The Reality of Infrastructure Development in 2023

The energy transition isn't waiting for anyone to get comfortable. Capital is moving, technology is maturing, and the projects being permitted, financed, and built right now will define the grid — and the broader infrastructure ecosystem — for the next three decades. If you're developing land, managing assets, or allocating capital in this space, what’s happening in 2023 isn’t background noise. It’s the main event.

The Infrastructure Pressure Cooker

The U.S. infrastructure system is being pulled in three directions simultaneously: decarbonization mandates, surging electricity demand, and a supply chain that's still finding its footing after years of disruption. That combination creates both stress and opportunity, depending on where you sit.

Electricity demand — long assumed to be flat or declining — is climbing again. Data centers, electric vehicle charging networks, and the onshoring of energy-intensive manufacturing are all drawing more from a grid that wasn’t designed to handle it. The Department of Energy projects that U.S. electricity consumption could increase by as much as 20% over the next decade. That number sounds abstract until you realize it means hundreds of gigawatts of new generation, transmission, and storage capacity need to come online — and fast.

The developers, landowners, and capital allocators who understand this demand shift earliest will have a structural advantage that's nearly impossible to replicate later.

The Inflation Reduction Act changed the math on clean energy investment in ways the industry is still fully processing. The ITC and PTC extensions, the domestic content adders, and the energy community bonuses — stacked together, these incentives can push the effective tax credit value on a solar-plus-storage project well above 40% of capital costs. That’s not a marginal improvement; it rewrites pro formas.

Solar's Maturation — and What Comes After It

Utility-scale solar is no longer an emerging technology. It’s the cheapest source of new electricity generation in most of the United States, often coming in below $40/MWh on an unsubsidized basis in high-irradiance markets. That cost trajectory — driven by relentless manufacturing scale, module efficiency gains, and installation experience — has fundamentally repositioned solar from a policy-dependent niche into a mainstream infrastructure asset class.

But the more interesting story is what's happening at the edges of that maturity curve.

Bifacial modules, tracking systems, and improved inverter technology have pushed capacity factors well beyond what the industry modeled even five years ago. A well-sited utility-scale project in the Southwest can now realistically achieve capacity factors above 28-30%, compared to the 22-24% that was considered strong a decade ago. That improvement doesn’t sound dramatic, but at 200 MW of nameplate capacity, it translates to hundreds of thousands of additional megawatt-hours annually — real revenue that changes project economics meaningfully.

Distributed solar — rooftop commercial, community solar, agrivoltaic systems — is growing faster than utility-scale on a percentage basis, and it's creating new land use configurations that didn't exist five years ago.

The agrivoltaic angle deserves particular attention from anyone in land development. Dual-use solar, where panels are co-located with grazing, specialty crops, or pollinator habitats, is moving from pilot projects to commercial scale. For landowners, it’s a way to capture solar lease revenue without permanently removing productive acreage from agricultural use. For developers, it’s a permitting and community relations advantage that’s increasingly valuable in regions where agricultural land conversion faces opposition.

Battery Storage: From Novelty to Grid Infrastructure

Battery energy storage has cleared its proof-of-concept phase. That phase is over. What’s happening now is deployment at a scale that would have seemed speculative in 2019.

The U.S. added roughly 4.9 GW of battery storage capacity in 2022 alone, and 2023 projections are higher. The driving force isn’t just renewable integration — though that’s part of it. Utilities and grid operators are procuring storage explicitly for capacity, frequency regulation, and transmission deferral. Storage is doing jobs the grid used to require gas peakers to do, and in many markets, it’s doing them more cheaply.

Lithium iron phosphate (LFP) chemistry has become the dominant choice for grid-scale applications, displacing the NMC chemistries that dominated earlier installations. The reason is straightforward: LFP trades some energy density for significantly better thermal stability, longer cycle life, and lower cost at scale. For a stationary application where weight and volume aren’t constraints, those tradeoffs are entirely rational.

The four-hour duration standard that’s driven most procurement to date is already being challenged. California’s latest resource adequacy proceedings are pushing toward longer durations — 8, 10, even 12 hours — as the penetration of solar generation deepens the "duck curve" problem. This is an important signal for developers and manufacturers alike: the storage market isn’t static, and projects being designed today need to accommodate potential augmentation and duration extension as grid needs evolve.

Every peaker plant retirement announcement you see in 2023 is effectively a storage procurement signal — the grid doesn’t tolerate capacity gaps, and batteries are increasingly first in line to fill them.

The Economics of Getting This Right

The financial case for clean energy infrastructure has become harder to argue against, and not just because of incentives. The levelized cost of energy from solar-plus-storage systems is now competitive with new gas generation in most U.S. markets on a purely economic basis, before any tax credit layering.

From an investment perspective, the risk profile of clean energy infrastructure has also shifted. Long-term offtake agreements — PPAs structured at 15-20 years — provide revenue certainty that most infrastructure asset classes can’t match. Institutional investors have noticed. Pension funds, insurance companies, and sovereign wealth funds that spent years watching from the sidelines have become active acquirers of operating clean energy assets and development-stage portfolios.

The land component of this equation is underappreciated. Solar and storage projects require significant acreage — a utility-scale solar facility typically needs 5-10 acres per megawatt — and the land rights acquisition process is increasingly competitive. Landowners in high-irradiance regions with transmission proximity are sitting on an asset that’s more valuable than many of them realize. The lease rates being offered for solar and storage land rights have increased substantially in competitive markets, with some projects in the Southeast and Southwest offering $1,000-$2,000 per acre annually, and more in constrained areas near existing substations.

Developers who underinvest in site control and transmission interconnection will find themselves locked out of viable development windows that are narrowing as competition intensifies.

The Cost of Staying on the Sidelines

Regulatory pressure on conventional infrastructure is accelerating, not plateauing. The EPA's latest proposed rules on coal plant emissions, state-level clean energy standards, and SEC climate disclosure requirements are creating a compliance cost environment that makes "wait and see" an increasingly expensive posture.

Beyond regulation, there’s a more immediate financial reality: the fossil fuel assets on utility balance sheets are aging. The average U.S. coal plant is over 40 years old. Maintaining aging thermal generation while simultaneously meeting decarbonization commitments creates a capital allocation problem with no clean solution — except, increasingly, replacement with renewables and storage.

Communities and counties that have relied on fossil fuel facilities for tax base and employment are already grappling with transition timelines. The infrastructure development challenge isn’t purely technical or financial. It’s also political and social, and the projects that navigate that complexity successfully — through genuine community engagement, local hiring commitments, and transparent communication — tend to be the ones that actually get built.

Where This Is Heading

The trajectory is clear, even if the exact path isn’t. Clean energy is becoming the default infrastructure investment, not the alternative one. The question for developers, landowners, and capital allocators isn’t whether to engage with solar, storage, and the broader energy transition — it’s how to position for the specific opportunities that match their capabilities and risk tolerance.

The most sophisticated players in this space are already thinking beyond individual projects. They’re building platform strategies: assembling land portfolios in target markets, pre-positioning for interconnection queue slots, and developing relationships with offtakers before projects are fully designed. That kind of systematic, patient approach is what separates the developers who thrive in this environment from those who find themselves perpetually reacting to a market that moved faster than they expected.

The infrastructure being built and financed in 2023 will still be operating in 2055. The decisions being made now — site selection, technology choices, partnership structures — carry that kind of weight. Act accordingly.

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