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
|
|
|
|
|
|
|
|
|
|
|
Note
|
|
Page
|
|
A
|
|
|
|
B
|
|
|
|
C
|
|
|
|
D
|
|
|
|
E
|
|
|
|
F
|
|
|
|
G
|
|
|
|
H
|
|
|
|
I
|
|
|
|
J
|
|
|
|
K
|
|
|
|
L
|
|
|
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, L
|
|
Alabama Power
|
A, B, C, D, F, G, H, I, J
|
|
Georgia Power
|
A, B, C, D, F, G, H, I, J
|
|
Mississippi Power
|
A, B, C, D, F, G, H, I, J
|
|
Southern Power
|
A, C, D, E, F, G, H, I, J, K
|
|
Southern Company Gas
|
A, B, C, D, E, F, G, H, I, J, K, L
|
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, 2020 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, 2021 and 2020. 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, including the impacts of the COVID-19 pandemic, 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, 2021 and December 31, 2020 was as follows:
|
|
|
|
|
|
|
|
|
|
Goodwill
|
|
|
|
(in millions)
|
|
Southern Company
|
$
|
5,280
|
|
|
|
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 in the fourth quarter of the year and on an interim basis as events and changes in circumstances occur.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
Other intangible assets were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
At June 30, 2021
|
|
At December 31, 2020
|
|
|
Gross Carrying Amount
|
Accumulated Amortization
|
Other
Intangible Assets, Net
|
|
Gross Carrying Amount
|
Accumulated Amortization
|
Other
Intangible Assets, Net
|
|
|
(in millions)
|
|
(in millions)
|
|
Southern Company
|
|
|
|
|
|
|
|
|
Other intangible assets subject to amortization:
|
|
|
|
|
|
|
|
|
Customer relationships
|
$
|
212
|
|
$
|
(142)
|
|
$
|
70
|
|
|
$
|
212
|
|
$
|
(135)
|
|
$
|
77
|
|
|
Trade names
|
64
|
|
(35)
|
|
29
|
|
|
64
|
|
(31)
|
|
33
|
|
|
Storage and transportation contracts(*)
|
—
|
|
—
|
|
—
|
|
|
64
|
|
(64)
|
|
—
|
|
|
PPA fair value adjustments
|
390
|
|
(99)
|
|
291
|
|
|
390
|
|
(89)
|
|
301
|
|
|
Other
|
11
|
|
(10)
|
|
1
|
|
|
10
|
|
(9)
|
|
1
|
|
|
Total other intangible assets subject to amortization
|
$
|
677
|
|
$
|
(286)
|
|
$
|
391
|
|
|
$
|
740
|
|
$
|
(328)
|
|
$
|
412
|
|
|
Other intangible assets not subject to amortization:
|
|
|
|
|
|
|
|
|
Federal Communications Commission licenses
|
75
|
|
—
|
|
75
|
|
|
75
|
|
—
|
|
75
|
|
|
Total other intangible assets
|
$
|
752
|
|
$
|
(286)
|
|
$
|
466
|
|
|
$
|
815
|
|
$
|
(328)
|
|
$
|
487
|
|
|
|
|
|
|
|
|
|
|
|
Southern Power
|
|
|
|
|
|
|
|
|
Other intangible assets subject to amortization:
|
|
|
|
|
|
|
|
|
PPA fair value adjustments
|
$
|
390
|
|
$
|
(99)
|
|
$
|
291
|
|
|
$
|
390
|
|
$
|
(89)
|
|
$
|
301
|
|
|
|
|
|
|
|
|
|
|
|
Southern Company Gas
|
|
|
|
|
|
|
|
|
Other intangible assets subject to amortization:
|
|
|
|
|
|
|
|
|
Gas marketing services
|
|
|
|
|
|
|
|
|
Customer relationships
|
$
|
156
|
|
$
|
(124)
|
|
$
|
32
|
|
|
$
|
156
|
|
$
|
(119)
|
|
$
|
37
|
|
|
Trade names
|
26
|
|
(14)
|
|
12
|
|
|
26
|
|
(12)
|
|
14
|
|
|
Wholesale gas services
|
|
|
|
|
|
|
|
|
Storage and transportation contracts(*)
|
—
|
|
—
|
|
—
|
|
|
64
|
|
(64)
|
|
—
|
|
|
Total other intangible assets subject to amortization
|
$
|
182
|
|
$
|
(138)
|
|
$
|
44
|
|
|
$
|
246
|
|
$
|
(195)
|
|
$
|
51
|
|
(*)See Note (K) under "Southern Company Gas" for information regarding the sale of Sequent.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
Amortization associated with other intangible assets was as follows:
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
Six Months Ended
|
|
|
June 30, 2021
|
|
|
(in millions)
|
|
Southern Company(a)
|
$
|
10
|
|
$
|
21
|
|
|
Southern Power(b)
|
5
|
|
10
|
|
|
Southern Company Gas(c)
|
3
|
|
7
|
|
(a)Includes $5 million and $10 million for the three and six months ended June 30, 2021, respectively, recorded as a reduction to operating revenues.
(b)Recorded as a reduction to operating revenues.
(c)Relates to gas marketing services.
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
|
|
Southern Power
|
|
Southern
Company Gas
|
|
|
June 30, 2021
|
|
December 31, 2020
|
|
June 30, 2021
|
|
June 30, 2021
|
December 31, 2020
|
|
|
(in millions)
|
|
(in millions)
|
|
(in millions)
|
|
Cash and cash equivalents
|
$
|
1,582
|
|
|
$
|
1,065
|
|
|
$
|
165
|
|
|
$
|
37
|
|
$
|
17
|
|
|
Cash and cash equivalents classified as held for sale
|
8
|
|
|
—
|
|
|
—
|
|
|
8
|
|
—
|
|
|
Restricted cash(a):
|
|
|
|
|
|
|
|
|
|
Other current assets
|
2
|
|
|
2
|
|
|
—
|
|
|
2
|
|
2
|
|
|
Other deferred charges and assets
|
24
|
|
|
—
|
|
|
24
|
|
|
—
|
|
—
|
|
|
Total cash, cash equivalents, and restricted cash(b)
|
$
|
1,617
|
|
|
$
|
1,068
|
|
|
$
|
189
|
|
|
$
|
48
|
|
$
|
19
|
|
(a)For Southern Company Gas, reflects restricted cash held as collateral for workers' compensation, life insurance, and long-term disability insurance. For Southern Power, reflects restricted cash held for construction payables.
(b)Total may not add due to rounding.
Natural Gas for Sale
With the exception of Nicor Gas, Southern Company Gas' natural gas distribution utilities record 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, 2021 is expected to be restored prior to year end.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
(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, 2021 and December 31, 2020 were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Regulatory Clause
|
Balance Sheet Line Item
|
June 30,
2021
|
December 31, 2020
|
|
|
|
(in millions)
|
|
Alabama Power
|
|
|
|
|
Rate CNP Compliance
|
Other regulatory liabilities, current
|
$
|
1
|
|
$
|
28
|
|
|
|
|
|
|
|
|
|
|
|
|
Rate CNP PPA
|
Other regulatory assets, deferred
|
64
|
|
58
|
|
|
Retail Energy Cost Recovery
|
Other regulatory liabilities, current
|
—
|
|
18
|
|
|
|
|
|
|
|
|
Other regulatory assets, deferred
|
54
|
|
—
|
|
|
|
|
|
|
|
Natural Disaster Reserve
|
Other regulatory liabilities, deferred
|
36
|
|
77
|
|
|
Georgia Power
|
|
|
|
|
Fuel Cost Recovery
|
Over recovered fuel clause revenues
|
$
|
—
|
|
$
|
113
|
|
|
|
Other deferred charges and assets
|
21
|
|
—
|
|
|
|
|
|
|
|
Mississippi Power
|
|
|
|
|
Fuel Cost Recovery
|
Over recovered regulatory clause liabilities
|
$
|
9
|
|
$
|
24
|
|
|
Ad Valorem Tax
|
Other regulatory assets, current
|
12
|
|
11
|
|
|
|
Other regulatory assets, deferred
|
45
|
|
41
|
|
|
Property Damage Reserve
|
Other regulatory liabilities, deferred
|
—
|
|
4
|
|
|
|
Other regulatory assets, deferred
|
5
|
|
—
|
|
|
Southern Company Gas
|
|
|
|
|
Natural Gas Cost Recovery(*)
|
Other regulatory liabilities
|
$
|
5
|
|
$
|
88
|
|
|
|
Natural gas cost under recovery
|
485
|
|
—
|
|
|
|
Other regulatory assets, deferred
|
119
|
|
—
|
|
(*)The significant change during the six months ended June 30, 2021 was primarily driven by an increase in the cost of gas purchased in February 2021 resulting from Winter Storm Uri.
Alabama Power
Certificate of Convenience and Necessity
Energy Alabama, Gasp, Inc., and the Sierra Club filed requests for reconsideration and rehearing with the Alabama PSC regarding the certificate of convenience and necessity (CCN) issued to Alabama Power in August 2020, which authorized, among other things, the construction of Plant Barry Unit 8 and the acquisition of the Central Alabama Generating Station. In December 2020, the Alabama PSC issued an order denying the requests. On January 7, 2021, Energy Alabama and Gasp, Inc. filed a judicial appeal regarding both the Alabama PSC's August 2020 CCN order and the December 2020 order denying reconsideration and rehearing. On March 9, 2021, the Circuit Court of Montgomery County, Alabama granted a motion by Alabama Power to intervene in the appeal. At June 30, 2021, expenditures associated with the construction of Plant Barry Unit 8 included in CWIP totaled approximately $188 million. The ultimate outcome of this matter cannot be determined at this time.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
Plant Greene County
Alabama Power jointly owns Plant Greene County with an affiliate, Mississippi Power. See Note 5 under "Joint Ownership Agreements" in Item 8 of the Form 10-K for additional information.
On April 15, 2021, Mississippi Power filed its 2021 IRP with the Mississippi PSC, which includes a schedule to retire its 40% ownership interest in Plant Greene County Units 1 and 2 in December 2025 and 2026, respectively, consistent with each unit's remaining useful life. Mississippi Power's IRP is subject to a review period during which the Mississippi PSC may note any deficiencies which could require re-evaluation or resubmission of the IRP. If no deficiencies are noted, the Mississippi PSC's review will conclude on August 13, 2021.
The Plant Greene County unit retirements identified by Mississippi Power require the completion of transmission and system reliability improvements, as well as agreement by Alabama Power. Alabama Power will continue to monitor the status of Mississippi Power's IRP and associated regulatory processes, as well as the transmission and system reliability improvements. Currently, Alabama Power plans to retire Plant Greene County Units 1 and 2 at the dates indicated. The ultimate outcome of this matter cannot be determined at this time.
Rate NDR
Based on an order from the Alabama PSC, when Alabama Power's NDR balance falls below $50 million, a reserve establishment charge will be activated and the ongoing reserve maintenance charge will be concurrently suspended until the NDR balance reaches $75 million. At June 30, 2021, Alabama Power's NDR balance was $36 million. As a result, effective with October 2021 billings, the reserve maintenance charge component of Rate NDR will be suspended and the reserve establishment charge will be activated. Alabama Power expects to collect approximately $4 million in the fourth quarter 2021 and $16 million annually under Rate NDR until the NDR balance is restored to $75 million.
Georgia Power
Rate Plan
Effective January 1, 2021, Georgia Power reduced its amortization of costs associated with CCR AROs by approximately $90 million as approved by the Georgia PSC in conjunction with Georgia Power's annual compliance filings.
In February 2020, the Georgia PSC denied a motion for reconsideration filed by the Sierra Club regarding the Georgia PSC's decision in the 2019 ARP allowing Georgia Power to recover compliance costs for CCR AROs, and, in December 2020, the Superior Court of Fulton County affirmed the decision of the Georgia PSC. On January 5, 2021, the Sierra Club filed a notice of appeal with the Georgia Court of Appeals. The ultimate outcome of this matter cannot be determined at this time.
See Note 6 to the financial statements in Item 8 of the Form 10-K for additional information regarding Georgia Power's AROs.
Plant Vogtle Unit 3 and Common Facilities Rate Proceeding
On June 15, 2021, Georgia Power filed an application with the Georgia PSC to adjust retail base rates to include the portion of costs related to its investment in Plant Vogtle Unit 3 and common facilities shared between Plant Vogtle Units 3 and 4 (Common Facilities) previously deemed prudent by the Georgia PSC ($2.38 billion), as well as the related costs of operation.
The request includes an annual rate increase totaling approximately $370 million to be effective the month after Unit 3 is placed in service. Unit 3 is projected to be placed in service in the second quarter 2022. This increase will be partially offset by a decrease in the NCCR tariff of approximately $116 million expected to be effective January 1, 2022. In addition, an estimated $45 million of fuel cost savings related to Unit 3 is already incorporated in Georgia Power's current fuel cost recovery rates.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
Georgia Power also is requesting to defer some of its 2022 financing costs (approximately $42 million) relating to the remaining portion of the total Unit 3 and Common Facilities construction costs not being recovered through the NCCR tariff until Unit 4 costs are placed in retail base rates.
The Georgia PSC is scheduled to issue a final order in this proceeding on November 2, 2021. The ultimate outcome of this matter cannot be determined at this time. See "Nuclear Construction" herein for additional information on Plant Vogtle Units 3 and 4.
Deferral of Incremental COVID-19 Costs
In June 2021, Georgia Power performed a review of bad debt amounts deferred under the Georgia PSC-approved methodology, including consideration of actual amounts repaid by customers from arrears and installment plans after the disconnection moratorium period ended in July 2020. As a result of the review, Georgia Power reduced the balance of deferred incremental costs by approximately $20 million. At June 30, 2021, the incremental costs deferred totaled approximately $20 million, including approximately $2 million of incremental bad debt costs and $18 million of other incremental costs. The period over which these costs will be recovered is expected to be determined in Georgia Power's next base rate case. The ultimate outcome of this matter cannot be determined at this time.
Nuclear Construction
In 2009, the Georgia PSC certified construction of Plant Vogtle Units 3 and 4, in which Georgia Power holds a 45.7% ownership interest. In 2012, the NRC issued the related combined construction and operating licenses, which allowed full construction of the two AP1000 nuclear units (with electric generating capacity of approximately 1,100 MWs each) and related facilities to begin. Until March 2017, construction on Plant Vogtle Units 3 and 4 continued under the Vogtle 3 and 4 Agreement, which was a substantially fixed price agreement.
In connection with the EPC Contractor's bankruptcy filing in March 2017, Georgia Power, acting for itself and as agent for the other Vogtle Owners, entered into several transitional arrangements to allow construction to continue. In July 2017, Georgia Power, acting for itself and as agent for the other Vogtle Owners, entered into the Vogtle Services Agreement, whereby Westinghouse provides facility design and engineering services, procurement and technical support, and staff augmentation on a time and materials cost basis. The Vogtle Services Agreement provides that it will continue until the start-up and testing of Plant Vogtle Units 3 and 4 are complete and electricity is generated and sold from both units. The Vogtle Services Agreement is terminable by the Vogtle Owners upon 30 days' written notice.
In October 2017, Georgia Power, acting for itself and as agent for the other Vogtle Owners, executed the Bechtel Agreement, a cost reimbursable plus fee arrangement, whereby Bechtel is reimbursed for actual costs plus a base fee and an at-risk fee, which is subject to adjustment based on Bechtel's performance against cost and schedule targets. Each Vogtle Owner is severally (not jointly) liable for its proportionate share, based on its ownership interest, of all amounts owed to Bechtel under the Bechtel Agreement. The Vogtle Owners may terminate the Bechtel Agreement at any time for their convenience, provided that the Vogtle Owners will be required to pay amounts related to work performed prior to the termination (including the applicable portion of the base fee), certain termination-related costs, and, at certain stages of the work, the applicable portion of the at-risk fee. Bechtel may terminate the Bechtel Agreement under certain circumstances, including certain Vogtle Owner suspensions of work, certain breaches of the Bechtel Agreement by the Vogtle Owners, Vogtle Owner insolvency, and certain other events.
See Note 8 to the financial statements under "Long-term Debt – DOE Loan Guarantee Borrowings" in Item 8 of the Form 10-K for information on the Amended and Restated Loan Guarantee Agreement, including applicable covenants, events of default, mandatory prepayment events, and conditions to borrowing.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
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 June 2022 and March 2023, respectively, is as follows:
|
|
|
|
|
|
|
|
|
(in millions)
|
|
Base project capital cost forecast(a)(b)
|
$
|
9,096
|
|
|
Construction contingency estimate
|
119
|
|
|
|
|
|
Total project capital cost forecast(a)(b)
|
9,215
|
|
|
Net investment at June 30, 2021(b)
|
(7,856)
|
|
|
Remaining estimate to complete
|
$
|
1,359
|
|
(a) Includes approximately $570 million of costs that are not shared with the other Vogtle Owners. Excludes financing costs expected to be capitalized through AFUDC of approximately $290 million, of which $143 million had been accrued through June 30, 2021.
(b) Net of $1.7 billion received from Toshiba under the Guarantee Settlement Agreement and approximately $188 million in related customer refunds.
Georgia Power estimates that its financing costs for construction of Plant Vogtle Units 3 and 4 will total approximately $3.2 billion, of which $2.7 billion had been incurred through June 30, 2021.
As part of its ongoing processes, Southern Nuclear continues to evaluate cost and schedule forecasts on a regular basis to incorporate current information available, particularly in the areas of engineering support, commodity installation, system turnovers and related test results, and workforce statistics. Southern Nuclear establishes aggressive target values for monthly construction production and system turnover activities. Southern Nuclear's site work plans continue to reflect this approach in support of safely completing Units 3 and 4, while achieving the required construction quality.
In mid-March 2020, Southern Nuclear began implementing policies and procedures designed to mitigate the risk of transmission of COVID-19 at the construction site, including worker distancing measures; isolating individuals who tested positive for COVID-19, showed symptoms consistent with COVID-19, were being tested for COVID-19, or were in close contact with such persons; requiring self-quarantine; and adopting additional precautionary measures. Since March 2020, the number of active cases at the site has fluctuated and impacted productivity levels and pace of activity completion. The site has experienced an overall decline in the number of active cases since a peak in January 2021. The lower productivity levels and slower pace of activity completion experienced since March 2020 contributed to a backlog to the aggressive site work plan established at the beginning of 2020. Georgia Power estimates the productivity impacts of the COVID-19 pandemic have consumed approximately three to four months of schedule margin previously embedded in the site work plan for Unit 3 and Unit 4. In addition, the project continued to face challenges including, but not limited to, higher than expected absenteeism; overall construction and subcontractor labor productivity; system turnover and testing activities; and electrical equipment and commodity installation. As a result of these factors, in January 2021, Southern Nuclear further extended certain milestone dates, including the start of hot functional testing and fuel load for Unit 3, from those established in October 2020.
Following the January 2021 milestone extensions, Southern Nuclear has been performing additional construction remediation work necessary to ensure quality and design standards are met as system turnovers are completed to support hot functional testing and fuel load for Unit 3. Hot functional testing for Unit 3 was completed in July 2021. As a result of challenges including, but not limited to, construction productivity, construction remediation work, the pace of system turnovers, spent fuel pool repairs, and the timeframe and duration for hot functional and other testing, at the end of the second quarter 2021, Southern Nuclear further extended certain milestone dates, including the fuel load for Unit 3, from those established in January 2021. The site work plan currently targets fuel load for Unit 3 in the fourth quarter 2021 and an in-service date of March 2022. As the site work plan includes minimal margin to these milestone dates, an in-service date in the second quarter 2022 for Unit 3 is projected, although any further delays could result in a later in-service date.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
As the result of productivity challenges, at the end of the second quarter 2021, Southern Nuclear also further extended milestone dates for Unit 4 from those established in January 2021. The site work plan targets an in-service date of November 2022 and primarily depends on overall construction productivity and production levels significantly improving as well as appropriate levels of craft laborers, particularly electricians and pipefitters, being added and maintained. As the site work plan includes minimal margin to the milestone dates, an in-service date in the first quarter 2023 for Unit 4 is projected, although any further delays could result in a later in-service date.
As of March 31, 2021, approximately $84 million of the construction contingency established in the fourth quarter 2020 was assigned to the base capital cost forecast for costs primarily associated with the schedule extension for Unit 3 to December 2021, construction productivity, support resources, and construction remediation work. Georgia Power increased its total capital cost forecast as of March 31, 2021 by adding $48 million to the remaining construction contingency. Considering the factors above, during the second quarter 2021, all of the remaining construction contingency previously established and an additional $341 million was assigned to the base capital cost forecast for costs primarily associated with the schedule extensions for Units 3 and 4 described above, construction remediation work for Unit 3, and construction productivity and support resources for Units 3 and 4. Georgia Power also increased its total capital cost forecast as of June 30, 2021 by adding $119 million to replenish construction contingency.
After considering the significant level of uncertainty that exists regarding the future recoverability of these costs since the ultimate outcome of these matters is subject to the outcome of future assessments by management, as well as Georgia PSC decisions in future regulatory proceedings, Georgia Power recorded pre-tax charges to income in the first quarter 2021 and the second quarter 2021 of $48 million ($36 million after tax) and $460 million ($343 million after tax), respectively, for the increases in the total project capital cost forecast. As and when these amounts are spent, Georgia Power may request the Georgia PSC to evaluate those expenditures for rate recovery.
In addition, the continuing effects of the COVID-19 pandemic could further disrupt or delay construction and testing activities at Plant Vogtle Units 3 and 4. Georgia Power's proportionate share of the estimated incremental cost associated with COVID-19 mitigation actions and impacts on construction productivity is currently estimated to be between $160 million and $200 million and is included in the total project capital cost forecast.
As construction, including subcontract work, continues and testing and system turnover activities increase, ongoing or future challenges with management of contractors and vendors; subcontractor performance; supervision of craft labor and related productivity, particularly in the installation of electrical, mechanical, and instrumentation and controls commodities, ability to attract and retain craft labor, and/or related cost escalation; procurement, fabrication, delivery, assembly, installation, system turnover, and the initial testing and start-up, including any required engineering changes or any remediation related thereto, of plant systems, structures, or components (some of which are based on new technology that only within the last few years began initial operation in the global nuclear industry at this scale), including the spent fuel pools, any of which may require additional labor and/or materials; or other issues could continue or arise and change the projected schedule and estimated cost.
There have been technical and procedural challenges to the construction and licensing of Plant Vogtle Units 3 and 4 at the federal and state level and additional challenges may arise. Processes are in place that are designed to ensure compliance with the requirements specified in the Westinghouse Design Control Document and the combined construction and operating licenses, including inspections by Southern Nuclear and the NRC that occur throughout construction. In connection with the additional construction remediation work described above, Southern Nuclear reviewed the project's construction quality programs and, where needed, is implementing improvement plans consistent with these processes. In June 2021, the NRC began a special inspection to review the root cause of this additional construction remediation work and the corresponding corrective action plans. Findings resulting from this or other inspections could require additional remediation and/or further NRC oversight. In addition, certain license amendment requests have been filed and approved or are pending before the NRC. On March 15, 2021, the NRC denied the Blue Ridge Environmental Defense League's (BREDL) December 2020 motion to reopen proceedings on BREDL's petition challenging a requested license amendment, which has been issued by the NRC staff.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
In September 2020, Southern Nuclear notified the NRC of its intent to load fuel for Unit 3 in 2021. Various design and other licensing-based compliance matters, including the timely submittal by Southern Nuclear of the ITAAC documentation for each unit and the related reviews and approvals by the NRC necessary to support NRC authorization to load fuel, have arisen or may arise, which may result in additional license amendments or require other resolution. If any license amendment requests or other licensing-based compliance issues, including inspections and ITAACs, are not resolved in a timely manner, there may be delays in the project schedule that could result in increased costs.
The ultimate outcome of these matters cannot be determined at this time. However, any extension of the in-service date beyond the second quarter 2022 for Unit 3 or the first quarter 2023 for Unit 4 is currently estimated to result in additional base capital costs for Georgia Power of approximately $25 million per month for Unit 3 and approximately $15 million per month for Unit 4, as well as the related AFUDC. While Georgia Power is not precluded from seeking recovery of any future capital cost forecast increase, management will ultimately determine whether or not to seek recovery. Any further changes to the capital cost forecast that are not expected to be recoverable through regulated rates will be required to be charged to income and such charges could be material.
Joint Owner Contracts
In November 2017, the Vogtle Owners entered into an amendment to their joint ownership agreements for Plant Vogtle Units 3 and 4 to provide for, among other conditions, additional Vogtle Owner approval requirements. Effective in August 2018, the Vogtle Owners further amended the joint ownership agreements to clarify and provide procedures for certain provisions of the joint ownership agreements related to adverse events that require the vote of the holders of at least 90% of the ownership interests in Plant Vogtle Units 3 and 4 to continue construction (as amended, and together with the November 2017 amendment, the Vogtle Joint Ownership Agreements). The Vogtle Joint Ownership Agreements also confirm that the Vogtle Owners' sole recourse against Georgia Power or Southern Nuclear for any action or inaction in connection with their performance as agent for the Vogtle Owners is limited to removal of Georgia Power and/or Southern Nuclear as agent, except in cases of willful misconduct.
As a result of an increase in the total project capital cost forecast and Georgia Power's decision not to seek rate recovery of the increase in the base capital costs in conjunction with the nineteenth VCM report in 2018, the holders of at least 90% of the ownership interests in Plant Vogtle Units 3 and 4 were required to vote to continue construction. In September 2018, the Vogtle Owners unanimously voted to continue construction of Plant Vogtle Units 3 and 4.
Amendments to the Vogtle Joint Ownership Agreements
In connection with the vote to continue construction, Georgia Power entered into (i) a binding term sheet (Vogtle Owner Term Sheet) with the other Vogtle Owners and MEAG Power's wholly-owned subsidiaries MEAG Power SPVJ, LLC (MEAG SPVJ), MEAG Power SPVM, LLC (MEAG SPVM), and MEAG Power SPVP, LLC (MEAG SPVP) to take certain actions which partially mitigate potential financial exposure for the other Vogtle Owners, including additional amendments to the Vogtle Joint Ownership Agreements and the purchase of PTCs from the other Vogtle Owners at pre-established prices, and (ii) a term sheet (MEAG Term Sheet) with MEAG Power and MEAG SPVJ to provide up to $300 million of funding with respect to MEAG SPVJ's ownership interest in Plant Vogtle Units 3 and 4 under certain circumstances. In January 2019, Georgia Power, MEAG Power, and MEAG SPVJ entered into an agreement to implement the provisions of the MEAG Term Sheet. In February 2019, Georgia Power, the other Vogtle Owners, and MEAG Power's wholly-owned subsidiaries MEAG SPVJ, MEAG SPVM, and MEAG SPVP entered into certain amendments to the Vogtle Joint Ownership Agreements to implement the provisions of the Vogtle Owner Term Sheet (Global Amendments).
As previously disclosed, pursuant to the Global Amendments: (i) each Vogtle Owner must pay its proportionate share of qualifying construction costs for Plant Vogtle Units 3 and 4 based on its ownership percentage up to the estimated cost at completion (EAC) for Plant Vogtle Units 3 and 4 which formed the basis of Georgia Power's forecast of $8.4 billion in the nineteenth VCM plus $800 million; (ii) Georgia Power will be responsible for 55.7% of actual qualifying construction costs between $800 million and $1.6 billion over the EAC in the nineteenth VCM
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
(resulting in $80 million of potential additional costs to Georgia Power), with the remaining Vogtle Owners responsible for 44.3% of such costs pro rata in accordance with their respective ownership interests; and (iii) Georgia Power will be responsible for 65.7% of qualifying construction costs between $1.6 billion and $2.1 billion over the EAC in the nineteenth VCM (resulting in a further $100 million of potential additional costs to Georgia Power), with the remaining Vogtle Owners responsible for 34.3% of such costs pro rata in accordance with their respective ownership interests. If the EAC is revised and exceeds the EAC in the nineteenth VCM by more than $2.1 billion, each of the other Vogtle Owners will have a one-time option at the time the project budget forecast is so revised to tender a portion of its ownership interest to Georgia Power in exchange for Georgia Power's agreement to pay 100% of such Vogtle Owner's remaining share of total construction costs in excess of the EAC in the nineteenth VCM plus $2.1 billion.
In addition, pursuant to the Global Amendments, the holders of at least 90% of the ownership interests in Plant Vogtle Units 3 and 4 must vote to continue construction if certain adverse events occur, including, among other events: (i) the bankruptcy of Toshiba; (ii) the termination or rejection in bankruptcy of certain agreements, including the Vogtle Services Agreement, the Bechtel Agreement, or the agency agreement with Southern Nuclear; (iii) Georgia Power's public announcement of its intention not to submit for rate recovery any portion of its investment in Plant Vogtle Units 3 and 4 or the Georgia PSC determines that any of Georgia Power's costs relating to the construction of Plant Vogtle Units 3 and 4 will not be recovered in retail rates, excluding any additional amounts paid by Georgia Power on behalf of the other Vogtle Owners pursuant to the Global Amendments described above and the first 6% of costs during any six-month VCM reporting period that are disallowed by the Georgia PSC for recovery, or for which Georgia Power elects not to seek cost recovery, through retail rates; and (iv) an incremental extension of one year or more over the most recently approved schedule.
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, 2021, Georgia Power had recovered approximately $2.6 billion of financing costs. Financing costs related to capital costs above $4.418 billion are being recognized through AFUDC and are expected to be recovered through retail rates over the life of Plant Vogtle Units 3 and 4; however, Georgia Power will not record AFUDC related to any capital costs in excess of the total deemed reasonable by the Georgia PSC (currently $7.3 billion) and not requested for rate recovery. In November 2020, the Georgia PSC approved Georgia Power's request to decrease the NCCR tariff by $142 million annually, effective January 1, 2021.
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
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
be reasonable and prudent with the burden of proof on any party challenging such costs, (b) Georgia Power would have the burden to show that any capital costs above $5.68 billion were prudent, and (c) a revised capital cost forecast of $7.3 billion (after reflecting the impact of payments received under the Guarantee Settlement Agreement and related customer refunds) was found reasonable; (iv) construction of Plant Vogtle Units 3 and 4 should be completed, with Southern Nuclear serving as project manager and Bechtel as primary contractor; (v) approved and deemed reasonable Georgia Power's revised schedule placing Plant Vogtle Units 3 and 4 in service in November 2021 and November 2022, respectively; (vi) confirmed that the revised cost forecast does not represent a cost cap and that a prudence proceeding on cost recovery will occur following Unit 4 fuel load, consistent with applicable Georgia law; (vii) reduced the ROE used to calculate the NCCR tariff (a) from 10.95% (the ROE rate setting point authorized by the Georgia PSC in the 2013 alternate rate plan) to 10.00% effective January 1, 2016, (b) from 10.00% to 8.30%, effective January 1, 2020, and (c) from 8.30% to 5.30%, effective January 1, 2021 (provided that the ROE in no case will be less than Georgia Power's average cost of long-term debt); (viii) reduced the ROE used for AFUDC equity for Plant Vogtle Units 3 and 4 from 10.00% to Georgia Power's average cost of long-term debt, effective January 1, 2018; and (ix) agreed that upon Unit 3 reaching commercial operation, retail base rates would be adjusted to include the costs related to Unit 3 and common facilities deemed prudent in the Vogtle Cost Settlement Agreement. The January 11, 2018 order also stated that if Plant Vogtle Units 3 and 4 are not commercially operational by June 1, 2021 and June 1, 2022, respectively, the ROE used to calculate the NCCR tariff will be further reduced by 10 basis points each month (but not lower than Georgia Power's average cost of long-term debt) until the respective Unit is commercially operational. The ROE reductions negatively impacted earnings by approximately $150 million in 2020 and are estimated to have negative earnings impacts of approximately $270 million, $270 million, and $90 million in 2021, 2022, and 2023, respectively. In its January 11, 2018 order, the Georgia PSC also stated if other conditions change and assumptions upon which Georgia Power's seventeenth VCM report are based do not materialize, the Georgia PSC reserved the right to reconsider the decision to continue construction.
The Georgia PSC has approved 23 VCM reports covering periods through June 30, 2020 and is scheduled to vote on the twenty-fourth VCM report in August 2021, including total construction capital costs incurred through December 31, 2020 of $8.7 billion (before $1.7 billion of payments received under the Guarantee Settlement Agreement and approximately $188 million in related customer refunds). On July 28, 2021, Georgia Power and the staff of the Georgia PSC reached a stipulated agreement providing for approval of the twenty-fourth VCM report as well as a change to future VCM proceedings. Beginning with its twenty-fifth VCM report, which Georgia Power expects to file with the Georgia PSC by August 31, 2021, Georgia Power will continue to report to the Georgia PSC all costs incurred during the period for review and will include a request for approval of costs up to the $7.3 billion determined to be reasonable in the Georgia PSC's seventeenth VCM order. Under the stipulation, Georgia Power will not seek verification or approval of costs above $7.3 billion prior to the Georgia PSC's prudence review contemplated by the seventeenth VCM order. The twenty-fifth VCM report will reflect the revised capital cost forecast discussed above. See "Plant Vogtle Unit 3 and Common Facilities Rate Proceeding" herein for information on Georgia Power's request to adjust retail base rates to include a portion of costs related to its investment in Plant Vogtle Unit 3 and Common Facilities.
The ultimate outcome of these matters cannot be determined at this time.
Mississippi Power
Performance Evaluation Plan
On June 8, 2021, the Mississippi PSC approved Mississippi Power's annual retail PEP filing for 2021, resulting in an annual increase in revenues of approximately $16 million, or 1.8%, which became effective with the first billing cycle of April 2021 in accordance with the PEP rate schedule.
Integrated Resource Plan
In December 2020, the Mississippi PSC issued an order in the Reserve Margin Plan docket requiring Mississippi Power to incorporate into its 2021 IRP a schedule reflecting the retirement of 950 MWs of fossil-steam generation
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
by year-end 2027 to reduce Mississippi Power's excess reserve margin. On April 15, 2021, Mississippi Power filed its 2021 IRP with the Mississippi PSC. The filing includes a schedule to retire Plant Watson Unit 4 (268 MWs) and Mississippi Power's 40% ownership interest in Plant Greene County Units 1 and 2 (103 MWs each) in December 2023, 2025, and 2026, respectively, consistent with each unit's remaining useful life in the most recent approved depreciation studies. In addition, the schedule reflects the early retirement of Mississippi Power's 50% undivided ownership interest in Plant Daniel Units 1 and 2 (502 MWs) by the end of 2027. The Plant Greene County unit retirements require the completion by Alabama Power of transmission and system reliability improvements, as well as agreement by Alabama Power.
The remaining net book value of Plant Daniel Units 1 and 2 was approximately $522 million at June 30, 2021. Mississippi Power expects to reclassify the net book value remaining at retirement to a regulatory asset to be amortized over a period to be determined by the Mississippi PSC in future proceedings, consistent with the December 2020 order. The Plant Watson and Greene County units are expected to be fully depreciated upon retirement.
The 2021 IRP is subject to a review period during which the Mississippi PSC may note any deficiencies which could require re-evaluation or resubmission of the IRP. If no deficiencies are noted, the Mississippi PSC's review will conclude on August 13, 2021.
The ultimate outcome of this matter cannot be determined at this time.
Environmental Compliance Overview Plan
On June 8, 2021, the Mississippi PSC approved Mississippi Power's ECO Plan filing for 2021, resulting in an annual decrease in revenues of approximately $9 million, primarily due to a change in the amortization periods of certain regulatory assets and liabilities. The rate decrease became effective with the first billing cycle of July 2021.
Ad Valorem Tax Adjustment
On April 6, 2021, the Mississippi PSC approved Mississippi Power's annual ad valorem tax adjustment filing for 2021, which requested an annual increase in revenues of approximately $28 million, including approximately $19 million of ad valorem taxes previously recovered through PEP in accordance with the Mississippi Power Rate Case Settlement Agreement. The rate increase became effective with the first billing cycle of May 2021.
Southern Company Gas
Infrastructure Replacement Programs and Capital Projects
Capital expenditures incurred under specific infrastructure replacement programs during the first six months of 2021 were as follows:
|
|
|
|
|
|
|
|
|
|
|
Utility
|
Program
|
Six Months Ended June 30, 2021
|
|
|
|
(in millions)
|
|
Nicor Gas
|
Investing in Illinois
|
$
|
179
|
|
|
Virginia Natural Gas
|
Steps to Advance Virginia's Energy
|
22
|
|
|
Total
|
|
$
|
201
|
|
Atlanta Gas Light
On April 28, 2021, Atlanta Gas Light filed its first Integrated Capacity and Delivery Plan (i-CDP) with the Georgia PSC, which includes a series of ongoing and proposed pipeline safety, reliability, and growth programs for the next 10 years (2022 through 2031), as well as the required capital investments and related costs to implement the programs. The i-CDP reflects capital investments totaling approximately $0.5 billion to $0.6 billion annually.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
Recovery of the related revenue requirements will be included in either subsequent annual GRAM filings or the new System Reinforcement Rider for authorized large pressure improvement and system reliability projects. The Georgia PSC is scheduled to vote on this matter in November 2021. The ultimate outcome of this matter cannot be determined at this time.
Virginia Natural Gas
On April 6, 2021, the Virginia Commission approved a motion filed by Virginia Natural Gas to withdraw the application for its 9.5-mile interconnect project due to a change in the capacity needs of one of the project's customers. No further action is necessary and this matter is now concluded.
Rate Proceedings
Virginia Natural Gas
On May 10, 2021, Virginia Natural Gas, the Virginia Commission staff, and other intervenors entered into a stipulation agreement related to Virginia Natural Gas' June 2020 general rate case filing, which allows for a $43 million increase in annual base rate revenues, including $14 million related to the recovery of investments under the SAVE program, based on a ROE of 9.5% and an equity ratio of 51.9%. On July 8, 2021, the hearing examiner issued a report recommending adoption of the stipulation agreement. The Virginia Commission is expected to rule on this matter by September 2021. Interim rate adjustments became effective as of November 1, 2020, subject to refund, based on Virginia Natural Gas' original request for an increase of approximately $50 million. The ultimate outcome of this matter cannot be determined at this time.
Atlanta Gas Light
On July 21, 2021, Atlanta Gas Light filed its annual GRAM filing with the Georgia PSC. The filing requests an annual base rate increase of $49 million based on the projected 12-month period beginning January 1, 2022. The proposed rate increase may be updated pending the resolution of Atlanta Gas Light's i-CDP filing. Resolution of the GRAM filing is expected by December 31, 2021, with the new rates to become effective January 1, 2022. The ultimate outcome of this matter cannot be determined at this time. See "Infrastructure Replacement Programs and Capital Projects – Atlanta Gas Light" herein for additional information.
Deferral of Incremental COVID-19 Costs
Nicor Gas
On March 18, 2021, the Illinois Commission approved a phased-in schedule for disconnections related to non-payment. Nicor Gas began certain disconnections in late April 2021 and resumed normal disconnections in June 2021. Nicor Gas will continue certain flexible credit and collection procedures through the third quarter 2021.
(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.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
Southern Company
In February 2017, Jean Vineyard and Judy Mesirov each filed a shareholder derivative lawsuit in the U.S. District Court for the Northern District of Georgia. Each of these lawsuits names as defendants Southern Company, certain of its directors, certain of its current and former officers, and certain former Mississippi Power officers. In 2017, these two shareholder derivative lawsuits were consolidated in the U.S. District Court for the Northern District of Georgia. The complaints allege that the defendants caused Southern Company to make false or misleading statements regarding the Kemper County energy facility cost and schedule. Further, the complaints allege that the defendants were unjustly enriched and caused the waste of corporate assets and also allege that the individual defendants violated their fiduciary duties.
In May 2017, Helen E. Piper Survivor's Trust filed a shareholder derivative lawsuit in the Superior Court of Gwinnett County, Georgia that names as defendants Southern Company, certain of its directors, certain of its current and former officers, and certain former Mississippi Power officers. The complaint alleges that the individual defendants, among other things, breached their fiduciary duties in connection with schedule delays and cost overruns associated with the construction of the Kemper County energy facility. The complaint further alleges that the individual defendants authorized or failed to correct false and misleading statements regarding the Kemper County energy facility schedule and cost and failed to implement necessary internal controls to prevent harm to Southern Company. In August 2019, the court granted a motion filed by the plaintiff in July 2019 to substitute a new named plaintiff, Martin J. Kobuck, in place of Helen E. Piper Survivor's Trust.
The plaintiffs in each of these cases seek to recover, on behalf of Southern Company, unspecified actual damages and, on each plaintiff's own behalf, attorneys' fees and costs in bringing the lawsuit. The plaintiffs also seek certain changes to Southern Company's corporate governance and internal processes. In 2018, the court in each case entered an order staying each lawsuit until 30 days after the settlement of a securities class action filed in January 2017 against Southern Company, certain of its current and former officers, and certain former Mississippi Power officers. In September 2020, the plaintiffs in each case filed a status report noting the settlement of the securities class action and informing the court that the parties had scheduled mediation, which occurred in November 2020. The parties in each case did not reach settlement but continue to explore possible resolution. Each case is stayed while the parties discuss potential resolution.
Georgia Power
In 2011, plaintiffs filed a putative class action against Georgia Power in the Superior Court of Fulton County, Georgia alleging that Georgia Power's collection in rates of amounts for municipal franchise fees (which fees are paid to municipalities) exceeded the amounts allowed in orders of the Georgia PSC and alleging certain state law claims. This case has been ruled upon and appealed numerous times over the last several years. In one recent appeal, the Georgia Supreme Court remanded the case and noted that the trial court could refer the matter to the Georgia PSC to interpret its tariffs. Following a motion by Georgia Power, in February 2019, the Superior Court of Fulton County ordered the parties to submit petitions to the Georgia PSC for a declaratory ruling and also conditionally certified the proposed class. In March 2019, Georgia Power and the plaintiffs filed petitions with the Georgia PSC seeking confirmation of the proper application of the municipal franchise fee schedule pursuant to the Georgia PSC's orders. Also in March 2019, Georgia Power appealed the class certification decision to the Georgia Court of Appeals. In October 2019, the Georgia PSC issued an order that found Georgia Power has appropriately implemented the municipal franchise fee schedule. In March 2020, the Georgia Court of Appeals vacated the Superior Court of Fulton County's February 2019 order granting conditional class certification and remanded the case to the Superior Court of Fulton County for further proceedings. In September 2020, the plaintiffs and Georgia Power each filed motions for summary judgment and the plaintiffs renewed their motion for class certification. On March 16, 2021, the Superior Court of Fulton County granted class certification and Georgia Power's motion for summary judgment. On March 22, 2021, the plaintiffs filed a notice of appeal, and, on April 2, 2021, Georgia Power filed a notice of cross appeal on the issue of class certification. The amount of any possible losses cannot be estimated at this time because, among other factors, it is unknown whether any losses would be subject to recovery from any municipalities.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
In July 2020, a group of individual plaintiffs filed a complaint in the Superior Court of Fulton County, Georgia against Georgia Power alleging that releases from Plant Scherer have impacted groundwater, surface water, 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 September 2020, Georgia Power filed a motion to dismiss. The amount of any possible losses 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. Mississippi Power received Mississippi PSC approval in 2013 to charge a mirror CWIP rate premised upon including in its rate base pre-construction and construction costs for the Kemper IGCC prior to placing the Kemper IGCC into service. The Mississippi Supreme Court reversed that approval and ordered Mississippi Power to refund the amounts paid by customers under the previously-approved mirror CWIP rate. The plaintiffs allege that the initial approval process, and the amount approved, were improper. They also allege that Mississippi Power underpaid customers by up to $23.5 million in the refund process by applying an incorrect interest rate. The plaintiffs seek to recover, on behalf of themselves and their putative class, actual damages, punitive damages, pre-judgment interest, post-judgment interest, attorney's fees, and costs. In response to Mississippi Power and the Mississippi PSC each filing a motion to dismiss, the plaintiffs filed an amended complaint in March 2019. The amended complaint included four additional plaintiffs and additional claims for gross negligence, reckless conduct, and intentional wrongdoing. Mississippi Power and the Mississippi PSC each filed a motion to dismiss the amended complaint, which occurred in May 2020 and March 2020, respectively. Also 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 court denied each of the plaintiffs' pending motions and entered final judgment in favor of Mississippi Power. On January 22, 2021, the court denied further motions by the plaintiffs to vacate the judgment and to file a revised second amended complaint. On February 19, 2021, 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.
See Note 3 to the financial statements under "Other Matters – Mississippi Power – Kemper County Energy Facility" in Item 8 of the Form 10-K for additional information.
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 $15 million at both June 30, 2021 and December 31, 2020. 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.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
Southern Company Gas' environmental remediation liability was $247 million and $245 million at June 30, 2021 and December 31, 2020, respectively, based on the estimated cost of environmental investigation and remediation associated with known former manufactured gas plant operating sites.
The ultimate outcome of these matters cannot be determined at this time; however, as a result of the regulatory treatment for environmental remediation expenses described above, the final disposition of these matters is not expected to have a material impact on the financial statements of the applicable Registrants.
Other Matters
Southern Company Gas
PennEast Pipeline Project
Work continues with state and federal agencies to obtain the required permits to begin construction of the PennEast Pipeline. On June 29, 2021, the U.S. Supreme Court ruled in favor of PennEast Pipeline regarding its federal eminent domain authority over lands in which a state has property rights interests.
Southern Company Gas tests its equity method investments for impairment whenever events or changes in circumstances indicate that the investment may be impaired. Following the U.S. Supreme Court ruling, during the second quarter 2021, Southern Company Gas management reassessed the project construction timing, including the anticipated timing for receipt of the FERC certificate and all remaining state and local permits for both Phase 1 (the construction of 68 miles of pipe entirely within Pennsylvania) and Phase 2 (the construction of the remaining 50 miles in Pennsylvania and New Jersey), as well as potential challenges thereto, and performed an impairment analysis. The outcome of the analysis resulted in a pre-tax impairment charge of $82 million ($58 million after tax). The ultimate outcome of the PennEast Pipeline construction project cannot be determined at this time. See Note (E) under "Southern Company Gas" for additional information.
SNG
As a 50% equity investor in SNG, Southern Company Gas is required to make additional capital contributions as necessary pursuant to the terms of its operating agreement with SNG. Southern Company Gas previously committed to fund up to $150 million as a contingent capital contribution if SNG was unable to refinance or otherwise satisfy $300 million of debt maturing in June 2021. On April 29, 2021, SNG successfully refinanced the debt obligation. See Note (E) under "Southern Company Gas" for additional information.
(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.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
The following table disaggregates revenue from contracts with customers for the three and six months ended June 30, 2021 and 2020:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Southern Company
|
Alabama Power
|
Georgia Power
|
Mississippi Power
|
Southern Power
|
Southern Company Gas
|
|
|
(in millions)
|
|
Three Months Ended June 30, 2021
|
|
|
|
|
|
|
|
Operating revenues
|
|
|
|
|
|
|
|
Retail electric revenues
|
|
|
|
|
|
|
|
Residential
|
$
|
1,469
|
|
$
|
553
|
|
$
|
852
|
|
$
|
64
|
|
$
|
—
|
|
$
|
—
|
|
|
Commercial
|
1,176
|
|
386
|
|
724
|
|
66
|
|
—
|
|
—
|
|
|
Industrial
|
728
|
|
334
|
|
321
|
|
73
|
|
—
|
|
—
|
|
|
Other
|
23
|
|
4
|
|
17
|
|
2
|
|
—
|
|
—
|
|
|
Total retail electric revenues
|
3,396
|
|
1,277
|
|
1,914
|
|
205
|
|
—
|
|
—
|
|
|
Natural gas distribution revenues
|
|
|
|
|
|
|
|
Residential
|
311
|
|
—
|
|
—
|
|
—
|
|
—
|
|
311
|
|
|
Commercial
|
73
|
|
—
|
|
—
|
|
—
|
|
—
|
|
73
|
|
|
Transportation
|
247
|
|
—
|
|
—
|
|
—
|
|
—
|
|
247
|
|
|
Industrial
|
8
|
|
—
|
|
—
|
|
—
|
|
—
|
|
8
|
|
|
Other
|
59
|
|
—
|
|
—
|
|
—
|
|
—
|
|
59
|
|
|
Total natural gas distribution revenues
|
698
|
|
—
|
|
—
|
|
—
|
|
—
|
|
698
|
|
|
Wholesale electric revenues
|
|
|
|
|
|
|
|
PPA energy revenues
|
209
|
|
38
|
|
16
|
|
2
|
|
158
|
|
—
|
|
|
PPA capacity revenues
|
118
|
|
29
|
|
14
|
|
1
|
|
75
|
|
—
|
|
|
Non-PPA revenues
|
55
|
|
25
|
|
3
|
|
75
|
|
78
|
|
—
|
|
|
Total wholesale electric revenues
|
382
|
|
92
|
|
33
|
|
78
|
|
311
|
|
—
|
|
|
Other natural gas revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Wholesale gas services
|
578
|
|
—
|
|
—
|
|
—
|
|
—
|
|
578
|
|
|
Gas marketing services
|
63
|
|
—
|
|
—
|
|
—
|
|
—
|
|
63
|
|
|
Other natural gas revenues
|
10
|
|
—
|
|
—
|
|
—
|
|
—
|
|
10
|
|
|
Total natural gas revenues
|
651
|
|
—
|
|
—
|
|
—
|
|
—
|
|
651
|
|
|
Other revenues
|
295
|
|
52
|
|
137
|
|
7
|
|
5
|
|
—
|
|
|
Total revenue from contracts with customers
|
5,422
|
|
1,421
|
|
2,084
|
|
290
|
|
316
|
|
1,349
|
|
|
Other revenue sources(a)
|
1,179
|
|
135
|
|
141
|
|
13
|
|
174
|
|
731
|
|
|
Other adjustments(b)
|
(1,403)
|
|
—
|
|
—
|
|
—
|
|
—
|
|
(1,403)
|
|
|
Total operating revenues
|
$
|
5,198
|
|
$
|
1,556
|
|
$
|
2,225
|
|
$
|
303
|
|
$
|
490
|
|
$
|
677
|
|
|
|
|
|
|
|
|
|
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, 2021
|
|
|
|
|
|
|
|
Operating revenues
|
|
|
|
|
|
|
|
Retail electric revenues
|
|
|
|
|
|
|
|
Residential
|
$
|
2,936
|
|
$
|
1,181
|
|
$
|
1,627
|
|
$
|
128
|
|
$
|
—
|
|
$
|
—
|
|
|
Commercial
|
2,294
|
|
758
|
|
1,410
|
|
126
|
|
—
|
|
—
|
|
|
Industrial
|
1,397
|
|
654
|
|
606
|
|
137
|
|
—
|
|
—
|
|
|
Other
|
47
|
|
9
|
|
34
|
|
4
|
|
—
|
|
—
|
|
|
Total retail electric revenues
|
6,674
|
|
2,602
|
|
3,677
|
|
395
|
|
—
|
|
—
|
|
|
Natural gas distribution revenues
|
|
|
|
|
|
|
|
Residential
|
925
|
|
—
|
|
—
|
|
—
|
|
—
|
|
925
|
|
|
Commercial
|
243
|
|
—
|
|
—
|
|
—
|
|
—
|
|
243
|
|
|
Transportation
|
536
|
|
—
|
|
—
|
|
—
|
|
—
|
|
536
|
|
|
Industrial
|
24
|
|
—
|
|
—
|
|
—
|
|
—
|
|
24
|
|
|
Other
|
155
|
|
—
|
|
—
|
|
—
|
|
—
|
|
155
|
|
|
Total natural gas distribution revenues
|
1,883
|
|
—
|
|
—
|
|
—
|
|
—
|
|
1,883
|
|
|
Wholesale electric revenues
|
|
|
|
|
|
|
|
PPA energy revenues
|
422
|
|
81
|
|
30
|
|
7
|
|
313
|
|
—
|
|
|
PPA capacity revenues
|
237
|
|
58
|
|
27
|
|
4
|
|
150
|
|
—
|
|
|
Non-PPA revenues
|
119
|
|
57
|
|
12
|
|
162
|
|
139
|
|
—
|
|
|
Total wholesale electric revenues
|
778
|
|
196
|
|
69
|
|
173
|
|
602
|
|
—
|
|
|
Other natural gas revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Wholesale gas services
|
2,168
|
|
—
|
|
—
|
|
—
|
|
—
|
|
2,168
|
|
|
Gas marketing services
|
257
|
|
—
|
|
—
|
|
—
|
|
—
|
|
257
|
|
|
Other natural gas revenues
|
17
|
|
—
|
|
—
|
|
—
|
|
—
|
|
17
|
|
|
Total natural gas revenues
|
2,442
|
|
—
|
|
—
|
|
—
|
|
—
|
|
2,442
|
|
|
Other revenues
|
542
|
|
97
|
|
249
|
|
14
|
|
9
|
|
—
|
|
|
Total revenue from contracts with customers
|
12,319
|
|
2,895
|
|
3,995
|
|
582
|
|
611
|
|
4,325
|
|
|
Other revenue sources(a)
|
2,488
|
|
220
|
|
200
|
|
28
|
|
319
|
|
1,745
|
|
|
Other adjustments(b)
|
(3,699)
|
|
—
|
|
—
|
|
—
|
|
—
|
|
(3,699)
|
|
|
Total operating revenues
|
$
|
11,108
|
|
$
|
3,115
|
|
$
|
4,195
|
|
$
|
610
|
|
$
|
930
|
|
$
|
2,371
|
|
|
|
|
|
|
|
|
|
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, 2020
|
|
|
|
|
|
|
|
Operating revenues
|
|
|
|
|
|
|
|
Retail electric revenues
|
|
|
|
|
|
|
|
Residential
|
$
|
1,430
|
|
$
|
549
|
|
$
|
817
|
|
$
|
64
|
|
$
|
—
|
|
$
|
—
|
|
|
Commercial
|
1,103
|
|
353
|
|
689
|
|
61
|
|
—
|
|
—
|
|
|
Industrial
|
642
|
|
302
|
|
273
|
|
67
|
|
—
|
|
—
|
|
|
Other
|
23
|
|
6
|
|
15
|
|
2
|
|
—
|
|
—
|
|
|
Total retail electric revenues
|
3,198
|
|
1,210
|
|
1,794
|
|
194
|
|
—
|
|
—
|
|
|
Natural gas distribution revenues
|
|
|
|
|
|
|
|
Residential
|
239
|
|
—
|
|
—
|
|
—
|
|
—
|
|
239
|
|
|
Commercial
|
58
|
|
—
|
|
—
|
|
—
|
|
—
|
|
58
|
|
|
Transportation
|
234
|
|
—
|
|
—
|
|
—
|
|
—
|
|
234
|
|
|
Industrial
|
5
|
|
—
|
|
—
|
|
—
|
|
—
|
|
5
|
|
|
Other
|
49
|
|
—
|
|
—
|
|
—
|
|
—
|
|
49
|
|
|
Total natural gas distribution revenues
|
585
|
|
—
|
|
—
|
|
—
|
|
—
|
|
585
|
|
|
Wholesale electric revenues
|
|
|
|
|
|
|
|
PPA energy revenues
|
167
|
|
28
|
|
7
|
|
2
|
|
134
|
|
—
|
|
|
PPA capacity revenues
|
108
|
|
25
|
|
13
|
|
1
|
|
71
|
|
—
|
|
|
Non-PPA revenues
|
50
|
|
5
|
|
2
|
|
73
|
|
59
|
|
—
|
|
|
Total wholesale electric revenues
|
325
|
|
58
|
|
22
|
|
76
|
|
264
|
|
—
|
|
|
Other natural gas revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Wholesale gas services
|
341
|
|
—
|
|
—
|
|
—
|
|
—
|
|
341
|
|
|
Gas marketing services
|
57
|
|
—
|
|
—
|
|
—
|
|
—
|
|
57
|
|
|
Other natural gas revenues
|
8
|
|
—
|
|
—
|
|
—
|
|
—
|
|
8
|
|
|
Total natural gas revenues
|
406
|
|
—
|
|
—
|
|
—
|
|
—
|
|
406
|
|
|
Other revenues
|
251
|
|
44
|
|
119
|
|
6
|
|
4
|
|
—
|
|
|
Total revenue from contracts with customers
|
4,765
|
|
1,312
|
|
1,935
|
|
276
|
|
268
|
|
991
|
|
|
Other revenue sources(a)
|
728
|
|
53
|
|
(7)
|
|
7
|
|
171
|
|
518
|
|
|
Other adjustments(b)
|
(873)
|
|
—
|
|
—
|
|
—
|
|
—
|
|
(873)
|
|
|
Total operating revenues
|
$
|
4,620
|
|
$
|
1,365
|
|
$
|
1,928
|
|
$
|
283
|
|
$
|
439
|
|
$
|
636
|
|
|
|
|
|
|
|
|
|
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, 2020
|
|
|
|
|
|
|
|
Operating revenues
|
|
|
|
|
|
|
|
Retail electric revenues
|
|
|
|
|
|
|
|
Residential
|
$
|
2,801
|
|
$
|
1,103
|
|
$
|
1,577
|
|
$
|
121
|
|
$
|
—
|
|
$
|
—
|
|
|
Commercial
|
2,247
|
|
717
|
|
1,409
|
|
121
|
|
—
|
|
—
|
|
|
Industrial
|
1,323
|
|
623
|
|
555
|
|
145
|
|
—
|
|
—
|
|
|
Other
|
46
|
|
11
|
|
31
|
|
4
|
|
—
|
|
—
|
|
|
Total retail electric revenues
|
6,417
|
|
2,454
|
|
3,572
|
|
391
|
|
—
|
|
—
|
|
|
Natural gas distribution revenues
|
|
|
|
|
|
|
|
Residential
|
736
|
|
—
|
|
—
|
|
—
|
|
—
|
|
736
|
|
|
Commercial
|
188
|
|
—
|
|
—
|
|
—
|
|
—
|
|
188
|
|
|
Transportation
|
499
|
|
—
|
|
—
|
|
—
|
|
—
|
|
499
|
|
|
Industrial
|
17
|
|
—
|
|
—
|
|
—
|
|
—
|
|
17
|
|
|
Other
|
144
|
|
—
|
|
—
|
|
—
|
|
—
|
|
144
|
|
|
Total natural gas distribution revenues
|
1,584
|
|
—
|
|
—
|
|
—
|
|
—
|
|
1,584
|
|
|
Wholesale electric revenues
|
|
|
|
|
|
|
|
PPA energy revenues
|
326
|
|
55
|
|
15
|
|
4
|
|
259
|
|
—
|
|
|
PPA capacity revenues
|
213
|
|
52
|
|
25
|
|
2
|
|
136
|
|
—
|
|
|
Non-PPA revenues
|
100
|
|
24
|
|
4
|
|
142
|
|
117
|
|
—
|
|
|
Total wholesale electric revenues
|
639
|
|
131
|
|
44
|
|
148
|
|
512
|
|
—
|
|
|
Other natural gas revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Wholesale gas services
|
737
|
|
—
|
|
—
|
|
—
|
|
—
|
|
737
|
|
|
Gas marketing services
|
220
|
|
—
|
|
—
|
|
—
|
|
—
|
|
220
|
|
|
Other natural gas revenues
|
15
|
|
—
|
|
—
|
|
—
|
|
—
|
|
15
|
|
|
Total natural gas revenues
|
972
|
|
—
|
|
—
|
|
—
|
|
—
|
|
972
|
|
|
Other revenues
|
441
|
|
78
|
|
214
|
|
13
|
|
7
|
|
—
|
|
|
Total revenue from contracts with customers
|
10,053
|
|
2,663
|
|
3,830
|
|
552
|
|
519
|
|
2,556
|
|
|
Other revenue sources(a)
|
1,599
|
|
53
|
|
(76)
|
|
7
|
|
295
|
|
1,343
|
|
|
Other adjustments(b)
|
(2,014)
|
|
—
|
|
—
|
|
—
|
|
—
|
|
(2,014)
|
|
|
Total operating revenues
|
$
|
9,638
|
|
$
|
2,716
|
|
$
|
3,754
|
|
$
|
559
|
|
$
|
814
|
|
$
|
1,885
|
|
(a)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.
(b)Other adjustments relate to the cost of Southern Company Gas' energy and risk management activities. Wholesale gas services revenues are presented net of the related costs of those activities on the statement of income. See Notes (K) and (L) under "Southern Company Gas" for information on the sale of Sequent and components of wholesale gas services' operating revenues, respectively.
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, 2021 and December 31, 2020:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Southern Company
|
Alabama Power
|
Georgia Power
|
Mississippi Power
|
Southern Power
|
Southern Company Gas
|
|
|
(in millions)
|
|
Accounts Receivable
|
|
|
|
|
|
|
|
At June 30, 2021
|
$
|
2,271
|
|
$
|
633
|
|
$
|
887
|
|
$
|
85
|
|
$
|
129
|
|
$
|
368
|
|
|
At December 31, 2020
|
2,614
|
|
632
|
|
806
|
|
77
|
|
112
|
|
788
|
|
|
Contract Assets
|
|
|
|
|
|
|
|
At June 30, 2021
|
$
|
98
|
|
$
|
—
|
|
$
|
36
|
|
$
|
—
|
|
$
|
1
|
|
$
|
—
|
|
|
At December 31, 2020
|
158
|
|
2
|
|
71
|
|
—
|
|
—
|
|
—
|
|
|
Contract Liabilities
|
|
|
|
|
|
|
|
At June 30, 2021
|
$
|
67
|
|
$
|
5
|
|
$
|
37
|
|
$
|
1
|
|
$
|
1
|
|
$
|
—
|
|
|
At December 31, 2020
|
61
|
|
6
|
|
27
|
|
1
|
|
1
|
|
1
|
|
At June 30, 2021 and December 31, 2020, Georgia Power had contract assets primarily related to unregulated service agreements, where payment is contingent on project completion, as well as, at December 31, 2020, contract assets related to fixed retail customer 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. Contract liabilities for Georgia Power relate to cash collections recognized in advance of revenue for unregulated service agreements. Southern Company's unregulated distributed generation business had $60 million and $81 million of contract assets and $24 million and $27 million of contract liabilities at June 30, 2021 and December 31, 2020, respectively, for outstanding performance obligations.
Revenues recognized by Southern Company in the three and six months ended June 30, 2021, which were included in contract liabilities at December 31, 2020, were $12 million and $21 million, respectively, and immaterial for all other Registrants.
Remaining Performance Obligations
The traditional electric operating companies and Southern Power have long-term contracts with customers in which revenues are recognized as performance obligations are satisfied over the contract term. These contracts primarily relate to PPAs whereby the traditional electric operating companies and Southern Power provide electricity and generation capacity 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. Southern Company's unregulated distributed generation business also has partially satisfied performance obligations related to certain fixed price contracts. Revenues from contracts with customers related to these performance obligations remaining at June 30, 2021 are expected to be recognized as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2021 (remaining)
|
2022
|
2023
|
2024
|
2025
|
Thereafter
|
|
|
(in millions)
|
|
Southern Company
|
$
|
354
|
|
$
|
464
|
|
$
|
343
|
|
$
|
327
|
|
$
|
307
|
|
$
|
2,667
|
|
|
Alabama Power
|
23
|
|
31
|
|
24
|
|
7
|
|
5
|
|
—
|
|
|
Georgia Power
|
41
|
|
58
|
|
39
|
|
23
|
|
21
|
|
41
|
|
|
|
|
|
|
|
|
|
|
Southern Power
|
165
|
|
323
|
|
281
|
|
297
|
|
281
|
|
2,644
|
|
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
Revenue expected to be recognized for performance obligations remaining at June 30, 2021 was immaterial for Mississippi Power and Southern Company Gas.
Lease Income
Lease income for the three and six months ended June 30, 2021 and 2020 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, 2021
|
|
Lease income - interest income on sales-type leases
|
$
|
4
|
|
$
|
—
|
|
$
|
—
|
|
$
|
4
|
|
$
|
—
|
|
$
|
—
|
|
|
Lease income - operating leases
|
56
|
|
21
|
|
10
|
|
—
|
|
21
|
|
9
|
|
|
Variable lease income
|
128
|
|
(1)
|
|
—
|
|
—
|
|
138
|
|
—
|
|
|
Total lease income
|
$
|
188
|
|
$
|
20
|
|
$
|
10
|
|
$
|
4
|
|
$
|
159
|
|
$
|
9
|
|
|
|
|
|
|
|
|
|
|
For the Six Months Ended June 30, 2021
|
|
Lease income - interest income on sales-type leases
|
$
|
7
|
|
$
|
—
|
|
$
|
—
|
|
$
|
7
|
|
$
|
—
|
|
$
|
—
|
|
|
Lease income - operating leases
|
112
|
|
41
|
|
21
|
|
1
|
|
42
|
|
17
|
|
|
Variable lease income
|
212
|
|
—
|
|
—
|
|
—
|
|
228
|
|
—
|
|
|
Total lease income
|
$
|
331
|
|
$
|
41
|
|
$
|
21
|
|
$
|
8
|
|
$
|
270
|
|
$
|
17
|
|
|
|
|
|
|
|
|
|
|
For the Three Months Ended June 30, 2020
|
|
Lease income - interest income on sales-type leases
|
$
|
3
|
|
$
|
—
|
|
$
|
—
|
|
$
|
3
|
|
$
|
—
|
|
$
|
—
|
|
|
Lease income - operating leases
|
47
|
|
6
|
|
15
|
|
—
|
|
21
|
|
9
|
|
|
Variable lease income
|
126
|
|
—
|
|
—
|
|
—
|
|
136
|
|
—
|
|
|
Total lease income
|
$
|
176
|
|
$
|
6
|
|
$
|
15
|
|
$
|
3
|
|
$
|
157
|
|
$
|
9
|
|
|
|
|
|
|
|
|
|
|
For the Six Months Ended June 30, 2020
|
|
Lease income - interest income on sales-type leases
|
$
|
6
|
|
$
|
—
|
|
$
|
—
|
|
$
|
5
|
|
$
|
—
|
|
$
|
—
|
|
|
Lease income - operating leases
|
97
|
|
13
|
|
30
|
|
—
|
|
45
|
|
17
|
|
|
Variable lease income
|
200
|
|
—
|
|
—
|
|
—
|
|
215
|
|
—
|
|
|
Total lease income
|
$
|
303
|
|
$
|
13
|
|
$
|
30
|
|
$
|
5
|
|
$
|
260
|
|
$
|
17
|
|
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.
Lease Receivables
Mississippi Power completed construction of additional leased assets under an existing sales-type lease during the second quarter 2021. Upon completion of construction, the book value of $35 million was transferred from CWIP to lease receivables and is primarily included in other property and investments at June 30, 2021. The transfer represents a noncash investing transaction for purposes of the statements of cash flows.
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 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, 2021 and December 31, 2020, SP Solar had total assets of $6.2 billion and $6.1 billion, respectively, total liabilities of $382 million and $387 million, respectively, and noncontrolling interests of $1.1 billion. 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, 2021 and December 31, 2020, SP Wind had total assets of $2.3 billion and $2.4 billion, respectively, total liabilities of $140 million and $138 million, respectively, and noncontrolling interests of $42 million and $43 million, respectively. 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, 2021 and December 31, 2020, the other VIEs had total assets of $1.9 billion and $1.1 billion, respectively, total liabilities of $249 million and $110 million, respectively, and noncontrolling interests of $913 million and $454 million, respectively. Under the terms of the partnership agreements, distributions of all available cash are required each month or quarter and additional distributions require partner consent.
Equity Method Investments
At June 30, 2021 and December 31, 2020, Southern Power had equity method investments in wind and battery storage projects totaling $84 million and $19 million, respectively.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
Southern Company Gas
Equity Method Investments
The carrying amounts of Southern Company Gas' equity method investments at June 30, 2021 and December 31, 2020 and related earnings (loss) from those investments for the three and six months ended June 30, 2021 and 2020 were as follows:
|
|
|
|
|
|
|
|
|
|
|
Investment Balance
|
June 30, 2021
|
December 31, 2020
|
|
|
(in millions)
|
|
SNG
|
$
|
1,143
|
|
$
|
1,167
|
|
|
PennEast Pipeline(*)
|
13
|
|
91
|
|
|
Other
|
33
|
|
32
|
|
|
Total
|
$
|
1,189
|
|
$
|
1,290
|
|
(*)Investment balance at June 30, 2021 reflects a pre-tax impairment charge of $82 million ($58 million after tax) recorded in the second quarter 2021. See Note (C) under "Other Matters – Southern Company Gas" for additional information.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended June 30,
|
|
Six Months Ended June 30,
|
|
Earnings (Loss) from Equity Method Investments
|
2021
|
2020
|
|
2021
|
2020
|
|
|
(in millions)
|
|
SNG
|
$
|
28
|
|
$
|
28
|
|
|
$
|
66
|
|
$
|
65
|
|
|
PennEast Pipeline(a)(b)
|
(81)
|
|
1
|
|
|
(79)
|
|
3
|
|
|
Other(a)(c)
|
1
|
|
1
|
|
|
2
|
|
4
|
|
|
Total
|
$
|
(52)
|
|
$
|
30
|
|
|
$
|
(11)
|
|
$
|
72
|
|
(a)Earnings primarily result from AFUDC equity recorded by the project entity.
(b)Includes a pre-tax impairment charge of $82 million ($58 million after tax) for the three and six months ended June 30, 2021. See Note (C) under "Other Matters – Southern Company Gas" for additional information.
(c)On March 24, 2020, Southern Company Gas completed the sale of its interests in Atlantic Coast Pipeline and Pivotal LNG. See Note 15 to the financial statements under "Southern Company Gas" in Item 8 of the Form 10-K for additional information.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
(F) FINANCING
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, 2021, committed credit arrangements with banks were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expires
|
|
|
|
|
|
|
|
|
|
Company
|
2021
|
2022
|
2023
|
2024
|
2026
|
|
Total
|
|
Unused
|
|
|
|
|
|
|
|
Due within One Year
|
|
|
(in millions)
|
|
Southern Company parent
|
$
|
—
|
|
$
|
—
|
|
$
|
—
|
|
$
|
—
|
|
$
|
2,000
|
|
|
$
|
2,000
|
|
|
$
|
1,999
|
|
|
|
|
|
|
|
|
$
|
—
|
|
|
Alabama Power
|
3
|
|
525
|
|
—
|
|
—
|
|
700
|
|
|
1,228
|
|
|
1,228
|
|
|
|
|
|
|
|
|
3
|
|
|
Georgia Power
|
—
|
|
—
|
|
—
|
|
—
|
|
1,750
|
|
|
1,750
|
|
|
1,728
|
|
|
|
|
|
|
|
|
—
|
|
|
Mississippi Power
|
—
|
|
—
|
|
125
|
|
150
|
|
—
|
|
|
275
|
|
|
250
|
|
|
|
|
|
|
|
|
—
|
|
|
Southern Power(a)
|
—
|
|
—
|
|
—
|
|
—
|
|
600
|
|
|
600
|
|
|
568
|
|
|
|
|
|
|
|
|
—
|
|
|
Southern Company Gas(b)
|
—
|
|
250
|
|
—
|
|
—
|
|
1,500
|
|
|
1,750
|
|
|
1,747
|
|
|
|
|
|
|
|
|
250
|
|
|
SEGCO
|
—
|
|
30
|
|
—
|
|
—
|
|
—
|
|
|
30
|
|
|
30
|
|
|
|
|
|
|
|
|
30
|
|
|
Southern Company
|
$
|
3
|
|
$
|
805
|
|
$
|
125
|
|
$
|
150
|
|
$
|
6,550
|
|
|
$
|
7,633
|
|
|
$
|
7,550
|
|
|
|
|
|
|
|
|
$
|
283
|
|
(a)Does not include Southern Power Company's $75 million and $60 million continuing letter of credit facilities for standby letters of credit expiring in 2023, of which $23 million and $1 million, respectively, was unused at June 30, 2021. Southern Power's subsidiaries are not parties to its bank credit arrangements or letter of credit facilities.
(b)Southern Company Gas, as the parent entity, guarantees the obligations of Southern Company Gas Capital, which is the borrower of $800 million of the arrangement expiring in 2026 and all $250 million of the arrangement expiring in 2022. Southern Company Gas' committed credit arrangement expiring in 2026 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 2026, the allocations between Southern Company Gas Capital and Nicor Gas may be adjusted.
As reflected in the table above, in May 2021, Southern Company, Alabama Power, Georgia Power, and Southern Power each amended and restated certain of its multi-year credit arrangements, which, among other things, extended the maturity dates from 2024 to 2026. Alabama Power also decreased the borrowing capacity under its credit arrangement now maturing in 2026 from $800 million to $700 million. Also in May 2021, Southern Company Gas Capital, along with Nicor Gas, amended and restated their multi-year credit arrangement to extend the maturity date from 2024 to 2026 and decrease the aggregate borrowing capacity from $1.75 billion to $1.5 billion. In addition, Southern Company Gas Capital entered into a new $250 million credit arrangement, which is guaranteed by Southern Company Gas, that matures in 2022. In June 2021, Mississippi Power amended and restated certain of its multi-year credit arrangements aggregating $150 million, which, among other things, extended the maturity dates from 2022 to 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 or, in the case of Southern Power, cross-default provisions to other indebtedness (including guarantee obligations) that are restricted only to the indebtedness of the individual company. Such cross-default provisions to other indebtedness would trigger an event of default if Southern Power defaulted on indebtedness or guarantee obligations over a specified threshold. Such cross-acceleration 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, 2021, the Registrants, Nicor Gas, and
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
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, 2021 was approximately $1.4 billion (comprised of approximately $854 million at Alabama Power, $550 million at Georgia Power, and $34 million at Mississippi Power). In addition, at June 30, 2021, Georgia Power and Mississippi Power had approximately $105 million and $50 million, respectively, of fixed rate revenue bonds outstanding that are required to be remarketed within the next 12 months.
Earnings per Share
For Southern Company, the only differences in computing basic and diluted earnings per share are attributable to awards outstanding under stock-based compensation plans and the equity units issued in 2019. Earnings per share dilution resulting from stock-based compensation plans and the equity units issuance is determined using the treasury stock method. See Note 8 to the financial statements under "Equity Units" in Item 8 of the Form 10-K for information on the equity units and Note 12 to the financial statements in Item 8 of the Form 10-K for information on stock-based compensation plans. Shares used to compute diluted earnings per share were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended June 30,
|
Six Months Ended June 30,
|
|
|
2021
|
2020
|
2021
|
2020
|
|
|
(in millions)
|
|
As reported shares
|
1,061
|
|
1,058
|
|
1,060
|
|
1,057
|
|
|
Effect of stock-based compensation
|
6
|
|
5
|
|
6
|
|
7
|
|
|
Effect of equity units
|
—
|
|
—
|
|
—
|
|
1
|
|
|
Diluted shares
|
1,067
|
|
1,063
|
|
1,066
|
|
1,065
|
|
For all periods presented, an immaterial number of stock-based compensation awards was not included in the diluted earnings per share calculation because the awards were anti-dilutive
(G) INCOME TAXES
See Note 10 to the financial statements in Item 8 of the Form 10-K for additional tax information.
Current and Deferred Income Taxes
Tax Credit and Net Operating Loss Carryforwards
Southern Company had federal ITC and PTC carryforwards (primarily related to Southern Power) totaling $1.3 billion at June 30, 2021 compared to $1.4 billion at December 31, 2020.
The federal ITC and PTC carryforwards begin expiring in 2034 and 2032, respectively, but are expected to be fully utilized by 2024. 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, the purchase of rights to additional PTCs of Plant Vogtle Units 3 and 4 pursuant to certain joint ownership agreements, 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.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
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.
Georgia Power
Georgia Power's effective tax benefit rate was (6.9)% for the six months ended June 30, 2021 compared to an effective tax rate of 4.0% for the corresponding period in 2020. The effective tax rate decrease was primarily due to higher charges to earnings in 2021 associated with the construction of Plant Vogtle Units 3 and 4. See Note (B) under "Georgia Power – Nuclear Construction" for additional information.
Southern Power
Southern Power's effective tax benefit rate was (12.8)% for the six months ended June 30, 2021 compared to an effective tax rate of 10.5% for the corresponding period in 2020. The effective tax rate decrease was primarily due to changes in state apportionment methodology resulting from tax legislation enacted by the State of Alabama in February 2021, as well as the tax impact from the sale of Plant Mankato in January 2020. See Note 15 to the financial statements under "Southern Power" in Item 8 of the Form 10-K for additional information.
(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, 2021. 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, 2021 and 2020 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, 2021
|
|
|
|
|
|
|
|
|
|
|
|
Pension Plans
|
|
|
|
|
|
|
|
|
|
|
|
|
Service cost
|
$
|
108
|
|
|
$
|
25
|
|
|
$
|
28
|
|
|
$
|
5
|
|
|
$
|
3
|
|
|
$
|
9
|
|
|
Interest cost
|
86
|
|
|
21
|
|
|
26
|
|
|
4
|
|
|
1
|
|
|
6
|
|
|
Expected return on plan assets
|
(297)
|
|
|
(71)
|
|
|
(94)
|
|
|
(13)
|
|
|
(4)
|
|
|
(22)
|
|
|
Amortization:
|
|
|
|
|
|
|
|
|
|
|
|
|
Prior service costs
|
—
|
|
|
—
|
|
|
1
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
Regulatory asset
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
4
|
|
|
Net (gain)/loss
|
79
|
|
|
20
|
|
|
25
|
|
|
3
|
|
|
1
|
|
|
3
|
|
|
Net periodic pension cost (income)
|
$
|
(24)
|
|
|
$
|
(5)
|
|
|
$
|
(14)
|
|
|
$
|
(1)
|
|
|
$
|
1
|
|
|
$
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Postretirement Benefits
|
|
|
|
|
|
|
|
|
|
|
|
|
Service cost
|
$
|
6
|
|
|
$
|
2
|
|
|
$
|
1
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
1
|
|
|
Interest cost
|
9
|
|
|
2
|
|
|
3
|
|
|
1
|
|
|
—
|
|
|
1
|
|
|
Expected return on plan assets
|
(19)
|
|
|
(7)
|
|
|
(6)
|
|
|
(1)
|
|
|
—
|
|
|
(2)
|
|
|
Amortization:
|
|
|
|
|
|
|
|
|
|
|
|
|
Prior service costs
|
(1)
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
Regulatory asset
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1
|
|
|
Net (gain)/loss
|
1
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
Net periodic postretirement benefit cost (income)
|
$
|
(4)
|
|
|
$
|
(3)
|
|
|
$
|
(2)
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
1
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended June 30, 2021
|
|
|
|
|
|
|
|
|
|
|
|
Pension Plans
|
|
Service cost
|
$
|
217
|
|
|
$
|
51
|
|
|
$
|
56
|
|
|
$
|
9
|
|
|
$
|
5
|
|
|
$
|
18
|
|
|
Interest cost
|
173
|
|
|
41
|
|
|
52
|
|
|
8
|
|
|
2
|
|
|
12
|
|
|
Expected return on plan assets
|
(595)
|
|
|
(143)
|
|
|
(188)
|
|
|
(27)
|
|
|
(7)
|
|
|
(43)
|
|
|
Amortization:
|
|
|
|
|
|
|
|
|
|
|
|
|
Prior service costs
|
—
|
|
|
—
|
|
|
1
|
|
|
—
|
|
|
—
|
|
|
(1)
|
|
|
Regulatory asset
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
8
|
|
|
Net (gain)/loss
|
157
|
|
|
41
|
|
|
50
|
|
|
7
|
|
|
2
|
|
|
6
|
|
|
Net periodic pension cost (income)
|
$
|
(48)
|
|
|
$
|
(10)
|
|
|
$
|
(29)
|
|
|
$
|
(3)
|
|
|
$
|
2
|
|
|
$
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Postretirement Benefits
|
|
Service cost
|
$
|
12
|
|
|
$
|
3
|
|
|
$
|
3
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
1
|
|
|
Interest cost
|
17
|
|
|
4
|
|
|
6
|
|
|
1
|
|
|
—
|
|
|
2
|
|
|
Expected return on plan assets
|
(38)
|
|
|
(14)
|
|
|
(13)
|
|
|
(1)
|
|
|
—
|
|
|
(4)
|
|
|
Amortization:
|
|
|
|
|
|
|
|
|
|
|
|
|
Prior service costs
|
(1)
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
Regulatory asset
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
3
|
|
|
Net (gain)/loss
|
2
|
|
|
—
|
|
|
1
|
|
|
—
|
|
|
—
|
|
|
(1)
|
|
|
Net periodic postretirement benefit cost (income)
|
$
|
(8)
|
|
|
$
|
(7)
|
|
|
$
|
(3)
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
1
|
|
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, 2020
|
|
|
|
|
|
|
|
|
|
|
|
Pension Plans
|
|
Service cost
|
$
|
94
|
|
|
$
|
22
|
|
|
$
|
24
|
|
|
$
|
4
|
|
|
$
|
2
|
|
|
$
|
8
|
|
|
Interest cost
|
108
|
|
|
25
|
|
|
34
|
|
|
5
|
|
|
2
|
|
|
7
|
|
|
Expected return on plan assets
|
(275)
|
|
|
(66)
|
|
|
(87)
|
|
|
(12)
|
|
|
(3)
|
|
|
(20)
|
|
|
Amortization:
|
|
|
|
|
|
|
|
|
|
|
|
|
Prior service costs
|
—
|
|
|
—
|
|
|
1
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
Regulatory asset
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
4
|
|
|
Net (gain)/loss
|
67
|
|
|
18
|
|
|
21
|
|
|
3
|
|
|
—
|
|
|
3
|
|
|
Net periodic pension cost (income)
|
$
|
(6)
|
|
|
$
|
(1)
|
|
|
$
|
(7)
|
|
|
$
|
—
|
|
|
$
|
1
|
|
|
$
|
2
|
|
|
Postretirement Benefits
|
|
|
|
|
|
|
|
|
|
|
|
|
Service cost
|
$
|
6
|
|
|
$
|
1
|
|
|
$
|
2
|
|
|
$
|
1
|
|
|
$
|
—
|
|
|
$
|
1
|
|
|
Interest cost
|
14
|
|
|
3
|
|
|
5
|
|
|
1
|
|
|
—
|
|
|
4
|
|
|
Expected return on plan assets
|
(18)
|
|
|
(7)
|
|
|
(6)
|
|
|
(1)
|
|
|
—
|
|
|
(2)
|
|
|
Amortization:
|
|
|
|
|
|
|
|
|
|
|
|
|
Prior service costs
|
(1)
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
Regulatory asset
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1
|
|
|
Net (gain)/loss
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(1)
|
|
|
Net periodic postretirement benefit cost (income)
|
$
|
1
|
|
|
$
|
(3)
|
|
|
$
|
1
|
|
|
$
|
1
|
|
|
$
|
—
|
|
|
$
|
3
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended June 30, 2020
|
|
|
|
|
|
|
|
|
|
|
|
Pension Plans
|
|
Service cost
|
$
|
188
|
|
|
$
|
44
|
|
|
$
|
48
|
|
|
$
|
8
|
|
|
$
|
4
|
|
|
$
|
16
|
|
|
Interest cost
|
216
|
|
|
50
|
|
|
67
|
|
|
10
|
|
|
3
|
|
|
15
|
|
|
Expected return on plan assets
|
(550)
|
|
|
(132)
|
|
|
(174)
|
|
|
(25)
|
|
|
(6)
|
|
|
(39)
|
|
|
Amortization:
|
|
|
|
|
|
|
|
|
|
|
|
|
Prior service costs
|
1
|
|
|
—
|
|
|
1
|
|
|
—
|
|
|
—
|
|
|
(1)
|
|
|
Regulatory asset
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
8
|
|
|
Net (gain)/loss
|
134
|
|
|
36
|
|
|
43
|
|
|
6
|
|
|
1
|
|
|
5
|
|
|
Net periodic pension cost (income)
|
$
|
(11)
|
|
|
$
|
(2)
|
|
|
$
|
(15)
|
|
|
$
|
(1)
|
|
|
$
|
2
|
|
|
$
|
4
|
|
|
Postretirement Benefits
|
|
Service cost
|
$
|
11
|
|
|
$
|
3
|
|
|
$
|
3
|
|
|
$
|
1
|
|
|
$
|
—
|
|
|
$
|
1
|
|
|
Interest cost
|
27
|
|
|
6
|
|
|
10
|
|
|
1
|
|
|
—
|
|
|
6
|
|
|
Expected return on plan assets
|
(36)
|
|
|
(14)
|
|
|
(13)
|
|
|
(1)
|
|
|
—
|
|
|
(4)
|
|
|
Amortization:
|
|
|
|
|
|
|
|
|
|
|
|
|
Prior service costs
|
(1)
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
Regulatory asset
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
3
|
|
|
Net (gain)/loss
|
1
|
|
|
—
|
|
|
1
|
|
|
—
|
|
|
—
|
|
|
(2)
|
|
|
Net periodic postretirement benefit cost (income)
|
$
|
2
|
|
|
$
|
(5)
|
|
|
$
|
1
|
|
|
$
|
1
|
|
|
$
|
—
|
|
|
$
|
4
|
|
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
(I) FAIR VALUE MEASUREMENTS
At June 30, 2021, 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, 2021
|
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)
|
$
|
656
|
|
|
$
|
436
|
|
|
$
|
28
|
|
|
$
|
—
|
|
|
$
|
1,120
|
|
|
Interest rate derivatives
|
—
|
|
|
17
|
|
|
—
|
|
|
—
|
|
|
17
|
|
|
Foreign currency derivatives
|
—
|
|
|
55
|
|
|
—
|
|
|
—
|
|
|
55
|
|
|
Investments in trusts:(b)(c)
|
|
|
|
|
|
|
|
|
|
|
Domestic equity
|
812
|
|
|
236
|
|
|
—
|
|
|
—
|
|
|
1,048
|
|
|
Foreign equity
|
171
|
|
|
191
|
|
|
—
|
|
|
—
|
|
|
362
|
|
|
U.S. Treasury and government agency securities
|
—
|
|
|
311
|
|
|
—
|
|
|
—
|
|
|
311
|
|
|
Municipal bonds
|
—
|
|
|
45
|
|
|
—
|
|
|
—
|
|
|
45
|
|
|
Pooled funds – fixed income
|
—
|
|
|
18
|
|
|
—
|
|
|
—
|
|
|
18
|
|
|
Corporate bonds
|
4
|
|
|
453
|
|
|
—
|
|
|
—
|
|
|
457
|
|
|
Mortgage and asset backed securities
|
—
|
|
|
92
|
|
|
—
|
|
|
—
|
|
|
92
|
|
|
Private equity
|
—
|
|
|
—
|
|
|
—
|
|
|
102
|
|
|
102
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
|
29
|
|
|
23
|
|
|
—
|
|
|
—
|
|
|
52
|
|
|
Cash equivalents
|
1,039
|
|
|
13
|
|
|
—
|
|
|
—
|
|
|
1,052
|
|
|
Other investments
|
9
|
|
|
30
|
|
|
—
|
|
|
—
|
|
|
39
|
|
|
Total
|
$
|
2,720
|
|
|
$
|
1,920
|
|
|
$
|
28
|
|
|
$
|
102
|
|
|
$
|
4,770
|
|
|
Liabilities:
|
|
|
|
|
|
|
|
|
|
|
Energy-related derivatives(a)
|
$
|
664
|
|
|
$
|
333
|
|
|
$
|
10
|
|
|
$
|
—
|
|
|
$
|
1,007
|
|
|
Interest rate derivatives
|
—
|
|
|
9
|
|
|
—
|
|
|
—
|
|
|
9
|
|
|
Foreign currency derivatives
|
—
|
|
|
10
|
|
|
—
|
|
|
—
|
|
|
10
|
|
|
Contingent consideration
|
—
|
|
|
—
|
|
|
16
|
|
|
—
|
|
|
16
|
|
|
Total
|
$
|
664
|
|
|
$
|
352
|
|
|
$
|
26
|
|
|
$
|
—
|
|
|
$
|
1,042
|
|
|
|
|
|
|
|
|
|
|
|
|
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value Measurements Using:
|
|
|
|
At June 30, 2021
|
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
|
$
|
—
|
|
|
$
|
46
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
46
|
|
|
Nuclear decommissioning trusts:(b)
|
|
|
|
|
|
|
|
|
|
|
Domestic equity
|
453
|
|
|
226
|
|
|
—
|
|
|
—
|
|
|
679
|
|
|
Foreign equity
|
171
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
171
|
|
|
U.S. Treasury and government agency securities
|
—
|
|
|
22
|
|
|
—
|
|
|
—
|
|
|
22
|
|
|
Municipal bonds
|
—
|
|
|
1
|
|
|
—
|
|
|
—
|
|
|
1
|
|
|
Corporate bonds
|
4
|
|
|
241
|
|
|
—
|
|
|
—
|
|
|
245
|
|
|
Mortgage and asset backed securities
|
—
|
|
|
24
|
|
|
—
|
|
|
—
|
|
|
24
|
|
|
Private equity
|
—
|
|
|
—
|
|
|
—
|
|
|
102
|
|
|
102
|
|
|
Other
|
6
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
6
|
|
|
Cash equivalents
|
507
|
|
|
13
|
|
|
—
|
|
|
—
|
|
|
520
|
|
|
Other investments
|
—
|
|
|
30
|
|
|
—
|
|
|
—
|
|
|
30
|
|
|
Total
|
$
|
1,141
|
|
|
$
|
603
|
|
|
$
|
—
|
|
|
$
|
102
|
|
|
$
|
1,846
|
|
|
Liabilities:
|
|
|
|
|
|
|
|
|
|
|
Energy-related derivatives
|
$
|
—
|
|
|
$
|
3
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
3
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Georgia Power
|
|
|
|
|
|
|
|
|
|
|
Assets:
|
|
|
|
|
|
|
|
|
|
|
Energy-related derivatives
|
$
|
—
|
|
|
$
|
73
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
73
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nuclear decommissioning trusts:(b)(c)
|
|
|
|
|
|
|
|
|
|
|
Domestic equity
|
359
|
|
|
1
|
|
|
—
|
|
|
—
|
|
|
360
|
|
|
Foreign equity
|
—
|
|
|
188
|
|
|
—
|
|
|
—
|
|
|
188
|
|
|
U.S. Treasury and government agency securities
|
—
|
|
|
289
|
|
|
—
|
|
|
—
|
|
|
289
|
|
|
Municipal bonds
|
—
|
|
|
44
|
|
|
—
|
|
|
—
|
|
|
44
|
|
|
Corporate bonds
|
—
|
|
|
212
|
|
|
—
|
|
|
—
|
|
|
212
|
|
|
Mortgage and asset backed securities
|
—
|
|
|
68
|
|
|
—
|
|
|
—
|
|
|
68
|
|
|
Other
|
23
|
|
|
23
|
|
|
—
|
|
|
—
|
|
|
46
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
$
|
382
|
|
|
$
|
898
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
1,280
|
|
|
Liabilities:
|
|
|
|
|
|
|
|
|
|
|
Energy-related derivatives
|
$
|
—
|
|
|
$
|
4
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
4
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value Measurements Using:
|
|
|
|
At June 30, 2021
|
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
|
$
|
—
|
|
|
$
|
44
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
44
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash equivalents
|
455
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
455
|
|
|
Total
|
$
|
455
|
|
|
$
|
44
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
499
|
|
|
Liabilities:
|
|
|
|
|
|
|
|
|
|
|
Energy-related derivatives
|
$
|
—
|
|
|
$
|
3
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
3
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Southern Power
|
|
|
|
|
|
|
|
|
|
|
Assets:
|
|
|
|
|
|
|
|
|
|
|
Energy-related derivatives
|
$
|
—
|
|
|
$
|
4
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
4
|
|
|
Foreign currency derivatives
|
—
|
|
|
55
|
|
|
—
|
|
|
—
|
|
|
55
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
$
|
—
|
|
|
$
|
59
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
59
|
|
|
Liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Foreign currency derivatives
|
$
|
—
|
|
|
$
|
10
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
10
|
|
|
Contingent consideration
|
—
|
|
|
—
|
|
|
16
|
|
|
—
|
|
|
16
|
|
|
Total
|
$
|
—
|
|
|
$
|
10
|
|
|
$
|
16
|
|
|
$
|
—
|
|
|
$
|
26
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Southern Company Gas
|
|
|
|
|
|
|
|
|
|
|
Assets:
|
|
|
|
|
|
|
|
|
|
|
Energy-related derivatives(a)
|
$
|
656
|
|
|
$
|
269
|
|
|
$
|
28
|
|
|
$
|
—
|
|
|
$
|
953
|
|
|
Interest rate derivatives
|
—
|
|
|
4
|
|
|
—
|
|
|
—
|
|
|
4
|
|
|
Non-qualified deferred compensation trusts:
|
|
|
|
|
|
|
|
|
|
|
Domestic equity
|
—
|
|
|
9
|
|
|
—
|
|
|
—
|
|
|
9
|
|
|
Foreign equity
|
—
|
|
|
3
|
|
|
—
|
|
|
—
|
|
|
3
|
|
|
Pooled funds – fixed income
|
—
|
|
|
18
|
|
|
—
|
|
|
—
|
|
|
18
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
$
|
656
|
|
|
$
|
303
|
|
|
$
|
28
|
|
|
$
|
—
|
|
|
$
|
987
|
|
|
Liabilities:
|
|
|
|
|
|
|
|
|
|
|
Energy-related derivatives(a)
|
$
|
664
|
|
|
$
|
323
|
|
|
$
|
10
|
|
|
$
|
—
|
|
|
$
|
997
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a)Includes assets ($626 million, $260 million, and $28 million categorized as Level 1, 2, and 3, respectively) and liabilities ($657 million, $323 million, and $10 million categorized as Level 1, 2, and 3, respectively) related to Sequent, which were classified as held for sale at June 30, 2021. See Note (K) under "Southern Company Gas" and "Assets and Liabilities Held for Sale" for additional information. Excludes cash collateral of $41 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, 2021, approximately $48 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)
See Note (K) under "Assets and Liabilities Held for Sale" for information regarding assets recorded at fair value on a nonrecurring basis.
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 six months ended June 30, 2021 and 2020. The changes were recorded as a change to the regulatory assets and liabilities related to AROs for Georgia Power and Alabama Power, respectively.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair value increases (decreases)
|
Three Months Ended June 30, 2021
|
Three Months Ended June 30, 2020
|
Six Months Ended June 30, 2021
|
Six Months Ended June 30, 2020
|
|
|
(in millions)
|
|
Southern Company
|
$
|
125
|
|
$
|
223
|
|
$
|
164
|
|
$
|
(23)
|
|
|
Alabama Power
|
77
|
|
124
|
|
118
|
|
(42)
|
|
|
Georgia Power
|
48
|
|
99
|
|
46
|
|
19
|
|
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
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
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.
"Other investments" include 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, 2021, the fair value measurements of private equity 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 $102 million and unfunded commitments related to the private equity investments totaled $67 million. Private equity investments include high-quality private equity funds across several market sectors and funds that invest in real estate assets. Private equity 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, 2021, 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
|
$
|
50.4
|
|
$
|
9.3
|
|
$
|
13.5
|
|
$
|
1.9
|
|
$
|
4.0
|
|
$
|
6.3
|
|
|
Fair value
|
56.2
|
|
10.6
|
|
15.2
|
|
2.1
|
|
4.5
|
|
7.3
|
|
(*)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.
Commodity Contracts with Level 3 Valuation Inputs
At June 30, 2021, Southern Company Gas had Level 3 physical natural gas forward contracts totaling $18 million related to Sequent, which were classified as held for sale. See Note (K) under "Southern Company Gas" and "Assets and Liabilities Held for Sale" for additional information. Since commodity contracts classified as Level 3 typically include a combination of observable and unobservable components, the changes in fair value may include amounts due in part to observable market factors, or changes to assumptions on the unobservable components. The following table includes transfers to Level 3, which represent the fair value of Southern Company Gas' commodity derivative contracts that include a significant unobservable component for the first time during the period.
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended June 30, 2021
|
Six Months Ended June 30, 2021
|
|
|
(in millions)
|
|
Beginning balance
|
$
|
28
|
|
$
|
28
|
|
|
|
|
|
|
|
|
|
|
Instruments realized or otherwise settled during period
|
(4)
|
|
(6)
|
|
|
Changes in fair value
|
(6)
|
|
(4)
|
|
|
Ending balance
|
$
|
18
|
|
$
|
18
|
|
Changes in fair value of Level 3 instruments represent changes in gains and losses for the periods that are reported on Southern Company Gas' statements of income in natural gas revenues.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
The valuation of certain commodity contracts requires the use of certain unobservable inputs. All forward pricing used in the valuation of such contracts is directly based on third-party market data, such as broker quotes and exchange settlements, when that data is available. If third-party market data is not available, then industry standard methodologies are used to develop inputs that maximize the use of relevant observable inputs and minimize the use of unobservable inputs. Observable inputs, including some forward prices used for determining fair value, reflect the best available market information. Unobservable inputs are updated using industry standard techniques such as extrapolation, combining observable forward inputs supplemented by historical market and other relevant data. Level 3 physical natural gas forward contracts include unobservable forward price inputs (ranging from $(0.06) to $0.38 per mmBtu). Forward price increases (decreases) at June 30, 2021 would have resulted in higher (lower) values on a net basis.
(J) DERIVATIVES
Southern Company, the traditional electric operating companies, Southern Power, and Southern Company Gas 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. Through the sale of Sequent on July 1, 2021, Southern Company Gas' wholesale gas operations used various contracts in its commercial activities that generally meet the definition of derivatives. For the traditional electric operating companies, Southern Power, and Southern Company Gas' other businesses, each company's policy is that derivatives are to be used primarily for hedging purposes and mandates strict adherence to all applicable risk management policies. Derivative positions are monitored using techniques including, but not limited to, market valuation, value at risk, stress testing, and sensitivity analysis. 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. See Note (K) under "Southern Company Gas" for information regarding Southern Company Gas' sale of Sequent.
Energy-Related Derivatives
The traditional electric operating companies, Southern Power, and Southern Company Gas 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 of operating margins 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.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
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.
At June 30, 2021, 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(*)
|
978
|
|
2030
|
|
2031
|
|
Alabama Power
|
73
|
|
2024
|
|
—
|
|
Georgia Power
|
125
|
|
2024
|
|
—
|
|
Mississippi Power
|
85
|
|
2025
|
|
—
|
|
Southern Power
|
9
|
|
2030
|
|
2022
|
|
Southern Company Gas(*)
|
686
|
|
2024
|
|
2031
|
(*)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 long natural gas positions of 4.6 billion mmBtu and short natural gas positions of 3.9 billion mmBtu at June 30, 2021, which is also included in Southern Company's total volume. See Note (K) under "Southern Company Gas" for information regarding Southern Company Gas' sale of Sequent.
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 44 million mmBtu for Southern Company, which includes 11 million mmBtu for Alabama Power, 13 million mmBtu for Georgia Power, 6 million mmBtu for Mississippi Power, and 14 million mmBtu for Southern Power.
For cash flow hedges of energy-related derivatives, the estimated pre-tax gains (losses) expected to be reclassified from accumulated OCI to earnings for the 12-month period ending June 30, 2022 are immaterial for all Registrants.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
Interest Rate Derivatives
Southern Company and certain subsidiaries may enter into interest rate derivatives to hedge exposure to changes in interest rates. The derivatives employed as hedging instruments are structured to minimize ineffectiveness. 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.
At June 30, 2021, the following interest rate derivatives were outstanding:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Notional
Amount
|
|
Interest
Rate
Received
|
Weighted
Average
Interest
Rate Paid
|
Hedge
Maturity
Date
|
|
Fair Value Gain (Loss) at June 30, 2021
|
|
|
(in millions)
|
|
|
|
|
|
(in millions)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash Flow Hedges of Existing Debt
|
|
|
|
|
|
|
|
Mississippi Power
|
$
|
60
|
|
|
1-month LIBOR
|
0.58%
|
December 2021
|
|
$
|
—
|
|
|
Fair Value Hedges of Existing Debt
|
|
|
|
|
|
|
|
Southern Company parent
|
400
|
|
|
1.75%
|
1-month LIBOR + 0.68%
|
March 2028
|
|
—
|
|
|
Southern Company parent
|
1,000
|
|
|
3.70%
|
1-month LIBOR + 2.36%
|
April 2030
|
|
4
|
|
|
Southern Company Gas
|
500
|
|
|
1.75%
|
1-month LIBOR + 0.38%
|
January 2031
|
|
3
|
|
|
Southern Company
|
$
|
1,960
|
|
|
|
|
|
|
$
|
7
|
|
For cash flow hedge 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, 2022 total $(23) million for Southern Company and are immaterial for all other Registrants. Deferred gains and losses related to interest rate derivatives are expected to be amortized into earnings through 2051 for the Southern Company parent entity, 2051 for Alabama Power, 2044 for Georgia Power, 2028 for Mississippi Power, and 2046 for Southern Company Gas.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
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. The derivatives employed as hedging instruments are structured to minimize ineffectiveness.
At June 30, 2021, Southern Power had the following outstanding foreign currency derivatives designated as cash flow hedges of existing debt:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pay Notional
|
Pay
Rate
|
Receive Notional
|
Receive
Rate
|
Hedge
Maturity Date
|
Fair Value Gain (Loss) at June 30, 2021
|
|
|
(in millions)
|
|
(in millions)
|
|
|
(in millions)
|
|
|
$
|
677
|
|
2.95%
|
€
|
600
|
|
1.00%
|
June 2022
|
$
|
27
|
|
|
|
564
|
|
3.78%
|
500
|
|
1.85%
|
June 2026
|
18
|
|
|
|
$
|
1,241
|
|
|
€
|
1,100
|
|
|
|
$
|
45
|
|
The estimated pre-tax gains (losses) related to Southern Power's foreign currency derivatives expected to be reclassified from accumulated OCI to earnings for the 12-month period ending June 30, 2022 are $17 million.
Derivative Financial Statement Presentation and Amounts
Southern Company, the traditional electric operating companies, Southern Power, and Southern Company Gas 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 sheet 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, 2021
|
At December 31, 2020
|
|
Derivative Category and Balance Sheet Location
|
Assets
|
Liabilities
|
Assets
|
Liabilities
|
|
|
(in millions)
|
(in millions)
|
|
Southern Company
|
|
|
|
|
|
Derivatives designated as hedging instruments for regulatory purposes
|
|
|
|
|
|
Energy-related derivatives:
|
|
|
|
|
|
Assets from risk management activities/Other current liabilities
|
$
|
130
|
|
$
|
2
|
|
$
|
24
|
|
$
|
11
|
|
|
Other deferred charges and assets/Other deferred credits and liabilities
|
54
|
|
8
|
|
18
|
|
19
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total derivatives designated as hedging instruments for regulatory purposes
|
$
|
184
|
|
$
|
10
|
|
$
|
42
|
|
$
|
30
|
|
|
Derivatives designated as hedging instruments in cash flow and fair value hedges
|
|
|
|
|
|
Energy-related derivatives:
|
|
|
|
|
|
Assets from risk management activities/Other current liabilities
|
$
|
13
|
|
$
|
—
|
|
$
|
3
|
|
$
|
5
|
|
|
Other deferred charges and assets/Other deferred credits and liabilities
|
1
|
|
—
|
|
—
|
|
—
|
|
|
Interest rate derivatives:
|
|
|
|
|
|
Assets from risk management activities/Other current liabilities
|
17
|
|
—
|
|
20
|
|
—
|
|
|
Other deferred charges and assets/Other deferred credits and liabilities
|
—
|
|
9
|
|
—
|
|
—
|
|
|
Foreign currency derivatives:
|
|
|
|
|
|
Assets from risk management activities/Other current liabilities
|
27
|
|
10
|
|
—
|
|
23
|
|
|
Other deferred charges and assets/Other deferred credits and liabilities
|
28
|
|
—
|
|
87
|
|
—
|
|
|
Total derivatives designated as hedging instruments in cash flow and fair value hedges
|
$
|
86
|
|
$
|
19
|
|
$
|
110
|
|
$
|
28
|
|
|
Derivatives not designated as hedging instruments
|
|
|
|
|
|
Energy-related derivatives:
|
|
|
|
|
|
Assets from risk management activities/Other current liabilities
|
$
|
8
|
|
$
|
7
|
|
$
|
388
|
|
$
|
331
|
|
|
Other deferred charges and assets/Other deferred credits and liabilities
|
—
|
|
—
|
|
270
|
|
232
|
|
|
Assets held for sale, current/Liabilities held for sale, current
|
914
|
|
990
|
|
—
|
|
—
|
|
|
Total derivatives not designated as hedging instruments
|
$
|
922
|
|
$
|
997
|
|
$
|
658
|
|
$
|
563
|
|
|
Gross amounts recognized
|
$
|
1,192
|
|
$
|
1,026
|
|
$
|
810
|
|
$
|
621
|
|
|
Gross amounts offset(a)
|
(851)
|
|
(892)
|
|
(529)
|
|
(557)
|
|
|
Net amounts recognized in the Balance Sheets(b)
|
$
|
341
|
|
$
|
134
|
|
$
|
281
|
|
$
|
64
|
|
|
|
|
|
|
|
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
At June 30, 2021
|
At December 31, 2020
|
|
Derivative Category and Balance Sheet Location
|
Assets
|
Liabilities
|
Assets
|
Liabilities
|
|
|
(in millions)
|
(in millions)
|
|
Alabama Power
|
|
|
|
|
|
Derivatives designated as hedging instruments for regulatory purposes
|
|
|
|
|
|
Energy-related derivatives:
|
|
|
|
|
|
Other current assets/Other current liabilities
|
$
|
31
|
|
$
|
1
|
|
$
|
7
|
|
$
|
2
|
|
|
Other deferred charges and assets/Other deferred credits and liabilities
|
15
|
|
2
|
|
5
|
|
5
|
|
|
Total derivatives designated as hedging instruments for regulatory purposes
|
$
|
46
|
|
$
|
3
|
|
$
|
12
|
|
$
|
7
|
|
|
Gross amounts recognized
|
$
|
46
|
|
$
|
3
|
|
$
|
12
|
|
$
|
7
|
|
|
Gross amounts offset
|
(3)
|
|
(3)
|
|
(7)
|
|
(7)
|
|
|
Net amounts recognized in the Balance Sheets
|
$
|
43
|
|
$
|
—
|
|
$
|
5
|
|
$
|
—
|
|
|
|
|
|
|
|
|
Georgia Power
|
|
|
|
|
|
Derivatives designated as hedging instruments for regulatory purposes
|
|
|
|
|
|
Energy-related derivatives:
|
|
|
|
|
|
Other current assets/Other current liabilities
|
$
|
52
|
|
$
|
1
|
|
$
|
7
|
|
$
|
5
|
|
|
Other deferred charges and assets/Other deferred credits and liabilities
|
21
|
|
3
|
|
8
|
|
8
|
|
|
Total derivatives designated as hedging instruments for regulatory purposes
|
$
|
73
|
|
$
|
4
|
|
$
|
15
|
|
$
|
13
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross amounts recognized
|
$
|
73
|
|
$
|
4
|
|
$
|
15
|
|
$
|
13
|
|
|
Gross amounts offset
|
(4)
|
|
(4)
|
|
(12)
|
|
(12)
|
|
|
Net amounts recognized in the Balance Sheets
|
$
|
69
|
|
$
|
—
|
|
$
|
3
|
|
$
|
1
|
|
|
|
|
|
|
|
|
Mississippi Power
|
|
|
|
|
|
Derivatives designated as hedging instruments for regulatory purposes
|
|
|
|
|
|
Energy-related derivatives:
|
|
|
|
|
|
Other current assets/Other current liabilities
|
$
|
28
|
|
$
|
—
|
|
$
|
4
|
|
$
|
3
|
|
|
Other deferred charges and assets/Other deferred credits and liabilities
|
16
|
|
3
|
|
5
|
|
6
|
|
|
Total derivatives designated as hedging instruments for regulatory purposes
|
$
|
44
|
|
$
|
3
|
|
$
|
9
|
|
$
|
9
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross amounts recognized
|
$
|
44
|
|
$
|
3
|
|
$
|
9
|
|
$
|
9
|
|
|
Gross amounts offset
|
(3)
|
|
(3)
|
|
(7)
|
|
(7)
|
|
|
Net amounts recognized in the Balance Sheets
|
$
|
41
|
|
$
|
—
|
|
$
|
2
|
|
$
|
2
|
|
|
|
|
|
|
|
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
At June 30, 2021
|
At December 31, 2020
|
|
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
|
$
|
4
|
|
$
|
—
|
|
$
|
2
|
|
$
|
2
|
|
|
|
|
|
|
|
|
Foreign currency derivatives:
|
|
|
|
|
|
Other current assets/Other current liabilities
|
27
|
|
10
|
|
—
|
|
23
|
|
|
Other deferred charges and assets/Other deferred credits and liabilities
|
28
|
|
—
|
|
87
|
|
—
|
|
|
Total derivatives designated as hedging instruments in cash flow and fair value hedges
|
$
|
59
|
|
$
|
10
|
|
$
|
89
|
|
$
|
25
|
|
|
Derivatives not designated as hedging instruments
|
|
|
|
|
|
Energy-related derivatives:
|
|
|
|
|
|
Other current assets/Other current liabilities
|
$
|
—
|
|
$
|
—
|
|
$
|
—
|
|
$
|
1
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total derivatives not designated as hedging instruments
|
$
|
—
|
|
$
|
—
|
|
$
|
—
|
|
$
|
1
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net amounts recognized in the Balance Sheets
|
$
|
59
|
|
$
|
10
|
|
$
|
89
|
|
$
|
26
|
|
|
|
|
|
|
|
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
At June 30, 2021
|
At December 31, 2020
|
|
Derivative Category and Balance Sheet Location
|
Assets
|
Liabilities
|
Assets
|
Liabilities
|
|
|
(in millions)
|
(in millions)
|
|
Southern Company Gas
|
|
|
|
|
|
Derivatives designated as hedging instruments for regulatory purposes
|
|
|
|
|
|
Energy-related derivatives:
|
|
|
|
|
|
Assets from risk management activities/Other current liabilities
|
$
|
19
|
|
$
|
—
|
|
$
|
6
|
|
$
|
1
|
|
|
Other deferred charges and assets/Other deferred credits and liabilities
|
2
|
|
—
|
|
—
|
|
—
|
|
|
Total derivatives designated as hedging instruments for regulatory purposes
|
$
|
21
|
|
$
|
—
|
|
$
|
6
|
|
$
|
1
|
|
|
Derivatives designated as hedging instruments in cash flow and fair value hedges
|
|
|
|
|
|
Energy-related derivatives:
|
|
|
|
|
|
Assets from risk management activities/Other current liabilities
|
$
|
9
|
|
$
|
—
|
|
$
|
1
|
|
$
|
3
|
|
|
Other deferred charges and assets/Other deferred credits and liabilities
|
1
|
|
—
|
|
—
|
|
—
|
|
|
Interest rate derivatives:
|
|
|
|
|
|
Assets from risk management activities/Liabilities from risk management activities-current
|
4
|
|
—
|
|
—
|
|
—
|
|
|
|
|
|
|
|
|
Total derivatives designated as hedging instruments in cash flow and fair value hedges
|
$
|
14
|
|
$
|
—
|
|
$
|
1
|
|
$
|
3
|
|
|
Derivatives not designated as hedging instruments
|
|
|
|
|
|
Energy-related derivatives:
|
|
|
|
|
|
Assets from risk management activities/Other current liabilities
|
$
|
8
|
|
$
|
7
|
|
$
|
388
|
|
$
|
330
|
|
|
Other deferred charges and assets/Other deferred credits and liabilities
|
—
|
|
—
|
|
270
|
|
232
|
|
|
Assets held for sale, current/Liabilities held for sale, current
|
914
|
|
990
|
|
—
|
|
—
|
|
|
Total derivatives not designated as hedging instruments
|
$
|
922
|
|
$
|
997
|
|
$
|
658
|
|
$
|
562
|
|
|
Gross amounts of recognized
|
$
|
957
|
|
$
|
997
|
|
$
|
665
|
|
$
|
566
|
|
|
Gross amounts offset(a)
|
(841)
|
|
(882)
|
|
(503)
|
|
(531)
|
|
|
Net amounts recognized in the Balance Sheets(b)
|
$
|
116
|
|
$
|
115
|
|
$
|
162
|
|
$
|
35
|
|
(a)Gross amounts offset include cash collateral held on deposit in broker margin accounts of $41 million and $28 million at June 30, 2021 and December 31, 2020, respectively.
(b)Net amounts of derivative instruments outstanding exclude immaterial premium and intrinsic value associated with weather derivatives for both periods presented.
The traditional electric operating companies had immaterial energy-related derivatives not designated as hedging instruments at June 30, 2021 and no such instruments at December 31, 2020.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
At June 30, 2021 and December 31, 2020, 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, 2021:
|
|
|
|
|
|
|
Energy-related derivatives:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other regulatory liabilities, current
|
$
|
120
|
|
$
|
31
|
|
$
|
51
|
|
$
|
28
|
|
$
|
10
|
|
|
Other regulatory liabilities, deferred
|
46
|
|
13
|
|
18
|
|
14
|
|
1
|
|
|
Total energy-related derivative gains (losses)
|
$
|
166
|
|
$
|
44
|
|
$
|
69
|
|
$
|
42
|
|
$
|
11
|
|
|
|
|
|
|
|
|
|
At December 31, 2020:
|
|
|
|
|
|
|
Energy-related derivatives:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other regulatory assets, deferred
|
$
|
(2)
|
|
$
|
—
|
|
$
|
(1)
|
|
$
|
(1)
|
|
$
|
—
|
|
|
Other regulatory liabilities, current
|
12
|
|
5
|
|
2
|
|
1
|
|
4
|
|
|
Other regulatory liabilities, deferred
|
2
|
|
1
|
|
1
|
|
—
|
|
—
|
|
|
Total energy-related derivative gains (losses)
|
$
|
12
|
|
$
|
6
|
|
$
|
2
|
|
$
|
—
|
|
$
|
4
|
|
For the three and six months ended June 30, 2021 and 2020, the pre-tax effects of cash flow hedge accounting on accumulated OCI were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gain (Loss) Recognized in OCI on Derivative
|
For the Three Months Ended June 30,
|
For the Six Months Ended June 30,
|
|
2021
|
2020
|
2021
|
2020
|
|
|
(in millions)
|
(in millions)
|
|
Southern Company
|
|
|
|
|
|
Energy-related derivatives
|
$
|
16
|
|
$
|
(2)
|
|
$
|
20
|
|
$
|
(6)
|
|
|
Interest rate derivatives
|
(1)
|
|
(1)
|
|
2
|
|
(28)
|
|
|
Foreign currency derivatives
|
4
|
|
17
|
|
(43)
|
|
(65)
|
|
|
Total
|
$
|
19
|
|
$
|
14
|
|
$
|
(21)
|
|
$
|
(99)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Southern Power
|
|
|
|
|
|
Energy-related derivatives
|
$
|
5
|
|
$
|
(2)
|
|
$
|
8
|
|
$
|
(2)
|
|
|
|
|
|
|
|
|
Foreign currency derivatives
|
4
|
|
17
|
|
(43)
|
|
(65)
|
|
|
Total
|
$
|
9
|
|
$
|
15
|
|
$
|
(35)
|
|
$
|
(67)
|
|
|
Southern Company Gas
|
|
|
|
|
|
Energy-related derivatives
|
$
|
11
|
|
$
|
—
|
|
$
|
12
|
|
$
|
(4)
|
|
|
Interest rate derivatives
|
—
|
|
(1)
|
|
—
|
|
(25)
|
|
|
Total
|
$
|
11
|
|
$
|
(1)
|
|
$
|
12
|
|
$
|
(29)
|
|
For the three and six months ended June 30, 2021 and 2020, the pre-tax effects of energy-related derivatives and interest rate derivatives designated as cash flow hedging instruments on accumulated OCI were immaterial for the other Registrants.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
For the three and six months ended June 30, 2021 and 2020, 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,
|
|
|
|
2021
|
2020
|
2021
|
2020
|
|
|
(in millions)
|
(in millions)
|
|
Southern Company
|
|
|
|
|
|
Total cost of natural gas
|
$
|
231
|
|
$
|
144
|
|
$
|
814
|
|
$
|
583
|
|
|
Gain (loss) on energy-related cash flow hedges(a)
|
1
|
|
(1)
|
|
(2)
|
|
(8)
|
|
|
Total depreciation and amortization
|
891
|
|
873
|
|
1,762
|
|
1,730
|
|
|
Gain (loss) on energy-related cash flow hedges(a)
|
1
|
|
(1)
|
|
4
|
|
(2)
|
|
|
Total interest expense, net of amounts capitalized
|
(450)
|
|
(444)
|
|
(901)
|
|
(900)
|
|
|
Gain (loss) on interest rate cash flow hedges(a)
|
(7)
|
|
(6)
|
|
(14)
|
|
(13)
|
|
|
Gain (loss) on foreign currency cash flow hedges(a)
|
(6)
|
|
(6)
|
|
(12)
|
|
(12)
|
|
|
Gain (loss) on interest rate fair value hedges(b)
|
(3)
|
|
1
|
|
(12)
|
|
30
|
|
|
Total other income (expense), net
|
108
|
|
101
|
|
167
|
|
204
|
|
|
Gain (loss) on foreign currency cash flow hedges(a)(c)
|
17
|
|
27
|
|
(43)
|
|
(4)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Southern Power
|
|
|
|
|
|
Total depreciation and amortization
|
$
|
132
|
|
$
|
121
|
|
$
|
251
|
|
$
|
239
|
|
|
Gain (loss) on energy-related cash flow hedges(a)
|
1
|
|
(1)
|
|
4
|
|
(2)
|
|
|
Total interest expense, net of amounts capitalized
|
(37)
|
|
(38)
|
|
(75)
|
|
(77)
|
|
|
Gain (loss) on foreign currency cash flow hedges(a)
|
(6)
|
|
(6)
|
|
(12)
|
|
(12)
|
|
|
Total other income (expense), net
|
1
|
|
1
|
|
8
|
|
4
|
|
|
Gain (loss) on foreign currency cash flow hedges(a)(c)
|
17
|
|
27
|
|
(43)
|
|
(4)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(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.
For the three and six months ended June 30, 2021 and 2020, 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 and Southern Company Gas.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
At June 30, 2021 and December 31, 2020, 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, 2021
|
At December 31, 2020
|
|
At June 30, 2021
|
At December 31, 2020
|
|
|
(in millions)
|
|
(in millions)
|
|
Southern Company
|
|
|
|
|
|
|
Securities due within one year
|
$
|
—
|
|
$
|
(1,509)
|
|
|
$
|
—
|
|
$
|
(10)
|
|
|
Long-term debt
|
(1,883)
|
|
—
|
|
|
—
|
|
—
|
|
|
|
|
|
|
|
|
|
Southern Company Gas
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-term debt
|
$
|
(492)
|
|
$
|
—
|
|
|
$
|
3
|
|
$
|
—
|
|
For the three and six months ended June 30, 2021 and 2020, 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
|
2021
|
2020
|
|
2021
|
2020
|
|
|
|
(in millions)
|
|
(in millions)
|
|
|
|
|
|
|
|
|
|
Energy-related derivatives:
|
Natural gas revenues(*)
|
$
|
(103)
|
|
$
|
14
|
|
|
$
|
(120)
|
|
$
|
84
|
|
|
|
|
|
|
|
|
|
|
|
Cost of natural gas
|
9
|
|
5
|
|
|
16
|
|
13
|
|
|
Total derivatives in non-designated hedging relationships
|
$
|
(94)
|
|
$
|
19
|
|
|
$
|
(104)
|
|
$
|
97
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(*)Excludes immaterial gains (losses) recorded in natural gas revenues associated with weather derivatives for all periods presented.
For the three and six months ended June 30, 2021 and 2020, the pre-tax effects of energy-related derivatives not designated as hedging instruments were immaterial for all other Registrants.
Contingent Features
Southern Company, the traditional electric operating companies, Southern Power, and Southern Company Gas 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. At June 30, 2021, the Registrants had no collateral posted with derivative counterparties to satisfy these arrangements.
At June 30, 2021, the Registrants had no interest rate derivative liabilities with contingent features. At June 30, 2021, the fair value of Southern Company Gas' 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, 2021, the other Registrants had no energy-related derivative liabilities with contingent features. 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. Following the sale of Gulf Power to NextEra Energy, Inc.,
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
Gulf Power is continuing to participate in the Southern Company power pool for a defined transition period that, subject to certain potential adjustments, is scheduled to end on January 1, 2024.
Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. If collateral is required, fair value amounts recognized for the right to reclaim cash collateral or the obligation to return cash collateral are not offset against fair value amounts recognized for derivatives executed with the same counterparty.
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, 2021, cash collateral posted in these accounts was immaterial. 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, 2021, cash collateral held on deposit in broker margin accounts was $41 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) ACQUISITIONS AND DISPOSITIONS
See Note 15 to the financial statements in Item 8 of the Form 10-K for additional information.
Southern Power
Asset Acquisition
During the six months ended June 30, 2021, Southern Power acquired a controlling membership interest in the wind facility listed below. Acquisition-related costs were expensed as incurred and were not material.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Project Facility
|
Resource
|
Seller
|
Approximate Nameplate Capacity (MW)
|
Location
|
Southern Power Ownership Percentage
|
COD
|
PPA Contract Period
|
|
Deuel Harvest(*)
|
Wind
|
Invenergy Renewables, LLC
|
300
|
Deuel County, SD
|
100% of
Class B
|
February 2021
|
25 years
and
15 years
|
(*)On March 26, 2021, Southern Power acquired a controlling interest in the facility and consolidates the project's operating results in its financial statements. On March 30, 2021, Southern Power completed a tax equity transaction whereby it received $220 million. The tax equity partner, which is the Class A member, and Invenergy Renewables, LLC each own a noncontrolling interest.
Construction Projects
During the six months ended June 30, 2021, Southern Power continued construction of the Garland and Tranquillity battery energy storage facilities and the Glass Sands wind facility. Total aggregate construction costs, excluding acquisition costs, are expected to be between $390 million and $460 million for the facilities under construction. At June 30, 2021, total costs of construction incurred for these projects were $208 million and are included in CWIP. The ultimate outcome of these matters cannot be determined at this time.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Project Facility
|
Resource
|
Approximate Nameplate Capacity (MW)
|
Location
|
Actual/Expected COD
|
PPA Contract Period
|
|
Projects Under Construction at June 30, 2021
|
|
Garland Solar Storage(a)
|
Battery energy storage system
|
88
|
Kern County, CA
|
August 2021
|
20 years
|
|
Tranquillity Solar Storage(a)
|
Battery energy storage system
|
72
|
Fresno County, CA
|
Fourth quarter 2021
|
20 years
|
|
Glass Sands(b)
|
Wind
|
118
|
Murray County, OK
|
Fourth quarter 2021
|
12 years
|
(a)Subsequent to June 30, 2021, Southern Power further restructured its ownership in the Garland battery energy storage project and completed a tax equity transaction whereby it received initial proceeds of $11 million, while retaining the controlling interest. Prior to commercial operation, Southern Power expects to further restructure its ownership in the Tranquillity battery energy storage project and complete a tax equity transaction, but expects to retain the controlling interest. The ultimate outcome of this matter cannot be determined at this time.
(b)In December 2020, Southern Power purchased 100% of the membership interests of the Glass Sands facility.
Development Projects
Southern Power continues to evaluate and refine the deployment of the remaining wind turbine equipment purchased in 2016 and 2017 to development and construction projects. During the six months ended June 30, 2021, gains on wind turbine equipment contributed to various equity method investments totaled approximately $37 million.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
Southern Company Gas
Sale of Sequent
On July 1, 2021, Southern Company Gas affiliates completed the sale of Sequent to Williams Field Services Group for a total cash purchase price of $150 million, including estimated working capital adjustments. The preliminary gain associated with the transaction is approximately $90 million, which will be recorded in the third quarter 2021.
Prior to the sale, Southern Company Gas had existing agreements in place in which it guaranteed the payment performance of Sequent. Southern Company Gas will continue to guarantee Sequent's payment performance for a period of time as Williams Field Services Group obtains releases from these obligations. At June 30, 2021, the obligations subject to the payment performance guarantee totaled $268 million. Changes in the price of natural gas, market conditions, and the number of open contracts may change the amount that Southern Company Gas is required to guarantee for Sequent each month. The maximum potential exposure over the period of the payment performance guarantee generally is capped at $1 billion. At closing, Williams Field Services Group issued a payment performance guarantee to Southern Company Gas, equal to the outstanding guarantee obligation throughout this period.
The assets and liabilities of Sequent were classified as held for sale on the balance sheets of Southern Company and Southern Company Gas at June 30, 2021. See "Assets and Liabilities Held for Sale" herein for additional information.
Sale of Pivotal LNG
In connection with its March 2020 sale of Pivotal LNG, Southern Company Gas was entitled to two $5 million payments contingent upon Dominion Modular LNG Holdings, Inc. meeting certain milestones related to Pivotal LNG. Southern Company Gas received the first payment on April 22, 2021 and expects to receive the second payment in February 2022.
Assets and Liabilities Held for Sale
The following table provides the major classes of assets and liabilities classified as held for sale by Southern Company and Southern Company Gas at June 30, 2021 and/or December 31, 2020:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Southern Company
|
|
Southern Company Gas
|
|
|
At June 30,
|
At December 31,
|
|
At June 30,
|
|
|
2021
|
2020
|
|
2021
|
|
|
(in millions)
|
|
Assets Held for Sale:
|
|
|
|
|
|
Receivables – energy marketing
|
$
|
486
|
|
$
|
—
|
|
|
$
|
486
|
|
|
Natural gas for sale
|
90
|
|
—
|
|
|
90
|
|
|
Other current assets
|
76
|
|
—
|
|
|
76
|
|
|
Total property, plant, and equipment
|
11
|
|
8
|
|
|
5
|
|
|
Leveraged leases
|
45
|
|
52
|
|
|
—
|
|
|
Accumulated deferred income taxes
|
30
|
|
—
|
|
|
30
|
|
|
Other non-current assets
|
49
|
|
—
|
|
|
49
|
|
|
Total Assets Held for Sale
|
$
|
787
|
|
$
|
60
|
|
|
$
|
736
|
|
|
|
|
|
|
|
|
Liabilities Held for Sale:
|
|
|
|
|
|
Energy marketing trade payables
|
$
|
491
|
|
$
|
—
|
|
|
$
|
491
|
|
|
Other current liabilities
|
148
|
|
—
|
|
|
148
|
|
|
Other non-current liabilities
|
38
|
|
—
|
|
|
38
|
|
|
Total Liabilities Held for Sale
|
$
|
677
|
|
$
|
—
|
|
|
$
|
677
|
|
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
Southern Company Gas' assets and liabilities held for sale at June 30, 2021 were recorded based on their carrying value as the net carrying value of Sequent was lower than the agreed upon price in the sale agreement. See Note (I) for information regarding Sequent's energy-related derivatives held for sale that are recorded at fair value on a recurring basis. Southern Company's other assets held for sale at June 30, 2021 and December 31, 2020 were recorded at fair value on a nonrecurring basis, based primarily on unobservable inputs (Level 3).
See Note 3 to the financial statements under "Other Matters – Southern Company" in Item 8 of the Form 10-K for additional information regarding the leveraged lease investment held for sale.
Southern Company's and Southern Company Gas' asset sales, both individually and combined, do not represent a strategic shift in operations that has, or is expected to have, a major effect on operations and financial results; therefore, none of the assets have been classified as discontinued operations for any of the periods presented.
(L) SEGMENT AND RELATED INFORMATION
Southern Company
The primary businesses of the Southern Company system are electricity sales by the traditional electric operating companies and Southern Power and the distribution of natural gas by Southern Company Gas. The traditional electric operating companies – Alabama Power, Georgia Power, and Mississippi Power – 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, wholesale gas services (through June 30, 2021), 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 $112 million and $193 million for the three and six months ended June 30, 2021, respectively, and $92 million and $178 million for the three and six months ended June 30, 2020, respectively. Revenues from sales of natural gas from Southern Company Gas to the traditional electric operating companies were immaterial for all periods presented. Revenues from sales of natural gas from Southern Company Gas to Southern Power were $6 million and $18 million for the three and six months ended June 30, 2021, respectively, and $3 million and $13 million for the three and six months ended June 30, 2020, respectively. 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 energy solutions to electric utilities and their customers in the areas of distributed generation, energy storage and renewables, and energy efficiency, as well as investments in telecommunications and leveraged lease projects. 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, 2021 and 2020 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, 2021
|
|
|
|
|
|
|
|
|
Operating revenues
|
$
|
4,031
|
|
$
|
490
|
|
$
|
(114)
|
|
$
|
4,407
|
|
$
|
677
|
|
$
|
154
|
|
$
|
(40)
|
|
$
|
5,198
|
|
|
Segment net income (loss)(a)(b)(c)(d)
|
511
|
|
36
|
|
—
|
|
547
|
|
(65)
|
|
(108)
|
|
(2)
|
|
372
|
|
|
Six Months Ended June 30, 2021
|
|
|
|
|
|
|
|
|
Operating revenues
|
$
|
7,795
|
|
$
|
930
|
|
$
|
(201)
|
|
$
|
8,524
|
|
$
|
2,371
|
|
$
|
288
|
|
$
|
(75)
|
|
$
|
11,108
|
|
|
Segment net income (loss)(a)(b)(c)(d)(e)
|
1,267
|
|
133
|
|
—
|
|
1,400
|
|
333
|
|
(216)
|
|
(9)
|
|
1,508
|
|
|
At June 30, 2021
|
|
|
|
|
|
|
|
|
|
Goodwill
|
$
|
—
|
|
$
|
2
|
|
$
|
—
|
|
$
|
2
|
|
$
|
5,015
|
|
$
|
263
|
|
$
|
—
|
|
$
|
5,280
|
|
|
Assets held for sale
|
2
|
|
—
|
|
—
|
|
2
|
|
736
|
|
49
|
|
—
|
|
787
|
|
|
Total assets
|
87,330
|
|
13,708
|
|
(693)
|
|
100,345
|
|
23,235
|
|
3,063
|
|
(736)
|
|
125,907
|
|
|
Three Months Ended June 30, 2020
|
|
|
|
|
|
|
|
|
Operating revenues
|
$
|
3,539
|
|
$
|
439
|
|
$
|
(94)
|
|
$
|
3,884
|
|
$
|
636
|
|
$
|
135
|
|
$
|
(35)
|
|
$
|
4,620
|
|
|
Segment net income (loss)(a)(b)(d)
|
645
|
|
63
|
|
—
|
|
708
|
|
71
|
|
(177)
|
|
10
|
|
612
|
|
|
Six Months Ended June 30, 2020
|
|
|
|
|
|
|
|
|
Operating revenues
|
$
|
6,946
|
|
$
|
814
|
|
$
|
(181)
|
|
$
|
7,579
|
|
$
|
1,885
|
|
$
|
248
|
|
$
|
(74)
|
|
$
|
9,638
|
|
|
Segment net income (loss)(a)(b)(d)(f)
|
1,287
|
|
138
|
|
—
|
|
1,425
|
|
346
|
|
(299)
|
|
8
|
|
1,480
|
|
|
At December 31, 2020
|
|
|
|
|
|
|
|
|
|
Goodwill
|
$
|
—
|
|
$
|
2
|
|
$
|
—
|
|
$
|
2
|
|
$
|
5,015
|
|
$
|
263
|
|
$
|
—
|
|
$
|
5,280
|
|
|
Assets held for sale
|
5
|
|
—
|
|
—
|
|
5
|
|
—
|
|
55
|
|
—
|
|
60
|
|
|
Total assets
|
85,486
|
|
13,235
|
|
(680)
|
|
98,041
|
|
22,630
|
|
3,168
|
|
(904)
|
|
122,935
|
|
(a)Attributable to Southern Company.
(b)For the traditional electric operating companies, includes pre-tax charges at Georgia Power for estimated losses associated with the construction of Plant Vogtle Units 3 and 4 of $460 million ($343 million after tax) and $508 million ($379 million after tax) for the three and six months ended June 30, 2021, respectively, and $149 million ($111 million after tax) for the three and six months ended June 30, 2020. See Note (B) and Note 2 to the financial statements in Item 8 of the Form 10-K under "Georgia Power – Nuclear Construction" for additional information.
(c)For Southern Company Gas, includes a pre-tax impairment charge of $82 million ($58 million after tax) related to its equity method investment in the PennEast Pipeline project. See Notes (C) and (E) under "Other Matters – Southern Company Gas" and "Southern Company Gas," respectively, for additional information.
(d)For the "All Other" column, includes pre-tax impairment charges related to leveraged lease investments of $7 million ($6 million after tax) for the three and six months ended June 30, 2021 and $154 million ($74 million after tax) for the three and six months ended June 30, 2020. See Note 3 to the financial statements in Item 8 of the Form 10-K under "Other Matters – Southern Company" for additional information.
(e)For Southern Power, includes gains on wind turbine equipment contributed to various equity method investments totaling approximately $37 million pre-tax ($28 million after tax). See Notes (E) and (K) under "Southern Power" for additional information.
(f)For Southern Power, includes a $39 million pre-tax gain ($23 million gain after tax) on the sale of Plant Mankato. See Note 15 to the financial statements in Item 8 of the Form 10-K under "Southern Power" 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, 2021
|
$
|
3,599
|
|
$
|
546
|
|
$
|
262
|
|
$
|
4,407
|
|
|
Three Months Ended June 30, 2020
|
3,182
|
|
472
|
|
230
|
|
3,884
|
|
|
Six Months Ended June 30, 2021
|
$
|
6,941
|
|
$
|
1,091
|
|
$
|
492
|
|
$
|
8,524
|
|
|
Six Months Ended June 30, 2020
|
6,260
|
|
889
|
|
430
|
|
7,579
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Southern Company Gas' Revenues
|
|
|
Gas
Distribution
Operations
|
Wholesale
Gas
Services(*)
|
Gas
Marketing
Services
|
Other
|
Total
|
|
|
(in millions)
|
|
Three Months Ended June 30, 2021
|
$
|
706
|
|
$
|
(110)
|
|
$
|
64
|
|
$
|
17
|
|
$
|
677
|
|
|
Three Months Ended June 30, 2020
|
583
|
|
(19)
|
|
56
|
|
16
|
|
636
|
|
|
Six Months Ended June 30, 2021
|
$
|
1,898
|
|
$
|
188
|
|
$
|
259
|
|
$
|
26
|
|
$
|
2,371
|
|
|
Six Months Ended June 30, 2020
|
1,596
|
|
32
|
|
233
|
|
24
|
|
1,885
|
|
(*)The revenues for wholesale gas services are netted with costs associated with its energy and risk management activities. See "Southern Company Gas" herein for additional information.
Southern Company Gas
Southern Company Gas manages its business through four reportable segments – gas distribution operations, gas pipeline investments, wholesale gas services, and gas marketing services. The non-reportable segments are combined and presented as all other. See Note 15 to the financial statements in Item 8 of the Form 10-K under "Southern Company Gas" for additional information on the disposition activities described herein.
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, a 20% ownership interest in the PennEast Pipeline project, 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. Gas pipeline investments also included a 5% ownership interest in the Atlantic Coast Pipeline construction project prior to its sale on March 24, 2020.
Wholesale gas services (until the sale of Sequent on July 1, 2021) provided natural gas asset management and/or related logistics services for each of Southern Company Gas' utilities except Nicor Gas as well as for non-affiliated companies. The Virginia Natural Gas asset management agreement ended on March 31, 2021 and was not extended. Additionally, wholesale gas services engaged in natural gas storage and gas pipeline arbitrage and related activities. See Note (K) under "Southern Company Gas" for information regarding the sale of Sequent on July 1, 2021.
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 Jefferson Island through its sale on December 1, 2020 and Pivotal LNG through its sale on March 24, 2020.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
Business segment financial data for the three and six months ended June 30, 2021 and 2020 was as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas Distribution Operations
|
Gas Pipeline Investments
|
Wholesale Gas Services(a)
|
Gas Marketing Services
|
Total
|
All Other
|
Eliminations
|
Consolidated
|
|
|
(in millions)
|
|
Three Months Ended June 30, 2021
|
|
|
|
|
|
|
|
Operating revenues
|
$
|
710
|
|
$
|
8
|
|
$
|
(110)
|
|
$
|
64
|
|
$
|
672
|
|
$
|
11
|
|
$
|
(6)
|
|
$
|
677
|
|
|
Segment net income (loss)(b)
|
80
|
|
(36)
|
|
(112)
|
|
6
|
|
(62)
|
|
(3)
|
|
—
|
|
(65)
|
|
|
Six Months Ended June 30, 2021
|
|
|
|
|
|
|
|
Operating revenues
|
$
|
1,910
|
|
$
|
16
|
|
$
|
188
|
|
$
|
259
|
|
$
|
2,373
|
|
$
|
18
|
|
$
|
(20)
|
|
$
|
2,371
|
|
|
Segment net income (loss)(b)
|
263
|
|
(7)
|
|
14
|
|
62
|
|
332
|
|
1
|
|
—
|
|
333
|
|
|
Total assets at June 30, 2021
|
20,245
|
|
1,492
|
|
807
|
|
1,486
|
|
24,030
|
|
11,300
|
|
(12,095)
|
|
23,235
|
|
|
Three Months Ended June 30, 2020
|
|
|
|
|
|
|
|
Operating revenues
|
$
|
587
|
|
$
|
8
|
|
$
|
(19)
|
|
$
|
56
|
|
$
|
632
|
|
$
|
8
|
|
$
|
(4)
|
|
$
|
636
|
|
|
Segment net income (loss)
|
74
|
|
21
|
|
(23)
|
|
5
|
|
77
|
|
(6)
|
|
—
|
|
71
|
|
|
Six Months Ended June 30, 2020
|
|
|
|
|
|
|
|
|
Operating revenues
|
$
|
1,607
|
|
$
|
16
|
|
$
|
32
|
|
$
|
233
|
|
$
|
1,888
|
|
$
|
16
|
|
$
|
(19)
|
|
$
|
1,885
|
|
|
Segment net income (loss)
|
238
|
|
51
|
|
—
|
|
62
|
|
351
|
|
(5)
|
|
—
|
|
346
|
|
|
Total assets at December 31, 2020
|
19,090
|
|
1,597
|
|
850
|
|
1,503
|
|
23,040
|
|
11,336
|
|
(11,746)
|
|
22,630
|
|
(a)The revenues for wholesale gas services are netted with costs associated with its energy and risk management activities. A reconciliation of operating revenues and intercompany revenues is shown in the following table.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Third Party Gross Revenues
|
Intercompany Revenues
|
Total Gross Revenues
|
Less Gross Gas Costs
|
Operating Revenues
|
|
|
(in millions)
|
|
Three Months Ended June 30, 2021
|
$
|
1,292
|
|
$
|
27
|
|
$
|
1,319
|
|
$
|
1,429
|
|
$
|
(110)
|
|
|
Three Months Ended June 30, 2020
|
854
|
|
18
|
|
872
|
|
891
|
|
(19)
|
|
|
Six Months Ended June 30, 2021
|
$
|
3,881
|
|
$
|
90
|
|
$
|
3,971
|
|
$
|
3,783
|
|
$
|
188
|
|
|
Six Months Ended June 30, 2020
|
2,039
|
|
47
|
|
2,086
|
|
2,054
|
|
32
|
|
(b)For gas pipeline investments, includes a pre-tax impairment charge of $82 million ($58 million after tax) related to the equity method investment in the PennEast Pipeline project. See Notes (C) and (E) under "Other Matters – Southern Company Gas" and "Southern Company Gas," respectively, for additional information.
Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations.
|
|
|
|
|
|
|
|
|
Page
|
|
Combined Management's Discussion and Analysis of Financial Condition and Results of Operations
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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), as well as 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, wholesale gas services (through June 30, 2021), and gas marketing services. See Notes (K) and (L) to the Condensed Financial Statements herein for additional information on the sale of Sequent and segment reporting, respectively. 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
Georgia Power
Plant Vogtle Unit 3 and Common Facilities Rate Proceeding
On June 15, 2021, Georgia Power filed an application with the Georgia PSC to adjust retail base rates to include a portion of costs related to its investment in Plant Vogtle Unit 3 and common facilities shared between Plant Vogtle Units 3 and 4, as well as the related costs of operation. The request includes an annual rate increase totaling approximately $370 million to be effective the month after Unit 3 is placed in service, which will be partially offset by a decrease in the NCCR tariff of approximately $116 million expected to be effective January 1, 2022. In addition, an estimated $45 million of fuel cost savings related to Unit 3 is already incorporated in Georgia Power's current fuel cost recovery rates. The Georgia PSC is scheduled to issue a final order in this proceeding on November 2, 2021. The ultimate outcome of this matter cannot be determined at this time. See Note (B) to the Condensed Financial Statements under "Georgia Power – Plant Vogtle Unit 3 and Common Facilities Rate Proceeding" herein for additional information.
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 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 June 2022 and March 2023, respectively, is $9.22 billion.
Georgia Power estimates the productivity impacts of the COVID-19 pandemic have consumed approximately three to four months of schedule margin previously embedded in the site work plan for Unit 3 and Unit 4. In addition, throughout 2020, the project continued to face challenges as described in Note (B) to the Condensed Financial Statements under "Georgia Power – Nuclear Construction" herein. As a result of these factors, in January 2021, Southern Nuclear further extended certain milestone dates, including the start of hot functional testing and fuel load for Unit 3, from those established in October 2020.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Following the January 2021 milestone extensions, Southern Nuclear has been performing additional construction remediation work necessary to ensure quality and design standards are met as system turnovers are completed to support hot functional testing and fuel load for Unit 3. Hot functional testing for Unit 3 was completed in July 2021. As a result of challenges including, but not limited to, construction productivity, construction remediation work, the pace of system turnovers, spent fuel pool repairs, and the timeframe and duration for hot functional and other testing, at the end of the second quarter 2021, Southern Nuclear further extended certain milestone dates, including the fuel load for Unit 3, from those established in January 2021. The site work plan currently targets fuel load for Unit 3 in the fourth quarter 2021 and an in-service date of March 2022. As the site work plan includes minimal margin to these milestone dates, an in-service date in the second quarter 2022 for Unit 3 is projected, although any further delays could result in a later in-service date.
As the result of productivity challenges, at the end of the second quarter 2021, Southern Nuclear also further extended milestone dates for Unit 4 from those established in January 2021. The site work plan targets an in-service date of November 2022 and primarily depends on overall construction productivity and production levels significantly improving as well as appropriate levels of craft laborers, particularly electricians and pipefitters, being added and maintained. As the site work plan includes minimal margin to the milestone dates, an in-service date in the first quarter 2023 for Unit 4 is projected, although any further delays could result in a later in-service date.
As of March 31, 2021, approximately $84 million of the construction contingency established in the fourth quarter 2020 was assigned to the base capital cost forecast for costs primarily associated with the schedule extension for Unit 3 to December 2021, construction productivity, support resources, and construction remediation work. Georgia Power increased its total capital cost forecast as of March 31, 2021 by adding $48 million to the remaining construction contingency. Considering the factors above, during the second quarter 2021, all of the remaining construction contingency previously established and an additional $341 million was assigned to the base capital cost forecast for costs primarily associated with the schedule extensions for Units 3 and 4 described above, construction remediation work for Unit 3, and construction productivity and support resources for Units 3 and 4. Georgia Power also increased its total capital cost forecast as of June 30, 2021 by adding $119 million to replenish construction contingency.
After considering the significant level of uncertainty that exists regarding the future recoverability of these costs since the ultimate outcome of these matters is subject to the outcome of future assessments by management, as well as Georgia PSC decisions in future regulatory proceedings, Georgia Power recorded pre-tax charges to income in the first quarter 2021 and the second quarter 2021 of $48 million ($36 million after tax) and $460 million ($343 million after tax), respectively, for the increases in the total project capital cost forecast. As and when these amounts are spent, Georgia Power may request the Georgia PSC to evaluate those expenditures for rate recovery.
The ultimate impact of the COVID-19 pandemic and other factors on the construction schedule and budget 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.
Mississippi Power
On April 15, 2021, Mississippi Power filed its 2021 IRP with the Mississippi PSC. The filing includes a schedule to retire Plant Watson Unit 4 (268 MWs) and Mississippi Power's 40% ownership interest in Plant Greene County Units 1 and 2 (103 MWs each) in December 2023, 2025, and 2026, respectively, consistent with each unit's remaining useful life in the most recent approved depreciation studies. In addition, the schedule reflects the early retirement of Mississippi Power's 50% undivided ownership interest in Plant Daniel Units 1 and 2 (502 MWs) by the end of 2027. If no deficiencies are noted that would require re-evaluation or resubmission of the IRP, the
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Mississippi PSC's review period will conclude on August 13, 2021. The ultimate outcome of this matter cannot be determined at this time.
During the first half of 2021, the Mississippi PSC approved the following rate changes related to Mississippi Power's annual rate filings for 2021:
•an annual increase in revenues related to the ad valorem tax adjustment factor of approximately $28 million, which became effective with the first billing cycle of May 2021,
•an annual increase in revenues related to PEP of approximately $16 million, or 1.8%, which became effective with the first billing cycle of April 2021 in accordance with the PEP rate schedule, and
•an annual decrease in revenues related to the ECO Plan of approximately $9 million, which became effective with the first billing cycle of July 2021.
See Note (B) to the Condensed Financial Statements under "Mississippi Power" herein for additional information.
Southern Power
During the six months ended June 30, 2021, Southern Power continued construction of the 88-MW Garland and 72-MW Tranquillity battery energy storage facilities and the 118-MW Glass Sands wind facility. On March 26, 2021, Southern Power purchased a controlling membership interest in the approximately 300-MW Deuel Harvest wind facility located in Deuel County, South Dakota from Invenergy Renewables, LLC. See Note (K) to the Condensed Financial Statements under "Southern Power" herein for additional information.
At June 30, 2021, 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 generation facilities' net book value (or expected in-service value for facilities under construction) as the investment amount was 93% through 2025 and 91% through 2030, with an average remaining contract duration of approximately 14 years.
Southern Company Gas
On April 28, 2021, Atlanta Gas Light filed its first Integrated Capacity and Delivery Plan (i-CDP) with the Georgia PSC, which includes a series of ongoing and proposed pipeline safety, reliability, and growth programs for the next 10 years, as well as the required capital investments and related costs to implement the programs. The Georgia PSC is scheduled to vote on this matter in November 2021.
On May 10, 2021, Virginia Natural Gas, the Virginia Commission staff, and other intervenors entered into a stipulation agreement related to Virginia Natural Gas' June 2020 general rate case filing, which allows for a $43 million increase in annual base rate revenues, including $14 million related to the recovery of investments under the SAVE program, based on a ROE of 9.5% and an equity ratio of 51.9%. On July 8, 2021, the hearing examiner issued a report recommending adoption of the stipulation agreement. The Virginia Commission is expected to rule on this matter by September 2021. Interim rate adjustments became effective as of November 1, 2020, subject to refund, based on Virginia Natural Gas' original request for an increase of approximately $50 million.
On July 21, 2021, Atlanta Gas Light filed its annual GRAM filing with the Georgia PSC requesting an annual base rate increase of $49 million. Resolution of the GRAM filing is expected by December 31, 2021, with the new rates to become effective January 1, 2022.
See Note (B) to the Condensed Financial Statements under "Southern Company Gas" herein for additional information. The ultimate outcome of these matters cannot be determined at this time.
During the second quarter 2021, Southern Company Gas recorded a pre-tax impairment charge of $82 million ($58 million after tax) related to its equity method investment in the PennEast Pipeline project. See Notes (C) and (E) to
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
the Condensed Financial Statements herein under "Other Matters – Southern Company Gas" and "Southern Company Gas," respectively, for additional information.
On July 1, 2021, Southern Company Gas affiliates completed the sale of Sequent to Williams Field Services Group for a total cash purchase price of $150 million, including estimated working capital adjustments. The preliminary gain associated with the transaction is approximately $90 million, which will be recorded in the third quarter 2021. See Note (K) to the Condensed Financial Statements under "Southern Company Gas" herein for additional information.
RESULTS OF OPERATIONS
Southern Company
Net Income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Second Quarter 2021 vs. Second Quarter 2020
|
|
Year-To-Date 2021 vs. Year-To-Date 2020
|
|
(change in millions)
|
|
(% change)
|
|
(change in millions)
|
|
(% change)
|
|
$(240)
|
|
(39.2)
|
|
$28
|
|
1.9
|
Consolidated net income attributable to Southern Company was $372 million ($0.35 per share) for the second quarter 2021 compared to $612 million ($0.58 per share) for the corresponding period in 2020. The decrease was primarily due to a $232 million increase in after-tax charges related to the construction of Plant Vogtle Units 3 and 4 at Georgia Power and an after-tax impairment charge related to the PennEast Pipeline project at Southern Company Gas, partially offset by a decrease in after-tax leveraged lease impairment charges. The decrease was also due to higher non-fuel operations and maintenance costs, partially offset by higher retail electric revenues associated with rates and pricing and sales growth.
Consolidated net income attributable to Southern Company was $1.51 billion ($1.42 per share) for year-to-date 2021 compared to $1.48 billion ($1.40 per share) for the corresponding period in 2020. The increase was primarily due to increases in both natural gas revenues and retail electric revenues associated with colder weather in the first quarter 2021 as compared to the corresponding period in 2020, higher retail electric revenues associated with rates and pricing and sales growth, and higher wholesale electric capacity revenues, largely offset by higher non-fuel operations and maintenance costs and the net impact of the charges in the second quarter 2021 and 2020, as described previously.
Retail Electric Revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Second Quarter 2021 vs. Second Quarter 2020
|
|
Year-To-Date 2021 vs. Year-To-Date 2020
|
|
(change in millions)
|
|
(% change)
|
|
(change in millions)
|
|
(% change)
|
|
$417
|
|
13.1
|
|
$681
|
|
10.9
|
In the second quarter 2021, retail electric revenues were $3.6 billion compared to $3.2 billion for the corresponding period in 2020. For year-to-date 2021, retail electric revenues were $6.9 billion compared to $6.3 billion for the corresponding period in 2020.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Details of the changes in retail electric revenues were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Second Quarter 2021
|
|
Year-To-Date 2021
|
|
|
(in millions)
|
|
(% change)
|
|
(in millions)
|
|
(% change)
|
|
Retail electric – prior year
|
$
|
3,182
|
|
|
|
|
$
|
6,260
|
|
|
|
|
Estimated change resulting from –
|
|
|
|
|
|
|
|
|
Rates and pricing
|
112
|
|
|
3.5
|
%
|
|
137
|
|
|
2.2
|
%
|
|
Sales growth
|
86
|
|
|
2.7
|
|
|
72
|
|
|
1.2
|
|
|
Weather
|
18
|
|
|
0.6
|
|
|
106
|
|
|
1.7
|
|
|
Fuel and other cost recovery
|
201
|
|
|
6.3
|
|
|
366
|
|
|
5.8
|
|
|
Retail electric – current year
|
$
|
3,599
|
|
|
13.1
|
%
|
|
$
|
6,941
|
|
|
10.9
|
%
|
Revenues associated with changes in rates and pricing increased in the second quarter and year-to-date 2021 when compared to the corresponding periods in 2020 primarily due to an increase in Alabama Power's Rate RSE effective January 1, 2021 and increases at Georgia Power resulting from higher contributions by commercial and industrial customers with variable demand-driven pricing, higher pricing effects associated with decreased residential customer usage, and increased ECCR tariff revenues associated with higher KWH sales, partially offset by decreases in the NCCR tariff effective January 1, 2021. See Note 2 to the financial statements under "Alabama Power – Rate RSE" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Georgia Power – Nuclear Construction – Regulatory Matters" herein for additional information.
Revenues attributable to changes in sales increased in the second quarter and year-to-date 2021 when compared to the corresponding periods in 2020. Weather-adjusted residential KWH sales decreased 2.0% and 0.4% in the second quarter and year-to-date 2021, respectively, when compared to the corresponding periods in 2020 as customer usage decreased, primarily due to shelter-in-place orders in effect during 2020, partially offset by customer growth. Weather-adjusted commercial KWH sales increased 8.7% and 2.7% in the second quarter and year-to-date 2021, respectively, and industrial KWH sales increased 11.7% and 4.0% in the second quarter and year-to-date 2021, respectively, when compared to the corresponding periods in 2020, primarily due to the negative impact of the COVID-19 pandemic on energy demand in 2020.
Fuel and other cost recovery revenues increased $201 million and $366 million in the second quarter and year-to-date 2021, respectively, compared to the corresponding periods in 2020 primarily due to higher fuel and purchased power costs. Electric rates for the traditional electric operating companies include provisions to adjust billings for fluctuations in fuel costs, including the energy component of purchased power costs. Under these provisions, fuel revenues generally equal fuel expenses, including the energy component of PPA costs, and do not affect net income. The traditional electric operating companies each have one or more regulatory mechanisms to recover other costs such as environmental and other compliance costs, storm damage, new plants, and PPA capacity costs.
Wholesale Electric Revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Second Quarter 2021 vs. Second Quarter 2020
|
|
Year-To-Date 2021 vs. Year-To-Date 2020
|
|
(change in millions)
|
|
(% change)
|
|
(change in millions)
|
|
(% change)
|
|
$74
|
|
15.7
|
|
$202
|
|
22.7
|
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
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
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.
In the second quarter 2021, wholesale electric revenues were $546 million compared to $472 million for the corresponding period in 2020. For year-to-date 2021, wholesale electric revenues were $1.1 billion compared to $0.9 billion for the corresponding period in 2020. Increases in energy revenues of $51 million and $153 million for the second quarter and year-to-date 2021, respectively, reflect higher natural gas prices when compared to the corresponding periods in 2020. In addition, increases in capacity revenues of $23 million and $49 million for the second quarter and year-to-date 2021, respectively, primarily resulted from a power sales agreement at Alabama Power that began in September 2020 and new natural gas PPAs at Southern Power that began subsequent to the second quarter 2020.
Other Electric Revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Second Quarter 2021 vs. Second Quarter 2020
|
|
Year-To-Date 2021 vs. Year-To-Date 2020
|
|
(change in millions)
|
|
(% change)
|
|
(change in millions)
|
|
(% change)
|
|
$7
|
|
4.2
|
|
$26
|
|
8.1
|
For year-to-date 2021, other electric revenues were $346 million compared to $320 million for the corresponding period in 2020. The increase was primarily due to increases of $16 million in customer fees largely resulting from the COVID-19 pandemic-related temporary suspensions of disconnections and late fees in 2020 for the traditional electric operating companies, $5 million related to outdoor lighting sales at Georgia Power, and $3 million in transmission services.
Natural Gas Revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Second Quarter 2021 vs. Second Quarter 2020
|
|
Year-To-Date 2021 vs. Year-To-Date 2020
|
|
(change in millions)
|
|
(% change)
|
|
(change in millions)
|
|
(% change)
|
|
$41
|
|
6.4
|
|
$486
|
|
25.8
|
In the second quarter 2021, natural gas revenues were $677 million compared to $636 million for the corresponding period in 2020. For year-to-date 2021, natural gas revenues were $2.4 billion compared to $1.9 billion for the corresponding period in 2020.
Details of the changes in natural gas revenues were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Second Quarter 2021
|
|
Year-To-Date 2021
|
|
|
(in millions)
|
|
(% change)
|
|
(in millions)
|
|
(% change)
|
|
Natural gas revenues – prior year
|
$
|
636
|
|
|
|
|
$
|
1,885
|
|
|
|
|
Estimated change resulting from –
|
|
|
|
|
|
|
|
|
Infrastructure replacement programs and base rate changes
|
41
|
|
|
6.4
|
%
|
|
81
|
|
|
4.3
|
%
|
|
Gas costs and other cost recovery
|
88
|
|
|
13.8
|
|
|
240
|
|
|
12.7
|
|
|
|
|
|
|
|
|
|
|
|
Wholesale gas services
|
(91)
|
|
|
(14.3)
|
|
|
156
|
|
|
8.3
|
|
|
Other
|
3
|
|
|
0.5
|
|
|
9
|
|
|
0.5
|
|
|
Natural gas revenues – current year
|
$
|
677
|
|
|
6.4
|
%
|
|
$
|
2,371
|
|
|
25.8
|
%
|
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Revenues from infrastructure replacement programs and base rate changes at the natural gas distribution utilities increased in the second quarter and year-to-date 2021 compared to the corresponding periods in 2020 primarily due to rate increases at Atlanta Gas Light, Virginia Natural Gas, and Chattanooga Gas and continued investment in infrastructure replacement. See Note 2 to the financial statements under "Southern Company Gas – Rate Proceedings" in Item 8 of the Form 10-K for additional information.
Revenues associated with gas costs and other cost recovery increased in the second quarter and year-to-date 2021 compared to the corresponding periods in 2020 primarily due to higher volumes sold and higher gas cost recovery. 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 Southern Company Gas' wholesale gas services business decreased in the second quarter 2021 compared to the corresponding period in 2020 due to derivative losses, partially offset by higher commercial activities. Revenues from wholesale gas services increased for year-to-date 2021 compared to the corresponding period in 2020 due to higher volumes sold and higher commercial activities as a result of Winter Storm Uri, partially offset by derivative losses. See Note (K) to the Condensed Financial Statements under "Southern Company Gas" herein for information regarding the sale of Sequent on July 1, 2021.
Other Revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Second Quarter 2021 vs. Second Quarter 2020
|
|
Year-To-Date 2021 vs. Year-To-Date 2020
|
|
(change in millions)
|
|
(% change)
|
|
(change in millions)
|
|
(% change)
|
|
$39
|
|
24.1
|
|
$75
|
|
26.4
|
In the second quarter 2021, other revenues were $201 million compared to $162 million for the corresponding period in 2020. For year-to-date 2021, other revenues were $359 million compared to $284 million for the corresponding period in 2020. The increases for the second quarter and year-to-date 2021 were primarily due to increases of $28 million and $38 million, respectively, in unregulated sales of products and services at Alabama Power and Georgia Power and increases of $15 million and $32 million, respectively, in distributed infrastructure projects at PowerSecure.
Fuel and Purchased Power Expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Second Quarter 2021 vs. Second Quarter 2020
|
|
Year-To-Date 2021 vs. Year-To-Date 2020
|
|
|
(change in millions)
|
|
(% change)
|
|
(change in millions)
|
|
(% change)
|
|
Fuel
|
$
|
227
|
|
|
36.6
|
|
$
|
439
|
|
|
34.9
|
|
Purchased power
|
17
|
|
|
8.5
|
|
43
|
|
|
11.3
|
|
Total fuel and purchased power expenses
|
$
|
244
|
|
|
|
|
$
|
482
|
|
|
|
In the second quarter 2021, total fuel and purchased power expenses were $1.1 billion compared to $0.8 billion for the corresponding period in 2020. The increase was primarily the result of a $163 million increase in the average cost of fuel and purchased power and an $81 million net increase in the volume of KWHs generated and purchased.
For year-to-date 2021, total fuel and purchased power expenses were $2.1 billion compared to $1.6 billion for the corresponding period in 2020. The increase was primarily the result of a $322 million increase in the average cost of fuel and purchased power and a $160 million net increase 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.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Details of the Southern Company system's generation and purchased power were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Second Quarter 2021
|
Second Quarter 2020
|
Year-To-Date 2021
|
Year-To-Date 2020
|
|
Total generation (in billions of KWHs)(a)
|
43
|
41
|
86
|
82
|
|
Total purchased power (in billions of KWHs)
|
4
|
4
|
8
|
9
|
|
Sources of generation (percent)(a) —
|
|
|
|
|
|
Gas
|
47
|
55
|
46
|
54
|
|
Coal
|
22
|
19
|
23
|
19
|
|
Nuclear
|
18
|
12
|
18
|
13
|
|
Hydro
|
4
|
5
|
4
|
6
|
|
Wind, Solar, and Other
|
9
|
9
|
9
|
8
|
|
Cost of fuel, generated (in cents per net KWH)—
|
|
|
|
|
|
Gas(a)
|
2.58
|
1.89
|
2.56
|
1.92
|
|
Coal
|
2.87
|
2.96
|
2.85
|
2.92
|
|
Nuclear
|
0.75
|
0.78
|
0.75
|
0.78
|
|
Average cost of fuel, generated (in cents per net KWH)(a)
|
2.28
|
1.79
|
2.27
|
1.82
|
|
Average cost of purchased power (in cents per net KWH)(b)
|
5.65
|
4.74
|
5.37
|
4.30
|
(a)Second quarter and year-to-date 2021 excludes Central Alabama Generating Station KWHs and associated cost of fuel as its fuel is 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 purchased by the Southern Company system for tolling agreements where power is generated by the provider.
Fuel
In the second quarter 2021, fuel expense was $848 million compared to $621 million for the corresponding period in 2020. The increase was primarily due to an 84.8% increase in the volume of KWHs generated by coal and a 36.5% increase in the average cost of natural gas per KWH generated, partially offset by an 8.6% decrease in the volume of KWHs generated by natural gas.
For year-to-date 2021, fuel expense was $1.7 billion compared to $1.3 billion for the corresponding period in 2020. The increase was primarily due to an 81.8% increase in the volume of KWHs generated by coal, a 27.6% decrease in the volume of KWHs generated by hydro, and a 33.3% increase in the average cost of natural gas per KWH generated, partially offset by an 8.9% decrease in the volume of KWHs generated by natural gas.
Purchased Power
In the second quarter 2021, purchased power expense was $217 million compared to $200 million for the corresponding period in 2020. The increase was primarily due to a 19.2% increase in the average cost per KWH purchased primarily due to higher natural gas prices, partially offset by a 4.5% decrease in the volume of KWHs purchased.
For year-to-date 2021, purchased power expense was $424 million compared to $381 million for the corresponding period in 2020. The increase was primarily due to a 24.9% increase in the average cost per KWH purchased primarily due to higher natural gas prices, partially offset by a 6.6% decrease 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.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Cost of Natural Gas
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Second Quarter 2021 vs. Second Quarter 2020
|
|
Year-To-Date 2021 vs. Year-To-Date 2020
|
|
(change in millions)
|
|
(% change)
|
|
(change in millions)
|
|
(% change)
|
|
$87
|
|
60.4
|
|
$231
|
|
39.6
|
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 87% of total cost of natural gas for both the second quarter and year-to-date 2021.
In the second quarter 2021, cost of natural gas was $231 million compared to $144 million for the corresponding period in 2020. The increase reflects higher gas cost recovery and a 65.0% increase in natural gas prices in the second quarter 2021 compared to the corresponding period in 2020.
For year-to-date 2021, cost of natural gas was $814 million compared to $583 million for the corresponding period in 2020. The increase reflects higher volumes sold due to colder weather and higher gas cost recovery for year-to-date 2021 compared to the corresponding period in 2020. The increase also reflects a 50.6% increase in natural gas prices for year-to-date 2021 compared to the corresponding period in 2020.
Cost of Other Sales
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Second Quarter 2021 vs. Second Quarter 2020
|
|
Year-To-Date 2021 vs. Year-To-Date 2020
|
|
(change in millions)
|
|
(% change)
|
|
(change in millions)
|
|
(% change)
|
|
$29
|
|
39.2
|
|
$56
|
|
43.4
|
In the second quarter 2021, cost of other sales was $103 million compared to $74 million for the corresponding period in 2020. For year-to-date 2021, cost of other sales was $185 million compared to $129 million for the corresponding period in 2020. The increases for second quarter and year-to-date 2021 primarily relate to increases of $16 million and $23 million, respectively, in unregulated power delivery construction and maintenance projects at Georgia Power and $12 million and $22 million, respectively, in distributed infrastructure projects at PowerSecure.
Other Operations and Maintenance Expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Second Quarter 2021 vs. Second Quarter 2020
|
|
Year-To-Date 2021 vs. Year-To-Date 2020
|
|
(change in millions)
|
|
(% change)
|
|
(change in millions)
|
|
(% change)
|
|
$235
|
|
19.5
|
|
$312
|
|
12.5
|
In the second quarter 2021, other operations and maintenance expenses were $1.4 billion compared to $1.2 billion for the corresponding period in 2020. The increase reflects increases of $68 million in scheduled generation outage and maintenance expenses, $44 million in transmission and distribution expenses, including $11 million of reliability NDR credits at Alabama Power, and $16 million in compliance and environmental expenses at the traditional electric operating companies. These increases reflect the impacts of cost containment activities implemented for 2020 during the COVID-19 pandemic. Also contributing to the increase was an increase of $46 million in compensation and benefit expenses.
For year-to-date 2021, other operations and maintenance expenses were $2.8 billion compared to $2.5 billion for the corresponding period in 2020. The increase reflects increases of $58 million in scheduled generation outage and maintenance expenses, $52 million in transmission and distribution expenses, including $22 million of reliability NDR credits at Alabama Power, and $15 million in compliance and environmental expenses at the traditional electric operating companies. These increases reflect the impacts of cost containment activities implemented for
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
2020 during the COVID-19 pandemic. Also contributing to the increase was an increase of $101 million in compensation and benefit expenses and an $18 million decrease in nuclear property insurance refunds.
Depreciation and Amortization
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Second Quarter 2021 vs. Second Quarter 2020
|
|
Year-To-Date 2021 vs. Year-To-Date 2020
|
|
(change in millions)
|
|
(% change)
|
|
(change in millions)
|
|
(% change)
|
|
$18
|
|
2.1
|
|
$32
|
|
1.8
|
In the second quarter 2021, depreciation and amortization was $891 million compared to $873 million for the corresponding period in 2020. For year-to-date 2021, depreciation and amortization was $1.8 billion compared to $1.7 billion for the corresponding period in 2020. The increases for the second quarter and year-to-date 2021 primarily reflect increases of $42 million and $79 million, respectively, in depreciation associated with additional plant in service, partially offset by decreased amortization of regulatory assets related to CCR AROs of $22 million and $44 million, respectively, under the terms of Georgia Power's 2019 ARP. See Note (B) to the Condensed Financial Statements under "Georgia Power – Rate Plan" herein and Note 2 to the financial statements under "Georgia Power – Rate Plans – 2019 ARP" in Item 8 of the Form 10-K for additional information regarding Georgia Power's recovery of costs associated with CCR AROs.
Taxes Other Than Income Taxes
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Second Quarter 2021 vs. Second Quarter 2020
|
|
Year-To-Date 2021 vs. Year-To-Date 2020
|
|
(change in millions)
|
|
(% change)
|
|
(change in millions)
|
|
(% change)
|
|
$15
|
|
5.0
|
|
$28
|
|
4.5
|
In the second quarter 2021, taxes other than income taxes were $313 million compared to $298 million for the corresponding period in 2020. The increase primarily reflects increases at Georgia Power of $9 million in property taxes primarily from higher assessed values, including the impact of Plant Vogtle Units 3 and 4 construction, and $7 million in municipal franchise fees largely related to higher retail revenues.
For year-to-date 2021, taxes other than income taxes were $657 million compared to $629 million for the corresponding period in 2020. The increase primarily reflects increases of $18 million in property taxes primarily from higher assessed values, including the impact of Plant Vogtle Units 3 and 4 construction, and $10 million in revenue tax expenses as a result of higher natural gas revenues at Southern Company Gas.
Estimated Loss on Plant Vogtle Units 3 and 4
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Second Quarter 2021 vs. Second Quarter 2020
|
|
Year-To-Date 2021 vs. Year-To-Date 2020
|
|
(change in millions)
|
|
(% change)
|
|
(change in millions)
|
|
(% change)
|
|
$311
|
|
208.7
|
|
$359
|
|
240.9
|
In the second quarter 2021 and 2020, estimated probable losses on Plant Vogtle Units 3 and 4 of $460 million and $149 million, respectively, were recorded at Georgia Power. For year-to-date 2021 and 2020, estimated probable losses on Plant Vogtle Units 3 and 4 of $508 million and $149 million, respectively, were recorded at Georgia Power. These losses reflect 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)
(Gain) Loss on Dispositions, Net
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Second Quarter 2021 vs. Second Quarter 2020
|
|
Year-To-Date 2021 vs. Year-To-Date 2020
|
|
(change in millions)
|
|
(% change)
|
|
(change in millions)
|
|
(% change)
|
|
$11
|
|
N/M
|
|
$15
|
|
38.5
|
N/M - Not meaningful
In the second quarter 2021, gain on dispositions, net was $11 million compared to an immaterial loss for the corresponding period in 2020. The increase primarily reflects $6 million in gains at Alabama Power primarily from property sales and a $5 million gain on the sale of Pivotal LNG at Southern Company Gas.
For year-to-date 2021, gain on dispositions, net was $54 million compared to $39 million for the corresponding period in 2020. The increase primarily reflects $39 million in gains at Southern Power, primarily from contributions of wind turbine equipment to various equity method investments, $10 million in gains at Alabama Power primarily from property sales, and a $6 million gain on the sale of Pivotal LNG at Southern Company Gas, partially offset by a $39 million gain at Southern Power related to the sale of Plant Mankato in the first quarter 2020.
See Note (E) to the Condensed Financial Statements under "Southern Power" herein, Note (K) to the Condensed Financial Statements under "Southern Power" and "Southern Company Gas" herein, and Note 15 to the financial statements under "Southern Power – Sales of Natural Gas and Biomass Plants" and "Southern Company Gas – Sale of Pivotal LNG and Atlantic Coast Pipeline" in Item 8 of the Form 10-K for additional information.
Allowance for Equity Funds Used During Construction
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Second Quarter 2021 vs. Second Quarter 2020
|
|
Year-To-Date 2021 vs. Year-To-Date 2020
|
|
(change in millions)
|
|
(% change)
|
|
(change in millions)
|
|
(% change)
|
|
$10
|
|
28.6
|
|
$22
|
|
32.4
|
In the second quarter 2021, allowance for equity funds used during construction was $45 million compared to $35 million for the corresponding period in 2020. For year-to-date 2021, allowance for equity funds used during construction was $90 million compared to $68 million for the corresponding period in 2020. The increases were primarily due to increases at Georgia Power, primarily associated with 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 regarding Plant Vogtle Units 3 and 4.
Earnings (Loss) from Equity Method Investments
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Second Quarter 2021 vs. Second Quarter 2020
|
|
Year-To-Date 2021 vs. Year-To-Date 2020
|
|
(change in millions)
|
|
(% change)
|
|
(change in millions)
|
|
(% change)
|
|
$(70)
|
|
N/M
|
|
$(67)
|
|
N/M
|
N/M - Not meaningful
In the second quarter 2021, loss from equity method investments was $40 million compared to earnings of $30 million for the corresponding period in 2020. For year-to-date 2021, earnings from equity method investments were $5 million compared to $72 million for the corresponding period in 2020. The decreases were primarily due to a pre-tax impairment charge of $82 million in the second quarter 2021 related to the PennEast Pipeline project at Southern Company Gas. The decreases were partially offset by increases in investment income at Southern Holdings of $12 million and $17 million for the second quarter and year-to-date 2021, respectively. See Notes (C) and (E) to the Condensed Financial Statements herein under "Other Matters – Southern Company Gas" and "Southern Company Gas," respectively, for additional information.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Impairment of Leveraged Leases
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Second Quarter 2021 vs. Second Quarter 2020
|
|
Year-To-Date 2021 vs. Year-To-Date 2020
|
|
(change in millions)
|
|
(% change)
|
|
(change in millions)
|
|
(% change)
|
|
$(147)
|
|
N/M
|
|
$(147)
|
|
N/M
|
N/M - Not meaningful
In the second quarter 2021 and 2020, impairment charges of $7 million and $154 million, respectively, were recorded related to leveraged lease investments at Southern Holdings. See Note (K) to the Condensed Financial Statements under "Assets and Liabilities Held for Sale" herein and Note 3 to the financial statements under "Other Matters – Southern Company" in Item 8 of the Form 10-K for additional information.
Other Income (Expense), Net
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Second Quarter 2021 vs. Second Quarter 2020
|
|
Year-To-Date 2021 vs. Year-To-Date 2020
|
|
(change in millions)
|
|
(% change)
|
|
(change in millions)
|
|
(% change)
|
|
$7
|
|
6.9
|
|
$(37)
|
|
(18.1)
|
In the second quarter 2021, other income (expense), net was $108 million compared to $101 million for the corresponding period in 2020. The increase was primarily due to a $36 million increase in non-service cost-related retirement benefits income, partially offset by $26 million in charitable contributions in the second quarter 2021 at Southern Company Gas.
For year-to-date 2021, other income (expense), net was $167 million compared to $204 million for the corresponding period in 2020. The decrease was primarily due to $101 million in charitable contributions at Southern Company Gas, partially offset by a $71 million increase in non-service cost-related retirement benefits income.
See Note (H) to the Condensed Financial Statements herein for additional information.
Income Taxes (Benefit)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Second Quarter 2021 vs. Second Quarter 2020
|
|
Year-To-Date 2021 vs. Year-To-Date 2020
|
|
(change in millions)
|
|
(% change)
|
|
(change in millions)
|
|
(% change)
|
|
$(17)
|
|
N/M
|
|
$28
|
|
18.7
|
N/M - Not meaningful
In the second quarter 2021, income tax benefit was $12 million compared to income tax expense of $5 million for the corresponding period in 2020. The change was primarily due to lower pre-tax earnings, partially offset by the tax impact of the second quarter 2020 charge to earnings associated with a leveraged lease investment.
For year-to-date 2021, income taxes were $178 million compared to $150 million for the corresponding period in 2020. The increase was primarily due to the tax impact of the second quarter 2020 charge to earnings associated with a leveraged lease investment.
See Note (G) to the Condensed Financial Statements herein and Note 3 to the financial statements under "Other Matters – Southern Company" in Item 8 of the Form 10-K for additional information.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Alabama Power
Net Income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Second Quarter 2021 vs. Second Quarter 2020
|
|
Year-To-Date 2021 vs. Year-To-Date 2020
|
|
(change in millions)
|
|
(% change)
|
|
(change in millions)
|
|
(% change)
|
|
$33
|
|
11.1
|
|
$112
|
|
19.4
|
Alabama Power's net income after dividends on preferred stock for the second quarter 2021 was $331 million compared to $298 million for the corresponding period in 2020. Alabama Power's net income after dividends on preferred stock for year-to-date 2021 was $690 million compared to $578 million for the corresponding period in 2020. The increases were primarily due to an increase in retail revenues associated with a Rate RSE adjustment effective in January 2021 and higher customer usage, as well as additional wholesale capacity revenues related to a power sales agreement that began in September 2020. Also contributing to the year-to-date 2021 increase was colder weather in Alabama Power's service territory in the first quarter 2021 compared to the corresponding period in 2020. The second quarter and year-to-date 2021 increases were partially offset by an increase in operations and maintenance expenses and depreciation.
Retail Revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Second Quarter 2021 vs. Second Quarter 2020
|
|
Year-To-Date 2021 vs. Year-To-Date 2020
|
|
(change in millions)
|
|
(% change)
|
|
(change in millions)
|
|
(% change)
|
|
$131
|
|
10.7
|
|
$279
|
|
11.5
|
In the second quarter 2021, retail revenues were $1.35 billion compared to $1.22 billion for the corresponding period in 2020. For year-to-date 2021, retail revenues were $2.71 billion compared to $2.43 billion for the corresponding period in 2020.
Details of the changes in retail revenues were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Second Quarter 2021
|
|
Year-To-Date 2021
|
|
|
(in millions)
|
|
(% change)
|
|
(in millions)
|
|
(% change)
|
|
Retail – prior year
|
$
|
1,223
|
|
|
|
|
$
|
2,427
|
|
|
|
|
Estimated change resulting from –
|
|
|
|
|
|
|
|
|
Rates and pricing
|
66
|
|
|
5.4
|
%
|
|
116
|
|
|
4.8
|
%
|
|
Sales growth
|
16
|
|
|
1.3
|
|
|
13
|
|
|
0.5
|
|
|
Weather
|
3
|
|
|
0.2
|
|
|
42
|
|
|
1.7
|
|
|
Fuel and other cost recovery
|
46
|
|
|
3.8
|
|
|
108
|
|
|
4.5
|
|
|
Retail – current year
|
$
|
1,354
|
|
|
10.7
|
%
|
|
$
|
2,706
|
|
|
11.5
|
%
|
Revenues associated with changes in rates and pricing increased in the second quarter and year-to-date 2021 when compared to the corresponding periods in 2020 primarily due to a Rate RSE increase effective January 1, 2021. See Note 2 to the financial statements under "Alabama Power – Rate RSE" in Item 8 of the Form 10-K for additional information.
Revenues attributable to changes in sales increased in the second quarter and year-to-date 2021 when compared to the corresponding periods in 2020. Weather-adjusted residential KWH sales decreased 3.9% and 2.0% in the second quarter and year-to-date 2021, respectively, when compared to the corresponding periods in 2020 primarily due to safer-at-home guidelines in effect during 2020. Weather-adjusted commercial KWH sales increased 7.8% and 2.8% in the second quarter and year-to-date 2021, respectively, and industrial KWH sales increased 10.0% and 1.8% in the second quarter and year-to-date 2021, respectively, when compared to the corresponding periods in 2020, primarily due to the negative impact of the COVID-19 pandemic on energy demand in 2020.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Fuel and other cost recovery revenues increased in the second quarter and year-to-date 2021 when compared to the corresponding periods in 2020 primarily due to increases in generation and the average cost of fuel. 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 2021 vs. Second Quarter 2020
|
|
Year-To-Date 2021 vs. Year-To-Date 2020
|
|
(change in millions)
|
|
(% change)
|
|
(change in millions)
|
|
(% change)
|
|
$31
|
|
57.4
|
|
$67
|
|
60.4
|
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.
In the second quarter 2021, wholesale revenues from sales to non-affiliates were $85 million compared to $54 million for the corresponding period in 2020. For year-to-date 2021, wholesale revenues from sales to non-affiliates were $178 million compared to $111 million for the corresponding period in 2020. The second quarter and year-to-date 2021 increases consisted of increases in capacity revenues of $18 million and $35 million, respectively, primarily related to a power sales agreement that began in September 2020 and increases in energy revenues of $13 million and $32 million, respectively, primarily due to higher natural gas prices.
Wholesale Revenues – Affiliates
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Second Quarter 2021 vs. Second Quarter 2020
|
|
Year-To-Date 2021 vs. Year-To-Date 2020
|
|
(change in millions)
|
|
(% change)
|
|
(change in millions)
|
|
(% change)
|
|
$17
|
|
242.9
|
|
$29
|
|
111.5
|
Wholesale revenues from sales to affiliated companies will vary depending on demand and the availability and cost of generating resources at each company. These affiliate sales are made in accordance with the IIC, as approved by the FERC. These transactions do not have a significant impact on earnings since this energy is generally sold at marginal cost and energy purchases are generally offset by energy revenues through Alabama Power's energy cost recovery clause.
In the second quarter 2021, wholesale revenues from sales to affiliates were $24 million compared to $7 million for the corresponding period in 2020. For year-to-date 2021, wholesale revenues from sales to affiliates were $55 million compared to $26 million for the corresponding period in 2020. The second quarter and year-to-date 2021 increases were primarily due to increases of 133.8% and 50.1%, respectively, in the price of energy as a result of higher natural gas prices and increases of 51.9% and 43.5%, respectively, in KWH sales due to increased demand for Alabama Power's available lower cost generation compared to the corresponding periods in 2020.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Other Revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Second Quarter 2021 vs. Second Quarter 2020
|
|
Year-To-Date 2021 vs. Year-To-Date 2020
|
|
(change in millions)
|
|
(% change)
|
|
(change in millions)
|
|
(% change)
|
|
$12
|
|
14.8
|
|
$24
|
|
15.8
|
In the second quarter 2021, other revenues were $93 million compared to $81 million for the corresponding period in 2020. For year-to-date 2021, other revenues were $176 million compared to $152 million for the corresponding period in 2020. The second quarter and year-to-date 2021 increases were primarily due to increases of $12 million and $15 million, respectively, in unregulated sales of products and services. In addition, the year-to-date 2021 increase included a $6 million increase in customer fees largely resulting from the COVID-19 pandemic-related temporary suspensions of disconnections and late fees in 2020.
Fuel and Purchased Power Expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Second Quarter 2021 vs. Second Quarter 2020
|
|
Year-To-Date 2021 vs. Year-To-Date 2020
|
|
|
(change in millions)
|
|
(% change)
|
|
(change in millions)
|
|
(% change)
|
|
Fuel
|
$
|
64
|
|
|
32.2
|
|
|
$
|
139
|
|
|
33.5
|
|
|
Purchased power – non-affiliates
|
(1)
|
|
|
(2.0)
|
|
|
8
|
|
|
9.0
|
|
|
Purchased power – affiliates
|
9
|
|
|
30.0
|
|
|
20
|
|
|
40.8
|
|
|
Total fuel and purchased power expenses
|
$
|
72
|
|
|
|
|
$
|
167
|
|
|
|
In the second quarter 2021, total fuel and purchased power expenses were $350 million compared to $278 million for the corresponding period in 2020. The increase was primarily due a $42 million net increase related to the volume of KWHs generated and purchased and a $30 million increase in the average cost of fuel and purchased power.
For year-to-date 2021, total fuel and purchased power expenses were $720 million compared to $553 million for the corresponding period in 2020. The increase was primarily due to a $98 million increase related to the volume of KWHs generated and purchased and a $69 million increase in the average cost of fuel and purchased power.
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 2021
|
|
Second Quarter 2020
|
|
Year-To-Date 2021
|
|
Year-To-Date 2020
|
|
Total generation (in billions of KWHs)(a)
|
13
|
|
12
|
|
28
|
|
26
|
|
Total purchased power (in billions of KWHs)
|
2
|
|
2
|
|
3
|
|
3
|
|
Sources of generation (percent)(a) —
|
|
|
|
|
|
|
|
|
Coal
|
43
|
|
33
|
|
45
|
|
33
|
|
Nuclear
|
25
|
|
32
|
|
25
|
|
30
|
|
Gas
|
22
|
|
24
|
|
20
|
|
22
|
|
Hydro
|
10
|
|
11
|
|
10
|
|
15
|
|
Cost of fuel, generated (in cents per net KWH) —
|
|
|
|
|
|
|
|
|
Coal
|
2.73
|
|
2.82
|
|
2.74
|
|
2.72
|
|
Nuclear
|
0.69
|
|
0.75
|
|
0.71
|
|
0.75
|
|
Gas(a)
|
2.47
|
|
1.95
|
|
2.49
|
|
2.07
|
|
Average cost of fuel, generated (in cents per net KWH)(a)
|
2.10
|
|
1.85
|
|
2.12
|
|
1.86
|
|
Average cost of purchased power (in cents per net KWH)(b)
|
5.57
|
|
4.29
|
|
5.99
|
|
4.51
|
(a)Second quarter and year-to-date 2021 excludes Central Alabama Generating Station KWHs and associated cost of fuel as its fuel is 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 2021, fuel expense was $263 million compared to $199 million for the corresponding period in 2020. The increase was primarily due to a 44.6% increase in the volume of KWHs generated by coal and a 26.7% increase in the average cost of KWHs generated by natural gas, which excludes tolling agreements.
For year-to-date 2021, fuel expense was $554 million compared to $415 million for the corresponding period in 2020. The increase was primarily due to a 44.6% increase in the volume of KWHs generated by coal, a 26.9% decrease in the volume of KWHs generated by hydro, and a 20.3% increase in the average cost of KWHs generated by natural gas, which excludes tolling agreements.
Purchased Power – Affiliates
In the second quarter 2021, purchased power expense from affiliates was $39 million compared to $30 million for the corresponding period in 2020. For year-to-date 2021, purchased power expense from affiliates was $69 million compared to $49 million for the corresponding period in 2020. The second quarter and year-to-date 2021 increases were primarily due to increases of 74.2% and 70.7%, respectively, in the average cost per KWH purchased as a result of higher natural gas prices, partially offset by decreases of 27.0% and 17.2%, respectively, in the volume of KWH purchased as a result of increased generation compared to the corresponding periods in 2020.
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.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Other Operations and Maintenance Expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Second Quarter 2021 vs. Second Quarter 2020
|
|
Year-To-Date 2021 vs. Year-To-Date 2020
|
|
(change in millions)
|
|
(% change)
|
|
(change in millions)
|
|
(% change)
|
|
$71
|
|
20.8
|
|
$85
|
|
12.3
|
In the second quarter 2021, other operations and maintenance expenses were $413 million compared to $342 million for the corresponding period in 2020. The increase was primarily due to an increase of $36 million in generation expenses associated with scheduled outages and Rate CNP Compliance-related expenses primarily related to the addition of new environmental systems in 2021. These increases reflect the impacts of cost containment activities implemented for 2020 during the COVID-19 pandemic. Also contributing to the increase were increases of $17 million in compensation and benefit expenses and $5 million related to unregulated services, as well as $11 million of reliability NDR credits applied in 2020.
For year-to-date 2021, other operations and maintenance expenses were $775 million compared to $690 million for the corresponding period in 2020. The increase was primarily due to an increase of $34 million in generation expenses associated with scheduled outages and Rate CNP Compliance-related expenses primarily related to the addition of new environmental systems in 2021. These increases reflect the impacts of cost containment activities implemented for 2020 during the COVID-19 pandemic. Also contributing to the increase were increases of $17 million in compensation and benefit expenses and $7 million related to unregulated services, as well as $22 million of reliability NDR credits applied in 2020 and a $10 million decrease in nuclear property insurance refunds. These increases were partially offset by gains of $10 million primarily related to property sales and an $8 million decrease in bad debt expense.
See Note 2 to the financial statements under "Alabama Power – Rate NDR" and " – Rate CNP Compliance" in Item 8 of the Form 10-K for additional information.
Depreciation and Amortization
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Second Quarter 2021 vs. Second Quarter 2020
|
|
Year-To-Date 2021 vs. Year-To-Date 2020
|
|
(change in millions)
|
|
(% change)
|
|
(change in millions)
|
|
(% change)
|
|
$12
|
|
5.9
|
|
$23
|
|
5.7
|
In the second quarter 2021, depreciation and amortization was $214 million compared to $202 million in the corresponding period in 2020. For year-to-date 2021, depreciation and amortization was $425 million compared to $402 million for the corresponding period in 2020. These increases were primarily due to additional plant in service, including the purchase of the Central Alabama Generating Station in August 2020. See Note 15 to the financial statements under "Alabama Power" in Item 8 of the Form 10-K for additional information.
Other Income (Expense), Net
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Second Quarter 2021 vs. Second Quarter 2020
|
|
Year-To-Date 2021 vs. Year-To-Date 2020
|
|
(change in millions)
|
|
(% change)
|
|
(change in millions)
|
|
(% change)
|
|
$7
|
|
26.9
|
|
$14
|
|
29.2
|
In the second quarter 2021, other income (expense), net was $33 million compared to $26 million for the corresponding period in 2020. For year-to-date 2021, other income (expense), net was $62 million compared to $48 million for the corresponding period in 2020. These increases were primarily due to an increase in non-service cost-related retirement benefits income. The year-to-date 2021 increase was partially offset by a decrease in interest income associated with lower interest rates. See Note (H) to the Condensed Financial Statements herein for additional information.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Income Taxes
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Second Quarter 2021 vs. Second Quarter 2020
|
|
Year-To-Date 2021 vs. Year-To-Date 2020
|
|
(change in millions)
|
|
(% change)
|
|
(change in millions)
|
|
(% change)
|
|
$11
|
|
11.8
|
|
$36
|
|
20.3
|
In the second quarter 2021, income taxes were $104 million compared to $93 million for the corresponding period in 2020. For year-to-date 2021, income taxes were $213 million compared to $177 million for the corresponding period in 2020. The increases were primarily due to higher pre-tax earnings.
Georgia Power
Net Income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Second Quarter 2021 vs. Second Quarter 2020
|
|
Year-To-Date 2021 vs. Year-To-Date 2020
|
|
(change in millions)
|
|
(% change)
|
|
(change in millions)
|
|
(% change)
|
|
$(165)
|
|
(53.6)
|
|
$(144)
|
|
(22.6)
|
Georgia Power's net income for the second quarter 2021 was $143 million compared to $308 million for the corresponding period in 2020. The decrease was primarily due to a $232 million increase in after-tax charges related to the construction of Plant Vogtle Units 3 and 4. Also contributing to the decrease was higher non-fuel operations and maintenance costs, partially offset by higher retail revenues associated with sales growth and rates and pricing.
For year-to-date 2021, net income was $494 million compared to $638 million for the corresponding period in 2020. The decrease was primarily due to a $268 million increase in after-tax charges related to the construction of Plant Vogtle Units 3 and 4. Also contributing to the decrease was higher non-fuel operations and maintenance costs, partially offset by higher retail revenues associated with colder weather in the first quarter 2021 as compared to the corresponding period in 2020 and sales growth.
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 regarding Plant Vogtle Units 3 and 4.
Retail Revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Second Quarter 2021 vs. Second Quarter 2020
|
|
Year-To-Date 2021 vs. Year-To-Date 2020
|
|
(change in millions)
|
|
(% change)
|
|
(change in millions)
|
|
(% change)
|
|
$266
|
|
15.1
|
|
$378
|
|
11.0
|
In the second quarter 2021, retail revenues were $2.03 billion compared to $1.76 billion for the corresponding period in 2020. For year-to-date 2021, retail revenues were $3.81 billion compared to $3.44 billion for the corresponding period in 2020.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Details of the changes in retail revenues were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Second Quarter 2021
|
|
Year-To-Date 2021
|
|
|
(in millions)
|
|
(% change)
|
|
(in millions)
|
|
(% change)
|
|
Retail – prior year
|
$
|
1,760
|
|
|
|
|
$
|
3,435
|
|
|
|
|
Estimated change resulting from –
|
|
|
|
|
|
|
|
|
Rates and pricing
|
38
|
|
|
2.2
|
%
|
|
20
|
|
|
0.6
|
%
|
|
Sales growth
|
64
|
|
|
3.6
|
|
|
59
|
|
|
1.7
|
|
|
Weather
|
18
|
|
|
1.0
|
|
|
59
|
|
|
1.7
|
|
|
Fuel cost recovery
|
146
|
|
|
8.3
|
|
|
240
|
|
|
7.0
|
|
|
Retail – current year
|
$
|
2,026
|
|
|
15.1
|
%
|
|
$
|
3,813
|
|
|
11.0
|
%
|
Revenues associated with changes in rates and pricing increased in the second quarter and year-to-date 2021 when compared to the corresponding periods in 2020. These increases were primarily due to higher contributions from commercial and industrial customers with variable demand-driven pricing, pricing effects associated with decreased residential customer usage, and increased ECCR tariff revenues associated with higher KWH sales. The increases were partially offset by a decrease in the NCCR tariff effective January 1, 2021. See Note (B) to the Condensed Financial Statements under "Georgia Power – Nuclear Construction – Regulatory Matters" herein for additional information.
Revenues attributable to changes in sales increased in the second quarter and year-to-date 2021 when compared to the corresponding periods in 2020. Weather-adjusted residential KWH sales decreased 0.8% in the second quarter 2021 when compared to the corresponding period in 2020 as customer usage decreased, primarily due to shelter-in-place orders in effect during the second quarter 2020. Weather-adjusted residential KWH sales increased 0.7% for year-to-date 2021 when compared to the corresponding period in 2020 primarily due to customer growth, partially offset by decreased customer usage, primarily due to shelter-in-place orders in effect during 2020. Weather-adjusted commercial KWH sales increased 9.0% and 2.6% in the second quarter and year-to-date 2021, respectively, and weather-adjusted industrial KWH sales increased 14.0% and 7.3% in the second quarter and year-to-date 2021, respectively, when compared to the corresponding periods in 2020, primarily due to the negative impact of the COVID-19 pandemic on energy demand in 2020.
Fuel revenues and costs are allocated between retail and wholesale jurisdictions. Retail fuel cost recovery revenues increased in the second quarter and year-to-date 2021 when compared to the corresponding periods in 2020 due to higher 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 2 to the financial statements under "Georgia Power – Fuel Cost Recovery" in Item 8 of the Form 10-K for additional information.
Wholesale Revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Second Quarter 2021 vs. Second Quarter 2020
|
|
Year-To-Date 2021 vs. Year-To-Date 2020
|
|
(change in millions)
|
|
(% change)
|
|
(change in millions)
|
|
(% change)
|
|
$11
|
|
44.0
|
|
$29
|
|
56.9
|
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
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
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. These transactions do not have a significant impact on earnings since this energy is generally sold at marginal cost.
In the second quarter 2021, wholesale revenues were $36 million compared to $25 million for the corresponding period in 2020. For year-to-date 2021, wholesale revenues were $80 million compared to $51 million for the corresponding period in 2020. The increases for the second quarter and year-to-date 2021 were primarily due to increases of 4.3% and 8.9%, respectively, in KWH sales as a result of higher market demand and higher natural gas prices.
Other Revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Second Quarter 2021 vs. Second Quarter 2020
|
|
Year-To-Date 2021 vs. Year-To-Date 2020
|
|
(change in millions)
|
|
(% change)
|
|
(change in millions)
|
|
(% change)
|
|
$20
|
|
14.0
|
|
$34
|
|
12.7
|
In the second quarter 2021, other revenues were $163 million compared to $143 million for the corresponding period in 2020. For year-to-date 2021, other revenues were $302 million compared to $268 million for the corresponding period in 2020. The increases for the second quarter and year-to-date 2021 were primarily due to increases of $20 million and $30 million, respectively, in unregulated sales associated with power delivery construction and maintenance projects and $7 million and $8 million, respectively, in customer fees largely resulting from the COVID-19 pandemic-related temporary suspension of disconnections and late fees in 2020. These increases were partially offset by decreases of $5 million and $7 million in the second quarter and year-to-date 2021, respectively, associated with the timing of certain unregulated energy conservation projects.
Fuel and Purchased Power Expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Second Quarter 2021 vs. Second Quarter 2020
|
|
Year-To-Date 2021 vs. Year-To-Date 2020
|
|
|
(change in millions)
|
|
(% change)
|
|
(change in millions)
|
|
(% change)
|
|
Fuel
|
$
|
117
|
|
|
51.8
|
|
|
$
|
198
|
|
|
43.2
|
|
|
Purchased power – non-affiliates
|
11
|
|
|
8.3
|
|
|
26
|
|
|
9.9
|
|
|
Purchased power – affiliates
|
27
|
|
|
22.1
|
|
|
34
|
|
|
13.5
|
|
|
Total fuel and purchased power expenses
|
$
|
155
|
|
|
|
|
$
|
258
|
|
|
|
In the second quarter 2021, total fuel and purchased power expenses were $636 million compared to $481 million for the corresponding period in 2020. For year-to-date 2021, total fuel and purchased power expenses were $1.23 billion compared to $0.97 billion for the corresponding period in 2020. The increases for the second quarter and year-to-date 2021 were due to increases of $108 million and $184 million, respectively, related to the average cost of fuel and purchased power and net increases of $47 million and $74 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 2 to the financial statements under "Georgia Power – Fuel Cost Recovery" 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 Georgia Power's generation and purchased power were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Second Quarter 2021
|
|
Second Quarter 2020
|
|
Year-To-Date 2021
|
|
Year-To-Date 2020
|
|
Total generation (in billions of KWHs)
|
15
|
|
13
|
|
30
|
|
25
|
|
Total purchased power (in billions of KWHs)
|
7
|
|
8
|
|
14
|
|
16
|
|
Sources of generation (percent) —
|
|
|
|
|
|
|
|
|
Gas
|
46
|
|
56
|
|
47
|
|
57
|
|
Nuclear
|
28
|
|
32
|
|
27
|
|
30
|
|
Coal
|
22
|
|
7
|
|
22
|
|
7
|
|
Hydro and solar
|
4
|
|
5
|
|
4
|
|
6
|
|
Cost of fuel, generated (in cents per net KWH) —
|
|
|
|
|
|
|
|
|
Gas
|
2.65
|
|
2.11
|
|
2.62
|
|
2.11
|
|
Nuclear
|
0.80
|
|
0.81
|
|
0.79
|
|
0.80
|
|
Coal
|
3.09
|
|
3.37
|
|
3.01
|
|
3.60
|
|
Average cost of fuel, generated (in cents per net KWH)
|
2.21
|
|
1.76
|
|
2.18
|
|
1.82
|
|
Average cost of purchased power (in cents per net KWH)(*)
|
4.77
|
|
3.58
|
|
4.49
|
|
3.36
|
(*)Average cost of purchased power includes fuel purchased by Georgia Power for tolling agreements where power is generated by the provider.
Fuel
In the second quarter 2021, fuel expense was $343 million compared to $226 million for the corresponding period in 2020. For year-to-date 2021, fuel expense was $656 million compared to $458 million for the corresponding period in 2020. The increases for the second quarter and year-to-date 2021 were primarily due to increases of 261.8% and 247.1%, respectively, in the volume of KWHs generated by coal and increases of 25.6% and 24.2%, respectively, in the average cost of natural gas per KWH generated. The increase for year-to-date 2021 was partially offset by a 16.4% decrease in the average cost of coal per KWH generated.
Purchased Power – Non-Affiliates
In the second quarter 2021, purchased power expense from non-affiliates was $144 million compared to $133 million in the corresponding period in 2020. For year-to-date 2021, purchased power expense from non-affiliates was $288 million compared to $262 million in the corresponding period in 2020. The increases for the second quarter and year-to-date 2021 were primarily due to increases of 19.4% and 21.6%, respectively, in the average cost per KWH purchased primarily due to higher natural gas prices, partially offset by decreases of 7.9% and 8.9%, respectively, in the volume of KWHs purchased as Georgia Power units generally dispatched at a lower cost than available market resources.
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 2021, purchased power expense from affiliates was $149 million compared to $122 million in the corresponding period in 2020. For year-to-date 2021, purchased power expense from affiliates was $285 million compared to $251 million in the corresponding period in 2020. The increases for the second quarter and year-to-date 2021 were primarily due to increases of 44.7% and 41.3%, respectively, in the average cost per KWH purchased primarily due to higher natural gas prices, partially offset by decreases of 15.2% and 19.1%, respectively, in the
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
volume of KWHs purchased due to higher cost Southern Company system resources as compared to available Georgia Power-owned generation.
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 2021 vs. Second Quarter 2020
|
|
Year-To-Date 2021 vs. Year-To-Date 2020
|
|
(change in millions)
|
|
(% change)
|
|
(change in millions)
|
|
(% change)
|
|
$79
|
|
17.1
|
|
$87
|
|
9.4
|
In the second quarter 2021, other operations and maintenance expenses were $542 million compared to $463 million for the corresponding period in 2020. The increase was primarily associated with increases of $27 million related to distribution maintenance activities, $14 million in generation expenses associated with non-outage maintenance costs and environmental projects, and $8 million in transmission overhead line costs. These increases reflect the impacts of cost containment activities implemented for 2020 during the COVID-19 pandemic. Also contributing to the increase were increases of $16 million related to unregulated power delivery construction and maintenance projects and $7 million in benefit expenses.
For year-to-date 2021, other operations and maintenance expenses were $1.02 billion compared to $0.93 billion for the corresponding period in 2020. The increase was primarily associated with increases of $27 million related to distribution maintenance activities, $9 million in transmission overhead line costs, and $8 million in generation environmental projects. These increases reflect the impacts of cost containment activities implemented for 2020 during the COVID-19 pandemic. Also contributing to the increase were increases of $23 million related to unregulated power delivery construction and maintenance projects and $10 million in benefit expenses, as well as an $8 million decrease in nuclear property insurance refunds, partially offset by a decrease of $9 million in expenses associated with the timing of certain unregulated energy conservation projects.
Depreciation and Amortization
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Second Quarter 2021 vs. Second Quarter 2020
|
|
Year-To-Date 2021 vs. Year-To-Date 2020
|
|
(change in millions)
|
|
(% change)
|
|
(change in millions)
|
|
(% change)
|
|
$(12)
|
|
(3.4)
|
|
$(27)
|
|
(3.8)
|
In the second quarter 2021, depreciation and amortization was $342 million compared to $354 million for the corresponding period in 2020. For year-to-date 2021, depreciation and amortization was $680 million compared to $707 million for the corresponding period in 2020. The decreases for the second quarter and year-to-date 2021 primarily reflect decreased amortization of regulatory assets related to CCR AROs of $22 million and $44 million, respectively, under the terms of the 2019 ARP, partially offset by increases of $10 million and $20 million, respectively, in depreciation associated with additional plant in service. See Note (B) to the Condensed Financial Statements under "Georgia Power – Rate Plan" herein and Note 2 to the financial statements under "Georgia Power – Rate Plans – 2019 ARP" in Item 8 of the Form 10-K for additional information regarding recovery of costs associated with CCR AROs.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Taxes Other Than Income Taxes
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Second Quarter 2021 vs. Second Quarter 2020
|
|
Year-To-Date 2021 vs. Year-To-Date 2020
|
|
(change in millions)
|
|
(% change)
|
|
(change in millions)
|
|
(% change)
|
|
$10
|
|
9.3
|
|
$14
|
|
6.3
|
In the second quarter 2021, taxes other than income taxes was $118 million compared to $108 million for the corresponding period in 2020. For year-to-date 2021, taxes other than income taxes was $235 million compared to $221 million for the corresponding period in 2020. The increases for the second quarter and year-to-date 2021 were primarily due to increases of $7 million and $9 million, respectively, in municipal franchise fees largely related to higher retail revenues and increases of $3 million and $7 million, respectively, in property taxes primarily associated with the construction 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.
Estimated Loss on Plant Vogtle Units 3 and 4
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Second Quarter 2021 vs. Second Quarter 2020
|
|
Year-To-Date 2021 vs. Year-To-Date 2020
|
|
(change in millions)
|
|
(% change)
|
|
(change in millions)
|
|
(% change)
|
|
$311
|
|
208.7
|
|
$359
|
|
240.9
|
In the second quarter 2021 and 2020, Georgia Power recorded estimated probable losses on Plant Vogtle Units 3 and 4 of $460 million and $149 million, respectively. For year-to-date 2021 and 2020, Georgia Power recorded estimated probable losses on Plant Vogtle Units 3 and 4 of $508 million and $149 million, respectively. These losses reflect 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 2021 vs. Second Quarter 2020
|
|
Year-To-Date 2021 vs. Year-To-Date 2020
|
|
(change in millions)
|
|
(% change)
|
|
(change in millions)
|
|
(% change)
|
|
$10
|
|
50.0
|
|
$21
|
|
52.5
|
In the second quarter 2021, allowance for equity funds used during construction was $30 million compared to $20 million for the corresponding period in 2020. For year-to-date 2021, allowance for equity funds used during construction was $61 million compared to $40 million for the corresponding period in 2020. The increases were primarily associated with 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 regarding Plant Vogtle Units 3 and 4.
Other Income (Expense), Net
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Second Quarter 2021 vs. Second Quarter 2020
|
|
Year-To-Date 2021 vs. Year-To-Date 2020
|
|
(change in millions)
|
|
(% change)
|
|
(change in millions)
|
|
(% change)
|
|
$11
|
|
35.5
|
|
$20
|
|
31.7
|
In the second quarter 2021, other income (expense), net was $42 million compared to $31 million for the corresponding period in 2020. For year-to-date 2021, other income (expense), net was $83 million compared to $63 million for the corresponding period in 2020. The increases were primarily due to increases of $12 million and $25 million, respectively, in non-service cost-related retirement benefits income. The increase for year-to-date 2021 was
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
partially offset by a $5 million decrease in interest income due to lower short-term cash investments. See Note (H) to the Condensed Financial Statements herein for additional information on retirement benefits.
Income Taxes (Benefit)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Second Quarter 2021 vs. Second Quarter 2020
|
|
Year-To-Date 2021 vs. Year-To-Date 2020
|
|
(change in millions)
|
|
(% change)
|
|
(change in millions)
|
|
(% change)
|
|
$(61)
|
|
N/M
|
|
$(59)
|
|
N/M
|
N/M - Not meaningful
In the second quarter 2021, income tax benefit was $50 million compared to income tax expense of $11 million for the corresponding period in 2020. For year-to-date 2021, income tax benefit was $32 million compared to income tax expense of $27 million for the corresponding period in 2020. The changes were primarily due to lower pre-tax earnings resulting from higher charges in 2021 compared to the corresponding periods in 2020 associated with the construction 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" and Note (G) to the Condensed Financial Statements herein for additional information.
Mississippi Power
Net Income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Second Quarter 2021 vs. Second Quarter 2020
|
|
Year-To-Date 2021 vs. Year-To-Date 2020
|
|
(change in millions)
|
|
(% change)
|
|
(change in millions)
|
|
(% change)
|
|
$(1)
|
|
(2.6)
|
|
$12
|
|
16.9
|
In the second quarter 2021, net income was $38 million compared to $39 million for the corresponding period in 2020. The decrease was primarily due to an increase in operations and maintenance expenses and income taxes, largely offset by an increase in base rates that became effective for the first billing cycle of April 2021 and higher customer usage in the second quarter 2021 when compared to the corresponding period in 2020.
For year-to-date 2021, net income was $83 million compared to $71 million for the corresponding period in 2020. The increase was primarily due to an increase in base revenues primarily due to colder weather in the first quarter 2021 as compared to the corresponding period in 2020, as well as an increase in other income.
Retail Revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Second Quarter 2021 vs. Second Quarter 2020
|
|
Year-To-Date 2021 vs. Year-To-Date 2020
|
|
(change in millions)
|
|
(% change)
|
|
(change in millions)
|
|
(% change)
|
|
$20
|
|
10.1
|
|
$24
|
|
6.0
|
In the second quarter 2021, retail revenues were $219 million compared to $199 million for the corresponding period in 2020. For year-to-date 2021, retail revenues were $422 million compared to $398 million for the corresponding period in 2020.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Details of the changes in retail revenues were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Second Quarter 2021
|
|
Year-To-Date 2021
|
|
|
(in millions)
|
|
(% change)
|
|
(in millions)
|
|
(% change)
|
|
Retail – prior year
|
$
|
199
|
|
|
|
|
$
|
398
|
|
|
|
|
Estimated change resulting from –
|
|
|
|
|
|
|
|
|
Rates and pricing
|
8
|
|
|
4.0
|
%
|
|
1
|
|
|
0.3
|
%
|
|
Sales growth
|
6
|
|
|
3.0
|
|
|
—
|
|
|
—
|
|
|
Weather
|
(3)
|
|
|
(1.5)
|
|
|
5
|
|
|
1.3
|
|
|
Fuel and other cost recovery
|
9
|
|
|
4.5
|
|
|
18
|
|
|
4.5
|
|
|
Retail – current year
|
$
|
219
|
|
|
10.0
|
%
|
|
$
|
422
|
|
|
6.1
|
%
|
Revenues associated with changes in rates and pricing increased in the second quarter 2021 when compared to the corresponding period in 2020 primarily due to an increase in revenues in accordance with new PEP rates that became effective for the first billing cycle of April 2021. See Note (B) to the Condensed Financial Statements under "Mississippi Power – Performance Evaluation Plan" herein for additional information.
Revenues attributable to changes in sales increased in the second quarter 2021 when compared to the corresponding period in 2020. Weather-adjusted residential KWH sales decreased 1.9% and 1.3% in the second quarter and year-to-date 2021, respectively, when compared to the corresponding periods in 2020 as customer usage decreased, primarily due to shelter-in-place orders in effect during 2020. Weather-adjusted commercial KWH sales increased 9.0% and 2.4% in the second quarter and year-to-date 2021, respectively, and industrial KWH sales increased 7.2% in the second quarter 2021 when compared to the corresponding periods in 2020, primarily due to the negative impact of the COVID-19 pandemic on energy demand in 2020. Industrial KWH sales decreased 2.1% for year-to-date 2021 when compared to the corresponding period in 2020 as a result of decreased customer usage due to continued disruptions of supply chain and business operations driven by the COVID-19 pandemic, as well as non-pandemic related customer outages.
Fuel and other cost recovery revenues increased in the second quarter and year-to-date 2021 when compared to the corresponding periods in 2020 primarily as a result of higher recoverable fuel costs. Recoverable fuel costs include fuel and purchased power expenses reduced by the fuel 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.
Wholesale Revenues – Non-Affiliates
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Second Quarter 2021 vs. Second Quarter 2020
|
|
Year-To-Date 2021 vs. Year-To-Date 2020
|
|
(change in millions)
|
|
(% change)
|
|
(change in millions)
|
|
(% change)
|
|
$2
|
|
3.8
|
|
$14
|
|
13.6
|
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.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
For year-to-date 2021, wholesale revenues from sales to non-affiliates were $117 million compared to $103 million for the corresponding period in 2020. The increase was primarily due to higher fuel costs and an increase in revenue from MRA customers and opportunity sales as a result of colder weather in the first quarter 2021.
Wholesale Revenues – Affiliates
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Second Quarter 2021 vs. Second Quarter 2020
|
|
Year-To-Date 2021 vs. Year-To-Date 2020
|
|
(change in millions)
|
|
(% change)
|
|
(change in millions)
|
|
(% change)
|
|
$—
|
|
—
|
|
$10
|
|
21.3
|
Wholesale revenues from sales to affiliated companies will vary depending on demand and the availability and cost of generating resources at each company. These affiliate sales are made in accordance with the IIC, as approved by the FERC. These transactions do not have a significant impact on earnings since this energy is generally sold at marginal cost.
In both the second quarter 2021 and 2020, wholesale revenues from sales to affiliates were $25 million. Wholesale revenues from sales to affiliates in the second quarter 2021 reflected a decrease of $11 million associated with lower KWH sales offset by an $11 million increase associated with higher natural gas prices when compared to the corresponding period in 2020.
For year-to-date 2021, wholesale revenues from sales to affiliates were $57 million compared to $47 million for the corresponding period in 2020. The increase was primarily due to a $20 million increase related to higher natural gas prices, partially offset by a $10 million decrease related to lower KWH sales.
Fuel and Purchased Power Expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Second Quarter 2021 vs. Second Quarter 2020
|
|
Year-To-Date 2021 vs. Year-To-Date 2020
|
|
|
(change in millions)
|
|
(% change)
|
|
(change in millions)
|
|
(% change)
|
|
Fuel
|
$
|
8
|
|
|
9.6
|
|
$
|
30
|
|
|
18.5
|
|
Purchased power
|
4
|
|
|
57.1
|
|
4
|
|
|
33.3
|
|
Total fuel and purchased power expenses
|
$
|
12
|
|
|
|
|
$
|
34
|
|
|
|
In the second quarter 2021, total fuel and purchased power expenses were $102 million compared to $90 million for the corresponding period in 2020. The increase was primarily due to a $17 million increase in the average cost of fuel, partially offset by a $5 million decrease associated with the volume of KWHs generated and purchased.
For year-to-date 2021, total fuel and purchased power expenses were $208 million compared to $174 million for the corresponding period in 2020. The increase was primarily due to an increase in the average cost of fuel.
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.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Details of Mississippi Power's generation and purchased power were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Second Quarter 2021
|
|
Second Quarter 2020
|
|
Year-To-Date 2021
|
|
Year-To-Date 2020
|
|
Total generation (in millions of KWHs)
|
3,813
|
|
4,484
|
|
8,137
|
|
8,651
|
|
Total purchased power (in millions of KWHs)
|
317
|
|
208
|
|
438
|
|
396
|
|
Sources of generation (percent) –
|
|
|
|
|
|
|
|
|
Gas
|
91
|
|
96
|
|
91
|
|
96
|
|
Coal
|
9
|
|
4
|
|
9
|
|
4
|
|
Cost of fuel, generated (in cents per net KWH) –
|
|
|
|
|
|
|
|
|
Gas
|
2.50
|
|
1.88
|
|
2.45
|
|
1.92
|
|
Coal
|
3.06
|
|
3.82
|
|
3.12
|
|
4.02
|
|
Average cost of fuel, generated (in cents per net KWH)
|
2.56
|
|
1.97
|
|
2.52
|
|
2.00
|
|
Average cost of purchased power (in cents per net KWH)
|
3.38
|
|
3.27
|
|
3.57
|
|
2.97
|
Fuel
In the second quarter 2021, fuel expense was $91 million compared to $83 million for the corresponding period in 2020. The increase was primarily due to a 93.4% increase in the volume of KWHs generated by coal and a 33.0% increase in the average cost of natural gas per KWH generated, partially offset by a 21.0% decrease in the volume of KWHs generated by natural gas and a 19.9% decrease in the average cost of coal per KWH generated.
For year-to-date 2021, fuel expense was $192 million compared to $162 million for the corresponding period in 2020. The increase was due to a 146.5% increase in the volume of KWHs generated by coal and a 27.6% increase in the average cost of natural gas per KWH generated, partially offset by a 22.4% decrease in the average cost of coal per KWH generated and a 12.5% decrease in the volume of KWHs generated by natural gas.
Purchased Power
In the second quarter 2021, purchased power expense was $11 million compared to $7 million for the corresponding period in 2020. For year-to-date 2021, purchased power expense was $16 million compared to $12 million for the corresponding period in 2020. The second quarter and year-to-date 2021 increases reflect increases of 52.4% and 10.6%, respectively, in the volume of KWHs purchased and increases of 3.4% and 20.2%, respectively, in the average cost per KWH purchased primarily due to higher natural gas prices.
Other Operations and Maintenance Expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Second Quarter 2021 vs. Second Quarter 2020
|
|
Year-To-Date 2021 vs. Year-To-Date 2020
|
|
(change in millions)
|
|
(% change)
|
|
(change in millions)
|
|
(% change)
|
|
$9
|
|
13.4
|
|
$2
|
|
1.4
|
In the second quarter 2021, other operations and maintenance expenses were $76 million compared to $67 million for the corresponding period in 2020. The increase was primarily due to increases of $7 million related to planned generation outage and baseline costs and $2 million related to compensation and benefit costs.
Other Income (Expense), Net
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Second Quarter 2021 vs. Second Quarter 2020
|
|
Year-To-Date 2021 vs. Year-To-Date 2020
|
|
(change in millions)
|
|
(% change)
|
|
(change in millions)
|
|
(% change)
|
|
$5
|
|
83.3
|
|
$6
|
|
42.9
|
In the second quarter 2021, other income (expense), net was $11 million compared to $6 million for the corresponding period in 2020. For year-to-date 2021, other income (expense), net was $20 million compared to $14
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
million for the corresponding period in 2020. The second quarter and year-to-date 2021 increases were primarily related to increases of $3 million and $2 million, respectively, in contributions in aid of construction and $2 million and $3 million, respectively, in non-service cost-related retirement benefits income. See Note (H) to the Condensed Financial Statements herein for additional information.
Income Taxes
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Second Quarter 2021 vs. Second Quarter 2020
|
|
Year-To-Date 2021 vs. Year-To-Date 2020
|
|
(change in millions)
|
|
(% change)
|
|
(change in millions)
|
|
(% change)
|
|
$6
|
|
N/M
|
|
$4
|
|
50.0
|
N/M - Not meaningful
In the second quarter 2021, income taxes were $8 million compared to $2 million for the corresponding period in 2020. The increase was primarily due to a $4 million increase associated with the flowback of excess deferred income taxes as a result of the Mississippi Power Rate Case Settlement and a $1 million increase due to higher pre-tax earnings.
For year-to-date 2021, income taxes were $12 million compared to $8 million for the corresponding period in 2020. The increase was primarily due to higher pre-tax earnings.
Southern Power
Net Income Attributable to Southern Power
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Second Quarter 2021 vs. Second Quarter 2020
|
|
Year-To-Date 2021 vs. Year-To-Date 2020
|
|
(change in millions)
|
|
(% change)
|
|
(change in millions)
|
|
(% change)
|
|
$(27)
|
|
(42.9)
|
|
$(5)
|
|
(3.6)
|
Net income attributable to Southern Power for the second quarter 2021 was $36 million compared to $63 million for the corresponding period in 2020. Net income attributable to Southern Power for year-to-date 2021 was $133 million compared to $138 million for the corresponding period in 2020. The decreases were primarily due to an increase in other operations and maintenance expenses associated with scheduled outages and maintenance. Partially offsetting the year-to-date 2021 decrease was a $16 million tax benefit due to changes in state apportionment methodology resulting from tax legislation enacted by the State of Alabama in February 2021.
Operating Revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Second Quarter 2021 vs. Second Quarter 2020
|
|
Year-To-Date 2021 vs. Year-To-Date 2020
|
|
(change in millions)
|
|
(% change)
|
|
(change in millions)
|
|
(% change)
|
|
$51
|
|
11.6
|
|
$116
|
|
14.3
|
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
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
prices of wholesale energy compared to the cost of Southern Power's energy. Energy revenues also include fees for support services, fuel storage, and unit start charges. Increases and decreases in energy revenues under PPAs that are driven by fuel or purchased power prices are accompanied by an increase or decrease in fuel and purchased power costs and do not have a significant impact on net income.
Solar and Wind Energy Revenue
Southern Power's energy sales from solar and wind generating facilities are predominantly through long-term PPAs that do not have capacity revenue. Customers either purchase the energy output of a dedicated renewable facility through an energy charge or pay a fixed price related to the energy generated from the respective facility and sold to the grid. As a result, Southern Power's ability to recover fixed and variable operations and maintenance expenses is dependent upon the level of energy generated from these facilities, which can be impacted by weather conditions, equipment performance, transmission constraints, and other factors.
See FUTURE EARNINGS POTENTIAL – "Southern Power's Power Sales Agreements" 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 2021
|
|
Second Quarter 2020
|
|
Year-To-Date 2021
|
|
Year-To-Date 2020
|
|
|
(in millions)
|
|
PPA capacity revenues
|
$
|
96
|
|
|
$
|
92
|
|
|
$
|
192
|
|
|
$
|
181
|
|
|
PPA energy revenues
|
296
|
|
|
270
|
|
|
541
|
|
|
475
|
|
|
Total PPA revenues
|
392
|
|
|
362
|
|
|
733
|
|
|
656
|
|
|
Non-PPA revenues
|
93
|
|
|
73
|
|
|
188
|
|
|
151
|
|
|
Other revenues
|
5
|
|
|
4
|
|
|
9
|
|
|
7
|
|
|
Total operating revenues
|
$
|
490
|
|
|
$
|
439
|
|
|
$
|
930
|
|
|
$
|
814
|
|
In the second quarter 2021, total operating revenues were $490 million, reflecting a $51 million, or 12%, increase from the corresponding period in 2020. The increase in operating revenues was primarily due to the following:
•PPA capacity revenues increased $4 million, or 4%, primarily due to new natural gas PPAs, which began subsequent to the second quarter 2020, and increased capacity on existing contracts, partially offset by the contractual expiration of natural gas PPAs.
•PPA energy revenues increased $26 million, or 10%, primarily due to a $31 million increase in sales from natural gas facilities resulting from a $39 million increase in the price of fuel and purchased power, partially offset by an $8 million decrease in the volume of KWHs sold.
•Non-PPA revenues increased $20 million, or 27%, due to a $31 million increase in the market price of energy, partially offset by an $11 million decrease in the volume of KWHs sold through short-term sales.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
For year-to-date 2021, total operating revenues were $930 million, reflecting a $116 million, or 14%, increase from the corresponding period in 2020. The increase in operating revenues was primarily due to the following:
•PPA capacity revenues increased $11 million, or 6%, primarily due to new natural gas PPAs, which began subsequent to the second quarter 2020, and increased capacity on existing contracts, partially offset by the disposition of Plant Mankato in the first quarter 2020 and the contractual expiration of natural gas PPAs.
•PPA energy revenues increased $66 million, or 14%, due to a $66 million increase in sales from natural gas facilities resulting from an $82 million increase in the price of fuel and purchased power, partially offset by a $16 million decrease in the volume of KWHs sold.
•Non-PPA revenues increased $37 million, or 25%, due to a $69 million increase in the market price of energy, partially offset by a $32 million decrease in the volume of KWHs sold through short-term sales.
Fuel and Purchased Power Expenses
Details of Southern Power's generation and purchased power were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Second Quarter 2021
|
Second Quarter 2020
|
|
Year-To-Date 2021
|
Year-To-Date 2020
|
|
|
(in billions of KWHs)
|
|
Generation
|
10.3
|
11.3
|
|
19.7
|
22.0
|
|
Purchased power
|
0.7
|
0.9
|
|
1.3
|
1.5
|
|
Total generation and purchased power
|
11.0
|
12.2
|
|
21.0
|
23.5
|
|
|
|
|
|
|
|
|
Total generation and purchased power, excluding solar, wind, and tolling agreements
|
6.3
|
7.4
|
|
12.4
|
14.5
|
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 2021 vs. Second Quarter 2020
|
|
Year-To-Date 2021 vs. Year-To-Date 2020
|
|
|
(change in millions)
|
|
(% change)
|
|
(change in millions)
|
|
(% change)
|
|
Fuel
|
$
|
38
|
|
|
37.3
|
|
$
|
72
|
|
|
34.4
|
|
Purchased power
|
7
|
|
|
38.9
|
|
14
|
|
|
43.8
|
|
Total fuel and purchased power expenses
|
$
|
45
|
|
|
|
|
$
|
86
|
|
|
|
In the second quarter 2021, total fuel and purchased power expenses increased $45 million, or 38%, compared to the corresponding period in 2020. Fuel expense increased $38 million due to a $52 million increase in the average cost of fuel per KWH generated, partially offset by a $14 million decrease associated with the volume of KWHs
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
generated. Purchased power expense increased $7 million due to a $10 million increase associated with the average cost of purchased power, partially offset by a $3 million decrease associated with the volume of KWHs purchased.
For year-to-date 2021, total fuel and purchased power expenses increased $86 million, or 36%, compared to the corresponding period in 2020. Fuel expense increased $72 million due to a $102 million increase in the average cost of fuel per KWH generated, partially offset by a $30 million decrease associated with the volume of KWHs generated. Purchased power expense increased $14 million due to a $19 million increase associated with the average cost of purchased power, partially offset by a $5 million decrease associated with the volume of KWHs purchased.
Other Operations and Maintenance Expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Second Quarter 2021 vs. Second Quarter 2020
|
|
Year-To-Date 2021 vs. Year-To-Date 2020
|
|
(change in millions)
|
|
(% change)
|
|
(change in millions)
|
|
(% change)
|
|
$34
|
|
44.2
|
|
$55
|
|
35.3
|
In the second quarter 2021, other operations and maintenance expenses were $111 million compared to $77 million for the corresponding period in 2020. The increase was primarily due to increases of $20 million in scheduled outage and maintenance expenses and $4 million in expenses associated with new wind facilities placed in service in 2020 and 2021.
For year-to-date 2021, other operations and maintenance expenses were $211 million compared to $156 million for the corresponding period in 2020. The increase was primarily due to increases of $27 million in scheduled outage and maintenance expenses, $6 million in expenses associated with new wind facilities placed in service in 2020 and 2021, and $6 million related to the allocation of uncollected settlements by the Energy Reliability Council of Texas market as a result of Winter Storm Uri.
Depreciation and Amortization
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Second Quarter 2021 vs. Second Quarter 2020
|
|
Year-To-Date 2021 vs. Year-To-Date 2020
|
|
(change in millions)
|
|
(% change)
|
|
(change in millions)
|
|
(% change)
|
|
$11
|
|
9.1
|
|
$12
|
|
5.0
|
In the second quarter 2021, depreciation and amortization was $132 million compared to $121 million for the corresponding period in 2020. For year-to-date 2021, depreciation and amortization was $251 million compared to $239 million for the corresponding period in 2020. The increases were primarily associated with new wind facilities placed in service in 2020 and 2021.
(Gain) Loss on Dispositions, Net
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Second Quarter 2021 vs. Second Quarter 2020
|
|
Year-To-Date 2021 vs. Year-To-Date 2020
|
|
(change in millions)
|
|
(% change)
|
|
(change in millions)
|
|
(% change)
|
|
$—
|
|
—
|
|
$—
|
|
—
|
For year-to-date 2021, gains on dispositions totaled $39 million primarily from contributions of wind turbine equipment to various equity method investments in the first quarter 2021. A $39 million gain was also recorded in the first quarter 2020 related to the sale of Plant Mankato. See Notes (E) and (K) to the Condensed Financial
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Statements under "Southern Power" herein and Note 15 to the financial statements under "Southern Power – Sales of Natural Gas and Biomass Plants" in Item 8 of the Form 10-K for additional information.
Income Taxes (Benefit)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Second Quarter 2021 vs. Second Quarter 2020
|
|
Year-To-Date 2021 vs. Year-To-Date 2020
|
|
(change in millions)
|
|
(% change)
|
|
(change in millions)
|
|
(% change)
|
|
$(8)
|
|
(133.3)
|
|
$(24)
|
|
(184.6)
|
In the second quarter 2021, income tax benefit was $2 million compared to income tax expense of $6 million for the corresponding period in 2020. The change was primarily due to lower pre-tax earnings.
For year-to-date 2021, income tax benefit was $11 million compared to income tax expense of $13 million for the corresponding period in 2020. The change was primarily due to changes in state apportionment methodology resulting from tax legislation enacted by the State of Alabama in February 2021 and the tax impact from the sale of Plant Mankato in January 2020.
See Note (G) to the Condensed Financial Statements herein, MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Income Tax Matters – Alabama State Tax Reform Legislation" in Item 7 of the Form 10-K, and Note 15 to the financial statements under "Southern Power" in Item 8 of the Form 10-K for additional information.
Southern Company Gas
Operating Metrics
Southern Company Gas continues to focus on several operating metrics, including Heating Degree Days, customer count, and volumes of natural gas sold.
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. Wholesale gas services' physical sales volumes represent the daily average natural gas volumes sold to its customers.
Seasonality of Results
During the Heating Season, natural gas usage and operating revenues are generally higher as more customers are connected to the gas distribution systems and natural gas usage is higher in periods of colder weather. Prior to the sale of Sequent, wholesale gas services' operating revenues occasionally were impacted due to peak usage by power generators in response to summer energy demands. Southern Company Gas' base operating expenses, excluding cost of natural gas, bad debt expense, and certain incentive compensation costs, are incurred relatively evenly throughout the year. Seasonality also affects the comparison of certain balance sheet items across quarters, including receivables, unbilled revenues, natural gas for sale, and notes payable. However, these items are comparable when reviewing Southern Company Gas' annual results. Thus, Southern Company Gas' operating results for the interim periods presented are not necessarily indicative of annual results and can vary significantly from quarter to quarter.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Net Income (Loss)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Second Quarter 2021 vs. Second Quarter 2020
|
|
Year-To-Date 2021 vs. Year-To-Date 2020
|
|
(change in millions)
|
|
(% change)
|
|
(change in millions)
|
|
(% change)
|
|
$(136)
|
|
(191.5)
|
|
$(13)
|
|
(3.8)
|
In the second quarter 2021, net loss was $65 million compared to income of $71 million for the corresponding period in 2020. The decrease was primarily due to an $89 million decrease at wholesale gas services primarily due to an increase in derivative losses, partially offset by higher commercial activities, and an after-tax impairment charge of $58 million at gas pipeline investments related to the PennEast Pipeline project. These decreases were partially offset by a $6 million increase at gas distribution operations primarily due to base rate increases and continued investment in infrastructure replacement.
For year-to-date 2021, net income was $333 million compared to $346 million for the corresponding period in 2020. The decrease was primarily due to an after-tax impairment charge of $58 million at gas pipeline investments related to the PennEast Pipeline project, partially offset by a $25 million increase at gas distribution operations primarily due to base rate increases and continued investment in infrastructure replacement and a $14 million increase at wholesale gas services primarily due to higher commercial activities as a result of Winter Storm Uri, partially offset by derivative losses.
See Notes (C) and (E) to the Condensed Financial Statements herein under "Other Matters – Southern Company Gas" and "Southern Company Gas," respectively, as well as Note 2 to the financial statements under "Southern Company Gas" in Item 8 of the Form 10-K for additional information.
Natural Gas Revenues, including Alternative Revenue Programs
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Second Quarter 2021 vs. Second Quarter 2020
|
|
Year-To-Date 2021 vs. Year-To-Date 2020
|
|
(change in millions)
|
|
(% change)
|
|
(change in millions)
|
|
(% change)
|
|
$41
|
|
6.4
|
|
$486
|
|
25.8
|
In the second quarter 2021, natural gas revenues, including alternative revenue programs, were $677 million compared to $636 million for the corresponding period in 2020. For year-to-date 2021, natural gas revenues, including alternative revenue programs, were $2.4 billion compared to $1.9 billion for the corresponding period in 2020.
Details of the changes in natural gas revenues, including alternative revenue programs, were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Second Quarter 2021
|
|
Year-To-Date 2021
|
|
|
(in millions)
|
|
(% change)
|
|
(in millions)
|
|
(% change)
|
|
Natural gas revenues – prior year
|
$
|
636
|
|
|
|
|
$
|
1,885
|
|
|
|
|
Estimated change resulting from –
|
|
|
|
|
|
|
|
|
Infrastructure replacement programs and base rate changes
|
41
|
|
|
6.4
|
%
|
|
81
|
|
|
4.3
|
%
|
|
Gas costs and other cost recovery
|
88
|
|
|
13.8
|
|
|
240
|
|
|
12.7
|
|
|
|
|
|
|
|
|
|
|
|
Wholesale gas services
|
(91)
|
|
|
(14.3)
|
|
|
156
|
|
|
8.3
|
|
|
|
|
|
|
|
|
|
|
|
Other
|
3
|
|
|
0.5
|
|
|
9
|
|
|
0.5
|
|
|
Natural gas revenues – current year
|
$
|
677
|
|
|
6.4
|
%
|
|
$
|
2,371
|
|
|
25.8
|
%
|
Revenues from infrastructure replacement programs and base rate changes increased in the second quarter and year-to-date 2021 compared to the corresponding periods in 2020 primarily due to rate increases at Atlanta Gas Light, Virginia Natural Gas, and Chattanooga Gas and continued investment in infrastructure replacement. See Note 2 to the financial statements under "Southern Company Gas – Rate Proceedings" in Item 8 of the Form 10-K for additional information.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Revenues associated with gas costs and other cost recovery increased in the second quarter and year-to-date 2021 compared to the corresponding periods in 2020 primarily due to higher volumes sold and higher gas cost recovery. See "Cost of Natural Gas" herein for additional information. Revenue impacts from weather and customer growth are described further below.
Revenues from wholesale gas services decreased in the second quarter 2021 compared to the corresponding period in 2020 due to derivative losses, partially offset by higher commercial activities. Revenues from wholesale gas services increased for year-to-date 2021 compared to the corresponding period in 2020 due to higher volumes sold and higher commercial activities as a result of Winter Storm Uri, partially offset by derivative losses. See "Segment Information – Wholesale Gas Services" herein for additional information. Also see Note (K) to the Condensed Financial Statements under "Southern Company Gas" herein for information regarding the sale of Sequent on July 1, 2021.
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 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
|
|
2021
vs.
normal
|
2021
vs.
2020
|
|
Year-to-Date
|
|
2021
vs.
normal
|
2021
vs.
2020
|
|
|
Normal(*)
|
2021
|
2020
|
|
colder (warmer)
|
(warmer)
|
|
Normal(*)
|
2021
|
2020
|
|
(warmer)
|
colder
|
|
|
(in thousands)
|
|
|
|
|
(in thousands)
|
|
|
|
|
Illinois
|
657
|
|
634
|
|
736
|
|
|
(3.5)
|
%
|
(13.9)
|
%
|
|
3,681
|
|
3,580
|
|
3,495
|
|
|
(2.7)
|
%
|
2.4
|
%
|
|
Georgia
|
125
|
|
142
|
|
188
|
|
|
13.6
|
%
|
(24.5)
|
%
|
|
1,451
|
|
1,396
|
|
1,279
|
|
|
(3.8)
|
%
|
9.1
|
%
|
(*)Normal represents the 10-year average from January 1, 2011 through June 30, 2020 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.
The following table provides the number of customers served by Southern Company Gas at June 30, 2021 and 2020:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
June 30,
|
|
|
|
|
2021
|
|
2020
|
|
2021 vs. 2020
|
|
|
(in thousands, except market share %)
|
|
(% change)
|
|
Gas distribution operations
|
4,300
|
|
|
4,275
|
|
|
0.6
|
%
|
|
Gas marketing services
|
|
|
|
|
|
|
Energy customers(*)
|
612
|
|
|
671
|
|
|
(8.8)
|
%
|
|
Market share of energy customers in Georgia
|
29.1
|
%
|
|
29.0
|
%
|
|
0.3
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(*)Gas marketing services' customers are primarily located in Georgia and Illinois. June 30, 2020 also includes approximately 50,000 customers in Ohio contracted through an annual auction process to serve for 12 months beginning April 1, 2020.
Southern Company Gas anticipates continued customer growth as it expects continued low natural gas prices. Southern Company Gas uses a variety of targeted marketing programs to attract new customers and to retain existing customers.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Cost of Natural Gas
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Second Quarter 2021 vs. Second Quarter 2020
|
|
Year-To-Date 2021 vs. Year-To-Date 2020
|
|
(change in millions)
|
|
(% change)
|
|
(change in millions)
|
|
(% change)
|
|
$87
|
|
60.4
|
|
$231
|
|
39.6
|
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 87% of total cost of natural gas for both the second quarter and year-to-date 2021. 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, including Alternative Revenue Programs" herein for additional information.
In the second quarter 2021, cost of natural gas was $231 million compared to $144 million for the corresponding period in 2020. The increase reflects higher gas cost recovery and a 65.0% increase in natural gas prices in the second quarter 2021 compared to the corresponding period in 2020.
For year-to-date 2021, cost of natural gas was $814 million compared to $583 million for the corresponding period in 2020. The increase reflects higher volumes sold due to colder weather and higher gas cost recovery for year-to-date 2021 compared to the corresponding period in 2020. The increase also reflects a 50.6% increase in natural gas prices for year-to-date 2021 compared to the corresponding period in 2020.
The following table details the volumes of natural gas sold during all periods presented.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Second Quarter
|
2021 vs. 2020
|
|
Year-to-Date
|
2021 vs. 2020
|
|
|
2021
|
2020
|
|
2021
|
2020
|
|
Gas distribution operations (mmBtu in millions)
|
|
|
|
|
|
|
|
Firm
|
103
|
|
100
|
|
3.0
|
%
|
|
391
|
|
357
|
|
9.5
|
%
|
|
Interruptible
|
23
|
|
21
|
|
9.5
|
|
|
50
|
|
45
|
|
11.1
|
|
|
Total
|
126
|
|
121
|
|
4.1
|
%
|
|
441
|
|
402
|
|
9.7
|
%
|
|
Wholesale gas services (mmBtu in millions/day)
|
|
|
|
|
|
|
|
Daily physical sales
|
6.1
|
|
6.4
|
|
(4.7)
|
%
|
|
6.6
|
|
6.6
|
|
—
|
%
|
|
Gas marketing services (mmBtu in millions)
|
|
|
|
|
|
|
|
Firm:
|
|
|
|
|
|
|
|
|
Georgia
|
4
|
|
4
|
|
—
|
%
|
|
23
|
|
18
|
|
27.8
|
%
|
|
Illinois
|
1
|
|
1
|
|
—
|
|
|
5
|
|
6
|
|
(16.7)
|
|
|
|
|
|
|
|
|
|
|
|
Other
|
2
|
|
3
|
|
(33.3)
|
|
|
8
|
|
7
|
|
14.3
|
|
|
Interruptible large commercial and industrial
|
3
|
|
3
|
|
—
|
|
|
7
|
|
7
|
|
—
|
|
|
Total
|
10
|
|
11
|
|
(9.1)
|
%
|
|
43
|
|
38
|
|
13.2
|
%
|
Other Operations and Maintenance Expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Second Quarter 2021 vs. Second Quarter 2020
|
|
Year-To-Date 2021 vs. Year-To-Date 2020
|
|
(change in millions)
|
|
(% change)
|
|
(change in millions)
|
|
(% change)
|
|
$13
|
|
5.9
|
|
$53
|
|
11.1
|
In the second quarter 2021, other operations and maintenance expenses were $233 million compared to $220 million for the corresponding period in 2020. For year-to-date 2021, other operations and maintenance expenses were $532 million compared to $479 million for the corresponding period in 2020. The increases were primarily
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
due to higher compensation expenses, primarily related to an increase in variable compensation at wholesale gas services.
Depreciation and Amortization
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Second Quarter 2021 vs. Second Quarter 2020
|
|
Year-To-Date 2021 vs. Year-To-Date 2020
|
|
(change in millions)
|
|
(% change)
|
|
(change in millions)
|
|
(% change)
|
|
$10
|
|
8.1
|
|
$20
|
|
8.2
|
In the second quarter 2021, depreciation and amortization was $133 million compared to $123 million for the corresponding period in 2020. For year-to-date 2021, depreciation and amortization was $263 million compared to $243 million for the corresponding period in 2020. The increases were primarily due to continued infrastructure investments at the natural gas distribution utilities.
Taxes Other Than Income Taxes
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Second Quarter 2021 vs. Second Quarter 2020
|
|
Year-To-Date 2021 vs. Year-To-Date 2020
|
|
(change in millions)
|
|
(% change)
|
|
(change in millions)
|
|
(% change)
|
|
$2
|
|
4.3
|
|
$12
|
|
10.2
|
In the second quarter 2021, taxes other than income taxes were $49 million compared to $47 million for the corresponding period in 2020. For year-to-date 2021, taxes other than income taxes were $130 million compared to $118 million for the corresponding period in 2020. The increases primarily reflect an increase in revenue tax expenses as a result of higher natural gas revenues at Nicor Gas. These revenue tax expenses are passed directly to customers and have no impact on net income.
Earnings (Loss) from Equity Method Investments
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Second Quarter 2021 vs. Second Quarter 2020
|
|
Year-To-Date 2021 vs. Year-To-Date 2020
|
|
(change in millions)
|
|
(% change)
|
|
(change in millions)
|
|
(% change)
|
|
$(82)
|
|
(273.3)
|
|
$(83)
|
|
(115.3)
|
In the second quarter 2021, loss from equity method investments was $52 million compared to earnings of $30 million for the corresponding period in 2020. For year-to-date 2021, loss from equity method investments was $11 million compared to earnings of $72 million for the corresponding period in 2020. The decreases were primarily due to a pre-tax impairment charge of $82 million recorded in the second quarter 2021 related to the PennEast Pipeline project. See Notes (C) and (E) to the Condensed Financial Statements herein under "Other Matters – Southern Company Gas" and "Southern Company Gas," respectively, for additional information.
Other Income (Expense), Net
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Second Quarter 2021 vs. Second Quarter 2020
|
|
Year-To-Date 2021 vs. Year-To-Date 2020
|
|
(change in millions)
|
|
(% change)
|
|
(change in millions)
|
|
(% change)
|
|
$(26)
|
|
(216.7)
|
|
$(99)
|
|
(471.4)
|
In the second quarter 2021, other income (expense), net was $14 million of expense compared to $12 million of income for the corresponding period in 2020. For year-to-date 2021, other income (expense), net was $78 million of expense compared to $21 million of income for the corresponding period in 2020. The increases in other expense were primarily due to charitable contributions of $26 million and $101 million in the second quarter and year-to-date 2021, respectively.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Income Taxes (Benefit)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Second Quarter 2021 vs. Second Quarter 2020
|
|
Year-To-Date 2021 vs. Year-To-Date 2020
|
|
(change in millions)
|
|
(% change)
|
|
(change in millions)
|
|
(% change)
|
|
$(45)
|
|
(281.3)
|
|
$(3)
|
|
(3.2)
|
In the second quarter 2021, income tax benefit was $29 million compared to income tax expense of $16 million for the corresponding period in 2020. The change was primarily the result of a pre-tax impairment charge at gas pipeline investments related to the PennEast Pipeline project and a pre-tax loss at wholesale gas services in the second quarter 2021. For year-to-date 2021, income taxes were $92 million compared to $95 million for the corresponding period in 2020. The pre-tax impairment charge at gas pipeline investments was largely offset by higher pre-tax earnings at wholesale gas services and gas distribution operations. See Notes (C) and (E) to the Condensed Financial Statements herein under "Other Matters – Southern Company Gas" and "Southern Company Gas," respectively, for additional information.
Performance and Non-GAAP Measures
Adjusted operating margin is a non-GAAP measure that is calculated as operating revenues less cost of natural gas, cost of other sales, and revenue tax expense. Adjusted operating margin excludes other operations and maintenance expenses, depreciation and amortization, and taxes other than income taxes, which are included in the calculation of operating income as calculated in accordance with GAAP and reflected in the statements of income. The presentation of adjusted operating margin is believed to provide useful information regarding the contribution resulting from base rate changes, infrastructure replacement programs and capital projects, and customer growth at gas distribution operations since the cost of natural gas and revenue tax expense can vary significantly and are generally billed directly to customers. Southern Company Gas further believes that utilizing adjusted operating margin at gas pipeline investments, wholesale gas services, and gas marketing services allows it to focus on a direct measure of performance before overhead costs. The applicable reconciliation of operating income to adjusted operating margin is provided herein.
Adjusted operating margin should not be considered an alternative to, or a more meaningful indicator of, Southern Company Gas' operating performance than operating income as determined in accordance with GAAP. In addition, Southern Company Gas' adjusted operating margin may not be comparable to similarly titled measures of other companies.
Detailed variance explanations of Southern Company Gas' financial performance are provided herein.
Reconciliations of operating income to adjusted operating margin are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Second Quarter 2021
|
Second Quarter 2020
|
|
Year-To-Date 2021
|
Year-To-Date 2020
|
|
|
(in millions)
|
|
Operating Income
|
$
|
31
|
|
$
|
102
|
|
|
$
|
632
|
|
$
|
462
|
|
|
Other operating expenses(a)
|
415
|
|
390
|
|
|
925
|
|
840
|
|
|
Revenue taxes(b)
|
(22)
|
|
(22)
|
|
|
(75)
|
|
(67)
|
|
|
Adjusted Operating Margin
|
$
|
424
|
|
$
|
470
|
|
|
$
|
1,482
|
|
$
|
1,235
|
|
(a)Includes other operations and maintenance, depreciation and amortization, and taxes other than income taxes.
(b)Nicor Gas' revenue tax expenses, which are passed through directly to customers.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Segment Information
Adjusted operating margin, operating expenses, and net income for each segment are provided in the table below. See Note (L) to the Condensed Financial Statements under "Southern Company Gas" herein for additional information.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Second Quarter 2021
|
|
Second Quarter 2020
|
|
|
Adjusted Operating Margin(*)
|
|
Operating Expenses(*)
|
|
Net Income (Loss)
|
|
Adjusted Operating Margin(*)
|
|
Operating Expenses(*)
|
|
Net Income (Loss)
|
|
|
(in millions)
|
|
(in millions)
|
|
Gas distribution operations
|
$
|
486
|
|
|
$
|
340
|
|
|
$
|
80
|
|
|
$
|
441
|
|
|
$
|
314
|
|
|
$
|
74
|
|
|
Gas pipeline investments
|
8
|
|
|
3
|
|
|
(36)
|
|
|
8
|
|
|
3
|
|
|
21
|
|
|
Wholesale gas services
|
(110)
|
|
|
11
|
|
|
(112)
|
|
|
(19)
|
|
|
11
|
|
|
(23)
|
|
|
Gas marketing services
|
35
|
|
|
25
|
|
|
6
|
|
|
35
|
|
|
28
|
|
|
5
|
|
|
All other
|
6
|
|
|
15
|
|
|
(3)
|
|
|
7
|
|
|
14
|
|
|
(6)
|
|
|
Intercompany eliminations
|
(1)
|
|
|
(1)
|
|
|
—
|
|
|
(2)
|
|
|
(2)
|
|
|
—
|
|
|
Consolidated
|
$
|
424
|
|
|
$
|
393
|
|
|
$
|
(65)
|
|
|
$
|
470
|
|
|
$
|
368
|
|
|
$
|
71
|
|
(*)Adjusted operating margin and operating expenses are adjusted for Nicor Gas' revenue tax expenses, which are passed through directly to customers.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year-To-Date 2021
|
|
Year-To-Date 2020
|
|
|
Adjusted Operating Margin(*)
|
|
Operating Expenses(*)
|
|
Net Income (Loss)
|
|
Adjusted Operating Margin(*)
|
|
Operating Expenses(*)
|
|
Net Income (Loss)
|
|
|
(in millions)
|
|
(in millions)
|
|
Gas distribution operations
|
$
|
1,130
|
|
|
$
|
697
|
|
|
$
|
263
|
|
|
$
|
1,036
|
|
|
$
|
654
|
|
|
$
|
238
|
|
|
Gas pipeline investments
|
16
|
|
|
6
|
|
|
(7)
|
|
|
16
|
|
|
6
|
|
|
51
|
|
|
Wholesale gas services
|
187
|
|
|
66
|
|
|
14
|
|
|
31
|
|
|
28
|
|
|
—
|
|
|
Gas marketing services
|
139
|
|
|
54
|
|
|
62
|
|
|
142
|
|
|
58
|
|
|
62
|
|
|
All other
|
13
|
|
|
30
|
|
|
1
|
|
|
13
|
|
|
30
|
|
|
(5)
|
|
|
Intercompany eliminations
|
(3)
|
|
|
(3)
|
|
|
—
|
|
|
(3)
|
|
|
(3)
|
|
|
—
|
|
|
Consolidated
|
$
|
1,482
|
|
|
$
|
850
|
|
|
$
|
333
|
|
|
$
|
1,235
|
|
|
$
|
773
|
|
|
$
|
346
|
|
(*)Adjusted operating margin and operating expenses are adjusted for Nicor Gas' revenue tax expenses, which are passed through directly to customers.
Gas Distribution Operations
Gas distribution operations is the largest component of Southern Company Gas' business and is subject to regulation and oversight by regulatory agencies in each of the states it serves. These agencies approve natural gas rates designed to provide Southern Company Gas with the opportunity to generate revenues to recover the cost of natural gas delivered to its customers and its fixed and variable costs, including depreciation, interest expense, operations and maintenance, taxes, and overhead costs, and to earn a reasonable return on its investments.
With the exception of Atlanta Gas Light, Southern Company Gas' second largest utility that operates in a deregulated natural gas market and has a straight-fixed-variable rate design that minimizes the variability of its revenues based on consumption, the earnings of the natural gas distribution utilities can be affected by customer consumption patterns that are a function of weather conditions, price levels for natural gas, and general economic conditions that may impact customers' ability to pay for natural gas consumed. Southern Company Gas has various 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.
In the second quarter and year-to-date 2021, net income increased $6 million, or 8.1%, and $25 million, or 10.5%, respectively, when compared to the corresponding periods in 2020. In the second quarter and year-to-date 2021, adjusted operating margin increased $45 million and $94 million, respectively, when compared to the corresponding periods in 2020 primarily due to rate increases for Atlanta Gas Light, Virginia Natural Gas, and Chattanooga Gas and continued investment in infrastructure replacement. In the second quarter and year-to-date 2021, operating expenses increased $26 million and $43 million, respectively, when compared to the corresponding periods in 2020 primarily due to higher depreciation resulting from additional assets placed in service, as well as higher compensation expenses. In the second quarter and year-to-date 2021, interest expense, net of amounts capitalized increased $5 million and $10 million, respectively, when compared to the corresponding periods in 2020 primarily due to additional debt issued to finance continued investments. In the second quarter and year-to-date 2021, income taxes increased $6 million and $12 million, respectively, when compared to the corresponding periods in 2020 primarily due to higher pre-tax earnings.
See Note 2 to the financial statements under "Southern Company Gas" in Item 8 of the Form 10-K for additional information.
Gas Pipeline Investments
Gas pipeline investments consists primarily of joint ventures in natural gas pipeline investments including SNG, PennEast Pipeline, Dalton Pipeline, and Atlantic Coast Pipeline (until its sale on March 24, 2020). See Note (E) to the Condensed Financial Statements under "Southern Company Gas" herein and Note 15 to the financial statements under "Southern Company Gas" in Item 8 of the Form 10-K for additional information.
For the second quarter and year-to-date 2021, net income decreased $57 million and $58 million, respectively, when compared to the corresponding periods in 2020. The decreases were due to a pre-tax impairment charge of $82 million ($58 million after tax) related to the equity method investment in the PennEast Pipeline project. See Notes (C) and (E) to the Condensed Financial Statements herein under "Other Matters – Southern Company Gas" and "Southern Company Gas," respectively, for additional information.
Wholesale Gas Services
Prior to the sale of Sequent on July 1, 2021, wholesale gas services was involved in asset management and optimization, storage, transportation, producer and peaking services, natural gas supply, natural gas services, and wholesale gas marketing. Southern Company Gas positioned the business to generate positive economic earnings on an annual basis even under low volatility market conditions that can result from a number of factors. When market price volatility increased, wholesale gas services was positioned to capture significant value and generate stronger results. Operating expenses primarily reflect employee compensation and benefits. See Note (K) to the Condensed Financial Statements under "Southern Company Gas" herein for information regarding the sale of Sequent on July 1, 2021.
In the second quarter 2021, net income decreased $89 million when compared to the corresponding period in 2020. The decrease primarily relates to a $91 million decrease in adjusted operating margin and a $26 million decrease in other income and (expense) related to higher charitable contributions, partially offset by a $27 million decrease in income tax expense due to lower pre-tax earnings.
For year-to-date 2021, net income increased $14 million when compared to the corresponding period in 2020. The increase primarily relates to a $156 million increase in adjusted operating margin, partially offset by a $38 million increase in operating expenses primarily related to an increase in variable compensation. The increase was also partially offset by a $101 million decrease in other income and (expense) related to higher charitable contributions and a $4 million increase in income tax expense due to higher pre-tax earnings.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Details of the changes in adjusted operating margin are provided in the table below.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Second Quarter 2021
|
Second Quarter 2020
|
|
Year-To-Date 2021
|
Year-To-Date 2020
|
|
|
(in millions)
|
|
Commercial activity recognized
|
$
|
(6)
|
|
$
|
(33)
|
|
|
$
|
309
|
|
$
|
(42)
|
|
|
Gain (loss) on storage derivatives
|
(24)
|
|
(5)
|
|
|
(26)
|
|
(11)
|
|
|
Gain (loss) on transportation and forward commodity derivatives
|
(80)
|
|
19
|
|
|
(96)
|
|
85
|
|
|
|
|
|
|
|
|
|
Purchase accounting adjustments to fair value inventory and contracts
|
—
|
|
—
|
|
|
—
|
|
(1)
|
|
|
Adjusted operating margin
|
$
|
(110)
|
|
$
|
(19)
|
|
|
$
|
187
|
|
$
|
31
|
|
Change in Commercial Activity
The commercial activity at wholesale gas services includes recognition of storage and transportation values that were generated in prior periods, which reflect the impact of prior period hedge gains and losses as associated physical transactions occur. The increase in commercial activity in the second quarter 2021 compared to the corresponding period in 2020 was primarily due to large losses in the second quarter 2020 driven by mild weather and tight transportation spreads. The increase in commercial activity for year-to-date 2021 compared to the corresponding period in 2020 was primarily due to natural gas price volatility that was generated by cold weather, particularly in the Midwest and Texas, resulting in wider transportation spreads.
Change in Storage and Transportation Derivatives
Volatility in the natural gas market arises from a number of factors, such as weather fluctuations or changes in supply or demand for natural gas in different regions of the U.S. The volatility of natural gas commodity prices has a significant impact on Southern Company Gas' customer rates, long-term competitive position against other energy sources, and the ability of wholesale gas services to capture value from locational and seasonal spreads. Forward storage or time spreads applicable to the locations of wholesale gas services' specific storage positions in 2021 resulted in storage derivative losses. Transportation and forward commodity derivative losses in 2021 were a result of widening transportation spreads.
Gas Marketing Services
Gas marketing services provides energy-related products and services to natural gas markets and participants in customer choice programs that were approved in various states to increase competition. These programs allow customers to choose their natural gas supplier while the local distribution utility continues to provide distribution and transportation services. Gas marketing services is weather sensitive and uses a variety of hedging strategies, such as weather derivative instruments and other risk management tools, to partially mitigate potential weather impacts.
All Other
All other includes natural gas storage businesses, including Jefferson Island through its sale on December 1, 2020, fuels operations through the sale of Southern Company Gas' interest in Pivotal LNG on March 24, 2020, 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. See Note 15 to the financial statements under "Southern Company Gas" in Item 8 of the Form 10-K for additional information on the sale of its interest in Pivotal LNG and the sale of Jefferson Island.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Segment Reconciliations
Reconciliations of operating income to adjusted operating margin for the second quarter and year-to-date 2021 and 2020 are reflected in the following tables. See Note (L) to the Condensed Financial Statements herein for additional information.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas Distribution Operations
|
Gas Pipeline Investments
|
Wholesale Gas Services
|
Gas Marketing Services
|
All Other
|
Intercompany Elimination
|
Consolidated
|
|
|
(in millions)
|
|
Second Quarter 2021
|
|
|
|
|
|
|
|
|
Operating Income (Loss)
|
$
|
146
|
|
$
|
5
|
|
$
|
(121)
|
|
$
|
10
|
|
$
|
(9)
|
|
$
|
—
|
|
$
|
31
|
|
|
Other operating expenses(a)
|
362
|
|
3
|
|
11
|
|
25
|
|
15
|
|
(1)
|
|
415
|
|
|
Revenue tax expense(b)
|
(22)
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
(22)
|
|
|
Adjusted Operating Margin
|
$
|
486
|
|
$
|
8
|
|
$
|
(110)
|
|
$
|
35
|
|
$
|
6
|
|
$
|
(1)
|
|
$
|
424
|
|
|
|
|
|
|
|
|
|
|
|
Second Quarter 2020
|
|
|
|
|
|
|
|
|
Operating Income (Loss)
|
$
|
127
|
|
$
|
5
|
|
$
|
(30)
|
|
$
|
7
|
|
$
|
(7)
|
|
$
|
—
|
|
$
|
102
|
|
|
Other operating expenses(a)
|
336
|
|
3
|
|
11
|
|
28
|
|
14
|
|
(2)
|
|
390
|
|
|
Revenue tax expense(b)
|
(22)
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
(22)
|
|
|
Adjusted Operating Margin
|
$
|
441
|
|
$
|
8
|
|
$
|
(19)
|
|
$
|
35
|
|
$
|
7
|
|
$
|
(2)
|
|
$
|
470
|
|
|
|
|
|
|
|
|
|
|
|
Year-To-Date 2021
|
|
|
|
|
|
|
|
|
Operating Income (Loss)
|
$
|
433
|
|
$
|
10
|
|
$
|
121
|
|
$
|
85
|
|
$
|
(17)
|
|
$
|
—
|
|
$
|
632
|
|
|
Other operating expenses(a)
|
772
|
|
6
|
|
66
|
|
54
|
|
30
|
|
(3)
|
|
925
|
|
|
Revenue tax expense(b)
|
(75)
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
(75)
|
|
|
Adjusted Operating Margin
|
$
|
1,130
|
|
$
|
16
|
|
$
|
187
|
|
$
|
139
|
|
$
|
13
|
|
$
|
(3)
|
|
$
|
1,482
|
|
|
|
|
|
|
|
|
|
|
|
Year-To-Date 2020
|
|
|
|
|
|
|
|
|
Operating Income (Loss)
|
$
|
382
|
|
$
|
10
|
|
$
|
3
|
|
$
|
84
|
|
$
|
(17)
|
|
$
|
—
|
|
$
|
462
|
|
|
Other operating expenses(a)
|
721
|
|
6
|
|
28
|
|
58
|
|
30
|
|
(3)
|
|
840
|
|
|
Revenue tax expense(b)
|
(67)
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
(67)
|
|
|
Adjusted Operating Margin
|
$
|
1,036
|
|
$
|
16
|
|
$
|
31
|
|
$
|
142
|
|
$
|
13
|
|
$
|
(3)
|
|
$
|
1,235
|
|
(a)Includes other operations and maintenance, depreciation and amortization, and taxes other than income taxes.
(b)Nicor Gas' revenue tax expenses, which are passed through directly to customers.
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, continued customer growth, and the trend of reduced electricity usage per customer, especially in residential and
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
commercial markets. For Georgia Power, completing construction of Plant Vogtle Units 3 and 4 and related cost recovery proceedings is another major factor.
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 have been significantly affected by a series of demand and supply shocks that caused a global and national economic recession in 2020. Most prominently, the COVID-19 pandemic has negatively impacted global supply chains and business operations as suppliers continue to experience difficulties keeping up with strong demand for factory goods, which is being driven by low business inventories. The combination of rising inoculation rates in the U.S. population and the recent federal COVID-19 relief package is expected to help boost economic recovery in 2021. The drivers, speed, and depth of the 2020 economic contraction were unprecedented and have reduced energy demand across the Southern Company system's service territory, primarily in the commercial and industrial classes. The negative impacts, which started in late-March 2020, of the COVID-19 pandemic and related recession on the Southern Company system's retail electric sales began to improve in the middle of May 2020. Retail electric revenues attributable to changes in sales increased in the first half of 2021 when compared to the corresponding period in 2020 primarily due to the normalization of economic activity; however, retail electric sales continued to be negatively impacted by the COVID-19 pandemic when compared to pre-pandemic trends. Recovery is expected to continue in the second half of 2021, but responses to the COVID-19 pandemic by both customers and governments could significantly affect the pace of recovery. The ultimate extent of the negative impact on revenues depends on the depth and duration of the economic contraction in the Southern Company system's service territory and cannot be determined at this time. See RESULTS OF OPERATIONS herein for information on COVID-19-related impacts on energy demand in the Southern Company system's service territory during the first half of 2021.
The level of future earnings for Southern Power's competitive wholesale electric business depends on numerous factors including Southern Power's ability to execute its growth strategy through the development or acquisition of renewable facilities and other energy projects while containing costs, as well as regulatory matters, creditworthiness of customers, total electric generating capacity available in Southern Power's market areas, and Southern Power's ability to successfully remarket capacity as current contracts expire. In addition, renewable portfolio standards, availability of tax credits, transmission constraints, cost of generation from units within the Southern Company power pool, and operational limitations could influence Southern Power's future earnings.
The level of future earnings for Southern Company Gas' primary business of distributing natural gas and its complementary businesses in the gas pipeline investments and gas marketing services sectors depends on numerous factors. These factors include the natural gas distribution utilities' ability to maintain constructive regulatory environments that allow for the timely recovery of prudently-incurred costs, the completion and subsequent operation of ongoing infrastructure and other construction projects, creditworthiness of customers, and Southern Company Gas' ability to optimize its transportation and storage positions and to re-contract storage rates at favorable prices. The volatility of natural gas prices has an impact on Southern Company Gas' customer rates, its long-term competitive position against other energy sources, and the ability of Southern Company Gas' gas marketing services business to capture value from locational and seasonal spreads. Additionally, changes in commodity prices subject a portion of Southern Company Gas' operations to earnings variability. Over the longer term, volatility is expected to be low to moderate and locational and/or transportation spreads are expected to decrease as new pipelines are built to reduce the existing supply constraints in the shale areas of the Northeast U.S. To the extent these pipelines are delayed or not built, volatility could increase. See Note 3 to the financial statements in Item 8 of the Form 10-K and Note (C) to the Condensed Financial Statements herein under "Other Matters – Southern Company Gas" for additional information on challenges experienced by the PennEast Pipeline project. Additional economic factors may contribute to this environment, including a significant drop in oil and natural gas prices, which could lead to consolidation of natural gas producers or reduced levels of natural gas production. In addition, if the COVID-19 pandemic results in continued economic uncertainty for a sustained
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
period, demand for natural gas may decrease, resulting in further downward pressure on natural gas prices and lower volatility in the natural gas markets on a longer-term basis.
Earnings for both the electricity and natural gas businesses are subject to a variety of other factors. These factors include weather, competition, developing new and maintaining existing energy contracts and associated load requirements with wholesale customers, energy conservation practiced by customers, the use of alternative energy sources by customers, government incentives to reduce overall energy usage, the prices of electricity and natural gas, and the price elasticity of demand. Demand for electricity and natural gas in the Registrants' service territories is primarily driven by the pace of economic growth or decline that may be affected by changes in regional and global economic conditions, which may impact future earnings.
As part of its ongoing effort to adapt to changing market conditions, Southern Company continues to evaluate and consider a wide array of potential business strategies. These strategies may include business combinations, partnerships, and acquisitions involving other utility or non-utility businesses or properties, disposition of certain assets or businesses, internal restructuring, or some combination thereof. Furthermore, Southern Company may engage in new business ventures that arise from competitive and regulatory changes in the utility industry. Pursuit of any of the above strategies, or any combination thereof, may significantly affect the business operations, risks, and financial condition of Southern Company. In addition, Southern Power and Southern Company Gas regularly consider and evaluate joint development arrangements as well as acquisitions and dispositions of businesses and assets as part of their business strategies. See Note 15 to the financial statements in Item 8 of the Form 10-K and Note (K) to the Condensed Financial Statements herein for additional information.
For additional information relating to these issues, see RISK FACTORS 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 "Environmental Remediation" herein, for additional information.
Environmental Laws and Regulations
Water Quality
On July 26, 2021, the EPA announced its intent to further revise the ELG Rules, with a proposed rule expected in the fall of 2022. The ultimate outcome of this matter cannot be determined at this time; however, any revisions could require changes in the traditional electric operating companies' compliance strategies.
Alabama Power is assessing the viability of complying with the ELG Rules for certain of its coal units (totaling approximately 2,000 MWs) due to the timing and anticipated cost to comply with the ELG Rules. The results of the assessment could accelerate a determination to discontinue or modify operation of the units. Alabama Power will review all of the facts and circumstances and evaluate all alternatives prior to reaching a final determination. The units under evaluation have net book values totaling approximately $2.3 billion at June 30, 2021. Additionally, net capitalized asset retirement costs associated with these facilities totaled approximately $900 million at June 30, 2021.
Based on an Alabama PSC order, Alabama Power is authorized to establish a regulatory asset to record the unrecovered investment costs, including the plant asset balance and the costs associated with site removal and closure, associated with future unit retirements caused by environmental regulations (Environmental Accounting Order). Under the Environmental Accounting Order, the regulatory asset would be amortized and recovered over an affected unit's remaining useful life, as established prior to the decision regarding early retirement, through Rate CNP Compliance. See Note 2 to the financial statements under "Alabama Power – Rate CNP Compliance" and " –
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Environmental Accounting Order" in Item 8 of the Form 10-K for additional information. The ultimate outcome of this matter cannot be determined at this time.
Regulatory Matters
See OVERVIEW – "Recent Developments" and Note 2 to the financial statements in Item 8 of the Form 10-K 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 16, 2021, Alabama Power filed a petition with the Alabama PSC to extend its Renewable Generation Certificate (RGC) expiration from September 16, 2021 to September 16, 2027. The RGC currently in place authorizes Alabama Power to procure up to 500 MWs of capacity and energy from renewable energy resources and to separately market the related energy and environmental attributes to customers and other third parties. Alabama Power has four solar projects under the RGC totaling approximately 170 MWs. The ultimate outcome of this matter cannot be determined at this time.
Georgia Power
In 2021, as authorized in its 2019 IRP, Georgia Power requested and received certification from the Georgia PSC for 970 MWs of utility-scale PPAs for solar generation resources, which are expected to be in operation by the end of 2023. 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 intends to continue its strategy of developing and constructing new electric generating facilities, expanding and improving the electric transmission and electric and natural gas distribution systems, and undertaking projects to comply with environmental laws and regulations.
For the traditional electric operating companies, major generation construction projects are subject to state PSC approval in order to be included in retail rates. The largest construction project currently underway in the Southern Company system is Plant Vogtle Units 3 and 4. See Note (B) to the Condensed Financial Statements under "Georgia Power – 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" for information regarding Alabama Power's construction of Plant Barry Unit 8.
See Note 15 to the financial statements in Item 8 of the Form 10-K and Note (K) to the Condensed Financial Statements herein under "Southern Power" for additional information about costs relating to Southern Power's acquisitions that involve construction of renewable energy facilities.
Southern Company Gas is engaged in various infrastructure improvement programs designed to update or expand the natural gas distribution systems of the natural gas distribution utilities to improve reliability and meet operational flexibility and growth. The natural gas distribution utilities recover their investment and a return associated with these infrastructure programs through their regulated rates. See Notes 2 and 3 to the financial statements in Item 8 of the Form 10-K and Notes (B) and (C) to the Condensed Financial Statements herein under "Southern Company Gas" and "Other Matters – Southern Company Gas – PennEast Pipeline Project," respectively, 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.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
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.
Alabama Power
On March 10, 2021, Alabama Power executed a coordinated planning and operations agreement with PowerSouth, with a minimum term of 10 years. The agreement, which includes combined operations (including joint commitment and dispatch), is expected to create energy cost savings and enhanced system reliability for both parties. Projected revenues are expected to offset any increased administrative costs incurred by Alabama Power; therefore, no material impact to net income is expected. Alabama Power has the right to participate in a portion of PowerSouth's future incremental load growth. Implementation of the agreement is subject to certain regulatory approvals, including approvals of the Rural Utilities Service, the SERC Reliability Corporation, and the FERC, and is expected to be completed by March 2022. 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.
Application of Critical Accounting Policies and Estimates
The Registrants prepare their financial statements in accordance with GAAP. Significant accounting policies are described in the notes to the financial statements in 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.
Estimated Cost, Schedule, and Rate Recovery for the Construction of Plant Vogtle Units 3 and 4
(Southern Company and Georgia Power)
Following milestone extensions in January 2021, Southern Nuclear has been performing additional construction remediation work necessary to ensure quality and design standards are met as system turnovers are completed to support hot functional testing and fuel load for Unit 3. Hot functional testing for Unit 3 was completed in July 2021. As a result of challenges including, but not limited to, construction productivity, construction remediation work, the pace of system turnovers, spent fuel pool repairs, and the timeframe and duration for hot functional and other testing, at the end of the second quarter 2021, Southern Nuclear further extended certain milestone dates, including the fuel load for Unit 3, from those established in January 2021. The site work plan currently targets fuel load for Unit 3 in the fourth quarter 2021 and an in-service date of March 2022. As the site work plan includes minimal margin to these milestone dates, an in-service date in the second quarter 2022 for Unit 3 is projected, although any further delays could result in a later in-service date.
As the result of productivity challenges, at the end of the second quarter 2021, Southern Nuclear also further extended milestone dates for Unit 4 from those established in January 2021. The site work plan targets an in-service date of November 2022 and primarily depends on overall construction productivity and production levels significantly improving as well as appropriate levels of craft laborers, particularly electricians and pipefitters, being
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
added and maintained. As the site work plan includes minimal margin to the milestone dates, an in-service date in the first quarter 2023 for Unit 4 is projected, although any further delays could result in a later in-service date.
As of March 31, 2021, approximately $84 million of the construction contingency established in the fourth quarter 2020 was assigned to the base capital cost forecast for costs primarily associated with the schedule extension for Unit 3 to December 2021, construction productivity, support resources, and construction remediation work. Georgia Power increased its total capital cost forecast as of March 31, 2021 by adding $48 million to the remaining construction contingency. Considering the factors above, during the second quarter 2021, all of the remaining construction contingency previously established and an additional $341 million was assigned to the base capital cost forecast for costs primarily associated with the schedule extensions for Units 3 and 4 described above, construction remediation work for Unit 3, and construction productivity and support resources for Units 3 and 4. Georgia Power also increased its total capital cost forecast as of June 30, 2021 by adding $119 million to replenish construction contingency. Georgia Power's revised base capital cost forecast and contingency to complete construction and start-up of Plant Vogtle Units 3 and 4 is $9.10 billion and $0.12 billion, respectively, for a total capital cost forecast of $9.22 billion (net of $1.7 billion received under the Guarantee Settlement Agreement and approximately $188 million in related customer refunds).
After considering the significant level of uncertainty that exists regarding the future recoverability of these costs since the ultimate outcome of these matters is subject to the outcome of future assessments by management, as well as Georgia PSC decisions in future regulatory proceedings, Georgia Power recorded pre-tax charges to income in the first quarter 2021 and the second quarter 2021 of $48 million ($36 million after tax) and $460 million ($343 million after tax), respectively, for the increases in the total project capital cost forecast. As and when these amounts are spent, Georgia Power may request the Georgia PSC to evaluate those expenditures for rate recovery.
The ultimate impact of these matters on the construction schedule and budget 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.
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, 2021. 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 and Note (K) to the Condensed Financial Statements herein for additional information.
At the end of the second quarter 2021, the market price of Southern Company's common stock was $60.51 per share (based on the closing price as reported on the NYSE) and the book value was $26.63 per share, representing a market-to-book ratio of 227%, compared to $61.43, $26.48, and 232%, respectively, at the end of 2020. Southern Company's common stock dividend for the second quarter 2021 was $0.66 per share compared to $0.64 per share in the second quarter 2020.
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. 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
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
replacements and adding or changing fuel sources at existing electric generating units, to meet regulatory requirements; changes in FERC rules and regulations; state regulatory agency approvals; changes in the expected environmental compliance program; changes in legislation; the cost and efficiency of construction labor, equipment, and materials; project scope and design changes; abnormal weather; delays in construction due to judicial or regulatory action; storm impacts; and the cost of capital. The continued impacts of the COVID-19 pandemic could also impair the ability to develop, construct, and operate facilities, as discussed further in Item 1A of the Form 10-K. In addition, there can be no assurance that costs related to capital expenditures 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 in Item 8 of the Form 10-K and Note (K) to the Condensed Financial Statements herein under "Southern Power" for additional information regarding Southern Power's plant acquisitions and construction projects.
The construction program of Georgia Power includes Plant Vogtle Units 3 and 4, which includes components based on new technology that only within the last few years began initial operation in the global nuclear industry at this scale and which may be subject to additional revised cost estimates during construction. See Note 2 to the financial statements 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, 2020.
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 and equity issuances. Equity capital can be provided from any combination of Southern Company's stock plans, private placements, or public offerings. Southern Company does not expect to issue any equity in the capital markets through 2025 but may issue equity through its stock plans during this time. See Note 8 to the financial statements under "Equity Units" in Item 8 of the Form 10-K for information on stock purchase contracts associated with Southern Company's equity units.
The Subsidiary Registrants plan to obtain the funds to meet their future capital needs from sources similar to those they used in the past, which were primarily from operating cash flows, external securities issuances, borrowings from financial institutions, and equity contributions from Southern Company. In addition, Georgia Power plans to utilize borrowings from the FFB (as discussed further in Note 8 to the financial statements under "Long-term Debt – DOE Loan Guarantee Borrowings" in Item 8 of the Form 10-K) and Southern Power plans to utilize tax equity partnership contributions (as discussed further herein).
The amount, type, and timing of any financings in 2021, 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. In March 2021, Southern Power obtained tax equity funding for the Deuel Harvest wind facility and received proceeds of $220 million. In addition, during the first six months of 2021, Southern Power received tax equity funding totaling $17 million from existing partnerships. Subsequent to June 30, 2021, Southern Power obtained tax equity funding for the Garland battery energy storage facility and received initial proceeds of $11 million. See Note 1 to
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
the financial statements under "General" in Item 8 of the Form 10-K and Note (K) to the Condensed Financial Statements under "Southern Power" herein 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, 2021, the amount of subsidiary retained earnings restricted to dividend totaled $1.1 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, 2021 for the applicable Registrants:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
At June 30, 2021
|
Southern Company
|
|
Georgia
Power
|
Mississippi Power
|
Southern Power
|
Southern Company Gas
|
|
|
(in millions)
|
|
Current liabilities in excess of current assets
|
$
|
2,109
|
|
|
$
|
1,438
|
|
$
|
20
|
|
$
|
720
|
|
$
|
477
|
|
The Registrants believe the need for working capital can be adequately met by utilizing operating cash flows, as well as commercial paper, lines of credit, and short-term bank notes, as market conditions permit. In addition, under certain circumstances, the Subsidiary Registrants may utilize equity contributions and/or loans from Southern Company.
Bank Credit Arrangements
At June 30, 2021, the Registrants' unused committed credit arrangements with banks were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
At June 30, 2021
|
Southern
Company
parent
|
Alabama Power
|
Georgia
Power
|
Mississippi Power
|
Southern
Power(a)
|
Southern Company Gas(b)
|
SEGCO
|
Southern
Company
|
|
|
(in millions)
|
|
Unused committed credit
|
$
|
1,999
|
|
$
|
1,228
|
|
$
|
1,728
|
|
$
|
250
|
|
$
|
568
|
|
$
|
1,747
|
|
$
|
30
|
|
$
|
7,550
|
|
(a)At June 30, 2021, Southern Power also had two continuing letters of credit facilities for standby letters of credit, of which $24 million was unused. Southern Power's subsidiaries are not parties to its bank credit arrangements or letter of credit facilities.
(b)Includes $1.047 billion and $700 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, 2021 was approximately $1.4 billion (comprised of approximately $854 million at Alabama Power, $550 million at Georgia Power, and $34 million at Mississippi Power). In addition, at June 30, 2021, Georgia Power and Mississippi Power had approximately $105 million and $50 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.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
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, 2021
|
|
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
|
$
|
1,402
|
|
|
0.3
|
%
|
|
$
|
990
|
|
|
0.3
|
%
|
|
$
|
1,621
|
|
|
Alabama Power
|
—
|
|
|
—
|
|
|
50
|
|
|
0.1
|
|
|
200
|
|
|
Georgia Power
|
310
|
|
|
0.2
|
|
|
183
|
|
|
0.2
|
|
|
407
|
|
|
Mississippi Power
|
—
|
|
|
—
|
|
|
39
|
|
|
0.2
|
|
|
81
|
|
|
Southern Power
|
119
|
|
|
0.2
|
|
|
152
|
|
|
0.2
|
|
|
315
|
|
|
Southern Company Gas:
|
|
|
|
|
|
|
|
|
|
|
Southern Company Gas Capital
|
$
|
444
|
|
|
0.2
|
%
|
|
$
|
85
|
|
|
0.2
|
%
|
|
$
|
485
|
|
|
Nicor Gas
|
390
|
|
|
0.5
|
|
|
396
|
|
|
0.5
|
|
|
512
|
|
|
Southern Company Gas Total
|
$
|
834
|
|
|
0.3
|
%
|
|
$
|
481
|
|
|
0.5
|
%
|
|
|
(*)Average and maximum amounts are based upon daily balances during the three-month period ended June 30, 2021.
Analysis of Cash Flows
Net cash flows provided from (used for) operating, investing, and financing activities for the six months ended June 30, 2021 and 2020 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, 2021
|
|
|
|
|
|
|
|
Operating activities
|
$
|
2,904
|
|
$
|
584
|
|
$
|
1,313
|
|
$
|
41
|
|
$
|
411
|
|
$
|
722
|
|
|
Investing activities
|
(4,026)
|
|
(893)
|
|
(1,730)
|
|
(117)
|
|
(601)
|
|
(668)
|
|
|
Financing activities
|
1,671
|
|
506
|
|
457
|
|
515
|
|
196
|
|
(25)
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended June 30, 2020
|
|
|
|
|
|
|
|
Operating activities
|
$
|
2,847
|
|
$
|
674
|
|
$
|
1,124
|
|
$
|
71
|
|
$
|
195
|
|
$
|
1,046
|
|
|
Investing activities
|
(2,655)
|
|
(783)
|
|
(1,659)
|
|
(145)
|
|
490
|
|
(570)
|
|
|
Financing activities
|
(285)
|
|
116
|
|
869
|
|
(178)
|
|
(808)
|
|
(401)
|
|
Fluctuations in cash flows from financing activities vary from year to year based on capital needs and the maturity or redemption of securities.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Southern Company
Net cash provided from operating activities increased $0.1 billion for the six months ended June 30, 2021 as compared to the corresponding period in 2020 primarily due to the timing of vendor payments and customer bill credits issued in 2020 at Georgia Power, partially offset by under recovered natural gas costs at Southern Company Gas resulting from Winter Storm Uri and decreased fuel cost recovery at the traditional electric operating companies resulting from an increase in the cost of fuel.
The net cash used for investing activities for the six months ended June 30, 2021 was primarily related to the Subsidiary Registrants' construction programs.
The net cash provided from financing activities for the six months ended June 30, 2021 was primarily related to net issuances of long-term debt, commercial paper, and short-term bank loans, partially offset by common stock dividend payments.
Alabama Power
Net cash provided from operating activities decreased $90 million for the six months ended June 30, 2021 as compared to the corresponding period in 2020 primarily due to the timing of income tax payments and decreased fuel cost recovery, partially offset by an increase in retail revenues associated with an increase in Rate RSE effective in January 2021 and colder weather in Alabama Power's service territory in the first quarter 2021 compared to the corresponding period in 2020, as well as the timing of fossil fuel stock purchases.
The net cash used for investing activities for the six months ended June 30, 2021 was primarily related to gross property additions.
The net cash provided from financing activities for the six months ended June 30, 2021 was primarily related to a capital contribution from Southern Company and the net issuance of senior notes, partially offset by common stock dividend payments.
Georgia Power
Net cash provided from operating activities increased $189 million for the six months ended June 30, 2021 as compared to the corresponding period in 2020 primarily due to customer bill credits issued in 2020 associated with Tax Reform and 2018 earnings in excess of the allowed retail ROE range and the timing of fossil fuel stock purchases and vendor payments, partially offset by decreased fuel cost recovery.
The net cash used for investing activities for the six months ended June 30, 2021 was primarily related to gross property additions, including a total of approximately $640 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 construction of Plant Vogtle Units 3 and 4.
The net cash provided from financing activities for the six months ended June 30, 2021 was primarily related to net issuances of senior notes, borrowings from the FFB for construction of Plant Vogtle Units 3 and 4, capital contributions from Southern Company, and an increase in notes payable, partially offset by common stock dividend payments.
Mississippi Power
Net cash provided from operating activities decreased $30 million for the six months ended June 30, 2021 as compared to the corresponding period in 2020 primarily due to decreased fuel cost recovery and the timing of vendor payments.
The net cash used for investing activities for the six months ended June 30, 2021 was primarily related to gross property additions.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
The net cash provided from financing activities for the six months ended June 30, 2021 was primarily related to the issuance of senior notes and capital contributions from Southern Company, partially offset by common stock dividend payments and a decrease in commercial paper borrowings.
Southern Power
Net cash provided from operating activities increased $216 million for the six months ended June 30, 2021 as compared to the corresponding period in 2020 primarily due to an increase in the utilization of tax credits in 2021.
The net cash used for investing activities for the six months ended June 30, 2021 was primarily related to the acquisition of the Deuel Harvest wind facility and ongoing construction activities. See Note (K) to the Condensed Financial Statements under "Southern Power" herein for additional information.
The net cash provided from financing activities for the six months ended June 30, 2021 was primarily related to the issuance of senior notes and net capital contributions from noncontrolling interests, partially offset by a return of capital to Southern Company and common stock dividend payments.
Southern Company Gas
Net cash provided from operating activities decreased $324 million for the six months ended June 30, 2021 as compared to the corresponding period in 2020 primarily due to natural gas cost under recovery, reflecting an increase in the cost of gas purchased during Winter Storm Uri, and the timing of customer receivable collections, partially offset by the timing of vendor payments.
The net cash used for investing activities for the six months ended June 30, 2021 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, 2021 was primarily related to the repayment of long-term debt and common stock dividend payments, largely offset by the issuance of short-term debt, an increase in commercial paper borrowings, and capital contributions from Southern Company.
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, 2021 included:
•an increase of $2.1 billion in long-term debt (including securities due within one year) related to new issuances;
•an increase of $2.0 billion in total property, plant, and equipment (net of pre-tax charges totaling $508 million recorded in the first half of 2021 for estimated probable losses associated with the construction of Plant Vogtle Units 3 and 4) primarily related to the Subsidiary Registrants' construction programs, as well as Southern Power's acquisition of the Deuel Harvest wind facility;
•an increase of $0.8 billion in notes payable related to net issuances of short-term bank debt and commercial paper;
•an increase of $0.7 billion in both assets and liabilities held for sale, due to the reclassification of assets and liabilities associated with Southern Company Gas' sale of Sequent, including $0.5 billion of energy marketing receivables and $0.5 billion of energy marketing trade payables;
•an increase of $0.5 billion in accumulated deferred income taxes primarily related to the utilization and expected further utilization of tax credits in 2021;
•an increase of $0.5 billion in cash and cash equivalents, as discussed further under "Analysis of Cash Flows – Southern Company" herein;
•an increase of $0.5 billion in natural gas cost under recovery, which was impacted by an increase in Southern Company Gas' cost of gas purchased during Winter Storm Uri; and
•an increase of $0.5 billion in total stockholders' equity primarily related to net income, partially offset by common stock dividend payments.
See "Financing Activities" herein and Notes (B), (G), and (K) to the Condensed Financial Statements herein for additional information.
Alabama Power
Significant balance sheet changes for the six months ended June 30, 2021 included:
•an increase of $827 million in common stockholder's equity primarily due to capital contributions from Southern Company;
•an increase of $450 million in total property, plant, and equipment primarily related to construction of Plant Barry Unit 8 and distribution and transmission facilities, as well as the installation of equipment to comply with environmental standards; and
•an increase of $396 million in long-term debt (including securities due within one year) primarily due to a net increase in outstanding senior notes.
See "Financing Activities – Alabama Power" herein for additional information.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Georgia Power
Significant balance sheet changes for the six months ended June 30, 2021 included:
•an increase of $656 million in total property, plant, and equipment primarily related to the construction of generation, transmission, and distribution facilities, including $151 million for Plant Vogtle Units 3 and 4 (net of pre-tax charges totaling $508 million recorded in the first half of 2021 for estimated probable losses);
•an increase of $680 million in long-term debt (including securities due within one year) primarily due to a net increase in outstanding senior notes and borrowings from the FFB for construction of Plant Vogtle Units 3 and 4; and
•an increase of $250 million in notes payable related to net issuances of commercial paper.
See "Financing Activities – Georgia Power" herein and Note (B) to the Condensed Financial Statements under "Georgia Power – Nuclear Construction" herein for additional information.
Mississippi Power
Significant balance sheet changes for the six months ended June 30, 2021 included:
•an increase of $439 million in cash and cash equivalents and an increase of $514 million in long-term debt (including securities due within one year) primarily due to the issuance of senior notes;
•an increase of $107 million in common stockholder's equity primarily from capital contributions from Southern Company; and
•a decrease of $51 million in accrued taxes primarily due to the payment of ad valorem taxes.
See "Financing Activities – Mississippi Power" herein for additional information.
Southern Power
Significant balance sheet changes for the six months ended June 30, 2021 included:
•an increase of $468 million in property, plant, and equipment in service primarily due to the acquisition of the Deuel Harvest wind facility;
•an increase of $356 million in long-term debt (including securities due within one year) primarily related to the issuance of senior notes; and
•an increase of $142 million in prepaid income taxes, a decrease of $262 million in accumulated deferred income tax assets, and a $98 million increase in accumulated deferred income tax liabilities primarily related to the utilization and expected further utilization of ITCs in 2021.
See "Financing Activities – Southern Power" herein and Notes (G) and (K) to the Condensed Financial Statements herein for additional information.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Southern Company Gas
Significant balance sheet changes for the six months ended June 30, 2021 included:
•increases of $736 million and $677 million in assets and liabilities held for sale, respectively, due to the reclassification of assets and liabilities associated with the sale of Sequent, including $516 million of energy marketing receivables and $494 million of energy marketing trade payables;
•an increase of $510 million in notes payable due to issuances of short-term debt and an increase in commercial paper borrowings;
•increases of $485 million in natural gas cost under recovery, $82 million in other regulatory assets, deferred, and $148 million in accumulated deferred income taxes, all primarily related to natural gas cost under recovery, reflecting an increase in the cost of gas purchased during Winter Storm Uri;
•an increase of $461 million in total property, plant, and equipment primarily related to the construction of transportation and distribution assets recovered through base rates and infrastructure investment recovered through replacement programs;
•a decrease of $344 million in long-term debt (including securities due within one year) primarily due to the redemption of senior notes;
•a decrease of $282 million in natural gas for sale primarily due to higher volumes of natural gas sold;
•an increase of $182 million in temporary LIFO liquidation due to higher natural gas prices during Winter Storm Uri;
•an increase of $162 million in common stockholder's equity primarily related to net income and capital contributions from Southern Company, partially offset by dividends paid to Southern Company;
•an increase of $114 million in prepaid expenses primarily due to the prepayment of income taxes; and
•a decrease of $101 million in equity investments in unconsolidated subsidiaries primarily due to an $82 million impairment charge related to the PennEast Pipeline project.
See "Financing Activities – Southern Company Gas" herein, Notes (B), (E), and (K) to the Condensed Financial Statements under "Southern Company Gas" herein, and Note (C) to the Condensed Financial Statements under "Other Matters – Southern Company Gas" herein for additional information.
Financing Activities
The following table outlines the Registrants' long-term debt financing activities for the first six months of 2021:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Issuances
|
|
|
Maturities, Redemptions, and Repurchases
|
|
Company
|
Senior Notes
|
Other Long-Term Debt
|
|
|
Senior Notes
|
Revenue Bonds
|
Other Long-Term Debt(*)
|
|
|
(in millions)
|
|
Southern Company parent
|
$
|
1,000
|
|
$
|
1,000
|
|
|
|
$
|
1,500
|
|
$
|
—
|
|
$
|
—
|
|
|
Alabama Power
|
600
|
|
—
|
|
|
|
200
|
|
—
|
|
—
|
|
|
Georgia Power
|
750
|
|
371
|
|
|
|
325
|
|
69
|
|
46
|
|
|
Mississippi Power
|
525
|
|
—
|
|
|
|
—
|
|
—
|
|
—
|
|
|
Southern Power
|
400
|
|
—
|
|
|
|
—
|
|
—
|
|
—
|
|
|
Southern Company Gas
|
—
|
|
—
|
|
|
|
300
|
|
—
|
|
30
|
|
|
Other
|
—
|
|
—
|
|
|
|
—
|
|
—
|
|
7
|
|
|
|
|
|
|
|
|
|
|
|
Southern Company
|
$
|
3,275
|
|
$
|
1,371
|
|
|
|
$
|
2,325
|
|
$
|
69
|
|
$
|
83
|
|
(*)Includes reductions in finance lease obligations resulting from cash payments under finance leases and, for Georgia Power, principal amortization payments for FFB borrowings.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
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 2021, Southern Company issued approximately 2.4 million shares of common stock primarily through employee equity compensation plans and received proceeds of approximately $24 million.
In January 2021, Southern Company borrowed $25 million pursuant to a short-term uncommitted bank credit arrangement, which it repaid in March 2021.
In February 2021, Southern Company issued $600 million aggregate principal amount of Series 2021A 0.60% Senior Notes due February 26, 2024 and $400 million aggregate principal amount of Series 2021B 1.75% Senior Notes due March 15, 2028.
In May 2021, Southern Company issued $1.0 billion aggregate principal amount of Series 2021A 3.75% Fixed-to-Fixed Reset Rate Junior Subordinated Notes due September 15, 2051.
Also in May 2021, Southern Company redeemed all of its $1.5 billion aggregate principal amount of 2.35% Senior Notes due July 1, 2021.
Alabama Power
In March 2021, Alabama Power extended the maturity dates from March 2021 to March 2026 on its three bank term loan agreements with an aggregate principal amount of $45 million, bearing interest based on three-month LIBOR.
In June 2021, Alabama Power repaid at maturity $200 million aggregate principal amount of its Series 2011B 3.950% Senior Notes.
Also in June 2021, Alabama Power issued $600 million aggregate principal amount of Series 2021A 3.125% Senior Notes due July 15, 2051.
Subsequent to June 30, 2021, Alabama Power redeemed all of its approximately $206 million aggregate principal amount of Series E Junior Subordinated Notes due October 1, 2042. The Series E Junior Subordinated Notes were held by an affiliated trust, Alabama Power Capital Trust V, which applied the redemption proceeds to the simultaneous redemption of (i) its Flexible Trust Preferred Securities totaling approximately $200 million, which were guaranteed by Alabama Power, and (ii) shares of its common securities totaling approximately $6 million that were held by Alabama Power.
Georgia Power
In February 2021, Georgia Power issued $750 million aggregate principal amount of Series 2021A 3.25% Senior Notes due March 15, 2051. An amount equal to the net proceeds of the senior notes is being allocated to finance or refinance, in whole or in part, one or more renewable energy projects and/or expenditures and programs related to enabling opportunities for diverse and small businesses/suppliers.
In March 2021, Georgia Power redeemed all $325 million aggregate principal amount of its Series 2016B 2.40% Senior Notes due April 1, 2021.
Also in March 2021, Georgia Power extended the maturity date of its $125 million term loan from June 2021 to June 2022.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
In June 2021, Georgia Power purchased and held approximately $69 million aggregate principal amount of Development Authority of Burke County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Vogtle Project), First Series 2008, which may be remarketed to the public at a later date.
Also in June 2021, Georgia Power made additional borrowings under the FFB Credit Facilities in an aggregate principal amount of $371 million at an interest rate of 2.434% through the final maturity date of February 20, 2044. The proceeds were used to reimburse Georgia Power for Eligible Project Costs relating to the construction of Plant Vogtle Units 3 and 4. During the six months ended June 30, 2021, Georgia Power made principal amortization payments of $45 million under the FFB Credit Facilities. At June 30, 2021, the outstanding principal balance under the FFB Credit Facilities was $4.9 billion. 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.
Mississippi Power
In June 2021, Mississippi Power issued $200 million aggregate principal amount of Series 2021A Floating Rate Senior Notes due June 28, 2024 and $325 million aggregate principal amount of Series 2021B 3.10% Senior Notes due July 30, 2051. An amount equal to the net proceeds of the Series 2021B Senior Notes is being allocated to finance or refinance, in whole or in part, one or more renewable energy projects and/or expenditures and programs related to enabling opportunities for diverse and small businesses/suppliers.
Also in June 2021, Mississippi Power announced the redemption in July 2021 of all $270 million aggregate principal amount of its Mississippi Business Finance Corporation Taxable Revenue Bonds, 7.13% Series 1999A due October 20, 2021 at par plus accrued interest and a make-whole premium.
Subsequent to June 30, 2021, Mississippi Power repaid its $60 million and $15 million floating rate bank term loans, with maturity dates in December 2021 and January 2022, respectively, each bearing interest based on one-month LIBOR.
Southern Power
In January 2021, Southern Power issued $400 million aggregate principal amount of Series 2021A 0.90% Senior Notes due January 15, 2026. An amount equal to the net proceeds of the senior notes was allocated to finance or refinance, in whole or in part, one or more renewable energy projects.
Southern Company Gas
In February 2021, Atlanta Gas Light repaid at maturity $30 million aggregate principal amount of 9.1% medium-term notes.
In March 2021, Nicor Gas entered into three short-term floating rate bank loans in an aggregate principal amount of $300 million, each bearing interest based on one-month LIBOR.
In June 2021, Southern Company Gas Capital redeemed all $300 million aggregate principal amount of its 3.50% Senior Notes due September 15, 2021.
Credit Rating Risk
At June 30, 2021, 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.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
The maximum potential collateral requirements under these contracts at June 30, 2021 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
|
$
|
40
|
|
$
|
1
|
|
$
|
—
|
|
$
|
—
|
|
$
|
39
|
|
$
|
—
|
|
|
At BBB- and/or Baa3
|
431
|
|
2
|
|
61
|
|
1
|
|
369
|
|
—
|
|
|
At BB+ and/or Ba1 or below
|
1,942
|
|
370
|
|
968
|
|
310
|
|
1,216
|
|
5
|
|
(*)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 $105 million of cash collateral posted related to PPA requirements at June 30, 2021.
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.
Market Price Risk
Other than the Southern Company Gas items discussed below, there were no material changes to the Registrants' disclosures about market price risk during the second quarter 2021. For an in-depth discussion of Southern Company Gas' market price risks, see MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Market Price Risk" in Item 7 of the Form 10-K. Also see Notes (I) and (J) to the Condensed Financial Statements herein for information relating to derivative instruments. See Note (K) to the Condensed Financial Statements under "Southern Company Gas" herein for information regarding Southern Company Gas' sale of Sequent on July 1, 2021.
Southern Company Gas is exposed to market risks, including commodity price risk, interest rate risk, and weather risk. Due to various cost recovery mechanisms, the natural gas distribution utilities that sell natural gas directly to end-use customers continue to have limited exposure to market volatility of natural gas prices. Certain of the natural gas distribution utilities manage fuel-hedging programs implemented per the guidelines of their respective state regulatory agencies to hedge the impact of market fluctuations in natural gas prices for customers. In addition, certain of Southern Company Gas' non-regulated operations (primarily Sequent until its sale on July 1, 2021) routinely utilize various types of derivative instruments to economically hedge certain commodity price and weather risks inherent in the natural gas industry. These instruments include a variety of exchange-traded and over-the-counter energy contracts, such as forward contracts, futures contracts, options contracts, and swap agreements. Some of these economic hedge activities may not qualify, or may not be designated, for hedge accounting treatment.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
The changes in net fair value of Southern Company Gas' energy-related derivative contracts for the periods presented are provided in the table below. Contracts outstanding at the end of the period for Sequent's energy-related derivatives are included in the preliminary gain associated with the transaction, which will be recorded in the third quarter 2021, as discussed further in Note (K) to the Condensed Financial Statements under "Southern Company Gas" herein.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Second Quarter 2021
|
Second Quarter 2020
|
|
Year-To-Date 2021
|
Year-To-Date 2020
|
|
|
(in millions)
|
|
Contracts outstanding at beginning of period, assets (liabilities), net
|
$
|
40
|
|
$
|
38
|
|
|
$
|
101
|
|
$
|
70
|
|
|
Contracts realized or otherwise settled
|
(9)
|
|
(8)
|
|
|
(58)
|
|
(99)
|
|
|
Current period changes(a)
|
(75)
|
|
19
|
|
|
(87)
|
|
78
|
|
|
Contracts outstanding at the end of period, assets (liabilities), net
|
$
|
(44)
|
|
$
|
49
|
|
|
$
|
(44)
|
|
$
|
49
|
|
|
Netting of cash collateral
|
41
|
|
114
|
|
|
41
|
|
114
|
|
|
Cash collateral and net fair value of contracts outstanding at end of period(b)
|
$
|
(3)
|
|
$
|
163
|
|
|
$
|
(3)
|
|
$
|
163
|
|
(a)Current period changes also include the fair value of new contracts entered into during the period, if any.
(b)Includes $(22) million of energy-related derivatives related to Sequent, which are classified as held for sale at June 30, 2021. See Note (K) to the Condensed Financial Statements under "Southern Company Gas" and "Assets and Liabilities Held for Sale" herein for additional information.
Item 3. Quantitative and Qualitative Disclosures About Market Risk.
During the six months ended June 30, 2021, there were no material changes to Southern Company's, Alabama Power's, Georgia Power's, Mississippi Power's, and Southern Power's disclosures about market risk. See Note (K) to the Condensed Financial Statements under "Southern Company Gas" herein for information regarding Southern Company Gas' sale of Sequent on July 1, 2021. For additional market risk disclosures relating to Southern Company Gas, see MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Market Price Risk" herein. 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 Sections 13a-15(e) and 15d-15(e) of 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 controls 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 2021 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.