Xcel Energy Inc. — First-Quarter 2021 Form 10-Q
Business context and period. Xcel Energy is a regulated electric and natural gas utility operating through subsidiaries across multiple U.S. states. This summary covers the three months ended March 31, 2021, compared with the same period in 2020. The company cautions that seasonal interim results are not an appropriate basis for projecting full-year results.
Financial results and position
| Metric | Q1 2021 | Q1 2020 / prior date |
|---|---|---|
| Operating revenue | $3.541 billion | $2.811 billion |
| Operating income | $507 million | $455 million |
| Net income | $362 million | $295 million |
| Diluted EPS | $0.67 | $0.56 |
| Electric margin | $1.484 billion | $1.406 billion |
| Natural gas margin | $348 million | $298 million |
| Cash from operating activities | $(136) million | $669 million |
| Capital/construction expenditures | $1.024 billion | $1.607 billion |
| Cash and cash equivalents | $1.039 billion | $129 million at Dec. 31, 2020 |
| Long-term debt, including current portion | $21.491 billion | $20.066 billion at Dec. 31, 2020 |
Revenue rose 26%, net income 23%, and diluted EPS 20% year over year. Electric margin increased $78 million, mainly from non-fuel riders, regulatory rate outcomes and proprietary commodity trading, partly offset by customer credits for production tax credits (PTCs) and lower sales and demand. Natural gas margin rose $50 million, primarily from Colorado rate outcomes.
Operating cash flow declined by $805 million year over year, primarily because Winter Storm Uri costs were deferred as regulatory assets. Financing provided $2.081 billion, including $893 million of net short-term borrowings and $1.821 billion of long-term debt issuance, partly offset by $400 million of long-term debt repayments. At March 31, short-term debt was $1.477 billion; committed revolving facilities had $2.803 billion available. The company also had a fully drawn $1.2 billion term loan. The filing reports a 65% maximum funded-debt-to-capitalization covenant for that loan but does not provide the actual covenant ratio here.
Changes and management commentary
- Earnings increased $0.11 per share. Higher electric and natural gas margins and a lower effective tax rate contributed; increased depreciation, lower allowance for funds used during construction (AFUDC), and higher interest charges partly offset the gains.
- Revenue growth includes substantial fuel and purchased-energy activity, much of which is recovered through regulatory mechanisms; revenue growth therefore should not be read as equivalent to margin growth.
- Retail electric sales were down 2.4% year over year; weather-normalized sales were down 3.0%. Management attributed lower commercial and industrial sales primarily to COVID-19 effects, while residential sales increased.
- Depreciation and amortization increased $58 million, or 12.5%, largely due to wind farms entering service and new depreciation rates. Operating and maintenance expense increased $5 million.
Outlook, risks and unusual items
- 2021 guidance: GAAP and ongoing EPS of $2.90–$3.00. Assumptions include constructive regulatory outcomes, modest COVID-19 impacts, normal weather for the remainder of the year, approximately 1% weather-normalized retail electric sales growth, relatively flat firm natural gas sales, and relatively flat O&M expense. Long-term objectives are 5%–7% annual EPS growth and dividend increases, with a 60%–70% payout ratio.
- Winter Storm Uri: The company reported approximately $965 million of net natural gas, fuel and purchased-energy costs after about $190 million of mitigating market settlements; most costs were deferred as regulatory assets. Recovery proceedings were underway or planned in affected jurisdictions, generally proposing recovery over up to 24 months without financing charges. Final recoverability and timing remain subject to regulatory review. The storm also drove a temporary trading VaR spike to $52 million on Feb. 17; VaR returned to $1 million by Feb. 19.
- Regulatory and capital plans: Rate cases were pending in New Mexico and Texas. The company also described major proposed transmission and generation investments, including Colorado’s Power Pathway project and resource plans involving coal retirements, renewable generation and storage. Approvals and cost recovery are not assured.
- Contingencies: Potential exposures include a pending MPUC review of roughly $17 million in Sherco replacement-power costs, a Westmoreland arbitration seeking approximately $36 million (with damages not currently estimable), and a dispute concerning SPS’s Lubbock contract whose potential damages are unknown. PSCo reported coal-ash groundwater findings at four locations and was evaluating corrective actions at two; it had not met the April 2021 deadline for an alternative Comanche ash-pond system and was discussing next steps with EPA.
- Other risks: COVID-19 effects on customer sales and collections, regulatory cost recovery, commodity and counterparty risks, weather, environmental requirements, nuclear fuel supply, and financing conditions. Management reported no material change in previously disclosed risk factors and stated disclosure controls were effective.
Key facts for investors to verify
- Whether regulators approve recovery of Uri-related costs, and the resulting timing, customer-bill effects and cash-flow impact.
- Progress and outcomes in the New Mexico and Texas rate cases and other material rate, rider and resource-plan proceedings.
- Debt and liquidity needs relative to the capital program, including the term-loan maturity, covenant compliance and planned financing.
- Whether 2021 guidance assumptions remain achievable, particularly regulatory outcomes, weather, sales, depreciation and interest expense.
- Developments in the Sherco, Westmoreland and Lubbock matters and in coal-ash corrective actions and compliance.