Xcel Energy Inc. — Q3 2010 Form 10-Q
Business context and period. Unaudited results for the quarter and nine months ended September 30, 2010, compared with the corresponding 2009 periods. Xcel Energy is a regulated electric and natural gas utility holding company operating through four principal utility subsidiaries. Management cautions that seasonal interim results are not necessarily indicative of full-year performance.
Financial performance
| Metric | Q3 2010 | Q3 2009 | Nine months 2010 | Nine months 2009 |
|---|---|---|---|---|
| Operating revenue | $2.629 billion | $2.315 billion | $7.744 billion | $7.026 billion |
| Operating income | $568.6 million | $465.1 million | $1.298 billion | $1.115 billion |
| Net income | $312.3 million | $220.8 million | $619.2 million | $512.0 million |
| Diluted EPS | $0.67 | $0.48 | $1.34 | $1.11 |
| Ongoing diluted EPS (non-GAAP) | $0.62 | $0.48 | $1.34 | $1.12 |
Year over year, Q3 revenue increased approximately 14%, operating income 22%, net income 41%, and diluted EPS $0.19. Nine-month revenue rose approximately 10%, operating income 16%, net income 21%, and diluted EPS $0.23. Q3 operating margin was approximately 21.6% of revenue versus 20.1% a year earlier; nine-month operating margin was approximately 16.8% versus 15.9%.
- Margins: Q3 electric margin was $1.330 billion, up $183 million; nine-month electric margin was $3.392 billion, up $347 million. Q3 natural gas margin was $104 million, up $6 million; nine-month natural gas margin was $435 million, up $21 million. Fuel-cost recovery mechanisms largely offset commodity price fluctuations in margins.
- Cash flow: Nine-month operating cash flow was $1.522 billion, down $107 million from 2009. Investing outflow was $1.521 billion, up $227 million, primarily reflecting higher utility capital spending. Financing provided $103 million, versus a $492 million outflow in 2009. Cash and equivalents at September 30 were $213.5 million.
- Debt and liquidity: Long-term debt, including current maturities, totaled $9.279 billion at September 30, compared with $8.432 billion at year-end 2009. Short-term debt was $40 million, down from $459 million. The company issued $550 million of 4.70% senior notes; NSP-Minnesota issued $500 million of first mortgage bonds. As of October 20, committed facilities provided $2.120 billion of availability; with $94 million cash shown in that liquidity schedule, reported liquidity was $2.214 billion.
- Balance sheet: Total assets were $26.301 billion and common stockholders’ equity was $7.606 billion at September 30. Current assets of $2.530 billion exceeded current liabilities of $2.199 billion.
- Dividends and shares: Common dividends declared were $0.25 per share in Q3 and $0.75 for the first nine months. Shares outstanding at September 30 were approximately 460.1 million.
Drivers and material changes
- Management attributed higher ongoing Q3 EPS primarily to warmer weather, rate increases, seasonal rate design and a lower effective tax rate. Q3 temperatures were warmer than normal, whereas 2009 was cooler than normal; weather contributed an estimated $0.09 per share to the year-over-year comparison.
- Electric margin growth reflected rate increases, weather, riders and customer growth. Seasonal rates increased Q3 electric revenue and margin by an estimated $45 million; management expected part of this timing benefit to reverse in Q4, with rates designed to be revenue-neutral annually.
- O&M expense rose $43 million in Q3 and $97 million year to date, driven by employee benefits, generation maintenance, labor, nuclear operations and insurance. Depreciation and amortization increased $23 million in Q3 and $30 million year to date, including the effect of Comanche Unit 3 entering service.
- Q3 other income included a $25 million, nontaxable Provident settlement relating to the discontinued COLI program, approximately $0.05 per share. This is nonrecurring. First-quarter items included approximately $17 million of Medicare Part D tax-benefit reversal and a roughly $10 million COLI-related tax and interest charge; the latter was partly reduced by a $0.6 million Q3 expense adjustment.
- PSCo’s planned acquisition of two natural-gas generation facilities for $739 million received CPUC approval after quarter-end and was expected to close in December 2010. Recovery of associated costs is subject to regulatory arrangements.
Outlook, risks and contingencies
- Guidance: 2010 ongoing EPS guidance was $1.55–$1.65, with management expecting the upper half. 2011 guidance was $1.65–$1.75. Assumptions include normal weather, constructive regulatory outcomes, sales growth and expense, depreciation, interest and tax-rate estimates. These are ongoing, non-GAAP measures, not GAAP EPS forecasts.
- Management’s 2010 assumptions included weather-adjusted retail electric sales growth of 1.2%–1.4%, O&M growth of 8%–9%, and an effective tax rate of 35%–37%. For 2011, it assumed roughly 1% electric sales growth (adjusted for the Lubbock asset sale), flat natural gas sales, and O&M growth of 3%–4%.
- Regulatory outcomes and cost recovery are central risks. Pending matters include rate cases and fuel-cost reconciliations; Wisconsin fuel costs could exceed the variance band and require customer refunds. SPS sought an annual Texas base-rate increase of approximately $62 million, with implementation expected no earlier than February 2011.
- Environmental obligations include an estimated $101.9 million site-remediation liability. NSP-Wisconsin recorded $97.5 million for the Ashland site cleanup, deferred as a regulatory asset based on expected rate recovery; final scope and cost remained uncertain. SPS intends to contest a New Mexico compliance order proposing a $7.6 million penalty.
- Other material uncertainties include climate and air-quality rules, possible unrecovered compliance costs, reliability-standard investigations, and litigation. PSCo’s Comanche Unit 3 contractor sought approximately $144 million, while PSCo counterclaimed for approximately $82 million; trial began in October 2010. A natural-gas explosion litigation matter and several climate-related lawsuits also remain unresolved.
- Pension costs were projected to rise to $48 million in 2010 and $71 million in 2011. Management anticipated a voluntary $35 million pension contribution in 2010 and estimated 2011 contributions of $125 million–$175 million.
- Management reported effective disclosure controls and no material quarterly change in internal control over financial reporting.
Important facts for investors to verify
- Whether reported earnings growth is sustainable after excluding the $25 million COLI settlement and considering weather and seasonal-rate timing.
- Progress and final outcomes in rate cases, fuel-cost recovery proceedings and regulatory approvals, including the PSCo generation acquisition and Colorado emissions plan.
- Capital spending, debt issuance, equity-forward settlement and pension contributions, and their effects on leverage, liquidity and share dilution.
- Potential environmental and legal liabilities, particularly the Ashland remediation estimate, the Cunningham penalty and Comanche contractor litigation.
- Actual performance against 2010 and 2011 ongoing EPS guidance and its stated assumptions; the filing does not provide a GAAP EPS guidance range.