Power demand from semiconductor fabs and data centers in Arizona is growing at a staggering pace. Utility resource plans across the state project roughly two to three times growth in generation capacity over the next decade — a dramatic shift after nearly 25 years of relatively stable peak demand. That level of expansion presents real challenges for developers, utilities and regulators alike.
Utility power is no longer infinitely available or predictably priced. Rapid industrial growth has led to long interconnection queues, substation constraints and multi-year transmission upgrade timelines. At the same time, utilities face mounting capital expenditures for grid hardening, wildfire mitigation and new generation. The result: sustained upward pressure on retail electricity rates, with double-digit annual increases becoming the norm.
Faced with these realities, many industrial users are exploring on-site generation, storage and microgrids to accelerate timelines and hedge cost risk. But building power infrastructure independently introduces its own engineering, regulatory and fuel-supply complexities.
Utility Power and Constraints
Investor-owned utilities remain the backbone of reliable power delivery. For advanced manufacturing facilities that require high-quality, uninterrupted electricity, grid supply is essential. However, scaling infrastructure to meet unprecedented demand is not instantaneous.
Natural gas, historically the go-to solution for dispatchable generation, is constrained as well. Existing interstate pipelines serving Arizona are fully subscribed, with expansion projects targeting late 2029, subject to regulatory approvals. Even if pipeline capacity increases materially, global supply chain bottlenecks for combined-cycle and peaker turbines are extending equipment lead times into the early 2030s.
Other frequently cited alternatives, such as small modular nuclear reactors (SMRs), remain commercially unproven at scale. While promising in theory, financing models, regulatory pathways and deployment timelines are uncertain. For projects breaking ground in the next five to seven years, SMRs remain speculative.
If utility-scale solutions are slow to materialize, what options remain?
Microgrids and On-Site Generation: Realistic but Limited
Microgrids are often presented as a silver bullet, but expectations must be calibrated. Solar-plus-storage systems require significant land area, and generation density limits their practicality for very large industrial loads. Without access to on-site natural gas or future nuclear options, most renewable-based microgrids are best suited for facilities with peak loads under roughly 3 MW, e.g., schools, healthcare facilities or office campuses.
That said, microgrids can provide meaningful value. Properly designed systems can: island during grid outages, reduce peak demand charges, hedge on-peak energy exposure, improve resiliency.
For facilities already budgeting for backup generators, integrating solar and storage can significantly reduce diesel sizing and improve asset utilization. Traditional backup systems sit idle nearly 99.9% of the time while hybrid systems create operational and financial returns. In many cases, well-structured projects can achieve 7- to 10-year payback periods.
Local Ordinances and Their Impact on Microgrids
Even when economics align, local regulations can become a bottleneck — particularly for battery energy storage systems.
Municipalities such as the City of Mesa have introduced new setback requirements and clarified definitions of “principal” versus “accessory” energy uses. These ordinance updates reflect a balancing act between economic development and public safety. As more projects advance, these local precedents will shape adoption statewide.
Developers should expect close coordination with planning departments, fire marshals and utilities. Early engagement is essential if energy infrastructure is core to a project’s financial model.
Commercial Project Financing: The Missing Link
While fabs and hyperscale campuses dominate headlines, smaller commercial and industrial operators face similar cost pressures. Rooftop- and carport-mounted solar, energy storage and hybrid backup solutions are increasingly attractive, but capital allocation remains the hurdle.
Corporate decision-making often prioritizes sub-five-year paybacks, which can undervalue long-term energy assets. At the same time, financing energy improvements over 15–25 years can be challenging for tenants or companies with shorter operational horizons.
One promising tool is Commercial Property Assessed Capital Expenditures (C-PACE), currently under consideration at the Arizona legislature. C-PACE would allow long-term financing for on-site improvements tied to property tax assessments, potentially unlocking significant private investment in on-site infrastructure improvements, including distributed energy resources.
A Practical Path Forward
For large energy users, I recommend a staged approach: secure utility power as foundational supply, layer in on-site generation and storage to hedge exposure and enhance resiliency, design infrastructure with future fuel flexibility in mind, and engage municipalities early to navigate permitting requirements.
Power availability is now a primary development constraint in Arizona. Organizations that treat energy strategy as a parallel workstream by integrating that variable into site selection, budgeting and regulatory planning will move faster and reduce risk.
John Mitman is the founder and CEO of Obodo Energy Partners, a leading provider of large-scale solar and energy infrastructure solutions headquartered in Tempe, and board president of AriSEIA, a 501(c)(6) trade organization representing solar, storage and electrification interests in Arizona. After earning acclaim as part of a national energy services provider, Mitman is thrilled to refocus his attention on Arizona’s communities with Obodo’s suite of development-design-build-maintain services.
