Regulatory Matters

9 Months Ended

Sep. 30, 2021

Regulated Operations [Abstract]

Regulatory Matters

REGULATORY MATTERS

See Note 2 to the financial statements in Item 8 of the Form 10-K for additional information relating to regulatory matters.

The recovery balances for certain retail regulatory clauses of the traditional electric operating companies and Southern Company Gas at September 30, 2021 and December 31, 2020 were as follows:

Regulatory Clause	Balance Sheet Line Item	September 30, 2021		December 31, 2020
		(in millions)
Alabama Power
Rate CNP Compliance	Other regulatory liabilities, current	$	—	$	28
	Other regulatory liabilities, deferred	24		—
Rate CNP PPA	Other regulatory assets, deferred	88		58
Retail Energy Cost Recovery	Other regulatory liabilities, current	—		18
	Other regulatory assets, current	79		—
	Other regulatory assets, deferred	6		—
Natural Disaster Reserve	Other regulatory liabilities, deferred	36		77
Georgia Power
Fuel Cost Recovery	Over recovered fuel clause revenues	$	—	$	113
	Other deferred charges and assets	203		—
Mississippi Power
Fuel Cost Recovery	Over recovered regulatory clause liabilities	$	5	$	24
Ad Valorem Tax	Other regulatory assets, current	12		11
	Other regulatory assets, deferred	39		41
Property Damage Reserve	Other regulatory liabilities, deferred	—		4
	Other regulatory assets, deferred	16		—
Southern Company Gas
Natural Gas Cost Recovery(*)	Other regulatory liabilities	$	—	$	88
	Natural gas cost under recovery	432		—
	Other regulatory assets, deferred	79		—

(*)The significant change during the nine months ended September 30, 2021 was primarily driven by an increase in the cost of gas purchased in February 2021 resulting from Winter Storm Uri.

Alabama Power

Certificate of Convenience and Necessity

Energy Alabama, Gasp, Inc., and the Sierra Club filed requests for reconsideration and rehearing with the Alabama PSC regarding the certificate of convenience and necessity (CCN) issued to Alabama Power in August 2020, which authorized, among other things, the construction of Plant Barry Unit 8 and the acquisition of the Central Alabama Generating Station. In December 2020, the Alabama PSC issued an order denying the requests. On January 7, 2021, Energy Alabama and Gasp, Inc. filed a judicial appeal regarding both the Alabama PSC's August 2020 CCN order and the December 2020 order denying reconsideration and rehearing. On March 9, 2021, the Circuit Court of Montgomery County, Alabama granted a motion by Alabama Power to intervene in the appeal. On August 27, 2021, the court affirmed both the August 2020 and December 2020 Alabama PSC orders. On October 7, 2021, Energy Alabama and Gasp, Inc. filed an unopposed motion for voluntary dismissal of their direct appeal previously

filed on January 7, 2021. This matter is now concluded. At September 30, 2021, expenditures associated with the construction of Plant Barry Unit 8 included in CWIP totaled approximately $222 million.

Plant Greene County

Alabama Power jointly owns Plant Greene County with an affiliate, Mississippi Power. See Note 5 under "Joint Ownership Agreements" in Item 8 of the Form 10-K for additional information.

On September 9, 2021, the Mississippi PSC issued an order confirming the conclusion of its review of Mississippi Power's 2021 IRP with no deficiencies identified. Mississippi Power's 2021 IRP includes a schedule to retire Mississippi Power's 40% ownership interest in Plant Greene County Units 1 and 2 in December 2025 and 2026, respectively, consistent with each unit's remaining useful life. The Plant Greene County unit retirements identified by Mississippi Power require the completion of transmission and system reliability improvements, as well as agreement by Alabama Power. Alabama Power will continue to monitor the status of the transmission and system reliability improvements. Currently, Alabama Power plans to retire Plant Greene County Units 1 and 2 at the dates indicated. The ultimate outcome of this matter cannot be determined at this time.

Rate NDR

Based on an order from the Alabama PSC, when Alabama Power's NDR balance falls below $50 million, a reserve establishment charge will be activated and the ongoing reserve maintenance charge will be concurrently suspended until the NDR balance reaches $75 million. At September 30, 2021, Alabama Power's NDR balance was $36 million. Effective with October 2021 billings, the reserve maintenance charge component of Rate NDR was suspended and the reserve establishment charge was activated. Alabama Power expects to collect approximately $4 million in the fourth quarter 2021 and $16 million annually under Rate NDR until the NDR balance is restored to $75 million.

Calhoun Generating Station Acquisition

On September 23, 2021, Alabama Power entered into an agreement to acquire all of the equity interests in Calhoun Power Company, LLC, which owns and operates a 743-MW winter peak, simple-cycle, combustion turbine generation facility in Calhoun County, Alabama (Calhoun Generating Station). The total purchase price associated with the acquisition is approximately $180 million, subject to working capital adjustments. The completion of the acquisition is subject to the satisfaction and waiver of certain conditions, including, among other customary conditions, approval by the Alabama PSC and the FERC, as well as the expiration or termination of the waiting period under the Hart-Scott-Rodino Antitrust Improvements Act. Alabama Power expects to complete the transaction by September 30, 2022.

On October 28, 2021, Alabama Power filed a petition for a CCN with the Alabama PSC to procure additional generating capacity through the acquisition of the Calhoun Generating Station.

Upon certification, Alabama Power expects to recover costs associated with the Calhoun Generating Station through its existing rate structure, primarily Rate CNP New Plant, Rate CNP Compliance, Rate ECR, and Rate RSE.

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

Georgia Power

Rate Plan

Effective January 1, 2021, Georgia Power reduced its amortization of costs associated with CCR AROs by approximately $90 million as approved by the Georgia PSC in conjunction with Georgia Power's annual compliance filings.

In February 2020, the Georgia PSC denied a motion for reconsideration filed by the Sierra Club regarding the Georgia PSC's decision in the 2019 ARP allowing Georgia Power to recover compliance costs for CCR AROs, and, in December 2020, the Superior Court of Fulton County affirmed the decision of the Georgia PSC. On October 25,

2021, the Georgia Court of Appeals affirmed the Superior Court of Fulton County's December 2020 order. On November 3, 2021, the Sierra Club filed a motion for reconsideration with the Georgia Court of Appeals. The ultimate outcome of this matter cannot be determined at this time.

In accordance with the terms of the 2019 ARP, on October 1, 2021, Georgia Power filed the following tariff adjustments to become effective January 1, 2022 pending approval by the Georgia PSC:

•increase traditional base tariffs by approximately $192 million;

•decrease the ECCR tariff by approximately $12 million;

•decrease Demand-Side Management tariffs by approximately $25 million; and

•increase Municipal Franchise Fee tariffs by approximately $2 million.

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

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

Plant Vogtle Unit 3 and Common Facilities Rate Proceeding

On June 15, 2021, Georgia Power filed an application with the Georgia PSC to adjust retail base rates to include the portion of costs related to its investment in Plant Vogtle Unit 3 and the common facilities shared between Plant Vogtle Units 3 and 4 (Common Facilities) previously deemed prudent by the Georgia PSC ($2.38 billion), as well as the related costs of operation. On November 2, 2021, the Georgia PSC voted to approve Georgia Power's application as filed, with the following modifications pursuant to a stipulated agreement between Georgia Power and the staff of the Georgia PSC. Georgia Power will include in rate base $2.1 billion of the $2.38 billion previously deemed prudent by the Georgia PSC and will recover the related depreciation expense through retail base rates. Financing costs on the remaining portion of the total Unit 3 and the Common Facilities construction costs will continue to be recovered through the NCCR tariff or deferred. Georgia Power will defer as a regulatory asset the remaining depreciation expense (approximately $38 million annually) until Unit 4 costs are placed in retail base rates. In addition, the stipulated agreement clarified that following the prudency review, the remaining amount to be placed in retail base rates will be net of the proceeds from the Guarantee Settlement Agreement and will not be used to offset imprudent costs, if any.

The related increase in annual retail base rates of approximately $302 million also includes recovery of all projected operations and maintenance expenses for Unit 3 and the Common Facilities and other related costs of operation, partially offset by the related production tax credits, and will become effective the month after Unit 3 is placed in service. This increase will be partially offset by a decrease in the NCCR tariff of approximately $78 million expected to be effective January 1, 2022.

See "Nuclear Construction" herein for additional information on Plant Vogtle Units 3 and 4.

Deferral of Incremental COVID-19 Costs

Since June 2021, Georgia Power has continued a review of bad debt amounts deferred under the Georgia PSC-approved methodology, including consideration of actual amounts repaid by customers from arrears and installment plans after the disconnection moratorium period ended in July 2020. As a result, Georgia Power has reduced the balance of deferred incremental costs by a total of approximately $23 million through September 30, 2021. At September 30, 2021, the incremental costs deferred totaled approximately $20 million, including approximately $1 million of incremental bad debt costs and $19 million of other incremental costs. The period over which these costs will be recovered is expected to be determined in Georgia Power's next base rate case. The ultimate outcome of this matter cannot be determined at this time.

Fuel Cost Recovery

Georgia Power has established fuel cost recovery rates approved by the Georgia PSC. On October 12, 2021, Georgia Power filed a notification and plan with the Georgia PSC to implement an interim fuel rider and increase

fuel rates by 15% effective January 1, 2022, which is expected to increase annual billings by approximately $252 million. The Georgia PSC has 30 days from the filing to approve the plan; however, if the Georgia PSC elects to take no action, the new rates become effective as requested. Georgia Power is currently scheduled to file its next fuel case by February 28, 2023. The ultimate outcome of this matter cannot be determined at this time.

Nuclear Construction

In 2009, the Georgia PSC certified construction of Plant Vogtle Units 3 and 4, in which Georgia Power holds a 45.7% ownership interest. In 2012, the NRC issued the related combined construction and operating licenses, which allowed full construction of the two AP1000 nuclear units (with electric generating capacity of approximately 1,100 MWs each) and related facilities to begin. Until March 2017, construction on Plant Vogtle Units 3 and 4 continued under the Vogtle 3 and 4 Agreement, which was a substantially fixed price agreement.

In connection with the EPC Contractor's bankruptcy filing in March 2017, Georgia Power, acting for itself and as agent for the other Vogtle Owners, entered into several transitional arrangements to allow construction to continue. In July 2017, Georgia Power, acting for itself and as agent for the other Vogtle Owners, entered into the Vogtle Services Agreement, whereby Westinghouse provides facility design and engineering services, procurement and technical support, and staff augmentation on a time and materials cost basis. The Vogtle Services Agreement provides that it will continue until the start-up and testing of Plant Vogtle Units 3 and 4 are complete and electricity is generated and sold from both units. The Vogtle Services Agreement is terminable by the Vogtle Owners upon 30 days' written notice.

In October 2017, Georgia Power, acting for itself and as agent for the other Vogtle Owners, executed the Bechtel Agreement, a cost reimbursable plus fee arrangement, whereby Bechtel is reimbursed for actual costs plus a base fee and an at-risk fee, which is subject to adjustment based on Bechtel's performance against cost and schedule targets. Each Vogtle Owner is severally (not jointly) liable for its proportionate share, based on its ownership interest, of all amounts owed to Bechtel under the Bechtel Agreement. The Vogtle Owners may terminate the Bechtel Agreement at any time for their convenience, provided that the Vogtle Owners will be required to pay amounts related to work performed prior to the termination (including the applicable portion of the base fee), certain termination-related costs, and, at certain stages of the work, the applicable portion of the at-risk fee. Bechtel may terminate the Bechtel Agreement under certain circumstances, including certain Vogtle Owner suspensions of work, certain breaches of the Bechtel Agreement by the Vogtle Owners, Vogtle Owner insolvency, and certain other events.

See Note 8 to the financial statements under "Long-term Debt – DOE Loan Guarantee Borrowings" in Item 8 of the Form 10-K for information on the Amended and Restated Loan Guarantee Agreement, including applicable covenants, events of default, mandatory prepayment events, and conditions to borrowing.

Cost and Schedule

Georgia Power's approximate proportionate share of the remaining estimated capital cost to complete Plant Vogtle Units 3 and 4, including contingency, through September 2022 and June 2023, respectively, is as follows:

	(in millions)
Base project capital cost forecast(a)(b)	$	9,342
Construction contingency estimate	137
Total project capital cost forecast(a)(b)	9,479
Net investment at September 30, 2021(b)	(8,159)
Remaining estimate to complete	$	1,320

(a)    Includes approximately $570 million of costs that are not shared with the other Vogtle Owners. Excludes financing costs expected to be capitalized through AFUDC of approximately $318 million, of which $169 million had been accrued through September 30, 2021.

(b)    Net of $1.7 billion received from Toshiba under the Guarantee Settlement Agreement and approximately $188 million in related customer refunds.

Georgia Power estimates that its financing costs for construction of Plant Vogtle Units 3 and 4 will total approximately $3.2 billion, of which $2.8 billion had been incurred through September 30, 2021.

As part of its ongoing processes, Southern Nuclear continues to evaluate cost and schedule forecasts on a regular basis to incorporate current information available, particularly in the areas of engineering support, commodity installation, system turnovers and related test results, and workforce statistics. Southern Nuclear establishes aggressive target values for monthly construction production and system turnover activities. Southern Nuclear's site work plans continue to reflect this approach in support of safely completing Units 3 and 4, while achieving the required construction quality.

In mid-March 2020, Southern Nuclear began implementing policies and procedures designed to mitigate the risk of transmission of COVID-19 at the construction site, including worker distancing measures; isolating individuals who tested positive for COVID-19, showed symptoms consistent with COVID-19, were being tested for COVID-19, or were in close contact with such persons; requiring self-quarantine; and adopting additional precautionary measures. Since March 2020, the number of active cases at the site has fluctuated and impacted productivity levels and pace of activity completion. Through June 2021, the site experienced an overall decline in the number of active cases since the peak in January 2021. During the third quarter 2021, the site experienced a similar peak in August 2021; however, the number of active cases since this peak has declined. The lower productivity levels and slower pace of activity completion experienced since March 2020 contributed to a backlog to the aggressive site work plan established at the beginning of 2020. Georgia Power estimates the productivity impacts of the COVID-19 pandemic have consumed approximately three to four months of schedule margin previously embedded in the site work plan for Unit 3 and Unit 4. In addition, the project continued to face challenges including, but not limited to, higher than expected absenteeism; overall construction and subcontractor labor productivity; system turnover and testing activities; and electrical equipment and commodity installation. As a result of these factors, in January 2021, Southern Nuclear further extended certain milestone dates, including the start of hot functional testing and fuel load for Unit 3, from those established in October 2020.

Following the January 2021 milestone extensions, Southern Nuclear has been performing additional construction remediation work necessary to ensure quality and design standards are met as system turnovers are completed to support hot functional testing, which was completed in July 2021, and fuel load for Unit 3. As a result of challenges including, but not limited to, construction productivity, construction remediation work, the pace of system turnovers, spent fuel pool repairs, and the timeframe and duration for hot functional and other testing, at the end of the second quarter 2021, Southern Nuclear further extended certain milestone dates, including the fuel load for Unit 3, from those established in January 2021. Through the third quarter 2021, the project continued to face challenges including, but not limited to, construction productivity, construction remediation work, and the pace of system turnovers. As a result of these continued challenges, at the end of the third quarter 2021, Southern Nuclear further extended certain milestone dates, including fuel load for Unit 3, from those established at the end of the second quarter 2021. The site work plan currently targets fuel load for Unit 3 in the first quarter 2022 and an in-service date of May 2022 and primarily depends on significant improvements in overall construction productivity and production levels, the volume of construction remediation work, the pace of system and area turnovers, and the progression of startup and other testing. As the site work plan includes minimal margin to these milestone dates, an in-service date in the third quarter 2022 for Unit 3 is projected, although any further delays could result in a later in-service date.

As the result of productivity challenges, at the end of the second quarter 2021, Southern Nuclear also further extended milestone dates for Unit 4 from those established in January 2021. These productivity challenges continued into the third quarter 2021 and some craft and support resources were diverted temporarily to support construction efforts on Unit 3. As a result of these factors, at the end of the third quarter 2021, Southern Nuclear further extended the milestone dates for Unit 4 from those established at the end of the second quarter 2021. The site work plan targets an in-service date of March 2023 for Unit 4 and primarily depends on overall construction productivity and production levels significantly improving as well as appropriate levels of craft laborers, particularly electricians and pipefitters, being added and maintained. As the site work plan includes minimal margin

to the milestone dates, an in-service date in the second quarter 2023 for Unit 4 is projected, although any further delays could result in a later in-service date.

As of March 31, 2021, approximately $84 million of the construction contingency established in the fourth quarter 2020 was assigned to the base capital cost forecast for costs primarily associated with the schedule extension for Unit 3 to December 2021, construction productivity, support resources, and construction remediation work. Georgia Power increased its total capital cost forecast as of March 31, 2021 by adding $48 million to the remaining construction contingency. As of June 30, 2021, all of the remaining construction contingency previously established and an additional $341 million was assigned to the base capital cost forecast for costs primarily associated with the schedule extensions for Units 3 and 4, construction remediation work for Unit 3, and construction productivity and support resources for Units 3 and 4. Georgia Power also increased its total capital cost forecast as of June 30, 2021 by adding $119 million to replenish construction contingency. As a result of the factors discussed above, during the third quarter 2021, all of the remaining construction contingency previously established in the second quarter 2021 and an additional $127 million was assigned to the base capital cost forecast for costs primarily associated with the schedule extensions for Units 3 and 4, construction productivity and support resources for Units 3 and 4, and construction remediation work for Unit 3. Georgia Power also increased its total capital cost forecast as of September 30, 2021 by adding $137 million to replenish construction contingency.

After considering the significant level of uncertainty that exists regarding the future recoverability of these costs since the ultimate outcome of these matters is subject to the outcome of future assessments by management, as well as Georgia PSC decisions in future regulatory proceedings, Georgia Power recorded pre-tax charges to income in the first quarter 2021, the second quarter 2021, and the third quarter 2021 of $48 million ($36 million after tax), $460 million ($343 million after tax), and $264 million ($197 million after tax), respectively, for the increases in the total project capital cost forecast. As and when these amounts are spent, Georgia Power may request the Georgia PSC to evaluate those expenditures for rate recovery.

In addition, the continuing effects of the COVID-19 pandemic could further disrupt or delay construction and testing activities at Plant Vogtle Units 3 and 4. Georgia Power's proportionate share of the estimated incremental cost associated with COVID-19 mitigation actions and impacts on construction productivity is currently estimated to be between $160 million and $200 million and is included in the total project capital cost forecast.

As construction, including subcontract work, continues and testing and system turnover activities increase, ongoing or future challenges with management of contractors and vendors; subcontractor performance; supervision of craft labor and related productivity, particularly in the installation of electrical, mechanical, and instrumentation and controls commodities, ability to attract and retain craft labor, and/or related cost escalation; procurement, fabrication, delivery, assembly, installation, system turnover, and the initial testing and start-up, including any required engineering changes or any remediation related thereto, of plant systems, structures, or components (some of which are based on new technology that only within the last few years began initial operation in the global nuclear industry at this scale), including the spent fuel pools, any of which may require additional labor and/or materials; or other issues could continue or arise and change the projected schedule and estimated cost.

There have been technical and procedural challenges to the construction and licensing of Plant Vogtle Units 3 and 4 at the federal and state level and additional challenges may arise. Processes are in place that are designed to ensure compliance with the requirements specified in the Westinghouse Design Control Document and the combined construction and operating licenses, including inspections by Southern Nuclear and the NRC that occur throughout construction. In connection with the additional construction remediation work described above, Southern Nuclear reviewed the project's construction quality programs and, where needed, is implementing improvement plans consistent with these processes. In June 2021, the NRC began a special inspection to review the root cause of this additional construction remediation work and the corresponding corrective action plans. On August 26, 2021, the NRC issued an inspection report with initial findings. Southern Nuclear had already identified and self-reported many of the issues in this report to the NRC and implemented corrective-action plans to resolve these issues. Southern Nuclear responded to the NRC's initial findings on October 5, 2021 and expects a final report from the NRC by November 24, 2021. Findings resulting from this or other inspections could require additional remediation

and/or further NRC oversight. In addition, certain license amendment requests have been filed and approved or are pending before the NRC. On March 15, 2021, the NRC denied the Blue Ridge Environmental Defense League's (BREDL) December 2020 motion to reopen proceedings on BREDL's petition challenging a requested license amendment, which has been issued by the NRC staff.

The site work plan currently targets fuel load for Unit 3 in the first quarter 2022. Various design and other licensing-based compliance matters, including the timely submittal by Southern Nuclear of the ITAAC documentation for each unit and the related reviews and approvals by the NRC necessary to support NRC authorization to load fuel, have arisen or may arise, which may result in additional license amendments or require other resolution. If any license amendment requests or other licensing-based compliance issues, including inspections and ITAACs, are not resolved in a timely manner, there may be delays in the project schedule that could result in increased costs.

The ultimate outcome of these matters cannot be determined at this time. However, any extension of the in-service date beyond the third quarter 2022 for Unit 3 or the second quarter 2023 for Unit 4 is currently estimated to result in additional base capital costs for Georgia Power of approximately $25 million per month for Unit 3 and approximately $15 million per month for Unit 4, as well as the related AFUDC and any additional related construction or testing costs. While Georgia Power is not precluded from seeking recovery of any future capital cost forecast increase, management will ultimately determine whether or not to seek recovery. Any further changes to the capital cost forecast that are not expected to be recoverable through regulated rates will be required to be charged to income and such charges could be material.

Joint Owner Contracts

In November 2017, the Vogtle Owners entered into an amendment to their joint ownership agreements for Plant Vogtle Units 3 and 4 to provide for, among other conditions, additional Vogtle Owner approval requirements. Effective in August 2018, the Vogtle Owners further amended the joint ownership agreements to clarify and provide procedures for certain provisions of the joint ownership agreements related to adverse events that require the vote of the holders of at least 90% of the ownership interests in Plant Vogtle Units 3 and 4 to continue construction (as amended, and together with the November 2017 amendment, the Vogtle Joint Ownership Agreements). The Vogtle Joint Ownership Agreements also confirm that the Vogtle Owners' sole recourse against Georgia Power or Southern Nuclear for any action or inaction in connection with their performance as agent for the Vogtle Owners is limited to removal of Georgia Power and/or Southern Nuclear as agent, except in cases of willful misconduct.

As a result of an increase in the total project capital cost forecast and Georgia Power's decision not to seek rate recovery of the increase in the base capital costs in conjunction with the nineteenth VCM report in 2018, the holders of at least 90% of the ownership interests in Plant Vogtle Units 3 and 4 were required to vote to continue construction. In September 2018, the Vogtle Owners unanimously voted to continue construction of Plant Vogtle Units 3 and 4.

Amendments to the Vogtle Joint Ownership Agreements

In connection with the vote to continue construction, Georgia Power entered into (i) a binding term sheet (Vogtle Owner Term Sheet) with the other Vogtle Owners and MEAG Power's wholly-owned subsidiaries MEAG Power SPVJ, LLC (MEAG SPVJ), MEAG Power SPVM, LLC (MEAG SPVM), and MEAG Power SPVP, LLC (MEAG SPVP) to take certain actions which partially mitigate potential financial exposure for the other Vogtle Owners, including additional amendments to the Vogtle Joint Ownership Agreements and the purchase of PTCs from the other Vogtle Owners at pre-established prices, and (ii) a term sheet (MEAG Term Sheet) with MEAG Power and MEAG SPVJ to provide up to $300 million of funding with respect to MEAG SPVJ's ownership interest in Plant Vogtle Units 3 and 4 under certain circumstances. In January 2019, Georgia Power, MEAG Power, and MEAG SPVJ entered into an agreement to implement the provisions of the MEAG Term Sheet. In February 2019, Georgia Power, the other Vogtle Owners, and MEAG Power's wholly-owned subsidiaries MEAG SPVJ, MEAG SPVM, and MEAG SPVP entered into certain amendments to the Vogtle Joint Ownership Agreements to implement the provisions of the Vogtle Owner Term Sheet (Global Amendments).

As previously disclosed, pursuant to the Global Amendments: (i) each Vogtle Owner must pay its proportionate share of qualifying construction costs for Plant Vogtle Units 3 and 4 based on its ownership percentage up to the estimated cost at completion (EAC) for Plant Vogtle Units 3 and 4 which formed the basis of Georgia Power's forecast of $8.4 billion in the nineteenth VCM plus $800 million; (ii) Georgia Power will be responsible for 55.7% of actual qualifying construction costs between $800 million and $1.6 billion over the EAC in the nineteenth VCM (resulting in $80 million of potential additional costs to Georgia Power), with the remaining Vogtle Owners responsible for 44.3% of such costs pro rata in accordance with their respective ownership interests; and (iii) Georgia Power will be responsible for 65.7% of qualifying construction costs between $1.6 billion and $2.1 billion over the EAC in the nineteenth VCM (resulting in a further $100 million of potential additional costs to Georgia Power), with the remaining Vogtle Owners responsible for 34.3% of such costs pro rata in accordance with their respective ownership interests. If the EAC is revised and exceeds the EAC in the nineteenth VCM by more than $2.1 billion, each of the other Vogtle Owners will have a one-time option at the time the project budget forecast is so revised to tender a portion of its ownership interest to Georgia Power in exchange for Georgia Power's agreement to pay 100% of such Vogtle Owner's remaining share of total construction costs in excess of the EAC in the nineteenth VCM plus $2.1 billion.

In addition, pursuant to the Global Amendments, the holders of at least 90% of the ownership interests in Plant Vogtle Units 3 and 4 must vote to continue construction if certain adverse events occur, including, among other events: (i) the bankruptcy of Toshiba; (ii) the termination or rejection in bankruptcy of certain agreements, including the Vogtle Services Agreement, the Bechtel Agreement, or the agency agreement with Southern Nuclear; (iii) Georgia Power's public announcement of its intention not to submit for rate recovery any portion of its investment in Plant Vogtle Units 3 and 4 or the Georgia PSC determines that any of Georgia Power's costs relating to the construction of Plant Vogtle Units 3 and 4 will not be recovered in retail rates, excluding any additional amounts paid by Georgia Power on behalf of the other Vogtle Owners pursuant to the Global Amendments described above and the first 6% of costs during any six-month VCM reporting period that are disallowed by the Georgia PSC for recovery, or for which Georgia Power elects not to seek cost recovery, through retail rates; and (iv) an incremental extension of one year or more over the most recently approved schedule.

Georgia Power and the other Vogtle Owners do not agree on either the starting dollar amount for the determination of cost increases subject to the cost-sharing and tender provisions of the Global Amendments or the extent to which COVID-19-related costs impact the calculation. Based on the definition in the Global Amendments, Georgia Power believes the starting dollar amount is $18.38 billion and does not believe estimated project costs have reached a level where cost-sharing would be triggered. However, the other Vogtle Owners have asserted the cost increases through September 30, 2021 have reached the cost-sharing thresholds and could be sufficient to trigger the tender provisions under the Global Amendments, which could require Georgia Power to record additional pre-tax charges to income of up to approximately $350 million. On October 29, 2021, Georgia Power and the other Vogtle Owners entered into an agreement to clarify the process for the tender provisions of the Global Amendments, which will provide additional time to resolve these matters.

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

Regulatory Matters

In 2009, the Georgia PSC voted to certify construction of Plant Vogtle Units 3 and 4 with a certified capital cost of $4.418 billion. In addition, in 2009 the Georgia PSC approved inclusion of the Plant Vogtle Units 3 and 4 related CWIP accounts in rate base, and the State of Georgia enacted the Georgia Nuclear Energy Financing Act, which allows Georgia Power to recover financing costs for Plant Vogtle Units 3 and 4. Financing costs are recovered on all applicable certified costs through annual adjustments to the NCCR tariff up to the certified capital cost of $4.418 billion. At September 30, 2021, Georgia Power had recovered approximately $2.7 billion of financing costs. Financing costs related to capital costs above $4.418 billion are being recognized through AFUDC and are expected to be recovered through retail rates over the life of Plant Vogtle Units 3 and 4; however, Georgia Power will not record AFUDC related to any capital costs in excess of the total deemed reasonable by the Georgia PSC (currently

$7.3 billion) and not requested for rate recovery. On October 1, 2021, Georgia Power filed a request to decrease the NCCR tariff by $78 million annually, effective January 1, 2022, pending approval by the Georgia PSC.

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

In 2016, the Georgia PSC voted to approve a settlement agreement (Vogtle Cost Settlement Agreement) resolving certain prudency matters in connection with the fifteenth VCM report. In December 2017, the Georgia PSC voted to approve (and issued its related order on January 11, 2018) Georgia Power's seventeenth VCM report and modified the Vogtle Cost Settlement Agreement. The Vogtle Cost Settlement Agreement, as modified by the January 11, 2018 order, resolved the following regulatory matters related to Plant Vogtle Units 3 and 4: (i) none of the $3.3 billion of costs incurred through December 31, 2015 and reflected in the fourteenth VCM report should be disallowed from rate base on the basis of imprudence; (ii) the Contractor Settlement Agreement was reasonable and prudent and none of the $0.3 billion paid pursuant to the Contractor Settlement Agreement should be disallowed from rate base on the basis of imprudence; (iii) (a) capital costs incurred up to $5.68 billion would be presumed to be reasonable and prudent with the burden of proof on any party challenging such costs, (b) Georgia Power would have the burden to show that any capital costs above $5.68 billion were prudent, and (c) a revised capital cost forecast of $7.3 billion (after reflecting the impact of payments received under the Guarantee Settlement Agreement and related customer refunds) was found reasonable; (iv) construction of Plant Vogtle Units 3 and 4 should be completed, with Southern Nuclear serving as project manager and Bechtel as primary contractor; (v) approved and deemed reasonable Georgia Power's revised schedule placing Plant Vogtle Units 3 and 4 in service in November 2021 and November 2022, respectively; (vi) confirmed that the revised cost forecast does not represent a cost cap and that a prudence proceeding on cost recovery will occur following Unit 4 fuel load, consistent with applicable Georgia law; (vii) reduced the ROE used to calculate the NCCR tariff (a) from 10.95% (the ROE rate setting point authorized by the Georgia PSC in the 2013 alternate rate plan) to 10.00% effective January 1, 2016, (b) from 10.00% to 8.30%, effective January 1, 2020, and (c) from 8.30% to 5.30%, effective January 1, 2021 (provided that the ROE in no case will be less than Georgia Power's average cost of long-term debt); (viii) reduced the ROE used for AFUDC equity for Plant Vogtle Units 3 and 4 from 10.00% to Georgia Power's average cost of long-term debt, effective January 1, 2018; and (ix) agreed that effective the first month after Unit 3 reaches commercial operation, retail base rates would be adjusted to include the costs related to Unit 3 and common facilities deemed prudent in the Vogtle Cost Settlement Agreement. The January 11, 2018 order also stated that if Plant Vogtle Units 3 and 4 are not commercially operational by June 1, 2021 and June 1, 2022, respectively, the ROE used to calculate the NCCR tariff will be further reduced by 10 basis points each month (but not lower than Georgia Power's average cost of long-term debt) until the respective Unit is commercially operational. The ROE reductions negatively impacted earnings by approximately $150 million in 2020 and are estimated to have negative earnings impacts of approximately $270 million, $260 million, and $135 million in 2021, 2022, and 2023, respectively. In its January 11, 2018 order, the Georgia PSC also stated if other conditions change and assumptions upon which Georgia Power's seventeenth VCM report are based do not materialize, the Georgia PSC reserved the right to reconsider the decision to continue construction.

The Georgia PSC has approved 24 VCM reports covering periods through December 31, 2020, including total construction capital costs incurred through December 31, 2020 of $7.3 billion (net of $1.7 billion of payments received under the Guarantee Settlement Agreement and approximately $188 million in related customer refunds). In the August 24, 2021 order approving the twenty-fourth VCM report, the Georgia PSC also approved a stipulation addressing the following matters: (i) beginning with its twenty-fifth VCM report, Georgia Power will continue to report to the Georgia PSC all costs incurred during the period for review and will request for approval costs up to the $7.3 billion determined to be reasonable in the Georgia PSC's seventeenth VCM order and (ii) Georgia Power will not seek rate recovery of the $0.7 billion increase to the base capital cost forecast included in the nineteenth VCM report and charged to income by Georgia Power in the second quarter 2018. In addition, the stipulation

confirms Georgia Power may request verification and approval of costs above $7.3 billion for inclusion in rate base at a later time, but no earlier than the prudence review contemplated by the seventeenth VCM order described previously. Georgia Power filed its twenty-fifth VCM report with the Georgia PSC on August 31, 2021, which reflects the revised capital cost forecast as of June 30, 2021 of $9.2 billion (net of $1.7 billion of payments received under the Guarantee Settlement Agreement and approximately $188 million in related customer refunds). See "Plant Vogtle Unit 3 and Common Facilities Rate Proceeding" herein for information on Georgia Power's request to adjust retail base rates to include a portion of costs related to its investment in Plant Vogtle Unit 3 and Common Facilities.

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

Mississippi Power

Performance Evaluation Plan

On June 8, 2021, the Mississippi PSC approved Mississippi Power's annual retail PEP filing for 2021, resulting in an annual increase in revenues of approximately $16 million, or 1.8%, which became effective with the first billing cycle of April 2021 in accordance with the PEP rate schedule.

Integrated Resource Plan

In December 2020, the Mississippi PSC issued an order in the Reserve Margin Plan docket requiring Mississippi Power to incorporate into its 2021 IRP a schedule reflecting the retirement of 950 MWs of fossil-steam generation by year-end 2027 to reduce Mississippi Power's excess reserve margin. On September 9, 2021, the Mississippi PSC issued an order confirming the conclusion of its review of Mississippi Power's 2021 IRP with no deficiencies identified. The 2021 IRP includes a schedule to retire Plant Watson Unit 4 (268 MWs) and Mississippi Power's 40% ownership interest in Plant Greene County Units 1 and 2 (103 MWs each) in December 2023, 2025, and 2026, respectively, consistent with each unit's remaining useful life in the most recent approved depreciation studies. In addition, the schedule reflects the early retirement of Mississippi Power's 50% undivided ownership interest in Plant Daniel Units 1 and 2 (502 MWs) by the end of 2027. The Plant Greene County unit retirements require the completion by Alabama Power of transmission and system reliability improvements, as well as agreement by Alabama Power.

The remaining net book value of Plant Daniel Units 1 and 2 was approximately $520 million at September 30, 2021 and Mississippi Power is continuing to depreciate these units using the current approved rates through the end of 2027. Mississippi Power expects to reclassify the net book value remaining at retirement, which is expected to total approximately $390 million, to a regulatory asset to be amortized over a period to be determined by the Mississippi PSC in future proceedings, consistent with the December 2020 order. The Plant Watson and Greene County units are expected to be fully depreciated upon retirement. The ultimate outcome of these matters cannot be determined at this time.

Environmental Compliance Overview Plan

On June 8, 2021, the Mississippi PSC approved Mississippi Power's ECO Plan filing for 2021, resulting in an annual decrease in revenues of approximately $9 million, primarily due to a change in the amortization periods of certain regulatory assets and liabilities. The rate decrease became effective with the first billing cycle of July 2021.

Ad Valorem Tax Adjustment

On April 6, 2021, the Mississippi PSC approved Mississippi Power's annual ad valorem tax adjustment filing for 2021, which requested an annual increase in revenues of approximately $28 million, including approximately $19 million of ad valorem taxes previously recovered through PEP in accordance with the Mississippi Power Rate Case Settlement Agreement. The rate increase became effective with the first billing cycle of May 2021.

System Restoration Rider

On October 14, 2021, the Mississippi PSC issued an accounting order giving Mississippi Power the authority to reclassify the retail costs associated with Hurricanes Zeta and Ida to a regulatory asset to be recovered through PEP over a period to be determined in Mississippi Power's 2022 PEP proceeding. At September 30, 2021, these costs totaled approximately $49 million.

On October 25, 2021, Mississippi Power made its annual System Restoration Rider filing with the Mississippi PSC, which requested an annual increase in retail revenues of approximately $9 million primarily for an increase in the property damage reserve accrual. The requested increase is expected to become effective with the first billing cycle following approval by the Mississippi PSC. The filing excludes recovery of the costs associated with Hurricanes Zeta and Ida.

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

Southern Company Gas

Infrastructure Replacement Programs and Capital Projects

Capital expenditures incurred under specific infrastructure replacement programs during the first nine months of 2021 were as follows:

Utility	Program	Nine Months Ended September 30, 2021
		(in millions)
Nicor Gas	Investing in Illinois	$	307
Virginia Natural Gas	Steps to Advance Virginia's Energy	36
Total		$	343

Atlanta Gas Light

On April 28, 2021, Atlanta Gas Light filed its first Integrated Capacity and Delivery Plan (i-CDP) with the Georgia PSC, which includes a series of ongoing and proposed pipeline safety, reliability, and growth programs for the next 10 years (2022 through 2031), as well as the required capital investments and related costs to implement the programs. The i-CDP reflects capital investments totaling approximately $0.5 billion to $0.6 billion annually.

Recovery of the related revenue requirements will be included in either subsequent annual GRAM filings or the new System Reinforcement Rider for authorized large pressure improvement and system reliability projects. On October 14, 2021, Atlanta Gas Light and the staff of the Georgia PSC filed a joint stipulation agreement, under which, for the years 2022 through 2024, Atlanta Gas Light would incrementally reduce its combined GRAM and System Reinforcement Rider request by 10% through Atlanta Gas Light's GRAM mechanism, or $5 million for 2022 based on the initial July 21, 2021 GRAM filing. The stipulation agreement also would provide for $1.7 billion of total capital investment for the years 2022 through 2024. The Georgia PSC is scheduled to vote on this matter later in November 2021. The ultimate outcome of this matter cannot be determined at this time. See "Rate Proceedings – Atlanta Gas Light" herein for additional information.

Virginia Natural Gas

On April 6, 2021, the Virginia Commission approved a motion filed by Virginia Natural Gas to withdraw the application for its 9.5-mile interconnect project due to a change in the capacity needs of one of the project's customers. No further action is necessary and this matter is now concluded.

Rate Proceedings

Virginia Natural Gas

On September 14, 2021, the Virginia Commission approved a stipulation agreement related to Virginia Natural Gas' June 2020 general rate case filing, which allows for a $43 million increase in annual base rate revenues, including $14 million related to the recovery of investments under the SAVE program, based on a ROE of 9.5% and an equity ratio of 51.9%. Interim rate adjustments became effective as of November 1, 2020, subject to refund, based on Virginia Natural Gas' original request for an increase of approximately $50 million. Refunds to customers related to the difference between the approved rates and the interim rates will be completed during the fourth quarter 2021.

Atlanta Gas Light

On July 21, 2021, Atlanta Gas Light filed its annual GRAM filing with the Georgia PSC. The filing requested an annual base rate increase of $49 million based on the projected 12-month period beginning January 1, 2022. Later in November 2021, Atlanta Gas Light expects to file an amended GRAM filing in accordance with the reduction agreed to in the October 14, 2021 joint stipulation agreement, as discussed previously under "Infrastructure Replacement Programs and Capital Projects – Atlanta Gas Light" herein. Resolution of the GRAM filing is expected by December 31, 2021, with the new rates to become effective January 1, 2022. The ultimate outcome of this matter cannot be determined at this time.

Deferral of Incremental COVID-19 Costs

Nicor Gas

On March 18, 2021, the Illinois Commission approved a phased-in schedule for disconnections related to non-payment. Nicor Gas began certain disconnections in late April 2021 and resumed normal disconnections in June 2021.

Virginia Natural Gas

On June 30, 2021, the declared state of emergency in Virginia expired, ending the suspension of disconnections related to non-payment. Virginia Natural Gas began certain disconnections in July 2021 and late payment fees resumed in October 2021.