Wisconsin Energy Corporation — Q3 2013 Form 10-Q
Business context and period: Unaudited results for the quarter and nine months ended September 30, 2013, compared with the same 2012 periods. The company operates regulated electric, natural gas and steam utilities, plus a non-utility energy segment primarily comprising We Power. Amounts below are in millions of dollars unless stated otherwise.
Financial performance and position
| Metric | Q3 2013 | Q3 2012 | Nine months 2013 | Nine months 2012 |
|---|---|---|---|---|
| Operating revenues | $1,053.2 | $1,039.3 | $3,340.7 | $3,175.2 |
| Operating income | $258.0 | $280.6 | $808.5 | $798.9 |
| Net income | $137.5 | $156.1 | $433.1 | $447.5 |
| Diluted EPS | $0.60 | $0.67 | $1.88 | $1.92 |
| Cash provided by operating activities | — | $1,050.3 | $992.4 | |
| Capital expenditures | — | $497.7 | $477.5 |
- Q3 revenue increased 1.3%, while net income fell 11.9% and diluted EPS fell 10.4%. Nine-month revenue rose 5.2%, but net income declined 3.2% and diluted EPS declined 2.1%.
- Q3 operating margin was approximately 24.5% versus 27.0% in 2012; nine-month operating margin was approximately 24.2% versus 25.2%. These percentages are calculated from reported operating income and revenue.
- Nine-month operating cash flow improved $57.9, principally because the company made no qualified benefit-plan contributions, compared with $100.0 in 2012. Cash used for investing was $544.8; cash used for financing was $522.6. Cash at period-end was $18.5.
- At September 30, total debt was $5,103.7, including $4,741.9 of long-term debt and current maturities and $361.8 of short-term debt. Management’s adjusted debt-to-capitalization ratio, reflecting rating-agency treatment of junior notes, was 52.0%, versus 54.7% on the reported basis.
- Current liabilities exceeded current assets by approximately $53.0. The company reported approximately $1.2 billion of available undrawn bank facilities and $361.8 of commercial paper outstanding.
Material changes and management commentary
- Q3 utility-segment operating income declined $24.4 to $166.6, mainly as operating and maintenance costs increased $25.4, including reinstated regulatory amortizations, and depreciation rose $5.2. Non-utility operating income increased $1.7 to $93.2.
- Q3 electric utility revenue rose $9.8. Higher Wisconsin retail pricing and increased sales for resale were partly offset by milder cooling weather, lower wholesale revenue and reduced other revenue. Retail electric sales fell 6.1%; the two Michigan iron ore mines moved to alternative suppliers effective September 1, 2013.
- Q3 gas gross margin declined $2.2 to $59.0, reflecting lower rates and customer mix; gas operating revenue rose as higher gas commodity costs flowed through to customers. For the first nine months, gas gross margin increased $16.4 to $304.7, primarily because colder weather increased heating volumes, partly offset by lower rates.
- Nine-month operating income increased $9.6, but lower AFUDC-equity income and higher net interest expense contributed to the $14.4 decline in net income. AFUDC-equity fell $18.3, and net interest expense increased $9.0.
- Management expects approximately $690 of consolidated capital expenditures in 2013. It anticipates a 2013 annual effective tax rate of 36%–37% and expects to fund capital needs with internal cash, short-term borrowings and, as appropriate, debt issuance.
Outlook, risks and contingencies
- The company expected to recognize an approximately $72 Section 1603 grant for its Rothschild biomass facility in Q4 2013, when the facility was expected to enter service. Customer bill credits had reduced revenue before grant recognition; management estimated matching grant income would have increased each of Q1–Q3 EPS by about $0.03. The plant was targeted for completion by year-end 2013.
- In July, the board accelerated a planned dividend increase: quarterly dividend rose to $0.3825 per share, an annualized rate of $1.53. The stated payout-ratio policy targets a trend to 65%–70% by 2017. The company had repurchased $254.8 of stock under a $300 share-repurchase authorization through 2013.
- Before mitigation, management estimated that Michigan customer switching could reduce 2014 pre-tax results by $50–$54. MISO required the Presque Isle Power Plant units to remain available for reliability; the company expected to become eligible for system-support payments in February 2014, potentially $35–$82 annualized, subject to the costs covered and payment determination. Mitigation and cost recovery remained uncertain.
- Environmental and regulatory matters include potential PIPP controls to comply with air rules, evolving greenhouse-gas and wastewater requirements, and the Paris Generating Station Units 1 and 4 outage following a state environmental notice. Those units were expected to remain out of service until at least 2014, and fines or penalties were possible. The filing says additional environmental costs could be material in some scenarios, depending on final rules and rate recovery.
- Manufactured-gas-plant remediation costs were estimated at $16–$62 over ten years, with $38.2 accrued. Management stated that known and quantifiable environmental contingencies beyond amounts accrued or disclosed were not expected to materially affect financial position or results.
- Contractual obligations and other commercial commitments totaled approximately $22.4 billion at September 30, 2013. Management stated liquidity was adequate for the foreseeable future, while noting that access to capital depends in part on credit quality and market conditions.
- Management reported no material change in market-risk disclosures and concluded disclosure controls were effective; no material change in internal control over financial reporting was reported during the quarter.
Important facts for investors to verify
- Whether the biomass facility entered service and the grant was recognized as expected, including the timing and rate treatment of the related customer credits.
- Actual Michigan customer losses, the MISO system-support payment amount and the effectiveness of management’s mitigation and regulatory cost-recovery efforts.
- Progress and cost exposure for PIPP environmental compliance, Paris Generating Station proceedings, and evolving federal and state environmental rules.
- Capital spending, liquidity and debt refinancing needs, especially given the working-capital deficit and planned utility infrastructure investment.
- Whether utility pricing, customer demand and weather normalize sufficiently to offset operating-cost increases and support earnings and the dividend policy.