IDACORP, Inc. Form 10-Q Summary
Business context and reporting period. This combined, unaudited filing covers the quarter and nine months ended September 30, 2016, with comparisons to 2015. IDACORP is a holding company whose principal operating subsidiary, Idaho Power, is a regulated electric utility serving southern Idaho and eastern Oregon. Unless otherwise noted, amounts below are IDACORP consolidated and are rounded to millions.
Financial performance and position
| Metric | Q3 2016 | Q3 2015 | Nine months 2016 | Nine months 2015 |
|---|---|---|---|---|
| Operating revenue | $372.0m | $369.2m | $968.4m | $984.9m |
| Operating income | $97.9m | $104.7m | $218.7m | $233.5m |
| Net income attributable to IDACORP | $83.1m | $73.3m | $165.1m | $162.8m |
| Diluted EPS | $1.65 | $1.46 | $3.28 | $3.24 |
| Net cash from operating activities | Not separately presented for quarter | $275.4m | $290.8m |
- Third-quarter operating margin was approximately 26.3% versus 28.4% a year earlier; nine-month operating margin was approximately 22.6% versus 23.7%. Nine-month net margin was approximately 17.0% versus 16.5%.
- Nine-month investing cash outflow was $197.5m, primarily reflecting capital spending. Financing cash outflow was $91.9m; cash declined $14.0m to $100.8m.
- At September 30, IDACORP had $1.746bn of long-term debt, $5.4m of commercial paper and $100.8m of cash. Current assets were $459.9m and current liabilities $205.3m. Its covenant leverage ratio was 45%; Idaho Power’s was 47%, against a 65% maximum.
- Idaho Power’s nine-month operating cash flow was $249.8m, down from $260.8m. Its cash balance was $88.9m. The utility issued $120m of 4.05% bonds due 2046 and redeemed $100m of 6.15% bonds early, paying a roughly $14m make-whole premium.
Material changes and drivers
- Q3 IDACORP net income rose $9.8m year over year, while nine-month net income rose $2.3m. Idaho Power’s nine-month net income increased only $0.8m.
- Customer growth supported results: customer count grew 1.8% over the year and added $8.2m to nine-month operating income. Lower usage per customer reduced operating income by $12.2m year to date, reflecting milder summer temperatures and a shorter, later-starting irrigation season.
- Nine-month general business revenue declined $12.5m, and off-system sales revenue declined $6.8m, partly due to lower wholesale prices. Higher PURPA purchase volumes and higher coal costs raised Q3 power supply expenses; year-to-date fuel expense was lower, in part because of stronger spring hydro generation.
- Equity-method investment income increased, principally because Bridger Coal Company realized higher coal sales prices. Management expected those prices to decline in Q4 and BCC income for full-year 2016 to be in line with 2015.
- Lower income tax expense supported earnings. Factors included share-based compensation tax benefits, additional deferred investment tax credit amortization, and affordable-housing investment distributions. Idaho Power recorded $1.5m of additional ADITC amortization through September and estimated $2m for full-year 2016.
- Ten solar power purchase agreements were terminated, reducing Idaho Power’s contractual payment obligations by approximately $267m over their 20-year terms.
Outlook, risks and contingencies
- Management said its outlook remained consistent with the 2015 year-end discussion; this filing provides no clear full-year earnings or EPS guidance. It expected customer growth to continue and approximately $1.5bn of capital expenditures over 2016–2020. Estimated construction spending, excluding AFUDC, was $290–$300m for 2016, $275–$285m for 2017 and $860–$920m for 2018–2020.
- IDACORP’s long-term dividend payout target is 50%–60% of sustainable earnings. In September, the board approved raising the regular quarterly dividend from $0.51 to $0.55 per share. Future dividends remain at board discretion.
- Idaho Power’s Idaho PCA and fixed-cost adjustment mechanisms help manage power-cost volatility and customer-usage effects, but deferred cost recovery can affect cash flow. Regulatory decisions, rate recovery timing, weather and hydrology, wholesale prices, PURPA obligations, and large infrastructure requirements remain important uncertainties.
- Major projects and exposures include Hells Canyon Complex relicensing, with $240m of costs in construction work in progress and estimated annual relicensing costs of $20–$30m until a license is issued; transmission projects with permitting, cost and timing uncertainty; and environmental compliance spending, including potential coal-plant modifications or retirements. Management could not estimate the financial impact of pending environmental requirements.
- Idaho Power filed an application to accelerate depreciation of the North Valmy plant and adjust rates; the requested annualized rate impacts were $28.5m for accelerated depreciation and $6.7m for revised depreciation rates. These were requests, not approved rate increases.
- The Hoku bankruptcy trustee sought recovery of up to approximately $36m from Idaho Power. Following a September 2016 bankruptcy court decision consolidating related cases, Idaho Power considered potential liability remote. Accruals for loss contingencies were not material overall, though future accruals could be material. The companies also cited unresolved western energy proceedings and other ordinary-course litigation.
- Credit downgrade could trigger additional collateral demands; Idaho Power estimated approximately $5.2m of potential collateral exposure under current market conditions. The interim financial statements received an independent accountant review, not an audit.
Important facts for investors to verify
- Whether customer growth, weather-normalized usage and regulatory mechanisms sustain earnings as lower usage and wholesale prices continue to affect revenue.
- Whether Idaho Power can recover planned capital, environmental and relicensing costs in rates on a timely basis, and how regulators rule on pending rate and depreciation requests.
- Actual spending, financing needs and returns on the stated five-year capital program, including the Boardman-to-Hemingway and Gateway West projects.
- Full-year BCC contribution and the extent to which lower coal prices or mining-cost changes affect results after Q3.
- Any developments in the Hoku claim, environmental proceedings, PURPA obligations and other contingencies that could change estimated exposure.
- Dividend sustainability, covenant headroom and liquidity as capital expenditures and pension funding continue.