IDACORP, Inc. — Q3 2017 Form 10-Q
Business context and reporting period. This combined, unaudited quarterly filing covers IDACORP, Inc. and its principal operating subsidiary, Idaho Power Company, for the quarter and nine months ended September 30, 2017. Idaho Power is a regulated electric utility serving southern Idaho and eastern Oregon; its results are seasonal, with peak sales generally in summer. The interim financial statements received an independent accountant review, not an audit.
Key financial results
| IDACORP consolidated | Q3 2017 | Q3 2016 | 9M 2017 | 9M 2016 |
|---|---|---|---|---|
| Operating revenue | $408.3m | $372.0m | $1,043.9m | $968.4m |
| Operating income | $120.9m | $97.9m | $250.8m | $218.7m |
| Net income attributable to IDACORP | $90.6m | $83.1m | $173.6m | $165.1m |
| Diluted EPS | $1.80 | $1.65 | $3.44 | $3.28 |
| Operating margin | 29.6% | 26.3% | 24.0% | 22.6% |
For the nine months, IDACORP generated $348.8m of operating cash flow, used $198.8m in investing activities, and used $107.1m in financing activities. Cash and equivalents were $104.4m at September 30, up from $61.5m at year-end 2016. Capital expenditures were approximately $207m. Long-term debt was $1.746bn; including $2.4m of commercial paper, debt was approximately $1.748bn. Total equity was $2.252bn. Covenant leverage was 44% for IDACORP and 46% for Idaho Power, below the 65% limit. IDACORP declared dividends of $0.55 per share for Q3 and $1.65 year to date.
Changes and operating drivers
- Q3 IDACORP-attributable net income rose $7.5m; nine-month income rose $8.5m. Increased customer usage and growth, rate changes, and higher transmission-related revenue supported results. Customer count grew 1.8% year over year; Q3 general business sales volumes increased 7%.
- Warmer summer and colder winter weather boosted residential use, while wetter conditions reduced irrigation use. The fixed-cost adjustment mechanism partly offset higher customer usage.
- Hydroelectric generation rose 38% for the first nine months, contributing to lower fuel expense and higher off-system sales volumes. However, abundant regional supply reduced wholesale prices: average off-system sales prices fell about 28% year over year for the nine months.
- Valmy settlement stipulations increased Idaho and Oregon revenue collections and accelerated depreciation. They added $3.8m to after-tax income in the first nine months; management estimated a full-year 2017 benefit of approximately $5.2m. Lower income from the Bridger Coal Company investment partly offset utility operating gains.
- Operating cash flow increased from the prior-year period, with regulatory account changes and timing of tax payments and working capital among the cited factors. Nine-month capital investment remained substantial.
Outlook, risks, and notable items
- Management said its outlook remained consistent with its prior annual report. It expected positive customer growth and approximately $1.5bn of capital expenditures over 2017–2021, including $290–300m in 2017. Management believed available cash, operating cash flow, credit facilities, and capital-market access would meet requirements for at least the next 12 months.
- Management forecast 2017 hydroelectric generation of 8.5–9.0 million MWh. This depends on water conditions; weather and hydrology can materially affect customer demand, generation mix, and wholesale prices.
- The 2017 resource plan anticipates Boardman-to-Hemingway transmission completion by 2026, exit from Valmy coal operations by 2019 for Unit 1 and 2025 for Unit 2, and early retirement of Jim Bridger Units 1 and 2 in 2032 and 2028. Project timing, resource costs, regulation, and operating economics remain uncertain.
- Major risks include regulatory decisions and timely recovery of capital and operating costs; environmental compliance and potential plant retirements; Hells Canyon Complex relicensing and water-right matters; commodity prices, power availability, and counterparty or credit risks. Hells Canyon relicensing costs of $269m were in construction work in progress, and the timing, license terms, and ultimate costs were undetermined.
- New solar, biomass, and hydro PURPA contracts added approximately $85m of contractual payment obligations over 20 years. Idaho Power’s $57m share of Bridger Coal reclamation obligations was supported by a $97m trust fund; management considered the guarantee’s estimated fair value minimal.
- Loss-contingency accruals were not material at filing, and the companies said ordinary-course proceedings were not expected to have a material adverse effect. Future environmental costs and some litigation outcomes could not be estimated clearly.
- The companies planned to adopt the new revenue standard in 2018 using the modified-retrospective method, expecting presentation and disclosure changes but no change to revenue timing or amount. The dollar impact of the lease standard was still under evaluation.
Important facts for investors to verify
- Whether weather-driven sales, customer growth, and higher rates persist, and how the fixed-cost adjustment affects future revenue.
- Whether the forecast hydroelectric output and wholesale power prices materialize, and how power-cost adjustment mechanisms affect cash-flow timing.
- Actual capital spending, project permitting and completion schedules, and timely regulatory recovery of investment.
- The continuing earnings effect of the Valmy settlements, and the outcome and cost of Hells Canyon relicensing and other environmental matters.
- Debt-market access, covenant headroom, pension funding, and the ability to sustain dividends while funding the capital program.