Southern Company (SO) — Q3 2020 Form 10-Q
Reporting period: Three and nine months ended September 30, 2020; filed October 28, 2020. Unaudited combined filing covering Southern Company and five subsidiaries. Dollar amounts are in millions unless noted.
Financial results
| Metric | Q3 2020 | Q3 2019 | 9M 2020 | 9M 2019 |
|---|---|---|---|---|
| Operating revenues | $5,620 | $5,995 | $15,258 | $16,505 |
| Operating income | $1,835 | $2,013 | $4,156 | $7,046 |
| Net income attributable to Southern Company | $1,251 | $1,316 | $2,732 | $4,298 |
| Diluted EPS | $1.18 | $1.25 | $2.57 | $4.09 |
| Operating margin (operating income/revenue) | 32.7% | 33.6% | 27.2% | 42.7% |
Quarterly revenue fell 6.3% and attributable net income fell 4.9%. Nine-month revenue declined 7.6%; attributable net income declined 36.4%, chiefly because 2019 included a $2.5 billion pretax gain on the Gulf Power sale. 2020 results also included a $149 million pretax Vogtle construction charge and a $154 million pretax leveraged-lease impairment. Lower fuel costs largely flow through customer recovery mechanisms and generally do not materially affect earnings.
Cash flow, debt and liquidity
- Nine-month operating cash flow: $5,220, up from $4,881 in 2019. Property additions were $5,365, implying approximately $145 million of negative operating cash flow less property additions, before other investing activity.
- Cash: $3,379 at September 30, versus $1,975 at December 31, 2019. Net investing cash outflow was $4,892; financing provided $1,077. Common dividends paid were $2,008.
- Debt: Long-term debt was $45,581 and securities due within one year were $4,378; notes payable were $171. Combined debt and notes payable were approximately $50.1 billion, versus approximately $46.8 billion at year-end 2019.
- Working capital and credit: Current liabilities exceeded current assets by $1,176. The registrants reported $7,671 of unused committed bank credit in aggregate; facilities support commercial paper and certain revenue bonds. Management said liquidity and capital-market access remained adequate and credit covenants were met.
Material changes and business developments
- Retail electric revenue declined 6.0% in Q3 and 5.7% year to date. Management attributed the decline to milder weather, lower fuel-cost recovery, and COVID-19-related reductions in commercial and industrial usage. Weather-adjusted residential sales rose, while commercial and industrial sales fell.
- Georgia Power’s nine-month net income declined to $1,411 from $1,598, including the Vogtle charge and higher depreciation and amortization. Alabama Power’s nine-month net income after preferred dividends increased to $1,022 from $982; Mississippi Power’s was broadly flat at $138 versus $139.
- Southern Power’s attributable income fell to $212 from $316 for nine months, reflecting the absence of the 2019 Nacogdoches gain and lower earnings following asset sales. Southern Company Gas earned $360 versus $347; stronger distribution results were partly offset by weaker wholesale gas services.
- Alabama Power acquired the approximately 885-MW Autauga combined-cycle facility for $461. Southern Power sold Plant Mankato for approximately $663 million, recognizing a $39 million pretax gain; Southern Company Gas sold interests in Pivotal LNG and Atlantic Coast Pipeline for $178 million in aggregate proceeds.
Outlook, risks and contingencies
- Vogtle Units 3 and 4: Georgia Power continued to expect regulatory-approved in-service dates of November 2021 and November 2022. Its proportionate project capital-cost forecast was $8.5 billion, with $6.9 billion net invested and $1.6 billion estimated to complete; financing costs are additional. The forecast includes estimated COVID-related costs of $70 million to $115 million. Construction productivity, labor availability, subcontractors, testing and licensing remain risks; a schedule extension was estimated to add about $50 million monthly in base capital costs and $10 million monthly in AFUDC. Further unrecoverable cost increases could be charged to earnings.
- Environmental obligations: Alabama Power and Georgia Power increased asset retirement obligations by approximately $462 million and $411 million, respectively, for coal-ash pond closure estimates. Estimates and regulated recovery remain subject to refinement and regulatory approval; unrecovered costs could materially affect results, cash flows and financial condition.
- COVID-19 and demand: Management expected recovery in electric sales to continue through the rest of 2020 and into 2021, but said its pace and ultimate effects were uncertain. The pandemic could affect customer demand, collections, construction productivity, supply chains and access to financing. Certain pandemic-related costs were deferred as regulatory assets, with recovery timing or approval unresolved in some jurisdictions.
- Regulatory outlook: Georgia Power filed proposed tariff changes for 2021, including an approximately $120 million increase in traditional base tariffs, subject to approval. Alabama Power was authorized to construct a 720-MW Plant Barry unit, acquire Autauga, purchase 240 MW under a long-term PPA and pursue demand-side programs. Mississippi Power’s 2020 rate settlement reduced annual retail rates by approximately $16.7 million.
- Other exposures: PennEast Pipeline faces legal and permitting uncertainty; Southern Company Gas estimated its project costs at approximately $300 million, excluding financing. The Department of Justice is investigating $387 million of DOE grants related to Kemper; the filing says the outcome could materially affect Southern Company and Mississippi Power. A separate Mississippi Power lawsuit over Kemper-related customer refunds also remained pending and could be material. The Martin arbitration ended in Mississippi Power’s favor in October 2020. The leveraged-lease investment was fully impaired in Q2; the lessee’s future payment capacity remains a concern.
Important facts for investors to verify
- Whether Vogtle meets the November 2021 and November 2022 dates, stays within the $8.5 billion forecast, and obtains recovery of future costs.
- Updated coal-ash closure estimates, regulatory approvals and customer-rate recovery for the increased AROs.
- COVID-19 effects on commercial and industrial demand, customer collections, bad debt and deferred-cost recovery.
- Progress and potential financial exposure relating to PennEast, the DOE grant investigation and remaining Kemper-related litigation.
- Debt maturities, refinancing needs, available credit and cash generation relative to capital spending and dividends.