Entergy Corporation — Q2 2013 Form 10-Q
Business context and period. This combined, unaudited quarterly filing covers the three and six months ended June 30, 2013, with comparative periods in 2012. Entergy operates regulated electric and gas utilities across parts of Arkansas, Louisiana, Mississippi and Texas, alongside Entergy Wholesale Commodities, principally a merchant nuclear-generation business. The filing also includes separate reports for subsidiary registrants.
Financial performance
| Metric | Q2 2013 | Q2 2012 | Six months 2013 | Six months 2012 |
|---|---|---|---|---|
| Operating revenue | $2.738bn | $2.519bn | $5.347bn | $4.902bn |
| Operating income | $346.5m | $343.0m | $740.6m | $286.1m |
| Consolidated net income | $168.1m | $370.6m | $335.0m | $223.8m |
| Net income attributable to Entergy Corporation | $163.7m | $365.0m | $325.1m | $213.3m |
| Diluted EPS | $0.92 | $2.06 | $1.82 | $1.20 |
| Operating cash flow | Not separately presented for quarter | Not separately presented for quarter | $1.116bn | $1.188bn |
- Revenue rose about 9% in both the quarter and half-year. Utility net revenue increased $219m in Q2 and $337m for six months, helped by rate changes, Grand Gulf cost recovery and the absence of 2012 customer-sharing regulatory charges tied to the Louisiana Act 55 tax settlement. Lower sales from weather and usage partly offset gains.
- Wholesale Commodities net revenue fell $61m in Q2 to $383m, mainly from lower nuclear output, outages and weaker energy prices. For six months it declined $19m to $876m; improved realized prices partly offset lower generation. Nuclear fleet capacity factor was 82% versus 85% in Q2 and 82% versus 87% for six months.
- Margins: Calculated operating margin was approximately 12.7% in Q2 2013 versus 13.6% in Q2 2012; for the first half it was 13.9% versus 5.8%. The prior-year half-year comparison includes a $355.5m Vermont Yankee impairment charge ($223.5m after tax), which was not repeated in 2013.
- Cash and cash equivalents were $311m at June 30, down from $533m at year-end 2012. Six-month investing cash outflow was $1.305bn, including $1.245bn of construction/capital expenditures; financing cash outflow was $33m. Cash flow from operations declined $72m year over year, reflecting fuel refunds, outage spending, taxes, storm restoration and ANO costs.
- Debt-to-capital was 59.0% (57.3% excluding non-recourse securitization bonds); net debt-to-net capital excluding those bonds was 56.7%, compared with 55.8% at year-end. The $3.5bn parent credit facility had $3.302bn available; commercial paper outstanding was $948m. Entergy reported compliance with its 65% credit-facility debt-ratio covenant.
- Entergy declared a quarterly common dividend of $0.83 per share, unchanged from 2010.
Material changes, outlook and risks
- Tax-related comparison: Q2 2012 earnings benefited from reversals of uncertain tax provisions following the Louisiana Act 55 IRS settlement and a favorable U.K. windfall-tax decision. Entergy’s Q2 effective tax rate was 30.3% in 2013 versus negative 49.2% in 2012; the unusual prior-period benefit is a major reason reported net income fell year over year. For the first half, 2013’s 36.2% rate compares with negative 120.6% in 2012.
- ANO incident: A lifting apparatus collapse on March 31 killed one contractor and injured others, damaged the turbine building and interrupted both Arkansas Nuclear One units. Unit 2 returned to service April 28; Unit 1 restoration was expected before September 30, 2013. Estimated restoration and related property costs were $95m–$120m, excluding incremental replacement-power costs. Entergy recorded a $50m insurance receivable, while about $14m of O&M costs remained above that receivable at June 30. NEIL asserted a $50m policy sublimit that Entergy disputed; litigation against contractors and others was filed in July.
- Transmission transaction and regulation: Entergy and ITC extended the proposed transmission spin-off/merger agreement to December 31, 2013. FERC approved the transaction under Section 203, but rate-related issues remained for hearing and multiple state staffs or parties raised objections. Texas ALJs recommended denial; the PUCT decision was expected in August 2013. Customer mitigation commitments could change as proceedings continue.
- Restructuring and asset sale: Management expected a new organization design to eliminate about 800 positions, with one-time costs of $145m–$185m, mostly by year-end 2013. In August, Entergy agreed to sell its district-energy business for approximately $130m, subject to adjustments, with closing expected in 2013; its June book value was about $90m.
- Market, plant and operating risks: Merchant nuclear economics remain pressured by low power prices, outage exposure and plant-specific costs. Entergy had contracted 83% of planned nuclear generation for the rest of 2013 and 77% for 2014, at expected average contracted energy prices of about $46/MWh. Indian Point license-renewal and state water/coastal approvals, Vermont Yankee operating approvals, nuclear safety requirements and environmental compliance remain important uncertainties.
- Other material exposures include Hurricane Isaac cost-recovery proceedings, proposed MISO integration, the scheduled 2013/2015 exits of Arkansas and Mississippi from the System Agreement, rate cases, and a pending Texas power-price class-action appeal. A FERC reliability settlement required a $975,000 penalty and mitigation activities. Management said it could not predict legal and regulatory outcomes, but generally did not expect the matters discussed to materially adversely affect results, cash flows or financial condition except as otherwise disclosed.
- No specific full-year earnings guidance is provided in the supplied filing text. Management cautions that utility demand is seasonal, with peak periods in the third quarter, and interim results should not be used as a full-year estimate.
Most important facts for investors to verify
- Whether the transmission spin-off/ITC merger obtains all required approvals, and the final transaction terms, rate treatment and customer mitigation obligations.
- ANO Unit 1 restoration timing, total incident and replacement-power costs, insurance recoveries and litigation outcomes.
- Wholesale nuclear realized prices, outage performance, hedging and collateral needs, and the outlook for Vermont Yankee and Indian Point operations.
- Cash generation, capital spending, debt and commercial-paper levels, and the ability to fund planned investment and restructuring costs while maintaining the dividend.
- Decisions and outcomes in material rate, fuel-cost recovery, storm-cost, MISO/System Agreement and litigation proceedings.