XCEL ENERGY INC quarterly report, Q2 FY2016

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Xcel Energy Inc. — Q2 2016 Form 10-Q

Business context and reporting period

Xcel Energy is a regulated electric and natural gas utility holding company with operating subsidiaries serving parts of the Midwest, Colorado, Texas and New Mexico. This unaudited report covers the quarter and six months ended June 30, 2016; comparisons are with the same 2015 periods. Management cautions that seasonal interim results are not a reliable basis for projecting full-year results.

Financial performance and position

  • Q2 revenue: $2.500 billion, down 0.6% year over year. Electric revenue was $2.224 billion; natural gas revenue was $259 million.
  • Q2 earnings: Operating income was $432 million versus $423 million; net income was $197 million versus $197 million; diluted EPS was $0.39 in both periods. Operating margin was approximately 17.3% of revenue, versus 16.8%.
  • First-half revenue and earnings: Revenue was $5.272 billion, down 3.7%; operating income was $921 million versus $774 million; net income was $438 million versus $349 million; diluted EPS was $0.86 versus $0.69. First-half operating margin was approximately 17.5%, versus 14.1%.
  • Margins: Electric margin rose to $1.368 billion in Q2 from $1.308 billion and to $2.691 billion year to date from $2.583 billion. Natural gas margin increased to $169 million in Q2 from $157 million and to $423 million year to date from $401 million.
  • Cash flow: First-half operating cash flow was $1.413 billion, down from $1.509 billion. Utility capital/construction expenditures were $1.413 billion. Investing cash outflow was $1.443 billion; financing provided $23 million. Cash ended the period at $77 million.
  • Debt and liquidity: Long-term debt, including its current portion, was $13.815 billion; short-term debt was $447 million. Cash plus current assets totaled $2.704 billion against current liabilities of $3.506 billion. At June 30, committed credit facilities totaled $2.750 billion, with $2.275 billion available. The facilities were extended to June 2021.
  • Shareholder returns: Dividends declared were $0.34 per share for Q2 and $0.68 for the first half, up from $0.32 and $0.64, respectively.

Material changes versus prior periods

  • First-half EPS increased to $0.86 from $0.69, but the comparison includes a 2015 Monticello project charge of $0.16 per share. On management’s ongoing basis, first-half EPS was $0.86 versus $0.85; Q2 ongoing EPS was unchanged at $0.39.
  • Higher electric and natural gas margins supported results, reflecting rate increases, non-fuel riders and favorable Q2 weather. The first-half increase in electric margin was $108 million and in natural gas margin $22 million.
  • These gains were partly offset by higher depreciation and amortization (up $95 million year to date), interest charges (up $30 million) and non-income taxes (up $17 million).
  • Lower natural gas commodity costs and related recovery reduced reported revenue, while generally having limited effect on gas margin because of cost-recovery mechanisms.

Outlook, commentary and key risks

  • 2016 guidance: Ongoing EPS of $2.12–$2.27. Assumptions include normal weather, approximately 0.5% lower weather-normalized retail electric sales, relatively flat firm natural gas sales, O&M expense growth of 0%–1%, and an effective tax rate of 34%–36%. Guidance assumes constructive regulatory outcomes.
  • Long-term objectives: Annual EPS growth of 4%–6% from 2015 ongoing EPS of $2.10; annual dividend growth of 5%–7%; a 60%–70% payout ratio; and senior unsecured ratings in the BBB+ to A range.
  • Regulatory exposure: Minnesota’s multi-year electric rate case remained subject to approval and potential refunds of interim rates; the company reported a settlement in principle with parties, still requiring final documentation and MPUC approval. Rate cases and proceedings were also pending in Wisconsin, Texas, New Mexico and before FERC. A proposed FERC transmission ROE change could reduce NSP System annual transmission revenue, net of expense, by an estimated $8–$10 million.
  • Capital and resource plans: Proposed projects include PSCo’s approximately $1 billion, 600 MW Rush Creek wind project and a $500 million advanced-grid initiative, both subject to regulatory approval. Xcel’s resource plan proposes substantial wind and solar additions and retirement or replacement of coal generation.
  • Environmental and legal contingencies: The potential Tolk scrubber investment is approximately $600 million if required; SPS is challenging the relevant EPA rule and obtained a stay. NSP-Wisconsin recorded a $95 million liability for the Ashland site, where sediment cleanup scope and cost remain uncertain. A Pacific Northwest FERC refund claim is reasonably possible, but PSCo could not estimate a loss range and recorded no accrual.
  • Other uncertainties: IRS audit proceedings include a proposed $14 million tax adjustment; unrecognized tax benefits could decrease by up to approximately $58 million as audits and appeals progress. SPS estimates possible SPP transmission upgrade charges of $5–$10 million, which it expects to recover through regulatory mechanisms. Nuclear fuel deliveries are partly exposed to events in Ukraine and sanctions against Russia, though management expects near-term alternatives to protect supply.
  • Management identified weather, customer demand, financing costs and access to capital, regulatory decisions, environmental requirements, litigation, commodity and counterparty risks, cybersecurity, and nuclear operations among factors that could cause actual results to differ from expectations. It reported effective disclosure controls and no material change in internal control over financial reporting during the quarter.

Most important facts for investors to verify

  • Whether the Minnesota rate-case settlement received final documentation and MPUC approval, and the resulting rates and refund obligation.
  • Whether Xcel achieved its $2.12–$2.27 ongoing EPS guidance and how actual weather, sales, rate cases and cost increases compared with assumptions.
  • Progress on depreciation, interest and property-tax increases, and the funding and regulatory treatment of major capital projects.
  • Final scope, liability and recoverability of environmental, FERC ROE, tax-audit and other contingent exposures.
  • Debt issuance, available credit capacity and cash-flow coverage of capital expenditures and dividends.