IDACORP INC quarterly report, Q3 FY2011

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IDACORP, Inc. — Form 10-Q Summary

Reporting period: Quarter and nine months ended September 30, 2011. The combined filing covers IDACORP and its principal operating subsidiary, Idaho Power, a regulated electric utility serving southern Idaho and eastern Oregon. Financial figures below are for IDACORP unless otherwise noted; dollars are in millions except per-share amounts.

Financial performance and position

  • Third-quarter revenue: $309.6, essentially unchanged from $309.4 a year earlier. Net income attributable to IDACORP was $107.1 versus $67.1; diluted EPS was $2.16 versus $1.39.
  • Nine-month revenue: $796.1 versus $804.1. Net income attributable to IDACORP was $157.7 versus $122.4; diluted EPS was $3.19 versus $2.55.
  • Operating income: Third-quarter operating income fell to $71.4 from $89.0; nine-month operating income was $155.8 versus $159.6. Calculated operating margin was approximately 23.1% for the quarter (28.8% in 2010) and 19.6% year to date (19.9% in 2010).
  • Tax and earnings quality: The third-quarter income tax benefit was $45.4, including recognition of $56.9 of previously unrecognized tax benefits after IRS/JCT approval of a tax accounting method settlement. This nonrecurring item materially boosted reported earnings.
  • Cash flow and investment: Nine-month operating cash flow was $234.9, compared with $222.5 in 2010. Capital additions were $267.0, versus $249.4; operating cash flow less capital additions was negative by approximately $32.1. Cash declined to $31.3 at September 30 from $228.7 at year-end 2010.
  • Debt and liquidity: Long-term debt was $1,487.5, with $51.5 of commercial paper outstanding. IDACORP’s current liabilities were $254.5 and current assets $309.3. Leverage covenant ratios were 48% for IDACORP and 50% for Idaho Power, below the 65% limit. New revolving credit agreements entered into October 26, 2011 provide $125 of capacity for IDACORP and $300 for Idaho Power; neither had borrowings under its facility at September 30.
  • Dividends: $0.30 per share declared in the quarter and $0.90 for the nine months, unchanged from 2010 periods.

Material changes and operating drivers

  • Tax settlement benefits lifted earnings, while an $18.1 regulatory liability reduced third-quarter revenue to reflect the sharing with Idaho customers of estimated earnings above the 10.5% return threshold under a prior settlement. The company also reversed $6.8 of additional deferred investment tax credit amortization.
  • Favorable water conditions drove hydroelectric generation to 8.683 million MWh year to date, versus 5.887 million in 2010. Management expected full-year hydro generation of 11.0–11.5 million MWh, compared with 7.3 million in 2010.
  • Higher hydro generation reduced thermal generation and fuel expense, but purchased power expense rose due largely to increased purchases under PURPA contracts. Lower regional wholesale prices reduced average off-system sale prices by 37% in the quarter and 33% year to date, despite higher sales volumes.
  • Operating and maintenance expense increased $12.6 in the quarter and $21.5 year to date, principally from labor, pension, and plant maintenance costs. Idaho Power’s customer growth remained modest: 0.7% for the 12 months ended September 30, versus a 20-year average of 2.7%.

Outlook, regulation, and risks

  • Idaho rates: A settlement stipulation, pending IPUC approval, would raise annual Idaho base-rate revenue by $34.0, or 4.07%, effective January 1, 2012. It provides for a 7.86% authorized return and shifts specified PURPA power costs to the Idaho PCA mechanism. Approval and final terms were uncertain at filing.
  • Other rate cases: Idaho Power requested a $5.8 annual Oregon revenue increase, with any approved new rates anticipated no earlier than June 1, 2012. It also sought extension of prior Idaho settlement provisions; approval could trigger an additional estimated fourth-quarter 2011 pre-tax customer-sharing charge of about $10.
  • 2011 estimates: Management reported no change to estimated Idaho Power O&M expense of $310–$320 and capital expenditures of $320–$330. Estimated hydro generation was revised to 11.0–11.5 million MWh. The company expected total capital expenditures of $770–$800 from 2011 through 2013.
  • Projects and funding: The $427 Langley Gulch natural-gas plant was under construction, with $321 incurred through September 30; management expected it to be in service by June 2012 and at or below the commitment estimate. Heavy infrastructure spending means operating cash flow may not fully fund capital needs; the company expects to use internal cash and external financing.
  • Material risks and contingencies: Key exposures include regulatory cost recovery, drought and water rights, fuel and wholesale power prices, mandated intermittent generation, environmental compliance, and construction costs. A FERC Pacific Northwest refund proceeding remains unresolved and the possible loss could not be estimated. An EPA notice concerning Boardman also remains unresolved; Idaho Power’s 10% share of any penalty was not estimable. Two wind projects appealed the rejection of 13 power purchase agreements, which had represented about $1.3 billion of expected lifetime payments.
  • Unusual items: The Boardman plant is scheduled to cease coal operations by the end of 2020; Idaho Power estimated its share of required emissions-control capital costs at $6.0. Pension funding, hydroelectric relicensing, and transmission projects also entail substantial ongoing cash requirements.

Investor verification priorities

  1. Separate recurring operating performance from the $56.9 tax benefit and assess the resulting tax rate and EPS quality.
  2. Check the IPUC’s final decision on the Idaho rate settlement and the proposed extension of earnings-sharing and tax-credit provisions, including any fourth-quarter charge.
  3. Monitor actual hydro generation, wholesale prices, and PURPA purchase costs against management’s outlook and their effects on cash flow and customer rates.
  4. Review capital spending, cash balances, commercial-paper use, debt maturities, and access to the renewed credit facilities.
  5. Track outcomes of the FERC refund matter, Boardman environmental proceedings, wind-contract appeals, water-rights proceedings, and major construction plans.