NOTES TO THE CONDENSED FINANCIAL STATEMENTS
FOR
THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
ALABAMA POWER COMPANY
GEORGIA POWER COMPANY
MISSISSIPPI POWER COMPANY
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
(UNAUDITED)
INDEX TO THE NOTES TO THE CONDENSED FINANCIAL STATEMENTS
INDEX TO APPLICABLE NOTES TO FINANCIAL STATEMENTS BY REGISTRANT
The following unaudited notes to the condensed financial statements are a combined presentation; however, information contained herein relating to any individual Registrant is filed by such Registrant on its own behalf and each Registrant makes no representation as to information related to the other Registrants. The list below indicates the Registrants to which each footnote applies.
| | | | | |
| Registrant | Applicable Notes |
| Southern Company | A, B, C, D, E, F, G, H, I, J, K |
| Alabama Power | A, B, C, D, F, G, H, I, J |
| Georgia Power | A, B, C, D, F, G, H, I, J |
| Mississippi Power | A, B, C, D, F, G, H, I, J |
| Southern Power | A, C, D, E, F, G, H, I, J |
| Southern Company Gas | A, B, C, D, E, F, G, H, I, J, K |
NOTES TO THE CONDENSED FINANCIAL STATEMENTS
(UNAUDITED)
(A) INTRODUCTION
The condensed quarterly financial statements of each Registrant included herein have been prepared by such Registrant, without audit, pursuant to the rules and regulations of the SEC. The Condensed Balance Sheets at December 31, 2022 have been derived from the audited financial statements of each Registrant. In the opinion of each Registrant's management, the information regarding such Registrant furnished herein reflects all adjustments, which, except as otherwise disclosed, are of a normal recurring nature, necessary to present fairly the results of operations for the periods ended June 30, 2023 and 2022. Certain information and footnote disclosures normally included in annual financial statements prepared in accordance with GAAP have been condensed or omitted pursuant to such rules and regulations, although each Registrant believes that the disclosures regarding such Registrant are adequate to make the information presented not misleading. Disclosures which would substantially duplicate the disclosures in the Form 10-K and details which have not changed significantly in amount or composition since the filing of the Form 10-K are generally omitted from this Quarterly Report on Form 10-Q unless specifically required by GAAP. Therefore, these Condensed Financial Statements should be read in conjunction with the financial statements and the notes thereto included in the Form 10-K. Due to the seasonal variations in the demand for energy and other factors, operating results for the periods presented are not necessarily indicative of the operating results to be expected for the full year.
Certain prior year data presented in the financial statements have been reclassified to conform to the current year presentation. These reclassifications had no impact on the overall results of operations, financial position, or cash flows of any Registrant.
Goodwill and Other Intangible Assets
Goodwill at June 30, 2023 and December 31, 2022 was as follows:
| | | | | | |
| Goodwill | |
| (in millions) |
| Southern Company | $ | 5,161 | | |
| Southern Company Gas: | | |
| Gas distribution operations | $ | 4,034 | | |
| Gas marketing services | 981 | | |
| Southern Company Gas total | $ | 5,015 | | |
Goodwill is not amortized, but is subject to an annual impairment test during the fourth quarter of each year, or more frequently if goodwill impairment indicators arise.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
Other intangible assets were as follows:
| | | | | | | | | | | | | | | | | | | | | | | |
| At June 30, 2023 | | At December 31, 2022 |
| Gross Carrying Amount | Accumulated Amortization | Other
Intangible Assets, Net | | Gross Carrying Amount | Accumulated Amortization | Other
Intangible Assets, Net |
| (in millions) | | (in millions) |
| Southern Company | | | | | | | |
| Subject to amortization: | | | | | | | |
| Customer relationships | $ | 212 | | $ | (167) | | $ | 45 | | | $ | 212 | | $ | (162) | | $ | 50 | |
| Trade names | 64 | | (49) | | 15 | | | 64 | | (44) | | 20 | |
| PPA fair value adjustments | 390 | | (139) | | 251 | | | 390 | | (129) | | 261 | |
| Other | 3 | | (3) | | — | | | 5 | | (5) | | — | |
| Total subject to amortization | $ | 669 | | $ | (358) | | $ | 311 | | | $ | 671 | | $ | (340) | | $ | 331 | |
| Not subject to amortization: | | | | | | | |
| FCC licenses | 75 | | — | | 75 | | | 75 | | — | | 75 | |
| Total other intangible assets | $ | 744 | | $ | (358) | | $ | 386 | | | $ | 746 | | $ | (340) | | $ | 406 | |
| | | | | | | |
Southern Power(*) | | | | | | | |
| PPA fair value adjustments | $ | 390 | | $ | (139) | | $ | 251 | | | $ | 390 | | $ | (129) | | $ | 261 | |
| | | | | | | |
Southern Company Gas(*) | | | | | | | |
| | | | | | | |
| Gas marketing services | | | | | | | |
| Customer relationships | $ | 156 | | $ | (142) | | $ | 14 | | | $ | 156 | | $ | (139) | | $ | 17 | |
| Trade names | 26 | | (19) | | 7 | | | 26 | | (17) | | 9 | |
| Total other intangible assets | $ | 182 | | $ | (161) | | $ | 21 | | | $ | 182 | | $ | (156) | | $ | 26 | |
(*) All subject to amortization.
Amortization associated with other intangible assets was as follows:
| | | | | | | | | | | | | | | |
| Three Months Ended | Six Months Ended | Three Months Ended | Six Months Ended | |
| June 30, 2023 | June 30, 2022 | |
| (in millions) |
Southern Company(a) | $ | 9 | | $ | 18 | | $ | 9 | | $ | 19 | | |
Southern Power(b) | 5 | | 10 | | 5 | | 10 | | |
| Southern Company Gas | 2 | | 5 | | 2 | | 5 | | |
(a)Includes $5 million, $10 million, $5 million, and $10 million for the three and six months ended June 30, 2023 and 2022, respectively, recorded as a reduction to operating revenues.
(b)Recorded as a reduction to operating revenues.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
Cash, Cash Equivalents, and Restricted Cash
The following table provides a reconciliation of cash, cash equivalents, and restricted cash reported within the condensed balance sheets that total to the amount shown in the condensed statements of cash flows for the applicable Registrants:
| | | | | | | | | | | | | | |
| Southern Company | Georgia Power | Southern Power | Southern
Company Gas |
| (in millions) |
| At June 30, 2023 | | | | |
| Cash and cash equivalents | $ | 2,123 | | $ | 44 | | $ | 169 | | $ | 242 | |
Restricted cash(a): | | | | |
| Other current assets | 83 | | 80 | | — | | 3 | |
| Other deferred charges and assets | 39 | | 36 | | 3 | | — | |
Total cash, cash equivalents, and restricted cash(b) | $ | 2,244 | | $ | 160 | | $ | 172 | | $ | 244 | |
| | | | |
| At December 31, 2022 | | | | |
| Cash and cash equivalents | $ | 1,917 | | $ | 364 | | $ | 131 | | $ | 81 | |
Restricted cash(a): | | | | |
| Other current assets | 62 | | 60 | | — | | 2 | |
| Other deferred charges and assets | 58 | | 56 | | 3 | | — | |
Total cash, cash equivalents, and restricted cash(b) | $ | 2,037 | | $ | 480 | | $ | 133 | | $ | 83 | |
(a)For Georgia Power, reflects $116 million at both June 30, 2023 and December 31, 2022 related to proceeds from the issuance of solid waste disposal facility revenue bonds in 2022. For Southern Power, reflects $3 million at both June 30, 2023 and December 31, 2022 held to fund estimated construction completion costs at the Deuel Harvest wind facility. For Southern Company Gas, reflects collateral for workers' compensation, life insurance, and long-term disability insurance.
(b)Total may not add due to rounding.
Natural Gas for Sale
With the exception of Nicor Gas, Southern Company Gas records natural gas inventories on a WACOG basis. For any declines in market prices below the WACOG considered to be other than temporary, an adjustment is recorded to reduce the value of natural gas inventories to market value. Nicor Gas' natural gas inventory is carried at cost on a LIFO basis. Inventory decrements occurring during the year that are restored prior to year-end are charged to cost of natural gas at the estimated annual replacement cost. Inventory decrements that are not restored prior to year-end are charged to cost of natural gas at the actual LIFO cost of the inventory layers liquidated.
Southern Company Gas recorded no material adjustments to natural gas inventories for either period presented. Nicor Gas' inventory decrement at June 30, 2023 is expected to be restored prior to year-end.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
Storm Damage Reserves
See Note 1 to the financial statements in Item 8 of the Form 10-K under "Storm Damage and Reliability Reserves" for additional information.
Storm damage reserve activity for the traditional electric operating companies during the six months ended June 30, 2023 was as follows:
| | | | | | | | | | | | | | |
| Southern
Company | Alabama Power | Georgia Power | Mississippi
Power |
| | (in millions) |
Balance at December 31, 2022 | $ | 216 | | $ | 97 | | $ | 83 | | $ | 36 | |
| Accrual | 28 | | 6 | | 16 | | 6 | |
Weather-related damages | (85) | | (24) | | (58) | | (3) | |
Balance at June 30, 2023 | $ | 159 | | $ | 79 | | $ | 41 | | $ | 39 | |
Asset Retirement Obligations
See Note 6 to the financial statements in Item 8 of the Form 10-K for additional information.
Following initial criticality on March 6, 2023, Georgia Power recorded AROs of approximately $90 million related to Plant Vogtle Unit 3. See Note (B) under "Georgia Power – Nuclear Construction" for additional information on Plant Vogtle Units 3 and 4.
In June 2023, Alabama Power completed an updated decommissioning cost site study for Plant Farley. The estimated cost of decommissioning based on the study resulted in a decrease in Alabama Power's ARO liability of approximately $15 million. See "Nuclear Decommissioning" herein for additional information.
Nuclear Decommissioning
See Note 6 to the financial statements in Item 8 of the Form 10-K under "Nuclear Decommissioning" for additional information. Site study cost is the estimate to decommission a specific facility as of the site study year. The decommissioning cost estimates are based on prompt dismantlement and removal of the plant from service. The actual decommissioning costs may vary from these estimates because of changes in the assumed date of decommissioning, changes in NRC requirements, or changes in the assumptions used in making these estimates.
The estimated costs of decommissioning Plant Farley based on Alabama Power's June 2023 site study are as follows:
| | | | | |
| Plant Farley |
| Decommissioning periods: | |
| Beginning year | 2037 |
| Completion year | 2087 |
| |
| (in millions) |
| Site study costs: | |
| Radiated structures | $ | 1,402 | |
| Spent fuel management | 513 | |
| Non-radiated structures | 133 | |
| Total site study costs | $ | 2,048 | |
For ratemaking purposes, Alabama Power's decommissioning costs are based on the site study. Significant assumptions used to determine these costs for ratemaking were an estimated inflation rate of 4.5% and an estimated trust earnings rate of 7.0%.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
Amounts previously contributed to the external trust funds are currently projected to be adequate to meet the updated decommissioning obligations. Alabama Power's site-specific estimates of decommissioning costs for Plant Farley are updated every five years. The next site study for Alabama Power is expected to be completed in 2028. Projections of funds are reviewed with the Alabama PSC to ensure that, over time, the deposits and earnings of the funds in the external trust will provide adequate funding to cover the site-specific costs. If necessary, Alabama Power would seek the Alabama PSC's approval to address any changes in a manner consistent with NRC and other applicable requirements.
(B) 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, 2023 and December 31, 2022 were as follows:
| | | | | | | | | | | |
| Regulatory Clause | Balance Sheet Line Item | June 30,
2023 | December 31, 2022 |
| | (in millions) |
| Alabama Power | | | |
| | | |
| | | |
| Rate CNP Compliance | Other regulatory assets, current | $ | 20 | | $ | 47 | |
| Other regulatory assets, deferred | 40 | | — | |
| Rate CNP PPA | Other regulatory assets, current | 17 | | 18 | |
| Other regulatory assets, deferred | 95 | | 102 | |
| | | |
| | | |
| Retail Energy Cost Recovery | Other regulatory assets, current | 146 | | 102 | |
| Other regulatory assets, deferred | 283 | | 520 | |
| Georgia Power | | | |
Fuel Cost Recovery(*) | Receivables – under recovered fuel clause revenues | $ | 695 | | $ | — | |
| Deferred under recovered fuel clause revenues | 1,489 | | 2,056 | |
| | | |
| Mississippi Power | | | |
| | | |
| Fuel Cost Recovery | Receivables – customer accounts, net | $ | 24 | | $ | 1 | |
| Ad Valorem Tax | Other regulatory assets, current | 6 | | 12 | |
| Other regulatory assets, deferred | 16 | | 19 | |
| | | |
| | | |
| Southern Company Gas | | | |
| | | |
| Natural Gas Cost Recovery | Natural gas cost under recovery | $ | — | | $ | 108 | |
| Natural gas cost over recovery | 161 | | — | |
| | | |
| | | |
(*)See "Georgia Power – Fuel Cost Recovery" herein for additional information.
Alabama Power
Certificates of Convenience and Necessity
In 2020, the Alabama PSC approved a certificate of convenience and necessity authorizing Alabama Power's construction of Plant Barry Unit 8 and the recovery of estimated in-service costs of $652 million. At June 30, 2023, project expenditures associated with Plant Barry Unit 8 totaled approximately $568 million, of which $563 million and $5 million was included in CWIP and property, plant, and equipment in service, respectively. The unit is expected to be placed in service in November 2023. The ultimate outcome of this matter cannot be determined at this time.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
Rate CNP New Plant
On March 24, 2023, Alabama Power filed Rate CNP New Plant with the Alabama PSC to recover costs associated with the acquisition of the Central Alabama Generating Station. The filing reflected an annual increase in retail revenues of $78 million effective with June 2023 billings. Through May 2023, Alabama Power recovered substantially all costs associated with the Central Alabama Generating Station through Rate RSE, offset by revenues from a power sales agreement. On May 24, 2023, the Central Alabama Generating Station was placed into retail service. See Note 15 to the financial statements under "Alabama Power" in Item 8 of the Form 10-K for additional information.
Renewable Generation Certificate
Through the issuance of a Renewable Generation Certificate (RGC), Alabama Power is authorized by the Alabama PSC to procure renewable capacity and energy and to market the related energy and environmental attributes to customers and other third parties. On April 4, 2023, the Alabama PSC approved two new solar PPAs totaling 160 MWs. Upon approval of these PPAs, Alabama Power had procured solar capacity totaling approximately 490 MWs under the RGC's original 500-MW limit.
On June 14, 2023, the Alabama PSC issued an order approving modifications to Alabama Power's RGC. The modifications authorized Alabama Power to procure an additional 2,400 MWs of renewable capacity and energy by June 14, 2029 and to market the related energy and environmental attributes to customers and other third parties. The modifications also increased the size of allowable renewable projects from 80 MWs to 200 MWs and increased the annual approval limit from 160 MWs to 400 MWs.
Reliability Reserve Accounting Order
On July 11, 2023, the Alabama PSC issued an order authorizing Alabama Power to expand the existing authority of its reliability reserve to include certain production-related expenses that are intended to maintain reliability in between scheduled generating unit maintenance outages.
Georgia Power
Plant Vogtle Unit 3 and Common Facilities Rate Proceeding
In compliance with a Georgia PSC order approved in November 2021, Georgia Power increased annual retail base rates by $318 million effective August 1, 2023 based on the actual in-service date of July 31, 2023 for Plant Vogtle Unit 3.
See "Nuclear Construction" herein for additional information on Plant Vogtle Units 3 and 4.
Fuel Cost Recovery
On May 16, 2023, the Georgia PSC approved a stipulation agreement between Georgia Power and the staff of the Georgia PSC to increase annual fuel billings by 54%, or approximately $1.1 billion, effective June 1, 2023. The increase includes a three-year recovery period for $2.2 billion of Georgia Power's under recovered fuel balance at May 31, 2023. Under the approved stipulation agreement, Georgia Power is allowed to adjust its fuel cost recovery rates under an interim fuel rider prior to the next fuel case, subject to a maximum 40% cumulative change, if its under or over recovered fuel balance accumulated since May 31, 2023 exceeds $200 million. Georgia Power is scheduled to file its next fuel case no later than February 28, 2026. Changes in fuel rates have no significant effect on Georgia Power's net income but do impact the related operating cash flows.
Integrated Resource Plans
In August 2022, Restore Chattooga Gorge Coalition (RCG) filed a petition in the Superior Court of Fulton County, Georgia against Georgia Power and the Georgia PSC. The petition challenges Georgia Power's plan to expend $115 million to modernize Plant Tugalo (a hydro facility), as approved in the 2019 IRP, and seeks judicial review of the Georgia PSC's order in the 2022 IRP proceeding with respect to the denial of RCG's challenge to the
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
modernization plan. In November 2022, Georgia Power and the Georgia PSC both filed motions to dismiss the RCG petition. 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 currently 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 July 2023 and March 2024, respectively, is as follows:
| | | | | |
| (in millions) |
Base project capital cost forecast(a)(b) | $ | 10,576 | |
| Construction contingency estimate | 17 | |
| |
Total project capital cost forecast(a)(b) | 10,593 | |
Net investment at June 30, 2023(b) | (9,944) | |
| Remaining estimate to complete | $ | 649 | |
(a)Includes approximately $610 million of costs that are not shared with the other Vogtle Owners, including $33 million of construction monitoring costs approved for recovery by the Georgia PSC in its nineteenth VCM order, and approximately $407 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 $422 million, of which $365 million had been accrued through June 30, 2023.
(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 $3.5 billion, of which $3.4 billion had been incurred through June 30, 2023.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
On March 6, 2023, Unit 3 achieved self-sustaining nuclear fission, commonly referred to as initial criticality, and, on April 1, 2023, the generator successfully synchronized to the power grid and generated electricity for the first time. Georgia Power placed Unit 3 in service on July 31, 2023. See "Plant Vogtle Unit 3 and Common Facilities Rate Proceeding" herein for additional information.
As part of its ongoing processes, Southern Nuclear continues to evaluate cost and schedule forecasts for Unit 4 on a regular basis to incorporate current information available, particularly in the areas of start-up testing and related test results, engineering support, commodity installations, system turnovers, and workforce statistics. Southern Nuclear establishes aggressive target values for monthly construction production and system turnover activities, which are reflected in the site work plan for Unit 4.
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 plans. As of June 30, 2023, 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 approximately $200 million and is included in the total project capital cost forecast.
During the first half of 2023, established construction contingency totaling $43 million was assigned to the base capital cost forecast for costs primarily associated with the Unit 3 schedule extension, including continued need of support resources for Unit 3 testing, as well as additional craft and support resources and subcontract work for Unit 4.
Hot functional testing for Unit 4 was completed on May 1, 2023. On July 20, 2023, Southern Nuclear announced that all Unit 4 ITAACs had been submitted to the NRC, and, on July 28, 2023, the NRC published its 103(g) finding that the accepted criteria in the combined license for Unit 4 had been met, which allows nuclear fuel to be loaded and start-up testing to begin. Fuel load for Unit 4 is projected to be completed by the end of October 2023. Unit 4 is projected to be placed in service during late fourth quarter 2023 or the first quarter 2024.
The projected schedule for Unit 4 significantly depends on maintaining overall construction productivity and production levels, particularly in completing remaining subcontractor scopes of work while reducing the level of craft laborers based on work remaining. As Unit 4 completes construction and transitions further into testing, ongoing and potential future challenges include the pace and quality of remaining commodity installations, the management of contractors and vendors, subcontractor performance, the availability of materials and parts, and/or related cost escalation; the pace of remaining work package closures; the availability of craft, supervisory, and technical support resources; and the timeframe and duration of final component and pre-operational testing. New challenges also may continue to arise as Unit 4 moves further into 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). These challenges may result in further schedule delays and/or cost increases.
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. With the receipt of the NRC's 103(g) findings for Units 3 and 4 in August 2022 and July 2023, respectively, the site is subject to the NRC's operating reactor oversight process and must meet applicable technical and operational requirements contained in its operating license. Various design and other licensing-based compliance matters may result in additional license amendment requests or require other resolution. If any license amendment requests or other licensing-based compliance issues are not resolved in a timely manner, there may be delays in the Unit 4 project schedule that could result in increased costs.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
The ultimate outcome of these matters cannot be determined at this time. However, any extension of the in-service date beyond March 2024 for Unit 4, including the joint owner cost sharing and tender impacts described below, is estimated to result in additional base capital costs for Georgia Power of up to $45 million per month, 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, of which Georgia Power's share is $8.4 billion (VCM 19 Forecast Amount), 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 VCM 19 Forecast Amount (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 VCM 19 Forecast Amount (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. The Global Amendments provide that if the EAC is revised and exceeds the VCM 19 Forecast Amount 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 VCM 19 Forecast Amount plus $2.1 billion.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
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 (Project 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 and all the Vogtle Owners 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. The other Vogtle Owners notified Georgia Power that they believe the project capital cost forecast approved by the Vogtle Owners in February 2022 triggered the tender provisions. In June 2022 and July 2022, OPC and Dalton, respectively, notified Georgia Power of their purported exercises of their tender options. Georgia Power did not accept these purported tender exercises.
In June 2022, OPC and MEAG Power each filed a separate lawsuit against Georgia Power in the Superior Court of Fulton County, Georgia seeking a declaratory judgment that the starting dollar amount is $17.1 billion and that the cost-sharing and tender provisions had been triggered. 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. In July 2022, Georgia Power filed its answers in the lawsuits filed by MEAG Power and OPC and included counterclaims seeking a declaratory judgment that the starting dollar amount is $18.38 billion and that costs related to force majeure events are excluded prior to calculating the cost-sharing and tender provisions and when calculating Georgia Power's related financial obligations. In September 2022, Dalton filed complaints in each of these lawsuits. Also in September 2022, Georgia Power and MEAG Power reached an agreement to resolve their dispute regarding the proper interpretation of the cost-sharing and tender provisions of the Global Amendments. Under the terms of the agreement, among other items, (i) MEAG Power will not exercise its tender option and will retain its full ownership interest in Plant Vogtle Units 3 and 4; (ii) Georgia Power will reimburse a portion of MEAG Power's costs of construction for Plant Vogtle Units 3 and 4 as such costs are incurred and with no further adjustment for force majeure costs, which payments will total approximately $92 million based on the current project capital cost forecast; and (iii) Georgia Power will reimburse 20% of MEAG Power's costs of construction with respect to any amounts over the current project capital cost forecast, with no further adjustment for force majeure costs. In addition, MEAG Power agreed to vote to continue construction upon occurrence of a Project Adverse Event unless the commercial operation date of either of Plant Vogtle Unit 3 or Unit 4 is not projected to occur by December 31, 2025. In October 2022, MEAG Power and Georgia Power filed a notice of settlement and
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
voluntary dismissal of their pending litigation, including Georgia Power's counterclaim, and Dalton dismissed its related complaint.
Georgia Power recorded pre-tax charges to income through the fourth quarter 2022 of $407 million ($304 million after tax) associated with the cost-sharing and tender provisions of the Global Amendments, including the settlement with MEAG Power. This total is included in the total project capital cost forecast and will not be recovered from retail customers. The settlement with MEAG Power does not resolve the separate pending litigation with OPC, including Dalton's associated complaint, described above. Georgia Power may be required to record further pre-tax charges to income of up to approximately $345 million associated with the cost-sharing and tender provisions of the Global Amendments for OPC and Dalton based on the current project capital cost forecast.
Georgia Power's ownership interest in Plant Vogtle Units 3 and 4 continues to be 45.7%. Georgia Power believes the increases in the total project capital cost forecast through December 31, 2022 triggered the tender provisions, but Georgia Power disagrees with OPC and Dalton on the tender provisions trigger date. Valid notices of tender from OPC and Dalton would require Georgia Power to pay 100% of their respective remaining shares of the costs necessary to complete Plant Vogtle Units 3 and 4. Georgia Power's incremental ownership interest will 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, 2023, Georgia Power had recovered approximately $3.0 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 December 2022, the Georgia PSC approved Georgia Power's filing to increase the NCCR tariff by $36 million annually, effective January 1, 2023.
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
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
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 at that time) 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. On July 31, 2023, Georgia Power notified the Georgia PSC that Unit 3 had reached commercial operation, and, effective August 1, 2023, Georgia Power adjusted retail base rates for Unit 3 and the common facilities shared between Units 3 and 4 (see "Plant Vogtle Unit 3 and Common Facilities Rate Proceeding" herein 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 $300 million in 2022 and are estimated to have negative earnings impacts of approximately $290 million in 2023 and $60 million in 2024. 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 also has reviewed two additional VCM reports, which reflected $1.1 billion of additional construction capital costs incurred through June 30, 2022. Georgia Power filed its twenty-eighth VCM report with the Georgia PSC on February 16, 2023, which reflected the capital cost forecast described above and $461 million of construction capital costs incurred from July 1, 2022 through December 31, 2022. Georgia Power expects to file its twenty-ninth VCM report with the Georgia PSC on August 31, 2023, which will reflect the capital cost forecast described above and $390 million of construction capital costs incurred from January 1, 2023 through June 30, 2023.
The ultimate outcome of these matters cannot be determined at this time.
Mississippi Power
Performance Evaluation Plan
On June 13, 2023, the Mississippi PSC approved Mississippi Power's annual retail PEP filing for 2023 indicating no change in retail rates.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
Ad Valorem Tax Adjustment
On May 2, 2023, the Mississippi PSC approved Mississippi Power's annual ad valorem tax adjustment filing for 2023, resulting in a $7 million annual decrease in revenues effective with the first billing cycle of June 2023.
Mississippi Power's operating revenues are adjusted for differences in actual recoverable ad valorem taxes and amounts billed in accordance with the currently approved cost recovery rate. Accordingly, changes in the billing factor should have no significant effect on Mississippi Power's revenues or net income but will affect operating cash flows.
Environmental Compliance Overview Plan
On April 4, 2023, the Mississippi PSC approved Mississippi Power's annual ECO Plan filing for 2023, resulting in a $3 million annual increase in revenues effective with the first billing cycle of May 2023.
System Restoration Rider
On April 4, 2023, the Mississippi PSC approved Mississippi Power's annual SRR filing, which indicated no change in retail rates. Mississippi Power's minimum annual SRR accrual was increased from $8 million to $12 million.
Municipal and Rural Associations Tariff
On July 31, 2023, Mississippi Power and Cooperative Energy filed a settlement agreement with the FERC related to Mississippi Power's July 2022 request for a $23 million increase in annual wholesale base revenues under the MRA tariff. Interim rates based on the initial request became effective September 14, 2022, subject to refund. The settlement agreement provides for a $16 million increase in annual wholesale base revenues and a refund to customers of approximately $6 million. The settlement agreement is subject to approval by the FERC. The ultimate outcome of this matter 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 2023 were as follows:
| | | | | | | | |
| Utility | Program | Six Months Ended June 30, 2023 |
| | (in millions) |
| Nicor Gas | Investing in Illinois | $ | 196 | |
| Virginia Natural Gas | SAVE | 37 | |
| Atlanta Gas Light | System Reinforcement Rider | 57 | |
| Chattanooga Gas | Pipeline Replacement Program | 4 | |
| Total | | $ | 294 | |
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
Nicor Gas
On June 15, 2023, the Illinois Commission concluded its review of the Qualifying Infrastructure Plant (QIP) capital investments by Nicor Gas for calendar year 2019 under the QIP Rider, or Investing in Illinois, program. The Illinois Commission disallowed $32 million of the $415 million of capital investments commissioned in 2019, together with the related return on investment. Nicor Gas recorded a pre-tax charge to income in the second quarter 2023 of $38 million ($28 million after tax) associated with the disallowance of capital investments. The disallowance is reflected on the income statement as an $8 million reduction to revenues and a $30 million increase in operating expenses. On July 14, 2023, Nicor Gas requested rehearing by the Illinois Commission, which is expected to render a decision by August 3, 2023. Nicor Gas defends these investments in infrastructure as prudently incurred and, if necessary, intends to appeal to the Illinois Appellate Court. The Illinois Commission has not yet conducted its review for calendar years 2020 through 2022 or the six months ended June 30, 2023. Any further disallowance by the Illinois Commission could be material. The ultimate outcome of these matters cannot be determined at this time.
Rate Proceedings
Atlanta Gas Light
On July 14, 2023, Atlanta Gas Light filed its annual GRAM update with the Georgia PSC. The filing requests an annual base rate increase of $53 million based on the projected 12-month period beginning January 1, 2024. Resolution of the GRAM filing is expected by December 31, 2023, with new rates effective January 1, 2024. The ultimate outcome of this matter cannot be determined at this time.
Virginia Natural Gas
On June 7, 2023, Virginia Natural Gas, the Virginia Commission staff, and the Virginia Attorney General's Division of Consumer Counsel entered into a stipulation agreement related to Virginia Natural Gas' August 2022 general base rate case filing. The stipulation provides for a $48 million increase in annual base rate revenues, including the recovery of investments under the SAVE program, an ROE of 9.70%, and an equity ratio of 49.06%. Interim rates became effective January 1, 2023, subject to refund, based on Virginia Natural Gas' original requested increase of approximately $69 million. The Virginia Commission is expected to rule on this matter by the end of 2023. The ultimate outcome of this matter is subject to a final order from the Virginia Commission and cannot be determined at this time.
(C) CONTINGENCIES
See Note 3 to the financial statements in Item 8 of the Form 10-K for information relating to various lawsuits and other contingencies.
General Litigation Matters
The Registrants are involved in various matters being litigated and regulatory matters. The ultimate outcome of such pending or potential litigation or regulatory matters against each Registrant and any subsidiaries cannot be determined at this time; however, for current proceedings not specifically reported herein, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on such Registrant's financial statements.
The Registrants believe the pending legal challenges discussed below have no merit; however, the ultimate outcome of these matters cannot be determined at this time.
Alabama Power
In September 2022, Mobile Baykeeper filed a citizen suit in the U.S. District Court for the Southern District of Alabama alleging that Alabama Power's plan to close the Plant Barry ash pond utilizing a closure-in-place methodology violates the Resource Conservation and Recovery Act (RCRA) and regulations governing CCR. Among other relief requested, Mobile Baykeeper seeks a declaratory judgment that the RCRA and regulations
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
governing CCR are being violated, preliminary and injunctive relief to prevent implementation of Alabama Power's closure plan and the development of a closure plan that satisfies regulations governing CCR requirements. On December 19, 2022, Alabama Power filed a motion to dismiss the case.
On January 31, 2023, the EPA issued a Notice of Potential Violations associated with Alabama Power's plan to close the Plant Barry ash pond. Alabama Power has affirmed to the EPA its position that it is in compliance with CCR requirements.
The ultimate outcome of these matters cannot be determined at this time but could have a material impact on Alabama Power's ARO estimates and cash flows. See Note 6 to the financial statements in Item 8 of the Form 10-K for a discussion of Alabama Power's ARO liabilities.
Georgia Power
Municipal Franchise Fees
In 2011, plaintiffs filed a putative class action against Georgia Power in the Superior Court of Fulton County, Georgia alleging that Georgia Power's collection in rates of amounts for municipal franchise fees (which fees are paid to municipalities) exceeded the amounts allowed in orders of the Georgia PSC and alleging certain state law claims. This case has been ruled upon and appealed numerous times over the last several years. In 2019, the Georgia PSC issued an order that found Georgia Power has appropriately implemented the municipal franchise fee schedule. In March 2021, the Superior Court of Fulton County granted class certification and Georgia Power's motion for summary judgment and the plaintiffs filed a notice of appeal. In April 2021, Georgia Power filed a notice of cross appeal on the issue of class certification. In December 2021, the Georgia Court of Appeals affirmed the Superior Court's ruling that granted summary judgment to Georgia Power and dismissed Georgia Power's cross appeal on the issue of class certification as moot. Also in December 2021, the plaintiffs filed a petition for writ of certiorari to the Georgia Supreme Court, which was denied on January 27, 2023. On February 6, 2023, the plaintiffs filed a motion for reconsideration with the Georgia Supreme Court, which was denied on February 16, 2023. This matter is now concluded.
Plant Scherer
In July 2020, a group of individual plaintiffs filed a complaint, which was amended in December 2022, in the Superior Court of Fulton County, Georgia against Georgia Power alleging that the construction and operation of Plant Scherer has impacted groundwater and air, resulting in alleged personal injuries and property damage. The plaintiffs seek an unspecified amount of monetary damages including punitive damages, a medical monitoring fund, and injunctive relief. In December 2022, the Superior Court of Fulton County, Georgia granted Georgia Power's motion to transfer the case to the Superior Court of Monroe County, Georgia. On May 9, 2023, the Superior Court of Monroe County, Georgia denied Georgia Power's motion to dismiss the case for lack of subject matter jurisdiction. On July 27, 2023, the Superior Court of Monroe County, Georgia denied the remaining motions to dismiss certain claims and plaintiffs that Georgia Power filed at the outset of the case.
In October 2021, February 2022, and January 2023, a total of eight additional complaints were filed in the Superior Court of Monroe County, Georgia against Georgia Power alleging that releases from Plant Scherer have impacted groundwater and air, resulting in alleged personal injuries and property damage. The plaintiffs sought an unspecified amount of monetary damages including punitive damages. After Georgia Power removed these cases to the U.S. District Court for the Middle District of Georgia, the plaintiffs voluntarily dismissed their complaints without prejudice in November 2022 and January 2023. On May 12, 2023, the plaintiffs in the cases originally filed in October 2021, February 2022, and January 2023 refiled their eight complaints in the Superior Court of Monroe County, Georgia. Also on May 12, 2023, a new complaint was filed in the Superior Court of Monroe County, Georgia against Georgia Power alleging that the construction and operation of Plant Scherer have impacted groundwater and air, resulting in alleged personal injuries. The plaintiff seeks an unspecified amount of monetary damages, including punitive damages. On May 18, 2023, Georgia Power removed all of these cases to the U.S.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
District Court for the Middle District of Georgia. The plaintiffs are requesting the court remand the cases back to the Superior Court of Monroe County, Georgia.
The amount of any possible losses from these matters cannot be estimated at this time.
Mississippi Power
In 2018, Ray C. Turnage and 10 other individual plaintiffs filed a putative class action complaint against Mississippi Power and the three then-serving members of the Mississippi PSC in the U.S. District Court for the Southern District of Mississippi, which was amended in March 2019 to include four additional plaintiffs. Mississippi Power received Mississippi PSC approval in 2013 to charge a mirror CWIP rate premised upon including in its rate base pre-construction and construction costs for the Kemper IGCC prior to placing the Kemper IGCC into service. The Mississippi Supreme Court reversed that approval and ordered Mississippi Power to refund the amounts paid by customers under the previously-approved mirror CWIP rate. The plaintiffs allege that the initial approval process, and the amount approved, were improper and make claims for gross negligence, reckless conduct, and intentional wrongdoing. They also allege that Mississippi Power underpaid customers by up to $23.5 million in the refund process by applying an incorrect interest rate. The plaintiffs seek to recover, on behalf of themselves and their putative class, actual damages, punitive damages, pre-judgment interest, post-judgment interest, attorney's fees, and costs. The district court dismissed the amended complaint; however, in March 2020, the plaintiffs filed a motion seeking to name the new members of the Mississippi PSC, the Mississippi Development Authority, and Southern Company as additional defendants and add a cause of action against all defendants based on a dormant commerce clause theory under the U.S. Constitution. In July 2020, the plaintiffs filed a motion for leave to file a third amended complaint, which included the same federal claims as the proposed second amended complaint, as well as several additional state law claims based on the allegation that Mississippi Power failed to disclose the annual percentage rate of interest applicable to refunds. In November 2020, the district court denied each of the plaintiffs' pending motions and entered final judgment in favor of Mississippi Power. In January 2021, the district court denied further motions by the plaintiffs to vacate the judgment and to file a revised second amended complaint. In February 2021, the plaintiffs filed a notice of appeal with the U.S. Court of Appeals for the Fifth Circuit. In March 2022, the U.S. Court of Appeals for the Fifth Circuit issued an opinion affirming the dismissal of the claims against the Mississippi PSC defendants but reversing the dismissal of the claims against Mississippi Power. In May 2022, the U.S. Court of Appeals for the Fifth Circuit denied a petition by Mississippi Power for a rehearing en banc and remanded the case to the U.S. District Court for the Southern District of Mississippi for further proceedings. In June 2022, Mississippi Power filed with the trial court a motion to dismiss the complaint with prejudice, which was granted on March 15, 2023. On March 28, 2023, the plaintiffs filed a notice of appeal with the U.S. Court of Appeals for the Fifth Circuit. An adverse outcome in this proceeding could have a material impact on Mississippi Power's financial statements.
Environmental Remediation
The Southern Company system must comply with environmental laws and regulations governing the handling and disposal of waste and releases of hazardous substances. Under these various laws and regulations, the Southern Company system could incur substantial costs to clean up affected sites. The traditional electric operating companies and the natural gas distribution utilities in Illinois and Georgia have each received authority from their respective state PSCs or other applicable state regulatory agencies to recover approved environmental remediation costs through regulatory mechanisms. These regulatory mechanisms are adjusted annually or as necessary within limits approved by the state PSCs or other applicable state regulatory agencies.
Georgia Power's environmental remediation liability was $14 million and $15 million at June 30, 2023 and December 31, 2022, respectively. Georgia Power has been designated or identified as a potentially responsible party at sites governed by the Georgia Hazardous Site Response Act and/or by the federal Comprehensive Environmental Response, Compensation, and Liability Act, and assessment and potential cleanup of such sites is expected.
Southern Company Gas' environmental remediation liability was $230 million and $256 million at June 30, 2023 and December 31, 2022, respectively, based on the estimated cost of environmental investigation and remediation associated with known former manufactured gas plant operating sites.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
The ultimate outcome of these matters cannot be determined at this time; however, as a result of the regulatory treatment for environmental remediation expenses described above, the final disposition of these matters is not expected to have a material impact on the financial statements of the applicable Registrants.
Other Matters
Traditional Electric Operating Companies
In April 2019, Bellsouth Telecommunications d/b/a AT&T Alabama (AT&T) filed a complaint against Alabama Power with the FCC alleging that the pole rental rate AT&T is required to pay pursuant to the parties' joint use agreement is unjust and unreasonable under federal law. The complaint sought a new rate and approximately $87 million in refunds of alleged overpayments for the preceding six years. In August 2019, the FCC stayed the case in favor of arbitration, which AT&T has not pursued. The ultimate outcome of this matter cannot be determined at this time, but an adverse outcome could have a material impact on the financial statements of Southern Company and Alabama Power. Georgia Power and Mississippi Power have joint use agreements with other AT&T affiliates.
Mississippi Power
In August 2022, the Mississippi Department of Revenue (Mississippi DOR) completed an audit of sales and use taxes paid by Mississippi Power from 2016 to 2019 and entered a final assessment, indicating a total amount due of $28 million, including associated penalties and interest. Additional interest of approximately $1 million was estimated through June 30, 2023. Mississippi Power does not agree with the audit findings and, in October 2022, filed an administrative appeal with the Mississippi DOR. See Note 3 to the financial statements in Item 8 of the Form 10-K under "Other Matters – Mississippi Power – Department of Revenue Audit" for information regarding a Mississippi PSC accounting order related to the tax audit proceeding. The ultimate outcome of this matter cannot be determined at this time.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
(D) REVENUE FROM CONTRACTS WITH CUSTOMERS AND LEASE INCOME
Revenue from Contracts with Customers
The Registrants generate revenues from a variety of sources, some of which are not accounted for as revenue from contracts with customers, such as leases, derivatives, and certain cost recovery mechanisms. See Note 1 to the financial statements under "Revenues" in Item 8 of the Form 10-K for additional information on the revenue policies of the Registrants. See "Lease Income" herein and Note (J) for additional information on revenue accounted for under lease and derivative accounting guidance, respectively.
The following table disaggregates revenue from contracts with customers for the three and six months ended June 30, 2023 and 2022:
| | | | | | | | | | | | | | | | | | | | |
| Southern Company | Alabama Power | Georgia Power | Mississippi Power | Southern Power | Southern Company Gas |
| (in millions) |
| Three Months Ended June 30, 2023 | | | | | | |
| Operating revenues | | | | | | |
| Retail electric revenues | | | | | | |
| Residential | $ | 1,647 | | $ | 648 | | $ | 928 | | $ | 71 | | $ | — | | $ | — | |
| Commercial | 1,370 | | 465 | | 830 | | 75 | | — | | — | |
| Industrial | 864 | | 429 | | 353 | | 82 | | — | | — | |
| Other | 27 | | 3 | | 22 | | 2 | | — | | — | |
| Total retail electric revenues | 3,908 | | 1,545 | | 2,133 | | 230 | | — | | — | |
| Natural gas distribution revenues | | | | | | |
| Residential | 330 | | — | | — | | — | | — | | 330 | |
| Commercial | 82 | | — | | — | | — | | — | | 82 | |
| Transportation | 284 | | — | | — | | — | | — | | 284 | |
| Industrial | 6 | | — | | — | | — | | — | | 6 | |
| Other | 51 | | — | | — | | — | | — | | 51 | |
| Total natural gas distribution revenues | 753 | | — | | — | | — | | — | | 753 | |
| Wholesale electric revenues | | | | | | |
| PPA energy revenues | 253 | | 58 | | 24 | | 2 | | 175 | | — | |
| PPA capacity revenues | 149 | | 44 | | 13 | | 2 | | 91 | | — | |
| Non-PPA revenues | 61 | | 12 | | 6 | | 70 | | 83 | | — | |
| Total wholesale electric revenues | 463 | | 114 | | 43 | | 74 | | 349 | | — | |
| Other natural gas revenues | | | | | | |
| Gas marketing services | 73 | | — | | — | | — | | — | | 73 | |
| Other natural gas revenues | 8 | | — | | — | | — | | — | | 8 | |
| Total natural gas revenues | 81 | | — | | — | | — | | — | | 81 | |
| Other revenues | 327 | | 43 | | 145 | | 10 | | 16 | | — | |
| Total revenue from contracts with customers | 5,532 | | 1,702 | | 2,321 | | 314 | | 365 | | 834 | |
Other revenue sources(*) | 216 | | (13) | | 70 | | (3) | | 160 | | 18 | |
| | | | | | |
| Total operating revenues | $ | 5,748 | | $ | 1,689 | | $ | 2,391 | | $ | 311 | | $ | 525 | | $ | 852 | |
| | | | | | |
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
| | | | | | | | | | | | | | | | | | | | |
| Southern Company | Alabama Power | Georgia Power | Mississippi Power | Southern Power | Southern Company Gas |
| (in millions) |
| Six Months Ended June 30, 2023 | | | | | | |
| Operating revenues | | | | | | |
| Retail electric revenues | | | | | | |
| Residential | $ | 3,174 | | $ | 1,308 | | $ | 1,730 | | $ | 136 | | $ | — | | $ | — | |
| Commercial | 2,619 | | 894 | | 1,582 | | 143 | | — | | — | |
| Industrial | 1,653 | | 827 | | 666 | | 160 | | — | | — | |
| Other | 54 | | 6 | | 44 | | 4 | | — | | — | |
| Total retail electric revenues | 7,500 | | 3,035 | | 4,022 | | 443 | | — | | — | |
| Natural gas distribution revenues | | | | | | |
| Residential | 1,226 | | — | | — | | — | | — | | 1,226 | |
| Commercial | 314 | | — | | — | | — | | — | | 314 | |
| Transportation | 603 | | — | | — | | — | | — | | 603 | |
| Industrial | 29 | | — | | — | | — | | — | | 29 | |
| Other | 168 | | — | | — | | — | | — | | 168 | |
| Total natural gas distribution revenues | 2,340 | | — | | — | | — | | — | | 2,340 | |
| Wholesale electric revenues | | | | | | |
| PPA energy revenues | 534 | | 129 | | 35 | | 5 | | 376 | | — | |
| PPA capacity revenues | 341 | | 105 | | 25 | | 34 | | 179 | | — | |
| Non-PPA revenues | 98 | | 32 | | 10 | | 178 | | 187 | | — | |
| Total wholesale electric revenues | 973 | | 266 | | 70 | | 217 | | 742 | | — | |
| Other natural gas revenues | | | | | | |
| | | | | | |
| Gas marketing services | 304 | | — | | — | | — | | — | | 304 | |
| Other natural gas revenues | 20 | | — | | — | | — | | — | | 20 | |
| Total natural gas revenues | 324 | | — | | — | | — | | — | | 324 | |
| Other revenues | 640 | | 103 | | 276 | | 22 | | 27 | | — | |
| Total revenue from contracts with customers | 11,777 | | 3,404 | | 4,368 | | 682 | | 769 | | 2,664 | |
Other revenue sources(*) | 451 | | (68) | | 199 | | 20 | | 264 | | 64 | |
| | | | | | |
| Total operating revenues | $ | 12,228 | | $ | 3,336 | | $ | 4,567 | | $ | 702 | | $ | 1,033 | | $ | 2,728 | |
| | | | | | |
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
| | | | | | | | | | | | | | | | | | | | |
| Southern Company | Alabama Power | Georgia Power | Mississippi Power | Southern Power | Southern Company Gas |
| (in millions) |
| Three Months Ended June 30, 2022 | | | | | | |
| Operating revenues | | | | | | |
| Retail electric revenues | | | | | | |
| Residential | $ | 1,655 | | $ | 617 | | $ | 962 | | $ | 76 | | $ | — | | $ | — | |
| Commercial | 1,387 | | 410 | | 900 | | 77 | | — | | — | |
| Industrial | 1,005 | | 368 | | 553 | | 84 | | — | | — | |
| Other | 25 | | 3 | | 20 | | 2 | | — | | — | |
| Total retail electric revenues | 4,072 | | 1,398 | | 2,435 | | 239 | | — | | — | |
| Natural gas distribution revenues | | | | | | |
| Residential | 474 | | — | | — | | — | | — | | 474 | |
| Commercial | 130 | | — | | — | | — | | — | | 130 | |
| Transportation | 276 | | — | | — | | — | | — | | 276 | |
| Industrial | 16 | | — | | — | | — | | — | | 16 | |
| Other | 67 | | — | | — | | — | | — | | 67 | |
| Total natural gas distribution revenues | 963 | | — | | — | | — | | — | | 963 | |
| Wholesale electric revenues | | | | | | |
| PPA energy revenues | 585 | | 108 | | 40 | | 5 | | 441 | | — | |
| PPA capacity revenues | 136 | | 40 | | 12 | | — | | 85 | | — | |
| Non-PPA revenues | 62 | | 35 | | 6 | | 169 | | 196 | | — | |
| Total wholesale electric revenues | 783 | | 183 | | 58 | | 174 | | 722 | | — | |
| Other natural gas revenues | | | | | | |
| Gas marketing services | 90 | | — | | — | | — | | — | | 90 | |
| Other natural gas revenues | 10 | | — | | — | | — | | — | | 10 | |
| Total natural gas revenues | 100 | | — | | — | | — | | — | | 100 | |
| Other revenues | 308 | | 63 | | 121 | | 9 | | 9 | | — | |
| Total revenue from contracts with customers | 6,226 | | 1,644 | | 2,614 | | 422 | | 731 | | 1,063 | |
Other revenue sources(*) | 980 | | 287 | | 507 | | 12 | | 168 | | 20 | |
| | | | | | |
| Total operating revenues | $ | 7,206 | | $ | 1,931 | | $ | 3,121 | | $ | 434 | | $ | 899 | | $ | 1,083 | |
| | | | | | |
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
| | | | | | | | | | | | | | | | | | | | |
| Southern Company | Alabama Power | Georgia Power | Mississippi Power | Southern Power | Southern Company Gas |
| (in millions) |
| Six Months Ended June 30, 2022 | | | | | | |
| Operating revenues | | | | | | |
| Retail electric revenues | | | | | | |
| Residential | $ | 3,179 | | $ | 1,250 | | $ | 1,783 | | $ | 146 | | $ | — | | $ | — | |
| Commercial | 2,567 | | 786 | | 1,638 | | 143 | | — | | — | |
| Industrial | 1,732 | | 691 | | 887 | | 154 | | — | | — | |
| Other | 51 | | 7 | | 40 | | 4 | | — | | — | |
| Total retail electric revenues | 7,529 | | 2,734 | | 4,348 | | 447 | | — | | — | |
| Natural gas distribution revenues | | | | | | |
| Residential | 1,490 | | — | | — | | — | | — | | 1,490 | |
| Commercial | 400 | | — | | — | | — | | — | | 400 | |
| Transportation | 613 | | — | | — | | — | | — | | 613 | |
| Industrial | 48 | | — | | — | | — | | — | | 48 | |
| Other | 195 | | — | | — | | — | | — | | 195 | |
| Total natural gas distribution revenues | 2,746 | | — | | — | | — | | — | | 2,746 | |
| Wholesale electric revenues | | | | | | |
| PPA energy revenues | 930 | | 168 | | 72 | | 8 | | 694 | | — | |
| PPA capacity revenues | 268 | | 78 | | 23 | | 3 | | 166 | | — | |
| Non-PPA revenues | 124 | | 99 | | 15 | | 271 | | 269 | | — | |
| Total wholesale electric revenues | 1,322 | | 345 | | 110 | | 282 | | 1,129 | | — | |
| Other natural gas revenues | | | | | | |
| | | | | | |
| Gas marketing services | 333 | | — | | — | | — | | — | | 333 | |
| Other natural gas revenues | 26 | | — | | — | | — | | — | | 26 | |
| Total natural gas revenues | 359 | | — | | — | | — | | — | | 359 | |
| Other revenues | 530 | | 109 | | 216 | | 17 | | 17 | | — | |
| Total revenue from contracts with customers | 12,486 | | 3,188 | | 4,674 | | 746 | | 1,146 | | 3,105 | |
Other revenue sources(*) | 1,368 | | 392 | | 654 | | 23 | | 292 | | 35 | |
| | | | | | |
| Total operating revenues | $ | 13,854 | | $ | 3,580 | | $ | 5,328 | | $ | 769 | | $ | 1,438 | | $ | 3,140 | |
(*)Other revenue sources relate to revenues from customers accounted for as derivatives and leases, alternative revenue programs at Southern Company Gas, and cost recovery mechanisms and revenues that meet other scope exceptions for revenues from contracts with customers at the traditional electric operating companies.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
Contract Balances
The following table reflects the closing balances of receivables, contract assets, and contract liabilities related to revenues from contracts with customers at June 30, 2023 and December 31, 2022:
| | | | | | | | | | | | | | | | | | | | |
| Southern Company | Alabama Power | Georgia Power | Mississippi Power | Southern Power | Southern Company Gas |
| (in millions) |
| Accounts Receivable | | | | | | |
| At June 30, 2023 | $ | 2,423 | | $ | 670 | | $ | 986 | | $ | 101 | | $ | 126 | | $ | 461 | |
| At December 31, 2022 | 3,123 | | 696 | | 922 | | 92 | | 237 | | 1,107 | |
| Contract Assets | | | | | | |
| At June 30, 2023 | $ | 167 | | $ | — | | $ | 73 | | $ | — | | $ | — | | $ | 30 | |
| At December 31, 2022 | 156 | | 2 | | 89 | | — | | — | | — | |
| Contract Liabilities | | | | | | |
| At June 30, 2023 | $ | 73 | | $ | 1 | | $ | 28 | | $ | 3 | | $ | 1 | | $ | — | |
| At December 31, 2022 | 45 | | 4 | | 9 | | — | | 1 | | — | |
Contract assets for Georgia Power primarily relate to retail customer fixed bill programs, where the payment is contingent upon Georgia Power's continued performance and the customer's continued participation in the program over a one-year contract term, and unregulated service agreements, where payment is contingent on project completion. Contract liabilities for Georgia Power primarily relate to cash collections recognized in advance of revenue for unregulated service agreements and retail customer fixed bill programs. At June 30, 2023, Southern Company Gas' contract assets relate to work performed on an energy efficiency enhancement and upgrade contract with the U.S. General Services Administration. Southern Company Gas receives cash advances from a third-party financial institution to fund work performed, of which approximately $41 million had been received at June 30, 2023. These advances have been accounted for as long-term debt on the balance sheets. See Note 1 to the financial statements under "Affiliate Transactions" in Item 8 of the Form 10-K for additional information regarding the construction contract. At June 30, 2023 and December 31, 2022, Southern Company's unregulated distributed generation business had contract assets of $64 million and $65 million, respectively, and contract liabilities of $42 million and $32 million, respectively, for outstanding performance obligations.
Revenues recognized in the three and six months ended June 30, 2023, which were included in contract liabilities at December 31, 2022, were immaterial for the applicable Registrants. Contract liabilities are primarily classified as current on the balance sheets as the corresponding revenues are generally expected to be recognized within one year.
Remaining Performance Obligations
The Subsidiary Registrants may enter into long-term contracts with customers in which revenues are recognized as performance obligations are satisfied over the contract term. For Alabama Power, Georgia Power, and Southern Power, these contracts primarily relate to PPAs whereby electricity and generation capacity are provided to a customer. The revenue recognized for the delivery of electricity is variable; however, certain PPAs include a fixed payment for fixed generation capacity over the term of the contract. For Southern Company Gas, these contracts primarily relate to the U.S. General Services Administration contract described above. Southern Company's unregulated distributed generation business also has partially satisfied performance obligations related to certain
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
fixed price contracts. Revenues from contracts with customers related to these performance obligations remaining at June 30, 2023 are expected to be recognized as follows:
| | | | | | | | | | | | | | | | | | | | |
| 2023 (remaining) | 2024 | 2025 | 2026 | 2027 | Thereafter |
| (in millions) |
| Southern Company | $ | 333 | | $ | 544 | | $ | 351 | | $ | 316 | | $ | 319 | | $ | 2,089 | |
| Alabama Power | 11 | | 8 | | 7 | | — | | — | | — | |
| Georgia Power | 43 | | 58 | | 28 | | 14 | | 14 | | 23 | |
| | | | | | |
| Southern Power | 188 | | 358 | | 302 | | 303 | | 310 | | 2,077 | |
| Southern Company Gas | 11 | | 29 | | — | | — | | — | | — | |
Lease Income
Lease income for the three and six months ended June 30, 2023 and 2022 is as follows:
| | | | | | | | | | | | | | | | | | | | |
| Southern
Company | Alabama Power | Georgia Power | Mississippi
Power | Southern Power | Southern Company Gas |
| | (in millions) |
For the Three Months Ended June 30, 2023 |
| Lease income - interest income on sales-type leases | $ | 6 | | $ | — | | $ | — | | $ | 4 | | $ | 2 | | $ | — | |
| Lease income - operating leases | 42 | | 11 | | 7 | | 1 | | 21 | | 9 | |
| Variable lease income | 123 | | — | | — | | — | | 132 | | — | |
| Total lease income | $ | 171 | | $ | 11 | | $ | 7 | | $ | 5 | | $ | 155 | | $ | 9 | |
| | | | | | |
For the Six Months Ended June 30, 2023 |
| Lease income - interest income on sales-type leases | $ | 12 | | $ | — | | $ | — | | $ | 7 | | $ | 5 | | $ | — | |
| Lease income - operating leases | 92 | | 29 | | 14 | | 2 | | 42 | | 18 | |
| Variable lease income | 192 | | — | | — | | — | | 207 | | — | |
| Total lease income | $ | 296 | | $ | 29 | | $ | 14 | | $ | 9 | | $ | 254 | | $ | 18 | |
| | | | | | |
For the Three Months Ended June 30, 2022 |
| Lease income - interest income on sales-type leases | $ | 7 | | $ | — | | $ | — | | $ | 4 | | $ | 3 | | $ | — | |
| Lease income - operating leases | 52 | | 19 | | 8 | | — | | 21 | | 9 | |
| Variable lease income | 129 | | — | | — | | — | | 138 | | — | |
| Total lease income | $ | 188 | | $ | 19 | | $ | 8 | | $ | 4 | | $ | 162 | | $ | 9 | |
| | | | | | |
For the Six Months Ended June 30, 2022 |
| Lease income - interest income on sales-type leases | $ | 13 | | $ | — | | $ | — | | $ | 8 | | $ | 5 | | $ | — | |
| Lease income - operating leases | 105 | | 39 | | 16 | | 1 | | 42 | | 18 | |
| Variable lease income | 211 | | — | | — | | — | | 227 | | — | |
| Total lease income | $ | 329 | | $ | 39 | | $ | 16 | | $ | 9 | | $ | 274 | | $ | 18 | |
Lease payments received under tolling arrangements and PPAs consist of either scheduled payments or variable payments based on the amount of energy produced by the underlying electric generating units. Lease income for Alabama Power and Southern Power is included in wholesale revenues.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
(E) CONSOLIDATED ENTITIES AND EQUITY METHOD INVESTMENTS
See Note 7 to the financial statements in Item 8 of the Form 10-K for additional information.
Southern Company
At June 30, 2023 and December 31, 2022, Southern Holdings had equity method investments totaling $122 million and $112 million, respectively, primarily related to investments in venture capital funds focused on energy and utility investments. Earnings from these investments were immaterial for all periods presented.
Southern Power
Variable Interest Entities
Southern Power has certain subsidiaries that are determined to be VIEs. Southern Power is considered the primary beneficiary of these VIEs because it controls the most significant activities of the VIEs, including operating and maintaining the respective assets, and has the obligation to absorb expected losses of these VIEs to the extent of its equity interests.
SP Solar and SP Wind
At June 30, 2023 and December 31, 2022, SP Solar had total assets of $5.8 billion and $5.9 billion, respectively, total liabilities of $0.4 billion, and noncontrolling interests of $1.0 billion and $1.1 billion, respectively. Cash distributions from SP Solar are allocated 67% to Southern Power and 33% to Global Atlantic in accordance with their partnership interest percentage. Under the terms of the limited partnership agreement, distributions without limited partner consent are limited to available cash and SP Solar is obligated to distribute all such available cash to its partners each quarter. Available cash includes all cash generated in the quarter subject to the maintenance of appropriate operating reserves.
At June 30, 2023 and December 31, 2022, SP Wind had total assets of $2.2 billion, total liabilities of $175 million and $169 million, respectively, and noncontrolling interests of $39 million. Under the terms of the limited liability agreement, distributions without Class A member consent are limited to available cash and SP Wind is obligated to distribute all such available cash to its members each quarter. Available cash includes all cash generated in the quarter subject to the maintenance of appropriate operating reserves. Cash distributions from SP Wind are generally allocated 60% to Southern Power and 40% to the three financial investors in accordance with the limited liability agreement.
Southern Power consolidates both SP Solar and SP Wind, as the primary beneficiary, since it controls the most significant activities of each entity, including operating and maintaining their assets. Certain transfers and sales of the assets in the VIEs are subject to partner consent and the liabilities are non-recourse to the general credit of Southern Power. Liabilities consist of customary working capital items and do not include any long-term debt.
Other Variable Interest Entities
Southern Power has other consolidated VIEs that relate to certain subsidiaries that have either sold noncontrolling interests to tax equity investors or acquired less than a 100% interest from facility developers. These entities are considered VIEs because the arrangements are structured similar to a limited partnership and the noncontrolling members do not have substantive kick-out rights.
At June 30, 2023 and December 31, 2022, the other VIEs had total assets of $1.7 billion and $1.8 billion, respectively, total liabilities of $0.2 billion, and noncontrolling interests of $0.8 billion. Under the terms of the partnership agreements, distributions of all available cash are required each month or quarter and additional distributions require partner consent.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
Equity Method Investments
At December 31, 2022, Southern Power had equity method investments in wind and battery energy storage projects totaling $49 million. During the first quarter 2023, Southern Power sold its remaining equity method investments in the projects and received proceeds of $50 million. Earnings (loss) from these investments, including the gains associated with the sales, were immaterial for all periods presented.
Southern Company Gas
Equity Method Investments
The carrying amounts of Southern Company Gas' equity method investments at June 30, 2023 and December 31, 2022 and related earnings from those investments for the three and six months ended June 30, 2023 and 2022 were as follows:
| | | | | | | | |
| Investment Balance | June 30, 2023 | December 31, 2022 |
| (in millions) |
| SNG | $ | 1,220 | | $ | 1,243 | |
| Other | 32 | | 33 | |
| Total | $ | 1,252 | | $ | 1,276 | |
| | | | | | | | | | | | | | | | | |
| Three Months Ended June 30, | | Six Months Ended June 30, |
| Earnings from Equity Method Investments | 2023 | 2022 | | 2023 | 2022 |
| (in millions) |
| SNG | $ | 28 | | $ | 31 | | | $ | 72 | | $ | 70 | |
| Other | — | | — | | | — | | 1 | |
| Total | $ | 28 | | $ | 31 | | | $ | 72 | | $ | 71 | |
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
(F) FINANCING AND LEASES
Bank Credit Arrangements
See Note 8 to the financial statements under "Bank Credit Arrangements" in Item 8 of the Form 10-K for additional information.
At June 30, 2023, committed credit arrangements with banks were as follows:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Expires | | | | | | | | |
| Company | | 2024 | 2025 | 2026 | 2028 | | Total | | Unused | | | | | | | | Expires within
One Year |
| | (in millions) |
Southern Company parent(a) | | $ | 150 | | $ | — | | $ | — | | $ | 1,850 | | | $ | 2,000 | | | $ | 1,998 | | | | | | | | | $ | 150 | |
| Alabama Power | | 550 | | — | | — | | 700 | | | 1,250 | | | 1,250 | | | | | | | | | — | |
| Georgia Power | | — | | — | | — | | 1,750 | | | 1,750 | | | 1,726 | | | | | | | | | — | |
| Mississippi Power | | — | | 125 | | 150 | | — | | | 275 | | | 275 | | | | | | | | | — | |
Southern Power(a)(b) | | — | | — | | — | | 600 | | | 600 | | | 589 | | | | | | | | | — | |
Southern Company Gas(c) | | 100 | | — | | — | | 1,500 | | | 1,600 | | | 1,598 | | | | | | | | | 100 | |
| SEGCO | | 30 | | — | | — | | — | | | 30 | | | 30 | | | | | | | | | 30 | |
| Southern Company | | $ | 830 | | $ | 125 | | $ | 150 | | $ | 6,400 | | | $ | 7,505 | | | $ | 7,466 | | | | | | | | | $ | 280 | |
(a)Arrangement expiring in 2028 represents a $2.45 billion combined arrangement for Southern Company and Southern Power as borrowers. Pursuant to the combined facility, the allocations between Southern Company and Southern Power may be adjusted.
(b)Does not include Southern Power Company's $75 million and $100 million continuing letter of credit facilities for standby letters of credit, expiring in 2025 and 2026, respectively, of which $9 million and $16 million, respectively, was unused at June 30, 2023. In March 2023, Southern Power amended the $100 million letter of credit facility, which, among other things, extended the expiration date from 2025 to 2026 and increased the amount from $75 million. Southern Power's subsidiaries are not parties to its bank credit arrangements or letter of credit facilities.
(c)Southern Company Gas, as the parent entity, guarantees the obligations of Southern Company Gas Capital, which is the borrower of $800 million of the credit arrangement expiring in 2028. Southern Company Gas' committed credit arrangement expiring in 2028 also includes $700 million for which Nicor Gas is the borrower and which is restricted for working capital needs of Nicor Gas. Pursuant to the multi-year credit arrangement expiring in 2028, the allocations between Southern Company Gas Capital and Nicor Gas may be adjusted. Nicor Gas is also the borrower under a $100 million credit arrangement expiring in 2024.
As reflected in the table above, in May 2023, Southern Company and Southern Power combined and extended their multi-year credit arrangements previously maturing in 2026, resulting in a single aggregate $2.45 billion facility (currently allocated $1.85 billion for Southern Company and $600 million for Southern Power) maturing in 2028. Pursuant to the combined facility, the allocations between Southern Company and Southern Power may be adjusted. Alabama Power, Georgia Power, and Southern Company Gas Capital, along with Nicor Gas, amended and restated certain of their multi-year credit arrangements, which, among other things, extended the maturity dates from 2026 to 2028. Mississippi Power amended and restated certain of its multi-year credit arrangements aggregating $150 million, which, among other things, extended the maturity dates from 2024 to 2026. Nicor Gas also entered into a $100 million credit arrangement maturing in 2024 to replace its $250 million credit arrangement that expired in 2023. In June 2023, Southern Company also entered into a new $150 million credit arrangement maturing in 2024.
Subject to applicable market conditions, Southern Company and its subsidiaries expect to renew or replace their bank credit arrangements as needed, prior to expiration. In connection therewith, Southern Company and its subsidiaries may extend the maturity dates and/or increase or decrease the lending commitments thereunder.
These bank credit arrangements, as well as the term loan arrangements of the Registrants, Nicor Gas, and SEGCO, contain covenants that limit debt levels and contain cross-acceleration provisions to other indebtedness (including guarantee obligations) that are restricted only to the indebtedness of the individual company. The cross-acceleration
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
provisions to other indebtedness would trigger an event of default if the applicable borrower defaulted on indebtedness, the payment of which was then accelerated. At June 30, 2023, the Registrants, Nicor Gas, and SEGCO were in compliance with all such covenants. None of the bank credit arrangements contain material adverse change clauses at the time of borrowings.
A portion of the unused credit with banks is allocated to provide liquidity support to the revenue bonds of the traditional electric operating companies and the commercial paper programs of the Registrants, Nicor Gas, and SEGCO. The amount of variable rate revenue bonds of the traditional electric operating companies outstanding requiring liquidity support at June 30, 2023 was approximately $1.4 billion (comprised of approximately $492 million at Alabama Power, $819 million at Georgia Power, and $69 million at Mississippi Power). In addition, at June 30, 2023, Alabama Power and Georgia Power had approximately $120 million and $225 million, respectively, of fixed rate revenue bonds outstanding that are required to be remarketed within the next 12 months.
Convertible Senior Notes
In February 2023, Southern Company issued $1.5 billion aggregate principal amount of Series 2023A 3.875% Convertible Senior Notes due December 15, 2025 (Series 2023A Convertible Senior Notes). In March 2023, Southern Company issued an additional $225 million aggregate principal amount of the Series 2023A Convertible Senior Notes upon the exercise by the initial purchasers of their over-allotment option.
Interest on the Series 2023A Convertible Senior Notes is payable semiannually, beginning June 15, 2023. The Series 2023A Convertible Senior Notes will mature on December 15, 2025, unless earlier converted or repurchased, but are not redeemable at the option of Southern Company. The Series 2023A Convertible Senior Notes are direct, unsecured, and unsubordinated obligations of Southern Company, ranking equally with all of Southern Company's other unsecured and unsubordinated indebtedness from time to time outstanding, and are effectively subordinated to all secured indebtedness of Southern Company.
Holders may convert their Series 2023A Convertible Senior Notes at their option prior to the close of business on the business day preceding September 15, 2025, but only under the following circumstances:
•during any calendar quarter (and only during such calendar quarter), if the last reported sale price of Southern Company's common stock for at least 20 trading days (whether or not consecutive) during the period of 30 consecutive trading days ending on, and including, the last trading day of the immediately preceding calendar quarter is greater than or equal to 130% of the conversion price on each applicable trading day as determined by Southern Company;
•during the five business day period after any 10 consecutive trading day period (Measurement Period) in which the trading price per $1,000 principal amount of Series 2023A Convertible Senior Notes for each trading day of the Measurement Period was less than 98% of the product of the last reported sale price of the common stock and the conversion rate on each such trading day; or
•upon the occurrence of certain corporate events specified in the indenture governing the Series 2023A Convertible Senior Notes.
On or after September 15, 2025, a holder may convert all or any portion of its Series 2023A Convertible Senior Notes at any time prior to the close of business on the second scheduled trading day immediately preceding the maturity date regardless of the foregoing conditions.
Southern Company will settle conversions of the Series 2023A Convertible Senior Notes by paying cash up to the aggregate principal amount of the Series 2023A Convertible Senior Notes to be converted and paying or delivering, as the case may be, cash, shares of common stock or a combination of cash and shares of common stock, at Southern Company's election, in respect of the remainder, if any, of Southern Company's conversion obligation in excess of the aggregate principal amount of the Series 2023A Convertible Senior Notes being converted. The Series 2023A Convertible Senior Notes are initially convertible at a rate of 11.8818 shares of common stock per $1,000 principal amount converted, which is approximately equal to $84.16 per share of common stock. The conversion rate will be subject to adjustment upon the occurrence of certain specified events but will not be adjusted for
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
accrued and unpaid interest. In addition, upon the occurrence of a make-whole fundamental change (as defined in the indenture governing the Series 2023A Convertible Senior Notes), Southern Company will, in certain circumstances, increase the conversion rate by a number of additional shares of common stock for conversions in connection with the make-whole fundamental change.
Upon the occurrence of a fundamental change (as defined in the indenture governing the Series 2023A Convertible Senior Notes), holders of the Series 2023A Convertible Senior Notes may require Southern Company to purchase all or a portion of their Series 2023A Convertible Senior Notes, in principal amounts equal to $1,000 or an integral multiple thereof, for cash at a price equal to 100% of the principal amount of the Series 2023A Convertible Senior Notes to be purchased plus any accrued and unpaid interest.
Earnings per Share
For Southern Company, the only difference in computing basic and diluted earnings per share (EPS) is attributable to awards outstanding under stock-based compensation plans, the Series 2023A Convertible Senior Notes, and the equity units issued in 2019 and settled in August 2022. EPS dilution resulting from stock-based compensation plans and the equity units is determined using the treasury stock method and EPS dilution resulting from the Series 2023A Convertible Senior Notes is determined using the net share settlement method. See Note 12 to the financial statements in Item 8 of the Form 10-K, "Convertible Senior Notes" herein, and Note 8 to the financial statements under "Equity Units" in Item 8 of the Form 10-K for additional information. Shares used to compute diluted EPS were as follows:
| | | | | | | | | | | | | | |
| Three Months Ended June 30, | Six Months Ended June 30, |
| 2023 | 2022 | 2023 | 2022 |
| | (in millions) |
| As reported shares | 1,092 | | 1,065 | | 1,092 | | 1,064 | |
| Effect of stock-based compensation | 6 | | 5 | | 6 | | 5 | |
| Effect of equity units | — | | 2 | | — | | 1 | |
| Diluted shares | 1,098 | | 1,072 | | 1,098 | | 1,070 | |
For all periods presented, an immaterial number of stock-based compensation awards was excluded from the diluted EPS calculation because the awards were anti-dilutive.
For all periods presented, there was no dilution resulting from the Series 2023A Convertible Senior Notes.
Southern Company Leveraged Lease
See Note 9 to the financial statements in Item 8 of the Form 10-K for information on a leveraged lease agreement related to energy generation. In June 2022, the Southern Holdings subsidiary operating the generating plant for the lessee provided notice to the lessee to terminate the related operating and maintenance agreement effective June 30, 2023. Subsequently, the lessee failed to make the semi-annual lease payment due in December 2022. As a result, the Southern Holdings subsidiary was unable to make its corresponding payment to the holders of the underlying non-recourse debt related to the generation assets. The parties to the lease entered into forbearance agreements which suspended the related contractual rights of the parties while they continued restructuring negotiations, during which the termination date for the operating and maintenance agreement was delayed until July 31, 2023. The negotiations were completed on July 14, 2023, resulting in the Southern Holdings subsidiary agreeing to continue operating the plant for the lessee until the lessee's associated power off-take agreement ends in 2032, subject to certain terms and conditions. The restructuring had no material impact on Southern Company's financial statements. Southern Company will continue to monitor the operational performance of the underlying assets and evaluate the ability of the lessee to continue to meet its obligations, including those associated with a future closure or retirement of the generation assets and associated properties, including the dry ash landfill.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
(G) INCOME TAXES
See Note 10 to the financial statements in Item 8 of the Form 10-K for additional tax information.
Current and Deferred Income Taxes
Tax Credit and Net Operating Loss Carryforwards
Southern Company's federal PTC and ITC carryforwards begin expiring in 2031, but are expected to be fully utilized by 2027. The utilization of each Registrant's estimated tax credit and state net operating loss carryforwards and related valuation allowances could be impacted by numerous factors, including the acquisition of additional renewable projects, an increase in Georgia Power's ownership interest in Plant Vogtle Units 3 and 4, changes in taxable income projections, and potential income tax rate changes. See Note (B) and Note 2 to the financial statements in Item 8 of the Form 10-K under "Georgia Power – Nuclear Construction" for additional information on Plant Vogtle Units 3 and 4.
Effective Tax Rate
Southern Company's effective tax rate is typically lower than the statutory rate due to employee stock plans' dividend deduction, non-taxable AFUDC equity at the traditional electric operating companies, flowback of excess deferred income taxes at the regulated utilities, and federal income tax benefits from ITCs and PTCs primarily at Southern Power.
Details of significant changes in the effective tax rate for the applicable Registrants are provided herein.
Southern Company
Southern Company's effective tax rate was 10.7% for the six months ended June 30, 2023 compared to 18.7% for the corresponding period in 2022. The effective tax rate decrease was primarily due to an increase in the flowback of certain excess deferred income taxes at Alabama Power in 2023, lower pre-tax earnings in 2023, and an adjustment related to state tax credit carryforwards and the related valuation allowance at Georgia Power in 2022 and 2023, partially offset by the flowback of certain excess deferred income taxes ending in 2022 at Georgia Power.
Alabama Power
Alabama Power's effective tax rate was 3.9% for the six months ended June 30, 2023 compared to 23.6% for the corresponding period in 2022. The effective tax rate decrease was primarily due to an increase in the flowback of certain excess deferred income taxes in 2023 and lower pre-tax earnings in 2023. See Note 2 to the financial statements under "Alabama Power – Excess Accumulated Deferred Income Tax Accounting Order" in Item 8 of the Form 10-K for additional information.
Georgia Power
Georgia Power's effective tax rate was 15.8% for the six months ended June 30, 2023 compared to 16.4% for the corresponding period in 2022. The effective tax rate decrease was primarily due to an adjustment related to state tax credit carryforwards in 2022, a decrease in a valuation allowance on certain state tax credit carryforwards in 2023, and lower pre-tax earnings in 2023, largely offset by the flowback of certain excess deferred income taxes ending in 2022.
Mississippi Power
Mississippi Power's effective tax rate was 15.2% for the six months ended June 30, 2023 compared to 18.8% for the corresponding period in 2022. The effective tax rate decrease was primarily due to an increase in the flowback of certain excess deferred income taxes in 2023.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
Southern Power
Southern Power's effective tax benefit rate was (0.7)% for the six months ended June 30, 2023 compared to an effective tax rate of 11.2% for the corresponding period in 2022. The effective tax rate decrease was primarily due to changes in state apportionment methodology resulting from tax legislation enacted by the State of Tennessee in May 2023.
Unrecognized Tax Benefits
Southern Company's and Georgia Power's unrecognized tax positions balances at June 30, 2023 were $130 million and $48 million, respectively, compared to $80 million for Southern Company at December 31, 2022. The increases from prior periods are primarily related to the amendment of certain 2019 state tax filing positions related to tax credit utilization. If accepted by the state, these positions would decrease Southern Company's and Georgia Power's effective tax rates. The ultimate outcome of this unrecognized tax benefit is dependent on acceptance by the state and is expected to be resolved in the next 12 months.
(H) RETIREMENT BENEFITS
The Southern Company system has a qualified defined benefit, trusteed, pension plan covering substantially all employees, with the exception of employees at PowerSecure. The qualified pension plan is funded in accordance with requirements of the Employee Retirement Income Security Act of 1974, as amended (ERISA). No mandatory contributions to the qualified pension plan are anticipated for the year ending December 31, 2023. The Southern Company system also provides certain non-qualified defined benefits for a select group of management and highly compensated employees, which are funded on a cash basis. In addition, the Southern Company system provides certain medical care and life insurance benefits for retired employees through other postretirement benefit plans. The traditional electric operating companies fund other postretirement trusts to the extent required by their respective regulatory commissions. Southern Company Gas has a separate unfunded supplemental retirement health care plan that provides medical care and life insurance benefits to employees of discontinued businesses.
See Note 11 to the financial statements in Item 8 of the Form 10-K for additional information.
On each Registrant's condensed statements of income, the service cost component of net periodic benefit costs is included in other operations and maintenance expenses and all other components of net periodic benefit costs are included in other income (expense), net. Components of the net periodic benefit costs for the three and six months ended June 30, 2023 and 2022 are presented in the following tables.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Southern
Company | | Alabama
Power | | Georgia
Power | | Mississippi
Power | | Southern Power | | Southern Company Gas |
| (in millions) |
| Three Months Ended June 30, 2023 | | | | | | | | | | |
| Pension Plans | | | | | | | | | | | |
| Service cost | $ | 69 | | | $ | 16 | | | $ | 17 | | | $ | 3 | | | $ | 1 | | | $ | 6 | |
| Interest cost | 157 | | | 36 | | | 47 | | | 7 | | | 2 | | | 11 | |
| Expected return on plan assets | (308) | | | (74) | | | (96) | | | (14) | | | (4) | | | (22) | |
| Amortization: | | | | | | | | | | | |
| Prior service costs | — | | | — | | | 1 | | | — | | | — | | | (1) | |
| Regulatory asset | — | | | — | | | — | | | — | | | — | | | 4 | |
| Net (gain) loss | 8 | | | 3 | | | 3 | | | — | | | — | | | (1) | |
| Net periodic pension income | $ | (74) | | | $ | (19) | | | $ | (28) | | | $ | (4) | | | $ | (1) | | | $ | (3) | |
| | | | | | | | | | | |
| Postretirement Benefits | | | | | | | | | | | |
| Service cost | $ | 3 | | | $ | 1 | | | $ | 1 | | | $ | — | | | $ | — | | | $ | — | |
| Interest cost | 17 | | | 4 | | | 7 | | | 1 | | | — | | | 2 | |
| Expected return on plan assets | (20) | | | (9) | | | (8) | | | — | | | — | | | (2) | |
| Amortization: | | | | | | | | | | | |
| Prior service costs | 1 | | | — | | | — | | | — | | | — | | | — | |
| Regulatory asset | — | | | — | | | — | | | — | | | — | | | 2 | |
| Net gain | (3) | | | — | | | (1) | | | — | | | — | | | (1) | |
| Net periodic postretirement benefit cost (income) | $ | (2) | | | $ | (4) | | | $ | (1) | | | $ | 1 | | | $ | — | | | $ | 1 | |
| | | | | | | | | | | |
| Six Months Ended June 30, 2023 | | | | | | | | | | |
| Pension Plans |
| Service cost | $ | 138 | | | $ | 32 | | | $ | 34 | | | $ | 6 | | | $ | 3 | | | $ | 12 | |
| Interest cost | 313 | | | 72 | | | 95 | | | 14 | | | 4 | | | 21 | |
| Expected return on plan assets | (615) | | | (148) | | | (192) | | | (28) | | | (8) | | | (44) | |
| Amortization: | | | | | | | | | | | |
| Prior service costs | — | | | — | | | 1 | | | — | | | — | | | (1) | |
| Regulatory asset | — | | | — | | | — | | | — | | | — | | | 8 | |
| Net (gain) loss | 16 | | | 5 | | | 6 | | | — | | | — | | | (2) | |
| Net periodic pension income | $ | (148) | | | $ | (39) | | | $ | (56) | | | $ | (8) | | | $ | (1) | | | $ | (6) | |
| | | | | | | | | | | |
| Postretirement Benefits |
| Service cost | $ | 7 | | | $ | 2 | | | $ | 2 | | | $ | — | | | $ | — | | | $ | — | |
| Interest cost | 35 | | | 8 | | | 13 | | | 2 | | | — | | | 4 | |
| Expected return on plan assets | (41) | | | (17) | | | (15) | | | (1) | | | — | | | (3) | |
| Amortization: | | | | | | | | | | | |
| Prior service costs | 1 | | | — | | | — | | | — | | | — | | | — | |
| Regulatory asset | — | | | — | | | — | | | — | | | — | | | 3 | |
| Net gain | (6) | | | (1) | | | (2) | | | — | | | — | | | (2) | |
| Net periodic postretirement benefit cost (income) | $ | (4) | | | $ | (8) | | | $ | (2) | | | $ | 1 | | | $ | — | | | $ | 2 | |
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Southern
Company | | Alabama
Power | | Georgia
Power | | Mississippi
Power | | Southern Power | | Southern Company Gas |
| (in millions) |
| Three Months Ended June 30, 2022 | | | | | | | | | | |
| Pension Plans |
| Service cost | $ | 103 | | | $ | 24 | | | $ | 26 | | | $ | 4 | | | $ | 3 | | | $ | 8 | |
| Interest cost | 102 | | | 24 | | | 30 | | | 4 | | | 1 | | | 7 | |
| Expected return on plan assets | (317) | | | (75) | | | (100) | | | (14) | | | (4) | | | (24) | |
| Amortization: | | | | | | | | | | | |
| Prior service costs | — | | | — | | | 1 | | | — | | | — | | | — | |
| Regulatory asset | — | | | — | | | — | | | — | | | — | | | 4 | |
| Net loss | 60 | | | 15 | | | 19 | | | 4 | | | — | | | 1 | |
| Net periodic pension income | $ | (52) | | | $ | (12) | | | $ | (24) | | | $ | (2) | | | $ | — | | | $ | (4) | |
| | | | | | | | | | | |
| Postretirement Benefits | | | | | | | | | | | |
| Service cost | $ | 5 | | | $ | 2 | | | $ | 1 | | | $ | — | | | $ | — | | | $ | — | |
| Interest cost | 11 | | | 2 | | | 3 | | | 1 | | | — | | | 1 | |
| Expected return on plan assets | (20) | | | (8) | | | (6) | | | (1) | | | — | | | (1) | |
| Amortization: | | | | | | | | | | | |
| | | | | | | | | | | |
| Regulatory asset | — | | | — | | | — | | | — | | | — | | | 1 | |
| Net loss | — | | | — | | | 1 | | | — | | | — | | | — | |
| Net periodic postretirement benefit cost (income) | $ | (4) | | | $ | (4) | | | $ | (1) | | | $ | — | | | $ | — | | | $ | 1 | |
| | | | | | | | | | | |
| Six Months Ended June 30, 2022 | | | | | | | | | | |
| Pension Plans |
| Service cost | $ | 206 | | | $ | 49 | | | $ | 52 | | | $ | 8 | | | $ | 5 | | | $ | 17 | |
| Interest cost | 204 | | | 48 | | | 61 | | | 9 | | | 3 | | | 14 | |
| Expected return on plan assets | (633) | | | (152) | | | (199) | | | (29) | | | (8) | | | (46) | |
| Amortization: | | | | | | | | | | | |
| Prior service costs | — | | | — | | | 1 | | | — | | | — | | | (1) | |
| Regulatory asset | — | | | — | | | — | | | — | | | — | | | 8 | |
| Net loss | 120 | | | 31 | | | 37 | | | 7 | | | 1 | | | 3 | |
| Net periodic pension cost (income) | $ | (103) | | | $ | (24) | | | $ | (48) | | | $ | (5) | | | $ | 1 | | | $ | (5) | |
| | | | | | | | | | | |
| Postretirement Benefits |
| Service cost | $ | 11 | | | $ | 3 | | | $ | 3 | | | $ | — | | | $ | — | | | $ | 1 | |
| Interest cost | 21 | | | 5 | | | 7 | | | 1 | | | — | | | 2 | |
| Expected return on plan assets | (40) | | | (16) | | | (13) | | | (1) | | | — | | | (3) | |
| Amortization: | | | | | | | | | | | |
| | | | | | | | | | | |
| Regulatory asset | — | | | — | | | — | | | — | | | — | | | 3 | |
| Net (gain) loss | — | | | — | | | 1 | | | — | | | — | | | (1) | |
| Net periodic postretirement benefit cost (income) | $ | (8) | | | $ | (8) | | | $ | (2) | | | $ | — | | | $ | — | | | $ | 2 | |
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
(I) FAIR VALUE MEASUREMENTS
At June 30, 2023, assets and liabilities measured at fair value on a recurring basis during the period, together with their associated level of the fair value hierarchy, were as follows:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Fair Value Measurements Using: | | |
| At June 30, 2023 | Quoted Prices
in Active
Markets for
Identical
Assets
(Level 1) | | Significant
Other
Observable
Inputs
(Level 2) | | Significant
Unobservable
Inputs
(Level 3) | | Net Asset Value as a Practical Expedient (NAV) | | Total |
| (in millions) |
| Southern Company | | | | | | | | | |
| Assets: | | | | | | | | | |
Energy-related derivatives(a) | $ | 7 | | | $ | 86 | | | $ | — | | | $ | — | | | $ | 93 | |
| Interest rate derivatives | — | | | 4 | | | — | | | — | | | 4 | |
| | | | | | | | | |
Investments in trusts:(b)(c) | | | | | | | | | |
| Domestic equity | 718 | | | 205 | | | — | | | — | | | 923 | |
| Foreign equity | 140 | | | 167 | | | — | | | — | | | 307 | |
| U.S. Treasury and government agency securities | — | | | 333 | | | — | | | — | | | 333 | |
| Municipal bonds | — | | | 46 | | | — | | | — | | | 46 | |
| Pooled funds – fixed income | — | | | 7 | | | — | | | — | | | 7 | |
| Corporate bonds | — | | | 391 | | | — | | | — | | | 391 | |
| Mortgage and asset backed securities | — | | | 90 | | | — | | | — | | | 90 | |
| Private equity | — | | | — | | | — | | | 166 | | | 166 | |
| Cash and cash equivalents | 2 | | | — | | | — | | | — | | | 2 | |
| Other | 31 | | | 7 | | | — | | | 9 | | | 47 | |
| Cash equivalents | 1,494 | | | 12 | | | — | | | — | | | 1,506 | |
| Other investments | 9 | | | 34 | | | 8 | | | — | | | 51 | |
| Total | $ | 2,401 | | | $ | 1,382 | | | $ | 8 | | | $ | 175 | | | $ | 3,966 | |
| Liabilities: | | | | | | | | | |
Energy-related derivatives(a) | $ | 33 | | | $ | 278 | | | $ | — | | | $ | — | | | $ | 311 | |
| Interest rate derivatives | — | | | 304 | | | — | | | — | | | 304 | |
| Foreign currency derivatives | — | | | 170 | | | — | | | — | | | 170 | |
| Contingent consideration | — | | | — | | | 12 | | | — | | | 12 | |
| Other | — | | | 13 | | | — | | | — | | | 13 | |
| Total | $ | 33 | | | $ | 765 | | | $ | 12 | | | $ | — | | | $ | 810 | |
| | | | | | | | | |
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Fair Value Measurements Using: | | |
| At June 30, 2023 | Quoted Prices
in Active
Markets for
Identical
Assets
(Level 1) | | Significant
Other
Observable
Inputs
(Level 2) | | Significant
Unobservable
Inputs
(Level 3) | | Net Asset Value as a Practical Expedient (NAV) | | Total |
| (in millions) |
| Alabama Power | | | | | | | | | |
| Assets: | | | | | | | | | |
| Energy-related derivatives | $ | — | | | $ | 32 | | | $ | — | | | $ | — | | | $ | 32 | |
| | | | | | | | | |
Nuclear decommissioning trusts:(b) | | | | | | | | | |
| Domestic equity | 420 | | | 198 | | | — | | | — | | | 618 | |
| Foreign equity | 140 | | | — | | | — | | | — | | | 140 | |
| U.S. Treasury and government agency securities | — | | | 20 | | | — | | | — | | | 20 | |
| Municipal bonds | — | | | 1 | | | — | | | — | | | 1 | |
| Corporate bonds | — | | | 221 | | | — | | | — | | | 221 | |
| Mortgage and asset backed securities | — | | | 21 | | | — | | | — | | | 21 | |
| Private equity | — | | | — | | | — | | | 166 | | | 166 | |
| Other | 7 | | | — | | | — | | | 9 | | | 16 | |
| Cash equivalents | 110 | | | 12 | | | — | | | — | | | 122 | |
| Other investments | — | | | 34 | | | — | | | — | | | 34 | |
| Total | $ | 677 | | | $ | 539 | | | $ | — | | | $ | 175 | | | $ | 1,391 | |
| Liabilities: | | | | | | | | | |
| Energy-related derivatives | $ | — | | | $ | 84 | | | $ | — | | | $ | — | | | $ | 84 | |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
| Georgia Power | | | | | | | | | |
| Assets: | | | | | | | | | |
| Energy-related derivatives | $ | — | | | $ | 17 | | | $ | — | | | $ | — | | | $ | 17 | |
| | | | | | | | | |
Nuclear decommissioning trusts:(b)(c) | | | | | | | | | |
| Domestic equity | 298 | | | 1 | | | — | | | — | | | 299 | |
| Foreign equity | | | 166 | | | — | | | — | | | 166 | |
| U.S. Treasury and government agency securities | — | | | 313 | | | — | | | — | | | 313 | |
| Municipal bonds | — | | | 45 | | | — | | | — | | | 45 | |
| Corporate bonds | — | | | 170 | | | — | | | — | | | 170 | |
| Mortgage and asset backed securities | — | | | 69 | | | — | | | — | | | 69 | |
| Other | 24 | | | 7 | | | — | | | — | | | 31 | |
| | | | | | | | | |
| Total | $ | 322 | | | $ | 788 | | | $ | — | | | $ | — | | | $ | 1,110 | |
| Liabilities: | | | | | | | | | |
| Energy-related derivatives | $ | — | | | $ | 102 | | | $ | — | | | $ | — | | | $ | 102 | |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Fair Value Measurements Using: | | |
| At June 30, 2023 | Quoted Prices
in Active
Markets for
Identical
Assets
(Level 1) | | Significant
Other
Observable
Inputs
(Level 2) | | Significant
Unobservable
Inputs
(Level 3) | | Net Asset Value as a Practical Expedient (NAV) | | Total |
| (in millions) |
| Mississippi Power | | | | | | | | | |
| Assets: | | | | | | | | | |
| Energy-related derivatives | $ | — | | | $ | 27 | | | $ | — | | | $ | — | | | $ | 27 | |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
| Liabilities: | | | | | | | | | |
| Energy-related derivatives | $ | — | | | $ | 55 | | | $ | — | | | $ | — | | | $ | 55 | |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
| Southern Power | | | | | | | | | |
| Assets: | | | | | | | | | |
| Energy-related derivatives | $ | — | | | $ | 4 | | | $ | — | | | $ | — | | | $ | 4 | |
| | | | | | | | | |
| Cash equivalents | 5 | | | — | | | — | | | — | | | 5 | |
| Total | $ | 5 | | | $ | 4 | | | $ | — | | | $ | — | | | $ | 9 | |
| Liabilities: | | | | | | | | | |
| Energy-related derivatives | $ | — | | | $ | 10 | | | $ | — | | | $ | — | | | $ | 10 | |
| Foreign currency derivatives | — | | | 28 | | | — | | | — | | | 28 | |
| Contingent consideration | — | | | — | | | 12 | | | — | | | 12 | |
| Other | — | | | 13 | | | — | | | — | | | 13 | |
| Total | $ | — | | | $ | 51 | | | $ | 12 | | | $ | — | | | $ | 63 | |
| | | | | | | | | |
| Southern Company Gas | | | | | | | | | |
| Assets: | | | | | | | | | |
Energy-related derivatives(a) | $ | 7 | | | $ | 6 | | | $ | — | | | $ | — | | | $ | 13 | |
| Interest rate derivatives | — | | | 4 | | | — | | | — | | | 4 | |
| Non-qualified deferred compensation trusts: | | | | | | | | | |
| Domestic equity | — | | | 6 | | | — | | | — | | | 6 | |
| Foreign equity | — | | | 1 | | | — | | | — | | | 1 | |
| Pooled funds – fixed income | — | | | 7 | | | — | | | — | | | 7 | |
| Cash equivalents | 2 | | | — | | | — | | | — | | | 2 | |
| Cash equivalents and restricted cash | 215 | | | — | | | — | | | — | | | 215 | |
| | | | | | | | | |
| Total | $ | 224 | | | $ | 24 | | | $ | — | | | $ | — | | | $ | 248 | |
| Liabilities: | | | | | | | | | |
Energy-related derivatives(a) | $ | 33 | | | $ | 27 | | | $ | — | | | $ | — | | | $ | 60 | |
| Interest rate derivatives | — | | | 88 | | | — | | | — | | | 88 | |
| | | | | | | | | |
| Total | $ | 33 | | | $ | 115 | | | $ | — | | | $ | — | | | $ | 148 | |
(a)Excludes cash collateral of $52 million.
(b)Excludes receivables related to investment income, pending investment sales, payables related to pending investment purchases, and currencies. See Note 6 to the financial statements in Item 8 of the Form 10-K for additional information.
(c)Includes investment securities pledged to creditors and collateral received and excludes payables related to the securities lending program. At June 30, 2023, approximately $25 million of the fair market value of Georgia Power's nuclear decommissioning trust funds' securities were on loan to creditors under the funds' managers' securities lending program. See Note 6 to the financial statements in Item 8 of the Form 10-K for additional information.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
Southern Company, Alabama Power, and Georgia Power continue to elect the option to fair value investment securities held in the nuclear decommissioning trust funds. The fair value of the funds, including reinvested interest and dividends and excluding the funds' expenses, increased (decreased) by the amounts shown in the table below for the three and six months ended June 30, 2023 and 2022. The changes were recorded as a change to the regulatory assets and liabilities related to AROs for Georgia Power and Alabama Power, respectively.
| | | | | | | | | | | | | | |
| Three Months Ended | Six Months Ended |
| Fair value increases (decreases) | June 30, 2023 | June 30, 2022 | June 30, 2023 | June 30, 2022 |
| (in millions) |
| Southern Company | $ | 132 | | $ | (230) | | $ | 228 | | $ | (380) | |
| Alabama Power | 58 | | (125) | | 103 | | (192) | |
| Georgia Power | 74 | | (105) | | 125 | | (188) | |
Valuation Methodologies
The energy-related derivatives primarily consist of exchange-traded and over-the-counter financial products for natural gas and physical power products, including, from time to time, basis swaps. These are standard products used within the energy industry and are valued using the market approach. The inputs used are mainly from observable market sources, such as forward natural gas prices, power prices, implied volatility, and overnight index swap interest rates. Interest rate derivatives are also standard over-the-counter products that are valued using observable market data and assumptions commonly used by market participants. The fair value of interest rate derivatives reflects the net present value of expected payments and receipts under the swap agreement based on the market's expectation of future interest rates. Additional inputs to the net present value calculation may include the contract terms, counterparty credit risk, and occasionally, implied volatility of interest rate options. The fair value of cross-currency swaps reflects the net present value of expected payments and receipts under the swap agreement based on the market's expectation of future foreign currency exchange rates. Additional inputs to the net present value calculation may include the contract terms, counterparty credit risk, and discount rates. The interest rate derivatives and cross-currency swaps are categorized as Level 2 under Fair Value Measurements as these inputs are based on observable data and valuations of similar instruments. See Note (J) for additional information on how these derivatives are used.
For fair value measurements of the investments within the nuclear decommissioning trusts and the non-qualified deferred compensation trusts, external pricing vendors are designated for each asset class with each security specifically assigned a primary pricing source. For investments held within commingled funds, fair value is determined at the end of each business day through the net asset value, which is established by obtaining the underlying securities' individual prices from the primary pricing source. A market price secured from the primary source vendor is then evaluated by management in its valuation of the assets within the trusts. As a general approach, fixed income market pricing vendors gather market data (including indices and market research reports) and integrate relative credit information, observed market movements, and sector news into proprietary pricing models, pricing systems, and mathematical tools. Dealer quotes and other market information, including live trading levels and pricing analysts' judgments, are also obtained when available.
The NRC requires licensees of commissioned nuclear power reactors to establish a plan for providing reasonable assurance of funds for future decommissioning. See Note 6 to the financial statements under "Nuclear Decommissioning" in Item 8 of the Form 10-K for additional information.
Southern Power has contingent payment obligations related to certain acquisitions whereby it is primarily obligated to make generation-based payments to the seller, which commenced at the commercial operation of the respective facility and continue through 2026. The obligations are categorized as Level 3 under Fair Value Measurements as the fair value is determined using significant unobservable inputs for the forecasted facility generation in MW-hours, as well as other inputs such as a fixed dollar amount per MW-hour, and a discount rate. The fair value of contingent consideration reflects the net present value of expected payments and any periodic change arising from forecasted generation is expected to be immaterial.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
Southern Power also has payment obligations through 2040 whereby it must reimburse the transmission owners for interconnection facilities and network upgrades constructed to support connection of a Southern Power generating facility to the transmission system. The obligations are categorized as Level 2 under Fair Value Measurements as the fair value is determined using observable inputs for the contracted amounts and reimbursement period, as well as a discount rate. The fair value of the obligations reflects the net present value of expected payments.
"Other investments" primarily includes investments traded in the open market that have maturities greater than 90 days, which are categorized as Level 2 under Fair Value Measurements and are comprised of corporate bonds, bank certificates of deposit, treasury bonds, and/or agency bonds.
At June 30, 2023, the fair value measurements of private market investments held in Alabama Power's nuclear decommissioning trusts that are calculated at net asset value per share (or its equivalent) as a practical expedient totaled $175 million and unfunded commitments related to the private market investments totaled $77 million. Private market investments include high-quality private equity funds across several market sectors, funds that invest in real estate assets, and a private credit fund. Private market funds do not have redemption rights. Distributions from these funds will be received as the underlying investments in the funds are liquidated.
At June 30, 2023, other financial instruments for which the carrying amount did not equal fair value were as follows:
| | | | | | | | | | | | | | | | | | | | |
| Southern
Company | Alabama Power | Georgia Power | Mississippi Power | Southern Power | Southern Company Gas(*) |
| (in billions) |
| Long-term debt, including securities due within one year: | | | | |
| Carrying amount | $ | 58.9 | | $ | 10.8 | | $ | 16.5 | | $ | 1.6 | | $ | 3.0 | | $ | 7.5 | |
| Fair value | 53.5 | | 9.5 | | 15.0 | | 1.4 | | 2.8 | | 6.6 | |
(*)The long-term debt of Southern Company Gas is recorded at amortized cost, including the fair value adjustments at the effective date of the 2016 merger with Southern Company. Southern Company Gas amortizes the fair value adjustments over the remaining lives of the respective bonds, the latest being through 2043.
The fair values are determined using Level 2 measurements and are based on quoted market prices for the same or similar issues or on the current rates available to the Registrants.
(J) DERIVATIVES
The Registrants are exposed to market risks, including commodity price risk, interest rate risk, weather risk, and occasionally foreign currency exchange rate risk. To manage the volatility attributable to these exposures, each company nets its exposures, where possible, to take advantage of natural offsets and enters into various derivative transactions for the remaining exposures pursuant to each company's policies in areas such as counterparty exposure and risk management practices. For the traditional electric operating companies, Southern Power, and Southern Company Gas' other businesses, each company's policy is that derivatives are to be used primarily for hedging purposes and mandates strict adherence to all applicable risk management policies. Derivative positions are monitored using techniques including, but not limited to, market valuation, value at risk, stress testing, and sensitivity analysis. Derivative instruments are recognized at fair value in the balance sheets as either assets or liabilities and are presented on a net basis. See Note (I) for additional fair value information. In the statements of cash flows, any cash impacts of settled energy-related and interest rate derivatives are recorded as operating activities. Any cash impacts of settled foreign currency derivatives are classified as operating or financing activities to correspond with the classification of the hedged interest or principal, respectively. See Note 1 to the financial statements under "Financial Instruments" in Item 8 of the Form 10-K for additional information.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
Energy-Related Derivatives
The Subsidiary Registrants enter into energy-related derivatives to hedge exposures to electricity, natural gas, and other fuel price changes. However, due to cost-based rate regulations and other various cost recovery mechanisms, the traditional electric operating companies and the natural gas distribution utilities have limited exposure to market volatility in energy-related commodity prices. Each of the traditional electric operating companies and certain of the natural gas distribution utilities of Southern Company Gas manage fuel-hedging programs, implemented per the guidelines of their respective state PSCs or other applicable state regulatory agencies, through the use of financial derivative contracts, which are expected to continue to mitigate price volatility. The traditional electric operating companies (with respect to wholesale generating capacity) and Southern Power have limited exposure to market volatility in energy-related commodity prices because their long-term sales contracts shift substantially all fuel cost responsibility to the purchaser. However, the traditional electric operating companies and Southern Power may be exposed to market volatility in energy-related commodity prices to the extent any uncontracted capacity is used to sell electricity. Southern Company Gas retains exposure to price changes that can, in a volatile energy market, be material and can adversely affect its results of operations.
Southern Company Gas also enters into weather derivative contracts as economic hedges in the event of warmer-than-normal weather. Exchange-traded options are carried at fair value, with changes reflected in operating revenues. Non-exchange-traded options are accounted for using the intrinsic value method. Changes in the intrinsic value for non-exchange-traded contracts are reflected in operating revenues.
Energy-related derivative contracts are accounted for under one of three methods:
•Regulatory Hedges – Energy-related derivative contracts designated as regulatory hedges relate primarily to the traditional electric operating companies' and the natural gas distribution utilities' fuel-hedging programs, where gains and losses are initially recorded as regulatory liabilities and assets, respectively, and then are included in fuel expense as the underlying fuel is used in operations and ultimately recovered through an approved cost recovery mechanism.
•Cash Flow Hedges – Gains and losses on energy-related derivatives designated as cash flow hedges (which are mainly used to hedge anticipated purchases and sales) are initially deferred in accumulated OCI before being recognized in the statements of income in the same period and in the same income statement line item as the earnings effect of the hedged transactions.
•Not Designated – Gains and losses on energy-related derivative contracts that are not designated or fail to qualify as hedges are recognized in the statements of income as incurred.
Some energy-related derivative contracts require physical delivery as opposed to financial settlement, and this type of derivative is both common and prevalent within the electric and natural gas industries. When an energy-related derivative contract is settled physically, any cumulative unrealized gain or loss is reversed and the contract price is recognized in the respective line item representing the actual price of the underlying goods being delivered.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
At June 30, 2023, the net volume of energy-related derivative contracts for natural gas positions, together with the longest hedge date over which the respective entity is hedging its exposure to the variability in future cash flows for forecasted transactions and the longest non-hedge date for derivatives not designated as hedges, were as follows:
| | | | | | | | | | | | | | | | | |
| Net
Purchased
mmBtu | | Longest
Hedge
Date | | Longest
Non-Hedge
Date |
| (in millions) | | | | |
Southern Company(*) | 422 | | 2030 | | 2028 |
| Alabama Power | 108 | | 2026 | | 2023 |
| Georgia Power | 109 | | 2026 | | 2023 |
| Mississippi Power | 85 | | 2027 | | 2023 |
| Southern Power | 10 | | 2030 | | 2024 |
Southern Company Gas(*) | 110 | | 2028 | | 2028 |
(*)Southern Company Gas' derivative instruments include both long and short natural gas positions. A long position is a contract to purchase natural gas and a short position is a contract to sell natural gas. Southern Company Gas' volume represents the net of 119.7 million mmBtu long natural gas positions and 9.4 million mmBtu short natural gas positions at June 30, 2023, which is also included in Southern Company's total volume.
In addition to the volumes discussed above, the traditional electric operating companies and Southern Power enter into physical natural gas supply contracts that provide the option to sell back excess natural gas due to operational constraints. The maximum expected volume of natural gas subject to such a feature is 11 million mmBtu for Southern Company, which includes 3 million mmBtu for Alabama Power, 4 million mmBtu for Georgia Power, 1 million mmBtu for Mississippi Power, and 3 million mmBtu for Southern Power.
For cash flow hedges of energy-related derivatives, the estimated pre-tax losses expected to be reclassified from accumulated OCI to earnings for the 12-month period ending June 30, 2024 are $33 million for Southern Company, $24 million for Southern Company Gas, and $9 million for Southern Power.
Interest Rate Derivatives
Southern Company and certain subsidiaries may enter into interest rate derivatives to hedge exposure to changes in interest rates. Derivatives related to existing variable rate securities or forecasted transactions are accounted for as cash flow hedges where the derivatives' fair value gains or losses are recorded in OCI and are reclassified into earnings at the same time and presented on the same income statement line item as the earnings effect of the hedged transactions. Derivatives related to existing fixed rate securities are accounted for as fair value hedges, where the derivatives' fair value gains or losses and hedged items' fair value gains or losses are both recorded directly to earnings on the same income statement line item. Fair value gains or losses on derivatives that are not designated or fail to qualify as hedges are recognized in the statements of income as incurred.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
At June 30, 2023, the following interest rate derivatives were outstanding:
| | | | | | | | | | | | | | | | | | | | |
| Notional
Amount | | Weighted
Average Interest
Rate Paid | Interest
Rate
Received | Hedge
Maturity
Date | Fair Value Gain (Loss) at June 30, 2023 |
| | (in millions) | | | | | (in millions) |
| Cash Flow Hedges of Forecasted Debt | | | | | |
| Southern Company Gas | $ | 250 | | | 3.40% | N/A | August
2033 | $ | 4 | |
| Fair Value Hedges of Existing Debt | | | | | |
| Southern Company parent | 400 | | | 1-month LIBOR + 0.68% | 1.75% | March 2028 | (56) | |
| Southern Company parent | 1,000 | | | 1-month LIBOR + 2.36% | 3.70% | April
2030 | (160) | |
| Southern Company Gas | 500 | | | 1-month LIBOR + 0.38% | 1.75% | January 2031 | (88) | |
| Southern Company | $ | 2,150 | | | | | | $ | (300) | |
For cash flow hedges of interest rate derivatives, the estimated pre-tax gains (losses) expected to be reclassified from accumulated OCI to interest expense for the 12-month period ending June 30, 2024 are $(15) million for Southern Company and immaterial for the traditional electric operating companies and Southern Company Gas. Deferred gains and losses related to interest rate derivatives are expected to be amortized into earnings through 2052 for Southern Company, Alabama Power, and Georgia Power, 2028 for Mississippi Power, and 2046 for Southern Company Gas.
Foreign Currency Derivatives
Southern Company and certain subsidiaries, including Southern Power, may enter into foreign currency derivatives to hedge exposure to changes in foreign currency exchange rates, such as that arising from the issuance of debt denominated in a currency other than U.S. dollars. Derivatives related to forecasted transactions are accounted for as cash flow hedges where the derivatives' fair value gains or losses are recorded in OCI and are reclassified into earnings at the same time and on the same income statement line as the earnings effect of the hedged transactions, including foreign currency gains or losses arising from changes in the U.S. currency exchange rates. Derivatives related to existing fixed rate securities are accounted for as fair value hedges, where the derivatives' fair value gains or losses and hedged items' fair value gains or losses are both recorded directly to earnings on the same income statement line item, including foreign currency gains or losses arising from changes in the U.S. currency exchange rates. Southern Company has elected to exclude the cross-currency basis spread from the assessment of effectiveness in the fair value hedges of its foreign currency risk and record any difference between the change in the fair value of the excluded components and the amounts recognized in earnings as a component of OCI.
At June 30, 2023, the following foreign currency derivatives were outstanding:
| | | | | | | | | | | | | | | | | | | | |
| Pay Notional | Pay
Rate | Receive Notional | Receive
Rate | Hedge
Maturity Date | Fair Value Gain (Loss) at June 30, 2023 |
| (in millions) | | (in millions) | | | (in millions) |
| Cash Flow Hedges of Existing Debt | | | | | |
| Southern Power | $ | 564 | | 3.78% | € | 500 | | 1.85% | June 2026 | $ | (28) | |
| | | | | | |
| Fair Value Hedges of Existing Debt | | | | | |
| | | | | | |
| Southern Company parent | 1,476 | | 3.39% | 1,250 | | 1.88% | September 2027 | (142) | |
| | | | | | |
| | | | | | |
| Southern Company | $ | 2,040 | | | € | 1,750 | | | | $ | (170) | |
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
For cash flow hedges of foreign currency derivatives, the estimated pre-tax losses expected to be reclassified from accumulated OCI to earnings for the 12-month period ending June 30, 2024 are $11 million for Southern Power.
Derivative Financial Statement Presentation and Amounts
The Registrants enter into derivative contracts that may contain certain provisions that permit intra-contract netting of derivative receivables and payables for routine billing and offsets related to events of default and settlements. Southern Company and certain subsidiaries also utilize master netting agreements to mitigate exposure to counterparty credit risk. These agreements may contain provisions that permit netting across product lines and against cash collateral. The fair value amounts of derivative assets and liabilities on the balance sheets are presented net to the extent that there are netting arrangements or similar agreements with the counterparties.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
The fair value of energy-related derivatives, interest rate derivatives, and foreign currency derivatives was reflected in the balance sheets as follows:
| | | | | | | | | | | | | | |
| At June 30, 2023 | At December 31, 2022 |
| Derivative Category and Balance Sheet Location | Assets | Liabilities | Assets | Liabilities |
| (in millions) | (in millions) |
| Southern Company | | | | |
| Energy-related derivatives designated as hedging instruments for regulatory purposes | | | | |
| | | | |
| Assets from risk management activities/Liabilities from risk management activities | $ | 46 | | $ | 166 | | $ | 123 | | $ | 121 | |
| Other deferred charges and assets/Other deferred credits and liabilities | 36 | | 101 | | 52 | | 44 | |
| | | | |
| | | | |
| Total derivatives designated as hedging instruments for regulatory purposes | 82 | | 267 | | 175 | | 165 | |
| Derivatives designated as hedging instruments in cash flow and fair value hedges | | | | |
| Energy-related derivatives: | | | | |
| Assets from risk management activities/Liabilities from risk management activities | 1 | | 32 | | 3 | | 27 | |
| Other deferred charges and assets/Other deferred credits and liabilities | 3 | | 5 | | 6 | | 4 | |
| Interest rate derivatives: | | | | |
| Assets from risk management activities/Liabilities from risk management activities | 4 | | 77 | | 12 | | 62 | |
| Other deferred charges and assets/Other deferred credits and liabilities | — | | 227 | | — | | 240 | |
| Foreign currency derivatives: | | | | |
| Assets from risk management activities/Liabilities from risk management activities | — | | 35 | | — | | 34 | |
| Other deferred charges and assets/Other deferred credits and liabilities | — | | 135 | | — | | 182 | |
| Total derivatives designated as hedging instruments in cash flow and fair value hedges | 8 | | 511 | | 21 | | 549 | |
| Energy-related derivatives not designated as hedging instruments | | | | |
| | | | |
| Assets from risk management activities/Liabilities from risk management activities | 7 | | 7 | | 13 | | 13 | |
| Other deferred charges and assets/Other deferred credits and liabilities | — | | — | | 2 | | 1 | |
| | | | |
| Total derivatives not designated as hedging instruments | 7 | | 7 | | 15 | | 14 | |
| Gross amounts recognized | 97 | | 785 | | 211 | | 728 | |
Gross amounts offset(a) | (40) | | (92) | | (70) | | (111) | |
Net amounts recognized in the Balance Sheets(b) | $ | 57 | | $ | 693 | | $ | 141 | | $ | 617 | |
| | | | |
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
| | | | | | | | | | | | | | |
| At June 30, 2023 | At December 31, 2022 |
| Derivative Category and Balance Sheet Location | Assets | Liabilities | Assets | Liabilities |
| (in millions) | (in millions) |
Alabama Power(c) | | | | |
| Energy-related derivatives designated as hedging instruments for regulatory purposes | | | | |
| | | | |
| Other current assets/Other current liabilities | $ | 20 | | $ | 46 | | $ | 42 | | $ | 21 | |
| Other deferred charges and assets/Other deferred credits and liabilities | 12 | | 38 | | 20 | | 18 | |
| Total derivatives designated as hedging instruments for regulatory purposes | 32 | | 84 | | 62 | | 39 | |
| | | | |
| | | | |
| | | | |
| | | | |
| | | | |
| | | | |
| Gross amounts offset | (20) | | (20) | | (24) | | (24) | |
| Net amounts recognized in the Balance Sheets | $ | 12 | | $ | 64 | | $ | 38 | | $ | 15 | |
| | | | |
| Georgia Power | | | | |
| Energy-related derivatives designated as hedging instruments for regulatory purposes | | | | |
| | | | |
| Assets from risk management activities/Other current liabilities | $ | 7 | | $ | 65 | | $ | 36 | | $ | 43 | |
| Other deferred charges and assets/Other deferred credits and liabilities | 8 | | 37 | | 6 | | 18 | |
| Total derivatives designated as hedging instruments for regulatory purposes | 15 | | 102 | | 42 | | 61 | |
| | | | |
| | | | |
| | | | |
| | | | |
| | | | |
| Energy-related derivatives not designated as hedging instruments | | | | |
| | | | |
| Other current assets/Other current liabilities | 2 | | — | | — | | 1 | |
| | | | |
| Gross amounts recognized | 17 | | 102 | | 42 | | 62 | |
| Gross amounts offset | (12) | | (12) | | (21) | | (21) | |
| Net amounts recognized in the Balance Sheets | $ | 5 | | $ | 90 | | $ | 21 | | $ | 41 | |
| | | | |
Mississippi Power(c) | | | | |
| Energy-related derivatives designated as hedging instruments for regulatory purposes | | | | |
| | | | |
| Assets from risk management activities/Other current liabilities | $ | 11 | | $ | 28 | | $ | 33 | | $ | 24 | |
| Other deferred charges and assets/Other deferred credits and liabilities | 16 | | 27 | | 26 | | 8 | |
| Total derivatives designated as hedging instruments for regulatory purposes | 27 | | 55 | | 59 | | 32 | |
| | | | |
| | | | |
| | | | |
| | | | |
| | | | |
| | | | |
| Gross amounts offset | (19) | | (19) | | (17) | | (17) | |
| Net amounts recognized in the Balance Sheets | $ | 8 | | $ | 36 | | $ | 42 | | $ | 15 | |
| | | | |
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
| | | | | | | | | | | | | | |
| At June 30, 2023 | At December 31, 2022 |
| Derivative Category and Balance Sheet Location | Assets | Liabilities | Assets | Liabilities |
| (in millions) | (in millions) |
| Southern Power | | | | |
| Derivatives designated as hedging instruments in cash flow and fair value hedges | | | | |
| Energy-related derivatives: | | | | |
| Other current assets/Other current liabilities | $ | — | | $ | 9 | | $ | — | | $ | 12 | |
| Other deferred charges and assets/Other deferred credits and liabilities | 3 | | 1 | | 5 | | — | |
| Foreign currency derivatives: | | | | |
| Other current assets/Other current liabilities | — | | 11 | | — | | 11 | |
| Other deferred charges and assets/Other deferred credits and liabilities | — | | 17 | | — | | 36 | |
| Total derivatives designated as hedging instruments in cash flow and fair value hedges | 3 | | 38 | | 5 | | 59 | |
| Energy-related derivatives not designated as hedging instruments | | | | |
| | | | |
| Other current assets/Other current liabilities | — | | — | | 2 | | — | |
| Other deferred charges and assets/Other deferred credits and liabilities | 1 | | — | | 1 | | — | |
| | | | |
| | | | |
| Total derivatives not designated as hedging instruments | 1 | | — | | 3 | | — | |
| Gross amounts recognized | 4 | | 38 | | 8 | | 59 | |
| Gross amounts offset | (1) | | (1) | | — | | — | |
| Net amounts recognized in the Balance Sheets | $ | 3 | | $ | 37 | | $ | 8 | | $ | 59 | |
| | | | |
| Southern Company Gas | | | | |
| Energy-related derivatives designated as hedging instruments for regulatory purposes | | | | |
| | | | |
| Other current assets/Other current liabilities | $ | 8 | | $ | 27 | | $ | 12 | | $ | 33 | |
| | | | |
| | | | |
| Derivatives designated as hedging instruments in cash flow and fair value hedges | | | | |
| Energy-related derivatives: | | | | |
| Other current assets/Other current liabilities | 1 | | 23 | | 3 | | 15 | |
| Other deferred charges and assets/Other deferred credits and liabilities | — | | 4 | | 1 | | 4 | |
| Interest rate derivatives: | | | | |
| Other current assets/Other current liabilities | 4 | | 19 | | — | | 14 | |
| Other deferred charges and assets/Other deferred credits and liabilities | — | | 69 | | — | | 72 | |
| Total derivatives designated as hedging instruments in cash flow and fair value hedges | 5 | | 115 | | 4 | | 105 | |
| Energy-related derivatives not designated as hedging instruments | | | | |
| | | | |
| Other current assets/Other current liabilities | 4 | | 6 | | 11 | | 12 | |
| Other deferred charges and assets/Other deferred credits and liabilities | — | | — | | 1 | | 1 | |
| | | | |
| Total derivatives not designated as hedging instruments | 4 | | 6 | | 12 | | 13 | |
| Gross amounts recognized | 17 | | 148 | | 28 | | 151 | |
Gross amounts offset(a) | 14 | | (38) | | — | | (41) | |
Net amounts recognized in the Balance Sheets(b) | $ | 31 | | $ | 110 | | $ | 28 | | $ | 110 | |
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
(a)Gross amounts offset includes cash collateral held on deposit in broker margin accounts of $52 million and $41 million at June 30, 2023 and December 31, 2022, respectively.
(b)Net amounts of derivative instruments outstanding exclude immaterial premium and intrinsic value associated with weather derivatives for both periods presented.
(c)Energy-related derivatives not designated as hedging instruments were immaterial for Alabama Power and Mississippi Power for both periods presented.
At June 30, 2023 and December 31, 2022, the pre-tax effects of unrealized derivative gains (losses) arising from energy-related derivative instruments designated as regulatory hedging instruments and deferred were as follows:
| | | | | | | | | | | | | | | | | |
| Regulatory Hedge Unrealized Gain (Loss) Recognized in the Balance Sheet |
Derivative Category and Balance Sheet
Location | Southern
Company | Alabama
Power | Georgia
Power | Mississippi
Power | Southern Company Gas |
| | (in millions) |
At June 30, 2023: | | | | | |
| Energy-related derivatives: | | | | | |
| Other regulatory assets, current | $ | (141) | | $ | (37) | | $ | (60) | | $ | (22) | | $ | (22) | |
| Other regulatory assets, deferred | (71) | | (27) | | (30) | | (14) | | — | |
| | | | | |
| | | | | |
| Other regulatory liabilities, current | 29 | | 11 | | 2 | | 4 | | 12 | |
| Other regulatory liabilities, deferred | 6 | | 1 | | 1 | | 4 | | — | |
| Total energy-related derivative gains (losses) | $ | (177) | | $ | (52) | | $ | (87) | | $ | (28) | | $ | (10) | |
| | | | | |
At December 31, 2022: | | | | | |
| Energy-related derivatives: | | | | | |
| Other regulatory assets, current | $ | (71) | | $ | (8) | | $ | (26) | | $ | (13) | | $ | (24) | |
| Other regulatory assets, deferred | (23) | | (7) | | (14) | | (2) | | — | |
| Other regulatory liabilities, current | 72 | | 29 | | 19 | | 22 | | 2 | |
| Other regulatory liabilities, deferred | 31 | | 9 | | 2 | | 20 | | — | |
| Total energy-related derivative gains (losses) | $ | 9 | | $ | 23 | | $ | (19) | | $ | 27 | | $ | (22) | |
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
For the three and six months ended June 30, 2023 and 2022, the pre-tax effects of cash flow and fair value hedge accounting on accumulated OCI for the applicable Registrants were as follows:
| | | | | | | | | | | | | | |
| Gain (Loss) Recognized in OCI on Derivatives | For the Three Months Ended June 30, | For the Six Months Ended June 30, |
| 2023 | 2022 | 2023 | 2022 |
| (in millions) | (in millions) |
| Southern Company | | | | |
| Cash flow hedges: | | | | |
| Energy-related derivatives | $ | (5) | | $ | (1) | | $ | (50) | | $ | 41 | |
| Interest rate derivatives | 3 | | 21 | | (10) | | 30 | |
| Foreign currency derivatives | 8 | | (74) | | 9 | | (102) | |
Fair value hedges(*): | | | | |
| Foreign currency derivatives | 30 | | (7) | | 1 | | (3) | |
| Total | $ | 36 | | $ | (61) | | $ | (50) | | $ | (34) | |
| | | | |
| | | | |
| Georgia Power | | | | |
| Cash flow hedges: | | | | |
| Interest rate derivatives | $ | (1) | | $ | 19 | | $ | (3) | | $ | 31 | |
| | | | |
| | | | |
| | | | |
| Southern Power | | | | |
| Cash flow hedges: | | | | |
| Energy-related derivatives | $ | (2) | | $ | 2 | | $ | (13) | | $ | 7 | |
| | | | |
| Foreign currency derivatives | 8 | | (74) | | 9 | | (102) | |
| Total | $ | 6 | | $ | (72) | | $ | (4) | | $ | (95) | |
| Southern Company Gas | | | | |
| Cash flow hedges: | | | | |
| Energy-related derivatives | $ | (3) | | $ | (2) | | $ | (37) | | $ | 35 | |
| Interest rate derivatives | 3 | | (5) | | 4 | | (5) | |
| Total | $ | — | | $ | (7) | | $ | (33) | | $ | 30 | |
(*)Represents amounts excluded from the assessment of effectiveness for which the difference between changes in fair value and periodic amortization is recorded in OCI.
For the three and six months ended June 30, 2023 and 2022, the pre-tax effects of energy-related derivatives designated as cash flow hedging instruments on accumulated OCI were immaterial for Alabama Power and Mississippi Power.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
For the three and six months ended June 30, 2023 and 2022, the pre-tax effects of cash flow and fair value hedge accounting on income were as follows:
| | | | | | | | | | | | | | |
| Location and Amount of Gain (Loss) Recognized in Income on Cash Flow and Fair Value Hedging Relationships | For the Three Months Ended June 30, | For the Six Months Ended June 30, |
|
| 2023 | 2022 | 2023 | 2022 |
| (in millions) | (in millions) |
| Southern Company | | | | |
| Total cost of natural gas | $ | 199 | | $ | 452 | | $ | 1,097 | | $ | 1,546 | |
Gain (loss) on energy-related cash flow hedges(a) | (9) | | 10 | | (29) | | 18 | |
| Total depreciation and amortization | 1,112 | | 913 | | 2,222 | | 1,805 | |
Gain (loss) on energy-related cash flow hedges(a) | (4) | | 4 | | (13) | | 6 | |
| Total interest expense, net of amounts capitalized | (610) | | (488) | | (1,192) | | (950) | |
Gain (loss) on interest rate cash flow hedges(a) | (5) | | (6) | | (9) | | (13) | |
Gain (loss) on foreign currency cash flow hedges(a) | (2) | | (7) | | (5) | | (13) | |
Gain (loss) on interest rate fair value hedges(b) | (45) | | (76) | | (3) | | (198) | |
| Total other income (expense), net | 142 | | 139 | | 286 | | 283 | |
Gain (loss) on foreign currency cash flow hedges(a)(c) | — | | (73) | | 10 | | (97) | |
| Gain (loss) on foreign currency fair value hedges | 29 | | (96) | | 26 | | (121) | |
| Amount excluded from effectiveness testing recognized in earnings | (29) | | 7 | | (1) | | 3 | |
| | | | |
| | | | |
| | | | |
| | | | |
| | | | |
| | | | |
| | | | |
| | | | |
| | | | |
| | | | |
| Southern Power | | | | |
| Total depreciation and amortization | $ | 122 | | $ | 131 | | $ | 250 | | $ | 251 | |
Gain (loss) on energy-related cash flow hedges(a) | (4) | | 4 | | (13) | | 6 | |
| Total interest expense, net of amounts capitalized | (33) | | (36) | | (66) | | (73) | |
Gain (loss) on foreign currency cash flow hedges(a) | (2) | | (7) | | (5) | | (13) | |
| Total other income (expense), net | 2 | | 1 | | 4 | | 3 | |
Gain (loss) on foreign currency cash flow hedges(a)(c) | — | | (73) | | 10 | | (97) | |
| Southern Company Gas | | | | |
| Total cost of natural gas | $ | 199 | | $ | 452 | | $ | 1,097 | | $ | 1,546 | |
Gain (loss) on energy-related cash flow hedges(a) | (9) | | 10 | | (29) | | 18 | |
| Total interest expense, net of amounts capitalized | (73) | | (61) | | (150) | | (122) | |
Gain (loss) on interest rate cash flow hedges(a) | — | | (1) | | (1) | | (1) | |
Gain (loss) on interest rate fair value hedges(b) | (15) | | (22) | | (2) | | (57) | |
(a)Reclassified from accumulated OCI into earnings.
(b)For fair value hedges, changes in the fair value of the derivative contracts are generally equal to changes in the fair value of the underlying debt and have no material impact on income.
(c)The reclassification from accumulated OCI into other income (expense), net completely offsets currency gains and losses arising from changes in the U.S. currency exchange rates used to record the euro-denominated notes.
The pre-tax effects of cash flow and fair value hedge accounting on income for energy-related derivatives and interest rate derivatives were immaterial for the traditional electric operating companies for all periods presented.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
At June 30, 2023 and December 31, 2022, the following amounts were recorded on the balance sheets related to cumulative basis adjustments for fair value hedges:
| | | | | | | | | | | | | | | | | |
| Carrying Amount of the Hedged Item | | Cumulative Amount of Fair Value Hedging Adjustment included in Carrying Amount of the Hedged Item |
| Balance Sheet Location of Hedged Items | At June 30, 2023 | At December 31, 2022 | | At June 30, 2023 | At December 31, 2022 |
| (in millions) | | (in millions) |
| Southern Company | | | | | |
| | | | | |
| Long-term debt | $ | (2,970) | | $ | (2,927) | | | $ | 265 | | $ | 282 | |
| | | | | |
| Southern Company Gas | | | | | |
| | | | | |
| Long-term debt | $ | (417) | | $ | (415) | | | $ | 80 | | $ | 81 | |
For the three and six months ended June 30, 2023 and 2022, the pre-tax effects of energy-related derivatives not designated as hedging instruments on the statements of income of Southern Company and Southern Company Gas were as follows:
| | | | | | | | | | | | | | | | | | | | |
| | Gain (Loss) |
| | Three Months Ended June 30, | | Six Months Ended June 30, |
| Derivatives in Non-Designated Hedging Relationships | Statements of Income Location | 2023 | 2022 | | 2023 | 2022 |
| | (in millions) | | (in millions) |
| | | | | | |
| Energy-related derivatives: | Natural gas revenues(*) | $ | — | | $ | (15) | | | $ | — | | $ | (13) | |
| Cost of natural gas | 16 | | (25) | | | 29 | | (5) | |
| | | | | | |
| Total derivatives in non-designated hedging relationships | $ | 16 | | $ | (40) | | | $ | 29 | | $ | (18) | |
| | | | | | |
| | | | | | |
| | | | | | |
| | | | | |
(*)Excludes $14 million of gains for the six months ended June 30, 2023, and immaterial amounts for all other periods presented, recorded in natural gas revenues associated with weather derivatives.
For the three and six months ended June 30, 2023 and 2022, the pre-tax effects of energy-related derivatives not designated as hedging instruments were immaterial for the other Registrants.
Contingent Features
The Registrants do not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade. There are certain derivatives that could require collateral, but not accelerated payment, in the event of various credit rating changes of certain Southern Company subsidiaries. Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. At June 30, 2023, the Registrants had no collateral posted with derivative counterparties to satisfy these arrangements.
For Southern Company and Southern Power, the fair value of interest rate derivative liabilities with contingent features and the maximum potential collateral requirements arising from the credit-risk-related contingent features, at a rating below BBB- and/or Baa3, were $65 million and $13 million, respectively, at June 30, 2023. For the traditional electric operating companies and Southern Power, energy-related derivative liabilities with contingent features and the maximum potential collateral requirements arising from the credit-risk-related contingent features, at a rating below BBB- and/or Baa3, were immaterial at June 30, 2023. The maximum potential collateral requirements arising from the credit-risk-related contingent features for the traditional electric operating companies and Southern Power include certain agreements that could require collateral in the event that one or more Southern Company power pool participants has a credit rating change to below investment grade.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
Alabama Power and Southern Power maintain accounts with certain regional transmission organizations to facilitate financial derivative transactions and they may be required to post collateral based on the value of the positions in these accounts and the associated margin requirements. At June 30, 2023, cash collateral posted in these accounts was $15 million for Southern Power and immaterial for Alabama Power. Southern Company Gas maintains accounts with brokers or the clearing houses of certain exchanges to facilitate financial derivative transactions. Based on the value of the positions in these accounts and the associated margin requirements, Southern Company Gas may be required to deposit cash into these accounts. At June 30, 2023, cash collateral held on deposit in broker margin accounts was $52 million.
The Registrants are exposed to losses related to financial instruments in the event of counterparties' nonperformance. The Registrants only enter into agreements and material transactions with counterparties that have investment grade credit ratings by Moody's and S&P or with counterparties who have posted collateral to cover potential credit exposure. The Registrants have also established risk management policies and controls to determine and monitor the creditworthiness of counterparties in order to mitigate their exposure to counterparty credit risk.
Southern Company Gas uses established credit policies to determine and monitor the creditworthiness of counterparties, including requirements to post collateral or other credit security, as well as the quality of pledged collateral. Collateral or credit security is most often in the form of cash or letters of credit from an investment-grade financial institution, but may also include cash or U.S. government securities held by a trustee. Prior to entering a physical transaction, Southern Company Gas assigns its counterparties an internal credit rating and credit limit based on the counterparties' Moody's, S&P, and Fitch ratings, commercially available credit reports, and audited financial statements. Southern Company Gas may require counterparties to pledge additional collateral when deemed necessary.
Southern Company Gas utilizes netting agreements whenever possible to mitigate exposure to counterparty credit risk. Netting agreements enable Southern Company Gas to net certain assets and liabilities by counterparty across product lines and against cash collateral, provided the netting and cash collateral agreements include such provisions. While the amounts due from, or owed to, counterparties are settled net, they are recorded on a gross basis on the balance sheet as energy marketing receivables and energy marketing payables.
The Registrants do not anticipate a material adverse effect on their respective financial statements as a result of counterparty nonperformance.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
(K) SEGMENT AND RELATED INFORMATION
Southern Company
The primary businesses of the Southern Company system are electricity sales by the traditional electric operating companies and Southern Power and the distribution of natural gas by Southern Company Gas. The traditional electric operating companies are vertically integrated utilities providing electric service in three Southeastern states. Southern Power develops, constructs, acquires, owns, and manages power generation assets, including renewable energy and battery energy storage projects, and sells electricity at market-based rates in the wholesale market. Southern Company Gas distributes natural gas through its natural gas distribution utilities and is involved in several other complementary businesses including gas pipeline investments and gas marketing services.
Southern Company's reportable business segments are the sale of electricity by the traditional electric operating companies, the sale of electricity in the competitive wholesale market by Southern Power, and the sale of natural gas and other complementary products and services by Southern Company Gas. Revenues from sales by Southern Power to the traditional electric operating companies were $116 million and $251 million for the three and six months ended June 30, 2023, respectively, and $232 million and $337 million for the three and six months ended June 30, 2022, respectively. Revenues from sales of natural gas from Southern Company Gas to the traditional electric operating companies and Southern Power were immaterial for all periods presented. The "All Other" column includes the Southern Company parent entity, which does not allocate operating expenses to business segments. Also, this category includes segments below the quantitative threshold for separate disclosure. These segments include providing distributed energy and resilience solutions and deploying microgrids for commercial, industrial, governmental, and utility customers, as well as investments in telecommunications. All other inter-segment revenues are not material.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
Financial data for business segments and products and services for the three and six months ended June 30, 2023 and 2022 was as follows:
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| Electric Utilities | | | | |
| Traditional
Electric Operating
Companies | Southern
Power | Eliminations | Total | Southern Company Gas | All
Other | Eliminations | Consolidated |
| (in millions) |
| Three Months Ended June 30, 2023 | | | | | | | |
| Operating revenues | $ | 4,359 | | $ | 525 | | $ | (120) | | $ | 4,764 | | $ | 852 | | $ | 180 | | $ | (48) | | $ | 5,748 | |
Segment net income (loss)(a)(b) | 823 | | 85 | | — | | 908 | | 85 | | (157) | | 2 | | 838 | |
| Six Months Ended June 30, 2023 | | | | | | | |
| Operating revenues | $ | 8,472 | | $ | 1,033 | | $ | (258) | | $ | 9,247 | | $ | 2,728 | | $ | 346 | | $ | (93) | | $ | 12,228 | |
Segment net income (loss)(a)(b)(c) | 1,433 | | 187 | | — | | 1,620 | | 393 | | (311) | | (2) | | 1,700 | |
| At June 30, 2023 | | | | | | | | |
| Goodwill | $ | — | | $ | 2 | | $ | — | | $ | 2 | | $ | 5,015 | | $ | 144 | | $ | — | | $ | 5,161 | |
| Total assets | 97,751 | | 13,046 | | (589) | | 110,208 | | 24,331 | | 3,523 | | (946) | | 137,116 | |
| Three Months Ended June 30, 2022 | | | | | | | |
| Operating revenues | $ | 5,563 | | $ | 899 | | $ | (456) | | $ | 6,006 | | $ | 1,083 | | $ | 159 | | $ | (42) | | $ | 7,206 | |
Segment net income (loss)(a)(d) | 1,036 | | 98 | | — | | 1,134 | | 115 | | (137) | | (5) | | 1,107 | |
| Six Months Ended June 30, 2022 | | | | | | | |
| Operating revenues | $ | 9,778 | | $ | 1,438 | | $ | (700) | | $ | 10,516 | | $ | 3,140 | | $ | 283 | | $ | (85) | | $ | 13,854 | |
Segment net income (loss)(a)(d) | 1,811 | | 170 | | — | | 1,981 | | 433 | | (263) | | (12) | | 2,139 | |
| At December 31, 2022 | | | | | | | | |
| Goodwill | $ | — | | $ | 2 | | $ | — | | $ | 2 | | $ | 5,015 | | $ | 144 | | $ | — | | $ | 5,161 | |
| Total assets | 95,861 | | 13,081 | | (659) | | 108,283 | | 24,621 | | 2,665 | | (678) | | 134,891 | |
(a)Attributable to Southern Company.
(b)For Southern Company Gas, includes a pre-tax charge of approximately $38 million ($28 million after tax) associated with the disallowance of certain capital expenditures at Nicor Gas. See Note (B) under "Southern Company Gas" for additional information.
(c)For Southern Power, includes a $16 million pre-tax gain ($12 million after tax) on the sale of spare parts.
(d)For the traditional electric operating companies, includes pre-tax charges of $52 million ($39 million after tax) at Georgia Power for the estimated probable loss associated with the construction of Plant Vogtle Units 3 and 4. See Note (B) and Note 2 to the financial statements in Item 8 of the Form 10-K under "Georgia Power – Nuclear Construction" for additional information.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
Products and Services
| | | | | | | | | | | | | | |
| | Electric Utilities' Revenues |
| Retail | Wholesale | Other | Total |
| (in millions) |
| Three Months Ended June 30, 2023 | $ | 3,859 | | $ | 605 | | $ | 300 | | $ | 4,764 | |
| Three Months Ended June 30, 2022 | 4,789 | | 937 | | 280 | | 6,006 | |
| Six Months Ended June 30, 2023 | $ | 7,458 | | $ | 1,203 | | $ | 586 | | $ | 9,247 | |
| Six Months Ended June 30, 2022 | 8,402 | | 1,601 | | 513 | | 10,516 | |
| | | | | | | | | | | | | | |
| | Southern Company Gas' Revenues |
| Gas
Distribution
Operations | Gas
Marketing
Services | Other | Total |
| (in millions) |
| Three Months Ended June 30, 2023 | $ | 761 | | $ | 75 | | $ | 16 | | $ | 852 | |
| Three Months Ended June 30, 2022 | 975 | | 92 | | 16 | | 1,083 | |
| Six Months Ended June 30, 2023 | $ | 2,372 | | $ | 320 | | $ | 36 | | $ | 2,728 | |
| Six Months Ended June 30, 2022 | 2,765 | | 335 | | 40 | | 3,140 | |
Southern Company Gas
Southern Company Gas manages its business through three reportable segments – gas distribution operations, gas pipeline investments, and gas marketing services. The non-reportable segments are combined and presented as all other.
Gas distribution operations is the largest component of Southern Company Gas' business and includes natural gas local distribution utilities that construct, manage, and maintain intrastate natural gas pipelines and gas distribution facilities in four states.
Gas pipeline investments consists of joint ventures in natural gas pipeline investments including a 50% interest in SNG and a 50% joint ownership interest in the Dalton Pipeline. These natural gas pipelines enable the provision of diverse sources of natural gas supplies to the customers of Southern Company Gas. See Note 7 to the financial statements under "Southern Company Gas" in Item 8 of the Form 10-K for additional information.
Gas marketing services provides natural gas marketing to end-use customers primarily in Georgia and Illinois through SouthStar.
The all other column includes segments and subsidiaries that fall below the quantitative threshold for separate disclosure, including storage and fuels operations. The all other column included a natural gas storage facility in Texas through its sale in November 2022. See Note 15 to the financial statements under "Southern Company Gas" in Item 8 of the Form 10-K for additional information, including the sale of a natural gas storage facility in California expected to be completed later in 2023.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
Business segment financial data for the three months ended June 30, 2023 and 2022 was as follows:
| | | | | | | | | | | | | | | | | | | | | | | |
| Gas Distribution Operations | Gas
Pipeline Investments | Gas Marketing Services | Total | All Other | Eliminations | Consolidated |
| (in millions) |
| Three Months Ended June 30, 2023 | | | | | |
| Operating revenues | $ | 764 | | $ | 8 | | $ | 75 | | $ | 847 | | $ | 9 | | $ | (4) | | $ | 852 | |
Segment net income (loss)(*) | 60 | | 19 | | 7 | | 86 | | (1) | | — | | 85 | |
| Six Months Ended June 30, 2023 | | | | | |
| Operating revenues | $ | 2,383 | | $ | 16 | | $ | 320 | | $ | 2,719 | | $ | 22 | | $ | (13) | | $ | 2,728 | |
Segment net income(*) | 281 | | 50 | | 56 | | 387 | | 6 | | — | | 393 | |
Total assets at June 30, 2023 | 22,366 | | 1,552 | | 1,542 | | 25,460 | | 9,606 | | (10,735) | | 24,331 | |
| Three Months Ended June 30, 2022 | | | | | |
| Operating revenues | $ | 980 | | $ | 8 | | $ | 92 | | $ | 1,080 | | $ | 10 | | $ | (7) | | $ | 1,083 | |
| Segment net income (loss) | 92 | | 23 | | 1 | | 116 | | (1) | | — | | 115 | |
| Six Months Ended June 30, 2022 | | | | | | |
| Operating revenues | $ | 2,782 | | $ | 16 | | $ | 335 | | $ | 3,133 | | $ | 26 | | $ | (19) | | $ | 3,140 | |
| Segment net income | 306 | | 52 | | 67 | | 425 | | 8 | | — | | 433 | |
Total assets at December 31, 2022 | 22,040 | | 1,577 | | 1,616 | | 25,233 | | 8,943 | | (9,555) | | 24,621 | |
(*)For gas distribution operations, includes a pre-tax charge of approximately $38 million ($28 million after tax) associated with the disallowance of certain capital expenditures at Nicor Gas. See Note (B) under "Southern Company Gas" for additional information.
Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations.
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Combined Management's Discussion and Analysis of Financial Condition and Results of Operations | |
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The following Management's Discussion and Analysis of Financial Condition and Results of Operations is a combined presentation; however, information contained herein relating to any individual Registrant is filed by such Registrant on its own behalf and each Registrant makes no representation as to information related to the other Registrants.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS
OVERVIEW
Southern Company is a holding company that owns all of the common stock of three traditional electric operating companies (Alabama Power, Georgia Power, and Mississippi Power), Southern Power, and Southern Company Gas and owns other direct and indirect subsidiaries. The primary businesses of the Southern Company system are electricity sales by the traditional electric operating companies and Southern Power and the distribution of natural gas by Southern Company Gas. Southern Company's reportable segments are the sale of electricity by the traditional electric operating companies, the sale of electricity in the competitive wholesale market by Southern Power, and the sale of natural gas and other complementary products and services by Southern Company Gas. Southern Company Gas' reportable segments are gas distribution operations, gas pipeline investments, and gas marketing services. See Note (K) to the Condensed Financial Statements herein for additional information on segment reporting. Alabama Power, Georgia Power, and Mississippi Power each operate with one reportable business segment, since substantially all of their business is providing electric service to customers. Southern Power also operates its business with one reportable business segment, the sale of electricity in the competitive wholesale market. For additional information on the Registrants' primary business activities, see BUSINESS – "The Southern Company System" in Item 1 of the Form 10-K.
The Registrants continue to focus on several key performance indicators. For the traditional electric operating companies and Southern Company Gas, these indicators include, but are not limited to, customer satisfaction, plant availability, electric and natural gas system reliability, and execution of major construction projects. For Southern Power, these indicators include, but are not limited to, the equivalent forced outage rate and contract availability to evaluate operating results and help ensure its ability to meet its contractual commitments to customers. In addition, Southern Company and the Subsidiary Registrants focus on earnings per share and net income, respectively, as a key performance indicator.
Recent Developments
Alabama Power
During the first six months of 2023, Alabama Power continued construction of Plant Barry Unit 8, which is expected to be placed in service in November 2023. At June 30, 2023, project expenditures associated with Plant Barry Unit 8 totaled approximately $568 million.
On March 24, 2023, Alabama Power filed Rate CNP New Plant with the Alabama PSC to recover costs associated with the acquisition of the Central Alabama Generating Station. The filing reflected an annual increase in retail revenues of $78 million effective with June 2023 billings. Through May 2023, Alabama Power recovered substantially all costs associated with the Central Alabama Generating Station through Rate RSE, offset by revenues from a power sales agreement. On May 24, 2023, the Central Alabama Generating Station was placed into retail service.
On June 14, 2023, the Alabama PSC issued an order approving modifications to Alabama Power's Renewable Generation Certificate. The modifications authorized Alabama Power to procure an additional 2,400 MWs of renewable capacity and energy by June 14, 2029 and to market the related energy and environmental attributes to customers and other third parties. The modifications also increased the size of allowable renewable projects from 80 MWs to 200 MWs and increased the annual approval limit from 160 MWs to 400 MWs.
On July 11, 2023, the Alabama PSC issued an order authorizing Alabama Power to expand the existing authority of its reliability reserve to include certain production-related expenses that are intended to maintain reliability in periods between scheduled generating unit outages.
See Note (B) to the Condensed Financial Statements under "Alabama Power" herein for additional information.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Georgia Power
Plant Vogtle Units 3 and 4 Construction and Start-Up Status
Construction continues on Plant Vogtle Units 3 and 4 (with electric generating capacity of approximately 1,100 MWs each), in which Georgia Power currently holds a 45.7% ownership interest. Georgia Power's share of the total project capital cost forecast to complete Plant Vogtle Units 3 and 4, including contingency, through July 2023 and March 2024, respectively, is $10.6 billion.
On March 6, 2023, Unit 3 achieved self-sustaining nuclear fission, commonly referred to as initial criticality, and, on April 1, 2023, the generator successfully synchronized to the power grid and generated electricity for the first time. Georgia Power placed Unit 3 in service on July 31, 2023.
Hot functional testing for Unit 4 was completed on May 1, 2023. On July 20, 2023, Southern Nuclear announced that all Unit 4 ITAACs had been submitted to the NRC, and, on July 28, 2023, the NRC published its 103(g) finding that the accepted criteria in the combined license for Unit 4 had been met, which allows nuclear fuel to be loaded and start-up testing to begin. Fuel load for Unit 4 is projected to be completed by the end of October 2023. Unit 4 is projected to be placed in service during late fourth quarter 2023 or the first quarter 2024. The projected schedule for Unit 4 significantly depends on maintaining overall construction productivity and production levels, particularly in completing remaining subcontractor scopes of work while reducing the level of craft laborers based on work remaining. Any further delays could result in a later in-service date and cost increases.
During the first half of 2023, established construction contingency totaling $43 million was assigned to the base capital cost forecast for costs primarily associated with the Unit 3 schedule extension, including continued need of support resources for Unit 3 testing, as well as additional craft and support resources and subcontract work for Unit 4.
Georgia Power and the other Vogtle Owners do not agree on the starting dollar amount for the determination of cost increases subject to the cost-sharing and tender provisions of the Global Amendments (as defined in Note (B) to the Condensed Financial Statements under "Georgia Power – Nuclear Construction – Joint Owner Contracts" herein). The other Vogtle Owners notified Georgia Power that they believe the project capital cost forecast approved by the Vogtle Owners in February 2022 triggered the tender provisions.
In June 2022 and July 2022, OPC and Dalton, respectively, notified Georgia Power of their purported exercises of their tender options. Georgia Power did not accept these purported tender exercises. In June 2022, OPC and MEAG Power each filed a separate lawsuit against Georgia Power in the Superior Court of Fulton County, Georgia seeking a declaratory judgment that the starting dollar amount is $17.1 billion and that the cost-sharing and tender provisions had been triggered. In July 2022, Georgia Power filed its answers in the lawsuits filed by MEAG Power and OPC and included counterclaims seeking a declaratory judgment that the starting dollar amount is $18.38 billion and that costs related to force majeure events are excluded prior to calculating the cost-sharing and tender provisions and when calculating Georgia Power's related financial obligations. In September 2022, Dalton filed complaints in each of these lawsuits.
Also in September 2022, Georgia Power and MEAG Power reached an agreement to resolve their dispute regarding the proper interpretation of the cost-sharing and tender provisions of the Global Amendments. Under the terms of the agreement, among other items, (i) MEAG Power will not exercise its tender option and will retain its full ownership interest in Plant Vogtle Units 3 and 4; (ii) Georgia Power will reimburse a portion of MEAG Power's costs of construction for Plant Vogtle Units 3 and 4 as such costs are incurred and with no further adjustment for force majeure costs, which payments will total approximately $92 million based on the current project capital cost forecast; and (iii) Georgia Power will reimburse 20% of MEAG Power's costs of construction with respect to any amounts over the current project capital cost forecast, with no further adjustment for force majeure costs. In October 2022, MEAG Power and Georgia Power filed a notice of settlement and voluntary dismissal of the pending litigation described above, including Georgia Power's counterclaim, and Dalton dismissed its related complaint.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Georgia Power recorded pre-tax charges to income through the fourth quarter 2022 of $407 million ($304 million after tax) associated with the cost-sharing and tender provisions of the Global Amendments, including the settlement with MEAG Power. This total is included in the total project capital cost forecast and will not be recovered from retail customers. The settlement with MEAG Power does not resolve the separate pending litigation with OPC, including Dalton's associated complaint, described above. Georgia Power may be required to record further pre-tax charges to income of up to approximately $345 million associated with the cost-sharing and tender provisions of the Global Amendments for OPC and Dalton based on the current project capital cost forecast.
Georgia Power's ownership interest in Plant Vogtle Units 3 and 4 continues to be 45.7%. Georgia Power believes the increases in the total project capital cost forecast through December 31, 2022 triggered the tender provisions, but Georgia Power disagrees with OPC and Dalton on the tender provisions trigger date. Valid notices of tender from OPC and Dalton would require Georgia Power to pay 100% of their respective remaining shares of the costs necessary to complete Plant Vogtle Units 3 and 4. Georgia Power's incremental ownership interest will be calculated and conveyed to Georgia Power after Plant Vogtle Units 3 and 4 are placed in service.
The ultimate impact of these matters on the construction schedule and project capital cost forecast and related cost recovery for Plant Vogtle Units 3 and 4 cannot be determined at this time. See Note (B) to the Condensed Financial Statements under "Georgia Power – Nuclear Construction" herein for additional information.
Plant Vogtle Unit 3 and Common Facilities Rate Proceeding
In compliance with a Georgia PSC order approved in November 2021, Georgia Power increased annual retail base rates by $318 million effective August 1, 2023 based on the actual in-service date of July 31, 2023 for Plant Vogtle Unit 3.
See Note (B) to the Condensed Financial Statements under "Georgia Power – Nuclear Construction" herein for additional information on Plant Vogtle Units 3 and 4.
Fuel Cost Recovery
On May 16, 2023, the Georgia PSC approved a stipulation agreement between Georgia Power and the staff of the Georgia PSC to increase annual fuel billings by 54%, or approximately $1.1 billion, effective June 1, 2023. The increase reflects a three-year recovery period for $2.2 billion of Georgia Power's under recovered fuel balance at May 31, 2023. Changes in fuel rates have no significant effect on Georgia Power's net income but do impact the related operating cash flows. See Note (B) to the Condensed Financial Statements under "Georgia Power – Fuel Cost Recovery" herein for additional information.
Mississippi Power
On July 31, 2023, Mississippi Power and Cooperative Energy filed a settlement agreement with the FERC related to Mississippi Power's July 2022 request for a $23 million increase in annual wholesale base revenues under the MRA tariff. Interim rates based on the initial request became effective September 14, 2022, subject to refund. The settlement agreement provides for a $16 million increase in annual wholesale base revenues and a refund to customers of approximately $6 million. The settlement agreement is subject to approval by the FERC. The ultimate outcome of this matter cannot be determined at this time.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Southern Company Gas
On July 14, 2023, Atlanta Gas Light filed its annual GRAM update with the Georgia PSC. The filing requests an annual base rate increase of $53 million based on the projected 12-month period beginning January 1, 2024. Resolution of the GRAM filing is expected by December 31, 2023, with new rates effective January 1, 2024.
On June 7, 2023, Virginia Natural Gas, the Virginia Commission staff, and the Virginia Attorney General's Division of Consumer Counsel entered into a stipulation agreement related to Virginia Natural Gas' August 2022 general base rate case filing. The stipulation provides for a $48 million increase in annual base rate revenues, including the recovery of investments under the SAVE program, an ROE of 9.70%, and an equity ratio of 49.06%. The Virginia Commission is expected to rule on this matter by the end of 2023.
On June 15, 2023, the Illinois Commission concluded its review of the Qualifying Infrastructure Plant (QIP) capital investments by Nicor Gas for calendar year 2019 under the QIP Rider, or Investing in Illinois, program. The Illinois Commission disallowed $32 million of the $415 million of capital investments commissioned in 2019, together with the related return on investment. Nicor Gas recorded a pre-tax charge to income in the second quarter 2023 of $38 million ($28 million after tax) associated with the disallowance of capital investments. The disallowance is reflected on the income statement as an $8 million reduction to revenues and a $30 million increase in operating expenses. On July 14, 2023, Nicor Gas requested rehearing by the Illinois Commission, which is expected to render a decision by August 3, 2023. Nicor Gas defends these investments in infrastructure as prudently incurred and, if necessary, intends to appeal to the Illinois Appellate Court.
The ultimate outcome of these matters cannot be determined at this time. See Note (B) to the Condensed Financial Statements under "Southern Company Gas" herein for additional information.
RESULTS OF OPERATIONS
Southern Company
Net Income
| | | | | | | | | | | | | | | | | | | | |
| Second Quarter 2023 vs. Second Quarter 2022 | | Year-To-Date 2023 vs. Year-To-Date 2022 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(269) | | (24.3) | | $(439) | | (20.5) |
Consolidated net income attributable to Southern Company was $0.8 billion ($0.77 per share) in the second quarter 2023 compared to $1.1 billion ($1.04 per share) for the corresponding period in 2022. For year-to-date 2023, consolidated net income attributable to Southern Company was $1.7 billion ($1.56 per share) compared to $2.1 billion ($2.01 per share) for the corresponding period in 2022. The decreases were primarily due to higher depreciation and amortization, a decrease in retail electric revenues associated with milder weather and rates and pricing, and higher interest expense, partially offset by a decrease in income tax expense and lower non-fuel operations and maintenance costs. The year-to-date 2023 decrease was partially offset by an increase in other revenues and an increase in natural gas revenues from rate increases and continued infrastructure replacement.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Retail Electric Revenues
In the second quarter 2023, retail electric revenues were $3.9 billion compared to $4.8 billion for the corresponding period in 2022. For year-to-date 2023, retail electric revenues were $7.5 billion compared to $8.4 billion for the corresponding period in 2022. Details of the changes in retail electric revenues were as follows:
| | | | | | | | | | | | | | | | | | | | | | | |
| | Second Quarter 2023 vs. Second Quarter 2022 | | Year-To-Date 2023 vs. Year-To-Date 2022 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| Rates and pricing | $ | (113) | | | (2.4) | % | | $ | (17) | | | (0.2) | % |
| Sales decline | (24) | | | (0.5) | | | (16) | | | (0.2) | |
| Weather | (174) | | | (3.6) | | | (326) | | | (3.8) | |
| Fuel and other cost recovery | (619) | | | (12.9) | | | (585) | | | (7.0) | |
| Retail electric revenues | $ | (930) | | | (19.4) | % | | $ | (944) | | | (11.2) | % |
Revenues associated with changes in rates and pricing decreased in the second quarter and year-to-date 2023 when compared to the corresponding periods in 2022. The decreases were primarily due to lower contributions from commercial and industrial customers with variable demand-driven pricing at Georgia Power, partially offset by an increase in Rate CNP Compliance revenues at Alabama Power and base tariff increases in accordance with Georgia Power's 2022 ARP. In addition, in the second quarter and year-to-date 2023, revenues associated with Rate CNP Depreciation increased $68 million and $141 million, respectively, and were fully offset by customer bill credits related to the flowback of excess accumulated deferred income taxes at Alabama Power. See Note 2 to the financial statements under "Alabama Power" and "Georgia Power – Rate Plans" in Item 8 of the Form 10-K for additional information.
Revenues attributable to changes in sales decreased in the second quarter and year-to-date 2023 when compared to the corresponding periods in 2022. Weather-adjusted residential KWH sales decreased 0.4% in the second quarter 2023 when compared to the corresponding period in 2022 primarily due to decreased customer usage, partially offset by customer growth. Weather-adjusted residential KWH sales increased 0.5% for year-to-date 2023 when compared to the corresponding period in 2022 primarily due to customer growth. Weather-adjusted commercial KWH sales increased 0.9% and 1.3% in the second quarter and year-to-date 2023, respectively, when compared to the corresponding periods in 2022 due to both increased customer usage and customer growth. Industrial KWH sales decreased 2.4% and 2.0% in the second quarter and year-to-date 2023, respectively, when compared to the corresponding periods in 2022 primarily due to a decrease in the chemicals and textiles sectors, partially offset by an increase in the pipeline sector.
Fuel and other cost recovery revenues decreased $619 million and $585 million in the second quarter and year-to-date 2023, respectively, compared to the corresponding periods in 2022 primarily due to lower recoverable fuel costs. Electric rates for the traditional electric operating companies include provisions to adjust billings for fluctuations in fuel costs, including the energy component of purchased power costs. Under these provisions, fuel revenues generally equal fuel expenses, including the energy component of PPA costs, and do not affect net income. The traditional electric operating companies each have one or more regulatory mechanisms to recover other costs such as environmental and other compliance costs, storm damage, new plants, and PPA capacity costs. See Note 2 to the financial statements in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements herein for additional information.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Wholesale Electric Revenues
| | | | | | | | | | | | | | | | | | | | |
| Second Quarter 2023 vs. Second Quarter 2022 | | Year-To-Date 2023 vs. Year-To-Date 2022 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(332) | | (35.4) | | $(398) | | (24.9) |
In the second quarter 2023, wholesale electric revenues were $605 million compared to $937 million for the corresponding period in 2022. For year-to-date 2023, wholesale electric revenues were $1.2 billion compared to $1.6 billion for the corresponding period in 2022. The decreases were primarily due to decreases of $342 million and $440 million in energy revenues in the second quarter and year-to-date 2023, respectively, as a result of fuel and purchased power price decreases when compared to the corresponding periods in 2022 and a net decrease in the volume of KWHs sold primarily associated with natural gas PPAs at Southern Power. The decreases in energy revenues were partially offset by increases in capacity revenues of $10 million and $42 million in the second quarter and year-to-date 2023, respectively, primarily resulting from a power sales agreement that began in July 2022 and ended in May 2023 at Alabama Power and a net increase in capacity sales from natural gas PPAs at Southern Power.
Wholesale electric revenues consist of revenues from PPAs and short-term opportunity sales. Wholesale electric revenues from PPAs (other than solar and wind PPAs) have both capacity and energy components. Capacity revenues generally represent the greatest contribution to net income and are designed to provide recovery of fixed costs plus a return on investment. Energy revenues will vary depending on fuel prices, the market prices of wholesale energy compared to the Southern Company system's generation, demand for energy within the Southern Company system's electric service territory, and the availability of the Southern Company system's generation. Increases and decreases in energy revenues that are driven by fuel prices are accompanied by an increase or decrease in fuel costs and do not have a significant impact on net income. Energy sales from solar and wind PPAs do not have a capacity charge and customers either purchase the energy output of a dedicated renewable facility through an energy charge or through a fixed price related to the energy. As a result, the ability to recover fixed and variable operations and maintenance expenses is dependent upon the level of energy generated from these facilities, which can be impacted by weather conditions, equipment performance, transmission constraints, and other factors. Wholesale electric revenues at Mississippi Power include FERC-regulated municipal and rural association sales under cost-based tariffs as well as market-based sales. Short-term opportunity sales are made at market-based rates that generally provide a margin above the Southern Company system's variable cost to produce the energy.
Other Electric Revenues
| | | | | | | | | | | | | | | | | | | | |
| Second Quarter 2023 vs. Second Quarter 2022 | | Year-To-Date 2023 vs. Year-To-Date 2022 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $17 | | 8.9 | | $29 | | 7.8 |
In the second quarter 2023, other electric revenues were $209 million compared to $192 million for the corresponding period in 2022. For year-to-date 2023, other electric revenues were $399 million compared to $370 million for the corresponding period in 2022. The increases in the second quarter and year-to-date 2023 were primarily due to increases of $14 million and $21 million, respectively, in transmission revenues primarily associated with open access transmission tariff sales, $8 million and $11 million, respectively, in realized gains associated with price stability products for retail customers on variable demand-driven pricing tariffs at Georgia Power, and $6 million and $12 million, respectively, in outdoor lighting sales at Georgia Power, partially offset by decreases of $7 million and $12 million, respectively, in cogeneration steam revenue primarily associated with lower natural gas prices at Alabama Power.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Natural Gas Revenues
In the second quarter 2023, natural gas revenues were $0.9 billion compared to $1.1 billion for the corresponding period in 2022. For year-to-date 2023, natural gas revenues were $2.7 billion compared to $3.1 billion for the corresponding period in 2022. Details of the changes in natural gas revenues were as follows:
| | | | | | | | | | | | | | | | | | | | | | | |
| Second Quarter 2023 vs. Second Quarter 2022 | | Year-To-Date 2023 vs. Year-To-Date 2022 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| Infrastructure replacement programs and rate changes | $ | 38 | | | 3.5 | % | | $ | 88 | | | 2.8 | % |
| Gas costs and other cost recovery | (265) | | | (24.4) | | | (464) | | | (14.8) | |
| Gas marketing services | (1) | | | (0.1) | | | (22) | | | (0.7) | |
| Other | (3) | | | (0.3) | | | (14) | | | (0.4) | |
| Natural gas revenues | $ | (231) | | | (21.3) | % | | $ | (412) | | | (13.1) | % |
Revenues from infrastructure replacement programs and rate changes at the natural gas distribution utilities increased in the second quarter and year-to-date 2023 compared to the corresponding periods in 2022 primarily due to rate increases at the natural gas distribution utilities and continued investment in infrastructure replacement, partially offset by a regulatory disallowance at Nicor Gas. See Note 2 to the financial statements under "Southern Company Gas – Rate Proceedings" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Southern Company Gas – Infrastructure Replacement Programs and Capital Projects" herein for additional information.
Revenues from gas costs and other cost recovery decreased in the second quarter and year-to-date 2023 compared to the corresponding periods in 2022 primarily due to lower natural gas cost recovery associated with the timing of natural gas purchases and the recovery of those costs from customers. Natural gas distribution rates include provisions to adjust billings for fluctuations in natural gas costs. Therefore, gas costs recovered through natural gas revenues generally equal the amount expensed in cost of natural gas and do not affect net income from the natural gas distribution utilities.
Revenues from gas marketing services decreased in the second quarter and year-to-date 2023 compared to the corresponding periods in 2022 primarily due to lower natural gas prices and the timing of unrealized hedge losses, partially offset by higher variable price spreads in Georgia and Illinois and higher customer count in Georgia.
Other Revenues
| | | | | | | | | | | | | | | | | | | | |
| Second Quarter 2023 vs. Second Quarter 2022 | | Year-To-Date 2023 vs. Year-To-Date 2022 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $18 | | 8.8 | | $99 | | 29.0 |
In the second quarter 2023, other revenues were $223 million compared to $205 million for the corresponding period in 2022. The increase was primarily due to increases of $20 million at Southern Linc primarily related to sales associated with commercial customers and $11 million in power delivery construction and maintenance projects at Georgia Power, partially offset by an $8 million decrease related to distributed infrastructure projects at PowerSecure.
For year-to-date 2023, other revenues were $440 million compared to $341 million for the corresponding period in 2022. The increase was primarily due to increases of $32 million in power delivery construction and maintenance projects at Georgia Power, $28 million related to distributed infrastructure projects at PowerSecure, $17 million at Southern Linc primarily related to sales associated with commercial customers, and $16 million in unregulated sales of products and services at Alabama Power.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Fuel and Purchased Power Expenses
| | | | | | | | | | | | | | | | | | | | | | | |
| | Second Quarter 2023 vs. Second Quarter 2022 | | Year-To-Date 2023 vs. Year-To-Date 2022 |
| | (change in millions) | | (% change) | | (change in millions) | | (% change) |
| Fuel | $ | (756) | | | (44.1) | | $ | (817) | | | (28.9) |
| Purchased power | (177) | | | (43.4) | | (167) | | | (26.1) |
| Total fuel and purchased power expenses | $ | (933) | | | | | $ | (984) | | | |
In the second quarter 2023, total fuel and purchased power expenses were $1.2 billion compared to $2.1 billion for the corresponding period in 2022. The decrease was due to a $792 million decrease in the average cost of fuel and purchased power and a $141 million decrease in the volume of KWHs generated and purchased.
For year-to-date 2023, total fuel and purchased power expenses were $2.5 billion compared to $3.5 billion for the corresponding period in 2022. The decrease was due to an $868 million decrease in the average cost of fuel and purchased power and a $116 million decrease in the volume of KWHs generated and purchased.
Fuel and purchased power energy transactions at the traditional electric operating companies are generally offset by fuel revenues and do not have a significant impact on net income. See Note 2 to the financial statements in Item 8 of the Form 10-K for additional information. Fuel expenses incurred under Southern Power's PPAs are generally the responsibility of the counterparties and do not significantly impact net income.
Details of the Southern Company system's generation and purchased power were as follows:
| | | | | | | | | | | | | | |
| Second Quarter 2023 | Second Quarter 2022 | Year-To-Date 2023 | Year-To-Date 2022 |
Total generation (in billions of KWHs)(a)(b) | 44 | 46 | 88 | 92 |
Total purchased power (in billions of KWHs) | 5 | 6 | 9 | 11 |
Sources of generation (percent)(a) — | | | | |
| Gas | 54 | 49 | 54 | 47 |
Nuclear(b) | 18 | 16 | 17 | 16 |
| Coal | 16 | 22 | 16 | 23 |
| Hydro | 3 | 3 | 4 | 5 |
| Wind, Solar, and Other | 9 | 10 | 9 | 9 |
Cost of fuel, generated (in cents per net KWH)— | | | | |
Gas(a) | 2.42 | 5.59 | 2.78 | 4.60 |
Nuclear(b) | 0.71 | 0.72 | 0.71 | 0.72 |
| Coal | 4.55 | 3.50 | 4.30 | 3.30 |
Average cost of fuel, generated (in cents per net KWH)(a)(b) | 2.47 | 4.13 | 2.63 | 3.50 |
Average cost of purchased power (in cents per net KWH)(c) | 4.97 | 7.83 | 5.23 | 6.90 |
(a)Excludes Central Alabama Generating Station KWHs and associated cost of fuel through July 12, 2022 as its fuel was previously provided by the purchaser under a power sales agreement. See Note 15 to the financial statements under "Alabama Power" in Item 8 of the Form 10-K for additional information.
(b)Excludes KWHs generated from test period energy at Plant Vogtle Unit 3 prior to its in-service date. The related fuel costs are charged to CWIP in accordance with FERC guidance. See Note (B) to the Condensed Financial Statements under "Georgia Power – Nuclear Construction" herein for additional information on Plant Vogtle Units 3 and 4.
(c)Average cost of purchased power includes fuel purchased by the Southern Company system for tolling agreements where power is generated by the provider.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Fuel
In the second quarter 2023, fuel expense was $1.0 billion compared to $1.7 billion for the corresponding period in 2022. For year-to-date 2023, fuel expense was $2.0 billion compared to $2.8 billion for the corresponding period in 2022. The decreases for the second quarter and year-to-date 2023 were primarily due to decreases of 56.7% and 39.6%, respectively, in the average cost of natural gas per KWH generated and 28.8% and 34.0%, respectively, in the volume of KWHs generated by coal, partially offset by increases of 30.0% and 30.3%, respectively, in the average cost of coal per KWH generated, decreases of 8.3% and 12.0%, respectively, in the volume of KWHs generated by hydro, and increases of 6.0% and 10.9%, respectively, in the volume of KWHs generated by natural gas.
Purchased Power
In the second quarter 2023, purchased power expense was $231 million compared to $408 million for the corresponding period in 2022. For year-to-date 2023, purchased power expense was $473 million compared to $640 million for the corresponding period in 2022. The decreases for the second quarter and year-to-date 2023 were primarily due to decreases of 36.5% and 24.2%, respectively, in the average cost per KWH purchased primarily due to a decrease in natural gas prices and decreases of 22.8% and 12.7%, respectively, in the volume of KWHs purchased.
Energy purchases will vary depending on demand for energy within the Southern Company system's electric service territory, the market prices of wholesale energy as compared to the cost of the Southern Company system's generation, and the availability of the Southern Company system's generation.
Cost of Natural Gas
| | | | | | | | | | | | | | | | | | | | |
| Second Quarter 2023 vs. Second Quarter 2022 | | Year-To-Date 2023 vs. Year-To-Date 2022 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(253) | | (56.0) | | $(449) | | (29.0) |
Excluding Atlanta Gas Light, which does not sell natural gas to end-use customers, natural gas distribution rates include provisions to adjust billings for fluctuations in natural gas costs. Therefore, gas costs recovered through natural gas revenues generally equal the amount expensed in cost of natural gas and do not affect net income from the natural gas distribution utilities. Cost of natural gas at the natural gas distribution utilities represented 84% and 85% of the total cost of natural gas in the second quarter and year-to-date 2023, respectively.
In the second quarter 2023, cost of natural gas was $199 million compared to $452 million for the corresponding period in 2022. For year-to-date 2023, cost of natural gas was $1.1 billion compared to $1.5 billion for the corresponding period in 2022. The decreases reflect lower gas cost recovery as a result of decreases of 71% and 54% in natural gas prices in the second quarter and year-to-date 2023, respectively, compared to the corresponding periods in 2022.
Cost of Other Sales
| | | | | | | | | | | | | | | | | | | | |
| Second Quarter 2023 vs. Second Quarter 2022 | | Year-To-Date 2023 vs. Year-To-Date 2022 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $14 | | 12.3 | | $72 | | 39.3 |
In the second quarter 2023, cost of other sales was $128 million compared to $114 million for the corresponding period in 2022. The increase was primarily due to increases of $16 million at Southern Linc primarily related to sales associated with commercial customers and $11 million related to energy service contracts at Southern Company Gas, partially offset by a $13 million decrease related to distributed infrastructure projects at PowerSecure.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
For year-to-date 2023, cost of other sales was $255 million compared to $183 million for the corresponding period in 2022. The increase was primarily due to increases of $24 million from unregulated power delivery construction and maintenance projects at Georgia Power, $16 million related to energy service contracts at Southern Company Gas, $16 million at Southern Linc primarily related to sales associated with commercial customers, $16 million related to distributed infrastructure projects at PowerSecure, and $7 million in expenses related to unregulated products and services at Alabama Power.
Other Operations and Maintenance Expenses
| | | | | | | | | | | | | | | | | | | | |
| Second Quarter 2023 vs. Second Quarter 2022 | | Year-To-Date 2023 vs. Year-To-Date 2022 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(59) | | (3.8) | | $(113) | | (3.7) |
In the second quarter 2023, other operations and maintenance expenses were $1.49 billion compared to $1.55 billion for the corresponding period in 2022. The decrease was primarily due to decreases of $45 million in storm damage recovery as authorized in Georgia Power's 2022 ARP, $29 million in transmission and distribution expenses primarily related to line maintenance, $20 million in expenses passed through to customers primarily related to bad debt and energy efficiency programs at Southern Company Gas, and $14 million in generation expenses primarily associated with non-outage and scheduled outage maintenance costs, partially offset by a $32 million increase in technology infrastructure and application production costs and $30 million related to a regulatory disallowance at Nicor Gas.
For year-to-date 2023, other operations and maintenance expenses were $2.9 billion compared to $3.0 billion for the corresponding period in 2022. The decrease was primarily due to decreases of $91 million in storm damage recovery as authorized in Georgia Power's 2022 ARP, $59 million in transmission and distribution expenses primarily related to line maintenance, $57 million in generation expenses primarily associated with non-outage and scheduled outage maintenance costs, and $36 million in expenses passed through to customers primarily related to bad debt and energy efficiency programs at Southern Company Gas, as well as a $16 million gain on the sale of spare parts in 2023 at Southern Power, partially offset by a $69 million increase in technology infrastructure and application production costs, $30 million related to a regulatory disallowance at Nicor Gas, a $25 million decrease in nuclear property insurance refunds at Georgia Power and Alabama Power, and a $14 million increase in employee compensation and benefit expenses.
See Note (B) to the Condensed Financial Statements under "Southern Company Gas – Infrastructure Replacement Programs and Capital Projects" herein for additional information on the regulatory disallowance at Nicor Gas.
Depreciation and Amortization
| | | | | | | | | | | | | | | | | | | | |
| Second Quarter 2023 vs. Second Quarter 2022 | | Year-To-Date 2023 vs. Year-To-Date 2022 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $199 | | 21.8 | | $417 | | 23.1 |
In the second quarter 2023, depreciation and amortization was $1.1 billion compared to $0.9 billion for the corresponding period in 2022. For year-to-date 2023, depreciation and amortization was $2.2 billion compared to $1.8 billion for the corresponding period in 2022. The increases in the second quarter and year-to-date 2023 were primarily due to increases of $182 million and $363 million, respectively, resulting from higher depreciation rates at Alabama Power and Georgia Power and increases of $20 million and $46 million, respectively, from additional plant in service. See Notes 2 and 5 to the financial statements under "Alabama Power" and "Depreciation and Amortization," respectively, in Item 8 of the Form 10-K for additional information.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Taxes Other Than Income Taxes
| | | | | | | | | | | | | | | | | | | | |
| Second Quarter 2023 vs. Second Quarter 2022 | | Year-To-Date 2023 vs. Year-To-Date 2022 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(9) | | (2.6) | | $13 | | 1.8 |
In the second quarter 2023, taxes other than income taxes were $340 million compared to $349 million for the corresponding period in 2022. The decrease was primarily due to decreases of $17 million in municipal franchise fees resulting from lower retail revenues at Georgia Power and $7 million in revenue tax expenses at Southern Company Gas, partially offset by increases of $10 million in property taxes primarily at Georgia Power resulting from an increase in the assessed value of property and $7 million in utility license taxes at Alabama Power.
For year-to-date 2023, taxes other than income taxes were $734 million compared to $721 million for the corresponding period in 2022. The increase was primarily due to increases of $22 million in property taxes primarily at Georgia Power resulting from an increase in the assessed value of property and $16 million in utility license taxes at Alabama Power, partially offset by decreases of $17 million in municipal franchise fees resulting from lower retail revenues at Georgia Power and $12 million in revenue tax expenses at Southern Company Gas.
Estimated Loss on Plant Vogtle Units 3 and 4
| | | | | | | | | | | | | | | | | | | | |
| Second Quarter 2023 vs. Second Quarter 2022 | | Year-To-Date 2023 vs. Year-To-Date 2022 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(52) | | (100.0) | | $(52) | | (100.0) |
In the second quarter 2022, Georgia Power recorded an estimated probable loss on Plant Vogtle Units 3 and 4 of $52 million. The loss reflected revisions to the total project capital cost forecast to complete construction and start-up of Plant Vogtle Units 3 and 4. See Note (B) to the Condensed Financial Statements herein and Note 2 to the financial statements in Item 8 of the Form 10-K under "Georgia Power – Nuclear Construction" for additional information.
Allowance for Equity Funds Used During Construction
| | | | | | | | | | | | | | | | | | | | |
| Second Quarter 2023 vs. Second Quarter 2022 | | Year-To-Date 2023 vs. Year-To-Date 2022 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $17 | | 32.1 | | $31 | | 29.8 |
In the second quarter 2023, allowance for equity funds used during construction was $70 million compared to $53 million for the corresponding period in 2022. For year-to-date 2023, allowance for equity funds used during construction was $135 million compared to $104 million for the corresponding period in 2022. The increases were primarily associated with an increase in capital expenditures subject to AFUDC at Georgia Power and an increase in capital expenditures related to Plant Barry Unit 8 construction at Alabama Power. See Note 2 to the financial statements in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements herein under "Alabama Power – Certificates of Convenience and Necessity" for additional information.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Interest Expense, Net of Amounts Capitalized
| | | | | | | | | | | | | | | | | | | | |
| Second Quarter 2023 vs. Second Quarter 2022 | | Year-To-Date 2023 vs. Year-To-Date 2022 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $122 | | 25.0 | | $242 | | 25.5 |
In the second quarter 2023, interest expense, net of amounts capitalized was $610 million compared to $488 million for the corresponding period in 2022. For year-to-date 2023, interest expense, net of amounts capitalized was $1.2 billion compared to $1.0 billion for the corresponding period in 2022. The increases in the second quarter and year-to-date 2023 primarily reflect approximately $76 million and $170 million, respectively, related to higher interest rates and $48 million and $87 million, respectively, related to higher average outstanding borrowings. See FINANCIAL CONDITION AND LIQUIDITY – "Sources of Capital" and "Financing Activities" herein for additional information on borrowings.
Other Income (Expense), Net
| | | | | | | | | | | | | | | | | | | | |
| Second Quarter 2023 vs. Second Quarter 2022 | | Year-To-Date 2023 vs. Year-To-Date 2022 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $3 | | 2.2 | | $3 | | 1.1 |
In the second quarter 2023, other income (expense), net was $142 million compared to $139 million for the corresponding period in 2022. For year-to-date 2023, other income (expense), net was $286 million compared to $283 million for the corresponding period in 2022. The increases for the second quarter and year-to-date 2023 were primarily due to increases of $21 million and $26 million, respectively, in interest income, largely offset by decreases of $12 million and $19 million, respectively, in non-service cost-related retirement benefits income and $7 million and $13 million, respectively, in customer charges related to contributions in aid of construction at Georgia Power. The year-to-date 2023 increase also reflects an $8 million gain on investments at Southern Holdings. See Note (H) to the Condensed Financial Statements herein for additional information.
Income Taxes
| | | | | | | | | | | | | | | | | | | | |
| Second Quarter 2023 vs. Second Quarter 2022 | | Year-To-Date 2023 vs. Year-To-Date 2022 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(206) | | (67.8) | | $(283) | | (59.3) |
In the second quarter 2023, income taxes were $98 million compared to $304 million for the corresponding period in 2022. For year-to-date 2023, income taxes were $194 million compared to $477 million for the corresponding period in 2022. The decreases were primarily due to lower pre-tax earnings, an increase in the flowback of certain excess deferred income taxes at Alabama Power, an adjustment in the second quarter 2022 related to a prior year state tax credit carryforward at Georgia Power, and a decrease in a valuation allowance on certain state tax credit carryforwards at Georgia Power in 2023, partially offset by a decrease in the flowback of certain excess deferred income taxes at Georgia Power that ended in 2022. See Note (G) to the Condensed Financial Statements herein for additional information.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Net Loss Attributable to Noncontrolling Interests
| | | | | | | | | | | | | | | | | | | | |
| Second Quarter 2023 vs. Second Quarter 2022 | | Year-To-Date 2023 vs. Year-To-Date 2022 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $7 | | 31.8 | | $(11) | | (16.4) |
Substantially all noncontrolling interests relate to renewable projects at Southern Power. In the second quarter 2023, net loss attributable to noncontrolling interests was $15 million compared to $22 million for the corresponding period in 2022. The decreased loss was primarily due to $7 million in lower HLBV loss allocations to Southern Power's wind tax equity partners and $6 million in lower loss allocations to Southern Power's battery energy storage partners, partially offset by $5 million in lower income allocations to Southern Power's equity partners.
For year-to-date 2023, net loss attributable to noncontrolling interests was $78 million compared to $67 million for the corresponding period in 2022. The increased loss was primarily due to $15 million in lower income allocations to Southern Power's equity partners and $9 million in higher HLBV loss allocations to Southern Power's wind tax equity partners, partially offset by $14 million in lower loss allocations to Southern Power's battery energy storage partners.
Alabama Power
Net Income
| | | | | | | | | | | | | | | | | | | | |
| Second Quarter 2023 vs. Second Quarter 2022 | | Year-To-Date 2023 vs. Year-To-Date 2022 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(71) | | (18.5) | | $(162) | | (22.2) |
Alabama Power's net income after dividends on preferred stock in the second quarter 2023 was $312 million compared to $383 million for the corresponding period in 2022. Alabama Power's net income after dividends on preferred stock for year-to-date 2023 was $568 million compared to $730 million for the corresponding period in 2022. These decreases were primarily due to an increase in depreciation rates effective January 2023 and a decrease in weather-related revenues due to milder weather in Alabama Power's service territory in 2023 compared to the corresponding periods in 2022. In addition, the year-to-date 2023 decrease was also due to increased capacity-related expenses. These decreases to income were partially offset by a decrease in income tax expense and an increase in Rate CNP Compliance revenues. See Note 2 to the financial statements in Item 8 of the Form 10-K under "Alabama Power" for additional information.
Retail Revenues
In the second quarter 2023, retail revenues were $1.47 billion compared to $1.63 billion for the corresponding period in 2022. For year-to-date 2023, retail revenues were $2.85 billion compared to $3.01 billion for the corresponding period in 2022. Details of the changes in retail revenues were as follows:
| | | | | | | | | | | | | | | | | | | | | | | |
| | Second Quarter 2023 vs. Second Quarter 2022 | | Year-To-Date 2023 vs. Year-To-Date 2022 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| Rates and pricing | $ | 56 | | | 3.4 | % | | $ | 114 | | | 3.8 | % |
| Sales decline | (16) | | | (1.0) | | | (33) | | | (1.1) | |
| Weather | (58) | | | (3.6) | | | (119) | | | (4.0) | |
| Fuel and other cost recovery | (144) | | | (8.8) | | | (122) | | | (4.1) | |
| Retail revenues | $ | (162) | | | (10.0) | % | | $ | (160) | | | (5.4) | % |
Revenues associated with changes in rates and pricing increased in the second quarter and year-to-date 2023 when compared to the corresponding periods in 2022 primarily due to an increase in Rate CNP Compliance revenues. In
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
addition, in the second quarter and year-to-date 2023, revenues associated with Rate CNP Depreciation increased $68 million and $141 million, respectively, and were fully offset by customer bill credits related to the flowback of excess accumulated deferred income taxes. See Note 2 to the financial statements under "Alabama Power" in Item 8 of the Form 10-K for additional information.
Revenues attributable to changes in sales decreased in the second quarter and year-to-date 2023 when compared to the corresponding periods in 2022. Weather-adjusted residential KWH sales increased 1.1% and 0.6% in the second quarter and year-to-date 2023, respectively, when compared to the corresponding periods in 2022 primarily due to customer growth. Weather-adjusted commercial KWH sales increased 1.5% and 0.6% in the second quarter and year-to-date 2023, respectively, when compared to the corresponding periods in 2022 primarily due to increases in customer demand and customer growth. Industrial KWH sales decreased 4.3% and 3.4% in the second quarter and year-to-date 2023, respectively, primarily due to decreases in the chemicals and forest products sectors. Also contributing to the industrial KWH sales decrease in the second quarter 2023 was a decrease in the primary metals sector.
Fuel and other cost recovery revenues decreased in the second quarter and year-to-date 2023 when compared to the corresponding periods in 2022 primarily as a result of lower recoverable fuel costs.
Electric rates include provisions to recognize the recovery of fuel costs, purchased power costs, PPAs certificated by the Alabama PSC, and costs associated with the NDR. Under these provisions, fuel and other cost recovery revenues generally equal fuel and other cost recovery expenses and do not affect net income. See Note 2 to the financial statements under "Alabama Power" in Item 8 of the Form 10-K for additional information.
Wholesale Revenues – Non-Affiliates
| | | | | | | | | | | | | | | | | | | | |
| Second Quarter 2023 vs. Second Quarter 2022 | | Year-To-Date 2023 vs. Year-To-Date 2022 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(47) | | (29.6) | | $(20) | | (7.4) |
In the second quarter 2023, wholesale revenues from sales to non-affiliates were $112 million compared to $159 million for the corresponding period in 2022. The decrease was primarily due to a 28.3% decrease in the price of energy primarily as a result of lower natural gas prices in the second quarter 2023 compared to the corresponding period in 2022.
For year-to-date 2023, wholesale revenues from sales to non-affiliates were $252 million compared to $272 million for the corresponding period in 2022. The decrease was primarily due to a 14.5% decrease in the price of energy due to lower natural gas prices, partially offset by an 8.3% increase in the volume of KWHs sold as a result of a power sales agreement that began in July 2022 and ended in May 2023.
Wholesale revenues from sales to non-affiliates will vary depending on fuel prices, the market prices of wholesale energy compared to the cost of Alabama Power's and the Southern Company system's generation, demand for energy within the Southern Company system's electric service territory, and the availability of the Southern Company system's generation. Increases and decreases in energy revenues that are driven by fuel prices are accompanied by an increase or decrease in fuel costs and do not affect net income. Short-term opportunity energy sales are also included in wholesale energy sales to non-affiliates. These opportunity sales are made at market-based rates that generally provide a margin above Alabama Power's variable cost to produce the energy.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Wholesale Revenues – Affiliates
| | | | | | | | | | | | | | | | | | | | |
| Second Quarter 2023 vs. Second Quarter 2022 | | Year-To-Date 2023 vs. Year-To-Date 2022 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(24) | | (70.6) | | $(71) | | (71.0) |
In the second quarter 2023, wholesale revenues from sales to affiliates were $10 million compared to $34 million for the corresponding period in 2022. For year-to-date 2023, wholesale revenues from sales to affiliates were $29 million compared to $100 million for the corresponding period in 2022. The decreases for the second quarter and year-to-date 2023 were primarily due to decreases of 62.0% and 35.4%, respectively, in the price of energy due to lower natural gas prices and 23.9% and 54.3%, respectively, in the volume of KWH sales due to lower customer demand as a result of milder weather in 2023 compared to the corresponding period in 2022.
Wholesale revenues from sales to affiliated companies will vary depending on demand and the availability and cost of generating resources at each company. These affiliate sales are made in accordance with the IIC, as approved by the FERC. Energy revenues related to these transactions do not have a significant impact on earnings since this energy is generally sold at marginal cost and energy purchases are generally offset by energy revenues through Alabama Power's energy cost recovery clause.
Fuel and Purchased Power Expenses
| | | | | | | | | | | | | | | | | | | | | | | |
| Second Quarter 2023 vs. Second Quarter 2022 | | Year-To-Date 2023 vs. Year-To-Date 2022 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| Fuel | $ | (98) | | | (24.4) | | | $ | (122) | | | (16.6) | |
| Purchased power – non-affiliates | (41) | | | (43.2) | | | (7) | | | (4.3) | |
| Purchased power – affiliates | (67) | | | (55.4) | | | (34) | | | (23.1) | |
| Total fuel and purchased power expenses | $ | (206) | | | | | $ | (163) | | | |
In the second quarter 2023, total fuel and purchased power expenses were $411 million compared to $617 million for the corresponding period in 2022. For year-to-date 2023, total fuel and purchased power expenses were $879 million compared to $1.04 billion for the corresponding period in 2022. The decreases for the second quarter and year-to-date 2023 were due to decreases of $214 million and $222 million, respectively, in the average cost of fuel and purchased power, partially offset by an increase of $8 million and a net increase of $59 million, respectively, related to the volume of KWHs generated and purchased.
Fuel and purchased power energy transactions do not have a significant impact on earnings, since energy expenses are generally offset by energy revenues through Alabama Power's energy cost recovery clause. See Note 2 to the financial statements under "Alabama Power – Rate ECR" in Item 8 of the Form 10-K for additional information.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Details of Alabama Power's generation and purchased power were as follows:
| | | | | | | | | | | | | | | | | | | | | | | |
| Second Quarter 2023 | | Second Quarter 2022 | | Year-To-Date 2023 | | Year-To-Date 2022 |
Total generation (in billions of KWHs)(a) | 13 | | 13 | | 27 | | 29 |
Total purchased power (in billions of KWHs) | 3 | | 3 | | 5 | | 4 |
Sources of generation (percent)(a) — | | | | | | | |
| Coal | 35 | | 45 | | 33 | | 44 |
| Nuclear | 29 | | 25 | | 28 | | 25 |
| Gas | 29 | | 22 | | 29 | | 20 |
| Hydro | 7 | | 8 | | 10 | | 11 |
Cost of fuel, generated (in cents per net KWH) — | | | | | | | |
| Coal | 3.50 | | 3.35 | | 3.42 | | 3.11 |
| Nuclear | 0.69 | | 0.67 | | 0.68 | | 0.67 |
Gas(a) | 2.69 | | 4.88 | | 3.03 | | 4.17 |
Average cost of fuel, generated (in cents per net KWH)(a) | 2.39 | | 2.98 | | 2.44 | | 2.66 |
Average cost of purchased power (in cents per net KWH)(b) | 4.08 | | 8.88 | | 5.17 | | 8.12 |
(a)Excludes Central Alabama Generating Station KWHs and associated cost of fuel through July 12, 2022 as its fuel was previously provided by the purchaser under a power sales agreement. See Note 15 to the financial statements under "Alabama Power" in Item 8 of the Form 10-K for additional information.
(b)Average cost of purchased power includes fuel, energy, and transmission purchased by Alabama Power for tolling agreements where power is generated by the provider.
Fuel
In the second quarter 2023, fuel expense was $303 million compared to $401 million for the corresponding period in 2022. The decrease was primarily due to a 44.9% decrease in the average cost of natural gas per KWH generated, which excludes tolling agreements, and a 23.0% decrease in the volume of KWHs generated by coal, partially offset by a 33.3% increase in the volume of KWHs generated by natural gas, a 9.2% decrease in the volume of KWHs generated by hydro facilities as a result of less rainfall in the second quarter 2023 compared to the corresponding period in 2022, and a 4.5% increase in the average cost of coal per KWH generated.
For year-to-date 2023, fuel expense was $611 million compared to $733 million for the corresponding period in 2022. The decrease was primarily due to a 29.1% decrease in the volume of KWHs generated by coal and a 27.3% decrease in the average cost of natural gas per KWH generated, which excludes tolling agreements, partially offset by a 34.9% increase in the volume of KWHs generated by natural gas, an 11.6% decrease in the volume of KWHs generated by hydro facilities as a result of less rainfall for year-to-date 2023 compared to the corresponding period in 2022, and a 10.0% increase in the average cost of coal per KWH generated.
Purchased Power – Non-Affiliates
In the second quarter 2023, purchased power expense from non-affiliates was $54 million compared to $95 million for the corresponding period in 2022. The decrease was primarily due to a 50.8% decrease in the average cost per KWH purchased due to lower natural gas prices.
For year-to-date 2023, purchased power expense from non-affiliates was $155 million compared to $162 million for the corresponding period in 2022. The decrease was primarily due to a 35.7% decrease in the average cost per KWH purchased as a result of lower natural gas prices, partially offset by a 25.5% increase in the volume of KWHs purchased due to a new power purchase contract that began in July 2022 and ended in May 2023.
Energy purchases from non-affiliates will vary depending on the market prices of wholesale energy as compared to the cost of the Southern Company system's generation, demand for energy within the Southern Company system's electric service territory, and the availability of the Southern Company system's generation.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Purchased Power – Affiliates
In the second quarter 2023, purchased power expense from affiliates was $54 million compared to $121 million for the corresponding period in 2022. For year-to-date 2023, purchased power expense from affiliates was $113 million compared to $147 million for the corresponding period in 2022. The decreases for the second quarter and year-to-date 2023 were primarily due to decreases of 57.8% and 36.6%, respectively, in the average cost per KWH purchased due to lower purchase prices as a result of lower natural gas prices, partially offset by increases of 6.3% and 21.0%, respectively, in the volume of KWHs purchased due to the availability of lower cost gas generation in the Southern Company system.
Energy purchases from affiliates will vary depending on demand for energy and the availability and cost of generating resources at each company within the Southern Company system. These purchases are made in accordance with the IIC or other contractual agreements, as approved by the FERC.
Other Operations and Maintenance Expenses
| | | | | | | | | | | | | | | | | | | | |
| Second Quarter 2023 vs. Second Quarter 2022 | | Year-To-Date 2023 vs. Year-To-Date 2022 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(1) | | (0.2) | | $10 | | 1.2 |
In the second quarter 2023, other operations and maintenance expenses were $440 million compared to $441 million for the corresponding period in 2022. The decrease was primarily due to a $15 million decrease in generation expenses primarily associated with planned outages and maintenance and a $4 million decrease related to the injuries and damages reserve. The decreases were largely offset by increases of $10 million in technology infrastructure and application production costs, $5 million in customer accounts primarily associated with bad debt expense, and $5 million in expenses related to unregulated products and services.
For year-to-date 2023, other operations and maintenance expenses were $862 million compared to $852 million for the corresponding period in 2022. The increase was primarily due to a $14 million decrease in nuclear property insurance refunds and increases of $18 million in technology infrastructure and application production costs, $13 million in expenses related to unregulated products and services, and $9 million in customer accounts primarily associated with bad debt expense. The increases were partially offset by a $47 million decrease in generation expenses primarily associated with planned outages and maintenance.
Depreciation and Amortization
| | | | | | | | | | | | | | | | | | | | |
| Second Quarter 2023 vs. Second Quarter 2022 | | Year-To-Date 2023 vs. Year-To-Date 2022 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $131 | | 60.1 | | $262 | | 60.6 |
In the second quarter 2023, depreciation and amortization was $349 million compared to $218 million for the corresponding period in 2022. For year-to-date 2023, depreciation and amortization was $694 million compared to $432 million for the corresponding period in 2022. The increases were primarily due to an increase in depreciation rates effective in 2023. See Notes 2 and 5 to the financial statements under "Alabama Power" and "Depreciation and Amortization," respectively, in Item 8 of the Form 10-K for additional information.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Taxes Other Than Income Taxes
| | | | | | | | | | | | | | | | | | | | |
| Second Quarter 2023 vs. Second Quarter 2022 | | Year-To-Date 2023 vs. Year-To-Date 2022 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $7 | | 7.0 | | $19 | | 9.3 |
In the second quarter 2023, taxes other than income taxes were $107 million compared to $100 million for the corresponding period in 2022. For year-to-date 2023, taxes other than income taxes were $223 million compared to $204 million for the corresponding period in 2022. The increases were primarily due to an increase in utility license taxes.
Interest Expense, Net of Amounts Capitalized
| | | | | | | | | | | | | | | | | | | | |
| Second Quarter 2023 vs. Second Quarter 2022 | | Year-To-Date 2023 vs. Year-To-Date 2022 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $14 | | 15.4 | | $28 | | 15.6 |
In the second quarter 2023, interest expense, net of amounts capitalized was $105 million compared to $91 million for the corresponding period in 2022. For year-to-date 2023, interest expense, net of amounts capitalized was $208 million compared to $180 million for the corresponding period in 2022. The increases for the second quarter and year-to-date 2023 were primarily associated with increases of approximately $9 million and $20 million, respectively, related to higher average outstanding borrowings and $6 million and $11 million, respectively, related to higher interest rates. See FINANCIAL CONDITION AND LIQUIDITY – "Sources of Capital" herein for additional information on borrowings.
Other Income (Expense), Net
| | | | | | | | | | | | | | | | | | | | |
| Second Quarter 2023 vs. Second Quarter 2022 | | Year-To-Date 2023 vs. Year-To-Date 2022 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $12 | | 44.4 | | $18 | | 29.5 |
In the second quarter 2023, other income (expense), net was $39 million compared to $27 million for the corresponding period in 2022. For year-to-date 2023, other income (expense), net was $79 million compared to $61 million for the corresponding period in 2022. The increases were primarily due to an increase in interest income and a decrease in non-operating expenses.
Income Taxes
| | | | | | | | | | | | | | | | | | | | |
| Second Quarter 2023 vs. Second Quarter 2022 | | Year-To-Date 2023 vs. Year-To-Date 2022 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(96) | | (79.3) | | $(204) | | (89.9) |
In the second quarter 2023, income taxes were $25 million compared to $121 million for the corresponding period in 2022. For year-to-date 2023, income taxes were $23 million compared to $227 million for the corresponding period in 2022. The decreases were primarily due to an increase in the flowback of certain excess deferred income taxes and lower pre-tax earnings. See Note 2 to the financial statements under "Alabama Power – Excess Accumulated Deferred Income Tax Accounting Order" in Item 8 of the Form 10-K and Note (G) to the Condensed Financial Statements herein for additional information.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Georgia Power
Net Income
| | | | | | | | | | | | | | | | | | | | |
| Second Quarter 2023 vs. Second Quarter 2022 | | Year-To-Date 2023 vs. Year-To-Date 2022 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(137) | | (22.5) | | $(226) | | (22.8) |
Georgia Power's net income in the second quarter 2023 was $471 million compared to $608 million for the corresponding period in 2022. For year-to-date 2023, net income was $767 million compared to $993 million for the corresponding period in 2022. The decreases were primarily due to decreases in retail revenues associated with lower contributions from variable demand-driven pricing and milder weather in the second quarter and year-to-date 2023 compared to the corresponding periods in 2022 and higher interest expense, partially offset by lower non-fuel operations and maintenance costs and a decrease of $39 million in after-tax charges related to the construction of Plant Vogtle Units 3 and 4. Also partially offsetting the net income reductions were the impacts of the 2022 ARP effective January 1, 2023, including increased retail rates, largely offset by higher depreciation and amortization.
See Note 2 to the financial statements under "Georgia Power" in Item 8 of the Form 10-K for additional information.
Retail Revenues
In the second quarter 2023, retail revenues were $2.17 billion compared to $2.91 billion for the corresponding period in 2022. For year-to-date 2023, retail revenues were $4.15 billion compared to $4.93 billion for the corresponding period in 2022. Details of the changes in retail revenues were as follows:
| | | | | | | | | | | | | | | | | | | | | | | |
| | Second Quarter 2023 vs. Second Quarter 2022 | | Year-To-Date 2023 vs. Year-To-Date 2022 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| Rates and pricing | $ | (166) | | | (5.7) | % | | $ | (132) | | | (2.7) | % |
| Sales growth (decline) | (9) | | | (0.3) | | | 14 | | | 0.3 | |
| Weather | (111) | | | (3.8) | | | (197) | | | (4.0) | |
| Fuel cost recovery | (457) | | | (15.7) | | | (465) | | | (9.4) | |
| Retail revenues | $ | (743) | | | (25.5) | % | | $ | (780) | | | (15.8) | % |
Revenues associated with changes in rates and pricing decreased in the second quarter and year-to-date 2023 when compared to the corresponding periods in 2022. The decreases were primarily due to lower contributions from commercial and industrial customers with variable demand-driven pricing, partially offset by base tariff increases in accordance with the 2022 ARP. See Note 2 to the financial statements under "Georgia Power – Rate Plans" in Item 8 of the Form 10-K for additional information.
Revenues attributable to changes in sales decreased in the second quarter 2023 and increased for year-to-date 2023 when compared to the corresponding periods in 2022. Weather-adjusted residential KWH sales decreased 1.3% in the second quarter 2023 when compared to the corresponding period in 2022 primarily due to decreased customer usage, partially offset by customer growth. Weather-adjusted residential KWH sales increased 0.5% for year-to-date 2023 when compared to the corresponding period in 2022 primarily due to customer growth, partially offset by decreased customer usage. Weather-adjusted commercial KWH sales increased 0.5% in the second quarter 2023 when compared to the corresponding period in 2022 primarily due to customer growth, partially offset by decreased customer usage. Weather-adjusted commercial KWH sales increased 1.5% for year-to-date 2023 when compared to the corresponding period in 2022 primarily due to customer growth and increased customer usage as customers continued their return to regular business trends. Weather-adjusted industrial KWH sales increased 0.4% in the second quarter 2023 when compared to the corresponding period in 2022 primarily due to increases in the paper and electronics sectors, partially offset by decreases in the textile and mining sectors. Weather-adjusted industrial KWH
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
sales decreased 0.8% for year-to-date 2023 when compared to the corresponding period in 2022 primarily due to decreases in the textile and rubber sectors, partially offset by increases in the electronics and pipeline sectors.
Fuel revenues and costs are allocated between retail and wholesale jurisdictions. Retail fuel cost recovery revenues decreased in the second quarter and year-to-date 2023 when compared to the corresponding periods in 2022 due to lower fuel and purchased power costs. Electric rates include provisions to adjust billings for fluctuations in fuel costs, including the energy component of purchased power costs. Under these fuel cost recovery provisions, fuel revenues generally equal fuel expenses and do not affect net income. See Note (B) to the Condensed Financial Statements herein and Note 2 to the financial statements in Item 8 of the Form 10-K under "Georgia Power – Fuel Cost Recovery" for additional information.
Wholesale Revenues
| | | | | | | | | | | | | | | | | | | | |
| Second Quarter 2023 vs. Second Quarter 2022 | | Year-To-Date 2023 vs. Year-To-Date 2022 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(17) | | (26.6) | | $(52) | | (40.0) |
In the second quarter 2023, wholesale revenues were $47 million compared to $64 million for the corresponding period in 2022. The decrease was primarily due to a $22 million decrease related to the average cost per KWH sold due to lower Southern Company system fuel and purchased power costs.
For year-to-date 2023, wholesale revenues were $78 million compared to $130 million for the corresponding period in 2022. The decrease was primarily due to a $26 million decrease related to the volume of KWH sales associated with lower market demand and a $23 million decrease related to the average cost per KWH sold due to lower Southern Company system fuel and purchased power costs.
Wholesale revenues from sales to non-affiliates consist of PPAs and short-term opportunity sales. Wholesale revenues from PPAs have both capacity and energy components. Wholesale capacity revenues from PPAs are recognized in amounts billable under the contract terms and provide for recovery of fixed costs and a return on investment. Wholesale revenues from sales to non-affiliates will vary depending on fuel prices, the market prices of wholesale energy compared to the cost of Georgia Power's and the Southern Company system's generation, demand for energy within the Southern Company system's electric service territory, and the availability of the Southern Company system's generation. Increases and decreases in energy revenues that are driven by fuel prices are accompanied by an increase or decrease in fuel costs and do not have a significant impact on net income. Short-term opportunity sales are made at market-based rates that generally provide a margin above Georgia Power's variable cost of energy.
Wholesale revenues from sales to affiliated companies will vary depending on demand and the availability and cost of generating resources at each company. These affiliate sales are made in accordance with the IIC, as approved by the FERC. Energy revenues related to these transactions do not have a significant impact on earnings since this energy is generally sold at marginal cost.
Other Revenues
| | | | | | | | | | | | | | | | | | | | |
| Second Quarter 2023 vs. Second Quarter 2022 | | Year-To-Date 2023 vs. Year-To-Date 2022 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $30 | | 20.1 | | $71 | | 26.1 |
In the second quarter 2023, other revenues were $179 million compared to $149 million for the corresponding period in 2022. For year-to-date 2023, other revenues were $343 million compared to $272 million for the corresponding period in 2022. The increases for the second quarter and year-to-date 2023 were primarily due to increases of $15 million and $46 million, respectively, in unregulated sales associated with power delivery construction and maintenance and outdoor lighting, net increases of $8 million and $11 million, respectively, in
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
realized gains associated with price stability products for retail customers on variable demand-driven pricing tariffs, and increases of $4 million and $7 million, respectively, in open access transmission tariff sales.
Fuel and Purchased Power Expenses
| | | | | | | | | | | | | | | | | | | | | | | |
| Second Quarter 2023 vs. Second Quarter 2022 | | Year-To-Date 2023 vs.
Year-To-Date 2022 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| Fuel | $ | (214) | | | (34.1) | | | $ | (230) | | | (22.0) | |
| Purchased power – non-affiliates | (104) | | | (42.3) | | | (130) | | | (32.8) | |
| Purchased power – affiliates | (171) | | | (52.9) | | | (171) | | | (32.3) | |
| Total fuel and purchased power expenses | $ | (489) | | | | | $ | (531) | | | |
In the second quarter 2023, total fuel and purchased power expenses were $0.7 billion compared to $1.2 billion for the corresponding period in 2022. For year-to-date 2023, total fuel and purchased power expenses were $1.4 billion compared to $2.0 billion for the corresponding period in 2022. The decreases for the second quarter and year-to-date 2023 were due to decreases of $330 million and $344 million, respectively, related to the average cost of fuel and purchased power and $159 million and $187 million, respectively, related to the volume of KWHs generated and purchased.
Fuel and purchased power energy transactions do not have a significant impact on earnings since these fuel expenses are generally offset by fuel revenues through Georgia Power's fuel cost recovery mechanism. See Note (B) to the Condensed Financial Statements herein and Note 2 to the financial statements in Item 8 of the Form 10-K under "Georgia Power – Fuel Cost Recovery" for additional information.
Details of Georgia Power's generation and purchased power were as follows:
| | | | | | | | | | | | | | | | | | | | | | | |
| Second Quarter 2023 | | Second Quarter 2022 | | Year-To-Date 2023 | | Year-To-Date 2022 |
Total generation (in billions of KWHs)(a) | 15 | | 15 | | 28 | | 30 |
Total purchased power (in billions of KWHs) | 6 | | 8 | | 14 | | 16 |
Sources of generation (percent) — | | | | | | | |
| Gas | 51 | | 45 | | 53 | | 45 |
| | | | | | | |
Nuclear(a) | 28 | | 27 | | 27 | | 25 |
| Coal | 17 | | 24 | | 16 | | 25 |
| Hydro and other | 4 | | 4 | | 4 | | 5 |
Cost of fuel, generated (in cents per net KWH) — | | | | | | | |
| Gas | 2.67 | | 5.10 | | 3.11 | | 4.34 |
| | | | | | | |
Nuclear(a) | 0.72 | | 0.76 | | 0.73 | | 0.76 |
| Coal | 6.45 | | 3.68 | | 5.92 | | 3.54 |
Average cost of fuel, generated (in cents per net KWH)(a) | 2.76 | | 3.52 | | 2.89 | | 3.18 |
Average cost of purchased power (in cents per net KWH)(b) | 4.91 | | 8.22 | | 4.70 | | 6.58 |
(a)Excludes KWHs generated from test period energy at Plant Vogtle Unit 3 prior to its in-service date. The related fuel costs are charged to CWIP in accordance with FERC guidance. See Note (B) to the Condensed Financial Statements under "Georgia Power – Nuclear Construction" herein for additional information on Plant Vogtle Units 3 and 4.
(b)Average cost of purchased power includes fuel purchased by Georgia Power for tolling agreements where power is generated by the provider.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Fuel
In the second quarter 2023, fuel expense was $414 million compared to $628 million for the corresponding period in 2022. For year-to-date 2023, fuel expense was $0.82 billion compared to $1.05 billion for the corresponding period in 2022. The decreases for the second quarter and year-to-date 2023 were primarily due to decreases of 47.6% and 28.3%, respectively, in the average cost per KWH generated by natural gas and 31.3% and 40.0%, respectively, in the volume of KWHs generated by coal, partially offset by increases of 75.3% and 67.2%, respectively, in the average cost per KWH generated by coal and 12.3% and 9.4%, respectively, in the volume of KWHs generated by natural gas.
Purchased Power – Non-Affiliates
In the second quarter 2023, purchased power expense from non-affiliates was $142 million compared to $246 million for the corresponding period in 2022. For year-to-date 2023, purchased power expense from non-affiliates was $266 million compared to $396 million for the corresponding period in 2022. The decreases for the second quarter and year-to-date 2023 were primarily due to decreases of 40.5% and 37.6%, respectively, in the volume of KWHs purchased as Georgia Power and other Southern Company system units generally dispatched at a lower cost than available market resources and 18.3% and 4.2%, respectively, in the average cost per KWH purchased primarily due to lower natural gas prices.
Energy purchases from non-affiliates will vary depending on the market prices of wholesale energy as compared to the cost of the Southern Company system's generation, demand for energy within the Southern Company system's electric service territory, and the availability of the Southern Company system's generation.
Purchased Power – Affiliates
In the second quarter 2023, purchased power expense from affiliates was $152 million compared to $323 million for the corresponding period in 2022. The decrease reflects decreases of 52.6% in the average cost per KWH purchased primarily due to lower natural gas prices and 8.0% in the volume of KWHs purchased.
For year-to-date 2023, purchased power expense from affiliates was $358 million compared to $529 million for the corresponding period in 2022. The decrease reflects a 38.6% decrease in the average cost per KWH purchased primarily due to lower natural gas prices, partially offset by a 4.0% increase in the volume of KWHs purchased.
Energy purchases from affiliates will vary depending on the demand and the availability and cost of generating resources at each company within the Southern Company system. These purchases are made in accordance with the IIC or other contractual agreements, all as approved by the FERC.
Other Operations and Maintenance Expenses
| | | | | | | | | | | | | | | | | | | | |
| Second Quarter 2023 vs. Second Quarter 2022 | | Year-To-Date 2023 vs. Year-To-Date 2022 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(77) | | (13.4) | | $(100) | | (9.2) |
In the second quarter 2023, other operations and maintenance expenses were $496 million compared to $573 million for the corresponding period in 2022. The decrease was primarily due to decreases of $45 million in storm damage recovery as authorized in the 2022 ARP, $32 million in transmission and distribution expenses primarily associated with line maintenance, $23 million in generation non-outage maintenance expense, and $13 million in certain employee compensation and benefit expenses. These decreases were partially offset by increases of $24 million in technology infrastructure and application production costs, $17 million in generation environmental projects, and $9 million from unregulated power delivery construction and maintenance and energy conservation projects.
For year-to-date 2023, other operations and maintenance expenses were $0.99 billion compared to $1.09 billion for the corresponding period in 2022. The decrease was primarily due to decreases of $91 million in storm damage
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
recovery as authorized in the 2022 ARP, $57 million in transmission and distribution expenses primarily associated with line maintenance, $49 million in generation non-outage maintenance expense, and $18 million in certain employee compensation and benefit expenses. These decreases were partially offset by increases of $48 million in technology infrastructure and application production costs, $29 million from unregulated power delivery construction and maintenance and energy conservation projects, and $26 million in generation environmental projects and planned outages, as well as a $12 million decrease in nuclear property insurance refunds.
See Note 2 to the financial statements under "Georgia Power – Storm Damage Recovery" in Item 8 of the Form 10-K for additional information.
Depreciation and Amortization
| | | | | | | | | | | | | | | | | | | | |
| Second Quarter 2023 vs. Second Quarter 2022 | | Year-To-Date 2023 vs. Year-To-Date 2022 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $55 | | 15.4 | | $113 | | 16.0 |
In the second quarter 2023, depreciation and amortization was $411 million compared to $356 million for the corresponding period in 2022. For year-to-date 2023, depreciation and amortization was $819 million compared to $706 million for the corresponding period in 2022. The increases for the second quarter and year-to-date 2023 were primarily due to increases of $47 million and $94 million, respectively, resulting from higher depreciation rates as authorized in the 2022 ARP and $15 million and $30 million, respectively, associated with additional plant in service. Partially offsetting these increases for the second quarter and year-to-date 2023 were decreases of $5 million and $7 million, respectively, in amortization of regulatory assets related to CCR AROs under the terms of the 2022 ARP and $4 million and $7 million, respectively, in amortization of regulatory assets related to the retirement of certain generating units that ended in 2022.
See Note 5 to the financial statements under "Depreciation and Amortization" in Item 8 of the Form 10-K for additional information.
Taxes Other Than Income Taxes
| | | | | | | | | | | | | | | | | | | | |
| Second Quarter 2023 vs. Second Quarter 2022 | | Year-To-Date 2023 vs. Year-To-Date 2022 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(9) | | (6.4) | | $(2) | | (0.8) |
In the second quarter 2023, taxes other than income taxes were $132 million compared to $141 million for the corresponding period in 2022. For year-to-date 2023, taxes other than income taxes were $263 million compared to $265 million for the corresponding period in 2022. The decreases for the second quarter and year-to-date 2023 were due to decreases of $17 million in municipal franchise fees resulting from lower retail revenues and $3 million and $4 million, respectively, in payroll taxes, largely offset by increases of $11 million and $19 million, respectively, in property taxes primarily resulting from an increase in the assessed value of property.
Estimated Loss on Plant Vogtle Units 3 and 4
| | | | | | | | | | | | | | | | | | | | |
| Second Quarter 2023 vs. Second Quarter 2022 | | Year-To-Date 2023 vs. Year-To-Date 2022 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(52) | | (100.0) | | $(52) | | (100.0) |
In the second quarter 2022, Georgia Power recorded an estimated probable loss on Plant Vogtle Units 3 and 4 of $52 million. The loss reflected revisions to the total project capital cost forecast to complete construction and start-up of Plant Vogtle Units 3 and 4. See Note (B) to the Condensed Financial Statements herein and Note 2 to the financial statements in Item 8 of the Form 10-K under "Georgia Power – Nuclear Construction" for additional information.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Allowance for Equity Funds Used During Construction
| | | | | | | | | | | | | | | | | | | | |
| Second Quarter 2023 vs. Second Quarter 2022 | | Year-To-Date 2023 vs. Year-To-Date 2022 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $10 | | 30.3 | | $18 | | 27.7 |
In the second quarter 2023, allowance for equity funds used during construction was $43 million compared to $33 million for the corresponding period in 2022. For year-to-date 2023, allowance for equity funds used during construction was $83 million compared to $65 million for the corresponding period in 2022. The increases were primarily due to an increase in capital expenditures subject to AFUDC.
Interest Expense, Net of Amounts Capitalized
| | | | | | | | | | | | | | | | | | | | |
| Second Quarter 2023 vs. Second Quarter 2022 | | Year-To-Date 2023 vs. Year-To-Date 2022 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $43 | | 36.8 | | $82 | | 36.6 |
In the second quarter 2023, interest expense, net of amounts capitalized was $160 million compared to $117 million for the corresponding period in 2022. For year-to-date 2023, interest expense, net of amounts capitalized was $306 million compared to $224 million for the corresponding period in 2022. The increases for the second quarter and year-to-date 2023 were primarily associated with increases of approximately $23 million and $44 million, respectively, related to higher average outstanding borrowings and $20 million and $39 million, respectively, related to higher interest rates. See FINANCIAL CONDITION AND LIQUIDITY – "Sources of Capital" and "Financing Activities" herein for additional information on borrowings.
Other Income (Expense), Net
| | | | | | | | | | | | | | | | | | | | |
| Second Quarter 2023 vs. Second Quarter 2022 | | Year-To-Date 2023 vs. Year-To-Date 2022 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(18) | | (33.3) | | $(23) | | (22.3) |
In the second quarter 2023, other income (expense), net was $36 million compared to $54 million for the corresponding period in 2022. For year-to-date 2023, other income (expense), net was $80 million compared to $103 million for the corresponding period in 2022. The decreases for the second quarter and year-to-date 2023 were primarily due to decreases of $7 million and $13 million, respectively, in customer charges related to contributions in aid of construction and a $7 million charge in the second quarter 2023 under a stipulation agreement approved by the Georgia PSC related to Georgia Power's fuel cost recovery case.
See Note (B) to the Condensed Financial Statements herein under "Georgia Power – Fuel Cost Recovery" for additional information.
Income Taxes
| | | | | | | | | | | | | | | | | | | | |
| Second Quarter 2023 vs. Second Quarter 2022 | | Year-To-Date 2023 vs. Year-To-Date 2022 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(72) | | (43.9) | | $(50) | | (25.8) |
In the second quarter 2023, income taxes were $92 million compared to $164 million for the corresponding period in 2022. For year-to-date 2023, income taxes were $144 million compared to $194 million for the corresponding period in 2022. The decreases were primarily due to lower pre-tax earnings, an adjustment in the second quarter 2022 related to a prior year state tax credit carryforward, and a decrease in a valuation allowance on certain state tax credit carryforwards in 2023, partially offset by the flowback of certain excess deferred income taxes that ended in 2022.
See Note (G) to the Condensed Financial Statements herein for additional information.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Mississippi Power
Net Income
| | | | | | | | | | | | | | | | | | | | |
| Second Quarter 2023 vs. Second Quarter 2022 | | Year-To-Date 2023 vs. Year-To-Date 2022 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(5) | | (11.1) | | $11 | | 12.6 |
Mississippi Power's net income for the second quarter 2023 was $40 million compared to $45 million for the corresponding period in 2022. The decrease was primarily due to a decrease in revenues due to milder weather in the second quarter 2023 compared to the corresponding period in 2022 and changes in power supply agreements.
Mississippi Power's net income for year-to-date 2023 was $98 million compared to $87 million for the corresponding period in 2022. The increase was primarily due to an increase in affiliate wholesale capacity revenues, partially offset by a decrease in revenues due to milder weather in 2023 compared to the corresponding period in 2022 and an increase in interest expense.
Retail Revenues
In the second quarter 2023, retail revenues were $227 million compared to $252 million for the corresponding period in 2022. For year-to-date 2023, retail revenues were $464 million compared to $469 million for the corresponding period in 2022. Details of the changes in retail revenues were as follows:
| | | | | | | | | | | | | | | | | | | | | | | |
| | Second Quarter 2023 vs. Second Quarter 2022 | | Year-To-Date 2023 vs. Year-To-Date 2022 |
| | (change in millions) | | (% change) | | (change in millions) | | (% change) |
| Rates and pricing | $ | (3) | | | (1.2) | % | | $ | 2 | | | 0.4 | % |
| Sales growth | — | | | — | | | 2 | | | 0.4 | |
| Weather | (4) | | | (1.6) | | | (10) | | | (2.1) | |
| Fuel and other cost recovery | (18) | | | (7.1) | | | 1 | | | 0.2 | |
| Retail revenues | $ | (25) | | | (9.9) | % | | $ | (5) | | | (1.1) | % |
Revenues associated with changes in rates and pricing decreased in the second quarter 2023 and increased year-to-date 2023 when compared to the corresponding periods in 2022. The second quarter 2023 decrease was primarily due to the expiration of a PEP surcharge at the end of 2022 that became effective for the first billing cycle of April 2022. The year-to-date 2023 increase was primarily due to ECO Plan rates that became effective in May 2022. See Note 2 to the financial statements under "Mississippi Power – Performance Evaluation Plan" and " – Environmental Compliance Overview Plan" in Item 8 of the Form 10-K for additional information.
Revenues attributable to changes in sales were relatively flat in the second quarter and year-to-date 2023 when compared to the corresponding periods in 2022. Weather-adjusted residential KWH sales increased 0.1% in the second quarter 2023 when compared to the corresponding period in 2022 due to an increase in customer usage. Weather-adjusted residential KWH sales decreased 1.0% year-to-date 2023 when compared to the corresponding period in 2022 due to a decrease in customer usage. Weather-adjusted commercial KWH sales increased 2.7% and 2.9% in the second quarter and year-to-date 2023, respectively, when compared to the corresponding periods in 2022 due to an increase in customer usage. Industrial KWH sales decreased 2.1% in the second quarter 2023 when compared to the corresponding period in 2022 primarily due to decreases in the chemicals, petroleum, and lumber sectors, partially offset by increases in the non-manufacturing sector. Industrial KWH sales increased 1.4% year-to-date 2023 when compared to the corresponding period in 2022 primarily due to increases in the non-manufacturing, petroleum, and pipeline sectors, partially offset by decreases in the chemicals sector.
Fuel and other cost recovery revenues decreased in the second quarter 2023 when compared to the corresponding period in 2022 primarily as a result of lower recoverable fuel costs. Recoverable fuel costs include fuel and
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
purchased power expenses reduced by the fuel and emissions portion of wholesale revenues from energy sold to customers outside Mississippi Power's service territory. Electric rates include provisions to adjust billings for fluctuations in fuel costs, including the energy component of purchased power costs. Under these provisions, fuel revenues generally equal fuel expenses, including the energy component of purchased power costs, and do not affect net income. See Note 2 to the financial statements in Item 8 of the Form 10-K for additional information.
Wholesale Revenues – Non-Affiliates
| | | | | | | | | | | | | | | | | | | | |
| Second Quarter 2023 vs. Second Quarter 2022 | | Year-To-Date 2023 vs. Year-To-Date 2022 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(7) | | (11.1) | | $(7) | | (5.3) |
In the second quarter 2023, wholesale revenues from sales to non-affiliates were $56 million compared to $63 million for the corresponding period in 2022. For year-to-date 2023, wholesale revenues from sales to non-affiliates were $124 million compared to $131 million for the corresponding period in 2022. The decreases were primarily due to a decrease in revenue from MRA customers primarily due to the lower cost of natural gas and changes in power supply agreements, partially offset by higher opportunity sales.
Wholesale revenues from sales to non-affiliates will vary depending on fuel prices, the market prices of wholesale energy compared to the cost of Mississippi Power's and the Southern Company system's generation, demand for energy within the Southern Company system's electric service territory, and the availability of the Southern Company system's generation. Increases and decreases in energy revenues that are driven by fuel prices are accompanied by an increase or decrease in fuel costs and do not have a significant impact on net income. In addition, Mississippi Power provides service under long-term contracts with rural electric cooperative associations and municipalities located in southeastern Mississippi under cost-based electric tariffs which are subject to regulation by the FERC. See Note 2 to the financial statements under "Mississippi Power" in Item 8 of the Form 10-K for additional information. See Note (B) to the Condensed Financial Statements under "Mississippi Power – Municipal and Rural Associations Tariff" herein for additional information.
Wholesale Revenues – Affiliates
| | | | | | | | | | | | | | | | | | | | |
| Second Quarter 2023 vs. Second Quarter 2022 | | Year-To-Date 2023 vs. Year-To-Date 2022 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(89) | | (83.2) | | $(56) | | (37.6) |
In the second quarter 2023, wholesale revenues from sales to affiliates were $18 million compared to $107 million for the corresponding period in 2022. The decrease was primarily due to a $44 million decrease associated with lower natural gas prices and a $44 million decrease associated with lower KWH sales.
For year-to-date 2023, wholesale revenues from sales to affiliates were $93 million compared to $149 million for the corresponding period in 2022. The decrease was due to an $81 million decrease associated with lower natural gas prices and a $4 million decrease associated with lower KWH sales, partially offset by a $29 million increase in capacity revenues resulting from an increase in pricing and volume of generation reserves.
Wholesale revenues from sales to affiliated companies will vary depending on demand and the availability and cost of generating resources at each company. These affiliate sales are made in accordance with the IIC, as approved by the FERC. Energy revenues related to these transactions do not have a significant impact on earnings since this energy is generally sold at marginal cost.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Fuel and Purchased Power Expenses
| | | | | | | | | | | | | | | | | | | | | | | |
| Second Quarter 2023 vs. Second Quarter 2022 | | Year-To-Date 2023 vs.
Year-To-Date 2022 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| Fuel | $ | (107) | | | (54.6) | | $ | (87) | | | (27.0) |
| Purchased power | (4) | | | (36.4) | | (6) | | | (35.3) |
| Total fuel and purchased power expenses | $ | (111) | | | | | $ | (93) | | | |
In the second quarter 2023, total fuel and purchased power expenses were $96 million compared to $207 million for the corresponding period in 2022. The decrease was primarily due to an $86 million decrease related to the average cost of fuel and purchased power and a $25 million decrease related to the volume of KWHs generated.
For year-to-date 2023, total fuel and purchased power expenses were $246 million compared to $339 million for the corresponding period in 2022. The decrease was primarily due to an $85 million decrease related to the average cost of fuel and purchased power and an $8 million decrease related to the volume of KWHs generated.
Fuel and purchased power energy transactions do not have a significant impact on earnings since energy expenses are generally offset by energy revenues through Mississippi Power's fuel cost recovery clause.
Details of Mississippi Power's generation and purchased power were as follows:
| | | | | | | | | | | | | | | | | | | | | | | |
| Second Quarter 2023 | | Second Quarter 2022 | | Year-To-Date 2023 | | Year-To-Date 2022 |
Total generation (in millions of KWHs) | 3,897 | | 4,483 | | 8,340 | | 8,557 |
Total purchased power (in millions of KWHs) | 174 | | 166 | | 274 | | 286 |
Sources of generation (percent) – | | | | | | | |
| Gas | 97 | | 88 | | 95 | | 90 |
| Coal | 3 | | 12 | | 5 | | 10 |
Cost of fuel, generated (in cents per net KWH) – | | | | | | | |
| Gas | 2.31 | | 4.73 | | 2.85 | | 4.04 |
| Coal | 6.31 | | 3.95 | | 5.94 | | 3.86 |
Average cost of fuel, generated (in cents per net KWH) | 2.44 | | 4.63 | | 3.01 | | 4.02 |
Average cost of purchased power (in cents per net KWH) | 4.07 | | 6.57 | | 4.08 | | 5.72 |
Fuel
In the second quarter 2023, fuel expense was $89 million compared to $196 million for the corresponding period in 2022. The decrease was due to a 78.3% decrease in the volume of KWHs generated by coal, a 51.2% decrease in the average cost of natural gas per KWH generated, and a 5.0% decrease in the volume of KWHs generated by natural gas, partially offset by a 59.7% increase in the average cost of coal per KWH generated.
For year-to-date 2023, fuel expense was $235 million compared to $322 million for the corresponding period in 2022. The decrease was due to a 55.0% decrease in the volume of KWHs generated by coal and a 29.5% decrease in the average cost of natural gas per KWH generated, partially offset by a 53.9% increase in the average cost of coal per KWH generated and a 4.0% increase in the volume of KWHs generated by natural gas.
Purchased Power
In the second quarter 2023, purchased power expense was $7 million compared to $11 million for the corresponding period in 2022. The decrease was due to a 38.1% decrease in the average cost per KWH purchased primarily due to lower natural gas prices, partially offset by a 5.1% increase in the volume of KWHs purchased.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
For year-to-date 2023, purchased power expense was $11 million compared to $17 million for the corresponding period in 2022. The decrease was due to a 28.7% decrease in the average cost per KWH purchased primarily due to lower natural gas prices and a 4.1% decrease in the volume of KWHs purchased.
Other Operations and Maintenance Expenses
| | | | | | | | | | | | | | | | | | | | |
| Second Quarter 2023 vs. Second Quarter 2022 | | Year-To-Date 2023 vs. Year-To-Date 2022 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $— | | — | | $8 | | 4.8 |
For year-to-date 2023, other operations and maintenance expenses were $175 million compared to $167 million for the corresponding period in 2022. The increase was primarily due to increases of $4 million in generation expenses, $3 million in storm reserve accruals, and $2 million associated with the Kemper County energy facility (primarily related to lower salvage proceeds in 2023), partially offset by a decrease of $3 million in distribution lines and substation expenses. See Notes 2 and 3 to the financial statements under "Mississippi Power – System Restoration Rider" and "Other Matters – Mississippi Power," respectively, in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Mississippi Power – System Restoration Rider" herein for additional information.
Taxes Other Than Income Taxes
| | | | | | | | | | | | | | | | | | | | |
| Second Quarter 2023 vs. Second Quarter 2022 | | Year-To-Date 2023 vs. Year-To-Date 2022 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(4) | | (12.5) | | $(1) | | (1.6) |
In the second quarter 2023, taxes other than income taxes were $28 million compared to $32 million for the corresponding period in 2022. For year-to-date 2023, taxes other than income taxes were $60 million compared to $61 million for the corresponding period in 2022. The decreases primarily reflect a decrease in ad valorem taxes due to lower assessed values.
Interest Expense, Net of Amounts Capitalized
| | | | | | | | | | | | | | | | | | | | |
| Second Quarter 2023 vs. Second Quarter 2022 | | Year-To-Date 2023 vs. Year-To-Date 2022 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $4 | | 28.6 | | $7 | | 25.9 |
In the second quarter 2023, interest expense, net of amounts capitalized was $18 million compared to $14 million for the corresponding period in 2022. For year-to-date 2023, interest expense, net of amounts capitalized was $34 million compared to $27 million for the corresponding period in 2022. The increases for the second quarter and year-to-date 2023 were associated with increases of approximately $3 million and $5 million, respectively, related to higher interest rates and $1 million and $2 million, respectively, related to higher average outstanding borrowings. See FINANCIAL CONDITION AND LIQUIDITY – "Sources of Capital" and "Financing Activities" herein for additional information on borrowings.
Income Taxes
| | | | | | | | | | | | | | | | | | | | |
| Second Quarter 2023 vs. Second Quarter 2022 | | Year-To-Date 2023 vs. Year-To-Date 2022 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(8) | | (66.7) | | $(3) | | (15.0) |
In the second quarter 2023, income taxes were $4 million compared to $12 million for the corresponding period in 2022. The decrease was primarily due to lower pre-tax earnings and the flowback of certain excess deferred income taxes.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
For year-to-date 2023, income taxes were $17 million compared to $20 million for the corresponding period in 2022. The decrease was primarily due the flowback of certain excess deferred income taxes, partially offset by higher pre-tax earnings.
See Note (G) to the Condensed Financial Statements herein for additional information.
Southern Power
Net Income Attributable to Southern Power
| | | | | | | | | | | | | | | | | | | | |
| Second Quarter 2023 vs. Second Quarter 2022 | | Year-To-Date 2023 vs. Year-To-Date 2022 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(13) | | (13.3) | | $17 | | 10.0 |
Net income attributable to Southern Power in the second quarter 2023 was $85 million compared to $98 million for the corresponding period in 2022. The decrease was primarily due to lower revenues driven by lower market prices of energy, as well as lower HLBV income associated with tax equity partnerships. These decreases were partially offset by a tax benefit related to changes in state apportionment methodology due to tax legislation enacted by the State of Tennessee and insurance proceeds received for damaged generation equipment.
Net income attributable to Southern Power for year-to-date 2023 was $187 million compared to $170 million for the corresponding period in 2022. The increase was primarily due to a gain on the sale of spare parts and higher HLBV income associated with tax equity partnerships, as well as changes in state apportionment methodology related to tax legislation enacted by the State of Tennessee and receipts of liquidated damages associated with generation facility production guarantees. These increases were partially offset by lower revenues driven by lower market prices of energy.
Operating Revenues
| | | | | | | | | | | | | | | | | | | | |
| Second Quarter 2023 vs. Second Quarter 2022 | | Year-To-Date 2023 vs. Year-To-Date 2022 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(374) | | (41.6) | | $(405) | | (28.2) |
Total operating revenues include PPA capacity revenues, which are derived primarily from long-term contracts involving natural gas facilities, and PPA energy revenues from Southern Power's generation facilities. To the extent Southern Power has capacity not contracted under a PPA, it may sell power into an accessible wholesale market, or, to the extent those generation assets are part of the FERC-approved IIC, it may sell power into the Southern Company power pool.
Natural Gas Capacity and Energy Revenue
Capacity revenues generally represent the greatest contribution to operating income and are designed to provide recovery of fixed costs plus a return on investment.
Energy is generally sold at variable cost or is indexed to published natural gas indices. Energy revenues will vary depending on the energy demand of Southern Power's customers and their generation capacity, as well as the market prices of wholesale energy compared to the cost of Southern Power's energy. Energy revenues also include fees for support services, fuel storage, and unit start charges. Increases and decreases in energy revenues under PPAs that are driven by fuel or purchased power prices are accompanied by an increase or decrease in fuel and purchased power costs and do not have a significant impact on net income.
Solar and Wind Energy Revenue
Southern Power's energy sales from solar and wind generating facilities are predominantly through long-term PPAs that do not have capacity revenue. Customers either purchase the energy output of a dedicated renewable facility
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
through an energy charge or pay a fixed price related to the energy generated from the respective facility and sold to the grid. As a result, Southern Power's ability to recover fixed and variable operations and maintenance expenses is dependent upon the level of energy generated from these facilities, which can be impacted by weather conditions, equipment performance, transmission constraints, and other factors.
See FUTURE EARNINGS POTENTIAL – "Southern Power's Power Sales Agreements" in Item 7 of the Form 10-K for additional information regarding Southern Power's PPAs.
Operating Revenues Details
Details of Southern Power's operating revenues were as follows:
| | | | | | | | | | | | | | | | | | | | | | | |
| Second Quarter 2023 | | Second Quarter 2022 | | Year-To-Date 2023 | | Year-To-Date 2022 |
| (in millions) |
| PPA capacity revenues | $ | 114 | | | $ | 109 | | | $ | 227 | | | $ | 214 | |
| PPA energy revenues | 307 | | | 579 | | | 583 | | | 921 | |
| Total PPA revenues | 421 | | | 688 | | | 810 | | | 1,135 | |
| Non-PPA revenues | 88 | | | 202 | | | 196 | | | 286 | |
| Other revenues | 16 | | | 9 | | | 27 | | | 17 | |
| Total operating revenues | $ | 525 | | | $ | 899 | | | $ | 1,033 | | | $ | 1,438 | |
In the second quarter 2023, total operating revenues were $525 million, reflecting a $374 million, or 41.6%, decrease from the corresponding period in 2022. The change in operating revenues was primarily due to the following:
•PPA capacity revenues increased $5 million, or 4.6%, primarily due to a net increase in MW capacity under contract from natural gas PPAs and an increase associated with a change in rates from natural gas PPAs.
•PPA energy revenues decreased $272 million, or 47.0%, primarily due to a $267 million decrease in sales under natural gas PPAs resulting from a $209 million decrease in the price of fuel and purchased power and a $58 million decrease in the volume of KWHs sold.
•Non-PPA revenues decreased $114 million, or 56.4%, primarily due to a $183 million decrease in the market price of energy, partially offset by a $68 million increase in the volume of KWHs sold through short-term sales.
•Other revenues increased $7 million, or 77.8%, primarily due to receipts of liquidated damages associated with generation facility production guarantees and business interruption insurance proceeds received for damaged generation equipment.
For year-to-date 2023, total operating revenues were $1.0 billion, reflecting a $405 million, or 28.2%, decrease from the corresponding period in 2022. The change in operating revenues was primarily due to the following:
•PPA capacity revenues increased $13 million, or 6.1%, primarily due to a net increase in MW capacity under contract from natural gas PPAs and an increase associated with a change in rates from natural gas PPAs.
•PPA energy revenues decreased $338 million, or 36.7%, primarily due to a $328 million decrease in sales under natural gas PPAs resulting from a $269 million decrease in the price of fuel and purchased power and a $59 million decrease in the volume of KWHs sold.
•Non-PPA revenues decreased $90 million, or 31.5%, primarily due to a $244 million decrease in the market price of energy, largely offset by a $152 million increase in the volume of KWHs sold through short-term sales.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
•Other revenues increased $10 million, or 58.8%, primarily due to receipts of liquidated damages associated with generation facility production guarantees and business interruption insurance proceeds for damaged generation equipment.
Fuel and Purchased Power Expenses
Details of Southern Power's generation and purchased power were as follows:
| | | | | | | | | | | | | | | | | |
| | Second Quarter 2023 | Second Quarter 2022 | | Year-To-Date 2023 | Year-To-Date 2022 |
| (in billions of KWHs) |
| Generation | 11.7 | 12.8 | | 24.0 | 23.9 |
| Purchased power | 0.9 | 0.7 | | 1.6 | 1.1 |
| Total generation and purchased power | 12.6 | 13.5 | | 25.6 | 25.0 |
| | | | | |
Total generation and purchased power (excluding solar, wind, fuel cells, and tolling agreements) | 7.8 | 7.5 | | 16.2 | 14.4 |
Southern Power's PPAs for natural gas generation generally provide that the purchasers are responsible for either procuring the fuel (tolling agreements) or reimbursing Southern Power for substantially all of the cost of fuel relating to the energy delivered under such PPAs. Consequently, changes in such fuel costs are generally accompanied by a corresponding change in related fuel revenues and do not have a significant impact on net income. Southern Power is responsible for the cost of fuel for generating units that are not covered under PPAs. Power from these generating units is sold into the wholesale market or into the Southern Company power pool for capacity owned directly by Southern Power.
Purchased power expenses will vary depending on demand, availability, and the cost of generating resources throughout the Southern Company system and other contract resources. Load requirements are submitted to the Southern Company power pool on an hourly basis and are fulfilled with the lowest cost alternative, whether that is generation owned by Southern Power, an affiliate company, or external parties. Such purchased power costs are generally recovered through PPA revenues.
Details of Southern Power's fuel and purchased power expenses were as follows:
| | | | | | | | | | | | | | | | | | | | | | | |
| | Second Quarter 2023 vs. Second Quarter 2022 | | Year-To-Date 2023 vs.
Year-To-Date 2022 |
| | (change in millions) | | (% change) | | (change in millions) | | (% change) |
| Fuel | $ | (298) | | | (68.2) | | $ | (339) | | | (50.7) |
| Purchased power | (40) | | | (58.8) | | (35) | | | (39.3) |
| Total fuel and purchased power expenses | $ | (338) | | | | | $ | (374) | | | |
In the second quarter 2023, total fuel and purchased power expenses decreased $338 million, or 66.9%, compared to the corresponding period in 2022. Fuel expense decreased $298 million due to a $303 million decrease associated with the average cost of fuel, partially offset by a $4 million increase associated with the volume of KWHs generated. Purchased power expense decreased $40 million due to a $62 million decrease associated with the average cost of purchased power, partially offset by a $23 million increase associated with the volume of KWHs purchased.
For year-to-date 2023, total fuel and purchased power expenses decreased $374 million, or 49.3%, compared to the corresponding period in 2022. Fuel expense decreased $339 million due to a $403 million decrease associated with the average cost of fuel, partially offset by a $64 million increase associated with the volume of KWHs generated. Purchased power expense decreased $35 million due to a $72 million decrease associated with the average cost of purchased power, partially offset by a $37 million increase associated with the volume of KWHs purchased.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Depreciation and Amortization
| | | | | | | | | | | | | | | | | | | | |
| Second Quarter 2023 vs. Second Quarter 2022 | | Year-To-Date 2023 vs. Year-To-Date 2022 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(9) | | (6.9) | | $(1) | | (0.4) |
In the second quarter 2023, depreciation and amortization was $122 million compared to $131 million for the corresponding period in 2022. The decrease was primarily due to a decrease in units-of-production depreciation related to lower production from natural gas generating facilities and insurance proceeds received for damaged generation equipment, partially offset by an increase in depreciation related to capital improvements at natural gas generating facilities.
Gain on Dispositions, Net
| | | | | | | | | | | | | | | | | | | | |
| Second Quarter 2023 vs. Second Quarter 2022 | | Year-To-Date 2023 vs. Year-To-Date 2022 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $— | | — | | $18 | | N/M |
For year-to-date 2023, gain on dispositions, net was $20 million compared to $2 million for the corresponding period in 2022. The increase was primarily due to a $16 million gain on the sale of spare parts in 2023.
Interest Expense, Net of Amounts Capitalized
| | | | | | | | | | | | | | | | | | | | |
| Second Quarter 2023 vs. Second Quarter 2022 | | Year-To-Date 2023 vs. Year-To-Date 2022 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(3) | | (8.3) | | $(7) | | (9.6) |
In the second quarter 2023, interest expense, net of amounts capitalized was $33 million compared to $36 million for the corresponding period in 2022. For year-to-date 2023, interest expense, net of amounts capitalized was $66 million compared to $73 million for the corresponding period in 2022. The decreases were primarily due to lower average outstanding borrowings.
Income Taxes (Benefit)
| | | | | | | | | | | | | | | | | | | | |
| Second Quarter 2023 vs. Second Quarter 2022 | | Year-To-Date 2023 vs. Year-To-Date 2022 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(19) | | (76.0) | | $(14) | | (107.7) |
In the second quarter 2023, income tax expense was $6 million compared to $25 million for the corresponding period in 2022. For year-to-date 2023, income tax benefit was $1 million compared to income tax expense of $13 million for the corresponding period in 2022. These changes were primarily due to lower pre-tax earnings and a change in state apportionment methodology resulting from tax legislation enacted by the state of Tennessee in the second quarter 2023. See Note (G) to the Condensed Financial Statements herein for additional information.
Net Loss Attributable to Noncontrolling Interests
| | | | | | | | | | | | | | | | | | | | |
| Second Quarter 2023 vs. Second Quarter 2022 | | Year-To-Date 2023 vs. Year-To-Date 2022 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $7 | | 31.8 | | $(11) | | (16.4) |
In the second quarter 2023, net loss attributable to noncontrolling interests was $15 million compared to $22 million for the corresponding period in 2022. The decreased loss was primarily due to $7 million in lower HLBV loss allocations to wind tax equity partners and $6 million in lower loss allocations to battery energy storage partners, partially offset by $5 million in lower income allocations to equity partners.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
For year-to-date 2023, net loss attributable to noncontrolling interests was $78 million compared to $67 million for the corresponding period in 2022. The increased loss was primarily due to $15 million in lower income allocations to equity partners and $9 million in higher HLBV loss allocations to wind tax equity partners, partially offset by $14 million in lower loss allocations to battery energy storage partners.
Southern Company Gas
Operating Metrics
Southern Company Gas continues to focus on several operating metrics, including Heating Degree Days, customer count, and volumes of natural gas sold.
Southern Company Gas measures weather and the effect on its business using Heating Degree Days. Generally, increased Heating Degree Days result in higher demand for natural gas on Southern Company Gas' distribution system. Southern Company Gas has various regulatory mechanisms, such as weather and revenue normalization and straight-fixed-variable rate design, which limit its exposure to weather changes within typical ranges in each of its utility's respective service territory. Southern Company Gas also utilizes weather hedges to limit the negative income impacts in the event of warmer-than-normal weather.
The number of customers served by gas distribution operations and gas marketing services can be impacted by natural gas prices, economic conditions, and competition from alternative fuels. Gas distribution operations and gas marketing services' customers are primarily located in Georgia and Illinois.
Southern Company Gas' natural gas volume metrics for gas distribution operations and gas marketing services illustrate the effects of weather and customer demand for natural gas.
Seasonality of Results
During the Heating Season, natural gas usage and operating revenues are generally higher as more customers are connected to the gas distribution systems and natural gas usage is higher in periods of colder weather. Southern Company Gas' base operating expenses, excluding cost of natural gas, bad debt expense, and certain incentive compensation costs, are incurred relatively evenly throughout the year. Seasonality also affects the comparison of certain balance sheet items across quarters, including receivables, unbilled revenues, natural gas for sale, and notes payable. However, these items are comparable when reviewing Southern Company Gas' annual results. Thus, Southern Company Gas' operating results for the interim periods presented are not necessarily indicative of annual results and can vary significantly from quarter to quarter.
Net Income
| | | | | | | | | | | | | | | | | | | | |
| Second Quarter 2023 vs. Second Quarter 2022 | | Year-To-Date 2023 vs. Year-To-Date 2022 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(30) | | (26.1) | | $(40) | | (9.2) |
In the second quarter 2023, net income was $85 million compared to $115 million for the corresponding period in 2022. For year-to-date 2023, net income was $393 million compared to $433 million for the corresponding period in 2022. The decreases were primarily due to lower net income at gas distribution operations primarily as a result of a $28 million loss related to a regulatory disallowance at Nicor Gas. The year-to-date 2023 decrease also included an $11 million decrease in net income at gas marketing services primarily related to hedge losses. See Note (B) to the Condensed Financial Statements under "Southern Company Gas – Infrastructure Replacement Programs and Capital Projects" herein for additional information.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Natural Gas Revenues
In the second quarter 2023, natural gas revenues were $0.9 billion compared to $1.1 billion for the corresponding period in 2022. For year-to-date 2023, natural gas revenues were $2.7 billion compared to $3.1 billion for the corresponding period in 2022. Details of the changes in natural gas revenues were as follows:
| | | | | | | | | | | | | | | | | | | | | | | |
| Second Quarter 2023 vs. Second Quarter 2022 | | Year-To-Date 2023 vs. Year-To-Date 2022 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| | | | | | | |
| | | | | | | |
| Infrastructure replacement programs and rate changes | $ | 38 | | | 3.5 | % | | $ | 88 | | | 2.8 | % |
| Gas costs and other cost recovery | (265) | | | (24.4) | | | (464) | | | (14.8) | |
| Gas marketing services | (1) | | | (0.1) | | | (22) | | | (0.7) | |
| | | | | | | |
| Other | (3) | | | (0.3) | | | (14) | | | (0.4) | |
| Natural gas revenues | $ | (231) | | | (21.3) | % | | $ | (412) | | | (13.1) | % |
Revenues from infrastructure replacement programs and rate changes increased in the second quarter and year-to-date 2023 compared to the corresponding periods in 2022 primarily due to rate increases at the natural gas distribution utilities and continued investment in infrastructure replacement, partially offset by a regulatory disallowance at Nicor Gas. See Note 2 to the financial statements under "Southern Company Gas – Rate Proceedings" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Southern Company Gas – Infrastructure Replacement Programs and Capital Projects" herein for additional information.
Revenues from gas costs and other cost recovery decreased in the second quarter and year-to-date 2023 compared to the corresponding periods in 2022 primarily due to lower natural gas cost recovery associated with the timing of natural gas purchases and the recovery of those costs from customers. See "Cost of Natural Gas" herein for additional information. Revenue impacts from weather and customer growth are described further below.
Revenues from gas marketing services decreased in the second quarter and year-to-date 2023 compared to the corresponding periods in 2022 primarily due to lower natural gas prices and the timing of unrealized hedge losses, partially offset by higher variable price spreads in Georgia and Illinois and higher customer count in Georgia.
Southern Company Gas' natural gas distribution utilities have various regulatory mechanisms that limit their exposure to weather changes. Southern Company Gas also uses hedges for the majority of any remaining exposure to warmer-than-normal weather in Illinois for gas distribution operations and in Illinois and Georgia for gas marketing services; therefore, weather typically does not have a significant net income impact. The following table presents Heating Degree Days information for Illinois and Georgia, the primary locations where Southern Company Gas' operations are impacted by weather.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Second Quarter | | Year-to-Date |
| | | 2023 vs. normal | 2023 vs. 2022 | | | | 2023 vs. normal | 2023 vs. 2022 |
| Normal(*) | 2023 | 2022 | | warmer | colder (warmer) | | Normal(*) | 2023 | 2022 | | warmer | warmer |
| (in thousands) | | | | | (in thousands) | | | |
| Illinois | 651 | | 538 | | 620 | | | (17.4) | % | (13.2) | % | | 3,715 | | 3,198 | | 3,627 | | | (13.9) | % | (11.8) | % |
| Georgia | 129 | | 121 | | 110 | | | (6.2) | % | 10.0 | % | | 1,458 | | 1,029 | | 1,361 | | | (29.4) | % | (24.4) | % |
(*)Normal represents the 10-year average from January 1, 2013 through June 30, 2022 for Illinois at Chicago Midway International Airport and for Georgia at Atlanta Hartsfield-Jackson International Airport, based on information obtained from the National Oceanic and Atmospheric Administration, National Climatic Data Center.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
The following table provides the number of customers served by Southern Company Gas at June 30, 2023 and 2022:
| | | | | | | | | | | | | | | | | |
| June 30, | | |
| 2023 | | 2022 | | 2023 vs. 2022 |
| (in thousands, except market share %) | | (% change) |
| Gas distribution operations | 4,337 | | | 4,314 | | | 0.5 | % |
| Gas marketing services | | | | | |
Energy customers(*) | 665 | | | 610 | | | 9.0 | % |
| Market share of energy customers in Georgia | 30.0 | % | | 28.6 | % | | |
| | | | | |
| | | | | |
(*)Gas marketing services' customers are primarily located in Georgia and Illinois.
Southern Company Gas anticipates customer growth and uses a variety of targeted marketing programs to attract new customers and to retain existing customers.
Cost of Natural Gas
| | | | | | | | | | | | | | | | | | | | |
| Second Quarter 2023 vs. Second Quarter 2022 | | Year-To-Date 2023 vs. Year-To-Date 2022 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(253) | | (56.0) | | $(449) | | (29.0) |
Excluding Atlanta Gas Light, which does not sell natural gas to end-use customers, natural gas distribution rates include provisions to adjust billings for fluctuations in natural gas costs. Therefore, gas costs recovered through natural gas revenues generally equal the amount expensed in cost of natural gas and do not affect net income from gas distribution operations. Cost of natural gas at gas distribution operations represented 84% and 85% of the total cost of natural gas in the second quarter and year-to-date 2023, respectively. See MANAGEMENT'S DISCUSSION AND ANALYSIS – RESULTS OF OPERATIONS – "Southern Company Gas – Cost of Natural Gas" in Item 7 of the Form 10-K and "Natural Gas Revenues" herein for additional information.
In the second quarter 2023, cost of natural gas was $199 million compared to $452 million for the corresponding period in 2022. For year-to-date 2023, cost of natural gas was $1.1 billion compared to $1.5 billion for the corresponding period in 2022. The decreases reflect lower gas cost recovery as a result of decreases of 71% and 54% in natural gas prices in the second quarter and year-to-date 2023, respectively, compared to the corresponding periods in 2022.
The following table details the volumes of natural gas sold during both periods presented.
| | | | | | | | | | | | | | | | | | | | | | | |
| Second Quarter | | Year-to-Date |
| 2023 | 2022 | 2023 vs. 2022 | | 2023 | 2022 | 2023 vs. 2022 |
Gas distribution operations (mmBtu in millions) | | | | | | |
| Firm | 101 | | 111 | | (9.0) | % | | 359 | | 415 | | (13.5) | % |
| Interruptible | 23 | | 22 | | 4.5 | | | 47 | | 47 | | — | |
| Total | 124 | | 133 | | (6.8) | % | | 406 | | 462 | | (12.1) | % |
| | | | | | |
| | | | | | | |
Gas marketing services (mmBtu in millions) | | | | | | |
| Firm: | | | | | | | |
| Georgia | 5 | | 5 | | — | % | | 18 | | 21 | | (14.3) | % |
| Illinois | 1 | | 1 | | — | | | 4 | | 4 | | — | |
| | | | | | | |
| Other | 3 | | 3 | | — | | | 7 | | 7 | | — | |
| Interruptible large commercial and industrial | 4 | | 3 | | 33.3 | | | 7 | | 7 | | — | |
| Total | 13 | | 12 | | 8.3 | % | | 36 | | 39 | | (7.7) | % |
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Other Operations and Maintenance Expenses
| | | | | | | | | | | | | | | | | | | | |
| Second Quarter 2023 vs. Second Quarter 2022 | | Year-To-Date 2023 vs. Year-To-Date 2022 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $43 | | 16.2 | | $45 | | 7.9 |
In the second quarter 2023, other operations and maintenance expenses were $309 million compared to $266 million for the corresponding period in 2022. For year-to-date 2023, other operations and maintenance expenses were $615 million compared to $570 million for the corresponding period in 2022. The increases for the second quarter and year-to-date 2023 were primarily due to increases of $30 million and $43 million, respectively, in compensation and benefits, $30 million for both periods related to a regulatory disallowance at Nicor Gas, and increases of $11 million and $16 million, respectively, related to energy service contracts, partially offset by decreases of $20 million and $36 million, respectively, in expenses passed through to customers primarily related to bad debt and energy efficiency programs at gas distribution operations. See Note (B) to the Condensed Financial Statements under "Southern Company Gas – Infrastructure Replacement Programs and Capital Projects" herein for additional information on the regulatory disallowance.
Depreciation and Amortization
| | | | | | | | | | | | | | | | | | | | |
| Second Quarter 2023 vs. Second Quarter 2022 | | Year-To-Date 2023 vs. Year-To-Date 2022 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $5 | | 3.6 | | $9 | | 3.3 |
In the second quarter 2023, depreciation and amortization was $143 million compared to $138 million for the corresponding period in 2022. For year-to-date 2023, depreciation and amortization was $284 million compared to $275 million for the corresponding period in 2022. The increases were primarily due to continued infrastructure investments at the natural gas distribution utilities.
Taxes Other Than Income Taxes
| | | | | | | | | | | | | | | | | | | | |
| Second Quarter 2023 vs. Second Quarter 2022 | | Year-To-Date 2023 vs. Year-To-Date 2022 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(3) | | (4.8) | | $(2) | | (1.2) |
In the second quarter 2023, taxes other than income taxes was $59 million compared to $62 million for the corresponding period in 2022. For year-to-date 2023, taxes other than income taxes was $161 million compared to $163 million for the corresponding period in 2022. The decreases for the second quarter and year-to-date 2023 were primarily due to decreases of $7 million and $12 million, respectively, in revenue taxes, largely offset by increases of $5 million and $11 million, respectively, in payroll, property, and invested capital taxes.
Interest Expense, Net of Amounts Capitalized
| | | | | | | | | | | | | | | | | | | | |
| Second Quarter 2023 vs. Second Quarter 2022 | | Year-To-Date 2023 vs. Year-To-Date 2022 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $12 | | 19.7 | | $28 | | 23.0 |
In the second quarter 2023, interest expense, net of amounts capitalized was $73 million compared to $61 million for the corresponding period in 2022. For year-to-date 2023, interest expense, net of amounts capitalized was $150 million compared to $122 million for the corresponding period in 2022. The increases for the second quarter and year-to-date 2023 were primarily associated with increases of approximately $13 million and $31 million, respectively, related to higher interest rates. See FINANCIAL CONDITION AND LIQUIDITY – "Sources of Capital" and "Financing Activities" herein for additional information on borrowings.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Income Taxes
| | | | | | | | | | | | | | | | | | | | |
| Second Quarter 2023 vs. Second Quarter 2022 | | Year-To-Date 2023 vs. Year-To-Date 2022 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(7) | | (19.4) | | $(2) | | (1.5) |
In the second quarter 2023, income taxes were $29 million compared to $36 million for the corresponding period in 2022. For year-to-date 2023, income taxes were $132 million compared to $134 million for the corresponding period in 2022. The decreases were primarily the result of the regulatory disallowance at Nicor Gas, partially offset by higher pre-tax earnings. See Note (B) under "Southern Company Gas – Infrastructure Replacement Programs and Capital Projects" and Note (G) under "Southern Company Gas" to the Condensed Financial Statements herein for additional information.
Segment Information
Operating revenues, operating expenses, and net income for each segment are provided in the table below. See Note (K) to the Condensed Financial Statements under "Southern Company Gas" herein for additional information.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | 2023 | | 2022 |
| Operating Revenues | | Operating Expenses | | Net Income (Loss) | | Operating Revenues | | Operating Expenses | | Net Income (Loss) |
| (in millions) | | (in millions) |
| Second Quarter |
| Gas distribution operations | $ | 764 | | | $ | 636 | | | $ | 60 | | | $ | 980 | | | $ | 819 | | | $ | 92 | |
| Gas pipeline investments | 8 | | | 2 | | | 19 | | | 8 | | | 2 | | | 23 | |
| | | | | | | | | | | |
| Gas marketing services | 75 | | | 64 | | | 7 | | | 92 | | | 90 | | | 1 | |
| All other | 9 | | | 9 | | | (1) | | | 10 | | | 14 | | | (1) | |
| Intercompany eliminations | (4) | | | (1) | | | — | | | (7) | | | (7) | | | — | |
| Consolidated | $ | 852 | | | $ | 710 | | | $ | 85 | | | $ | 1,083 | | | $ | 918 | | | $ | 115 | |
| | | | | | | | | | | |
| Year-to-Date |
| Gas distribution operations | $ | 2,383 | | | $ | 1,901 | | | $ | 281 | | | $ | 2,782 | | | $ | 2,293 | | | $ | 306 | |
| Gas pipeline investments | 16 | | | 5 | | | 50 | | | 16 | | | 5 | | | 52 | |
| Gas marketing services | 320 | | | 239 | | | 56 | | | 335 | | | 240 | | | 67 | |
| All other | 22 | | | 18 | | | 6 | | | 26 | | | 35 | | | 8 | |
| Intercompany eliminations | (13) | | | (6) | | | — | | | (19) | | | (19) | | | — | |
| Consolidated | $ | 2,728 | | | $ | 2,157 | | | $ | 393 | | | $ | 3,140 | | | $ | 2,554 | | | $ | 433 | |
Gas Distribution Operations
Gas distribution operations is the largest component of Southern Company Gas' business and is subject to regulation and oversight by regulatory agencies in each of the states it serves. These agencies approve natural gas rates designed to provide Southern Company Gas with the opportunity to generate revenues to recover the cost of natural gas delivered to its customers and its fixed and variable costs, including depreciation, interest expense, operations and maintenance, taxes, and overhead costs, and to earn a reasonable return on its investments.
With the exception of Atlanta Gas Light, Southern Company Gas' second largest utility that operates in a deregulated natural gas market and has a straight-fixed-variable rate design that minimizes the variability of its revenues based on consumption, the earnings of the natural gas distribution utilities can be affected by customer consumption patterns that are a function of weather conditions, price levels for natural gas, and general economic conditions that may impact customers' ability to pay for natural gas consumed. Southern Company Gas has various regulatory and other mechanisms, such as weather and revenue normalization mechanisms and weather derivative
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
instruments, that limit its exposure to changes in customer consumption, including weather changes within typical ranges in its natural gas distribution utilities' service territories. See Note 2 to the financial statements under "Southern Company Gas" in Item 8 of the Form 10-K for additional information.
In the second quarter 2023, net income decreased $32 million, or 34.8%, when compared to the corresponding period in 2022, as described further below:
•Operating revenues decreased $216 million primarily due to lower gas cost recovery and the regulatory disallowance at Nicor Gas, partially offset by rate increases and continued investment in infrastructure replacement. Gas costs recovered through natural gas revenues generally equal the amount expensed in cost of natural gas.
•Operating expenses decreased $183 million primarily due to a $230 million decrease in cost of natural gas as a result of lower gas prices and lower volumes sold compared to 2022, partially offset by higher depreciation resulting from additional assets placed in service, $30 million related to the regulatory disallowance at Nicor Gas, and an $11 million increase related to energy service contracts. The decrease in operating expenses also includes costs passed through directly to customers, primarily related to bad debt expenses and revenue taxes.
•Interest expense, net of amounts capitalized increased $12 million primarily due to higher interest rates and higher average outstanding debt.
•Income taxes decreased $12 million primarily as a result of the tax benefit resulting from the regulatory disallowance at Nicor Gas.
For year-to-date 2023, net income decreased $25 million, or 8.2%, when compared to the corresponding period in 2022, as described further below:
•Operating revenues decreased $399 million primarily due to lower gas cost recovery, partially offset by rate increases and continued investment in infrastructure replacement. Gas costs recovered through natural gas revenues generally equal the amount expensed in cost of natural gas.
•Operating expenses decreased $392 million primarily due to a $447 million decrease in cost of natural gas as a result of lower gas prices and lower volumes sold compared to 2022, partially offset by higher depreciation resulting from additional assets placed in service, higher compensation and benefits, $30 million related to the regulatory disallowance at Nicor Gas, and a $16 million increase related to energy service contracts. The decrease in operating expenses also includes costs passed through directly to customers, primarily related to bad debt expenses and revenue taxes.
•Interest expense, net of amounts capitalized increased $26 million primarily due to higher interest rates and higher average outstanding debt.
•Income taxes decreased $9 million primarily as a result of the tax benefit resulting from the regulatory disallowance at Nicor Gas.
See Note (B) to the Condensed Financial Statements under "Southern Company Gas – Infrastructure Replacement Programs and Capital Projects" herein for additional information.
Gas Pipeline Investments
Gas pipeline investments consists primarily of joint ventures in natural gas pipeline investments including SNG and Dalton Pipeline. See Note (E) to the Condensed Financial Statements under "Southern Company Gas" herein for additional information.
Gas Marketing Services
Gas marketing services provides energy-related products and services to natural gas markets and participants in customer choice programs that were approved in various states to increase competition. These programs allow customers to choose their natural gas supplier while the local distribution utility continues to provide distribution and transportation services. Gas marketing services is weather sensitive and uses a variety of hedging strategies,
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
such as weather derivative instruments and other risk management tools, to partially mitigate potential weather impacts.
In the second quarter 2023, net income increased $6 million, when compared to the corresponding period in 2022 primarily due to a $27 million decrease in cost of gas, partially offset by a $17 million decrease in operating revenue primarily due to the timing of unrealized hedge losses and a $3 million increase in income taxes.
For year-to-date 2023, net income decreased $11 million, or 16.4%, when compared to the corresponding period in 2022 primarily due to a $15 million decrease in operating revenue primarily due to the timing of unrealized hedge losses, partially offset by lower gas prices and lower volumes sold.
All Other
All other includes natural gas storage businesses, a renewable natural gas business, AGL Services Company, and Southern Company Gas Capital, as well as various corporate operating expenses that are not allocated to the reportable segments and interest income (expense) associated with affiliate financing arrangements. All other included a natural gas storage facility in Texas through its sale in November 2022. See Note 15 to the financial statements under "Southern Company Gas" in Item 8 of the Form 10-K for additional information, including the sale of a natural gas storage facility in California expected to be completed later in 2023.
For year-to-date 2023, net income decreased $2 million when compared to the corresponding period in 2022. The decrease was primarily related to an increase in income taxes, largely offset by a decrease in operating expenses primarily related to lower depreciation in 2023.
FUTURE EARNINGS POTENTIAL
Each Registrant's results of operations are not necessarily indicative of its future earnings potential. The level of the Registrants' future earnings depends on numerous factors that affect the opportunities, challenges, and risks of the Registrants' primary businesses of selling electricity and/or distributing natural gas, as described further herein.
For the traditional electric operating companies, these factors include the ability to maintain constructive regulatory environments that allow for the timely recovery of prudently-incurred costs during a time of increasing costs, including those related to projected long-term demand growth, stringent environmental standards, including CCR rules, safety, system reliability and resiliency, fuel, restoration following major storms, and capital expenditures, including constructing new electric generating plants and expanding and improving the transmission and distribution systems; continued customer growth; and the trends of higher inflation and reduced electricity usage per customer, especially in residential and commercial markets. For Georgia Power, other major factors are completing construction and start-up of Plant Vogtle Unit 4, meeting the related cost and schedule projections, and completing the related cost recovery proceedings for Plant Vogtle Units 3 and 4.
Earnings in the electricity business will also depend upon maintaining and growing sales, considering, among other things, the adoption and/or penetration rates of increasingly energy-efficient technologies and increasing volumes of electronic commerce transactions, which could contribute to a net reduction in customer usage.
Global and U.S. economic conditions continue to be significantly affected by a series of demand and supply shocks that caused a global and national economic recession in 2020 and have been further impacted by the invasion of Ukraine and significant declines in labor force participation rates. The confluence of these disruptions has resulted in the highest levels of inflation globally in 40 years and driven a significant policy response by central banks across the global economy. The U.S. Federal Reserve has increased policy interest rates faster than any rate increase cycle in the last 40 years and to levels high enough to slow economic activity and reduce inflation, although target inflation levels have not yet been achieved. These actions and impacts, including increased costs for goods and services and borrowing costs, have led to a slowing of some economic activity and an increased risk of recession. Recent challenges facing small and midsize banks may tighten lending standards, cause uncertainty in the banking sector, and further reduce economic growth. Additionally, inflation remains elevated in part due to continued supply chain and labor market constraints. Electricity sales across all classes have recovered to pre-COVID-19 pandemic levels and customer growth at both the traditional electric operating companies and natural gas distribution utilities has remained strong. However, weakening economic activity increases the risk of slowing to declining energy sales.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Additionally, the current economic environment has increased the uncertainty of future energy demand and operating costs. See RESULTS OF OPERATIONS herein for information on energy sales in the Southern Company system's service territory during the first half of 2023.
The level of future earnings for Southern Power's competitive wholesale electric business depends on numerous factors including the parameters of the wholesale market and the efficient operation of its wholesale generating assets; Southern Power's ability to execute its growth strategy through the development or acquisition of renewable facilities and other energy projects while containing costs; regulatory matters; customer creditworthiness; total electric generating capacity available in Southern Power's market areas; Southern Power's ability to successfully remarket capacity as current contracts expire; renewable portfolio standards; continued availability of federal and state ITCs and PTCs, which could be impacted by future tax legislation; transmission constraints; cost of generation from units within the Southern Company power pool; and operational limitations. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Income Tax Matters" in Item 7 of the Form 10-K for information regarding the Inflation Reduction Act's expansion of the availability of federal ITCs and PTCs.
The level of future earnings for Southern Company Gas' primary business of distributing natural gas and its complementary businesses in the gas pipeline investments and gas marketing services sectors depends on numerous factors. These factors include the natural gas distribution utilities' ability to maintain constructive regulatory environments that allow for the timely recovery of prudently-incurred costs, including those related to projected long-term demand growth, safety, system reliability and resiliency, natural gas, and capital expenditures, including expanding and improving the natural gas distribution systems; the completion and subsequent operation of ongoing infrastructure and other construction projects; customer creditworthiness; and certain policies to limit the use of natural gas, such as the potential across certain parts of the U.S. for state or municipal bans on the use of natural gas or policies designed to promote electrification. The volatility of natural gas prices has an impact on Southern Company Gas' customer rates, its long-term competitive position against other energy sources, and the ability of Southern Company Gas' gas marketing services business to capture value from locational and seasonal spreads. Additionally, changes in commodity prices, primarily driven by tight gas supplies, geopolitical events, and diminished gas production, subject a portion of Southern Company Gas' operations to earnings variability and may result in higher natural gas prices. Additional economic factors may contribute to this environment. The demand for natural gas may increase, which may cause natural gas prices to rise and drive higher volatility in the natural gas markets on a longer-term basis. Alternatively, a significant drop in oil and natural gas prices could lead to a consolidation of natural gas producers or reduced levels of natural gas production.
Earnings for both the electricity and natural gas businesses are subject to a variety of other factors. These factors include weather; competition; developing new and maintaining existing energy contracts and associated load requirements with wholesale customers; customer energy conservation practices; the use of alternative energy sources by customers; government incentives to reduce overall energy usage; fuel, labor, and material prices in an environment of heightened inflation and material and labor supply chain disruptions; and the price elasticity of demand. Demand for electricity and natural gas in the Registrants' service territories is primarily driven by the pace of economic growth or decline that may be affected by changes in regional and global economic conditions, which may impact future earnings.
As part of its ongoing effort to adapt to changing market conditions, Southern Company continues to evaluate and consider a wide array of potential business strategies. These strategies may include business combinations, partnerships, and acquisitions involving other utility or non-utility businesses or properties, disposition of, or the sale of interests in, certain assets or businesses, internal restructuring, or some combination thereof. Furthermore, Southern Company may engage in new business ventures that arise from competitive and regulatory changes in the utility industry. Pursuit of any of the above strategies, or any combination thereof, may significantly affect the business operations, risks, and financial condition of Southern Company. In addition, Southern Power and Southern Company Gas regularly consider and evaluate joint development arrangements as well as acquisitions and dispositions of businesses and assets as part of their business strategies. See Note 15 to the financial statements in Item 8 of the Form 10-K for additional information.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
For additional information relating to these issues, see RISK FACTORS in Item 1A and MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL in Item 7 of the Form 10-K.
Environmental Matters
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters" in Item 7 and Note 3 to the financial statements under "Environmental Remediation" in Item 8 of the Form 10-K, as well as Note (C) to the Condensed Financial Statements under "General Litigation Matters" and "Environmental Remediation" herein, for additional information.
Environmental Laws and Regulations
Air Quality
On February 13, 2023, the EPA published a final rule disapproving 19 state implementation plans (SIPs), including the States of Alabama and Mississippi, under the interstate transport (good neighbor) provisions of the Clean Air Act for the 2015 Ozone National Ambient Air Quality Standards (NAAQS). On March 14, 2023 and March 15, 2023, the State of Mississippi and Mississippi Power, respectively, challenged the EPA's disapproval of the Mississippi SIP in the U.S. Court of Appeals for the Fifth Circuit. On May 11, 2023, the State of Mississippi and Mississippi Power filed a joint motion for stay of the EPA's disapproval of the Mississippi SIP, which was granted on June 8, 2023. On April 13, 2023 and April 14, 2023, the State of Alabama and Alabama Power, respectively, challenged the EPA's disapproval of the Alabama SIP in the U.S. Court of Appeals for the Eleventh Circuit. On June 13, 2023, the State of Alabama, Alabama Power, and PowerSouth Energy Cooperative filed a joint motion for stay of the EPA's disapproval of the Alabama SIP.
On June 5, 2023, the EPA published the 2015 Ozone NAAQS Good Neighbor federal implementation plan (FIP), which will become effective August 4, 2023. On June 16, 2023 and June 27, 2023, the State of Mississippi and Mississippi Power, respectively, challenged the FIP in the U.S. Court of Appeals for the Fifth Circuit. On June 30, 2023, the State of Mississippi and Mississippi Power filed in the U.S. Court of Appeals for the Fifth Circuit a joint motion for stay of the FIP as to the State of Mississippi, which was denied on July 20, 2023.
On July 31, 2023, the EPA published an interim final rule that stays the implementation of the FIP for states with judicially stayed SIP disapprovals, including Mississippi. The interim final rule revises the existing regulations to maintain currently applicable trading programs for those states.
The ultimate impact of the rule and associated legal matters cannot be determined at this time; however, implementation of the FIP will likely result in increased compliance costs for the traditional electric operating companies.
Water Quality
On March 29, 2023, the EPA published a proposed ELG Supplemental Rule revising certain effluent limits of the 2020 and 2015 ELG rules. The proposal imposes more stringent requirements for flue gas desulfurization wastewater, bottom ash transport water, and combustion residual leachate to be met no later than December 31, 2029. The EPA is also proposing that a limited number of facilities already achieving compliance with the 2020 ELG Reconsideration Rule be allowed to elect retirement or repowering by December 31, 2032 as opposed to meeting the new more stringent requirements. The proposal maintains the 2020 ELG Reconsideration Rule's permanent cessation of coal combustion subcategory allowing units to continue to operate until the end of 2028 without having to install additional technologies. A final rule is anticipated in 2024. The ultimate impact of this proposal cannot be determined at this time; however, it may result in significant compliance costs.
Coal Combustion Residuals
On May 18, 2023, the EPA published a proposal to establish two new categories of federally regulated CCR, legacy surface impoundments and CCR management units (CCRMUs). The EPA is proposing to define a legacy surface impoundment as a CCR surface impoundment that no longer receives CCR but contained both CCR and liquids on
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
or after October 19, 2015 and that is located at an inactive electric generating facility. The EPA is proposing that owners and operators of legacy surface impoundments comply with all of the existing CCR Rule requirements with the exception of location restrictions and liner demonstrations. The proposal establishes accelerated compliance deadlines for legacy surface impoundments to meet regulatory requirements, including a requirement to initiate closure within 12 months after the effective date of the final rule. The EPA is also proposing to define CCRMUs as any area of land on which any non-containerized accumulation of CCR is received, placed, or otherwise managed at any time, that is not a CCR unit, including inactive CCR landfills and CCR units that closed prior to October 17, 2015. The EPA's proposal would require evaluations to be completed at both active facilities and inactive facilities with one or more legacy surface impoundment. CCRMUs must comply with the CCR Rule's provisions for groundwater monitoring, corrective action, closure, and post-closure activities. A final rule is anticipated in 2024. The ultimate impact of this proposal cannot be determined at this time; however, it may result in significant compliance costs.
Greenhouse Gases
On May 23, 2023, the EPA published the proposed GHG standards and state plan guidelines for fossil fuel-fired power plants. The proposal includes GHG limits for both new and existing units based on technologies such as carbon capture and sequestration, low-GHG hydrogen co-firing, and natural gas co-firing. The proposed standards for new combustion turbines include subcategories for different operational uses including peaking, intermediate, and base load. Compliance with new source standards, once finalized, begins when the unit comes online. The EPA proposes a phased approach for intermediate and base load units that increases in stringency over time. The proposed state plan guidelines for existing units include subcategories based on unit type, retirement date, size, and capacity factor. The EPA is proposing a 24-month state plan submission deadline for the existing unit implementation and proposes to potentially allow some limited form of trading and averaging for the state plans. Existing source compliance is proposed to begin as early as January 1, 2030, depending on the unit type and subcategory. The EPA also proposes to simultaneously repeal the Affordable Clean Energy rule. A final rule is anticipated in 2024. The ultimate impact of this proposal cannot be determined at this time; however, it may result in significant compliance costs.
Regulatory Matters
See Note 2 to the financial statements in Item 8 of the Form 10-K, OVERVIEW – "Recent Developments" herein, and Note (B) to the Condensed Financial Statements herein for a discussion of regulatory matters related to Alabama Power, Georgia Power, Mississippi Power, and Southern Company Gas, including items that could impact the applicable Registrants' future earnings, cash flows, and/or financial condition.
Alabama Power
On July 14, 2023, Alabama Power issued a request for proposals of between 100 MWs and 1,200 MWs of capacity beginning no later than December 1, 2028, with consideration for commencement as early as 2025. Any purchases will depend upon the cost competitiveness of the respective offers, as well as other options available to Alabama Power, and would ultimately require approval by the Alabama PSC. The ultimate outcome of this matter cannot be determined at this time.
Construction Programs
The Subsidiary Registrants are engaged in continuous construction programs to accommodate existing and estimated future loads on their respective systems. The Southern Company system strategy continues to include developing and constructing new electric generating facilities, expanding and improving the electric transmission and electric and natural gas distribution systems, and undertaking projects to comply with environmental laws and regulations.
For the traditional electric operating companies, major generation construction projects are subject to state PSC approval in order to be included in retail rates. The largest construction project currently underway in the Southern Company system is Plant Vogtle Unit 4. See Note (B) to the Condensed Financial Statements under "Georgia Power
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
– Nuclear Construction" herein for additional information. Also see Note 2 to the financial statements in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements herein under "Alabama Power – Certificates of Convenience and Necessity" for information regarding Alabama Power's construction of Plant Barry Unit 8.
Southern Company Gas is engaged in various infrastructure improvement programs designed to update or expand the natural gas distribution systems of the natural gas distribution utilities to improve reliability and resiliency, reduce emissions, and meet operational flexibility and growth. The natural gas distribution utilities recover their investment and a return associated with these infrastructure programs through their regulated rates. See Note 2 to the financial statements in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements herein under "Southern Company Gas" for additional information on Southern Company Gas' construction program.
See FINANCIAL CONDITION AND LIQUIDITY – "Cash Requirements" herein for additional information regarding the Registrants' capital requirements for their construction programs.
Southern Power's Power Sales Agreements
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Southern Power's Power Sales Agreements" in Item 7 of the Form 10-K for additional information.
At June 30, 2023, Southern Power's average investment coverage ratio for its generating assets, including those owned with various partners, based on the ratio of investment under contract to total investment using the respective facilities' net book value (or expected in-service value for facilities under construction) as the investment amount was 97% through 2027 and 90% through 2032, with an average remaining contract duration of approximately 12 years.
General Litigation and Other Matters
The Registrants are involved in various matters being litigated and/or regulatory and other matters that could affect future earnings, cash flows, and/or financial condition. The ultimate outcome of such pending or potential litigation against each Registrant and any subsidiaries or regulatory and other matters cannot be determined at this time; however, for current proceedings and/or matters not specifically reported herein or in Notes (B) and (C) to the Condensed Financial Statements herein, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings and/or matters would have a material effect on such Registrant's financial statements. See Notes (B) and (C) to the Condensed Financial Statements for a discussion of various contingencies, including matters being litigated, regulatory matters, and other matters which may affect future earnings potential.
Traditional Electric Operating Companies
See BUSINESS – "The Southern Company System – Traditional Electric Operating Companies" in Item 1 of the Form 10-K for information regarding the Southeast Energy Exchange Market (SEEM). On July 14, 2023, the U.S. Court of Appeals for the District of Columbia Circuit vacated the FERC's orders related to SEEM and remanded the proceeding to the FERC. The ultimate outcome of this matter cannot be determined at this time.
ACCOUNTING POLICIES
See MANAGEMENT'S DISCUSSION AND ANALYSIS – ACCOUNTING POLICIES in Item 7 of the Form 10-K for a complete discussion of the Registrants' critical accounting policies and estimates, as well as recently issued accounting standards.
The Registrants prepare their financial statements in accordance with GAAP. Significant accounting policies are described in the notes to the financial statements in Item 8 of the Form 10-K. In the application of these policies, certain estimates are made that may have a material impact on the Registrants' results of operations and related disclosures. Different assumptions and measurements could produce estimates that are significantly different from those recorded in the financial statements.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
FINANCIAL CONDITION AND LIQUIDITY
Overview
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Overview" in Item 7 of the Form 10-K for additional information. The financial condition of each Registrant remained stable at June 30, 2023. The Registrants intend to continue to monitor their access to short-term and long-term capital markets as well as their bank credit arrangements to meet future capital and liquidity needs. See "Cash Requirements," "Sources of Capital," and "Financing Activities" herein for additional information.
At the end of the second quarter 2023, the market price of Southern Company's common stock was $70.25 per share (based on the closing price as reported on the NYSE) and the book value was $28.12 per share, representing a market-to-book ratio of 250%, compared to $71.41, $27.93, and 256%, respectively, at the end of 2022. Southern Company's common stock dividend for the second quarter 2023 was $0.70 per share compared to $0.68 per share in the second quarter 2022.
Cash Requirements
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Cash Requirements" in Item 7 of the Form 10-K for a description of the Registrants' significant cash requirements.
The Registrants' significant cash requirements include estimated capital expenditures associated with their construction programs and, for the traditional electric operating companies, operating cash flows related to fuel cost under recovery. The fuel cost under recovery balances are primarily the result of higher than forecasted prices for natural gas and purchased power. See Note (B) to the Condensed Financial Statements herein under "Georgia Power – Fuel Cost Recovery" for additional information.
The construction programs are subject to periodic review and revision, and actual construction costs may vary from these estimates because of numerous factors. These factors include: changes in business conditions; changes in load projections; changes in environmental laws and regulations; the outcome of any legal challenges to environmental rules; changes in electric generating plants, including unit retirements and replacements and adding or changing fuel sources at existing electric generating units, to meet regulatory requirements; changes in FERC rules and regulations; state regulatory agency approvals; changes in the expected environmental compliance program; changes in legislation and/or regulation; the cost, availability, and efficiency of construction labor, equipment, and materials; project scope and design changes; abnormal weather; delays in construction due to judicial or regulatory action; storm impacts; and the cost of capital. In addition, there can be no assurance that costs related to capital expenditures and AROs will be fully recovered. Additionally, expenditures associated with Southern Power's planned acquisitions may vary due to market opportunities and the execution of its growth strategy. See Note 15 to the financial statements under "Southern Power" in Item 8 of the Form 10-K for additional information regarding Southern Power's plant acquisitions and construction projects.
The construction program of Georgia Power includes Plant Vogtle Unit 4, which includes components based on new technology that only within the last few years began initial operation in the global nuclear industry at this scale and which may be subject to additional revised cost estimates during construction. See Note 2 to the financial statements in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements herein under "Georgia Power – Nuclear Construction" for information regarding Plant Vogtle Units 3 and 4 and additional factors that may impact construction expenditures.
Long-term debt maturities and the interest payable on long-term debt each represent a significant cash requirement for the Registrants. See "Financing Activities" herein for information on changes in the Registrants' long-term debt balances since December 31, 2022.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Sources of Capital
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Sources of Capital" in Item 7 of the Form 10-K for additional information. Southern Company intends to meet its future capital needs through operating cash flows, borrowings from financial institutions, and debt, hybrid, and/or equity issuances. Equity capital can be provided from any combination of Southern Company's stock plans, private placements, or public offerings.
The Subsidiary Registrants plan to obtain the funds to meet their future capital needs from sources similar to those they used in the past, which were primarily from operating cash flows, external securities issuances, borrowings from financial institutions, and equity contributions from Southern Company. Operating cash flows provide a substantial portion of the Registrants' cash needs. Georgia Power intends to utilize a mix of senior note issuances, short-term floating rate bank loans, and commercial paper issuances to continue funding operating cash flows related to fuel cost under recovery.
The amount, type, and timing of any financings in 2023, as well as in subsequent years, will be contingent on investment opportunities and the Registrants' capital requirements and will depend upon prevailing market conditions, regulatory approvals (for certain of the Subsidiary Registrants), and other factors. See "Cash Requirements" and "Financing Activities" herein for additional information.
Southern Power utilizes tax equity partnerships as one of its financing sources, where the tax partner takes significantly all of the federal tax benefits. These tax equity partnerships are consolidated in Southern Power's financial statements and are accounted for using HLBV methodology to allocate partnership gains and losses. During the six months ended June 30, 2023, Southern Power obtained tax equity funding for existing tax equity partnerships totaling $21 million. See Note 1 to the financial statements under "General" in Item 8 of the Form 10-K for additional information.
By regulation, Nicor Gas is restricted, to the extent of its retained earnings balance, in the amount it can dividend or loan to affiliates and is not permitted to make money pool loans to affiliates. At June 30, 2023, the amount of subsidiary retained earnings restricted to dividend totaled $1.6 billion. This restriction did not impact Southern Company Gas' ability to meet its cash obligations, nor does management expect such restriction to materially impact Southern Company Gas' ability to meet its currently anticipated cash obligations.
Certain Registrants' current liabilities frequently exceed their current assets because of long-term debt maturities and the periodic use of short-term debt as a funding source, as well as significant seasonal fluctuations in cash needs. The Registrants generally plan to refinance long-term debt as it matures. The following table shows the amount by which current liabilities exceeded current assets at June 30, 2023 for the applicable Registrants:
| | | | | | | | | | | | | | | | |
| At June 30, 2023 | Southern Company | | Georgia
Power | Mississippi Power | | Southern Company Gas |
| (in millions) |
| Current liabilities in excess of current assets | $ | 2,261 | | | $ | 1,689 | | $ | 232 | | | $ | 626 | |
The Registrants believe the need for working capital can be adequately met by utilizing operating cash flows, as well as commercial paper, lines of credit, and short-term bank notes, as market conditions permit. In addition, under certain circumstances, the Subsidiary Registrants may utilize equity contributions and/or loans from Southern Company.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Bank Credit Arrangements
At June 30, 2023, the Registrants' unused committed credit arrangements with banks were as follows:
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| At June 30, 2023 | Southern
Company
parent | Alabama Power | Georgia
Power | Mississippi Power | Southern Power(a) | Southern Company Gas(b) | SEGCO | Southern
Company |
| (in millions) |
| Unused committed credit | $ | 1,998 | | $ | 1,250 | | $ | 1,726 | | $ | 275 | | $ | 589 | | $ | 1,598 | | $ | 30 | | $ | 7,466 | |
(a)At June 30, 2023, Southern Power also had two continuing letters of credit facilities for standby letters of credit, of which $25 million was unused. Southern Power's subsidiaries are not parties to its bank credit arrangements or letter of credit facilities.
(b)Includes $798 million and $800 million at Southern Company Gas Capital and Nicor Gas, respectively.
Subject to applicable market conditions, the Registrants, Nicor Gas, and SEGCO expect to renew or replace their bank credit arrangements as needed, prior to expiration. In connection therewith, the Registrants, Nicor Gas, and SEGCO may extend the maturity dates and/or increase or decrease the lending commitments thereunder.
A portion of the unused credit with banks is allocated to provide liquidity support to the revenue bonds of the traditional electric operating companies and the commercial paper programs of the Registrants, Nicor Gas, and SEGCO. The amount of variable rate revenue bonds of the traditional electric operating companies outstanding requiring liquidity support at June 30, 2023 was approximately $1.4 billion (comprised of approximately $492 million at Alabama Power, $819 million at Georgia Power, and $69 million at Mississippi Power). In addition, at June 30, 2023, Alabama Power and Georgia Power had approximately $120 million and $225 million, respectively, of fixed rate revenue bonds outstanding that are required to be remarketed within the next 12 months.
See Note 8 to the financial statements in Item 8 of the Form 10-K and Note (F) to the Condensed Financial Statements herein under "Bank Credit Arrangements" for additional information.
Short-term Borrowings
The Registrants, Nicor Gas, and SEGCO make short-term borrowings primarily through commercial paper programs that have the liquidity support of the committed bank credit arrangements described above. Southern Power's subsidiaries are not issuers or obligors under its commercial paper program. Commercial paper and short-term bank term loans are included in notes payable in the balance sheets. Details of the Registrants' short-term borrowings were as follows:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Short-term Debt at June 30, 2023 | | Short-term Debt During the Period(*) |
| | Amount
Outstanding | | Weighted
Average
Interest
Rate | | Average
Amount
Outstanding | | Weighted
Average
Interest
Rate | | Maximum
Amount
Outstanding |
| | (in millions) | | | | (in millions) | | | | (in millions) |
| Southern Company | $ | 1,647 | | | 5.9 | % | | $ | 2,115 | | | 5.7 | % | | $ | 2,595 | |
| Alabama Power | — | | | — | | | 84 | | | 5.1 | | | 195 | |
| Georgia Power | 1,295 | | | 6.0 | | | 1,553 | | | 5.7 | | | 2,110 | |
| Mississippi Power | 53 | | | 5.3 | | | 130 | | | 5.7 | | | 169 | |
| Southern Power | 100 | | | 5.7 | | | 117 | | | 5.7 | | | 197 | |
| Southern Company Gas: | | | | | | | | | |
| Southern Company Gas Capital | $ | 196 | | | 5.3 | % | | $ | 104 | | | 5.4 | % | | $ | 206 | |
| | | | | | | | | |
| | | | | | | | | |
(*)Average and maximum amounts are based upon daily balances during the three-month period ended June 30, 2023.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Analysis of Cash Flows
Net cash flows provided from (used for) operating, investing, and financing activities for the six months ended June 30, 2023 and 2022 are presented in the following table:
| | | | | | | | | | | | | | | | | | | | |
Net cash provided from
(used for): | Southern Company | Alabama Power | Georgia
Power | Mississippi Power | Southern Power | Southern Company Gas |
| (in millions) |
Six Months Ended June 30, 2023 | | | | | | |
| Operating activities | $ | 2,900 | | $ | 656 | | $ | 576 | | $ | 82 | | $ | 357 | | $ | 1,530 | |
| Investing activities | (4,288) | | (1,011) | | (2,260) | | (193) | | (18) | | (761) | |
| Financing activities | 1,595 | | (11) | | 1,364 | | 71 | | (300) | | (608) | |
| | | | | | |
Six Months Ended June 30, 2022 | | | | | | |
| Operating activities | $ | 3,579 | | $ | 510 | | $ | 926 | | $ | 112 | | $ | 552 | | $ | 1,478 | |
| Investing activities | (3,460) | | (889) | | (1,668) | | (133) | | (73) | | (658) | |
| Financing activities | (213) | | 227 | | 939 | | (18) | | (403) | | (650) | |
Fluctuations in cash flows from financing activities vary from year to year based on capital needs and the maturity or redemption of securities.
Southern Company
Net cash provided from operating activities decreased $0.7 billion for the six months ended June 30, 2023 as compared to the corresponding period in 2022 primarily due to the timing of vendor payments and fossil fuel stock purchases, partially offset by the timing of customer receivable collections.
The net cash used for investing activities for the six months ended June 30, 2023 was primarily related to the Subsidiary Registrants' construction programs.
The net cash provided from financing activities for the six months ended June 30, 2023 was primarily related to net issuances of long-term debt, partially offset by common stock dividend payments, net repayments of short-term bank loans, and a reduction in commercial paper borrowings.
Alabama Power
Net cash provided from operating activities increased $146 million for the six months ended June 30, 2023 as compared to the corresponding period in 2022 primarily due to an increase in fuel cost recovery and the timing of customer receivable collections, partially offset by the timing of vendor payments and fuel stock purchases.
The net cash used for investing activities for the six months ended June 30, 2023 was primarily related to gross property additions, including approximately $50 million related to the construction of Plant Barry Unit 8. See Note (B) to the Condensed Financial Statements under "Alabama Power" herein for additional information.
The net cash used for financing activities for the six months ended June 30, 2023 was primarily related to common stock dividend payments, largely offset by capital contributions from Southern Company and the issuance of senior notes.
Georgia Power
Net cash provided from operating activities decreased $350 million for the six months ended June 30, 2023 as compared to the corresponding period in 2022 primarily due to the timing of vendor payments and fossil fuel stock purchases, partially offset by the timing of customer receivable collections.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
The net cash used for investing activities for the six months ended June 30, 2023 was primarily related to gross property additions, including a total of approximately $425 million related to the construction of Plant Vogtle Units 3 and 4. See Note (B) to the Condensed Financial Statements under "Georgia Power – Nuclear Construction" herein for additional information on Plant Vogtle Units 3 and 4.
The net cash provided from financing activities for the six months ended June 30, 2023 was primarily related to issuances of senior notes, capital contributions from Southern Company, and reofferings of pollution control revenue bonds which were previously held by Georgia Power, partially offset by common stock dividend payments and a net decrease in short-term borrowings.
Mississippi Power
Net cash provided from operating activities decreased $30 million for the six months ended June 30, 2023 as compared to the corresponding period in 2022 primarily due to the timing of vendor payments, partially offset by the timing of customer receivable collections.
The net cash used for investing activities for the six months ended June 30, 2023 was primarily related to gross property additions.
The net cash provided from financing activities for the six months ended June 30, 2023 was primarily related to the issuance of senior notes and an increase in short-term borrowings, partially offset by common stock dividend payments.
Southern Power
Net cash provided from operating activities decreased $195 million for the six months ended June 30, 2023 as compared to the corresponding period in 2022 primarily due to the timing of vendor payments and a decrease in the utilization of tax credits, partially offset by the timing of customer receivable collections.
The net cash used for investing activities for the six months ended June 30, 2023 was primarily related to ongoing construction activities, partially offset by proceeds from the sale of equity investments.
The net cash used for financing activities for the six months ended June 30, 2023 was primarily related to common stock dividend payments, net repayments of short-term debt, and net distributions to noncontrolling interests.
Southern Company Gas
Net cash provided from operating activities increased $52 million for the six months ended June 30, 2023 as compared to the corresponding period in 2022 primarily due to the timing of customer receivable collections and higher gas cost recovery, partially offset by the timing of vendor payments and a change in natural gas for sale, net of temporary LIFO liquidation due to use of stored natural gas.
The net cash used for investing activities for the six months ended June 30, 2023 was primarily related to construction of transportation and distribution assets recovered through base rates and infrastructure investment recovered through replacement programs at gas distribution operations.
The net cash used for financing activities for the six months ended June 30, 2023 was primarily related to repayment of short-term borrowings and common stock dividend payments, partially offset by capital contributions from Southern Company and proceeds from other long-term debt.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Significant Balance Sheet Changes
Southern Company
Significant balance sheet changes for the six months ended June 30, 2023 included:
•an increase of $4.3 billion in long-term debt (including securities due within one year) related to new issuances;
•an increase of $2.2 billion in total property, plant, and equipment primarily related to the Subsidiary Registrants' construction programs;
•a decrease of $1.0 billion in accounts payable primarily related to the timing of vendor payments;
•a decrease of $1.0 billion in notes payable due to a reduction in commercial paper borrowings and the repayment of short-term bank loans;
•an increase of $0.6 billion in accumulated deferred income taxes primarily related to the expected utilization of ITCs in 2023, as well as an increase in property-related timing differences; and
•a decrease of $0.4 billion in accrued compensation due to the timing of payments.
See "Financing Activities" herein and Notes (B) and (G) to the Condensed Financial Statements herein for additional information.
Alabama Power
Significant balance sheet changes for the six months ended June 30, 2023 included:
•an increase of $355 million in common stockholder's equity primarily due to net income and capital contributions from Southern Company, partially offset by dividends paid to Southern Company;
•a decrease of $366 million in cash and cash equivalents, as discussed further under "Analysis of Cash Flows – Alabama Power" herein;
•an increase of $269 million in total property, plant, and equipment primarily related to the construction of Plant Barry Unit 8 and transmission and distribution facilities;
•a decrease of $269 million in other accounts payable primarily due to the timing of vendor payments; and
•an increase of $214 million in long-term debt (including securities due within one year) primarily due to the issuance of senior notes.
See "Financing Activities – Alabama Power" and Note (B) to the Condensed Financial Statements under "Alabama Power" herein for additional information.
Georgia Power
Significant balance sheet changes for the six months ended June 30, 2023 included:
•an increase of $1.8 billion in long-term debt (including securities due within one year) primarily due to issuances of senior notes;
•an increase of $1.5 billion in total property, plant, and equipment primarily related to the construction of generation, transmission, and distribution facilities, including $514 million for Plant Vogtle Units 3 and 4;
•an increase of $626 million in common stockholder's equity primarily due to capital contributions from Southern Company and net income, partially offset by dividends paid to Southern Company;
•a decrease of $320 million in cash and cash equivalents, as discussed further under "Analysis of Cash Flows – Georgia Power" herein; and
•a decrease of $305 million in notes payable primarily due to repayments of short-term bank debt.
See "Financing Activities – Georgia Power" herein and Note (B) to the Condensed Financial Statements herein under "Georgia Power – Nuclear Construction" for additional information.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Mississippi Power
Significant balance sheet changes for the six months ended June 30, 2023 included:
•an increase of $100 million in long-term debt (including securities due within one year) primarily due to issuances of senior notes;
•an increase of $92 million in total property, plant, and equipment primarily related to the construction of transmission and distribution facilities;
•decreases of $62 million in affiliated receivables and $47 million in affiliated accounts payable primarily due to fluctuations in affiliate sales/purchases and the timing of payments;
•a decrease of $61 million in accrued taxes primarily due to the payment of ad valorem taxes;
•an increase of $53 million in notes payable due to commercial paper borrowings; and
•a decrease of $40 million in cash and cash equivalents, as discussed further under "Analysis of Cash Flows – Mississippi Power" herein.
See "Financing Activities – Mississippi Power" herein for additional information.
Southern Power
Significant balance sheet changes for the six months ended June 30, 2023 included:
•increases of $319 million in accumulated deferred income tax liabilities and $223 million in prepaid income taxes primarily related to the expected utilization of ITCs in 2023;
•a decrease of $220 million in total property, plant, and equipment primarily due to continued depreciation of assets; and
•a decrease of $125 million in notes payable primarily due to net repayments of commercial paper.
See "Financing Activities – Southern Power" herein and Note (G) to the Condensed Financial Statements herein for additional information.
Southern Company Gas
Significant balance sheet changes for the six months ended June 30, 2023 included:
•a decrease of $663 million in total accounts receivable primarily related to decreases of $367 million in unbilled revenues and $297 million in customer accounts receivable as a result of seasonality;
•a decrease of $572 million in notes payable due to a reduction in commercial paper borrowings and the repayment of short-term bank loans;
•an increase of $525 million in total property, plant, and equipment primarily related to the construction of transportation and distribution assets and additional infrastructure investment;
•an increase of $341 million in common stockholder's equity related to net income and capital contributions from Southern Company, partially offset by dividends paid to Southern Company;
•a decrease of $278 million in other accounts payable due to seasonality and the timing of vendor payments; and
•a decrease of $204 million in natural gas for sale primarily due to the use of stored natural gas.
See "Financing Activities – Southern Company Gas" herein and Note (B) to the Condensed Financial Statements herein for additional information.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Financing Activities
The following table outlines the Registrants' long-term debt financing activities for the first six months of 2023:
| | | | | | | | | | | | | | | | | | | | | |
| Issuances and
Reofferings | | Maturities and Redemptions |
| Company | Senior
Notes | Revenue
Bonds | Other Long-
Term Debt | | Senior
Notes | | Other Long- Term Debt(*) |
| (in millions) |
| Southern Company parent | $ | 3,225 | | $ | — | | $ | — | | | $ | 600 | | | $ | 550 | |
| Alabama Power | 200 | | — | | 17 | | | — | | | 1 | |
| Georgia Power | 1,750 | | 229 | | — | | | 100 | | | 44 | |
| Mississippi Power | 100 | | — | | — | | | — | | | — | |
| | | | | | | |
| Southern Company Gas | — | | — | | 19 | | | — | | | — | |
| Other | — | | — | | — | | | — | | | 5 | |
| | | | | | | |
| Southern Company | $ | 5,275 | | $ | 229 | | $ | 36 | | | $ | 700 | | | $ | 600 | |
(*)Includes reductions in finance lease obligations resulting from cash payments under finance leases and, for Georgia Power, principal amortization payments totaling $43 million for FFB borrowings. See Note 8 to the financial statements under "Long-term Debt – DOE Loan Guarantee Borrowings" in Item 8 of the Form 10-K for additional information.
Except as otherwise described herein, the Registrants used the proceeds of debt issuances for their redemptions and maturities shown in the table above, to repay short-term indebtedness, and for general corporate purposes, including working capital. The Subsidiary Registrants also used the proceeds for their construction programs.
In addition to any financings that may be necessary to meet capital requirements and contractual obligations, the Registrants plan to continue, when economically feasible, a program to retire higher-cost securities and replace these obligations with lower-cost capital if market conditions permit.
Southern Company
During the first six months of 2023, Southern Company issued approximately 1.8 million shares of common stock primarily through employee equity compensation plans and received proceeds of approximately $22 million.
In January 2023, Southern Company redeemed all $550 million aggregate principal amount of its Series 2016B Junior Subordinated Notes due March 15, 2057.
In February 2023, Southern Company issued $1.5 billion aggregate principal amount of its Series 2023A 3.875% Convertible Senior Notes due December 15, 2025 (Series 2023A Convertible Senior Notes) in a private offering. In March 2023, Southern Company issued an additional $225 million aggregate principal amount of the Series 2023A Convertible Senior Notes upon the exercise by the initial purchasers of their over-allotment option. See Note (F) to the Condensed Financial Statements under "Convertible Senior Notes" herein for additional information.
In May 2023, Southern Company repaid at maturity $600 million aggregate principal amount of its 2021C Floating Rate Senior Notes.
Also in May 2023, Southern Company issued $750 million aggregate principal amount of Series 2023B 4.85% Senior Notes due June 15, 2028 and $750 million aggregate principal amount of Series 2023C 5.20% Senior Notes due June 15, 2033.
Subsequent to June 30, 2023, Southern Company repaid at maturity $1.25 billion aggregate principal amount of its 2.95% Senior Notes.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Alabama Power
During the first half of 2023, a subsidiary of Alabama Power borrowed $17 million under a $39 million long-term floating rate bank loan entered into in December 2022 with a maturity date of December 12, 2029.
In May 2023, Alabama Power issued $200 million aggregate principal amount of Series 2023A Floating Rate Senior Notes due May 15, 2073.
Georgia Power
In March 2023, Georgia Power reoffered to the public the following pollution control revenue bonds that previously had been purchased and were held by Georgia Power at December 31, 2022:
•approximately $28 million aggregate principal amount of Development Authority of Monroe County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Scherer Project), Second Series 2006;
•approximately $89 million aggregate principal amount of Development Authority of Monroe County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Scherer Project), Second Series 2009;
•approximately $49 million aggregate principal amount of Development Authority of Monroe County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Scherer Project), First Series 2012;
•approximately $18 million aggregate principal amount of Development Authority of Monroe County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Scherer Project), First Series 2013; and
•$46 million aggregate principal amount of Development Authority of Burke County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Vogtle Project), First Series 1996.
Also in March 2023, Georgia Power borrowed $100 million pursuant to a short-term uncommitted bank credit arrangement bearing interest at a mutually agreed upon rate and payable on demand. In April 2023, Georgia Power borrowed an additional $150 million under the arrangement. In May 2023, Georgia Power repaid the aggregate $250 million outstanding.
Also in March 2023, Georgia Power repaid at maturity a $200 million short-term floating rate bank loan entered into in March 2022.
In April 2023, Georgia Power repaid at maturity $100 million aggregate principal amount of its Series N 5.750% Senior Notes.
Also in April 2023, Georgia Power repaid at maturity a $200 million short-term floating rate bank loan entered into in April 2022.
In May 2023, Georgia Power issued $750 million aggregate principal amount of Series 2023A 4.65% Senior Notes due May 16, 2028 and $1.0 billion aggregate principal amount of Series 2023B 4.95% Senior Notes due May 17, 2033.
Subsequent to June 30, 2023, Georgia Power repaid at maturity $700 million aggregate principal amount of its Series 2020A 2.10% Senior Notes.
Mississippi Power
In March 2023, Mississippi Power borrowed $50 million of short-term debt pursuant to its $125 million revolving credit arrangement, which it repaid in June 2023.
In June 2023, Mississippi Power issued in a private placement $65 million aggregate principal amount of Series 2023A 5.64% Senior Notes due July 15, 2026 and $35 million aggregate principal amount of Series 2023B 5.63% Senior Notes due July 15, 2033.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Southern Power
In January 2023, Southern Power borrowed $100 million pursuant to a short-term uncommitted bank credit arrangement bearing interest at a mutually agreed upon rate and payable on demand. During the second quarter 2023, Southern Power made net repayments of $50 million of the $100 million borrowed.
Southern Company Gas
In February 2023, Nicor Gas repaid its $150 million and $50 million short-term floating rate bank loans entered into in February 2022 and March 2022, respectively.
During the first half of 2023, Southern Company Gas received cash advances totaling $19 million under a long-term financing agreement related to a construction contract.
Subsequent to June 30, 2023, Nicor Gas issued in a private placement $50 million aggregate principal amount of 5.28% Series First Mortgage Bonds due July 31, 2030 and $75 million aggregate principal amount of 5.43% Series First Mortgage Bonds due July 31, 2035. Pursuant to the same agreement, Nicor Gas agreed to issue in a private placement in October 2023 $75 million aggregate principal amount of 5.67% Series First Mortgage Bonds due October 31, 2053 and $75 million aggregate principal amount of 5.77% Series First Mortgage Bonds due October 31, 2063.
Credit Rating Risk
At June 30, 2023, the Registrants did not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade.
There are certain contracts that could require collateral, but not accelerated payment, in the event of a credit rating change of certain Registrants to BBB and/or Baa2 or below. These contracts are primarily for physical electricity and natural gas purchases and sales, fuel purchases, fuel transportation and storage, energy price risk management, transmission, interest rate management, and, for Georgia Power, construction of new generation at Plant Vogtle Units 3 and 4.
The maximum potential collateral requirements under these contracts at June 30, 2023 were as follows:
| | | | | | | | | | | | | | | | | | | | |
| Credit Ratings | Southern Company(*) | Alabama Power | Georgia Power | Mississippi Power | Southern Power(*) | Southern Company Gas |
| (in millions) |
| At BBB and/or Baa2 | $ | 33 | | $ | 1 | | $ | — | | $ | — | | $ | 32 | | $ | — | |
| At BBB- and/or Baa3 | 432 | | 2 | | 60 | | — | | 370 | | — | |
| At BB+ and/or Ba1 or below | 2,113 | | 424 | | 952 | | 328 | | 1,297 | | 30 | |
(*)Southern Power has PPAs that could require collateral, but not accelerated payment, in the event of a downgrade of Southern Power's credit. The PPAs require credit assurances without stating a specific credit rating. The amount of collateral required would depend upon actual losses resulting from a credit downgrade. Southern Power had $106 million of cash collateral posted related to PPA requirements at June 30, 2023.
The amounts in the previous table for the traditional electric operating companies and Southern Power include certain agreements that could require collateral if either Alabama Power or Georgia Power has a credit rating change to below investment grade. Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. Additionally, a credit rating downgrade could impact the ability of the Registrants to access capital markets and would be likely to impact the cost at which they do so.
On August 2, 2023, S&P revised its credit rating outlook for Southern Company and its subsidiaries to positive from stable.
Item 3. Quantitative and Qualitative Disclosures About Market Risk.
During the six months ended June 30, 2023, there were no material changes to Southern Company's, Alabama Power's, Georgia Power's, Mississippi Power's, Southern Power's, or Southern Company Gas' disclosures about market risk. For an in-depth discussion of each Registrant's market risks, see MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Market Price Risk" in Item 7 of the Form 10-K and Note 1 to the financial statements under "Financial Instruments" and Notes 13 and 14 to the financial statements in Item 8 of the Form 10-K, as well as Notes (I) and (J) to the Condensed Financial Statements herein.
Item 4. Controls and Procedures.
(a)Evaluation of disclosure controls and procedures.
As of the end of the period covered by this Quarterly Report on Form 10-Q, Southern Company, Alabama Power, Georgia Power, Mississippi Power, Southern Power, and Southern Company Gas conducted separate evaluations under the supervision and with the participation of each company's management, including the Chief Executive Officer and the Chief Financial Officer, of the effectiveness of the design and operation of the disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended). Based upon these evaluations, the Chief Executive Officer and the Chief Financial Officer, in each case, concluded that the disclosure controls and procedures are effective.
(b) Changes in internal control over financial reporting.
There have been no changes in Southern Company's, Alabama Power's, Georgia Power's, Mississippi Power's, Southern Power's, or Southern Company Gas' internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934, as amended) during the second quarter 2023 that have materially affected or are reasonably likely to materially affect Southern Company's, Alabama Power's, Georgia Power's, Mississippi Power's, Southern Power's, or Southern Company Gas' internal control over financial reporting.