Executive Summary / Key Takeaways

• Rate Base Doubling as Core Value Driver: IDACORP is executing a capital-intensive transformation that will more than double its Idaho-jurisdictional rate base from $4.6 billion at year-end 2024 to approximately $9.1 billion by 2029, representing a 16.1% compound annual growth rate that far exceeds typical utility sector expansion and creates a powerful earnings growth engine if regulatory mechanisms function as intended.

• Industrial Load Growth Creating Structural Demand Tailwind: Idaho Power's service territory is experiencing an unprecedented industrial renaissance, with Micron (MU)'s two fab projects representing the largest private capital investment in Idaho history, alongside new mining, agricultural processing, and data center developments driving an 8.3% forecasted annual growth rate in retail sales through 2029—nearly triple the national utility average and providing visibility into load growth well into the 2030s.

• Regulatory Strategy Evolution Critical to Investment Returns: The company is aggressively pursuing new regulatory mechanisms—including a depreciation and interest expense tracker and a modified ADITC amortization cap—to combat regulatory lag from massive capital deployment, with the October 2025 settlement stipulation seeking $110 million in annual revenue recovery effective January 2026 serving as a pivotal test of Idaho regulators' willingness to accommodate accelerated cost recovery.

• Hydro Portfolio: Cost Advantage Meets Weather Vulnerability: Idaho Power's 17 hydroelectric plants provide a structural cost advantage that keeps customer bills 20-30% below national averages and supports 27.3% operating margins, but this same concentration creates asymmetric downside risk during drought conditions that could force higher-cost market purchases and erode the very affordability that underpins the company's regulatory relationships.

• Valuation Premium Hinges on Execution of Complex Capital Program: Trading at 17.4x EV/EBITDA and 21.9x P/E, IDA commands a modest premium to regional peers but remains attractive relative to its 16.1% projected rate base CAGR, though this premium will only be sustained if the company successfully navigates construction risks on $3.1-3.6 billion in 2027-2029 CapEx while maintaining its 50-50 capital structure without dilutive equity issuance.

Setting the Scene: A Century-Old Utility Reinventing Itself for Idaho's Next Chapter

IDACORP, Inc., founded in 1915 as Idaho Power Company and restructured as a holding company in 1998, operates today as a fundamentally different enterprise than it was just five years ago. The transformation extends far beyond the standard utility narrative of coal-to-gas switching and renewable additions. Idaho Power, the principal subsidiary serving 604,000 customers across 24,000 square miles of southern Idaho and eastern Oregon, is simultaneously decommissioning its final coal units, constructing major transmission arteries to access regional power markets, and building generation capacity to serve an industrial expansion that rivals any region in the United States.

The company's core business model follows the traditional regulated utility framework: invest capital in generation, transmission, and distribution assets; earn a regulated return on that rate base; and recover operating costs through customer rates. What distinguishes IDA in the current environment is the velocity and scale of this capital deployment relative to its existing asset base, and the corresponding acceleration in load growth that provides the revenue to support it. While most utilities grapple with flat to 1-2% annual load growth, Idaho Power's integrated resource plan forecasts 8.3% annual growth in retail sales and 5.1% peak demand growth through 2029—figures that transform the company from a slow-growth bond proxy into a capital growth story.

This positioning within the Pacific Northwest utility landscape creates both opportunities and competitive pressures. Unlike Avista (AVA) with its natural gas diversification, Portland General Electric (POR) with its urban Portland focus, or NorthWestern Energy (NWE) with its coal-heavy portfolio, Idaho Power's nearly pure-play electric strategy concentrated in Idaho's agricultural and emerging tech economy creates a unique risk-reward profile. The company's hydroelectric heritage provides cost advantages that competitors cannot replicate, but also concentrates weather risk in ways that diversified portfolios avoid.

Technology, Infrastructure, and Strategic Differentiation: The Hydro Advantage and Transmission Moats

The Hydroelectric Foundation: A Structural Cost Edge

Idaho Power's 17 hydroelectric plants represent more than just clean energy assets—they form the bedrock of the company's economic moat. These facilities provide baseload power at marginal costs that are materially lower than thermal generation, enabling the company to maintain residential customer bills that are 20-30% below the national average while still earning authorized returns. This cost advantage functions as a self-reinforcing cycle: lower bills support robust customer growth (2.3% in the twelve months ended September 2025), which spreads fixed costs across a larger base, further enhancing affordability and regulatory standing.

The operational benefits extend beyond simple cost. Hydro generation provides critical grid flexibility, allowing rapid ramping to meet peak demands and balancing intermittent renewable resources. In the second quarter of 2025, the company updated its hydropower generation forecast to 6.5-7.0 million megawatt hours for the year, reflecting favorable water conditions that directly translate to reduced market purchases and higher margins. However, this same concentration creates the company's most significant vulnerability: during drought years, the forced shift to purchased power can increase power supply costs by 20-30%, compressing margins precisely when regulators resist rate increases.

Transmission Infrastructure as Strategic Offense

IDACORP's $3.1-3.6 billion capital expenditure plan for 2027-2029 centers on three major transmission projects that serve as both reliability enhancements and market access tools. The Boardman-to-Hemingway (B2H) line, with construction commencing in June 2025 and a late 2027 in-service date, represents a $1.5-1.7 billion investment that will connect Idaho Power to Pacific Northwest markets, enabling access to lower-cost renewable energy and providing outlet capacity for future generation. Through September 2025, the company had spent $578 million on B2H, receiving $300 million in reimbursements from co-participants, demonstrating the project-level financing discipline that will be critical for maintaining capital structure targets.

The Gateway West (GWW) and Southwest Intertie Project-North (SWIP-N) lines provide similar strategic value, with GWW's $900 million to $1.1 billion cost for Idaho Power's share and SWIP-N's partial ownership structure creating a networked transmission footprint that competitors cannot easily replicate. These projects function as toll roads for electricity, providing regulated returns on invested capital while simultaneously reducing portfolio costs through market access. The regulatory approval process, while lengthy and complex, ultimately creates barriers to entry that protect the company's market position.

Generation Portfolio Evolution: From Coal to Flexible Gas

The company's generation strategy reflects a pragmatic approach to the energy transition. The 2019 retirement of one North Valmy coal unit, followed by the October 2020 cessation of the Boardman plant and the Q2 2024 conversion of Jim Bridger Units 1 and 2 to natural gas, eliminates coal from the portfolio by year-end 2025. This transition reduces environmental compliance risks and aligns with regulatory preferences, but the real strategic shift lies in the replacement strategy.

The termination of the 600-megawatt Jackalope Wind Project agreements in September 2025, due to permitting delays and federal land use policy uncertainty, forced Idaho Power to pivot toward natural gas and battery storage solutions. The planned 167-megawatt Bennett Mountain gas-fired power plant expansion, with construction beginning spring 2026 and online by 2028, provides dispatchable capacity that wind resources cannot match. Concurrently, the company brought nearly 200 megawatts of solar and battery storage online in 2024 and commenced construction on 80 megawatts of company-owned battery storage in 2025. This combination of gas for reliability and batteries for flexibility creates a more resilient portfolio than a renewables-only approach, particularly given the 8.3% load growth forecast that requires dispatchable capacity to maintain grid stability.

Financial Performance: The Tension Between Growth and Regulatory Lag

Third Quarter 2025: Rate Recovery Offsetting Operational Headwinds

IDACORP's third quarter results reveal the financial mechanics of a utility in heavy investment mode. While operating revenue declined modestly to $523.5 million from $527.5 million year-over-year, net income attributable to IDACORP increased 9.7% to $122.2 million, demonstrating the power of rate relief in offsetting operational pressures. The $17.6 million increase in retail revenues per megawatt-hour, resulting from Idaho base rate increases effective January 1, 2025, directly flowed to the bottom line, illustrating why timely rate recovery is existential for the investment thesis.

Customer growth contributed $7.8 million to operating income, with the 2.3% increase in customer count providing a stable demand foundation. However, usage per retail customer decreased operating income by $5.7 million, as higher precipitation and moderate temperatures reduced irrigation load. This weather-driven volatility underscores the risk of relying on volumetric sales growth in a changing climate, making the rate base growth story more critical than unit sales growth.

Operating expenses tell a concerning inflationary story. Other operations and maintenance expenses increased $4.2 million in the quarter and $22.5 million year-to-date, driven by inflationary pressures on labor and professional services plus increased wildfire mitigation and insurance expenses. Depreciation and amortization rose $8.1 million in the quarter and $20.3 million year-to-date due to increased plant-in-service and a new leased battery storage facility. These cost pressures, while expected in a capital-intensive business, highlight why regulatory lag poses such a threat to returns—costs are incurred immediately, while recovery may take 12-18 months.

Capital Structure and Liquidity: Walking the 50-50 Tightrope

IDACORP's financing strategy centers on maintaining a 50-50 debt-to-equity capital structure at Idaho Power, a target that becomes increasingly difficult as capital expenditures accelerate. As of September 30, 2025, Idaho Power's leverage ratio stood at 54%, with common equity at 47% of total adjusted capital—still above the 35% IPUC minimum but trending toward the upper end of the target range. The company issued $400 million in first mortgage bonds during 2025, offset by $19.9 million in variable rate bond repayments and $140 million in dividend payments, demonstrating the balancing act required to fund growth while preserving financial flexibility.

The company's forward sale agreements, totaling $145 million gross under its ATM program with $155 million remaining available, plus $575 million in separate FSAs, provide contingent equity capacity that management can deploy if capital markets conditions warrant. This "dry powder" is crucial given the $1.25-1.35 billion in estimated CapEx for 2026 and the $3.1-3.6 billion planned for 2027-2029. As CFO Brian Buckham noted, the termination of the Jackalope Wind project and its replacement with gas-fired generation could reduce near-term equity needs by pushing capital requirements further into the five-year window, but the fundamental financing challenge remains.

Outlook, Guidance, and Execution Risk: The Load Growth Hurdle Rate

Management's Confidence Versus Historical Conservatism

IDACORP's 2025 guidance, with diluted EPS raised to $5.80-$5.90 from earlier ranges, reflects strong operational performance that allowed management to reduce its ADITC amortization estimate to $50-60 million while still increasing earnings. This dynamic—growing earnings without fully utilizing tax credit mechanisms—signals underlying business strength. However, the guidance assumes historically normal weather and normal power supply expenses for the fourth quarter, a caveat that directly ties to the hydro risk identified earlier.

The company's load forecasting methodology reveals a disciplined, conservative approach that may understate actual growth. As CEO Lisa Grow emphasized, new large projects are excluded from forecasts until procurement and construction contracts are executed and the service method is identified. This means the 8.3% retail sales growth forecast and 5.1% peak demand growth projection likely represent a floor rather than a ceiling. The prospective customer pipeline exceeding Idaho Power's all-time peak load of 3,800 megawatts provides visibility into incremental growth through the 2030s that is not yet reflected in capital plans, creating potential upside to the rate base CAGR if even a fraction of these projects materialize.

The 2025 Rate Case Settlement: A Regulatory Inflection Point

The October 2025 settlement stipulation, if approved by the Idaho Public Utilities Commission, would increase annual Idaho-jurisdictional retail revenue by approximately $110 million (7.48%) effective January 1, 2026, based on a 9.6% return on equity and $4.9 billion rate base. More importantly, the settlement includes a depreciation and interest expense tracking mechanism designed to reduce regulatory lag from heightened capital investment, and caps annual ADITC amortization at $55 million for 2026 and thereafter.

This settlement represents a critical test of regulatory support for IDACORP's growth strategy. The tracking mechanism directly addresses the earnings drag that forced the company to use $39 million in additional ADITC amortization during the first nine months of 2025 to reach its authorized returns. If approved, it would provide more timely cost recovery and reduce reliance on tax credit mechanisms, improving earnings quality. The $55 million ADITC cap, while limiting near-term earnings upside, creates transparency and predictability that credit rating agencies and equity investors favor.

Capital Deployment Execution: The $3.6 Billion Question

The company's ability to execute on its 2027-2029 capital plan will determine whether the rate base growth story translates to shareholder returns. The B2H transmission line, with its $1.5-1.7 billion total cost and late 2027 in-service date, faces typical utility construction risks including permitting delays, material cost escalation, and contractor performance issues. The recent experience with Jackalope Wind, where permitting delays and federal land use policy uncertainty forced project termination, serves as a cautionary tale. While management has identified alternative solutions including short-term market purchases, natural gas projects, and additional solar and battery storage, each substitution introduces new execution timelines and cost uncertainties.

The 167-megawatt Bennett Mountain gas plant expansion, expected to begin construction in spring 2026 and achieve commercial operation in 2028, exemplifies the compressed timelines required to meet load growth. Any delay in this project could create a supply shortfall during peak summer loads, forcing expensive market purchases that compress margins and test regulatory patience on cost recovery.

Risks and Asymmetries: Where the Thesis Can Break

Regulatory Lag: The Primary Erosion Mechanism

The most material risk to IDACORP's investment thesis is regulatory lag that prevents timely cost recovery from massive capital deployment. While the proposed depreciation and interest tracker in the 2025 rate case addresses this theoretically, its approval is not guaranteed, and even if approved, the mechanism may not capture all cost increases. The company's experience in 2024, when it first utilized ADITC amortization to reach the 9.12% ROE floor, demonstrates that regulatory lag can persist even in constructive regulatory environments. If Idaho regulators reject the tracker or approve it with limitations, the 16.1% rate base CAGR could translate to sub-authorized returns, destroying the earnings growth story.

This risk is amplified by the scale of capital deployment. The $3.1-3.6 billion planned for 2027-2029 represents more than 50% of the company's current asset base, creating an unprecedented test of regulatory willingness to support growth. Competitors like Avista and NorthWestern Energy face similar challenges, but their more diversified portfolios and smaller relative capital programs create less regulatory friction. IDACORP's concentrated Idaho exposure means a single adverse regulatory decision could disproportionately impact returns.

Weather and Hydrology: The Asymmetric Downside

While hydroelectric generation provides cost advantages, it creates asymmetric downside risk. A severe drought could reduce hydropower output by 30-40%, forcing market purchases at prices that may not be fully recoverable through the Power Cost Adjustment mechanism, which allocates only 5% of net power supply expense deviations to Idaho Power. The company's Q3 2025 experience, where favorable weather reduced irrigation load and offset customer growth, demonstrates how weather can swing earnings by $5-10 million quarterly. In a drought scenario, this could easily become a $20-30 million headwind, eliminating the earnings contribution from rate base growth.

This vulnerability contrasts sharply with competitors like Portland General Electric, whose more diversified portfolio includes greater thermal capacity that provides generation certainty during low water years. While IDA's hydro assets provide environmental and cost advantages in normal years, they create earnings volatility that utility investors typically discount.

Policy and Permitting Uncertainty: The Jackalope Precedent

The Jackalope Wind project termination reveals how federal policy shifts can disrupt capital plans. The 600-megawatt project, which would have provided substantial renewable capacity, fell victim to permitting delays and uncertainty around federal land use policies. While management's pivot to natural gas and battery storage provides alternative solutions, gas projects face their own regulatory hurdles, including potential carbon constraints, while battery storage remains subject to supply chain disruptions and tariff risks that management explicitly monitors.

This policy uncertainty creates execution risk on the 2027-2029 capital plan. The B2H transmission line, while currently proceeding, could face similar federal permitting challenges. Any significant delay would push rate base growth beyond the forecast period, compressing the CAGR and reducing the present value of future earnings.

Valuation Context: Pricing the Growth Premium

At $126.88 per share, IDACORP trades at a market capitalization of $6.86 billion and an enterprise value of $10.20 billion, reflecting a capital structure that is approaching its 50-50 debt-to-equity target. The valuation multiples—21.9x trailing P/E, 17.4x EV/EBITDA, and 11.4x price-to-operating cash flow—position IDA at a modest premium to regional peers but at a discount to high-growth utilities with similar rate base expansion profiles.

Peer Comparison: Growth Justifies Premium

Comparing IDA to direct competitors reveals a valuation that appears reasonable for the growth profile. Avista trades at 16.3x P/E and 10.0x EV/EBITDA with slower growth and higher dividend payout (82.4% vs. IDA's 59.2%), reflecting its more mature, gas-diversified business. Portland General Electric trades at 17.6x P/E and 9.7x EV/EBITDA with lower operating margins (18.4% vs. IDA's 27.3%) and higher debt-to-equity (1.36 vs. 1.05), despite its attractive urban load growth. NorthWestern Energy's 18.5x P/E and 12.2x EV/EBITDA come with lower ROE (7.6% vs. 9.4%) and a coal-heavy portfolio facing environmental compliance costs. Black Hills (BKH) trades at 17.6x P/E with merger-related execution challenges.

IDA's premium appears justified by three factors: superior operating margins driven by hydro cost structure, a clearly articulated rate base growth trajectory (16.1% CAGR) that exceeds all peers, and a constructive regulatory environment that supports timely cost recovery. The 2.78% dividend yield, while lower than some peers, reflects a more conservative payout ratio that retains capital for growth investments.

Cash Flow and Capital Intensity Considerations

The company's operating cash flow of $594 million on a trailing basis provides coverage of the current $1.0-1.1 billion CapEx program, but falls well short of the $1.25-1.35 billion planned for 2026 and the $3.1-3.6 billion for 2027-2029. This funding gap necessitates external financing, creating potential equity dilution risk if management cannot execute its preferred mix of debt and forward equity sales. The $145 million in forward sale agreements outstanding, with $155 million remaining ATM capacity and $575 million in separate FSAs, provides flexibility but also creates overhang risk if markets deteriorate.

The EV/Revenue multiple of 5.6x appears elevated relative to the 3.8x P/S ratio, reflecting the debt-financed growth strategy. However, this is consistent with other capital-intensive utilities during heavy investment phases. The key valuation question is whether the market is appropriately discounting the execution risk on the 2027-2029 capital program. If IDA can deploy $3.6 billion at its 9.6% authorized ROE, the incremental earnings would be approximately $345 million annually, nearly doubling current net income and making the current valuation appear attractive. If regulatory lag or construction delays reduce the effective return to 7-8%, the valuation premium becomes harder to justify.

Conclusion: A Utility at the Inflection Point of Growth and Execution

IDACORP stands at a critical juncture where its strategic positioning in Idaho's rapidly industrializing economy and its hydroelectric cost advantages create a compelling earnings growth narrative, but this potential can only be realized through flawless execution of the most ambitious capital program in the company's 110-year history. The 16.1% rate base CAGR to 2029, driven by $5.6 billion in capital deployment, offers a clear path to doubling earnings if regulatory mechanisms function as designed and construction timelines hold.

The company's success hinges on three variables that will determine whether this premium valuation is earned or eroded. First, the Idaho Public Utilities Commission's decision on the 2025 rate case settlement, particularly the depreciation and interest tracker, will signal whether regulators will support timely cost recovery or impose traditional regulatory lag that compresses returns. Second, the realization of the industrial load growth pipeline—particularly Micron's fab expansion and the prospective customer list exceeding 3,800 megawatts—will determine whether the 8.3% sales growth forecast proves conservative or aspirational. Third, weather patterns and hydrology will either validate the hydro portfolio's cost advantage or expose its earnings volatility.

For investors, IDACORP offers a rare combination of utility sector stability and above-average growth, but this comes with corresponding execution risks that traditional utility investors may find unfamiliar. The stock's modest premium to peers appears justified by the rate base growth trajectory, but any misstep on regulatory recovery, capital deployment, or load growth realization could trigger a multiple re-rating. The hydro cost advantage provides a durable moat against competitive threats, yet creates weather-dependent earnings volatility that requires careful monitoring. In an industry where most companies promise slow and steady, IDA is betting on fast and furious—making it either a compelling growth story or a cautionary tale in regulatory risk management.