IDACORP, Inc. — Q1 2017 Form 10-Q
Reporting period: Three months ended March 31, 2017; unaudited. IDACORP is a holding company whose principal operating subsidiary is Idaho Power, a regulated electric utility serving southern Idaho and eastern Oregon. Results are seasonal and the quarter is not necessarily indicative of full-year performance.
Financial results
Unless otherwise stated, amounts are IDACORP consolidated and in U.S. dollars. Percentage changes are calculated from reported figures.
| Metric | Q1 2017 | Q1 2016 | Change |
|---|---|---|---|
| Operating revenue | $302.5 million | $281.0 million | +7.7% |
| Operating income | $50.8 million | $43.8 million | +16.0% |
| Net income attributable to IDACORP | $33.1 million | $25.7 million | +28.7% |
| Diluted EPS | $0.66 | $0.51 | +29.4% |
| Operating margin | 16.8% | 15.6% | +1.2 percentage points |
| Net margin attributable to IDACORP | 10.9% | 9.2% | +1.8 percentage points |
| Operating cash flow | $113.7 million | $66.2 million | +$47.5 million |
| Capital expenditures | $73.9 million | $54.7 million | +$19.2 million |
- Cash and cash equivalents were $47.0 million at March 31, down from $61.5 million at December 31, 2016. Long-term debt was $1.745 billion; no short-term borrowings were outstanding at quarter-end. IDACORP’s and Idaho Power’s covenant leverage ratios were 45% and 47%, respectively, below the 65% limit.
- Unused revolving credit facilities were $100 million for IDACORP and $275.8 million net available for Idaho Power at March 31. Management said available cash, operating cash flow, credit facilities, and debt-market access should fund requirements for at least the next 12 months.
- Dividends declared were $0.55 per share, versus $0.51 a year earlier. Operating cash flow less capital expenditures was approximately $39.8 million, compared with $11.5 million in Q1 2016.
- Regulatory assets totaled $1.367 billion at March 31. These balances reflect regulated cost recovery and may be collected from customers in future periods.
Material changes and drivers
- Higher customer usage was the largest earnings driver: colder weather increased heating demand, and general business sales volume rose 8% to 3.408 million MWh. Customer count grew 1.9% year over year.
- Higher usage contributed $9.1 million to Idaho Power operating income, but the fixed cost adjustment reduced revenue by $6.1 million versus Q1 2016. Increased customer count contributed $2.7 million to operating income; a new wheeling agreement and higher transmission tariff rates also supported revenue.
- Hydroelectric generation rose to 2.362 million MWh from 1.847 million MWh, with greater precipitation. Off-system sales volume increased 49%, but average revenue per MWh fell 21% as regional supply increased and wholesale prices declined.
- Power cost adjustment expense increased to $23.5 million from $13.4 million. Other operations and maintenance expense increased $2.2 million; depreciation rose $1.1 million. Idaho Power’s regulatory mechanisms defer or recover much of the fluctuation in power supply costs, though timing affects cash flows.
- Cash from operations improved partly due to regulatory asset and liability changes, higher distributions from the Bridger Coal joint venture, and tax-related working-capital movements. Capital spending increased as infrastructure investment continued.
Outlook, risks, and contingencies
- Management’s outlook remained consistent with its 2016 year-end discussion. It expects approximately $1.5 billion in capital expenditures over 2017–2021; the filing estimates $290–$300 million for 2017. Management expects 2017 hydroelectric generation of 8–10 million MWh, compared with a 20-year average of 7.6 million MWh.
- Idaho Power filed for a $10.6 million net Idaho power-cost-adjustment rate increase and a $6.9 million fixed-cost-adjustment increase, both pending at the filing date. These rate mechanisms primarily address cost recovery and do not necessarily translate dollar-for-dollar into earnings.
- After quarter-end, Idaho Power filed an IPUC settlement stipulation proposing a $13.3 million Idaho revenue-requirement increase for accelerated depreciation of the North Valmy plant, with coal operations assumed to cease at unit 1 in 2019 and unit 2 in 2025. Regulatory approval was pending. A separate depreciation settlement was proposed with no required Idaho revenue increase.
- Key uncertainties include regulatory decisions and timely recovery of capital and operating costs; drought, hydroelectric output and wholesale power prices; PURPA and other purchased-power costs; environmental compliance and potential plant retirements; and permitting, cost, and timing of major transmission projects.
- Hells Canyon Complex relicensing costs of $256 million were included in construction work in progress. Idaho Power said it could not predict the timing or requirements of a new license; estimated annual relicensing costs were $25–$35 million until issuance, excluding post-license compliance costs. Idaho and Oregon had withdrawn water-quality certification applications while the states continued discussions.
- Gateway West permitting faced further uncertainty: in April 2017, the Interior Board of Land Appeals set aside the BLM decision for two line segments and remanded the matter. The Boardman-to-Hemingway project remained subject to permitting, with an in-service date not expected before 2024.
- A new biomass PURPA contract added approximately $25 million of contractual payments over 20 years. Idaho Power also planned $20–$40 million of pension contributions during 2017. The Bridger Coal reclamation guarantee was $71 million, supported by an $85 million trust fund.
- Management said legal and regulatory loss-contingency accruals were not material at the report date and believed resolution of existing matters would not materially adversely affect the companies. Environmental regulation impacts remained difficult to estimate. The interim financial statements received a review, not an audit, from Deloitte.
Investor verification priorities
- Confirm the outcome and timing of the pending PCA, FCA, Valmy, and depreciation proceedings, and how resulting rates affect cash recovery and earnings.
- Track actual hydroelectric generation, power-supply costs, wholesale sales prices, and customer growth against management’s assumptions.
- Compare capital spending and financing needs with the five-year investment plan; monitor debt levels, credit access, covenant headroom, and dividend capacity.
- Follow Hells Canyon relicensing and water-quality certification, Gateway West and Boardman-to-Hemingway permitting, and environmental decisions affecting coal generation.
- Assess whether regulatory assets and deferred power costs remain recoverable on expected schedules, and verify pension funding and PURPA contract commitments.