What Renewable Energy Can Teach Us About Making Nature Investable
The policy architecture that turned wind and solar into an investable asset class—and what it could teach us about ecological infrastructure
In my last post, I argued that we do not need to wait for a new environmental market to begin investing in nature. Grassland restoration can already work within conventional farmland economics: land produces agricultural income, investors participate through a familiar asset class, and ecological improvement can strengthen the underlying asset without depending on the sale of a new credit.
But grasslands are only part of the answer to building a resilient future. Grazing income will not, by itself, finance the restoration of every wetland, floodplain, or riparian corridor we need to address the water challenges we have in the US. Natural infrastructure creates enormous public value, yet we do not have adequate mechanisms to compensate those that restore and maintain that infrastructure. We lack a systematic framework to effectively charge for that value to the communities, utilities, insurers, and businesses that benefit. As a result, the infrastructure has not been maintained and we experience the impact of this deferred maintenance on a regular basis.
We need to create the framework for greater capital to flow into natural infrastructure, and so we need to move beyond: “How do we put a price on nature?” to: How did another climate-positive infrastructure sector move from expensive, fragmented projects driven by sustainability to a repeatable market capable of attracting private capital at scale?
For the answer, we need to examine how renewable energy became investable.
Wind and solar did not scale because policymakers or investors discovered one perfect financial instrument. Nor did private capital simply arrive once the technologies became environmentally desirable. Renewable energy scaled because the United States gradually assembled a market architecture around it: independent power producers (IPPs) gained access to buyers; governments created demand (Renewable Portfolio Standards or RPS); long-term contracts converted that demand into predictable revenue (offtake agreements and Power Purchase Agreements); renewable energy certificates separated environmental attributes from the underlying electricity; tax incentives reduced project costs; and public finance absorbed risks private investors were not yet prepared to take.
Technology improved dramatically along the way. Manufacturing scale and competition lowered costs. But those gains occurred within a policy and financial system that gave developers a reason to build and investors a path to repayment. Those gains were possible because large amounts of capital were already flowing to the industry, creating incentives to improve technology and lower costs.
That distinction matters. If ecological infrastructure remains difficult to fund and finance, it may not be because nature lacks economic value. It is likely because we have not yet built the institutions that turn that value into durable demand and contracted cash flow.
First, the market had to open.
For much of the twentieth century, electric utilities were vertically integrated monopolies. They generated electricity, transmitted it, distributed it, and sold it to customers. An independent company could build a power plant, but it did not necessarily have a practical or legally enforceable route to connect to the system and sell its output.
The Public Utility Regulatory Policies Act of 1978—better known as PURPA—began changing that structure. PURPA established a new class of “qualifying facilities,” including certain renewable-energy and cogeneration facilities. It gave those facilities the right to sell energy or capacity to utilities and, subject to applicable rules, required utilities to purchase their output. Qualifying facilities could generally sell at the purchasing utility’s avoided cost—the incremental cost the utility would otherwise incur by generating the power itself or buying it from another source—or at a negotiated rate. PURPA also gave qualifying facilities certain interconnection rights and relief from some traditional utility regulation. (FERC).
PURPA did not create the modern renewable-energy industry by itself. Its implementation varied by state, and the avoided-cost framework has always been contested. But it established a foundational principle: an infrastructure service did not have to be produced by the incumbent utility in order to be purchased by the system.
That mattered because it gave independent developers a legally recognized path into a previously closed market. If a qualifying facility could supply energy at the utility’s avoided cost, the utility generally could not reject the purchase simply because it preferred to generate the electricity itself. The policy protected consumers from paying more than the utility’s alternative cost while creating a market opportunity for non-utility generators.
Think of many renewable energy companies that exist today that develop projects and sell them to utilities or own and operate themselves, selling power into the grid. Companies such as Invenergy and Doral Renewables are Independent Power Producers that operate within the market architecture that grew from the initial enabling effect of PURPA and other policies, discussed further below.
This may be the most important lesson for ecological infrastructure. A farmer, landowner, conservation organization, or restoration developer should not need to become a stormwater utility or flood-control district in order to provide water storage, peak-flow reduction, groundwater recharge, or nutrient removal. A future system could recognize independent ecological-service providers and create a standardized route through which public or regional buyers procure their services. This happens today on a fragmented basis, but a federally authorized program could require utilities, states and municipalities to look at alternative solutions to meet their objectives outside of their own system. Many government entities get hung up on “design-build” terminology and procurement limitations, but enabling legislation could address this in the same way that PURPA enabled procurement of electricity via IPPs.
THE WHY THEN: The federal government was motivated to pass PURPA because of the 1970s energy crisis and the need to strengthen domestic energy security.
THE WHY NOW: The federal government should be motivated to pass new enabling legislation for ecological infrastructure because it is becoming too expensive not to. In the first half of 2026 alone, extreme billion-dollar weather disasters cost $31.9 billion in damages and at least 183 lives.
Next, state-level policy created buyers.
Market access was necessary, but it was not sufficient. A developer can have the legal right to sell something and still have no dependable customer.
States addressed that problem through renewable portfolio standards (RPS) policies. These laws generally require utilities or electricity suppliers to obtain a defined share of their electricity from qualifying renewable resources. Instead of hoping that buyers would voluntarily pay more for cleaner power, states created recurring demand through regulation.
The scale of that demand has been significant. As of 2024, 29 states and the District of Columbia had binding RPS policies, while a growing number of states had adopted broader clean-electricity standards. Lawrence Berkeley National Laboratory estimates that almost half of the growth in U.S. renewable-electricity generation and capacity since 2000 was nominally associated with state RPS requirements, although the share has declined as other drivers have grown. (Lawrence Berkeley National Laboratory)
This is what voluntary ecological markets generally lack. Corporations, philanthropies, and public agencies may choose to fund restoration, but voluntary demand is vulnerable to changing budgets, leadership, and priorities. A project developer cannot finance a 30-year wetland restoration project on the assumption that a buyer might continue purchasing credits one year at a time.
Renewable portfolio standards created something far more powerful than environmental interest: an obligated buyer.
An ecological equivalent could require a defined amount of qualifying water storage, flood mitigation, nutrient reduction, habitat, or other landscape services within an appropriate geographic area. Because ecological services are location-dependent, this could not operate as a simple nationwide market. One acre-foot of water storage in the wrong watershed is not interchangeable with one acre-foot upstream of a flood-prone community. Demand would likely need to be organized at the state, basin, or watershed level. That makes it even more important to have state-mandated buying. Ecological infrastructure has to be distributed infrastructure and regionally specific to achieve the necessary outcomes.
The underlying principle still applies: markets scale when public policy turns a widely recognized need into recurring procurement.
THE WHY THEN: States adopted RPS amid electricity-market restructuring, growing environmental concerns, and a desire to improve energy security by diversifying the power supply and reducing exposure to fossil-fuel shortages and price volatility.
THE WHY NOW: States should be motivated to adopt Ecological Portfolio Standards (EPS) to reduce the impact of severe weather and environmental health hazards on its constituents, incentivize reduced reliance on foreign produced inputs like fertilizer, and strengthen domestic food and water supplies.
Certificates made an invisible attribute ownable.
Renewable Portfolio Standards created mandated buyers for renewable energy projects (utilities and electricity suppliers). There was also growing interest from corporations, often major electricity consumers, to switch to renewable energy sources. However, there was often a mismatch between where energy was consumed and where renewable energy projects were being built. Further, electricity from different sources becomes indistinguishable once it enters a shared grid. A customer cannot look at an electron and determine whether it came from a wind turbine, a solar array, a coal plant, or a hydroelectric dam.
Renewable energy certificates solved an accounting problem. A REC represents the non-power attributes associated with one megawatt-hour of renewable electricity generated and delivered to the grid. The certificate can be tracked, transferred, retired, and used to substantiate a renewable-energy claim. (U.S. Environmental Protection Agency)
That standardization allowed the environmental attribute to be recognized separately from the physical electricity. RECs became instruments for both compliance markets and voluntary purchasing by corporations.
Ecological infrastructure could also benefit from a standardized certificate that could be purchased in the voluntary market, and as a stop-gap in the compliance market while supply ramps up. It’s not a perfect analog to RECs, of course. A megawatt-hour is a standardized unit. Flood protection and water storage depend on location, timing, soil, antecedent moisture, watershed position, maintenance, and the intensity of a particular event. Ecological Infrastructure Certificates should therefore document a verified service within a defined geography; they should not imply that every unit is nationally interchangeable.
But it could provide a means for corporate buyers to start participating in this market. They already are, to some degree, through the Voluntary Water Benefit Accounting (VWBA) framework. What’s missing is a connection to a larger market framework that connects to regional watershed infrastructure and financing. The certificate would be the accounting layer. The physical project and its long-term service agreement would remain the foundation.
THE WHY THEN: Corporations started buying RECs to meet their sustainability goals in the absence of local renewable energy sources to supply their actual footprint. Utilities started buying RECs to meet their RPS when there was not yet adequate renewable energy projects to supply their actual footprint. The immediate effect was more funding flowing to renewable energy project development, and ultimately, more localized production as project development scaled.
THE WHY NOW: A few corporations are already buying VWBA projects. More corporations should be funding an ecological infrastructure equivalent to RECs because it offsets their supply chain impacts on water, biodiversity, and ecosystem function and reduces risk to their physical assets. Utilities could start buying these credits, but the more likely outcome would be that they would start investing in ecological infrastructure in their watershed proactively, potentially financed, in part, by the corporations tied to their geography.
Long-term contracts made projects financeable.
A mandate creates demand. It does not automatically make an individual project bankable.
Renewable-energy projects typically require substantial capital before they produce anything. Developers must secure land, permits, equipment, interconnection rights, engineering, and construction financing. These projects take multiple years and face complex permitting and engineering challenges, not unlike ecological infrastructure projects. Investors and lenders need confidence that, once built, the project will have a buyer and generate enough revenue to repay them.
Long-term power purchase agreements, or PPAs, became a central answer. Under a PPA, a utility, corporation, or other buyer agrees to purchase electricity—or the economic value associated with it—under defined terms for an extended period. The contract gives the project a predictable revenue stream. That predictable revenue, rather than the mere existence of sunlight or wind, supports project finance.
Left just to the utilities, renewable energy demand might have progressed more slowly. But there was a huge influx of demand from another buyer: corporations looking to offset their carbon footprint.
Utilities had long used PPAs, but their procurement was constrained by regulatory approvals, resource plans, and state requirements. Corporations such as Google, Amazon, Microsoft, Meta, and Walmart could create additional demand based on sustainability commitments and electricity-price hedging, as described above. Many used “virtual” PPAs: the corporation did not physically receive the project’s electrons but entered into a long-term financial contract and received the RECs. In just three years, corporations signed PPAs worth 57.4 GW from 2018-2020—unlocking tens of billions of dollars in renewable energy project investment.
Corporations signing PPAs were going beyond RECS—they were not simply making charitable sustainability commitments. Through physical or virtual PPAs, they entered into long-term contracts tied to the output of renewable-energy projects. In a common virtual PPA structure, the independent power producer retained ownership of the project and sold its electricity into the wholesale market, while the corporation and producer settled the difference between the market price and an agreed contract price. The corporation effectively was buying a futures contract on energy pricing.
The corporation typically received the renewable-energy certificates, while the producer gained the predictable revenue needed to finance construction. The corporation did not need to take physical delivery of the electricity for the contract to create value—but it also did not ordinarily own or resell the power itself.
This is the bridge that ecological infrastructure is largely missing.
Watersheds are not electricity grids. A corporation could sign a “Ecological Infrastructure Purchase Agreement” (EIPA) to finance a watershed restoration project, but in the current landscape, they would be just making a charitable sustainability commitment. This is how VWBA contracts work today—similar to a REC-only purchase.
Alternatively, corporations could become mandated buyers based on physical footprint of facilities, in which case their acquisition of ecological infrastructure effectively becomes part of their utility bill. That second structure is better, in my opinion. That structure better accounts for the corporate benefit of the infrastructure—lower risk of negative impacts to their physical assets. It also potentially makes the purchase more on par with an asset they can sell. If corporations invest through EIPAs, their physical footprint could have lower insurance or higher land value, which could be “resold” to future tenants.
Sidenote: A “hedge” on water prices doesn’t seem to make sense, as we don’t price water today like we do electricity and it’s not as “movable” as electrons, but there may be other analogs that do.
THE WHY THEN: Corporations signed long-term renewable energy PPAs for two reasons: 1) to obtain RECs, offset their carbon footprint amidst growing concern about climate change and help bring new renewable energy projects online (additionality); and 2) to secure a long-term financial hedge on energy prices (a financial asset rather than sustainability alone).
THE WHY NOW: A few corporations are already making voluntary investments in water stewardship due to a growing recognition that water supplies are valuable and under threat, or to support their social license to operate. We need this to grow beyond voluntary sustainability into a recognized financial investment that generates real ROI through reduced risk to physical assets. Some regional utilities are already doing this through proactive investment in ecological infrastructure. A standardized market framework for EIPAs or equivalent could accelerate the pace of investment.
Public incentives improved project economics.
Renewable-energy markets were also supported by public incentives that reduced the cost of producing a desired public benefit. The federal Production Tax Credit supported qualifying electricity generation on a per-kilowatt-hour basis, while the Investment Tax Credit reduced the upfront tax cost of eligible projects. More recent law has shifted toward technology-neutral clean-electricity credits, but the underlying function remains familiar: public policy improves project economics so private capital can deploy more rapidly. (Internal Revenue Service)
Tax incentives did not replace demand or contracts. A tax credit without a buyer does not produce a viable project. But incentives reduced the amount of revenue a project needed to support its capital cost and helped technologies move down the cost curve.
Public finance played a related role. The Department of Energy’s loan programs have supplied loans and loan guarantees for projects and technologies that faced barriers to conventional commercial financing, helping bridge the gap between demonstration and widespread deployment. (U.S. Department of Energy)
An ecological-infrastructure system could use a similar toolkit: tax credits for restoration construction, grants for public benefits that cannot be captured, loan guarantees for early projects, revolving funds, first-loss capital, and support for measurement and project development. These tools would lower costs and absorb emerging-market risks. But, as with renewable energy, they would work best alongside recurring demand and long-term contracts.
THE WHY THEN: Federal tax incentives helped unlock financing capacity that otherwise would have been slower to deploy debt to new technologies or nascent project developers, slowing down renewable energy project development.
THE WHY NOW: There are sources of catalytic capital that can play a role in financing ecological infrastructure projects if there is a guaranteed buyer, but the returns are often not high enough for institutional investors, or the cost of capital can challenge the economics of long project development cycles. Tax incentives earmarked for these ecological infrastructure projects would accelerate the pace of institutional capital looking for these projects and stimulate project development timelines.
Scale reinforced itself.
Once these pieces were in place, renewable energy became more than a collection of environmentally motivated projects. It became a recognizable asset class.
Developers could assemble pipelines. Lawyers and lenders could reuse contracts. Engineers and contractors gained experience. Manufacturers invested in supply chains. Investors learned to underwrite resource risk, construction risk, interconnection risk, and offtaker credit. More projects meant more data, greater competition, lower transaction costs, and technological improvement.
The results are visible in federal generation data. Among independent power producers alone, utility-scale solar generation grew from about 13.8 million megawatt-hours in 2014 to 185.3 million in 2024. Wind generation from independent producers rose from roughly 153.8 million to 362.6 million megawatt-hours over the same period. (U.S. Energy Information Administration)
No single policy deserves all the credit. Renewable energy also benefited from public research, global manufacturing, state procurement, federal incentives, corporate purchasing, transmission investment, competitive auctions, and dramatic technological gains. Policy mistakes and uneven implementation were part of the story too. Interconnection queues, transmission constraints, permitting disputes, local opposition, and policy uncertainty continue to limit development.
The relevant lesson is not that renewable policy was simple or perfectly designed. It is that scale emerged from a system of reinforcing institutions.
Ecological infrastructure projects are slow and cumbersome to develop right now. Getting municipal buyers to commit and fully understand their cost benefit analysis is a huge lift, and they often cannot see the benefit until the project is 30% developed. Right now, there is no systematic way to finance that development speculatively, but the need is high for investment. The market is ripe for a framework with levers at the federal, state, regional, municipal, and corporate levels.
WHY THEN: Renewable energy scaled because of systems-level legislation and investment, not just one policy. But aligned forces drove the process forward—bipartisan interest in reducing reliance on foreign energy, improving air quality, and ultimately, reducing electricity costs.
WHY NOW: Resilience to extreme weather, flooding, drought, global supply chain disruptions and demand for clean air and water are bipartisan priorities, or should be. We can’t ask individual taxpayers or municipalities to solve system-level problems with Band-Aids. We need to create the framework for institutional investment and systematic governance for widespread adoption.
Ecological infrastructure has pieces of this system—but not the full architecture.
None of the individual tools proposed here is entirely new. Mitigation banks, water-quality trading, stormwater credits, environmental impact bonds, water funds, revolving loan funds, payments for ecosystem services, and Forest Resilience Bonds already demonstrate parts of the model.
Some of these strategies are genuinely commercial. Wetland mitigation banking, for example, shows that regulation can create demand for verified ecological outcomes and support private project developers. But these markets generally compensate for permitted environmental damage; they do not broadly procure new resilience capacity in advance of disaster.
Other models aggregate beneficiaries or use private capital, but remain bespoke, geographically narrow, grant-supported, or dependent on philanthropic participation. What the United States does not yet have is a widely adopted market architecture that turns watershed resilience into standardized, long-term, infrastructure-grade cash flows.
Renewable energy suggests the components that architecture may require:
1. A public standard that creates recurring demand for qualifying ecological infrastructure.
2. Market access for independent providers, including farmers, landowners, and restoration developers.
3. A regional or watershed-scale buyer with authority to aggregate beneficiaries and recover costs.
4. Long-term service agreements that pay for verified, maintained capacity.
5. Certificates or registries that document ownership and prevent double counting.
6. Tax incentives, grants, guarantees, and low-cost financing that improve early project economics and protect affordability.
7. Standard contracts, measurement protocols, and performance data that allow projects to be repeated and underwritten.
That is a larger proposition than creating a new environmental credit. It is an infrastructure-market design problem.
We already pay for the absence of resilience.
The predictable criticism is that such a standard would impose a new cost on utilities, municipalities, businesses, or taxpayers. That concern deserves to be taken seriously. Water systems and local governments already face major affordability and maintenance challenges.
But unstable water is not free. Society already pays through flood damage, disaster relief, insurance claims, crop losses, emergency repairs, business interruption, water shortages, rising food prices, and household displacement. Those costs are fragmented and reactive, and they often fall hardest on households and communities least able to absorb them.
The question is not whether we pay. It is whether we continue paying primarily after systems fail, or begin converting a portion of those expected losses into planned investment before disaster occurs.
Avoided loss, however, is not automatically revenue. Even when a wetland is expected to prevent millions of dollars in future damage, investors cannot be repaid unless beneficiaries or public institutions agree to convert part of that value into contractual payments. That is why regional institutions, procurement standards, and long-term agreements matter.
Renewable energy did not become investable because society merely acknowledged that cleaner electricity was valuable. It became investable when policy connected that value to buyers, contracts, standardized claims, and finance.
Ecological infrastructure will require the same kind of institutional work.
Grasslands show what we can finance within the market we already have. The next challenge is to build the market that wetlands, floodplains, and resilient landscapes still need.
In the next post, I will explore what this framework could look like in practice: what if a restored wetland were developed and financed more like a renewable-energy project, with independent developers, long-term service agreements, verified performance, and multiple beneficiaries sharing the cost?
References
· Federal Energy Regulatory Commission. “PURPA Qualifying Facilities.” https://www.ferc.gov/qf
· Internal Revenue Service. “Clean Electricity Production Credit.” https://www.irs.gov/credits-deductions/clean-electricity-production-credit
· Lawrence Berkeley National Laboratory. U.S. State Renewables Portfolio & Clean Electricity Standards: 2024 Status Update. https://eta-publications.lbl.gov/publications/us-state-renewables-portfolio-clean-0
· U.S. Department of Energy. “LPO Year in Review 2024.” https://www.energy.gov/edf/articles/lpo-year-review-2024
· U.S. Energy Information Administration. Electric Power Annual, Table 3.3.B: Net Generation from Renewable Sources: Independent Power Producers, 2014–2024. https://www.eia.gov/electricity/annual/table.php?t=epa_03_03_b.html
· U.S. Environmental Protection Agency. “Renewable Energy Certificates (RECs).” https://www.epa.gov/green-power-markets/renewable-energy-certificates-recs
*AI Disclaimer: I used AI to research parts of this post, but the concepts proposed and arguments made are all my own.