Xcel Energy Inc. 2009 Form 10-K Summary
Business context and reporting period
Fiscal year ended December 31, 2009; the filing also presents fourth-quarter results. Xcel Energy is a regulated utility holding company whose four principal utilities serve electric and natural gas customers in eight states. Results are driven by regulated rates, customer demand, weather, fuel costs and investment in utility infrastructure. Fuel and purchased-energy costs are generally passed through to customers under regulatory adjustment mechanisms.
Financial results and liquidity
| Metric | 2009 | 2008 |
|---|---|---|
| Operating revenue | $9.644 billion | $11.203 billion |
| Operating income | $1.469 billion | $1.391 billion |
| Net income | $680.9 million | $645.6 million |
| Diluted GAAP EPS | $1.48 | $1.46 |
| Ongoing diluted EPS, a non-GAAP measure | $1.50 | $1.45 |
| Operating cash flow | $1.918 billion | $1.680 billion |
| Cash used in investing activities | $1.735 billion | $2.156 billion |
| Long-term debt | $7.889 billion | $7.732 billion |
Operating margin was approximately 15.2%, compared with 12.4% in 2008. Electric margin increased to $4.033 billion from $3.735 billion, primarily on rate increases; natural-gas margin decreased to $600 million from $610 million. Revenue declined 13.9%, largely reflecting lower fuel and purchased-power costs passed through to customers, lower sales and trading revenue. Retail electric sales fell about 3% and total electric sales about 4%. O&M expense increased $130 million, or 7.3%, including higher employee-benefit and nuclear costs.
For the fourth quarter, revenue was $2.618 billion versus $2.708 billion in 2008; net income was $168.9 million versus $164.1 million, and diluted EPS was $0.37 versus $0.36. At year-end, cash was $107.8 million; current assets were $2.763 billion and current liabilities $3.015 billion. Debt included $7.889 billion of long-term debt, $543.8 million current portion and $459 million short-term debt. As of February 12, 2010, available committed credit facilities were $1.692 billion; reported total liquidity including cash was $1.776 billion.
Material changes versus 2008
- Ongoing EPS rose to $1.50 from $1.45, although weather, lower sales and higher operating costs offset part of the benefit from improved electric margins and rate increases.
- Operating cash flow improved by $263 million; cash used in investing declined, while financing activities shifted to a $322 million use of cash from a $671 million source.
- Capital spending remains substantial: planned expenditures total $2.235 billion in 2010, $2.290 billion in 2011, $2.125 billion in 2012 and $2.675 billion in 2013.
- Common shares outstanding increased; management cited dilution from the dividend reinvestment plan, benefit plans and prior equity issuance.
Guidance, outlook, risks and unusual items
Management guided to 2010 ongoing EPS of $1.55–$1.65, assuming normal weather, approximately 1% weather-adjusted retail electric sales growth and a 1%–2% decline in retail firm natural-gas sales. The outlook also assumes constructive regulatory outcomes, higher O&M expense of $115–$135 million, and increased depreciation and interest expense. Management’s longer-term targets are 5%–7% annual EPS growth, 2%–4% annual dividend increases and rate-base growth averaging approximately 7% per year from 2009 through 2013.
Major planned investments include wind generation, transmission expansion, nuclear uprates and life extensions, and completion of Comanche Unit 3. Execution, permitting, cost recovery and financing are material dependencies. Risks include adverse rate decisions, climate and other environmental regulation, milder weather, economic weakness and lower demand, fuel or supply disruption, interest rates, capital-market access, counterparty credit, nuclear operations and spent-fuel disposal. Pension assumptions and costs are also significant; management projected higher pension expense in 2010 and 2011.
Contingencies include a $97.5 million recorded liability for the Ashland manufactured-gas-plant site, within total estimated remediation liabilities of $102.1 million; management expects recovery through rates, but final site costs and responsibility remain uncertain. A New Mexico draft compliance order alleged permit violations at Cunningham Station and proposed a $16.1 million penalty; SPS disputed the allegations. Federal reliability investigations, climate-change litigation, the Comanche Unit 3 air-permit lawsuit, and other legal matters remain unresolved. The filing reports a $315.9 million fourth-quarter reduction in the Prairie Island nuclear decommissioning obligation following a revised recovery-period assumption. Auditors issued unqualified opinions on the financial statements and internal controls.
Important facts for investors to verify
- Whether 2010 EPS guidance and the assumed rate-case outcomes are achieved, particularly amid weak sales and weather variability.
- How the planned capital program is funded, and whether regulatory riders and rate cases provide timely recovery while maintaining credit quality.
- Final regulatory requirements and recoverable costs for GHG emissions, air quality, mercury and other environmental compliance.
- Developments in the Cunningham, Ashland, Comanche and reliability matters, plus nuclear license extensions and spent-fuel storage approvals.
- Whether pension funding, benefit costs and other contractual commitments affect cash generation, dividends or borrowing needs.