XCEL ENERGY INC. — Q1 2015 Form 10-Q
Business context and reporting period
Xcel Energy is a regulated electric and natural gas utility holding company operating through subsidiaries in Minnesota, Wisconsin, Colorado, Texas and New Mexico. This unaudited report covers the three months ended March 31, 2015; balance-sheet comparisons are with December 31, 2014. Management cautions that seasonal interim results are not necessarily indicative of full-year performance.
Financial performance
| Metric | Q1 2015 | Q1 2014 |
|---|---|---|
| Operating revenue | $2.962 billion | $3.203 billion |
| Operating income | $350.8 million | $494.0 million |
| Net income | $152.1 million | $261.2 million |
| GAAP diluted EPS | $0.30 | $0.52 |
| Ongoing diluted EPS (non-GAAP) | $0.46 | $0.52 |
| Operating cash flow | $985.4 million | $592.6 million |
| Utility capital/construction expenditures | $770.6 million | $822.6 million |
| Cash and cash equivalents at quarter-end | $133.0 million | $132.3 million |
Operating margin was approximately 11.8% of revenue, compared with 15.4% a year earlier; net margin was approximately 5.1%, versus 8.2%. These are calculated from reported figures. Electric margin rose to $1.275 billion from $1.235 billion, while natural gas margin declined to $244 million from $256 million. Lower fuel and gas-cost recovery reduced reported revenue, with limited margin impact because these costs are generally passed through to customers.
Long-term debt, including current maturities, was approximately $11.76 billion at March 31; short-term debt was $969 million. Total current assets were $3.06 billion and current liabilities were $3.77 billion. The company reported $1.72 billion of available credit capacity at March 31 under $2.75 billion of committed facilities. Long-term debt fair value was $13.62 billion versus a carrying value of $11.76 billion.
Material changes and unusual items
- GAAP earnings included a $129 million pretax ($0.16 per share) charge for the Monticello life-cycle management/extended power uprate project. The Minnesota regulator allowed a return on about $415 million of project costs but recovery without return on the remaining approximately $333 million. The charge drove much of the decline in GAAP earnings.
- Ongoing EPS fell $0.06 year over year. Management attributed the decline mainly to weather: unusually cold Q1 2014 had contributed approximately $0.05 per share, while Q1 2015 weather was closer to normal. Higher depreciation, O&M, taxes and interest, and lower construction-related allowance for funds used during construction also weighed on results; higher electric margins partly offset these factors.
- Operating cash flow increased $392.7 million, chiefly from working-capital and regulatory-balance changes and lower pension contributions, despite lower net income. Financing cash flow shifted to a $193.6 million outflow from a $233.3 million inflow, reflecting lower debt and equity issuance, higher dividends and short-term debt repayment.
- Quarterly dividends declared were $0.32 per share, up from $0.30. Dividends paid totaled $144.0 million.
Outlook, regulation and risks
- 2015 ongoing EPS guidance is $2.00–$2.15. Assumptions include constructive regulatory outcomes, normal weather, weather-normalized retail electric sales growth of about 1%, gas sales growth of 0%–1%, O&M growth of 0%–2%, and an effective tax rate of 34%–36%. Guidance is non-GAAP and subject to risks.
- Long-term objectives are annual EPS growth of 4%–6% from weather-normalized ongoing 2014 EPS of $2.00, dividend growth of 5%–7%, and a 60%–70% payout ratio. The company targets BBB+ to A senior unsecured debt ratings.
- Minnesota approved estimated combined 2014 and 2015 electric rate increases of about $168 million; final rates, interim-rate refund treatment and the written order remained pending. The decision also included a revenue-decoupling pilot effective in 2016.
- Colorado approved a 2015 electric revenue increase of about $53.3 million, including riders. A separate Colorado gas-rate request sought staged increases through 2017; a decision was expected in Q4 2015. Texas SPS sought a revised $58.9 million annual electric increase, with a decision expected in the second half of 2015.
- Regulatory and legal uncertainties include FERC wholesale-return-on-equity complaints and possible refunds; SPS estimated $4–$6 million of annual revenue reductions from certain ROE cases and recorded refund liabilities. A separate MISO ROE matter was estimated to reduce NSP System annual transmission revenue by $7–$9 million.
- Environmental exposure includes the Ashland site, for which NSP-Wisconsin had recorded a $112.4 million liability. Sediment cleanup approach and cost remain uncertain; the EPA’s estimated Hybrid Remedy range was $63–$77 million before potential deviations. A proposed EPA requirement for dry scrubbers at SPS’s Tolk units could cost about $600 million plus $10.4 million annual operating costs; the final decision was pending.
- Other disclosed contingencies include a possible Pacific Northwest refund claim against PSCo (preliminary claim about $28 million excluding interest) and a disputed biomass-fuel reimbursement demand of about $20 million; no accrual was recorded for either. Management said the amount of any potential loss was not estimable.
- Potential risks also include weather, regulatory recovery, environmental compliance, litigation, financing conditions, cybersecurity and nuclear operations. The filing reported no material change to previously disclosed risk factors. Management reported effective disclosure controls and no material quarterly change in internal control over financial reporting.
Most important facts for investors to verify
- Whether the Monticello written order, cost recovery treatment and any reconsideration change the recorded charge or future earnings and rates.
- Final outcomes and refund exposure in Minnesota, Colorado, Texas and FERC rate proceedings, including interim rates and earnings-test obligations.
- Whether 2015 EPS guidance assumptions remain achievable given weather, sales, regulatory rulings and rising depreciation, property taxes and interest costs.
- How Ashland remediation and potential Tolk scrubber requirements develop, and whether customer recovery or third-party contributions offset the costs.
- Whether the higher operating cash flow persists, and how planned debt issuance, capital spending and dividend commitments affect leverage and liquidity.