Regulatory Matters

6 Months Ended

Jun. 30, 2022

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 June 30, 2022 and December 31, 2021 were as follows:

Regulatory Clause	Balance Sheet Line Item	June 30, 2022		December 31, 2021
		(in millions)
Alabama Power
Rate CNP Compliance	Other regulatory assets, deferred	$	29	$	16
Rate CNP PPA	Other regulatory assets, deferred	93		84
Retail Energy Cost Recovery(*)	Other regulatory assets, current	60		—
	Other regulatory assets, deferred	191		126
Georgia Power
Fuel Cost Recovery	Deferred under recovered fuel clause revenues	$	948	$	410
Mississippi Power
Fuel Cost Recovery	Other customer accounts receivable	$	29	$	4
Ad Valorem Tax	Other regulatory assets, current	12		12
	Other regulatory assets, deferred	29		37
Southern Company Gas
Natural Gas Cost Recovery	Natural gas cost under recovery	$	361	$	266
	Other regulatory assets, deferred	15		207

(*)In accordance with an Alabama PSC order issued on February 1, 2022, Alabama Power applied $126 million of its 2021 Rate RSE refund to reduce the Rate ECR under recovered balance.

Alabama Power

Certificate of Convenience and Necessity

On July 12, 2022, the Alabama PSC approved and, on July 15, 2022, issued its order regarding Alabama Power's petition for a certificate of convenience and necessity (CCN) which authorizes Alabama Power to complete the acquisition of the Calhoun Generating Station, which was approved by the FERC on March 25, 2022, and is expected to close by September 30, 2022. Alabama Power expects to recover all approved costs associated with the acquisition through existing rate mechanisms as outlined in Note 2 to the financial statements in Item 8 of the Form 10-K. The Alabama PSC's order is subject to any rehearing request or judicial appeal filed on or before August 15, 2022. The ultimate outcome of this matter cannot be determined at this time.

Rate ECR

On July 12, 2022, the Alabama PSC approved an adjustment to Rate ECR from 1.960 cents per KWH to 2.557 cents per KWH, or approximately $310 million annually, effective with August 2022 billings. The approved increase in the Rate ECR factor will have no significant effect on Alabama Power's net income, but will increase operating cash flows related to fuel cost recovery. The rate will adjust to 5.910 cents per KWH in January 2025 absent a further order from the Alabama PSC.

Rate NDR

On July 12, 2022, the Alabama PSC approved modifications to Rate NDR, which include an adjustment to the charges to establish and maintain the reserve and an adjustment to the recovery period for any existing deferred storm-related operations and maintenance costs and future reserve deficits from 24 months to 48 months. As modified, the maximum total Rate NDR charge to recover a deficit is limited to $5.00 per month per non-residential customer account and $2.50 per month per residential customer account.

At June 30, 2022, Alabama Power's NDR balance was $103 million. Beginning with August 2022 billings, the reserve establishment charge will be suspended and the reserve maintenance charge will be activated as a result of the NDR balance exceeding $75 million. Alabama Power expects to collect $6 million in the second half of 2022 and approximately $12 million annually beginning in 2023 under Rate NDR unless the NDR balance falls below $50 million. Alabama Power continues to have the authority to accrue additional amounts to the NDR as circumstances warrant.

Reliability Reserve Accounting Order

On July 12, 2022, the Alabama PSC approved an accounting order authorizing Alabama Power to create a reliability reserve separate from the NDR and transition the previous Rate NDR authority related to reliability expenditures to the reliability reserve. Alabama Power may make accruals to the reliability reserve if the NDR balance exceeds $35 million.

Renewable Generation Certificate

Through the issuance of a Renewable Generation Certificate (RGC), Alabama Power is authorized by the Alabama PSC to procure up to 500 MWs of renewable capacity and energy by September 16, 2027 and to market the related energy and environmental attributes to customers and other third parties. In April 2022, one of the existing solar projects which was expected to be served through a PPA commencing in first quarter 2024 was terminated, resulting in the restoration of 80 MWs of capacity under the RGC. The ultimate outcome of this matter cannot be determined at this time.

Georgia Power

Rate Plans

2022 Base Rate Case

On June 24, 2022, Georgia Power filed a base rate case (Georgia Power 2022 Base Rate Case) with the Georgia PSC. The filing proposes continuation of a three-year alternate rate plan with requested rate increases totaling $852 million, $107 million, and $45 million effective January 1, 2023, January 1, 2024, and January 1, 2025, respectively. These increases are based on a proposed retail ROE of 11.00% using the currently approved equity ratio of 56% and reflect levelized revenue requirements during the three-year period, with the exception of incremental compliance costs related to CCR AROs, Demand-Side Management (DSM) programs, and related adjustments to the Municipal Franchise Fee tariff.

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

Tariff	2023		2024		2025
	(in millions)
Traditional base	$	739	$	—	$	—
ECCR
Traditional	(1)		—		—
CCR ARO(a)	64		78		47
DSM(a)	30		27		(2)
Municipal Franchise Fee	20		2		1
Total(b)	$	852	$	107	$	45

(a)As determined by the Georgia PSC through annual compliance filings.

(b)Totals may not add due to rounding.

Georgia Power's filing primarily reflects requests to (i) recover the costs of recent and future capital investments in the electric grid including the transmission and distribution systems and the continuation of its grid investment plan, all designed to support customer long-term reliability and resiliency needs, (ii) recover the cost of coal-fired generation units proposed for retirement, or made unavailable, as requested in the 2022 IRP, as Georgia Power continues the transition of the generation fleet to more economical and cleaner resources, (iii) make the necessary investments and recover costs to comply with federal and state environmental regulations, including costs associated with the CCR AROs related to ash pond and landfill closures and post-closure care, and (iv) reduce operating costs despite significant inflationary pressures. In addition, the filing includes the following provisions:

•Continuation of an allowed retail ROE range of 9.50% to 12.00%.

•Continuation of the process whereby 80% of any earnings above the top of the allowed ROE range are shared with Georgia Power's customers and the remaining 20% are retained by Georgia Power.

•Continuation of the option to file an Interim Cost Recovery tariff in the event earnings are projected to fall below the bottom of the allowed ROE range during the three-year term of the plan.

Georgia Power expects the Georgia PSC to render a final decision in this matter on December 20, 2022. The ultimate outcome of this matter cannot be determined at this time.

2019 ARP

In 2020, the Georgia PSC denied a motion for reconsideration filed by Sierra Club regarding the Georgia PSC's decision in the 2019 ARP allowing Georgia Power to recover compliance costs for CCR AROs. The Superior Court of Fulton County subsequently affirmed the Georgia PSC's decision and, in October 2021, the Georgia Court of Appeals affirmed the Superior Court of Fulton County's order. In December 2021, Sierra Club filed a petition for writ of certiorari to the Georgia Supreme Court, which was denied on July 14, 2022. This matter is now concluded. See Note 6 to the financial statements in Item 8 of the Form 10-K for additional information regarding Georgia Power's AROs.

Integrated Resource Plans

In response to supply chain challenges in the solar industry, the Georgia PSC approved Georgia Power's request to amend 970 MWs of utility-scale solar PPAs that were authorized by the Georgia PSC in Georgia Power's 2019 IRP. The amendments extended the required commercial operation dates for the PPAs from 2023 to 2024.

On July 21, 2022, the Georgia PSC approved the 2022 IRP, as modified by a stipulated agreement among Georgia Power, the staff of the Georgia PSC, and certain intervenors and as further modified by the Georgia PSC. In the 2022 IRP decision, the Georgia PSC approved the following requests:

•Decertification and retirement of Plant Wansley Units 1 and 2 (926 MWs based on 53.5% ownership) by August 31, 2022 and reclassification to regulatory asset accounts of the remaining net book values ($302 million and $279 million for Unit 1 and Unit 2, respectively, at June 30, 2022) and any remaining unusable materials and supplies inventories upon retirement. The regulatory asset accounts for the net book values of the units will be amortized at a rate equal to the unit depreciation rates authorized in the 2019 ARP through December 31, 2022. In the Georgia Power 2022 Base Rate Case, Georgia Power requested recovery of the remaining regulatory asset balances for the net book values of the units through 2030 and requested that the timing of recovery of the regulatory asset account for the unusable materials and supplies inventories be determined in a future base rate case.

•Decertification and retirement of Plant Scherer Unit 3 (614 MWs based on 75% ownership) by December 31, 2028 and reclassification to regulatory asset accounts of the remaining net book value (approximately $614 million at June 30, 2022) and any remaining unusable materials and supplies inventory to regulatory asset accounts upon retirement. The timing of recovery for these regulatory assets is expected to be determined in a future base rate case.

•Decertification and retirement of Plant Gaston Units 1 through 4 (500 MWs based on 50% ownership through SEGCO) by December 31, 2028. See Note 7 to the financial statements under "SEGCO" in Item 8 of the Form 10-K for additional information.

•Georgia Power's environmental compliance strategy, including approval of Georgia Power's plans to address CCR at its ash ponds and landfills. Recovery of the related costs is expected to be determined in future base rate cases. The Georgia PSC's approval included a change in the method of closure for one ash pond. Georgia Power is currently evaluating the related impact on its cost estimates and AROs; however, it is not expected to be material.

•Installation of environmental controls at Plants Bowen and Scherer for compliance with rules related to effluent limitations guidelines.

•Initiation of a license renewal application with the NRC for Plant Hatch.

•Investments related to the continued hydro operations of Plants Sinclair and Burton.

•Provisional authorization for development of a 265-MW battery energy storage facility with expected commercial operation in 2026.

•Issuance of requests for proposals (RFP) for 2,300 MWs of renewable resources, an additional 500 MWs of energy storage, and up to 140 MWs of biomass generation.

•Related transmission projects necessary to support the generation facilities plan.

•Certification of six PPAs (including five affiliate PPAs with Southern Power that are subject to approval by the FERC) with capacities of 1,567 MWs beginning in 2024, 380 MWs beginning in 2025, and 228 MWs beginning in 2028, procured through RFPs authorized in the 2019 IRP. See Note (F) under "Georgia Power Lease Modification" for additional information.

The Georgia PSC deferred a decision on the requested decertification and retirement of Plant Bowen Units 1 and 2 (1,400 MWs) to the 2025 IRP and rejected Georgia Power's request to certify approximately 88 MWs of wholesale capacity to be placed in retail rate base between January 1, 2024 and January 1, 2025. Georgia Power may offer such capacity in the wholesale market or to the retail jurisdiction in a future regulatory proceeding.

The ultimate outcome of these matters 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, under which Bechtel is reimbursed for actual costs plus a base fee and an at-risk fee, 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, and mandatory prepayment events.

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 the end of the first quarter 2023 and the fourth quarter 2023, respectively, is as follows:

	(in millions)
Base project capital cost forecast(a)(b)	$	10,393
Construction contingency estimate	60
Total project capital cost forecast(a)(b)	10,453
Net investment at June 30, 2022(b)	(8,966)
Remaining estimate to complete	$	1,487

(a)Includes approximately $590 million of costs that are not shared with the other Vogtle Owners and approximately $455 million of incremental costs under the cost-sharing and tender provisions of the joint ownership agreements described below. Excludes financing costs expected to be capitalized through AFUDC of approximately $385 million, of which $247 million had been accrued through June 30, 2022.

(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 $3.4 billion, of which $3.0 billion had been incurred through June 30, 2022.

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, which are reflected in the site work plans.

Since March 2020, the number of active COVID-19 cases at the site has fluctuated consistent with the surrounding area and impacted productivity levels and pace of activity completion, with the site experiencing peaks in the number of active cases in January 2021, August 2021, and January 2022. 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. As of June 30, 2022, Georgia Power's proportionate share of the estimated incremental cost associated with COVID-19 mitigation actions and impacts on construction productivity is estimated to be between $160 million and $200 million and is included in the total project capital cost forecast. The continuing effects of the COVID-19 pandemic could further disrupt or delay construction and testing activities at Plant Vogtle Units 3 and 4.

Fuel load for Unit 3 is projected during the fourth quarter 2022 with an in-service date projected during the first quarter 2023. Unit 3's projected schedule primarily depends on the volume and completion of construction remediation work, completion of work packages, including inspection records, and other documentation necessary to submit the remaining ITAACs and begin fuel load, the pace of system and area turnovers, and the progression of startup and other testing. An in-service date during the fourth quarter 2023 for Unit 4 is projected. Unit 4's projected schedule primarily depends on Unit 3 progress through fuel load, startup, and testing; overall construction productivity and production levels improving, particularly in electrical installation, including terminations; and appropriate levels of craft laborers, particularly electricians and pipefitters, being added and maintained. Any further delays could result in later in-service dates and cost increases.

During the first half of 2022, established construction contingency totaling $126 million was assigned to the base capital cost forecast for costs primarily associated with construction productivity, the pace of system turnovers, additional craft and support resources, and procurement for Units 3 and 4. Georgia Power also increased its total project capital cost forecast as of June 30, 2022 by adding $36 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 a pre-tax charge to income in the second quarter 2022 of $36 million ($27 million after tax) for the increase in the total project capital cost forecast. Georgia Power may request the Georgia PSC to evaluate those expenditures for rate recovery during the prudence review following the Unit 4 fuel load pursuant to the twenty-fourth VCM stipulation described below.

As Unit 3 completes system turnover from construction and moves to testing and transition to operations, ongoing and potential future challenges include construction productivity, completion of construction remediation work, completion of work packages, including inspection records, and other documentation necessary to submit the remaining ITAACs and begin fuel load, and final component and pre-operational tests. As Unit 4 progresses through construction and continues to transition into testing, ongoing and potential future challenges include the pace and quality of electrical installation; availability of craft and supervisory resources, including the temporary diversion of such resources to support Unit 3 construction efforts; the pace of work package closures and system turnovers; and the timeframe and duration of hot functional and other testing. As construction, including subcontract work, continues on both Units 3 and 4, ongoing or future challenges include 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; and procurement and related installation. New challenges may arise, particularly as Units 3 and 4 move into initial testing and start-up, which may result in required engineering changes or remediation related to 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). The ongoing and potential future challenges described above may 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. Additional license amendment requests also may be filed with the NRC. 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. On March 25, 2022, the NRC completed its follow-up inspection related to the November 2021 final significance report on its special inspection to review the root cause of this additional construction remediation work and the corresponding corrective action plans. The NRC closed the two white findings identified in November 2021 and returned Vogtle Unit 3 to the NRC's baseline inspection program.

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 first quarter 2023 for Unit 3 or the fourth quarter 2023 for Unit 4, including the current level of cost sharing described below, is estimated to result in additional base capital costs for Georgia Power of up to $35 million per month for Unit 3 and $45 million per month for Unit 4, as well as the related AFUDC and any additional related construction, support resources, or testing costs. While Georgia Power is not precluded from seeking retail recovery of any future capital cost forecast increase other than the amounts related to the cost-sharing and tender provisions of the joint ownership agreements described below, 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.

Amendments to the Vogtle Joint Ownership Agreements

In connection with a September 2018 vote by the Vogtle Owners 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).

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 cost 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.

For purposes of the foregoing provisions, qualifying construction costs will not include costs (i) resulting from force majeure events, including epidemics and quarantines, governmental actions or inactions (or significant delays associated with issuance of such actions) that affect the licensing, completion, start-up, operations, or financing of Plant Vogtle Units 3 and 4, administrative proceedings or litigation regarding ITAAC or other regulatory challenges to commencement of operation of Plant Vogtle Units 3 and 4, and changes in laws or regulations governing Plant Vogtle Units 3 and 4, (ii) legal fees and legal expenses incurred due to litigation with contractors or subcontractors that are not subsidiaries or affiliates of Southern Company, and (iii) additional costs caused by requests from the Vogtle Owners other than Georgia Power, except for the exercise of a right to vote granted under the Vogtle Joint Ownership Agreements, that increase costs by $100,000 or more.

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 from the seventeenth VCM report estimated in-service dates of November 2021 and November 2022 for Units 3 and 4, respectively. The schedule extension announced in February 2022 triggered the requirement for a vote to continue construction. Effective February 25, 2022, all of the Vogtle Owners had voted to continue construction.

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 those provisions. Based on the definition in the Global Amendments, Georgia Power believes the starting dollar amount is $18.38 billion and the current project capital cost forecast exceeds the cost-sharing provision threshold, but not the tender provision threshold. The other Vogtle Owners have notified Georgia Power that they believe the current project capital cost forecast exceeds the cost-sharing thresholds and triggers the tender provisions under the Global Amendments. Georgia Power recorded pre-tax charges to income in the fourth quarter 2021 and the second quarter 2022 of approximately $440 million ($328 million after tax) and $16 million ($12 million after tax), respectively, associated with these cost-sharing and tender provisions, which are

included in the total project capital cost forecast. Georgia Power may be required to record further pre-tax charges to income of up to approximately $480 million associated with these provisions based on the current project capital cost forecast. Georgia Power's incremental charges associated with these provisions, which relate to the other Vogtle Owners' share of costs, will not be recovered from retail customers. In October 2021, Georgia Power and the other Vogtle Owners entered into an agreement, which was modified on June 3, 2022, to clarify the process for the tender provisions of the Global Amendments to provide for a decision between 120 and 194 days after the tender option is triggered, which the other Vogtle Owners assert occurred on February 14, 2022, and would require the other Vogtle Owners to notify Georgia Power of their intent to exercise their tender options by August 27, 2022. On June 17, 2022 and July 26, 2022, OPC and Dalton, respectively, notified Georgia Power of their purported exercises of their tender options. On June 18, 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 have been triggered. The lawsuits also assert other claims, including breach of contract allegations, and seek, among other remedies, damages and injunctive relief requiring Georgia Power to track and allocate construction costs consistent with MEAG Power's and OPC's interpretations of the Global Amendments. On July 25, 2022, Georgia Power filed its answer in the lawsuit filed by MEAG Power 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.

Georgia Power's ownership interest in Plant Vogtle Units 3 and 4 continues to be 45.7%; however, it could increase if one or more of the other Vogtle Owners effectively exercise the option to tender a portion of their ownership interest to Georgia Power and require Georgia Power to pay 100% of the remaining share of the costs necessary to complete Plant Vogtle Units 3 and 4. Georgia Power's incremental ownership interest would be calculated and conveyed to Georgia Power after Plant Vogtle Units 3 and 4 are placed in service.

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 June 30, 2022, Georgia Power had recovered approximately $2.8 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 is not recording 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. In November 2021, the Georgia PSC approved Georgia Power's request to decrease the NCCR tariff by $78 million annually, effective January 1, 2022.

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 (see Note 2 to the financial statements under "Georgia Power – Plant Vogtle Unit 3 and Common Facilities Rate Proceeding" in Item 8 of the Form 10-K for additional information). 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 $270 million in 2021 and are estimated to have negative earnings impacts of approximately $300 million and $250 million in 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.

In the August 2021 order approving the twenty-fourth VCM report, the Georgia PSC 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.

The Georgia PSC has approved 25 VCM reports covering periods through June 30, 2021. These reports reflect total construction capital costs incurred of $7.9 billion (net of $1.7 billion of payments received under the Guarantee Settlement Agreement and approximately $188 million in related customer refunds), of which the Georgia PSC has verified and approved $7.3 billion as described above. The Georgia PSC has reviewed the twenty-sixth VCM report, which reflects $584 million of additional construction capital costs incurred through December 31, 2021. Georgia Power expects to file its twenty-seventh VCM report with the Georgia PSC by August 31, 2022, which will reflect the revised capital cost forecast discussed above and $522 million of construction capital costs incurred from January 1, 2022 through June 30, 2022.

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

Mississippi Power

Performance Evaluation Plan

On June 7, 2022, the Mississippi PSC approved Mississippi Power's annual retail PEP filing for 2022, resulting in an annual increase in revenues of approximately $18 million, or 1.9%, primarily due to increases in rate base, operations and maintenance expenses, and depreciation and amortization. The rate increase became effective with the first billing cycle of April 2022 in accordance with the PEP rate schedule.

Ad Valorem Tax Adjustment

On June 7, 2022, the Mississippi PSC approved Mississippi Power's annual ad valorem tax adjustment filing for 2022, resulting in an annual increase in revenues of $5 million, effective with the first billing cycle of July 2022.

Municipal and Rural Associations Tariff

On May 26, 2022, Mississippi Power and Cooperative Energy executed an amended shared service agreement (SSA) under which Cooperative Energy will continue to decrease its use of Mississippi Power's generation services under the MRA tariff up to 2.5% annually through 2035. At June 30, 2022, Mississippi Power is serving approximately 400 MWs of Cooperative Energy's annual demand. Beginning in 2036, Cooperative Energy will provide 100% of its electricity requirements at the MRA delivery points under the tariff. Neither party has the option to cancel the amended SSA. On June 30, 2022, Mississippi Power filed a request with the FERC for approval of the amended SSA.

On July 15, 2022, Mississippi Power filed a request with the FERC for a $23 million increase in annual wholesale base revenues under the MRA tariff and requested an effective date of July 15, 2022.

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 and capital projects during the first six months of 2022 were as follows:

Utility	Program	Six Months Ended June 30, 2022
		(in millions)
Nicor Gas	Investing in Illinois	$	177
Virginia Natural Gas	Steps to Advance Virginia's Energy	33
Atlanta Gas Light	System Reinforcement Rider	28
Chattanooga Gas	Pipeline Replacement Program	2
Total		$	240

Rate Proceedings

Atlanta Gas Light

On July 1, 2022, 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, 2023. Resolution of the GRAM filing is expected by December 28, 2022, with the new rates effective January 1, 2023. The ultimate outcome of this matter cannot be determined at this time.

Virginia Natural Gas

On May 31, 2022, Virginia Natural Gas filed a notice of intent with the Virginia State Corporation Commission to file a base rate case later in the third quarter 2022. The ultimate outcome of this matter cannot be determined at this time.