Xcel Energy Inc. (XEL) — 2014 Form 10-K Summary
Business context and reporting period
Fiscal year ended December 31, 2014. Xcel Energy is a regulated utility holding company whose four utility subsidiaries provide electric service across eight states and natural gas service in portions of its territory. Results are seasonal and subject to regulation, weather and significant infrastructure investment.
Financial performance and liquidity
| Metric | 2014 | 2013 |
|---|---|---|
| Operating revenue | $11.686 billion | $10.915 billion |
| Operating income | $1.948 billion | $1.848 billion |
| Net income | $1.021 billion | $948 million |
| Diluted GAAP EPS | $2.03 | $1.91 |
| Operating cash flow | $2.648 billion | $2.584 billion |
| Capital expenditures | $3.200 billion | $3.395 billion |
| Long-term debt | $11.500 billion | $10.911 billion |
| Short-term debt | $1.020 billion | $759 million |
Electric margin increased to $5.256 billion from $5.015 billion; natural gas margin increased to $771 million from $722 million. Margin growth primarily reflected rate increases and weather-normalized sales growth. Higher fuel and purchased-power costs were largely passed through to customers under recovery mechanisms. Cash from operations was below capital expenditures by approximately $552 million. Year-end cash and cash equivalents were $79.6 million. At December 31, $1.670 billion of the $2.750 billion committed credit facilities was available; facilities mature in October 2019.
Dividends declared were $1.20 per share, up from $1.11. Return on average common equity was 10.3%, unchanged from 2013. Assets were $36.958 billion, and book value per share was $20.20.
Material changes versus 2013
- Revenue rose 7.1%, net income rose 7.7%, and diluted GAAP EPS increased from $1.91 to $2.03. Ongoing EPS rose from $1.95 to $2.03; the 2013 GAAP figure included a $0.04-per-share SPS FERC-related charge.
- Electric margin increased $241 million on a GAAP basis, including the prior-year comparison effect of the SPS matter; natural gas margin increased $49 million.
- Electric retail sales were nearly flat, up 0.2%; weather-normalized retail electric sales increased 1.3%. Natural gas revenues rose with higher purchased-gas recovery and sales.
- Operating cash flow increased $64 million, while long-term debt increased approximately $589 million and short-term debt increased $261 million.
- 2014 operating results faced milder summer conditions and lower electric weather-related contribution than in 2013. Higher O&M, property taxes, depreciation and conservation-program expenses partly offset margin gains.
Guidance, outlook, risks and unusual items
- Management set 2015 ongoing EPS guidance at $2.00–$2.15. Assumptions include normal weather, retail electric sales growth of about 1%, firm natural gas sales decline of about 2%, O&M growth of 0%–2%, and an effective tax rate of 34%–36%.
- Long-term objectives include 4%–6% annual EPS growth based on weather-normalized 2014 ongoing EPS of $2.00, 5%–7% annual dividend increases, and a 60%–70% payout ratio. Planned 2015–2019 capital expenditures are $14.48 billion; management expects rate base to grow at an average compounded annual rate of about 4.7%.
- The Monticello nuclear life-extension/uprate project had approximately $748 million of capitalized costs, compared with an initial 2008 estimate of about $320 million excluding AFUDC. An administrative law judge recommended a disallowance that could reduce the 2015 revenue requirement by about $10.2 million for Minnesota, equivalent to about $94 million systemwide if adopted by relevant commissions. Final regulatory decisions were pending.
- PSCo recorded a $74 million estimated 2014 customer refund obligation under its electric earnings test. The final amount remained subject to regulatory review. The Minnesota multi-year electric rate case also included interim rates subject to refund.
- Environmental regulation remains a significant exposure. A proposed EPA requirement for dry scrubbers at SPS’s Tolk units could cost about $600 million plus approximately $10.4 million in annual operating costs if finalized. Costs for cooling-water intake compliance were estimated at $46 million for impingement, with possible additional entrainment costs up to $145 million. Recovery through rates is expected for many compliance costs but is not assured in every proceeding.
- Other notable exposures include the Ashland former manufactured-gas-plant cleanup liability of $107.6 million, with sediment remediation unresolved; the Monticello NRC safety finding and outstanding determinations; coal inventory below normal at several systems because of rail congestion; and nuclear fuel sourcing exposure to events involving Ukraine and Russia.
- Key broader risks include regulatory cost recovery and authorized returns, weather, fuel and supply disruptions, environmental and climate rules, nuclear operations and spent-fuel disposal, pension assumptions, interest rates, credit ratings, cybersecurity, and distributed-generation competition. Management reported effective internal controls; the independent auditor issued unqualified opinions on the financial statements and internal control.
Most important facts for investors to verify
- Final outcomes and recoverability in the Monticello prudence review and Minnesota electric rate case, including any refunds or disallowances.
- Whether 2015 EPS guidance is achieved, especially its weather, sales, expense, tax and regulatory assumptions.
- Funding of the $14.48 billion capital plan, resulting debt levels, and continued access to committed liquidity.
- Final environmental requirements and cost recovery, particularly Tolk scrubbers and cooling-water intake measures.
- Updated estimates, timing and recovery for Ashland remediation and other legal or regulatory contingencies.
- Progress in addressing nuclear plant safety findings and secure long-term spent-fuel storage.