Xcel Energy Inc. — Form 10-Q Summary
Business context and reporting period. Xcel Energy is a regulated electric and natural gas utility serving customers across the Midwest, Colorado, Texas and New Mexico. This unaudited filing covers the quarter and nine months ended September 30, 2023; balance-sheet comparisons are against December 31, 2022. Results are seasonal, so interim results may not indicate full-year performance.
Key financial metrics
| Metric | Q3 2023 | Q3 2022 | Nine months 2023 | Nine months 2022 |
|---|---|---|---|---|
| Operating revenue | $3.662 billion | $4.082 billion | $10.764 billion | $11.257 billion |
| Operating income | $915 million | $924 million | $1.906 billion | $1.903 billion |
| Net income | $656 million | $649 million | $1.362 billion | $1.357 billion |
| Diluted GAAP EPS | $1.19 | $1.18 | $2.47 | $2.48 |
| Diluted ongoing EPS (non-GAAP) | $1.23 | $1.18 | $2.52 | $2.48 |
| Operating cash flow | Not separately stated | Not separately stated | $4.353 billion | $3.167 billion |
| Capital/construction expenditures | Not separately stated | Not separately stated | $4.240 billion | $3.325 billion |
Margins and costs. Electric margin (electric revenue less fuel and purchased power) was $2.206 billion in Q3 versus $2.202 billion; year to date it was $5.423 billion versus $5.483 billion. Natural gas margin was $175 million versus $184 million in Q3 and $842 million versus $789 million year to date. Fuel and purchased-energy costs are generally recovered from customers through regulatory mechanisms. Calculated net margin was approximately 17.9% for Q3 2023 versus 15.9% in Q3 2022, and 12.7% year to date versus 12.1%.
Debt and liquidity. At September 30, long-term debt was $24.910 billion, with $1.051 billion current; no short-term debt was outstanding. Total debt including current maturities was $25.961 billion, compared with $23.964 billion at year-end 2022. Cash was $594 million. As of October 23, committed credit facilities had $3.296 billion available and cash liquidity totaled $3.352 billion. The company issued $2.631 billion of long-term debt during the first nine months and paid $814 million in dividends.
Material changes versus prior comparable periods
- Q3 revenue fell $420 million, principally reflecting lower electric and natural gas revenues; lower fuel and purchased-power costs substantially offset the revenue decline. Year-to-date revenue declined $493 million.
- Q3 GAAP net income increased $7 million, while nine-month net income increased $5 million. Q3 ongoing diluted EPS rose to $1.23 from $1.18; nine-month ongoing EPS was $2.52 versus $2.48.
- Q3 results included a $34 million pre-tax charge for Comanche Unit 3 litigation. Excluding the after-tax effect, ongoing earnings were $682 million for the quarter and $1.388 billion for the nine months.
- Nine-month operating cash flow increased $1.186 billion, largely due to collections of prior-year deferred energy costs and working-capital effects. Capital expenditures increased $915 million, reflecting continued system expansion.
- Interest charges rose $25 million in Q3 and $85 million year to date, primarily due to higher interest rates and increased debt. Year-to-date O&M expense increased $37 million, including higher bad-debt, inflation-related and generation-maintenance costs.
Guidance, outlook and management commentary
- 2023 ongoing EPS guidance: narrowed to $3.32–$3.37 per share from $3.30–$3.40. Assumptions include normal weather for the remainder of the year, weather-normalized electric sales growth of approximately 1%–2%, and constructive regulatory outcomes.
- 2024 ongoing EPS guidance: $3.50–$3.60 per share, assuming normal weather, electric sales growth of 2%–3%, and constructive regulatory outcomes. Management’s 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. Ongoing EPS is non-GAAP and is not quantitatively reconciled to GAAP guidance.
- Base capital expenditures are forecast at $34 billion for 2024–2028. The company expects to fund the plan with operating cash flow, debt and equity; potential renewable additions could require approximately $10 billion of additional investment.
- Management cited infrastructure-investment recovery, sales and demand, and lower Q3 O&M as contributors to ongoing earnings growth; higher depreciation and interest costs were offsets. Weather-normalized retail electric sales rose 1.1% year to date, while actual retail electric sales declined 0.2%.
- Key risks include the Marshall Fire litigation, cost recovery and regulatory outcomes, higher financing costs, supply-chain constraints, weather and commodity exposure, environmental requirements, and execution of major generation and transmission investments.
Risks, contingencies and unusual items
- Marshall Fire: PSCo disputes that its equipment caused the 2021 fire. The sheriff’s report identified a likely second ignition near PSCo lines but also said an underground coal fire could not be ruled out. As of October 24, 2023, PSCo knew of 14 complaints involving at least 675 plaintiffs. The company could not estimate a loss range; potential damages could exceed approximately $500 million of insurance coverage and materially affect financial results or condition.
- Comanche Unit 3: A jury awarded CORE $26 million for lost power damages on October 25, 2023. PSCo recorded $34 million, including estimated interest and other costs, in Q3 and intends to appeal.
- Regulatory matters: Outcomes remain pending in several rate and cost-recovery proceedings. Minnesota’s electric rate decision provides an approximately $316 million increase over 2022–2024; interim-rate refunds are scheduled to begin in Q1 2024. The Colorado and New Mexico rate proceedings concluded with approved increases, while a Texas rate case remained pending.
- Environmental and project exposure: Coal-ash corrective actions and other environmental requirements may add costs, generally expected by the company to be recoverable through rates. Proposed emissions and PFAS rules have uncertain impacts. Solar import tariffs and supply constraints could affect renewable project costs and timing.
- DOE awards announced after quarter-end include up to $925 million for the Heartland Hydrogen Hub, a $70 million grant for long-duration storage pilots, $100 million for wildfire and grid-resilience work, and a $464 million transmission grant shared with other utilities. These awards are subject to project development and, where applicable, negotiations or implementation.
Important facts for investors to verify
- Track the Marshall Fire investigations, litigation, potential liability and adequacy of insurance coverage.
- Confirm the final outcome and appeal status of the Comanche Unit 3 verdict and related costs.
- Assess whether 2023 and 2024 EPS guidance assumptions—especially regulatory outcomes, sales growth, weather and financing costs—remain achievable.
- Monitor capital spending, incremental renewable and transmission investment, and the planned mix and cost of debt and equity financing.
- Review subsequent rate-case decisions and the timing and customer-rate treatment of deferred fuel and other costs.
- Consider that higher operating cash flow benefited from working-capital and regulatory timing effects, while capital spending exceeded operating cash flow for the nine-month period.