IDACORP, Inc. 10-Q Summary
Reporting period: Quarter and six months ended June 30, 2012. The combined filing covers IDACORP, Inc., a holding company, and its principal operating subsidiary, Idaho Power, a regulated electric utility serving southern Idaho and eastern Oregon. Interim financial statements are unaudited; the independent accountants performed a review, not an audit.
Financial performance and position
| Metric | Q2 2012 | Q2 2011 | Six months 2012 | Six months 2011 |
|---|---|---|---|---|
| Operating revenue | $254.7 million | $235.0 million | $495.8 million | $486.5 million |
| Operating income | $58.8 million | $34.3 million | $101.1 million | $84.4 million |
| Net income attributable to IDACORP | $35.3 million | $20.9 million | $60.2 million | $50.6 million |
| Diluted EPS | $0.71 | $0.42 | $1.21 | $1.02 |
Drivers and margins: Q2 results benefited mainly from higher electricity sales volumes, weather-related irrigation demand, and rate changes; higher income taxes partly offset the gains. Revenue grew about 8% in Q2 and 2% year to date. Operating margin was approximately 23.1% in Q2 versus 14.6%; net income attributable to IDACORP was approximately 13.9% of revenue versus 8.9%. These percentages are calculated from reported amounts.
For the first six months, IDACORP generated $83.0 million of operating cash flow, down from $156.9 million. Capital additions were $123.1 million, compared with $186.0 million. Cash declined to $14.4 million from $27.8 million at year-end 2011. The cash-flow decline reflected, among other items, a $34 million pension contribution, tax-payment timing, and lower cash benefit from power-cost regulatory balances.
At June 30, IDACORP reported $1.537 billion of long-term debt and $64.7 million of commercial paper; equity was $1.696 billion. It issued $150 million of first-mortgage bonds at 2.95% and 4.30%, and used part of the proceeds to redeem $100 million of bonds due in November 2012. The companies reported leverage ratios of 49% for IDACORP and 50% for Idaho Power, within the 65% covenant limit. No loans were outstanding under either revolving credit facility; reported net available facility capacity was $70.3 million for IDACORP and $265.8 million for Idaho Power. IDACORP declared dividends of $0.33 per share for the quarter.
Material changes and business developments
- General business electricity sales volume rose 14% in Q2, led by irrigation usage that nearly doubled; six-month usage rose 6%. Total customers increased about 1% year over year.
- Hydroelectric generation declined 15.5% in the first half, and purchased power increased 29% to $79.5 million. Off-system sales revenue fell 23% year to date as higher customer load and lower hydro generation reduced surplus sales. Power-cost adjustment mechanisms defer or recover most power-supply cost fluctuations from customers, though timing affects cash flow.
- Idaho approved a $34 million annual base-rate increase effective January 2012. Additional annual rate changes included a $43 million Idaho power-cost adjustment increase and $27.1 million revenue-sharing decrease, for a net $15.9 million rate increase for the June 2012–May 2013 period. Idaho also approved a $58.1 million annual rate increase for the Langley Gulch plant, effective July 1, 2012. Oregon approved a $1.8 million annual general-rate increase effective March 2012.
- Langley Gulch, a roughly 300 MW natural-gas plant, entered commercial service June 29. Idaho Power reported approximately $395 million of project expenditures through June 2012, including AFUDC.
- Three power-purchase agreements were terminated following counterparty breaches, reducing Idaho Power’s contractual payment obligations by approximately $217 million over the contracts’ 15- to 25-year terms.
Outlook, risks and contingencies
2012 estimates: Idaho Power retained its O&M expense estimate at $325–$335 million, narrowed capital expenditure guidance to $230–$235 million, and estimated hydroelectric generation of 7.5–8.5 million MWh. IDACORP estimated non-regulated subsidiary earnings and holding-company expenses together at $0–$3 million. Management did not expect to use additional ADITC amortization in 2012. Estimated capital expenditures for 2012–2014 were $720–$735 million.
Management cited improved local economic indicators and customer growth, but expected growth below the 20-year historical average. Hydro conditions, weather-driven demand, fuel and wholesale power prices, regulatory cost recovery, infrastructure spending, and environmental compliance remain important uncertainties. Management noted that future environmental compliance investment could be significant, but the filing did not provide a clear estimate of its financial impact. The Boardman coal unit is scheduled to cease coal operations by 2020; proposed and pending air rules may affect costs or plant operations. The Boardman-to-Hemingway transmission project’s in-service date before 2018 was considered unlikely.
Idaho Power contributed $34 million to its pension plan in the first half and expected significant contributions in future years; federal legislation enacted in July 2012 was expected to reduce minimum required contributions in at least the next few years. Hoku Materials’ service was terminated in May after missed payments. Idaho Power estimated 2012 revenue from Hoku at $6.6 million, down from a prior expectation of $12.2 million, and anticipated a relatively small net-income impact after cost and regulatory mechanisms.
Unresolved contingencies include Pacific Northwest electricity-refund proceedings; the companies could not estimate reasonably possible losses. Idaho Power also faces water-rights, hydroelectric relicensing, PURPA contract, and environmental regulatory risks. A downgrade below investment grade could prompt collateral demands; management estimated approximately $12 million of additional collateral exposure under then-current conditions. The filing reported no material change to previously disclosed risk factors.
Important facts for investors to verify
- Whether higher Q2 earnings persist when irrigation demand, weather, hydro generation, and off-system sales normalize.
- Progress in recovering Langley Gulch costs in Oregon and the effect of Idaho’s rate and power-cost adjustment mechanisms.
- Actual 2012 capital expenditures, hydroelectric generation, pension contributions, and cash-flow performance against guidance.
- Developments in Hoku collection or legal remedies, FERC refund proceedings, PURPA contracts, and environmental compliance requirements.
- Debt and liquidity headroom, refinancing needs, credit ratings, collateral exposure, and compliance with dividend and leverage covenants.