Xcel Energy Inc. — Form 10-Q Summary
Business context and reporting period. Xcel Energy is a regulated electric and natural gas utility holding company operating through subsidiaries in the Upper Midwest, Colorado, Texas and New Mexico. This unaudited filing covers the three and nine months ended Sept. 30, 2016; comparisons are with the corresponding 2015 periods. Management cautions that seasonal interim results are not necessarily indicative of full-year performance.
Financial performance and liquidity
- Third quarter: Operating revenue was $3.040 billion, up 4.8%; operating income was $827 million, up 5.2%; net income was $458 million, up 7.3%; and diluted EPS was $0.90 versus $0.84. Electric margin rose to $1.763 billion from $1.652 billion, while natural gas margin increased to $154 million from $150 million.
- Nine months: Operating revenue was $8.312 billion, down 0.8%; operating income was $1.749 billion, up 12.1%; net income was $896 million, up 15.5%; and diluted EPS was $1.76 versus $1.53. 2015 GAAP results included a $129 million pre-tax Monticello project charge; excluding that item, ongoing EPS was $1.69 in 2015 versus $1.76 in 2016.
- Margins and costs: Nine-month electric margin increased to $4.454 billion from $4.236 billion, and natural gas margin increased to $577 million from $551 million. Rate increases, riders and sales growth helped; higher depreciation and amortization, O&M and interest costs partly offset gains. Nine-month depreciation and amortization rose 17.3% to $971 million; interest charges rose 9.9% to $465 million.
- Cash flow: Nine-month operating cash flow was $2.413 billion, down from $2.490 billion. Utility capital/construction expenditures were $2.186 billion; net cash used in investing was $2.206 billion. Financing provided $62 million, versus $26 million used in 2015. Cash ended the period at $353 million, compared with $85 million at year-end 2015.
- Debt and liquidity: At Sept. 30, long-term debt was $13.403 billion, current long-term debt $710 million and short-term debt $366 million. Committed credit facilities totaled $2.750 billion, with $2.365 billion available; commercial paper outstanding was $366 million. Current assets were $3.076 billion and current liabilities $3.454 billion.
- Shareholder returns: Dividends declared were $0.34 per share in the quarter and $1.02 for the nine months, compared with $0.32 and $0.96, respectively, in 2015.
Material changes versus the prior comparable period
- Quarterly and year-to-date earnings improved, led by higher electric margins; nine-month revenue nevertheless declined, largely reflecting lower natural gas cost-recovery revenues.
- Management attributed higher electric margin to rate increases, transmission revenue, non-fuel riders, sales growth and conservation incentives. Nine-month retail electric sales were up 0.6% actual and 0.2% weather-normalized; weather-normalized firm natural gas sales were approximately flat.
- Capital investment and the reduction of excess depreciation reserves in Minnesota contributed to materially higher depreciation expense. Higher debt levels to fund investment increased interest expense.
- The 2015 Monticello LCM/EPU charge did not recur in 2016. In 2015, regulators allowed return on $415 million of project costs but not on the remaining $333 million.
Guidance, outlook, risks and contingencies
- EPS guidance: Revised 2016 ongoing EPS guidance is $2.17–$2.22, versus prior guidance of $2.12–$2.27. 2017 ongoing EPS guidance is $2.25–$2.35. These are non-GAAP measures, and the company says it cannot quantitatively reconcile the guidance to GAAP EPS.
- Assumptions and long-term objectives: Guidance assumes constructive regulatory outcomes and normal weather. Management expects 2017 weather-normalized electric and gas sales growth of 0%–0.5%, capital-rider revenue growth of $65–$75 million over 2016, and flat O&M. Long-term objectives are 4%–6% annual EPS growth, 5%–7% annual dividend increases and a 60%–70% payout ratio.
- Investment and funding: Forecast capital expenditures for 2017–2021 total $18.385 billion. Management expects to fund them with $13.465 billion of cash from operations, net of dividends, and $4.920 billion of new debt, with no equity issuance planned for the capital program. The company also expected to issue about $800 million of senior notes in fourth-quarter 2016.
- Regulatory developments: NSP-Minnesota reached a multi-year electric-rate settlement with parties, including a 9.2% ROE and proposed revenue increases, subject to MPUC approval; a refund liability for 2016 interim rates was recorded. The MPUC verbally approved a modified Minnesota resource plan, with a written order expected late in 2016. Other important proceedings include SPS’s Texas rate case settlement in principle and FERC transmission ROE complaints.
- Environmental and other contingencies: The Ashland manufactured-gas-plant site liability was $84.6 million; remediation scope, timing and cost remain subject to change, although rate recovery has historically been authorized. The Fargo site liability was $12.2 million. SPS’s potential Tolk scrubber investment was estimated at about $600 million, subject to litigation and regulatory developments; management expects required costs or alternatives to be recoverable. Potential SPS charges under SPP transmission-upgrade rules were estimated at $12–$14 million and expected to be recoverable through regulatory mechanisms.
- Other risks: The filing identifies weather, regulatory outcomes, fuel and commodity prices, interest rates, environmental requirements, litigation, credit and cyber risks, and potential changes in customer load. SPS also faces possible revenue and cost impacts if Lubbock Power & Light transfers load to ERCOT. Management reported no material changes to previously disclosed risk factors.
- Tax matters: The IRS proposed adjustments that could result in $14 million of tax expense related to carryback claims; the matter was before IRS Appeals with outcome and timing uncertain. Total unrecognized tax benefits were $130.8 million, and the filing says they could decrease by up to approximately $58 million as audits and appeals progress.
Important facts for investors to verify
- Whether the Minnesota rate settlement receives MPUC approval and the final refund obligation for interim rates.
- Whether 2016 and 2017 ongoing EPS guidance assumptions, particularly regulatory outcomes, weather, sales and cost expectations, are achieved.
- How the $18.385 billion five-year capital program affects debt, financing needs and cash generation.
- Final costs, regulatory recovery and timing for environmental remediation and potential emissions-control requirements.
- Outcomes of the IRS Appeals process, MISO ROE complaints and other material rate and regulatory proceedings.
- Whether customer-load changes, including the potential LP&L transition, affect SPS revenue and remaining-customer costs.