IDACORP, Inc. — Q1 2022 Form 10-Q
Business context and period. The filing covers the three months ended March 31, 2022, compared with Q1 2021; balance-sheet figures are compared with December 31, 2021. IDACORP is a holding company whose principal operating subsidiary, Idaho Power, is a regulated electric utility serving southern Idaho and eastern Oregon. Results are seasonal and Q1 is not necessarily indicative of full-year performance. Dollar amounts below are in millions unless stated otherwise.
Financial performance and position
| Metric | Q1 2022 | Q1 2021 / prior date |
|---|---|---|
| IDACORP operating revenue | $344.3 | $316.1 |
| Operating income | $60.7 | $61.1 |
| Net income attributable to IDACORP | $46.3 | $44.8 |
| Diluted earnings per share | $0.91 | $0.89 |
| Operating margin | 17.6% | 19.3% |
| Net margin attributable to IDACORP | 13.4% | 14.2% |
| Operating cash flow | $93.0 | $83.7 |
| Cash and cash equivalents | $218.6 | $215.2 at Dec. 31, 2021 |
| Long-term debt | $2,050.6 | $2,000.6 at Dec. 31, 2021 |
| Total equity | $2,684.2 | $2,675.2 at Dec. 31, 2021 |
Revenue rose 8.9% year over year, while IDACORP net income increased 3.2% and diluted EPS increased by $0.02. Operating income edged down despite revenue growth, with higher purchased power, fuel, and O&M costs. Operating cash flow less property and equipment additions was approximately negative $9.5 million; the company also paid $38.4 million in common dividends and drew $50 million under Idaho Power’s new term loan facility.
At March 31, IDACORP’s current assets were $611.9 million and current liabilities were $327.6 million. Its covenant leverage ratio was 43%; Idaho Power’s was 45%, against a 65% maximum. Idaho Power had $275.8 million of net revolving-credit availability, plus $100 million remaining on its $150 million delayed-draw term facility, available through May 31, 2022. Management stated it expects available cash, operating cash flow, credit facilities, commercial paper, and debt-market access to cover requirements for at least the next 12 months.
Material changes and operating drivers
- Customer growth and higher usage supported earnings: Idaho Power’s customer count grew 2.6% over 12 months; retail sales volume increased 8%. Management attributed higher usage to colder weather and increased commercial and industrial activity.
- Hydropower generation fell 11% and natural-gas generation fell 28%; coal generation increased 53%, while purchased power volume rose 28%. Purchased-power expense increased $17.4 million and fuel expense increased $12.4 million.
- Higher sales and customer usage reduced Idaho fixed-cost adjustment revenues by $5.9 million versus Q1 2021. Transmission wheeling revenue rose $2.0 million, partly reflecting new agreements and higher tariff rates.
- Other O&M expense increased $6.4 million, reflecting a planned Langley Gulch maintenance project, inflationary cost pressures, and a return from unusually low prior-year costs.
- Capital spending remains substantial: Idaho Power reported $99 million of construction expenditures, excluding allowance for funds used during construction, in Q1. Its forecast for 2022–2026 is up to $2.8 billion overall; estimated additions to electric plant are $480–$500 million in 2022, $690–$715 million in 2023, and $1.45–$1.55 billion in 2024–2026.
Outlook, regulatory matters, and risks
- Management’s strategy and outlook were described as consistent with the 2021 Annual Report. It expects continued customer growth and targets 100% clean energy by 2045; the filing does not provide a specific full-year 2022 earnings or EPS forecast.
- Given low reservoir carryover and below-normal snowpack, Idaho Power expects 2022 hydropower generation of 5.0–6.5 million MWh, versus a 30-year average of about 7.7 million MWh. The company cited higher market energy and natural-gas prices as well as supply constraints and inflation as operating and project-cost pressures.
- An April 2022 Idaho filing seeks a $103.4 million net increase in power-cost-adjustment revenues for the June 2022–May 2023 period; approval was pending at the report date. A separate Idaho fixed-cost adjustment filing requests a $3.1 million decrease. The amended Jim Bridger rate case seeks $27.1 million of annual revenue recovery and also remained pending.
- Idaho Power identifies projected peak-capacity deficits in 2023–2025. It has contracted for 120 MW of battery storage and a 20-year agreement for output from a planned 40-MW solar facility; regulatory approvals and procurement for further capacity additions remain important uncertainties. Oregon regulators denied a request to waive competitive-bidding rules for resource procurement.
- The planned Boardman-to-Hemingway transmission line is not expected in service before 2026; Idaho Power’s estimated share of project costs is subject to change. Hydropower relicensing is another material uncertainty: Hells Canyon relicensing costs in construction work in progress were $397 million, and a new license was expected in 2024 or later.
- On April 7, 2022, Idaho Power entered a consent judgment requiring a $1.1 million fine, interim compliance measures, and new permit applications for 15 hydroelectric projects. The filing also discusses wildfire liability, environmental regulation, water availability, regulatory cost recovery, project permitting, and commodity and supply-chain risks.
- Moody’s outlooks for both companies remained negative, though management said a downgrade to a rating level comparable to S&P would still leave the companies investment grade. A downgrade below investment grade could prompt collateral demands; estimated potential additional collateral at March 31 was about $12.8 million.
Most important facts for investors to verify
- Whether regulators approve the requested PCA and Jim Bridger rate changes, and how approval, mitigation, or timing affects cash recovery and earnings.
- Actual 2022 hydropower output, wholesale power and fuel costs, and the extent to which adjustment mechanisms offset cost volatility.
- Capital-project estimates, procurement and permitting progress, and funding needs relative to the company’s debt and liquidity capacity.
- Capacity-resource approvals and in-service timing, particularly for battery storage, solar, and resources needed for 2024–2025 peak deficits.
- Developments in Hells Canyon relicensing, environmental compliance, and the hydroelectric permitting consent judgment and associated costs.
- Customer receivable collections and uncollectible-account exposure: the allowance was $4.9 million, or 5.6% of customer receivables, at March 31.
The interim financial statements were unaudited; Deloitte & Touche reported that its review found no material modifications necessary for conformity with U.S. GAAP. The filing notes that the review was substantially narrower in scope than an audit.