Xcel Energy Inc. — 2017 Form 10-K Summary
Business context and reporting period
Annual report for the year ended December 31, 2017, filed February 23, 2018. Xcel Energy is a regulated utility holding company operating through four utilities across eight states, providing electric service and, through three utilities, natural gas service. The filing includes annual results; fourth-quarter figures are identified separately where relevant.
Financial and operating metrics
| Metric | 2017 | 2016 |
|---|---|---|
| Operating revenue | $11.404 billion | $11.107 billion |
| Operating income | $2.190 billion | $2.214 billion |
| Net income | $1.148 billion | $1.123 billion |
| GAAP diluted EPS | $2.25 | $2.21 |
| Ongoing diluted EPS (non-GAAP) | $2.30 | $2.21 |
| Operating cash flow | $3.126 billion | $3.052 billion |
| Utility capital/construction expenditures | $3.319 billion | $3.256 billion |
| Long-term debt | $14.520 billion | $14.195 billion |
| Short-term debt | $814 million | $392 million |
- Electric margin increased to $5.919 billion from $5.782 billion; natural gas margin rose to $827 million from $798 million.
- Operating cash flow less utility capital expenditures was approximately negative $193 million. Cash and cash equivalents were $83 million at year-end.
- As of February 20, 2018, committed credit facilities and cash provided $2.242 billion of reported liquidity, including $2.237 billion of available facilities.
- Total assets were $43.030 billion and common equity was $11.455 billion at year-end. Declared dividends were $1.44 per share for 2017, versus $1.36 in 2016.
Material changes versus the prior comparable period
- Revenue rose 2.7% and net income rose 2.2%; GAAP diluted EPS increased from $2.21 to $2.25. Ongoing diluted EPS increased 4.1% to $2.30.
- Management attributed improved ongoing earnings chiefly to higher electric and natural gas margins, lower operating and maintenance expense, a lower effective tax rate and higher allowance for funds used during construction. Higher depreciation, interest and property taxes partly offset these benefits.
- Depreciation and amortization increased $176 million, or 13.5%, to $1.479 billion, mainly reflecting capital investment and prior-year Minnesota reserve amortization. Interest charges increased $16 million.
- Operating cash flow increased $74 million. Investing cash outflow rose to $3.296 billion, largely due to capital spending on the Rush Creek wind project.
- Retail electric sales declined 0.7% overall; weather-normalized sales, adjusted for leap day, grew 0.1%. Natural gas revenue increased to $1.650 billion, with natural gas margin up $29 million.
Outlook, management commentary, risks and unusual items
- 2018 GAAP and ongoing EPS guidance is $2.37–$2.47. Assumptions include constructive regulatory outcomes, normal weather, flat O&M, and 0%–0.5% weather-normalized electric sales growth; firm natural gas sales are projected 0%–0.5% lower.
- Long-term objectives are annual EPS growth of 5%–6% from the 2017 ongoing EPS base of $2.30, dividend increases of 5%–7%, and a 60%–70% ongoing EPS payout ratio. The company targets A-range secured and BBB+ to A-range unsecured ratings.
- Following the Tax Cuts and Jobs Act (TCJA), Xcel recorded an estimated one-time, non-cash $23 million tax expense in 2017, excluded from ongoing earnings. Management estimates the law will reduce annual revenue requirements by approximately $400 million; rate treatment is subject to regulatory proceedings. The company cited potential pressure on cash flow and credit metrics and reduced its 2018–2022 capital forecast by $500 million for potential tax-reform effects.
- Base capital expenditures are forecast at $18.5 billion for 2018–2022. This excludes the proposed Colorado Energy Plan, which could add up to $1.5 billion of investment if approved. Planned wind additions and coal-unit retirements are subject to approvals, project execution and regulatory cost recovery.
- Key risks include regulatory decisions on rates and cost recovery, weather and modest underlying load growth, rising capital and financing needs, environmental requirements, fuel and supply interruptions, cybersecurity, nuclear operations and unresolved spent-fuel disposal. The Tolk generating station also faces water-supply constraints and potential environmental-control costs.
- Notable contingencies include litigation challenging Minnesota and Texas transmission right-of-first-refusal rules; pending regulatory proceedings and appeals; and environmental remediation. The Ashland MGP site had an estimated total cost of $168 million, with $30 million accrued at year-end; the Fargo MGP site had an estimated cost of $23 million, with $16 million accrued.
- Management reported that Prairie Island and Monticello had NRC Column 1 status with green indicators and no findings or violations above green at year-end. The permanent federal spent-fuel disposal site remains unresolved. The independent auditor issued an unqualified opinion on the financial statements and internal controls.
Important facts for investors to verify
- Track commission decisions on TCJA-related customer refunds, rate cases, authorized returns and proposed capital recovery; these affect the $2.37–$2.47 2018 EPS outlook.
- Compare actual spending, financing and project approvals with the $18.5 billion five-year capital plan, including whether the Colorado Energy Plan is approved.
- Monitor debt growth, liquidity, credit ratings and financing plans, alongside the company’s dividend and payout objectives.
- Review the assumptions and regulatory recoverability supporting pension, nuclear decommissioning, environmental remediation and other recorded regulatory balances.
- Assess whether weather-normalized demand, customer usage and cost-control performance support management’s earnings and bill-affordability targets.