The distributed energy market presents a paradox. On a per-megawatt-hour basis, behind-the-meter solar and storage systems routinely earn more than their utility-scale counterparts. A rooftop solar array paired with a battery in a commercial building offsets retail electricity rates -- often two to four times higher than wholesale prices -- while simultaneously providing demand charge reduction, backup power, and in some markets, revenue from grid services. The economics are strong. Yet the sector has consistently failed to attract capital at scale. The reason is not technological. It is financial.
The DER Taxonomy and Why It Matters
Distributed energy resources encompass a wide range of technologies installed at or near the point of consumption: rooftop and carport solar, behind-the-meter battery storage, small wind, combined heat and power systems, EV chargers with vehicle-to-grid capability, and demand response programs. The International Energy Agency's World Energy Outlook 2023 estimated that distributed solar PV alone accounted for roughly half of all new solar capacity additions globally, with rooftop systems reaching approximately 130 GW of cumulative installed capacity worldwide by the end of 2022.
What distinguishes these assets from utility-scale generation is not just their size but their relationship to the grid. A 5 MW solar farm sells power into a wholesale market at marginal clearing prices. A 500 kW rooftop system on a warehouse offsets power that would otherwise be purchased at retail rates, which in many jurisdictions include not only energy charges but demand charges, transmission and distribution fees, and various surcharges. This structural advantage -- what economists call the "retail rate arbitrage" -- is the fundamental driver of DER economics. According to the U.S. Energy Information Administration, average commercial retail electricity rates in the United States reached approximately 13.5 cents per kWh in 2023, compared to wholesale prices that ranged from 2 to 6 cents per kWh across most ISO markets outside of scarcity events.
The Hype Cycle and the Hard Lessons
The distributed energy sector has endured at least two distinct hype-and-correction cycles. The first, from roughly 2012 to 2016, was driven by the residential solar boom. Companies such as SolarCity, Sunrun, and Vivint Solar scaled rapidly on the back of the federal investment tax credit and third-party ownership models. SolarCity's acquisition by Tesla in 2016 at a valuation of approximately $2.6 billion obscured mounting financial stress: the cost of customer acquisition was high, loan defaults were rising, and the securitization market for residential solar receivables remained illiquid relative to the volume of capital needed.
The second wave, from 2018 to 2021, was fuelled by the addition of battery storage to the DER stack. The promise was compelling: pair solar with a battery, add intelligent controls, and the system can provide not just bill savings but backup power, demand charge management, and participation in wholesale ancillary service markets. BloombergNEF tracked lithium-ion battery pack prices declining from roughly $1,100 per kWh in 2010 to under $140 per kWh by 2023, making the economics of paired solar-plus-storage increasingly attractive. Yet many of the companies that attempted to build portfolios of distributed solar-plus-storage assets found themselves struggling with the same fundamental problem that had plagued the earlier wave: the cost of originating, underwriting, deploying, and managing a distributed asset was disproportionately high relative to the revenue each individual site generated.
The Balance Sheet Problem
This is the core structural challenge. To understand it, consider the difference between financing a 200 MW utility-scale solar farm and financing 400 individual 500 kW commercial rooftop systems that sum to the same capacity. The utility-scale project has one site, one interconnection agreement, one offtaker (or merchant exposure to a single wholesale market), one set of permits, one construction contract, and one operations and maintenance agreement. The transaction costs -- legal, engineering, insurance, due diligence -- are spread over 200 MW of capacity. A typical utility-scale solar project might incur total soft costs of $5 to $10 per watt-DC of transaction and development overhead, which on a per-MW basis is highly manageable.
The distributed portfolio, by contrast, requires 400 separate site assessments, 400 lease or license agreements, 400 interconnection applications, 400 permit packages, 400 individual customer credit evaluations, and ongoing management of 400 separate utility accounts, net metering arrangements, and maintenance schedules. NREL's benchmark analyses of solar soft costs have repeatedly shown that customer acquisition, system design, permitting, and interconnection costs for commercial rooftop solar are substantially higher per watt than for utility-scale systems, often by a factor of two or more. When you add battery storage -- which introduces additional complexity around fire code compliance, utility interconnection requirements, and dispatch optimization -- the per-site overhead increases further.
This per-site overhead creates what might be called a "balance sheet problem" that affects every stakeholder in the value chain differently, but afflicts them all.
For the end customer, the balance sheet impact is direct. A commercial or industrial business that purchases a solar-plus-storage system outright must capitalize the asset, which affects debt covenants, return-on-assets calculations, and in many cases requires board-level approval for capital expenditure. For businesses whose core competency is manufacturing widgets or running hotels, taking on the ownership and operational risk of a power generation and storage asset is a distraction. This is why the commercial and industrial (C&I) segment has historically lagged residential solar in adoption rates despite stronger underlying economics.
For utilities, distributed assets present both an accounting challenge and a regulatory one. Most vertically integrated utilities operate under rate-of-return regulation, where they earn a guaranteed return on capital investments in their rate base. Distributed resources owned by third parties or customers reduce load and erode the utility's revenue base without a corresponding reduction in the fixed costs of maintaining the grid. The "utility death spiral" narrative has been overstated, but the underlying accounting tension is real: DERs shift value from centralised infrastructure to distributed assets that sit outside the utility's regulated asset base.
For traditional project finance, the challenge is one of standardisation and scale. Infrastructure funds and tax equity investors are structured to deploy large amounts of capital into individual projects or small portfolios of large assets. A typical tax equity fund might target a minimum deal size of $50 million to $100 million, with transaction costs (legal, accounting, independent engineering) of $500,000 to $2 million per deal. Those transaction costs are bearable on a 100 MW utility-scale project but ruinous if spread across dozens of sub-megawatt distributed sites. The result is that distributed energy projects often fall into a "financing gap" -- too large for simple commercial lending, too small and too numerous for traditional project finance.
Energy-as-a-Service: Third-Party Ownership as a Structural Solution
The Energy-as-a-Service (EaaS) model attempts to resolve the balance sheet problem by shifting asset ownership from the end customer to a specialised third party. The customer signs a service agreement -- typically structured as a power purchase agreement (PPA), energy services agreement (ESA), or managed energy agreement -- under which they pay for energy outcomes (reduced bills, backup power, carbon reduction) rather than owning the underlying hardware.
This structure offers clear advantages. The customer gets the economic benefits of on-site generation and storage without the capital expenditure, ongoing maintenance responsibility, or technology risk. The asset remains off the customer's balance sheet. The third-party owner, meanwhile, can aggregate multiple sites into a portfolio, apply standardised underwriting and operational processes, and potentially access lower-cost capital by securitising the revenue streams.
The model is not new. It is essentially the same third-party ownership structure that drove the residential solar boom, adapted for commercial and industrial applications. What has changed is the recognition that the model requires a fundamentally different operational infrastructure than utility-scale development. Aggregating and managing hundreds or thousands of small distributed assets is not simply a scaled-down version of managing a few large ones. It requires automation at every stage: automated site assessment, automated financial modelling, automated permit tracking, automated commissioning verification, and automated ongoing performance monitoring and dispatch optimisation.
This operational complexity is where most EaaS providers have historically stumbled. Building the software infrastructure to manage distributed portfolios at scale requires significant upfront investment, and the revenue per site is modest -- meaning the business must reach substantial portfolio size before the unit economics work. Several well-funded EaaS startups burned through capital in the 2018-2021 period attempting to build this infrastructure while simultaneously acquiring customers and deploying assets, a capital-intensive combination that proved difficult to sustain.
Regional Dynamics: Four Markets, Four Different Constraints
The distributed energy market is fundamentally local, shaped by electricity tariff structures, regulatory frameworks, grid topology, and climate. Four markets illustrate the range of dynamics at play.
California remains the largest and most mature distributed energy market in the United States, but its economics shifted significantly with the implementation of NEM 3.0 (Net Billing Tariff) in April 2023. Under NEM 3.0, the export compensation for rooftop solar dropped by approximately 75% compared to the prior NEM 2.0 regime, from roughly retail rate to an avoided-cost-based rate averaging around 5 to 8 cents per kWh. This dramatically changed the economics: standalone solar became much less attractive, while solar-plus-storage systems -- which can store excess generation and discharge during high-rate evening peak hours -- became essential. The California Solar and Storage Association reported a sharp decline in residential solar permit applications following NEM 3.0 implementation, but commercial solar-plus-storage activity held up better, as C&I demand charge savings and time-of-use optimisation provide additional value streams beyond net metering.
The United Kingdom has seen a surge in commercial solar and battery deployment driven by persistently high electricity prices following the 2022 energy crisis. Average non-domestic electricity prices in the UK rose above 30 pence per kWh (approximately $0.38/kWh) during the crisis and, while they have moderated somewhat, remain elevated compared to historical norms. Solar Power Portal and industry associations reported that UK commercial solar installations exceeded 800 MW in 2023, a record. The UK market is also distinctive for its grid-side revenue opportunities: battery storage systems can participate in frequency response, the Balancing Mechanism, and the Capacity Market, adding revenue streams that improve the investment case. However, the UK grid connection queue has become severely congested, with National Grid ESO reporting over 700 GW of projects in the connection pipeline as of late 2024 -- many times the actual grid capacity -- creating multi-year delays that disproportionately affect smaller distributed projects.
Texas operates under ERCOT, the only major deregulated wholesale market in the United States without capacity payments. This means generators are compensated purely on energy and ancillary services, and scarcity pricing during peak events can produce extreme price spikes -- most notoriously during Winter Storm Uri in February 2021, when wholesale prices hit the $9,000/MWh cap for extended periods. ERCOT market data shows that behind-the-meter battery storage in Texas can capture significant value through wholesale price arbitrage and demand charge reduction, but the absence of a capacity market makes the revenue streams more volatile and harder to finance. The Texas market also lacks a statewide net metering mandate, meaning distributed solar economics vary significantly by retail electricity provider.
Australia has one of the highest rooftop solar penetration rates in the world, with the Clean Energy Regulator reporting over 3.7 million rooftop solar installations by mid-2024 on a population of roughly 26 million. This extraordinary penetration has created a new set of challenges: in South Australia and Queensland, midday solar generation regularly exceeds demand, pushing wholesale prices to zero or negative and reducing the value of solar exports. The Australian Energy Market Operator (AEMO) has had to implement minimum demand protocols and curtail rooftop solar generation on occasion to maintain grid stability. This has made battery storage increasingly important: a battery allows a household or business to shift consumption of self-generated solar from the low-value midday period to the high-value evening peak. The AEMO Integrated System Plan projects that distributed storage will be a critical component of grid management over the coming decade.
The Software Layer: Where the Economics Tip
The balance sheet problem is, at its root, a transaction cost problem. Each distributed site generates modest revenue individually -- perhaps $30,000 to $150,000 per year for a typical C&I system, depending on size, tariff, and market participation. If the cost of underwriting, deploying, and managing each site consumes a large fraction of that revenue, the economics do not work. If those costs can be reduced by an order of magnitude through automation, the economics become compelling.
This is where the distributed energy sector is heading. The combination of standardised hardware (solar panels and battery systems are increasingly commoditised), improving data availability (smart meter data, satellite imagery, utility rate databases), and advances in software automation (automated financial modelling, AI-assisted site assessment, algorithmic dispatch optimisation) is gradually reducing the per-site overhead that has historically made distributed assets expensive to finance and manage.
The companies that will capture the most value in distributed energy over the next decade are likely not hardware manufacturers or traditional project developers, but those that build the operational software layer -- the systems that can underwrite a site in hours rather than weeks, monitor thousands of assets simultaneously, optimise dispatch across an entire portfolio in real time, and present the resulting data to capital providers in formats that enable efficient financing.
The distributed energy thesis has always been sound at the level of physics and basic economics: generating and storing power at the point of consumption avoids transmission losses, offsets retail-rate electricity, and provides resilience. The challenge has been making that thesis investable at scale. That challenge is fundamentally one of software, data, and process automation -- not hardware cost curves or policy incentives. The balance sheet problem is real, but it is solvable. And solving it unlocks a market that, by the IEA's own projections, could represent the single largest segment of new electricity generation capacity over the coming decades.