydro	3	3	8	8
Cost of fuel, generated (in cents per net KWH) —
Coal	3.57	3.89	3.48	3.40
Gas(a)	3.07	6.55	3.05	5.20
Nuclear	0.68	0.67	0.68	0.67
Average cost of fuel, generated (in cents per net KWH)(a)	2.64	3.91	2.51	3.13
Average cost of purchased power (in cents per net KWH)(b)	4.57	8.55	4.97	8.33

(b)Average cost of purchased power includes fuel, energy, and transmission purchased by Alabama Power for tolling agreements where power is generated by the provider.

Fuel

In the third quarter 2023, fuel expense was $402 million compared to $666 million for the corresponding period in 2022. The decrease was primarily due to a 53.1% decrease in the average cost of natural gas per KWH generated, which excludes tolling agreements, and an 18.9% decrease in the volume of KWHs generated by coal.

For year-to-date 2023, fuel expense was $1.01 billion compared to $1.40 billion for the corresponding period in 2022. The decrease was primarily due to a 41.3% decrease in the average cost of natural gas per KWH generated, which excludes tolling agreements, and a 25.3% decrease in the volume of KWHs generated by coal, partially offset by a 23.4% increase in the volume of KWHs generated by natural gas and a 10.6% decrease in the volume of KWHs generated by hydro facilities as a result of less rainfall for year-to-date 2023 compared to the corresponding period in 2022.

Purchased Power – Non-Affiliates

In the third quarter 2023, purchased power expense from non-affiliates was $42 million compared to $185 million for the corresponding period in 2022. For year-to-date 2023, purchased power expense from non-affiliates was $197 million compared to $347 million for the corresponding period in 2022. The decreases for the third quarter and year-to-date 2023 were primarily due to decreases of 41.0% and 37.6%, respectively, in the average cost per KWH purchased due to lower purchase prices as a result of lower natural gas prices and decreases of 64.2% and 21.8%, respectively, in the volume of KWHs purchased due to a new PPA that began in July 2022 and ended in May 2023.

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

In the third quarter 2023, purchased power expense from affiliates was $80 million compared to $113 million for the corresponding period in 2022. For year-to-date 2023, purchased power expense from affiliates was $193 million

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AND RESULTS OF OPERATIONS (Continued)

compared to $260 million for the corresponding period in 2022. The decreases for the third quarter and year-to-date 2023 were primarily due to decreases of 65.8% and 51.3%, respectively, in the average cost per KWH purchased due to lower purchase prices as a result of lower natural gas prices, partially offset by increases of 107.6% and 52.6%, respectively, in the volume of KWHs purchased due to the availability of lower cost gas generation in the Southern Company system.

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


Third Quarter 2023 vs. Third Quarter 2022		Year-To-Date 2023 vs. Year-To-Date 2022
(change in millions)	(% change)	(change in millions)	(% change)
$(7)	(1.7)	$5	0.4

In the third quarter 2023, other operations and maintenance expenses were $411 million compared to $418 million for the corresponding period in 2022. The decrease was primarily due to decreases of $15 million in transmission and distribution expenses related to line maintenance, $9 million in technology infrastructure and application production costs, and $9 million in certain employee compensation and benefit expenses. The decreases were largely offset by an increase of $26 million in planned outages and generation non-outage maintenance expenses.

For year-to-date 2023, other operations and maintenance expenses were $1.28 billion compared to $1.27 billion for the corresponding period in 2022. The increase was primarily due to a $14 million decrease in nuclear property insurance refunds and increases of $19 million in expenses related to unregulated products and services, $9 million in technology infrastructure and application production costs, and $9 million in customer accounts expenses primarily associated with bad debt expense. The increases were largely offset by decreases of $21 million in generation expenses primarily associated with planned outages and generation non-outage maintenance expenses, $15 million in certain employee compensation and benefit expenses, and $10 million in transmission and distribution related to line maintenance.

Depreciation and Amortization


Third Quarter 2023 vs. Third Quarter 2022		Year-To-Date 2023 vs. Year-To-Date 2022
(change in millions)	(% change)	(change in millions)	(% change)
$131	59.5	$393	60.3

In the third quarter 2023, depreciation and amortization was $351 million compared to $220 million for the corresponding period in 2022. For year-to-date 2023, depreciation and amortization was $1.05 billion compared to $652 million for the corresponding period in 2022. The increases were primarily due to an increase in depreciation rates effective in 2023. See Notes 2 and 5 to the financial statements under "Alabama Power" and "Depreciation and Amortization," respectively, in Item 8 of the Form 10-K for additional information.

Taxes Other Than Income Taxes


Third Quarter 2023 vs. Third Quarter 2022		Year-To-Date 2023 vs. Year-To-Date 2022
(change in millions)	(% change)	(change in millions)	(% change)
$4	3.8	$24	7.8

In the third quarter 2023, taxes other than income taxes were $110 million compared to $106 million for the corresponding period in 2022. For year-to-date 2023, taxes other than income taxes were $333 million compared to $309 million for the corresponding period in 2022. The increases were primarily due to an increase in utility license taxes.

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Allowance for Equity Funds Used During Construction


Third Quarter 2023 vs. Third Quarter 2022		Year-To-Date 2023 vs. Year-To-Date 2022
(change in millions)	(% change)	(change in millions)	(% change)
$5	27.8	$14	27.5

In the third quarter 2023, allowance for equity funds used during construction was $23 million compared to $18 million for the corresponding period in 2022. For year-to-date 2023, allowance for equity funds used during construction was $65 million compared to $51 million for the corresponding period in 2022. The increases were primarily due to an increase in capital expenditures related to Plant Barry Unit 8 construction, as well as an increase in capital expenditures related to hydro production. See Note (B) to the Condensed Financial Statements under "Alabama Power – Certificates of Convenience and Necessity" herein for additional information.

Interest Expense, Net of Amounts Capitalized


Third Quarter 2023 vs. Third Quarter 2022		Year-To-Date 2023 vs. Year-To-Date 2022
(change in millions)	(% change)	(change in millions)	(% change)
$6	6.1	$33	11.9

In the third quarter 2023, interest expense, net of amounts capitalized was $104 million compared to $98 million for the corresponding period in 2022. For year-to-date 2023, interest expense, net of amounts capitalized was $311 million compared to $278 million for the corresponding period in 2022. The increases for the third quarter and year-to-date 2023 were primarily associated with increases of approximately $5 million and $25 million, respectively, related to higher average outstanding borrowings and $4 million and $15 million, respectively, related to higher interest rates. See FINANCIAL CONDITION AND LIQUIDITY – "Sources of Capital" herein for additional information on borrowings.

Other Income (Expense), Net


Third Quarter 2023 vs. Third Quarter 2022		Year-To-Date 2023 vs. Year-To-Date 2022
(change in millions)	(% change)	(change in millions)	(% change)
$—	—	$16	15.8

For year-to-date 2023, other income (expense), net was $117 million compared to $101 million for the corresponding period in 2022. The increase was primarily due to a decrease in non-operating benefit-related expenses and an increase in interest income, partially offset by a decrease in non-service cost-related retirement benefits income. See Note (H) to the Condensed Financial Statements herein for additional information.

Income Taxes


Third Quarter 2023 vs. Third Quarter 2022		Year-To-Date 2023 vs. Year-To-Date 2022
(change in millions)	(% change)	(change in millions)	(% change)
$(87)	(52.4)	$(291)	(73.9)

In the third quarter 2023, income taxes were $79 million compared to $166 million for the corresponding period in 2022. For year-to-date 2023, income taxes were $103 million compared to $394 million for the corresponding period in 2022. The decreases were primarily due to an increase in the flowback of certain excess deferred income taxes and lower pre-tax earnings. See Note 2 to the financial statements under "Alabama Power – Excess Accumulated Deferred Income Tax Accounting Order" in Item 8 of the Form 10-K and Note (G) to the Condensed Financial Statements herein for additional information.

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Georgia Power

Net Income


Third Quarter 2023 vs. Third Quarter 2022		Year-To-Date 2023 vs. Year-To-Date 2022
(change in millions)	(% change)	(change in millions)	(% change)
$(78)	(9.1)	$(304)	(16.4)

Georgia Power's net income in the third quarter 2023 was $780 million compared to $858 million for the corresponding period in 2022. The decrease was primarily due to an increase of $172 million in after-tax charges related to the construction of Plant Vogtle Units 3 and 4, as well as higher interest expense, partially offset by an increase in retail revenues associated with warmer weather in the third quarter 2023 compared to the corresponding period in 2022 and lower non-fuel operations and maintenance costs. Also partially offsetting the net income reductions were the impacts of the 2022 ARP effective January 1, 2023, including increased retail rates, largely offset by higher depreciation and amortization.

For year-to-date 2023, net income was $1.55 billion compared to $1.85 billion for the corresponding period in 2022. The decrease was primarily due to a decrease in retail revenues associated with lower contributions from variable demand-driven pricing and milder weather in the first and second quarters of 2023 compared to the corresponding periods in 2022, an increase of $133 million in after-tax charges related to the construction of Plant Vogtle Units 3 and 4, and higher interest expense, partially offset by lower non-fuel operations and maintenance costs. Also partially offsetting the net income reductions were the impacts of the 2022 ARP effective January 1, 2023, including increased retail rates, largely offset by higher depreciation and amortization.

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

Retail Revenues

In the third quarter 2023, retail revenues were $3.00 billion compared to $3.70 billion for the corresponding period in 2022. For year-to-date 2023, retail revenues were $7.14 billion compared to $8.63 billion for the corresponding period in 2022. Details of the changes in retail revenues were as follows:


	Third Quarter 2023 vs. Third Quarter 2022				Year-To-Date 2023 vs. Year-To-Date 2022
	(change in millions)		(% change)		(change in millions)		(% change)
Rates and pricing	$	17	0.4	%	$	(115)	(1.3)	%
Sales decline	(31)		(0.8)		(17)		(0.2)
Weather	88		2.4		(109)		(1.3)
Fuel cost recovery	(781)		(21.1)		(1,246)		(14.4)
Retail revenues	$	(707)	(19.1)	%	$	(1,487)	(17.2)	%

Revenues associated with changes in rates and pricing increased in the third quarter 2023 when compared to the corresponding period in 2022 primarily due to base tariff increases in accordance with the 2022 ARP, partially offset by lower contributions from commercial and industrial customers with variable demand-driven pricing and a decrease in revenues recognized under the NCCR tariff. Revenues associated with changes in rates and pricing decreased for year-to-date 2023 when compared to the corresponding period in 2022 primarily due to lower contributions from commercial and industrial customers with variable demand-driven pricing and a decrease in revenues recognized under the NCCR tariff, partially offset by base tariff increases in accordance with the 2022 ARP. See Note 2 to the financial statements under "Georgia Power – Rate Plans" and " – Nuclear Construction" in Item 8 of the Form 10-K for additional information.

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Revenues attributable to changes in sales decreased in the third quarter and year-to-date 2023 when compared to the corresponding periods in 2022. Weather-adjusted residential KWH sales decreased 2.6% and 0.7% in the third quarter and year-to-date 2023, respectively, when compared to the corresponding periods in 2022 primarily due to decreased customer usage, partially offset by customer growth. Weather-adjusted commercial KWH sales increased 0.4% and 1.1% in the third quarter and year-to-date 2023, respectively, when compared to the corresponding periods in 2022 primarily due to customer growth. The increase in weather-adjusted commercial KWH sales in the third quarter 2023 was partially offset by decreased customer usage. Weather-adjusted industrial KWH sales decreased 1.3% in the third quarter 2023 when compared to the corresponding period in 2022 primarily due to decreases in the pipeline and chemicals sectors, partially offset by an increase in the paper sector. Weather-adjusted industrial KWH sales decreased 1.0% for year-to-date 2023 when compared to the corresponding period in 2022 primarily due to decreases in the textile and mining sectors, partially offset by increases in the paper and electronics sectors.

Fuel revenues and costs are allocated between retail and wholesale jurisdictions. Retail fuel cost recovery revenues decreased in the third quarter and year-to-date 2023 when compared to the corresponding periods in 2022 due to lower fuel and purchased power costs. 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 Note (B) to the Condensed Financial Statements herein and Note 2 to the financial statements in Item 8 of the Form 10-K under "Georgia Power – Fuel Cost Recovery" for additional information.

Wholesale Revenues


Third Quarter 2023 vs. Third Quarter 2022		Year-To-Date 2023 vs. Year-To-Date 2022
(change in millions)	(% change)	(change in millions)	(% change)
$13	23.2	$(39)	(21.0)

In the third quarter 2023, wholesale revenues were $69 million compared to $56 million for the corresponding period in 2022. The increase was primarily due to a $22 million increase related to the volume of KWH sales associated with higher market demand and a $17 million increase related to new capacity contracts, partially offset by a $26 million decrease related to the average cost per KWH sold due to lower Southern Company system fuel and purchased power costs.

For year-to-date 2023, wholesale revenues were $147 million compared to $186 million for the corresponding period in 2022. The decrease was primarily due to a $41 million decrease related to the average cost per KWH sold due to lower Southern Company system fuel and purchased power costs and a $13 million decrease related to the volume of KWH sales associated with lower market demand, partially offset by a $19 million increase related to new capacity contracts.

Wholesale revenues from sales to non-affiliates consist of PPAs and short-term opportunity sales. Wholesale revenues from PPAs have both capacity and energy components. Wholesale capacity revenues from PPAs are recognized in 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.

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the FERC. Energy revenues related to these transactions do not have a significant impact on earnings since this energy is generally sold at marginal cost.

Other Revenues


Third Quarter 2023 vs. Third Quarter 2022		Year-To-Date 2023 vs. Year-To-Date 2022
(change in millions)	(% change)	(change in millions)	(% change)
$42	32.3	$113	28.0

In the third quarter 2023, other revenues were $172 million compared to $130 million for the corresponding period in 2022. For year-to-date 2023, other revenues were $516 million compared to $403 million for the corresponding period in 2022. The increases for the third quarter and year-to-date 2023 were primarily due to increases of $27 million and $78 million, respectively, in unregulated sales associated with power delivery construction and maintenance, outdoor lighting, and energy conservation projects, net increases of $7 million and $18 million, respectively, in realized gains associated with price stability products for retail customers on variable demand-driven pricing tariffs, and increases of $10 million in retail solar program fees. Also contributing to the increase for year-to-date 2023 was an $11 million increase in open access transmission tariff sales.

Fuel and Purchased Power Expenses


	Third Quarter 2023 vs. Third Quarter 2022			Year-To-Date 2023 vs. Year-To-Date 2022
	(change in millions)		(% change)	(change in millions)		(% change)
Fuel	$	(265)	(31.5)	$	(495)	(26.2)
Purchased power – non-affiliates	(173)		(56.9)	(303)		(43.3)
Purchased power – affiliates	(350)		(61.3)	(521)		(47.4)
Total fuel and purchased power expenses	$	(788)		$	(1,319)

In the third quarter 2023, total fuel and purchased power expenses were $0.9 billion compared to $1.7 billion for the corresponding period in 2022. For year-to-date 2023, total fuel and purchased power expenses were $2.4 billion compared to $3.7 billion for the corresponding period in 2022. The decreases for the third quarter and year-to-date 2023 were due to decreases of $689 million and $1.0 billion, respectively, related to the average cost of fuel and purchased power and net decreases of $99 million and $293 million, respectively, related to the volume of KWHs generated and purchased.

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

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


	Third Quarter 2023	Third Quarter 2022	Year-To-Date 2023	Year-To-Date 2022
Total generation (in billions of KWHs)(a)	18	15	46	45
Total purchased power (in billions of KWHs)	9	11	23	27
Sources of generation (percent) —
Gas	47	53	51	48

Nuclear(a)	26	28	27	26
Coal	25	16	19	22
Hydro and other	2	3	3	4
Cost of fuel, generated (in cents per net KWH) —
Gas	2.99	6.10	3.07	4.99

Nuclear(a)	0.87	0.75	0.79	0.76
Coal	5.69	4.73	5.80	3.84
Average cost of fuel, generated (in cents per net KWH)(a)	3.11	4.32	2.98	3.56
Average cost of purchased power (in cents per net KWH)(b)	4.55	10.14	4.64	8.00

(a)Excludes KWHs generated from test period energy at Plant Vogtle Unit 3 prior to its in-service date. The related fuel costs are charged to CWIP in accordance with FERC guidance. See Note (B) to the Condensed Financial Statements under "Georgia Power – Nuclear Construction" herein for additional information on Plant Vogtle Units 3 and 4.

(b)Average cost of purchased power includes fuel purchased by Georgia Power for tolling agreements where power is generated by the provider.

Fuel

In the third quarter 2023, fuel expense was $576 million compared to $841 million for the corresponding period in 2022. The decrease was primarily due to a decrease of 51.0% in the average cost per KWH generated by natural gas, partially offset by increases of 78.6% in the volume of KWHs generated by coal, 20.3% in the average cost per KWH generated by coal, 16.0% in the average cost per KWH generated by nuclear, 8.8% in the volume of KWHs generated by nuclear, and 3.0% in the volume of KWHs generated by natural gas.

For year-to-date 2023, fuel expense was $1.39 billion compared to $1.89 billion for the corresponding period in 2022. The decrease was primarily due to decreases of 38.5% in the average cost per KWH generated by natural gas and 10.2% in the volume of KWHs generated by coal, partially offset by increases of 51.0% in the average cost per KWH generated by coal and 7.0% in the volume of KWHs generated by natural gas.

Purchased Power – Non-Affiliates

In the third quarter 2023, purchased power expense from non-affiliates was $131 million compared to $304 million for the corresponding period in 2022. For year-to-date 2023, purchased power expense from non-affiliates was $397 million compared to $700 million for the corresponding period in 2022. The decreases for the third quarter and year-to-date 2023 were primarily due to decreases of 38.1% and 37.8%, respectively, in the volume of KWHs purchased as Georgia Power and other Southern Company system units generally dispatched at a lower cost than available market resources and 45.1% and 24.1%, respectively, in the average cost per KWH purchased primarily due to lower natural gas prices.

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Purchased Power – Affiliates

In the third quarter 2023, purchased power expense from affiliates was $221 million compared to $571 million for the corresponding period in 2022. For year-to-date 2023, purchased power expense from affiliates was $579 million compared to $1.1 billion for the corresponding period in 2022. The decreases for the third quarter and year-to-date 2023 reflect decreases of 60.0% and 49.8%, respectively, in the average cost per KWH purchased primarily due to lower natural gas prices. Also contributing to the decrease in the third quarter 2023 was a 5.5% decrease in the volume of KWHs purchased.

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


Third Quarter 2023 vs. Third Quarter 2022		Year-To-Date 2023 vs. Year-To-Date 2022
(change in millions)	(% change)	(change in millions)	(% change)
$(83)	(13.9)	$(181)	(10.7)

In the third quarter 2023, other operations and maintenance expenses were $512 million compared to $595 million for the corresponding period in 2022. The decrease was primarily due to decreases of $64 million in transmission and distribution expenses primarily associated with line maintenance, $45 million in storm damage recovery as authorized in the 2022 ARP, and $25 million in generation non-outage maintenance expenses. These decreases were partially offset by increases of $21 million in generation environmental projects and $20 million from unregulated power delivery construction and maintenance and energy conservation projects.

For year-to-date 2023, other operations and maintenance expenses were $1.51 billion compared to $1.69 billion for the corresponding period in 2022. The decrease was primarily due to decreases of $136 million in storm damage recovery as authorized in the 2022 ARP, $121 million in transmission and distribution expenses primarily associated with line maintenance, $74 million in generation non-outage maintenance expenses, and $14 million in certain employee compensation and benefit expenses. These decreases were partially offset by increases of $48 million from unregulated power delivery construction and maintenance and energy conservation projects, $41 million in generation environmental projects, and $39 million in technology infrastructure and application production costs, as well as a $12 million decrease in nuclear property insurance refunds.

See Note 2 to the financial statements under "Georgia Power – Storm Damage Recovery" in Item 8 of the Form 10-K for additional information.

Depreciation and Amortization


Third Quarter 2023 vs. Third Quarter 2022		Year-To-Date 2023 vs. Year-To-Date 2022
(change in millions)	(% change)	(change in millions)	(% change)
$70	19.5	$182	17.1

In the third quarter 2023, depreciation and amortization was $429 million compared to $359 million for the corresponding period in 2022. For year-to-date 2023, depreciation and amortization was $1.25 billion compared to $1.07 billion for the corresponding period in 2022. The increases for the third quarter and year-to-date 2023 were primarily due to increases of $48 million and $142 million, respectively, resulting from higher depreciation rates as authorized in the 2022 ARP and $21 million and $51 million, respectively, associated with additional plant in service. Partially offsetting the increase for year-to-date 2023 was a decrease of $11 million in amortization of regulatory assets related to the retirement of certain generating units that ended in 2022.

See Note 5 to the financial statements under "Depreciation and Amortization" in Item 8 of the Form 10-K for additional information.

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Taxes Other Than Income Taxes


Third Quarter 2023 vs. Third Quarter 2022		Year-To-Date 2023 vs. Year-To-Date 2022
(change in millions)	(% change)	(change in millions)	(% change)
$(11)	(7.1)	$(14)	(3.3)

In the third quarter 2023, taxes other than income taxes were $144 million compared to $155 million for the corresponding period in 2022. For year-to-date 2023, taxes other than income taxes were $406 million compared to $420 million for the corresponding period in 2022. The decreases for the third quarter and year-to-date 2023 were due to decreases of $15 million and $33 million, respectively, in municipal franchise fees resulting from lower retail revenues, partially offset by increases of $3 million and $21 million, respectively, in property taxes primarily resulting from an increase in the assessed value of property.

Estimated Loss on Plant Vogtle Units 3 and 4

Third Quarter 2023 vs. Third Quarter 2022

Year-To-Date 2023 vs. Year-To-Date 2022

(change in millions)

(% change)

(change in millions)

(% change)

$230

N/M

$178

N/M

Georgia Power recorded pre-tax charges (credits) to income for the estimated probable loss on Plant Vogtle Units 3 and 4 totaling $160 million and $(70) million in the third quarter 2023 and 2022, respectively, and $160 million and $(18) million for year-to-date 2023 and 2022, respectively. The charges (credits) reflected revisions to the total project capital cost forecast to complete construction and start-up of Plant Vogtle Units 3 and 4. See Note (B) to the Condensed Financial Statements herein and Note 2 to the financial statements in Item 8 of the Form 10-K under "Georgia Power – Nuclear Construction" for additional information.

Allowance for Equity Funds Used During Construction


Third Quarter 2023 vs. Third Quarter 2022		Year-To-Date 2023 vs. Year-To-Date 2022
(change in millions)	(% change)	(change in millions)	(% change)
$—	—	$19	18.6

For year-to-date 2023, allowance for equity funds used during construction was $121 million compared to $102 million for the corresponding period in 2022. The increase was primarily due to an increase in capital expenditures subject to AFUDC.

Interest Expense, Net of Amounts Capitalized


Third Quarter 2023 vs. Third Quarter 2022		Year-To-Date 2023 vs. Year-To-Date 2022
(change in millions)	(% change)	(change in millions)	(% change)
$43	35.0	$125	36.0

In the third quarter 2023, interest expense, net of amounts capitalized was $166 million compared to $123 million for the corresponding period in 2022. For year-to-date 2023, interest expense, net of amounts capitalized was $472 million compared to $347 million for the corresponding period in 2022. The increases for the third quarter and year-to-date 2023 were primarily associated with increases of approximately $20 million and $64 million, respectively, related to higher average outstanding borrowings and $19 million and $59 million, respectively, related to higher interest rates. See FINANCIAL CONDITION AND LIQUIDITY – "Sources of Capital" and "Financing Activities" herein for additional information on borrowings.

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Other Income (Expense), Net


Third Quarter 2023 vs. Third Quarter 2022		Year-To-Date 2023 vs. Year-To-Date 2022
(change in millions)	(% change)	(change in millions)	(% change)
$9	25.0	$(15)	(10.7)

In the third quarter 2023, other income (expense), net was $45 million compared to $36 million for the corresponding period in 2022. The increase was primarily due to a $6 million decrease in non-operating marketing expenses.

For year-to-date 2023, other income (expense), net was $125 million compared to $140 million for the corresponding period in 2022. The decrease was primarily due to a decrease of $13 million in customer charges related to contributions in aid of construction and a $7 million charge in the second quarter 2023 under a stipulation agreement approved by the Georgia PSC related to Georgia Power's fuel cost recovery case, partially offset by a $6 million decrease in non-operating marketing expenses. See Note (B) to the Condensed Financial Statements herein under "Georgia Power – Fuel Cost Recovery" for additional information.

Income Taxes


Third Quarter 2023 vs. Third Quarter 2022		Year-To-Date 2023 vs. Year-To-Date 2022
(change in millions)	(% change)	(change in millions)	(% change)
$(26)	(11.5)	$(76)	(18.1)

In the third quarter 2023, income taxes were $200 million compared to $226 million for the corresponding period in 2022. For year-to-date 2023, income taxes were $345 million compared to $421 million for the corresponding period in 2022. The decreases were primarily due to lower pre-tax earnings largely resulting from higher charges associated with the construction of Plant Vogtle Units 3 and 4 and a decrease in a valuation allowance on certain state tax credit carryforwards in 2023, partially offset by the flowback of certain excess deferred income taxes that ended in 2022. Also contributing to the year-to-date 2023 decrease was an adjustment in the second quarter 2022 related to a prior year state tax credit carryforward. See Note (G) to the Condensed Financial Statements herein for additional information.

Mississippi Power

Net Income


Third Quarter 2023 vs. Third Quarter 2022		Year-To-Date 2023 vs. Year-To-Date 2022
(change in millions)	(% change)	(change in millions)	(% change)
$13	21.0	$23	15.3

Mississippi Power's net income for the third quarter 2023 was $75 million compared to $62 million for the corresponding period in 2022. The increase was primarily due to an increase in revenues due to warmer weather in the third quarter 2023 when compared to the corresponding period in 2022.

Mississippi Power's net income for year-to-date 2023 was $173 million compared to $150 million for the corresponding period in 2022. The increase was primarily due to an increase in affiliate wholesale capacity revenues, partially offset by an increase in interest expense.

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Retail Revenues

In the third quarter 2023, retail revenues were $284 million compared to $250 million for the corresponding period in 2022. For year-to-date 2023, retail revenues were $747 million compared to $718 million for the corresponding period in 2022. Details of the changes in retail revenues were as follows:


	Third Quarter 2023 vs. Third Quarter 2022				Year-To-Date 2023 vs. Year-To-Date 2022
	(change in millions)		(% change)		(change in millions)		(% change)
Rates and pricing	$	(3)	(1.2)	%	$	2	0.2	%
Sales growth	5		2.0		4		0.6
Weather	9		3.6		(1)		(0.1)
Fuel and other cost recovery	23		9.2		24		3.3
Retail revenues	$	34	13.6	%	$	29	4.0	%

Revenues associated with changes in rates and pricing decreased in the third quarter 2023 and increased year-to-date 2023 when compared to the corresponding periods in 2022. The third quarter 2023 decrease was primarily due to lower contributions from commercial and industrial customers with variable demand-driven pricing and the expiration of a PEP surcharge at the end of 2022 that became effective for the first billing cycle of April 2022, partially offset by higher revenues associated with a tolling arrangement accounted for as a sales-type lease. The year-to-date 2023 increase was primarily due to ECO Plan rates that became effective in May 2022 and higher revenues associated with a tolling arrangement accounted for as a sales-type lease, partially offset by the expiration of the PEP surcharge at the end of 2022 that became effective for the first billing cycle of April 2022. See Notes 2 and 9 to the financial statements under "Mississippi Power" and "Lessor," respectively, in Item 8 of the Form 10-K and Note (D) to the Condensed Financial Statements under "Lease Income" herein for additional information.

Revenues attributable to changes in sales increased in the third quarter and year-to-date 2023 when compared to the corresponding periods in 2022. Weather-adjusted residential KWH sales increased0.9% in the third quarter 2023 when compared to the corresponding period in 2022 due to an increase in customer usage. Weather-adjusted residential KWH sales decreased0.3% year-to-date 2023 when compared to the corresponding period in 2022 due to a decrease in customer usage. Weather-adjusted commercial KWH sales increased 11.8% and 6.4% in the third quarter and year-to-date 2023, respectively, when compared to the corresponding periods in 2022 due to sales growth associated with new commercial contracts. Industrial KWH sales increased 1.1% and 1.3% in the third quarter and year-to-date 2023, respectively, when compared to the corresponding periods in 2022 primarily due to an increase in the non-manufacturing sector, partially offset by a decrease in the chemicals sector.

Fuel and other cost recovery revenues increased in the third quarter and year-to-date 2023 when compared to the corresponding periods in 2022 primarily as a result of higher recoverable fuel costs. 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. Electric rates 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. See Note 2 to the financial statements in Item 8 of the Form 10-K for additional information.

Wholesale Revenues – Non-Affiliates


Third Quarter 2023 vs. Third Quarter 2022		Year-To-Date 2023 vs. Year-To-Date 2022
(change in millions)	(% change)	(change in millions)	(% change)
$17	28.3	$10	5.2

In the third quarter 2023, wholesale revenues from sales to non-affiliates were $77 million compared to $60 million for the corresponding period in 2022. The increase was primarily due to an $11 million increase associated with

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MRA customers and a $6 million increase associated with opportunity sales. The increase from MRA customers was primarily due to higher recoverable fuel costs and an increase in demand as a result of weather impacts.

For year-to-date 2023, wholesale revenues from sales to non-affiliates were $201 million compared to $191 million for the corresponding period in 2022. The increase was due to a $6 million increase associated with MRA customers and a $4 million increase associated with opportunity sales. The increase from MRA customers was primarily due to a rate increase under the MRA tariff effective September 2022 and higher recoverable fuel costs, partially offset by a decrease in demand as a result of weather impacts.

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

Wholesale Revenues – Affiliates


Third Quarter 2023 vs. Third Quarter 2022		Year-To-Date 2023 vs. Year-To-Date 2022
(change in millions)	(% change)	(change in millions)	(% change)
$(122)	(65.2)	$(178)	(53.0)

In the third quarter 2023, wholesale revenues from sales to affiliates were $65 million compared to $187 million for the corresponding period in 2022. The decrease was primarily due to a $141 million decrease associated with lower natural gas prices, partially offset by a $19 million increase associated with higher KWH sales.

For year-to-date 2023, wholesale revenues from sales to affiliates were $158 million compared to $336 million for the corresponding period in 2022. The decrease was primarily due to a $216 million decrease associated with lower natural gas prices, partially offset by a $29 million increase in capacity revenues resulting from an increase in pricing and volume of generation reserves and a $9 million increase associated with higher KWH sales.

Fuel and Purchased Power Expenses


	Third Quarter 2023 vs. Third Quarter 2022			Year-To-Date 2023 vs. Year-To-Date 2022
	(change in millions)		(% change)	(change in millions)		(% change)
Fuel	$	(80)	(33.1)	$	(167)	(29.6)
Purchased power	(13)		(65.0)	(18)		(50.0)
Total fuel and purchased power expenses	$	(93)		$	(185)

In the third quarter 2023, total fuel and purchased power expenses were $169 million compared to $262 million for the corresponding period in 2022. For year-to-date 2023, total fuel and purchased power expenses were $416 million compared to $601 million for the corresponding period in 2022. The decreases for the third quarter and year-to-date 2023 were primarily due to decreases of $122 million and $203 million, respectively, related to the

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average cost of fuel and purchased power, partially offset by net increases of $29 million and $18 million, respectively, related to the volume of KWHs generated and purchased.

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


	Third Quarter 2023	Third Quarter 2022	Year-To-Date 2023	Year-To-Date 2022
Total generation (in millions of KWHs)	5,783	5,093	14,123	13,650
Total purchased power (in millions of KWHs)	153	241	427	527
Sources of generation (percent) –
Gas	87	89	92	89
Coal	13	11	8	11
Cost of fuel, generated (in cents per net KWH) –
Gas	2.52	5.10	2.72	4.43
Coal	5.49	4.50	5.64	4.12
Average cost of fuel, generated (in cents per net KWH)	2.92	5.02	2.97	4.40
Average cost of purchased power (in cents per net KWH)	4.61	8.15	4.27	6.83

Fuel

In the third quarter 2023, fuel expense was $162 million compared to $242 million for the corresponding period in 2022. The decrease was due to a 50.6% decrease in the average cost of natural gas per KWH generated, partially offset by a 28.5% increase in the volume of KWHs generated by coal, a 22.0% increase in the average cost of coal per KWH generated, and a 13.5% increase in the volume of KWHs generated by natural gas.

For year-to-date 2023, fuel expense was $398 million compared to $565 million for the corresponding period in 2022. The decrease was due to a 38.6% decrease in the average cost of natural gas per KWH generated and a 21.7% decrease in the volume of KWHs generated by coal, partially offset by a 36.9% increase in the average cost of coal per KWH generated and a 7.5% increase in the volume of KWHs generated by natural gas.

Purchased Power

In the third quarter 2023, purchased power expense was $7 million compared to $20 million for the corresponding period in 2022. For year-to-date 2023, purchased power expense was $18 million compared to $36 million for the corresponding period in 2022. The decreases for the third quarter and year-to-date 2023 were due to decreases of 43.4% and 37.5%, respectively, in the average cost per KWH purchased primarily due to lower natural gas prices and decreases of 36.4% and 18.9%, respectively, in the volume of KWHs purchased.

Other Operations and Maintenance Expenses


Third Quarter 2023 vs. Third Quarter 2022		Year-To-Date 2023 vs. Year-To-Date 2022
(change in millions)	(% change)	(change in millions)	(% change)
$(2)	(2.3)	$6	2.4

For year-to-date 2023, other operations and maintenance expenses were $258 million compared to $252 million for the corresponding period in 2022. The increase was primarily due to increases of $5 million in generation expenses and $4 million in storm reserve accruals, partially offset by a decrease of $5 million in sales and use taxes associated with the Kemper County energy facility.

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See Notes 2 and 3 to the financial statements under "Mississippi Power – System Restoration Rider" and "Other Matters – Mississippi Power," respectively, in Item 8 of the Form 10-K and Notes (B) and (C) to the Condensed Financial Statements under "Mississippi Power – System Restoration Rider" and "Other Matters – Mississippi Power," respectively, herein for additional information.

Interest Expense, Net of Amounts Capitalized


Third Quarter 2023 vs. Third Quarter 2022		Year-To-Date 2023 vs. Year-To-Date 2022
(change in millions)	(% change)	(change in millions)	(% change)
$4	26.7	$11	26.2

In the third quarter 2023, interest expense, net of amounts capitalized was $19 million compared to $15 million for the corresponding period in 2022. For year-to-date 2023, interest expense, net of amounts capitalized was $53 million compared to $42 million for the corresponding period in 2022. The increases for the third quarter and year-to-date 2023 were associated with increases of approximately $2 million and $8 million, respectively, related to higher interest rates and $2 million and $4 million, respectively, related to higher average outstanding borrowings. See FINANCIAL CONDITION AND LIQUIDITY – "Sources of Capital" and "Financing Activities" herein for additional information on borrowings.

Income Taxes


Third Quarter 2023 vs. Third Quarter 2022		Year-To-Date 2023 vs. Year-To-Date 2022
(change in millions)	(% change)	(change in millions)	(% change)
$1	5.9	$(3)	(7.9)

For year-to-date 2023, income taxes were $35 million compared to $38 million for the corresponding period in 2022. The decrease was primarily due to a decrease of $7 million associated with the flowback of certain excess deferred income taxes, largely offset by an increase of $5 million associated with higher pre-tax earnings. See Note (G) to the Condensed Financial Statements herein for additional information.

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Southern Power

Net Income Attributable to Southern Power


Third Quarter 2023 vs. Third Quarter 2022		Year-To-Date 2023 vs. Year-To-Date 2022
(change in millions)	(% change)	(change in millions)	(% change)
$5	5.3	$23	8.7

Net income attributable to Southern Power in the third quarter 2023 was $100 million compared to $95 million for the corresponding period in 2022. The increase was primarily due to an arbitration interim award received for losses previously incurred, higher HLBV income associated with tax equity partnerships, and receipts of liquidated damages associated with generation facility production guarantees, partially offset by lower revenues driven by lower market prices of energy.

Net income attributable to Southern Power for year-to-date 2023 was $288 million compared to $265 million for the corresponding period in 2022. The increase was primarily due to an arbitration interim award received for losses previously incurred, a gain on the sale of spare parts, higher HLBV income associated with tax equity partnerships, and receipts of liquidated damages and insurance proceeds related to generation facility production and equipment, as well as changes in state apportionment methodology related to tax legislation enacted by the State of Tennessee. These increases were largely offset by lower revenues driven by lower market prices of energy.

See Note (C) to the Condensed Financial Statements under "General Litigation Matters – Southern Power" herein for additional information.

Operating Revenues


Third Quarter 2023 vs. Third Quarter 2022		Year-To-Date 2023 vs. Year-To-Date 2022
(change in millions)	(% change)	(change in millions)	(% change)
$(527)	(44.7)	$(932)	(35.6)

Total operating revenues include PPA capacity revenues, which are derived primarily from long-term contracts involving natural gas facilities, 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 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

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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" in Item 7 of the Form 10-K for additional information regarding Southern Power's PPAs.

Operating Revenues Details

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


	Third Quarter 2023		Third Quarter 2022		Year-To-Date 2023		Year-To-Date 2022
	(in millions)
PPA capacity revenues	$	134	$	131	$	360	$	344
PPA energy revenues	370		736		953		1,657
Total PPA revenues	504		867		1,313		2,001
Non-PPA revenues	131		304		327		590
Other revenues	18		9		46		27
Total operating revenues	$	653	$	1,180	$	1,686	$	2,618

In the third quarter 2023, total operating revenues were $653 million, reflecting a $527 million, or 44.7%, decrease from the corresponding period in 2022. The change in operating revenues was primarily due to the following:

•PPA energy revenues decreased $366 million, or 49.7%, primarily due to a $378 million decrease in sales under natural gas PPAs resulting from a $304 million decrease in the price of fuel and purchased power and a $75 million decrease in the volume of KWHs sold.

•Non-PPA revenues decreased $173 million, or 56.9%, primarily due to a $252 million decrease in the market price of energy, partially offset by a $76 million increase in the volume of KWHs sold through short-term sales.

•Other revenues increased $9 million, or 100.0%, primarily due to an arbitration interim award received for losses previously incurred. See Note (C) to the Condensed Financial Statements under "General Litigation Matters – Southern Power" herein for additional information.

For year-to-date 2023, total operating revenues were $1.7 billion, reflecting a $932 million, or 35.6%, decrease from the corresponding period in 2022. The change in operating revenues was primarily due to the following:

•PPA capacity revenues increased $16 million, or 4.7%, primarily due to a net increase in MW capacity under contract from natural gas PPAs and an increase associated with a change in rates from natural gas PPAs.

•PPA energy revenues decreased $704 million, or 42.5%, primarily due to a $706 million decrease in sales under natural gas PPAs resulting from a $577 million decrease in the price of fuel and purchased power and a $129 million decrease in the volume of KWHs sold.

•Non-PPA revenues decreased $263 million, or 44.6%, primarily due to a $522 million decrease in the market price of energy, partially offset by a $255 million increase in the volume of KWHs sold through short-term sales.

•Other revenues increased $19 million, or 70.4%, primarily due to receipts of liquidated damages associated with generation facility production guarantees, an arbitration interim award received for losses previously incurred, and business interruption insurance proceeds for damaged generation equipment. See Note (C) to the Condensed Financial Statements under "General Litigation Matters – Southern Power" herein for additional information.

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Fuel and Purchased Power Expenses

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


	Third Quarter 2023	Third Quarter 2022	Year-To-Date 2023	Year-To-Date 2022
	(in billions of KWHs)
Generation	12.9	12.8	36.9	36.7
Purchased power	0.8	1.2	2.4	2.3
Total generation and purchased power	13.7	14.0	39.3	39.0

Total generation and purchased power (excluding solar, wind, fuel cells, and tolling agreements)	8.5	8.8	24.7	23.2

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.

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


	Third Quarter 2023 vs. Third Quarter 2022			Year-To-Date 2023 vs. Year-To-Date 2022
	(change in millions)		(% change)	(change in millions)		(% change)
Fuel	$	(409)	(67.6)	$	(748)	(58.7)
Purchased power	(111)		(77.1)	(146)		(62.7)
Total fuel and purchased power expenses	$	(520)		$	(894)

In the third quarter 2023, total fuel and purchased power expenses decreased $520 million, or 69.4%, compared to the corresponding period in 2022. Fuel expense decreased $409 million primarily due to a $421 million decrease associated with the average cost of fuel. Purchased power expense decreased $111 million due to a $61 million decrease associated with the average cost of purchased power and a $50 million decrease associated with the volume of KWHs purchased.

For year-to-date 2023, total fuel and purchased power expenses decreased $894 million, or 59.3%, compared to the corresponding period in 2022. Fuel expense decreased $748 million due to an $835 million decrease associated with the average cost of fuel, partially offset by an $87 million increase associated with the volume of KWHs generated. Purchased power expense decreased $146 million primarily due to a $152 million decrease associated with the average cost of purchased power.

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Other Operations and Maintenance Expenses


Third Quarter 2023 vs. Third Quarter 2022		Year-To-Date 2023 vs. Year-To-Date 2022
(change in millions)	(% change)	(change in millions)	(% change)
$(9)	(8.0)	$(5)	(1.5)

In the third quarter 2023, other operations and maintenance expenses were $104 million compared to $113 million for the corresponding period in 2022. For year-to-date 2023, other operations and maintenance expenses were $327 million compared to $332 million for the corresponding period in 2022. The decreases were primarily due to $11 million from an arbitration interim award received for losses previously incurred. The year-to-date 2023 decrease was largely offset by an increase in generation maintenance expenses. See Note (C) to the Condensed Financial Statements under "General Litigation Matters – Southern Power" herein for additional information.

Gain on Dispositions, Net

Third Quarter 2023 vs. Third Quarter 2022

Year-To-Date 2023 vs. Year-To-Date 2022

(change in millions)

(% change)

(change in millions)

(% change)

$—

—

$18

N/M

For year-to-date 2023, gain on dispositions, net was $20 million compared to $2 million for the corresponding period in 2022. The increase was primarily due to a $16 million gain on the sale of spare parts in 2023.

Interest Expense, Net of Amounts Capitalized


Third Quarter 2023 vs. Third Quarter 2022		Year-To-Date 2023 vs. Year-To-Date 2022
(change in millions)	(% change)	(change in millions)	(% change)
$—	—	$(7)	(6.7)

For year-to-date 2023, interest expense, net of amounts capitalized was $98 million compared to $105 million for the corresponding period in 2022. The decrease was primarily due to lower average outstanding borrowings.

Income Taxes


Third Quarter 2023 vs. Third Quarter 2022		Year-To-Date 2023 vs. Year-To-Date 2022
(change in millions)	(% change)	(change in millions)	(% change)
$3	8.3	$(11)	(22.4)

For year-to-date 2023, income tax expense was $38 million compared to $49 million for the corresponding period in 2022. The decrease was primarily due to a change in state apportionment methodology resulting from tax legislation enacted by the State of Tennessee in the second quarter 2023, partially offset by higher pre-tax earnings. See Note (G) to the Condensed Financial Statements herein for additional information.

Net Income (Loss) Attributable to Noncontrolling Interests


Third Quarter 2023 vs. Third Quarter 2022		Year-To-Date 2023 vs. Year-To-Date 2022
(change in millions)	(% change)	(change in millions)	(% change)
$(2)	(16.7)	$(13)	(23.6)

In the third quarter 2023, net income attributable to noncontrolling interests was $10 million compared to $12 million for the corresponding period in 2022. The decrease was primarily due to $7 million in higher HLBV loss allocations to wind tax equity partners, largely offset by an allocation of $6 million to equity partners related to an arbitration interim award received for losses previously incurred.

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For year-to-date 2023, net loss attributable to noncontrolling interests was $68 million compared to $55 million for the corresponding period in 2022. The increase was primarily due to $16 million in higher HLBV loss allocations to wind tax equity partners and $12 million in lower income allocations to equity partners, partially offset by $15 million in lower loss allocations to battery energy storage partners.

See Note (C) to the Condensed Financial Statements under "General Litigation Matters – Southern Power" herein for additional information.

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. ~~For additional information on these indicators, see MANAGEMENT'S DISCUSSION AND ANALYSIS – RESULTS OF OPERATIONS – "Operating Metrics" of Southern Company Gas in Item 7 of the Form 10-K.~~

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. ~~With the exception of Southern Company Gas' utilities in Illinois and Florida,~~ Southern Company Gas has various regulatory mechanisms, such as weather and revenue normalization ~~mechanisms,~~and straight-fixed-variable rate design, which limit its exposure to weather changes within typical ranges in each of its ~~utilities'~~utility's respective service territory. ~~However, the utility customers in Illinois and the gas marketing services customers primarily in Georgia and Illinois can be impacted by warmer- or colder-than-normal weather.~~ Southern Company Gas also utilizes weather hedges ~~at gas distribution operations and gas marketing services~~ to ~~reduce~~limit the negative ~~earnings impact~~income impacts in the event of warmer-than-normal ~~weather, while retaining most of the earnings upside.~~weather.

The number of customers atserved by gas distribution operations and ~~energy customers at~~ 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, ~~is the period from November through March when~~ 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 and 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. ~~Operating~~Thus, Southern Company Gas' operating results for the interim periods presented are not necessarily indicative of annual results and can vary significantly from quarter to quarter.

~~RESULTS OF OPERATIONS~~

Net Income


Third Quarter 2023 vs. Third Quarter 2022		Year-To-Date 2023 vs. Year-To-Date 2022
(change in millions)	(% change)	(change in millions)	(% change)
$(1)	(1.2)	$(41)	(7.9)



~~Successor~~
~~Third Quarter 2017 vs. Third Quarter 2016~~
~~(change in millions)~~		~~(% change)~~
~~$11~~		~~N/M~~

~~N/M - Not meaningful~~

~~Net income attributable to~~ Southern Company ~~Gas~~Gas' net income for year-to-date 2023 was ~~$15~~$475 million ~~for the third quarter 2017~~ compared to $4$516 million for the corresponding period in ~~2016. This increase~~2022. The decrease was primarily due to $11 million of additional income from infrastructure replacement programs and base rate increases, net of associated depreciation, and a $7 million gain from the settlement of contractor litigation claims, partially offset by $12 million lower net income at ~~wholesale~~ gas ~~services. Also contributing~~distribution operations primarily as a result of a $28 million regulatory disallowance at Nicor Gas and a $6 million decrease in net income at gas marketing services primarily related to hedge losses. See Note (B) to the ~~increase was $24 million in Merger-related expenses in the third quarter 2016, partially offset by $23 million of~~Condensed Financial Statements under "Southern Company Gas – Infrastructure Replacement Programs and Capital Projects" herein for additional ~~deferred income tax expense in the third quarter 2017.~~

information.

~~177~~

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~~SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES~~

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION

AND RESULTS OF OPERATIONS (Continued)

Successor Predecessor
Year-to-Date 2017 July 1, 2016 through September 30, 2016 January 1, 2016 through June 30, 2016
(in millions) (in millions) (in millions)
Net Income Attributable to
Southern Company Gas $ 303
$ 4
$ 131

Net income attributable to Southern Company Gas for the successor year-to-date 2017 included $28 million of net income from wholesale gas services and $38 million in earnings from the SNG investment, net of related interest expense. Also included in net income for this period was $29 million generated from the continued investment in infrastructure replacement programs and base rate increases, primarily at Atlanta Gas Light effective March 1, 2017, less the associated increases in depreciation. For additional information, see ~~FUTURE EARNINGS POTENTIAL– "Regulatory Matters – Base Rate Cases" herein. These increases were partially offset by $23 million of additional deferred income tax expense.~~

Net income attributable to Southern Company Gas for the successor period of July 1, 2016 through September 30, 2016 and the predecessor period of January 1, 2016 through June 30, 2016 included $11 million and $42 million, respectively, in net losses from wholesale gas services. The successor period of July 1, 2016 through September 30, 2016 also included $16 million in earnings from the SNG investment, net of related interest expense. Also included in net income for these periods were $24 million and $41 million, respectively, of Merger-related expenses and $14 million of net income attributable to noncontrolling interest in the predecessor period of January 1, 2016 through June 30, 2016. As a result of purchasing the remaining interest in SouthStar in October 2016, all net income was attributable to Southern Company Gas in the successor periods.

Natural Gas Revenues

Successor
Third Quarter 2017 vs. Third Quarter 2016
(change in millions) (% change)
$14 2.7

In the third quarter ~~2017,~~2023, natural gas revenues were ~~$532 million~~$0.7 billion compared to ~~$518 million~~$0.9 billion for the corresponding period in ~~2016.~~

2022. For year-to-date 2023, natural gas revenues were $3.4 billion compared to $4.0 billion for the corresponding period in 2022. Details of the changes in natural gas revenues were as follows:


	Third Quarter 2023 vs. Third Quarter 2022				Year-To-Date 2023 vs. Year-To-Date 2022
	(change in millions)		(% change)		(change in millions)		(% change)


Infrastructure replacement programs and rate changes	$	9	1.1	%	$	97	2.4	%
Gas costs and other cost recovery	(181)		(21.1)		(645)		(16.1)
Gas marketing services	(22)		(2.6)		(44)		(1.1)

Other	26		3.0		11		0.3
Natural gas revenues	$	(168)	(19.6)	%	$	(581)	(14.5)	%

Third Quarter 2017
(in millions) (% change)
Natural gas – prior year $ 518

Estimated change resulting from –
Infrastructure replacement programs and base rate increases 25
4.8 %
Gas costs and other cost recovery 1
0.2
Mark-to-market adjustments at gas marketing services 3
0.6
Wholesale gas services (16 ) (3.1 )
Other 1
0.2
Natural gas – current year $ 532
2.7 %

~~The increase~~Revenues from infrastructure replacement programs and rate changes increased in the third quarter and year-to-date 2023 compared to the corresponding periods in 2022 primarily due to rate increases at the natural gas ~~revenue primarily relates to gas~~ distribution ~~operations as a result of~~utilities and continued investment in infrastructure replacement programs and increases in base rate revenues, primarily at Atlanta Gas Light effective March 1, 2017, as well as the positive impact from the amortization of assets established in the application of acquisition accounting at gas marketing services. These increases were partially offset by mark-to-

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~~MANAGEMENT'S DISCUSSION AND ANALYSIS OF~~

~~FINANCIAL CONDITION AND RESULTS OF OPERATIONS~~

market losses from derivative instruments at wholesale gas services and gas marketing services due to changes in natural gas prices and a decrease in commercial activity at wholesale gas services. For information on commercial activity at wholesale gas services, see "Segment Information – Wholesale Gas Services – Change in Commercial Activity" herein.

Successor Predecessor
Year-to-Date 2017 July 1, 2016 through September 30, 2016 January 1, 2016 through June 30, 2016
(in millions) (in millions) (in millions)
Natural gas revenues $ 2,746
$ 518
$ 1,841

~~For the successor~~replacement. The year-to-date 2017, natural gas revenues included recovery of $1.1 billion in cost of natural gas and $95 million in net revenues from wholesale gas services, net of $14 million of amortization associated with assets established in the application of acquisition accounting. Also included in natural gas revenues were $69 million in additional revenues generated from gas distribution operations as a result of continued investment in infrastructure replacement programs and increases in base rate revenues, primarily at Atlanta Gas Light effective March 1, 2017,2023 increase was partially offset by a ~~$16 million decrease attributable~~regulatory disallowance at Nicor Gas. See Note 2 to ~~warmer-than-normal weather, net~~the financial statements under "Southern Company Gas – Rate Proceedings" in Item 8 of ~~hedging.~~the Form 10-K and Note (B) to the Condensed Financial Statements under "Southern Company Gas – Infrastructure Replacement Programs and Capital Projects" herein for additional information.

~~For~~Revenues from gas costs and other cost recovery decreased in the ~~successor period of July 1, 2016 through September 30, 2016~~third quarter and year-to-date 2023 compared to the ~~predecessor period of January 1, 2016 through June 30, 2016,~~corresponding periods in 2022 primarily due to lower natural gas ~~revenues included~~cost recovery ~~of $133 million and $755 million, respectively, in cost~~associated with lower natural gas prices, the timing of natural gas ~~as well as $8 million~~purchases, and ~~$32 million, respectively, in net losses~~the recovery of those costs from wholesale gas services. Also included in natural gas revenues for the predecessor period of January 1, 2016 through June 30, 2016 was a $7 million decrease attributable to warmer-than-normal weather, net of hedging.

customers. See "~~Segment Information" herein for additional information on wholesale gas services' revenues and losses.~~

Natural gas distribution rates include provisions to adjust billings for fluctuations in natural gas costs. Therefore, recoverable natural gas revenues generally equal the cost of natural gas and do not affect net income from gas distribution operations. See "~~Cost~~"Cost of Natural ~~Gas~~"Gas" herein for additional information. Revenue impacts from weather and customer growth are described further below.

~~During Heating Season~~Revenues from gas marketing services decreased in the third quarter and year-to-date 2023 compared to the corresponding periods in 2022 primarily due to lower natural gas ~~usage~~prices and ~~operating revenues are generally higher. Weather~~lower variable price spreads.

Southern Company Gas' natural gas distribution utilities have various regulatory mechanisms that limit their exposure to weather changes. Southern Company Gas also uses hedges for the majority of any remaining exposure to warmer-than-normal weather in Illinois for gas distribution operations and in Illinois and Georgia for gas marketing services; therefore, weather typically does not have a significant net income ~~impact during the non-Heating Season.~~impact. 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.~~weather:


	Third Quarter							Year-to-Date
				2023 vs. normal		2023 vs. 2022					2023 vs. normal		2023 vs. 2022
	Normal(*)	2023	2022	warmer		warmer		Normal(*)	2023	2022	warmer		warmer
	(in thousands)							(in thousands)
Illinois	40	18	56	(55.0)	%	(67.9)	%	3,755	3,216	3,683	(14.4)	%	(12.7)	%
Georgia	3	—	—	—	%	—	%	1,461	1,029	1,361	(29.6)	%	(24.4)	%

(*)Normal represents the 10-year average from January 1, 2013 through September 30, 2022 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.

137

Year-to-Date 2017
vs.
2016 2017
vs.
normal

Normal^(a)
2017 2016 (warmer) (warmer)
Illinois^(b)
3,817
3,146
3,353
(6.2 )% (17.6 )%
Georgia 1,631
1,008
1,449
(30.4 )% (38.2 )%


~~(a)~~	Normal represents the 10-year average from January 1, 2007 through September 30, 2016 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)~~	~~The 10-year average Heating Degree Days established by the Illinois Commission in Nicor Gas' 2009 rate case is 3,580 for the first nine months from 1998 through 2007.~~

~~For the third quarters 2017 and 2016, the weather-related pre-tax income impact was immaterial.~~

Southern Company Gas hedged its exposure to warmer-than-normal weather at Nicor Gas in Illinois; therefore, the weather-related negative pre-tax income impact on gas distribution operations was limited to $6 million ($3 million after tax) and $7 million ($5 million after tax) for year-to-date 2017 and 2016, respectively. Southern Company Gas also hedged its exposure at gas marketing services to warmer-than-normal weather in Georgia and Illinois;

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION

AND RESULTS OF OPERATIONS (Continued)

therefore, the weather-related negative pre-tax income impact on gas marketing services was limited to $10 million ($6 million after tax) for year-to-date 2017 and there was no impact for year-to-date 2016.

The following table provides the number of customers served by Southern Company Gas at September 30, ~~2017~~2023 and ~~2016:~~2022:


	September 30,
	2023		2022		2023 vs. 2022
	(in thousands, except market share %)				(% change)
Gas distribution operations	4,316		4,300		0.4	%
Gas marketing services
Energy customers(*)	656		598		9.7	%
Market share of energy customers in Georgia	29.9	%	28.3	%

September 30,
2017 2016 2017 vs. 2016
(in thousands, except market share %) (% change)
Gas distribution operations 4,555
4,522
0.7 %
Gas marketing services
Energy customers^(*)
756
626
20.8 %
Market share of energy customers in Georgia 28.8 % 29.4 %
Service contracts 1,183
1,189
(0.5 )%
(*)Gas marketing services' customers are primarily located in Georgia, Ohio, and Illinois.


~~(*)~~	~~Includes approximately 140,000 customers as of September 30, 2017 that were contracted to serve beginning April 1, 2017.~~

Southern Company Gas anticipates ~~overall~~ customer growth ~~trends at gas distribution operations~~and uses a variety of targeted marketing programs to ~~continue as it expects continued improvement in the~~attract new ~~housing market and low natural gas prices.~~

Gas marketing services' market share in Georgia decreased at September 30, 2017 compared to the corresponding period in 2016 as a result of a highly competitive marketing environment, which Southern Company Gas expects to continue for the foreseeable future. Southern Company Gas will continue efforts at gas marketing services to enter into targeted markets and expand its energy customers and ~~service contracts.~~to retain existing customers.

Cost of Natural Gas


Third Quarter 2023 vs. Third Quarter 2022		Year-To-Date 2023 vs. Year-To-Date 2022
(change in millions)	(% change)	(change in millions)	(% change)
$(192)	(65.3)	$(641)	(34.8)

Successor
Third Quarter 2017 vs. Third Quarter 2016
(change in millions) (% change)
$1 0.8

~~In the third quarter 2017, cost of~~Excluding Atlanta Gas Light, which does not sell natural gas ~~was $134 million compared~~ to ~~$133 million for the corresponding period in 2016. This increase reflected 7% higher~~end-use customers, natural ~~gas prices during the third quarter 2017 compared to the corresponding period in 2016, partially offset by lower demand for natural gas.~~

Successor Predecessor
Year-to-Date 2017 July 1, 2016 through September 30, 2016 January 1, 2016 through June 30, 2016
(in millions) (in millions) (in millions)
Cost of natural gas $ 1,085
$ 133
$ 755

Cost of natural gas primarily reflected an increase of 38% in natural gas prices during the year-to-date 2017 compared to the corresponding period in 2016, partially offset by lower demand for natural gas driven by warmer-than-normal weather.

~~Natural~~ gas distribution rates include provisions to adjust billings for fluctuations in natural gas costs. Therefore, ~~recoverable~~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 ~~approximately 79%~~76% and 84% of the total cost of natural gas ~~for~~in the third quarter and year-to-date ~~2017 and will be recovered in this manner. For additional information, see~~2023, respectively. See MANAGEMENT'S DISCUSSION AND ANALYSIS – RESULTS OF OPERATIONS – ~~"Cost~~"Southern Company Gas – Cost of Natural Gas" ~~of Southern Company Gas~~ in Item 7 of the Form 10-K and "~~Natural~~"Natural Gas ~~Revenues" herein.~~Revenues" herein for additional information.

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~~Table~~In the third quarter 2023, cost of ~~Contents~~

~~SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES~~

~~MANAGEMENT'S DISCUSSION AND ANALYSIS OF~~

~~FINANCIAL CONDITION AND RESULTS OF OPERATIONS~~

natural gas was $102 million compared to $294 million for the corresponding period in 2022. For year-to-date 2023, cost of natural gas was $1.2 billion compared to $1.8 billion for the corresponding period in 2022. The decreases reflect lower gas cost recovery as a result of decreases of 69% and 60% in natural gas prices in the third quarter and year-to-date 2023, respectively, compared to the corresponding periods in 2022.

The following table details the volumes of natural gas sold during ~~all~~both periods ~~presented.~~presented:


	Third Quarter				Year-to-Date
	2023	2022	2023 vs. 2022		2023	2022	2023 vs. 2022
Gas distribution operations (mmBtu in millions)
Firm	71	70	1.4	%	429	485	(11.5)	%
Interruptible	22	22	—		70	69	1.4
Total	93	92	1.1	%	499	554	(9.9)	%


Gas marketing services (mmBtu in millions)
Firm:
Georgia	3	3	—	%	21	24	(12.5)	%
Illinois	1	—	100.0		5	4	25.0

Other	3	2	50.0		9	8	12.5
Interruptible large commercial and industrial	2	3	(33.3)		10	11	(9.1)
Total	9	8	12.5	%	45	47	(4.3)	%

138

Third Quarter 2017
vs.
2016 Year-to-Date 2017
vs.
2016
2017 2016 % Change 2017 2016 % Change
Gas distribution operations
(mmBtu in millions)

Firm 73
71
2.8 % 438
467
(6.2 )%
Interruptible 22
22
— % 71
71
— %
Total 95
93
2.2 % 509
538
(5.4 )%
Gas marketing services
(mmBtu in millions)

Firm:
Georgia 3
3
— % 11
25
(56.0 )%
Illinois 1
1
— % 4
8
(50.0 )%
Other emerging markets 2
2
— % 7
9
(22.2 )%
Interruptible:
Large commercial and industrial 3
3
— % 8
10
(20.0 )%
Total 9
9
— % 30
52
(42.3 )%
Wholesale gas services
(mmBtu in millions/day)

Daily physical sales 6.3
7.6
(17.1 )% 6.4
7.6
(15.8 )%

Table of ContentsIndex to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION

AND RESULTS OF OPERATIONS (Continued)

Other Operations and Maintenance Expenses


Third Quarter 2023 vs. Third Quarter 2022		Year-To-Date 2023 vs. Year-To-Date 2022
(change in millions)	(% change)	(change in millions)	(% change)
$12	4.8	$55	6.7

Successor
Third Quarter 2017 vs. Third Quarter 2016
(change in millions) (% change)
$(11) (5.1)

In the third quarter ~~2017,~~2023, other operations and maintenance expenses were ~~$205~~$264 million compared to ~~$216~~$252 million for the corresponding period in ~~2016.~~2022. The ~~decrease~~increase for the third quarter 2023 was primarily due to increases of $8 million in compensation and benefits, $5 million related to $8energy service contracts, and $4 million ~~of expenses associated with certain benefit arrangements recorded in 2016, $2 million lower marketing expenses~~ at gas marketing services primarily related to customer service and information. The increases were partially offset by a $3decrease of $12 million ~~decrease~~ in expenses passed through to customers primarily related to bad debt and energy efficiency programs at gas distribution operations.

For year-to-date 2023, other ~~employee benefit and incentive costs.~~

Successor Predecessor
Year-to-Date 2017 July 1, 2016 through September 30, 2016 January 1, 2016 through June 30, 2016
(in millions) (in millions) (in millions)
Other operations and maintenance $ 671
$ 216
$ 454

~~Other operations~~operations and maintenance expenses for the successor year-to-date 2017 reflected increased compensation expenses due to timing, partially offset by low bad debt expense. For all periods presented, other operations and maintenance expenses primarily includes professional services, including pipeline compliance and maintenance and legal services, as well as compensation and benefit costs.

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~~MANAGEMENT'S DISCUSSION AND ANALYSIS OF~~

~~FINANCIAL CONDITION AND RESULTS OF OPERATIONS~~

~~Depreciation and Amortization~~

Successor
Third Quarter 2017 vs. Third Quarter 2016
(change in millions) (% change)
$9 7.8

~~In the third quarter 2017, depreciation and amortization was $125~~were $879 million compared to ~~$116~~$824 million for the corresponding period in ~~2016.~~2022. The increase was primarily due to $7increases of $52 million in ~~additional depreciation~~compensation and benefits, $30 million related to a regulatory disallowance at Nicor Gas, and an increase of $20 million related to energy service contracts, partially offset by a decrease of $32 million in expenses passed through to customers primarily related to bad debt and energy efficiency programs at gas distribution ~~operations associated with~~operations. See Note (B) to the Condensed Financial Statements under "Southern Company Gas – Infrastructure Replacement Programs and Capital Projects" herein for additional ~~plant in service primarily related to continued investment in infrastructure replacement programs.~~

Successor Predecessor
Year-to-Date 2017 July 1, 2016 through September 30, 2016 January 1, 2016 through June 30, 2016
(in millions) (in millions) (in millions)
Depreciation and amortization $ 370
$ 116
$ 206
information on the regulatory disallowance.

Depreciation and Amortization


Third Quarter 2023 vs. Third Quarter 2022		Year-To-Date 2023 vs. Year-To-Date 2022
(change in millions)	(% change)	(change in millions)	(% change)
$5	3.6	$15	3.6

In the third quarter 2023, depreciation and amortization was $145 million compared to $140 million for the ~~successor~~corresponding period in 2022. For year-to-date ~~2017 included $29~~2023, depreciation and amortization was $429 million ~~of additional amortization of intangible assets established~~compared to $414 million for the corresponding period in 2022. The increases were primarily due to continued infrastructure investments at the ~~application of acquisition accounting primarily at gas marketing services, $21 million in additional depreciation at~~natural gas distribution operations due to additional assets placed in service primarily related to continued investment in infrastructure replacement programs, and $7 million from the acceleration of depreciation relating to certain assets.utilities.

Taxes Other Than Income Taxes


Third Quarter 2023 vs. Third Quarter 2022		Year-To-Date 2023 vs. Year-To-Date 2022
(change in millions)	(% change)	(change in millions)	(% change)
$(3)	(6.7)	$(5)	(2.4)

Successor
Third Quarter 2017 vs. Third Quarter 2016
(change in millions) (% change)
$(3) (10.3)

In the third quarter ~~2017,~~2023, taxes other than income taxes ~~were $26~~was $42 million compared to ~~$29~~$45 million for the corresponding period in ~~2016. The decrease primarily reflects establishing a regulatory asset related to Nicor Gas' invested capital tax.~~2022. For ~~additional information, see~~ ~~FUTURE EARNINGS POTENTIAL– "Regulatory Matters – Riders" herein.~~

Successor Predecessor
Year-to-Date 2017 July 1, 2016 through September 30, 2016 January 1, 2016 through June 30, 2016
(in millions) (in millions) (in millions)
Taxes other than income taxes $ 140
$ 29
$ 99

~~Taxes~~year-to-date 2023, taxes other than income taxes ~~in the successor periods reflected increased revenue-based taxes due to higher revenues at gas distribution operations during the successor periods.~~

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~~MANAGEMENT'S DISCUSSION AND ANALYSIS OF~~

~~FINANCIAL CONDITION AND RESULTS OF OPERATIONS~~

~~Earnings from Equity Method Investments~~

Successor
Third Quarter 2017 vs. Third Quarter 2016
(change in millions) (% change)
$3 10.3

~~In the third quarter 2017, earnings from equity method investments were $32~~was $203 million compared to ~~$29~~$208 million for the corresponding period in ~~2016.~~2022. The ~~increase was~~decreases for the third quarter and year-to-date 2023 were primarily due to ~~higher earnings from SNG, PennEast Pipeline,~~decreases of $3 million and ~~Horizon Pipeline.~~

Successor Predecessor
Year-to-Date 2017 July 1, 2016 through September 30, 2016 January 1, 2016 through June 30, 2016
(in millions) (in millions) (in millions)
Earnings from equity method investments $ 100
$ 29
$ 2

~~Earnings from equity method investments~~$15 million, respectively, in ~~the successor~~revenue taxes. The year-to-date ~~2017 consisted~~2023 decrease was largely offset by increases of ~~$86~~$8 million and $2 million in ~~earnings from SNG~~payroll and ~~$14 million in earnings from all other investments.~~

See Notes 4 and 11 to the financial statements of Southern Company Gas under "Equity Method Investments – SNG" and "Investment in SNG," respectively, in Item 8 of the Form 10-K and Note (J) to the Condensed Financial Statements under "~~Southern Company Gas~~ – ~~Equity Method Investments" herein for additional information.~~

~~Other Income (Expense), Net~~

Successor
Third Quarter 2017 vs. Third Quarter 2016
(change in millions) (% change)
$9 100.0

In the third quarter 2017, other income (expense), net was $18 million compared to $9 million for the corresponding period in 2016. The increase was primarily due to a $14 million gain from the settlement of contractor litigation claims.

Successor Predecessor
Year-to-Date 2017 July 1, 2016 through September 30, 2016 January 1, 2016 through June 30, 2016
(in millions) (in millions) (in millions)
Other income (expense), net $ 26
$ 9
$ 5

The successor year-to-date 2017 reflects a $16 million gain from the settlement of contractor litigation claims. The successor period of July 1, 2016 through September 30, 2016 and the predecessor period of January 1, 2016 through June 30, 2016 primarily represent the tax gross-up on contributions in aid of construction and AFUDC.

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~~MANAGEMENT'S DISCUSSION AND ANALYSIS OF~~

~~FINANCIAL CONDITION AND RESULTS OF OPERATIONS~~

property taxes, respectively.

Interest Expense, Net of Amounts Capitalized


Third Quarter 2023 vs. Third Quarter 2022		Year-To-Date 2023 vs. Year-To-Date 2022
(change in millions)	(% change)	(change in millions)	(% change)
$12	18.5	$39	20.9

Successor
Third Quarter 2017 vs. Third Quarter 2016
(change in millions) (% change)
$12 30.8

In the third quarter ~~2017,~~2023, interest expense, net of amounts capitalized was $77 million compared to $65 million for the corresponding period in 2022. For year-to-date 2023, interest expense, net of amounts capitalized was ~~$51~~$226 million compared to ~~$39~~$187 million for the corresponding period in ~~2016.~~2022. The ~~increase was primarily due to additional interest expense on new debt issuances.~~

Successor Predecessor
Year-to-Date 2017 July 1, 2016 through September 30, 2016 January 1, 2016 through June 30, 2016
(in millions) (in millions) (in millions)
Interest expense, net of amounts capitalized $ 145
$ 39
$ 96

The successor year-to-date 2017 and the period of July 1, 2016 through September 30, 2016 reflect additional interest expense on new debt issuances, partially offset by reductions of $29 million and $9 million, respectively, resulting from the fair value adjustment of long-term debt in acquisition accounting.

~~Income Taxes~~



~~Successor~~
~~Third Quarter 2017 vs. Third Quarter 2016~~
~~(change in millions)~~		~~(% change)~~
~~$45~~		~~N/M~~

~~N/M - Not meaningful~~

Inincreases for the third quarter ~~2017, income taxes~~and year-to-date 2023 were ~~$52 million compared to $7 million for the corresponding period in 2016. The increase reflects $23 million of additional deferred income tax expense~~primarily associated with ~~State~~increases of ~~Illinois tax legislation enacted during the third quarter 2017~~approximately $8 million and the allocation of new tax apportionment factors in several states for the inclusion of Southern Company Gas into the consolidated Southern Company state tax filings, as well as higher pre-tax earnings. See FUTURE EARNINGS POTENTIAL herein for additional information.$31 million, respectively,

139

Successor Predecessor
Year-to-Date 2017 July 1, 2016 through September 30, 2016 January 1, 2016 through June 30, 2016
(in millions) (in millions) (in millions)
Income taxes $ 233
$ 7
$ 87

The successor year-to-date 2017 income taxes reflect $23 million of additional deferred income tax expense associated with State of Illinois tax legislation and the allocation of new tax apportionment factors, as well as increased income taxes from higher pre-tax earnings. See FUTURE EARNINGS POTENTIAL herein for additional information.

~~Performance and Non-GAAP Measures~~

Prior to the Merger, Southern Company Gas evaluated segment performance using earnings before interest and taxes (EBIT), which includes operating income, earnings from equity method investments, and other income

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION

AND RESULTS OF OPERATIONS

(Continued)

~~(expense), net. EBIT excludes interest expense, net of amounts capitalized and income taxes (benefit), which were evaluated on a consolidated basis for those periods. EBIT is used herein~~related to discuss the results of Southern Company Gas' segments for the predecessor period, as EBIT was the primary measure of segment profit or loss for that period. Subsequent to the Merger, Southern Company Gas changed its segment performance measure from EBIT to net income to better align with the performance measure utilized by Southern Company. EBIT for the successor third quarters 2017 and 2016 and the successor year-to-date 2017 presented herein is considered a non-GAAP measure. Southern Company Gas also discusses consolidated EBIT, which is considered a non-GAAP measure for all periods presented. The presentation of consolidated EBIT is believed to provide useful supplemental information regarding a consolidated measure of profit or loss. Southern Company Gas further believes that the presentation of segment EBIT for the successor third quarters 2017 and 2016 and the successor year-to-date 2017 is useful as it allows for a measure of comparability to other companies with different capital and legal structures, which accordingly may be subject to differenthigher interest rates and ~~effective tax rates. The applicable reconciliations of net income~~approximately $3 million and $7 million, respectively, related to ~~consolidated EBIT and segment EBIT are provided herein.~~

Adjusted operating margin is a non-GAAP measure that is calculated as operating revenues minus 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, and Merger-related expenses, which are included in the calculation of operating income as calculated in accordance with GAAP and reflected in the consolidated statements of income. The presentation of adjusted operating margin is believed to provide useful information regarding the contribution resulting from 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 marketing services, wholesale gas services, and gas midstream operations allows it to focus on a direct measure of adjusted operating margin before overhead costs. The applicable reconciliation of operating income to adjusted operating margin is provided herein.

EBIT and adjusted operating margin should not be considered alternatives to, or more meaningful indicators of, Southern Company Gas' operating performance than consolidated net income attributable to Southern Company Gas or 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.

Successor Predecessor
Third Quarter 2017 Third Quarter 2016 Year-to-Date 2017 July 1, 2016 through September 30, 2016 January 1, 2016 through
June 30,
2016
(in millions) (in millions)
Operating Income $ 68
$ 12
$ 555
$ 12
$ 321
Other operating expenses^(a)
356
396
1,181
396
815
Revenue taxes^(b)
(8 ) (8 ) (74 ) (8 ) (56 )
Adjusted Operating Margin $ 416
$ 400
$ 1,662
$ 400
$ 1,080


~~(a)~~	~~Includes other operations and maintenance, depreciation and amortization, taxes other than income taxes, and Merger-related expenses.~~


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

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~~MANAGEMENT'S DISCUSSION AND ANALYSIS OF~~

higher outstanding debt. See FINANCIAL CONDITION AND ~~RESULTS OF OPERATIONS~~LIQUIDITY – "Sources of Capital" and "Financing Activities" herein for additional information on borrowings.

Successor Predecessor
Third Quarter 2017 Third Quarter 2016 Year-to-Date 2017 July 1, 2016 through September 30, 2016 January 1, 2016
through
June 30,
2016
(in millions) (in millions)
Consolidated Net Income Attributable
to Southern Company Gas $ 15
$ 4
$ 303
$ 4
$ 131
Net income attributable to
noncontrolling interest ^(*)
—
—
—
14
Income taxes 52
7
233
7
87
Interest expense, net of amounts
capitalized 51
39
145
39
96
EBIT $ 118
$ 50
$ 681
$ 50
$ 328


~~(*)~~	~~See Note 4 to the financial statements of Southern Company Gas under "Variable Interest Entities" in Item 8 of the Form 10-K for additional information.~~

Segment Information

~~Adjusted operating margin,~~Operating revenues, operating expenses, and ~~Southern Company Gas' primary performance metric~~net income for each segment ~~is illustrated~~are provided in the ~~tables~~table below. See Note ~~(K)~~(L) to the Condensed Financial Statements under "Southern Company Gas" herein for additional information.


	2023						2022
	Operating Revenues		Operating Expenses		Net Income (Loss)		Operating Revenues		Operating Expenses		Net Income (Loss)
	(in millions)						(in millions)
Third Quarter
Gas distribution operations	$	619	$	485	$	70	$	751	$	629	$	59
Gas pipeline investments	8		2		24		8		3		24

Gas marketing services	56		53		2		85		87		(2)
All other	8		12		(14)		16		12		2
Intercompany eliminations	(2)		1		—		(3)		—		—
Consolidated	$	689	$	553	$	82	$	857	$	731	$	83

Year-to-Date
Gas distribution operations	$	3,002	$	2,386	$	352	$	3,533	$	2,922	$	365
Gas pipeline investments	24		7		73		24		8		76
Gas marketing services	376		292		59		420		327		65
All other	30		30		(9)		43		48		10
Intercompany eliminations	(15)		(5)		—		(22)		(19)		—
Consolidated	$	3,417	$	2,710	$	475	$	3,998	$	3,286	$	516

Successor
Third Quarter 2017
Third Quarter 2016

Adjusted Operating
Operating
Net Income
Adjusted Operating
Operating
Net Income

Margin^(*)

Expenses^(*)

(Loss)
Margin^(*)

Expenses^(*)

(Loss)

(in millions)
(in millions)
Gas distribution operations $ 379

$ 271

$ 52

$ 353

$ 284

$ 27
Gas marketing services 51

48

1

45

51

(4 )
Wholesale gas services (25 )
11

(23 )
(8 )
10

(11 )
Gas midstream operations 12

13

14

9

13

14
All other 2

8

(29 )
2

31

(22 )
Intercompany eliminations (3 )
(3 )
—

(1 )
(1 )
—
Consolidated $ 416

$ 348

$ 15

$ 400

$ 388

$ 4


~~(*)~~	~~Operating margin and operating expenses are adjusted for Nicor Gas' revenue tax expenses, which are passed through directly to customers.~~

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~~FINANCIAL CONDITION AND RESULTS OF OPERATIONS~~

Successor Predecessor
Year-to-Date 2017 July 1, 2016 through
September 30, 2016 January 1, 2016 through
June 30, 2016
Adjusted Operating Operating Net Income Adjusted Operating Operating Net Income Adjusted Operating Operating

Margin^(*)

Expenses^(*)
(Loss)
Margin^(*)

Expenses^(*)
(Loss)
Margin^(*)

Expenses^(*)
EBIT
(in millions) (in millions)
Gas distribution
operations $ 1,329
$ 866
$ 223
$ 353
$ 284
$ 27
$ 911
$ 560
$ 353
Gas marketing
services 213
149
36
45
51
(4 ) 190
81
109
Wholesale gas
services 93
40
28
(8 ) 10
(11 ) (36 ) 33
(68 )
Gas midstream
operations 28
38
38
9
13
14
15
24
(6 )
All other 7
22
(22 ) 2
31
(22 ) 4
65
(60 )
Intercompany
eliminations (8 ) (8 ) —
(1 ) (1 ) —
(4 ) (4 ) —
Consolidated $ 1,662
$ 1,107
$ 303
$ 400
$ 388
$ 4
$ 1,080
$ 759
$ 328


~~(*)~~	~~Operating margin and operating expenses are adjusted for Nicor Gas' revenue tax expenses, which are passed through directly to customers.~~

Gas Distribution Operations

Gas distribution operations is the largest component of Southern Company Gas' business and is subject to regulation and oversight by regulatory 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~~regulatory and other mechanisms, such as weather and revenue normalization mechanisms and weather derivative instruments, that limit its exposure to changes in customer consumption, including weather changes within typical ranges in its natural gas distribution utilities' service territories.

~~Successor Third Quarter 2017 vs. Third Quarter 2016~~ See Note 2 to the financial statements under "Southern Company Gas" in Item 8 of the Form 10-K for additional information.

In the third quarter ~~2017,~~2023, net income ~~was $52~~increased $11 million, or 18.6%, when compared to ~~$27 million for~~ the corresponding period in ~~2016. The increase in net income relates~~2022, as described further below:

•Operating revenues decreased $132 million primarily due to ~~an increase of $26 million in adjusted operating margin, a decrease of $13 million in operating expenses,~~lower gas cost recovery, partially offset by rate increases and an increase of $11 million in other income (expense), net. The change in net income also includes an increase of $7 million in interest expense, net of amounts capitalized, and an increase of $18 million in income tax expense. The increase in adjusted operating margin primarily reflects $24 million in additional revenue from the continued investment in infrastructure ~~replacement programs and base rate increases, primarily at Atlanta~~replacement. Gas ~~Light effective March 1, 2017. The decrease~~costs recovered through natural gas revenues generally equal the amount expensed in ~~operating expenses primarily reflects $18 million in rate credits provided to customers~~cost of Elizabethtown Gas in 2016 as a condition of the Merger, partially offset by $7 million in additional depreciation due to continued investment in infrastructure programs. The increase in other income (expense), net primarily reflects a $14 million gain from the settlement of contractor litigation claims in 2017. The increase in interest expense includes the impact of intercompany promissory notes executed in December 2016 and the issuance of first mortgage bonds at Nicor Gas on August 10, 2017. The increase in income tax expense relates primarily to higher pre-tax earnings.

~~Successor Year-to-Date 2017~~

Net income of $223 million includes $1.3 billion in adjusted operating margin, $866 million in operating expenses, and $23 million in other income (expense), net, which resulted in EBIT of $486 million. Net income also includes

natural gas.

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION

AND RESULTS OF OPERATIONS

(Continued)

•Operating expenses decreased $144 million primarily due to a $152 million decrease in cost of natural gas as a result of lower gas prices compared to 2022, partially offset by higher depreciation resulting from additional assets placed in service and an increase related to energy service contracts. The decrease in operating expenses also includes costs passed through directly to customers, primarily related to bad debt expenses, energy efficiency programs, and revenue taxes.

~~$119 million in interest~~•Interest expense, net of amounts capitalized increased $7 million primarily due to higher interest rates and ~~$144~~higher average outstanding debt.

For year-to-date 2023, net income decreased $13 million, or 3.6%, when compared to the corresponding period in ~~income tax expense. Adjusted operating margin reflects $69~~2022, as described further below:

•Operating revenues decreased $531 million ~~in additional revenue from~~primarily due to lower gas cost recovery, partially offset by rate increases and continued investment in infrastructure ~~replacement programs~~replacement. Gas costs recovered through natural gas revenues generally equal the amount expensed in cost of natural gas.

•Operating expenses decreased $536 million primarily due to a $599 million decrease in cost of natural gas as a result of lower gas prices and ~~base rate increases, primarily at Atlanta Gas Light effective March 1, 2017. Also included in adjusted operating margin was increased customer growth,~~lower volumes sold compared to 2022, partially offset by ~~a $6 million negative impact of warmer-than-normal weather, net of hedging. Operating expenses reflect a $21 million increase in~~higher depreciation ~~associated with~~resulting from additional assets placed in service, ~~as well as increased~~higher compensation ~~expense, legal expenses,~~ and ~~pipeline compliance and maintenance activities. Other income (expense), net reflects a $16~~benefits, $30 million ~~gain from~~related to the ~~settlement of contractor litigation claims. Interest expense reflects the impact of intercompany promissory notes executed in December 2016 and the issuance of first mortgage bonds~~regulatory disallowance at Nicor Gas, ~~on August 10, 2017.~~

~~Successor Period of July 1, 2016 through September 30, 2016~~

~~Net income of $27~~and a $20 million ~~includes $353 million in adjusted operating margin, $284 million~~increase related to energy service contracts. The decrease in operating expenses ~~including $18 million in rate credits provided~~also includes costs passed through directly to customers, primarily related to bad debt expenses, energy efficiency programs, and ~~$6 million in other income (expense),~~revenue taxes.

•Interest expense, net ~~which resulted in EBIT~~ of ~~$75 million. Net income also includes~~amounts capitalized increased $32 million primarily due to higher interest rates and higher average outstanding debt.

•Income taxes decreased $13 million primarily as a result of the tax benefit resulting from the regulatory disallowance at Nicor Gas.

See Note (B) to the Condensed Financial Statements under "Southern Company Gas – Infrastructure Replacement Programs and Capital Projects" herein for additional information.

Gas Pipeline Investments

Gas pipeline investments consists primarily of joint ventures in ~~interest expense~~natural gas pipeline investments including SNG and ~~$16 million in income tax expense.~~

~~Predecessor Period of January 1, 2016 through June 30, 2016~~

EBIT of $353 million includes $911 million in adjusted operating margin, $560 million in operating expenses, and $2 million in other income (expense), net. Adjusted operating margin reflects revenue from continued investment in infrastructure replacement programs and increased usage and customer growth, partially offset by a $7 million negative impact of warmer-than-normal weather, net of hedging. Operating expenses reflect depreciation associated withDalton Pipeline. See Note (E) to the Condensed Financial Statements under "Southern Company Gas" herein for additional ~~assets placed in service.~~information.

Gas Marketing Services

Gas marketing services ~~consists of several businesses that provide~~provides energy-related products and services to natural gas markets ~~including warranty sales.~~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. ~~Operating expenses primarily reflect employee costs, marketing, and bad debt expenses.~~

~~Successor Third Quarter 2017 vs. Third Quarter 2016~~

In the third quarter ~~2017,~~2023, net income ~~was $1 million compared to a net loss of~~increased $4 million, ~~for~~when compared to the corresponding period in ~~2016. The increase in net income~~2022 primarily ~~relates~~due to a $6$39 million ~~increase~~decrease in ~~adjusted operating margin and~~cost of gas, largely offset by a $3$29 million decrease in operating ~~expenses. The change in net income also includes increases of $1 million and $3 million in interest expense and income tax expense, respectively. Adjusted operating margin~~revenue primarily reflects a $3 million decrease in unrealized hedge losses, net of recoveries, and a $4 million increase from the elimination of deferred revenue in the third quarter 2016 from the application of acquisition accounting. Operating expenses reflect decreased amortization of intangible assets established in the application of acquisition accounting.

~~Successor Year-to-Date 2017~~

Net income of $36 million includes $213 million in adjusted operating margin and $149 million in operating expenses, which resulted in EBIT of $64 million. Net income also includes $4 million in interest expense and $24 million in income tax expense. Adjusted operating margin reflects a $10 million negative impact of warmer-than-normal weather, net of hedging, and $7 million in unrealized hedge losses, net of recoveries. Operating expenses include $30 million in additional amortization of intangible assets established in the application of acquisition accounting.

~~Successor Period of July 1, 2016 through September 30, 2016~~

Net loss of $4 million includes $45 million in adjusted operating margin and $51 million in operating expenses, which resulted in a loss before interest and taxes of $6 million. Also included in net loss is $2 million in income tax benefit.

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~~FINANCIAL CONDITION AND RESULTS OF OPERATIONS~~

~~Predecessor Period of January 1, 2016 through June 30, 2016~~

EBIT of $109 million includes $190 million in adjusted operating margin and $81 million in operating expenses. Adjusted operating margin reflects $9 million in unrealized hedge gains. Earnings in the predecessor period include $14 million attributable to noncontrolling interest.

~~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.

~~Successor Third Quarter 2017 vs. Third Quarter 2016~~

In the third quarter 2017, net loss was $23 million compared to a net loss of $11 million for the corresponding period in 2016. The increase in net loss relates primarily to a $17 million decrease in adjusted operating margin, partially offset by an increase of $8 million in income tax benefit due to ~~higher losses. The decrease in adjusted gross margin includes $22 million in additional mark-to-market losses~~lower price spreads and ~~a $7 million decrease in gains from commercial activity, partially offset by a $12 million positive impact from the amortization of liabilities recorded in the application of acquisition accounting.~~

~~Successor Year-to-Date 2017~~

Net income of $28 million includes $93 million in adjusted operating margin and $40 million in operating expenses, which resulted in EBIT of $53 million. Net income also includes $5 million in interest expense and $20 million in income tax expense.

~~Successor Period of July 1, 2016 through September 30, 2016~~

Net loss of $11 million includes $(8) million in adjusted operating margin and $10 million in operating expenses, which resulted in a loss before interest and taxes of $17 million. Also included in net loss is $1 million in interest expense and $7 million in income tax benefit.

~~Predecessor Period of January 1, 2016 through June 30, 2016~~

~~Loss before interest and taxes of $68 million includes $(36) million in adjusted operating margin, $33 million in operating expenses, and $1 million in other income (expense), net.~~

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~~The following table illustrates the components of wholesale~~lower gas ~~services' adjusted operating margin for the periods presented.~~

Successor Predecessor
Third Quarter 2017 Third Quarter 2016 Year-to-Date 2017 July 1, 2016 through September 30, 2016 January 1, 2016
through
June 30,
2016
(in millions) (in millions)
Commercial activity recognized $ 3
$ 10
$ 80
10
$ 34
Gain (loss) on storage derivatives 4
11
13
11
(38 )
Gain (loss) on transportation and forward
commodity derivatives (22 ) (7 ) 14
(7 ) (31 )
LOCOM adjustments, net of current period
recoveries —
—
—
—
(1 )
Purchase accounting adjustments (10 ) (22 ) (14 ) (22 ) —
Adjusted Operating Margin $ (25 ) $ (8 ) $ 93
$ (8 ) $ (36 )

~~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. Warmer-than-normal weather during the 2016/2017 Heating Season, lower power generation volumes, and build-out of new U.S. pipeline infrastructure, along with increases in natural gas supply, caused low volatility and a tightening of locational or transportation spreads in 2017, negatively impacting the amount of commercial activity revenues generated relative to demand fees for contracted pipeline transportation and storage capacity, and minimum sharing under asset management agreements. However, as natural gas prices and forward storage or time spreads increased, wholesale gas services was able to capture higher storage values that it expects to recognize as commercial activity revenues when natural gas is physically withdrawn from storage. Southern Company Gas anticipates continued low volatility in certain areas of wholesale gas services' portfolio.

~~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. In 2017 and 2016, there was little price volatility; however, the potential exists for market fundamentals indicating some level of increased volatility that would benefit Southern Company Gas' portfolio of pipeline transportation capacity. Additionally, during the first nine months of 2017, forward storage or time spreads applicable to the locations of wholesale gas services' specific storage positions resulted in storage derivative gains. Transportation and forward commodity derivative gains are primarily the result of narrowing transportation basis spreads due to some reduction in supply constraints resulting from new U.S. pipeline infrastructure and increases in natural gas supply and warmer-than-normal weather, which impacted forward prices at natural gas receipt and delivery points, primarily in the Northeast and Midwest regions.

~~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

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~~FINANCIAL CONDITION AND RESULTS OF OPERATIONS~~

charges, but are net of the estimated impact of profit sharing under its 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 September 30, 2017. 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.

Storage withdrawal schedule

Total storage
(WACOG $2.67)

Expected net operating gains^(a)

Physical transportation transactions – expected net operating gains (losses)^(b)
(in mmBtu in millions) (in millions) (in millions)
2017 22.0
$ 4
$ (13 )
2018 and thereafter 40.0
17
28
Total at September 30, 2017 62.0
$ 21
$ 15


~~(a)~~	Represents expected operating gains 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.


~~(b)~~	Represents the periods associated with the transportation derivative gains during which the derivatives will be settled and the physical transportation transactions will occur that offset the derivative gains and losses that were previously recognized.

The unrealized storage and transportation derivative gains do not change the underlying economic value of wholesale gas services' storage and transportation positions and will be reversed when the related transactions occur and are recognized. For more information on wholesale gas services' energy marketing and risk management activities, see MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Market Price Risk" of Southern Company Gas in Item 7 of the Form 10-K.

~~Gas Midstream Operations~~

Gas midstream operations consists primarily of gas pipeline investments, with storage and fuels also aggregated into this segment. Gas pipeline investments include SNG, Horizon Pipeline, Atlantic Coast Pipeline, PennEast Pipeline, Dalton Pipeline, and Magnolia Enterprise Holdings, Inc. See Note (J) to the Condensed Financial Statements herein and Notes 4 and 11 to the financial statements of Southern Company Gas under "Equity Method Investments – SNG" and "Investment in SNG," respectively, in Item 8 of the Form 10-K for additional information.

~~Successor Third Quarter 2017 vs. Third Quarter 2016~~

~~In both the third quarter 2017 and the corresponding period in 2016 net income was $14 million. Net income reflects a $3 million increase in adjusted operating margin~~ and a $4 million increase in ~~earnings from equity method investments at SNG, PennEast Pipeline,~~operations and ~~Horizon Pipeline. The change in~~maintenance expenses primarily related to customer service and information.

For year-to-date 2023, net income ~~also includes~~decreased $6 million, or 9.2%, when compared to the corresponding period in 2022 primarily due to a $44 million decrease in operating revenue, primarily due to lower price spreads, lower gas prices, and lower volumes sold, as well as a $9 million increase in ~~interest expense, net of amounts capitalized~~operations and maintenance expenses, largely offset by a $2$44 million decrease in ~~income taxes. The increase in interest expense includes the impact~~cost of ~~intercompany promissory notes executed in December 2016.~~

~~Successor Year-to-Date 2017~~

Net income of $38 million includes $28 million in adjusted operating margin, $38 million in operating expenses, $97 million in earnings from equity method investments, consisting primarily of earnings from equity method investments at SNG, and $3 million in other income (expense), net, which resulted in EBIT of $90 million. Also included in net income are $25 million in interest expense and $27 million in income tax expense.

~~Successor Period of July 1, 2016 through September 30, 2016~~

Net income of $14 million includes $9 million in adjusted operating margin, $13 million in operating expenses, $28 million in earnings from equity method investments, consisting primarily of earnings from equity method

gas.

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FINANCIAL CONDITION

AND RESULTS OF OPERATIONS (Continued)

~~investments at SNG, and $1 million in other income (expense), net, which resulted in EBIT of $25 million. Also included in net income is $11 million in income tax expense.~~

~~Predecessor Period of January 1, 2016 through June 30, 2016~~

~~Loss before interest and taxes of $6 million includes $15 million in adjusted operating margin, $24 million in operating expenses, and $3 million of other income (expense), net.~~

All Other

All other includes ~~Southern Company Gas' investment in Triton,~~natural gas storage businesses, a renewable natural gas business, 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.

~~Successor Third Quarter 2017 vs. Third Quarter 2016~~

~~In the third quarter 2017, net loss was $29 million compared to $22 million~~ All other included a natural gas storage facility in ~~the corresponding period~~Texas through its sale in ~~2016. The increase in net loss reflects a $23 million decrease in operating expenses~~November 2022 and a ~~decrease~~natural gas storage facility in California through its sale in September 2023. See Note 15 to the financial statements in Item 8 of ~~$2 million in other income (expense), net. Net loss also reflected a $6 million increase in interest expense, net of amounts capitalized~~the Form 10-K and an increase of $34 million in income taxes. The decrease in operating expenses reflects a $35 million decrease in Merger-related expenses, partially offset by a $10 million increase in other operations and maintenance expenses and a $3 million increase from the acceleration of depreciation relating to certain assets. Interest expense decreased as a result of intercompany promissory notes executed in December 2016. The increase in income taxes primarily reflects additional deferred income tax expenses associated with State of Illinois tax legislation enacted during the third quarter 2017, as well as the allocation of new tax apportionment factors in several states for the inclusion of Southern Company Gas into the consolidated Southern Company state tax filings.

~~Successor Year-to-Date 2017, Successor Period of July 1, 2016 through September 30, 2016, and Predecessor Period of January 1, 2016 through June 30, 2016~~

For the successor period of July 1, 2016 through September 30, 2016 and the predecessor period of January 1, 2016 through June 30, 2016, Merger-related expenses were $35 million and $56 million, respectively. There were no Merger-related expenses during the successor year-to-date 2017. In the successor year-to-date 2017, depreciation and amortization includes $7 million from the acceleration of depreciation relating to certain assets. Interest expense, net of amounts capitalized was $8 million, $6 million, and $34 million, respectively, in the successor year-to-date 2017, the successor period of July 1, 2016 through September 30, 2016, and the predecessor period of January 1, 2016 through June 30, 2016. Income taxes were $18 million in the successor year-to-date 2017 and income tax benefit was $11 million and $35 million, respectively, in the successor period of July 1, 2016 through September 30, 2016 and the predecessor period of January 1, 2016 through June 30, 2016. In the successor year-to-date 2017, income taxes reflect $23 million of additional deferred income tax expense associated with State of Illinois tax legislation enacted during the third quarter 2017 and the allocation of new tax apportionment factors in several states for the inclusion of Southern Company Gas into the consolidated Southern Company state tax filings.

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~~FINANCIAL CONDITION AND RESULTS OF OPERATIONS~~

~~Segment Reconciliations~~

Reconciliations of consolidated net income attributable to Southern Company Gas to EBIT for the successor third quarter and year-to-date 2017, and operating income to adjusted operating margin for all periods presented, are in the following tables. See Note (K) to the Condensed Financial Statements herein under "Southern Company Gas" for additional information.

In the third quarter 2023, net income decreased $16 million when compared to the corresponding period in 2022, primarily due to a decrease in operating revenue and increases in operating expenses, interest expenses, and income taxes.

For year-to-date 2023, net income decreased $19 million when compared to the corresponding period in 2022. The decrease was primarily related to a decrease in operating revenue and increases in interest expenses and income taxes, partially offset by a decrease in operating expenses primarily related to lower depreciation in 2023, lower cost of gas, and lower taxes other than income taxes.

Successor

Third Quarter 2017

Gas Distribution Operations Gas Marketing Services Wholesale Gas Services Gas Midstream Operations All Other Intercompany Elimination Consolidated

(in millions)
Consolidated Net Income
(Loss) $ 52
$ 1
$ (23 ) $ 14
$ (29 ) $ —
$ 15
Income taxes (benefit) 34
1
(15 ) 9
23
—
52
Interest expense, net of
amounts capitalized 39
1
2
9
—
—
51
EBIT $ 125
$ 3
$ (36 ) $ 32
$ (6 ) $ —
$ 118

Successor
Third Quarter 2016
Gas Distribution Operations Gas Marketing Services Wholesale Gas Services Gas Midstream Operations All Other Intercompany Elimination Consolidated
(in millions)
Consolidated Net Income
(Loss) $ 27
$ (4 ) $ (11 ) $ 14
$ (22 ) $ —
$ 4
Income taxes (benefit) 16
(2 ) (7 ) 11
(11 ) —
7
Interest expense, net of
amounts capitalized 32
—
1
—
6
—
39
EBIT $ 75
$ (6 ) $ (17 ) $ 25
$ (27 ) $ —
$ 50

Successor
Year-to-Date 2017
Gas Distribution Operations Gas Marketing Services Wholesale Gas Services Gas Midstream Operations All Other Intercompany Elimination Consolidated
(in millions)
Consolidated Net Income
(Loss) $ 223
$ 36
$ 28
$ 38
$ (22 ) $ —
$ 303
Income taxes 144
24
20
27
18
—
233
Interest expense, net of
amounts capitalized 119
4
5
25
(8 ) —
145
EBIT $ 486
$ 64
$ 53
$ 90
$ (12 ) $ —
$ 681

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~~FINANCIAL CONDITION AND RESULTS OF OPERATIONS~~

Successor

Third Quarter 2017

Gas Distribution Operations Gas Marketing Services Wholesale Gas Services Gas Midstream Operations All Other Intercompany Elimination Consolidated

(in millions)
Operating Income (Loss) $ 108
$ 3
$ (36 ) $ (1 ) $ (6 ) $ —
$ 68
Other operating expenses^(a)
279
48
11
13
8
(3 ) 356
Revenue tax expense^(b)
(8 ) —
—
—
—
—
(8 )
Adjusted Operating
Margin $ 379
$ 51
$ (25 ) $ 12
$ 2
$ (3 ) $ 416

Successor
Third Quarter 2016
Gas Distribution Operations Gas Marketing Services Wholesale Gas Services Gas Midstream Operations All Other Intercompany Elimination Consolidated
(in millions)
Operating Income (Loss) $ 69
$ (6 ) $ (18 ) $ (4 ) $ (29 ) $ —
$ 12
Other operating expenses^(a)
292
51
10
13
31
(1 ) 396
Revenue tax expense^(b)
(8 ) —
—
—
—
—
(8 )
Adjusted Operating
Margin $ 353
$ 45
$ (8 ) $ 9
$ 2
$ (1 ) $ 400

Successor
Year-to-Date 2017
Gas Distribution Operations Gas Marketing Services Wholesale Gas Services Gas Midstream Operations All Other Intercompany Elimination Consolidated
(in millions)
Operating Income (Loss) $ 463
$ 64
$ 53
$ (10 ) $ (15 ) $ —
$ 555
Other operating expenses^(a)
940
149
40
38
22
(8 ) 1,181
Revenue tax expense^(b)
(74 ) —
—
—
—
—
(74 )
Adjusted Operating
Margin $ 1,329
$ 213
$ 93
$ 28
$ 7
$ (8 ) $ 1,662

Predecessor
January 1, 2016 through June 30, 2016
Gas Distribution Operations Gas Marketing Services Wholesale Gas Services Gas Midstream Operations All Other Intercompany Elimination Consolidated
(in millions)
Operating Income (Loss) $ 351
$ 109
$ (69 ) $ (9 ) $ (61 ) $ —
$ 321
Other operating expenses^(a)
616
81
33
24
65
(4 ) 815
Revenue tax expense^(b)
(56 ) —
—
—
—
—
(56 )
Adjusted Operating Margin $ 911
$ 190
$ (36 ) $ 15
$ 4
$ (4 ) $ 1,080


~~(a)~~	~~Includes other operations and maintenance, depreciation and amortization, taxes other than income taxes, and Merger-related expenses.~~


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

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FUTURE EARNINGS POTENTIAL

~~The~~Each Registrant's results of operations ~~discussed above~~ are not necessarily indicative of ~~Southern Company Gas'~~its future earnings potential. The level of ~~Southern Company Gas'~~the Registrants' future earnings depends on numerous factors that affect the opportunities, challenges, and risks of ~~its~~the Registrants' primary ~~business~~businesses of selling electricity and/or distributing natural gas, ~~distribution and complementary businesses in~~as described further herein.

For the ~~gas marketing services, wholesale gas services, and gas midstream operations sectors. These~~traditional electric operating companies, these factors include ~~Southern Company Gas'~~the ability to maintain a constructive regulatory ~~environment~~environments that ~~allows~~allow for the timely recovery of prudently-incurred costs during a time of increasing costs, including those related to projected long-term demand growth, stringent environmental standards, including CCR rules, safety, system reliability and resiliency, fuel, restoration following major storms, and capital expenditures, including constructing new electric generating plants and expanding and improving the transmission and distribution systems; continued customer growth; and the trends of higher inflation and reduced electricity usage per customer, especially in residential and commercial markets. For Georgia Power, other major factors are completing construction and start-up of Plant Vogtle Unit 4, meeting the related cost and schedule projections, and completing the related cost recovery proceedings for Plant Vogtle Units 3 and 4.

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 and increasing volumes of electronic commerce transactions, which could contribute to a net reduction in customer usage.

Global and U.S. economic conditions continue to be significantly affected by a series of demand and supply shocks that caused a global and national economic recession in 2020 and have been further impacted by the invasion of Ukraine and significant declines in labor force participation rates. The confluence of these disruptions has resulted in the highest levels of inflation globally in 40 years and driven a significant policy response by central banks across the global economy. The U.S. Federal Reserve has increased interest rates faster than any rate increase cycle in the last 40 years and to levels high enough to slow economic activity and reduce inflation rates, although target inflation levels have not yet been achieved. These actions and impacts, including increased costs for goods and services and borrowing costs, have led to a slowing of some economic activity and an increased risk of recession. Additionally, inflation remains elevated in part due to continued supply chain and labor market constraints. Electricity sales across all classes have recovered to pre-COVID-19 pandemic levels and customer growth at both the traditional electric operating companies and natural gas distribution utilities has remained strong. However, weakening economic activity increases the risk of slowing to declining energy sales. Additionally, the current economic environment has increased the uncertainty of future energy demand and operating costs. See RESULTS OF OPERATIONS herein for information on energy sales in the Southern Company system's service territory during the first nine months of 2023.

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AND RESULTS OF OPERATIONS (Continued)

The level of future earnings for Southern Power's competitive wholesale electric business depends on numerous factors including the parameters of the wholesale market and the efficient operation of its wholesale generating assets; Southern Power's ability to execute its growth strategy through the development, construction, or acquisition of renewable facilities and other energy projects while containing costs; regulatory matters; customer creditworthiness; total electric generating capacity available in Southern Power's market areas; Southern Power's ability to successfully remarket capacity as current contracts expire; renewable portfolio standards; continued availability of federal and state ITCs and PTCs, which could be impacted by future tax legislation; transmission constraints; cost of generation from units within the Southern Company power pool; and operational limitations. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Income Tax Matters" in Item 7 of the Form 10-K for information regarding the Inflation Reduction Act's expansion of the availability of federal ITCs and PTCs and Note (K) to the Condensed Financial Statements under "Southern Power" herein for information regarding acquisitions.

The level of future earnings for Southern Company Gas' primary business of distributing natural gas and its complementary businesses in the gas pipeline investments 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, including those related to projected long-term demand growth, safety, system reliability and resiliency, natural gas, and capital expenditures, including expanding and improving the natural gas distribution systems; the completion and subsequent operation of ongoing infrastructure and other construction ~~projects, creditworthiness of customers, Southern Company Gas' ability~~projects; customer creditworthiness; and certain policies to optimize its transportation and storage positions, and its ability to re-contract storage rates at favorable prices. Future earnings in the near term will depend, in part, upon maintaining and growing sales and customers which are subject to a number of factors. These factors include weather, competition, new energy contracts with other utilities, energy conservation practiced by customers,limit the use of ~~alternative energy sources by customers,~~natural gas, such as the ~~price~~potential across certain parts of the U.S. for state or municipal bans on the use of natural gas ~~the price elasticity of demand, and the rate of economic growth~~ or decline in Southern Company Gas' service territories. Demand for natural gas is primarily driven by the pace of economic growth that may be affected by changes in regional and global economic conditions, which may impact future earnings.

~~Current proposals related~~policies designed to ~~potential federal tax reform legislation are primarily focused on reducing the corporate income tax rate, allowing 100% of capital expenditures to be deducted, and eliminating the interest deduction.~~promote electrification. The ultimate impact of any tax reform proposals is dependent on the final form of any legislation enacted and the related transition rules and cannot be determined at this time, but could have a material impact on Southern Company Gas' financial statements.

On July 6, 2017, the State of Illinois enacted tax legislation that repealed its non-combination tax rule and increased the effective corporate income tax rate from 5.25% to 7.0% (making the total corporate tax rate 9.5% when combined with the 2.5% personal property replacement tax) effective July 1, 2017. In addition to increasing taxes on future earnings, this legislation required Southern Company Gas to increase accumulated deferred income tax liabilities by $24 million during the third quarter 2017 to reflect these changes, $15 million of which was expensed and $9 million was recorded as a regulatory asset. In addition, during the third quarter 2017, Southern Company calculated new apportionment factors in several states to include Southern Company Gas in its consolidated tax filings, which resulted in $8 million of additional deferred income tax expenses.

On October 15, 2017, Southern Company Gas subsidiary, Pivotal Utility Holdings, entered into agreements for the sale of the assets of two of its natural gas distribution utilities, Elizabethtown Gas and Elkton Gas, to South Jersey Industries, Inc. The execution of the asset purchase agreements triggered an interim assessment of goodwill, which is currently being performed with the assistance of a third-party valuation specialist. The preliminary results of this valuation indicate that the estimated fair values of the reporting units with goodwill exceed their carrying amounts and are not at risk of impairment. See OVERVIEW – ~~"Merger, Acquisition, and Disposition Activities" and Note (I) to the Condensed Financial Statements under "Southern Company Gas" herein for additional information on the sales.~~

~~Volatility~~volatility of natural gas prices has ~~a significant~~an impact on Southern Company Gas' customer rates, its long-term competitive position against other energy sources, and the ability of ~~its~~Southern Company Gas' gas marketing services ~~and wholesale gas services segments~~business to capture value from locational and seasonal spreads. Additionally, changes in commodity prices, primarily driven by tight gas supplies, geopolitical events, and diminished gas production, subject a ~~significant~~ portion of Southern Company Gas' operations to earnings ~~variability. Over the longer-term, volatility is expected to be low to moderate~~variability and ~~locational and/or transportation spreads are expected to decrease as new pipelines are built to reduce the existing supply constraints~~may result in ~~the shale areas of the Northeast U.S. To the extent these pipelines are delayed or not built, volatility could increase.~~higher natural gas prices. 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, including the new housing market, theenvironment. 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. Alternatively, a significant drop in oil and natural gas prices could lead to a consolidation of natural gas producers or reduced levels of natural gas production.

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; customer energy conservation practices; the use of alternative energy sources by customers; government incentives to reduce overall energy usage; fuel, labor, and material prices in an environment of heightened inflation and material and labor supply chain disruptions; 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.

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~~SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES~~

~~MANAGEMENT'S DISCUSSION AND ANALYSIS OF~~

~~FINANCIAL CONDITION AND RESULTS OF OPERATIONS~~

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, or the sale of interests in, 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 Note 15 to the financial statements in Item 8 of the Form 10-K and Note (K) to the Condensed Financial Statements herein for additional information.

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

~~Environmental Matters~~

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~~Compliance costs related~~

Table of ContentsIndex to federal and state environmental statutes and regulations could affect earnings if such costs cannot continue to be fully recovered in rates on a timely basis or through market-based contracts. Environmental compliance spending over the next several years may differ materially from the amounts estimated. The timing, specific requirements, and estimated costs could change as environmental statutes and regulations are adopted or modified, as compliance plans are revised or updated, and as legal challenges to rules are completed. Further, higher costs that are recovered through regulated rates could contribute to reduced demand for natural gas, which could negatively affect results of operations, cash flows, and financial condition. See Note (B) under "Environmental Matters –~~Environmental Remediation" to the Condensed~~ Financial Statements ~~herein and~~

MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION

AND RESULTS OF OPERATIONS (Continued)

Environmental Matters

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters" ~~of Southern Company Gas~~ in Item 7 and Note 3 to the financial statements ~~of Southern Company Gas~~ under "Environmental ~~Matters"~~Remediation" in Item 8 of the Form 10-K, as well as Note (C) to the Condensed Financial Statements under "General Litigation Matters" and "Environmental Remediation" herein, for additional information.

~~Natural Gas Storage~~Environmental Laws and Regulations

~~A wholly-owned subsidiary~~Air Quality

On February 13, 2023, the EPA published a final rule disapproving 19 state implementation plans (SIPs), including the States of ~~Southern Company Gas owns~~Alabama and ~~operates a natural gas storage facility consisting of two salt dome caverns in Louisiana. Periodic integrity tests are required in accordance with rules~~Mississippi, under the interstate transport (good neighbor) provisions of the ~~Louisiana~~Clean Air Act for the 2015 Ozone National Ambient Air Quality Standards (NAAQS). On March 14, 2023 and March 15, 2023, the State of Mississippi and Mississippi Power, respectively, challenged the EPA's disapproval of the Mississippi SIP in the U.S. Court of Appeals for the Fifth Circuit. On May 11, 2023, the State of Mississippi and Mississippi Power filed a joint motion for stay of the EPA's disapproval of the Mississippi SIP, which was granted on June 8, 2023. On April 13, 2023 and April 14, 2023, the State of Alabama, Alabama Power, and PowerSouth Energy Cooperative challenged the EPA's disapproval of the Alabama SIP in the U.S. Court of Appeals for the Eleventh Circuit. On June 13, 2023, the State of Alabama, Alabama Power, and PowerSouth Energy Cooperative filed a joint motion for stay of the EPA's disapproval of the Alabama SIP, which was granted on August 17, 2023.

On June 5, 2023, the EPA published the 2015 Ozone NAAQS Good Neighbor federal implementation plans (FIP), which became effective on August 4, 2023. On June 16, 2023 and June 27, 2023, the State of Mississippi and Mississippi Power, respectively, challenged the FIP for Mississippi in the U.S. Court of Appeals for the Fifth Circuit. On June 30, 2023, the State of Mississippi and Mississippi Power filed in the U.S. Court of Appeals for the Fifth Circuit a joint motion for stay of the FIP for Mississippi and a request to hold the case in abeyance pending resolution of the Mississippi SIP disapproval case. On July 20, 2023, the U.S. Court of Appeals for the Fifth Circuit denied the motion for stay but granted the motion to hold the case in abeyance. On August 4, 2023, the State of Alabama, Alabama Power, and PowerSouth Energy Cooperative challenged the FIP for Alabama in the U.S. Court of Appeals for the Eleventh Circuit. On August 16, 2023, the State of Alabama, Alabama Power, and PowerSouth Energy Cooperative filed in the U.S. Court of Appeals for the Eleventh Circuit a joint motion requesting an abeyance of the case pending resolution of the Alabama SIP disapproval case, which was granted on August 30, 2023.

On July 31, 2023, the EPA published an Interim Final Rule that stays the implementation of the FIPs for states with judicially stayed SIP disapprovals, including Mississippi. On September 29, 2023, the EPA published an updated Interim Final Rule addressing judicial stays of states' interstate transport SIP disapprovals, including Alabama. The Interim Final Rule revises the existing regulations to maintain currently applicable trading programs for those states.

The ultimate impact of the rule and associated legal matters cannot be determined at this time; however, implementation of the FIPs will likely result in increased compliance costs for the traditional electric operating companies.

Water Quality

On March 29, 2023, the EPA published a proposed ELG Supplemental Rule revising certain effluent limits of the 2020 and 2015 ELG rules. The proposal imposes more stringent requirements for flue gas desulfurization wastewater, bottom ash transport water, and combustion residual leachate to be met no later than December 31, 2029. The EPA is also proposing that a limited number of facilities already achieving compliance with the 2020 ELG Reconsideration Rule be allowed to elect retirement or repowering by December 31, 2032 as opposed to meeting the new more stringent requirements. The proposal maintains the 2020 ELG Reconsideration Rule's permanent cessation of coal combustion subcategory allowing units to continue to operate until the end of 2028 without having to install additional technologies. A final rule is anticipated in 2024. The ultimate impact of this proposal cannot be determined at this time; however, it may result in significant compliance costs.

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AND RESULTS OF OPERATIONS (Continued)

In 2021, Alabama Power submitted its notice of planned participation (NOPP) to the Alabama Department of ~~Natural Resources (LDNR). In August 2017,~~Environmental Management (ADEM), which included plans to retire Plant Barry Unit 5. Alabama Power subsequently indicated that it expected to retire Plant Barry Unit 5 in ~~connection with an ongoing integrity project, updated seismic mapping indicated the proximity of one of the caverns~~late 2023 or early 2024 subject to certain operating conditions. Alabama Power has continued to evaluate operating conditions relevant to the edge of the salt dome may be less than the required minimum and could result in Southern Company Gas retiring the cavern early. At September 30, 2017, the facility's property, plant, and equipment had a net book value of $111 million, of which the cavern itself represents approximately 20%. A potential earlyexpected retirement of ~~this cavern is dependent upon several factors including~~Plant Barry Unit 5 in late 2023 or early 2024 and now expects the ~~results of ongoing third-party technical engineering reviews, testing, and compliance with an order from the LDNR detailing the requirements~~unit to ~~place the cavern back~~remain in service ~~which includes, among other things, obtaining a core sample~~beyond these periods. Alabama Power plans to ~~determine~~retire the ~~composition~~unit on or before the NOPP compliance date of ~~the sheath surrounding the edge of the salt dome. Early retirement of the cavern could trigger impairment of other long-lived assets associated with the natural gas storage facility.~~December 31, 2028. The ultimate ~~outcome~~impact of this matter cannot be determined at this time.

Coal Combustion Residuals

On May 18, 2023, the EPA published a proposal to establish two new categories of federally regulated CCR, legacy surface impoundments and CCR management units (CCRMUs). The EPA is proposing to define a legacy surface impoundment as a CCR surface impoundment that no longer receives CCR but contained both CCR and liquids on or after October 19, 2015 and that is located at an inactive electric generating facility. The EPA is proposing that owners and operators of legacy surface impoundments comply with all of the existing CCR Rule requirements with the exception of location restrictions and liner demonstrations. The proposal establishes accelerated compliance deadlines for legacy surface impoundments to meet regulatory requirements, including a requirement to initiate closure within 12 months after the effective date of the final rule. The EPA is also proposing to define CCRMUs as any area of land on which any non-containerized accumulation of CCR is received, placed, or otherwise managed at any time, ~~but could~~that is not a CCR unit, including inactive CCR landfills and CCR units that closed prior to October 17, 2015. The EPA's proposal would require evaluations to be completed at both active facilities and inactive facilities with one or more legacy surface impoundment. CCRMUs must comply with the CCR Rule's provisions for groundwater monitoring, corrective action, closure, and post-closure activities. A final rule is anticipated in 2024. The ultimate impact of this proposal cannot be determined at this time; however, it may result in significant compliance costs.

On August 14, 2023, the EPA published a proposal to deny the ADEM's CCR permit program application. Alabama Power's permits to close its CCR facilities remain valid under state law. In the absence of an EPA-approved state permit program, CCR facilities in Alabama will remain subject to both the federal and state CCR rules.

Based on requirements for closure and monitoring of landfills and ash ponds pursuant to the CCR Rule and applicable state rules, the traditional electric operating companies have ~~a material impact on~~periodically updated, and expect to continue periodically updating, their related cost estimates and ARO liabilities for each CCR unit as additional information related to closure methodologies, schedules, and/or costs becomes available. Some of these updates have been, and future updates may 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 ~~Gas' financial statements.~~

~~FERC Matters~~

and the traditional electric operating companies could be materially impacted. See ~~MANAGEMENT'S DISCUSSION AND ANALYSIS~~ – ~~FUTURE EARNINGS POTENTIAL~~ – ~~"FERC Matters" of Southern Company Gas in Item 7 and~~ Note 46 to the financial statements ~~of Southern Company Gas in Item 8 of the Form 10-K for additional information regarding the Dalton Pipeline project.~~

~~On August 1, 2017, the Dalton Pipeline was placed in service as authorized by the FERC and transportation service for customers commenced.~~

~~On October 13, 2017, the Atlantic Coast Pipeline project received FERC approval.~~

~~Regulatory Matters~~

~~See Note 3 to the financial statements of Southern Company Gas under "Regulatory Matters"~~ in Item 8 of the Form 10-K and ~~Note (B)~~Notes (A) and (C) to the Condensed Financial Statements under "~~Regulatory~~"Asset Retirement Obligations" and "General Litigation Matters – ~~Southern Company Gas~~Alabama Power," respectively, herein for additional ~~information regarding Southern Company Gas' regulatory matters.~~information.

~~Riders~~Greenhouse Gases

~~Nicor Gas has established a variable tax cost adjustment rider, which was approved by~~On May 23, 2023, the ~~Illinois Commission effective July 16, 2017. This rider provides~~EPA published the proposed GHG standards and state plan guidelines for ~~recovery of the invested capital tax imposed on Nicor Gas through an annual true-up~~fossil fuel-fired power plants. The proposal includes GHG limits for both new and ~~reconciliation mechanism~~existing units based on ~~amounts approved~~technologies such as carbon capture and sequestration, low-GHG hydrogen co-firing, and natural gas co-firing. The proposed standards for new combustion turbines include subcategories for different operational uses including peaking, intermediate, and base load. Compliance with new source standards, once finalized, begins when the unit comes online. The EPA proposes a phased approach for intermediate and base load units that increases in ~~prior rate cases. Accordingly, this rider will not have~~stringency over time. The proposed state plan guidelines for existing units include subcategories based on unit type, retirement date, size, and capacity factor. The EPA is proposing a ~~significant effect~~24-month state plan submission deadline for the existing unit implementation and proposes to potentially allow some limited form of trading and averaging for the state plans. Existing source compliance is proposed to begin as early as January 1, 2030, depending on ~~Southern Company Gas' net income.~~

the unit type and

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION

AND RESULTS OF OPERATIONS

(Continued)

~~Natural Gas Cost Recovery~~

~~Southern Company Gas has established natural gas cost recovery rates approved by~~subcategory. The EPA also proposes to simultaneously repeal the ~~relevant state regulatory agencies~~Affordable Clean Energy rule. A final rule is anticipated in the states in which it serves. 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.

~~Base Rate Cases~~

~~Settled Base Rate Cases~~

On February 21, 2017, the Georgia PSC approved the Georgia Rate Adjustment Mechanism (GRAM) and a $20 million increase in annual base rate revenues for Atlanta Gas Light, effective March 1, 2017. GRAM adjusts base rates annually, up or down, based on the previously approved ROE of 10.75% and does not collect revenue through special riders and surcharges. Various infrastructure programs previously authorized by the Georgia PSC under Atlanta Gas Light's STRIDE program, which include the Integrated Vintage Plastic Replacement Program and Integrated System Reinforcement Program, will continue under GRAM and the recovery of and return on the infrastructure program investments will be included in annual base rate adjustments. The Georgia PSC will review Atlanta Gas Light's performance annually under GRAM.

Pursuant to the GRAM approval, Atlanta Gas Light and the staff of the Georgia PSC agreed to a variation to the Integrated Customer Growth Program that was formerly part of Atlanta Gas Light's STRIDE program. As a result, a new tariff was created, effective October 10, 2017, to provide $15 million annually for Atlanta Gas Light to commit to strategic economic development projects.

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

In September 2016, Elizabethtown Gas filed a general base rate case with the New Jersey BPU requesting a $19 million increase in annual base rate revenues. The requested increase was based on a projected 12-month test year ending March 31, 2017 and a ROE of 10.25%. On June 30, 2017, the New Jersey BPU approved a settlement that provides for a $13 million increase in annual base rate revenues, effective July 1, 2017, based on a ROE of 9.6%. Also included in the settlement was a new composite depreciation rate that is expected to result in a $3 million annual reduction of depreciation. See OVERVIEW – "Merger, Acquisition, and Disposition Activities" and Note (I) to the Condensed Financial Statements under "Southern Company Gas" herein for information on the proposed sale of Elizabethtown Gas.

~~Pending Base Rate Cases~~

On March 10, 2017, Nicor Gas filed a general base rate case with the Illinois Commission requesting a $208 million increase in annual base rate revenues. The requested increase is based on a 2018 projected test year and a ROE of 10.7%. The Illinois Commission is expected to rule on the requested increase in December 2017, after which rate adjustments will be effective.

On March 31, 2017, Virginia Natural Gas filed a general base rate case with the Virginia Commission requesting a $44 million increase in annual base rate revenues. The requested increase was based on a projected 12-month test year beginning September 1, 2017 and a ROE of 10.25%. The requested increase included $13 million related to the recovery of investments under the Steps to Advance Virginia's Energy (SAVE) program. On October 3, 2017, Virginia Natural Gas entered into a proposed stipulation with the Staff of the Virginia Commission, the Office of the Attorney General, Division of Consumer Counsel, and the Virginia Industrial Gas Users' Association resolving all related issues. The proposed stipulation includes a $34 million increase in annual base rate revenues, including $13 million related to the recovery of investments under the SAVE program. An authorized ROE range of 9.0% to 10.0% with a midpoint of 9.5% will be used to determine the revenue requirement in any filing, other than for a

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~~FINANCIAL CONDITION AND RESULTS OF OPERATIONS~~

change in base rates. The Virginia Commission is expected to rule on the proposed stipulation in the fourth quarter 2017. Rate adjustments based on the proposed stipulation became effective September 1, 2017, subject to refund.

On October 23, 2017, Florida City Gas filed a general base rate case with the Florida PSC requesting a $19 million increase in annual base rate revenues. The requested increase is based on a 2018 projected test year and a ROE of 11.25%. The requested increase includes $3 million related to the recovery of investments under the Safety, Access, and Facility Enhancement (SAFE) program. Additionally, Florida City Gas requested interim rates of $5 million to be effective in January 2018, subject to refund. The Florida PSC is expected to rule on the requested increase in mid-2018.

2024. The ultimate ~~outcome~~impact of ~~these pending base rate cases~~this proposal cannot be determined at this ~~time.~~time; however, it may result in significant compliance costs.

Regulatory ~~Infrastructure Programs~~Matters

Southern Company Gas is engaged in various infrastructure programs that update or expand its gas distribution systems to improve reliability and ensure the safety of its utility infrastructure, and recovers in rates its investment and a return associated with these infrastructure programs.

~~Nicor Gas~~

In 2014, the Illinois Commission approved Nicor Gas' nine-year regulatory infrastructure program, Investing in Illinois. Under this program, Nicor Gas placed into service $178 million of qualifying assets during the first nine months of 2017.

~~Atlanta Gas Light~~

Atlanta Gas Light's STRIDE program, which started in 2009, consists of three individual programs that update and expand gas distribution systems and LNG facilities as well as improve system reliability to meet operational flexibility and customer growth. Through the programs under STRIDE, Atlanta Gas Light invested $127 million during the first nine months of 2017. The recovery of and return on current and future capital investments under the STRIDE program are included in the annual base rate revenue adjustment under GRAM.

In August 2016, Atlanta Gas Light filed a petition with the Georgia PSC for approval of a four-year extension of its Integrated System Reinforcement Program (i-SRP) seeking approval to invest an additional $177 million to improve and upgrade its core gas distribution system in years 2017 through 2020. Subsequently, the proposed capital investments associated with the extension of i-SRP were included in the 2017 annual base rate revenue under GRAM approved by the Georgia PSC on February 21, 2017.

See "~~Base Rate Cases" herein for additional information.~~

~~Elizabethtown Gas~~

In 2013, the New Jersey BPU approved the extension of Elizabethtown Gas' Aging Infrastructure Replacement program, under which Elizabethtown Gas invested $16 million during the first nine months of 2017. Effective July 1, 2017, investments under this program are being recovered through base rate revenues.

~~Virginia Natural Gas~~

~~In March 2016, the Virginia Commission approved an extension~~Note 2 to the ~~SAVE program, under which Virginia Natural Gas invested $21 million during~~financial statements in Item 8 of the ~~first nine months of 2017.~~

~~Florida City Gas~~

~~The Florida PSC approved Florida City Gas' SAFE program in 2015. Under the program, Florida City Gas invested $9 million during the first nine months of 2017.~~

~~Other Matters~~

~~Southern Company Gas is involved in various other matters being litigated~~Form 10-K, OVERVIEW – "Recent Developments" herein, and ~~regulatory matters that could affect future earnings. In addition, Southern Company Gas is subject to certain claims and legal actions arising in the~~

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~~FINANCIAL CONDITION AND RESULTS OF OPERATIONS~~

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

~~Nicor Gas and Nicor Energy Services Company, wholly-owned subsidiaries of~~ Southern Company Gas, including items that could impact the applicable Registrants' future earnings, cash flows, and/or financial condition.

Alabama Power

On July 14, 2023, Alabama Power issued a request for proposals of between 100 MWs and ~~Nicor Inc. were defendants in a putative class action initially filed in 2011 in~~1,200 MWs of capacity beginning no later than December 1, 2028, with consideration for commencement as early as 2025. Any purchases will depend upon the ~~state court in Cook County, Illinois. The plaintiffs purported to represent a class~~cost competitiveness of the ~~customers who purchased~~respective offers, as well as other options available to Alabama Power, and would ultimately require approval by the ~~Gas Line Comfort Guard product from Nicor Energy Services Company~~Alabama PSC. The ultimate outcome of this matter cannot be determined at this time.

Construction Programs

The Subsidiary Registrants are engaged in continuous construction programs to accommodate existing and variously alleged that the marketing, sale, and billing of the Gas Line Comfort Guard product violated the Illinois Consumer Fraud and Deceptive Business Practices Act, constituting common law fraud and resulting in unjust enrichment of these entities.estimated future loads on their respective systems. The plaintiffs sought, on behalf of the classes they purported to represent, actual and punitive damages, interest, costs, attorney fees, and injunctive relief. On February 8, 2017, the judge denied the plaintiffs' motion for class certification and Southern Company ~~Gas' motion for summary judgment. On March 7, 2017,~~system strategy continues to include developing and constructing new electric generating facilities, expanding and improving the ~~parties reached a settlement, which was finalized~~electric transmission and ~~effective on April 3, 2017. The settlement did not have a material impact on Southern Company Gas' financial statements.~~electric and natural gas distribution systems, and undertaking projects to comply with environmental laws and regulations.

~~ACCOUNTING POLICIES~~

~~Application of Critical Accounting Policies and Estimates~~

~~Southern Company Gas prepares its financial statements~~For the traditional electric operating companies, major generation construction projects are subject to state PSC approval in accordance with GAAP. Significant accounting policies are described in Note 1 to the financial statements of Southern Company Gas in Item 8 of the Form 10-K. In the application of these policies, certain estimates are made that may have a material impact on Southern Company Gas' results of operations and related disclosures. Different assumptions and measurements could produce estimates that are significantly different from those recorded in the financial statements. See MANAGEMENT'S DISCUSSION AND ANALYSIS – ACCOUNTING POLICIES – "Application of Critical Accounting Policies and Estimates" of Southern Company Gas in Item 7 of the Form 10-K for a complete discussion of Southern Company Gas' critical accounting policies and estimates related to Utility Regulation, Pushdown of Acquisition Accounting, Assessment of Assets, Derivatives and Hedging Activities, Pension and Other Postretirement Benefits, and Contingent Obligations.

~~Recently Issued Accounting Standards~~

~~See MANAGEMENT'S DISCUSSION AND ANALYSIS – ACCOUNTING POLICIES – "Recently Issued Accounting Standards" of Southern Company Gas in Item 7 of the Form 10-K for additional information.~~

~~While Southern Company Gas expects most of its revenue~~order to be included in ~~the scope of ASC 606, it has not fully completed its evaluation of all revenue arrangements.~~retail rates. The ~~majority of~~largest construction project currently underway in the Southern Company ~~Gas' revenue, including energy provided to customers,~~system is from tariff offerings that provide natural gas without a defined contractual term, as well as longer-term contractual agreements, including non-derivative natural gas asset management and optimization arrangements. Southern Company Gas expects that the revenue from contracts with these customers will not result in a significant shift in the timing of revenue recognition for such sales.

Southern Company Gas' ongoing evaluation of other revenue streams and related contracts includes unregulated sales to customers. Some revenue arrangements, such as energy-related derivatives and alternative revenue programs, are excluded from the scope of ASC 606 and, therefore, will be accounted for and disclosed or presented separately from revenues under ASC 606 on Southern Company Gas' financial statements. In addition, the power

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~~MANAGEMENT'S DISCUSSION AND ANALYSIS OF~~

~~FINANCIAL CONDITION AND RESULTS OF OPERATIONS~~

and utilities industry continues to evaluate other specific industry issues, including the applicability of ASC 606 to contributions in aid of construction (CIAC). Although final implementation guidance has not been issued, Southern Company Gas expects CIAC to be out of the scope of ASC 606.

The new standard is effective for interim and annual reporting periods beginning after December 15, 2017. Southern Company Gas intends to use the modified retrospective method of adoption effective January 1, 2018. Southern Company Gas has also elected to utilize practical expedients which allow it to apply the standard to open contracts at the date of adoption and to reflect the aggregate effect of all modifications when identifying performance obligations and allocating the transaction price for contracts modified before the effective date. Under the modified retrospective method of adoption, prior year reported results are not restated; however, a cumulative-effect adjustment to retained earnings at January 1, 2018 is recorded. In addition, disclosures will include comparative information on 2018 financial statement line items under current guidance. While the adoption of ASC 606, including the cumulative-effect adjustment, is not expected to have a material impact on either the timing or amount of revenues recognized in Southern Company Gas' financial statements, Southern Company Gas will continue to evaluate the requirements, as well as any additional clarifying guidance that may be issued.

~~On January 26, 2017, the FASB issued ASU No. 2017-04,~~ ~~Intangibles – Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment~~ (ASU 2017-04). ASU 2017-04 removes the requirement to compare the implied fair value of goodwill with the carrying amount as part of Step 2 of the goodwill impairment test. Under the new standard, the goodwill impairment loss will be measured as the excess of a reporting unit's carrying amount over its fair value, not exceeding the total amount of goodwill allocated to that reporting unit, which may increase the frequency of goodwill impairment charges if a future goodwill impairment test does not pass the Step 1 evaluation. ASU 2017-04 is effective prospectively for annual and interim periods beginning on or after December 15, 2019, and early adoption is permitted on testing dates after January 1, 2017. Southern Company Gas is evaluating the standard and expects to early adopt ASU 2017-04 effective January 1, 2018.

~~On March 10, 2017, the FASB issued ASU No. 2017-07,~~ ~~Compensation – Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost~~ (ASU 2017-07). ASU 2017-07 requires that an employer report the service cost component in the same line item or items as other compensation costs and requires the other components of net periodic pension and postretirement benefit costs to be separately presented in the income statement outside income from operations. Additionally, only the service cost component is eligible for capitalization, when applicable. However, all cost components remain eligible for capitalization under FERC regulations. ASU 2017-07 will be applied retrospectively for the presentation of the service cost component and the other components of net periodic pension and postretirement benefit costs in the income statement. The capitalization of the service cost component of net periodic pension and postretirement benefit costs in assets will be applied on a prospective basis. ASU 2017-07 is effective for annual periods beginning after December 15, 2017, including interim periods within those annual periods. The presentation changes required for net periodic pension and postretirement benefit costs will result in a decrease in Southern Company Gas' operating income and an increase in other income for 2016 and 2017 and are expected to result in a decrease in operating income and an increase in other income for 2018. The adoption of ASU 2017-07 is not expected to have a material impact on Southern Company Gas' financial statements.

~~On August 28, 2017, the FASB issued ASU No. 2017-12,~~ ~~Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities~~ (ASU 2017-12), amending the hedge accounting recognition and presentation requirements. ASU 2017-12 makes more financial and non-financial hedging strategies eligible for hedge accounting, amends the related presentation and disclosure requirements, and simplifies hedge effectiveness assessment requirements. ASU 2017-12 is effective for fiscal years beginning after December 15, 2018 and interim periods within those fiscal years, with early adoption permitted. Southern Company Gas is evaluating the standard and expects to early adopt ASU 2017-12 effective January 1, 2018. The adoption of ASU 2017-12 is not expected to have a material impact on Southern Company Gas' financial statements.

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~~MANAGEMENT'S DISCUSSION AND ANALYSIS OF~~

~~FINANCIAL CONDITION AND RESULTS OF OPERATIONS~~

~~FINANCIAL CONDITION AND LIQUIDITY~~

~~Overview~~

Plant Vogtle Unit 4. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Overview" of Southern Company Gas in Item 7 of the Form 10-K for additional information. As a result of the Merger that closed on July 1, 2016, the results reported herein include disclosure of the successor third quarter and year-to-date 2017, the successor period of July 1, 2016 through September 30, 2016, and the predecessor period of January 1, 2016 through June 30, 2016. See ~~OVERVIEW~~ ~~– "Merger, Acquisition, and Disposition Activities" and~~ Note ~~(I)~~(B) to the Condensed Financial Statements under "~~Southern Company~~"Georgia Power – ~~Merger with Southern Company Gas~~"Nuclear Construction" herein for additional information.

Southern Company Gas' financial condition remained stable at September 30, 2017. Southern Company Gas intends to continue to monitor its access to short-term and long-term capital markets as well as bank credit agreements to meet future capital and liquidity needs. See "~~Capital Requirements and Contractual Obligations," "Sources of Capital," and "Financing Activities" herein for additional information.~~

~~By regulation, Nicor Gas is restricted,~~ Also see Note 2 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. Due to the increased working capital requirements associated with Nicor Gas' Investing in Illinois infrastructure replacement program, since 2015, Nicor Gas has temporarily ceased distributing dividends to Southern Company Gas. Elizabethtown Gas is restricted by its dividend policy as established by the New Jersey BPU in the amount it can dividend to its parent company to the extent of 70% of its quarterly net income. Additionally, as stipulated in the New Jersey BPU's order approving the Merger, Southern Company Gas is prohibited from paying dividends to its parent company, Southern Company, if Southern Company Gas' senior unsecured debt rating falls below investment grade. As of September 30, 2017, the amount of subsidiary retained earnings and net income available to dividend totaled $752 million. These restrictions did not have any impact on Southern Company Gas' ability to meet its cash obligations, nor does management expect such restrictions to materially impact Southern Company Gas' ability to meet its currently anticipated cash obligations.

Net cash provided from (used for) operating activities totaled $1.1 billion for the successor first nine months of 2017, $(342) million for the successor period of July 1, 2016 through September 30, 2016, and $1.1 billion for the predecessor period of January 1, 2016 through June 30, 2016. These cash flows were primarily driven by the sale of natural gas inventory during the respective periods.

Net cash used for investing activities totaled $1.2 billion for the successor first nine months of 2017, primarily due to gross property additions related to capital expenditures for infrastructure replacement programs at gas distribution operations and capital contributed to equity method investments in pipelines. Net cash used for investing activities totaled $1.7 billion for the successor period of July 1, 2016 through September 30, 2016 and $559 million for the predecessor period of January 1, 2016 through June 30, 2016 primarily due to gross property additions related to capital expenditures for infrastructure replacement programs at gas distribution operations and the acquisition of Southern Company Gas' ownership interest in SNG in September 2016.

Net cash provided from financing activities totaled $45 million for the successor first nine months of 2017, primarily due to proceeds from debt issuances and capital contributions from Southern Company, partially offset by net repayments of commercial paper borrowings and common stock dividend payments to Southern Company. Net cash provided from (used for) financing activities totaled $2.1 billion for the successor period of July 1, 2016 through September 30, 2016 and $(558) million for the predecessor period of January 1, 2016 through June 30, 2016 primarily due to net repayments of commercial paper borrowings, the redemption of long-term debt, and common stock dividend payments to shareholders, partially offset by proceeds from debt issuances. The successor period of July 1, 2016 through September 30, 2016 also includes capital contributions from Southern Company to fund the investment in SNG. Cash flows from financing activities vary from period to period based on capital needs and the maturity or redemption of securities.

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~~MANAGEMENT'S DISCUSSION AND ANALYSIS OF~~

~~FINANCIAL CONDITION AND RESULTS OF OPERATIONS~~

Significant balance sheet changes at September 30, 2017 include an increase of $847 million in total property, plant, and equipment primarily due to capital expenditures for infrastructure replacement programs, an increase in long-term debt of $603 million primarily due to $450 million of senior notes and $200 million of first mortgage bonds at Nicor Gas issued in May 2017 and August 2017, respectively, and a decrease of $323 million in notes payable related primarily to net repayments of commercial paper borrowings at Nicor Gas. Other significant balance sheet changes include an increase of $239 million in accumulated deferred income taxes, primarily as a result of tax depreciation related to infrastructure assets placed in service as well as the impact of State of Illinois tax legislation, and decreases of $196 million and $146 million in energy marketing receivables and payables, respectively, due to lower natural gas prices.

~~Capital Requirements and Contractual Obligations~~

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" of Southern Company Gas in Item 7 of the Form 10-K for a description of Southern Company Gas' capital requirements for its infrastructure programs, scheduled maturities of long-term debt and the related interest, as well as pipeline charges, storage capacity, and gas supply, operating leases, asset management agreements, standby letters of credit and performance/surety bonds, financial derivative obligations, pension and other postretirement benefit plans, and other purchase commitments, primarily related to environmental remediation liabilities. There are no scheduled maturities of long-term debt through September 30, 2018. See "~~Sources of Capital" herein for additional information.~~

The regulatory infrastructure programs and other construction programs are subject to periodic review and revision, and actual costs may vary from these estimates because of numerous factors. These factors include: changes in business conditions; changes in FERC rules and regulations; state regulatory approvals; changes in legislation; the cost and efficiency of labor, equipment, and materials; project scope and design changes; and the cost of capital. In addition, there can be no assurance that costs related to capital expenditures will be fully recovered. See Note 3 to the consolidated financial statements ~~of Southern Company Gas~~ in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements herein under "Alabama Power – Certificates of Convenience and Necessity" for information regarding ~~additional factors that may impact infrastructure investment expenditures.~~Alabama Power's construction of Plant Barry Unit 8, which was placed in service on November 1, 2023.

~~Sources~~See Note (K) to the Condensed Financial Statements under "Southern Power" herein for information relating to Southern Power's construction of ~~Capital~~renewable energy facilities.

Southern Company Gas ~~plans~~is engaged in various infrastructure improvement programs designed to ~~obtain~~update or expand the funds to meet its future capital needs through operating cash flows, short-term debt borrowings under its commercial paper programs, external securities issuances, and equity contributions from Southern Company. However, the amount, type, and timing of any future financings, if needed, depend upon regulatory approval, prevailing market conditions, and other factors. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Sources of Capital" of Southern Company Gas in Item 7natural gas distribution systems of the ~~Form 10-K for additional information.~~

~~At September 30, 2017, Southern Company Gas' current liabilities exceeded current assets by $645 million primarily as~~natural gas distribution utilities to improve reliability and resiliency, reduce emissions, and meet operational flexibility and growth. The natural gas distribution utilities recover their investment and a result of $934 million in notes payable. Southern Company Gas' current liabilities frequently exceed current assets because of commercial paper borrowings used to fund daily operations, scheduled maturities of long-term debt, and significant seasonal fluctuations in cash needs. Southern Company Gas intends to utilize operating cash flows, commercial paper, and debt securities issuances, as market conditions permit, as well as equity contributions from Southern Company to fund its short-term capital needs. Southern Company Gas has substantial cash flow from operating activities and accessreturn associated with these infrastructure programs through their regulated rates. See Note 2 to the ~~capital markets and financial institutions to meet liquidity needs.~~

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~~MANAGEMENT'S DISCUSSION AND ANALYSIS OF~~

~~FINANCIAL CONDITION AND RESULTS OF OPERATIONS~~

~~At September 30, 2017, Southern Company Gas had approximately $21 million of cash and cash equivalents. Committed credit arrangements with banks at September 30, 2017 were as follows:~~

Company Expires 2022 Unused
(millions)
Southern Company Gas Capital $ 1,200
$ 1,161
Nicor Gas 700
700
Total $ 1,900
$ 1,861

Additionally, Pivotal Utility Holdings is party to a series of loan agreements with the New Jersey Economic Development Authority and Brevard County, Florida under which five series of gas facility revenue bonds totaling $200 million have been issued.

~~See Note 6 to the consolidated~~ financial statements ~~of Southern Company Gas under "Bank Credit Arrangements"~~ in Item 8 of the Form 10-K and Note ~~(E) to the Condensed Financial Statements under "Bank Credit Arrangements" herein for additional information.~~

In May 2017, Southern Company Gas Capital and Nicor Gas terminated their existing credit arrangements for $1.3 billion and $700 million, respectively, which were to mature in 2017 and 2018, and entered into a new multi-year credit arrangement (Facility) currently allocated for $1.2 billion and $700 million, respectively, with a maturity date of 2022, as reflected in the table above. Pursuant to the Facility, the allocations may be adjusted.

The Facility contains a covenant that limits the ratio of debt to capitalization (as defined in each facility) to a maximum of 70% for each of Southern Company Gas and Nicor Gas and contains a cross-acceleration provision to other indebtedness (including guarantee obligations) of the applicable company. Such cross-acceleration provision to other indebtedness would trigger an event of default of the applicable company if Southern Company Gas or Nicor Gas defaulted on indebtedness, the payment of which was then accelerated. At September 30, 2017, both companies were in compliance with such covenant. The Facility does not contain a material adverse change clause at the time of borrowings.

Subject to applicable market conditions, the applicable company expects to renew or replace the Facility as needed, prior to expiration. In connection therewith, the applicable company may extend the maturity dates and/or increase or decrease the lending commitments thereunder.

Southern Company Gas makes short-term borrowings primarily through commercial paper programs that have the liquidity support of the committed bank credit arrangements described above. Commercial paper borrowings are included in notes payable in the balance sheets.

~~Details of commercial paper borrowings were as follows:~~

Commercial Paper at September 30, 2017
Commercial Paper During the Period^(*)
Amount
Outstanding Weighted Average Interest Rate Average Amount Outstanding Weighted Average Interest Rate Maximum Amount Outstanding
Commercial paper: (in millions) (in millions) (in millions)
Southern Company Gas Capital $ 836
1.5 % $ 680
1.5 % $ 838
Nicor Gas 98
1.3
40
1.3
120
Total $ 934
1.5 % $ 720
1.5 %


~~(*)~~	~~Average and maximum amounts are based upon daily balances during the successor three-month period ended September 30, 2017.~~

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

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~~MANAGEMENT'S DISCUSSION AND ANALYSIS OF~~

~~FINANCIAL CONDITION AND RESULTS OF OPERATIONS~~

~~Credit Rating Risk~~

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

There are certain contracts that could require collateral, but not accelerated payment, in the event of a credit rating change below BBB- and/or Baa3. These contracts are for physical gas purchases and sales and energy price risk management. The maximum potential collateral requirements under these contracts at September 30, 2017 were $12 million.

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

On March 24, 2017, S&P revised its consolidated credit rating outlook for Southern Company and its subsidiaries (including Southern Company Gas, Southern Company Gas Capital, and Nicor Gas) from stable to negative.

~~Financing Activities~~

The long-term debt on Southern Company Gas' consolidated balance sheets includes both principal and non-principal components. As of September 30, 2017, the non-principal components totaled $523 million, which consisted of the unamortized portions of the fair value adjustment recorded in purchase accounting, debt premiums, debt discounts, and debt issuance costs.

In December 2016, Southern Company Gas executed intercompany promissory notes to further allocate interest expense to its reportable segments that previously remained in the "all other" segment. These intercompany promissory notes allow Southern Company Gas to calculate net income, which is its performance measure subsequent to the Merger, at the segment level that incorporates the full impact of interest costs.

In May 2017, Southern Company Gas Capital issued $450 million aggregate principal amount of Series 2017A 4.40% Senior Notes due May 30, 2047. The proceeds were used to repay Southern Company Gas' short-term indebtedness and for general corporate purposes.

~~In July 2017, Atlanta Gas Light Company repaid at maturity $22 million of Series C medium-term notes.~~

In July 2017, Nicor Gas agreed to issue $400 million aggregate principal amount of first mortgage bonds in a private placement. On August 10, 2017, Nicor Gas issued $100 million aggregate principal amount of First Mortgage Bonds 3.03% Series due August 10, 2027 and $100 million aggregate principal amount of First Mortgage Bonds 3.62% Series due August 10, 2037. The proceeds were used to repay short-term indebtedness incurred under the Nicor Gas commercial paper program and for other working capital needs. The remaining $200 million is expected to be issued in November 2017.

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

~~Market Price Risk~~

Other than the items discussed below, there were no material changes to Southern Company Gas' disclosures about market price risk during the successor third quarter and year-to-date 2017. For an in-depth discussion of Southern Company Gas' market price risks, see MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Market Price Risk" of Southern Company Gas in Item 7 of the Form 10-K. Also see Notes (C) and (H)(B) to the Condensed Financial Statements herein under "Southern Company Gas" for additional information ~~relating to derivative instruments.~~

on Southern Company Gas is exposed to market risks, primarily commodity price risk, interest rate risk, and weather risk. Due to various cost recovery mechanisms, the natural gas distribution utilities of Southern Company Gas that sell natural gas directly to end-use customers have limited exposure to market volatility of natural gas prices.Gas' construction program.

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~~MANAGEMENT'S DISCUSSION AND ANALYSIS OF~~

See FINANCIAL CONDITION AND ~~RESULTS OF OPERATIONS~~

Certain natural gas distribution utilities of Southern Company Gas manage fuel-hedging programs implemented per the guidelines of their respective state regulatory agencies to hedge the impact of market fluctuations in natural gas prices for customers. For the weather risk associated with Nicor Gas, Southern Company Gas has a corporate weather hedging program that utilizes weather derivatives to reduce the risk of lower operating margins potentially resulting from significantly warmer-than-normal weather. In addition, certain non-regulated operations routinely utilize various types of derivative instruments to economically hedge certain commodity price and weather risks inherent in the natural gas industry. These instruments include a variety of exchange-traded and over-the-counter energy contracts, such as forward contracts, futures contracts, options contracts, and swap agreements. Some of these economic hedge activities may not qualify, or are not designated, for hedge accounting treatment. The following table illustrates the change in the net fair value of Southern Company Gas' derivative instruments during all periods presented, and provides details of the net fair value of contracts outstanding as of the dates presented.

Successor Predecessor
Third Quarter Third Quarter Year-to-Date July 1, 2016 through September 30, 2016 January 1, 2016
through
June 30,
2016
2017 2016 2017
(in millions) (in millions)
Contracts outstanding at beginning of period,
assets (liabilities), net $ 51
$ (54 ) $ 12
$ (54 ) $ 75
Contracts realized or otherwise settled (6 ) (3 ) (22 ) (3 ) (77 )
Current period changes^(a)
(16 ) —
39
—
(82 )
Contracts outstanding at the end of period,
assets (liabilities), net 29
(57 ) 29
(57 ) (84 )
Netting of cash collateral 76
111
76
111
120
Cash collateral and net fair value of contracts
outstanding at end of period^(b)
$ 105
$ 54
$ 105
$ 54
$ 36


~~(a)~~	~~Current period changes also include the fair value of new contracts entered into during the period, if any.~~


~~(b)~~	Net fair value of derivative instruments outstanding includes premiums and the intrinsic values associated with weather derivatives of $13 million at September 30, 2017 and $7 million at September 30, 2016.

~~The maturities of Southern Company Gas' energy-related derivative contracts at September 30, 2017 were as follows:~~

Fair Value Measurements
Successor – September 30, 2017
Total
Fair Value Maturity
Year 1 Years 2 & 3 Years 4 and thereafter
(in millions)
Level 1^(a)
$ (35 ) $ (10 ) $ (20 ) $ (5 )
Level 2^(b)
64
12
45
7
Fair value of contracts outstanding at end of period^(c)
$ 29
$ 2
$ 25
$ 2


~~(a)~~	~~Valued using NYMEX futures prices.~~


~~(b)~~	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.


~~(c)~~	~~Excludes cash collateral of $76 million at September 30, 2017.~~

~~NOTES TO THE CONDENSED FINANCIAL STATEMENTS~~

~~FOR~~

~~THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES~~

~~ALABAMA POWER COMPANY~~

~~GEORGIA POWER COMPANY~~

~~GULF POWER COMPANY~~

~~MISSISSIPPI POWER COMPANY~~

~~SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES~~

~~SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES~~

~~(UNAUDITED)~~

~~INDEX TO THE NOTES TO THE CONDENSED FINANCIAL STATEMENTS~~

~~INDEX TO APPLICABLE NOTES TO FINANCIAL STATEMENTS BY REGISTRANT~~

~~The following unaudited notes to the condensed financial statements are a combined presentation. The list below indicates the registrants to which each footnote applies.~~



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

~~THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES~~

~~ALABAMA POWER COMPANY~~

~~GEORGIA POWER COMPANY~~

~~GULF POWER COMPANY~~

~~MISSISSIPPI POWER COMPANY~~

~~SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES~~

~~SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES~~

~~NOTES TO THE CONDENSED FINANCIAL STATEMENTS:~~

~~(UNAUDITED)~~


~~(A)~~	~~INTRODUCTION~~

~~The condensed quarterly financial statements of each registrant included~~LIQUIDITY – "Cash Requirements" herein have been prepared by such registrant, without audit, pursuant to the rules and regulations of the SEC. The Condensed Balance Sheets as of December 31, 2016 have been derived from the audited financial statements of each registrant. In the opinion of each registrant's management, the information regarding such registrant furnished herein reflects all adjustments, which, except as otherwise disclosed, are of a normal recurring nature, necessary to present fairly the results of operations for the periods ended September 30, 2017 and 2016. Certain information and footnote disclosures normally included in annual financial statements prepared in accordance with GAAP have been condensed or omitted pursuant to such rules and regulations, although each registrant believes that the disclosures regarding such registrant are adequate to make the information presented not misleading. Disclosures which would substantially duplicate the disclosures in the Form 10-K and details which have not changed significantly in amount or composition since the filing of the Form 10-K are generally omitted from this Quarterly Report on Form 10-Q unless specifically required by GAAP. Therefore, these Condensed Financial Statements should be read in conjunction with the financial statements and the notes thereto included in the Form 10-K. Due to the seasonal variations in the demand for energy, operating results for the periods presented are not necessarily indicative of the operating results to be expected for the full year.

Southern Company's financial statements reflect its investments in its subsidiaries, including Southern Company Gas as a result of the Merger, on a consolidated basis. Southern Company Gas' results of operations and cash flows for the three and nine months ended September 30, 2017 and the three months ended September 30, 2016, as well as its financial condition as of September 30, 2017 and December 31, 2016, are reflected within Southern Company's consolidated amounts in these accompanying notes herein. The equity method is used for entities in which Southern Company has significant influence but does not control, including Southern Company Gas' investment in SNG, and for variable interest entities where Southern Company has an equity investment but is not the primary beneficiary. See Note (I) under "~~Southern Company~~– ~~Merger with Southern Company Gas~~" for additional information regarding the ~~Merger.~~

Pursuant to the Merger, Southern Company pushed down the application of the acquisition method of accounting to the consolidated financial statements of Southern Company Gas such that the assets and liabilities are recorded at their respective fair values, and goodwill has been established for the excess of the purchase price over the fair value of net identifiable assets. Accordingly, the consolidated financial statements of Southern Company Gas for periods before and after July 1, 2016 (acquisition date) reflect different bases of accounting, and the financial positions and results of operations of those periods are not comparable. Throughout Southern Company Gas' condensed consolidated financial statements and the accompanying notes herein, periods prior to July 1, 2016 are identified as "predecessor," while periods after the acquisition date are identified as "successor."

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

~~NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)~~

~~(UNAUDITED)~~

~~Recently Issued Accounting Standards~~

~~See Note 1 to the financial statements of the registrants under "Recently Issued Accounting Standards" in Item 8 of the Form 10-K for additional information.~~

While the registrants expect most of their revenue to be included in the scope of ASC 606, they have not fully completed the evaluation of all revenue arrangements. The majority of Southern Company's, the traditional electric operating companies', and Southern Company Gas' revenue, including energy provided to customers, is from tariff offerings that provide electricity or natural gas without a defined contractual term, as well as longer-term contractual commitments, including PPAs and non-derivative natural gas asset management and optimization arrangements. The majority of Southern Power's revenues includes longer-term PPAs for generation capacity and energy. The registrants expect the adoption of ASC 606 will not result in a significant shift from the current timing of revenue recognition for such transactions.

The registrants' ongoing evaluation of other revenue streams and related contracts includes unregulated sales to customers. Some revenue arrangements, such as certain PPAs, energy-related derivatives, and alternative revenue programs, are excluded from the scope of ASC 606 and, therefore, will be accounted for and disclosed or presented separately from revenues under ASC 606 on the registrants' financial statements. In addition, the power and utilities industry continues to evaluate other specific industry issues, including the applicability of ASC 606 to contributions in aid of construction (CIAC). Although final implementation guidance has not been issued, Southern Company, the traditional electric operating companies, and Southern Company Gas expect CIAC to be out of the scope of ASC 606.

The new standard is effective for interim and annual reporting periods beginning after December 15, 2017. The registrants intend to use the modified retrospective method of adoption effective January 1, 2018. The registrants have also elected to utilize practical expedients which allow them to apply the standard to open contracts at the date of adoption and to reflect the aggregate effect of all modifications when identifying performance obligations and allocating the transaction price for contracts modified before the effective date. Under the modified retrospective method of adoption, prior year reported results are not restated; however, a cumulative-effect adjustment to retained earnings at January 1, 2018 is recorded. In addition, disclosures will include comparative information on 2018 financial statement line items under current guidance. While the adoption of ASC 606, including the cumulative-effect adjustment, is not expected to have a material impact on either the timing or amount of revenues recognized in the registrants' financial statements, the registrants will continue to evaluate theRegistrants' capital requirements ~~as well as any additional clarifying guidance that may be issued.~~

~~On January 26, 2017, the FASB issued ASU No. 2017-04,~~ ~~Intangibles – Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment~~ (ASU 2017-04). ASU 2017-04 removes the requirement to compare the implied fair value of goodwill with the carrying amount as part of Step 2 of the goodwill impairment test. Under the new standard, the goodwill impairment loss will be measured as the excess of a reporting unit's carrying amount over its fair value, not exceeding the total amount of goodwill allocated to that reporting unit, which may increase the frequency of goodwill impairment charges if a future goodwill impairment test does not pass the Step 1 evaluation. ASU 2017-04 is effective prospectively for annual and interim periods beginning on or after December 15, 2019, and early adoption is permitted on testing dates after January 1, 2017. Southern Company and Southern Company Gas are evaluating the standard and expect to early adopt ASU 2017-04 effective January 1, 2018.

~~NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)~~

~~(UNAUDITED)~~

2017-07). ASU 2017-07 requires that an employer report the service cost component in the same line item or items as other compensation costs and requires the other components of net periodic pension and postretirement benefit costs to be separately presented in the income statement outside income from operations. Additionally, only the service cost component is eligible for capitalization, when applicable. However, all cost components remain eligible for capitalization under FERC regulations. ASU 2017-07 will be applied retrospectively for the presentation of the service cost component and the other components of net periodic pension and postretirement benefit costs in the income statement. The capitalization of the service cost component of net periodic pension and postretirement benefit costs in assets will be applied on a prospective basis. ASU 2017-07 is effective for annual periods beginning after December 15, 2017, including interim periods within those annual periods. The presentation changes required for net periodic pension and postretirement benefit costs will result in a decrease in Southern Company's, the traditional electric operating companies', and Southern Company Gas' operating income and an increase in other income for 2016 and 2017 and are expected to result in a decrease in operating income and an increase in other income for 2018. The adoption of ASU 2017-07 is not expected to have a material impact on Southern Company's, the traditional electric operating companies', or Southern Company Gas' financial statements.

~~On August 28, 2017, the FASB issued ASU No. 2017-12,~~ ~~Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities~~ (ASU 2017-12), amending the hedge accounting recognition and presentation requirements. ASU 2017-12 makes more financial and non-financial hedging strategies eligible for hedge accounting, amends the related presentation and disclosure requirements, and simplifies hedge effectiveness assessment requirements. ASU 2017-12 is effective for fiscal years beginning after December 15, 2018 and interim periods within those fiscal years, with early adoption permitted. The registrants are evaluating the standard and expect to early adopt ASU 2017-12 effective January 1, 2018. The adoption of ASU 2017-12 is not expected to have a material impact on the registrants' financial statements.

~~Affiliate Transactions~~

Prior to the completion of Southern Company Gas' acquisition of its 50% equity interest in SNG, SCS (as agent for Alabama Power, Georgia Power, and Southern Power) and Southern Company Gas had entered into long-term interstate natural gas transportation agreements with SNG. The interstate transportation service provided to Alabama Power, Georgia Power, Southern Power, and Southern Company Gas by SNG pursuant to these agreements is governed by the terms and conditions of SNG's natural gas tariff and is subject to FERC regulation. For the nine months ended September 30, 2017, transportation costs under these agreements for Alabama Power, Georgia Power, Southern Power, and Southern Company Gas were approximately $8 million, $77 million, $19 million, and $24 million, respectively. For the period subsequent to Southern Company Gas' investment in SNG through September 30, 2016, transportation costs under these agreements for Alabama Power, Georgia Power, Southern Power, and Southern Company Gas were approximately $1 million, $8 million, $2 million, and $4 million, respectively.

SCS, as agent for Georgia Power and Southern Power, has agreements with certain subsidiaries of Southern Company Gas to purchase natural gas. For the nine months ended September 30, 2017, natural gas purchases made by Georgia Power and Southern Power from Southern Company Gas' subsidiaries were approximately $18 million and $94 million, respectively. For the period subsequent to Southern Company's acquisition of Southern Company Gas through September 30, 2016, natural gas purchases made by Georgia Power and Southern Power from Southern Company Gas' subsidiaries were approximately $7 million and $2 million, respectively.

~~NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)~~

~~(UNAUDITED)~~

~~Goodwill and Other Intangible Assets~~

~~At September 30, 2017 and December 31, 2016, goodwill was as follows:~~

Goodwill
At September 30, 2017 At December 31, 2016
(in millions)
Southern Company $ 6,267
$ 6,251
Southern Power $ 2
$ 2
Southern Company Gas
Gas distribution operations $ 4,702
$ 4,702
Gas marketing services 1,265
1,265
Southern Company Gas total $ 5,967
$ 5,967

~~Goodwill is not amortized, but is subject to an annual impairment test during the fourth quarter of each year, or more frequently if impairment indicators arise.~~

~~NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)~~

~~(UNAUDITED)~~


~~1-3526~~			1-3526						The Southern Company						58-0690070

	~~58-0690070~~
		1-3164
~~1-3164~~	Alabama Power Company		63-0004250

	~~63-0004250~~
		1-6468
~~1-6468~~	Georgia Power Company		58-0257110

	~~64-0205820~~
		001-37803
~~001-37803~~	Southern Power Company		58-2598670

	~~58-2598670~~
		1-14174
~~1-14174~~	Southern Company Gas ~~(A Georgia Corporation)~~ ~~Ten Peachtree Place, N.E.~~ ~~Atlanta, Georgia 30309~~ ~~(404) 584-4000~~		58-2210952


Registrant	Title of Each Class	Trading Symbol(s)	Name of Each Exchange on Which Registered
The Southern Company	Common Stock, par value $5 per share	SO	New York Stock Exchange
			(NYSE)
The Southern Company	Series 2017B 5.25% Junior Subordinated Notes due 2077	SOJC	NYSE
The Southern Company	Series 2020A 4.95% Junior Subordinated Notes due 2080	SOJD	NYSE
The Southern Company	Series 2020C 4.20% Junior Subordinated Notes due 2060	SOJE	NYSE
The Southern Company	Series 2021B 1.875% Fixed-to-Fixed Reset Rate Junior Subordinated Notes due 2081	SO 81	NYSE
Georgia Power Company	Series 2017A 5.00% Junior Subordinated Notes due 2077	GPJA	NYSE
Southern Power Company	Series 2016B 1.850% Senior Notes due 2026	SO/26A	NYSE



Registrant	Description of Common Stock			~~Description of~~ ~~Common Stock~~			Shares Outstanding at September 30, ~~2017~~	2023
The Southern Company				Par Value $5 Per Share	1,090,619,349	~~1,003,627,691~~
Alabama Power Company				Par Value $40 Per Share	30,537,500	~~30,537,500~~
Georgia Power Company				Without Par Value	9,261,500	~~9,261,500~~
~~Gulf~~Mississippi Power Company				Without Par Value	1,121,000	~~7,392,717~~
~~Mississippi Power Company~~		~~Without Par Value~~		~~1,121,000~~
Southern Power Company		Par Value $0.01 Per Share	1,000		~~1,000~~
Southern Company Gas				Par Value $0.01 Per Share	100	~~100~~


					Page

			Definitions		4
			Cautionary Statement Regarding Forward-Looking Information		8

			PART I—FINANCIAL INFORMATION

			Item 1.	~~Page~~Financial Statements (Unaudited)		~~Number~~10

~~DEFINITIONS~~ Item 2.		5
~~CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION~~		8

	~~PART I—FINANCIAL INFORMATION~~
~~Item 1.~~	~~Financial Statements (Unaudited)~~
~~Item 2.~~	~~Management's Discussion and Analysis of Financial Condition and Results of Operations~~
	~~The Southern Company and Subsidiary Companies~~
	~~Condensed Consolidated Statements of Income~~	11
	~~Condensed Consolidated Statements of Comprehensive Income~~	12
	~~Condensed Consolidated Statements of Cash Flows~~	13
	~~Condensed Consolidated Balance Sheets~~	14
	Management's Discussion and Analysis of Financial Condition and Results of Operations	16100
Item 3.			~~Alabama Power Company~~
	~~Condensed Statements of Income~~	57
	~~Condensed Statements of Comprehensive Income~~	57
	~~Condensed Statements of Cash Flows~~	58
	~~Condensed Balance Sheets~~	59
	~~Management's Discussion and Analysis of Financial Condition and Results of Operations~~	61
	~~Georgia Power Company~~
	~~Condensed Statements of Income~~	75
	~~Condensed Statements of Comprehensive Income~~	75
	~~Condensed Statements of Cash Flows~~	76
	~~Condensed Balance Sheets~~	77
	~~Management's Discussion and Analysis of Financial Condition and Results of Operations~~	79
	~~Gulf Power Company~~
	~~Condensed Statements of Income~~	~~101~~
	~~Condensed Statements of Comprehensive Income~~	~~101~~
	~~Condensed Statements of Cash Flows~~	~~102~~
	~~Condensed Balance Sheets~~	~~103~~
	~~Management's Discussion and Analysis of Financial Condition and Results of Operations~~	~~105~~
	~~Mississippi Power Company~~
	~~Condensed Statements of Income~~	~~120~~
	~~Condensed Statements of Comprehensive Income~~	~~120~~
	~~Condensed Statements of Cash Flows~~	~~121~~
	~~Condensed Balance Sheets~~	~~122~~
	~~Management's Discussion and Analysis of Financial Condition and Results of Operations~~	~~124~~
	~~Southern Power Company and Subsidiary Companies~~
	~~Condensed Consolidated Statements of Income~~	~~152~~
	~~Condensed Consolidated Statements of Comprehensive Income~~	~~152~~
	~~Condensed Consolidated Statements of Cash Flows~~	~~153~~
	~~Condensed Consolidated Balance Sheets~~	~~154~~
	~~Management's Discussion and Analysis of Financial Condition and Results of Operations~~	~~156~~



		~~Page~~ ~~Number~~
	~~PART I—FINANCIAL INFORMATION (CONTINUED)~~
	~~Southern Company Gas and Subsidiary Companies~~
	~~Condensed Consolidated Statements of Income~~	~~171~~
	~~Condensed Consolidated Statements of Comprehensive Income~~	~~172~~
	~~Condensed Consolidated Statements of Cash Flows~~	~~173~~
	~~Condensed Consolidated Balance Sheets~~	~~174~~
	~~Management's Discussion and Analysis of Financial Condition and Results of Operations~~	~~176~~
	~~Notes to the Condensed Financial Statements~~	~~206~~
~~Item 3.~~	Quantitative and Qualitative Disclosures about Market Risk	55160
Item 4.			Controls and Procedures	55160

			PART II—OTHER INFORMATION

Item 1.			Legal Proceedings	~~279~~161
Item 1A.			Risk Factors	~~279~~161
Item 2.			Unregistered Sales of Equity Securities and Use of Proceeds	Inapplicable
Item 3.			Defaults Upon Senior Securities	Inapplicable
Item 4.			Mine Safety Disclosures	Inapplicable
Item 5.			Other Information	~~Inapplicable~~
~~Item 6.~~	~~Exhibits~~	~~282~~161
Item 6.			~~Signatures~~Exhibits	~~286~~161

			Signatures	164



Term		Meaning
2022 ARP
~~2012 MPSC CPCN Order~~	A detailed order issued by the Mississippi PSC in April 2012 confirming the CPCN originally approved by the Mississippi PSC in 2010 authorizing the acquisition, construction, and operation of the Kemper IGCC
~~2013 ARP~~	~~Alternative~~Alternate Rate Plan approved by the Georgia PSC in ~~2013~~2022 for Georgia Power for the years ~~2014~~2023 through ~~2016 and subsequently extended through 2019~~2025
AFUDC		Allowance for funds used during construction
Alabama Power		Alabama Power Company
~~ASC~~		~~Accounting Standards Codification~~
~~ASU~~	~~Accounting Standards Update~~
~~Atlanta Gas Light~~	~~Atlanta Gas Light Company, a wholly-owned subsidiary of Southern Company Gas~~
~~Atlantic Coast Pipeline~~	~~Atlantic Coast Pipeline, LLC, a joint venture to construct~~Amended and ~~operate a natural gas pipeline in which Southern Company Gas has a 5% ownership interest~~
~~Baseload Act~~	~~State of Mississippi legislation designed to enhance the Mississippi PSC's authority to facilitate development and construction of baseload generation in the State of Mississippi~~
~~CCR~~	~~Coal combustion residuals~~
~~Clean Power Plan~~	~~Final action published by the EPA in 2015 that established guidelines for states to develop plans to meet EPA-mandated CO~~₂ ~~emission rates or emission reduction goals for existing electric generating units~~
CO₂	~~Carbon dioxide~~
~~COD~~	~~Commercial operation date~~
~~Contractor Settlement Agreement~~	~~The December 31, 2015 agreement between Westinghouse and the Vogtle Owners resolving disputes between the Vogtle Owners and the EPC Contractor under the Vogtle 3 and 4 Agreement~~
~~Cooperative Energy~~	~~Electric cooperative in Mississippi formerly known as South Mississippi Electric Power Association (SMEPA)~~
~~CPCN~~	~~Certificate of public convenience and necessity~~
~~CWIP~~	~~Construction work in progress~~
~~Dalton Pipeline~~	~~A 50% undivided ownership interest of Southern Company Gas in a pipeline facility in Georgia~~
~~DOE~~	~~U.S. Department of Energy~~
~~ECO Plan~~	~~Mississippi Power's Environmental Compliance Overview Plan~~
~~Eligible Project Costs~~	~~Certain costs of construction relating to Plant Vogtle Units 3 and 4 that are eligible for financing under the Title XVII Loan Guarantee Program~~
~~EPA~~	~~U.S. Environmental Protection Agency~~
~~EPC Contractor~~	Westinghouse and its affiliate, WECTEC (formerly known as CB&I Stone & Webster, Inc.), formerly a subsidiary of The Shaw Group Inc. and Chicago Bridge & Iron Company N.V.; the former engineering, procurement, and construction contractor for Plant Vogtle Units 3 and 4
~~FASB~~	~~Financial Accounting Standards Board~~
~~FERC~~	~~Federal Energy Regulatory Commission~~
~~FFB~~	~~Federal Financing Bank~~
~~Fitch~~	~~Fitch Ratings, Inc.~~
~~Form 10-K~~	Annual Report on Form 10-K of Southern Company, Alabama Power, Georgia Power, Gulf Power, Mississippi Power, Southern Power, and Southern Company Gas for the year ended December 31, 2016, as applicable
~~GAAP~~	~~U.S. generally accepted accounting principles~~
~~Georgia Power~~	~~Georgia Power Company~~
~~Gulf Power~~	~~Gulf Power Company~~
~~Heating Degree Days~~	~~A measure of weather, calculated when the average daily temperatures are less than 65 degrees Fahrenheit~~
~~Horizon Pipeline~~	~~Horizon Pipeline Company, LLC~~



~~Term~~	~~Meaning~~

~~IGCC~~	~~Integrated coal gasification combined cycle~~
~~IIC~~	~~Intercompany interchange contract~~
~~Illinois Commission~~	~~Illinois Commerce Commission, the state regulatory agency for Nicor Gas~~
~~IRC~~	~~Internal Revenue Code of 1986, as amended~~
~~IRS~~	~~Internal Revenue Service~~
~~ITC~~	~~Investment tax credit~~
~~Kemper IGCC~~	~~Mississippi Power's IGCC project in Kemper County, Mississippi~~
~~KWH~~	~~Kilowatt-hour~~
~~LIBOR~~	~~London Interbank Offered Rate~~
~~LIFO~~	~~Last-in, first-out~~
~~LNG~~	~~Liquefied natural gas~~
Restated Loan Guarantee Agreement	Loan guarantee agreement entered into by Georgia Power with the DOE in 2014, as amended and restated in March 2019, under which the proceeds of borrowings may be used to reimburse Georgia Power for Eligible Project Costs incurred in connection with its construction of Plant Vogtle Units 3 and 4
~~LOCOM~~ARO		~~Lower of weighted average cost or current market price~~Asset retirement obligation
~~LTSA~~ASU		~~Long-term service agreement~~Accounting Standards Update
~~MATS rule~~Atlanta Gas Light		~~Mercury and Air Toxics Standards rule~~
~~Merger~~	~~The merger, effective July 1, 2016, of~~Atlanta Gas Light Company, a wholly-owned ~~direct~~ subsidiary of Southern Company Gas
Bechtel		Bechtel Power Corporation, the primary contractor for the remaining construction activities for Plant Vogtle Units 3 and 4
Bechtel Agreement		The 2017 construction completion agreement between the Vogtle Owners and Bechtel
CCR		Coal combustion residuals
CCR Rule		Disposal of Coal Combustion Residuals from Electric Utilities final rule published by the EPA in 2015
Chattanooga Gas		Chattanooga Gas Company, a wholly-owned subsidiary of Southern Company Gas
Clean Air Act		Clean Air Act Amendments of 1990
COD		Commercial operation date
Contractor Settlement Agreement		The December 31, 2015 agreement between Westinghouse and the Vogtle Owners resolving disputes between the Vogtle Owners and the EPC Contractor under the Vogtle 3 and 4 Agreement
Cooperative Energy		Electric generation and transmission cooperative in Mississippi
COVID-19		The novel coronavirus disease declared a pandemic by the World Health Organization and the Centers for Disease Control and Prevention in March 2020
CWIP		Construction work in progress
Dalton		City of Dalton, Georgia, an incorporated municipality in the State of Georgia, acting by and through its Board of Water, Light, and Sinking Fund Commissioners
Dalton Pipeline		A pipeline facility in Georgia in which Southern Company Gas has a 50% undivided ownership interest
DOE		U.S. Department of Energy

ECO Plan		Mississippi Power's environmental compliance overview plan
ELG		Effluent limitations guidelines
Eligible Project Costs		Certain costs of construction relating to Plant Vogtle Units 3 and 4 that are eligible for financing under the loan guarantee program established under Title XVII of the Energy Policy Act of 2005
EPA		U.S. Environmental Protection Agency
EPC Contractor		Westinghouse and its affiliate, WECTEC Global Project Services Inc.; the former engineering, procurement, and construction contractor for Plant Vogtle Units 3 and 4
FASB		Financial Accounting Standards Board
FCC		Federal Communications Commission
FERC		Federal Energy Regulatory Commission
FFB		Federal Financing Bank
First Solar		First Solar Electric, LLC
Fitch		Fitch Ratings, Inc.
Form 10-K		Annual Report on Form 10-K of Southern Company, Alabama Power, Georgia Power, Mississippi Power, Southern Power, and Southern Company Gas for the year ended December 31, 2022, as applicable
GAAP		U.S. generally accepted accounting principles


Term		Meaning
Rate RSE		Alabama Power's Rate Stabilization and Equalization
Registrants		Southern Company, Alabama Power, Georgia Power, Mississippi Power, Southern Power Company, and Southern Company Gas
ROE		Return on equity
S&P		S&P Global Ratings, a ~~natural gas~~division of S&P Global Inc.
SAVE		Steps to Advance Virginia's Energy, an infrastructure replacement program at Virginia Natural Gas
SCS		Southern Company Services, Inc., the Southern Company system service company and a wholly-owned subsidiary of Southern Company
SEC		U.S. Securities and Exchange Commission
SEGCO		Southern Electric Generating Company, 50% owned by each of Alabama Power and Georgia Power
SNG		Southern Natural Gas Company, L.L.C., a pipeline system in which Southern Company Gas has a ~~20%~~50% ownership interest
~~PEP~~SOFR		~~Mississippi Power's Performance Evaluation Plan~~Secured Overnight Financing Rate
~~Piedmont~~Southern Company		~~Piedmont Natural Gas~~The Southern Company ~~Inc.~~
~~Pivotal Utility Holdings~~Southern Company Gas		~~Pivotal Utility Holdings, Inc.,~~Southern Company Gas and its subsidiaries
Southern Company Gas Capital		Southern Company Gas Capital Corporation, a ~~wholly-owned~~100%-owned subsidiary of Southern Company Gas ~~doing business as Elizabethtown Gas, Elkton Gas, and Florida City Gas~~
~~Plant Vogtle Units 3 and 4~~		~~Two new nuclear generating units under construction at Georgia Power's Plant Vogtle~~
~~PowerSecure~~	~~PowerSecure, Inc.~~
Southern Company power pool	The operating arrangement whereby the integrated generating resources of the traditional electric operating companies and Southern Power (excluding subsidiaries) are subject to joint commitment and dispatch in order to serve their combined load obligations



~~Term~~	~~Meaning~~

~~PPA~~	~~Power purchase agreements, as well as, for Southern Power, contracts for differences that provide the owner of a renewable facility a certain fixed price for the electricity sold to the grid~~
~~PSC~~	~~Public Service Commission~~
~~PTC~~	~~Production tax credit~~
~~Rate CNP~~	~~Alabama Power's Rate Certificated New Plant~~
~~Rate CNP Compliance~~	~~Alabama Power's Rate Certificated New Plant Compliance~~
~~Rate CNP PPA~~	~~Alabama Power's Rate Certificated New Plant Power Purchase Agreement~~
~~Rate ECR~~	~~Alabama Power's Rate Energy Cost Recovery~~
~~Rate NDR~~	~~Alabama Power's Rate Natural Disaster Reserve~~
~~Rate RSE~~	~~Alabama Power's Rate Stabilization and Equalization plan~~
~~registrants~~	~~Southern Company, Alabama Power, Georgia Power, Gulf Power, Mississippi Power, Southern Power Company, and Southern Company Gas~~
~~ROE~~	~~Return on equity~~
~~S&P~~	~~S&P Global Ratings, a division of S&P Global Inc.~~
~~scrubber~~	~~Flue gas desulfurization system~~
~~SCS~~	~~Southern Company Services, Inc. (the~~ Southern Company system ~~service company)~~
~~SEC~~	~~U.S. Securities and Exchange Commission~~
~~SNG~~	~~Southern Natural Gas Company, L.L.C.~~
~~Southern Company~~	~~The Southern Company~~
~~Southern Company Gas~~	~~Southern Company Gas and its subsidiaries~~
~~Southern Company Gas Capital~~	~~Southern Company Gas Capital Corporation, a 100%-owned subsidiary of Southern Company Gas~~
~~Southern Company system~~	Southern Company, the traditional electric operating companies, Southern Power, Southern Company Gas, ~~(as of July 1, 2016), Southern Electric Generating Company,~~SEGCO, Southern Nuclear, SCS, Southern Communications Services, Inc., PowerSecure, ~~(as of May 9, 2016),~~ and other subsidiaries
Southern Holdings		Southern Company Holdings, Inc., a wholly-owned subsidiary of Southern Company
Southern Linc		Southern Communications Services, Inc., a wholly-owned subsidiary of Southern Company, doing business as Southern Linc
Southern Nuclear		Southern Nuclear Operating Company, Inc., a wholly-owned subsidiary of Southern Company
Southern Power		Southern Power Company and its subsidiaries
SouthStar		SouthStar Energy Services, LLC (a Marketer), a wholly-owned subsidiary of Southern Company Gas
~~STRIDE~~SP Solar		~~Atlanta Gas Light's Strategic Infrastructure Development~~SP Solar Holdings I, LP, a limited partnership indirectly owning substantially all of Southern Power's solar and ~~Enhancement program~~battery energy storage facilities, in which Southern Power has a 67% ownership interest
~~Toshiba~~SP Wind		~~Toshiba Corporation, parent~~SP Wind Holdings II, LLC, a holding company owning a portfolio of ~~Westinghouse~~eight operating wind facilities, in which Southern Power is the controlling partner in a tax equity arrangement
~~Toshiba Guarantee~~SRR		~~Certain payment obligations of the EPC Contractor guaranteed by Toshiba~~Mississippi Power's System Restoration Rider, a tariff for retail property damage cost recovery and reserve
~~traditional electric operating companies~~Subsidiary Registrants		Alabama Power, Georgia Power, ~~Gulf~~Mississippi Power, Southern Power, and Southern Company Gas
Toshiba		Toshiba Corporation, the parent company of Westinghouse
traditional electric operating companies		Alabama Power, Georgia Power, and Mississippi Power
~~Triton~~VCM		~~Triton Container Investments, LLC~~Vogtle Construction Monitoring
VIE		Variable interest entity
Virginia Commission		Virginia State Corporation Commission ~~the state regulatory agency for~~
Virginia Natural Gas
~~Virginia Natural Gas~~	Virginia Natural Gas, Inc., a wholly-owned subsidiary of Southern Company Gas
Vogtle 3 and 4 Agreement		Agreement entered into with the EPC Contractor in 2008 by Georgia Power, acting for itself and as agent for the Vogtle Owners, and rejected in bankruptcy in July 2017, pursuant to which the EPC Contractor agreed to design, engineer, procure, construct, and test Plant Vogtle Units 3 and 4


Term		Meaning
Vogtle Owners		Georgia Power, ~~Oglethorpe~~OPC, MEAG Power, ~~Corporation,~~and Dalton
Vogtle Services Agreement		The June 2017 services agreement between the ~~Municipal Electric Authority of Georgia,~~Vogtle Owners and the ~~City~~EPC Contractor, as amended and restated in July 2017, for the EPC Contractor to transition construction management of ~~Dalton, Georgia, an incorporated municipality in the State of Georgia acting by~~Plant Vogtle Units 3 and ~~through its Board of Water, Light,~~4 to Southern Nuclear and ~~Sinking Fund Commissioners~~to provide ongoing design, engineering, and procurement services to Southern Nuclear
WACOG		Weighted average cost of gas
~~WECTEC~~Westinghouse		~~WECTEC Global Project Services Inc.~~
~~Westinghouse~~	Westinghouse Electric Company LLC


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

Alabama Power Company:
Condensed Statements of Income			18
Condensed Statements of Comprehensive Income			18
Condensed Statements of Cash Flows			19
Condensed Balance Sheets			20
Condensed Statements of Common Stockholder's Equity			22

Georgia Power Company:
Condensed Statements of Income			23
Condensed Statements of Comprehensive Income			23
Condensed Statements of Cash Flows			24
Condensed Balance Sheets			25
Condensed Statements of Common Stockholder's Equity			27

Mississippi Power Company:
Condensed Statements of Income and Comprehensive Income			28
Condensed Statements of Cash Flows			29
Condensed Balance Sheets			30
Condensed Statements of Common Stockholder's Equity			32

Southern Power Company and Subsidiary Companies:
Condensed Consolidated Statements of Income			33
Condensed Consolidated Statements of Comprehensive Income			33
Condensed Consolidated Statements of Cash Flows			34
Condensed Consolidated Balance Sheets			35
Condensed Consolidated Statements of Stockholders' Equity			37

Southern Company Gas and Subsidiary Companies:
Condensed Consolidated Statements of Income			38
Condensed Consolidated Statements of Comprehensive Income			38
Condensed Consolidated Statements of Cash Flows			39
Condensed Consolidated Balance Sheets			40
Condensed Consolidated Statements of Stockholder's Equity			42

Combined Notes to the Condensed Financial Statements			43



	For the Three Months Ended September 30,					For the Nine Months Ended September 30,
	2017			2016		2017			2016
	(in millions)					(in millions)
Consolidated Net Income	$	1,109		$	1,177	$	427		$	2,324
Other comprehensive income (loss):
Qualifying hedges:
Changes in fair value, net of tax of $15, $12, $32, and $(74), respectively	25			19		54			(118		)
Reclassification adjustment for amounts included in net income, net of tax of $(10), $2, $(36), and $13, respectively	(17		)	2		(59		)	20
Pension and other postretirement benefit plans:
Reclassification adjustment for amounts included in net income, net of tax of $1, $1, $2, and $2, respectively	1			1		3			3
Total other comprehensive income (loss)	9			22		(2		)	(95		)
Comprehensive Income	1,118			1,199		425			2,229
Less:
Dividends on preferred and preference stock of subsidiaries	10			11		32			34
Comprehensive income attributable to noncontrolling interests	30			27		48			39
Consolidated Comprehensive Income Attributable to Southern Company	$	1,078		$	1,161	$	345		$	2,156


Assets	At September 30, 2017			At December 31, 2016			Assets	At September 30, 2023		At December 31, 2022
	(in millions)							(in millions)
Current Assets:							Current Assets:
Cash and cash equivalents	$	1,841		$	1,975		Cash and cash equivalents	$	1,676	$	1,917

Receivables —							Receivables —
Customer accounts receivable	1,744			1,583
Energy marketing receivables	427			623
Customer accounts							Customer accounts	2,230		2,128

Unbilled revenues	595			706			Unbilled revenues	547		1,012
Under recovered fuel clause revenues	62			—			Under recovered fuel clause revenues	757		10
Income taxes receivable, current	138			544
Other accounts and notes receivable	578			377

Other accounts and notes							Other accounts and notes	553		637
Accumulated provision for uncollectible accounts	(43		)	(43		)	Accumulated provision for uncollectible accounts	(78)		(71)
Materials and supplies	1,499			1,462			Materials and supplies	1,913		1,664
Fossil fuel for generation	571			689			Fossil fuel for generation	829		575
Natural gas for sale	631			631			Natural gas for sale	406		438

Prepaid expenses	365			364			Prepaid expenses	321		347
Other regulatory assets, current	585			581

Assets from risk management activities, net of collateral							Assets from risk management activities, net of collateral	36		115
Regulatory assets – asset retirement obligations							Regulatory assets – asset retirement obligations	358		332

Other regulatory assets							Other regulatory assets	996		968
Other current assets	209			230			Other current assets	544		344
Total current assets	9,202			9,722			Total current assets	11,088		10,416
Property, Plant, and Equipment:							Property, Plant, and Equipment:
In service	102,014			98,416			In service	125,573		117,529
Less: Accumulated depreciation	31,164			29,852			Less: Accumulated depreciation	37,199		35,297
Plant in service, net of depreciation	70,850			68,564			Plant in service, net of depreciation	88,374		82,232
Other utility plant, net							Other utility plant, net	522		599
Nuclear fuel, at amortized cost	865			905			Nuclear fuel, at amortized cost	862		843
Construction work in progress	8,026			8,977			Construction work in progress	8,496		10,896
Total property, plant, and equipment	79,741			78,446			Total property, plant, and equipment	98,254		94,570
Other Property and Investments:							Other Property and Investments:
Goodwill	6,267			6,251			Goodwill	5,161		5,161
Nuclear decommissioning trusts, at fair value							Nuclear decommissioning trusts, at fair value	2,207		2,145
Equity investments in unconsolidated subsidiaries	1,637			1,549			Equity investments in unconsolidated subsidiaries	1,376		1,443
Other intangible assets, net of amortization of $156 and $62 at September 30, 2017 and December 31, 2016, respectively	902			970
Nuclear decommissioning trusts, at fair value	1,783			1,606
Leveraged leases	788			774
Other intangible assets, net of amortization of $367 and $340, respectively							Other intangible assets, net of amortization of $367 and $340, respectively	377		406

Miscellaneous property and investments	236			270			Miscellaneous property and investments	651		602
Total other property and investments	11,613			11,420			Total other property and investments	9,772		9,757
Deferred Charges and Other Assets:							Deferred Charges and Other Assets:
Operating lease right-of-use assets, net of amortization							Operating lease right-of-use assets, net of amortization	1,467		1,531
Deferred charges related to income taxes	1,318			1,629			Deferred charges related to income taxes	889		866
Prepaid pension costs							Prepaid pension costs	2,574		2,290

Unamortized loss on reacquired debt	210			223			Unamortized loss on reacquired debt	224		238
Deferred under recovered fuel clause revenues							Deferred under recovered fuel clause revenues	1,279		2,056
Regulatory assets – asset retirement obligations, deferred							Regulatory assets – asset retirement obligations, deferred	5,629		5,764
Other regulatory assets, deferred	6,718			6,851			Other regulatory assets, deferred	5,666		5,918

Other deferred charges and assets	1,513			1,406			Other deferred charges and assets	1,479		1,485
Total deferred charges and other assets	9,759			10,109			Total deferred charges and other assets	19,207		20,148
Total Assets	$	110,315		$	109,697		Total Assets	$	138,321	$	134,891


Liabilities and Stockholders' Equity	At September 30, 2017			At December 31, 2016			Liabilities and Stockholders' Equity	At September 30, 2023		At December 31, 2022
	(in millions)							(in millions)
Current Liabilities:							Current Liabilities:
Securities due within one year	$	3,505		$	2,587		Securities due within one year	$	3,076	$	4,285

Notes payable	2,579			2,241			Notes payable	1,726		2,609
Energy marketing trade payables	451			597

Accounts payable	2,353			2,228			Accounts payable	2,942		3,525
Customer deposits	550			558			Customer deposits	511		502
Accrued taxes —							Accrued taxes —
Accrued income taxes	176			193			Accrued income taxes	177		60
Unrecognized tax benefits	17			385

Other accrued taxes	690			667			Other accrued taxes	862		764
Accrued interest	443			518			Accrued interest	573		614

Accrued compensation	703			915			Accrued compensation	936		1,127
Asset retirement obligations, current	245			378
Acquisitions payable	—			489
Other regulatory liabilities, current	139			236
Asset retirement obligations							Asset retirement obligations	727		694
Liabilities from risk management activities, net of collateral							Liabilities from risk management activities, net of collateral	232		178

Operating lease obligations							Operating lease obligations	181		197
Natural gas cost over recovery							Natural gas cost over recovery	165		—
Other regulatory liabilities							Other regulatory liabilities	163		382
Other current liabilities	752			925			Other current liabilities	943		787
Total current liabilities	12,603			12,917			Total current liabilities	13,214		15,724
Long-term Debt	44,042			42,629			Long-term Debt	56,003		50,656
Deferred Credits and Other Liabilities:							Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	14,321			14,092			Accumulated deferred income taxes	10,774		10,036
Deferred credits related to income taxes							Deferred credits related to income taxes	4,813		5,235
Accumulated deferred ITCs	2,290			2,228			Accumulated deferred ITCs	2,071		2,133
Employee benefit obligations	2,139			2,299			Employee benefit obligations	1,184		1,238
Operating lease obligations, deferred							Operating lease obligations, deferred	1,320		1,388
Asset retirement obligations, deferred	4,356			4,136			Asset retirement obligations, deferred	9,872		10,146

Other cost of removal obligations	2,708			2,748			Other cost of removal obligations	1,940		1,903
Other regulatory liabilities, deferred	449			476			Other regulatory liabilities, deferred	660		733

Other deferred credits and liabilities	1,048			1,278			Other deferred credits and liabilities	1,166		1,167
Total deferred credits and other liabilities	27,311			27,257			Total deferred credits and other liabilities	33,800		33,979
Total Liabilities	83,956			82,803			Total Liabilities	103,017		100,359
Redeemable Preferred Stock of Subsidiaries	361			118
Redeemable Noncontrolling Interests	59			164
Stockholders' Equity:
Common Stockholders' Equity:
Common stock, par value $5 per share —
Authorized — 1.5 billion shares
Issued — September 30, 2017: 1.0 billion shares
— December 31, 2016: 991 million shares
Treasury — September 30, 2017: 0.9 million shares
— December 31, 2016: 0.8 million shares
Par value	5,018			4,952
Paid-in capital	10,300			9,661
Treasury, at cost	(35		)	(31		)
Retained earnings	8,981			10,356
Accumulated other comprehensive loss	(182		)	(180		)
Total Common Stockholders' Equity	24,082			24,758
Preferred and Preference Stock of Subsidiaries	462			609
Noncontrolling Interests	1,395			1,245
Total Stockholders' Equity	25,939			26,612

Total Stockholders' Equity (See accompanying statements)							Total Stockholders' Equity (See accompanying statements)	35,304		34,532
Total Liabilities and Stockholders' Equity	$	110,315		$	109,697		Total Liabilities and Stockholders' Equity	$	138,321	$	134,891


	Southern Company Common Stockholders' Equity
	Number of Common Shares		Common Stock								Accumulated Other Comprehensive Income (Loss)
	Issued	Treasury	Par Value		Paid-In Capital		Treasury		Retained Earnings				Noncontrolling Interests			Total
	(in millions)
Balance at December 31, 2021	1,061	(1)	$	5,279	$	11,950	$	(47)	$	10,929	$	(237)		$	4,402		$	32,276
Consolidated net income (loss)	—	—	—		—		—		1,032		—			(45)			987
Other comprehensive income	—	—	—		—		—		—		42			—			42
Stock issued	3	—	7		31		—		—		—			—			38
Stock-based compensation	—	—	—		6		—		—		—			—			6

Cash dividends of $0.66 per share	—	—	—		—		—		(702)		—			—			(702)

Capital contributions from noncontrolling interests	—	—	—		—		—		—		—			73			73
Distributions to noncontrolling interests	—	—	—		—		—		—		—			(98)			(98)



Other	—	—	—		7		(2)		2		—			—			7
Balance at March 31, 2022	1,064	(1)	5,286		11,994		(49)		11,261		(195)			4,332			32,629
Consolidated net income (loss)	—	—	—		—		—		1,107		—			(22)			1,085
Other comprehensive income	—	—	—		—		—		—		11			—			11
Stock issued	—	—	2		21		—		—		—			—			23
Stock-based compensation	—	—	—		14		—		—		—			—			14

Cash dividends of $0.68 per share	—	—	—		—		—		(723)		—			—			(723)


Distributions to noncontrolling interests	—	—	—		—		—		—		—			(28)			(28)




Other	—	—	—		4		(2)		—		—			—			2
Balance at June 30, 2022	1,064	(1)	5,288		12,033		(51)		11,645		(184)			4,282			33,013
Consolidated net income	—	—	—		—		—		1,472		—			12			1,484
Other comprehensive income	—	—	—		—		—		—		28			—			28

Stock issued	26	—	129		1,613		—		—		—			—			1,742
Stock-based compensation	—	—	—		15		—		—		—			—			15

Cash dividends of $0.68 per share	—	—	—		—		—		(741)		—			—			(741)


Distributions to noncontrolling interests	—	—	—		—		—		—		—			(57)			(57)




Other	—	—	—		(4)		(1)		(2)		(1)			—			(8)
Balance at September 30, 2022	1,090	(1)	$	5,417	$	13,657	$	(52)	$	12,374	$	(157)		$	4,237		$	35,476


Liabilities and Stockholder's Equity	At September 30, 2023		At December 31, 2022
	(in millions)
Current Liabilities:
Securities due within one year	$	522	$	301

Accounts payable —
Affiliated	305		443
Other	377		641
Customer deposits	105		106


Accrued taxes	305		57
Accrued interest	84		120

Accrued compensation	193		229

Asset retirement obligations	342		330
Other regulatory liabilities	28		96
Other current liabilities	158		91
Total current liabilities	2,419		2,414
Long-term Debt	10,661		10,329
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	4,082		3,981
Deferred credits related to income taxes	1,626		1,925
Accumulated deferred ITCs	76		81
Employee benefit obligations	146		145
Operating lease obligations	81		67
Asset retirement obligations, deferred	3,859		3,957

Other regulatory liabilities, deferred	284		315

Other deferred credits and liabilities	85		69
Total deferred credits and other liabilities	10,239		10,540
Total Liabilities	23,319		23,283









Common Stockholder's Equity (See accompanying statements)	12,351		11,687
Total Liabilities and Stockholder's Equity	$	35,670	$	34,970


	Number of Common Shares Issued	Common Stock		Paid-In Capital		Retained Earnings		Accumulated Other Comprehensive Income (Loss)		Total
	(in millions)
Balance at December 31, 2021	31	$	1,222	$	6,056	$	3,448	$	(13)	$	10,713
Net income after dividends on preferred stock	—	—		—		347		—		347

Capital contributions from parent company	—	—		626		—		—		626

Cash dividends on common stock	—	—		—		(254)		—		(254)

Balance at March 31, 2022	31	1,222		6,682		3,541		(13)		11,432
Net income after dividends on preferred stock	—	—		—		383		—		383

Capital contributions from parent company	—	—		32		—		—		32
Other comprehensive income	—	—		—		—		1		1
Cash dividends on common stock	—	—		—		(254)		—		(254)

Balance at June 30, 2022	31	1,222		6,714		3,670		(12)		11,594
Net income after dividends on preferred stock	—	—		—		525		—		525


Capital contributions from parent company	—	—		7		—		—		7
Other comprehensive income	—	—		—		—		2		2
Cash dividends on common stock	—	—		—		(254)		—		(254)

Balance at September 30, 2022	31	$	1,222	$	6,721	$	3,941	$	(10)	$	11,874

Balance at December 31, 2022	31	$	1,222	$	6,710	$	3,764	$	(9)	$	11,687
Net income after dividends on preferred stock	—	—		—		255		—		255

Capital contributions from parent company	—	—		330		—		—		330

Cash dividends on common stock	—	—		—		(285)		—		(285)

Balance at March 31, 2023	31	1,222		7,040		3,734		(9)		11,987
Net income after dividends on preferred stock	—	—		—		312		—		312

Capital contributions from parent company	—	—		29		—		—		29

Cash dividends on common stock	—	—		—		(286)		—		(286)

Balance at June 30, 2023	31	1,222		7,069		3,760		(9)		12,042
Net income after dividends on preferred stock	—	—		—		565		—		565


Capital contributions from parent company	—	—		28		—		—		28
Other comprehensive income	—	—		—		—		1		1
Cash dividends on common stock	—	—		—		(285)		—		(285)

Balance at September 30, 2023	31	$	1,222	$	7,097	$	4,040	$	(8)	$	12,351




Balance at December 31, 2022	$	1,069	$	1,741	$	(18)	$	2,792	$	4,124	$	6,916
Net income (loss)	—		102		—		102		(63)		39


Other comprehensive income (loss)	—		—		(7)		(7)		—		(7)
Cash dividends on common stock	—		(63)		—		(63)		—		(63)

Capital contributions from noncontrolling interests	—		—		—		—		21		21
Distributions to noncontrolling interests	—		—		—		—		(48)		(48)




Balance at March 31, 2023	1,069		1,780		(25)		2,824		4,034		6,858
Net income (loss)	—		85		—		85		(15)		70

Capital contributions from parent company	14		—		—		14		—		14
Other comprehensive income	—		—		10		10		—		10
Cash dividends on common stock	—		(63)		—		(63)		—		(63)


Distributions to noncontrolling interests	—		—		—		—		(42)		(42)




Other	—		—		1		1		(1)		—
Balance at June 30, 2023	1,083		1,802		(14)		2,871		3,976		6,847
Net income	—		100		—		100		10		110

Capital contributions from parent company	3		—		—		3		—		3
Other comprehensive income	—		—		4		4		—		4
Cash dividends on common stock	—		(63)		—		(63)		—		(63)


Distributions to noncontrolling interests	—		—		—		—		(59)		(59)



Other	1		—		—		1		—		1
Balance at September 30, 2023	$	1,087	$	1,839	$	(10)	$	2,916	$	3,927	$	6,843


	Paid-In Capital		Retained Earnings (Accumulated Deficit)		Accumulated Other Comprehensive Income (Loss)		Total
	(in millions)
Balance at December 31, 2021	$	10,024	$	(132)	$	24	$	9,916
Net income	—		319		—		319


Capital contributions from parent company	50		—		—		50
Other comprehensive income	—		—		20		20
Cash dividends on common stock	—		(130)		—		(130)

Balance at March 31, 2022	10,074		57		44		10,175
Net income	—		115		—		115

Capital contributions from parent company	312		—		—		312
Other comprehensive income (loss)	—		—		(12)		(12)
Cash dividends on common stock	—		(130)		—		(130)

Balance at June 30, 2022	10,386		42		32		10,460
Net income	—		83		—		83


Capital contributions from parent company	11		—		—		11
Other comprehensive income	—		—		14		14
Cash dividends on common stock	—		(130)		—		(130)

Balance at September 30, 2022	$	10,397	$	(5)	$	46	$	10,438

Balance at December 31, 2022	$	10,445	$	(79)	$	31	$	10,397
Net income	—		309		—		309


Capital contributions from parent company	203		—		—		203
Other comprehensive income (loss)	—		—		(10)		(10)
Cash dividends on common stock	—		(146)		—		(146)
Other	1		(1)		—		—
Balance at March 31, 2023	10,649		83		21		10,753
Net income	—		85		—		85


Capital contributions from parent company	40		—		—		40
Other comprehensive income	—		—		7		7
Cash dividends on common stock	—		(147)		—		(147)

Balance at June 30, 2023	10,689		21		28		10,738
Net income	—		82		—		82

Capital contributions from parent company	149		—		—		149
Other comprehensive income	—		—		10		10
Cash dividends on common stock	—		(146)		—		(146)

Balance at September 30, 2023	$	10,838	$	(43)	$	38	$	10,833


Note		Page
A	Introduction	44
B	Regulatory Matters	49
C	Contingencies	60
D	Revenue from Contracts with Customers and Lease Income	65
E	Consolidated Entities and Equity Method Investments	71
F	Financing and Leases	73
G	Income Taxes	76
H	Retirement Benefits	77
I	Fair Value Measurements	80
J	Derivatives	84
K	A cquisitions an d Dispositions	96
L	Segment and Related Information	96


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


	At September 30, 2023						At December 31, 2022
	Gross Carrying Amount		Accumulated Amortization		Other Intangible Assets, Net		Gross Carrying Amount		Accumulated Amortization		Other Intangible Assets, Net
	(in millions)						(in millions)
Southern Company
Subject to amortization:
Customer relationships	$	211	$	(169)	$	42	$	212	$	(162)	$	50
Trade names	63		(50)		13		64		(44)		20
PPA fair value adjustments	390		(143)		247		390		(129)		261
Other	5		(5)		—		5		(5)		—
Total subject to amortization	$	669	$	(367)	$	302	$	671	$	(340)	$	331
Not subject to amortization:
FCC licenses	75		—		75		75		—		75
Total other intangible assets	$	744	$	(367)	$	377	$	746	$	(340)	$	406

Southern Power(*)
PPA fair value adjustments	$	390	$	(143)	$	247	$	390	$	(129)	$	261

Southern Company Gas(*)

Gas marketing services
Customer relationships	$	156	$	(143)	$	13	$	156	$	(139)	$	17
Trade names	26		(20)		6		26		(17)		9
Total other intangible assets	$	182	$	(163)	$	19	$	182	$	(156)	$	26


	Southern Company(*)		Alabama Power		Georgia Power(*)		Mississippi Power
	(in millions)
Balance at December 31, 2022	$	216	$	97	$	83	$	36
Accrual	42		9		24		9
Weather-related damages	(242)		(35)		(204)		(3)
Balance at September 30, 2023	$	16	$	71	$	(97)	$	42


	Plant Farley
Decommissioning periods:
Beginning year	2037
Completion year	2087

	(in millions)
Site study costs:
Radiated structures	$	1,402
Spent fuel management	513
Non-radiated structures	133
Total site study costs	$	2,048


Regulatory Clause	Balance Sheet Line Item	September 30, 2023		December 31, 2022
		(in millions)
Alabama Power

Rate CNP Compliance	Other regulatory liabilities, deferred	$	3	$	—
	Other regulatory assets, current	—		47

Rate CNP PPA	Other regulatory assets, current	17		18
	Other regulatory assets, deferred	90		102


Retail Energy Cost Recovery	Other regulatory assets, current	208		102
	Other regulatory assets, deferred	80		520
Georgia Power
Fuel Cost Recovery(*)	Receivables – under recovered fuel clause revenues	$	730	$	—
	Deferred under recovered fuel clause revenues	1,279		2,056

Mississippi Power

Fuel Cost Recovery	Receivables – customer accounts, net	$	25	$	1
Ad Valorem Tax	Other regulatory assets, current	3		12
	Other regulatory assets, deferred	11		19


Southern Company Gas

Natural Gas Cost Recovery	Natural gas cost under recovery	$	—	$	108
	Natural gas cost over recovery	165		—



	Third Quarter 2017					Year-to-Date 2017
	(in millions)			(% change)		(in millions)			(% change)
Retail electric – prior year	$	4,808				$	11,932
Estimated change resulting from –
Rates and pricing	138			2.9		338			2.8
Sales decline	(52		)	(1.1	)	(74		)	(0.6	)
Weather	(162		)	(3.4	)	(351		)	(2.9	)
Fuel and other cost recovery	(117		)	(2.4	)	(59		)	(0.5	)
Retail electric – current year	$	4,615		(4.0	)%	$	11,786		(1.2	)%



	Third Quarter 2017 vs. Third Quarter 2016				Year-to-Date 2017 vs. Year-to-Date 2016
	(change in millions)			(% change)	(change in millions)		(% change)
Fuel	$	(115	)	(8.2)	$	38	1.1
Purchased power	29			12.8	65		11.2
Total fuel and purchased power expenses	$	(86	)		$	103



	Third Quarter 2017	Third Quarter 2016	Year-to-Date 2017	Year-to-Date 2016
Total generation (in billions of KWHs)	54	56	147	145
Total purchased power (in billions of KWHs)	6	6	14	15
Sources of generation (percent) —
Coal	31	38	30	33
Nuclear	15	15	16	16
Gas	47	44	46	46
Hydro	2	1	2	3
Other	5	2	6	2
Cost of fuel, generated (in cents per net KWH) —
Coal	2.82	2.97	2.82	3.10
Nuclear	0.80	0.81	0.80	0.82
Gas	2.92	2.74	2.93	2.40
Average cost of fuel, generated (in cents per net KWH)	2.54	2.54	2.51	2.38
Average cost of purchased power (in cents per net KWH)^(*)	4.96	4.98	5.32	4.75


~~(*)~~	~~Average cost of purchased power includes fuel purchased by the Southern Company system for tolling agreements where power is generated by the provider.~~



	(in billions)
Estimated cost to complete	$	4.2
CWIP as of September 30, 2017	4.6
Guarantee Obligations	(1.7		)
Estimated capital costs	$	7.1
Vogtle Cost Settlement Agreement Revised Forecast	(5.7		)
Estimated net additional capital costs	$	1.4

Third Quarter 2017 vs. Third Quarter 2016

Year-to-Date 2017 vs. Year-to-Date 2016

(change in millions)

(% change)

(change in millions)

(% change)