IDACORP, Inc. — Form 10-Q Summary
Reporting period: Quarter and nine months ended September 30, 2012. Filed November 1, 2012. The combined filing covers IDACORP, Inc. and its principal operating subsidiary, Idaho Power Company. Financial statements are unaudited; the independent accountant performed an interim review, not an audit.
Financial performance
Amounts are in millions of dollars except per-share data. IDACORP’s results are principally driven by Idaho Power’s regulated electric utility operations.
| Metric | Q3 2012 | Q3 2011 | 9M 2012 | 9M 2011 |
|---|---|---|---|---|
| Operating revenue | $334.0 | $309.6 | $829.9 | $796.1 |
| Operating income | $111.3 | $71.4 | $212.5 | $155.8 |
| Net income attributable to IDACORP | $92.1 | $107.1 | $152.3 | $157.7 |
| Diluted EPS | $1.84 | $2.16 | $3.05 | $3.19 |
Operating margin, calculated as operating income divided by revenue, was approximately 33.3% in Q3 2012 versus 23.0% in Q3 2011, and 25.6% for the first nine months versus 19.6%. Net income attributable to IDACORP fell despite stronger operating income, in large part because the prior-year comparison included a $56.9 million tax benefit from an IRS examination settlement. 2012 results included a $7.8 million tax benefit from a tax accounting method change.
Key operating drivers: General business revenue increased $53.8 million in Q3 and $74.1 million year to date, reflecting rate changes and customer demand. Lower hydroelectric generation and higher system load reduced off-system sales revenue by $19.3 million in Q3 and $30.7 million year to date. For the first nine months, hydro generation was down 24% year over year; general business electricity sales volume rose about 4%.
Cash flow, debt and liquidity
- For the first nine months, operating cash flow was $181.5 million, down from $234.9 million. Utility plant additions were $187.8 million, compared with $267.0 million in 2011; cash flow after these additions was negative $6.3 million.
- Cash and cash equivalents were $20.2 million at September 30, 2012. IDACORP had $51.4 million of commercial paper outstanding; Idaho Power had none. No loans were outstanding under either company’s credit facility.
- IDACORP reported $1.537 billion of long-term debt and $51.4 million of notes payable. Its quarter-end leverage ratio was 47%; Idaho Power’s was 49%, compared with a 65% covenant maximum. Both companies reported compliance with covenants.
- Net available capacity under credit facilities at September 30 was $73.6 million for IDACORP and $275.8 million for Idaho Power. Credit-facility maturities were extended to October 26, 2017, in October 2012.
- Idaho Power issued $150 million of first mortgage bonds in April and used part of the proceeds to redeem $100 million of bonds due in November 2012. The quarterly IDACORP dividend was increased to $0.33 per share during 2012; a further increase to $0.38 was declared for payment beginning November 30, 2012.
Material changes and notable items
- Rate increases approved in Idaho and Oregon, including recovery of the Langley Gulch plant, supported revenue and operating income. The Langley Gulch plant entered commercial service June 29, 2012; Idaho and Oregon annual rate increases were $58.1 million and approximately $3.0 million, respectively.
- In Q3, Idaho Power recorded $12.1 million under its earnings-sharing arrangement: a $6.3 million provision against revenue for a future customer rate reduction and $5.8 million of additional pension expense. The comparable Q3 2011 revenue-sharing provision was $18.1 million.
- Fuel expense rose $14.8 million in Q3, partly because of operation of Langley Gulch and greater thermal generation. Purchased-power expense rose $5.4 million in Q3 and $23.4 million year to date, including increased PURPA purchases. Most power-supply cost fluctuations are subject to regulatory deferral and recovery or refund through PCA mechanisms.
- Nine power purchase agreements were terminated, reducing Idaho Power’s contractual payment obligations by approximately $736 million over the contracts’ 15-to-25-year terms.
- Idaho Power contributed $44.3 million to its defined-benefit pension plan in the first nine months, versus $18.5 million in the comparable 2011 period. Management said further significant contributions are expected in coming years.
Outlook, risks and contingencies
- 2012 estimates as of November 1: Idaho Power O&M expense of $335–$345 million; hydroelectric generation of 7.8–8.2 million MWh; capital expenditures of $230–$235 million for 2012, including year-to-date spending; no additional ADITC amortization expected. The filing does not provide a specific full-year EPS or net-income forecast.
- Management cited improving local economic indicators and 1.1% customer growth over the 12 months ended September 30, but noted that economic recovery, load growth, weather and agricultural conditions remain uncertain. Management estimated 2012 hydro generation below 2011’s 10.9 million MWh and below the 8.6 million MWh median.
- Major risks include water availability and hydro generation, fuel and wholesale power prices, mandated and intermittent PURPA purchases, regulatory cost recovery, environmental compliance, project permitting and construction, pension funding, access to capital, and counterparty or credit-rating risks.
- Transmission projects remain subject to permitting, regulatory approval, cost and timing uncertainty. Management considered a Boardman-to-Hemingway in-service date before 2018 unlikely. Environmental rules could require significant capital spending; their financial impact was not yet determinable.
- Known direct claims in Pacific Northwest refund proceedings were settled for amounts not material to the companies. Potential “ripple claims” remain, but FERC characterized their likelihood as speculative; no amount remained accrued for these proceedings. Other loss-contingency accruals were not material in aggregate, though future accruals could be material in a period.
- Idaho Power reported $156 million of Hells Canyon Complex relicensing costs in construction work in progress. The filing also describes water-rights, coal-plant environmental, and regulatory proceedings whose outcomes or costs may be uncertain.
Important facts for investors to verify
- How much of the operating-income improvement is sustainable after rate changes, regulatory deferrals and customer-sharing mechanisms?
- Whether full-year earnings and cash generation meet management’s assumptions, given the tax-benefit comparison, pension cash contributions and seasonal utility demand.
- Actual hydroelectric generation and the resulting need for fuel, purchased power and PCA recovery or refunds.
- Timing, final cost, permitting and rate-recovery support for Langley Gulch and major transmission projects, especially Boardman-to-Hemingway and Gateway West.
- Potential costs and rate recovery from environmental requirements, PURPA contract obligations, pension funding, and unresolved regulatory or legal proceedings.
- Available liquidity and debt capacity, including any changes to commercial-paper usage, credit ratings, covenant headroom or dividend plans.