Renewable Developer Economics

Historically, renewable energy projects have been developed by ‘developers’ who progress projects to a shovel ready state and then sell the project rights to a long-term equity investor (for example, an infrastructure fund) who builds the project and owns it long-term.   However, there is an increasing trend of infrastructure investors investing in platforms that undertake both development and long-term project ownership activities.  From the investor side, this trend seems to be driven by a desire to boost overall returns, with a view that platforms offer materially higher returns compared to investing solely in renewable energy projects.  This additional return is important in the current market context, where equity investment in renewable energy projects is struggling to attract capital, particularly in a higher base rate world, compared to private debt investment or investment in more traditional infrastructure assets (e.g. regulated utilities, airports, etc.).

Therefore, we thought it would be interesting to talk about the economics and lifecycle of renewable energy development and provide our opinion as to whether this is an appropriate move (spoiler: we don’t think it will materially improve returns).

Let’s start with an explanation of each step of the process for a project developer.

Step 1 – Land Option

The first stage of a renewable energy project is to find an attractive location for a project e.g. close to existing/planned transmission infrastructure and strong solar irradiance/wind resources. If a site is suitable, the developer will secure an option to enter into a lease over the land with the landowner(s).  For a solar/battery project this would usually be with one or two landowners. For wind projects, it is not uncommon to have quite a number of landholders involved.   The upfront cost of the land lease option is usually pretty low (eg $10-100k per landholder). The option for a land lease grants the developer the right to conduct investigations on the land to determine the feasibility of the project including making grid connection, environmental and development applications.  For wind projects, it is common for meteorological equipment to be installed to establish a baseline for wind speeds at the site.

Step 2 – Grid connection and Development/Environmental Approvals

The developer will then submit a grid connection application to the relevant grid operator, as well as AEMO, and a development application to the relevant government body for approval. For smaller-scale solar and BESS projects the development application is submitted to the local council. For larger scale solar, wind and BESS projects, State and Federal Government approval may also be required. Larger projects often need to run the gauntlet of the so called EPBC approval process (under the Environmental Protection and Biodiversity Conservation Act 1999).

Parallel to this process is engagement and consultation with stakeholders, particularly First Nations communities and affected landholders in the area to build community support for the development.

Overall, the approvals process will generally cost 0.5-3% of the total build cost, taking around two years for solar/BESS projects and much longer for wind projects.

The breadth of the overall approvals process means many projects fail at this stage. It takes only one bad outcome for a project to be cancelled. This could be because approval cannot be obtained, for example due to community opposition, environmental issues (e.g., impact on local wildlife), or a concern from First Nations stakeholders. It could also be due to additional costs to achieve a grid connection or to mitigate environmental or community issues which render the project unviable, for example, the project is unable to connect to the grid without a large grid upgrade cost.

Step 3 – Construction Arrangements/EPC

Assuming the developer has been successful in navigating the various approval processes, they now must decide on what equipment to use. The grid connection and approvals process often locks in some of this equipment at an early stage, for example, the grid connection for a solar farm/BESS would often require specification of which model inverter will be used.

Developers also often seek to have a third-party contractor to take responsibility for the Engineering, Procurement and Construction (EPC) of the project on a fixed price basis. However, with the growth in the size/complexity of projects, it is becoming increasingly common to see unbundled delivery arrangements with separate contracts with key equipment suppliers (e.g., battery manufacturers or turbine manufacturers) and balance of plant contractors (who install this equipment on site and connect it to the grid).

Every project is different, and it is only at this point the developer will know how much the project will cost to build!

Step 4 (Optional) – Revenue Contracting

Most greenfield renewable projects seek to have a material portion of their revenue contracted with an offtake for the initial years of operations (usually the first 10 or so years).  This makes the cash flows of the project more predictable and, hence, more attractive to potential capital providers(both equity and debt).

A key issue is the relativity between project revenues and project costs.  If costs are high relative to expected revenues, then expected returns would be poor. Poor returns make it difficult to attract equity (and debt).

Step 5 – Equity (and Debt)

Traditionally, renewable energy project developers didn’t have access to sufficient capital to fund the construction of projects.   Thus, the final step of the development process was to sell the project rights (eg the land options, the various approvals and the rights under the various EPC and offtake contracts) to a counterparty who will undertake (and fund) the project.   This will be an infrastructure investor or vertically integrated retailer which is looking to own the project over the long-term.  These parties are not usually interested in taking development risks (i.e. the possibility of grid connection/development/environmental approvals not being obtained) but are better placed to fund the high capital costs of building a project (and are better placed to take long-term electricity price and operational risks).

Fundamentally, a project with an attractive risk/return profile to investors will be ‘saleable’.

The ‘risk’ side of the equation can be improved through an appropriate allocation of risk stipulated in construction (EPC) and operations and maintenance (O&M) contracts with third parties. For example, arrangements where the EPC contractor compensates the investor for any delivery issues/delays will lower construction risk from the perspective of the investor and incentivises the contractor to meet project deadlines.

The ‘return’ side can be improved by obtaining attractive revenues, commonly an offtake from a counterparty with a strong credit quality (eg Government entity or big 3 retailer). The developer can also generate return by improving capital and operating costs relative to revenue, that is, negotiating competitively priced EPC and O&M contracts.

Higher returning projects will command a high development fee i.e., premium over future costs paid by equity investor for project rights. A low returning project will earn a low fee, or it might not even be possible to attract equity.   In this case, the project wouldn’t proceed.

Development premiums are typically in the 5-20% of total project costs range.   For a renewable energy asset owner that undertakes its own development activities, this development premia is effectively captured through a lower cost base for projects it self-develops (compared to projects acquired from 3rd parties where a development fee is paid and forms part of the project cost).

Why developers earn their multiples

Renewable energy development is a risky game. It involves coordinating a lot of moving parts, the vast majority of which are outside the developer’s control. At any point in the development process, the project may be stalled, rejected by the relevant grid/development authority, or face material opposition to the project by stakeholders.

Even if a project is awarded a grid connection and development approval, there is no certainty that the developer can obtain an attractive offtake or EPC arrangement, find an investor that likes the risk/return profile of the project, and is willing to pay the developer’s expected premium. This is worsened by a multi-year development timeline which exposes the project to unpredictable macroeconomic cycles and conditions which change return hurdles for investors and inflate construction costs from what was previously envisaged.

If the developer is unable to line-up all elements of the development process up, they will lose all their initial capital spent on the land lease option, investigative works, grid connection and development applications and supporting studies.

For the risk developers take on, they definitely earn their premium!

Renewable Energy Development vs Venture Capital

Developers are in a lot of ways the ‘venture capitalists’ of the renewable energy industry. Where a VC fund invests in a portfolio of different early-stage companies, developers will undertake development activities on a portfolio of project sites at any given time. Theoretically, the strong payoff from one successful development will offset the losses on those that end up not proceeding.

Developers are also like VCs in the way they think of returns. VCs are chasing ‘multiples’ on their money, for taking on the risk of investing in an early-stage company. Likewise, the developer has likely spent up to 2-4% of total project capex in the hope of receiving 5-20% of total capex from an equity investor, generating a multiple on the costs incurred.

Critical to realising prospective multiples is having the skill to both (1) secure locations that have a high probability of housing a successful development, and (2) be able to quickly identify and cancel projects that will not be successful before spending significant amounts of money. This is a difficult task even for experienced developers.

Demand vs Pipeline

AEMO’s 2024 Integrated System Plan (ISP) includes forecasts with respect to how much capacity of each renewable technology should be installed in an ideal world for Australia’s energy transition. It displays a large demand for new renewable energy projects out to 2030 and beyond under the highest likelihood ‘Step Change’ scenario. This is to replace coal and gas-fired fleet, as well as potentially meeting growth in electricity demand. Per the below graph, solar capacity is expected to increase 65% from today’s capacity, onshore wind at 228% and batteries at a staggering 650%.

This sounds all good and well for developers, but let’s compare this to the pipeline forecasted to be operating by 2030.

The renewables pipeline overshoots the ISP forecast quite dramatically. For wind this is 35GW over, solar is 45GW and utility scale storage is a massive 70GW over!

Therefore, it is likely that only one in four pipeline projects will actually be built. Note the other 75% have already incurred material development costs.

Institutional equity & development – a good match?

We see claims that moving from investing purely in projects to investing in a platform that is a developer plus a portfolio of completed projects can boost returns by 1-2% year.   That is, a 9% project only return might become 11% blended platform return.

Mathematically this seems hard to achieve as, while the development premium is very high return on deployed capital, it is a small sum for a short period and, hence, has a reasonably weak impact on total IRR.

To illustrate this, we took an imaginary $100m project with an underlying equity IRR of 9% over a 35 year life.  We then blended these returns with a notional development phase with $2m million invested.  The key parameter is what multiple does this development stage development capital deliver in terms of notional development fee (which is effectively a saving in cost compared to a typical shovel ready project)?

To boost returns by 2%, requires a multiple of just under 6x.   That is, the $2m in costs delivers a $12m development fee.  This would be a fantastic result for a developer, and would be achieved for some projects.   Where it isn’t realistic, in our view, is that you need to account for all the losses on projects that never proceed (as well as the development fees on the ones that do) to fairly assess the benefit of getting involved in development.   In our view, a net multiple of 2x, is more realistic.   In this case, while the development is still very profitable (an IRR of more than 40% on the $2m of development capital), it has a de minimus impact on overall equity IRR – increasing only 0.3%.  That is, given the small dollar amounts and short period (relative to the life of the underlying project), adding in developments probably doesn’t add as much to returns as people might think.