EVERSOURCE ENERGY (then Northeast Utilities) — Form 10-Q Summary
Reporting period: Quarter and six months ended June 30, 2010. The filing is for Northeast Utilities (NU), the predecessor name, and also reports on CL&P, PSNH and WMECO. NU’s regulated electric and natural-gas businesses accounted for approximately 99% of consolidated revenue. Financial statements are unaudited; the independent accountant performed a review, not an audit. Dollar amounts below are in millions unless stated otherwise.
Financial performance
| NU consolidated | Q2 2010 | Q2 2009 | First half 2010 | First half 2009 |
|---|---|---|---|---|
| Operating revenue | $1,111.4 | $1,224.4 | $2,450.8 | $2,817.9 |
| Operating income | $178.3 | $179.2 | $405.0 | $396.5 |
| Net income attributable to controlling interests | $71.9 | $82.9 | $158.2 | $180.5 |
| Fully diluted EPS | $0.41 | $0.47 | $0.90 | $1.07 |
| Operating margin | 16.0% | 14.6% | 16.5% | 14.1% |
- Revenue declined 9% in Q2 and 13% in the first half, mainly because lower fuel and power costs passed through customer-rate tracking mechanisms reduced reported distribution revenue. These pass-through changes generally do not affect earnings.
- Operating income was nearly flat in Q2 and rose about 2% for the first half. Net income attributable to controlling interests fell about 13% and 12%, respectively; EPS also reflected a higher weighted-average share count in the first half.
- NU’s reported cash from operations was $533.8 in the first half versus $508.3 in 2009. Management separately cited operating cash flow net of rate-reduction-bond payments of $405.2 versus $388.0. Investing cash outflow was $447.9; financing cash outflow was $24.1. Cash capital expenditures were $442.4 versus $420.9.
- At June 30, NU had $88.8 cash, $157.3 bank notes payable, $66.3 current long-term debt, $4,635.9 long-term debt and $313.8 rate-reduction bonds. Aggregate revolving-credit availability was $647.1. NU reported compliance with debt covenants.
- NU assets were $14.23 billion, versus $14.06 billion at year-end 2009. Total capitalization was $8.41 billion, including $3.66 billion of equity.
Material changes and operating trends
- Second-quarter earnings were $11.1 lower than the prior year, principally because 2009 included an $11.1 net benefit from resolving routine tax matters. First-half 2010 also included a $3 after-tax charge related to the 2010 Healthcare Act and $14 of storm-restoration costs, including $8 in Q2.
- Regulated-company earnings were $69.0 in Q2 and $157.1 in the first half, down from $80.0 and $174.6. Transmission earnings increased to $41.9 in Q2 and $82.1 in the first half, supported by investment in transmission infrastructure. Distribution earnings fell to $27.1 and $75.0, affected by the absence of prior-year tax benefits and higher costs, partly offset by rate-case benefits and other factors.
- Retail electric sales were unchanged for the first half; Q2 sales rose 5.9%, largely due to unusually warm weather. Firm natural-gas sales fell 3.7% in the first half; management attributed this primarily to milder weather.
- NU declared common dividends of $0.26 per share in Q2 versus $0.24 a year earlier. The Board declared a $0.25625 quarterly dividend payable September 30, 2010.
Outlook, regulation and risks
- NU raised 2010 EPS guidance to $1.95–$2.05 from $1.80–$2.00. Components include distribution EPS of $1.00–$1.10, transmission about $0.95, competitive businesses about $0.05, and parent/other expenses about $0.05. Management cited rate-case outcomes, weather-driven sales, improving uncollectibles and first-half performance, partly offset by greater storm activity.
- Management continued to project 6%–9% annual EPS growth for 2010–2014, using 2009 EPS of $1.91 as the base, subject to capital-plan execution, regulatory returns, sales and costs. It projected 2010 operating cash flow of about $700 net of rate-reduction-bond payments, capital expenditures of about $1.1 billion, and a roughly $45 pension contribution in Q3.
- CL&P received approval for distribution increases of $63.4 annually effective July 2010 and a further $38.5 effective July 2011; billing of the first increase was deferred to January 2011. PSNH’s settlement authorized a $45.5 annualized increase effective July 2010. WMECO filed for a $28.4 rate increase and related relief; a decision was expected by January 2011.
- Major projects include the $457 Merrimack clean-air project, expected to be completed in mid-2012, and transmission expansion projects. The $714 GSRP remained subject to Massachusetts siting approval and a court appeal in Connecticut. Northern Pass was in development; NU’s current share-cost estimate was $675, with construction timing dependent on approvals.
- Key risks include regulatory decisions and cost recovery, weather and demand, storm restoration, capital-market access and interest rates, project permitting and costs, pension obligations, and environmental remediation. A Massachusetts manufactured-gas-plant site had a $1.4 remaining reserve; management said additional costs could be material but could not be reasonably estimated. Other environmental costs were generally expected to be recoverable through rates.
- Credit ratings and outlooks were stable following reaffirmations by Moody’s and S&P. NU planned to renew revolving facilities expiring in November 2010 and expected higher renewal costs. A below-investment-grade downgrade could trigger additional collateral requirements.
Most important facts for investors to verify
- Whether the revised $1.95–$2.05 EPS guidance and projected 6%–9% longer-term growth are achieved, particularly as weather and storm costs normalize.
- Implementation and cash-flow timing of CL&P and PSNH rate increases, and the outcome of WMECO’s rate case.
- Actual capital spending, project approvals, construction costs and schedules for GSRP, Northern Pass and other major programs.
- Renewal terms and costs for the revolving credit facilities, pension funding needs, and any change in credit ratings or collateral requirements.
- Environmental remediation exposure, including whether additional costs arise beyond recorded reserves and whether anticipated regulatory recovery is approved.