Page
Combined Management's Discussion and Analysis of Financial Condition and Results of Operations Overview II-16 Results of Operations II-20Southern Company II-20Alabama Power II-30Georgia Power II-34Mississippi Power II-39Southern Power II-43Southern Company Gas II-47 Future Earnings Potential II-57 Accounting Policies II-90 Financial Condition and Liquidity
II-100
This section generally discusses 2019 and 2018 items and year-to-year comparisons between 2019 and 2018. Discussions of 2017 items and year-to-year comparisons between 2018 and 2017 that are not included in this Annual Report on Form 10-K can be found in Item 7 of each Registrant's Annual Report on Form 10-K for the year endedDecember 31, 2018 , which was filed with theSEC onFebruary 19, 2019 . 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. Item 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK See MANAGEMENT'S DISCUSSION AND ANALYSIS - FINANCIAL CONDITION AND LIQUIDITY - "Market Price Risk" in Item 7 herein and Note 1 to the financial statements under "Financial Instruments" in Item 8 herein. Also see Notes 13 and 14 to the financial statements in Item 8 herein. II-15 -------------------------------------------------------------------------------- Table of Contents Index to Financial Statements COMBINED MANAGEMENT'S DISCUSSION AND ANALYSISSouthern Company and Subsidiary Companies 2019 Annual Report
OVERVIEW
Business ActivitiesSouthern Company is a holding company that owns all of the common stock of three traditional electric operating companies, as well as the parent entities ofSouthern Power andSouthern Company Gas , and owns other direct and indirect subsidiaries. The primary businesses ofthe Southern Company system are electricity sales by the traditional electric operating companies andSouthern Power and the distribution of natural gas bySouthern 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 bySouthern Power , and the sale of natural gas and other complementary products and services bySouthern Company Gas . • The traditional electric operating companies -Alabama Power ,Georgia Power, andMississippi Power - are vertically integrated utilities providing electric service to retail customers in three Southeastern states in addition to wholesale customers in the Southeast. •Southern Power develops, constructs, acquires, owns, and manages power generation assets, including renewable energy projects, and sells electricity at market-based rates in the wholesale market.Southern Power continually seeks opportunities to execute its strategy to create value through various transactions including acquisitions, dispositions, and sales of partnership interests, development and construction of new
generating facilities, and entry into PPAs primarily with investor-owned
utilities, IPPs, municipalities, electric cooperatives, and other
load-serving entities, as well as commercial and industrial customers. In
general,
generating capacity only after entering into or assuming long-term PPAs for the new facilities.
•
business is the distribution of natural gas.
natural gas distribution utilities in four states -
complementary businesses.
through four reportable segments - gas distribution operations, gas
pipeline investments, wholesale gas services, which includes Sequent, a
natural gas asset optimization company, and gas marketing services, which
includes SouthStar, a provider of energy-related products and services to
natural gas markets - and one non-reportable segment, all other. See Notes 7 and 16 to the financial statements for additional information. Many factors affect the opportunities, challenges, and risks ofthe Southern Company system's electric service and natural gas businesses. These factors include the ability to maintain constructive regulatory environments, to maintain and grow sales and customers, and to effectively manage and secure timely recovery of prudently-incurred costs. These costs include those related to projected long-term demand growth; stringent environmental standards, including CCR rules; safety; system reliability and resilience; fuel; natural gas; restoration following major storms; and capital expenditures, including constructing new electric generating plants and expanding and improving the electric transmission and electric and natural gas distribution systems. The traditional electric operating companies and natural gas distribution utilities have various regulatory mechanisms that address cost recovery. Effectively operating pursuant to these regulatory mechanisms and appropriately balancing required costs and capital expenditures with customer prices will continue to challengethe Southern Company system for the foreseeable future. See Note 2 to the financial statements for additional information.Southern Power's future earnings will depend upon the parameters of the wholesale market and the efficient operation of its wholesale generating assets, as well asSouthern Power's ability to execute its growth strategy and to develop and construct generating facilities. In addition,Southern Power's future earnings will depend upon the availability of federal and state ITCs and PTCs on its renewable energy projects, which could be impacted by future tax legislation. See FUTURE EARNINGS POTENTIAL - "Acquisitions and Dispositions," "Construction Programs," and "Income Tax Matters" herein and Notes 10 and 15 to the financial statements for additional information.Southern Company's other business activities include providing energy solutions to electric utilities and their customers in the areas of distributed generation, energy storage and renewables, and energy efficiency. Other business activities also include investments in telecommunications, leveraged lease projects, and gas storage facilities. Management continues to evaluate the contribution of each of these activities to total shareholder return and may pursue acquisitions, dispositions, and other strategic ventures or investments accordingly. II-16 -------------------------------------------------------------------------------- Table of Contents Index to Financial Statements
COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Recent DevelopmentsSouthern Company OnJanuary 1, 2019 ,Southern Company completed the sale ofGulf Power to NextEra Energy for an aggregate cash purchase price of approximately$5.8 billion (less$1.3 billion of indebtedness assumed), including the final working capital adjustments. The gain associated with the sale ofGulf Power totaled$2.6 billion pre-tax ($1.4 billion after tax).Alabama Power OnSeptember 6, 2019 ,Alabama Power filed a petition for a CCN with theAlabama PSC for authorization to procure additional generating capacity through the turnkey construction of a new combined cycle facility and long-term contracts for the purchase of power from others, as well as the acquisition of an existing combined cycle facility for a total capital investment of approximately$1.1 billion . The related costs would be recovered through existing rate mechanisms. In addition,Alabama Power will pursue approximately 200 MWs of certain demand side management and distributed energy resource programs. See FUTURE EARNINGS POTENTIAL - "Regulatory Matters -Alabama Power " herein for additional information.Georgia Power Rate Case OnDecember 17, 2019 , the Georgia PSC voted to approve the 2019 ARP, including estimated rate increases totaling$342 million ,$181 million , and$386 million effectiveJanuary 1, 2020 ,January 1, 2021 , andJanuary 1, 2022 , respectively. See FUTURE EARNINGS POTENTIAL - "Regulatory Matters -Georgia Power - Rate Plans - 2019 ARP" herein for additional information. Plant Vogtle Units 3 and 4 Status In 2009, the Georgia PSC certified construction of Plant Vogtle Units 3 and 4 (with electric generating capacity of approximately 1,100 MWs each).Georgia Power holds a 45.7% ownership interest in Plant Vogtle Units 3 and 4. InMarch 2017 , the EPC Contractor filed for bankruptcy protection under Chapter 11 of theU.S. Bankruptcy Code. InDecember 2017 , the Georgia PSC approvedGeorgia Power's recommendation to continue construction. The current expected in-service dates remainNovember 2021 for Unit 3 andNovember 2022 for Unit 4. In the second quarter 2018,Georgia Power revised its total project capital cost forecast to complete construction and start-up of Plant Vogtle Units 3 and 4 to$8.4 billion (net of$1.7 billion received under the Guarantee Settlement Agreement and approximately$188 million in related customer refunds), with respect toGeorgia Power's ownership interest. As ofDecember 31, 2019 , approximately$140 million of the$366 million construction contingency estimate established in the second quarter 2018 was allocated to the base capital cost forecast. As a result of the increase in the total project capital cost forecast andGeorgia Power's decision not to seek rate recovery of the increase in the base capital costs, the holders of at least 90% of the ownership interests in Plant Vogtle Units 3 and 4 were required to vote to continue construction. InSeptember 2018 , the Vogtle Owners unanimously voted to continue construction of Plant Vogtle Units 3 and 4. Following the vote to continue construction,Georgia Power entered into agreements to take certain actions which partially mitigate potential financial exposure for the other Vogtle Owners and to provide funding with respect to aMEAG Power wholly-owned subsidiary's ownership interest in Plant Vogtle Units 3 and 4 under certain circumstances. As part of its ongoing processes, Southern Nuclear continues to evaluate cost and schedule forecasts on a regular basis to incorporate current information available, particularly in the areas of commodity installation, system turnovers, and workforce statistics. InFebruary 2020 , Southern Nuclear updated its cost and schedule forecast, which did not change the projected overall capital cost forecast and confirmed the expected in-service dates ofNovember 2021 for Unit 3 andNovember 2022 for Unit 4. InMarch 2019 ,Georgia Power entered into the Amended and Restated Loan Guarantee Agreement with theDOE , under which the proceeds of borrowings may be used to reimburseGeorgia Power for Eligible Project Costs incurred in connection with its construction of Plant Vogtle Units 3 and 4, up to approximately$5.130 billion . AtDecember 31, 2019 ,Georgia Power had a total of$3.8 billion of borrowings outstanding under the related multi-advance credit facilities. The ultimate outcome of these matters cannot be determined at this time. See FUTURE EARNINGS POTENTIAL - "Construction Programs -Nuclear Construction " herein and Note 8 to the financial statements under "Long-term Debt - DOE Loan Guarantee Borrowings" for additional information. II-17 -------------------------------------------------------------------------------- Table of Contents Index to Financial Statements
COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Mississippi Power In 2019,Mississippi Power recorded pre-tax and after-tax charges to income of$24 million related to theKemper County energy facility, which was suspended in 2017, primarily associated with the expected close out of aDOE contract related to theKemper County energy facility, as well as other abandonment and related closure costs and ongoing period costs, net of salvage proceeds, for the mine and gasifier-related assets. The after-tax amount for 2019 includes an adjustment related to the tax abandonment of the Kemper IGCC following the filing of the 2018 tax return. InDecember 2019 ,Mississippi Power transferred ownership of the CO2 pipeline to an unrelated gas pipeline company, with no resulting impact on income. Mine reclamation activities are expected to be substantially completed in 2020 and dismantlement of the abandoned gasifier-related assets and site restoration activities are expected to be completed in 2024. The additional pre-tax period costs associated with dismantlement and site restoration activities, including related costs for compliance and safety, ARO accretion, and property taxes, are estimated to total$17 million in 2020,$15 million to$16 million annually in 2021 through 2023, and$5 million in 2024. See Note 2 to the financial statements under "Mississippi Power - Kemper County Energy Facility" and Note 3 to the financial statements for additional information, including remaining contingencies related to the Kemper IGCC. OnNovember 26, 2019 ,Mississippi Power filed a base rate case (Mississippi Power 2019 Base Rate Case) with the Mississippi PSC. The filing includes a requested annual decrease inMississippi Power's retail rates of$5.8 million , or 0.6%, which is driven primarily by changes in the amortization rates of certain regulatory assets and liabilities and cost reductions, partially offset by an increase inMississippi Power's requested return on investment and depreciation associated with the filing of an updated depreciation study. The revenue requirements included in the filing are based on a 53% average equity ratio and a 7.728% return on investment. OnDecember 10, 2019 , theMississippi PSC suspended the base rate case filing through no later thanMarch 25, 2020 . If no further action is taken by the Mississippi PSC, the proposed rates may be effective beginning onMarch 26, 2020 . The ultimate outcome of this matter cannot be determined at this time. See Note 2 to the financial statements under "Mississippi Power - 2019 Base Rate Case" for additional information.Southern Power During 2019,Southern Power completed construction and achieved commercial operation of the 100-MW Wildhorse Mountain wind facility, acquired and continued construction of the 136-MW Skookumchuck wind facility, and continued construction of the 200-MW Reading wind facility. In addition,Southern Power acquired a majority interest in DSGP, an affiliate of Bloom Energy, that owns and operates fuel cell generation facilities, for a total purchase price of approximately$167 million . OnJune 13, 2019 ,Southern Power completed the sale of its equity interests in Plant Nacogdoches, a 115-MW biomass facility located inNacogdoches County, Texas , toAustin Energy , for a purchase price of approximately$461 million , including working capital adjustments. OnJanuary 17, 2020 ,Southern Power completed the sale of its equity interests in Plant Mankato (including the 385-MW expansion unit completed inMay 2019 ) to a subsidiary of Xcel for a purchase price of approximately$663 million , including estimated working capital adjustments.Southern Power calculates an 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. With the inclusion of investments associated with the wind facilities currently under construction, as well as other capacity and energy contracts, and excluding Plant Mankato, which was sold onJanuary 17, 2020 ,Southern Power's average investment coverage ratio atDecember 31, 2019 was 93% through 2024 and 90% through 2029, with an average remaining contract duration of approximately 14 years. See FUTURE EARNINGS POTENTIAL - "Acquisitions and Dispositions -Southern Power " and Construction Programs -Southern Power " herein for additional information. II-18 -------------------------------------------------------------------------------- Table of Contents Index to Financial Statements
COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company Gas During 2019, the natural gas distribution utilities have been involved in the following regulatory proceedings: • OnSeptember 25, 2019 , theVirginia Commission approved Virginia Natural
Gas' Steps to Advance Virginia's Energy (SAVE) program request to amend
and extend the program through 2024 with estimated capital spend totaling
approximately
• On
base rate increase for
recovery of investments under the Investing in
became effective
• On
rate increase for
See FUTURE EARNINGS POTENTIAL - "Regulatory Matters -Southern Company Gas - Rate Proceedings" herein and Note 2 to the financial statements under "Southern Company Gas - Rate Proceedings" for additional information. Also during 2019,Southern Company Gas recorded a pre-tax impairment charge of$91 million ($69 million after tax) related to a natural gas storage facility inLouisiana . See Note 3 to the financial statements under "Other Matters -Southern Company Gas " for additional information. OnFebruary 7, 2020 ,Southern Company Gas entered into agreements withDominion Modular LNG Holdings, Inc. andDominion Atlantic Coast Pipeline, LLC for the sale of its interests in Pivotal LNG and Atlantic Coast Pipeline, respectively, for an aggregate purchase price of$165 million , including estimated working capital and timing adjustments.Southern Company Gas may also receive two payments of$5 million each, contingent upon certain milestones related to Pivotal LNG being met byDominion Modular LNG Holdings, Inc. after the completion of the sale. Based on the terms of these pending transactions,Southern Company Gas recorded an asset impairment charge, exclusive of the contingent payments, for Pivotal LNG of approximately$24 million ($17 million after tax) as ofDecember 31, 2019 . The completion of each transaction is subject to the satisfaction or waiver of certain conditions, including, among other customary closing conditions, the completion of the other transaction and, for the sale of the interest in Atlantic Coast Pipeline, the expiration or termination of any applicable waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976. The transactions are expected to be completed in the first half of 2020; however, the ultimate outcome cannot be determined at this time. The assets and liabilities of Pivotal LNG and the interest in Atlantic Coast Pipeline are classified as held for sale as ofDecember 31, 2019 . See Notes 3, 7, and 15 to the financial statements under "Southern Company Gas - Gas Pipeline Projects," "Southern Company Gas - Equity Method Investments," and "Southern Company Gas - Proposed Sale of Pivotal LNG and Atlantic Coast Pipeline," respectively, for additional information. See FUTURE EARNINGS POTENTIAL - "Acquisitions and Dispositions -Southern Company Gas " herein for information regardingSouthern Company Gas' 2018 disposition activity. Key Performance Indicators In striving to achieve attractive risk-adjusted returns while providing cost-effective energy to more than eight million electric and gas utility customers collectively, the traditional electric operating companies andSouthern Company Gas continue to focus on several key performance indicators. These indicators include, but are not limited to, customer satisfaction, plant availability, electric and natural gas system reliability, and execution of major construction projects. In addition,Southern Company and the Subsidiary Registrants focus on earnings per share (EPS) and net income, respectively, as a key performance indicator. See RESULTS OF OPERATIONS herein for information on the Registrants' financial performance. See RESULTS OF OPERATIONS - "Southern Company Gas - Operating Metrics" for additional information onSouthern Company Gas' operating metrics, including Heating Degree Days, customer count, and volumes of natural gas sold. The financial success of the traditional electric operating companies andSouthern Company Gas is directly tied to customer satisfaction. Key elements of ensuring customer satisfaction include outstanding service, high reliability, and competitive prices. The traditional electric operating companies use customer satisfaction surveys to evaluate their results and generally target the top quartile of these surveys in measuring performance. Reliability indicators are also used to evaluate results. See FUTURE EARNINGS POTENTIAL - "Regulatory Matters -Alabama Power - Rate RSE" and " -Mississippi Power - Performance Evaluation Plan" herein for additional information onAlabama Power's Rate RSE and Mississippi Power's PEP rate plan, respectively, both of which contain mechanisms that directly tie customer service indicators to the allowed equity return.Southern Power continues to focus on several key performance indicators, including, but 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. II-19 -------------------------------------------------------------------------------- Table of Contents Index to Financial Statements
COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
RESULTS OF OPERATIONSSouthern Company Consolidated net income attributable toSouthern Company was$4.7 billion in 2019, an increase of$2.5 billion , or 112.9%, from the prior year. The increase was primarily due to the$2.6 billion ($1.4 billion after tax) gain on the sale ofGulf Power in 2019 and a$1.1 billion ($0.8 billion after tax) charge in the second quarter 2018 for an estimated probable loss related toGeorgia Power's construction of Plant Vogtle Units 3 and 4. See "Electricity Business - Estimated Loss onPlants Under Construction " herein and Notes 2 and 15 to the financial statements under "Georgia Power -Nuclear Construction " and "Southern Company ," respectively, for additional information. Basic EPS was$4.53 in 2019 and$2.18 in 2018. Diluted EPS, which factors in additional shares related to stock-based compensation, was$4.50 in 2019 and$2.17 in 2018. EPS for 2019 and 2018 was negatively impacted by$0.11 and$0.04 per share, respectively, as a result of increases in the average shares outstanding. See Note 8 to the financial statements under "Outstanding Classes of Capital Stock -Southern Company " for additional information.Southern Company has paid dividends on its common stock since 1948. Dividends paid per share of common stock were$2.46 in 2019 and$2.38 in 2018. InJanuary 2020 ,Southern Company declared a quarterly dividend of62 cents per share. For 2019, the dividend payout ratio was 54% compared to 109% for 2018. The decrease was due to the increase in earnings in 2019. Discussion ofSouthern Company's results of operations is divided into three parts -the Southern Company system's primary business of electricity sales, its gas business, and its other business activities. 2019 2018 (in millions) Electricity business$ 3,268 $ 2,304 Gas business 585 372 Other business activities 886 (450 ) Net Income$ 4,739 $ 2,226 Electricity BusinessSouthern Company's electric utilities generate and sell electricity to retail and wholesale customers. The results of operations discussed below include the results ofGulf Power throughDecember 31, 2018 . See Note 15 to the financial statements under "Southern Company " for additional information. II-20 -------------------------------------------------------------------------------- Table of Contents Index to Financial Statements
COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
A condensed statement of income for the electricity business follows:
Increase (Decrease) 2019 from 2018 (in millions) Electric operating revenues$ 17,095 $ (1,476 ) Fuel 3,622 (1,015 ) Purchased power 816 (155 ) Cost of other sales 76 10 Other operations and maintenance 4,479 (156 ) Depreciation and amortization 2,472 (93 ) Taxes other than income taxes 1,011 (87 ) Estimated loss on plants under construction 24 (1,073 ) Impairment charges 3 (153 ) (Gain) loss on dispositions, net (21 ) (21 ) Total electric operating expenses 12,482 (2,743 ) Operating income 4,613
1,267
Allowance for equity funds used during construction 121 (10 ) Interest expense, net of amounts capitalized 987 (48 ) Other income (expense), net 234 90 Income taxes 708 501 Net income 3,273 894 Less:
Dividends on preferred and preference stock of subsidiaries 15
(1 ) Net income (loss) attributable to noncontrolling interests (10 ) (69 ) Net Income Attributable to Southern Company$ 3,268 $
964
2019 2018 (in millions) Retail electric - prior year$ 15,222 Estimated change resulting from - Rates and pricing 581 Sales decline (143 ) Weather 29 Fuel and other cost recovery (392 ) Gulf Power disposition (1,213 ) Retail electric - current year 14,084$ 15,222 Wholesale electric revenues 2,152 2,516 Other electric revenues 636 664 Other revenues 223 169 Electric operating revenues$ 17,095 $ 18,571 Percent change (7.9 )% 0.2 % II-21
-------------------------------------------------------------------------------- Table of Contents Index to Financial Statements
COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Retail electric revenues decreased$1.1 billion , or 7.5%, in 2019 as compared to the prior year. The significant factors driving this change are shown in the preceding table. The increase in rates and pricing in 2019 was primarily due to the impacts ofAlabama Power's customer bill credits issued in 2018 related to the Tax Reform Legislation, additional capital investments recovered through Rate CNP Compliance, and lower Rate RSE customer refund in 2019 as compared to the prior year;Georgia Power's higher contributions from commercial and industrial customers with variable demand-driven pricing, NCCR rate increase effectiveJanuary 1, 2019 , and pricing effects associated with a milder winter in 2019 compared to 2018; andMississippi Power's PEP and ECO Plan rate increases effective for the first billing cycle ofSeptember 2018 . Electric rates for the traditional electric operating companies include provisions to adjust billings for fluctuations in fuel costs, including the energy component of purchased power costs. Under these provisions, fuel revenues generally equal fuel expenses, including the energy component of PPA costs, and do not affect net income. The traditional electric operating companies each have one or more regulatory mechanisms to recover other costs such as environmental and other compliance costs, storm damage, new plants, and PPA capacity costs. See Note 2 to the financial statements under "Alabama Power ," "Georgia Power ," and "Mississippi Power " for additional information. Also see "Energy Sales" below for a discussion of changes in the volume of energy sold, including changes related to sales growth (decline) and weather. Wholesale electric revenues consist of 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 tothe Southern Company system's generation, demand for energy withinthe Southern Company system's electric service territory, and the availability ofthe 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 atMississippi Power includeFERC -regulated MRA sales as well as market-based sales. Short-term opportunity sales are made at market-based rates that generally provide a margin abovethe Southern Company system's variable cost to produce the energy. Wholesale electric revenues from power sales were as follows: 2019 2018 (in millions) Capacity and other$ 529 $ 620 Energy 1,623 1,896 Total$ 2,152 $ 2,516 In 2019, wholesale revenues decreased$364 million , or 14.5%, as compared to the prior year due to decreases of$273 million in energy revenues and$91 million in capacity revenues. Excluding the$28 million decrease associated with the sale ofGulf Power , energy revenues decreased$165 million atSouthern Power and$80 million at the traditional electric operating companies. The decrease atSouthern Power related to a$113 million decrease primarily in non-PPA short-term sales and a decrease in the market price of energy, as well as a$51 million decrease primarily in sales under PPAs from natural gas facilities. The decrease at the traditional electric operating companies was primarily due to lower natural gas prices. Excluding the$26 million decrease associated with the sale ofGulf Power , the decrease in capacity revenues was primarily related to the sales ofSouthern Power's Plant Oleander and Plant Stanton Unit A (together, the Florida Plants) inDecember 2018 andSouthern Power's Plant Nacogdoches inJune 2019 . See Note 15 to the financial statements for additional information. Other Electric Revenues Other electric revenues decreased$28 million , or 4.2%, in 2019 as compared to the prior year. The decrease was primarily due to a decrease of$66 million related to the sale ofGulf Power , partially offset by increases atGeorgia Power of$13 million in regulated power delivery construction and maintenance contracts and$11 million from outdoor lighting LED conversions and sales, as well as an increase atAlabama Power of$9 million from pole attachment agreements. II-22 -------------------------------------------------------------------------------- Table of Contents Index to Financial Statements
COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Energy Sales Changes in revenues are influenced heavily by the change in the volume of energy sold from year to year. KWH sales for 2019 and the percent change from the prior year were as follows: 2019 Adjusted(b) Total KWH Total Total KWH Weather-Adjusted Percent Weather-Adjusted KWHs Percent Change Percent Change(a) Change Percent Change(a) (in billions) Residential 48.5 (11.1 )% (10.7 )% (1.1 )% (0.8 )% Commercial 49.1 (8.1 ) (8.6 ) (1.1 ) (1.6 ) Industrial 50.1 (6.1 ) (6.1 ) (2.9 ) (2.9 ) Other 0.8 (9.1 ) (9.0 ) (5.8 ) (5.7 ) Total retail 148.5 (8.5 ) (8.4 )% (1.7 ) (1.8 )% Wholesale 48.0 (3.9 ) (2.6 ) Total energy sales 196.5 (7.4 )% (1.9 )%
(a) Weather-adjusted KWH sales are estimated by removing from KWH sales the
effect of deviations from normal temperature conditions, based on statistical
models of the historical relationship between temperatures and energy sales.
Normal temperature conditions are defined as those experienced in the
applicable service territory over a specified historical period. This metric
is useful because it allows trends in historical operations to be evaluated
apart from the influence of weather conditions. Management also considers
this metric in developing long-term capital and financial plans.
(b) Kilowatt-hour sales comparisons to the prior year were significantly impacted
by the disposition of
Changes in retail energy sales are generally the result of changes in electricity usage by customers, changes in weather, and changes in the number of customers. Excluding the impact of theGulf Power disposition onJanuary 1, 2019 , weather-adjusted retail energy sales decreased 2.7 billion KWHs in 2019 as compared to the prior year primarily due to lower customer usage. Weather-adjusted residential usage decreases are primarily attributable to an increase in energy-efficient residential appliances and energy saving initiatives, partially offset by customer growth. Weather-adjusted commercial usage decreases are primarily attributable to an increase in energy saving initiatives and an ongoing migration to the electronic commerce business model. Industrial usage decreases are a result of changes in production levels primarily in the primary metals, paper, chemicals, and textiles sectors. See "Electric Operating Revenues" above for a discussion of significant changes in wholesale revenues related to changes in price and KWH sales. Other Revenues Other revenues increased$54 million , or 32.0%, in 2019 as compared to the prior year. The increase was primarily due to increases atGeorgia Power of$20 million from unregulated sales associated with new energy conservation projects and$14 million from unregulated power delivery construction and maintenance contracts, as well as an increase atAlabama Power of$11 million in unregulated sales of products and services. Fuel and Purchased Power Expenses The mix of fuel sources for the generation of electricity is determined primarily by demand, the unit cost of fuel consumed, and the availability of generating units. Additionally, the electric utilities purchase a portion of their electricity needs from the wholesale market. II-23 -------------------------------------------------------------------------------- Table of Contents Index to Financial Statements
COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Details of
2019 2018(a) Total generation (in billions of KWHs) 187 191 Total purchased power (in billions of KWHs) 18 14 Sources of generation (percent) - Gas 52 48 Coal 22 27 Nuclear 16 16 Hydro 3 3 Other 7 6 Cost of fuel, generated (in cents per net KWH) - Gas 2.36 2.76 Coal 2.87 2.93 Nuclear 0.79 0.80
Average cost of fuel, generated (in cents per net KWH) 2.20 2.46 Average cost of purchased power (in cents per net KWH)(b) 5.01 5.94
(a)
(b) Average cost of purchased power includes fuel purchased by the Southern
Company system for tolling agreements where power is generated by the
provider.
In 2019, total fuel and purchased power expenses were$4.4 billion , a decrease of$1.2 billion , or 20.9%, as compared to the prior year. Excluding approximately$511 million associated with the sale ofGulf Power , the decrease was primarily the result of a$575 million decrease in the average cost of fuel and purchased power and an$84 million net decrease in the volume of KWHs generated and purchased. Fuel and purchased power energy transactions at the traditional electric operating companies are generally offset by fuel revenues and do not have a significant impact on net income. See FUTURE EARNINGS POTENTIAL - "Regulatory Matters" herein for additional information. Fuel expenses incurred underSouthern Power's PPAs are generally the responsibility of the counterparties and do not significantly impact net income. Fuel In 2019, fuel expense was$3.6 billion , a decrease of$1.0 billion , or 21.9%, as compared to the prior year. Excluding approximately$309 million related toGulf Power in 2018, the decrease was primarily due to an 18.1% decrease in the volume of KWHs generated by coal, a 14.5% decrease in the average cost of natural gas per KWH generated, and a 2.1% decrease in the average cost of coal per KWH generated, partially offset by a 5.0% increase in the volume of KWHs generated by natural gas.Purchased Power In 2019, purchased power expense was$816 million , a decrease of$155 million , or 16.0%, as compared to the prior year. Excluding approximately$202 million associated with the sale ofGulf Power , the change was primarily due to a 9.6% increase in the volume of KWHs purchased, partially offset by a 15.7% decrease in the average cost of KWH purchased. Energy purchases will vary depending on demand for energy withinthe Southern Company system's electric service territory, the market prices of wholesale energy as compared to the cost ofthe Southern Company system's generation, and the availability ofthe Southern Company system's generation. Other Operations and Maintenance Expenses Other operations and maintenance expenses decreased$156 million , or 3.4%, in 2019 as compared to the prior year. The decrease reflects approximately$356 million related toGulf Power in 2018 and$17 million related to the dispositions ofSouthern Power's Florida Plants and Plant Nacogdoches, partially offset by additional accruals of$123 million to the NDR atAlabama Power ,$21 million of increased transmission and distribution expenses primarily due to overhead line maintenance and vegetation management at the traditional electric operating companies,$18 million from costs associated with unregulated sales atGeorgia Power primarily associated with new energy conservation projects and power delivery construction and maintenance contracts, and$16 million related to an adjustment forFERC fees atGeorgia Power following the conclusion of a multi-year audit of II-24 -------------------------------------------------------------------------------- Table of Contents Index to Financial Statements
COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
headwater benefits associated with hydro facilities. See Notes 2 and 15 to the financial statements under "Alabama Power - Rate NDR" and "Southern Power - Sales of Natural Gas and Biomass Plants," respectively, for additional information. Depreciation and Amortization Depreciation and amortization decreased$93 million , or 3.6%, in 2019 as compared to the prior year. The decrease was primarily due to a decrease of$191 million related toGulf Power in 2018, partially offset by an increase in depreciation of$62 million primarily resulting from additional plant in service and an increase in the amortization of regulatory assets of$47 million primarily atMississippi Power andGeorgia Power . See Note 2 to the financial statements under "Southern Company - Regulatory Assets and Liabilities" and Note 5 to the financial statements under "Depreciation and Amortization" for additional information. Taxes Other Than Income Taxes Taxes other than income taxes decreased$87 million , or 7.9%, in 2019 as compared to the prior year primarily due to a decrease of$118 million related to the sale ofGulf Power , partially offset by higher property taxes of$30 million primarily atGeorgia Power . Estimated Loss onPlants Under Construction The$1.1 billion charge in 2018 reflectsGeorgia Power's revised estimate to complete construction and start-up of Plant Vogtle Units 3 and 4. The 2019 charges of$24 million were associated with abandonment and closure activities for the mine and gasifier-related assets of the Kemper IGCC atMississippi Power , net of sales proceeds. See Note 2 to the financial statements under "Georgia Power -Nuclear Construction " and "Mississippi Power -Kemper County Energy Facility" for additional information. Impairment Charges In the second quarter 2018,Southern Power recorded a$119 million asset impairment charge related to the sale of the Florida Plants and in the third quarter 2018 recorded a$36 million asset impairment charge on wind turbine equipment held for development projects. Asset impairment charges recorded in 2019 were immaterial. See Note 15 to the financial statements under "Southern Power - Sales of Natural Gas and Biomass Plants" and " - Development Projects" for additional information. (Gain) Loss on Dispositions,Net Gain on dispositions, net increased$21 million in 2019 as compared to the prior year primarily due toSouthern Power's sale of Plant Nacogdoches in the second quarter 2019. See Note 15 to the financial statements under "Southern Power - Sales of Natural Gas and Biomass Plants" for additional information. Interest Expense, Net of Amounts Capitalized Interest expense, net of amounts capitalized decreased$48 million , or 4.6%, in 2019 as compared to the prior year primarily related to the sale ofGulf Power . Other Income (Expense), Net Other income (expense), net increased$90 million , or 62.5%, in 2019 as compared to the prior year primarily due to a$36 million gain arising from the Roserock solar facility litigation settlement atSouthern Power in 2019,$37 million from decreased charitable donations in 2019 at the traditional electric operating companies,$23 million of increased non-service cost-related retirement benefits income, and$16 million of increased interest income primarily associated with a new tolling arrangement accounted for as a sales-type lease atMississippi Power as well as temporary cash investments, primarily atAlabama Power . These increases were partially offset by$24 million related to the settlement ofMississippi Power's Deepwater Horizon claim in 2018 and a$14 million gain from a joint-development wind project atSouthern Power in 2018 attributable to its partner in the project. See Note 3 to the financial statements under "General Litigation Matters -Southern Power " and "Other Matters -Mississippi Power " and Note 11 to the financial statements under "Pension Plans" for additional information. Income Taxes Income taxes increased$501 million , or 242.0%, in 2019 as compared to the prior year. Excluding an income tax benefit of approximately$20 million related toGulf Power in 2018, income taxes increased$481 million . The increase was primarily due to increases in pre-tax earnings, including the$1.1 billion charge in 2018 associated with Plant Vogtle Units 3 and 4 construction atGeorgia Power . See Notes 10 and 15 to the financial statements for additional information. II-25 -------------------------------------------------------------------------------- Table of Contents Index to Financial Statements
COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Net Income Attributable to Noncontrolling Interests Substantially all noncontrolling interests relate to renewable projects atSouthern Power . Net income attributable to noncontrolling interests decreased$69 million , or 116.9%, in 2019, as compared to the prior year. The decrease was primarily due to$92 million of losses attributable to noncontrolling interests related to the tax equity partnerships entered into in 2018 and$14 million attributable to a joint-development wind project in 2018, partially offset by an allocation of approximately$29 million of income to the noncontrolling interest partner related to the Roserock solar facility litigation settlement. See Note 3 to the financial statements under "General Litigation Matters -Southern Power " and Note 7 to the financial statements under "Southern Power " for additional information regarding the litigation settlement and tax equity partnerships, respectively. Gas BusinessSouthern Company Gas distributes natural gas through utilities in four states and is involved in several other complementary businesses including gas pipeline investments, wholesale gas services, and gas marketing services. A condensed statement of income for the gas business follows: Increase (Decrease) 2019 from 2018 (in millions) Operating revenues$ 3,792 $ (117 ) Cost of natural gas 1,319 (220 ) Cost of other sales - (12 ) Other operations and maintenance 888 (93 ) Depreciation and amortization 487 (13 ) Taxes other than income taxes 213 2 Impairment charges 115 73 (Gain) loss on dispositions, net - 291 Total operating expenses 3,022 28 Operating income 770 (145 ) Earnings from equity method investments 157 9 Interest expense, net of amounts capitalized 232 4 Other income (expense), net 20 19 Income taxes 130 (334 ) Net income$ 585 $ 213 The Southern Company Gas Dispositions were completed byJuly 29, 2018 and represent the primary variance driver for 2019 compared to 2018. Detailed variance explanations are provided herein. See Note 15 to the financial statements under "Southern Company Gas " for additional information on the Southern Company Gas Dispositions. Seasonality of Results During the period from November through March when natural gas usage and operating revenues are generally higher (Heating Season), more customers are connected toSouthern Company Gas' distribution systems and natural gas usage is higher in periods of colder weather. Occasionally in the summer, operating revenues are 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 equally over any given year. Thus, operating results can vary significantly from quarter to quarter as a result of seasonality. For 2019, the percentage of operating revenues and net income generated during the Heating Season (January through March and November through December) were 68.7% and 86.8%, respectively. For 2018, the percentage of operating revenues and net income generated during the Heating Season were 68.7% and 96.0%, respectively. II-26 -------------------------------------------------------------------------------- Table of Contents Index to Financial Statements
COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Operating Revenues Operating revenues in 2019 were$3.8 billion , a$117 million decrease compared to 2018. Details of operating revenues were as follows: 2019 (in millions) Operating revenues - prior year$ 3,909 Estimated change resulting from - Infrastructure replacement programs and base rate changes 96 Gas costs and other cost recovery (89 ) Wholesale gas services 150 Southern Company Gas Dispositions(*) (300 ) Other 26 Operating revenues - current year$ 3,792 Percent change (3.0 )%
(*) Includes a
alternative revenue programs, and a
revenues. See Note 15 to the financial statements under "
Gas" for additional information.
Revenues from infrastructure replacement programs and base rate changes increased in 2019 compared to the prior year primarily due to increases of$74 million atNicor Gas and$16 million atAtlanta Gas Light . These amounts include the natural gas distribution utilities' continued investments recovered through infrastructure replacement programs and base rate increases as well as customer refunds in 2018 as a result of the Tax Reform Legislation. See Note 2 to the financial statements under "Southern Company Gas " for additional information. Revenues attributable to gas costs and other cost recovery decreased in 2019 compared to the prior year primarily due to lower natural gas prices and decreased volumes of natural gas sold. Natural gas distribution rates include provisions to adjust billings for fluctuations in natural gas costs. Therefore, gas costs recovered through natural gas revenues generally equal the amount expensed in cost of natural gas and do not affect net income from the natural gas distribution utilities. Revenues from wholesale gas services increased in 2019 primarily due to derivative gains, partially offset by decreased commercial activity. Other natural gas revenues increased in 2019 primarily due to increases in customers at the natural gas distribution utilities and recovery of prior period hedge losses at gas marketing services. Cost of Natural Gas ExcludingAtlanta Gas Light , which does not sell natural gas to end-use customers, the natural gas distribution utilities charge their utility customers for natural gas consumed using natural gas cost recovery mechanisms set by the applicable state regulatory agencies. Under these mechanisms, all prudently-incurred natural gas costs are passed through to customers without markup, subject to regulatory review. The natural gas distribution utilities defer or accrue the difference between the actual cost of natural gas and the amount of commodity revenue earned in a given period. The deferred or accrued amount is either billed or refunded to customers prospectively through adjustments to the commodity rate. Deferred natural gas costs are reflected as regulatory assets and accrued natural gas costs are reflected as regulatory liabilities. Therefore, gas costs recovered through natural gas revenues generally equal the amount expensed in cost of natural gas and do not affect net income from the natural gas distribution utilities. Cost of natural gas at the natural gas distribution utilities represented 84.5% of the total cost of natural gas for 2019. Gas marketing services customers are charged for actual and estimated natural gas consumed. Cost of natural gas includes the cost of fuel and associated transportation costs, lost and unaccounted for gas, adjustments to reduce the value of inventories to market value, if applicable, and gains and losses associated with certain derivatives. In 2019, cost of natural gas was$1.3 billion , a decrease of$220 million , or 14.3%, compared to the prior year. Excluding a$106 million decrease related to the Southern Company Gas Dispositions, cost of natural gas decreased by$114 million , which reflects a 14.8% decrease in natural gas prices compared to 2018. II-27 -------------------------------------------------------------------------------- Table of Contents Index to Financial Statements
COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Cost of Other Sales Cost of other sales related to Pivotal Home Solutions, which was sold onJune 4, 2018 . See Note 15 to the financial statements under "Southern Company Gas - Sale of Pivotal Home Solutions" for additional information. Other Operations and Maintenance Expenses Other operations and maintenance expenses decreased$93 million , or 9.5%, in 2019 compared to the prior year. Excluding a$65 million decrease related to the Southern Company Gas Dispositions, other operations and maintenance expenses decreased$28 million . This decrease was primarily due to$28 million of disposition-related costs incurred during 2018, a$12 million adjustment in 2018 for the adoption of a new paid time off policy, an$11 million expense for a litigation settlement to facilitate the sale of Pivotal Home Solutions in 2018, and a$7 million decrease in compensation and benefits costs, partially offset by a$22 million increase in rider expenses, primarily atNicor Gas , passed through directly to customers. See FUTURE EARNINGS POTENTIAL - "Southern Company Gas - Utility Regulation and Rate Design" herein for additional information. Depreciation and Amortization Depreciation and amortization decreased$13 million , or 2.6%, in 2019 compared to the prior year. Excluding a$27 million decrease related to the Southern Company Gas Dispositions, depreciation and amortization increased$14 million . This increase was primarily due to continued infrastructure investments at the natural gas distribution utilities, partially offset by accelerated depreciation related to assets retired in 2018. See Note 2 to the financial statements under "Southern Company Gas - Infrastructure Replacement Programs and Capital Projects" for additional information. Impairment Charges In 2019,Southern Company Gas recorded impairment charges of$91 million related to a natural gas storage facility inLouisiana and$24 million in contemplation of the sale of its interests in Pivotal LNG and Atlantic Coast Pipeline. In 2018, a goodwill impairment charge of$42 million was recorded in contemplation of the sale of Pivotal Home Solutions. See Notes 1, 3, and 15 to the financial statements under "Goodwill and Other Intangible Assets and Liabilities," "Other Matters -Southern Company Gas ," and "Southern Company Gas ," respectively, for additional information. (Gain) Loss on Dispositions,Net Gain on dispositions, net was$291 million in 2018 and was associated with the Southern Company Gas Dispositions. The income tax expense on these gains included income tax expense on goodwill not deductible for tax purposes and for which a deferred tax liability had not been recorded previously. Earnings from Equity Method Investments Earnings from equity method investments increased$9 million , or 6.1%, in 2019 compared to the prior year and reflect higher earnings from SNG as a result of rate increases that became effectiveSeptember 2018 , partially offset by a$6 million pre-tax loss on the sale of Triton inMay 2019 . See Note 7 to the financial statements under "Southern Company Gas " for additional information. Other Income (Expense), Net Other income (expense), net increased$19 million in 2019 compared to the prior year. This increase primarily resulted from a$23 million decrease in charitable donations in 2019. Income Taxes Income taxes decreased$334 million , or 72.0%, in 2019 compared to the prior year. This decrease primarily reflects a reduction of$348 million related to the Southern Company Gas Dispositions, as well as$29 million in benefits associated with impairment charges in 2019 and additional benefits from the flowback of excess deferred income taxes in 2019 primarily atAtlanta Gas Light as previously authorized by the Georgia PSC, partially offset by$48 million of additional taxes associated with increased pre-tax earnings at wholesale gas services. See FUTURE EARNINGS POTENTIAL - "Income Tax Matters" herein and Note 10 to the financial statements for additional information. Also see Notes 2, 3, and 15 to the financial statements under "Southern Company Gas ," "Other Matters -Southern Company Gas ," and "Southern Company Gas - Proposed Sale of Pivotal LNG and Atlantic Coast Pipeline," respectively, for additional information onAtlanta Gas Light's regulatory treatment of the impacts of the Tax Reform Legislation and the impairment charges. II-28 -------------------------------------------------------------------------------- Table of Contents Index to Financial Statements
COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Other Business ActivitiesSouthern Company's other business activities primarily include the parent company (which does not allocate operating expenses to business units); PowerSecure, a provider of energy solutions to electric utilities and their customers in the areas of distributed generation, energy storage and renewables, and energy efficiency;Southern Holdings , which invests in various projects, including leveraged lease projects; and Southern Linc, which provides digital wireless communications for use bythe Southern Company system and also markets these services to the public and provides fiber optics services within the Southeast. A condensed statement of income forSouthern Company's other business activities follows: Increase (Decrease) 2019 from 2018 (in millions) Operating revenues$ 532 $ (483 ) Cost of other sales 359 (369 ) Other operations and maintenance 233 (40 ) Depreciation and amortization 79 13 Taxes other than income taxes 6 - Impairment charges 50 38 (Gain) loss on dispositions, net (2,548 ) (2,548 ) Total operating expenses (1,821 ) (2,906 ) Operating income (loss) 2,353 2,423 Interest expense 517 (62 ) Other income (expense), net 10 33 Income taxes (benefit) 960 1,182 Net income (loss)$ 886 $ 1,336 Operating RevenuesSouthern Company's operating revenues for these other business activities decreased$483 million , or 47.6%, in 2019 as compared to the prior year primarily related to PowerSecure's 2018 storm restoration services inPuerto Rico and the sale of PowerSecure's utility infrastructure services business inJune 2019 . Cost of Other Sales Cost of other sales for these other business activities decreased$369 million , or 50.7%, in 2019 as compared to the prior year primarily related to PowerSecure's 2018 storm restoration services inPuerto Rico and the sale of PowerSecure's utility infrastructure services business inJune 2019 . Other Operations and Maintenance Expenses Other operations and maintenance expenses for these other business activities decreased$40 million , or 14.7%, in 2019 as compared to the prior year. The decrease was primarily due to PowerSecure's lower employee compensation and benefits in 2019 and 2018 storm restoration services inPuerto Rico . Impairment Charges In 2019, goodwill and asset impairment charges totaling$50 million were recorded related to the sale of PowerSecure's utility infrastructure services and lighting businesses. In 2018, asset impairment charges of$12 million associated with Southern Linc's tower leases were recorded in contemplation of the sale ofGulf Power . (Gain) Loss on Dispositions, Net The 2019 gain on dispositions, net primarily relates to the gain of$2.6 billion ($1.4 billion after tax) on the sale ofGulf Power . See Note 15 to the financial statements under "Southern Company " for additional information. II-29 -------------------------------------------------------------------------------- Table of Contents Index to Financial Statements
COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Interest Expense Interest expense for these other business activities decreased$62 million , or 10.7%, in 2019 as compared to the prior year primarily due to a decrease in average outstanding long-term debt at the parent company. See Note 8 to the financial statements for additional information. Other Income (Expense), Net Other income (expense), net for these other business activities increased$33 million in 2019 as compared to the prior year primarily due to a$43 million decrease in charitable donations at the parent company, partially offset by a$17 million impairment charge associated with a leveraged lease atSouthern Holdings in 2019. See Notes 1 and 3 to the financial statements under "Leveraged Leases" and "Other Matters -Southern Company ," respectively, for additional information. Income Taxes (Benefit) The income tax for these other business activities increased$1.2 billion in 2019 as compared to the prior year primarily due to the tax impacts related to the sale ofGulf Power . See Note 10 to the financial statements and Note 15 to the financial statements under "Southern Company " for additional information.Alabama Power Alabama Power's 2019 net income after dividends on preferred and preference stock was$1.07 billion , representing a$140 million , or 15.1%, increase over the previous year. The increase was primarily due to an increase in retail revenues associated with the impacts of customer bill credits issued in 2018 related to the Tax Reform Legislation and a lower Rate RSE customer refund in 2019 as compared to the prior year, as well as additional capital investments recovered through Rate CNP Compliance. The increase in revenue is partially offset by increases in operations and maintenance and depreciation expenses and lower customer usage. See FUTURE EARNINGS POTENTIAL - "Regulatory Matters -Alabama Power - Rate RSE" and " - Rate CNP Compliance" herein for additional information. A condensed income statement forAlabama Power follows: Increase (Decrease) 2019 from 2018 (in millions) Operating revenues$ 6,125 $ 93 Fuel 1,112 (189 ) Purchased power 403 (29 ) Other operations and maintenance 1,821 152 Depreciation and amortization 793 29 Taxes other than income taxes 403 14 Total operating expenses 4,532 (23 ) Operating income 1,593 116 Allowance for equity funds used during construction 52 (10 ) Interest expense, net of amounts capitalized 336 13 Other income (expense), net 46 26 Income taxes 270 (21 ) Net income 1,085 140 Dividends on preferred and preference stock 15
-
Net income after dividends on preferred and preference stock
140 II-30
-------------------------------------------------------------------------------- Table of Contents Index to Financial Statements
COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Operating Revenues
Operating revenues for 2019 were
2019 2018 (in millions) Retail - prior year$ 5,367 Estimated change resulting from - Rates and pricing 347 Sales decline (79 ) Weather (3 ) Fuel and other cost recovery (131 ) Retail - current year 5,501$ 5,367 Wholesale revenues - Non-affiliates 258 279 Affiliates 81 119 Total wholesale revenues 339 398 Other operating revenues 285 267 Total operating revenues$ 6,125 $ 6,032 Percent change 1.5 % (0.1 )% Retail revenues in 2019 were$5.5 billion . These revenues increased$134 million , or 2.5%, in 2019 as compared to the prior year. The increase in 2019 was primarily due to increases in rates and pricing associated with the impact of customer bill credits issued in 2018 related to the Tax Reform Legislation and additional capital investments recovered through Rate CNP Compliance, as well as a lower Rate RSE customer refund in 2019 as compared to the prior year, partially offset by decreases in fuel revenues and customer usage, as well as milder weather in 2019 as compared to 2018. See Note 2 to the financial statements under "Alabama Power - Rate RSE" and " - Rate CNP Compliance" for additional information. See "Energy Sales" herein for a discussion of changes in the volume of energy sold, including changes related to sales decline and weather. Electric rates include provisions to recognize the recovery of fuel costs, purchased power costs, PPAs certificated by the Alabama PSC, and costs associated with the natural disaster reserve. Under these provisions, fuel and other cost recovery revenues generally equal fuel and other cost recovery expenses and do not affect net income. See FUTURE EARNINGS POTENTIAL - "Regulatory Matters -Alabama Power - Rate ECR" herein for additional information. Wholesale revenues from power sales to non-affiliated utilities were as follows: 2019 2018 (in millions) Capacity and other$ 102 $ 101 Energy 156 178
Total non-affiliated
Wholesale revenues from sales to non-affiliates will vary depending on fuel prices, the market prices of wholesale energy compared to the cost ofAlabama Power's andthe Southern Company system's generation, demand for energy withinthe Southern Company system's electric service territory, and availability ofthe 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 aboveAlabama Power's variable cost to produce the energy. II-31 -------------------------------------------------------------------------------- Table of Contents Index to Financial Statements
COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
In 2019, wholesale revenues from sales to non-affiliates decreased$21 million , or 7.5%, as compared to the prior year primarily as a result of an 8.2% decrease in energy prices due to lower natural gas prices, partially offset by a 1% increase in the amount of KWHs sold. 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 and purchases are made in accordance with the IIC, as approved by theFERC . 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 throughAlabama Power's energy cost recovery clause. In 2019, wholesale revenues from sales to affiliates decreased$38 million , or 31.9%, as compared to the prior year. In 2019, KWH sales decreased 22.7% due to the decreased availability of coal generation associated with the retirement of Plant Gorgas Units 8, 9, and 10, and the price of energy decreased 11.8% as a result of lower natural gas prices. In 2019, other operating revenues increased$18 million , or 6.7%, as compared to the prior year primarily due to an increase in unregulated sales of products and services and pole attachment agreements. Energy Sales Changes in revenues are influenced heavily by the change in the volume of energy sold from year to year. KWH sales for 2019 and the percent change from the prior year were as follows: 2019 Total Total KWH Weather-Adjusted KWHs Percent Change Percent Change (in billions) Residential 18.3 (1.9 )% (1.5 )% Commercial 13.6 (2.2 ) (2.2 ) Industrial 22.1 (3.7 ) (3.7 ) Other 0.2 (7.3 ) (7.3 ) Total retail 54.2 (2.8 ) (2.6 )% Wholesale Non-affiliates 5.1 1.2 Affiliates 3.5 (22.7 ) Total wholesale 8.6 (10.1 ) Total energy sales 62.8 (3.8 )% Changes in retail energy sales are generally the result of changes in electricity usage by customers, changes in weather, and changes in the number of customers. Retail energy sales in 2019 decreased 2.8% primarily due to lower customer usage and milder weather in 2019 compared to 2018. Weather-adjusted residential sales were 1.5% lower in 2019 primarily due to lower customer usage resulting from an increase in penetration of energy-efficient residential appliances, partially offset by customer growth. Weather-adjusted commercial sales were 2.2% lower in 2019 primarily due to lower customer usage resulting from customer initiatives in energy savings and an ongoing migration to the electronic commerce business model, partially offset by customer growth. Industrial sales decreased 3.7% in 2019 as compared to 2018 primarily as a result of changes in production levels in the primary metals and chemicals sectors. See "Operating Revenues" above for a discussion of significant changes in wholesale revenues from sales to non-affiliates and wholesale revenues from sales to affiliated companies related to changes in price and KWH sales. Fuel and Purchased Power Expenses The mix of fuel sources for generation of electricity is determined primarily by the unit cost of fuel consumed, demand, and the availability of generating units. Additionally,Alabama Power purchases a portion of its electricity needs from the wholesale market. II-32 -------------------------------------------------------------------------------- Table of Contents Index to Financial Statements
COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
2019 2018 Total generation (in billions of KWHs) 56.9 60.5 Total purchased power (in billions of KWHs) 9.4 8.1 Sources of generation (percent) - Coal 45 50 Nuclear 25 23 Gas 21 19 Hydro 9 8 Cost of fuel, generated (in cents per net KWH) - Coal 2.69 2.73 Nuclear 0.77 0.77 Gas 2.47 2.84
Average cost of fuel, generated (in cents per net KWH)(a)(b) 2.11 2.26 Average cost of purchased power (in cents per net KWH)(c) 4.39 5.47
(a) For 2018, cost of fuel, generated and average cost of fuel, generated
excludes a
accounting order related to excess deferred income taxes. See FUTURE EARNINGS
POTENTIAL - "Regulatory Matters -
Order" herein for additional information.
(b) KWHs generated by hydro are excluded from the average cost of fuel,
generated.
(c) Average cost of purchased power includes fuel, energy, and transmission
purchased by
the provider.
Fuel and purchased power expenses were$1.5 billion in 2019, a decrease of$218 million , or 12.6%, compared to 2018. The decrease was primarily due to a$102 million decrease in the average cost of purchased power, a$56 million decrease in the average cost of fuel, a$30 million net decrease related to the volume of KWHs purchased and generated, and a$30 million decrease in fuel expense associated with theMay 2018 Alabama PSC accounting order. Fuel and purchased power energy transactions do not have a significant impact on earnings, since energy expenses are generally offset by energy revenues throughAlabama Power's energy cost recovery clause.Alabama Power , along with the Alabama PSC, continuously monitors the under/over recovered balance to determine whether adjustments to billing rates are required. See Note 2 to the financial statements under "Alabama Power - Rate ECR" for additional information. Fuel Fuel expenses were$1.1 billion in 2019, a decrease of$189 million , or 14.5%, compared to 2018. The decrease was primarily due to a 13% decrease in the average cost of KWHs generated by natural gas, which excludes tolling agreements, a 14.4% decrease in the volume of KWHs generated by coal, and a 5.2% increase in the volume of KWHs generated by hydro, as well as a$30 million decrease in fuel expense associated with theMay 2018 Alabama PSC accounting order.Purchased Power - Non-Affiliates Purchased power expense from non-affiliates was$203 million in 2019, a decrease of$13 million , or 6.0%, compared to 2018. This decrease was primarily due to a 12.6% decrease in the average cost per KWH purchased due to lower natural gas prices. The decrease was partially offset by a 9.1% increase in the amount of energy purchased as a result of decreased coal generation due to the retirement of Plant Gorgas Units 8, 9, and 10. Energy purchases from non-affiliates will vary depending on the market prices of wholesale energy as compared to the cost ofthe Southern Company system's generation, demand for energy withinthe Southern Company system's service territory, and the availability ofthe Southern Company system's generation.Purchased Power - Affiliates Purchased power expense from affiliates was$200 million in 2019, a decrease of$16 million , or 7.4%, compared to 2018. This decrease was primarily due to a 25.2% decrease in the average cost per KWH purchased due to lower natural gas prices. The decrease was partially offset by a 24.1% increase in the amount of energy purchased primarily due to the availability of lower-cost II-33 -------------------------------------------------------------------------------- Table of Contents Index to Financial Statements
COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
generation compared toAlabama Power's owned generation and a decrease in coal generation due to the retirement of Plant Gorgas Units 8, 9, and 10. Energy purchases from affiliates will vary depending on demand for energy and the availability and cost of generating resources at each company withinthe Southern Company system. These purchases are made in accordance with the IIC or other contractual agreements, as approved by theFERC . Other Operations and Maintenance Expenses In 2019, other operations and maintenance expenses increased$152 million , or 9.1%, as compared to the prior year primarily due to additional accruals of$123 million to the NDR as well as$11 million in Rate CNP Compliance-related expenses. See Note 2 to the financial statements under "Alabama Power - Rate NDR" and " - Rate CNP Compliance" for additional information. Depreciation and Amortization Depreciation and amortization increased$29 million , or 3.8%, in 2019 as compared to the prior year primarily due to additional plant in service. See Note 5 to the financial statements under "Depreciation and Amortization" for additional information. Other Income (Expense), Net Other income (expense), net increased$26 million , or 130.0%, in 2019 as compared to the prior year primarily due to a decrease of$17 million in charitable donations and an increase of$9 million in interest income from temporary cash investments. Income Taxes Income taxes decreased$21 million , or 7.2%, in 2019 as compared to the prior year primarily due to additional benefits from the flowback of excess deferred income taxes in accordance with an Alabama PSC accounting order, partially offset by an increase in pre-tax net income. See Note 2 to the financial statements under "Alabama Power - Tax Reform Accounting Order" for additional information.Georgia Power Georgia Power's 2019 net income was$1.7 billion , representing a$927 million , or 116.9%, increase from the previous year. The increase was primarily due to a$1.1 billion ($0.8 billion after tax) charge in the second quarter 2018 for an estimated probable loss related toGeorgia Power's construction ofPlant Vogtle Units 3 and 4, an increase in retail base revenues associated with higher contributions from commercial and industrial customers with variable demand-driven pricing, and an increase in other revenues primarily related to unregulated sales. Partially offsetting the increase were higher non-fuel operations and maintenance expenses and depreciation and amortization. A condensed income statement forGeorgia Power follows: Increase (Decrease) 2019 from 2018 (in millions) Operating revenues$ 8,408 $ (12 ) Fuel 1,444 (254 ) Purchased power 1,096 (57 ) Other operations and maintenance 1,972 112 Depreciation and amortization 981 58 Taxes other than income taxes 454 17
Estimated loss on Plant Vogtle Units 3 and 4 - (1,060 ) Total operating expenses
5,947 (1,184 ) Operating income 2,461 1,172 Interest expense, net of amounts capitalized 409 12 Other income (expense), net 140 25 Income taxes 472 258 Net income$ 1,720 $ 927 II-34
-------------------------------------------------------------------------------- Table of Contents Index to Financial Statements
COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Operating Revenues Operating revenues for 2019 were$8.4 billion , a$12 million decrease from 2018. Details of operating revenues were as follows: 2019 2018 (in millions) Retail - prior year$ 7,752 Estimated change resulting from - Rates and pricing 202 Sales decline (66 ) Weather 39 Fuel cost recovery (220 ) Retail - current year 7,707$ 7,752 Wholesale revenues - Non-affiliates 129 163 Affiliates 11 24 Total wholesale revenues 140 187 Other operating revenues 561 481 Total operating revenues$ 8,408 $ 8,420 Percent change (0.1 )% 1.3 % Retail revenues of$7.7 billion in 2019 decreased$45 million , or 0.6%, compared to 2018. The significant factors driving this change are shown in the preceding table. The increase in rates and pricing was primarily due to higher contributions from commercial and industrial customers with variable demand-driven pricing, an increase in the NCCR tariff effectiveJanuary 1, 2019 , and pricing effects associated with a milder winter in 2019 compared to 2018. See Note 2 to the financial statements under "Georgia Power -Nuclear Construction " for additional information related to the NCCR tariff. See "Energy Sales" below for a discussion of changes in the volume of energy sold, including changes related to the sales decline in 2019. Electric rates include provisions to adjust billings for fluctuations in fuel costs, including the energy component of purchased power costs. Under these fuel cost recovery provisions, fuel revenues generally equal fuel expenses and do not affect net income. See FUTURE EARNINGS POTENTIAL - "Regulatory Matters -Georgia Power - Fuel Cost Recovery" herein for additional information. Wholesale revenues from power sales to non-affiliated utilities were as follows: 2019 2018 (in millions) Capacity and other$ 55 $ 54 Energy 74 109 Total non-affiliated$ 129 $ 163 Wholesale capacity revenues from PPAs are recognized either on a levelized basis over the appropriate contract period or the 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 ofGeorgia Power's andthe Southern Company system's generation, demand for energy withinthe Southern Company system's electric service territory, and the availability ofthe Southern Company system's generation. Increases and decreases in energy revenues that are driven by fuel prices are accompanied by an increase or decrease in fuel costs and do not have a significant impact on net income. Short-term opportunity sales are made at market-based rates that generally provide a margin aboveGeorgia Power's variable cost of energy. Wholesale revenues from non-affiliated sales decreased$34 million , or 20.9%, in 2019 as compared to 2018 primarily due to lower energy prices and lower demand. II-35 -------------------------------------------------------------------------------- Table of Contents Index to Financial Statements
COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
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 theFERC . These transactions do not have a significant impact on earnings since this energy is generally sold at marginal cost. In 2019, wholesale revenues from sales to affiliates decreased$13 million , or 54.2%, as compared to 2018 primarily due to a 36.3% decrease in KWH sales as a result of the lower market cost of available energy compared to the cost ofGeorgia Power -owned generation. Other operating revenues increased$80 million , or 16.6%, in 2019 from the prior year primarily due to revenue increases of$27 million from power delivery construction and maintenance contracts,$20 million from unregulated sales associated with new energy conservation projects,$11 million from outdoor lighting LED conversions and sales,$7 million from OATT sales, and$6 million in wholesale operating fees associated with contractual targets. Energy Sales Changes in revenues are influenced heavily by the change in the volume of energy sold from year to year. KWH sales for 2019 and the percent change from the prior year were as follows: 2019 Total Total KWH Weather-Adjusted KWHs Percent Change Percent Change (in billions) Residential 28.2 (0.5 )% (0.4 )% Commercial 32.8 (0.4 ) (1.3 ) Industrial 23.2 (2.1 ) (2.2 ) Other 0.5 (5.6 ) (5.5 ) Total retail 84.7 (0.9 ) (1.2 )% Wholesale Non-affiliates 2.7 (15.8 ) Affiliates 0.3 (36.3 ) Total wholesale 3.0 (18.7 ) Total energy sales 87.7 (1.7 )% Changes in retail energy sales are generally the result of changes in electricity usage by customers, changes in weather, and changes in the number of customers. In 2019, weather-adjusted residential and commercial KWH sales decreased 0.4% and 1.3%, respectively, compared to 2018 primarily due to a decline in average customer usage resulting from an increase in energy saving initiatives. The decreases in weather-adjusted residential and commercial KWH sales were largely and partially, respectively, offset by customer growth. Weather-adjusted industrial KWH sales decreased 2.2% primarily due to decreases in the paper, textile, stone, clay, and glass, and lumber sectors, partially offset by an increase in the pipeline sector. See "Operating Revenues" above for a discussion of significant changes in wholesale sales to non-affiliates and affiliated companies. Fuel and Purchased Power Expenses Fuel costs constitute one of the largest expenses forGeorgia Power . The mix of fuel sources for the generation of electricity is determined primarily by demand, the unit cost of fuel consumed, and the availability of generating units. Additionally,Georgia Power purchases a portion of its electricity needs from the wholesale market. II-36 -------------------------------------------------------------------------------- Table of Contents Index to Financial Statements
COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
2019 2018 Total generation (in billions of KWHs) 62.6 65.2 Total purchased power (in billions of KWHs) 29.1 27.9 Sources of generation (percent) - Gas 47 42 Nuclear 26 25 Coal 24 30 Hydro 3 3 Cost of fuel, generated (in cents per net KWH) - Gas 2.42 2.75 Nuclear 0.81 0.82 Coal 3.09 3.21
Average cost of fuel, generated (in cents per net KWH) 2.16 2.40 Average cost of purchased power (in cents per net KWH)(*) 4.21 4.79
(*) Average cost of purchased power includes fuel purchased byGeorgia Power for tolling agreements where power is generated by the provider. Fuel and purchased power expenses were$2.5 billion in 2019, a decrease of$311 million , or 10.9%, compared to 2018. The decrease was primarily due to a$289 million decrease related to the average cost of fuel and purchased power. Fuel and purchased power energy transactions do not have a significant impact on earnings since these fuel expenses are generally offset by fuel revenues throughGeorgia Power's fuel cost recovery mechanism. See FUTURE EARNINGS POTENTIAL - "Regulatory Matters -Georgia Power - Fuel Cost Recovery" herein for additional information. Fuel Fuel expense was$1.4 billion in 2019, a decrease of$254 million , or 15.0%, compared to 2018. The decrease was primarily due to a 10% decrease in the average cost of fuel, primarily related to lower natural gas prices, and a 3.9% decrease in the volume of KWHs generated, primarily due to the lower market cost of energy compared to availableGeorgia Power resources.Purchased Power - Non-Affiliates Purchased power expense from non-affiliates was$521 million in 2019, an increase of$91 million , or 21.2%, compared to 2018. The increase was primarily due to a 53.1% increase in the volume of KWHs purchased primarily due to the lower market cost of energy compared to availableSouthern Company system resources and warmer weather in the third quarter 2019 resulting in higher customer demand, partially offset by a 22.1% decrease in the average cost per KWH purchased primarily due to lower energy prices. The volume increase also reflects purchases fromGulf Power which were classified as affiliate prior toJanuary 1, 2019 . See Note 15 to the financial statements for information regarding the sale ofGulf Power . Energy purchases from non-affiliates will vary depending on the market prices of wholesale energy as compared to the cost ofthe Southern Company system's generation, demand for energy withinthe Southern Company system's electric service territory, and the availability ofthe Southern Company system's generation.Purchased Power - Affiliates Purchased power expense from affiliates was$575 million in 2019, a decrease of$148 million , or 20.5%, compared to 2018. The decrease was primarily due to an 11.1% decrease in the volume of KWHs purchased asGeorgia Power units generally dispatched at a lower cost than otherSouthern Company system resources and a 13.0% decrease in the average cost per KWH purchased resulting from lower energy prices. The decrease in purchased power expense from affiliates also reflects a change in the classification of capacity expenses of$24 million related to PPAs withSouthern Power accounted for as finance leases following the adoption of FASB ASC Topic 842, Leases (ASC 842). In 2019, these expenses are included in depreciation and amortization and interest expense, net of amounts capitalized. The decrease in the volume of KWHs purchased also includes the effect of classifying purchases fromGulf Power as II-37 -------------------------------------------------------------------------------- Table of Contents Index to Financial Statements
COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
non-affiliate beginningJanuary 1, 2019 . See Notes 9 and 15 to the financial statements for additional information regarding ASC 842 and the sale ofGulf Power , respectively. Energy purchases from affiliates will vary depending on the demand and the availability and cost of generating resources at each company withinthe Southern Company system. These purchases are made in accordance with the IIC or other contractual agreements, all as approved by theFERC . Other Operations and Maintenance Expenses In 2019, other operations and maintenance expenses increased$112 million , or 6.0%, compared to 2018. The increase reflects increases in expenses of$30 million from unregulated sales primarily associated with new energy conservation projects and power delivery construction and maintenance contracts,$26 million related to scheduled generation outages,$16 million related to an adjustment forFERC fees following the conclusion of a multi-year audit of headwater benefits associated with hydro facilities,$12 million primarily due to the timing of vegetation management and other transmission-related expenses, and$10 million associated with generation maintenance. Depreciation and Amortization Depreciation and amortization increased$58 million , or 6.3%, in 2019 compared to 2018. The increase was primarily due to a$31 million increase in depreciation associated with additional plant in service and a$19 million increase in the amortization of regulatory assets related to the retirement of certain generating units. See FUTURE EARNINGS POTENTIAL - "Regulatory Matters -Georgia Power - Integrated Resource Plan" herein for additional information on unit retirements. The increase also reflects the classification of approximately$9 million related to PPAs withSouthern Power accounted for as finance leases following the adoption of ASC 842. In prior periods, the expenses related to these PPAs were included in purchased power, affiliates. See Note 9 to the financial statements for additional information regarding ASC 842. See Note 5 to the financial statements under "Depreciation and Amortization" for additional information. Taxes Other Than Income Taxes In 2019, taxes other than income taxes increased$17 million , or 3.9%, compared to 2018 primarily due to higher property taxes of$25 million as a result of increases in the assessed value of property, partially offset by a decrease of$11 million in municipal franchise fees, largely due to adjustments associated with the Georgia Power Tax Reform Settlement Agreement. See FUTURE EARNINGS POTENTIAL - "Regulatory Matters -Georgia Power - Rate Plans - Tax Reform Settlement Agreement" herein for additional information. Estimated Loss on Plant Vogtle Units 3 and 4 In the second quarter 2018, an estimated probable loss of$1.1 billion was recorded to reflectGeorgia Power's revised estimate to complete construction and start-up of Plant Vogtle Units 3 and 4. See ACCOUNTING POLICIES - "Estimated Cost, Schedule, and Rate Recovery for the Construction of Plant Vogtle Units 3 and 4" herein and Note 2 to the financial statements under "Georgia Power -Nuclear Construction " for additional information. Interest Expense, Net of Amounts Capitalized In 2019, interest expense, net of amounts capitalized increased$12 million , or 3.0%, compared to 2018. The increase was primarily due to the reclassification of$15 million related to PPAs withSouthern Power accounted for as finance leases following the adoption of ASC 842 and a$6 million increase in interest expense associated with an increase in outstanding short-term borrowings, partially offset by a$9 million increase in amounts capitalized largely associated with Plant Vogtle Units 3 and 4. In prior periods, the expenses related to the PPAs withSouthern Power were included in purchased power, affiliates. See FINANCIAL CONDITION AND LIQUIDITY - "Sources of Capital" and "Financing Activities" herein for additional information on borrowings, Note 9 to the financial statements for additional information regarding ASC 842, and Note 2 to the financial statements under "Georgia Power -Nuclear Construction " for additional information regarding Plant Vogtle Units 3 and 4. Other Income (Expense), Net In 2019, other income (expense), net increased$25 million compared to the prior year primarily due to a$16 million increase in non-service cost-related retirement benefits income and a$13 million decrease in charitable donations, partially offset by a$4 million decrease in interest income from temporary cash investments. See Note 11 to the financial statements for additional information onGeorgia Power's net periodic pension and other postretirement benefit costs. II-38 -------------------------------------------------------------------------------- Table of Contents Index to Financial Statements
COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Income Taxes Income taxes increased$258 million , or 120.6%, in 2019 compared to the prior year primarily as a result of higher pre-tax earnings largely due to the 2018 charge associated with Plant Vogtle Units 3 and 4 construction. This increase was partially offset by additional state ITCs recognized in 2019 and the recognition of a valuation allowance in 2018. See Note 10 to the financial statements for additional information.Mississippi Power Mississippi Power's net income after dividends on preferred stock was$139 million in 2019 compared to$235 million in 2018. The change was primarily the result of higher income tax expense following the 2018 partial reversal of a valuation allowance. A condensed statement of operations follows: Increase (Decrease) 2019 from 2018 (in millions) Operating revenues$ 1,264 $ (1 ) Fuel 407 2 Purchased power 20 (21 ) Other operations and maintenance 283 (30 ) Depreciation and amortization 192 23 Taxes other than income taxes 113 6 Estimated loss on Kemper IGCC 24 (13 ) Total operating expenses 1,039 (33 ) Operating income 225 32 Allowance for equity funds used during construction 1 1 Interest expense, net of amounts capitalized 69 (7 ) Other income (expense), net 12 (5 ) Income taxes (benefit) 30 132 Net income 139 (97 ) Dividends on preferred stock - (1 )
Net income after dividends on preferred stock
II-39 -------------------------------------------------------------------------------- Table of Contents Index to Financial Statements
COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Operating Revenues
Operating revenues for 2019 were approximately
2019 2018 (in millions) Retail - prior year$ 889 Estimated change resulting from - Rates and pricing 31 Weather (2 ) Fuel and other cost recovery (41 ) Retail - current year 877$ 889 Wholesale revenues - Non-affiliates 237 263 Affiliates 132 91 Total wholesale revenues 369 354 Other operating revenues 18 22 Total operating revenues$ 1,264 $ 1,265 Percent change (0.1 )% 6.6 % Total retail revenues for 2019 decreased$12 million , or 1.3%, compared to 2018 primarily due to a fuel rate decrease that became effective for the first billing cycle ofFebruary 2019 . This decrease was largely offset by an increase in rates and pricing, primarily related to PEP and ECO Plan rate changes that became effective for the first billing cycle ofSeptember 2018 , net of a new tolling arrangement accounted for as a sales-type lease effectiveJanuary 2019 . See Note 2 to the financial statements under "Mississippi Power - Environmental Compliance Overview Plan" and " - Performance Evaluation Plan" and Note 9 to the financial statements under "Lessor" for additional information. See "Energy Sales" below for a discussion of changes in the volume of energy sold, including changes related to sales and weather. Electric rates forMississippi Power include provisions to adjust billings for fluctuations in fuel costs, including the energy component of purchased power costs. Under these provisions, fuel revenues generally equal fuel expenses, including the energy component of purchased power costs, and do not affect net income. Recoverable fuel costs include fuel and purchased power expenses reduced by the fuel and emissions portion of wholesale revenues from energy sold to customers outsideMississippi Power's service territory. See FUTURE EARNINGS POTENTIAL - "Regulatory Matters -Mississippi Power - Fuel Cost Recovery" herein for additional information. Wholesale revenues from power sales to non-affiliated utilities, includingFERC -regulated MRA sales as well as market-based sales, were as follows: 2019 2018 (in millions) Capacity and other$ 3 $ 6 Energy 234 257
Total non-affiliated
Wholesale revenues from sales to non-affiliates will vary depending on fuel prices, the market prices of wholesale energy compared to the cost ofMississippi Power's andthe Southern Company system's generation, demand for energy withinthe Southern Company system's electric service territory, and the availability ofthe 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 southeasternMississippi under cost-based electric tariffs which are subject to regulation by theFERC . The contracts with these wholesale customers represented 15.7% ofMississippi Power's total II-40 -------------------------------------------------------------------------------- Table of Contents Index to Financial Statements
COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
operating revenues in 2019 and are generally subject to 10-year rolling cancellation notices. Historically, these wholesale customers have acted as a group and any changes in contractual relationships for one customer are likely to be followed by the other wholesale customers. Short-term opportunity energy sales are also included in sales for resale to non-affiliates. These opportunity sales are made at market-based rates that generally provide a margin aboveMississippi Power's variable cost to produce the energy. Wholesale revenues from sales to non-affiliates decreased$26 million , or 9.9%, compared to 2018. This decrease primarily reflects decreases of$14 million from lower fuel prices,$6 million from decreased customer usage, and$8 million from lower PPA capacity and energy sales. Wholesale revenues from sales to affiliates 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 theFERC . These transactions do not have a significant impact on earnings since this energy is generally sold at marginal cost. Wholesale revenues from sales to affiliates increased$41 million , or 45.1%, in 2019 compared to 2018. This increase was primarily due to a$76 million increase associated with higher KWH sales due to the dispatch ofMississippi Power's lower cost generation resources to servethe Southern Company system's territorial load, partially offset by a$35 million decrease associated with lower natural gas prices. Energy Sales Changes in revenues are influenced heavily by the change in the volume of energy sold from year to year. KWH sales for 2019 and the percent change from the prior year were as follows: 2019 Total Total KWH Weather-Adjusted KWHs Percent Change Percent Change (in millions) Residential 2,062 (2.4 )% (0.8 )% Commercial 2,715 (2.9 ) (2.7 ) Industrial 4,795 (2.6 ) (2.6 ) Other 36 (1.9 ) (1.9 ) Total retail 9,608 (2.7 ) (2.2 )% Wholesale Non-affiliated 3,966 (0.3 ) Affiliated 4,758 84.1 Total wholesale 8,724 32.9 Total energy sales 18,332 11.5 % Changes in retail energy sales are generally the result of changes in electricity usage by customers, changes in weather, and changes in the number of customers. Retail energy sales decreased 2.7% in 2019 as compared to the prior year, primarily due to decreased demand by several large industrial customers. Weather-adjusted residential and commercial KWH sales decreased 0.8% and 2.7%, respectively, in 2019 primarily due to decreased customer usage as a result of an increase in energy saving initiatives, slightly offset by customer growth. See "Operating Revenues" above for a discussion of significant changes in wholesale revenues to affiliated companies. Fuel and Purchased Power Expenses The mix of fuel sources for generation of electricity is determined primarily by demand, the unit cost of fuel consumed, and the availability of generating units. Additionally,Mississippi Power purchases a portion of its electricity needs from the wholesale market. II-41 -------------------------------------------------------------------------------- Table of Contents Index to Financial Statements
COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
2019 2018 Total generation (in millions of KWHs) 18,269 15,966 Total purchased power (in millions of KWHs) 529 960 Sources of generation (percent) - Gas 94 93 Coal 6 7 Cost of fuel, generated (in cents per net KWH) - Gas 2.26 2.65 Coal 4.05 3.50
Average cost of fuel, generated (in cents per net KWH) 2.37 2.72 Average cost of purchased power (in cents per net KWH) 3.71 4.27
Fuel and purchased power expenses were$427 million in 2019, a decrease of$19 million , or 4.3%, as compared to the prior year. The decrease was primarily due to a$60 million decrease related to the average cost of fuel and purchased power primarily due to the lower average cost of natural gas, partially offset by a$41 million net increase associated with the volume of KWHs generated and purchased primarily due to the availability ofMississippi Power's lower-cost generation resources. Fuel and purchased power energy transactions do not have a significant impact on earnings, since energy expenses are generally offset by energy revenues throughMississippi Power's fuel cost recovery clauses. See FUTURE EARNINGS POTENTIAL - "Regulatory Matters -Mississippi Power - Fuel Cost Recovery" herein and Note 1 to the financial statements under "Fuel Costs" for additional information. Fuel Fuel expense increased$2 million , or 0.5%, in 2019 compared to 2018 primarily due to a 15% increase in the volume of KWHs generated, partially offset by a 13% net decrease in the average cost of fuel per KWH generated.Purchased Power Purchased power expense decreased$21 million , or 51.2%, in 2019 compared to 2018. The decrease was primarily the result of a 45% decrease in the volume of KWHs purchased due to the availability ofMississippi Power's lower-cost generation resources and a 13% decrease in the average cost per KWH purchased. Energy purchases will vary depending on the market prices of wholesale energy as compared to the cost ofthe Southern Company system's generation, demand for energy withinthe Southern Company system's service territory, and the availability ofthe Southern Company system's generation. These purchases are made in accordance with the IIC or other contractual agreements, as approved by theFERC . Other Operations and Maintenance Expenses Other operations and maintenance expenses decreased$30 million , or 9.6%, in 2019 compared to the prior year. The decrease was primarily due to decreases of$21 million in compensation and benefit expenses primarily due to an employee attrition plan implemented in the third quarter 2018,$5 million in amortization of previously deferredPlant Ratcliffe expenses as a result of a settlement agreement reached with wholesale customers (MRA Settlement Agreement),$5 million in planned generation outage costs, and$4 million inPlant Ratcliffe waste water treatment expenses. These decreases were partially offset by a$9 million increase in overhead line maintenance and vegetation management expenses. See Note 2 to the financial statements under "Mississippi Power - Municipal and Rural Associations Tariff" for additional information. Depreciation and Amortization Depreciation and amortization increased$23 million , or 13.6%, in 2019 compared to 2018 primarily related to increases in amortization associated with ECO Plan regulatory assets. See Note 2 to the financial statements under "Mississippi Power - Environmental Compliance Overview Plan" for additional information. II-42 -------------------------------------------------------------------------------- Table of Contents Index to Financial Statements
COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Taxes Other Than Income Taxes Taxes other than income taxes increased$6 million , or 5.6%, in 2019 compared to 2018 primarily due to increases of$4 million in ad valorem taxes and$2 million in franchise taxes. Estimated Loss on Kemper IGCC In 2019 and 2018, charges of$24 million and$37 million , respectively, were recorded associated with the abandonment and closure activities and period costs, net of sales proceeds for the mine and gasifier-related assets. The 2019 charge primarily related to the expected close out of aDOE contract related to theKemper County energy facility. See Note 2 to the financial statements under "Kemper County Energy Facility" for additional information. Interest Expense, Net of Amounts Capitalized Interest expense, net of amounts capitalized decreased$7 million , or 9.2%, in 2019 compared to 2018, primarily as the result of a decrease in outstanding long-term borrowings. See Note 8 to the financial statements for additional information. Other Income (Expense), Net Other income (expense), net decreased$5 million in 2019 compared to 2018. The decrease was primarily due to the$24 million settlement ofMississippi Power's Deepwater Horizon claim in 2018, partially offset by a$9 million increase in interest income associated with a new tolling arrangement accounted for as a sales-type lease and a$7 million decrease in charitable donations. See Notes 3 and 9 to the financial statements under "Other Matters -Mississippi Power " and "Lessor," respectively, for additional information. Income Taxes (Benefit) Income tax expense increased$132 million , or 129.4%, in 2019 compared to 2018 primarily due to a$92 million increase related to the 2018 reduction of a valuation allowance for a state income tax net operating loss (NOL) carryforward, a$42 million increase associated with the revaluation of deferred tax assets related to the Kemper IGCC recorded in 2018 in accordance with the Tax Reform Legislation, and a$9 million increase due to higher pre-tax earnings in 2019. These increases were partially offset by$15 million associated with the flowback of excess deferred income taxes resulting from the MRA Settlement Agreement and a new tolling arrangement accounted for as a sales-type lease. See FUTURE EARNINGS POTENTIAL - "Income Tax Matters" herein and Note 10 to the financial statements for additional information.Southern Power Net income attributable toSouthern Power for 2019 was$339 million , a$152 million increase from 2018, primarily due to net impacts totaling approximately$141 million from the dispositions of the Florida Plants in 2018 and PlantNacogdoches in the second quarter 2019, which include an asset impairment charge in 2018, a gain on sale in 2019 (including the recognition of deferred ITCs), and a decrease in operations and maintenance expense, partially offset by PPA capacity revenue decreases in 2019. The increase in net income also reflects$79 million in tax expense recognized in 2018 related to the Tax Reform Legislation, a$27 million wind turbine equipment impairment charge in 2018, and net gains in 2019 of$25 million from the Roserock solar facility litigation settlement and sales of wind equipment. These increases were partially offset by$65 million in state income tax benefits recorded in 2018 arising from the reorganization ofSouthern Power's legal entities and reductions in net income of approximately$60 million related to the SP Wind tax equity partnership entered into in 2018. See Note 15 to the financial statements under "Southern Power - Sales of Natural Gas and Biomass Plants" and " - Development Projects" for additional information on the Florida Plants and Plant Nacogdoches dispositions and sales of wind turbine equipment. See Notes 7 and 10 to the financial statements under "Southern Power " and "Legal Entity Reorganizations" for additional information on the tax equity partnerships and the legal entity reorganization, respectively. Also see Note 3 to the financial statements under "General Litigation -Southern Power " for additional information on the Roserock solar facility litigation settlement. II-43 -------------------------------------------------------------------------------- Table of Contents Index to Financial Statements
COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
A condensed statement of income follows:
Increase (Decrease) 2019 from 2018 (in millions) Operating revenues$ 1,938 $ (267 ) Fuel 577 (122 ) Purchased power 108 (68 ) Other operations and maintenance 359 (36 ) Depreciation and amortization 479 (14 ) Taxes other than income taxes 40 (6 ) Asset impairment 3 (153 ) Gain on disposition (23 ) (21 ) Total operating expenses 1,543 (420 ) Operating income 395 153 Interest expense, net of amounts capitalized 169 (14 ) Other income (expense), net 47 24 Income taxes (benefit) (56 ) 108 Net income 329 83
Net income (loss) attributable to noncontrolling interests (10 )
(69 ) Net income attributable to Southern Power$ 339 $
152
Operating Revenues Total operating revenues include PPA capacity revenues, which are derived primarily from long-term contracts involving natural gas facilities and a biomass generating facility (through the second quarter 2019 sale of PlantNacogdoches ), and PPA energy revenues fromSouthern Power's generation facilities. To the extentSouthern 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 theFERC -approved IIC, it may sell power intothe Southern Company power pool. Natural Gas and Biomass 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 ofSouthern Power's customers and their generation capacity, as well as the market prices of wholesale energy compared to the cost ofSouthern 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 RevenueSouthern 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" herein for additional information regardingSouthern Power's PPAs. II-44 -------------------------------------------------------------------------------- Table of Contents Index to Financial Statements
COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Operating Revenues Details Details ofSouthern Power's operating revenues were as follows: 2019 2018 (in millions) PPA capacity revenues$ 482 $ 580 PPA energy revenues 1,081 1,140 Total PPA revenues 1,563 1,720 Non-PPA revenues 363 472 Other revenues 12 13
Total operating revenues
Operating revenues for 2019 were$1.9 billion , a$267 million , or 12%, decrease from 2018. The decrease in operating revenues was primarily due to the following: • PPA capacity revenues decreased$98 million , or 17%, primarily due to the
sales of the Florida Plants in
2019. In addition, the change reflects a reduction of
expiration of an affiliate natural gas PPA, offset by a
in new PPA capacity revenues from existing natural gas facilities, of which
• PPA energy revenues decreased
million decrease in sales from natural gas facilities primarily driven by a
partially offset by a
increased customer load.
• Non-PPA revenues decreased
million decrease in the volume of KWHs sold through short-term sales and a
million decrease in the market price of energy.
Fuel and Purchased Power Expenses Details ofSouthern Power's generation and purchased power were as follows: Total Total KWH Total KWHs % Change KWHs 2019 2018 (in billions of KWHs) Generation 47 46 Purchased power 3 4 Total generation and purchased power 50 -%
50
Total generation and purchased power, excluding solar, wind, and tolling agreements 29 -%
29
Southern Power's PPAs for natural gas generation generally provide that the purchasers are responsible for either procuring the fuel (tolling agreements) or reimbursingSouthern 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 intothe Southern Company power pool for capacity owned directly bySouthern Power . Purchased power expenses will vary depending on demand, availability, and the cost of generating resources throughoutthe Southern Company system and other contract resources. Load requirements are submitted tothe Southern Company power pool on an hourly basis and are fulfilled with the lowest cost alternative, whether that is generation owned bySouthern Power , an affiliate company, or external parties. Such purchased power costs are generally recovered through PPA revenues. II-45 -------------------------------------------------------------------------------- Table of Contents Index to Financial Statements
COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Details ofSouthern Power's fuel and purchased power expenses were as follows: 2019 2018 (in millions) Fuel$ 577 $ 699 Purchased power 108 176
Total fuel and purchased power expenses
In 2019, total fuel and purchased power expenses decreased$190 million , or 22%, compared to 2018. Fuel expense decreased$122 million , or 17%, due to a$137 million decrease in the average cost of fuel per KWH generated, partially offset by a$15 million increase associated with the volume of KWHs generated. Purchased power expense decreased$68 million , or 39%, due to a$37 million decrease associated with the average cost of purchased power and a$31 million decrease associated with the volume of KWHs purchased. Other Operations and Maintenance Expenses In 2019, other operations and maintenance expenses decreased$36 million , or 9%, compared to 2018. The decrease was due to gains totaling$17 million on the sale of wind turbine equipment, decreased expense of$17 million related to the dispositions of the Florida Plants and Plant Nacogdoches, and the recovery of$5 million in legal costs related to the Roserock solar facility litigation settlement in the first quarter 2019. See Note 15 to the financial statements under "Southern Power - Development Projects" and " - Sales of Natural Gas and Biomass Plants" for additional information on the sale of wind turbine equipment and the dispositions, respectively. Also see Note 3 to the financial statements under "General Litigation Matters -Southern Power " for additional information on the litigation settlement. Asset Impairment Asset impairment charges totaling$156 million were recorded in 2018, including$119 million related to the sale of the Florida Plants and$36 million related to wind turbine equipment held for development projects. Asset impairment charges in 2019 were immaterial. See Note 15 to the financial statements under "Southern Power - Sales of Natural Gas and Biomass Plants" and " - Development Projects" for additional information. Gain on Dispositions, Net The sale of Plant Nacogdoches in 2019 resulted in a$23 million gain. See Note 15 to the financial statements under "Southern Power - Sales of Natural Gas and Biomass Plants" for additional information. Interest Expense, Net of Amounts Capitalized In 2019, interest expense, net of amounts capitalized decreased$14 million , or 8%, compared to 2018, primarily due to a decrease in the amount of outstanding debt. Other Income (Expense), Net In 2019, other income (expense), net increased$24 million , or 104%, compared to 2018 primarily due to a$36 million gain arising from the Roserock solar facility litigation settlement in 2019, partially offset by a$14 million gain from a joint-development wind project in 2018 attributable toSouthern Power's partner in the project, which was offset by a$14 million loss within noncontrolling interests. See Note 3 to the financial statements under "Southern Power " for additional information regarding the litigation settlement. Income Taxes (Benefit) In 2019, income tax benefit was$56 million compared to$164 million for 2018, a decrease of$108 million , primarily attributable to reductions in tax benefits of$127 million from wind PTCs primarily following the 2018 sale of a noncontrolling tax equity interest in SP Wind and$65 million from changes in state apportionment rates following the 2018 reorganizations of certain legal entities, as well as a$64 million increase in income tax expense as a result of higher pre-tax earnings, partially offset by$79 million in tax expense recognized in 2018 related to the Tax Reform Legislation and a$75 million tax benefit resulting from the recognition of deferred ITCs remaining from the original construction recognized in connection with the sale of PlantNacogdoches . II-46 -------------------------------------------------------------------------------- Table of Contents Index to Financial Statements
COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
See FUTURE EARNINGS POTENTIAL - "Income Tax Matters - Federal Tax Reform Legislation" herein and Notes 1, 10, and 15 to the financial statements under "Income Taxes," "Effective Tax Rate," and "Southern Power ," respectively, for additional information. Net Income Attributable to Noncontrolling Interests In 2019, net income attributable to noncontrolling interests decreased$69 million , or 117%, compared to 2018. The decrease was primarily due to$92 million of losses attributable to noncontrolling interests related to the tax equity partnerships entered into in 2018 and$14 million attributable to a joint-development wind project in 2018, partially offset by an allocation of approximately$29 million of income to the noncontrolling interest partner related to the Roserock solar facility litigation settlement. See Note 3 to the financial statements under "General Litigation Matters -Southern Power " and Note 7 to the financial statements under "Southern Power " for additional information regarding the litigation settlement and tax equity partnerships, respectively.Southern Company Gas Operating MetricsSouthern Company Gas continues to focus on several operating metrics, including Heating Degree Days, customer count, and volumes of natural gas sold.Southern Company Gas measures weather and the effect on its business using Heating Degree Days. Generally, increased Heating Degree Days result in higher demand for natural gas onSouthern 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, includingNicor Gas following the approval of a revenue decoupling mechanism for residential customers in its recent rate case.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 inGeorgia andIllinois .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. Occasionally in the summer, wholesale gas services' operating revenues are 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 reviewingSouthern Company Gas' annual results. Thus,Southern Company Gas' operating results can vary significantly from quarter to quarter as a result of seasonality, which is illustrated in the table below. Percent Generated During Heating Season Net Operating Revenues Income 2019 68.7 % 86.8 % 2018 68.7 % 96.0 % Net Income Net income attributable toSouthern Company Gas in 2019 was$585 million , an increase of$213 million , or 57.3%, compared to the prior year. The change in net income includes a$125 million increase at wholesale gas services, an increase of$57 million in continued investment in infrastructure replacement programs and base rate changes at gas distribution operations, net of depreciation, a$34 million decrease in income taxes primarily atAtlanta Gas Light due to increased flowback of excess deferred income taxes in lieu of a rate increase as previously authorized by the Georgia PSC, and an$11 million increase in earnings from equity method investments in 2019. This increase also includes a$51 million net loss in 2018 from theSouthern Company Gas II-47 -------------------------------------------------------------------------------- Table of Contents Index to Financial Statements
COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Dispositions (including the goodwill impairment charge) and$21 million in disposition-related costs in 2018, partially offset by$86 million in after-tax impairment charges in 2019. See Notes 3 and 15 to the financial statements under "Other Matters -Southern Company Gas " and "Southern Company Gas - Proposed Sale of Pivotal LNG and Atlantic Coast Pipeline," respectively, for additional information on the impairment charges. See Note 2 to the financial statements under "Southern Company Gas - Rate Proceedings -Nicor Gas " and " -Atlanta Gas Light " for additional information on the impacts of the Tax Reform Legislation. Also see FUTURE EARNINGS POTENTIAL - "Income Tax Matters" herein and Notes 10 and 15 to the financial statements for additional information. A condensed income statement forSouthern Company Gas follows: Increase (Decrease) 2019 from 2018 (in millions) Operating revenues$ 3,792 $ (117 ) Cost of natural gas 1,319 (220 ) Cost of other sales - (12 ) Other operations and maintenance 888 (93 ) Depreciation and amortization 487 (13 ) Taxes other than income taxes 213 2 Impairment charges 115 73 (Gain) loss on dispositions, net - 291 Total operating expenses 3,022 28 Operating income 770 (145 ) Earnings from equity method investments 157 9 Interest expense, net of amounts capitalized 232 4 Other income (expense), net 20 19 Earnings before income taxes 715 (121 ) Income taxes 130 (334 ) Net Income$ 585 $ 213
The Southern Company Gas Dispositions were completed by
II-48 -------------------------------------------------------------------------------- Table of Contents Index to Financial Statements
COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Operating Revenues Operating revenues in 2019 were$3.8 billion , a$117 million decrease, compared to 2018. Details of operating revenues were as follows: 2019 (in millions) Operating revenues - prior year$ 3,909 Estimated change resulting from - Infrastructure replacement programs and base rate changes 96 Gas costs and other cost recovery (89 ) Wholesale gas services 150 Southern Company Gas Dispositions(*) (300 ) Other 26 Operating revenues - current year$ 3,792 Percent change (3.0 )%
(*) Includes a
alternative revenue programs, and a
revenues. See Note 15 to the financial statements under "
Gas" for additional information.
Revenues from infrastructure replacement programs and base rate changes increased in 2019 compared to the prior year primarily due to increases of$74 million atNicor Gas and$16 million atAtlanta Gas Light . These amounts include gas distribution operations' continued investments recovered through infrastructure replacement programs and base rate increases as well as customer refunds in 2018 as a result of the Tax Reform Legislation. See Note 2 to the financial statements under "Southern Company Gas " for additional information. Revenues associated with gas costs and other cost recovery decreased in 2019 compared to the prior year primarily due to lower natural gas prices and decreased volumes of natural gas sold. 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. See "Cost of Natural Gas" herein for additional information. Revenues from wholesale gas services increased in 2019 primarily due to derivative gains, partially offset by decreased commercial activity. See "Segment Information - Wholesale Gas Services" herein for additional information. Other revenues increased in 2019 primarily due to increases in customers at gas distribution operations and recovery of prior period hedge losses at gas marketing services. Heating Degree Days During Heating Season, natural gas usage and operating revenues are generally higher. Weather typically does not have a significant net income impact other than during the Heating Season. The following table presents the Heating Degree Days information forIllinois andGeorgia , the primary locations whereSouthern Company Gas' operations are impacted by weather. Years Ended December 31, 2019 vs. normal 2019 vs. 2018 Normal(a) 2019 2018 colder (warmer) colder (warmer) (in thousands) Illinois(b) 5,782 6,136 6,101 6.1 % 0.6 % Georgia 2,529 2,157 2,588 (14.7 )% (16.7 )%
(a) Normal represents the 10-year average from
31, 2018 for
at
obtained from the
(b) Heating Degree Days in
impact in future years. On
volume balancing adjustment, a revenue decoupling mechanism for residential
customers that provides a monthly benchmark level of revenue per rate class
for recovery. II-49
-------------------------------------------------------------------------------- Table of Contents Index to Financial Statements
COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company Gas hedged its exposure to warmer-than-normal weather inIllinois for gas distribution operations and inIllinois andGeorgia for gas marketing services. The remaining impacts of weather on earnings were immaterial. Customer Count The following table provides the number of customers served bySouthern Company Gas atDecember 31, 2019 and 2018: 2019 2018 (in thousands, except market share %) Gas distribution operations 4,277 4,248 Gas marketing services Energy customers(*) 631 697 Market share of energy customers in Georgia 28.9 % 29.0 %
(*) Gas marketing services' customers are primarily located in
customers in
12 months beginning
Southern Company Gas anticipates overall customer growth trends in gas distribution operations to continue as it expects continued improvement in the new housing market and low natural gas prices.Southern Company Gas uses a variety of targeted marketing programs to attract new customers and to retain existing customers. Cost of Natural Gas ExcludingAtlanta Gas Light , which does not sell natural gas to end-use customers, gas distribution operations charges its utility customers for natural gas consumed using natural gas cost recovery mechanisms set by the applicable state regulatory agencies. Under these mechanisms, all prudently-incurred natural gas costs are passed through to customers without markup, subject to regulatory review. Gas distribution operations defers or accrues the difference between the actual cost of natural gas and the amount of commodity revenue earned in a given period. The deferred or accrued amount is either billed or refunded to customers prospectively through adjustments to the commodity rate. Deferred natural gas costs are reflected as regulatory assets and accrued natural gas costs are reflected as regulatory liabilities. Therefore, gas costs recovered through natural gas revenues generally equal the amount expensed in cost of natural gas and do not affect net income from gas distribution operations. Cost of natural gas at gas distribution operations represented 84.5% of the total cost of natural gas for 2019. Gas marketing services customers are charged for actual and estimated natural gas consumed. Cost of natural gas includes the cost of fuel and associated transportation costs, lost and unaccounted for gas, adjustments to reduce the value of inventories to market value, if applicable, and gains and losses associated with certain derivatives. In 2019, cost of natural gas was$1.3 billion , a decrease of$220 million , or 14.3%, compared to the prior year. Excluding a$106 million decrease related to the Southern Company Gas Dispositions, cost of natural gas decreased by$114 million , which reflects a 14.8% decrease in natural gas prices compared to 2018. II-50 -------------------------------------------------------------------------------- Table of Contents Index to Financial Statements
COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Volumes of Natural Gas Sold The following table details the volumes of natural gas sold during all periods presented. 2019 vs. 2018 2019 2018 % Change Gas distribution operations (mmBtu in millions) Firm 677 721 (6.1 )% Interruptible 92 95 (3.2 )% Total(*) 769 816 (5.8 )% Wholesale gas services (mmBtu in millions/day) Daily physical sales 6.4 6.7 (4.5
)%
Gas marketing services (mmBtu in millions) Firm: Georgia 33 37 (10.8 )% Illinois 12 13 (7.7 )% Other 15 20 (25.0 )% Interruptible large commercial and industrial 14 14 - % Total 74 84 (11.9 )%
(*) Includes total volumes of natural gas sold of 38 mmBtu for 2018 related to
2018. See Note 15 to the financial statements under "
Sale of
for additional information.
Cost of Other Sales Cost of other sales related to Pivotal Home Solutions, which was sold onJune 4, 2018 . See Note 15 to the financial statements under "Southern Company Gas - Sale of Pivotal Home Solutions" for additional information. Other Operations and Maintenance Expenses In 2019, other operations and maintenance expenses decreased$93 million , or 9.5%, compared to the prior year. Excluding a$65 million decrease related to the Southern Company Gas Dispositions, other operations and maintenance expenses decreased$28 million . This decrease was primarily due to$28 million of disposition-related costs incurred during 2018, a$12 million adjustment in 2018 for the adoption of a new paid time off policy, an$11 million expense for a litigation settlement to facilitate the sale of Pivotal Home Solutions in 2018, and a$7 million decrease in compensation and benefits costs, partially offset by a$22 million increase in rider expenses, primarily atNicor Gas , passed through directly to customers. See FUTURE EARNINGS POTENTIAL - "Southern Company Gas - Utility Regulation and Rate Design" herein for additional information. Depreciation and Amortization In 2019, depreciation and amortization decreased$13 million , or 2.6%, compared to the prior year. Excluding a$27 million decrease related to the Southern Company Gas Dispositions, depreciation and amortization increased$14 million . This increase was primarily due to continued infrastructure investments at gas distribution operations, partially offset by accelerated depreciation related to assets retired in 2018. See Note 2 to the financial statements under "Southern Company Gas - Infrastructure Replacement Programs and Capital Projects" for additional information. Impairment Charges In 2019,Southern Company Gas recorded impairment charges of$91 million related to a natural gas storage facility inLouisiana and$24 million in contemplation of the sale of its interests in Pivotal LNG and Atlantic Coast Pipeline. In 2018, a goodwill impairment charge of$42 million was recorded in contemplation of the sale of Pivotal Home Solutions. See Notes 1, 3, and 15 to the financial statements under "Goodwill and Other Intangible Assets and Liabilities," "Other Matters -Southern Company Gas ," and "Southern Company Gas ," respectively, for additional information. II-51 -------------------------------------------------------------------------------- Table of Contents Index to Financial Statements
COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
(Gain) Loss on Dispositions, Net In 2018, gain on dispositions, net was$291 million and was associated with the Southern Company Gas Dispositions. The income tax expense on these gains included income tax expense on goodwill not deductible for tax purposes and for which a deferred tax liability had not been recorded previously. Earnings from Equity Method Investments In 2019, earnings from equity method investments increased$9 million , or 6.1%, compared to the prior year and reflect higher earnings from SNG as a result of rate increases that became effectiveSeptember 2018 , partially offset by a$6 million pre-tax loss on the sale of Triton inMay 2019 . See Note 7 to the financial statements under "Southern Company Gas " for additional information. Other Income (Expense), Net In 2019, other income (expense), net increased$19 million compared to the prior year. This increase primarily resulted from a$23 million decrease in charitable donations in 2019. Income Taxes In 2019, income taxes decreased$334 million , or 72.0%, compared to the prior year. This decrease primarily reflects a reduction of$348 million related to the Southern Company Gas Dispositions, as well as$29 million in benefits associated with impairment charges in 2019 and additional benefits from the flowback of excess deferred income taxes in 2019 primarily atAtlanta Gas Light as previously authorized by the Georgia PSC, partially offset by$48 million of additional taxes associated with increased pre-tax earnings at wholesale gas services. See FUTURE EARNINGS POTENTIAL - "Income Tax Matters" herein and Note 10 to the financial statements for additional information. Also see Notes 2, 3, and 15 to the financial statements under "Southern Company Gas ," "Other Matters -Southern Company Gas ," and "Southern Company Gas - Proposed Sale of Pivotal LNG and Atlantic Coast Pipeline," respectively, for additional information onAtlanta Gas Light's regulatory treatment of the impacts of the Tax Reform Legislation and the impairment charges. Performance and Non-GAAP Measures Adjusted operating margin is a non-GAAP measure that is calculated as operating revenues less cost of natural gas, cost of other sales, and revenue tax expense. Adjusted operating margin excludes other operations and maintenance expenses, depreciation and amortization, taxes other than income taxes, impairment charges, and gain (loss) on dispositions, net, which are included in the calculation of operating income as calculated in accordance with GAAP and reflected in the statements of income. The presentation of adjusted operating margin is believed to provide useful information regarding the contribution resulting from base rate changes, infrastructure replacement programs and capital projects, and customer growth at gas distribution operations since the cost of natural gas and revenue tax expense can vary significantly and are generally billed directly to customers.Southern Company Gas further believes that utilizing adjusted operating margin at gas pipeline investments, wholesale gas services, and gas marketing services allows it to focus on a direct measure of performance before overhead costs. The applicable reconciliation of operating income to adjusted operating margin is provided herein. Adjusted operating margin should not be considered an alternative to, or a more meaningful indicator of,Southern Company Gas' operating performance than operating income as determined in accordance with GAAP. In addition,Southern Company Gas' adjusted operating margin may not be comparable to similarly titled measures of other companies. Detailed variance explanations ofSouthern Company Gas' financial performance are provided herein. II-52 -------------------------------------------------------------------------------- Table of Contents Index to Financial Statements
COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Reconciliations of operating income to adjusted operating margin are as follows:
2019 2018 (in millions) Operating Income$ 770 $ 915 Other operating expenses(a) 1,703 1,443 Revenue taxes(b) (114 ) (111 )
Adjusted Operating Margin
(a) Includes other operations and maintenance, depreciation and amortization,
taxes other than income taxes, impairment charges, and gain (loss) on
dispositions, net.
(b)
customers. Segment Information 2019 2018 Adjusted Operating Operating Adjusted Operating Operating Expenses Margin(a) Expenses(a) Net Income (Loss) Margin(a) (a)(b) Net Income (Loss)(b) (in millions) (in millions) Gas distribution operations$ 1,799 $ 1,226 $ 337$ 1,794 $ 890 $ 334 Gas pipeline investments 32 12 94 32 12 103 Wholesale gas services 273 54 163 134 64 38 Gas marketing services 234 122 83 263 244 (40 ) All other 28 182 (92 ) 33 131 (63 ) Intercompany eliminations (7 ) (7 ) - (9 ) (9 ) - Consolidated$ 2,359 $ 1,589 $ 585$ 2,247 $ 1,332 $ 372
(a) Adjusted operating margin and operating expenses are adjusted for
revenue tax expenses, which are passed through directly to customers.
(b) Operating expenses for gas distribution operations and gas marketing services
include the gain on dispositions, net. Net income for gas distribution
operations and gas marketing services includes the gain on dispositions, net
and the associated income tax expense. See Note 15 to the financial
statements under "
Gas Distribution Operations Gas distribution operations is the largest component ofSouthern Company Gas' business and is subject to regulation and oversight by agencies in each of the states it serves. These agencies approve natural gas rates designed to provideSouthern 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 ofAtlanta 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 weather mechanisms, such as weather normalization mechanisms and weather derivative instruments, that limit its exposure to weather changes within typical ranges in its natural gas distribution utilities' service territories. InJuly 2018 , aSouthern Company Gas subsidiary,Pivotal Utility Holdings , completed the sales of the assets of two of its natural gas distribution utilities,Elizabethtown Gas andElkton Gas , to South Jersey Industries, Inc. Also inJuly 2018 ,Southern Company Gas and its wholly-owned direct subsidiary,NUI Corporation , completed the sale ofPivotal Utility Holdings , which primarily consisted ofFlorida City Gas , to NextEra Energy. See Note 15 to the financial statements under "Southern Company Gas " for additional information. II-53 -------------------------------------------------------------------------------- Table of Contents Index to Financial Statements
COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
The following table details the results of gas distribution operations including and excluding the impact of the utilities sold in 2018.
Variance Impacts of Excluding Utilities Sold in Utilities Sold in Favorable(unfavorable) 2019 vs 2018 2018 2018 (in millions) Adjusted Operating Margin $ 5 $ 138 $ 143 Operating expenses (336 ) 246 (90 ) Other income (expense), net (3 ) - (3 ) Interest expenses (9 ) (13 ) (22 ) Income tax expense 346 (315 ) 31 Net income $ 3 $ 56 $ 59 Excluding the impact of the utilities sold in 2018, net income in 2019 increased$59 million , or 21.2%, compared to the prior year. The$143 million increase in adjusted operating margin reflects additional revenue from base rate increases and continued investment recovered through infrastructure replacement programs, a decrease in refunds associated with bad debt riders, and the customer refunds in 2018 as a result of the Tax Reform Legislation. The$90 million increase in operating expenses includes increases in compensation and benefit costs and rider expenses passed through directly to customers, as well as additional depreciation primarily due to additional assets placed in service. The$3 million decrease in other income (expense), net is primarily due to a contractor litigation settlement in 2018. The$22 million increase in interest expense is primarily from the issuance of first mortgage bonds atNicor Gas . The$31 million decrease in income tax expense is primarily due to an increase in the flowback of excess deferred income taxes in 2019 primarily atAtlanta Gas Light . See Note 2 to the financial statements under "Southern Company Gas - Rate Proceedings -Atlanta Gas Light " and " - Infrastructure Replacement Programs and Capital Projects -Atlanta Gas Light - PRP" herein for additional information onAtlanta Gas Light's stipulation reflecting the impacts of the Tax Reform Legislation and the contractor litigation settlement, respectively. Gas Pipeline Investments Gas pipeline investments consists primarily of joint ventures in natural gas pipeline investments including SNG, Atlantic Coast Pipeline, PennEast Pipeline, and Dalton Pipeline. See Note 7 to the financial statements under "Southern Company Gas " for additional information. Net income in 2019 decreased$9 million , or 8.7%, compared to the prior year. This decrease primarily relates to an increase in tax expense due to changes in state apportionment rates, partially offset by higher earnings from SNG. Wholesale Gas Services Wholesale gas services is 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 has 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 increases, wholesale gas services is well positioned to capture significant value and generate stronger results. Operating expenses primarily reflect employee compensation and benefits. Net income in 2019 increased$125 million , or 328.9%, compared to the prior year. This increase primarily relates to a$139 million increase in adjusted operating margin, a$10 million decrease in operating expenses, and a$20 million increase in other income (expense), partially offset by a$48 million increase in income taxes. II-54 -------------------------------------------------------------------------------- Table of Contents Index to Financial Statements
COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Details of adjusted operating margin are provided in the table below.
2019
2018
(in
millions)
Commercial activity recognized$ 54 $ 254 Gain on storage derivatives 40
9
Gain (loss) on transportation and forward commodity derivatives
186 (119 ) LOCOM adjustments, net of current period recoveries (16 ) (7 ) Purchase accounting adjustments to fair value inventory and contracts 9 (3 ) Adjusted operating margin$ 273 $ 134 Change in Commercial Activity The commercial activity at wholesale gas services includes recognition of storage and transportation values that were generated in prior periods, which reflect the impact of prior period hedge gains and losses as associated physical transactions occur. The decrease in commercial activity in 2019 compared to the prior year was primarily due to significant natural gas price volatility that resulted from prolonged cold weather during 2018 coupled with low natural gas supply. 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 theU.S. The volatility of natural gas commodity prices has a significant impact onSouthern 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 2019 resulted in storage derivative gains. Transportation and forward commodity derivative gains in 2019 are primarily the result of narrowing transportation spreads due to supply constraints and increases in natural gas supply, which impacted forward prices at natural gas receipt and delivery points, primarily in the Northeast and Midwest regions. The natural gas that wholesale gas services purchases and injects into storage is accounted for at the LOCOM value utilizing gas daily or spot prices at the end of the year. See Note 1 to the financial statements under "Natural Gas for Sale" for additional information. Withdrawal Schedule and Physical Transportation Transactions The expected natural gas withdrawals from storage and expected offset to prior hedge losses/gains associated with the transportation portfolio of wholesale gas services are presented in the following table, along with the net operating revenues expected at the time of withdrawal from storage and the physical flow of natural gas between contracted transportation receipt and delivery points. Wholesale gas services' expected net operating revenues exclude storage and transportation demand charges, as well as other variable fuel, withdrawal, receipt, and delivery charges, and exclude estimated profit sharing under asset management agreements. Further, the amounts that are realizable in future periods are based on the inventory withdrawal schedule, planned physical flow of natural gas between the transportation receipt and delivery points, and forward natural gas prices atDecember 31, 2019 . A portion of wholesale gas services' storage inventory and transportation capacity is economically hedged with futures contracts, which results in the realization of substantially fixed net operating revenues. II-55 -------------------------------------------------------------------------------- Table of Contents Index to Financial Statements
COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Storage Withdrawal Physical Transportation Expected net operating Transactions - Expected Net Total storage(a) losses(b) Operating Gains(c) (in mmBtu in millions) (in millions) (in millions) 2020 61 $ 6 $ (119 ) 2021 and thereafter - - (67 ) Total at December 31, 2019 61 $ 6 $ (186 )
(a) At
gas withdrawals from storage was
(b) Represents expected operating losses from planned storage withdrawals
associated with existing inventory positions and could change as wholesale
gas services adjusts its daily injection and withdrawal plans in response to
changes in future market conditions and forward NYMEX price fluctuations.
(c) Represents the expected net gains during the periods in which the derivatives
will be settled and the physical transportation transactions will occur that
offset the derivative gains and losses previously recognized.
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. OnJune 4, 2018 ,Southern Company Gas completed the sale of Pivotal Home Solutions toAmerican Water Enterprises LLC . See Note 15 under "Southern Company Gas - Sale of Pivotal Home Solutions" for additional information. Net income increased$123 million in 2019 compared to the prior year. This increase primarily relates to a$122 million decrease in operating expenses and a$27 million decrease in income tax expense, partially offset by a$29 million decrease in adjusted operating margin. Excluding a$43 million decrease attributable to the 2018 disposition of Pivotal Home Solutions, adjusted operating margin increased$14 million , which primarily reflects favorable margins and recovery of prior period hedge losses. Excluding a$116 million decrease attributable to the 2018 disposition of Pivotal Home Solutions that includes the related goodwill impairment charge, operating expense decreased$6 million due to lower amortization of intangible assets. Excluding a$33 million decrease attributable to the 2018 disposition of Pivotal Home Solutions, income tax expense increased$6 million primarily due to higher pre-tax earnings. All Other All other includesSouthern Company Gas' storage and fuels operations and its investment in Triton through completion of its sale onMay 29, 2019 ,AGL Services Company , andSouthern 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. Net loss increased$29 million , or 46.0%, in 2019 compared to the prior year. This increase primarily reflects a$51 million increase in operating expenses, partially offset by a$39 million decrease in income taxes. The increase in operating expenses primarily reflects a$91 million impairment charge related to a natural gas storage facility inLouisiana and a$24 million impairment charge in contemplation of the sale ofSouthern Company Gas' interests in Pivotal LNG and Atlantic Coast Pipeline, partially offset by a$12 million one-time adjustment in the first quarter 2018 for the adoption of a new paid time off policy,$28 million of disposition-related costs incurred during 2018, and a$14 million decrease in depreciation and amortization. The decrease in income taxes reflects a$29 million benefit due to the impairment charge, a$13 million benefit related to the reversal of a federal income tax valuation allowance in connection with the sale of Triton, the impact of deferred tax expenses related to the enactment of theState of Illinois income tax legislation in 2018, and changes in state income tax apportionment factors in several states during 2019. See Note 3 to the financial statements under "Other Matters -Southern Company Gas ," Note 10 to the financial statements, and Note 15 to the financial statements under "Southern Company Gas - Proposed Sale of Pivotal LNG and Atlantic Coast Pipeline" for additional information. Segment Reconciliations Reconciliations of operating income to adjusted operating margin for 2019 and 2018 are provided in the following tables. See Note 16 to the financial statements under "Southern Company Gas " for additional segment information. II-56 -------------------------------------------------------------------------------- Table of Contents Index to Financial Statements
COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
2019 Gas Distribution Gas Pipeline Wholesale Gas Gas Marketing Operations Investments Services Services All Other Intercompany Elimination Consolidated (in millions) Operating Income (Loss) $ 573 $ 20 $ 219 $ 112$ (154 ) $ - $
770
Other operating expenses(a) 1,340 12 54 122 182 (7 ) 1,703 Revenue tax expense(b) (114 ) - - - - - (114 ) Adjusted Operating Margin$ 1,799 $ 32 $ 273 $ 234$ 28 $ (7 )$ 2,359 2018 Gas Distribution Gas Pipeline Wholesale Gas Gas Marketing Operations Investments Services Services All Other Intercompany Elimination Consolidated (in millions) Operating Income (Loss) $ 904 $ 20 $ 70 $ 19$ (98 ) $ - $
915
Other operating expenses(a) 1,001 12 64 244 131 (9 ) 1,443 Revenue tax expense(b) (111 ) - - - - - (111 ) Adjusted Operating Margin$ 1,794 $ 32 $ 134 $ 263$ 33 $ (9 ) $
2,247
(a) Includes other operations and maintenance, depreciation and amortization,
taxes other than income taxes, impairment charges, and (gain) loss on
dispositions, net.
(b)
customers.
Effects of Inflation The traditional electric operating companies and the natural gas distribution utilities are subject to rate regulation that is generally based on the recovery of historical and projected costs. The effects of inflation can create an economic loss since the recovery of costs could be in dollars that have less purchasing power.Southern Power is party to long-term contracts reflecting market-based rates, including inflation expectations. Any adverse effect of inflation on the Registrants' results of operations has not been substantial in recent years. See Note 2 to the financial statements for additional information on rate regulation. FUTURE EARNINGS POTENTIAL General Prices for electric service provided by the traditional electric operating companies and natural gas distributed by the natural gas distribution utilities to retail customers are set by state PSCs or other applicable state regulatory agencies under cost-based regulatory principles. Retail rates and earnings are reviewed and may be adjusted periodically within certain limitations. Prices for wholesale electricity sales, interconnecting transmission lines, and the exchange of electric power are regulated by theFERC .Southern Power continues to focus on long-term PPAs. See ACCOUNTING POLICIES - "Application of Critical Accounting Policies and Estimates - Utility Regulation" herein and Note 2 to the financial statements for additional information about regulatory matters. Each Registrant's results of operations are not necessarily indicative of its future earnings potential. Recent disposition activities described under "Acquisitions and Dispositions" herein and in Note 15 to the financial statements will impact future earnings for the applicable Registrants. The level of the Registrants' future earnings depends on numerous factors that affect the opportunities, challenges, and risks of the Registrants' primary businesses of selling electricity and/or distributing natural gas, as described further herein. For the traditional electric operating companies, these factors include the ability to maintain constructive regulatory environments that allow for the timely recovery of prudently-incurred costs during a time of increasing costs, continued customer growth, and the trend of reduced electricity usage per customer, especially in residential and commercial markets. Other major factors include Plant Vogtle Units 3 and 4 construction and rate recovery related thereto forGeorgia Power and the ability to prevail against legal challenges associated with theKemper County energy facility forMississippi Power . II-57 -------------------------------------------------------------------------------- Table of Contents Index to Financial Statements
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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, increasing volumes of electronic commerce transactions, and, forGeorgia Power , more multi-family home construction, all of which could contribute to a net reduction in customer usage. The level of future earnings forSouthern Power's competitive wholesale electric business depends on numerous factors includingSouthern 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 inSouthern Power's market areas, andSouthern Power's ability to successfully remarket capacity as current contracts expire. In addition, renewable portfolio standards, transmission constraints, cost of generation from units withinthe Southern Company power pool, and operational limitations could influenceSouthern Power's future earnings. The level of future earnings forSouthern Company Gas' primary business of distributing natural gas and its complementary businesses in the gas pipeline investments, wholesale gas services, 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, andSouthern Company Gas' ability to optimize its transportation and storage positions and to re-contract storage rates at favorable prices. The volatility of natural gas prices has an impact onSouthern Company Gas' customer rates, its long-term competitive position against other energy sources, and the ability ofSouthern Company Gas' gas marketing services and wholesale gas services businesses to capture value from locational and seasonal spreads. Additionally, changes in commodity prices subject a portion ofSouthern Company Gas' operations to earnings variability. Over the longer term, volatility is expected to be low to moderate and locational and/or transportation spreads are expected to decrease as new pipelines are built to reduce the existing supply constraints in the shale areas of theNortheast U.S. To the extent these pipelines are further delayed or not built, volatility could increase. See "Construction Programs" herein for additional information on permitting challenges experienced by the Atlantic Coast Pipeline and the PennEast Pipeline. 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. Further, 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. 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, 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.Mississippi Power provides service under long-term contracts with rural electric cooperative associations and municipalities located in southeasternMississippi under cost-based electric tariffs which are subject to regulation by theFERC . The contracts with these wholesale customers represented 15.7% ofMississippi Power's total operating revenues in 2019 and are generally subject to 10-year rolling cancellation notices. Historically, these wholesale customers have acted as a group and any changes in contractual relationships for one customer are likely to be followed by the other wholesale customers. 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 ofSouthern Company . In addition,Southern Power andSouthern 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 "Acquisitions and Dispositions" herein and Note 15 to the financial statements for additional information. II-58 -------------------------------------------------------------------------------- Table of Contents Index to Financial Statements
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Acquisitions and Dispositions See Note 15 to the financial statements for additional information.Southern Company OnJanuary 1, 2019 ,Southern Company completed the sale ofGulf Power to NextEra Energy for an aggregate cash purchase price of approximately$5.8 billion (less$1.3 billion of indebtedness assumed), including the final working capital adjustments. The gain associated with the sale ofGulf Power totaled$2.6 billion pre-tax ($1.4 billion after tax). In 2018, net income attributable toGulf Power was$160 million .Alabama Power OnSeptember 6, 2019 ,Alabama Power entered into a purchase and sale agreement (Autauga Combined Cycle Acquisition) to acquire all of the equity interests inTenaska Alabama II Partners, L.P. Tenaska Alabama II Partners, L.P. owns and operates an approximately 885-MW combined cycle generation facility inAutauga County, Alabama . The transaction is expected to close bySeptember 1, 2020 . As part of the Autauga Combined Cycle Acquisition,Alabama Power will assume an existing power sales agreement under which the full output of the generating facility remains committed to another third party for its remaining term of approximately three years. The estimated revenues from the power sales agreement are expected to offset the associated costs of operation during the remaining term. The completion of the Autauga Combined Cycle Acquisition is subject to the satisfaction or waiver of certain conditions, including, among other customary conditions, approval by the Alabama PSC and theFERC .Alabama Power expects to obtain all regulatory approvals by the end of the third quarter 2020. The ultimate outcome of this matter cannot be determined at this time.Southern Power Acquisitions During 2019,Southern Power acquired a controlling interest in the fuel cell generation facility listed below and acquired the Skookumchuck wind facility discussed under "Construction Programs -Southern Power " herein. Acquisition-related costs were expensed as incurred and were not material. Approximate Southern Nameplate Power PPA Project Capacity Ownership PPA Remaining Facility Resource (MW) Location Percentage COD Counterparty Period Delmarva 100% of Power & DSGP(a) Fuel Cell 28 Delaware Class B N/A(b) Light 15 years
(a) During 2019,
million in DSGP and now holds a controlling interest and consolidates 100% of
DSGP's operating results.
noncontrolling interests for approximately 10 MWs of the facility.
(b)
partnership between the Class A member and
investment to repower the remaining 10 MWs. In connection with the Class C
member joining the partnership, the original fuel cells (before repower),
which had a carrying value of approximately
the Class A member in a non-cash transaction that was excluded from the
statements of cash flows.
Development ProjectsSouthern Power continues to evaluate and refine the deployment of the remaining wind turbine equipment purchased in 2016 and 2017 to development and construction projects. Wind projects utilizing equipment purchased in 2016 and 2017, and reaching commercial operation by the end of 2020 and 2021, are expected to qualify for 100% and 80% PTCs, respectively. The significant majority of this equipment either has been deployed to completed projects, projects under construction, or projects that are probable of being completed or has been sold to third parties. Sales during 2019 resulted in gains totaling approximately$17 million . Sales of Renewable Facility Interests InMay 2018 ,Southern Power completed the sale of a noncontrolling 33% equity interest in SP Solar, a limited partnership indirectly owning substantially all ofSouthern Power's solar facilities, to Global Atlantic for approximately$1.2 billion . SinceSouthern Power retained control of the limited partnership through its wholly-owned general partner, the sale was recorded as an II-59 -------------------------------------------------------------------------------- Table of Contents Index to Financial Statements
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equity transaction. Cash distributions from SP Solar are allocated 67% toSouthern Power and 33% to Global Atlantic in accordance with their partnership ownership interests. InDecember 2018 ,Southern Power completed the sale of a noncontrolling tax equity interest in SP Wind, which owns a portfolio of eight operating wind facilities, to three financial investors for approximately$1.2 billion . The tax equity investors together will generally receive 40% of the cash distributions from available cash and will receive 99% of the tax attributes, including future PTCs.Southern Power consolidates each entity, as the primary beneficiary of the VIE, since it controls the most significant activities, including operating and maintaining the assets. Sales of Natural Gas and Biomass Plants InDecember 2018 ,Southern Power completed the sale of all of its equity interests in the Florida Plants to NextEra Energy for$203 million , including working capital adjustments. In contemplation of this sale transaction,Southern Power recorded an asset impairment charge of approximately$119 million ($89 million after tax) inMay 2018 . Pre-tax net income for the Florida Plants was$49 million for the period fromJanuary 1, 2018 toDecember 4, 2018 . OnJune 13, 2019 ,Southern Power completed the sale of its equity interests in Plant Nacogdoches, a 115-MW biomass facility located inNacogdoches County, Texas , toAustin Energy , for a purchase price of approximately$461 million , including working capital adjustments.Southern Power recorded a gain of$23 million ($88 million after tax) on the sale. The pre-tax net income for PlantNacogdoches was$13 million and$27 million for the period fromJanuary 1, 2019 toJune 13, 2019 and for the year ended 2018, respectively. OnJanuary 17, 2020 ,Southern Power completed the sale of its equity interests in Plant Mankato (including the 385-MW expansion unit completed inMay 2019 ) to a subsidiary of Xcel for a purchase price of approximately$663 million , including estimated working capital adjustments. The sale resulted in a gain of approximately$39 million ($23 million after tax) in 2020. Pre-tax net income for Plant Mankato was$29 million and immaterial for the years endedDecember 31, 2019 and 2018, respectively. The assets and liabilities of Plant Mankato are classified as held for sale as ofDecember 31, 2019 and 2018.Southern Company Gas InJune 2018 ,Southern Company Gas completed the stock sale of Pivotal Home Solutions toAmerican Water Enterprises LLC .Southern Company Gas andAmerican Water Enterprises LLC entered into a transition services agreement wherebySouthern Company Gas provided certain administrative and operational services throughNovember 4, 2018 . InJuly 2018 , aSouthern Company Gas subsidiary,Pivotal Utility Holdings , completed the sales of the assets of two of its natural gas distribution utilities,Elizabethtown Gas andElkton Gas , to South Jersey Industries, Inc.Southern Company Gas and South Jersey Industries, Inc. entered into transition services agreements wherebySouthern Company Gas will provide certain administrative and operational services through no later thanJuly 31, 2020 . InJuly 2018 ,Southern Company Gas and its wholly-owned direct subsidiary,NUI Corporation , completed the stock sale ofPivotal Utility Holdings , which primarily consisted ofFlorida City Gas , to NextEra Energy.Southern Company Gas and NextEra Energy entered into a transition services agreement wherebySouthern Company Gas will provide certain administrative and operational services through no later thanJuly 29, 2020 . The Southern Company Gas Dispositions resulted in a net loss of$51 million in 2018, which includes$342 million of tax expense. The after-tax impacts of these dispositions included income tax expense on goodwill not deductible for tax purposes and for which a deferred tax liability had not been recorded previously. In addition, a goodwill impairment charge of$42 million was recorded during 2018 in contemplation of the sale of Pivotal Home Solutions. The Southern Company Gas Dispositions materially decreasedSouthern Company Gas' subsequent earnings and cash flows. For the year endedDecember 31, 2018 , pre-tax earnings attributable to these dispositions were$297 million , which includes a$291 million gain on dispositions, net and a$42 million goodwill impairment. Due to the seasonal nature of the natural gas business and other factors including, but not limited to, weather, regulation, competition, customer demand, and general economic conditions, these results are not necessarily indicative of the results to be expected for any other period. OnMay 29, 2019 ,Southern Company Gas sold its investment in Triton, a cargo container leasing company. This disposition resulted in a pre-tax loss of$6 million and a net after-tax gain of$7 million as a result of reversing a$13 million federal income tax valuation allowance. OnFebruary 7, 2020 ,Southern Company Gas entered into agreements withDominion Modular LNG Holdings, Inc. andDominion Atlantic Coast Pipeline, LLC for the sale of its interests in Pivotal LNG and Atlantic Coast Pipeline, respectively, for an II-60 -------------------------------------------------------------------------------- Table of Contents Index to Financial Statements
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aggregate purchase price of$165 million , including estimated working capital and timing adjustments.Southern Company Gas may also receive two payments of$5 million each, contingent upon certain milestones related to Pivotal LNG being met byDominion Modular LNG Holdings, Inc. after the completion of the sale. Based on the terms of these pending transactions,Southern Company Gas recorded an asset impairment charge, exclusive of the contingent payments, for Pivotal LNG of approximately$24 million ($17 million after tax) as ofDecember 31, 2019 . The completion of each transaction is subject to the satisfaction or waiver of certain conditions, including, among other customary closing conditions, the completion of the other transaction and, for the sale of the interest in Atlantic Coast Pipeline, the expiration or termination of any applicable waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976. The transactions are expected to be completed in the first half of 2020; however, the ultimate outcome cannot be determined at this time. The assets and liabilities of Pivotal LNG and the interest inAtlantic Coast Pipeline are classified as held for sale as ofDecember 31, 2019 . See Notes 3, 7, and 15 to the financial statements under "Southern Company Gas - Gas Pipeline Projects," "Southern Company Gas - Equity Method Investments," and "Southern Company Gas - Proposed Sale of Pivotal LNG and Atlantic Coast Pipeline," respectively, for additional information. Environmental MattersThe Southern Company system's operations are regulated by state and federal environmental agencies through a variety of laws and regulations governing air, water, land, and other natural resources.The Southern Company system maintains comprehensive environmental compliance and GHG strategies to assess both current and upcoming requirements and compliance costs associated with these environmental laws and regulations. The costs required to comply with environmental laws and regulations and to achieve stated goals, including capital expenditures, operations and maintenance costs, and costs reflected in ARO liabilities, may impact future electric generating unit retirement and replacement decisions, results of operations, cash flows, and/or financial condition. Related costs may result from the installation of additional environmental controls, closure and monitoring of CCR facilities, unit retirements, or changing fuel sources for certain existing units, as well as related upgrades tothe Southern Company system's transmission and distribution (electric and natural gas) systems. A major portion of these costs is expected to be recovered through retail and wholesale rates, including existing ratemaking and billing provisions. The ultimate impact of environmental laws and regulations and the GHG goals discussed herein will depend on various factors, such as state adoption and implementation of requirements, the availability and cost of any deployed technology, fuel prices, and the outcome of pending and/or future legal challenges. New or revised environmental laws and regulations could affect many areas of operations for the Subsidiary Registrants. The impact of any such changes cannot be determined at this time. Environmental compliance costs could affect earnings if such costs cannot continue to be recovered on a timely basis in rates for the traditional electric operating companies and the natural gas distribution utilities or through long-term wholesale agreements for the traditional electric operating companies andSouthern Power .Alabama Power andMississippi Power recover environmental compliance costs through separate mechanisms, Rate CNP Compliance and the ECO Plan, respectively.Georgia Power's base rates include an Environmental Compliance Cost Recovery (ECCR) tariff that allows for the recovery of environmental compliance costs. The natural gas distribution utilities ofSouthern Company Gas generally recover environmental remediation expenditures through rate mechanisms approved by their applicable state regulatory agencies. See Notes 2 and 3 to the financial statements for additional information.Southern Power's PPAs generally contain provisions that permit charging the counterparty with some of the new costs incurred as a result of changes in environmental laws and regulations. SinceSouthern Power's units are newer natural gas and renewable generating facilities, costs associated with environmental compliance for these facilities have been less significant than for similarly situated coal or older natural gas generating facilities. Environmental, natural resource, and land use concerns, including the applicability of air quality limitations, the potential presence of wetlands or threatened and endangered species, the availability of water withdrawal rights, uncertainties regarding impacts such as increased light or noise, and concerns about potential adverse health impacts can, however, increase the cost of siting and operating any type of future electric generating facility. The impact of such laws, regulations, and other considerations onSouthern Power and subsequent recovery through PPA provisions cannot be determined at this time. Further, increased costs that are recovered through regulated rates could contribute to reduced demand for electricity and natural gas, which could negatively affect results of operations, cash flows, and/or financial condition. Additionally, many commercial and industrial customers may also be affected by existing and future environmental requirements, which for some may have the potential to affect their demand for electricity and natural gas. Although the timing, requirements, and estimated costs could change as environmental laws and regulations are adopted or modified, as compliance plans are revised or updated, and as legal challenges to rules are initiated or completed, estimated capital II-61 -------------------------------------------------------------------------------- Table of Contents Index to Financial Statements
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expenditures through 2024 based on the current environmental compliance strategy forthe Southern Company system and the traditional electric operating companies are as follows: 2020 2021 2022 2023 2024 Total (in millions)
These estimates do not include any costs associated with potential regulation of GHG emissions. See "Global Climate Issues" herein for additional information.The Southern Company system also anticipates substantial expenditures associated with ash pond closure and ground water monitoring under the CCR Rule and related state rules, which are reflected in the applicable Registrants' ARO liabilities. See FINANCIAL CONDITION AND LIQUIDITY - "Capital Requirements" herein and Note 6 to the financial statements for additional information. Environmental Laws and Regulations Air QualityThe Southern Company system reduced SO2 and NOX air emissions by 98% and 88%, respectively, from 1990 to 2018.The Southern Company system reduced mercury air emissions by over 96% from 2005 to 2018. TheEPA finalized regional haze regulations in 2005 and 2017. These regulations require states, tribal governments, and various federal agencies to develop and implement plans to reduce pollutants that impair visibility and demonstrate reasonable progress toward the goal of restoring natural visibility conditions in certain areas, including national parks and wilderness areas. States are required to submit state implementation plans for the second ten-year planning period (2018 through 2028) byJuly 31, 2021 . These plans could require further reductions in particulate matter, SO2, and/or NOX, which could result in increased compliance costs at affected electric generating units. Water Quality In 2014, theEPA finalized requirements under Section 316(b) of the Clean Water Act (CWA) to regulate cooling water intake structures (CWIS) to minimize their effects on fish and other aquatic life at existing power plants. The regulation requires plant-specific studies to determine applicable CWIS changes to protect organisms.The Southern Company system is conducting these studies and currently anticipates applicable CWIS changes may include fish-friendly CWIS screens with fish return systems and minor additions of monitoring equipment at certain plants. The impact of this rule will depend on the outcome of these plant-specific studies, any additional protective measures required to be incorporated into each plant's National Pollutant Discharge Elimination System (NPDES) permit based on site-specific factors, and the outcome of any legal challenges. In 2015, theEPA finalized the steam electric effluent limitations guidelines (ELG) rule (2015 ELG Rule) that set national standards for wastewater discharges from new and existing steam electric generating units generating greater than 50 MWs. The 2015 ELG Rule prohibits effluent discharges of certain waste streams and imposes stringent limits on flue gas desulfurization (scrubber) wastewater discharges. The 2015 technology-based limits and the CCR Rule require extensive changes to existing ash and wastewater management systems or the installation and operation of new ash and wastewater management systems. Compliance with the 2015 ELG Rule is expected to require capital expenditures and increased operational costs for the traditional electric operating companies' coal-fired electric generation. State environmental agencies will incorporate specific compliance applicability dates in the NPDES permitting process for each ELG waste stream. OnNovember 22, 2019 , theEPA published a proposed rule that changes certain requirements in the 2015 ELG Rule, including adjusting compliance limits and providing certain exemptions for boilers that are expected to be retired byDecember 31, 2028 and for low utilization boilers (876,000 MWh/year or less). The proposal also extends the latest applicability date for flue gas desulfurization wastewater toDecember 31, 2025 but retains the latest applicability date ofDecember 31, 2023 for bottom ash transport water. The impact of any changes to the 2015 ELG Rule will depend on the content of a new final rule, which theEPA plans to finalize byAugust 2020 , and the outcome of any legal challenges. Coal Combustion Residuals In 2015, theEPA finalized non-hazardous solid waste regulations for the disposal of CCR, including coal ash and gypsum, in landfills and surface impoundments (ash ponds) at active electric generating power plants. The CCR Rule requires landfills and II-62 -------------------------------------------------------------------------------- Table of Contents Index to Financial Statements
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ash ponds to be evaluated against a set of performance criteria and potentially closed if certain criteria are not met. Closure of existing landfills and ash ponds requires installation of equipment and infrastructure to manage CCR in accordance with the CCR Rule. In addition to the CCR Rule, the States ofAlabama andGeorgia finalized state regulations regarding the handling of CCR within their respective states. TheState of Georgia received approval from theEPA on its partial permit program implementing the state CCR permit program in lieu of the federal self-implementing rule in accordance with the Water Infrastructure Improvements for the Nation Act. TheState of Alabama also submitted its state CCR program for theEPA 's review and approval. TheState of Mississippi has not yet developed a state CCR permit program. TheEPA is in the process of amending portions of the CCR Rule. Most recently, onDecember 2, 2019 , theEPA published a proposed rule that would require facilities to cease placement of both CCR and non-CCR waste in unlined surface impoundments as soon as technically feasible, no later thanAugust 31, 2020 . This proposed rule also includes extensions beyondAugust 31, 2020 , provided that certain conditions are met. Impacts of the proposed rule tothe Southern Company system are expected to be limited, as the traditional electric operating companies and SEGCO stopped sending coal ash from most of the generating units to unlined ponds inApril 2019 and expect to stop sending coal ash from the remaining generating units within the timeframes and associated extensions allowed in the proposed rule. Based on cost estimates for closure and monitoring of landfills and ash ponds pursuant to the CCR Rule,the Southern Company system recorded/revised AROs for each CCR unit in 2015 and has continued to update these cost estimates and ARO liabilities in subsequent years. The traditional electric operating companies expect to continue updating these estimates periodically as additional information related to ash pond closure methodologies, schedules, and/or costs becomes available.Alabama Power anticipates increasing the ARO for one of its ash ponds within the next nine months upon completion of a feasibility study and the related cost estimate, and the increase could be material. Additionally, the closure designs and plans in the States ofAlabama andGeorgia 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 forSouthern Company and the traditional electric operating companies could be materially impacted. See FINANCIAL CONDITION AND LIQUIDITY - "Capital Requirements" and FUTURE EARNINGS POTENTIAL - "Regulatory Matters -Georgia Power - Integrated Resource Plan" herein and Note 6 to the financial statements for additional information. The ultimate outcome of these matters cannot be determined at this time. Environmental RemediationThe Southern Company system must comply with environmental laws and regulations governing the handling and disposal of waste and releases of hazardous substances. Under these various laws and regulations,the Southern Company system could incur substantial costs to clean up affected sites. The traditional electric operating companies andSouthern Company Gas conduct studies to determine the extent of any required cleanup and have recognized the estimated costs to clean up known impacted sites in their financial statements. Amounts for cleanup and ongoing monitoring costs were not material for any year presented. The traditional electric operating companies and the natural gas distribution utilities inIllinois andGeorgia (which represent substantially all ofSouthern Company Gas' accrued remediation costs) have all received authority from their respective state PSCs or other applicable state regulatory agencies to recover approved environmental compliance costs through regulatory mechanisms. These regulatory mechanisms are adjusted annually or as necessary within limits approved by the state PSCs or other applicable state regulatory agencies. The traditional electric operating companies andSouthern Company Gas may be liable for some or all required cleanup costs for additional sites that may require environmental remediation. See Note 3 to the financial statements under "Environmental Remediation" for additional information. Global Climate Issues OnJuly 8, 2019 , theEPA published the final Affordable Clean Energy rule (ACE Rule) to repeal and replace the CPP. The ACE Rule requires states to develop unit-specific CO2 emission rate standards for existing coal-fired units based on heat-rate efficiency improvements. The ACE Rule is being challenged in theD.C. Circuit Court of Appeals andGeorgia Power is an intervenor in the litigation in support of the rule, as are other industry parties. The ultimate impact of the ACE Rule tothe Southern Company system will depend on state implementation plan requirements and the outcome of associated legal challenges and cannot be determined at this time. Additional GHG policies, including legislation, may emerge in the future requiringthe United States to transition to a lower GHG emitting economy; however, associated impacts are currently unknown.The Southern Company system has transitioned from an electric generating mix of 70% coal and 15% natural gas in 2007 to a mix of 22% coal and 52% natural gas in 2019, along with over 8,300 MWs of renewable resources. This transition has been supported in part bythe Southern Company system retiring over 5,600 MWs of coal- and oil-fired generating capacity since 2010 and converting over 3,400 MWs of generating capacity from coal to natural gas since 2015. In addition,Southern Company Gas has replaced approximately 5,600 miles of bare steel and II-63 -------------------------------------------------------------------------------- Table of Contents Index to Financial Statements
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cast-iron pipe, resulting in removal of approximately 2.5 million metric tons of GHG from its natural gas distribution system since 1998. The following table provides the Registrants' 2018 and preliminary 2019 GHG emissions based on ownership or financial control of facilities:
2018 Preliminary 2019 (in million metric tons of CO2 equivalent) Southern Company(a)(b) 102 88 Alabama Power 36 32 Georgia Power 30 27 Mississippi Power 8 9 Southern Power(b) 14 13 Southern Company Gas(b) 1 1
(a) Includes non-registrant subsidiaries.
(b) The 2018 and preliminary 2019 amounts include GHG emissions attributable to
disposed assets through the date of the applicable disposition. See Note 15
to the financial statements for additional information regarding disposition
activities.
Based on the preliminary 2019 amount above,the Southern Company system has achieved an estimated GHG emission reduction of 44% since 2007. InApril 2018 ,Southern Company established an intermediate goal of a 50% reduction in carbon emissions from 2007 levels by 2030 and a long-term goal of low- to no-carbon operations by 2050.The Southern Company system's ability to achieve these goals depends on many external factors, including supportive national energy policies, low natural gas prices, and the development, deployment, and advancement of relevant energy technologies.The Southern Company system expects to continue cost-effectively growing its renewable energy portfolio, optimizing technology advancements to modernize its transmission and distribution systems, increasing the use of natural gas for generation, completing Plant Vogtle Units 3 and 4, investing in energy efficiency, and continuing research and development efforts focused on technologies to lower GHG emissions.The Southern Company system is also evaluating methods of removing carbon from the atmosphere. Regulatory MattersAlabama Power Alabama Power's revenues from regulated retail operations are collected through various rate mechanisms subject to the oversight of the Alabama PSC.Alabama Power currently recovers its costs from the regulated retail business primarily through Rate RSE, Rate CNP, Rate ECR, and Rate NDR. In addition, the Alabama PSC issues accounting orders to address current events impactingAlabama Power . See Note 2 to the financial statements under "Alabama Power " for additional information regardingAlabama Power's rate mechanisms and accounting orders. Petition for Certificate of Convenience and Necessity OnSeptember 6, 2019 ,Alabama Power filed a petition for a CCN with theAlabama PSC for authorization to procure additional generating capacity through the turnkey construction of a new combined cycle facility and long-term contracts for the purchase of power from others, both as more fully described below, as well as the Autauga Combined Cycle Acquisition. In addition,Alabama Power will pursue approximately 200 MWs of certain demand side management and distributed energy resource programs. This filing was predicated on the results ofAlabama Power's 2019 IRP provided to the Alabama PSC, which identified an approximately 2,400-MW resource need forAlabama Power , driven by the need for additional winter reserve capacity. See Note 15 to the financial statements under "Alabama Power " for additional information regarding the Autauga Combined Cycle Acquisition. The procurement of these resources is subject to the satisfaction or waiver of certain conditions, including, among other customary conditions, approval by the Alabama PSC. The completion of the Autauga Combined Cycle Acquisition is also subject to approval by theFERC .Alabama Power expects to obtain all regulatory approvals by the end of the third quarter 2020. OnMay 8, 2019 ,Alabama Power entered into an Agreement for Engineering, Procurement, and Construction withMitsubishi Hitachi Power Systems Americas, Inc. andBlack & Veatch Construction, Inc. to construct an approximately 720-MW combined cycle facility at Plant Barry (Plant Barry Unit 8), which is expected to be placed in service by the end of 2023. II-64 -------------------------------------------------------------------------------- Table of Contents Index to Financial Statements
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The capital investment associated with the construction of Plant Barry Unit 8 and the Autauga Combined Cycle Acquisition is currently estimated to total approximately$1.1 billion .Alabama Power entered into additional long-term PPAs totaling approximately 640 MWs of generating capacity consisting of approximately 240 MWs of combined cycle generation expected to begin later in 2020 and approximately 400 MWs of solar generation coupled with battery energy storage systems (solar/battery systems) expected to begin in 2022 through 2024. The terms of the agreements for the solar/battery systems permitAlabama Power to use the energy and retire the associated renewable energy credits (REC) in service of customers or to sell RECs, separately or bundled with energy. Upon certification,Alabama Power expects to recover costs associated with Plant Barry Unit 8 pursuant to its Rate CNP New Plant. Additionally,Alabama Power expects to recover costs associated with the Autauga Combined Cycle Acquisition through the inclusion in Rate RSE of revenues from the existing power sales agreement and, on expiration of that agreement, pursuant to Rate CNP New Plant. The recovery of costs associated with laws, regulations, and other such mandates directed at the utility industry are expected to be recovered through Rate CNP Compliance.Alabama Power expects to recover the capacity-related costs associated with the PPAs through its Rate CNP PPA. In addition, fuel and energy-related costs are expected to be recovered through Rate ECR. Any remaining costs associated with the Autauga Combined Cycle Acquisition and Plant Barry Unit 8 will be incorporated through the annual filing of Rate RSE. The ultimate outcome of these matters cannot be determined at this time. Construction Work in Progress Accounting Order OnOctober 1, 2019 , the Alabama PSC acknowledged thatAlabama Power would begin certain limited preparatory activities associated with Plant Barry Unit 8 construction to meet the target in-service date by authorizingAlabama Power to record the related costs as CWIP prior to the issuance of an order on the CCN petition. Should a CCN not be granted andAlabama Power does not proceed with the related construction of Plant Barry Unit 8,Alabama Power may transfer those costs and any costs that directly result from the non-issuance of the CCN to a regulatory asset which would be amortized over a five-year period. If the balance of incurred costs reaches 5% of the estimated in-service cost of the total project prior to issuance of an order on the CCN petition,Alabama Power will confer with the Alabama PSC regarding the appropriateness of additional authorization. TheSierra Club subsequently filed a petition for reconsideration of the accounting order. The Alabama PSC voted to deny the petition for reconsideration onJanuary 7, 2020 . Rate RSE The Alabama PSC has adopted Rate RSE that provides for periodic annual adjustments based uponAlabama Power's projected weighted common equity return (WCER) compared to an allowable range. Rate RSE adjustments are based on forward-looking information for the applicable upcoming calendar year. Rate RSE adjustments for any two-year period, when averaged together, cannot exceed 4.0% and any annual adjustment is limited to 5.0%. When the projected WCER is under the allowed range, there is an adjusting point of 5.98% and eligibility for a performance-based adder of seven basis points, or 0.07%, to the WCER adjusting point ifAlabama Power (i) has an "A" credit rating equivalent with at least one of the recognized rating agencies or (ii) is in the top one-third of a designated customer value benchmark survey. IfAlabama Power's actual retail return is above the allowed WCER range, the excess will be refunded to customers unless otherwise directed by the Alabama PSC; however, there is no provision for additional customer billings should the actual retail return fall below the WCER range. Prior toJanuary 2019 , retail rates remained unchanged when the WCER range was between 5.75% and 6.21%. InMay 2018 , the Alabama PSC approved modifications to Rate RSE and other commitments designed to positionAlabama Power to address the growing pressure on its credit quality resulting from the Tax Reform Legislation, without increasing retail rates under Rate RSE in the near term.Alabama Power plans to reduce growth in total debt by increasing equity, with corresponding reductions in debt issuances, thereby de-leveraging its capital structure.Alabama Power's goal is to achieve an equity ratio of approximately 55% by the end of 2025. AtDecember 31, 2019 ,Alabama Power's equity ratio was approximately 50%. The approved modifications to Rate RSE began for billings inJanuary 2019 . The modifications include reducing the top of the allowed WCER range from 6.21% to 6.15% and modifications to the refund mechanism applicable to prior year actual results. The modifications to the refund mechanism allowAlabama Power to retain a portion of the revenue that causes the actual WCER for a given year to exceed the allowed range. Generally, during a year without a Rate RSE upward adjustment, ifAlabama Power's actual WCER is between 6.15% and 7.65%, customers will receive 25% of the amount between 6.15% and 6.65%, 40% of the amount between 6.65% and 7.15%, and 75% of the amount between 7.15% and 7.65%. Customers will receive all amounts in excess of an actual WCER of 7.65%. During a year II-65 -------------------------------------------------------------------------------- Table of Contents Index to Financial Statements
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with a Rate RSE upward adjustment, ifAlabama Power's actual WCER exceeds 6.15%, customers receive 50% of the amount between 6.15% and 6.90% and all amounts in excess of an actual WCER of 6.90%. In conjunction with these modifications to Rate RSE, inMay 2018 ,Alabama Power consented to a moratorium on any upward adjustments under Rate RSE for 2019 and 2020 and to return$50 million to customers through bill credits in 2019. OnNovember 27, 2019 ,Alabama Power made its required annual Rate RSE submission to the Alabama PSC of projected data for calendar year 2020. Projected earnings were within the specified range; therefore, retail rates under Rate RSE remain unchanged for 2020. During 2019,Alabama Power provided to the Alabama PSC and theAlabama Office of the Attorney General information related to the operation and utilization of Rate RSE, in accordance with the rules governing the operation of Rate RSE. The ultimate outcome of this matter cannot be determined at this time. AtDecember 31, 2019 ,Alabama Power's WCER exceeded 6.15%, resulting inAlabama Power establishing a current regulatory liability of$53 million for Rate RSE refunds, which will be refunded to customers through bill credits inApril 2020 . Rate CNP New Plant Rate CNP New Plant allows for recovery ofAlabama Power's retail costs associated with newly developed or acquired certificated generating facilities placed into retail service. No adjustments to Rate CNP New Plant occurred during the period 2017 through 2019. See Note 2 to the financial statements under "Alabama Power - Petition for Certificate of Convenience and Necessity" for additional information. Rate CNP PPA Rate CNP PPA allows for the recovery ofAlabama Power's retail costs associated with certificated PPAs. No adjustments to Rate CNP PPA occurred during the period 2017 through 2019 and no adjustment is expected for 2020. Rate CNP Compliance Rate CNP Compliance allows for the recovery ofAlabama Power's retail costs associated with laws, regulations, and other such mandates directed at the utility industry involving the environment, security, reliability, safety, sustainability, or similar considerations impactingAlabama Power's facilities or operations. Rate CNP Compliance is based on forward-looking information and provides for the recovery of these costs pursuant to factors that are calculated and submitted to the Alabama PSC byDecember 1 with rates effective for the following calendar year. Compliance costs to be recovered include operations and maintenance expenses, depreciation, and a return on certain invested capital. Revenues for Rate CNP Compliance, as recorded on the financial statements, are adjusted for differences in actual recoverable costs and amounts billed in current regulated rates. Accordingly, changes in the billing factor will have no significant effect onSouthern Company's orAlabama Power's revenues or net income, but will affect annual cash flow. Changes in Rate CNP Compliance-related operations and maintenance expenses and depreciation generally will have no effect on net income. OnNovember 27, 2019 ,Alabama Power submitted calculations associated with its cost of complying with governmental mandates, as provided under Rate CNP Compliance. The filing reflected a projected over recovered retail revenue requirement for governmental mandates, which resulted in a rate decrease of approximately$68 million that became effective for the billing month ofJanuary 2020 . Rate ECR Rate ECR recoversAlabama Power's retail energy costs based on an estimate of future energy costs and the current over or under recovered balance. Revenues recognized under Rate ECR and recorded on the financial statements are adjusted for the difference in actual recoverable fuel costs and amounts billed in current regulated rates. The difference in the recoverable fuel costs and amounts billed gives rise to the over or under recovered amounts recorded as regulatory assets or liabilities.Alabama Power , along with the Alabama PSC, continually monitors the over or under recovered cost balance to determine whether an adjustment to billing rates is required. Changes in the Rate ECR factor have no significant effect onSouthern Company's orAlabama Power's net income but will impact operating cash flows. The Alabama PSC may approve billing rates under Rate ECR of up to5.910 cents per KWH. OnDecember 3, 2019 , the Alabama PSC approved a decrease to Rate ECR from 2.353 to2.160 cents per KWH, equal to 1.82%, or approximately$102 million annually, effectiveJanuary 1, 2020 . The rate will adjust to5.910 cents per KWH inJanuary 2021 absent a further order from the Alabama PSC. II-66 -------------------------------------------------------------------------------- Table of Contents Index to Financial Statements
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Tax Reform Accounting Order InMay 2018 , the Alabama PSC approved an accounting order that authorizedAlabama Power to defer the benefits of federal excess deferred income taxes associated with the Tax Reform Legislation for the year endedDecember 31, 2018 as a regulatory liability and to use up to$30 million of such deferrals to offset under recovered amounts under Rate ECR. The final excess deferred tax liability for the year endedDecember 31, 2018 totaled approximately$69 million , of which$30 million was used to offset the Rate ECR under recovered balance. OnDecember 3, 2019 , the Alabama PSC issued an order authorizingAlabama Power to apply the remaining deferred balance of approximately$39 million to increase the balance in the NDR. See "Rate NDR" herein and Note 10 to the financial statements under "Current and Deferred Income Taxes" for additional information. Plant Greene CountyAlabama Power jointly owns Plant Greene County with an affiliate,Mississippi Power . See Note 5 to the financial statements under "Joint Ownership Agreements" for additional information regarding the joint ownership agreement. OnDecember 31, 2019 ,Mississippi Power updated its proposed Reserve Margin Plan (RMP), originally filed inAugust 2018 with the Mississippi PSC. The RMP proposed a four-year acceleration of the retirement of Plant Greene County Units 1 and 2 to the third quarter 2021 and the third quarter 2022, respectively.Mississippi Power's proposed Plant Greene County unit retirements would require the completion of proposed transmission and system reliability improvements, as well as agreement byAlabama Power .Alabama Power will continue to monitor the status ofMississippi Power's proposed RMP and associated regulatory process as well as the proposed transmission and system reliability improvements.Alabama Power will review all the facts and circumstances and will evaluate all its alternatives prior to reaching a final determination on the ongoing operations of Plant Greene County. The ultimate outcome of this matter cannot be determined at this time. Rate NDR Based on an order from the Alabama PSC,Alabama Power maintains a reserve for operations and maintenance expenses to cover the cost of damages from major storms to its transmission and distribution facilities. The order approves a separate monthly Rate NDR charge to customers consisting of two components. The first component is intended to establish and maintain a reserve balance for future storms and is an on-going part of customer billing. When the reserve balance falls below$50 million , a reserve establishment charge will be activated (and the on-going reserve maintenance charge concurrently suspended) until the reserve balance reaches$75 million . The second component of the Rate NDR charge is intended to allow recovery of any existing deferred storm-related operations and maintenance costs and any future reserve deficits over a 24-month period. The Alabama PSC order givesAlabama Power authority to record a deficit balance in the NDR when costs of storm damage exceed any established reserve balance. Absent further Alabama PSC approval, the maximum total Rate NDR charge consisting of both components is$10 per month per non-residential customer account and$5 per month per residential customer account.Alabama Power has the authority, based on an order from the Alabama PSC, to accrue certain additional amounts as circumstances warrant. The order allows for reliability-related expenditures to be charged against the additional accruals when the NDR balance exceeds$75 million .Alabama Power may designate a portion of the NDR to reliability-related expenditures as a part of an annual budget process for the following year or during the current year for identified unbudgeted reliability-related expenditures that are incurred. Accruals that have not been designated can be used to offset storm charges. Additional accruals to the NDR enhanceAlabama Power's ability to mitigate the financial effects of future natural disasters, promote system reliability, and offset costs retail customers would otherwise bear. As discussed herein under "Tax Reform Accounting Order," in accordance with an Alabama PSC order issued onDecember 3, 2019 ,Alabama Power applied the remaining excess deferred income tax regulatory liability balance of approximately$39 million to increase the balance in the NDR.Alabama Power also accrued an additional$84 million to the NDR inDecember 2019 resulting in an accumulated balance of$150 million atDecember 31, 2019 . Of this amount,Alabama Power designated$37 million to be applied to budgeted reliability-related expenditures for 2020, which is included in other regulatory liabilities, current. The remaining NDR balance of$113 million is included in other regulatory liabilities, deferred on the balance sheet. InDecember 2017 , the reserve maintenance charge was suspended and the reserve establishment charge was activated and collected approximately$16 million annually through 2019. Effective with theMarch 2020 billings, the reserve establishment charge will be suspended and the reserve maintenance charge will be activated as a result of the NDR balance exceeding$75 million .Alabama Power expects to collect approximately$5 million in 2020 and$3 million annually thereafter unless the NDR balance falls below$50 million . As revenue from the Rate NDR charge is recognized, an equal amount of operations and maintenance expenses related to the NDR will also be recognized. As a result, the Rate NDR charge will not have an effect on net income but will impact operating cash flows. II-67 -------------------------------------------------------------------------------- Table of Contents Index to Financial Statements
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Environmental Accounting Order Based on an order from the Alabama PSC (Environmental Accounting Order),Alabama Power is allowed to establish a regulatory asset to record the unrecovered investment costs, including the unrecovered plant asset balance and the unrecovered costs associated with site removal and closure associated with future unit retirements caused by environmental regulations. The regulatory asset is being amortized and recovered over the affected unit's remaining useful life, as established prior to the decision regarding early retirement through Rate CNP Compliance. OnApril 15, 2019 ,Alabama Power retired Plant Gorgas Units 8, 9, and 10 and reclassified approximately$654 million of the unrecovered asset balances to regulatory assets, which are being recovered over the units' remaining useful lives, the latest being through 2037, as established prior to the decision to retire. AtDecember 31, 2019 , the related regulatory assets totaled$649 million . Additionally, approximately$700 million of net capitalized asset retirement costs were reclassified to a regulatory asset in accordance with accounting guidance provided by the Alabama PSC. The asset retirement costs are being recovered through 2055. See Note 2 to the financial statements under "Alabama Power " and Note 6 to the financial statements for additional information.Georgia Power Georgia Power's revenues from regulated retail operations are collected through various rate mechanisms subject to the oversight of the Georgia PSC.Georgia Power currently recovers its costs from the regulated retail business through an alternate rate plan, which includes traditional base tariffs, Demand-Side Management (DSM) tariffs, the ECCR tariff, and Municipal Franchise Fee (MFF) tariffs. In addition, financing costs on certified construction costs of Plant Vogtle Units 3 and 4 are being collected through the NCCR tariff and fuel costs are collected through a separate fuel cost recovery tariff. See Note 2 to the financial statements under "Georgia Power - Rate Plans," " - Fuel Cost Recovery," and " -Nuclear Construction " for additional information. Rate Plans 2019 ARP OnDecember 17, 2019 , the Georgia PSC voted to approve the 2019 ARP, under whichGeorgia Power increased its rates onJanuary 1, 2020 and will increase rates annually for 2021 and 2022 as detailed below based on compliance filings to be made at least 90 days prior to the effective date.Georgia Power will recover estimated increases through its existing tariffs as follows: Tariff 2020 2021 2022 (in millions) Traditional base $ -$ 120 $ 192 ECCR(a) 318 55 184 DSM 12 1 1 MFF 12 4 9 Total(b)$ 342 $ 181 $ 386
(a) Effective
tariff. See "Integrated Resource Plan" herein for additional information on
recovery of compliance costs for CCR AROs.
(b) Totals may not add due to rounding.
Further, under the 2019 ARP,Georgia Power's retail ROE is set at 10.50%, and earnings will be evaluated against a retail ROE range of 9.50% to 12.00%. The Georgia PSC also approved an increase in the retail equity ratio to 56% from 55%. Any retail earnings above 12.00% will be shared, with 40% being applied to reduce regulatory assets, 40% directly refunded to customers, and the remaining 20% retained byGeorgia Power . There will be no recovery of any earnings shortfall below 9.50% on an actual basis. However, if at any time during the term of the 2019 ARP,Georgia Power projects that its retail earnings will be below 9.50% for any calendar year, it could petition the Georgia PSC for implementation of the Interim Cost Recovery (ICR) tariff to adjustGeorgia Power's retail rates to achieve a 9.50% ROE. The Georgia PSC would have 90 days to rule onGeorgia Power's request. The ICR tariff would expire at the earlier ofJanuary 1, 2023 or the end of the calendar year in which the ICR tariff becomes effective. In lieu of requesting implementation of an ICR tariff, or if the Georgia PSC chooses not to implement the ICR tariff,Georgia Power may file a full rate case. Additionally, under the 2019 ARP and pursuant to the sharing mechanism approved in the 2013 ARP whereby two-thirds of any earnings above the top of the allowed ROE range are shared withGeorgia Power's customers, (i)Georgia Power used 50% (approximately$50 million ) of the customer share of earnings above the band in 2018 to reduce regulatory assets and 50% II-68 -------------------------------------------------------------------------------- Table of Contents Index to Financial Statements
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(approximately$50 million ) will be refunded to customers in 2020 and (ii)Georgia Power will forgo its share of 2019 earnings in excess of the earnings band so that 50% (approximately$60 million ) of all earnings over the 2019 band will be refunded to customers and 50% (approximately$60 million ) were used to reduce regulatory assets. Except as provided above,Georgia Power will not file for a general base rate increase while the 2019 ARP is in effect.Georgia Power is required to file a general base rate case byJuly 1, 2022 , in response to which the Georgia PSC would be expected to determine whether the 2019 ARP should be continued, modified, or discontinued. 2013 ARP Pursuant to the terms and conditions of a settlement agreement related toSouthern Company's acquisition ofSouthern Company Gas approved by theGeorgia PSC in 2016, the 2013 ARP continued in effect untilDecember 31, 2019 . Furthermore, throughDecember 31, 2019 ,Georgia Power retained its merger savings, net of transition costs, as defined in the settlement agreement; throughDecember 31, 2022 , such net merger savings will be shared on a 60/40 basis with customers; thereafter, all merger savings will be retained by customers. There were no changes toGeorgia Power's traditional base tariffs, ECCR tariff, DSM tariffs, or MFF tariffs in 2017, 2018, or 2019. Under the 2013 ARP,Georgia Power's retail ROE was set at 10.95% and earnings were evaluated against a retail ROE range of 10.00% to 12.00%. Two-thirds of any earnings above 12.00% were to be directly refunded to customers, with the remaining one-third retained byGeorgia Power . OnFebruary 5, 2019 , theGeorgia PSC approved a settlement betweenGeorgia Power and the staff of the Georgia PSC under whichGeorgia Power's retail ROE for 2017 was stipulated to exceed 12.00% andGeorgia Power reduced certain regulatory assets by approximately$4 million in lieu of providing refunds to retail customers. In 2019 and 2018,Georgia Power's retail ROE exceeded 12.00% and, under the modified sharing mechanism pursuant to the 2019 ARP,Georgia Power has reduced regulatory assets by a total of approximately$110 million and expects to refund a total of approximately$110 million to customers, subject to review and approval by the Georgia PSC. See "2019 ARP" and "Integrated Resource Plan" herein for additional information. Tax Reform Settlement Agreement InApril 2018 , the Georgia PSC approved the Georgia Power Tax Reform Settlement Agreement. To reflect the federal income tax rate reduction impact of the Tax Reform Legislation,Georgia Power issued bill credits of approximately$95 million and$130 million in 2019 and 2018, respectively, and is issuing bill credits of approximately$105 million inFebruary 2020 , for a total of$330 million . In addition,Georgia Power deferred as a regulatory liability (i) the revenue equivalent of the tax expense reduction resulting from legislation lowering theGeorgia state income tax rate from 6.00% to 5.75% in 2019 and (ii) the entire benefit of federal and state excess accumulated deferred income taxes. AtDecember 31, 2019 , the related regulatory liability balance totaled$659 million , which is being amortized over a three-year period endingDecember 31, 2022 in accordance with the 2019 ARP. To address some of the negative cash flow and credit quality impacts of the Tax Reform Legislation, the Georgia PSC also approved an increase inGeorgia Power's retail equity ratio to the lower of (i) Georgia Power's actual common equity weight in its capital structure or (ii) 55%, until the Georgia PSC approved the 2019 ARP. Benefits from reduced federal income tax rates in excess of the amounts refunded to customers were retained by Georgia Power to cover the carrying costs of the incremental equity in 2018 and 2019. See "2019 ARP" herein for additional information. Integrated Resource Plan See "Environmental Matters" herein for additional information regarding proposed and finalEPA rules and regulations, including revisions to ELG for steam electric power plants and additional regulations of CCR and CO2. On July 16, 2019, the Georgia PSC voted to approve Georgia Power's modified triennial IRP (Georgia Power 2019 IRP). In the Georgia Power 2019 IRP, the Georgia PSC approved the decertification and retirement of Plant Hammond Units 1 through 4 (840 MWs) and Plant McIntosh Unit 1 (142.5 MWs) effective July 29, 2019. In accordance with the 2019 ARP, the remaining net book values at December 31, 2019 of $488 million for the Plant Hammond units are being recovered over a period equal to the respective unit's remaining useful life, which varies between 2024 and 2035, and $30 million for Plant McIntosh Unit 1 is being recovered over a three-year period ending December 31, 2022. In addition, approximately $20 million of related unusable materials and supplies inventory balances and approximately $295 million of net capitalized asset retirement costs were reclassified to a regulatory asset. In accordance with the modifications to the earnings sharing mechanism approved in the 2019 ARP, Georgia Power fully amortized the regulatory assets associated with these unusable materials and supplies inventory II-69 -------------------------------------------------------------------------------- Table of Contents Index to Financial Statements
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balances as well as a regulatory asset of approximately $50 million related to costs for a future generation site inStewart County, Georgia . See "Rate Plans - 2019 ARP" herein for additional information. Also in the Georgia Power 2019 IRP, the Georgia PSC approved Georgia Power's proposed environmental compliance strategy associated with ash pond and certain landfill closures and post-closure care in compliance with the CCR Rule and the related state rule. In the 2019 ARP, the Georgia PSC approved recovery of the estimated under recovered balance of these compliance costs at December 31, 2019 over a three-year period ending December 31, 2022 and recovery of estimated compliance costs for 2020, 2021, and 2022 over three-year periods ending December 31, 2022, 2023, and 2024, respectively, with recovery of construction contingency beginning in the year following actual expenditure. The under recovered balance at December 31, 2019 was $175 million and the estimated compliance costs expected to be incurred in 2020, 2021, and 2022 are $265 million, $290 million, and $390 million, respectively. The ECCR tariff is expected to be revised for actual expenditures and updated estimates through future annual compliance filings. See "Environmental Matters - Environmental Laws and Regulations - Coal Combustion Residuals" and FINANCIAL CONDITION AND LIQUIDITY - "Capital Requirements" and "Contractual Obligations" herein and Note 6 to the financial statements for additional information regardingGeorgia Power's AROs. On February 4, 2020, the Georgia PSC voted to deny a motion for reconsideration filed by theSierra Club regarding the Georgia PSC's decision in the 2019 ARP allowing Georgia Power to recover compliance costs for CCR AROs. Additionally, the Georgia PSC rejected a request to certify approximately 25 MWs of capacity at Plant Scherer Unit 3 for the retail jurisdiction beginning January 1, 2020 following the expiration of a wholesale PPA. Georgia Power may offer such capacity in the wholesale market or to the retail jurisdiction in a future IRP. The Georgia PSC also approved Georgia Power to (i) issue requests for proposals (RFP) for capacity beginning in 2022 or 2023 and in 2026, 2027, or 2028; (ii) procure up to an additional 2,210 MWs of renewable resources through competitive RFPs; and (iii) invest in a portfolio of up to 80 MWs of battery energy storage technologies. Fuel Cost Recovery Georgia Power has established fuel cost recovery rates approved by theGeorgia PSC. Georgia Power is scheduled to file its next fuel case no later than March 16, 2020, with new rates, if any, to be effective June 1, 2020. Georgia Power continues to be allowed to adjust its fuel cost recovery rates under an interim fuel rider prior to the next fuel case if the under or over recovered fuel balance exceeds $200 million. At December 31, 2019, Georgia Power's over recovered fuel balance was $73 million. Georgia Power's fuel cost recovery mechanism includes costs associated with a natural gas hedging program, as revised and approved by the Georgia PSC, allowing the use of an array of derivative instruments within a 48-month time horizon. Fuel cost recovery revenues as recorded on the financial statements are adjusted for differences in actual recoverable fuel costs and amounts billed in current regulated rates. Accordingly, changes in the billing factor will not have a significant effect onSouthern Company's or Georgia Power's revenues or net income but will affect operating cash flows. Storm Damage Recovery Beginning January 1, 2020, Georgia Power is recovering $213 million annually through December 31, 2022, as provided in the 2019 ARP, for incremental operations and maintenance costs of damage from major storms to its transmission and distribution facilities. At December 31, 2019, the balance in the regulatory asset related to storm damage was $410 million. The rate of storm damage cost recovery is expected to be adjusted in future regulatory proceedings as necessary. As a result of this regulatory treatment, costs related to storms are not expected to have a material impact onSouthern Company's or Georgia Power's financial statements. See Note 2 to the financial statements under "Georgia Power - Storm Damage Recovery" for additional information regardingGeorgia Power's storm damage reserve. Mississippi Power Mississippi Power's rates and charges for service to retail customers are subject to the regulatory oversight of the Mississippi PSC. Mississippi Power's rates are a combination of base rates and several separate cost recovery clauses for specific categories of costs. These separate cost recovery clauses address such items as fuel and purchased power, energy efficiency programs, ad valorem taxes, property damage, and the costs of compliance with environmental laws and regulations. Costs not addressed through one of the specific cost recovery clauses are expected to be recovered through Mississippi Power's base rates. See Note 2 to the financial statements under "Mississippi Power" for additional information. II-70 -------------------------------------------------------------------------------- Table of Contents Index to Financial Statements
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2019 Base Rate Case On November 26, 2019, Mississippi Power filed the Mississippi Power 2019 Base Rate Case with the Mississippi PSC. The filing includes a requested annual decrease in Mississippi Power's retail rates of $5.8 million, or 0.6%, which is driven primarily by changes in the amortization rates of certain regulatory assets and liabilities and cost reductions, partially offset by an increase in Mississippi Power's requested return on investment and depreciation associated with the filing of an updated depreciation study. The revenue requirements included in the filing are based on a projected test year period of January 1, 2020 through December 31, 2020, a 53% average equity ratio, and a 7.728% return on investment. The filing reflects the elimination of separate rates for costs associated with theKemper County energy facility and energy efficiency initiatives; those costs are proposed to be included in the PEP, ECO Plan, and ad valorem tax adjustment factor, as applicable. On December 10, 2019, the Mississippi PSC suspended the base rate case filing through no later than March 25, 2020. If no further action is taken by the Mississippi PSC, the proposed rates may be effective beginning on March 26, 2020. The ultimate outcome of this matter cannot be determined at this time. Operations Review In August 2018, the Mississippi PSC began an operations review ofMississippi Power, for which the final report is expected prior to the conclusion of the Mississippi Power 2019 Base Rate Case. The review includes, but is not limited to, a comparative analysis of its costs, its cost recovery framework, and ways in which it may streamline management operations for the reasonable benefit of ratepayers. The ultimate outcome of this matter cannot be determined at this time. Reserve Margin Plan On December 31, 2019, Mississippi Power updated its proposed RMP, originally filed in August 2018, as required by the Mississippi PSC. In 2018,Mississippi Power had proposed alternatives to reduce its reserve margin and lower or avoid operating costs, with the most economic alternatives being the two-year and seven-year acceleration of the retirement of Plant Watson Units 4 and 5, respectively, to the first quarter 2022 and the four-year acceleration of the retirement of Plant Greene County Units 1 and 2 to the third quarter 2021 and the third quarter 2022, respectively. The December 2019 update noted that Plant Daniel Units 1 and 2 currently have long-term economics similar toPlant Watson Unit 5. The Plant Greene County unit retirements would require the completion byAlabama Power of proposed transmission and system reliability improvements, as well as agreement byAlabama Power . The RMP filing also states that, in the event the Mississippi PSC ultimately approves an alternative that includes an accelerated retirement, Mississippi Power would require authorization to defer in a regulatory asset for future recovery the remaining net book value of the units at the time of retirement. A decision by the Mississippi PSC that does not include recovery of the remaining book value of any generating units retired could have a material impact onSouthern Company's and Mississippi Power's financial statements. The ultimate outcome of this matter cannot be determined at this time. See Note 3 to the financial statements under "Other Matters - Mississippi Power" for additional information on Plant Daniel Units 1 and 2. Performance Evaluation Plan Mississippi Power's retail base rates generally are set under the PEP, a rate plan approved by the Mississippi PSC. In recognition that Mississippi Power's long-term financial success is dependent upon how well it satisfies its customers' needs, PEP includes performance indicators that directly tie customer service indicators to Mississippi Power's allowed ROE. PEP measuresMississippi Power's performance on a 10-point scale as a weighted average of results in three areas: average customer price, as compared to prices of other regional utilities (weighted at 40%); service reliability, measured in percentage of time customers had electric service (40%); and customer satisfaction, measured in a survey of residential customers (20%). Typically, two PEP filings are made for each calendar year: the PEP projected filing, which is typically filed prior to the beginning of the year based on a projected revenue requirement, and the PEP lookback filing, which is filed after the end of the year and allows for review of the actual revenue requirement compared to the projected filing. In February 2018, Mississippi Power revised its annual projected PEP filing for 2018 to reflect the impacts of the Tax Reform Legislation. The revised filing requested an increase of $26 million in annual revenues, based on a performance adjusted ROE of 9.33% and an increased equity ratio of 55%. In July 2018, Mississippi Power and the MPUS entered into a settlement agreement, which was approved by the Mississippi PSC in August 2018 (PEP Settlement Agreement). Rates under the PEP Settlement Agreement became effective with the first billing cycle of September 2018. The PEP Settlement Agreement provided for an increase of approximately $21.6 million in annual base retail revenues, which excluded certain compensation costs contested by the MPUS, as well as approximately $2 million subsequently approved for recovery through the 2018 Energy Efficiency Cost Rider. Under the PEP Settlement Agreement, Mississippi Power deferred a portion of the contested compensation costs for 2018 and 2019 as a regulatory asset, which totaled $4 million as of December 31, 2019 and is included in other regulatory assets, II-71 -------------------------------------------------------------------------------- Table of Contents Index to Financial Statements
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deferred on the balance sheet. The Mississippi PSC is expected to rule on the appropriate treatment for such costs in connection with the Mississippi Power 2019 Base Rate Case. The ultimate outcome of this matter cannot be determined at this time. Pursuant to the PEP Settlement Agreement, Mississippi Power's performance-adjusted allowed ROE is 9.31% and its allowed equity ratio is capped at 51%, pending further review by the Mississippi PSC. In lieu of the requested equity ratio increase, Mississippi Power retained $44 million of excess accumulated deferred income taxes resulting from the Tax Reform Legislation until the conclusion of the Mississippi Power 2019 Base Rate Case. Further, Mississippi Power agreed to seek equity contributions sufficient to restore its equity ratio to 50% by December 31, 2018. Since Mississippi Power's actual average equity ratio for 2018 was more than 1% lower than the 50% target, Mississippi Power deferred the corresponding difference in its revenue requirement of approximately $4 million as a regulatory liability for resolution in the Mississippi Power 2019 Base Rate Case. Pursuant to the PEP Settlement Agreement, PEP proceedings are suspended until after the conclusion of the Mississippi Power 2019 Base Rate Case and Mississippi Power was not required to make any PEP filings for regulatory years 2018, 2019, and 2020. Energy Efficiency On February 5, 2019, the Mississippi PSC issued an order approvingMississippi Power's Energy Efficiency Cost Rider 2019 compliance filing, which included a slight decrease in annual retail revenues, effective with the first billing cycle in March 2019. As part of the Mississippi Power 2019 Base Rate Case, Mississippi Power has proposed that the Energy Efficiency Cost Rider be eliminated and those costs be included in the PEP. The ultimate outcome of this matter cannot be determined at this time. Environmental Compliance Overview Plan In accordance with a 2011 accounting order from the Mississippi PSC,Mississippi Power has the authority to defer in a regulatory asset for future recovery all plant retirement- or partial retirement-related costs resulting from environmental regulations. The Mississippi PSC approved $41 million and $17 million of costs that were reclassified to regulatory assets associated with the fuel conversion ofPlant Watson and Plant Greene County, respectively, for amortization over five-year periods ending in July 2021 and July 2022, respectively. In August 2018, the Mississippi PSC approved an annual increase in revenues related to the ECO Plan of approximately $17 million, effective with the first billing cycle for September 2018. This increase represented the maximum 2% annual increase in revenues and primarily related to the carryforward from the prior year. The increase was the result of Mississippi PSC approval of an agreement between Mississippi Power and the MPUS to settle the 2018 ECO Plan filing (ECO Settlement Agreement) and was sufficient to recover costs through 2019, including remaining amounts deferred from prior years along with the related carrying costs. In accordance with the ECO Settlement Agreement, ECO Plan proceedings are suspended until after the conclusion of the Mississippi Power 2019 Base Rate Case and Mississippi Power was not required to make any ECO Plan filings for 2018, 2019, and 2020, with any necessary adjustments reflected in the Mississippi Power 2019 Base Rate Case. The ECO Settlement Agreement contains the same terms as the PEP Settlement Agreement described herein with respect to allowed ROE and equity ratio. At December 31, 2019, Mississippi Power has recorded $2 million in other regulatory liabilities, deferred on the balance sheet related to the actual December 31, 2018 average equity ratio differential from target applicable to the ECO Plan. On October 24, 2019, the Mississippi PSC approved Mississippi Power's July 9, 2019 request for a CPCN to complete certain environmental compliance projects, primarily associated with the Plant Daniel coal units co-owned 50% with Gulf Power. The total estimated cost is approximately $125 million, withMississippi Power's share of approximately $66 million being proposed for recovery through its ECO Plan. Approximately $17 million of Mississippi Power's share is associated with ash pond closure and is reflected in Mississippi Power's ARO liabilities. See Note 6 to the financial statements for additional information on AROs and Note 3 to the financial statements under "Other Matters - Mississippi Power" for additional information on Gulf Power's ownership inPlant Daniel . Fuel Cost Recovery Mississippi Power annually establishes and is required to file for an adjustment to the retail fuel cost recovery factor that is approved by the Mississippi PSC. The Mississippi PSC approved decreases of $35 million and $24 million, effective in February 2019 and 2020, respectively. At December 31, 2019 and 2018, over recovered retail fuel costs included in other current liabilities onSouthern Company's balance sheets and over recovered regulatory clause liabilities on Mississippi Power's balance sheets were approximately $23 million and $8 million, respectively. II-72 -------------------------------------------------------------------------------- Table of Contents Index to Financial Statements
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Mississippi Power has wholesale MRA and Market Based (MB) fuel cost recovery factors. Effective with the first billing cycle for January 2019, the wholesale MRA fuel rate increased $16 million annually and the wholesale MB fuel rate decreased by an immaterial amount. Effective January 1, 2020, the wholesale MRA fuel rate increased $1 million annually and the wholesale MB fuel rate decreased by an immaterial amount. At December 31, 2019 and 2018, over recovered wholesale MRA fuel costs included in other current liabilities onSouthern Company's balance sheets and over recovered regulatory clause liabilities onMississippi Power's balance sheets were approximately $6 million. At December 31, 2019 and 2018, over/under recovered wholesale MB fuel costs included in the balance sheets were immaterial. Mississippi Power's operating revenues are adjusted for differences in actual recoverable fuel cost and amounts billed in accordance with the currently approved cost recovery rate. Accordingly, changes in the billing factor should have no significant effect on Mississippi Power's revenues or net income but will affect operating cash flows. Kemper County Energy Facility Overview TheKemper County energy facility was designed to utilize IGCC technology with an expected output capacity of 582 MWs and to be fueled by locally mined lignite (an abundant, lower heating value coal) from a mine owned by Mississippi Power and situated adjacent to theKemper County energy facility. Schedule and Cost Estimate In 2012, the Mississippi PSC issued an order confirming the CPCN originally approved by the Mississippi PSC in 2010 authorizing the acquisition, construction, and operation of theKemper County energy facility. The order approved a construction cost cap of up to $2.88 billion, with recovery of prudently-incurred costs subject to approval by the Mississippi PSC. TheKemper County energy facility was originally projected to be placed in service in May 2014. Mississippi Power placed the combined cycle and the associated common facilities portion of theKemper County energy facility in service in August 2014. The combined cycle and associated common facilities portions of theKemper County energy facility were dedicated asPlant Ratcliffe in April 2018. In June 2017, the Mississippi PSC stated its intent to issue an order, which occurred in July 2017, directing Mississippi Power to pursue a settlement under which theKemper County energy facility would be operated as a natural gas plant, rather than an IGCC plant, and address all issues associated with theKemper County energy facility. The order established a new docket for the purpose of pursuing a global settlement of the related costs (Kemper Settlement Docket). In June 2017, Mississippi Power notified the Mississippi PSC that it would begin a process to suspend operations and start-up activities on the gasifier portion of theKemper County energy facility, given the uncertainty as to its future. At the time of project suspension in June 2017, the total cost estimate for theKemper County energy facility was approximately $7.38 billion, including approximately $5.95 billion of costs subject to the construction cost cap, net of $137 million in additional grants from theDOE received in April 2016. In the aggregate, Mississippi Power had recorded charges to income of $3.07 billion ($1.89 billion after tax) as a result of changes in the cost estimate above the cost cap for the Kemper IGCC through May 2017. Given the Mississippi PSC's stated intent regarding no further rate increase for theKemper County energy facility and the subsequent suspension, cost recovery of the gasifier portions became no longer probable; therefore, Mississippi Power recorded an additional charge to income in June 2017 of $2.8 billion ($2.0 billion after tax), which included estimated costs associated with the gasification portions of the plant and lignite mine. During the third and fourth quarters of 2017, Mississippi Power recorded charges to income of $242 million ($206 million after tax), including $164 million for ongoing project costs, estimated mine and gasifier-related costs, and certain termination costs during the suspension period prior to conclusion of the Kemper Settlement Docket, as well as the charge associated with the Kemper Settlement Agreement discussed below. In 2019, Mississippi Power recorded pre-tax and after-tax charges to income of $24 million, primarily associated with the expected close out of a relatedDOE contract, as well as other abandonment and related closure costs and ongoing period costs, net of salvage proceeds, for the mine and gasifier-related assets. The after-tax amount for 2019 includes an adjustment related to the tax abandonment of the Kemper IGCC following the filing of the 2018 tax return. In 2018, Mississippi Power recorded pre-tax charges to income of $37 million ($68 million benefit after tax), primarily associated with abandonment and related closure costs and ongoing period costs, net of salvage proceeds, for the mine and gasifier-related assets, as well as the impact of a change in the valuation allowance for the related state income tax NOL carryforward. Mississippi Power expects to substantially complete mine reclamation activities in 2020 and dismantlement of the abandoned gasifier-related assets and site restoration activities are expected to be completed in 2024. The additional pre-tax period costs associated with dismantlement and site restoration activities, including related costs for compliance and safety, ARO accretion, II-73 -------------------------------------------------------------------------------- Table of Contents Index to Financial Statements
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and property taxes, are estimated to total $17 million in 2020, $15 million to $16 million annually in 2021 through 2023, and $5 million in 2024. See Note 10 to the financial statements for additional information. Rate Recovery In February 2018, the Mississippi PSC voted to approve a settlement agreement related to cost recovery for theKemper County energy facility amongMississippi Power, the MPUS, and certain intervenors (Kemper Settlement Agreement), which resolved all cost recovery issues, modified the CPCN to limit theKemper County energy facility to natural gas combined cycle operation, and provided for an annual revenue requirement of approximately $99.3 million for costs related to theKemper County energy facility, which included the impact of the Tax Reform Legislation. The revenue requirement was based on (i) a fixed ROE for 2018 of 8.6% excluding any performance adjustment, (ii) a ROE for 2019 calculated in accordance with PEP, excluding the performance adjustment, (iii) for future years, a performance-based ROE calculated pursuant to PEP, and (iv) amortization periods for the related regulatory assets and liabilities of eight years and six years, respectively. The revenue requirement also reflects a disallowance related to a portion of Mississippi Power's investment in theKemper County energy facility requested for inclusion in rate base, which was recorded in the fourth quarter 2017 as an additional charge to income of approximately $78 million ($85 million net of accumulated depreciation of $7 million) pre-tax ($48 million after tax). Under the Kemper Settlement Agreement, retail customer rates were reduced by approximately $26.8 million annually, effective with the first billing cycle of April 2018, and include no recovery for costs associated with the gasifier portion of theKemper County energy facility in 2018 or at any future date. On November 26, 2019, Mississippi Power filed the Mississippi Power 2019 Base Rate Case, which reflects the elimination of separate rates for costs associated with theKemper County energy facility; these costs are proposed to be included in rates for PEP, ECO Plan, and ad valorem tax adjustment factor, as applicable. The ultimate outcome of this matter cannot be determined at this time. Lignite Mine and CO2 Pipeline Facilities Mississippi Power owns the lignite mine and equipment and mineral reserves located around theKemper County energy facility site. The mine started commercial operation in June 2013. In connection with theKemper County energy facility construction, Mississippi Power also constructed a pipeline for the transport of captured CO2. In 2010, Mississippi Power executed a management fee contract with Liberty Fuels Company, LLC (Liberty Fuels), a wholly-owned subsidiary ofThe North American Coal Corporation , which developed, constructed, and is responsible for the mining operations through the end of the mine reclamation. As the mining permit holder, Liberty Fuels has a legal obligation to perform mine reclamation and Mississippi Power has a contractual obligation to fund all reclamation activities. As a result of the abandonment of the Kemper IGCC, final mine reclamation began in 2018 and is expected to be substantially completed in 2020, with monitoring expected to continue through 2027. See Note 6 to the financial statements for additional information. On December 31, 2019, Mississippi Power transferred ownership of the CO2 pipeline to an unrelated gas pipeline company, with no resulting impact on income. In conjunction with the transfer of the CO2 pipeline, the parties agreed to enter into a 15-year firm transportation agreement, which is expected to be signed by March 2020, providing for the conversion by the pipeline company of the CO2 pipeline to a natural gas pipeline to be used for the delivery of natural gas toPlant Ratcliffe . The agreement will be treated as a finance lease for accounting purposes upon commencement, which is expected to occur by August 2020. See Note 9 to the financial statements for additional information. Government Grants In 2010, theDOE , through a cooperative agreement with SCS, agreed to fund $270 million of theKemper County energy facility through the grants awarded to the project by theDOE under the Clean Coal Power Initiative Round 2. In 2016, additionalDOE grants in the amount of $137 million were awarded to theKemper County energy facility. Through December 31, 2018, Mississippi Power received totalDOE grants of $387 million, of which $382 million reduced the construction costs of theKemper County energy facility and $5 million reimbursedMississippi Power for expenses associated withDOE reporting. In December 2018,Mississippi Power filed with theDOE its request for property closeout certification under the contract related to the $387 million of grants received. Mississippi Power expects to close out theDOE contract related to theKemper County energy facility in 2020. In connection with theDOE closeout discussions, on April 29, 2019, the Civil Division of the Department of Justice informedSouthern Company and Mississippi Power of an investigation related to theKemper County energy facility. The ultimate outcome of this matter cannot be determined at this time; however, it could have a material impact onSouthern Company's andMississippi Power's financial statements. II-74 -------------------------------------------------------------------------------- Table of Contents Index to Financial Statements
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Municipal and Rural Associations Tariff Mississippi Power provides wholesale electric service to Cooperative Energy, East Mississippi Electric Power Association, and theCity of Collins , all located in southeasternMississippi , under a long-term, cost-based,FERC -regulated MRA tariff. In 2017, Mississippi Power and Cooperative Energy executed, and theFERC accepted, a Shared Service Agreement (SSA), as part of the MRA tariff, under which Mississippi Power and Cooperative Energy will share in providing electricity to the Cooperative Energy delivery points under the tariff, effective January 1, 2018. The SSA may be cancelled by Cooperative Energy with 10 years notice after December 31, 2020. As of December 31, 2019, Cooperative Energy has the option to decrease its use of Mississippi Power's generation services under the MRA tariff up to 2.5% annually, with required notice, up to a maximum total reduction of 11%, or approximately $9 million in cumulative annual base revenues. On May 7, 2019, theFERC accepted Mississippi Power's requested $3.7 million annual decrease in MRA base rates effective January 1, 2019, as agreed upon in the MRA Settlement Agreement, resolving all matters related to theKemper County energy facility, similar to the retail rate settlement agreement approved by the Mississippi PSC in February 2018, and reflecting the impacts of the Tax Reform Legislation. Cooperative Energy Power Supply Agreement Effective April 1, 2018, Mississippi Power and Cooperative Energy amended and extended a previous power supply agreement through March 31, 2021, which was subsequently extended through May 31, 2021. The amendment increased the total capacity from 86 MWs to 286 MWs. Cooperative Energy also has a 10-year network integration transmission service agreement (NITSA) with SCS for transmission service to certain delivery points on Mississippi Power's transmission system through March 31, 2021. As a result of the PSA amendment, Cooperative Energy and SCS also amended the terms of the NITSA, which theFERC approved, to provide for the purchase of incremental transmission capacity from April 1, 2018 through March 31, 2021.Southern Company Gas Utility Regulation and Rate Design The natural gas distribution utilities are subject to regulations and oversight by their respective state regulatory agencies. Rates charged to customers vary according to customer class (residential, commercial, or industrial) and rate jurisdiction. These agencies approve rates designed to provide the opportunity to generate revenues to recover all prudently-incurred costs, including a return on rate base sufficient to pay interest on debt and provide a reasonable ROE. Rate base generally consists of the original cost of the utility plant in service, working capital, and certain other assets, less accumulated depreciation on the utility plant in service and net deferred income tax liabilities, and may include certain other additions or deductions. The natural gas market forAtlanta Gas Light was deregulated in 1997. Accordingly, Marketers, rather than a traditional utility, sell natural gas to end-use customers inGeorgia and handle customer billing functions. The Marketers file their rates monthly with the Georgia PSC. As a result of operating in a deregulated environment,Atlanta Gas Light's role includes: • distributing natural gas for Marketers;
• constructing, operating, and maintaining the gas system infrastructure,
including responding to customer service calls and leaks;
• reading meters and maintaining underlying customer premise information for
Marketers; and • planning and contracting for capacity on interstate transportation and storage systems.Atlanta Gas Light earns revenue by charging rates to its customers based primarily on monthly fixed charges that are set by the Georgia PSC and adjusted periodically. The Marketers add these fixed charges when billing customers. This mechanism, called a straight-fixed-variable rate design, minimizes the seasonality ofAtlanta Gas Light's revenues since the monthly fixed charge is not volumetric or directly weather dependent. See "GRAM" and "PRP" herein for additional information. With the exception ofAtlanta Gas Light , the earnings of the natural gas distribution utilities can be affected by customer consumption patterns that are largely a function of weather conditions and price levels for natural gas. Specifically, customer demand substantially increases during the Heating Season when natural gas is used for heating purposes.Southern Company Gas has various mechanisms, such as weather and revenue normalization mechanisms and weather derivative instruments, that limit exposure to weather changes within typical ranges in these utilities' respective service territories. With the exception ofAtlanta Gas Light , the natural gas distribution utilities are authorized by the relevant regulatory agencies in the states in which they serve to use natural gas cost recovery mechanisms that adjust rates to reflect changes in the wholesale II-75 -------------------------------------------------------------------------------- Table of Contents Index to Financial Statements
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cost of natural gas and ensure recovery of all costs prudently incurred in purchasing natural gas for customers. Natural gas cost recovery revenues are adjusted for differences in actual recoverable natural gas costs and amounts billed in current regulated rates. Changes in the billing factor will not have a significant effect onSouthern Company Gas' revenues or net income, but will affect cash flows. SinceAtlanta Gas Light does not sell natural gas directly to its end-use customers, it does not utilize a traditional natural gas cost recovery mechanism. However,Atlanta Gas Light does maintain natural gas inventory for the Marketers inGeorgia and recovers the cost through recovery mechanisms approved by the Georgia PSC specific toGeorgia's deregulated market. In addition to natural gas recovery mechanisms, there are other cost recovery mechanisms, such as regulatory riders, which vary by utility but allow recovery of certain costs, such as those related to infrastructure replacement programs as well as environmental remediation and energy efficiency plans. In traditional rate designs, utilities recover a significant portion of the fixed customer service and pipeline infrastructure costs based on assumed natural gas volumes used by customers. The utilities, including Nicor Gas beginning in November 2019, have decoupled regulatory mechanisms thatSouthern Company Gas believes encourage conservation by separating the recoverable amount of these fixed costs from the amounts of natural gas used by customers. See Note 2 to the financial statements under "Southern Company Gas - Rate Proceedings" for additional information. Also see "Construction Programs -Southern Company Gas - Infrastructure Replacement Programs and Capital Projects" for additional information regarding infrastructure replacement programs at certain of the natural gas distribution utilities. The following table provides regulatory information forSouthern Company Gas' natural gas distribution utilities: Virginia Nicor Gas Atlanta Gas Light Natural Gas Chattanooga Gas Authorized ROE(a) 9.73% 10.25% 9.50% 9.80% 9.00% - Authorized ROE range(a) N/A 10.05% - 10.45% 10.00% N/A Weather normalization mechanisms(b) ü ü Decoupled, including straight-fixed-variable rates(c) ü ü
ü
Regulatory infrastructure program rates(d) ü ü Bad debt rider(e) ü ü ü Energy efficiency plan(f) ü ü Annual base rate adjustment mechanism(g) ü ü Year of last rate decision 2019 2019 2018 2018
(a)
1, 2020.
(b) Regulatory mechanisms that allow recovery of costs in the event of unseasonal
weather, but are not direct offsets to the potential impacts on earnings of
weather and customer consumption. These mechanisms are designed to help
stabilize operating results by increasing base rate amounts charged to
customers when weather is warmer than normal and decreasing amounts charged
when weather is colder than normal.
(c) Allows for recovery of fixed customer service costs separately from assumed
natural gas volumes used by customers. On October 2, 2019, Nicor Gas received
approval for a volume balancing adjustment, a revenue decoupling mechanism
for residential customers that provides a monthly benchmark level of revenue
per rate class for recovery.
(d) Programs that update or expand distribution systems and LNG facilities.
(e) The recovery (refund) of bad debt expense over (under) an established
benchmark expense. Nicor Gas,Virginia Natural Gas , and Chattanooga Gas recover the gas portion of bad debt expense through their purchased gas adjustment mechanisms.
(f) Recovery of costs associated with plans to achieve specified energy savings
goals.
(g) Regulatory mechanism allowing annual adjustments to base rates up or down
based on authorized ROE and/or ROE range.
GRAM
In December 2019, the Georgia PSC approved the continuation of GRAM as part ofAtlanta Gas Light's 2019 rate case order. Various infrastructure programs previously authorized by the Georgia PSC, including the Integrated Vintage Plastic Replacement Program (i-VPR) to replace aging plastic pipe and the Integrated System Reinforcement Program (i-SRP) to upgradeAtlanta Gas Light's distribution system and LNG facilities inGeorgia , continue under GRAM and the recovery of and return on the infrastructure program investments are included in annual base rate adjustments. The future expected costs to be recovered through rates related to allowed, but not incurred, costs are recognized in an unrecognized ratemaking amount that is not reflected on the balance sheets. This allowed cost is primarily the equity return on the capital investment under the infrastructure programs in place prior to GRAM. See "Unrecognized Ratemaking Amounts" herein for additional information. The Georgia PSC reviewsAtlanta Gas Light's performance annually under GRAM. See "Rate Proceedings" herein for additional information. II-76 -------------------------------------------------------------------------------- Table of Contents Index to Financial Statements
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Pursuant to the GRAM approval,Atlanta Gas Light and the staff of theGeorgia PSC agreed to a variation of the Integrated Customer Growth Program to extend pipeline facilities to serve customers in areas without pipeline access and create new economic development opportunities inGeorgia . As a result, a new tariff was created, effective October 10, 2017, to provide up to $15 million annually forAtlanta Gas Light to commit to strategic economic development projects. Projects under this tariff must be approved by the Georgia PSC. PRPAtlanta Gas Light previously recovered PRP costs through a PRP surcharge established in 2015 to address recovery of the under recovered PRP balance and the related carrying costs. Effective January 2018, PRP costs are being recovered through GRAM and base rates until the earlier of the full recovery of the under recovered amount or December 31, 2025. The under recovered balance at December 31, 2019 was $135 million, including $70 million of unrecognized equity return. See "Rate Proceedings" and "Unrecognized Ratemaking Amounts" herein for additional information. Rate Proceedings Nicor Gas In January 2018, theIllinois Commission approved a $137 million increase in annual base rate revenues, including $93 million related to the recovery of investments under the Investing inIllinois program, effective in February 2018, based on a ROE of 9.8%. In May 2018, theIllinois Commission approved Nicor Gas' rehearing request for revised base rates to incorporate the reduction in the federal income tax rate as a result of the Tax Reform Legislation. The resulting decrease of approximately $44 million in annual base rate revenues became effective May 5, 2018. The benefits of the Tax Reform Legislation from January 25, 2018 through May 4, 2018 were refunded to customers via bill credits and concluded in the second quarter 2019. In November 2018, Nicor Gas filed a general base rate case with theIllinois Commission. On October 2, 2019, theIllinois Commission approved a $168 million annual base rate increase effective October 8, 2019. The base rate increase included $65 million related to the recovery of program costs under the Investing inIllinois program and was based on a ROE of 9.73% and an equity ratio of 54.2%. Additionally, theIllinois Commission approved a volume balancing adjustment, a revenue decoupling mechanism for residential customers that provides a monthly benchmark level of revenue per rate class for recovery.Atlanta Gas Light On June 3, 2019,Atlanta Gas Light filed a general base rate case with the Georgia PSC. On December 19, 2019, the Georgia PSC approved a $65 million annual base rate increase, effective January 1, 2020, based on a ROE of 10.25% and an equity ratio of 56%. Earnings will be evaluated against a ROE range of 10.05% to 10.45%, with disposition of any earnings above 10.45% to be determined by the Georgia PSC. Additionally, the Georgia PSC approved continuation of the previously authorized inclusion in base rates of the recovery of and return on the infrastructure program investments, including, but not limited to, GRAM adjustments, and a reauthorization and continuation of GRAM until terminated by the Georgia PSC. GRAM filing rate adjustments will be based on the authorized ROE of 10.25%. GRAM adjustments for 2021 may not exceed 5% of 2020 base rates. The 5% limitation does not set a precedent in any future rate proceedings byAtlanta Gas Light . On January 31, 2020, in accordance with the Georgia PSC's order for the 2019 rate case,Atlanta Gas Light filed a recommended notice of proposed rulemaking for a long-range planning tool. The proposal provides for participating natural gas utilities to file a comprehensive capacity supply and related infrastructure delivery plan for a 10-year period, including capital and related operations and maintenance expense budgets. Participating natural gas utilities would file an updated 10-year plan at least once every third year under the proposal. Related costs of implementing an approved comprehensive plan would be included in the utility's next rate case or GRAM filing. The rulemaking process is expected to be completed during 2020.Virginia Natural Gas In December 2018, theVirginia Commission approvedVirginia Natural Gas' annual information form filing, which reduced annual base rates by $14 million effective January 1, 2019 due to lower tax expense as a result of the Tax Reform Legislation, along with customer refunds, via bill credits, for $14 million related to 2018 tax benefits deferred as a regulatory liability at December 31, 2018. These customer refunds were completed in the first quarter 2019. On February 3, 2020,Virginia Natural Gas filed a notice of intent with theVirginia Commission as required prior to the filing of a base rate case, which will occur between April 3, 2020 and April 30, 2020. The ultimate outcome of this matter cannot be determined at this time. See Note 2 to the financial statements under "Southern Company Gas - Rate Proceedings" for additional information. II-77 -------------------------------------------------------------------------------- Table of Contents Index to Financial Statements
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Affiliate Asset Management Agreements With the exception of Nicor Gas, the natural gas distribution utilities use asset management agreements with an affiliate, Sequent, for the primary purpose of reducing utility customers' gas cost recovery rates through payments to the utilities by Sequent. ForAtlanta Gas Light , these payments are controlled by the Georgia PSC and are utilized for infrastructure improvements and to fund heating assistance programs, rather than as a reduction to gas cost recovery rates. Under these asset management agreements, Sequent supplies natural gas to the utility and markets available pipeline and storage capacity to improve the overall cost of supplying gas to the utility customers. Currently, the natural gas distribution utilities primarily purchase their gas from Sequent. The purchase agreements require Sequent to provide firm gas to the natural gas distribution utilities, but these natural gas distribution utilities maintain the right and ability to make their own long-term supply arrangements if they believe it is in the best interest of their customers. Each agreement provides for Sequent to make payments to the natural gas distribution utility through either an annual minimum guarantee within a profit sharing structure, a profit sharing structure without an annual minimum guarantee, or a fixed fee. Unrecognized Ratemaking Amounts The following table illustratesSouthern Company Gas' authorized ratemaking amounts that are not recognized on its balance sheets. These amounts are primarily composed of an allowed equity rate of return on assets associated with certain regulatory infrastructure programs. These amounts will be recognized as revenues inSouthern Company Gas' financial statements in the periods they are billable to customers, the majority of which will be recovered by 2025. December 31, 2019 December 31, 2018 (in millions) Atlanta Gas Light $ 70 $ 95 Virginia Natural Gas 10 11 Nicor Gas 2 4 Total $ 82 $ 110 Construction Programs The 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 inthe Southern Company system is Plant Vogtle Units 3 and 4. See "Nuclear Construction" herein for additional information. Also see "Regulatory Matters -Alabama Power " herein for information regardingAlabama Power's construction of Plant Barry Unit 8. While Southern Power generally constructs and acquires generation assets covered by long-term PPAs, any uncontracted capacity could negatively affect future earnings. See "Southern Power" herein, "Acquisitions and Dispositions - Southern Power" herein, and Note 15 to the financial statements 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 "Southern Company Gas" herein for additional information regarding infrastructure improvement programs at the natural gas distribution utilities and certain pipeline construction projects. See FINANCIAL CONDITION AND LIQUIDITY - "Capital Requirements" herein for additional information regarding the Registrants' capital requirements for their construction programs, including estimated totals for each of the next five years. Nuclear Construction In 2009, the Georgia PSC certified construction of Plant Vogtle Units 3 and 4. Georgia Power holds a 45.7% ownership interest in Plant Vogtle Units 3 and 4. In 2012, the NRC issued the related combined construction and operating licenses, which allowed full construction of the two AP1000 nuclear units (with electric generating capacity of approximately 1,100 MWs each) and related facilities to begin. Until March 2017, construction on Plant Vogtle Units 3 and 4 continued under the Vogtle 3 and 4 Agreement, II-78 -------------------------------------------------------------------------------- Table of Contents Index to Financial Statements
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which was a substantially fixed price agreement. In March 2017, the EPC Contractor filed for bankruptcy protection under Chapter 11 of theU.S. Bankruptcy Code. In connection with the EPC Contractor's bankruptcy filing, Georgia Power, acting for itself and as agent for the other Vogtle Owners, entered into several transitional arrangements to allow construction to continue. In July 2017, Georgia Power, acting for itself and as agent for the other Vogtle Owners, entered into the Vogtle Services Agreement, whereby Westinghouse provides facility design and engineering services, procurement and technical support, and staff augmentation on a time and materials cost basis. The Vogtle Services Agreement provides that it will continue until the start-up and testing of Plant Vogtle Units 3 and 4 are complete and electricity is generated and sold from both units. The Vogtle Services Agreement is terminable by the Vogtle Owners upon 30 days' written notice. In October 2017, Georgia Power, acting for itself and as agent for the other Vogtle Owners, executed the Bechtel Agreement, a cost reimbursable plus fee arrangement, whereby Bechtel is reimbursed for actual costs plus a base fee and an at-risk fee, which is subject to adjustment based on Bechtel's performance against cost and schedule targets. Each Vogtle Owner is severally (not jointly) liable for its proportionate share, based on its ownership interest, of all amounts owed to Bechtel under the Bechtel Agreement. The Vogtle Owners may terminate the Bechtel Agreement at any time for their convenience, provided that the Vogtle Owners will be required to pay amounts related to work performed prior to the termination (including the applicable portion of the base fee), certain termination-related costs, and, at certain stages of the work, the applicable portion of the at-risk fee. Bechtel may terminate the Bechtel Agreement under certain circumstances, including certain Vogtle Owner suspensions of work, certain breaches of the Bechtel Agreement by the Vogtle Owners, Vogtle Owner insolvency, and certain other events. See Note 8 to the financial statements under "Long-term Debt - DOE Loan Guarantee Borrowings" for information on the Amended and Restated Loan Guarantee Agreement, including applicable covenants, events of default, mandatory prepayment events, and conditions to borrowing. Cost and Schedule Georgia Power's approximate proportionate share of the remaining estimated capital cost to complete Plant Vogtle Units 3 and 4 by the expected in-service dates of November 2021 and November 2022, respectively, is as follows: (in billions)
Base project capital cost forecast(a)(b) $ 8.2 Construction contingency estimate
0.2
Total project capital cost forecast(a)(b) 8.4 Net investment as of December 31, 2019(b) (5.9 ) Remaining estimate to complete(a) $ 2.5
(a) Excludes financing costs expected to be capitalized through AFUDC of
approximately $300 million, of which $23 million had been accrued through
December 31, 2019.
(b) Net of $1.7 billion received from Toshiba under the Guarantee Settlement
Agreement and approximately $188 million in related customer refunds.
As of December 31, 2019, approximately $140 million of the $366 million construction contingency estimate established in the second quarter 2018 was allocated to the base capital cost forecast for cost risks including, among other factors, construction productivity; craft labor incentives; adding resources for supervision, field support, project management, initial test program, start-up, and operations and engineering support; subcontracts; and procurement. As and when construction contingency is spent, Georgia Power may request the Georgia PSC to evaluate those expenditures for rate recovery. Georgia Power estimates that its financing costs for construction of Plant Vogtle Units 3 and 4 will total approximately $3.1 billion, of which $2.2 billion had been incurred through December 31, 2019. As part of its ongoing processes, Southern Nuclear continues to evaluate cost and schedule forecasts on a regular basis to incorporate current information available, particularly in the areas of commodity installation, system turnovers, and workforce statistics. In April 2019, Southern Nuclear established aggressive target values for monthly construction production and system turnover activities as part of a strategy to maintain and, where possible, build margin to the regulatory-approved in-service dates of November 2021 for Unit 3 and November 2022 for Unit 4. The project has faced challenges with the April 2019 aggressive strategy targets, including, but not limited to, electrical and pipefitting labor productivity and closure rates for work packages, which resulted in a backlog of activities and completion percentages below the April 2019 aggressive strategy targets. However, II-79 -------------------------------------------------------------------------------- Table of Contents Index to Financial Statements
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Southern Nuclear and Georgia Power believe that existing productivity levels and pace of activity completion are sufficient to meet the regulatory-approved in-service dates. In February 2020, Southern Nuclear updated its cost and schedule forecast, which did not change the projected overall capital cost forecast and confirmed the expected in-service dates of November 2021 for Unit 3 and November 2022 for Unit 4. This update included initiatives to improve productivity while refining and extending system turnover plans and certain near-term milestone dates. Other milestone dates did not change. Achievement of the aggressive site work plan relies on meeting increased monthly production and activity target values during 2020. To meet these 2020 targets, existing craft, including subcontractors, construction productivity must improve and be sustained above historical average levels, appropriate levels of craft laborers, particularly electrical and pipefitter craft labor, must be maintained, and additional supervision and other field support resources must be retained. Southern Nuclear and Georgia Power continue to believe that pursuit of an aggressive site work plan is an appropriate strategy to achieve completion of the units by their regulatory-approved in-service dates. As construction, including subcontract work, continues and testing and system turnover activities increase, challenges with management of contractors and vendors; subcontractor performance; supervision of craft labor and related craft labor productivity, particularly in the installation of electrical and mechanical commodities, ability to attract and retain craft labor, and/or related cost escalation; procurement, fabrication, delivery, assembly, installation, system turnover, and the initial testing and start-up, including any required engineering changes or any remediation related thereto, of plant systems, structures, or components (some of which are based on new technology that only within the last few years began initial operation in the global nuclear industry at this scale), or regional transmission upgrades, any of which may require additional labor and/or materials; or other issues could arise and change the projected schedule and estimated cost. There have been technical and procedural challenges to the construction and licensing of Plant Vogtle Units 3 and 4 at the federal and state level and additional challenges may arise. Processes are in place that are designed to assure compliance with the requirements specified in the Westinghouse Design Control Document and the combined construction and operating licenses, including inspections by Southern Nuclear and the NRC that occur throughout construction. As a result of such compliance processes, certain license amendment requests have been filed and approved or are pending before the NRC. Various design and other licensing-based compliance matters, including the timely submittal by Southern Nuclear of the ITAAC documentation for each unit and the related reviews and approvals by the NRC necessary to support NRC authorization to load fuel, may arise, which may result in additional license amendments or require other resolution. As part of the aggressive site work plan, in January 2020, Southern Nuclear notified the NRC of its intent to load fuel in 2020. If any license amendment requests or other licensing-based compliance issues are not resolved in a timely manner, there may be delays in the project schedule that could result in increased costs. The ultimate outcome of these matters cannot be determined at this time. However, any extension of the regulatory-approved project schedule is currently estimated to result in additional base capital costs of approximately $50 million per month, based on Georgia Power's ownership interests, and AFUDC of approximately $12 million per month. While Georgia Power is not precluded from seeking recovery of any future capital cost forecast increase, management will ultimately determine whether or not to seek recovery. Any further changes to the capital cost forecast that are not expected to be recoverable through regulated rates will be required to be charged to income and such charges could be material. Joint Owner Contracts In November 2017, the Vogtle Owners entered into an amendment to their joint ownership agreements for Plant Vogtle Units 3 and 4 to provide for, among other conditions, additional Vogtle Owner approval requirements. Effective in August 2018, the Vogtle Owners further amended the joint ownership agreements to clarify and provide procedures for certain provisions of the joint ownership agreements related to adverse events that require the vote of the holders of at least 90% of the ownership interests in Plant Vogtle Units 3 and 4 to continue construction (as amended, and together with the November 2017 amendment, the Vogtle Joint Ownership Agreements). The Vogtle Joint Ownership Agreements also confirm that the Vogtle Owners' sole recourse against Georgia Power or Southern Nuclear for any action or inaction in connection with their performance as agent for the Vogtle Owners is limited to removal of Georgia Power and/or Southern Nuclear as agent, except in cases of willful misconduct. As a result of an increase in the total project capital cost forecast and Georgia Power's decision not to seek rate recovery of the increase in the base capital costs in conjunction with the nineteenth VCM report in 2018, the holders of at least 90% of the ownership interests in Plant Vogtle Units 3 and 4 were required to vote to continue construction. In September 2018, the Vogtle Owners unanimously voted to continue construction of Plant Vogtle Units 3 and 4. II-80 -------------------------------------------------------------------------------- Table of Contents Index to Financial Statements
COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Amendments to the Vogtle Joint Ownership Agreements In connection with the vote to continue construction, Georgia Power entered into (i) a binding term sheet (Vogtle Owner Term Sheet) with the other Vogtle Owners and MEAG Power's wholly-owned subsidiaries MEAG Power SPVJ, LLC (MEAG SPVJ), MEAG Power SPVM, LLC (MEAG SPVM), and MEAG Power SPVP, LLC (MEAG SPVP) to take certain actions which partially mitigate potential financial exposure for the other Vogtle Owners, including additional amendments to the Vogtle Joint Ownership Agreements and the purchase of PTCs from the other Vogtle Owners at pre-established prices, and (ii) a term sheet (MEAG Term Sheet) with MEAG Power and MEAG SPVJ to provide funding with respect to MEAG SPVJ's ownership interest in Plant Vogtle Units 3 and 4 under certain circumstances. On January 14, 2019, Georgia Power, MEAG Power, and MEAG SPVJ entered into an agreement to implement the provisions of the MEAG Term Sheet. On February 18, 2019, Georgia Power, the other Vogtle Owners, and MEAG Power's wholly-owned subsidiaries MEAG SPVJ, MEAG SPVM, and MEAG SPVP entered into certain amendments to the Vogtle Joint Ownership Agreements to implement the provisions of the Vogtle Owner Term Sheet. The ultimate outcome of these matters cannot be determined at this time. Regulatory Matters In 2009, the Georgia PSC voted to certify construction of Plant Vogtle Units 3 and 4 with a certified capital cost of $4.418 billion. In addition, in 2009 the Georgia PSC approved inclusion of the Plant Vogtle Units 3 and 4 related CWIP accounts in rate base, and theState of Georgia enacted the Georgia Nuclear Energy Financing Act, which allows Georgia Power to recover financing costs for Plant Vogtle Units 3 and 4. Financing costs are recovered on all applicable certified costs through annual adjustments to the NCCR tariff up to the certified capital cost of $4.418 billion. At December 31, 2019, Georgia Power had recovered approximately $2.2 billion of financing costs. Financing costs related to capital costs above $4.418 billion are being recognized through AFUDC and are expected to be recovered through retail rates over the life of Plant Vogtle Units 3 and 4; however, Georgia Power will not record AFUDC related to any capital costs in excess of the total deemed reasonable by the Georgia PSC (currently $7.3 billion) and not requested for rate recovery. On December 17, 2019, the Georgia PSC approved Georgia Power's request to decrease the NCCR tariff by $62 million annually, effective January 1, 2020. Georgia Power is required to file semi-annual VCM reports with the Georgia PSC by February 28 and August 31 of each year. In 2013, in connection with the eighth VCM report, the Georgia PSC approved a stipulation between Georgia Power and the staff of the Georgia PSC to waive the requirement to amend the Plant Vogtle Units 3 and 4 certificate in accordance with the 2009 certification order until the completion of Plant Vogtle Unit 3, or earlier if deemed appropriate by the Georgia PSC and Georgia Power. In 2016, the Georgia PSC voted to approve a settlement agreement (Vogtle Cost Settlement Agreement) resolving certain prudency matters in connection with the fifteenth VCM report. In December 2017, the Georgia PSC voted to approve (and issued its related order on January 11, 2018) Georgia Power's seventeenth VCM report and modified the Vogtle Cost Settlement Agreement. The Vogtle Cost Settlement Agreement, as modified by the January 11, 2018 order, resolved the following regulatory matters related to Plant Vogtle Units 3 and 4: (i) none of the $3.3 billion of costs incurred through December 31, 2015 and reflected in the fourteenth VCM report should be disallowed from rate base on the basis of imprudence; (ii) the Contractor Settlement Agreement was reasonable and prudent and none of the amounts paid pursuant to the Contractor Settlement Agreement should be disallowed from rate base on the basis of imprudence; (iii) (a) capital costs incurred up to $5.68 billion would be presumed to be reasonable and prudent with the burden of proof on any party challenging such costs, (b) Georgia Power would have the burden to show that any capital costs above $5.68 billion were prudent, and (c) a revised capital cost forecast of $7.3 billion (after reflecting the impact of payments received under the Guarantee Settlement Agreement and related customer refunds) was found reasonable; (iv) construction of Plant Vogtle Units 3 and 4 should be completed, with Southern Nuclear serving as project manager and Bechtel as primary contractor; (v) approved and deemed reasonable Georgia Power's revised schedule placing Plant Vogtle Units 3 and 4 in service in November 2021 and November 2022, respectively; (vi) confirmed that the revised cost forecast does not represent a cost cap and that prudence decisions on cost recovery will be made at a later date, consistent with applicableGeorgia law; (vii) reduced the ROE used to calculate the NCCR tariff (a) from 10.95% (the ROE rate setting point authorized by the Georgia PSC in the 2013 ARP) to 10.00% effective January 1, 2016, (b) from 10.00% to 8.30%, effective January 1, 2020, and (c) from 8.30% to 5.30%, effective January 1, 2021 (provided that the ROE in no case will be less than Georgia Power's average cost of long-term debt); (viii) reduced the ROE used for AFUDC equity for Plant Vogtle Units 3 and 4 from 10.00% to Georgia Power's average cost of long-term debt, effective January 1, 2018; and (ix) agreed that upon Unit 3 reaching commercial operation, retail base rates would be adjusted to include carrying costs on those capital costs deemed prudent in the Vogtle Cost Settlement Agreement. The January 11, 2018 order also stated that if Plant Vogtle Units 3 and 4 are not commercially operational by June 1, 2021 and June 1, 2022, respectively, the ROE used to calculate the NCCR tariff will be further reduced by 10 basis points each month (but not lower than Georgia Power's average cost of long-term debt) until the respective Unit is commercially operational. The ROE reductions negatively impacted earnings by approximately $75 million, II-81 -------------------------------------------------------------------------------- Table of Contents Index to Financial Statements
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$100 million, and $25 million in 2019, 2018, and 2017, respectively, and are estimated to have negative earnings impacts of approximately $140 million, $240 million, and $190 million in 2020, 2021, and 2022, respectively. In its January 11, 2018 order, the Georgia PSC also stated if other conditions change and assumptions upon which Georgia Power's seventeenth VCM report are based do not materialize, the Georgia PSC reserved the right to reconsider the decision to continue construction. In February 2018, Georgia Interfaith Power & Light, Inc. (GIPL) and Partnership for Southern Equity, Inc. (PSE) filed a petition appealing the Georgia PSC's January 11, 2018 order with theFulton County Superior Court. In March 2018, Georgia Watch filed a similar appeal to theFulton County Superior Court for judicial review of the Georgia PSC's decision and denial of Georgia Watch's motion for reconsideration. In December 2018, theFulton County Superior Court granted Georgia Power's motion to dismiss the two appeals. On January 9, 2019, GIPL, PSE, and Georgia Watch filed an appeal of this decision with theGeorgia Court of Appeals. On October 29, 2019, theGeorgia Court of Appeals issued an opinion affirming theFulton County Superior Court's ruling that theGeorgia PSC's January 11, 2018 order was not a final, appealable decision. In addition, theGeorgia Court of Appeals remanded the case to theFulton County Superior Court to clarify its ruling as to whether the petitioners showed that review of the Georgia PSC's final order would not provide them an adequate remedy.Georgia Power believes the petitions have no merit; however, an adverse outcome in the litigation combined with subsequent adverse action by the Georgia PSC could have a material impact onSouthern Company's and Georgia Power's results of operations, financial condition, and liquidity. On February 18, 2020, the Georgia PSC approved Georgia Power's twentieth VCM report and its concurrently-filed twenty-first VCM report, including approval of (i) $1.2 billion of construction capital costs incurred from July 1, 2018 through June 30, 2019 and (ii) $21.5 million of expenditures related toGeorgia Power's portion of an administrative claim filed in the Westinghouse bankruptcy proceedings (which expenditures had previously been deferred by the Georgia PSC for later approval). Through the twenty-first VCM, the Georgia PSC has approved total construction capital costs incurred through June 30, 2019 of $6.7 billion (before $1.7 billion of payments received under the Guarantee Settlement Agreement and approximately $188 million in related customer refunds). On February 19, 2020, Georgia Power filed its twenty-second VCM report with the Georgia PSC covering the period from July 1, 2019 through December 31, 2019, requesting approval of $674 million of construction capital costs incurred during that period. The ultimate outcome of these matters cannot be determined at this time. Southern Power During 2019, Southern Power completed construction of and placed in service the 385-MW Plant Mankato expansion and the Wildhorse Mountain facility, acquired and continued construction of the Skookumchuck facility, and continued construction of the Reading facility. Approximate Nameplate PPA Project Capacity Actual/Expected PPA Contract Facility Resource (MW) Location COD
Counterparties Period
Projects Completed During the Year Ended December 31, 2019
Northern 20 years expansion(a) States Power Company Wildhorse Wind 100 Pushmataha December 2019 Arkansas 20 years Mountain (b) County, OK Electric Cooperative Corporation Projects Under Construction at December 31, 2019 Reading(c) Wind 200 Osage and Second quarter 2020 Royal 12 years Lyon Caribbean Counties, KS Cruises LTD Skookumchuck(d) Wind 136 Lewis and Second quarter 2020 Puget Sound 20 years Thurston Energy Counties, WA
(a) Southern Power completed the sale of its equity interests in Plant Mankato,
including the expansion, to a subsidiary of Xcel on January 17, 2020. The
expansion unit started providing energy under a PPA with Northern States
Power on June 1, 2019. See "Acquisitions and Dispositions - Southern Power -
Sales of Natural Gas and Biomass Plants" herein and Note 15 to the financial
statements under "Southern Power" and "Assets Held for Sale" for additional
information.
(b) In May 2018, Southern Power purchased 100% of the membership interests of the
Wildhorse Mountain facility. In December 2019, Southern Power entered into a
tax equity partnership and, as a result, owns 100% of the Class B membership
interests.
(c) In August 2018, Southern Power purchased 100% of the membership interests of
the Reading facility pursuant to a joint development arrangement. Southern
Power may enter into a tax equity partnership, in which case it would then
own 100% of the Class B membership interests. The ultimate outcome of this
matter cannot be determined at this time. II-82
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(d) In October 2019, Southern Power purchased 100% of the membership interests of
the Skookumchuck facility pursuant to a joint development arrangement. In
December 2019, Southern Power entered into a tax equity agreement as the
Class B member with funding of the tax equity amounts expected to occur upon
commercial operation. Shortly after commercial operation, Southern Power may
sell a noncontrolling interest in these Class B membership interests to
another partner. The ultimate outcome of this matter cannot be determined at
this time.
Total aggregate construction costs for the two projects under construction at December 31, 2019, excluding acquisition costs, are expected to be between $490 million and $535 million. At December 31, 2019, total costs of construction incurred for these projects were $417 million and are included in CWIP. The ultimate outcome of these matters cannot be determined at this time.Southern Company Gas Infrastructure Replacement Programs and Capital ProjectsSouthern Company Gas continues to focus on capital discipline and cost control while pursuing projects and initiatives that are expected to have current and future benefits to customers, provide an appropriate return on invested capital, and help ensure the safety and reliability of the utility infrastructure. In addition to capital expenditures recovered through base rates by each of the natural gas distribution utilities, Nicor Gas andVirginia Natural Gas have separate rate riders that provide timely recovery of capital expenditures for specific infrastructure replacement programs. Total capital expenditures incurred during 2019 for gas distribution operations were $1.4 billion. The following table and discussions provide updates on the infrastructure replacement programs and capital projects at the natural gas distribution utilities at December 31, 2019. These programs are risk-based and designed to update and replace cast iron, bare steel, and mid-vintage plastic materials or expandSouthern Company Gas' distribution systems to improve reliability and meet operational flexibility and growth. The anticipated expenditures for these programs in 2020 are quantified in the discussion below. Pipe Installed Since Last Expenditures in Expenditures Since Project Scope of Program Year of
Utility Program Recovery 2019 Project Inception Inception Program Duration Program (in millions) (miles) (miles) (years) Nicor Gas Investing in Illinois(*) Rider $ 396 $ 1,712 843 1,450 9 2023 Virginia Steps to Advance Natural Virginia's Energy Gas (SAVE and SAVE II) Rider 45 244 363 770 13 2024 Total $ 441 $ 1,956 1,206 2,220
(*) Includes replacement of pipes, compressors, and transmission mains along with
other improvements such as new meters. Scope of program miles is an estimate
and subject to change. Nicor Gas In 2013,Illinois enacted legislation that allows Nicor Gas to provide more widespread safety and reliability enhancements to its distribution system. The legislation stipulates that rate increases to customers as a result of any infrastructure investments shall not exceed a cumulative annual average of 4.0% or, in any given year, 5.5% of base rate revenues. In 2014, theIllinois Commission approved the nine-year regulatory infrastructure program, Investing inIllinois , subject to annual review. Nicor Gas expects to place into service $400 million of qualifying projects under Investing inIllinois in 2020. In conjunction with the base rate case order issued by theIllinois Commission in January 2018, Nicor Gas is recovering program costs incurred prior to December 31, 2017 through base rates. Additionally, theIllinois Commission's approval of Nicor Gas' rate case on October 2, 2019 included $65 million in annual revenues related to the recovery of program costs from January 1, 2018 through September 30, 2019 under the Investing inIllinois program. See "Regulatory Matters -Southern Company Gas - Rate Proceedings" herein for additional information.Virginia Natural Gas In 2012, theVirginia Commission approved the SAVE program, an accelerated infrastructure replacement program. In 2016 and on September 25, 2019, theVirginia Commission approved amendments and extensions to the SAVE program. The latest extension allowsVirginia Natural Gas to continue replacing aging pipeline infrastructure through 2024 and increases its authorized investment under the previously-approved plan from $35 million to $40 million in 2019 with additional annual investments of $50 million in 2020, $60 million in 2021, $70 million in each year from 2022 through 2024, and a total potential II-83 -------------------------------------------------------------------------------- Table of Contents Index to Financial Statements
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variance of up to $5 million allowed for the program, for a maximum total investment over the six-year term (2019 through 2024) of $365 million.Virginia Natural Gas expects to invest $50 million under this program in 2020. The SAVE program is subject to annual review by theVirginia Commission. In accordance with the base rate case order issued by theVirginia Commission in 2017,Virginia Natural Gas is recovering program costs incurred prior to September 1, 2017 through base rates. Program costs incurred subsequent to September 1, 2017 are currently recovered through a separate rider and are subject to future base rate case proceedings. On December 6, 2019,Virginia Natural Gas filed an application with theVirginia Commission for a 24.1-mile header improvement project to improve resiliency and increase the supply of natural gas delivered to energy suppliers, includingVirginia Natural Gas . The cost of the project is expected to total $346 million. TheVirginia Commission is expected to rule on this application in the second quarter 2020. Construction is expected to begin in June 2021 and the project is expected to be placed in service in the fourth quarter 2022. The ultimate outcome of this matter cannot be determined at this time.Atlanta Gas Light As discussed under "Regulatory Matters -Southern Company Gas - Utility Regulation and Rate Design" herein, i-SRP and i-VPR will continue under GRAM and the recovery of and return on current and future infrastructure program capital investments will be included in base rates. Pipeline Construction ProjectsSouthern Company Gas is involved in two significant pipeline construction projects within its gas pipeline investments segment. These projects, along withSouthern Company Gas' existing pipelines, are intended to provide diverse sources of natural gas supplies to customers, resolve current and long-term supply planning for new capacity, enhance system reliability, and generate economic development in the areas served. In 2014,Southern Company Gas entered into a joint venture, whereby it holds a 5% ownership interest in the Atlantic Coast Pipeline, an interstate pipeline company formed to develop and operate an approximate 605-mile natural gas pipeline inNorth Carolina ,Virginia , andWest Virginia with expected initial transportation capacity of 1.5 Bcf per day. The proposed pipeline project is expected to transport natural gas to customers inVirginia . In 2017, the Atlantic Coast Pipeline receivedFERC approval. The Atlantic Coast Pipeline has experienced challenges to its permits since construction began in 2018. During the third and fourth quarters 2018, aFERC stop work order, together with delays in obtaining permits necessary for construction and construction delays due to judicial actions, impacted the cost and schedule for the project. Project cost estimates are approximately $8.0 billion ($400 million forSouthern Company Gas ), excluding financing costs. On October 4, 2019, theU.S. Supreme Court agreed to hear Atlantic Coast Pipeline's appeal of a lower court ruling that overturned a key permit for the project. On January 7, 2020, theU.S. Court of Appeals for the Fourth Circuit vacated another key permit. The operator of the joint venture has indicated that it currently expects to complete construction by the end of 2021 and place the project in service shortly thereafter. On February 7, 2020,Southern Company Gas entered into an agreement with Dominion Atlantic Coast Pipeline, LLC for the sale of its interest inAtlantic Coast Pipeline. The transaction is expected to be completed in the first half of 2020; however, the ultimate outcome cannot be determined at this time. See Note 15 to the financial statements under "Southern Company Gas - Proposed Sale of Pivotal LNG and Atlantic Coast Pipeline" for additional information. Also in 2014,Southern Company Gas entered into a partnership in which it holds a 20% ownership interest in the PennEast Pipeline, an interstate pipeline company formed to develop and operate an approximate 118-mile natural gas pipeline betweenNew Jersey andPennsylvania . The expected initial transportation capacity of 1.0 Bcf per day is under long-term contracts, mainly with public utilities and other market-serving entities, such as electric generation companies, inNew Jersey ,Pennsylvania , andNew York .Southern Company Gas believes this pipeline will alleviate takeaway constraints in the Marcellus region and help mitigate some of the price volatility experienced during recent winters. Expected project costs related to the PennEast Pipeline forSouthern Company Gas total approximately $300 million, excluding financing costs. In January 2018, the PennEast Pipeline received initialFERC approval. Work continues with state and federal agencies to obtain the required permits to begin construction. On September 10, 2019, an appellate court ruled that the PennEast Pipeline does not have federal eminent domain authority over lands in which a state has property rights interests. On February 18, 2020, PennEast Pipeline filed a petition for a writ of certiorari to seekU.S. Supreme Court review of the appellate court decision. On December 30, 2019, PennEast Pipeline filed a two-year extension request with theFERC to complete the project by January 19, 2022. II-84 -------------------------------------------------------------------------------- Table of Contents Index to Financial Statements
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Additionally, on January 30, 2020, PennEast Pipeline filed an amendment with theFERC to construct the pipeline project in two phases. The first phase would consist of 68 miles of pipe, constructed entirely withinPennsylvania , which is expected to be completed by November 2021. The second phase would include the remaining route inPennsylvania andNew Jersey and is targeted for completion in 2023.FERC approval of the amended plan is required prior to beginning the first phase. The ultimate outcome of these matters cannot be determined at this time; however, any work delays, whether caused by judicial or regulatory action, abnormal weather, or other conditions, may result in additional cost or schedule modifications or, ultimately, in project cancellation, any of which could result in an impairment of one or both ofSouthern Company Gas' investments and could have a material impact onSouthern Company's andSouthern Company Gas' financial statements.Southern Company Gas evaluated its investments and determined there was no impairment as of December 31, 2019. See Notes 3 and 7 to the financial statements under "Guarantees" and "Southern Company Gas - Equity Method Investments," respectively, for additional information on these pipeline projects. Southern Power's Power Sales AgreementsGeneral Southern Power has PPAs with some of the traditional electric operating companies, other investor-owned utilities, IPPs, municipalities, and other load-serving entities, as well as commercial and industrial customers. The PPAs are expected to provide Southern Power with a stable source of revenue during their respective terms. Many of Southern Power's PPAs have provisions that require Southern Power or the counterparty to post collateral or an acceptable substitute guarantee in the event that S&P or Moody's downgrades the credit ratings of the respective company to an unacceptable credit rating or if the counterparty is not rated or fails to maintain a minimum coverage ratio. On January 29, 2019, Pacific Gas & Electric Company (PG&E) filed petitions to reorganize under Chapter 11 of theU.S. Bankruptcy Code. Southern Power, together with its noncontrolling partners, owns four solar facilities where PG&E is the energy off-taker for approximately 207 MWs of capacity under long-term PPAs. PG&E is also the transmission provider for these four facilities and two of Southern Power's other solar facilities. At December 31, 2019, Southern Power had outstanding accounts receivables due from PG&E of $2 million related to the PPAs and $33 million related to the transmission interconnections (of which $27 million is classified in receivables - other and $6 million is classified in other deferred charges and assets). Subsequent to December 31, 2019, Southern Power received $15 million in accordance with a November 2019 bankruptcy court order granting payment of transmission interconnections for amounts due and owing. Southern Power continues to evaluate the recoverability of its investments in these solar facilities under various scenarios, including selling the related energy into the competitive markets, and has concluded that these solar facilities are not impaired. PG&E has continued to perform under the terms of the PPAs. Southern Power does not expect a material impact to its financial statements if, as a result of the bankruptcy proceedings, PG&E does not perform in accordance with the PPAs or the terms of the PPAs are renegotiated; however, the ultimate outcome of this matter cannot be determined at this time. Southern Power is working to maintain and expand its share of the wholesale markets. During 2019, Southern Power saw an increase in the demand for energy and capacity that can be served from natural gas generating facilities, especially in the Southeast, and expects that this increase in demand will continue in the near term (2020-2022), with timing varying depending on the market. During 2019, Southern Power successfully remarketed approximately 190 to 650 MWs of annual natural gas generation capacity to load-serving entities through several PPAs extending over the next nine years. Southern Power calculates an 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. With the inclusion of investments associated with the wind facilities currently under construction, as well as other capacity and energy contracts, and excluding Plant Mankato, which was sold on January 17, 2020, Southern Power's average investment coverage ratio at December 31, 2019 was 93% through 2024 and 90% through 2029, with an average remaining contract duration of approximately 14 years. See "Acquisitions and Dispositions - Southern Power" and "Construction Programs - Southern Power" herein for additional information. Natural Gas Southern Power's electricity sales from natural gas facilities are primarily through long-term PPAs that consist of two types of agreements. The first type, referred to as a unit or block sale, is a customer purchase from a dedicated generating unit where all or a portion of the generation from that unit is reserved for that customer. Southern Power typically has the ability to serve the unit or block sale customer from an alternate resource. The second type, referred to as requirements service, provides that Southern Power serve the customer's capacity and energy requirements from a combination of the customer's own generating units and II-85 -------------------------------------------------------------------------------- Table of Contents Index to Financial Statements
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from Southern Power resources not dedicated to serve unit or block sales. Southern Power has rights to purchase power provided by the requirements customers' resources when economically viable. As a general matter, substantially all of the PPAs 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 or purchased power relating to the energy delivered under such PPAs. To the extent a particular generating facility does not meet the operational requirements contemplated in the PPAs, Southern Power may be responsible for excess fuel costs. With respect to fuel transportation risk, most of Southern Power's PPAs provide that the counterparties are responsible for the availability of fuel transportation to the particular generating facility. Capacity charges that form part of the PPA payments are designed to recover fixed and variable operation and maintenance costs based on dollars-per-kilowatt year. In general, to reduce Southern Power's exposure to certain operation and maintenance costs, Southern Power has LTSAs. See Note 1 to the financial statements under "Long-Term Service Agreements" for additional information. Solar and Wind Southern Power's electricity sales from solar and wind (renewable) generating facilities are also primarily through long-term PPAs; however, these 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 provide Southern Power a certain fixed price for the electricity 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. Generally, under the renewable generation PPAs, the purchasing party retains the right to keep or resell the renewable energy credits. Income Tax Matters Consolidated Income Taxes On behalf of the Registrants,Southern Company files a consolidated federal income tax return and various state income tax returns, some of which are combined or unitary. Under a joint consolidated income tax allocation agreement, eachSouthern Company subsidiary's current and deferred tax expense is computed on a stand-alone basis and no subsidiary is allocated more current expense than would be paid if it filed a separate income tax return. In accordance withIRS regulations, each company is jointly and severally liable for the federal tax liability. The impact of certain tax events atSouthern Company and/or its other subsidiaries can, and does, affect each Registrant's ability to utilize certain tax credits. See "Tax Credits" and ACCOUNTING POLICIES - "Application of Critical Accounting Policies and Estimates" herein and Note 10 to the financial statements for additional information. Federal Tax Reform Legislation In 2017, the Tax Reform Legislation was signed into law and became effective on January 1, 2018. The Tax Reform Legislation, among other things, reduced the federal corporate income tax rate to 21%, retained normalization provisions for public utility property and existing renewable energy incentives, and repealed the corporate alternative minimum tax. In addition, under the Tax Reform Legislation, NOLs generated after December 31, 2017 can no longer be carried back to previous tax years but can be carried forward indefinitely, with utilization limited to 80% of taxable income of the subsequent tax year. The projected reduction ofSouthern Company's consolidated income tax liability resulting from the tax rate reduction also delays the expected utilization of existing tax credit carryforwards. See "Consolidated Income Taxes" herein and Note 10 to the financial statements for information onSouthern Company's joint consolidated income tax allocation agreement. II-86 -------------------------------------------------------------------------------- Table of Contents Index to Financial Statements
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Bonus Depreciation Under the Tax Reform Legislation, projects with binding contracts prior to September 28, 2017 and placed in service after September 27, 2017 remain eligible for 50% bonus depreciation for 2015 through 2017, 40% bonus depreciation for 2018, and 30% bonus depreciation for 2019 and certain long-lived assets placed in service in 2020. Based on provisional estimates, bonus depreciation is expected to result in positive cash flows for the Registrants as follows: 2019 Tax Year 2020 Tax Year (in millions) Southern Company $ 989 $ 382 Alabama Power 180 68 Georgia Power 314 56 Mississippi Power 7 2 Southern Power(*) 87 95 Southern Company Gas 190 58
(*) Cash flows resulting from bonus depreciation for Southern Power would also be
impacted by Southern Power's use of tax equity partnerships.
See Note 10 to the financial statements under "Current and Deferred Income Taxes" for additional information. The ultimate outcome of this matter cannot be determined at this time. Tax Credits The Tax Reform Legislation retained solar energy incentives of 30% ITC for projects that commenced construction by December 31, 2019; 26% ITC for projects that commence construction in 2020; 22% ITC for projects that commence construction in 2021; and a permanent 10% ITC for projects that commence construction on or after January 1, 2022. In addition, the Tax Reform Legislation retained wind energy incentives of 100% PTC for projects that commenced construction in 2016; 80% PTC for projects that commenced construction in 2017; 60% PTC for projects that commenced construction in 2018; and 40% PTC for projects that commenced construction in 2019. As a result of a tax extenders bill passed in December 2019, projects that begin construction in 2020 will be entitled to 60% PTC. Projects commencing construction after 2020 will not be entitled to any PTCs.Southern Company has received ITCs and PTCs in connection with investments in solar, wind, and biomass facilities primarily at Southern Power and Georgia Power. Southern Power's ITCs relate to its investment in new solar facilities acquired or constructed and its PTCs relate to the first 10 years of energy production from its wind facilities, which have had, and may continue to have, a material impact on Southern Power's cash flows and net income. At December 31, 2019,Southern Company and Southern Power had approximately $1.8 billion and $1.4 billion, respectively, of unutilized ITCs and PTCs, which are currently expected to be fully utilized by 2024, but could be further delayed. Since 2018, Southern Power has been utilizing tax equity partnerships for wind and solar projects, where the tax partner takes significantly all of the respective federal tax benefits. These tax equity partnerships are consolidated inSouthern Company's and Southern Power's financial statements using the HLBV methodology to allocate partnership gains and losses. See Note 1 to the financial statements under "General" for additional information on the HLBV methodology and Note 1 to the financial statements under "Income Taxes" and Note 10 to the financial statements under "Deferred Tax Assets and Liabilities - Tax Credit Carryforwards" and "Effective Tax Rate" for additional information regarding utilization and amortization of credits and the tax benefit related to associated basis differences. General Litigation Matters The Registrants are involved in various other matters being litigated and regulatory matters that could affect future earnings. The ultimate outcome of such pending or potential litigation or regulatory matters against each Registrant and any subsidiaries cannot be determined at this time; however, for current proceedings not specifically reported herein or in Notes 2 and 3 to the financial statements, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on such Registrant's financial statements. See Notes 2 and 3 to the financial statements for a discussion of various other contingencies, regulatory matters, and other matters being litigated which may affect future earnings potential. The Registrants believe the pending legal challenges discussed below have no merit; however, the ultimate outcome of these matters cannot be determined at this time. II-87 -------------------------------------------------------------------------------- Table of Contents Index to Financial Statements
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Southern Company In January 2017, a securities class action complaint was filed againstSouthern Company , certain of its officers, and certain former Mississippi Power officers in theU.S. District Court for the Northern District ofGeorgia byMonroe County Employees' Retirement System on behalf of all persons who purchased shares ofSouthern Company's common stock between April 25, 2012 and October 29, 2013. The complaint alleges thatSouthern Company , certain of its officers, and certain former Mississippi Power officers made materially false and misleading statements regarding theKemper County energy facility in violation of certain provisions under the Securities Exchange Act of 1934, as amended. The complaint seeks, among other things, compensatory damages and litigation costs and attorneys' fees. In 2017, the plaintiffs filed an amended complaint that provided additional detail about their claims, increased the purported class period by one day, and added certain other former Mississippi Power officers as defendants. Also in 2017, the defendants filed a motion to dismiss the plaintiffs' amended complaint with prejudice, to which the plaintiffs filed an opposition. In March 2018, the court issued an order granting, in part, the defendants' motion to dismiss. The court dismissed certain claims against certain officers ofSouthern Company and Mississippi Power and dismissed the allegations related to a number of the statements that plaintiffs challenged as being false or misleading. In April 2018, the defendants filed a motion for reconsideration of the court's order, seeking dismissal of the remaining claims in the lawsuit. In August 2018, the court denied the motion for reconsideration and denied a motion to certify the issue for interlocutory appeal. On August 22, 2019, the court certified the plaintiffs' proposed class. On September 5, 2019, the defendants filed a petition for interlocutory appeal of the class certification order with theU.S. Court of Appeals for the Eleventh Circuit. On December 19, 2019, theU.S. District Court for the Northern District ofGeorgia entered an order staying all deadlines in the case pending mediation. The stay automatically expires on March 31, 2020. In February 2017,Jean Vineyard andJudy Mesirov each filed a shareholder derivative lawsuit in theU.S. District Court for the Northern District ofGeorgia . Each of these lawsuits names as defendantsSouthern Company , certain of its directors, certain of its officers, and certain former Mississippi Power officers. In 2017, these two shareholder derivative lawsuits were consolidated in theU.S. District Court for the Northern District ofGeorgia . The complaints allege that the defendants causedSouthern Company to make false or misleading statements regarding theKemper County energy facility cost and schedule. Further, the complaints allege that the defendants were unjustly enriched and caused the waste of corporate assets and also allege that the individual defendants violated their fiduciary duties. Each plaintiff seeks to recover, on behalf ofSouthern Company , unspecified actual damages and, on each plaintiff's own behalf, attorneys' fees and costs in bringing the lawsuit. Each plaintiff also seeks certain changes toSouthern Company's corporate governance and internal processes. In April 2018, the court entered an order staying this lawsuit until 30 days after the resolution of any dispositive motions or any settlement, whichever is earlier, in the securities class action. In May 2017, Helen E. Piper Survivor's Trust filed a shareholder derivative lawsuit in the Superior Court ofGwinnett County, Georgia that names as defendantsSouthern Company , certain of its directors, certain of its officers, and certain former Mississippi Power officers. The complaint alleges that the individual defendants, among other things, breached their fiduciary duties in connection with schedule delays and cost overruns associated with the construction of theKemper County energy facility. The complaint further alleges that the individual defendants authorized or failed to correct false and misleading statements regarding theKemper County energy facility schedule and cost and failed to implement necessary internal controls to prevent harm toSouthern Company . The plaintiff seeks to recover, on behalf ofSouthern Company , unspecified actual damages and disgorgement of profits and, on its behalf, attorneys' fees and costs in bringing the lawsuit. The plaintiff also seeks certain unspecified changes toSouthern Company's corporate governance and internal processes. In May 2018, the court entered an order staying this lawsuit until 30 days after the resolution of any dispositive motions or any settlement, whichever is earlier, in the securities class action. On August 5, 2019, the court granted a motion filed by the plaintiff on July 17, 2019 to substitute a new named plaintiff,Martin J. Kobuck , in place of Helen E. Piper Survivor's Trust. Georgia Power In 2011, plaintiffs filed a putative class action against Georgia Power in the Superior Court ofFulton County, Georgia alleging that Georgia Power's collection in rates of amounts for municipal franchise fees (which fees are paid to municipalities) exceeded the amounts allowed in orders of the Georgia PSC and alleging certain state tort law claims. In 2016, theGeorgia Court of Appeals reversed the trial court's previous dismissal of the case and remanded the case to the trial court. Georgia Power filed a petition for writ of certiorari with theGeorgia Supreme Court , which was granted in 2017. In June 2018, theGeorgia Supreme Court affirmed the judgment of theGeorgia Court of Appeals and remanded the case to the trial court for further proceedings. Following a motion by Georgia Power, on February 13, 2019, the Superior Court ofFulton County ordered the parties to submit petitions to the Georgia PSC for a declaratory ruling to address certain terms the court previously held were ambiguous as used in the Georgia PSC's orders. The order entered by the Superior Court ofFulton County also conditionally certified the proposed class. In March 2019, Georgia Power and the plaintiffs filed petitions with the Georgia PSC seeking confirmation of the proper II-88 -------------------------------------------------------------------------------- Table of Contents Index to Financial Statements
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application of the municipal franchise fee schedule pursuant to theGeorgia PSC's orders. On October 23, 2019, the Georgia PSC issued an order that found and concluded that Georgia Power has appropriately implemented the municipal franchise fee schedule. On March 6, 2019, Georgia Power filed a notice of appeal with theGeorgia Court of Appeals regarding the Superior Court ofFulton County's February 2019 order. The amount of any possible losses cannot be calculated at this time because, among other factors, it is unknown whether conditional class certification will be upheld and the ultimate composition of any class and whether any losses would be subject to recovery from any municipalities. Mississippi Power In May 2018,Southern Company and Mississippi Power received a notice of dispute and arbitration demand filed byMartin Product Sales, LLC (Martin) based on two agreements, both related to Kemper IGCC byproducts for which Mississippi Power provided termination notices in 2017. Martin alleges breach of contract, breach of good faith and fair dealing, fraud and misrepresentation, and civil conspiracy and makes a claim for damages in the amount of approximately $143 million, as well as additional unspecified damages, attorney's fees, costs, and interest. A portion of the claim for damages was on behalf ofMartin Transport, Inc. (Martin Transport), an affiliate of Martin. In the first quarter 2019, Mississippi Power andSouthern Company filed motions to dismiss, which were denied by the arbitration panel on May 10, 2019. On September 27, 2019, Martin Transport filed a separate complaint against Mississippi Power in the Circuit Court ofKemper County, Mississippi alleging claims of fraud, negligent misrepresentation, promissory estoppel, and equitable estoppel, each arising out of the same alleged facts and circumstances that underlie Martin's arbitration demand. Martin Transport seeks compensatory damages of $5 million and punitive damages of $50 million. In November 2019, Martin Transport's claim was combined with the Martin arbitration case and the separate court case was dismissed. On December 16, 2019,Southern Company and Mississippi Power each filed motions for summary judgment on all claims. On February 17, 2020, the arbitration panel grantedSouthern Company's motion and dismissedSouthern Company from the arbitration. An adverse outcome in this proceeding could have a material impact onSouthern Company's and Mississippi Power's financial statements. In November 2018, Ray C. Turnage and 10 other individual plaintiffs filed a putative class action complaint against Mississippi Power and three members of the Mississippi PSC in theU.S. District Court for the Southern District ofMississippi . Mississippi Power received Mississippi PSC approval in 2013 to charge a mirror CWIP rate premised upon including in its rate base pre-construction and construction costs for the Kemper IGCC prior to placing the Kemper IGCC into service. TheMississippi Supreme Court reversed that approval and ordered Mississippi Power to refund the amounts paid by customers under the previously-approved mirror CWIP rate. The plaintiffs allege that the initial approval process, and the amount approved, were improper. They also allege that Mississippi Power underpaid customers by up to $23.5 million in the refund process by applying an incorrect interest rate. The plaintiffs seek to recover, on behalf of themselves and their putative class, actual damages, punitive damages, pre-judgment interest, post-judgment interest, attorney's fees, and costs. In response to Mississippi Power and the Mississippi PSC each filing a motion to dismiss, the plaintiffs filed an amended complaint on March 14, 2019. The amended complaint included four additional plaintiffs and additional claims for gross negligence, reckless conduct, and intentional wrongdoing.Mississippi Power and the Mississippi PSC have each filed a motion to dismiss the amended complaint. An adverse outcome in this proceeding could have a material impact on Mississippi Power's financial statements. See Note 2 to the financial statements under "Kemper County Energy Facility" for additional information. Other Matters Southern Company A subsidiary of Southern Holdings has several leveraged lease agreements, with original terms ranging up to 45 years, which relate to international and domestic energy generation, distribution, and transportation assets. Southern Company receives federal income tax deductions for depreciation and amortization, as well as interest on long-term debt related to these investments. Southern Company reviews all important lease assumptions at least annually, or more frequently if events or changes in circumstances indicate that a change in assumptions has occurred or may occur. These assumptions include the effective tax rate, the residual value, the credit quality of the lessees, and the timing of expected tax cash flows. See Note 1 to the financial statements under "Leveraged Leases" for additional information. The ability of the lessees to make required payments to the Southern Holdings subsidiary is dependent on the operational performance of the assets. In 2017, the financial and operational performance of one of the lessees and the associated generation assets raised significant concerns about the short-term ability of the generation assets to produce cash flows sufficient to support ongoing operations and the lessee's contractual obligations and its ability to make the remaining semi-annual lease payments through the end of the lease term in 2047. In addition, following the expiration of the existing power offtake agreement in 2032, the lessee also is exposed to remarketing risk, which encompasses the price and availability of alternative sources of generation. II-89 -------------------------------------------------------------------------------- Table of Contents Index to Financial Statements
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While all lease payments through December 31, 2019 have been paid in full due to recent operational improvements, operational and remarketing risks and the resulting cash liquidity challenges persist, and significant concerns continue regarding the lessee's ability to make the remaining semi-annual lease payments. These challenges may also impact the expected residual value of the generation assets. Southern Company has evaluated the recoverability of the lease receivable and the expected residual value of the generation assets under various scenarios. Based on current forecasts of energy prices in the years following the expiration of the existing PPA, Southern Company concluded that it is no longer probable that all of the associated rental payments will be received over the term of the lease. As a result, during the fourth quarter 2019, Southern Company revised the estimate of cash flows to be received under the leveraged lease, which resulted in an impairment charge of $17 million ($13 million after tax). If any future lease payment is not paid in full, the Southern Holdings subsidiary may be unable to make its corresponding payment to the holders of the underlying non-recourse debt related to the generation assets. Failure to make the required payment to the debtholders could represent an event of default that would give the debtholders the right to foreclose on, and take ownership of, the generation assets from the Southern Holdings subsidiary, in effect terminating the lease and resulting in the write-off of the related lease receivable, which totaled approximately $76 million at December 31, 2019. Southern Company will continue to monitor the operational performance of the underlying assets and evaluate the ability of the lessee to continue to make the required lease payments. The ultimate outcome of this matter cannot be determined at this time. Mississippi Power In conjunction with Southern Company's sale of Gulf Power, NextEra Energy held back $75 million of the purchase price pending Mississippi Power and Gulf Power negotiating a mutually acceptable revised operating agreement for Plant Daniel. In addition, Mississippi Power and Gulf Power committed to seek a restructuring of their 50% undivided ownership interests in Plant Daniel such that each of them would, after the restructuring, own 100% of a generating unit. On January 15, 2019, Gulf Power provided notice to Mississippi Power that Gulf Power will retire its share of the generating capacity of Plant Daniel on January 15, 2024. Mississippi Power has the option to purchase Gulf Power's ownership interest for $1 on January 15, 2024, provided that Mississippi Power exercises the option no later than 120 days prior to that date. Mississippi Power is assessing the potential operational and economic effects of Gulf Power's notice. The ultimate outcome of these matters remains subject to completion of Mississippi Power's evaluations and applicable regulatory approvals, including by the FERC and the Mississippi PSC, and cannot be determined at this time. See Note 15 to the financial statements under "Southern Company" for information regarding the sale of Gulf Power. Southern Company Gas A wholly-owned subsidiary of Southern Company Gas owns and operates a natural gas storage facility consisting of two salt dome caverns in Louisiana. Periodic integrity tests are required in accordance with rules of the Louisiana Department of Natural Resources (DNR). In 2017, in connection with an ongoing integrity project, updated seismic mapping indicated the proximity of one of the caverns to the edge of the salt dome may be less than the required minimum and could result in Southern Company Gas retiring the cavern early. In the third quarter 2019, management determined that it no longer planned to obtain the core samples during 2020 that are necessary to determine the composition of the sheath surrounding the edge of the salt dome. Core sampling is a requirement of the Louisiana DNR to put the cavern back in service; as a result, the cavern will not return to service by 2021. This change in plan, which affects the future operation of the entire storage facility, resulted in a pre-tax impairment charge of $91 million ($69 million after-tax) recorded by Southern Company Gas in 2019. Southern Company Gas continues to monitor the pressure and overall structural integrity of the entire facility pending any future decisions regarding decommissioning. Southern Company Gas has two other natural gas storage facilities located in California and Texas, which could be impacted by ongoing changes in the U.S. natural gas storage market. Recent sales of natural gas storage facilities have resulted in losses for the sellers and may imply an impact on future rates and/or asset values. Sustained diminished natural gas storage values could trigger impairment of either or both of these natural gas storage facilities, which have a combined net book value of $326 million at December 31, 2019. The ultimate outcome of these matters cannot be determined at this time, but could have a material impact on the financial statements of Southern Company and Southern Company Gas. ACCOUNTING POLICIES 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 the application of these policies, certain estimates are made that may have a material impact II-90 -------------------------------------------------------------------------------- Table of Contents Index to Financial Statements
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on the results of operations and related disclosures of the applicable Registrants (as indicated in the section descriptions herein). Different assumptions and measurements could produce estimates that are significantly different from those recorded in the financial statements. Senior management has reviewed and discussed the following critical accounting policies and estimates with the Audit Committee of Southern Company's Board of Directors. Utility Regulation (Southern Company, Alabama Power, Georgia Power, Mississippi Power, and Southern Company Gas) The traditional electric operating companies and the natural gas distribution utilities are subject to retail regulation by their respective state PSCs or other applicable state regulatory agencies and wholesale regulation by the FERC. These regulatory agencies set the rates the traditional electric operating companies and the natural gas distribution utilities are permitted to charge customers based on allowable costs, including a reasonable ROE. As a result, the traditional electric operating companies and the natural gas distribution utilities apply accounting standards which require the financial statements to reflect the effects of rate regulation. Through the ratemaking process, the regulators may require the inclusion of costs or revenues in periods different than when they would be recognized by a non-regulated company. This treatment may result in the deferral of expenses and the recording of related regulatory assets based on anticipated future recovery through rates or the deferral of gains or creation of liabilities and the recording of related regulatory liabilities. The application of the accounting standards for rate regulated entities also impacts their financial statements as a result of the estimates of allowable costs used in the ratemaking process. These estimates may differ from those actually incurred by the traditional electric operating companies and the natural gas distribution utilities; therefore, the accounting estimates inherent in specific costs such as depreciation, AROs, and pension and other postretirement benefits have less of a direct impact on the results of operations and financial condition of the applicable Registrants than they would on a non-regulated company. Revenues related to regulated utility operations as a percentage of total operating revenues in 2019 for the applicable Registrants were as follows: 87% for Southern Company, 99% for Alabama Power, 97% for Georgia Power, 100% for Mississippi Power, and 80% for Southern Company Gas. As reflected in Note 2 to the financial statements, significant regulatory assets and liabilities have been recorded. Management reviews the ultimate recoverability of these regulatory assets and any requirement to refund these regulatory liabilities based on applicable regulatory guidelines and GAAP. However, adverse legislative, judicial, or regulatory actions could materially impact the amounts of such regulatory assets and liabilities and could adversely impact the financial statements of the applicable Registrants. Estimated Cost, Schedule, and Rate Recovery for the Construction of Plant Vogtle Units 3 and 4 (Southern Company and Georgia Power) In 2016, the Georgia PSC approved the Vogtle Cost Settlement Agreement, which resolved certain prudency matters in connection with Georgia Power's fifteenth VCM report. In 2017, the Georgia PSC approved Georgia Power's seventeenth VCM report, which included a recommendation to continue construction of Plant Vogtle Units 3 and 4, with Southern Nuclear serving as project manager and Bechtel serving as the primary construction contractor, as well as a modification of the Vogtle Cost Settlement Agreement. The Georgia PSC's related order stated that under the modified Vogtle Cost Settlement Agreement, (i) none of the $3.3 billion of costs incurred through December 31, 2015 should be disallowed as imprudent; (ii) capital costs incurred up to $5.68 billion would be presumed to be reasonable and prudent with the burden of proof on any party challenging such costs; (iii) Georgia Power would have the burden of proof to show that any capital costs above $5.68 billion were prudent; (iv) Georgia Power's total project capital cost forecast of $7.3 billion (net of $1.7 billion received under the Guarantee Settlement Agreement and approximately $188 million in related customer refunds) was found reasonable and did not represent a cost cap; and (v) prudence decisions would be made subsequent to achieving fuel load for Unit 4. In its order, the Georgia PSC also stated if other conditions change and assumptions upon which Georgia Power's seventeenth VCM report are based do not materialize, the Georgia PSC reserved the right to reconsider the decision to continue construction. In the second quarter 2018, Georgia Power revised its base cost forecast and estimated contingency to complete construction and start-up of Plant Vogtle Units 3 and 4 to $8.0 billion and $0.4 billion, respectively, for a total project capital cost forecast of $8.4 billion (net of $1.7 billion received under the Guarantee Settlement Agreement and approximately $188 million in related customer refunds). Although Georgia Power believes these incremental costs are reasonable and necessary to complete the project and the Georgia PSC's order in the seventeenth VCM proceeding specifically states that the construction of Plant Vogtle Units 3 and 4 is not subject to a cost cap, Georgia Power did not seek rate recovery for the $0.7 billion increase in costs included in the base capital cost forecast in the nineteenth VCM report. After considering the significant level of uncertainty that exists regarding the future recoverability of costs included in the construction contingency estimate since the ultimate outcome of these matters is subject to the outcome of future assessments by management, as well as Georgia PSC decisions in these future regulatory II-91 -------------------------------------------------------------------------------- Table of Contents Index to Financial Statements
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proceedings, Georgia Power recorded a total pre-tax charge to income of $1.1 billion ($0.8 billion after tax) in the second quarter 2018. Georgia Power's revised cost estimate reflects an expected in-service date of November 2021 for Unit 3 and November 2022 for Unit 4. As of December 31, 2019, approximately $140 million of the $366 million construction contingency estimate established in the second quarter 2018 was allocated to the base capital cost forecast for cost risks including, among other factors, construction productivity; craft labor incentives; adding resources for supervision, field support, project management, initial test program, start-up, and operations and engineering support; subcontracts; and procurement. As and when construction contingency is spent, Georgia Power may request the Georgia PSC to evaluate those expenditures for rate recovery. As part of its ongoing processes, Southern Nuclear continues to evaluate cost and schedule forecasts on a regular basis to incorporate current information available, particularly in the areas of commodity installation, system turnovers, and workforce statistics. In April 2019, Southern Nuclear established aggressive target values for monthly construction production and system turnover activities as part of a strategy to maintain and, where possible, build margin to the regulatory-approved in-service dates of November 2021 for Unit 3 and November 2022 for Unit 4. The project has faced challenges with the April 2019 aggressive strategy targets, including, but not limited to, electrical and pipefitting labor productivity and closure rates for work packages, which resulted in a backlog of activities and completion percentages below the April 2019 aggressive strategy targets. However, Southern Nuclear and Georgia Power believe that existing productivity levels and pace of activity completion are sufficient to meet the regulatory-approved in-service dates. In February 2020, Southern Nuclear updated its cost and schedule forecast, which did not change the projected overall capital cost forecast and confirmed the expected in-service dates of November 2021 for Unit 3 and November 2022 for Unit 4. This update included initiatives to improve productivity while refining and extending system turnover plans and certain near-term milestone dates. Other milestone dates did not change. Achievement of the aggressive site work plan relies on meeting increased monthly production and activity target values during 2020. To meet these 2020 targets, existing craft, including subcontractors, construction productivity must improve and be sustained above historical average levels, appropriate levels of craft laborers, particularly electrical and pipefitter craft labor, must be maintained, and additional supervision and other field support resources must be retained. Southern Nuclear and Georgia Power continue to believe that pursuit of an aggressive site work plan is an appropriate strategy to achieve completion of the units by their regulatory-approved in-service dates. As construction, including subcontract work, continues and testing and system turnover activities increase, challenges with management of contractors and vendors; subcontractor performance; supervision of craft labor and related craft labor productivity, particularly in the installation of electrical and mechanical commodities, ability to attract and retain craft labor, and/or related cost escalation; procurement, fabrication, delivery, assembly, installation, system turnover, and the initial testing and start-up, including any required engineering changes or any remediation related thereto, of plant systems, structures, or components (some of which are based on new technology that only within the last few years began initial operation in the global nuclear industry at this scale), or regional transmission upgrades, any of which may require additional labor and/or materials; or other issues could arise and change the projected schedule and estimated cost. There have been technical and procedural challenges to the construction and licensing of Plant Vogtle Units 3 and 4 at the federal and state level and additional challenges may arise. Processes are in place that are designed to assure compliance with the requirements specified in the Westinghouse Design Control Document and the combined construction and operating licenses, including inspections by Southern Nuclear and the NRC that occur throughout construction. As a result of such compliance processes, certain license amendment requests have been filed and approved or are pending before the NRC. Various design and other licensing-based compliance matters, including the timely submittal by Southern Nuclear of the ITAAC documentation for each unit and the related reviews and approvals by the NRC necessary to support NRC authorization to load fuel, may arise, which may result in additional license amendments or require other resolution. As part of the aggressive site work plan, in January 2020, Southern Nuclear notified the NRC of its intent to load fuel in 2020. If any license amendment requests or other licensing-based compliance issues are not resolved in a timely manner, there may be delays in the project schedule that could result in increased costs. The ultimate outcome of these matters cannot be determined at this time. However, any extension of the regulatory-approved project schedule is currently estimated to result in additional base capital costs of approximately $50 million per month, based on Georgia Power's ownership interests, and AFUDC of approximately $12 million per month. While Georgia Power is not precluded from seeking recovery of any future capital cost forecast increase, management will ultimately determine whether or II-92 -------------------------------------------------------------------------------- Table of Contents Index to Financial Statements
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not to seek recovery. Any further changes to the capital cost forecast that are not expected to be recoverable through regulated rates will be required to be charged to income and such charges could be material. Given the significant complexity involved in estimating the future costs to complete construction and start-up of Plant Vogtle Units 3 and 4 and the significant management judgment necessary to assess the related uncertainties surrounding future rate recovery of any projected cost increases, as well as the potential impact on results of operations and cash flows, Southern Company and Georgia Power consider these items to be critical accounting estimates. See Note 2 to the financial statements under "Georgia Power - Nuclear Construction" for additional information. Accounting for Income Taxes (Southern Company, Mississippi Power, Southern Power, and Southern Company Gas) The consolidated income tax provision and deferred income tax assets and liabilities, as well as any unrecognized tax benefits and valuation allowances, require significant judgment and estimates. These estimates are supported by historical tax return data, reasonable projections of taxable income, and interpretations of applicable tax laws and regulations across multiple taxing jurisdictions. The effective tax rate reflects the statutory tax rates and calculated apportionments for the various states in which the Southern Company system operates. On behalf of its subsidiaries, Southern Company files a consolidated federal income tax return and various state income tax returns, some of which are combined or unitary. Under a joint consolidated income tax allocation agreement, each Southern Company subsidiary's current and deferred tax expense is computed on a stand-alone basis and no subsidiary is allocated more current expense than would be paid if it filed a separate income tax return. Certain deductions and credits can be limited or utilized at the consolidated or combined level resulting in NOL and tax credit carryforwards that would not otherwise result on a stand-alone basis. Utilization of NOL and tax credit carryforwards and the assessment of valuation allowances are based on significant judgment and extensive analysis of Southern Company's and its subsidiaries' current financial position and results of operations, including currently available information about future years, to estimate when future taxable income will be realized. Current and deferred state income tax liabilities and assets are estimated based on laws of multiple states that determine the income to be apportioned to their jurisdictions. States utilize various formulas to calculate the apportionment of taxable income, primarily using sales, assets, or payroll within the jurisdiction compared to the consolidated totals. In addition, each state varies as to whether a stand-alone, combined, or unitary filing methodology is required. The calculation of deferred state taxes considers apportionment factors and filing methodologies that are expected to apply in future years. The apportionments and methodologies which are ultimately finalized in a manner inconsistent with expectations could have a material effect on the financial statements of the applicable Registrants. Given the significant judgment involved in estimating NOL and tax credit carryforwards and multi-state apportionments for all subsidiaries, the applicable Registrants consider deferred income tax liabilities and assets to be critical accounting estimates. Asset Retirement Obligations (Southern Company, Alabama Power, Georgia Power, Mississippi Power, and Southern Company Gas) AROs are computed as the present value of the estimated costs for an asset's future retirement and are recorded in the period in which the liability is incurred. The estimated costs are capitalized as part of the related long-lived asset and depreciated over the asset's useful life. In the absence of quoted market prices, AROs are estimated using present value techniques in which estimates of future cash outlays associated with the asset retirements are discounted using a credit-adjusted risk-free rate. Estimates of the timing and amounts of future cash outlays are based on projections of when and how the assets will be retired and the cost of future removal activities. The ARO liabilities for the traditional electric operating companies primarily relate to facilities that are subject to the CCR Rule and the related state rules, principally ash ponds. In addition, Alabama Power and Georgia Power have retirement obligations related to the decommissioning of nuclear facilities (Alabama Power's Plant Farley and Georgia Power's ownership interests in Plant Hatch and Plant Vogtle Units 1 and 2). The traditional electric operating companies also have AROs related to various landfill sites, asbestos removal, and underground storage tanks, as well as, for Alabama Power, disposal of polychlorinated biphenyls in certain transformers and sulfur hexafluoride gas in certain substation breakers, for Georgia Power, gypsum cells and restoration of land at the end of long-term land leases for solar facilities, and for Mississippi Power, mine reclamation and water wells. The traditional electric operating companies and Southern Company Gas also have identified other retirement obligations, such as obligations related to certain electric transmission and distribution facilities, certain asbestos-containing material within long-term assets not subject to ongoing repair and maintenance activities, certain wireless communication towers, the disposal of polychlorinated biphenyls in certain transformers, leasehold improvements, equipment on customer property, and property associated with the Southern Company system's rail lines and natural gas pipelines. However, liabilities for the removal of these II-93 -------------------------------------------------------------------------------- Table of Contents Index to Financial Statements
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assets have not been recorded because the settlement timing for certain retirement obligations related to these assets is indeterminable and, therefore, the fair value of the retirement obligations cannot be reasonably estimated. A liability for these retirement obligations will be recognized when sufficient information becomes available to support a reasonable estimation of the ARO. The cost estimates for AROs related to the disposal of CCR are based on information using various assumptions related to closure and post-closure costs, timing of future cash outlays, inflation and discount rates, and the potential methods for complying with the CCR Rule and the related state rules. The traditional electric operating companies expect to update their ARO cost estimates periodically as additional information related to these assumptions becomes available. See Note 6 to the financial statements for additional information, including increases to AROs related to ash ponds recorded during 2019 by certain Registrants. Given the significant judgment involved in estimating AROs, the applicable Registrants consider the liabilities for AROs to be critical accounting estimates. Pension and Other Postretirement Benefits (Southern Company, Alabama Power, Georgia Power, Mississippi Power, and Southern Company Gas) The applicable Registrants' calculations of pension and other postretirement benefits expense are dependent on a number of assumptions. These assumptions include discount rates, healthcare cost trend rates, expected long-term rate of return (LRR) on plan assets, mortality rates, expected salary and wage increases, and other factors. Components of pension and other postretirement benefits expense include interest and service cost on the pension and other postretirement benefit plans, expected return on plan assets, and amortization of certain unrecognized costs and obligations. Actual results that differ from the assumptions utilized are accumulated and amortized over future periods and, therefore, generally affect recognized expense and the recorded obligation in future periods. While the applicable Registrants believe the assumptions used are appropriate, differences in actual experience or significant changes in assumptions would affect their pension and other postretirement benefit costs and obligations. Key elements in determining the applicable Registrants' pension and other postretirement benefit expense are the LRR and the discount rate used to measure the benefit plan obligations and the periodic benefit plan expense for future periods. For purposes of determining the applicable Registrants' liabilities related to the pension and other postretirement benefit plans, Southern Company discounts the future related cash flows using a single-point discount rate for each plan developed from the weighted average of market-observed yields for high quality fixed income securities with maturities that correspond to expected benefit payments. The discount rate assumption impacts both the service cost and non-service costs components of net periodic benefit costs as well as the projected benefit obligations. The LRR on pension and other postretirement benefit plan assets is based on Southern Company's investment strategy, historical experience, and expectations that consider external actuarial advice, and represents the average rate of earnings expected over the long term on the assets invested to provide for anticipated future benefit payments. Southern Company determines the amount of the expected return on plan assets component of non-service costs by applying the LRR of various asset classes to Southern Company's target asset allocation. The LRR only impacts the non-service costs component of net periodic benefit costs for the following year and is set annually at the beginning of the year. For 2019, the LRR assumption for qualified pension plan assets was reduced from 7.95% to 7.75% for purposes of determining net periodic pension expense as a result of changes in the economic outlook used in estimating the expected returns as of December 31, 2018. As a result of the decrease in the LRR, the non-service costs component of net periodic pension expense increased by $24 million for the Southern Company system in 2019. See the table below for the impact on each Registrant. II-94 -------------------------------------------------------------------------------- Table of Contents Index to Financial Statements
COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Southern Company and Subsidiary Companies 2019 Annual Report
For 2020, net periodic pension expense will be impacted by two factors: a change in the approach used to determine the LRR assumption and cash contributions totaling $1.1 billion to the qualified pension plan made in December 2019. Historically, Southern Company has set the LRR assumption using asset return modeling based on geometric returns that reflect the compound average returns for dependent annual periods. Beginning in 2020, Southern Company will set the LRR assumption using an arithmetic mean which represents the expected simple average return to be earned by the pension plan assets over any one year. Southern Company believes the use of the arithmetic mean is more compatible with the LRR's function of estimating a single year's investment return. Excluding the additional pension contribution in December 2019, the change in the LRR assumption will reduce the non-service costs component of net periodic pension expense by $78 million for the Southern Company system in 2020. See the table below for the impact on each Registrant. The contributions in 2019 will further reduce expense by $88 million for the Southern Company system in 2020. Alabama Georgia Southern Company Power Power Mississippi Power Southern Company Gas (in millions) Increase (decrease) in pension expense: 2019 $ 24 $ 5 $ 8 $ 1 $ 2 2020 (78 ) (18 ) (25 ) (4 ) (7 ) The following table illustrates the sensitivity to changes in the applicable Registrants' long-term assumptions with respect to the discount rate, salary increases, and the long-term rate of return on plan assets: Increase/(Decrease) in Projected Obligation for Projected Other Obligation for Postretirement Pension Plan at Benefit Plans at Total Benefit December 31, December 31, 25 Basis Point Change in: Expense for 2020 2019 2019 (in millions) Discount rate: Southern Company $41/$(39) $549/$(518) $57/$(54) Alabama Power $10/$(10) $131/$(123) $14/$(13) Georgia Power $12/$(11) $166/$(156) $21/$(20) Mississippi Power $2/$(2) $25/$(23) $2/$(2) Southern Company Gas $1/$(1) $38/$(36) $6/$(6) Salaries: Southern Company $23/$(22) $118/$(113) $-/$- Alabama Power $6/$(6) $33/$(32) $-/$- Georgia Power $6/$(6) $34/$(33) $-/$- Mississippi Power $1/$(1) $5/$(5) $-/$- Southern Company Gas $1/$(1) $3/$(3) $-/$- Long-term return on plan assets: Southern Company $35/$(35) N/A N/A Alabama Power $9/$(9) N/A N/A Georgia Power $11/$(11) N/A N/A Mississippi Power $2/$(2) N/A N/A Southern Company Gas $3/$(3) N/A N/A
See Note 11 to the financial statements for additional information regarding pension and other postretirement benefits.
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COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Southern Company and Subsidiary Companies 2019 Annual Report
Asset Impairment (Southern Company, Southern Power, and Southern Company Gas) Goodwill (Southern Company and Southern Company Gas) The acquisition method of accounting requires the assets acquired and liabilities assumed to be recorded at the date of acquisition at their respective estimated fair values. The applicable Registrants have recognized goodwill as of the date of their acquisitions, as a residual over the fair values of the identifiable net assets acquired. Goodwill is tested for impairment at the reporting unit level on an annual basis in the fourth quarter of the year as well as on an interim basis as events and changes in circumstances occur, including, but not limited to, a significant change in operating performance, the business climate, legal or regulatory factors, or a planned sale or disposition of a significant portion of the business. A reporting unit is the operating segment, or a business one level below the operating segment (a component), if discrete financial information is prepared and regularly reviewed by management. Components are aggregated if they have similar economic characteristics. As part of the impairment tests, the applicable Registrant may perform an initial qualitative assessment to determine whether it is more likely than not that the fair value of each reporting unit is less than its carrying amount before applying the quantitative goodwill impairment test. If the applicable Registrant elects to perform the qualitative assessment, it evaluates relevant events and circumstances, including but not limited to, macroeconomic conditions, industry and market conditions, cost factors, financial performance, entity specific events, and events specific to each reporting unit. If the applicable Registrant determines that it is more likely than not that the fair value of a reporting unit is less than its carrying amount, or it elects not to perform a qualitative assessment, it compares the fair value of the reporting unit to its carrying value to determine if the fair value is greater than its carrying value. Goodwill for Southern Company and Southern Company Gas was $5.3 billion and $5.0 billion, respectively, at December 31, 2019. For its 2019 and 2018 annual impairment tests, Southern Company Gas performed the qualitative assessment and determined that it was more likely than not that the fair value of all of its reporting units with goodwill exceeded their carrying amounts, and therefore no quantitative analysis was required. For its 2017 annual impairment test, Southern Company Gas performed the quantitative assessment, which resulted in the fair value of all of its reporting units that have goodwill exceeding their carrying value. For its annual impairment tests for PowerSecure, Southern Company performed the quantitative assessment, which resulted in the fair value of goodwill at PowerSecure exceeding its carrying value in all years presented. However, Southern Company recorded goodwill impairment charges totaling $34 million in 2019 as a result of its decision to sell certain PowerSecure business units. See Note 15 to the financial statements under "Southern Company" for additional information. The judgments made in determining the estimated fair value assigned to each class of assets acquired and liabilities assumed, as well as asset lives, can significantly impact the applicable Registrant's results of operations. Fair values and useful lives are determined based on, among other factors, the expected future period of benefit of the asset, the various characteristics of the asset, and projected cash flows. As the determination of an asset's fair value and useful life involves management making certain estimates and because these estimates form the basis for the determination of whether or not an impairment charge should be recorded, the applicable Registrants consider these estimates to be critical accounting estimates. See Note 1 to the financial statements under "Goodwill and Other Intangible Assets and Liabilities" for additional information regarding the applicable Registrants' goodwill. Long-Lived Assets (Southern Company, Southern Power, and Southern Company Gas) Impairments of long-lived assets of the traditional electric utilities and natural gas distribution utilities are generally related to specific regulatory disallowances. The applicable Registrants assess their other long-lived assets for impairment whenever events or changes in circumstances indicate that an asset's carrying amount may not be recoverable. If an indicator exists, the asset is tested for recoverability by comparing the asset carrying value to the sum of the undiscounted expected future cash flows directly attributable to the asset's use and eventual disposition. If the estimate of undiscounted future cash flows is less than the carrying value of the asset, the fair value of the asset is determined and a loss is recorded equal to the difference between the carrying value and the fair value of the asset. In addition, when assets are identified as held for sale, an impairment loss is recognized to the extent the carrying value of the assets or asset group exceeds their fair value less cost to sell. A high degree of judgment is required in developing estimates related to these evaluations, which are based on projections of various factors, some of which have been quite volatile in recent years. Southern Power's investments in long-lived assets are primarily generation assets, whether in service or under construction. Excluding the natural gas distribution utilities, Southern Company Gas' investments in long-lived assets are primarily natural gas transportation and storage facility assets, whether in service or under construction. In addition, exclusive of the traditional electric operating companies and natural gas distribution utilities, Southern Company's investments in long-lived assets also include investments in leveraged leases. II-96 -------------------------------------------------------------------------------- Table of Contents Index to Financial Statements
COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Southern Company and Subsidiary Companies 2019 Annual Report
For Southern Power, examples of impairment indicators could include significant changes in construction schedules, current period losses combined with a history of losses or a projection of continuing losses, a significant decrease in market prices, the inability to remarket generating capacity for an extended period, the unplanned termination of a customer contract or the inability of a customer to perform under the terms of the contract, or the inability to deploy wind turbine equipment to a development project. For Southern Company Gas, examples of impairment indicators could include, but are not limited to, significant changes in the U.S. natural gas storage market, construction schedules, current period losses combined with a history of losses or a projection of continuing losses, a significant decrease in market prices, the inability to renew or extend customer contracts or the inability of a customer to perform under the terms of the contract, attrition rates, or the inability to deploy a development project. For Southern Company's investments in leveraged leases, impairment indicators include changes in estimates of future rental payments to be received under the lease as well as the residual value of the leased asset at the end of the lease. As the determination of the expected future cash flows generated from an asset, an asset's fair value, and useful life involves management making certain estimates and because these estimates form the basis for the determination of whether or not an impairment charge should be recorded, the applicable Registrants consider these estimates to be critical accounting estimates. See Note 3 to the financial statements under "Other Matters" and Note 15 to the financial statements for information on certain assets recently evaluated for impairment. Derivatives and Hedging Activities (Southern Company and Southern Company Gas) Determining whether a contract meets the definition of a derivative instrument, contains an embedded derivative requiring bifurcation, or qualifies for hedge accounting treatment is complex. The treatment of a single contract may vary from period to period depending upon accounting elections, changes in the applicable Registrant's assessment of the likelihood of future hedged transactions, or new interpretations of accounting guidance. As a result, judgment is required in determining the appropriate accounting treatment. In addition, the estimated fair value of derivative instruments may change significantly from period to period depending upon market conditions, and changes in hedge effectiveness may impact the accounting treatment. Derivative instruments (including certain derivative instruments embedded in other contracts) are recorded on the balance sheets as either assets or liabilities measured at their fair value. If the transaction qualifies for, and is designated as, a normal purchase or normal sale, it is exempt from fair value accounting treatment and is, instead, subject to traditional accrual accounting. The applicable Registrant utilizes market data or assumptions that market participants would use in pricing the derivative asset or liability, including assumptions about risk and the risks inherent in the inputs of the valuation technique. Changes in the derivatives' fair value are recognized concurrently in earnings unless specific hedge accounting criteria are met. If the derivatives meet those criteria, derivative gains and losses offset related results of the hedged item in the income statement in the case of a fair value hedge, or gains and losses are deferred in OCI on the balance sheets until the hedged transaction affects earnings in the case of a cash flow hedge. Additionally, a company is required to formally designate a derivative as a hedge as well as document and assess the effectiveness of derivatives associated with transactions that receive hedge accounting treatment. Southern Company Gas uses derivative instruments primarily to reduce the impact to its results of operations due to the risk of changes in the price of natural gas and, to a lesser extent, Southern Company Gas hedges against warmer-than-normal weather and interest rates. The fair value of natural gas derivative instruments used to manage exposure to changing natural gas prices reflects the estimated amounts that Southern Company Gas would receive or pay to terminate or close the contracts at the reporting date, taking into account the current unrealized gains or losses on open contracts. For derivatives utilized at gas marketing services and wholesale gas services that are not designated as accounting hedges, changes in fair value are reported as gains or losses in results of operations in the period of change. Gas marketing services records derivative gains or losses arising from cash flow hedges in OCI and reclassifies them into earnings in the same period that the underlying hedged item is recognized in earnings. Derivative assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. The assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy. The determination of the fair value of the derivative instruments incorporates various required factors. These factors include: • the creditworthiness of the counterparties involved and the impact of credit enhancements (such as cash deposits and letters of credit);
• events specific to a given counterparty; and
• the impact of nonperformance risk on liabilities.
A significant change in the underlying market prices or pricing assumptions used in pricing derivative assets or liabilities may result in a significant financial statement impact.
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COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Southern Company and Subsidiary Companies 2019 Annual Report
Given the assumptions used in pricing the derivative asset or liability, Southern Company and Southern Company Gas consider the valuation of derivative assets and liabilities a critical accounting estimate. See FINANCIAL CONDITION AND LIQUIDITY - "Market Price Risk" herein and Note 14 to the financial statements for more information. Revenue Recognition (Southern Power) Southern Power's power sale transactions, which include PPAs, are classified in one of four general categories: leases, non-derivatives or normal sale derivatives, derivatives designated as cash flow hedges, and derivatives not designated as hedges, as described further below. For more information on derivative transactions, see FINANCIAL CONDITION AND LIQUIDITY - "Market Price Risk" herein and Notes 1 and 14 to the financial statements. Southern Power's revenues are dependent upon significant judgments used to determine the appropriate transaction classification, which must be documented upon the inception of each contract. Lease Transactions Southern Power considers the following factors to determine whether the sales contract is a lease: • Assessing whether specific property is explicitly or implicitly identified in
the agreement;
• Determining whether the fulfillment of the arrangement is dependent on the
use of the identified property; and
• Assessing whether the arrangement conveys to the counterparty substantially
all of the economic benefits and the right to direct the use of the asset.
If the contract meets the above criteria for a lease, Southern Power performs further analysis as to whether the lease is classified as operating, financing, or sales-type. All of Southern Power's power sales contracts that are determined to be leases are accounted for as operating leases and the capacity revenue is recognized on a straight-line basis over the term of the contract and is included in Southern Power's operating revenues. Energy revenues and other contingent revenues are recognized in the period the energy is delivered or the service is rendered. See Note 9 to the financial statements for additional information. Non-Derivative and Normal Sale Derivative Transactions If the power sales contract is not classified as a lease, Southern Power further considers the following factors to determine proper classification: • Assessing whether the contract meets the definition of a derivative;
• Assessing whether the contract meets the definition of a capacity contract;
• Assessing the probability at inception and throughout the term of the
individual contract that the contract will result in physical delivery; and
• Ensuring that the contract quantities do not exceed available generating
capacity (including purchased capacity).
Contracts that do not meet the definition of a derivative or are designated as normal sales (i.e. capacity contracts which provide for the sale of electricity that involve physical delivery in quantities within Southern Power's available generating capacity) are accounted for as executory contracts. For contracts that have a capacity charge, the revenue is generally recognized in the period that it becomes billable. Revenues related to energy and ancillary services are recognized in the period the energy is delivered or the service is rendered. See Note 4 to the financial statements for additional information. Cash Flow Hedge Transactions Southern Power further considers the following in designating other derivative contracts for the sale of electricity as cash flow hedges of anticipated sale transactions: • Identifying the hedging instrument, the forecasted hedged transaction, and
the nature of the risk being hedged; and
• Assessing hedge effectiveness at inception and throughout the contract term.
These contracts are accounted for on a fair value basis and are recorded in AOCI over the life of the contract. Realized gains and losses are then recognized in operating revenues as incurred. Derivative (Non-Hedge) Transactions Contracts for sales of electricity, which meet the definition of a derivative and that either do not qualify or are not designated as normal sales or as cash flow hedges, are accounted for on a fair value basis and are recorded in operating revenues. II-98 -------------------------------------------------------------------------------- Table of Contents Index to Financial Statements
COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Southern Company and Subsidiary Companies 2019 Annual Report
Acquisition Accounting (Southern Power) Southern Power may acquire generation assets as part of its overall growth strategy. At the time of an acquisition, Southern Power will assess if these assets and activities meet the definition of a business. For acquisitions that meet the definition of a business, the purchase price, including any contingent consideration, is allocated based on the fair value of the identifiable assets acquired and liabilities assumed (including any intangible assets, primarily related to acquired PPAs). Assets acquired that do not meet the definition of a business are accounted for as an asset acquisition. The purchase price of each asset acquisition is allocated based on the relative fair value of assets acquired. Determining the fair value of assets acquired and liabilities assumed requires management judgment and Southern Power may engage independent valuation experts to assist in this process. Fair values are determined by using market participant assumptions, and typically include the timing and amounts of future cash flows, incurred construction costs, the nature of acquired contracts, discount rates, power market prices, and expected asset lives. Any due diligence or transition costs incurred by Southern Power for potential or successful acquisitions are expensed as incurred. Contingent consideration primarily relates to fixed amounts due to the seller once the facility is placed in service. For contingent consideration with variable payments, Southern Power fair values the arrangement with any changes recorded in the consolidated statements of income. See Note 13 to the financial statements for additional fair value information and Note 15 to the financial statements for additional information on recent acquisitions. Variable Interest Entities (Southern Power) Southern Power enters into partnerships with varying ownership structures. Upon entering into such arrangements, membership interests and other variable interests are evaluated to determine if the legal entity is a VIE. If the legal entity is a VIE, Southern Power will assess if it has both the power to direct the activities of the VIE that most significantly impact the VIE's economic performance and the obligation to absorb losses or the right to receive benefits from the VIE that could potentially be significant to the VIE, making it the primary beneficiary. Making this determination may require significant management judgment. If Southern Power is the primary beneficiary, the assets, liabilities, and results of operations of the entity are consolidated. If Southern Power is not the primary beneficiary, the legal entity is generally accounted for under the equity method of accounting. Southern Power reconsiders its conclusions as to whether the legal entity is a VIE and whether it is the primary beneficiary for events that impact the rights of variable interests, such as ownership changes in membership interests. Southern Power has partial ownership in certain legal entities for which the contractual provisions represent profit-sharing arrangements because the allocations of cash distributions and tax benefits are not based on fixed ownership percentages. For these arrangements, the noncontrolling interest is accounted for under a balance sheet approach utilizing the HLBV method. The HLBV method calculates each partner's share of income based on the change in net equity the partner can legally claim in a HLBV at the end of the period compared to the beginning of the period. Contingent Obligations (All Registrants) The Registrants are subject to a number of federal and state laws and regulations, as well as other factors and conditions that subject them to environmental, litigation, and other risks. See FUTURE EARNINGS POTENTIAL herein and Notes 2 and 3 to the financial statements for more information regarding certain of these contingencies. The Registrants periodically evaluate their exposure to such risks and record reserves for those matters where a non-tax-related loss is considered probable and reasonably estimable. The adequacy of reserves can be significantly affected by external events or conditions that can be unpredictable; thus, the ultimate outcome of such matters could materially affect the results of operations, cash flows, or financial condition of the Registrants. Recently Issued Accounting Standards See Note 1 to the financial statements under "Recently Adopted Accounting Standards" for additional information. In 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842) (ASU 2016-02). ASU 2016-02 requires lessees to recognize on the balance sheet a lease liability and a right-of-use asset for all leases. ASU 2016-02 also changes the recognition, measurement, and presentation of expense associated with leases and provides clarification regarding the identification of certain components of contracts that would represent a lease. The accounting required by lessors is relatively unchanged and there is no change to the accounting for existing leveraged leases. The Registrants adopted the new standard effective January 1, 2019. See Note 9 to the financial statements for additional information and related disclosures. II-99 -------------------------------------------------------------------------------- Table of Contents Index to Financial Statements
COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Southern Company and Subsidiary Companies 2019 Annual Report
FINANCIAL CONDITION AND LIQUIDITY Overview The financial condition of each Registrant remained stable at December 31, 2019. The Registrants' cash requirements primarily consist of funding ongoing operations, including unconsolidated subsidiaries, as well as common stock dividends, capital expenditures, and debt maturities. Southern Power's cash requirements also include distributions to noncontrolling interests. Capital expenditures and other investing activities for the traditional electric operating companies include investments to meet projected long-term demand requirements, including to build new generation facilities, to maintain existing generation facilities, to comply with environmental regulations including adding environmental modifications to certain existing generating units and closures of ash ponds, to expand and improve transmission and distribution facilities, and for restoration following major storms. Southern Power's capital expenditures and other investing activities may include acquisitions or new construction associated with its overall growth strategy and to maintain its existing generation fleet's performance. Southern Company Gas' capital expenditures and other investing activities include investments to meet projected long-term demand requirements, to maintain existing natural gas distribution systems as well as to update and expand these systems, and to comply with environmental regulations. Operating cash flows provide a substantial portion of the Registrants' cash needs. During 2019, Southern Power utilized tax credits, which provided $734 million in operating cash flows. For the three-year period from 2020 through 2022, each Registrant's projected stock dividends, capital expenditures, and debt maturities, as well as distributions to noncontrolling interests for Southern Power, are expected to exceed its operating cash flows. Southern Company plans to finance future cash needs in excess of its operating cash flows primarily by accessing borrowings from financial institutions and issuing debt and hybrid securities in the capital markets. Each Subsidiary Registrant plans to finance its future cash needs in excess of its operating cash flows primarily through external securities issuances, borrowings from financial institutions, and equity contributions from Southern Company. In addition, Georgia Power plans to utilize borrowings through the FFB and Southern Power plans to utilize tax equity partnership contributions. The Registrants plan to use commercial paper to manage seasonal variations in operating cash flows and for other working capital needs and 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 "Sources of Capital," "Financing Activities," "Capital Requirements," and "Contractual Obligations" herein for additional information. The Registrants' investments in their qualified pension plans and Alabama Power's and Georgia Power's investments in their nuclear decommissioning trust funds increased in value at December 31, 2019 as compared to December 31, 2018. In December 2019, the Registrants voluntarily contributed the following amounts to the qualified pension plan: Southern Southern Company Company Alabama Power Georgia Power Mississippi Power Southern Power Gas (in millions) Contributions to qualified pension plan $ 1,136 $ 362 $ 200 $ 54 $ 24 $ 145 No mandatory contributions to the qualified pension plans are anticipated during 2020. See "Contractual Obligations" herein and Notes 6 and 11 to the financial statements under "Nuclear Decommissioning" and "Pension Plans," respectively, for additional information. At the end of 2019, the market price of Southern Company's common stock was $63.70 per share (based on the closing price as reported on the NYSE) and the book value was $26.11 per share, representing a market-to-book value ratio of 244%, compared to $43.92, $23.91, and 184%, respectively, at the end of 2018. II-100 -------------------------------------------------------------------------------- Table of Contents Index to Financial Statements
COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Southern Company and Subsidiary Companies 2019 Annual Report
Analysis of Cash Flows Net cash flows provided from (used for) operating, investing, and financing activities in 2019 and 2018 are presented in the following table: Net cash provided from
Georgia Southern (used for): Southern Company Alabama Power Power Mississippi Power Southern Power Company Gas (in millions) 2019 Operating activities $ 5,781 $ 1,779 $ 2,907 $ 339 $ 1,385 $ 1,067 Investing activities (3,392 ) (1,963 ) (3,885 ) (263 ) (167 ) (1,386 ) Financing activities (1,930 ) 765 918 (83 ) (1,120 ) 298 2018 Operating activities $ 6,945 $ 1,881 $ 2,769 $ 804 $ 631 $ 764 Investing activities (5,760 ) (2,289 ) (3,109 ) (232 ) (227 ) 998 Financing activities (1,813 ) 177 (400 ) (527 ) (363 ) (1,770 ) 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 $1.2 billion in 2019 as compared to 2018 primarily due to the voluntary contribution to the qualified pension plan and the timing of vendor payments. The net cash used for investing activities in 2019 and 2018 was primarily due to the traditional electric operating companies' construction of electric generation, transmission, and distribution facilities, including installation of equipment to comply with environmental standards, and capital expenditures for Southern Company Gas' infrastructure replacement programs, partially offset by proceeds from the sale transactions described in Note 15 to the financial statements, which totaled $5.1 billion and $3.0 billion in 2019 and 2018, respectively. The net cash used for financing activities in 2019 was primarily due to common stock dividend payments and net repayments of short-term bank debt and commercial paper, partially offset by net issuances of long-term debt and the issuance of common stock. The net cash used for financing activities in 2018 was primarily due to net redemptions and repurchases of long-term debt, common stock dividend payments, and a decrease in commercial paper borrowings, partially offset by net issuances of short-term bank debt, proceeds from Southern Power's sales of non-controlling equity interests in entities indirectly owning substantially all of its solar facilities and eight of its wind facilities, and the issuance of common stock. Alabama Power Net cash provided from operating activities decreased $102 million in 2019 as compared to 2018 primarily due to the voluntary contribution to the qualified pension plan, partially offset by the impacts of customer bill credits issued in 2018 related to the Tax Reform Legislation and increased fuel cost recovery. The net cash used for investing activities in 2019 and 2018 was primarily due to gross property additions. The net cash provided from financing activities in 2019 was primarily due to capital contributions from Southern Company and a long-term debt issuance, partially offset by payments of common stock dividends and a maturity of long-term debt. The net cash provided from financing activities in 2018 was primarily due to issuances of long-term debt and additional capital contributions from Southern Company, partially offset by the payment of common stock dividends and a maturity of long-term debt. Georgia Power Net cash provided from operating activities increased $138 million in 2019 as compared to 2018 primarily due to lower customer refunds and increased fuel cost recovery, partially offset by the voluntary contribution to the qualified pension plan. II-101 -------------------------------------------------------------------------------- Table of Contents Index to Financial Statements
COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Southern Company and Subsidiary Companies 2019 Annual Report
The net cash used for investing activities in 2019 and 2018 was primarily due to gross property additions, including a total of $2.5 billion related to the construction of Plant Vogtle Units 3 and 4. See FUTURE EARNINGS POTENTIAL - "Construction Programs - Nuclear Construction" herein for additional information on construction of Plant Vogtle Units 3 and 4. The net cash provided from financing activities in 2019 was primarily due to borrowings from the FFB for construction of Plant Vogtle Units 3 and 4, issuances of senior notes, capital contributions from Southern Company, and pollution control revenue bonds reoffered to the public, partially offset by payment of common stock dividends and the maturity of senior notes. The net cash used for financing activities in 2018 was primarily due to the redemption and repurchase of senior notes, payment of common stock dividends, and pollution control revenue bond repurchases, partially offset by capital contributions from Southern Company. Mississippi Power Net cash provided from operating activities decreased $465 million in 2019 as compared to 2018 primarily due to higher income tax refunds in 2018 as a result of the tax impact of the abandonment of the Kemper IGCC and the voluntary contribution to the qualified pension plan in 2019. The net cash used for investing activities in 2019 and 2018 was primarily due to gross property additions. The net cash used for financing activities in 2019 was primarily due to a return of capital to Southern Company and the redemption of senior notes, partially offset by capital contributions from Southern Company and pollution control revenue bonds reoffered to the public. The net cash used for financing activities in 2018 was primarily due to the redemption of preferred stock, long-term bank debt, short-term borrowings, and senior notes, partially offset by the issuance of senior notes and short-term borrowings. Southern Power Net cash provided from operating activities increased $754 million in 2019 as compared to 2018 primarily due to the utilization of federal ITCs totaling $734 million in 2019. At December 31, 2019, Southern Power had $1.4 billion of unutilized ITCs and PTCs which are expected to be fully utilized by 2024. See FUTURE EARNINGS POTENTIAL - "Income Tax Matters - Tax Credits" herein for additional information. The net cash used for investing activities in 2019 was primarily due to Southern Power's investment in DSGP and ongoing construction activities, largely offset by proceeds from the sales of Plant Nacogdoches and certain wind turbine equipment. The net cash used for investing activities in 2018 was primarily due to the construction of generating facilities and payments for renewable acquisitions, partially offset by proceeds from the disposition of the Florida Plants. See FUTURE EARNINGS POTENTIAL - "Acquisitions and Dispositions" and "Construction Programs" herein and Note 15 to the financial statements for additional information. The net cash used for financing activities in 2019 was primarily due to returns of capital to Southern Company, the repayment at maturity of senior notes, payments of common stock dividends, and distributions to noncontrolling interests, partially offset by proceeds from net issuances of commercial paper. The net cash used for financing activities in 2018 was primarily due to returns of capital to Southern Company, payments of common stock dividends, and distributions to noncontrolling interests, partially offset by capital contributions from noncontrolling interests. Southern Company Gas Net cash provided from operating activities increased $303 million in 2019 as compared to 2018 primarily due to the timing of collection of customer receivables and lower income tax payments, partially offset by the timing of vendor payments and the voluntary contribution to the qualified pension plan. The net cash used for investing activities in 2019 was primarily due to gross property additions related to utility capital expenditures and infrastructure investments recovered through replacement programs at gas distribution operations and capital contributed to equity method pipeline investments, partially offset by proceeds from the sale of Triton and capital distributions in excess of earnings from equity method pipeline investments. The net cash provided from investing activities in 2018 was primarily due to proceeds from the Southern Company Gas Dispositions, partially offset by gross property additions primarily related to utility capital expenditures and pre-approved rider and infrastructure investments recovered through replacement programs at gas distribution operations as well as net capital contributions to equity method pipeline investments. The net cash provided from financing activities in 2019 was primarily due to capital contributions from Southern Company and proceeds from the issuance of first mortgage bonds, partially offset by the redemption of long-term debt and payments of common stock dividends. The net cash used for financing activities in 2018 was primarily due to payments of common stock dividends to II-102 -------------------------------------------------------------------------------- Table of Contents Index to Financial Statements
COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Southern Company and Subsidiary Companies 2019 Annual Report
Southern Company, return of capital to Southern Company, redemptions of gas facility revenue bonds and senior notes, and repayments of commercial paper borrowings and long-term debt, partially offset by debt issuances and capital contributions from Southern Company. Significant Balance Sheet Changes Southern Company Significant balance sheet changes in 2019 for Southern Company included: • decreases in assets and liabilities held for sale of $5.0 billion and $3.3
billion, respectively, and an increase of $2.7 billion in total stockholders'
equity primarily related to the sale of Gulf Power;
• an increase of $2.3 billion in total property, plant, and equipment primarily
related to the traditional electric operating companies' construction of
electric generation, transmission, and distribution facilities, including
installation of equipment to comply with environmental standards, net of $1.2
billion and $1.0 billion reclassified to other regulatory assets and regulatory assets associated with AROs, respectively, as a result of generating unit retirements at Alabama Power and Georgia Power;
• an increase in other regulatory assets of $1.8 billion primarily related to
the $1.2 billion reclassification from property, plant, and equipment
discussed above and a $0.8 billion increase in regulatory assets associated
with retiree benefit plans primarily resulting from a decrease in the overall
discount rate used to calculate benefit obligations;
• increases in operating lease right-of-use assets, net of amortization and
operating lease obligations, each totaling $1.8 billion, recorded upon the
adoption of ASC 842;
• an increase of $1.4 billion in regulatory assets associated with AROs
primarily related to the $1.0 billion reclassification from property, plant,
and equipment discussed above and ARO revisions at Alabama Power and
Mississippi Power related to the CCR Rule;
• an increase of $1.3 billion in accumulated deferred income taxes primarily
related to the expected utilization of tax credit carryforwards in the 2019
tax year as a result of increased taxable income from the sale of Gulf Power;
and
• a decrease of $0.9 billion in notes payable related to net repayments of
short-term bank debt and commercial paper.
See Notes 2, 5, 6, 8, 9, 10, 11, and 15 to the financial statements for additional information. Alabama Power Significant balance sheet changes in 2019 for Alabama Power included: • an increase of $1.5 billion in total common stockholder's equity primarily
due to a $1.2 billion capital contribution from Southern Company;
• increases of $0.9 billion in regulatory assets associated with AROs and $0.7
billion in other regulatory assets, deferred primarily due to the impacts of
retiring and reclassifying Plant Gorgas Units 8, 9, and 10;
• an increase of $0.6 billion in cash and cash equivalents; and
• an increase of $0.3 billion in AROs, deferred primarily due to an increase in
the ARO estimate related to ash pond facilities.
See Notes 2 and 6 to the financial statements for additional information.
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COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Southern Company and Subsidiary Companies 2019 Annual Report
Georgia Power Significant balance sheet changes in 2019 for Georgia Power included: • an increase of $1.8 billion in long-term debt (including securities due
within one year) primarily due to borrowings from the FFB for construction of
Plant Vogtle Units 3 and 4, issuances of senior notes, and pollution control
revenue bonds being reoffered to the public;
• an increase of $1.6 billion in property, plant, and equipment to comply with
environmental standards and the construction of generation, transmission, and
distribution facilities, net of approximately $0.8 billion reclassified to
regulatory assets due to the retirement of certain generating units as
approved in the Georgia Power 2019 IRP;
• increases in operating lease right-of-use assets, net of amortization and
operating lease obligations, each totaling $1.4 billion, recorded upon the
adoption of ASC 842;
• an increase of $1.2 billion in regulatory assets primarily due to the $0.8
billion reclassification from property, plant, and equipment discussed above
and $0.2 billion associated with retiree benefit plans primarily as a result
of a decrease in the overall discount rate used to calculate benefit
obligations; and
• an increase of $742 million in total common stockholder's equity primarily
due to capital contributions from Southern Company.
See Notes 2, 8, 9, and 11 to the financial statements for additional information. Mississippi Power Significant balance sheet changes in 2019 for Mississippi Power included: • a decrease of $231 million in long-term debt, primarily due to the
reclassification of $249 million of senior notes to securities due within one
year and the redemption of $25 million of senior notes, partially offset by
$43 million in pollution control revenue bonds reoffered to the public;
• an increase of $107 million in other property and investments primarily due
to a new tolling arrangement accounted for as a sales-type lease;
• increases of $67 million in regulatory assets associated with AROs and $31
million in AROs, deferred primarily due to ARO revisions; and
• a net change of $57 million in accumulated deferred income tax assets and
liabilities primarily due to the recognition of a tax loss on the CO2
pipeline transfer and the alternative minimum tax carryforward from prior
years.
See Notes 2, 6, 8, 9, and 10 to the financial statements for additional information. Southern Power Significant balance sheet changes in 2019 for Southern Power included: • a $662 million decrease in stockholders' equity due to returns of capital to
Southern Company;
• a $635 million decrease in accumulated deferred income tax assets primarily
related to the utilization of tax credits for the 2019 tax year;
• a $619 million decrease in long-term debt (including securities due within
one year) related to the maturity of $600 million in senior notes;
• a $449 million increase in notes payable due to net issuances of commercial
paper; and
• increases in operating lease right-of-use assets, net of amortization and
operating lease obligations totaling $369 million and $376 million,
respectively, recorded upon the adoption of ASC 842.
See Notes 8, 9, and 10 to the financial statements for additional information. Southern Company Gas Significant balance sheet changes in 2019 for Southern Company Gas included: • an increase of $950 million in property, plant, and equipment primarily due
to utility capital expenditures and infrastructure investments recovered
through replacement programs, partially offset by $115 million of asset
impairment charges;
• additional paid-in-capital of $841 million primarily related to capital
contributions from Southern Company;
• decreases of $373 million and $414 million in energy marketing receivables
and payables, respectively, due to lower natural gas prices and volumes of natural gas sold; II-104
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COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Southern Company and Subsidiary Companies 2019 Annual Report
• a $287 million decrease in equity investments in unconsolidated subsidiaries
primarily due to $151 million associated with Pivotal LNG and Atlantic Coast
Pipeline reclassified to assets held for sale, as well as distributions from
SNG and the sale of Triton;
• a $203 million increase in accumulated deferred income taxes primarily due to
accelerated tax depreciation and other timing differences;
• reclassification of $171 million in total assets held for sale associated
with Pivotal LNG and Atlantic Coast Pipeline;
• a $95 million decrease in long-term debt primarily due to the redemption of
$300 million in senior notes and the repayment of $50 million in first
mortgage bonds, partially offset by the issuance of $300 million in first
mortgage bonds; and
• increases of $93 million in operating right-of-use assets and $92 million in
operating lease obligations, respectively, related to the adoption of ASC
842.
See Notes 3, 7, 8, 9, 10, and 15 to the financial statements for additional information. Sources of Capital Southern Company intends to meet its future capital needs through operating cash flows, borrowings from financial institutions, and debt and equity issuances in the capital markets. 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 2024. 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," Southern Power plans to utilize tax equity partnership contributions, as discussed further herein, and Southern Company Gas plans to utilize proceeds from the pending sale of its interests in Pivotal LNG and Atlantic Coast Pipeline, as discussed further in Note 15 to the financial statements under "Southern Company Gas - Proposed Sale of Pivotal LNG and Atlantic Coast Pipeline." The amount, type, and timing of any financings in 2020, 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 the Subsidiary Registrants), and other factors. See "Capital Requirements" herein for additional information. Southern Power utilizes tax equity partnerships as one of its financing sources, where the tax partner takes significantly all of the federal tax benefits. These tax equity partnerships are consolidated in Southern Power's financial statements and are accounted for using HLBV methodology to allocate partnership gains and losses. During 2019, Southern Power obtained tax equity funding for the Wildhorse Mountain wind project and received proceeds of $97 million. See Notes 1 and 15 to the financial statements under "General" and "Southern Power," respectively, for additional information. The issuance of securities by the traditional electric operating companies and Nicor Gas is generally subject to the approval of the applicable state PSC or other applicable state regulatory agency. The issuance of all securities by Mississippi Power and short-term securities by Georgia Power is generally subject to regulatory approval by the FERC. Additionally, with respect to the public offering of securities, Southern Company, the traditional electric operating companies, and Southern Power (excluding its subsidiaries), Southern Company Gas Capital, and Southern Company Gas (excluding its other subsidiaries) file registration statements with the SEC under the Securities Act of 1933, as amended (1933 Act). The amounts of securities authorized by the appropriate regulatory authorities, as well as the securities registered under the 1933 Act, are closely monitored and appropriate filings are made to ensure flexibility in the capital markets. The Registrants generally obtain financing separately without credit support from any affiliate. See Note 8 to the financial statements under "Bank Credit Arrangements" for additional information. The Southern Company system does not maintain a centralized cash or money pool. Therefore, funds of each company are not commingled with funds of any other company in the Southern Company system, except in the case of Southern Company Gas, as described below. The traditional electric operating companies and SEGCO may utilize a Southern Company subsidiary organized to issue and sell commercial paper at their request and for their benefit. Proceeds from such issuances for the benefit of an individual company are loaned directly to that company. The obligations of each traditional electric operating company and SEGCO under these arrangements are several and there is no cross-affiliate credit support. Alabama Power also maintains its own separate commercial paper program. Southern Company Gas Capital obtains external financing for Southern Company Gas and its subsidiaries, other than Nicor Gas, which obtains financing separately without credit support from any affiliates. Southern Company Gas maintains commercial II-105 -------------------------------------------------------------------------------- Table of Contents Index to Financial Statements
COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Southern Company and Subsidiary Companies 2019 Annual Report
paper programs at Southern Company Gas Capital and Nicor Gas. Nicor Gas' commercial paper program supports its working capital needs as Nicor Gas is not permitted to make money pool loans to affiliates. All of the other Southern Company Gas subsidiaries benefit from Southern Company Gas Capital's commercial paper program. 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 December 31, 2019, the amount of subsidiary retained earnings restricted to dividend totaled $951 million. 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. The 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. See Note 8 to the financial statements for additional information. Also see "Financing Activities" herein for information on issuances of long-term debt subsequent to December 31, 2019. At December 31, 2019, the following Registrants' current liabilities exceeded their current assets, primarily as a result of securities due within one year and notes payable, as shown in the table below: Southern Georgia At December 31, 2019 Company(*) Power
Mississippi Power Southern Power
(in
millions)
Current liabilities in excess of current assets $ 2,729 $ 1,902 $ 125 $ 945 Securities due within one year 2,989 1,025 281 824 Notes payable 2,055 365 - 549
(*) Includes $600 million and $465 million of securities due within one year and
notes payable, respectively, at the parent company.
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 December 31, 2019, the Registrants' unused committed credit arrangements with banks were as follows: Southern At December 31, Company Alabama Georgia Southern Southern Southern 2019 parent Power Power Mississippi Power Power(a) Company Gas(b) SEGCO Company (in millions)
Unused committed
credit $ 1,999 $ 1,328 $ 1,733 $ 150
$ 591 $ 1,745 $ 30 $ 7,576
(a) At December 31, 2019, Southern Power also had a continuing letter of credit
facility for standby letters of credit, of which $23 million was unused.
Subsequent to December 31, 2019, Southern Power entered into an additional
$60 million continuing letter of credit facility for standby letters of
credit. Southern Power's subsidiaries are not parties to its bank credit
arrangement or to the letter of credit facilities.
(b) Includes $1.245 billion and $500 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. See Note 8 to the financial statements 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: II-106 -------------------------------------------------------------------------------- Table of Contents Index to Financial Statements
COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Southern Company and Subsidiary Companies 2019 Annual Report
Short-term Debt at the End of the Period Amount Weighted Average Outstanding Interest Rate December 31, December 31, 2019 2018 2017 2019 2018 2017 (in millions) Southern Company $ 2,055 $ 2,915 $ 2,439 2.1 % 3.1 % 1.9 % Alabama Power - - 3 - - 3.7 Georgia Power 365 294 150 2.2 3.1 2.2 Mississippi Power - - 4 - - 3.8 Southern Power 549 100 105 2.2 3.1 2.0 Southern Company Gas: Southern Company Gas Capital $ 372 $ 403 $ 1,243 2.1 % 3.1 % 1.7 % Nicor Gas 278 247 275 1.8 3.0 1.8 Southern Company Gas Total $ 650 $ 650 $ 1,518 2.0 % 3.0 % 1.8 % Short-term Debt During the Period(*) Weighted Average Average Amount Outstanding Interest Rate Maximum Amount Outstanding 2019 2018 2017 2019 2018 2017 2019 2018 2017 (in millions) (in millions)
Southern Company $ 1,240 $ 3,377 $ 2,672 2.6 % 2.6 %
1.5 % $ 2,914 $ 5,447 $ 3,668 Alabama Power 17 27 25 2.6 2.3 1.3 190 258 223 Georgia Power 371 139 427 2.7 2.5 1.8 935 710 1,460 Mississippi Power - 68 18 - 2.0 3.0 - 300 36 Southern Power 76 188 232 2.7 2.5 1.4 578 385 419 Southern Company Gas: Southern Company Gas Capital $ 302 $ 520 $ 723 2.6 % 2.3 % 1.4 % $ 490 $ 1,361 $ 1,243 Nicor Gas 91 123 176 2.3 2.2 1.1 278 275 525 Southern Company Gas Total $ 393 $ 643 $ 899 2.5 % 2.3 % 1.4 %
(*) Average and maximum amounts are based upon daily balances during the 12-month
periods ended December 31, 2019, 2018, and 2017. II-107
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COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Southern Company and Subsidiary Companies 2019 Annual Report
Financing Activities The following table outlines the Registrants' long-term debt financing activities for the year ended December 31, 2019:
Revenue Other Bond Revenue Long-Term Senior Note Issuances and Bond Other Debt Senior Maturities, Reofferings Maturities, Long-Term Redemptions Note Redemptions, and of Purchased Redemptions, Debt and Company Issuances Repurchases Bonds
and Repurchases Issuances Maturities(a)
(in millions) Southern Company parent $ - $ 2,400 $ - $ - $ 1,725 $ - Alabama Power 600 200 - - - 1 Georgia Power 750 500 584 223 1,218 13 Mississippi Power - 25 43 - - - Southern Power - 600 - - - - Southern Company Gas - 300 - - 300 50 Other - - - 25 - 17 Elimination(b) - - - - - (7 ) Southern Company $ 1,350 $ 4,025 $ 627 $ 248 $ 3,243 $ 74
(a) Includes reductions in finance lease obligations resulting from cash payments
under finance leases.
(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. 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 2019, Southern Company issued approximately 19.5 million shares of common stock through employee equity compensation plans and received proceeds of approximately $844 million. In addition, in August 2019, Southern Company issued 34.5 million 2019 Series A Equity Units (Equity Units), initially in the form of corporate units (Corporate Units), at a stated amount of $50 per Corporate Unit, for a total stated amount of $1.725 billion. Net proceeds from the issuance were approximately $1.682 billion. Each Corporate Unit is comprised of (i) a 1/40 undivided beneficial ownership interest in $1,000 principal amount of Southern Company's Series 2019A Remarketable Junior Subordinated Notes due 2024, (ii) a 1/40 undivided beneficial ownership interest in $1,000 principal amount of Southern Company's Series 2019B Remarketable Junior Subordinated Notes due 2027, and (iii) a stock purchase contract, which obligates the holder to purchase from Southern Company, no later than August 1, 2022, a certain number of shares of Southern Company's common stock for $50 in cash. See Note 8 to the financial statements under "Equity Units" for additional information. In January 2019, Southern Company repaid a $250 million short-term uncommitted bank credit arrangement and a $1.5 billion short-term floating rate bank loan. In 2019, Southern Company, through repurchases and redemptions, retired all $1.0 billion aggregate principal amount of its 1.85% Senior Notes due July 1, 2019, $350 million aggregate principal amount of its Series 2014B 2.15% Senior Notes due September 1, 2019, $750 million aggregate principal amount of its Series 2018A Floating Rate Notes due February 14, 2020, and $300 million aggregate principal amount of its Series 2017A Floating Rate Senior Notes due September 30, 2020. Subsequent to December 31, 2019, Southern Company issued $1.0 billion aggregate principal amount of Series 2020A 4.95% Junior Subordinated Notes due January 30, 2080. Alabama Power In February 2019, Alabama Power repaid at maturity $200 million aggregate principal amount of Series Z 5.125% Senior Notes due February 15, 2019. II-108 -------------------------------------------------------------------------------- Table of Contents Index to Financial Statements
COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Southern Company and Subsidiary Companies 2019 Annual Report
In September 2019, Alabama Power issued $600 million aggregate principal amount of Series 2019A 3.45% Senior Notes due October 1, 2049. Subsequent to December 31, 2019, Alabama Power received a capital contribution totaling $610 million from Southern Company. Georgia Power In March and December 2019, Georgia Power made borrowings under the multi-advance credit facilities related to the Amended and Restated Loan Guarantee Agreement in an aggregate principal amount of $835 million and $383 million, respectively, with applicable interest rates of 3.213% and 2.537%, respectively, both for an interest period that extends to 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. See Note 8 to the financial statements under "Long-term Debt - DOE Loan Guarantee Borrowings" for additional information. In June 2019, Georgia Power entered into two short-term floating rate bank loans in aggregate principal amounts of $125 million each, both of which bear interest based on one-month LIBOR. In September 2019, Georgia Power issued $400 million aggregate principal amount of Series 2019A 2.20% Senior Notes due September 15, 2024 and $350 million aggregate principal amount of Series 2019B 2.65% Senior Notes due September 15, 2029. Subsequent to December 31, 2019, Georgia Power issued $700 million aggregate principal amount of Series 2020A 2.10% Senior Notes due July 30, 2023, $500 million aggregate principal amount of Series 2020B 3.70% Senior Notes due January 30, 2050, and an additional $300 million aggregate principal amount of Series 2019B 2.65% Senior Notes due September 15, 2029. During 2019, Georgia Power reoffered to the public the following pollution control revenue bonds that previously had been purchased and were held by Georgia Power at December 31, 2018: • $173 million aggregate principal amount of Development Authority of Bartow
County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company
Plant Bowen Project), First Series 2009;
• approximately $105 million aggregate principal amount of Development
Authority of Burke County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Vogtle Project), First Series 2013; • $65 million aggregate principal amount of Development Authority of Burke
County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company
Plant Vogtle Project), Second Series 2008; • $55 million aggregate principal amount of Development Authority of Burke
County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company
Plant Vogtle Project), Fifth Series 1994; and
• approximately $72 million aggregate principal amount of Development
Authority of Bartow County (Georgia) Pollution Control Revenue Bonds
(Georgia Power Company Plant Bowen Project), First Series 2013.
During 2019, Georgia Power purchased, held, and subsequently reoffered to the public an additional $115 million of pollution control revenue bonds. In January 2019, Georgia Power redeemed approximately $13 million, $20 million, and $75 million aggregate principal amount of Development Authority of Burke County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Vogtle Project), First Series 1992, Eighth Series 1994, and Second Series 1995, respectively. In December 2019, Georgia Power repaid at maturity $500 million aggregate principal amount of its Series 2009B 4.25% Senior Notes. Subsequent to December 31, 2019, Georgia Power received a capital contribution totaling $500 million from Southern Company and announced the redemption of all $500 million aggregate principal amount of its Series 2017C 2.00% Senior Notes due September 8, 2020. Mississippi Power In March 2019, Mississippi Power reoffered to the public approximately $43 million of Mississippi Business Finance Corporation Pollution Control Revenue Refunding Bonds, Series 2002, which previously had been purchased and held by Mississippi Power. In December 2019, Mississippi Power redeemed $25 million aggregate principal amount of its Series 2018A Floating Rate Senior Notes due March 27, 2020. Southern Power In May 2019, Southern Power repaid at maturity a $100 million short-term floating rate bank loan. II-109 -------------------------------------------------------------------------------- Table of Contents Index to Financial Statements
COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Southern Company and Subsidiary Companies 2019 Annual Report
In December 2019, Southern Power repaid at maturity $600 million aggregate principal amount of its Series 2016D 1.95% Senior Notes. Also in December 2019, Southern Power entered into a short-term floating rate bank loan in the aggregate principal amount of $100 million, bearing interest based on one-month LIBOR. Subsequent to December 31, 2019, Southern Power repaid the bank loan. Southern Company Gas In July 2019, Nicor Gas repaid at maturity $50 million aggregate principal amount of its 4.7% first mortgage bonds. In August 2019, Southern Company Gas Capital repaid at maturity $300 million aggregate principal amount of its 5.25% Senior Notes. In August and October 2019, Nicor Gas issued $200 million and $100 million, respectively, aggregate principal amount of first mortgage bonds in a private placement. Credit Rating Risk At December 31, 2019, 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 December 31, 2019 were as follows: Southern Southern Company Credit Ratings Southern Company(*) Alabama Power Georgia Power Mississippi Power Power(*) Gas (in millions) At BBB and/or Baa2 $ 36 $ 1 $ - $ - $ 35 $ - At BBB- and/or Baa3 472 1 86 - 385 - At BB+ and/or Ba1 or below 2,040 322 1,020 267 1,174 18
(*) Excludes amounts related to Plant Mankato, which was sold on January 17,
2020. 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 $104 million of cash collateral
posted related to PPA requirements at December 31, 2019.
The potential collateral requirement amounts in the previous table for the traditional electric operating companies and Southern Power include certain agreements that could require collateral in the event that 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. Mississippi Power and its largest retail customer, Chevron, have agreements under which Mississippi Power continues to provide retail service to the Chevron refinery in Pascagoula, Mississippi through 2038. The agreements grant Chevron a security interest in the co-generation assets located at the refinery that is exercisable upon the occurrence of (i) certain bankruptcy events or (ii) other events of default coupled with specific reductions in steam output at the facility and a downgrade of Mississippi Power's credit rating to below investment grade by two of the three rating agencies. On August 1, 2019, Moody's upgraded Mississippi Power's senior unsecured long-term debt rating to Baa2 from Baa3 and maintained the positive rating outlook. On September 12, 2019, S&P upgraded the senior unsecured long-term debt rating of Alabama Power to A from A-, the long-term issuer rating of Nicor Gas to A from A-, and the senior secured debt rating of Nicor Gas to A+ from A. The ratings outlooks remained negative. II-110 -------------------------------------------------------------------------------- Table of Contents Index to Financial Statements
COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Southern Company and Subsidiary Companies 2019 Annual Report
Market Price Risk The Registrants are exposed to market risks, including commodity price risk, interest rate risk, weather risk, and occasionally foreign currency exchange rate risk. To manage the volatility attributable to these exposures, the applicable company nets the exposures, where possible, to take advantage of natural offsets and enters into various derivative transactions for the remaining exposures pursuant to the applicable company's policies in areas such as counterparty exposure and risk management practices. Southern Company Gas' wholesale gas operations uses various contracts in its commercial activities that generally meet the definition of derivatives. For the traditional electric operating companies, Southern Power, and Southern Company Gas' other businesses, each company's policy is that derivatives are to be used primarily for hedging purposes and mandates strict adherence to all applicable risk management policies. Derivative positions are monitored using techniques including, but not limited to, market valuation, value at risk, stress testing, and sensitivity analysis. Due to cost-based rate regulation and other various cost recovery mechanisms, the traditional electric operating companies and the natural gas distribution utilities that sell natural gas directly to end-use customers continue to have limited exposure to market volatility in interest rates, foreign currency exchange rates, commodity fuel prices, and prices of electricity. The traditional electric operating companies and certain of the natural gas distribution utilities manage fuel-hedging programs implemented per the guidelines of their respective state PSCs or other applicable state regulatory agencies to hedge the impact of market fluctuations in natural gas prices for customers. Mississippi Power also manages wholesale fuel-hedging programs under agreements with its wholesale customers. Because energy from Southern Power's facilities is primarily sold under long-term PPAs with tolling agreements and provisions shifting substantially all of the responsibility for fuel cost to the counterparties, Southern Power's exposure to market volatility in commodity fuel prices and prices of electricity is generally limited. However, Southern Power has been and may continue to be exposed to market volatility in energy-related commodity prices as a result of uncontracted generating capacity. To mitigate residual risks relative to movements in electricity prices, the traditional electric operating companies and Southern Power may enter into physical fixed-price contracts for the purchase and sale of electricity through the wholesale electricity market and, to a lesser extent, financial hedge contracts for natural gas purchases; however, a significant portion of contracts are priced at market. Certain of Southern Company Gas' non-regulated operations 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 OTC energy contracts, such as forward contracts, futures contracts, options contracts, and swap agreements. Southern Company Gas' gas marketing services and wholesale gas services businesses also actively manage storage positions through a variety of hedging transactions for the purpose of managing exposures arising from changing natural gas prices. These hedging instruments are used to substantially protect economic margins (as spreads between wholesale and retail natural gas prices widen between periods) and thereby minimize exposure to declining operating margins. Some of these economic hedge activities may not qualify, or may not be designated, for hedge accounting treatment. The Registrants had no material change in market risk exposure for the year ended December 31, 2019 when compared to the year ended December 31, 2018. See Note 1 to the financial statements under "Financial Instruments" and Note 14 to the financial statements for additional information. The Registrants may enter into interest rate derivatives designated as hedges, which are intended to mitigate interest rate volatility related to forecasted debt financings and existing fixed and floating rate obligations. Outstanding interest rate derivatives at December 31, 2019 are as follows: Georgia Southern
Company
At December 31, 2019 Southern Company(*) Power Gas (in millions) Hedges of forecasted debt $ 700 $ 500 $ 200 Hedges of existing debt 1,800 - - Total $ 2,500 $ 500 $ 200
(*) Includes $1.8 billion of hedges of existing debt at the Southern Company
parent. II-111
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COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Southern Company and Subsidiary Companies 2019 Annual Report
The following table provides information related to variable interest rate exposure on long-term debt (including amounts due within one year) at December 31, 2019 for the applicable Registrants:
Southern Alabama Georgia Mississippi Southern At December 31, 2019 Company(*) Power Power Power Power (in millions, except percentages) Long-term variable interest rate exposure $ 4,063 $ 1,079 $ 550 $ 308 $ 525 Weighted average interest rate on long-term variable interest rate exposure 2.38 % 2.35 % 1.74 % 2.51 % 2.46 % Impact on annualized interest expense of 100 basis point change in interest rates $ 41 $ 11 $ 6 $ 3 $ 5
(*) Includes $1.5 billion of long-term variable interest rate exposure at the
Southern Company parent entity.
Southern Power Company had foreign currency denominated debt of €1.1 billion at December 31, 2019. Southern Power Company has mitigated its exposure to foreign currency exchange rate risk through the use of foreign currency swaps converting all interest and principal payments to fixed-rate U.S. dollars. The changes in fair value of energy-related derivative contracts for Southern Company and Southern Company Gas for the years ended December 31, 2019 and 2018 are provided in the table below. The fair value of energy-related derivative contracts was not material for the other Registrants. Southern
Company(a) Southern Company Gas(a)
(in millions) Contracts outstanding at December 31, 2017, assets (liabilities), net $ (163 ) $ (106 ) Contracts realized or settled 93 66 Current period changes(b) (131 ) (127 ) Contracts outstanding at December 31, 2018, assets (liabilities), net $ (201 ) $ (167 ) Contracts realized or settled 69 26 Current period changes(b) 105 213 Disposition 6 -
Contracts outstanding at December 31, 2019, assets (liabilities), net
$ (21 ) $ 72
(a) Excludes cash collateral held on deposit in broker margin accounts of $99
million, $277 million, and $193 million at December 31, 2019, 2018, and 2017,
respectively, and premium and intrinsic value associated with weather
derivatives of $4 million, $8 million, and $11 million at December 31, 2019,
2018, and 2017, respectively.
(b) The changes in fair value of energy-related derivative contracts are
substantially attributable to both the volume and the price of natural gas.
Current period changes also include the changes in fair value of new
contracts entered into during the period, if any.
The net hedge volumes of energy-related derivative contracts for natural gas purchased (sold) at December 31, 2019 and 2018 for Southern Company and Southern Company Gas were as follows: Southern Company Southern Company Gas mmBtu Volume (in millions) At December 31, 2019: Commodity - Natural gas swaps 327 - Commodity - Natural gas options 262 218 Total hedge volume 589 218 At December 31, 2018: Commodity - Natural gas swaps 287 - Commodity - Natural gas options 144 120 Total hedge volume 431 120 II-112
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COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Southern Company and Subsidiary Companies 2019 Annual Report
Southern Company Gas' derivative contracts are comprised of both long and short natural gas positions. A long position is a contract to purchase natural gas, and a short position is a contract to sell natural gas. The volumes presented above for Southern Company Gas represent the net of long natural gas positions of 4.10 billion mmBtu and short natural gas positions of 3.88 billion mmBtu at December 31, 2019 and the net of long natural gas positions of 4.16 billion mmBtu and short natural gas positions of 4.04 billion mmBtu at December 31, 2018. For the Southern Company system, the weighted average swap contract cost above market prices was approximately $0.28 and $0.12 per mmBtu at December 31, 2019 and 2018, respectively. The change in option fair value is primarily attributable to the volatility of the market and the underlying change in the natural gas price. Substantially all of the traditional electric operating companies' natural gas hedge gains and losses are recovered through their respective fuel cost recovery clauses. At December 31, 2019 and 2018, substantially all of the traditional electric operating companies' and certain of the natural gas distribution utilities' energy-related derivative contracts were designated as regulatory hedges and were related to the applicable company's fuel-hedging program. Gains and losses associated with regulatory hedges are initially recorded as regulatory liabilities and assets, respectively, and then are included in fuel expense/cost of natural gas as they are recovered through their respective cost recovery clause. Gains and losses on energy-related derivatives designated as cash flow hedges, which are used to hedge anticipated purchases and sales, are initially deferred in AOCI before being recognized in income in the same period as the hedged transaction. Gains and losses on energy-related derivative contracts that are not designated or fail to qualify as hedges are recognized in the statements of income as incurred. See Note 14 to the financial statements for additional information. Some energy-related derivative contracts require physical delivery as opposed to financial settlement, and this type of derivative is both common and prevalent within the electric and natural gas industries. When an energy-related derivative contract is settled physically, any cumulative unrealized gain or loss is reversed and the contract price is recognized in the respective line item representing the actual price of the underlying goods being delivered. The Registrants use over-the-counter contracts that are not exchange traded but are fair valued using prices which are market observable, and thus fall into Level 2 of the fair value hierarchy. In addition, Southern Company Gas uses exchange-traded market-observable contracts, which are categorized as Level 1, and contracts that include a combination of observable and unobservable components, which are categorized as Level 3. See Note 13 to the financial statements for further discussion of fair value measurements. The maturities of the energy-related derivative contracts for Southern Company and Southern Company Gas at December 31, 2019 were as follows: Fair Value Measurements of Contracts at December 31, 2019 Total Maturity Fair Value Year 1 Years 2&3 Years 4&5 (in millions) Southern Company Level 1(a) $ (53 ) $ (19 ) $ (37 ) $ 3 Level 2(b) 18 42 (25 ) 1 Level 3 14 10 1 3 Southern Company total(c) $ (21 ) $ 33 $ (61 ) $ 7 Southern Company Gas Level 1(a) $ (53 ) $ (19 ) $ (37 ) $ 3 Level 2(b) 111 98 11 2 Level 3 14 10 1 3
Southern Company Gas total(c) $ 72 $ 89 $ (25 )
$ 8
(a) Valued using NYMEX futures prices.
(b) Level 2 amounts for Southern Company Gas are valued using basis transactions
that represent the cost to transport natural gas from a NYMEX delivery point
to the contract delivery point. These transactions are based on quotes obtained either through electronic trading platforms or directly from brokers.
(c) Excludes cash collateral of $99 million as well as premium and associated
intrinsic value associated with weather derivatives of $4 million at
December 31, 2019.
The Registrants are exposed to risk in the event of nonperformance by counterparties to energy-related and interest rate derivative contracts, as applicable. The Registrants only enter into agreements and material transactions with counterparties that have
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COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Southern Company and Subsidiary Companies 2019 Annual Report
investment grade credit ratings by Moody's and S&P, or with counterparties who have posted collateral to cover potential credit exposure. Therefore, the Registrants do not anticipate market risk exposure from nonperformance by the counterparties. For additional information, see Note 1 to the financial statements under "Financial Instruments" and Note 14 to the financial statements. Southern Company performs periodic reviews of its leveraged lease transactions, both domestic and international, and the creditworthiness of the lessees, including a review of the value of the underlying leased assets and the credit ratings of the lessees. Southern Company's domestic lease transactions generally do not have any credit enhancement mechanisms; however, the lessees in its international lease transactions have pledged various deposits as additional security to secure the obligations. The lessees in Southern Company's international lease transactions are also required to provide additional collateral in the event of a credit downgrade below a certain level. See Notes 1 and 3 to the financial statements under "Leveraged Leases" and "Other Matters - Southern Company," respectively, for additional information. Southern Company Gas Value at Risk (VaR) VaR is the maximum potential loss in portfolio value over a specified time period that is not expected to be exceeded within a given degree of probability. Southern Company Gas' VaR may not be comparable to that of other companies due to differences in the factors used to calculate VaR. Southern Company Gas' VaR is determined on a 95% confidence interval and a one-day holding period, which means that 95% of the time, the risk of loss in a day from a portfolio of positions is expected to be less than or equal to the amount of VaR calculated. The open exposure of Southern Company Gas is managed in accordance with established policies that limit market risk and require daily reporting of potential financial exposure to senior management. Because Southern Company Gas generally manages physical gas assets and economically protects its positions by hedging in the futures markets, Southern Company Gas' open exposure is generally mitigated. Southern Company Gas employs daily risk testing, using both VaR and stress testing, to evaluate the risk of its positions. Southern Company Gas actively monitors open commodity positions and the resulting VaR and maintains a relatively small risk exposure as total buy volume is close to sell volume, with minimal open natural gas price risk. Based on a 95% confidence interval and employing a one-day holding period, SouthStar's portfolio of positions for all periods presented was immaterial. Southern Company Gas' wholesale gas services segment had the following VaRs at December 31: 2019 2018 2017 (in millions) Period end(*) $ 2.6 $ 6.4 $ 4.8 Average 3.4 3.7 2.0 High(*) 7.0 11.7 4.8 Low 2.1 1.2 1.0
(*) The increase in VaR at December 31, 2018 reflects significant natural gas
price increases in Sequent's key markets driven by an industry-wide
lower-than-normal natural gas storage inventory position and
colder-than-normal weather in the middle of fourth quarter 2018. As weather
and natural gas prices moderated subsequent to December 31, 2018, VaR
reduced.
Credit Risk Southern Company (except as discussed herein), the traditional electric operating companies, and Southern Power are not exposed to any concentrations of credit risk. Southern Company Gas' exposure to concentrations of credit risk is discussed herein. Southern Company Gas Gas Distribution Operations Concentration of credit risk occurs at Atlanta Gas Light for amounts billed for services and other costs to its customers, which consist of 16 Marketers in Georgia. The credit risk exposure to Marketers varies seasonally, with the lowest exposure in the non-peak summer months and the highest exposure in the peak winter months. Marketers are responsible for the retail sale of natural gas to end-use customers in Georgia. The provisions of Atlanta Gas Light's tariff allow Atlanta Gas Light to obtain credit security support in an amount equal to a minimum of two times a Marketer's highest month's estimated bill from Atlanta Gas Light. For 2019, the four largest Marketers based on customer count, which includes SouthStar, accounted for 21% of Southern Company Gas' adjusted operating margin and 27% of adjusted operating margin for Southern Company Gas' gas distribution operations segment. II-114 -------------------------------------------------------------------------------- Table of Contents Index to Financial Statements
COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Southern Company and Subsidiary Companies 2019 Annual Report
Several factors are designed to mitigate Southern Company Gas' risks from the increased concentration of credit that has resulted from deregulation. In addition to the security support described above, Atlanta Gas Light bills intrastate delivery service to Marketers in advance rather than in arrears. Atlanta Gas Light accepts credit support in the form of cash deposits, letters of credit/surety bonds from acceptable issuers, and corporate guarantees from investment-grade entities. Southern Company Gas reviews the adequacy of credit support coverage, credit rating profiles of credit support providers, and payment status of each Marketer. Southern Company Gas believes that adequate policies and procedures are in place to properly quantify, manage, and report on Atlanta Gas Light's credit risk exposure to Marketers. Atlanta Gas Light also faces potential credit risk in connection with assignments of interstate pipeline transportation and storage capacity to Marketers. Although Atlanta Gas Light assigns this capacity to Marketers, in the event that a Marketer fails to pay the interstate pipelines for the capacity, the interstate pipelines would likely seek repayment from Atlanta Gas Light. Wholesale Gas Services Southern Company Gas has established credit policies to determine and monitor the creditworthiness of counterparties, as well as the quality of pledged collateral. Southern Company Gas also utilizes netting agreements whenever possible to mitigate exposure to counterparty credit risk. When Southern Company Gas is engaged in more than one outstanding derivative transaction with the same counterparty and also has a legally enforceable netting agreement with that counterparty, the "net" mark-to-market exposure represents the netting of the positive and negative exposures with that counterparty and a reasonable measure of Southern Company Gas' credit risk. Southern Company Gas also uses other netting agreements with certain counterparties with whom it conducts significant transactions. Netting agreements enable Southern Company Gas to net certain assets and liabilities by counterparty. Southern Company Gas also nets across product lines and against cash collateral, provided the netting and cash collateral agreements include such provisions. Southern Company Gas may require counterparties to pledge additional collateral when deemed necessary. Southern Company Gas conducts credit evaluations and obtains appropriate internal approvals for a counterparty's line of credit before any transaction with the counterparty is executed. In most cases, the counterparty must have an investment grade rating, which includes a minimum long-term debt rating of Baa3 from Moody's and BBB- from S&P. Generally, Southern Company Gas requires credit enhancements by way of a guaranty, cash deposit, or letter of credit for transaction counterparties that do not have investment grade ratings. Certain of Southern Company Gas' derivative instruments contain credit-risk-related or other contingent features that could increase the payments for collateral it posts in the normal course of business when its financial instruments are in net liability positions. At December 31, 2019, for agreements with such features, Southern Company Gas' derivative instruments with liability fair values were immaterial and Southern Company Gas had no collateral posted with derivatives counterparties to satisfy these arrangements. Southern Company Gas has a concentration of credit risk as measured by its 30-day receivable exposure plus forward exposure. At December 31, 2019, the top 20 counterparties of Southern Company Gas' wholesale gas services segment represented approximately 59%, or $218 million, of its total counterparty exposure and had a weighted average S&P equivalent credit rating of A-, all of which is consistent with the prior year. The S&P equivalent credit rating is determined by a process of converting the lower of the S&P or Moody's ratings to an internal rating ranging from 9 to 1, with 9 being equivalent to AAA/Aaa by S&P and Moody's, respectively, and 1 being D / Default by S&P and Moody's, respectively. A counterparty that does not have an external rating is assigned an internal rating based on the strength of the financial ratios of that counterparty. To arrive at the weighted average credit rating, each counterparty is assigned an internal ratio, which is multiplied by their credit exposure and summed for all counterparties. The sum is divided by the aggregate total counterparties' exposures, and this numeric value is then converted to a S&P equivalent. II-115 -------------------------------------------------------------------------------- Table of Contents Index to Financial Statements
COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Southern Company and Subsidiary Companies 2019 Annual Report
The following table provides credit risk information related to Southern Company Gas' third-party natural gas contracts receivable and payable positions at December 31: Gross Receivables Gross Payables 2019 2018 2019 2018 (in millions) (in millions) Netting agreements in place: Counterparty is investment grade $ 238 $ 461 $ 127 $ 255 Counterparty is non-investment grade 1 5 43 95 Counterparty has no external rating 175 314 272
505
No netting agreements in place: Counterparty is investment grade 14 19 - 1 Counterparty has no external rating - 2 - - Amount recorded in balance sheets $ 428 $ 801 $ 442
$ 856
Gas Marketing Services Southern Company Gas obtains credit scores for its firm residential and small commercial customers using a national credit reporting agency, enrolling only those customers that meet or exceed Southern Company Gas' credit threshold. Southern Company Gas considers potential interruptible and large commercial customers based on reviews of publicly available financial statements and commercially available credit reports. Prior to entering into a physical transaction, Southern Company Gas also assigns physical wholesale counterparties an internal credit rating and credit limit based on the counterparties' Moody's, S&P, and Fitch ratings, commercially available credit reports, and audited financial statements. Capital Requirements Total estimated capital expenditures for the Registrants through 2024 based on their current construction programs are as follows: 2020 2021 2022 2023 2024 (in billions) Southern Company(a)(b)(c)(d) $ 8.7 $ 7.3 $ 6.8 $ 6.8 $ 6.2 Alabama Power(b) 2.1 1.8 1.8 1.8 1.6 Georgia Power(c) 4.1 3.4 3.0 2.8 2.7 Mississippi Power 0.3 0.2 0.2 0.3 0.2 Southern Power(d) 0.3 0.2 0.1 0.1 0.1 Southern Company Gas 1.8 1.6 1.6 1.7 1.6
(a) Includes the Subsidiary Registrants, as well the other subsidiaries.
(b) Includes amounts contingent upon approval by the Alabama PSC related to
Alabama Power's September 6, 2019 CCN filing totaling $0.5 billion for 2020,
$0.2 billion for 2021, $0.3 billion for 2022, and $0.1 billion for 2023. See
FUTURE EARNINGS POTENTIAL - "Regulatory Matters - Alabama Power - Petition
for Certificate of Convenience and Necessity" herein for additional
information.
(c) These amounts include expenditures of approximately $1.6 billion, $0.9
billion, and $0.3 billion for the construction of Plant Vogtle Units 3 and 4
in 2020, 2021, and 2022, respectively.
(d) These amounts do not include approximately $0.5 billion per year for 2020
through 2024 for Southern Power's planned expenditures for plant acquisitions
and placeholder growth, which may vary materially due to market opportunities
and Southern Power's ability to execute its growth strategy.
These amounts include estimated capital expenditures to comply with environmental laws and regulations, but do not include any potential compliance costs associated with pending regulation of CO2 emissions from fossil fuel-fired electric generating units. See FUTURE EARNINGS POTENTIAL - "Environmental Matters" herein for additional information. These amounts also include capital expenditures related to contractual purchase commitments for nuclear fuel (for Southern Company, Alabama Power, and Georgia Power) and capital expenditures covered under LTSAs. The traditional electric operating companies also anticipate costs associated with closure and monitoring of ash ponds and landfills in accordance with the CCR Rule and the related state rules, which are reflected in the applicable Registrants' ARO liabilities. Alabama Power's cost estimates are based on closure-in-place for all of its ash ponds. The cost estimates for Georgia II-116 -------------------------------------------------------------------------------- Table of Contents Index to Financial Statements
COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Southern Company and Subsidiary Companies 2019 Annual Report
Power and Mississippi Power are based on a combination of closure-in-place for some ash ponds and closure by removal for others. These anticipated costs are likely to change, and could change materially, as assumptions and details pertaining to closure are refined and compliance activities continue. See FUTURE EARNINGS POTENTIAL - "Environmental Matters - Environmental Laws and Regulations - Coal Combustion Residuals" herein and Note 6 to the financial statements for additional information. The current estimates of these costs through 2024 are as follows: 2020 2021 2022 2023 2024 (in millions)
Southern Company $ 498 $ 551 $ 742 $ 916 $ 967 Alabama Power 200 217 284 363 386 Georgia Power 265 289 391 475 530 Mississippi Power 23 29 24 23 20
The construction programs are subject to periodic review and revision, and actual construction costs may vary from these estimates because of numerous factors. These factors include: changes in business conditions; changes in load projections; changes in environmental laws and regulations; the outcome of any legal challenges to environmental rules; changes in electric generating plants, including unit retirements and replacements and adding or changing fuel sources at existing electric generating units, to meet regulatory requirements; changes in FERC rules and regulations; state regulatory agency approvals; changes in the expected environmental compliance program; changes in legislation; 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. In addition, there can be no assurance that costs related to capital expenditures will be fully recovered. Additionally, Southern Power's planned expenditures for plant acquisitions may vary due to market opportunities and Southern Power's ability to execute its growth strategy. See Note 15 to the financial statements under "Southern Power" for additional information regarding Southern Power's plant acquisitions and construction projects. The construction program of Georgia Power also 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 under "Georgia Power - Nuclear Construction" for information regarding Plant Vogtle Units 3 and 4 and additional factors that may impact construction expenditures. See FUTURE EARNINGS POTENTIAL - "Construction Programs" herein for additional information. Also see "Contractual Obligations" herein for information regarding other future funding requirements of the Registrants. II-117 -------------------------------------------------------------------------------- Table of Contents Index to Financial Statements
COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Southern Company and Subsidiary Companies 2019 Annual Report
Contractual Obligations The following tables present the Registrants' contractual obligations at December 31, 2019. Additional information about these funding requirements is provided herein. Southern Company 2020 2021-2022 2023-2024 After 2024 Total (in millions) Long-term debt - Principal $ 2,971 $ 5,189 $ 2,890 $ 33,489 $ 44,539 Interest 1,677 3,109 2,809 25,986 33,581 Financial derivative obligations 450 204 65 - 719 Operating leases 294 543 386 1,609 2,832 Finance leases 31 47 33 246 357 Pipeline charges, storage capacity, and gas supply 725 1,085 784 1,677 4,271 Purchase commitments - Capital 7,758 12,981 11,989 32,728 Fuel 2,787 3,491 1,527 4,546 12,351 Purchased power 150 270 237 1,725 2,382 Other 406 618 530 2,174 3,728 ARO settlements 498 1,293 1,883 3,674 Other(*) 163 310 38 65 576 Southern Company system total $ 17,910 $ 29,140 $ 23,171 $ 71,517 $ 141,738
(*) Includes funding requirements related to pension and other postretirement
benefit plans, nuclear decommissioning trusts of Georgia Power, and preferred
stock dividends of Alabama Power.
Alabama Power 2020 2021-2022 2023-2024 After 2024 Total (in millions) Long-term debt - Principal $ 250 $ 1,060 $ 321 $ 6,956 $ 8,587 Interest 338 649 578 4,985 6,550 Preferred stock dividends 15 29 29 - 73 Financial derivative obligations 14 10 - - 24 Operating leases 54 105 5 1 165 Finance leases 1 2 1 - 4 Purchase commitments - Capital 1,502 2,891 2,927 7,320 Fuel 959 1,226 465 808 3,458 Purchased power 35 75 77 446 633 Other 39 81 62 243 425 ARO settlements 200 501 749 1,450 Pension and other postretirement benefit plans 14 28 42 Alabama Power total $ 3,421 $ 6,657 $ 5,214 $ 13,439 $ 28,731 II-118
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Georgia Power 2020 2021-2022 2023-2024 After 2024 Total (in millions) Long-term debt - Principal $ 1,014 $ 906 $ 628 $ 9,236 $ 11,784 Interest 384 715 668 5,070 6,837 Financial derivative obligations 49 21 - - 70 Operating leases 205 395 359 831 1,790 Finance leases 28 49 50 134 261 Purchase commitments - Capital 3,805 6,080 4,966 14,851 Fuel 1,091 1,401 629 3,610 6,731 Purchased power 56 117 123 862 1,158 Other 117 121 133 205 576 ARO settlements 265 680 1,006 1,951 Nuclear decommissioning trust 5 9 9 65 88 Pension and other postretirement benefit plans 50 93 143 Georgia Power total $ 7,069 $ 10,587 $ 8,571 $ 20,013 $ 46,240 Mississippi Power 2020 2021-2022 2023-2024 After 2024 Total (in millions) Long-term debt - Principal $ 282 $ 270 $ - $ 1,026 $ 1,578 Interest 68 102 83 542 795 Financial derivative obligations 15 11 1 - 27 Operating leases 2 2 1 2 7 Purchase commitments - Capital 255 397 402 1,054 Fuel 313 312 169 108 902 Purchased power 17 36 37 417 507 Other 28 58 69 230 385 ARO settlements 23 53 44 120 Pension and other postretirement benefits plans 7 14 21 Mississippi Power total $ 1,010 $ 1,255 $ 806 $ 2,325 $ 5,396 Southern Power 2020 2021-2022 2023-2024 After 2024 Total (in millions) Long-term debt - Principal $ 825 $ 977 $ 290 $ 2,339 $ 4,431 Interest 163 278 222 1,302 1,965 Financial derivative obligations 3 - - - 3 Operating leases 29 50 52 888 1,019 Purchase commitments - Capital 251 306 294 851 Fuel 424 552 265 20 1,261 Purchased power 42 42 - - 84 Other 159 296 239 1,481 2,175 Southern Power total $ 1,896 $ 2,501 $ 1,362 $ 6,030 $ 11,789 II-119
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Southern Company Gas 2020 2021-2022 2023-2024 After 2024 Total (in millions) Long-term debt - Principal $ - $ 376 $ 400 $ 4,659 $ 5,435 Interest 235 458 425 3,213 4,331 Financial derivative obligations 369 161 66 - 596 Operating leases 18 31 21 44 114 Pipeline charges, storage capacity, and gas supply 725 1,085 784 1,677 4,271 Purchase commitments - Capital 1,775 3,191 3,335 8,301 Other 31 14 1 - 46 Pension and other postretirement benefit plans 16 29 45 Southern Company Gas total $ 3,169 $ 5,345 $ 5,032 $ 9,593 $ 23,139
Additional information about these funding requirements is provided below: • Long-term debt - Represents scheduled maturities of long-term debt, as well
as the related interest. All amounts are reflected based on final maturity
dates except for amounts related to Georgia Power's FFB borrowings. The final
maturity date for Georgia Power's FFB borrowings is February 20, 2044;
however, principal amortization is reflected beginning in February 2020. The
interest amounts also include the effects of interest rate derivatives
employed to manage interest rate risk and effects of foreign currency swaps
employed to manage foreign currency exchange rate risk, as applicable. For
Southern Company and Southern Power, debt principal includes a $5 million
loss related to Southern Power's foreign currency hedge of €1.1 billion. The
Registrants plan to continue, when economically feasible, to retire
higher-cost securities and replace these obligations with lower-cost capital
if market conditions permit. Variable rate interest obligations are estimated
based on rates at December 31, 2019, as reflected in the statements of
capitalization for each Registrant. Long-term debt excludes finance lease
amounts, which are shown separately. See Note 8 to the financial statements
for additional information.
• Financial derivative obligations - See Note 14 to the financial statements
for additional information.
• Operating and finance leases - See Note 9 to the financial statements for
additional information. Operating lease commitments may include certain land
leases for facilities that may be subject to annual price escalation based on
indices. Estimated lease payments for Southern Company and Alabama Power
exclude amounts contingent upon approval by the Alabama PSC related to
Alabama Power's September 6, 2019 CCN filing totaling $1 million for 2021, $2
million for 2022, $3 million for 2023, $4 million for 2024, and $85 million
for after 2024. See Note 2 to the financial statements under "Alabama Power -
Petition for Certificate of Convenience and Necessity" for additional
information.
• Purchase commitments - Capital - Estimated capital expenditures are provided
for a five-year period, including capital expenditures associated with
environmental regulations. These amounts exclude contractual purchase
commitments for nuclear fuel, capital expenditures covered under LTSAs, and
estimated capital expenditures for AROs, which are reflected in the "fuel,"
"other," and "ARO settlements" categories, respectively, where applicable.
Estimated capital expenditures for Southern Company and Alabama Power exclude
amounts contingent upon approval by the Alabama PSC related to Alabama
Power's September 6, 2019 CCN filing totaling $0.5 billion for 2020, $0.2
billion for 2021, $0.3 billion for 2022, and $0.1 billion for 2023. See Note
2 to the financial statements under "Alabama Power - Petition for Certificate
of Convenience and Necessity" for additional information. Estimated capital
expenditures for Southern Company and Southern Power exclude approximately
$0.5 billion per year for 2020 through 2024 for Southern Power's planned
expenditures for plant acquisitions and placeholder growth. At December 31,
2019, significant purchase commitments were outstanding in connection with
the Registrants' construction programs. See FUTURE EARNINGS POTENTIAL - "Environmental Matters" and "Construction Programs" herein and "Capital Requirements" herein for additional information.
• Purchase commitments - Fuel - Primarily includes commitments to purchase coal
(for the traditional electric operating companies), natural gas (for the
traditional electric operating companies and Southern Power), and nuclear
fuel (for Alabama Power and Georgia Power), as well as the related
transportation and storage. In most cases, these contracts contain provisions
for price escalation, minimum purchase levels, and other financial
commitments. Natural gas purchase commitments are based on various indices at
the time of delivery. Amounts reflected for natural gas purchase commitments
have been estimated based on the NYMEX future prices at December 31, 2019.
• Purchase commitments - Purchased power - Represents estimated minimum
obligations for various PPAs for the purchase of capacity and energy, as well
as, for Georgia Power, capacity payments related to Plant Vogtle Units 1 and
2. Amounts exclude PPAs accounted for as leases, which are reflected in the
"operating leases" and "finance leases" categories, where applicable. II-120
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Estimated capacity payments for Southern Company and Alabama Power exclude amounts contingent upon approval by the Alabama PSC related to Alabama Power's September 6, 2019 CCN filing totaling $4 million for 2020, $7 million for 2021, $7 million for 2022, $8 million for 2023, $8 million for 2024, and $107 million for after 2024. See Note 2 to the financial statements under "Alabama Power - Petition for Certificate of Convenience and Necessity" for additional information. Mississippi Power's long-term PPAs are associated with solar facilities and only include an energy component. Southern Power's purchased power commitments will be resold under a third-party agreement at cost. See Note 3 to the financial statements under "Guarantees" for additional information. • Purchase commitments - Other - Includes LTSAs (for all Registrants),
contracts for the procurement of limestone (for Alabama Power and Georgia
Power), contractual environmental remediation liabilities (for Southern
Company Gas), operation and maintenance agreements (for Southern Power), and
transmission agreements (for Southern Power). LTSAs include price escalation
based on inflation indices. Southern Power's transmission commitments are
based on the Southern Company system's current tariff rate for point-to-point
transmission.
• Pension and other postretirement benefit plans - The Southern Company system
provides postretirement benefits to the majority of its employees and funds
trusts to the extent required by PSCs, other applicable state regulatory
agencies, or the FERC. The Registrants forecast contributions to their
pension and other postretirement benefit plans over a three-year period. The
Registrants anticipate no mandatory contributions to the qualified pension
plan during the next three years. Amounts presented represent estimated
benefit payments for the nonqualified pension plans, estimated non-trust
benefit payments for the other postretirement benefit plans, and estimated
contributions to the other postretirement benefit plan trusts, all of which
will be made from corporate assets of the applicable subsidiaries. See Note
11 to the financial statements for additional information related to the
pension and other postretirement benefit plans, including estimated benefit
payments. Certain benefit payments will be made through the related benefit
plans. Other benefit payments will be made from corporate assets of the
applicable subsidiaries.
• ARO settlements - Represents estimated costs for a five-year period
associated with closing and monitoring ash ponds at the traditional electric
operating companies in accordance with the CCR Rule and the related state
rules, which are reflected in the applicable Registrants' ARO liabilities.
Material expenditures in future years for ARO settlements also will be
required for ash ponds, nuclear decommissioning (for Alabama Power and
Georgia Power), and other liabilities reflected in the applicable
Registrants' AROs. See Note 6 to the financial statements for additional
information.
• Preferred stock dividends - Represents preferred stock of Alabama Power.
Preferred stock does not mature; therefore, amounts are provided for the next
five years only.
• Nuclear decommissioning trusts - As a result of NRC requirements, Alabama
Power and Georgia Power have external trust funds for nuclear decommissioning
costs. Based on its most recent site study completed in 2018, Alabama Power
currently has no additional funding requirements. Alabama Power's next site
study is expected to be conducted by 2023. Georgia Power's projections of
nuclear decommissioning trust fund contributions for Plant Hatch and Plant
Vogtle Units 1 and 2 are based on the 2019 ARP. See Note 6 to the financial
statements under "Nuclear Decommissioning" for additional information.
• Pipeline charges, storage capacity, and gas supply - Includes charges at
Southern Company Gas recoverable through a natural gas cost recovery
mechanism, or alternatively billed to Marketers selling retail natural gas,
and demand charges associated with Sequent. The gas supply balance includes
amounts for Nicor Gas and SouthStar gas commodity purchase commitments of 45
million mmBtu at floating gas prices calculated using forward natural gas
prices at December 31, 2019 and valued at $84 million. Southern Company Gas
provides guarantees to certain gas suppliers for certain of its subsidiaries,
including SouthStar, in support of payment obligations. II-121
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