Business context and reporting period
Wisconsin Energy Corporation filed this unaudited Form 10-Q for the quarter and nine months ended September 30, 2012. Its two principal segments were utility energy (electric, gas and steam service) and non-utility energy, primarily We Power, which owns and leases generating facilities to Wisconsin Electric.
Financial performance
| Metric | Third quarter 2012 | Third quarter 2011 | Nine months 2012 | Nine months 2011 |
|---|---|---|---|---|
| Operating revenue | $1,039.3m | $1,052.8m | $3,175.2m | $3,373.2m |
| Operating income | $280.6m | $224.3m | $798.9m | $694.3m |
| Net income | $156.1m | $129.8m | $447.5m | $410.2m |
| Diluted EPS from continuing operations | $0.67 | $0.55 | $1.92 | $1.69 |
| Operating margin, approximate | 27.0% | 21.3% | 25.2% | 20.6% |
For the quarter, revenue fell about 1.3% while operating income rose about 25.1%; for the nine-month period, revenue fell about 5.9% while operating income increased about 15.1%. Net income includes $11.5m of discontinued-operation income in the 2011 nine-month comparison; 2012 reported none. The 2011 discontinued-operation item related to favorable resolution of tax positions from a former manufacturing business.
Quarterly utility-segment operating income increased $55.4m, mainly as other operation and maintenance expense declined $52.9m. The nine-month utility increase was $96.5m. The principal cited driver was the PSCW-authorized one-year suspension of $148m in amortization of certain regulatory costs during 2012. Lower gas costs and lower fuel and purchased-power costs also reduced expenses. Higher depreciation reflected newly placed-in-service plant and environmental controls.
Weather affected demand: the first nine months were 24.2% warmer than the comparable 2011 period and 19.9% warmer than normal. Nine-month gas margin declined $41.1m to $288.3m, while electric utility revenue rose $11.7m; large commercial/industrial electricity sales were lower, partly reflecting a major customer’s planned mine outage and other customers’ self-generation.
Cash flow, debt and liquidity
- Nine-month operating cash flow was $992.4m, versus $827.6m in 2011. Investing cash outflow was $491.4m, versus $650.3m; financing cash outflow was $502.1m, versus $186.7m.
- Capital expenditures were $477.5m for the first nine months. Management estimated approximately $740m of consolidated capital expenditures for full-year 2012.
- At September 30, cash and cash equivalents were $13.0m. Current assets were $1,084.8m and current liabilities $1,387.0m; liabilities exceeded assets by $302.2m. Management said it expected no liquidity impact, citing credit facilities and capital-market access.
- Consolidated short-term debt was $453.2m and long-term debt, including current maturities, was $4,621.7m; total debt was $5,074.9m. The company-reported debt-to-total-capitalization ratio was 54.8%, or 52.1% using rating-agency treatment that assigns half of its $500m junior notes to equity.
- Approximately $1.2bn of undrawn bank credit facilities supported commercial paper and general purposes. Facilities were scheduled to expire in December 2013. The company expected to issue long-term debt in the fourth quarter, subject to market conditions; it issued none in the first nine months.
- Common dividends were $0.30 per share in the quarter, up from $0.26 a year earlier. The board’s policy targeted a payout ratio trending toward 60% of earnings in 2014. The company had repurchased $114m under its $300m authorization through September 30, 2012.
Outlook, regulatory matters and risks
- Management expected a 2012 effective tax rate of 35.5%–36.5%; the nine-month rate was 36.1%.
- Pending 2013 Wisconsin rate requests included a proposed $99.3m net electric increase for Wisconsin Electric, offset by expected renewable-energy grant proceeds, and proposed natural-gas rate decreases for Wisconsin Electric and Wisconsin Gas. A final PSCW written order was anticipated by year-end 2012.
- All Power the Future generating units were in service, with lease costs recovered through regulated rates. Oak Creek air-control equipment for units 5–8 entered commercial service by September 2012; final project cost was approximately $740m, or $900m including AFUDC.
- The company was building a 50 MW biomass facility, with expected investment of $245m–$255m excluding AFUDC and a target completion by year-end 2013. It also agreed to buy the Montfort Wind Energy Center for $27m, subject to regulatory approval.
- Management planned to convert Valley Power Plant from coal to natural gas, estimating $60m–$65m in costs and anticipating completion no later than 2016, subject to approvals. The company identified potential MATS compliance capital costs of $8m–$12.5m.
- Environmental and legal contingencies include manufactured-gas-plant remediation estimates of $21m–$65m over ten years, with $37.5m reserved; a Wisconsin DOJ referral concerning alleged violations following the Oak Creek bluff collapse, where fines or penalties were anticipated but not quantified; and ongoing permit-related proceedings concerning Valley Power Plant. Management said known quantifiable environmental costs beyond amounts accrued or disclosed were not expected to be material.
- The $45m cash-balance pension-plan class-action settlement was court-approved in April 2012; substantially all payments had been made and no further charges were anticipated. Management reported compliance with financial covenants, effective disclosure controls and no material change in internal control or market-risk disclosures.
- Forward-looking risks include weather and demand, generation availability, fuel and purchased-power prices, regulatory rate recovery, environmental requirements, construction execution, litigation, capital-market access and pension investment performance. Management cautioned that interim results are seasonal and not necessarily indicative of full-year results.
Most important facts for investors to verify
- Whether the 2012 operating-income improvement is sustainable after the one-year $148m regulatory-asset amortization suspension ends in 2013.
- PSCW decisions on the 2013 rate cases, including treatment of biomass grant proceeds and recovery of environmental and construction costs.
- Actual capital spending, project completion costs and approvals for the biomass facility, Montfort wind acquisition and Valley Power Plant conversion.
- Liquidity and refinancing plans, including expected fourth-quarter debt issuance, commercial-paper levels and the December 2013 credit-facility expirations.
- Developments and potential costs from the Oak Creek bluff-collapse enforcement matter, environmental proceedings and remediation obligations.