IDACORP, Inc. — Q2 2011 Form 10-Q
Business context and period. IDACORP is a holding company whose principal business is regulated electric utility Idaho Power, serving approximately 493,000 customers in southern Idaho and eastern Oregon. This unaudited report covers the quarter and six months ended June 30, 2011, with comparisons to 2010; results are seasonal and interim results are not necessarily indicative of the full year.
Financial performance
| Metric | Q2 2011 | Q2 2010 | Six months 2011 | Six months 2010 |
|---|---|---|---|---|
| Operating revenue | $235.0 million | $241.8 million | $486.5 million | $494.7 million |
| Operating income | $34.3 million | $36.6 million | $84.4 million | $70.7 million |
| Net income attributable to IDACORP | $20.9 million | $39.2 million | $50.6 million | $55.3 million |
| Diluted EPS | $0.42 | $0.82 | $1.02 | $1.15 |
- Q2 operating margin, calculated as operating income divided by revenue, was approximately 14.6%, versus 15.1% a year earlier; the six-month margin was approximately 17.4%, versus 14.3%.
- Six-month operating cash flow was $156.9 million, down from $187.2 million. Capital additions were $186.0 million, and financing cash outflow was $144.4 million, including $121.1 million of debt retirement and about $30.0 million of dividends.
- Cash and cash equivalents declined to $58.3 million at June 30 from $228.7 million at year-end 2010. IDACORP reported $1.487 billion of long-term debt and $66.4 million of commercial paper. Its $100 million credit facility had $33.6 million available after commercial paper; Idaho Power’s $300 million facility had $275.8 million available. Leverage ratios were 50% for IDACORP and 51% for Idaho Power, below the 65% covenant limit.
- Dividends declared were $0.30 per share for the quarter and $0.60 per share year to date.
Changes and drivers versus prior periods
- Q2 revenue fell 2.8% and IDACORP-attributable net income declined 46.7%. The six-month revenue decrease was modest, while operating income increased; net income nevertheless fell 8.4%.
- The largest earnings comparison factor was the 2010 tax accounting method change, which generated a substantial tax benefit (about $25 million) that did not recur. 2011 also included $6.8 million of additional accumulated deferred investment tax credit amortization through June, and a $3.4 million tax benefit recognized after resolution of the capitalized-repairs method issue.
- Cool, wet spring conditions reduced Q2 irrigation electricity use by 16.9% and general-business sales volume. Higher first-quarter heating demand partly offset this for the six-month period. Customer growth remained weak: 0.5% over the 12 months ended June 30, versus a 2.7% 20-year average.
- Above-average hydroelectric output and increased wind purchases reduced coal-fired generation and fuel expense, but mandated PURPA purchases increased purchased-power expense. Lower wholesale prices constrained the value of surplus-energy sales.
- Other operations and maintenance expense increased $10.3 million in Q2, primarily from pension costs, thermal plant maintenance and labor-related costs. Bridger Coal Company recorded losses as deliveries to the Bridger plant fell; management expected second-half coal-price adjustments to largely offset current losses.
Outlook, regulation and risks
- Management’s 2011 estimates, as of August 4, were Idaho Power O&M expense of $310–$320 million (raised from $300–$310 million), capital expenditures of $320–$330 million (unchanged), and hydroelectric generation of 9.5–10.5 million MWh (revised from 8.5–10.5 million). Estimated 2011–2013 capital expenditures were $770–$800 million. Management expected minimal external financing in 2011, but anticipated a mix of internal and external funding beyond 2011.
- Idaho Power’s Idaho rate case requests $82.6 million of additional annual base revenue, a 9.9% average increase, and a 10.5% authorized return on equity; any approved rates were expected no earlier than January 1, 2012. Its Oregon filing requests $5.8 million of annual revenue, a 14.7% average increase, with rates expected no earlier than June 1, 2012. Outcomes remain uncertain.
- Effective June 1, 2011, Idaho regulators approved a $40.4 million annual PCA rate decrease and a $3.0 million FCA increase. Power-cost adjustment mechanisms defer most differences between actual and rate-recovered supply costs, so changes can affect cash flow timing as well as customer rates.
- Idaho Power’s 2011 IRP forecasts customer growth of about 1.5% annually through 2030 and identifies transmission constraints. The approximately 300 MW Langley Gulch gas plant was under construction, with commercial operation targeted by June 2012 and total project cost estimated at $427 million. Management said the project remained on schedule and expected cost at or below that estimate.
- Tax outcome remains a significant variable: Joint Committee review of the IRS uniform-capitalization agreement could lead Idaho Power to recognize approximately $60 million of previously unrecognized tax benefits and generate an estimated $4–$6 million of additional annual tax benefit. Timing and approval were uncertain. Management estimated 2011 additional ADITC amortization of about $13.5 million, subject to actual results and possible reversal if the tax benefits are recognized.
- Risks include hydrology and water rights, regulatory cost recovery, weak local economic conditions, fuel and wholesale power prices, required renewable purchases and integration, construction and permitting, environmental rules, and credit or counterparty exposure. A credit downgrade below investment grade could trigger collateral demands; Idaho Power estimated approximately $16 million of additional collateral exposure under the stated scenario.
- Legal contingencies include unresolved Pacific Northwest energy-refund proceedings for which a possible loss could not be estimated; the filing states California refund exposure was materially reduced after FERC dismissed IDACORP and Idaho Power as respondents. Boardman-related environmental matters also remain: a proposed settlement was subject to approval, and the EPA notice of violation carried an operator-estimated maximum penalty of about $60 million, with Idaho Power’s potential share limited to 10% of any assessed amount. The filing reported no material accruals for legal proceedings.
Most important facts for investors to verify
- Progress and final outcomes of Idaho and Oregon rate cases, including timing and approved returns.
- Whether Joint Committee approval produces the anticipated tax benefit, and the resulting treatment of 2011 ADITC amortization and any customer earnings sharing.
- Actual 2011 hydro generation, irrigation demand, wholesale prices and PURPA purchase costs compared with management’s estimates.
- Capital spending, Langley Gulch schedule and cost, transmission-project funding, and the ability to finance the 2011–2013 investment program while maintaining liquidity and covenant compliance.
- Developments in Pacific Northwest refund claims, Boardman environmental proceedings, and water-rights matters, including any changes to currently unestimable exposures.