filings.toolsItem 2. Management's Discussion and Analysis of Financial Condition and Results of Operations.
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Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations.
| Page | |||||
| Combined Management's Discussion and Analysis of Financial Condition and Results of Operations | |||||
| Overview | 103 | ||||
| Results of Operations | 107 | ||||
| Southern Company | 107 | ||||
| Alabama Power | 116 | ||||
| Georgia Power | 121 | ||||
| Mississippi Power | 127 | ||||
| Southern Power | 131 | ||||
| Southern Company Gas | 135 | ||||
| Future Earnings Potential | 143 | ||||
| Accounting Policies | 148 | ||||
| Financial Condition and Liquidity | 149 |
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.
Table of Contents Index to Financial Statements
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 (until the sale of Sequent on July 1, 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
Alabama Power
On September 23, 2021, Alabama Power entered into an agreement to acquire all of the equity interests in Calhoun Power Company, LLC, which owns and operates a 743-MW winter peak, simple-cycle, combustion turbine generation facility in Calhoun County, Alabama (Calhoun Generating Station). The completion of the acquisition is subject to the satisfaction and waiver of certain conditions, including, among other customary conditions, approval by the Alabama PSC and the FERC. On October 28, 2021, Alabama Power filed a petition for a certificate of convenience and necessity with the Alabama PSC to procure additional generating capacity through the acquisition of the Calhoun Generating Station. The ultimate outcome of this matter cannot be determined at this time. See Note (B) to the Condensed Financial Statements under "Alabama Power – Calhoun Generating Station Acquisition" herein for additional information.
Georgia Power
Plant Vogtle Units 3 and 4 Construction and Start-Up Status
Construction continues on Plant Vogtle Units 3 and 4 (with electric generating capacity of approximately 1,100 MWs each), in which Georgia Power 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 September 2022 and June 2023, respectively, is $9.48 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.
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
Table of Contents Index to Financial Statements
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
support hot functional testing, which was completed in July 2021, and fuel load for Unit 3. As a result of challenges including, but not limited to, construction productivity, construction remediation work, the pace of system turnovers, spent fuel pool repairs, and the timeframe and duration for hot functional and other testing, at the end of the second quarter 2021, Southern Nuclear further extended certain milestone dates, including the fuel load for Unit 3, from those established in January 2021. Through the third quarter 2021, the project continued to face challenges including, but not limited to, construction productivity, construction remediation work, and the pace of system turnovers. As a result of these continued challenges, at the end of the third quarter 2021, Southern Nuclear further extended certain milestone dates, including fuel load for Unit 3, from those established at the end of the second quarter 2021. The site work plan currently targets fuel load for Unit 3 in the first quarter 2022 and an in-service date of May 2022 and primarily depends on significant improvements in overall construction productivity and production levels, the volume of construction remediation work, the pace of system and area turnovers, and the progression of startup and other testing. As the site work plan includes minimal margin to these milestone dates, an in-service date in the third quarter 2022 for Unit 3 is projected, although any further delays could result in a later in-service date.
As the result of productivity challenges, at the end of the second quarter 2021, Southern Nuclear also further extended milestone dates for Unit 4 from those established in January 2021. These productivity challenges continued into the third quarter 2021 and some craft and support resources were diverted temporarily to support construction efforts on Unit 3. As a result of these factors, at the end of the third quarter 2021, Southern Nuclear further extended the milestone dates for Unit 4 from those established at the end of the second quarter 2021. The site work plan targets an in-service date of March 2023 for Unit 4 and primarily depends on overall construction productivity and production levels significantly improving as well as appropriate levels of craft laborers, particularly electricians and pipefitters, being added and maintained. As the site work plan includes minimal margin to the milestone dates, an in-service date in the second quarter 2023 for Unit 4 is projected, although any further delays could result in a later in-service date.
As of March 31, 2021, approximately $84 million of the construction contingency established in the fourth quarter 2020 was assigned to the base capital cost forecast for costs primarily associated with the schedule extension for Unit 3 to December 2021, construction productivity, support resources, and construction remediation work. Georgia Power increased its total capital cost forecast as of March 31, 2021 by adding $48 million to the remaining construction contingency. As of June 30, 2021, all of the remaining construction contingency previously established and an additional $341 million was assigned to the base capital cost forecast for costs primarily associated with the schedule extensions for Units 3 and 4, construction remediation work for Unit 3, and construction productivity and support resources for Units 3 and 4. Georgia Power also increased its total capital cost forecast as of June 30, 2021 by adding $119 million to replenish construction contingency. As a result of the factors discussed above, during the third quarter 2021, all of the remaining construction contingency previously established in the second quarter 2021 and an additional $127 million was assigned to the base capital cost forecast for costs primarily associated with the schedule extensions for Units 3 and 4, construction productivity and support resources for Units 3 and 4, and construction remediation work for Unit 3. Georgia Power also increased its total capital cost forecast as of September 30, 2021 by adding $137 million to replenish construction contingency.
After considering the significant level of uncertainty that exists regarding the future recoverability of these costs since the ultimate outcome of these matters is subject to the outcome of future assessments by management, as well as Georgia PSC decisions in future regulatory proceedings, Georgia Power recorded pre-tax charges to income in the first quarter 2021, the second quarter 2021, and the third quarter 2021 of $48 million ($36 million after tax), $460 million ($343 million after tax), and $264 million ($197 million after tax), respectively, for the increases in the total project capital cost forecast. As and when these amounts are spent, Georgia Power may request the Georgia PSC to evaluate those expenditures for rate recovery.
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.
Table of Contents Index to Financial Statements
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
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 the common facilities shared between Plant Vogtle Units 3 and 4 (Common Facilities), as well as the related costs of operation. On November 2, 2021, the Georgia PSC voted to approve Georgia Power's application as filed, with certain modifications pursuant to a stipulated agreement between Georgia Power and the staff of the Georgia PSC. The related increase in annual retail base rates of approximately $302 million includes recovery of all projected operations and maintenance expenses for Unit 3 and the Common Facilities and other related costs of operation, partially offset by the related production tax credits, and will become effective the month after Unit 3 is placed in service. This increase will be partially offset by a decrease in the NCCR tariff of approximately $78 million expected to be effective January 1, 2022. See Note (B) to the Condensed Financial Statements under "Georgia Power – Plant Vogtle Unit 3 and Common Facilities Rate Proceeding" herein for additional information.
Rate Plan
In accordance with the terms of the 2019 ARP, on October 1, 2021, Georgia Power filed tariff adjustments to become effective January 1, 2022 that would result in a net increase in rates of $157 million pending approval by the Georgia PSC. The ultimate outcome of this matter cannot be determined at this time. See Note (B) to the Condensed Financial Statements under "Georgia Power – Rate Plan" herein for additional information.
Mississippi Power
During the first half of 2021, the Mississippi PSC approved the following non-fuel 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,
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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.
On September 9, 2021, the Mississippi PSC issued an order confirming the conclusion of its review of Mississippi Power's 2021 IRP with no deficiencies identified. The 2021 IRP includes a schedule to retire Plant Watson Unit 4 (268 MWs) and Mississippi Power's 40% ownership interest in Plant Greene County Units 1 and 2 (103 MWs each) in December 2023, 2025, and 2026, respectively, consistent with each unit's remaining useful life in the most recent approved depreciation studies. In addition, the schedule reflects the early retirement of Mississippi Power's 50% undivided ownership interest in Plant Daniel Units 1 and 2 (502 MWs) by the end of 2027.
On October 14, 2021, the Mississippi PSC issued an accounting order giving Mississippi Power the authority to reclassify the retail costs associated with Hurricanes Zeta and Ida to a regulatory asset to be recovered through PEP over a period to be determined in Mississippi Power's 2022 PEP proceeding. At September 30, 2021, these costs totaled approximately $49 million.
See Note (B) to the Condensed Financial Statements under "Mississippi Power" herein for additional information.
Southern Power
During the nine months ended September 30, 2021, Southern Power completed construction of and placed in service 45 MWs of the 88-MW Garland battery energy storage facility and continued construction of the 72-MW Tranquillity battery energy storage facility, the 118-MW Glass Sands wind facility, and the remainder of the Garland battery energy storage 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.
Table of Contents Index to Financial Statements
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
At September 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. On October 14, 2021, Atlanta Gas Light and the staff of the Georgia PSC filed a joint stipulation agreement, under which, for the years 2022 through 2024, Atlanta Gas Light would incrementally reduce its combined GRAM and System Reinforcement Rider request by 10% through Atlanta Gas Light's GRAM mechanism, or $5 million for 2022 based on the initial July 21, 2021 GRAM filing, as discussed further below. The stipulation agreement also would provide for $1.7 billion of total capital investment for the years 2022 through 2024. The Georgia PSC is scheduled to vote on this matter later in November 2021. The ultimate outcome of this matter cannot be determined at this time.
On September 14, 2021, the Virginia Commission approved a stipulation agreement related to Virginia Natural Gas' June 2020 general rate case filing, which allows for a $43 million increase in annual base rate revenues, including $14 million related to the recovery of investments under the SAVE program, based on a ROE of 9.5% and an equity ratio of 51.9%. Interim rate adjustments became effective as of November 1, 2020, subject to refund, based on Virginia Natural Gas' original request for an increase of approximately $50 million.
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. Later in November 2021, Atlanta Gas Light expects to file an amended GRAM filing in accordance with the reduction agreed to in the October 14, 2021 joint stipulation agreement, as discussed above. 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 Note (B) to the Condensed Financial Statements under "Southern Company Gas" herein 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 $159 million, including final working capital adjustments. The preliminary pre-tax gain associated with the transaction is approximately $121 million ($93 million after tax). As a result of the sale, changes in state apportionment rates resulted in $85 million of additional tax expense. See Note (K) to the Condensed Financial Statements under "Southern Company Gas" herein for additional information.
During the second and third quarters of 2021, Southern Company Gas recorded pre-tax impairment charges totaling $84 million ($67 million after tax) related to its equity method investment in the PennEast Pipeline project. On September 27, 2021, PennEast Pipeline announced that further development of the project is no longer supported, and, as a result, all further development of the project has ceased. 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.
Table of Contents Index to Financial Statements
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
RESULTS OF OPERATIONS
Southern Company
Net Income
| Third Quarter 2021 vs. Third Quarter 2020 | Year-To-Date 2021 vs. Year-To-Date 2020 | |||||||||||||||||||
| (change in millions) | (% change) | (change in millions) | (% change) | |||||||||||||||||
| $(150) | (12.0) | $(124) | (4.5) |
Consolidated net income attributable to Southern Company was $1.1 billion ($1.04 per share) for the third quarter 2021 compared to $1.3 billion ($1.18 per share) for the corresponding period in 2020. The decrease was primarily due to a $197 million after-tax charge in the third quarter 2021 related to the construction of Plant Vogtle Units 3 and 4 at Georgia Power and higher non-fuel operations and maintenance costs, partially offset by higher retail electric revenues driven by rates and pricing and sales growth.
Consolidated net income attributable to Southern Company was $2.6 billion ($2.46 per share) for year-to-date 2021 compared to $2.7 billion ($2.58 per share) for the corresponding period in 2020. The decrease was primarily due to a $465 million increase in after-tax charges related to the construction of Plant Vogtle Units 3 and 4 at Georgia Power and higher non-fuel operations and maintenance costs, partially offset by an increase in natural gas revenues associated with colder weather in the first quarter 2021 as compared to the corresponding period in 2020 and infrastructure replacement programs and base rate changes, higher retail electric revenues primarily associated with rates and pricing and sales growth, and higher wholesale electric capacity revenues.
Retail Electric Revenues
| Third Quarter 2021 vs. Third Quarter 2020 | Year-To-Date 2021 vs. Year-To-Date 2020 | |||||||||||||||||||
| (change in millions) | (% change) | (change in millions) | (% change) | |||||||||||||||||
| $308 | 7.3 | $989 | 9.4 |
In the third quarter 2021, retail electric revenues were $4.6 billion compared to $4.2 billion for the corresponding period in 2020. For year-to-date 2021, retail electric revenues were $11.5 billion compared to $10.5 billion for the corresponding period in 2020.
Details of the changes in retail electric revenues were as follows:
| Third Quarter 2021 | Year-To-Date 2021 | ||||||||||||||||||||||
| (in millions) | (% change) | (in millions) | (% change) | ||||||||||||||||||||
| Retail electric – prior year | $ | 4,243 | $ | 10,503 | |||||||||||||||||||
| Estimated change resulting from – | |||||||||||||||||||||||
| Rates and pricing | 74 | 1.8 | % | 210 | 2.0 | % | |||||||||||||||||
| Sales growth | 86 | 2.0 | 158 | 1.5 | |||||||||||||||||||
| Weather | (95) | (2.2) | 12 | 0.1 | |||||||||||||||||||
| Fuel and other cost recovery | 243 | 5.7 | 609 | 5.8 | |||||||||||||||||||
| Retail electric – current year | $ | 4,551 | 7.3 | % | $ | 11,492 | 9.4 | % |
Revenues associated with changes in rates and pricing increased in the third quarter and year-to-date 2021 when compared to the corresponding periods in 2020. These increases were 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 and fixed residential customer bill programs, partially offset by a decrease in the NCCR tariff effective January 1, 2021. The increase in the third quarter 2021 was also partially offset by pricing effects associated with decreased residential customer usage at
Table of Contents Index to Financial Statements
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Georgia Power. The increase for year-to-date 2021 also reflects increased ECCR tariff revenues at Georgia Power associated with higher KWH sales. 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 third quarter and year-to-date 2021 when compared to the corresponding periods in 2020. Weather-adjusted residential KWH sales increased 0.5% in the third quarter 2021 when compared to the corresponding period in 2020 primarily due to customer growth, largely offset by decreased customer usage primarily due to shelter-in-place orders in effect during 2020. Weather-adjusted residential KWH sales decreased 0.1% for year-to-date 2021 when compared to the corresponding period in 2020 primarily due to decreased customer usage resulting from shelter-in-place orders in effect during 2020, partially offset by customer growth. Weather-adjusted commercial KWH sales increased 4.2% and 3.3% in the third quarter and year-to-date 2021, respectively, and industrial KWH sales increased 4.8% and 4.3% in the third quarter and year-to-date 2021, respectively, when compared to the corresponding periods in 2020, primarily due to the negative impacts of the COVID-19 pandemic on energy sales in 2020.
Fuel and other cost recovery revenues increased $243 million and $609 million in the third 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
| Third Quarter 2021 vs. Third Quarter 2020 | Year-To-Date 2021 vs. Year-To-Date 2020 | |||||||||||||||||||
| (change in millions) | (% change) | (change in millions) | (% change) | |||||||||||||||||
| $147 | 25.2 | $349 | 23.7 |
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 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 third quarter 2021, wholesale electric revenues were $731 million compared to $584 million for the corresponding period in 2020. For year-to-date 2021, wholesale electric revenues were $1.8 billion compared to $1.5 billion for the corresponding period in 2020. Increases in energy revenues of $132 million and $285 million for the third 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 $15 million and $64 million for the third quarter and year-to-date 2021, respectively, primarily resulted from a power sales agreement at Alabama Power that began in September 2020 and increased capacity sales under existing contracts at Southern Power.
Table of Contents Index to Financial Statements
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Other Electric Revenues
| Third Quarter 2021 vs. Third Quarter 2020 | Year-To-Date 2021 vs. Year-To-Date 2020 | |||||||||||||||||||
| (change in millions) | (% change) | (change in millions) | (% change) | |||||||||||||||||
| $15 | 9.1 | $41 | 8.5 |
For year-to-date 2021, other electric revenues were $525 million compared to $484 million for the corresponding period in 2020. The increase was primarily due to increases of $25 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, $12 million in transmission revenues, and $8 million related to outdoor lighting sales at Georgia Power.
Natural Gas Revenues
| Third Quarter 2021 vs. Third Quarter 2020 | Year-To-Date 2021 vs. Year-To-Date 2020 | |||||||||||||||||||
| (change in millions) | (% change) | (change in millions) | (% change) | |||||||||||||||||
| $146 | 30.6 | $632 | 26.8 |
In the third quarter 2021, natural gas revenues were $623 million compared to $477 million for the corresponding period in 2020. For year-to-date 2021, natural gas revenues were $3.0 billion compared to $2.4 billion for the corresponding period in 2020.
Details of the changes in natural gas revenues were as follows:
| Third Quarter 2021 | Year-To-Date 2021 | ||||||||||||||||||||||
| (in millions) | (% change) | (in millions) | (% change) | ||||||||||||||||||||
| Natural gas revenues – prior year | $ | 477 | $ | 2,362 | |||||||||||||||||||
| Estimated change resulting from – | |||||||||||||||||||||||
| Infrastructure replacement programs and base rate changes | 28 | 5.9 | % | 109 | 4.6 | % | |||||||||||||||||
| Gas costs and other cost recovery | 54 | 11.3 | 294 | 12.5 | |||||||||||||||||||
| Wholesale gas services | 51 | 10.7 | 207 | 8.8 | |||||||||||||||||||
| Other | 13 | 2.7 | 22 | 0.9 | |||||||||||||||||||
| Natural gas revenues – current year | $ | 623 | 30.6 | % | $ | 2,994 | 26.8 | % |
Revenues from infrastructure replacement programs and base rate changes at the natural gas distribution utilities increased in the third 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 third quarter and year-to-date 2021 compared to the corresponding periods in 2020 primarily due to higher volumes of natural gas sold and higher natural 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.
For the third quarter 2021, the change in revenues related to Southern Company Gas' wholesale gas services was due to the sale of Sequent on July 1, 2021. The year-to-date 2021 change reflects higher volumes of natural gas sold and higher commercial activities as a result of Winter Storm Uri, partially offset by derivative losses all prior to the sale of Sequent on July 1, 2021. See Note (K) to the Condensed Financial Statements under "Southern Company Gas" herein for additional information.
Table of Contents Index to Financial Statements
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Other Revenues
| Third Quarter 2021 vs. Third Quarter 2020 | Year-To-Date 2021 vs. Year-To-Date 2020 | |||||||||||||||||||
| (change in millions) | (% change) | (change in millions) | (% change) | |||||||||||||||||
| $2 | 1.3 | $77 | 17.7 |
For year-to-date 2021, other revenues were $513 million compared to $436 million for the corresponding period in 2020. The increase was primarily due to increases of $42 million in unregulated sales of products and services at Alabama Power and Georgia Power and $26 million related to distributed infrastructure and energy efficiency projects at PowerSecure.
Fuel and Purchased Power Expenses
| Third Quarter 2021 vs. Third Quarter 2020 | Year-To-Date 2021 vs. Year-To-Date 2020 | ||||||||||||||||||||||
| (change in millions) | (% change) | (change in millions) | (% change) | ||||||||||||||||||||
| Fuel | $ | 301 | 32.3 | $ | 740 | 33.8 | |||||||||||||||||
| Purchased power | 58 | 25.2 | 101 | 16.5 | |||||||||||||||||||
| Total fuel and purchased power expenses | $ | 359 | $ | 841 |
In the third quarter 2021, total fuel and purchased power expenses were $1.5 billion compared to $1.2 billion for the corresponding period in 2020. The increase was primarily the result of a $370 million increase in the average cost of fuel and purchased power and an $11 million net decrease in the volume of KWHs generated and purchased.
For year-to-date 2021, total fuel and purchased power expenses were $3.6 billion compared to $2.8 billion for the corresponding period in 2020. The increase was primarily the result of a $690 million increase in the average cost of fuel and purchased power and a $151 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.
Table of Contents Index to Financial Statements
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:
| Third Quarter 2021 | Third Quarter 2020 | Year-To-Date 2021 | Year-To-Date 2020 | |||||||||||
| Total generation (in billions of KWHs)(a) | 50 | 50 | 136 | 132 | ||||||||||
| Total purchased power (in billions of KWHs) | 5 | 5 | 13 | 14 | ||||||||||
| Sources of generation (percent)(a) — | ||||||||||||||
| Gas | 48 | 52 | 47 | 53 | ||||||||||
| Coal | 26 | 24 | 24 | 17 | ||||||||||
| Nuclear | 16 | 16 | 17 | 17 | ||||||||||
| Hydro | 3 | 2 | 4 | 5 | ||||||||||
| Wind, Solar, and Other | 7 | 6 | 8 | 8 | ||||||||||
| Cost of fuel, generated (in cents per net KWH)— | ||||||||||||||
| Gas(a) | 3.38 | 1.98 | 2.87 | 1.94 | ||||||||||
| Coal | 2.82 | 3.01 | 2.84 | 2.96 | ||||||||||
| Nuclear | 0.78 | 0.78 | 0.76 | 0.78 | ||||||||||
| Average cost of fuel, generated (in cents per net KWH)(a) | 2.75 | 2.04 | 2.45 | 1.91 | ||||||||||
| Average cost of purchased power (in cents per net KWH)(b) | 6.45 | 4.94 | 5.77 | 4.53 |
(a)Third 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 third quarter 2021, fuel expense was $1.2 billion compared to $933 million for the corresponding period in 2020. The increase was primarily due to a 70.7% increase in the average cost of natural gas per KWH generated and a 9.1% increase in the volume of KWHs generated by coal, partially offset by a 91.2% increase in the volume of KWHs generated by hydro, a 6.3% decrease in the average cost of coal per KWH generated, and a 9.4% decrease in the volume of KWHs generated by natural gas.
For year-to-date 2021, fuel expense was $2.9 billion compared to $2.2 billion for the corresponding period in 2020. The increase was primarily due to a 47.9% increase in the average cost of natural gas per KWH generated, a 43.7% increase in the volume of KWHs generated by coal, and an 11.3% decrease in the volume of KWHs generated by hydro, partially offset by a 9.1% decrease in the volume of KWHs generated by natural gas and a 4.1% decrease in the average cost of coal per KWH generated.
Purchased Power
In the third quarter 2021, purchased power expense was $288 million compared to $230 million for the corresponding period in 2020. The increase was primarily due to a 30.6% increase in the average cost per KWH purchased primarily due to higher natural gas prices.
For year-to-date 2021, purchased power expense was $712 million compared to $611 million for the corresponding period in 2020. The increase was primarily due to a 27.4% increase in the average cost per KWH purchased primarily due to higher natural gas prices, partially offset by a 3.8% 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.
Table of Contents Index to Financial Statements
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Cost of Natural Gas
| Third Quarter 2021 vs. Third Quarter 2020 | Year-To-Date 2021 vs. Year-To-Date 2020 | |||||||||||||||||||
| (change in millions) | (% change) | (change in millions) | (% change) | |||||||||||||||||
| $58 | 81.7 | $289 | 44.2 |
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 78% and 85% of total cost of natural gas for the third quarter and year-to-date 2021, respectively.
In the third quarter 2021, cost of natural gas was $129 million compared to $71 million for the corresponding period in 2020. The increase reflects higher gas cost recovery driven by a 103% increase in natural gas prices in the third quarter 2021 compared to the corresponding period in 2020.
For year-to-date 2021, cost of natural gas was $943 million compared to $654 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 69% increase in natural gas prices for year-to-date 2021 compared to the corresponding period in 2020.
Cost of Other Sales
| Third Quarter 2021 vs. Third Quarter 2020 | Year-To-Date 2021 vs. Year-To-Date 2020 | |||||||||||||||||||
| (change in millions) | (% change) | (change in millions) | (% change) | |||||||||||||||||
| $(1) | (1.4) | $54 | 26.9 |
For year-to-date 2021, cost of other sales was $255 million compared to $201 million for the corresponding period in 2020. The increase primarily relates to increases of $24 million in unregulated power delivery construction and maintenance projects at Georgia Power and $19 million related to distributed infrastructure and energy efficiency projects at PowerSecure.
Other Operations and Maintenance Expenses
| Third Quarter 2021 vs. Third Quarter 2020 | Year-To-Date 2021 vs. Year-To-Date 2020 | |||||||||||||||||||
| (change in millions) | (% change) | (change in millions) | (% change) | |||||||||||||||||
| $160 | 12.4 | $472 | 12.5 |
In the third quarter 2021, other operations and maintenance expenses were $1.4 billion compared to $1.3 billion for the corresponding period in 2020. The increase reflects the impacts of cost containment activities implemented for 2020 during the COVID-19 pandemic. The increase was primarily associated with increases of $70 million in transmission and distribution expenses, including $9 million of reliability NDR credits applied in 2020 at Alabama Power, and $18 million in scheduled generation outage and maintenance expenses. Also contributing to the increase was a $15 million loss on a sales-type lease at Southern Power, which was recorded upon commencement of the Garland battery energy storage facility PPA, and an increase of $14 million in compensation and benefit expenses.
For year-to-date 2021, other operations and maintenance expenses were $4.3 billion compared to $3.8 billion for the corresponding period in 2020. The increase reflects the impacts of cost containment activities implemented for 2020 during the COVID-19 pandemic. The increase was primarily associated with increases of $122 million in transmission and distribution expenses, including $31 million of reliability NDR credits applied in 2020 at Alabama Power, and $115 million in compensation and benefit expenses, primarily associated with incentive compensation at Southern Company Gas prior to the sale of Sequent, as well as increases in pension and medical costs. Also contributing to the increase was a $76 million increase in scheduled generation outage and maintenance expenses, a
Table of Contents Index to Financial Statements
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
$19 million increase in compliance and environmental expenses at the traditional electric operating companies, an $18 million decrease in nuclear property insurance refunds, and a $15 million loss on a sales-type lease at Southern Power, which was recorded upon commencement of the Garland battery energy storage facility PPA.
Depreciation and Amortization
| Third Quarter 2021 vs. Third Quarter 2020 | Year-To-Date 2021 vs. Year-To-Date 2020 | |||||||||||||||||||
| (change in millions) | (% change) | (change in millions) | (% change) | |||||||||||||||||
| $7 | 0.8 | $39 | 1.5 |
In the third quarter 2021, depreciation and amortization was $896 million compared to $889 million for the corresponding period in 2020. For year-to-date 2021, depreciation and amortization was $2.7 billion compared to $2.6 billion for the corresponding period in 2020. The increases for the third quarter and year-to-date 2021 primarily reflect increases of $34 million and $113 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 $66 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
| Third Quarter 2021 vs. Third Quarter 2020 | Year-To-Date 2021 vs. Year-To-Date 2020 | |||||||||||||||||||
| (change in millions) | (% change) | (change in millions) | (% change) | |||||||||||||||||
| $8 | 2.6 | $37 | 4.0 |
For year-to-date 2021, taxes other than income taxes were $969 million compared to $932 million for the corresponding period in 2020. The increase primarily reflects increases of $24 million in property taxes primarily resulting from higher assessed values and $11 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
| Third Quarter 2021 vs. Third Quarter 2020 | Year-To-Date 2021 vs. Year-To-Date 2020 | |||||||||||||||||||
| (change in millions) | (% change) | (change in millions) | (% change) | |||||||||||||||||
| $264 | N/M | $623 | N/M |
N/M - Not meaningful
In the third quarter 2021, Georgia Power recorded an estimated probable loss on Plant Vogtle Units 3 and 4 of $264 million. For year-to-date 2021 and 2020, estimated probable losses on Plant Vogtle Units 3 and 4 of $772 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.
Table of Contents Index to Financial Statements
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
(Gain) Loss on Dispositions, Net
| Third Quarter 2021 vs. Third Quarter 2020 | Year-To-Date 2021 vs. Year-To-Date 2020 | |||||||||||||||||||
| (change in millions) | (% change) | (change in millions) | (% change) | |||||||||||||||||
| $125 | N/M | $140 | N/M |
N/M - Not meaningful
In the third quarter 2021, gain on dispositions, net was $125 million compared to an immaterial gain for the corresponding period in 2020. For year-to-date 2021, gain on dispositions, net was $179 million compared to $39 million for the corresponding period in 2020. The increases primarily reflect a $121 million gain at Southern Company Gas related to the sale of Sequent in the third quarter 2021. The year-to-date 2021 increase also reflects $39 million in gains at Southern Power primarily from contributions of wind turbine equipment to various equity method investments in the first quarter 2021 and $13 million in gains at Alabama Power primarily from property sales, 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" in Item 8 of the Form 10-K for additional information.
Allowance for Equity Funds Used During Construction
| Third Quarter 2021 vs. Third Quarter 2020 | Year-To-Date 2021 vs. Year-To-Date 2020 | |||||||||||||||||||
| (change in millions) | (% change) | (change in millions) | (% change) | |||||||||||||||||
| $11 | 28.9 | $34 | 32.1 |
In the third quarter 2021, allowance for equity funds used during construction was $49 million compared to $38 million for the corresponding period in 2020. For year-to-date 2021, allowance for equity funds used during construction was $140 million compared to $106 million for the corresponding period in 2020. The increases were primarily associated with Georgia Power's 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 from Equity Method Investments
| Third Quarter 2021 vs. Third Quarter 2020 | Year-To-Date 2021 vs. Year-To-Date 2020 | |||||||||||||||||||
| (change in millions) | (% change) | (change in millions) | (% change) | |||||||||||||||||
| $(3) | (9.1) | $(70) | (66.7) |
For year-to-date 2021, earnings from equity method investments were $35 million compared to $105 million for the corresponding period in 2020. The decrease was primarily due to pre-tax impairment charges totaling $84 million at Southern Company Gas related to the PennEast Pipeline project, partially offset by a $22 million increase in investment income at Southern Holdings. 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.
Table of Contents Index to Financial Statements
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Impairment of Leveraged Leases
| Third Quarter 2021 vs. Third Quarter 2020 | Year-To-Date 2021 vs. Year-To-Date 2020 | |||||||||||||||||||
| (change in millions) | (% change) | (change in millions) | (% change) | |||||||||||||||||
| $— | N/M | $(147) | (95.5) |
N/M - Not meaningful
For year-to-date 2020, impairment charges of $154 million were recorded related to leveraged lease investments at Southern Holdings. See Note (K) to the Condensed Financial Statements under "Southern Company" and "Assets 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
| Third Quarter 2021 vs. Third Quarter 2020 | Year-To-Date 2021 vs. Year-To-Date 2020 | |||||||||||||||||||
| (change in millions) | (% change) | (change in millions) | (% change) | |||||||||||||||||
| $18 | 15.9 | $(22) | (6.9) |
In the third quarter 2021, other income (expense), net was $131 million compared to $113 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 a $12 million gain recorded by Southern Power in the third quarter 2020 associated with the Roserock solar facility litigation.
For year-to-date 2021, other income (expense), net was $297 million compared to $319 million for the corresponding period in 2020. The decrease was primarily due to $101 million in charitable contributions at Southern Company Gas in the second quarter 2021, a $14 million decrease in interest income, and a $12 million gain recorded by Southern Power in the third quarter 2020 associated with the Roserock solar facility litigation, largely offset by a $107 million increase in non-service cost-related retirement benefits income.
See Note (H) to the Condensed Financial Statements herein for additional information.
Income Taxes
| Third Quarter 2021 vs. Third Quarter 2020 | Year-To-Date 2021 vs. Year-To-Date 2020 | |||||||||||||||||||
| (change in millions) | (% change) | (change in millions) | (% change) | |||||||||||||||||
| $79 | 27.0 | $107 | 24.2 |
In the third quarter 2021, income taxes were $372 million compared to $293 million for the corresponding period in 2020. For year-to-date 2021, income taxes were $550 million compared to $443 million for the corresponding period in 2020. The increases were primarily due to $85 million in additional tax expense resulting from changes in state apportionment rates as a result of Southern Company Gas' sale of Sequent in the third quarter 2021 and a $30 million increase in a valuation allowance on certain state tax credit carryforwards at Georgia Power, partially offset by lower pre-tax earnings primarily resulting from higher charges in 2021 compared to the corresponding periods in 2020 associated with the construction of Plant Vogtle Units 3 and 4 at Georgia Power. The increase for year-to-date 2021 also reflects the tax impact of the second quarter 2020 charge to earnings associated with a leveraged lease investment.
See Notes (G) and (K) 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.
Table of Contents Index to Financial Statements
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Net Income (Loss) Attributable to Noncontrolling Interests
| Third Quarter 2021 vs. Third Quarter 2020 | Year-To-Date 2021 vs. Year-To-Date 2020 | |||||||||||||||||||
| (change in millions) | (% change) | (change in millions) | (% change) | |||||||||||||||||
| $(23) | (82.1) | $(30) | N/M |
N/M - Not meaningful
Substantially all noncontrolling interests relate to renewable projects at Southern Power. In the third quarter 2021, net income attributable to noncontrolling interests was $5 million compared to $28 million for the corresponding period in 2020. For year-to-date 2021, net loss attributable to noncontrolling interests was $27 million compared to net income of $3 million for the corresponding period in 2020. These changes were primarily due to loss allocations of $13 million related to the commencement of the Garland battery energy storage facility PPA in the third quarter 2021 and lower income allocations to solar equity partners and higher HLBV loss allocations to Southern Power's wind tax equity partners, including new partnerships entered into subsequent to the third quarter 2020, totaling $10 million and $16 million for the third quarter and year-to-date 2021, respectively. See Notes (D) and (K) to the Condensed Financial Statements under "Lease Receivables" and "Southern Power," respectively, herein for additional information.
Alabama Power
Net Income
| Third Quarter 2021 vs. Third Quarter 2020 | Year-To-Date 2021 vs. Year-To-Date 2020 | |||||||||||||||||||
| (change in millions) | (% change) | (change in millions) | (% change) | |||||||||||||||||
| $55 | 12.4 | $167 | 16.3 |
Alabama Power's net income after dividends on preferred stock for the third quarter 2021 was $499 million compared to $444 million for the corresponding period in 2020. Alabama Power's net income after dividends on preferred stock for year-to-date 2021 was $1.19 billion compared to $1.02 billion 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. Also contributing to the increases were increased sales of unregulated products and services and additional wholesale capacity revenues related to a power sales agreement that began in September 2020. The third quarter 2021 increase was partially offset by a decrease in revenues associated with milder weather in the third quarter 2021 compared to the corresponding period in 2020. Additionally, the third quarter and year-to-date 2021 increases were partially offset by an increase in operations and maintenance expenses and depreciation.
Retail Revenues
| Third Quarter 2021 vs. Third Quarter 2020 | Year-To-Date 2021 vs. Year-To-Date 2020 | |||||||||||||||||||
| (change in millions) | (% change) | (change in millions) | (% change) | |||||||||||||||||
| $76 | 4.8 | $354 | 8.8 |
In the third quarter 2021, retail revenues were $1.65 billion compared to $1.58 billion for the corresponding period in 2020. For year-to-date 2021, retail revenues were $4.36 billion compared to $4.00 billion for the corresponding period in 2020.
Table of Contents Index to Financial Statements
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Details of the changes in retail revenues were as follows:
| Third Quarter 2021 | Year-To-Date 2021 | ||||||||||||||||||||||
| (in millions) | (% change) | (in millions) | (% change) | ||||||||||||||||||||
| Retail – prior year | $ | 1,575 | $ | 4,003 | |||||||||||||||||||
| Estimated change resulting from – | |||||||||||||||||||||||
| Rates and pricing | 57 | 3.6 | % | 172 | 4.3 | % | |||||||||||||||||
| Sales growth | 30 | 1.9 | 43 | 1.1 | |||||||||||||||||||
| Weather | (28) | (1.8) | 14 | 0.3 | |||||||||||||||||||
| Fuel and other cost recovery | 17 | 1.1 | 125 | 3.1 | |||||||||||||||||||
| Retail – current year | $ | 1,651 | 4.8 | % | $ | 4,357 | 8.8 | % |
Revenues associated with changes in rates and pricing increased in the third 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 third quarter and year-to-date 2021 when compared to the corresponding periods in 2020. Weather-adjusted residential KWH sales decreased 0.1% and 1.3% in the third 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 3.3% and 3.0% in the third quarter and year-to-date 2021, respectively, and industrial KWH sales increased 4.6% and 2.7% in the third quarter and year-to-date 2021, respectively, when compared to the corresponding periods in 2020, primarily due to the negative impacts of the COVID-19 pandemic on energy sales in 2020.
Fuel and other cost recovery revenues increased in the third 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
| Third Quarter 2021 vs. Third Quarter 2020 | Year-To-Date 2021 vs. Year-To-Date 2020 | |||||||||||||||||||
| (change in millions) | (% change) | (change in millions) | (% change) | |||||||||||||||||
| $34 | 46.6 | $101 | 54.9 |
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 third quarter 2021, wholesale revenues from sales to non-affiliates were $107 million compared to $73 million for the corresponding period in 2020. For year-to-date 2021, wholesale revenues from sales to non-affiliates were $285 million compared to $184 million for the corresponding period in 2020. The third quarter and year-to-date 2021 increases consisted of increases in capacity revenues of $12 million and $47 million, respectively, primarily related to a power sales agreement that began in September 2020 and increases in energy revenues of $22 million and $54 million, respectively, primarily due to higher natural gas prices.
Table of Contents Index to Financial Statements
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Wholesale Revenues – Affiliates
| Third Quarter 2021 vs. Third Quarter 2020 | Year-To-Date 2021 vs. Year-To-Date 2020 | |||||||||||||||||||
| (change in millions) | (% change) | (change in millions) | (% change) | |||||||||||||||||
| $42 | 381.8 | $73 | 202.8 |
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 third quarter 2021, wholesale revenues from sales to affiliates were $53 million compared to $11 million for the corresponding period in 2020. For year-to-date 2021, wholesale revenues from sales to affiliates were $109 million compared to $36 million for the corresponding period in 2020. The third quarter and year-to-date 2021 increases were primarily due to increases of 186.2% and 85.4%, respectively, in KWH sales due to increased demand for Alabama Power's available lower cost generation compared to the corresponding periods in 2020 and increases of 73.2% and 61.0%, respectively, in the price of energy as a result of higher natural gas prices.
Other Revenues
| Third Quarter 2021 vs. Third Quarter 2020 | Year-To-Date 2021 vs. Year-To-Date 2020 | |||||||||||||||||||
| (change in millions) | (% change) | (change in millions) | (% change) | |||||||||||||||||
| $23 | 32.9 | $46 | 20.7 |
In the third quarter 2021, other revenues were $93 million compared to $70 million for the corresponding period in 2020. For year-to-date 2021, other revenues were $268 million compared to $222 million for the corresponding period in 2020. The third quarter and year-to-date 2021 increases were primarily due to increases of $10 million and $25 million, respectively, in unregulated sales of products and services, increases of $5 million and $11 million, respectively, in customer fees largely resulting from the COVID-19 pandemic-related temporary suspensions of disconnections and late fees in 2020, and increases of $4 million and $7 million, respectively, in cogeneration steam revenue associated with higher natural gas prices. In addition, the third quarter 2021 increase included a $4 million increase in transmission revenues.
Fuel and Purchased Power Expenses
| Third Quarter 2021 vs. Third Quarter 2020 | Year-To-Date 2021 vs. Year-To-Date 2020 | ||||||||||||||||||||||
| (change in millions) | (% change) | (change in millions) | (% change) | ||||||||||||||||||||
| Fuel | $ | 67 | 21.9 | $ | 206 | 28.6 | |||||||||||||||||
| Purchased power – non-affiliates | 12 | 18.8 | 20 | 13.1 | |||||||||||||||||||
| Purchased power – affiliates | 1 | 2.3 | 21 | 22.6 | |||||||||||||||||||
| Total fuel and purchased power expenses | $ | 80 | $ | 247 |
In the third quarter 2021, total fuel and purchased power expenses were $494 million compared to $414 million for the corresponding period in 2020. The increase was primarily due to an $85 million increase in the average cost of fuel and purchased power, partially offset by a $5 million net decrease related to the volume of KWHs generated and purchased.
For year-to-date 2021, total fuel and purchased power expenses were $1.21 billion compared to $0.97 billion for the corresponding period in 2020. The increase was primarily due to a $151 million increase in the average cost of fuel and purchased power and a $96 million net increase related to the volume of KWHs generated and purchased.
Table of Contents Index to Financial Statements
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
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.
Details of Alabama Power's generation and purchased power were as follows:
| Third Quarter 2021 | Third Quarter 2020 | Year-To-Date 2021 | Year-To-Date 2020 | ||||||||||||||||||||
| Total generation (in billions of KWHs)(a) | 16 | 15 | 45 | 41 | |||||||||||||||||||
| Total purchased power (in billions of KWHs) | 2 | 2 | 5 | 5 | |||||||||||||||||||
| Sources of generation (percent)(a) — | |||||||||||||||||||||||
| Coal | 50 | 47 | 47 | 38 | |||||||||||||||||||
| Nuclear | 24 | 25 | 25 | 28 | |||||||||||||||||||
| Gas | 18 | 24 | 19 | 23 | |||||||||||||||||||
| Hydro | 8 | 4 | 9 | 11 | |||||||||||||||||||
| Cost of fuel, generated (in cents per net KWH) — | |||||||||||||||||||||||
| Coal | 2.85 | 2.86 | 2.78 | 2.78 | |||||||||||||||||||
| Nuclear | 0.73 | 0.76 | 0.71 | 0.76 | |||||||||||||||||||
| Gas(a) | 3.03 | 1.80 | 2.68 | 1.96 | |||||||||||||||||||
| Average cost of fuel, generated (in cents per net KWH)(a) | 2.33 | 2.04 | 2.20 | 1.93 | |||||||||||||||||||
| Average cost of purchased power (in cents per net KWH)(b) | 7.96 | 5.12 | 6.70 | 4.76 |
(a)Third 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 third quarter 2021, fuel expense was $373 million compared to $306 million for the corresponding period in 2020. The increase was primarily due to a 68.3% increase in the average cost of natural gas per KWH generated, which excludes tolling agreements, and a 15.9% increase in the volume of KWHs generated by coal, partially offset by a 121.6% increase in the volume of KWHs generated by hydro and a 19.8% decrease in the volume of KWHs generated by natural gas.
For year-to-date 2021, fuel expense was $927 million compared to $721 million for the corresponding period in 2020. The increase was primarily due to a 36.7% increase in the average cost of natural gas per KWH generated, which excludes tolling agreements, a 31.7% increase in the volume of KWHs generated by coal, and an 8.1% decrease in the volume of KWHs generated by hydro, partially offset by a 9.3% decrease in the volume of KWHs generated by natural gas.
Purchased Power – Non-Affiliates
In the third quarter 2021, purchased power expense from non-affiliates was $76 million compared to $64 million for the corresponding period in 2020. For year-to-date 2021, purchased power expense from non-affiliates was $173 million compared to $153 million for the corresponding period in 2020. These increases for the third quarter and year-to-date 2021 were primarily due to increases of 20.6% and 16.1%, respectively, in the amount of energy purchased due to a new PPA that began in September 2020 and increases of 12.3% and 14.0%, respectively, in the average cost of purchased power per KWH as a result of higher natural gas prices.
Energy purchases from non-affiliates will vary depending on the market prices of wholesale energy as compared to the cost of the Southern Company system's generation, demand for energy within the Southern Company system's electric service territory, and the availability of the Southern Company system's generation.
Table of Contents Index to Financial Statements
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Purchased Power – Affiliates
For year-to-date 2021, purchased power expense from affiliates was $114 million compared to $93 million for the corresponding period in 2020. The year-to-date 2021 increase was primarily due to an 88.0% increase in the average cost of purchased power per KWH as a result of higher natural gas prices, partially offset by a 35.0% decrease in the volume of KWH purchased as a result of increased generation compared to the corresponding period 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.
Other Operations and Maintenance Expenses
| Third Quarter 2021 vs. Third Quarter 2020 | Year-To-Date 2021 vs. Year-To-Date 2020 | |||||||||||||||||||
| (change in millions) | (% change) | (change in millions) | (% change) | |||||||||||||||||
| $14 | 3.6 | $97 | 9.0 |
In the third quarter 2021, other operations and maintenance expenses were $401 million compared to $387 million for the corresponding period in 2020. For year-to-date 2021, other operations and maintenance expenses were $1.18 billion compared to $1.08 billion for the corresponding period in 2020. The increases reflect the impacts of cost containment activities implemented for 2020 during the COVID-19 pandemic. The third quarter and year-to-date 2021 increases were primarily due to increases of $15 million and $49 million, respectively, in generation expenses associated with scheduled outages and Rate CNP Compliance-related expenses primarily related to the addition of new environmental systems in 2021. Also contributing to the third quarter and year-to-date 2021 increases were increases of $6 million and $23 million, respectively, in compensation and benefit expenses and $3 million and $10 million, respectively, related to unregulated services, as well as $9 million and $31 million, respectively, in transmission and distribution line maintenance expenses related to reliability NDR credits applied in 2020. The third quarter and year-to-date 2021 increases were partially offset by decreases of $22 million and $30 million, respectively, in bad debt expenses. 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
| Third Quarter 2021 vs. Third Quarter 2020 | Year-To-Date 2021 vs. Year-To-Date 2020 | |||||||||||||||||||
| (change in millions) | (% change) | (change in millions) | (% change) | |||||||||||||||||
| $9 | 4.4 | $34 | 5.6 |
In the third quarter 2021, depreciation and amortization was $214 million compared to $205 million in the corresponding period in 2020. For year-to-date 2021, depreciation and amortization was $640 million compared to $606 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
| Third Quarter 2021 vs. Third Quarter 2020 | Year-To-Date 2021 vs. Year-To-Date 2020 | |||||||||||||||||||
| (change in millions) | (% change) | (change in millions) | (% change) | |||||||||||||||||
| $(1) | (3.3) | $15 | 19.2 |
For year-to-date 2021, other income (expense), net was $93 million compared to $78 million for the corresponding period in 2020. The increase was primarily due to an increase in non-service cost-related retirement benefits income. See Note (H) to the Condensed Financial Statements herein for additional information.
Table of Contents Index to Financial Statements
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Income Taxes
| Third Quarter 2021 vs. Third Quarter 2020 | Year-To-Date 2021 vs. Year-To-Date 2020 | |||||||||||||||||||
| (change in millions) | (% change) | (change in millions) | (% change) | |||||||||||||||||
| $22 | 16.9 | $59 | 19.2 |
In the third quarter 2021, income taxes were $152 million compared to $130 million for the corresponding period in 2020. For year-to-date 2021, income taxes were $366 million compared to $307 million for the corresponding period in 2020. The increases were primarily due to higher pre-tax earnings.
Georgia Power
Net Income
| Third Quarter 2021 vs. Third Quarter 2020 | Year-To-Date 2021 vs. Year-To-Date 2020 | |||||||||||||||||||
| (change in millions) | (% change) | (change in millions) | (% change) | |||||||||||||||||
| $(237) | (30.7) | $(381) | (27.0) |
Georgia Power's net income for the third quarter 2021 was $536 million compared to $773 million for the corresponding period in 2020. The decrease was primarily due to a $197 million after-tax charge in the third quarter 2021 related to the construction of Plant Vogtle Units 3 and 4, higher non-fuel operations and maintenance costs, and lower retail revenues associated with milder weather in the third quarter 2021 as compared to the corresponding period in 2020, partially offset by sales growth.
For year-to-date 2021, net income was $1.03 billion compared to $1.41 billion for the corresponding period in 2020. The decrease was primarily due to a $465 million increase in after-tax charges related to the construction of Plant Vogtle Units 3 and 4. Also contributing to the decrease were higher non-fuel operations and maintenance costs, partially offset by higher retail revenues associated with 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
| Third Quarter 2021 vs. Third Quarter 2020 | Year-To-Date 2021 vs. Year-To-Date 2020 | |||||||||||||||||||
| (change in millions) | (% change) | (change in millions) | (% change) | |||||||||||||||||
| $217 | 8.9 | $595 | 10.1 |
In the third quarter 2021, retail revenues were $2.65 billion compared to $2.44 billion for the corresponding period in 2020. For year-to-date 2021, retail revenues were $6.47 billion compared to $5.87 billion for the corresponding period in 2020.
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MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Details of the changes in retail revenues were as follows:
| Third Quarter 2021 | Year-To-Date 2021 | ||||||||||||||||||||||
| (in millions) | (% change) | (in millions) | (% change) | ||||||||||||||||||||
| Retail – prior year | $ | 2,435 | $ | 5,870 | |||||||||||||||||||
| Estimated change resulting from – | |||||||||||||||||||||||
| Rates and pricing | 10 | 0.4 | % | 30 | 0.5 | % | |||||||||||||||||
| Sales growth | 51 | 2.1 | 110 | 1.9 | |||||||||||||||||||
| Weather | (63) | (2.6) | (4) | (0.1) | |||||||||||||||||||
| Fuel cost recovery | 219 | 9.0 | 459 | 7.8 | |||||||||||||||||||
| Retail – current year | $ | 2,652 | 8.9 | % | $ | 6,465 | 10.1 | % |
Revenues associated with changes in rates and pricing increased in the third quarter and year-to-date 2021 when compared to the corresponding periods in 2020. The increases were primarily due to higher contributions from commercial and industrial customers with variable demand-driven pricing and fixed residential customer bill programs, partially offset by a decrease in the NCCR tariff effective January 1, 2021. The increase in the third quarter 2021 was also partially offset by pricing effects associated with decreased residential customer usage. The increase for year-to-date 2021 also reflects increased ECCR tariff revenues associated with higher KWH sales. 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 third quarter and year-to-date 2021 when compared to the corresponding periods in 2020. Weather-adjusted residential KWH sales increased 0.7% in both the third quarter and year-to-date 2021 when compared to the corresponding periods in 2020 primarily due to customer growth, largely offset by decreased customer usage, primarily due to shelter-in-place orders in effect during 2020. Weather-adjusted commercial KWH sales increased 4.8% and 3.4% in the third quarter and year-to-date 2021, respectively, and weather-adjusted industrial KWH sales increased 5.5% and 6.7% in the third quarter and year-to-date 2021, respectively, when compared to the corresponding periods in 2020, primarily due to the negative impacts of the COVID-19 pandemic on energy sales in 2020.
Fuel revenues and costs are allocated between retail and wholesale jurisdictions. Retail fuel cost recovery revenues increased in the third 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 in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements herein under "Georgia Power – Fuel Cost Recovery" for additional information.
Wholesale Revenues
| Third Quarter 2021 vs. Third Quarter 2020 | Year-To-Date 2021 vs. Year-To-Date 2020 | |||||||||||||||||||
| (change in millions) | (% change) | (change in millions) | (% change) | |||||||||||||||||
| $29 | 85.3 | $58 | 68.2 |
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
Table of Contents Index to Financial Statements
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 third quarter 2021, wholesale revenues were $63 million compared to $34 million for the corresponding period in 2020. For year-to-date 2021, wholesale revenues were $143 million compared to $85 million for the corresponding period in 2020. The increases for the third quarter and year-to-date 2021 were primarily due to increases of 25.1% and 15.1%, respectively, in KWH sales as a result of higher market demand and higher natural gas prices.
Other Revenues
| Third Quarter 2021 vs. Third Quarter 2020 | Year-To-Date 2021 vs. Year-To-Date 2020 | |||||||||||||||||||
| (change in millions) | (% change) | (change in millions) | (% change) | |||||||||||||||||
| $(7) | (4.7) | $26 | 6.3 |
For year-to-date 2021, other revenues were $442 million compared to $416 million for the corresponding period in 2020. The increase for year-to-date 2021 was primarily due to increases of $37 million in unregulated sales associated with power delivery construction and maintenance projects and outdoor lighting and $13 million 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 $11 million associated with the timing of certain unregulated energy conservation projects, $4 million in pole attachment revenues, and $3 million in solar application fees.
Fuel and Purchased Power Expenses
| Third Quarter 2021 vs. Third Quarter 2020 | Year-To-Date 2021 vs. Year-To-Date 2020 | ||||||||||||||||||||||
| (change in millions) | (% change) | (change in millions) | (% change) | ||||||||||||||||||||
| Fuel | $ | 64 | 17.4 | $ | 262 | 31.7 | |||||||||||||||||
| Purchased power – non-affiliates | 27 | 18.5 | 52 | 12.7 | |||||||||||||||||||
| Purchased power – affiliates | 146 | 102.8 | 180 | 45.8 | |||||||||||||||||||
| Total fuel and purchased power expenses | $ | 237 | $ | 494 |
In the third quarter 2021, total fuel and purchased power expenses were $893 million compared to $656 million for the corresponding period in 2020. For year-to-date 2021, total fuel and purchased power expenses were $2.12 billion compared to $1.63 billion for the corresponding period in 2020. The increases for the third quarter and year-to-date 2021 were due to increases of $206 million and $409 million, respectively, related to the average cost of fuel and purchased power and net increases of $31 million and $85 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 in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements herein under "Georgia Power – Fuel Cost Recovery" for additional information.
Table of Contents Index to Financial Statements
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:
| Third Quarter 2021 | Third Quarter 2020 | Year-To-Date 2021 | Year-To-Date 2020 | ||||||||||||||||||||
| Total generation (in billions of KWHs) | 16 | 17 | 46 | 42 | |||||||||||||||||||
| Total purchased power (in billions of KWHs) | 10 | 8 | 23 | 25 | |||||||||||||||||||
| Sources of generation (percent) — | |||||||||||||||||||||||
| Gas | 45 | 48 | 46 | 53 | |||||||||||||||||||
| Nuclear | 24 | 24 | 26 | 27 | |||||||||||||||||||
| Coal | 28 | 26 | 24 | 15 | |||||||||||||||||||
| Hydro and solar | 3 | 2 | 4 | 5 | |||||||||||||||||||
| Cost of fuel, generated (in cents per net KWH) — | |||||||||||||||||||||||
| Gas | 3.28 | 2.14 | 2.84 | 2.12 | |||||||||||||||||||
| Nuclear | 0.83 | 0.81 | 0.80 | 0.81 | |||||||||||||||||||
| Coal | 2.73 | 3.19 | 2.89 | 3.31 | |||||||||||||||||||
| Average cost of fuel, generated (in cents per net KWH) | 2.51 | 2.09 | 2.30 | 1.93 | |||||||||||||||||||
| Average cost of purchased power (in cents per net KWH)(*) | 5.24 | 3.76 | 4.80 | 3.50 |
(*)Average cost of purchased power includes fuel purchased by Georgia Power for tolling agreements where power is generated by the provider.
Fuel
In the third quarter 2021, fuel expense was $432 million compared to $368 million for the corresponding period in 2020. For year-to-date 2021, fuel expense was $1.09 billion compared to $0.83 billion for the corresponding period in 2020. The increases for the third quarter and year-to-date 2021 were primarily due to increases of 53.3% and 34.0%, respectively, in the average cost of natural gas per KWH generated, partially offset by decreases of 14.4% and 12.7%, respectively, in the average cost of coal per KWH generated and decreases of 11.1% and 6.0%, respectively, in the volume of KWHs generated by natural gas. Also contributing to the increase for year-to-date 2021 was a 76.1% increase in the volume of KWHs generated by coal.
Purchased Power – Non-Affiliates
In the third quarter 2021, purchased power expense from non-affiliates was $173 million compared to $146 million in the corresponding period in 2020. For year-to-date 2021, purchased power expense from non-affiliates was $461 million compared to $409 million in the corresponding period in 2020. The increases for the third quarter and year-to-date 2021 were primarily due to increases of 28.5% and 24.2%, respectively, in the average cost per KWH purchased primarily due to higher natural gas prices, partially offset by decreases of 5.6% and 7.7%, respectively, in the volume of KWHs purchased as Georgia Power units and Southern Company system resources 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 third quarter 2021, purchased power expense from affiliates was $288 million compared to $142 million in the corresponding period in 2020. For year-to-date 2021, purchased power expense from affiliates was $573 million compared to $393 million in the corresponding period in 2020. The increases for the third quarter and year-to-date 2021 were primarily due to increases of 113.4% and 68.0%, respectively, in the average cost per KWH purchased
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MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
primarily due to higher natural gas prices. Also contributing to the increase for the third quarter 2021 was an increase of 26.9% in the volume of KWHs purchased due to lower 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
| Third Quarter 2021 vs. Third Quarter 2020 | Year-To-Date 2021 vs. Year-To-Date 2020 | |||||||||||||||||||
| (change in millions) | (% change) | (change in millions) | (% change) | |||||||||||||||||
| $61 | 12.6 | $147 | 10.4 |
In the third quarter 2021, other operations and maintenance expenses were $544 million compared to $483 million for the corresponding period in 2020. For year-to-date 2021, other operations and maintenance expenses were $1.56 billion compared to $1.41 billion for the corresponding period in 2020. These increases reflect the impacts of cost containment activities implemented for 2020 during the COVID-19 pandemic. The increases for the third quarter and year-to-date 2021 were primarily associated with increases of $37 million and $68 million, respectively, in transmission and distribution vegetation and asset management activities, $8 million and $14 million, respectively, in generation expenses associated with non-outage maintenance costs and environmental projects, and $5 million and $24 million, respectively, in certain compensation and benefit expenses. Also contributing to the increase for year-to-date 2021 was a net increase of $12 million related to unregulated power delivery construction and maintenance projects and energy conservation projects as well as an $8 million decrease in nuclear property insurance refunds.
Depreciation and Amortization
| Third Quarter 2021 vs. Third Quarter 2020 | Year-To-Date 2021 vs. Year-To-Date 2020 | |||||||||||||||||||
| (change in millions) | (% change) | (change in millions) | (% change) | |||||||||||||||||
| $(13) | (3.6) | $(39) | (3.7) |
In the third quarter 2021, depreciation and amortization was $345 million compared to $358 million for the corresponding period in 2020. For year-to-date 2021, depreciation and amortization was $1.03 billion compared to $1.06 billion for the corresponding period in 2020. The decreases for the third quarter and year-to-date 2021 primarily reflect decreased amortization of regulatory assets related to CCR AROs of $22 million and $66 million, respectively, under the terms of the 2019 ARP, partially offset by increases of $10 million and $30 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.
Taxes Other Than Income Taxes
| Third Quarter 2021 vs. Third Quarter 2020 | Year-To-Date 2021 vs. Year-To-Date 2020 | |||||||||||||||||||
| (change in millions) | (% change) | (change in millions) | (% change) | |||||||||||||||||
| $7 | 5.7 | $21 | 6.1 |
In the third quarter 2021, taxes other than income taxes was $130 million compared to $123 million for the corresponding period in 2020. For year-to-date 2021, taxes other than income taxes was $365 million compared to $344 million for the corresponding period in 2020. The increases for the third quarter and year-to-date 2021 were primarily due to increases of $5 million and $14 million, respectively, in municipal franchise fees largely related to
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MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
higher retail revenues and increases of $2 million and $9 million, respectively, in property taxes primarily resulting from an increase in the assessed value of property.
Estimated Loss on Plant Vogtle Units 3 and 4
| Third Quarter 2021 vs. Third Quarter 2020 | Year-To-Date 2021 vs. Year-To-Date 2020 | |||||||||||||||||||
| (change in millions) | (% change) | (change in millions) | (% change) | |||||||||||||||||
| $264 | N/M | $623 | N/M |
N/M - Not meaningful
In the third quarter 2021, Georgia Power recorded an estimated probable loss on Plant Vogtle Units 3 and 4 of $264 million. For year-to-date 2021 and 2020, Georgia Power recorded estimated probable losses on Plant Vogtle Units 3 and 4 of $772 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
| Third Quarter 2021 vs. Third Quarter 2020 | Year-To-Date 2021 vs. Year-To-Date 2020 | |||||||||||||||||||
| (change in millions) | (% change) | (change in millions) | (% change) | |||||||||||||||||
| $11 | 50.0 | $31 | 49.2 |
In the third quarter 2021, allowance for equity funds used during construction was $33 million compared to $22 million for the corresponding period in 2020. For year-to-date 2021, allowance for equity funds used during construction was $94 million compared to $63 million for the corresponding period in 2020. The increases were primarily related to a higher AFUDC base largely 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
| Third Quarter 2021 vs. Third Quarter 2020 | Year-To-Date 2021 vs. Year-To-Date 2020 | |||||||||||||||||||
| (change in millions) | (% change) | (change in millions) | (% change) | |||||||||||||||||
| $10 | 31.3 | $31 | 33.3 |
In the third quarter 2021, other income (expense), net was $42 million compared to $32 million for the corresponding period in 2020. For year-to-date 2021, other income (expense), net was $124 million compared to $93 million for the corresponding period in 2020. The increases were primarily due to increases of $12 million and $37 million, respectively, in non-service cost-related retirement benefits income. The increase for year-to-date 2021 was 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
| Third Quarter 2021 vs. Third Quarter 2020 | Year-To-Date 2021 vs. Year-To-Date 2020 | |||||||||||||||||||
| (change in millions) | (% change) | (change in millions) | (% change) | |||||||||||||||||
| $(59) | (34.3) | $(117) | (59.1) |
In the third quarter 2021, income taxes were $113 million compared to $172 million for the corresponding period in 2020. The decrease was primarily due to lower pre-tax earnings largely resulting from the third quarter 2021 charge
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MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
associated with the construction of Plant Vogtle Units 3 and 4, partially offset by an increase in a valuation allowance on certain state tax credit carryforwards.
For year-to-date 2021, income taxes were $81 million compared to $198 million for the corresponding period in 2020. The decrease was primarily due to lower pre-tax earnings resulting from higher charges in 2021 compared to the corresponding period in 2020 associated with the construction of Plant Vogtle Units 3 and 4, partially offset by an increase in a valuation allowance on certain state tax credit carryforwards.
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
| Third Quarter 2021 vs. Third Quarter 2020 | Year-To-Date 2021 vs. Year-To-Date 2020 | |||||||||||||||||||
| (change in millions) | (% change) | (change in millions) | (% change) | |||||||||||||||||
| $(17) | (25.4) | $(5) | (3.6) |
In the third quarter 2021, net income was $50 million compared to $67 million for the corresponding period in 2020. For year-to-date 2021, net income was $133 million compared to $138 million for the corresponding period in 2020. The decreases were primarily due to increases in operations and maintenance expenses, largely offset by an increase in revenues, resulting from an increase in base rates that became effective for the first billing cycle of April 2021 and higher customer usage when compared to the corresponding periods in 2020.
Retail Revenues
| Third Quarter 2021 vs. Third Quarter 2020 | Year-To-Date 2021 vs. Year-To-Date 2020 | |||||||||||||||||||
| (change in millions) | (% change) | (change in millions) | (% change) | |||||||||||||||||
| $16 | 6.9 | $40 | 6.3 |
In the third quarter 2021, retail revenues were $248 million compared to $232 million for the corresponding period in 2020. For year-to-date 2021, retail revenues were $670 million compared to $630 million for the corresponding period in 2020.
Details of the changes in retail revenues were as follows:
| Third Quarter 2021 | Year-To-Date 2021 | ||||||||||||||||||||||
| (in millions) | (% change) | (in millions) | (% change) | ||||||||||||||||||||
| Retail – prior year | $ | 232 | $ | 630 | |||||||||||||||||||
| Estimated change resulting from – | |||||||||||||||||||||||
| Rates and pricing | 7 | 3.0 | % | 8 | 1.3 | % | |||||||||||||||||
| Sales growth | 5 | 2.2 | 5 | 0.8 | |||||||||||||||||||
| Weather | (4) | (1.7) | 2 | 0.3 | |||||||||||||||||||
| Fuel and other cost recovery | 8 | 3.4 | 25 | 4.0 | |||||||||||||||||||
| Retail – current year | $ | 248 | 6.9 | % | $ | 670 | 6.4 | % |
Revenues associated with changes in rates and pricing increased in the third quarter and year-to-date 2021 when compared to the corresponding periods 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.
Table of Contents Index to Financial Statements
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Revenues attributable to changes in sales increased in the third quarter and year-to-date 2021 when compared to the corresponding periods in 2020. Weather-adjusted residential KWH sales increased 2.6% and 0.2% in the third quarter and year-to-date 2021, respectively, when compared to the corresponding periods in 2020 due to increased customer usage. Weather-adjusted commercial KWH sales increased 2.8% and 2.5% in the third quarter and year-to-date 2021, respectively, and industrial KWH sales increased 4.9% and 0.2% in the third quarter and year-to-date 2021, respectively, when compared to corresponding periods in 2020, primarily due to the negative impacts of the COVID-19 pandemic on energy sales in 2020.
Fuel and other cost recovery revenues increased in the third 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
| Third Quarter 2021 vs. Third Quarter 2020 | Year-To-Date 2021 vs. Year-To-Date 2020 | |||||||||||||||||||
| (change in millions) | (% change) | (change in millions) | (% change) | |||||||||||||||||
| $(1) | (1.6) | $14 | 8.5 |
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.
For year-to-date 2021, wholesale revenues from sales to non-affiliates were $178 million compared to $164 million for the corresponding period in 2020. The increase was primarily due to higher fuel costs and opportunity sales, as well as increases in revenue from MRA customers primarily due to colder weather in the first quarter 2021 and changes in power supply agreements subsequent to the third quarter 2020.
Wholesale Revenues – Affiliates
| Third Quarter 2021 vs. Third Quarter 2020 | Year-To-Date 2021 vs. Year-To-Date 2020 | |||||||||||||||||||
| (change in millions) | (% change) | (change in millions) | (% change) | |||||||||||||||||
| $26 | 72.2 | $38 | 46.3 |
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 the third quarter 2021, wholesale revenues from sales to affiliates were $62 million compared to $36 million for the corresponding period in 2020 . For year-to-date 2021, wholesale revenues from sales to affiliates were $120 million compared to $82 million for the corresponding period in 2020. The increases for third quarter and year-to-date 2021 were primarily due to increases of $29 million and $52 million, respectively, associated with higher
Table of Contents Index to Financial Statements
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
natural gas prices, partially offset by decreases of $2 million and $14 million, respectively, associated with lower KWH sales.
Fuel and Purchased Power Expenses
| Third Quarter 2021 vs. Third Quarter 2020 | Year-To-Date 2021 vs. Year-To-Date 2020 | ||||||||||||||||||||||
| (change in millions) | (% change) | (change in millions) | (% change) | ||||||||||||||||||||
| Fuel | $ | 36 | 35.0 | $ | 64 | 24.1 | |||||||||||||||||
| Purchased power | — | — | 3 | 16.7 | |||||||||||||||||||
| Total fuel and purchased power expenses | $ | 36 | $ | 67 |
In the third quarter 2021, total fuel and purchased power expenses were $145 million compared to $109 million for the corresponding period in 2020. For year-to-date 2021, total fuel and purchased power expenses were $351 million compared to $284 million for the corresponding period in 2020. The increases were primarily due to an increase in the average cost of fuel compared to the corresponding periods in 2020.
Fuel and purchased power energy transactions do not have a significant impact on earnings since energy expenses are generally offset by energy revenues through Mississippi Power's fuel cost recovery clause.
Details of Mississippi Power's generation and purchased power were as follows:
| Third Quarter 2021 | Third Quarter 2020 | Year-To-Date 2021 | Year-To-Date 2020 | ||||||||||||||||||||
| Total generation (in millions of KWHs) | 4,878 | 5,011 | 13,016 | 13,662 | |||||||||||||||||||
| Total purchased power (in millions of KWHs) | 124 | 162 | 562 | 558 | |||||||||||||||||||
| Sources of generation (percent) – | |||||||||||||||||||||||
| Gas | 93 | 89 | 91 | 94 | |||||||||||||||||||
| Coal | 7 | 11 | 9 | 6 | |||||||||||||||||||
| Cost of fuel, generated (in cents per net KWH) – | |||||||||||||||||||||||
| Gas | 2.99 | 1.99 | 2.66 | 1.94 | |||||||||||||||||||
| Coal | 3.16 | 3.52 | 3.13 | 3.70 | |||||||||||||||||||
| Average cost of fuel, generated (in cents per net KWH) | 3.00 | 2.16 | 2.70 | 2.06 | |||||||||||||||||||
| Average cost of purchased power (in cents per net KWH) | 4.51 | 3.66 | 3.78 | 3.17 |
Fuel
In the third quarter 2021, fuel expense was $139 million compared to $103 million for the corresponding period in 2020. The increase was primarily due to a 50.3% increase in the average cost of natural gas per KWH generated, partially offset by a 31.5% decrease in the volume of KWHs generated by coal and a 10.2% decrease in the average cost of coal per KWH generated.
For year-to-date 2021, fuel expense was $330 million compared to $266 million for the corresponding period in 2020. The increase was due to a 37.1% increase in the average cost of natural gas per KWH generated and 34.2% increase in the volume of KWHs generated by coal, partially offset by a 15.4% decrease in the average cost of coal per KWH generated and an 8.0% decrease in the volume of KWHs generated by natural gas.
Table of Contents Index to Financial Statements
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Other Operations and Maintenance Expenses
| Third Quarter 2021 vs. Third Quarter 2020 | Year-To-Date 2021 vs. Year-To-Date 2020 | |||||||||||||||||||
| (change in millions) | (% change) | (change in millions) | (% change) | |||||||||||||||||
| $23 | 37.1 | $28 | 13.9 |
In the third quarter 2021, other operations and maintenance expenses were $85 million compared to $62 million for the corresponding period in 2020. The increase reflects the impacts of cost containment activities implemented for 2020 during the COVID-19 pandemic. The increase primarily reflects increases of $9 million associated with the Kemper County energy facility (primarily related to increases in dismantlement and closure costs and no salvage proceeds in 2021) and $7 million in generation expenses associated with outage and non-outage maintenance.
For year-to-date 2021, other operations and maintenance expenses were $230 million compared to $202 million for the corresponding period in 2020. The increase reflects the impacts of cost containment activities implemented for 2020 during the COVID-19 pandemic. The increase was primarily due to increases of $5 million associated with the Kemper County energy facility (primarily related to increases in dismantlement and closure costs and less salvage proceeds in 2021), $8 million in generation expenses associated with outage and non-outage maintenance, and $5 million in compensation and benefit expenses.
Depreciation and Amortization
| Third Quarter 2021 vs. Third Quarter 2020 | Year-To-Date 2021 vs. Year-To-Date 2020 | |||||||||||||||||||
| (change in millions) | (% change) | (change in millions) | (% change) | |||||||||||||||||
| $(1) | (2.1) | $3 | 2.2 |
For year-to-date, depreciation and amortization was $138 million compared to $135 million for the corresponding period in 2020. The increase was primarily due to a $6 million increase in depreciation due to additional plant in service and an increase in depreciation rates in accordance with the Mississippi Power Rate Case Settlement, partially offset by a $2 million net decrease in amortization associated with regulatory assets and liabilities. 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 "Mississippi Power" for additional information.
Taxes Other Than Income Taxes
| Third Quarter 2021 vs. Third Quarter 2020 | Year-To-Date 2021 vs. Year-To-Date 2020 | |||||||||||||||||||
| (change in millions) | (% change) | (change in millions) | (% change) | |||||||||||||||||
| $2 | 6.5 | $6 | 6.7 |
For year-to-date 2021, taxes other than income taxes were $96 million compared to $90 million for the corresponding period in 2020. The increase primarily reflects an increase in ad valorem taxes due to higher assessed values.
Other Income (Expense), Net
| Third Quarter 2021 vs. Third Quarter 2020 | Year-To-Date 2021 vs. Year-To-Date 2020 | |||||||||||||||||||
| (change in millions) | (% change) | (change in millions) | (% change) | |||||||||||||||||
| $1 | 16.7 | $8 | 42.1 |
For year-to-date 2021, other income (expense), net was $27 million compared to $19 million for the corresponding period in 2020. The increase was primarily related to increases of $4 million in non-service cost-related retirement benefits income, $2 million in contributions in aid of construction, and $2 million in interest associated with a sales-type lease. See Notes (D) and (H) to the Condensed Financial Statements herein for additional information.
Table of Contents Index to Financial Statements
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Southern Power
Net Income Attributable to Southern Power
| Third Quarter 2021 vs. Third Quarter 2020 | Year-To-Date 2021 vs. Year-To-Date 2020 | |||||||||||||||||||
| (change in millions) | (% change) | (change in millions) | (% change) | |||||||||||||||||
| $4 | 5.4 | $(1) | (0.5) |
Net income attributable to Southern Power for the third quarter 2021 was $78 million compared to $74 million for the corresponding period in 2020. The increase was primarily due to a net increase in revenues associated with new PPAs.
Net income attributable to Southern Power for year-to-date 2021 was $211 million compared to $212 million for the corresponding period in 2020. The decrease was primarily due to an increase in other operations and maintenance expenses in 2021 primarily associated with scheduled outages and maintenance and a gain recorded in the third quarter 2020 associated with the Roserock solar facility litigation, partially offset by a net increase in revenues associated with new PPAs and a tax benefit due to changes in state apportionment methodology resulting from tax legislation enacted by the State of Alabama in February 2021.
Operating Revenues
| Third Quarter 2021 vs. Third Quarter 2020 | Year-To-Date 2021 vs. Year-To-Date 2020 | |||||||||||||||||||
| (change in millions) | (% change) | (change in millions) | (% change) | |||||||||||||||||
| $156 | 29.8 | $273 | 20.4 |
Total operating revenues include PPA capacity revenues, which are derived primarily from long-term contracts involving natural gas facilities, and PPA energy revenues from Southern Power's generation facilities. To the extent Southern Power has capacity not contracted under a PPA, it may sell power into an accessible wholesale market, or, to the extent those generation assets are part of the FERC-approved IIC, it may sell power into the Southern Company power pool.
Natural Gas Capacity and Energy Revenue
Capacity revenues generally represent the greatest contribution to operating income and are designed to provide recovery of fixed costs plus a return on investment.
Energy is generally sold at variable cost or is indexed to published natural gas indices. Energy revenues will vary depending on the energy demand of Southern Power's customers and their generation capacity, as well as the market prices of wholesale energy compared to the cost of Southern Power's energy. Energy revenues also include fees for support services, fuel storage, and unit start charges. Increases and decreases in energy revenues under PPAs that are driven by fuel or purchased power prices are accompanied by an increase or decrease in fuel and purchased power costs and do not have a significant impact on net income.
Solar and Wind Energy Revenue
Southern Power's energy sales from solar and wind generating facilities are predominantly through long-term PPAs that do not have capacity revenue. Customers either purchase the energy output of a dedicated renewable facility through an energy charge or pay a fixed price related to the energy generated from the respective facility and sold to the grid. As a result, Southern Power's ability to recover fixed and variable operations and maintenance expenses is 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.
Table of Contents Index to Financial Statements
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Operating Revenues Details
Details of Southern Power's operating revenues were as follows:
| Third Quarter 2021 | Third Quarter 2020 | Year-To-Date 2021 | Year-To-Date 2020 | ||||||||||||||||||||
| (in millions) | |||||||||||||||||||||||
| PPA capacity revenues | $ | 118 | $ | 116 | $ | 311 | $ | 297 | |||||||||||||||
| PPA energy revenues | 413 | 319 | 954 | 794 | |||||||||||||||||||
| Total PPA revenues | 531 | 435 | 1,265 | 1,091 | |||||||||||||||||||
| Non-PPA revenues | 139 | 84 | 327 | 235 | |||||||||||||||||||
| Other revenues | 9 | 4 | 18 | 11 | |||||||||||||||||||
| Total operating revenues | $ | 679 | $ | 523 | $ | 1,610 | $ | 1,337 |
In the third quarter 2021, total operating revenues were $679 million, reflecting a $156 million, or 30%, increase from the corresponding period in 2020. The increase in operating revenues was primarily due to the following:
-
PPA energy revenues increased $94 million, or 29%, primarily due to an increase in sales under existing natural gas PPAs resulting from a $75 million increase in the price of fuel and purchased power and a $20 million increase related to a net increase in natural gas PPAs.
-
Non-PPA revenues increased $55 million, or 65%, due to a $60 million increase in the market price of energy, partially offset by a $5 million decrease in the volume of KWHs sold through short-term sales.
For year-to-date 2021, total operating revenues were $1.6 billion, reflecting a $273 million, or 20%, increase from the corresponding period in 2020. The increase in operating revenues was primarily due to the following:
-
PPA capacity revenues increased $14 million, or 5%, primarily due to increased capacity sales under existing contracts.
-
PPA energy revenues increased $160 million, or 20%, primarily due to an increase in sales under existing natural gas PPAs resulting from a $139 million increase in the price of fuel and purchased power and a $25 million increase related to a net increase in natural gas PPAs. Also contributing to the increase was $12 million related to new wind PPAs which began subsequent to the first quarter 2020, partially offset by a $10 million decrease in sales under existing wind PPAs primarily due to a decrease in the volume of KWHs sold.
-
Non-PPA revenues increased $92 million, or 39%, due to a $132 million increase in the market price of energy, partially offset by a $40 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:
| Third Quarter 2021 | Third Quarter 2020 | Year-To-Date 2021 | Year-To-Date 2020 | ||||||||||||||
| (in billions of KWHs) | |||||||||||||||||
| Generation | 12.1 | 12.3 | 31.8 | 34.3 | |||||||||||||
| Purchased power | 0.8 | 0.7 | 2.0 | 2.3 | |||||||||||||
| Total generation and purchased power | 12.9 | 13.0 | 33.8 | 36.6 | |||||||||||||
| Total generation and purchased power, excluding solar, wind, and tolling agreements | 7.7 | 7.4 | 20.2 | 21.9 |
Table of Contents Index to Financial Statements
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Southern Power's PPAs for natural gas generation generally provide that the purchasers are responsible for either procuring the fuel (tolling agreements) or reimbursing Southern Power for substantially all of the cost of fuel relating to the energy delivered under such PPAs. Consequently, changes in such fuel costs are generally accompanied by a corresponding change in related fuel revenues and do not have a significant impact on net income. Southern Power is responsible for the cost of fuel for generating units that are not covered under PPAs. Power from these generating units is sold into the wholesale market or into the Southern Company power pool for capacity owned directly by Southern Power.
Purchased power expenses will vary depending on demand, availability, and the cost of generating resources throughout the Southern Company system and other contract resources. Load requirements are submitted to the Southern Company power pool on an hourly basis and are fulfilled with the lowest cost alternative, whether that is generation owned by Southern Power, an affiliate company, or external parties. Such purchased power costs are generally recovered through PPA revenues.
Details of Southern Power's fuel and purchased power expenses were as follows:
| Third Quarter 2021 vs. Third Quarter 2020 | Year-To-Date 2021 vs. Year-To-Date 2020 | ||||||||||||||||||||||
| (change in millions) | (% change) | (change in millions) | (% change) | ||||||||||||||||||||
| Fuel | $ | 122 | 89.1 | $ | 194 | 56.1 | |||||||||||||||||
| Purchased power | 22 | 115.8 | 34 | 65.4 | |||||||||||||||||||
| Total fuel and purchased power expenses | $ | 144 | $ | 228 |
In the third quarter 2021, total fuel and purchased power expenses increased $144 million, or 92%, compared to the corresponding period in 2020. Fuel expense increased $122 million due to a $115 million increase in the average cost of fuel per KWH generated and a $7 million increase associated with the volume of KWHs generated. Purchased power expense increased $22 million primarily due to an increase in the average cost of purchased power.
For year-to-date 2021, total fuel and purchased power expenses increased $228 million, or 57%, compared to the corresponding period in 2020. Fuel expense increased $194 million due to a $221 million increase in the average cost of fuel per KWH generated, partially offset by a $27 million decrease associated with the volume of KWHs generated. Purchased power expense increased $34 million due to a $39 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
| Third Quarter 2021 vs. Third Quarter 2020 | Year-To-Date 2021 vs. Year-To-Date 2020 | |||||||||||||||||||
| (change in millions) | (% change) | (change in millions) | (% change) | |||||||||||||||||
| $5 | 5.6 | $63 | 25.7 |
For year-to-date 2021, other operations and maintenance expenses were $308 million compared to $245 million for the corresponding period in 2020. The increase was primarily due to increases of $22 million in scheduled outage and maintenance expenses, $9 million in transmission expenses, $6 million in expenses associated with new wind facilities placed in service subsequent to the first quarter 2020, 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.
Table of Contents Index to Financial Statements
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Depreciation and Amortization
| Third Quarter 2021 vs. Third Quarter 2020 | Year-To-Date 2021 vs. Year-To-Date 2020 | |||||||||||||||||||
| (change in millions) | (% change) | (change in millions) | (% change) | |||||||||||||||||
| $3 | 2.3 | $16 | 4.4 |
For year-to-date 2021, depreciation and amortization was $383 million compared to $367 million for the corresponding period in 2020. The increase primarily resulted from new wind facilities placed in service subsequent to the first quarter 2020.
Loss on Sales-Type Lease
| Third Quarter 2021 vs. Third Quarter 2020 | Year-To-Date 2021 vs. Year-To-Date 2020 | |||||||||||||||||||
| (change in millions) | (% change) | (change in millions) | (% change) | |||||||||||||||||
| $15 | N/M | $15 | N/M |
N/M - Not meaningful
In the third quarter 2021, a $15 million loss on sales-type lease was recorded upon commencement of the Garland battery energy storage facility PPA, $10 million of which was allocated through noncontrolling interests to Southern Power's partners in the project. See Notes (D) and (K) to the Condensed Financial Statements under "Lease Receivables" and "Southern Power," respectively, herein for additional information.
(Gain) Loss on Dispositions, Net
| Third Quarter 2021 vs. Third 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
Table of Contents Index to Financial Statements
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.
Other Income (Expense), Net
| Third Quarter 2021 vs. Third Quarter 2020 | Year-To-Date 2021 vs. Year-To-Date 2020 | |||||||||||||||||||
| (change in millions) | (% change) | (change in millions) | (% change) | |||||||||||||||||
| $(11) | (84.6) | $(9) | (47.4) |
In the third quarter 2021, other income (expense), net was $2 million compared to $13 million for the corresponding period in 2020. For year-to-date 2021, other income (expense), net was $10 million compared to $19 million for the corresponding period in 2020. The decreases primarily related to a $12 million gain recorded in the third quarter 2020 associated with the Roserock solar facility litigation.
Income Taxes (Benefit)
| Third Quarter 2021 vs. Third Quarter 2020 | Year-To-Date 2021 vs. Year-To-Date 2020 | |||||||||||||||||||
| (change in millions) | (% change) | (change in millions) | (% change) | |||||||||||||||||
| $(5) | (35.7) | $(30) | (111.1) |
For year-to-date 2021, income tax benefit was $3 million compared to income tax expense of $27 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.
Net Income (Loss) Attributable to Noncontrolling Interests
| Third Quarter 2021 vs. Third Quarter 2020 | Year-To-Date 2021 vs. Year-To-Date 2020 | |||||||||||||||||||
| (change in millions) | (% change) | (change in millions) | (% change) | |||||||||||||||||
| $(23) | (82.1) | $(30) | N/M |
N/M - Not meaningful
In the third quarter 2021, net income attributable to noncontrolling interests was $5 million compared to $28 million for the corresponding period in 2020. For year-to-date 2021, net loss attributable to noncontrolling interests was $27 million compared to net income of $3 million for the corresponding period in 2020. These changes were primarily due to loss allocations of $13 million related to the commencement of the Garland battery energy storage facility PPA in the third quarter 2021, which includes $10 million allocated from the loss on sales-type lease. In addition, these changes were due to lower income allocations to solar equity partners and higher HLBV loss allocations to wind tax equity partners, including new partnerships entered into subsequent to the third quarter 2020, totaling $10 million and $16 million for the third quarter and year-to-date 2021, respectively. See Notes (D) and (K) to the Condensed Financial Statements under "Lease Receivables" and "Southern Power," respectively, herein for additional information.
Southern Company Gas
Operating Metrics
Southern Company Gas continues to focus on several operating metrics, including Heating Degree Days, customer count, and volumes of natural gas sold.
Table of Contents Index to Financial Statements
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
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.
Net Income
| Third Quarter 2021 vs. Third Quarter 2020 | Year-To-Date 2021 vs. Year-To-Date 2020 | |||||||||||||||||||
| (change in millions) | (% change) | (change in millions) | (% change) | |||||||||||||||||
| $42 | N/M | $29 | 8.1 |
N/M - Not meaningful
In the third quarter 2021, net income was $56 million compared to $14 million for the corresponding period in 2020. For year-to-date 2021, net income was $389 million compared to $360 million for the corresponding period in 2020. The increases for the third quarter and year-to-date 2021 primarily reflect increases of $139 million and $153 million, respectively, at wholesale gas services primarily due to the gain on the sale of Sequent and higher revenues, partially offset by $85 million of deferred income taxes. The third quarter 2021 change also reflects a decrease of $13 million at gas pipeline investments primarily from after-tax charges related to the PennEast Pipeline project. The year-to-date 2021 increase also reflects a $24 million increase at gas distribution operations primarily due to base rate increases and continued investment in infrastructure replacement, partially offset by a decrease of $71 million at gas pipeline investments primarily related to after-tax impairment charges related to the PennEast Pipeline project.
See Note (C) to the Condensed Financial Statements under "Other Matters – Southern Company Gas" herein and Notes (E) and (K) to the Condensed Financial Statements under "Southern Company Gas" herein, as well as Note 2 to the financial statements under "Southern Company Gas" in Item 8 of the Form 10-K for additional information.
Table of Contents Index to Financial Statements
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Natural Gas Revenues, including Alternative Revenue Programs
| Third Quarter 2021 vs. Third Quarter 2020 | Year-To-Date 2021 vs. Year-To-Date 2020 | |||||||||||||||||||
| (change in millions) | (% change) | (change in millions) | (% change) | |||||||||||||||||
| $146 | 30.6 | $632 | 26.8 |
In the third quarter 2021, natural gas revenues, including alternative revenue programs, were $623 million compared to $477 million for the corresponding period in 2020. For year-to-date 2021, natural gas revenues, including alternative revenue programs, were $3.0 billion compared to $2.4 billion for the corresponding period in 2020.
Details of the changes in natural gas revenues, including alternative revenue programs, were as follows:
| Third Quarter 2021 | Year-To-Date 2021 | ||||||||||||||||||||||
| (in millions) | (% change) | (in millions) | (% change) | ||||||||||||||||||||
| Natural gas revenues – prior year | $ | 477 | $ | 2,362 | |||||||||||||||||||
| Estimated change resulting from – | |||||||||||||||||||||||
| Infrastructure replacement programs and base rate changes | 28 | 5.9 | % | 109 | 4.6 | % | |||||||||||||||||
| Gas costs and other cost recovery | 54 | 11.3 | 294 | 12.5 | |||||||||||||||||||
| Wholesale gas services | 51 | 10.7 | 207 | 8.8 | |||||||||||||||||||
| Other | 13 | 2.7 | 22 | 0.9 | |||||||||||||||||||
| Natural gas revenues – current year | $ | 623 | 30.6 | % | $ | 2,994 | 26.8 | % |
Revenues from infrastructure replacement programs and base rate changes increased in the third 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 third quarter and year-to-date 2021 compared to the corresponding periods in 2020 primarily due to higher volumes of natural gas sold and higher natural gas cost recovery. See "Cost of Natural Gas" herein for additional information. Revenue impacts from weather and customer growth are described further below.
For the third quarter 2021, the change in revenues related to Southern Company Gas' wholesale gas services was due to the sale of Sequent on July 1, 2021. The year-to-date 2021 change reflects higher volumes of natural gas sold and higher commercial activities as a result of Winter Storm Uri, partially offset by derivative losses all prior to the sale of Sequent on July 1, 2021. 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 additional information.
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.
Table of Contents Index to Financial Statements
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
| Third Quarter | 2021 vs. normal | 2021 vs. 2020 | Year-to-Date | 2021 vs. normal | 2021 vs. 2020 | ||||||||||||||||||||||||||||||||||||
| Normal**(*)** | 2021 | 2020 | (warmer) | (warmer) | Normal**(*)** | 2021 | 2020 | (warmer) | colder | ||||||||||||||||||||||||||||||||
| (in thousands) | (in thousands) | ||||||||||||||||||||||||||||||||||||||||
| Illinois | 53 | 14 | 54 | (73.6) | % | (74.1) | % | 3,734 | 3,594 | 3,548 | (3.7) | % | 1.3 | % | |||||||||||||||||||||||||||
| Georgia | 3 | 3 | 15 | — | % | (80.0) | % | 1,454 | 1,396 | 1,294 | (4.0) | % | 7.9 | % |
(*)Normal represents the 10-year average from January 1, 2011 through September 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 September 30, 2021 and 2020:
| September 30, | |||||||||||||||||
| 2021 | 2020 | 2021 vs. 2020 | |||||||||||||||
| (in thousands, except market share %) | (% change) | ||||||||||||||||
| Gas distribution operations | 4,283 | 4,258 | 0.6 | % | |||||||||||||
| Gas marketing services | |||||||||||||||||
| Energy customers(*) | 603 | 659 | (8.5) | % | |||||||||||||
| Market share of energy customers in Georgia | 28.9 | % | 28.9 | % | — | % | |||||||||||
(*)Gas marketing services' customers are primarily located in Georgia and Illinois. September 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 customer growth and uses a variety of targeted marketing programs to attract new customers and to retain existing customers.
Cost of Natural Gas
| Third Quarter 2021 vs. Third Quarter 2020 | Year-To-Date 2021 vs. Year-To-Date 2020 | |||||||||||||||||||
| (change in millions) | (% change) | (change in millions) | (% change) | |||||||||||||||||
| $58 | 81.7 | $289 | 44.2 |
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 78% and 85% of total cost of natural gas for the third quarter and year-to-date 2021, respectively. See MANAGEMENT'S DISCUSSION AND ANALYSIS – RESULTS OF OPERATIONS – "Southern Company Gas – Cost of Natural Gas" in Item 7 of the Form 10-K and "Natural Gas Revenues, including Alternative Revenue Programs" herein for additional information.
In the third quarter 2021, cost of natural gas was $129 million compared to $71 million for the corresponding period in 2020. The increase reflects higher gas cost recovery driven by a 103% increase in natural gas prices in the third quarter 2021 compared to the corresponding period in 2020.
For year-to-date 2021, cost of natural gas was $943 million compared to $654 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 69% increase in natural gas prices for year-to-date 2021 compared to the corresponding period in 2020.
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AND RESULTS OF OPERATIONS (Continued)
The following table details the volumes of natural gas sold during all periods presented.
| Third Quarter | 2021 vs. 2020 | Year-to-Date | 2021 vs. 2020 | ||||||||||||||||||||
| 2021 | 2020 | 2021 | 2020 | ||||||||||||||||||||
| Gas distribution operations (mmBtu in millions) | |||||||||||||||||||||||
| Firm | 74 | 68 | 8.8 | % | 465 | 425 | 9.4 | % | |||||||||||||||
| Interruptible | 23 | 21 | 9.5 | 73 | 67 | 9.0 | |||||||||||||||||
| Total | 97 | 89 | 9.0 | % | 538 | 492 | 9.3 | % | |||||||||||||||
| Wholesale gas services (mmBtu in millions/day) | |||||||||||||||||||||||
| Daily physical sales | — | 7.1 | (100.0) | % | 6.6 | 6.8 | (2.9) | % | |||||||||||||||
| Gas marketing services (mmBtu in millions) | |||||||||||||||||||||||
| Firm: | |||||||||||||||||||||||
| Georgia | 3 | 3 | — | % | 26 | 21 | 23.8 | % | |||||||||||||||
| Illinois | — | 1 | (100.0) | 5 | 6 | (16.7) | |||||||||||||||||
| Other | 2 | 2 | — | 10 | 9 | 11.1 | |||||||||||||||||
| Interruptible large commercial and industrial | 3 | 3 | — | 10 | 10 | — | |||||||||||||||||
| Total | 8 | 9 | (11.1) | % | 51 | 46 | 10.9 | % |
Other Operations and Maintenance Expenses
| Third Quarter 2021 vs. Third Quarter 2020 | Year-To-Date 2021 vs. Year-To-Date 2020 | |||||||||||||||||||
| (change in millions) | (% change) | (change in millions) | (% change) | |||||||||||||||||
| $21 | 9.7 | $82 | 11.8 |
In the third quarter 2021, other operations and maintenance expenses were $238 million compared to $217 million for the corresponding period in 2020. The increase was primarily due to higher compensation primarily at distribution operations and bad debt expenses. For year-to-date 2021, other operations and maintenance expenses were $776 million compared to $694 million for the corresponding period in 2020. The increase was primarily due to higher compensation expenses primarily at distribution operations and wholesale gas services.
Depreciation and Amortization
| Third Quarter 2021 vs. Third Quarter 2020 | Year-To-Date 2021 vs. Year-To-Date 2020 | |||||||||||||||||||
| (change in millions) | (% change) | (change in millions) | (% change) | |||||||||||||||||
| $8 | 6.4 | $28 | 7.6 |
In the third quarter 2021, depreciation and amortization was $133 million compared to $125 million for the corresponding period in 2020. For year-to-date 2021, depreciation and amortization was $396 million compared to $368 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
| Third Quarter 2021 vs. Third Quarter 2020 | Year-To-Date 2021 vs. Year-To-Date 2020 | |||||||||||||||||||
| (change in millions) | (% change) | (change in millions) | (% change) | |||||||||||||||||
| $1 | 2.9 | $12 | 7.8 |
For year-to-date 2021, taxes other than income taxes were $166 million compared to $154 million for the corresponding period in 2020. The increase primarily reflects 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.
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AND RESULTS OF OPERATIONS (Continued)
(Gain) Loss on Dispositions, Net
| Third Quarter 2021 vs. Third Quarter 2020 | Year-To-Date 2021 vs. Year-To-Date 2020 | |||||||||||||||||||
| (change in millions) | (% change) | (change in millions) | (% change) | |||||||||||||||||
| $121 | N/M | $129 | N/M |
N/M - Not meaningful
In the third quarter and year-to-date 2021, gain on dispositions was $121 million and $127 million, respectively, and primarily related to the $121 million gain on the sale of Sequent recorded in the third quarter 2021. The year-to-date 2021 gain also includes $5 million of contingent payment from the sale of Pivotal LNG recorded in the second quarter 2021. See Note (K) to the Condensed Financial Statements under "Southern Company Gas" herein for additional information.
Earnings from Equity Method Investments
| Third Quarter 2021 vs. Third Quarter 2020 | Year-To-Date 2021 vs. Year-To-Date 2020 | |||||||||||||||||||
| (change in millions) | (% change) | (change in millions) | (% change) | |||||||||||||||||
| $(8) | (24.2) | $(92) | (86.8) |
In the third quarter 2021, earnings from equity method investments was $25 million compared to $33 million for the corresponding period in 2020. The decrease was primarily due to lower earnings at SNG resulting from lower revenues and an impairment charge related to the PennEast Pipeline project.
For year-to-date 2021, earnings from equity method investments was $14 million compared to $106 million for the corresponding period in 2020. The decrease was primarily due to pre-tax impairment charges totaling $84 million related to the PennEast Pipeline project and lower earnings at SNG resulting from lower revenues.
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
| Third Quarter 2021 vs. Third Quarter 2020 | Year-To-Date 2021 vs. Year-To-Date 2020 | |||||||||||||||||||
| (change in millions) | (% change) | (change in millions) | (% change) | |||||||||||||||||
| $1 | 8.3 | $(99) | N/M |
N/M - Not meaningful
For year-to-date 2021, other income (expense), net was $66 million of expense compared to $33 million of income for the corresponding period in 2020. The change was largely due to charitable contributions of $101 million in the second quarter 2021.
Income Taxes
| Third Quarter 2021 vs. Third Quarter 2020 | Year-To-Date 2021 vs. Year-To-Date 2020 | |||||||||||||||||||
| (change in millions) | (% change) | (change in millions) | (% change) | |||||||||||||||||
| $130 | N/M | $126 | 128.6 |
N/M - Not meaningful
In the third quarter 2021, income taxes were $133 million compared to $3 million for the corresponding period in 2020. For year-to-date 2021, income taxes were $224 million compared to $98 million for the corresponding period in 2020. The increases were primarily the result of $85 million in additional tax expense resulting from changes in state apportionment rates as a result of the sale of Sequent, $28 million of tax expense related to the sale of Sequent, and higher pre-tax earnings at wholesale gas services and gas distribution operations. Partially offsetting the year-to-date 2021 increase was $18 million of tax benefit resulting from the impairment charge in the second quarter 2021
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AND RESULTS OF OPERATIONS (Continued)
at gas pipeline investments 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, as well as Note (G) to the Condensed Financial Statements herein for additional information.
Segment Information
Operating revenues, operating expenses, and net income for each segment are provided in the table below. See Note (L) to the Condensed Financial Statements under "Southern Company Gas" herein for additional information.
| Third Quarter 2021 | Third Quarter 2020 | ||||||||||||||||||||||||||||||||||
| Operating Revenues | Operating Expenses | Net Income (Loss) | Operating Revenues | Operating Expenses | Net Income (Loss) | ||||||||||||||||||||||||||||||
| (in millions) | (in millions) | ||||||||||||||||||||||||||||||||||
| Gas distribution operations | $ | 556 | $ | 459 | $ | 45 | $ | 479 | $ | 384 | $ | 46 | |||||||||||||||||||||||
| Gas pipeline investments | 8 | 3 | 10 | 8 | 3 | 23 | |||||||||||||||||||||||||||||
| Wholesale gas services | — | (120) | 94 | (51) | 11 | (45) | |||||||||||||||||||||||||||||
| Gas marketing services | 52 | 52 | (2) | 39 | 45 | (3) | |||||||||||||||||||||||||||||
| All other | 11 | 25 | (91) | 8 | 11 | (7) | |||||||||||||||||||||||||||||
| Intercompany eliminations | (4) | (4) | — | (6) | (6) | — | |||||||||||||||||||||||||||||
| Consolidated | $ | 623 | $ | 415 | $ | 56 | $ | 477 | $ | 448 | $ | 14 |
| Year-To-Date 2021 | Year-To-Date 2020 | ||||||||||||||||||||||||||||||||||
| Operating Revenues | Operating Expenses | Net Income (Loss) | Operating Revenues | Operating Expenses | Net Income (Loss) | ||||||||||||||||||||||||||||||
| (in millions) | (in millions) | ||||||||||||||||||||||||||||||||||
| Gas distribution operations | $ | 2,466 | $ | 1,936 | $ | 308 | $ | 2,086 | $ | 1,609 | $ | 284 | |||||||||||||||||||||||
| Gas pipeline investments | 24 | 9 | 3 | 24 | 9 | 74 | |||||||||||||||||||||||||||||
| Wholesale gas services | 188 | (53) | 108 | (19) | 40 | (45) | |||||||||||||||||||||||||||||
| Gas marketing services | 311 | 226 | 60 | 272 | 194 | 59 | |||||||||||||||||||||||||||||
| All other | 29 | 60 | (90) | 24 | 45 | (12) | |||||||||||||||||||||||||||||
| Intercompany eliminations | (24) | (24) | — | (25) | (25) | — | |||||||||||||||||||||||||||||
| Consolidated | $ | 2,994 | $ | 2,154 | $ | 389 | $ | 2,362 | $ | 1,872 | $ | 360 |
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 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 third quarter and year-to-date 2021, net income decreased $1 million, or 2.2%, and increased $24 million, or 8.5%, respectively, when compared to the corresponding periods in 2020. In the third quarter and year-to-date 2021,
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AND RESULTS OF OPERATIONS (Continued)
operating revenue increased $77 million and $380 million, respectively, when compared to the corresponding periods in 2020 primarily due to higher gas cost recovery, rate increases for Atlanta Gas Light, Virginia Natural Gas, and Chattanooga Gas and continued investment in infrastructure replacement. Gas costs recovered through natural gas revenues generally equal the amount expensed in cost of natural gas. In the third quarter and year-to-date 2021, operating expenses increased $75 million and $327 million, respectively, when compared to the corresponding periods in 2020 primarily due to increases of $44 million and $245 million, respectively, in cost of gas as a result of higher natural gas prices and higher volumes sold, higher depreciation resulting from additional assets placed in service, higher taxes other than income taxes due to higher pass through taxes, and higher compensation expenses. In the third quarter and year-to-date 2021, other income and expense decreased $4 million and $8 million, respectively, when compared to the corresponding periods in 2020, primarily due to a decrease in non-service cost-related retirement benefits income. In the third quarter and year-to-date 2021, interest expense, net of amounts capitalized increased $6 million and $16 million, respectively, when compared to the corresponding periods in 2020 primarily due to additional debt issued to finance continued investments. In the third quarter and year-to-date 2021, income taxes decreased $7 million and increased $5 million, respectively, when compared to the corresponding periods in 2020, primarily due to changes in pre-tax earnings and a lower estimated tax rate.
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. Also see Note (C) to the Condensed Financial Statements under "Other Matters – Southern Company Gas" herein for information regarding the September 2021 cancellation of the PennEast Pipeline project.
In the third quarter 2021, net income decreased $13 million, or 56.5%, compared to the corresponding period in 2020. The decrease primarily relates to an impairment charge related to the PennEast Pipeline project.
For year-to-date 2021, net income decreased $71 million, or 95.9% when compared to the corresponding period in 2020. The decrease was primarily due to pre-tax impairment charges totaling $84 million ($67 million after tax) related to the equity method investment in the PennEast Pipeline project, as well as lower earnings at SNG due to lower revenues.
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 third quarter 2021, net income increased $139 million, or 308.9%, compared to the corresponding period in 2020. The sale of Sequent on July 1, 2021 resulted in $94 million of net income in the third quarter 2021. In the third quarter 2020, wholesale gas services had $51 million of commercial activity and derivative losses and $11 million in operating expenses, which resulted in a net loss of $45 million.
For year-to-date 2021, net income increased $153 million, or 340.0% when compared to the corresponding period in 2020. The increase primarily relates to a $207 million increase in operating revenue and a $121 million gain on the sale of Sequent, partially offset by a $28 million increase in operating expenses primarily related to an increase in
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AND RESULTS OF OPERATIONS (Continued)
variable compensation, a $101 million decrease in other income and (expense) related to higher charitable contributions, and a $47 million increase in income tax expense due to higher pre-tax earnings.
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. Due to the sale of Sequent on July 1, 2021, the change in the third quarter 2021 reflects the commercial activities and derivative losses in the third quarter 2020. 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.
In the third quarter and year-to-date 2021, operating revenue increased $13 million and $39 million, respectively, when compared to the corresponding periods in 2020. These increases primarily relate to higher natural gas prices and increased retail price spreads. In the third quarter and year-to-date 2021, cost of sales increased $10 million and $39 million, respectively, when compared to the corresponding periods in 2020 primarily due to higher natural gas prices.
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.
In the third quarter 2021, net loss increased $84 million and for year-to-date 2021, net income decreased $78 million when compared to the corresponding periods in 2020. The changes primarily relate to additional tax expense due to changes in state apportionment rates as a result of the sale of Sequent.
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. Also see Notes (G) and (K) to the Condensed Financial Statements herein.
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.
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AND RESULTS OF OPERATIONS (Continued)
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 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. In addition, rising inflation in 2021 has resulted in increasing costs for many goods and services. The combination of rising inoculation rates in the U.S. population and the federal COVID-19 relief package contributed to increased economic recovery in 2021; however, fiscal support of business and personal incomes is declining. 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 nine months 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 through the remainder 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 nine months 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 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, primarily driven by tight gas supplies and diminished gas production, subject a portion of Southern Company Gas' operations to earnings variability. 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. However, if economic conditions continue to improve, the demand for natural gas may increase, which may cause natural gas prices to rise and drive higher volatility in the natural gas markets on a longer-term basis.
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AND RESULTS OF OPERATIONS (Continued)
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.
On October 13, 2021, in accordance with the ELG Rules' requirement for electric utilities to identify compliance plans either through certain compliance pathways or by permanently ceasing combustion of coal by certain deadlines, Alabama Power and Georgia Power each submitted initial notices of planned participation (NOPP) for applicable units with its state permitting authority, as detailed further below.
Alabama Power submitted its NOPP to the Alabama Department of Environmental Management indicating plans to retire Plant Barry Unit 5 (700 MWs) and to cease using coal and begin operating solely on natural gas at Plant Barry Unit 4 (350 MWs) and Plant Gaston Unit 5 (880 MWs). Alabama Power, as agent for SEGCO, which is equally owned by Alabama Power and Georgia Power, indicated plans to retire Plant Gaston Units 1 through 4 (1,000 MWs). These plans are expected to be completed on or before the compliance date of December 31, 2028. The NOPP submittals are subject to the review of the Alabama Department of Environmental Management. Retirement of Plant Barry Unit 5 could occur as early as 2023, subject to completion of the acquisition of the Calhoun Generating Station and certain operating conditions. See Note 7 to the financial statements under "SEGCO" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Alabama Power – Calhoun Generating Station Acquisition" herein for additional information.
The assets for which Alabama Power has indicated retirement, due to early closure or repowering of the unit to natural gas, have net book values totaling approximately $1.5 billion (excluding capitalized asset retirement costs
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AND RESULTS OF OPERATIONS (Continued)
which are recovered through Rate CNP Compliance) at September 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 " – Environmental Accounting Order" in Item 8 of the Form 10-K for additional information.
Georgia Power submitted its NOPP to the Georgia Environmental Protection Division indicating plans to retire Plant Wansley Units 1 and 2 (926 MWs based on 53.5% ownership), Plant Bowen Units 1 and 2 (1,400 MWs), and Plant Scherer Unit 3 (614 MWs based on 75% ownership) on or before the compliance date of December 31, 2028. Georgia Power intends to pursue compliance with the ELG Rules for Plant Scherer Units 1 and 2 (137 MWs based on 8.4% ownership) through the voluntary incentive program by no later than December 31, 2028. Georgia Power intends to comply with the ELG Rules for Plant Bowen Units 3 and 4 through the generally applicable requirements by December 31, 2025; therefore, no NOPP submission was required for these units. The NOPP submittals and generally applicable requirements are subject to the review of the Georgia Environmental Protection Division.
The units for which Georgia Power has indicated early retirement plans have net book values totaling approximately $2.2 billion (excluding capitalized asset retirement costs which are recovered through the ECCR tariff) at September 30, 2021. A final decision regarding the future operation of Georgia Power's impacted units and the timing of any retirements will be subject to review by the Georgia PSC in Georgia Power's next IRP, which is required to be filed by January 31, 2022.
The ultimate outcome of these matters cannot be determined at this time.
Coal Combustion Residuals
Based on requirements for closure and monitoring of landfills and ash ponds pursuant to the CCR Rule and applicable state rules, the traditional electric operating companies have periodically updated, and expect to continue periodically updating, their related cost estimates and ARO liabilities for each CCR unit as additional information related to ash pond closure methodologies, schedules, and/or costs becomes available. Some of these updates have been, and future updates may be, material. Additionally, the closure designs and plans in the States of Alabama and Georgia are subject to approval by environmental regulatory agencies. Absent continued recovery of ARO costs through regulated rates, results of operations, cash flows, and financial condition for Southern Company and the traditional electric operating companies could be materially impacted. See Note (A) to the Condensed Financial Statements under "Asset Retirement Obligations" herein for information regarding increases in AROs recorded during the third quarter 2021 at Alabama Power, Georgia Power, and Mississippi Power.
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 August 11, 2021, the Alabama PSC issued an order approving an extension of Alabama Power's Renewable Generation Certificate (RGC) through September 16, 2027. The RGC 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.
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AND RESULTS OF OPERATIONS (Continued)
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 Note 2 to the financial statements in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements herein under "Southern Company Gas" for additional information on Southern Company Gas' construction program.
See FINANCIAL CONDITION AND LIQUIDITY – "Cash Requirements" herein for additional information regarding the Registrants' capital requirements for their construction programs.
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. All regulatory approvals have been received and the agreement was implemented on September 1, 2021.
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MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
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.
As a result of the sale of Sequent on July 1, 2021, Southern Company and Southern Company Gas no longer consider valuations regarding derivatives and hedging activities to be a critical accounting estimate. Except as described herein, there were no other significant changes to the Registrants' critical accounting policies and estimates during the nine months ended September 30, 2021. See Note (K) to the Condensed Financial Statements under "Southern Company Gas" herein for information regarding the sale of Sequent.
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, which was completed in July 2021, and fuel load for Unit 3. As a result of challenges including, but not limited to, construction productivity, construction remediation work, the pace of system turnovers, spent fuel pool repairs, and the timeframe and duration for hot functional and other testing, at the end of the second quarter 2021, Southern Nuclear further extended certain milestone dates, including the fuel load for Unit 3, from those established in January 2021. Through the third quarter 2021, the project continued to face challenges including, but not limited to, construction productivity, construction remediation work, and the pace of system turnovers. As a result of these continued challenges, at the end of the third quarter 2021, Southern Nuclear further extended certain milestone dates, including fuel load for Unit 3, from those established at the end of the second quarter 2021. The site work plan currently targets fuel load for Unit 3 in the first quarter 2022 and an in-service date of May 2022 and primarily depends on significant improvements in overall construction productivity and production levels, the volume of construction remediation work, the pace of system and area turnovers, and the progression of startup and other testing. As the site work plan includes minimal margin to these milestone dates, an in-service date in the third quarter 2022 for Unit 3 is projected, although any further delays could result in a later in-service date.
As the result of productivity challenges, at the end of the second quarter 2021, Southern Nuclear also further extended milestone dates for Unit 4 from those established in January 2021. These productivity challenges continued into the third quarter 2021 and some craft and support resources were diverted temporarily to support construction efforts on Unit 3. As a result of these factors, at the end of the third quarter 2021, Southern Nuclear further extended the milestone dates for Unit 4 from those established at the end of the second quarter 2021. The site work plan targets an in-service date of March 2023 for Unit 4 and primarily depends on overall construction productivity and production levels significantly improving as well as appropriate levels of craft laborers, particularly electricians and pipefitters, being added and maintained. As the site work plan includes minimal margin to the milestone dates, an in-service date in the second quarter 2023 for Unit 4 is projected, although any further delays could result in a later in-service date.
As of March 31, 2021, approximately $84 million of the construction contingency established in the fourth quarter 2020 was assigned to the base capital cost forecast for costs primarily associated with the schedule extension for Unit 3 to December 2021, construction productivity, support resources, and construction remediation work. Georgia
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AND RESULTS OF OPERATIONS (Continued)
Power increased its total capital cost forecast as of March 31, 2021 by adding $48 million to the remaining construction contingency. As of June 30, 2021, all of the remaining construction contingency previously established and an additional $341 million was assigned to the base capital cost forecast for costs primarily associated with the schedule extensions for Units 3 and 4, construction remediation work for Unit 3, and construction productivity and support resources for Units 3 and 4. Georgia Power also increased its total capital cost forecast as of June 30, 2021 by adding $119 million to replenish construction contingency. As a result of the factors discussed above, during the third quarter 2021, all of the remaining construction contingency previously established in the second quarter 2021 and an additional $127 million was assigned to the base capital cost forecast for costs primarily associated with the schedule extensions for Units 3 and 4, construction productivity and support resources for Units 3 and 4, and construction remediation work for Unit 3. Georgia Power also increased its total capital cost forecast as of September 30, 2021 by adding $137 million to replenish construction contingency. Georgia Power's revised base capital cost forecast and contingency to complete construction and start-up of Plant Vogtle Units 3 and 4 is $9.34 billion and $0.14 billion, respectively, for a total capital cost forecast of $9.48 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, the second quarter 2021, and the third quarter 2021 of $48 million ($36 million after tax), $460 million ($343 million after tax), and $264 million ($197 million after tax), respectively, for the increases in the total project capital cost forecast. As and when these amounts are spent, Georgia Power may request the Georgia PSC to evaluate those expenditures for rate recovery.
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 September 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 third quarter 2021, the market price of Southern Company's common stock was $61.97 per share (based on the closing price as reported on the NYSE) and the book value was $27.07 per share, representing a market-to-book ratio of 229%, compared to $61.43, $26.48, and 232%, respectively, at the end of 2020. Southern Company's common stock dividend for the third quarter 2021 was $0.66 per share compared to $0.64 per share in the third 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 replacements and adding or changing fuel sources at existing electric generating units, to meet regulatory
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AND RESULTS OF OPERATIONS (Continued)
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.
In October 2021, Alabama Power's Board of Directors approved updates to its construction program that is currently estimated to total $1.9 billion for 2022, $1.8 billion for 2023, and $1.7 billion for each of 2024, 2025, and 2026. These amounts include capital expenditures related to Plant Barry Unit 8, nuclear fuel, and LTSAs. These amounts also include estimated capital expenditures to comply with environmental laws and regulations, but do not include any potential compliance costs associated with any future regulation of CO2 emissions from fossil fuel-fired electric generating units. 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 on the construction of Plant Barry Unit 8.
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
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AND RESULTS OF OPERATIONS (Continued)
financial statements and are accounted for using HLBV methodology to allocate partnership gains and losses. During the first nine months of 2021, Southern Power obtained tax equity funding for the Deuel Harvest wind facility, the Garland and Tranquillity battery energy storage facilities, and existing tax equity partnerships totaling $256 million. See Note 1 to 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 September 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 September 30, 2021 for the applicable Registrants:
| At September 30, 2021 | Southern Company | Georgia Power | Mississippi Power | Southern Power | Southern Company Gas | |||||||||||||||
| (in millions) | ||||||||||||||||||||
| Current liabilities in excess of current assets | $ | 1,585 | $ | 1,152 | $ | 5 | $ | 743 | $ | 92 |
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 September 30, 2021, the Registrants' unused committed credit arrangements with banks were as follows:
| At September 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 | $ | 1,250 | $ | 1,726 | $ | 250 | $ | 568 | $ | 1,747 | $ | 30 | $ | 7,570 |
(a)At September 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 September 30, 2021 was approximately $1.6 billion (comprised of approximately $854 million at Alabama Power, $672 million at Georgia Power, and $34 million at Mississippi Power). In addition, at September 30, 2021, Georgia Power and Mississippi Power had approximately $262 million and $50 million, respectively, of fixed rate revenue bonds outstanding that are required to be remarketed within the next 12 months.
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AND RESULTS OF OPERATIONS (Continued)
See Note 8 to the financial statements in Item 8 of the Form 10-K and Note (F) to the Condensed Financial Statements herein under "Bank Credit Arrangements" for additional information.
Short-term Borrowings
The Registrants, Nicor Gas, and SEGCO make short-term borrowings primarily through commercial paper programs that have the liquidity support of the committed bank credit arrangements described above. Southern Power's subsidiaries are not issuers or obligors under its commercial paper program. Commercial paper and short-term bank term loans are included in notes payable in the balance sheets. Details of the Registrants' short-term borrowings were as follows:
| Short-term Debt at September 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 | $ | 707 | 0.4 | % | $ | 1,331 | 0.3 | % | $ | 1,716 | |||||||||||||||||||
| Alabama Power | — | — | 7 | 0.1 | 70 | ||||||||||||||||||||||||
| Georgia Power | — | — | 81 | 0.2 | 310 | ||||||||||||||||||||||||
| Mississippi Power | — | — | — | — | — | ||||||||||||||||||||||||
| Southern Power | 27 | 0.2 | 66 | 0.2 | 123 | ||||||||||||||||||||||||
| Southern Company Gas: | |||||||||||||||||||||||||||||
| Southern Company Gas Capital | $ | 72 | 0.2 | % | $ | 325 | 0.2 | % | $ | 484 | |||||||||||||||||||
| Nicor Gas | 590 | 0.4 | 451 | 0.5 | 590 | ||||||||||||||||||||||||
| Southern Company Gas Total | $ | 662 | 0.4 | % | $ | 776 | 0.4 | % |
(*)Average and maximum amounts are based upon daily balances during the three-month period ended September 30, 2021.
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AND RESULTS OF OPERATIONS (Continued)
Analysis of Cash Flows
Net cash flows provided from (used for) operating, investing, and financing activities for the nine months ended September 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) | ||||||||||||||||||||
| Nine Months Ended September 30, 2021 | ||||||||||||||||||||
| Operating activities | $ | 5,081 | $ | 1,419 | $ | 2,350 | $ | 159 | $ | 750 | $ | 757 | ||||||||
| Investing activities | (5,850) | (1,335) | (2,572) | (182) | (753) | (966) | ||||||||||||||
| Financing activities | 1,802 | 56 | 505 | 130 | 33 | 222 | ||||||||||||||
| Nine Months Ended September 30, 2020 | ||||||||||||||||||||
| Operating activities | $ | 5,220 | $ | 1,229 | $ | 2,125 | $ | 186 | $ | 774 | $ | 1,122 | ||||||||
| Investing activities | (4,892) | (1,591) | (2,526) | (200) | 424 | (973) | ||||||||||||||
| Financing activities | 1,077 | 505 | 867 | (214) | (1,060) | (37) |
Fluctuations in cash flows from financing activities vary from year to year based on capital needs and the maturity or redemption of securities.
Southern Company
Net cash provided from operating activities decreased $139 million for the nine months ended September 30, 2021 as compared to the corresponding period in 2020 primarily due to decreased fuel cost recovery at the traditional electric operating companies resulting from an increase in the cost of fuel and under recovered natural gas costs at Southern Company Gas resulting from Winter Storm Uri, partially offset by the timing of vendor payments and customer bill credits issued in 2020 at Georgia Power.
The net cash used for investing activities for the nine months ended September 30, 2021 was primarily related to the Subsidiary Registrants' construction programs.
The net cash provided from financing activities for the nine months ended September 30, 2021 was primarily related to net issuances of long-term debt, partially offset by common stock dividend payments.
Alabama Power
Net cash provided from operating activities increased $190 million for the nine months ended September 30, 2021 as compared to the corresponding period in 2020 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 the timing of fossil fuel stock purchases, partially offset by decreased fuel cost recovery.
The net cash used for investing activities for the nine months ended September 30, 2021 was primarily related to gross property additions.
The net cash provided from financing activities for the nine months ended September 30, 2021 was primarily related to capital contributions from Southern Company and the net issuance of long-term debt, partially offset by common stock dividend payments.
Georgia Power
Net cash provided from operating activities increased $225 million for the nine months ended September 30, 2021 as compared to the corresponding period in 2020 primarily due to customer bill credits issued in 2020 associated
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AND RESULTS OF OPERATIONS (Continued)
with Tax Reform and 2018 earnings in excess of the allowed retail ROE range, the timing of vendor payments, lower income tax payments, and the timing of customer receivable collections and fossil fuel stock purchases, partially offset by decreased fuel cost recovery.
The net cash used for investing activities for the nine months ended September 30, 2021 was primarily related to gross property additions, including a total of approximately $830 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 nine months ended September 30, 2021 was primarily related to capital contributions from Southern Company, net issuances of senior notes, and borrowings from the FFB for construction of Plant Vogtle Units 3 and 4, partially offset by common stock dividend payments.
Mississippi Power
Net cash provided from operating activities decreased $27 million for the nine months ended September 30, 2021 as compared to the corresponding period in 2020 primarily due to decreased fuel cost recovery and the timing of receivable collections, partially offset by the timing of vendor payments.
The net cash used for investing activities for the nine months ended September 30, 2021 was primarily related to gross property additions.
The net cash provided from financing activities for the nine months ended September 30, 2021 was primarily related to the issuance of senior notes and capital contributions from Southern Company, partially offset by debt redemptions, common stock dividend payments, and a decrease in commercial paper borrowings.
Southern Power
Net cash provided from operating activities decreased $24 million for the nine months ended September 30, 2021 as compared to the corresponding period in 2020 primarily due to a decrease in the utilization of tax credits in 2021.
The net cash used for investing activities for the nine months ended September 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 nine months ended September 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, common stock dividend payments, and net repayments of commercial paper.
Southern Company Gas
Net cash provided from operating activities decreased $365 million for the nine months ended September 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 nine months ended September 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, partially offset by proceeds from dispositions.
The net cash provided from financing activities for the nine months ended September 30, 2021 was primarily related to net issuances of long-term and short-term debt and capital contributions from Southern Company, partially offset by common stock dividend payments.
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AND RESULTS OF OPERATIONS (Continued)
Significant Balance Sheet Changes
Southern Company
Significant balance sheet changes for the nine months ended September 30, 2021 included:
-
an increase of $3.5 billion in long-term debt (including securities due within one year) related to new issuances;
-
an increase of $3.2 billion in total property, plant, and equipment primarily related to the Subsidiary Registrants' construction programs (net of pre-tax charges totaling $772 million recorded during 2021 at Georgia Power for estimated probable losses associated with the construction of Plant Vogtle Units 3 and 4);
-
an increase of $1.0 billion in total stockholders' equity primarily related to net income, partially offset by common stock dividend payments;
-
an increase of $1.0 billion in cash and cash equivalents, as discussed further under "Analysis of Cash Flows – Southern Company" herein;
-
increases of $0.9 billion and $0.5 billion in AROs and regulatory assets associated with AROs, respectively, primarily related to cost estimate updates at the traditional electric operating companies for ash pond facilities;
-
an increase of $0.7 billion in accumulated deferred income taxes primarily related to the utilization and expected further utilization of tax credits in 2021;
-
decreases of $0.5 billion each in energy marketing receivables and payables due to Southern Company Gas' sale of Sequent; and
-
an increase of $0.4 billion in natural gas cost under recovery, primarily resulting from Southern Company Gas' cost of gas purchased during Winter Storm Uri.
See "Financing Activities" herein and Notes (A), (B), (G), and (K) to the Condensed Financial Statements herein for additional information.
Alabama Power
Significant balance sheet changes for the nine months ended September 30, 2021 included:
-
an increase of $1.1 billion in common stockholder's equity primarily due to capital contributions from Southern Company;
-
an increase of $916 million in total property, plant, and equipment primarily related to construction of distribution and transmission facilities, increases to AROs, construction of Plant Barry Unit 8, and the installation of equipment to comply with environmental standards;
-
an increase of $349 million in AROs primarily related to cost estimate updates for ash pond facilities; and
-
an increase of $190 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 and Note (A) to the Condensed Financial Statements under "Asset Retirement Obligations" herein for additional information.
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AND RESULTS OF OPERATIONS (Continued)
Georgia Power
Significant balance sheet changes for the nine months ended September 30, 2021 included:
-
an increase of $1.2 billion in total property, plant, and equipment primarily related to the construction of generation, transmission, and distribution facilities, including $217 million for Plant Vogtle Units 3 and 4 (net of pre-tax charges totaling $772 million recorded during 2021 for estimated probable losses);
-
an increase of $0.9 billion in common stockholder's equity primarily due to capital contributions from Southern Company;
-
an increase of $0.8 billion 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;
-
increases of $0.5 billion and $0.3 billion in AROs and regulatory assets associated with AROs, respectively, primarily due to cost estimate updates for ash pond closures; and
-
an increase of $0.3 billion in cash and cash equivalents, as discussed further under "Analysis of Cash Flows – Georgia Power" herein.
See "Financing Activities – Georgia Power" herein and Notes (A) and (B) to the Condensed Financial Statements under "Asset Retirement Obligations" and "Georgia Power – Nuclear Construction," respectively, herein for additional information.
Mississippi Power
Significant balance sheet changes for the nine months ended September 30, 2021 included:
-
an increase of $166 million in long-term debt (including securities due within one year) primarily due to the issuance of senior notes, partially offset by the redemption of revenue bonds and bank term loans;
-
an increase of $121 million in common stockholder's equity related to net income and capital contributions from Southern Company, partially offset by dividends paid to Southern Company; and
-
an increase of $107 million in cash and cash equivalents, as discussed further under "Analysis of Cash Flows – Mississippi Power" herein.
See "Financing Activities – Mississippi Power" herein for additional information.
Southern Power
Significant balance sheet changes for the nine months ended September 30, 2021 included:
-
an increase of $495 million in property, plant, and equipment in service primarily due to the acquisition of the Deuel Harvest wind facility;
-
an increase of $323 million in long-term debt (including securities due within one year) primarily related to the issuance of senior notes;
-
a decrease of $262 million in accumulated deferred income tax assets primarily related to the utilization of ITCs in 2021; and
-
a decrease of $148 million in notes payable due to net repayments of commercial paper.
See "Financing Activities – Southern Power" herein and Notes (G) and (K) to the Condensed Financial Statements herein for additional information.
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AND RESULTS OF OPERATIONS (Continued)
Southern Company Gas
Significant balance sheet changes for the nine months ended September 30, 2021 included:
-
an increase of $776 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;
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decreases of $516 million in energy marketing receivables and $494 million in energy marketing trade payables due to the sale of Sequent;
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an increase of $432 million in natural gas cost under recovery reflecting an increase in the cost of gas purchased during Winter Storm Uri;
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an increase of $338 million in notes payable due to issuances of short-term debt and an increase in commercial paper borrowings;
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an increase of $306 million in accumulated deferred income taxes primarily due to the increase in natural gas cost under recovery, as discussed above, and changes in state apportionment rates as a result of the sale of Sequent;
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a decrease of $265 million in customer accounts receivable due to the timing of collections; and
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an increase of $187 million in long-term debt (including securities due within one year) primarily due to net issuances of senior notes and first mortgage bonds.
See "Financing Activities – Southern Company Gas" herein and Notes (B) and (K) to the Condensed Financial Statements under "Southern Company Gas" herein for additional information.
Financing Activities
The following table outlines the Registrants' long-term debt financing activities for the first nine months of 2021:
| Issuances/Reofferings | Maturities, Redemptions, and Repurchases | |||||||||||||||||||||||||
| Company | Senior Notes | Revenue Bonds | Other Long-Term Debt | Senior Notes | Revenue Bonds | Other Long-Term Debt**(a)** | ||||||||||||||||||||
| (in millions) | ||||||||||||||||||||||||||
| Southern Company parent | $ | 1,000 | $ | — | $ | 2,476 | $ | 1,500 | $ | — | $ | — | ||||||||||||||
| Alabama Power | 600 | — | — | 200 | — | 207 | ||||||||||||||||||||
| Georgia Power | 750 | 122 | 371 | 325 | 69 | 83 | ||||||||||||||||||||
| Mississippi Power | 525 | — | — | — | 270 | 75 | ||||||||||||||||||||
| Southern Power | 400 | — | — | — | — | — | ||||||||||||||||||||
| Southern Company Gas | 450 | — | 100 | 300 | — | 30 | ||||||||||||||||||||
| Other | — | — | — | — | — | 8 | ||||||||||||||||||||
| Elimination(b) | — | — | — | — | — | (7) | ||||||||||||||||||||
| Southern Company | $ | 3,725 | $ | 122 | $ | 2,947 | $ | 2,325 | $ | 339 | $ | 396 |
(a)Includes reductions in finance lease obligations resulting from cash payments under finance leases and, for Georgia Power, principal amortization payments for FFB borrowings.
(b)Represents reductions in affiliate finance lease obligations at Georgia Power, which are eliminated in Southern Company's consolidated financial statements.
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.
Table of Contents Index to Financial Statements
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
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 nine months of 2021, Southern Company issued approximately 3.3 million shares of common stock primarily through employee equity compensation plans and received proceeds of approximately $62 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.
In September 2021, Southern Company issued €1.25 billion (approximately $1.476 billion) aggregate principal amount of Series 2021B 1.875% Fixed-to-Fixed Reset Rate Junior Subordinated Notes due September 15, 2081. Southern Company's obligations under these notes were effectively converted to fixed-rate U.S. dollars at issuance for the first six years through cross-currency swaps, mitigating foreign currency exchange risk associated with the interest and principal payments during this period. See Note (J) to the Condensed Financial Statements under "Foreign Currency Derivatives" herein for additional information.
Subsequent to September 30, 2021, Southern Company redeemed all $800 million aggregate principal amount of its Series 2016A 5.25% Junior Subordinated Notes due October 1, 2076.
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.
In July 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.
Subsequent to September 30, 2021, Alabama Power repaid at maturity $65 million aggregate principal amount of The Industrial Development Board of the Town of Columbia (Alabama) Tax Exempt Variable Rate Demand Revenue Bonds (Alabama Power Company Project), Series 1997.
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
Table of Contents Index to Financial Statements
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
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.
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. In August 2021, Georgia Power reoffered these bonds to the public.
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 nine months ended September 30, 2021, Georgia Power made principal amortization payments of $75 million under the FFB Credit Facilities. At September 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.
In August 2021, Georgia Power reoffered to the public $53 million aggregate principal amount of Development Authority of Floyd County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Hammond Project), First Series 2010, which it had previously purchased and held.
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.
In July 2021, Mississippi Power redeemed 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.
Also in July 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.
Subsequent to September 30, 2021, Mississippi Power repaid $25 million previously borrowed under its $125 million revolving credit arrangement that matures in March 2023.
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.
Subsequent to September 30, 2021, Southern Power announced the planned redemption on November 15, 2021 of all $300 million aggregate principal amount of its Series 2016E 2.500% Senior Notes due December 15, 2021.
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.
Table of Contents Index to Financial Statements
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
In June 2021, Southern Company Gas Capital redeemed all $300 million aggregate principal amount of its 3.50% Senior Notes due September 15, 2021.
In August 2021, Nicor Gas issued in a private placement $50 million aggregate principal amount of 1.42% Series First Mortgage Bonds due August 31, 2026 and $50 million aggregate principal amount of 2.19% Series First Mortgage Bonds due August 31, 2033. Nicor Gas also entered into an agreement to issue in a private placement additional first mortgage bonds with aggregate principal amounts of $100 million, which were issued subsequent to September 30, 2021, and $100 million and $75 million expected to be issued in August 2022 and October 2022, respectively.
In September 2021, Southern Company Gas Capital, as borrower, and Southern Company Gas, as guarantor, issued $450 million aggregate principal amount of Series 2021A 3.15% Senior Notes due September 30, 2051.
Credit Rating Risk
At September 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.
The maximum potential collateral requirements under these contracts at September 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 | $ | 43 | $ | 1 | $ | — | $ | — | $ | 42 | $ | — | ||||||||
| At BBB- and/or Baa3 | 416 | 2 | 61 | 1 | 354 | — | ||||||||||||||
| At BB+ and/or Ba1 or below | 1,934 | 394 | 953 | 308 | 1,195 | 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 September 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.
On October 27, 2021, S&P downgraded the Southern Company issuer credit rating to BBB+ from A-. Due to S&P's consolidated rating methodology, the downgrade of Southern Company's issuer credit rating resulted in the downgrade of the senior unsecured long-term debt rating of Alabama Power and the long-term issuer rating of Nicor Gas to A- from A, the senior unsecured long-term debt ratings of Atlanta Gas Light, Georgia Power, Mississippi Power, and Southern Company Gas Capital to BBB+ from A-, and the senior unsecured long-term debt ratings of Southern Company and Southern Power to BBB from BBB+. S&P revised its credit rating outlook for Southern Company and its subsidiaries to stable from negative.
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 third quarter 2021. For an in-depth discussion of Southern Company
Table of Contents Index to Financial Statements
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
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.
The changes in net fair value of Southern Company Gas' energy-related derivative contracts for the periods presented are provided in the table below.
| Third Quarter 2021 | Third Quarter 2020 | Year-To-Date 2021 | Year-To-Date 2020 | ||||||||||||||
| (in millions) | |||||||||||||||||
| Contracts outstanding at beginning of period, assets (liabilities), net | $ | (44) | $ | 49 | $ | 101 | $ | 70 | |||||||||
| Contracts realized or otherwise settled | (10) | (31) | (68) | (130) | |||||||||||||
| Current period changes(*) | 62 | — | (25) | 78 | |||||||||||||
| Sale of Sequent | 76 | — | 76 | — | |||||||||||||
| Contracts outstanding at the end of period, assets (liabilities), net | $ | 84 | $ | 18 | $ | 84 | $ | 18 | |||||||||
| Netting of cash collateral | (20) | 70 | (20) | 70 | |||||||||||||
| Cash collateral and net fair value of contracts outstanding at end of period | $ | 64 | $ | 88 | $ | 64 | $ | 88 |
(*)Current period changes also include the fair value of new contracts entered into during the period, if any.
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