Xcel Energy Inc. — 2015 Form 10-K
Business context and period. This annual report covers the fiscal year ended December 31, 2015; it is not a standalone fourth-quarter filing. Xcel Energy is a regulated utility holding company whose four operating utilities provide electric service across eight states and natural gas service in parts of its territory. Results are primarily driven by regulated rates, customer usage, weather, capital investment and regulatory cost recovery.
Financial performance
| Metric | 2015 | 2014 | Change |
|---|---|---|---|
| Operating revenue | $11.024 billion | $11.686 billion | Down 5.7% |
| Operating income | $2.001 billion | $1.948 billion | Up 2.7% |
| Net income (GAAP) | $984.5 million | $1.021 billion | Down 3.6% |
| Diluted EPS (GAAP) | $1.94 | $2.03 | Down 4.4% |
| Ongoing diluted EPS (non-GAAP) | $2.09 | $2.03 | Up 3.0% |
| Net cash from operating activities | $3.026 billion | $2.648 billion | Up $378 million |
- Electric margin increased to $5.513 billion from $5.256 billion, chiefly reflecting rate increases, non-fuel riders and transmission revenue. Natural gas margin was $767 million versus $771 million.
- Operating margin, calculated as operating income divided by revenue, was approximately 18.1%, versus 16.7% in 2014. Net margin was approximately 8.9%, versus 8.7%.
- Cash used in investing activities was $3.623 billion, including $3.683 billion of utility capital and construction expenditures. Cash provided by financing was $602 million. Cash and cash equivalents ended the year at $84.9 million.
- Long-term debt was $12.491 billion, up from $11.500 billion. Including current long-term debt and short-term debt, reported debt was approximately $13.994 billion, versus $12.777 billion in 2014. Short-term debt included $846 million of commercial paper.
- At December 31, the $2.75 billion credit facilities had $1.875 billion available. Current assets were $2.910 billion and current liabilities $4.058 billion. The company reported $39.054 billion in assets and $10.601 billion in common equity.
- Dividends declared were $1.28 per share, up from $1.20; dividends paid totaled $607 million. Return on average common equity was 9.5%, versus 10.3% in 2014.
Material changes and unusual items
- GAAP earnings included a $129 million pretax ($79 million after-tax) charge for the Monticello life-cycle management/extended power uprate project, reducing EPS by $0.16. The Minnesota commission allowed recovery of $415 million of project costs with a return, but recovery of another $333 million without a return.
- Excluding that item, ongoing EPS rose $0.06. Management attributed the increase mainly to rate increases, non-fuel riders, lower conservation and O&M expenses, partly offset by unfavorable weather, higher depreciation, property taxes and interest, and lower allowance for funds used during construction.
- Revenue fell largely because lower fuel and purchased-power costs and lower natural-gas prices reduced pass-through revenue; these cost-recovery changes generally have limited effect on margins. Weather-normalized retail electric sales declined 0.2%; firm natural-gas sales declined 1.7%.
- Operating cash flow rose, helped by rate increases and income-tax refunds, partly offset by customer refunds under a settlement. Capital spending increased, including acquisition of two wind projects.
Outlook, management commentary and risks
- 2016 guidance: ongoing EPS of $2.12–$2.27. Assumptions include constructive regulatory outcomes, normal weather, 0.5%–1.0% weather-normalized retail electric sales growth, flat firm gas sales, O&M growth of 0%–2%, and a 34%–36% effective tax rate. Management projected higher depreciation, property taxes and interest expense than in 2015.
- Longer-term targets: annual ongoing EPS growth of 4%–6%, dividend increases of 5%–7%, a 60%–70% ongoing-EPS payout ratio, and BBB+ to A senior unsecured ratings. The filing describes 2015 ongoing EPS as $2.09 actual in its earnings reconciliation, while the long-term target basis cites $2.10, the midpoint of prior guidance.
- Investment plan: base capital expenditures of approximately $15.2 billion for 2016–2020, expected to grow rate base at about 3.7% annually. Potential incremental projects of $2.5 billion could bring the total to $17.7 billion and projected rate-base growth to 5.5%. Management said it did not expect equity issuance to fund the base program; estimated funding includes $13.280 billion from cash from operations and $1.885 billion of new debt.
- Regulatory and environmental exposure: rate recovery, rate-case outcomes and timing are central risks. The EPA Clean Power Plan was stayed by the U.S. Supreme Court in February 2016 while litigation proceeds. Potential compliance obligations include Tolk Unit 1 and 2 scrubbers estimated at approximately $600 million; management expects recovery through rates. Other environmental-rule costs and the ability to recover them are uncertain.
- Other material risks and contingencies: the Ashland manufactured-gas-plant site liability was $94.4 million, with the sediment remedy and final company share unresolved. A possible Seattle refund claim was preliminarily calculated at about $28 million excluding interest; no accrual was recorded and the loss range was not estimable. Possible SPP transmission-upgrade charges, including retroactive charges, were also not estimable. Nuclear fuel disposal remains dependent on unavailable federal storage; the company relies on interim on-site storage.
- Additional risks include weather volatility, capital-market and interest-rate access, pension funding and assumptions, fuel supply and grid reliability, cyber and physical security, environmental rules, and regulatory disallowance or delayed recovery of investment. The filing reports effective internal control over financial reporting and unqualified audit opinions.
Most important facts for investors to verify
- Reconcile GAAP EPS of $1.94 with ongoing EPS of $2.09, including the Monticello charge, and assess whether ongoing earnings are a useful basis for valuation.
- Track 2016 rate-case outcomes and actual recovery timing, particularly Minnesota and SPS proceedings, alongside the assumptions embedded in $2.12–$2.27 EPS guidance.
- Compare actual capital spending, cash generation and debt issuance with the 2016–2020 plan; monitor leverage, credit-facility availability and refinancing maturities.
- Assess execution and regulatory approval of planned generation and transmission investments, including the Minnesota resource plan, Colorado initiatives and potential Tolk scrubbers.
- Monitor resolution and potential cost changes for the Ashland site, Seattle refund matter, SPP upgrade charges, and nuclear plant and spent-fuel obligations.