IDACORP, Inc. — FY 2012 Form 10-K
Reporting period: Year ended December 31, 2012; filed February 21, 2013. This is a combined filing for IDACORP and its principal operating subsidiary, Idaho Power. IDACORP is a holding company whose results are driven primarily by Idaho Power, a regulated electric utility serving southern Idaho and eastern Oregon. The filing includes quarterly data, but the summary below focuses on the full fiscal year.
Financial performance and position
| Metric | 2012 | 2011 | Change / context |
|---|---|---|---|
| IDACORP operating revenue | $1,080.7 million | $1,026.8 million | Up 5.3% |
| Operating income | $242.6 million | $155.4 million | Up $87.3 million |
| Net income attributable to IDACORP | $168.8 million | $166.7 million | Up 1.2% |
| Diluted EPS | $3.37 | $3.36 | Up $0.01 |
| Net cash from operating activities | $249.3 million | $310.2 million | Down $61.0 million |
| Construction expenditures | $239.8 million | $337.8 million | Lower as Langley Gulch construction neared completion |
| Long-term debt, including current portion | $1,537.7 million | $1,488.6 million | Up $49.1 million |
IDACORP’s 2012 effective tax rate was 13.4%, versus a 45.5% tax benefit rate in 2011, when tax benefits and IRS examination settlements included $56.9 million of previously unrecognized benefits. Cash and equivalents were $26.5 million at year-end. Credit-facility leverage ratios were 48% for IDACORP and 49% for Idaho Power, below the 65% covenant limit. At year-end, unused short-term credit availability was $55.3 million for IDACORP and $275.8 million for Idaho Power; IDACORP also had $69.7 million of commercial paper outstanding.
Material changes versus 2011
- Rate changes increased operating income, including Idaho rate increases effective January 2012 and recovery of the Langley Gulch plant investment beginning July 2012. Higher irrigation usage also supported results.
- Idaho Power’s operating income rose $86.3 million before other items, but 2011’s favorable tax-method change and IRS settlement effects substantially offset the improvement at the net-income level.
- Idaho Power recorded $21.8 million of 2012 customer-sharing impacts: $7.2 million as a revenue reduction and $14.6 million as additional pension expense. Comparable 2011 sharing impacts were $47.4 million.
- Hydroelectric generation fell to 8.0 million MWh from 10.9 million MWh in 2011 due to weaker water conditions. Purchased power expense increased 21% to $196.9 million, and fuel expense rose 21% to $159.4 million. Power-cost adjustment mechanisms defer or recover much, but not all, of the related cost variability.
- General business sales increased to 14.1 million MWh, mainly on stronger irrigation use, while off-system sales revenue fell 39% to $61.5 million as lower hydro output reduced surplus power.
- Operating cash flow declined amid larger pension contributions and changes in power-cost adjustment balances. Idaho Power contributed $44.3 million to its pension plan in 2012, versus $18.5 million in 2011.
Outlook, commentary, risks, and unusual items
- 2013 estimates: Idaho Power forecast O&M expense of $340–$350 million, capital expenditures of $245–$255 million excluding AFUDC, hydroelectric generation of 6.0–8.0 million MWh, and less than $5 million of additional ADITC amortization. Total estimated capital expenditures for 2013–2015 were $815–$835 million.
- Management’s preliminary 2013 resource planning projected slower load growth than in the prior plan and, under one scenario, no peak-hour capacity deficit before summer 2016. The 2013 integrated resource plan was expected in June 2013. The Boardman-to-Hemingway transmission line was not expected in service before 2018.
- Management emphasized cost control, liquidity and credit-rating maintenance, expense management, transmission-project permitting, the new customer billing system, and Hells Canyon Complex relicensing. It expected to consider a further dividend increase; management anticipated recommending at least a 10% quarterly increase in September 2013, subject to board discretion.
- Key risks include regulatory decisions that limit or delay cost recovery; variable river flows and water-right disputes; fuel and wholesale-power costs; mandated PURPA purchases and intermittent-resource integration; environmental compliance and coal-plant investment; transmission-project permitting, cost, and schedule; pension funding; and financing or credit-rating changes.
- Environmental compliance estimates included $120 million for Idaho Power’s share of SCR controls at Jim Bridger Units 3 and 4, excluding AFUDC. Hells Canyon relicensing requirements and costs remained uncertain; $161 million of related costs was in construction work in progress at year-end. Idaho Power reported $1.2 billion of regulatory assets, whose recovery depends on continued regulatory approval.
- Idaho Power guaranteed $66 million of its share of Bridger Coal Company reclamation obligations; the associated trust held $72 million at year-end. The filing said loss-contingency accruals were not material overall, while noting outcomes and possible future accruals remain uncertain.
- The filing corrected classification of certain IDACORP operating expenses in the 2011 and 2010 income statements; the correction did not affect previously reported net income, cash flows, or equity. The auditors issued unqualified opinions on the financial statements and internal controls.
Most important facts for investors to verify
- Whether actual hydroelectric generation and water conditions in 2013 fell within management’s 6.0–8.0 million MWh estimate, and how that affected purchases, PCA deferrals, and cash flow.
- Progress and final cost-recovery treatment for the Boardman-to-Hemingway and Gateway West transmission projects, and for Hells Canyon relicensing and coal-plant environmental controls.
- Whether Idaho Power maintained earnings and customer-sharing outcomes under the Idaho settlement mechanisms, and whether regulatory asset recovery remained probable.
- Future pension contributions and expense, including the effect of lower discount-rate assumptions and the timing of recovery through customer rates.
- Whether the company met its 2013 expense, capital-spending, load/resource, and dividend expectations; the dividend remains subject to board approval and restrictions.