Xcel Energy Inc. — Q3 2021 Form 10-Q
Reporting period: Quarter and nine months ended Sept. 30, 2021. Xcel Energy is a regulated electric and natural gas utility holding company. Results are seasonal; interim results are not necessarily indicative of full-year performance. Amounts below are in millions of dollars except per-share data.
Financial performance and liquidity
| Metric | Q3 2021 | Q3 2020 | Nine months 2021 | Nine months 2020 |
|---|---|---|---|---|
| Operating revenue | $3,467 | $3,182 | $10,076 | $8,579 |
| Operating income | $825 | $813 | $1,770 | $1,690 |
| Net income | $609 | $603 | $1,282 | $1,185 |
| Diluted EPS | $1.13 | $1.14 | $2.38 | $2.25 |
| Electric margin | $1,966 | $1,960 | $5,000 | $4,819 |
| Natural gas margin | $182 | $165 | $761 | $657 |
For the nine months, operating cash flow was $1,579, down from $2,174, primarily due to regulatory deferral of Winter Storm Uri costs. Capital and construction expenditures were $3,032; cash used in investing was $3,065. Financing provided $1,988, including $1,920 of long-term debt issuance and $1,163 of net short-term borrowing proceeds. Dividends paid were $698. Cash, cash equivalents and restricted cash ended at $631.
At Sept. 30, total assets were $57,517 and stockholders’ equity was $15,171. Long-term debt was $20,979, current long-term debt $621 and short-term debt $1,747. The company reported $2,534 of available revolving credit capacity at quarter-end; its Oct. 26 update reported $2,871 of total liquidity including cash. Short-term borrowings carried a 0.56% period-end weighted average rate.
Material changes versus prior period
- Nine-month revenue rose $1,497, while diluted EPS increased $0.13. Management attributed the earnings improvement principally to higher electric and natural gas margins and a lower effective tax rate; higher depreciation and lower AFUDC partly offset the gains.
- Nine-month electric margin increased $181 and natural gas margin increased $104. Electric margin benefited from non-fuel riders, regulatory rate outcomes and trading; natural gas margin growth primarily reflected Colorado regulatory outcomes.
- Nine-month operating expenses increased $1,417, including higher electric fuel and purchased power, gas costs, and depreciation. Fuel and gas costs are generally recovered through regulatory mechanisms.
- Operating cash flow declined $595, largely because of changes in net regulatory and other assets and liabilities, including Uri-related cost deferrals. Capital expenditures were lower than in 2020, but 2020 included the sale of Mankato Energy Center.
- Long-term debt, including current maturities, had a $24,657 estimated fair value versus a $21,600 carrying amount at Sept. 30.
Outlook, commentary, risks and unusual items
- Guidance: 2021 GAAP and ongoing EPS guidance was narrowed to $2.94–$2.98 from $2.90–$3.00. 2022 EPS guidance was $3.10–$3.20. Long-term objectives are annual EPS and dividend growth of 5%–7%, a 60%–70% dividend payout ratio, and senior secured debt ratings in the A range. Guidance assumes constructive regulatory outcomes and normal weather, among other factors.
- Winter Storm Uri: The company incurred about $985 million of incremental natural gas, fuel and purchased energy costs, largely deferred as regulatory assets. Recovery proceedings remained subject to regulatory review and possible disallowances. An October 2021 proposed Colorado settlement would recover $263 million of electric and $287 million of gas costs over 24 and 30 months, without carrying charges; it also includes customer refunds and foregone recovery of certain costs. The settlement awaited a commission decision, expected in Q1 2022, and the UCA had not signed it.
- Capital program: Forecast base capital expenditures for 2022–2026 totaled $26 billion. Additional investment may be required for renewable generation and transmission projects, subject to regulatory approval. Management expected to fund the base program with operating cash, debt and equity.
- Regulatory and legal exposure: Significant proceedings include rate cases and rider filings; disputed Uri cost recovery; MISO transmission ROE appeals; a Comanche Unit 3 lawsuit seeking unspecified damages; and a pending MPUC review of Sherco replacement-power costs. The filing states some potential losses cannot currently be estimated.
- Other risks: COVID-19 impacts, inflation and supply-chain constraints, fuel and energy prices, weather, regulatory cost recovery, environmental requirements, credit and counterparty exposure, and nuclear fuel supply. CCR groundwater assessments in Colorado could entail costs up to $35 million; the amount and ultimate impact remain uncertain.
- A $39 million pension settlement charge was recorded in Q3, with most of the charge not recognized in earnings due to regulatory effects. The company reported no material change in previously disclosed risk factors and said disclosure controls were effective.
Investor verification priorities
- Track final regulatory decisions on Uri cost recovery, including any disallowances, refund terms and customer recovery timing.
- Verify progress and authorized returns for major rate cases, riders and the $26 billion 2022–2026 capital plan; assess resulting financing needs and debt levels.
- Compare realized 2021 and 2022 earnings with guidance assumptions, especially regulatory outcomes, sales growth, weather, depreciation and interest expense.
- Monitor Comanche, Sherco and other legal or environmental proceedings for changes in exposure, recoverability or estimated loss.
- Assess liquidity and cash conversion alongside ongoing regulatory asset balances and short-term borrowing requirements.