Why develop a solar project?​​

Investing in solar energy offers numerous advantages, not only for individuals and companies but also for the environment.

From a financial perspective, solar projects can be highly profitable, and developers and asset owners can benefit from:

• Ongoing income from electricity sales
• Potential profits from selling the project
• Supportive government policies create a favorable investment climate but before getting to the point of financing your projects, it is worth the time to check out the crucial elements that should be on your solar project teaser.

Selling solar projects​

Developers can sell solar projects at various stages, from pre-development to operational. Projects closer to completion typically fetch higher prices due to reduced risk and quicker time to market. The decision on when to sell depends on the developer’s strategy and the stage of project development.

Selling the electricity ​

The primary financial benefit of solar projects is the sale of electricity. Depending on where you are in the world, a 1-megawatt solar project typically generates between $21,250- $42,500 per acre per year. and significantly more than this in some markets.

While initial land preparation costs are substantial, scaling up by adding more panels can increase electricity output without proportionally increasing costs. Bulk purchasing of solar panels can further reduce expenses.

Government incentives​

Governments across the world are keen on encouraging the development of renewable projects for several reasons, including energy security and meeting agreed-upon climate targets, such as the EU’s goal of reducing its emissions by at least 55% by 2030, compared to 1990 levels.

For developers, the push by governments to meet targets means that it is not only a great time to enter the renewable energy sector but also, a great time to turn large profits.

Many governments, from local to national scale, may offer rebates and other financial incentives that can help with the transition to renewable energy. To know more we suggest you look at the EU policies for funding the renewable energy sector.

Challenges in securing funding for solar projects​

Despite the environmental benefits, obtaining funding for solar projects hinges on solid economic planning. The cost of solar energy generation has significantly decreased over the past decade, primarily due to cheaper Chinese solar panels and increased manufacturing efficiencies. However, upfront costs remain a considerable barrier.

Additionally, whereas the cost of materials was previously closer to 50% of the initial solar project development costs, this is now closer to 10% for some companies. This decrease in costs can largely be attributed to increases in manufacturing efficiencies and as such, manufacturing costs. However, this upfront cost, among others, still represents a significant and often problematic investment for many businesses and organizations.

The biggest challenge in raising capital is attributed to the large levels of early-stage risk. With all costs taken into account, a 1 MW solar power plant easily sets you back between $890,000 and $1.01 million. but returns on the solar project investment are between 10-20% on average. Most solar farms pay off their system within five to ten years, and then have at least 20 years of almost “free” electricity after that.

These upfront costs include site surveys, feasibility studies, planning permission applications, power generation license applications, legal fees, site preparation fees, cost of materials, and many more. We cover this in more detail here.

Given the risks of permission applications getting rejected or developers’ teams not being able to execute for other reasons, coupled with high fees, early-stage renewable projects can be very risky for investors, which is also reflected in the price they are willing to pay.  

However, once planning permission is granted, the projects are mostly considered low risk. Solar development is a rapidly growing industry, and with careful planning, all these challenges can be overcome.

Types of Solar Project Financing ​

Self-financing​

For those with available capital, self-financing allows complete control over the energy produced. This is most common for smaller projects where the energy is primarily for personal or business use. The project owner pays for the equipment and installation costs. The greatest benefit of this option is that the individual or company then owns and has control over all the energy produced; hence it is used most frequently for small projects where most or all energy is to be consumed.

Solar leasing​

While some may have the option to absorb the entirety of the cost, this is not always possible or most efficient.

Leasing solar PV systems avoids the upfront costs of purchase and installation. This option, which involves fixed monthly payments, is prevalent in residential rooftop projects and some commercial and industrial (C&I) projects.

Funding for larger-scale projects​

Utility-scale solar projects demand significant financial investment, and developers strive to secure the least expensive capital while minimizing their risk exposure. Various financing options are available, each involving different levels of third-party involvement.

In the early stages of development, equity financing is typically the most accessible due to the inherent risks and challenges. For projects that are ready-to-build (RTB), debt financing becomes more viable and cost-effective, provided a predictable revenue stream is established.

From a profit-maximizing perspective, developers often prefer to leverage debt as extensively as possible. This strategy minimizes the need for equity investment and enables rapid access to asset bases without being constrained by their own financial limitations.

De-risking revenue: PPAs ​

Securing cash flows can be achieved through Power Purchase Agreements (PPAs). These long-term contracts (usually 10+ years) between developers and energy buyers ensure a fixed rate for the electricity generated. Buyers can range from corporations to governmental bodies, each with distinct risk profiles.

PPAs are key to most utility-scale solar projects since they represent a low-risk and predictable source of revenue, given that the buyer is chosen carefully. With a signed PPA, the guaranteed revenue typically unlocks other sources of funding.  

Construction and installation​

With permits and financing secured, the construction and installation phase of a solar project can commence.

This phase is where the physical solar panels and equipment are installed on-site and connected to the power grid. It includes several key steps that require careful planning and execution.

Bank loans/Debt financing​

Debt can finance 60-80% (sometimes more) of a project’s capital outlay. Lenders bear no upside but face full downside risk, making risk assessment crucial. Traditional debt forms, such as personal and company loans, rely on historical financial metrics like repayment history and cash flow available for debt service (CFADS).

For new developers with no cash flow history, leveraging large debt amounts can be challenging and sometimes not even a possibility.

If you’re not put off by the thought of taking on large amounts of debt to finance the construction of your first projects or to rapidly accelerate the number of projects, then let’s look at project financing.

Project financing​

Project finance is transformative for developers, enabling them to isolate risks, secure more borrowing, and accelerate development. Unlike corporate financing, project finance involves creating a Special Purpose Vehicle (SPV), where loan repayments come solely from the project’s cash flows, typically generated by selling solar energy.

This method confines revenue risks to off-taker or counterparty risks, avoiding complications from other corporate activities. It usually features a non-recourse structure, limiting collateral to SPV assets and protecting the corporate owner’s balance sheet.

Equity financing​

For capital-intensive projects, equity financing often fills the funding gap left after securing debt. Typically, if a project is 60-80% debt-financed, the remaining 20-40% is covered by equity or shareholder loans, which can be even more efficient.

This involves issuing project equity in exchange for funding. Unlike loans, equity financing doesn’t require repayment; instead, investors receive a share of the project’s profits, which allows project owners to maintain control while providing investors with potentially high returns, incentivizing them to undertake higher risks associated with early-stage renewable projects.

How to find the right investor for your solar projects​

Whether you’re a new or seasoned developer, you’ve probably already witnessed first-hand that there are many investors out there, many of whom are willing to invest in renewable energy projects.

Although finding investors for solar projects is easy, finding just the right one typically proves itself to be a whole different game, oftentimes taking multiple months, especially if you want to be sure that you also get the optimum price for you project.    

Having been in this business for nearly a decade, we know the struggle, but we also know the solution to it.

Read more about how we help developers find the right investor for utility-scale solar projects.

La entrada How To Finance Your Solar Project se publicó primero en We turn good projects into great deals - Green Dealflow.

In addition to developers actively seeking sites to deploy more PV, land owners are also proactively pushing for more deployment on their land in a move to generate supplementary incomes with lease prices for PV installations ranging between £3000-3500 Euros per hectare in Europe, which is a substantial increase compared to the average farm lease price of 357Euro per hectare. In most countries, this trend is amplified by an ever-increasing renewable energy investment market and favorable development conditions led by various government incentive plans, such as the EU Solar Strategy.

This article will cover the considerations when building a solar farm, from initial thoughts to the final financing.

What is a solar farm?​​

Photovoltaic power plants, also just commonly referred to as solar farms or solar parks, use large arrays of solar panels to capture sunlight and convert it into electricity. When people talk about solar farms, this type is usually what comes to mind.

These installations are mostly ground-mounted and located in areas with high solar radiation and can range from a few megawatts to hundreds of megawatts in capacity, even gigawatts, like the current largest solar farm in the world boasting a huge 5 GW of capacity.

Solar farms come in two different versions: utility-scale solar farms and community solar farms.
Let’s cover their differences. 

Utility-scale solar farms ​

This type of solar farm is normally a rather large farm compared to community solar farms, but there is no generic number that defines the scale of a utility-scale solar farm since the capacity of the individual farm depends upon the local market to which the solar farm will deliver its power. In some places, farms producing only 1 MW of power are counted as utility-scale, while in others, utility-scale solar farms must produce more than 25 MW.

 It is common for utility-scale solar farms to have long-term agreements in place – often 10-20 years – with an ‘off-taker’ such as a utility company, government entity, or private business to buy their energy in what is known as a Private Purchase Agreement (PPA). PPAs are contractual agreements between energy buyers and sellers. They come together and agree to buy and sell an amount of energy that is or will be generated by a renewable asset, this provides financial security for the developer while the off-taker knows how much energy to expect coming

Community-scale solar farms​

Community-scale solar farms are generally smaller and provide power used for commercial or community consumption in a local area. Often working on a subscription basis, residents or local inhabitants can subscribe to a local community solar farm, using it to typically enjoy reduced power bills as a result.

Future demand for solar​

In the EU, the total solar power capacity reached 259,99 GW, up from 204,09 GW the year before. The EU predicts that it can manage to reach a total solar capacity of 320 GW by 2025 and almost 600 GW by 2030, leaving plenty of space for more growth.

The really encouraging aspect of solar farm development is how accessible it is to private individuals when compared to fossil fuel energy production. Granted, establishing a solar farm is a cost-intensive investment, however, routes to third-party investment are becoming more accessible as we’ll explore later on in this article. Further to this, the cost of generating solar energy becomes cheaper with every passing year due to advances in technology and the widespread production of solar generation components. 

How do you make money from a solar farm?​

Traditionally, there are two main ways to make money from solar farms. These include leasing land to a renewable developer or, developing the land and operating the solar farm yourself.

Farmers across the EU are increasingly aware of the supplementary income that’s possible to generate from leasing their land to developers, with prices in some countries ranging between €3000-3500 per hectare. This annual rate is for most crops more profitable than what’s possible to generate from crops. However, this trend has caused some politicians to put the brakes on solar farm development on what’s being classified as prime agricultural land over fears that it might compromise local food supplies in the long run.

But given that it’s a possibility to lease and get approval to build a solar farm, the main benefit to leasing your land is that you just need to provide the land, and the project developer will do the rest.

On the other hand, if landowners have access to renewable energy project investment to develop the solar farm themselves, they stand to make money off the electricity that they generate and earn an average ROI of 10%-20% per annum. These numbers vary, in the US for instance, it’s possible to make $21,250- $42,500 per acre per year.

It’s important to consider where your solar farm will be as this will determine how much solar energy it will be able to generate.

Whichever model you choose, income will trickle down into your pockets by selling energy to off-takers that include utilities, government entities, or private businesses via a Private Purchase Agreement (PPA).

Solar farm development considerations​

If you choose to act as the project developer and build the solar farm, there are several common mistakes and considerations that you need to be aware of before committing. Below, we’ve compiled a list of these considerations.

Also read: Our grand guide to PV project development

Environmental permits​

The location of a proposed solar project will determine how difficult it will be to attain a valid environmental permit with different countries having different regulations in place.

It’s important for developers to determine – as early as possible – whether they will be required to obtain such permits. This information should be available on local authority websites.

Figuring out whether you’ll require a permit means conducting an environmental impact assessment (EIA) which will evaluate the effects of the project on the surrounding wildlife and habitats – in some cases, a wildlife and habitat protection plan may need to be developed.

Site selection​

Location can make a big difference, not just in terms of solar irradiance but also, in whether your solar project can go ahead. 

The first consideration is the amount of sunlight/direct light the area gets as this will massively impact the output of the panels. The land should be flat, and ideally south-facing. It should get at least 4 hours of peak sun per day.

You will need to check the local zoning laws and land-use regulations since these vary across the EU.

Grid access is an important factor, if not the most important factor. You’ll need to make sure that your land will have access to the grid and how long it will take for your project to get a grid connection, and lastly, make sure that the site isn’t located in an area that’s prone to flooding.

Financial planning​

Starting a solar farm requires capital. A lot. The starting phase of the project is always the most capital-intensive when the infrastructure is being built. The good news is that roughly 1/3 of the costs associated with a solar farm are directly related to the solar panels, and these are currently at an all-time low, falling 40% in the last twelve months alone.

The cost of a 1 MW solar power plant varies depending on a number of factors, including:

• The type of solar panels you choose
• The efficiency of the solar panels
• The cost of labor and materials in your area
• The amount of land you need
• The permitting process

In general, you can expect to pay between $0.89 and $1.01 per watt for a 1 MW solar power plant. This means that a 1 MW solar power plant could cost between $890,000 and $1.01 million.

Don’t have the money on hand? Few do. There are many funding options out there to assist, including financing part of the capital expenditure through raising debt and typically bringing on board investors to cover much of the remainder or the whole lot.

You may give equity in exchange for the money, or agree on repayment options with a financial institution and retain full ownership of the solar farm.

You can learn more about funding and how to source capital for a solar farm in our article on how to finance your solar project.

Government incentives​

Depending on where you are in the world, various governments have different incentives to promote the development of solar energy infrastructure. What you can access will depend on where you are and the current schemes, but common financial incentives include tax incentives, capital subsidies, subsidized loans, and generation-based incentives.

How much financing you need and what financing options are right for you will depend heavily on how big your solar farm will be, where it’s going to be built, who it will serve, and more. Think about whether you are creating a utility-scale farm, a solar farm for a specific nearby commercial off-taker, or a farm just to power nearby residential consumption. The size and type of off-taker will determine the revenue risk and hence the kind of financing options available.

If you are seriously considering starting a utility-scale solar farm and are looking for financing options or investors, then read more on how we can help you find the right investor.

Equipment and technology​

Understanding the equipment that you are purchasing and the pros and cons that come with each part is important. Additional research and speaking to an advisor before going ahead with anything is recommended, but here are a few basics that you may find useful. 

Permitting and compliance​

Although governments in the EU are currently adjusting local legislation to align with the European Solar Strategy, it is still necessary to research the regulations in your local area since regulations still vary country by country.

The approval procedure can be quite rigorous; planners prefer to grant permission on unused land that is poorly suited for farming. If the land is agricultural, permission is more likely to be granted if the land can be dually used (e.g. grazing, wildflower meadows, etc.). Planners will look at socio-economic and ecological factors and the environmental impact of decommissioning the farm. This makes leasing more attractive to some individuals because it requires less work for the landowner.

Operations and maintenance​

There are operational and maintenance costs to a solar farm, although these tend to be low because there are few moving parts unless you choose trackers for your panels.

Estimates vary, but the annual maintenance may cost around 2% of the system’s startup cost per annum for a small farm, and 1% for a large farm.

Panels need cleaning and damage inspection at least twice per year. You should establish a schedule for panel maintenance. Your installer should visit twice each year to check everything is working correctly.

Read about the most common problems with solar panels.

You will also need to develop systems for monitoring the production of energy and how it is being used. This will help you to ensure that everything is running as it should be.

You should put a contingency plan in place to help you deal with any equipment failures. 

Although solar technology is good, no technology is infallible, so issues will eventually come. Having a plan allows you to respond promptly, minimizing the farm’s downtime. 

Remember that PV panels have a life expectancy of around 25 years, while monocrystalline panels should last upwards of 30 years. In the long term, you will need to think about panel replacement costs.

Community engagement and outreach​

Solar farms aren’t always the most popular addition to an area; although many people recognize the need for more solar power, nobody wants these farms in their backyards!
That means it’s important to spend time engaging with the local community, building relationships with the local authorities and organizations, and encouraging the public to get on board with your plans.

You should also work to listen to and address any concerns that local people have and do what you can to minimize the damage and disruption done to the surrounding countryside.

If you need a bit of inspiration, then take a look at our case study on how the Danish developer Andel managed to overcome NIMBY and gain plenty of public and local support for its onshore renewable energy projects.

La entrada Considerations When Building A Solar Farm se publicó primero en We turn good projects into great deals - Green Dealflow.

Inadequate Preliminary Assessments: A Costly Oversight​

One of the top mistakes PV developers make is failing to conduct a thorough preliminary project assessment, which covers both site assessment and feasibility studies. This critical step ensures that the chosen location is suitable for Solar PV installations and can significantly impact project timelines and costs. 

• Tip: Perform a comprehensive site evaluation and feasibility study, considering factors like soil quality, shading, and proximity to transmission lines. We cover these things in a more in-depth way in our guide on solar project development. 

Poor Financial Planning: The Road to Delays and Overruns​

Underestimating the financial needs of a Solar PV project is a common yet critical mistake. This can result in delays or, worse, project failure. Maybe not surprisingly, this step ties into the preliminary assessment, which includes evaluating the costs and benefits of the project to determine if the project will be financially viable in the end.  

• Tip: Develop a robust financial plan that includes all potential costs, including contingencies for unexpected expenses. 

Inadequate Permitting: The Silent Saboteur​

Permitting is a critical and often overlooked challenge in Solar PV development, and is another typical PV mistake developers make. Failing to secure the necessary permits can lead to costly delays and jeopardize your project’s success. The permitting process isn’t just about meeting basic requirements—it can involve stringent and expensive demands. Environmental permits, for example, may require mitigation measures like reforestation or stormwater management, while some projects might face additional costs for infrastructure upgrades, such as widening roads or installing stoplights.

The specific permits required depend on factors like location, size, and the nature of the project. Ground-mounted installations often attract extra scrutiny, especially when involving sensitive environmental areas or historical sites. 

• Tip: To navigate this complex process, integrate permitting considerations into your overall project management plan. This should include clear timelines, resource allocation, and regular progress reviews to ensure that all permitting requirements are met without derailing your project.

Neglecting The Local Community: Communication and Community is Key​

Failing to engage stakeholders early in the project is another common mistake that can lead to delays and budget overruns. Sometimes even complete discarding of the project. 

We have previously written an extensive piece on how a Danish developer and IPP overcame NIMBY, but since not all developers have the budget to launch nationwide campaigns to generate positive connotations to solar farms and get people to adjust their attitude, there are other ways of making sure NIMBY will not become a problem to limit the risk of local opposition, as is the case in Japan where roughly 80% of all large-scale projects are hit by some form of opposition from local residents. 

For utility-scale projects, but also even smaller ones, ensuring that communities are informed in advance through public consultations is oftentimes the key to getting any potential issues addressed before moving on. An example from the offshore industry, which isn’t that common, is RWE hosting local town halls ahead of its Thor project, resulting in minimal opposition. 

• Tip: Establish clear communication channels and identity and engage all stakeholders from the beginning of the project to limit the risk of anyone objecting against your project and putting a spanner in the works.

Lack of a Decommissioning Plan: The Long-Term Oversight​

One of the top mistakes PV developers make is overlooking the importance of a decommissioning plan. While the focus is often on the construction and operation phases, planning for the end of a Solar PV project’s life cycle is equally critical. Failing to develop a clear decommissioning strategy can lead to unexpected costs, legal complications, and environmental impacts when the time comes to retire the facility.

A well-crafted decommissioning plan outlines how the site will be restored to its original condition—or an agreed-upon state—once the solar panels are no longer in use. This includes the safe disposal or recycling of solar panels, the removal of electrical components, and the restoration of the land. Without such a plan, developers risk facing significant financial liabilities and regulatory challenges.

Moreover, decommissioning isn’t just about compliance; it’s also about sustainability. Ensuring that your solar farm can be dismantled responsibly aligns with broader environmental goals and can even improve community relations.

Tip: Begin developing your decommissioning plan during the initial project planning phase. This proactive approach can help you avoid future complications and ensure a smooth transition at the end of the project’s life.

La entrada Mistakes PV Developers Make – And How To Avoid Them se publicó primero en We turn good projects into great deals - Green Dealflow.

After the German Federal Government adopted the first draft of Solar Package 1 in August 2023 and a small selected part of Solar Package 1 already entered into force in December 2023, the German Parliament and the German Federal Council have now adopted the remaining (main) part of Solar Package 1. The Solar Package 1, which was significantly amended during the legislative process, contains a number of new regulations for solar energy in Germany, particularly in the Renewable Energy Sources Act (Erneuerbare-Energien-Gesetz – “EEG”) and in the Energy Industry Act (Energiewirtschaftsgesetz – “EnWG”). These new regulations are intended to facilitate and accelerate the expansion of solar energy in Germany and contain numerous changes for both ground-mounted and rooftop PV plants. In addition to solar-related provisions, the Solar Package I also contains new regulations for the acceleration of grid connections, and the operation of electricity storage systems, and introduces new or amended models for on-site electricity supply solutions.

In the following, we provide an overview of Solar Package 1’s main points. 

The key Changes of the Solar Package 1​

New regulations for ground-mounted plants​

New financial support regime for special solar plants (besondere Solaranlagen)​

The Solar Package 1 revises the financial support for the so-called “special solar plants” (e.g., agri-PV, floating-PV, moorland-PV, and parking-PV).

The previous bonuses that special solar plants received as a supplement on top of the EEG-awarded tariff were not sufficient, in the opinion of the legislator, to increase the expansion of solar plants in this segment.

In the future, the financial support for special solar plants will be replaced by a new sub-segment in the EEG tender procedures for solar energy with an adjusted maximum bid value (2024: 9.5 ct./kWh; from 2025: the average of the highest bids with a successful award from the last three bid dates plus a supplement of 8%, but not more than 9.5 ct./kWh).

In addition, a new special two-stage award procedure has been introduced (Section 37d EEG): in the first instance, the Federal Network Agency (Bundesnetzagentur – “BNetzA”) will grant the awards for the special solar plants up to the legally defined volumes:

2024: 300 MW
2025: 800 MW
2026: 1,200 MW
2027: 1,500 MW
2028: 2,000 MW
2029: 2,075 MW

Only afterward, in a second instance, the BNetzA will grant the awards for the remaining solar plants in the first segment up to the maximum bid volume.

New requirements for the compatibility of ground-mounted PV plants with nature and landscape conservation

The Solar Package 1 is introducing a new minimum nature protection criteria for all subsidized ground-mounted PV plants (with the exception of special solar plants), which intendeds to improve the compatibility of ground-mounted PV plants with nature and the landscape. For this purpose, Section 37 (1a) EEG provides for a catalog of five minimum criteria from which plant operators must meet at least three.

The choice of the respective three criteria to be met is at the sole discretion of the plant operator. It is also possible to select those minimum criteria that are already met due to technical or structural circumstances, such as not using pesticides or fertilizers on sealed surfaces. Plant operators are required to provide regular evidence to the grid operator (every 5 years) to demonstrate compliance with those criteria that are not plant-related but operation-related. Non-compliance with the minimum nature protection criteria is sanctioned under the EEG by penalty payments in the amount of EUR 2/kW of the installed capacity per month (Section 52 (1) No. 9a, (3) No. 2 EEG).

Increase in the maximum bid amount​

The Solar Package 1 increases the maximum bid amount for the EEG tender procedures for ground-mounted PV plants from the previous 20 MW to 50 MW of installed capacity per bid. Likewise, the maximum volume per bid for which a payment entitlement (Zahlungsberechtigung) can be issued to the plant operator has also been increased to 50 MW.

Disadvantaged regions: Conceptual switch from a “opt-in” to “opt-out” mechanism​

Under the previous legal framework, the German federal states had to explicitly designate disadvantaged regions (benachteiligte Gebiete) within the meaning of Section 3 No. 7 EEG (areas with certain natural or site-related disadvantages) by means of a legal ordinance in the respective state territory so that financial support under the EEG was made possible for ground-mounted PV plants in these areas. This previous practice of an “opt-in” authorization for the German federal states is replaced by an “opt-out” authorization under the Solar Package I: in the future, the German federal states must explicitly exclude areas in disadvantaged regions (Section 3 No. 7 EEG) to prevent them from being included in the EEG tender procedures. This change should increase the availability of areas in disadvantaged regions for solar energy.

New regulations for rooftop PV plants (co-called solar plants of the second segment)​

Reduction of the threshold for the obligation to participation in EEG tender procedures​

Previously, solar plants of the second segment with an installed capacity of up to and including 1 MW were exempt from participating in EEG tender procedures. This statutory threshold has now been reduced to 750 kW by the Solar Package 1, so that in the future, all rooftop PV plants with an installed capacity of more than 750 kW are obliged to participate in the EEG tender procedure in order to receive any financial support under the EEG.

Increase of tender volumes for solar plants of the second segment​

With the reduction of the threshold obligation to participate in the tendering procedure, the Solar Package 1, on the other hand, also increases the tender volumes for rooftop solar plants. In particular, a significant increase is made for the tender procedures starting in 2026 by more than doubling the tender volumes. In detail, the annual tender volume for the years 2024 to 2029 is adjusted as follows:

New rules for energy storage systems​

Strengthening the flexibility of energy storage operation​

In the past, energy storage systems faced the legal difficulty that they could not be used for mixed use (i.e., both with green electricity from RES plants and with grey electricity from the grid) while maintaining eligibility for financial support under the EEG for the temporarily stored electricity from the EEG-subsidized RES plants. This was due to the “exclusivity criterion,” which required the storage operator to use exclusively renewable electricity. In order to enable a more flexible (mixed) and thus commercially sensible use of energy storage systems, the Solar Package 1 contains the following important new rules:

• Adjustment of the exclusivity criterion: Previously, the BNetzA already argued that an energy storage system that has been used for mixed purposes meanwhile can regain the status of an energy plant pursuant to Section 3 No. 1 Hs. 2 EEG at the beginning of a new calendar year if it is again used exclusively with renewable electricity. The legislator has now adopted the calendar year-based approach to the exclusivity criterion and introduced a respective clarification in the law (Section 19 (3) EEG
• Switch between operating modes during the year: The Solar Package I further allows operators of energy storage systems to switch even during the year between the operating modes:

• Mixed-use eligible for EEG support: The Solar Package 1 also enables even greater flexibility in storage operation and for the first time introduces regulations for mixed use of an energy storage system (i.e., for the permanent selection of the “mixed-use operating mode”) that is eligible for financial support under the EEG. In the case of mixed-use, the entitlement to receive payments under the EEG will in the future be maintained for the so-called “eligible amount of electricity” (förderfähiger Anteil) (Section 19 (3b) EEG). More detailed requirements for determining and demonstrating the “eligible amount of electricity” will be set out by the BNetzA in a new determination (Festlegung) (Section 85d EEG). The new rules under the EEG on mixed-use eligible for financial support will only enter into force, however, after the BNetzA has issued its new determination in this regard (Section 100 (34) EEG).

Strengthening the grid connection of energy storage systems​

The Solar Package 1 contains significant changes for the grid connection of energy storage systems. According to the new provision in Section 17 (2a) EnWG, the statutory grid connection priority for RES plants (Section 8 (1) sentence 1 EEG) and CHP plants (Section 3 (1) sentence 1 KWKG) will not apply against energy storage systems. 

With this rule, the legislator aims to ensure that energy storage systems have a priority connection to the grid (over any conventional plants) and thus creates a certain parity between energy storage systems and RES plants/CHP plants, as grid operators will no longer be allowed to give RES plants or CHP plants a priority grid connection over energy storage systems. However, this may not represent complete equality of treatment, as the legislator has not explicitly stated that the statutory grid connection priority of the EEG/KWKG should directly apply to energy storage systems. Thus, it remains to be seen how grid operators will actually implement this new regulation in practice.

Strengthening of one-site electricity supply solutions​

Expansion of the tenant electricity model (Mieterstrommodell)​

The scope of the tenant electricity model, previously limited to electricity produced by solar plants installed on, at, or in residential buildings and its consumption within these residential buildings (or within a residential building within the same building quarter), has been extended by the Solar Package 1 (Section 21 (3) EEG).

In the future, tenant electricity regulations will also apply to electricity from solar plants installed on, at, or in other buildings (including those used for commercial purposes) and on ancillary facilities of these buildings. The location where tenant electricity is consumed is no longer restricted to residential buildings but can also occur in commercial premises or buildings. 

This new legislation will thus increase the importance of the tenant electricity model, particularly for the commercial sector. The legislator estimates that there is potential for 20,000 new tenant electricity agreements. However, according to the transitional provisions in the EEG, this expansion of the tenant electricity model only applies to new solar plants commissioned after the Solar Package 1 has entered into force (see Section 100 (24) EEG).

Introduction of the new on-site supply model „shared building supply“ (Gemeinschaftliche Gebäudeversorgung)​

The Solar Package 1 introduces a new model for on-site electricity supply from solar plants, known as the “shared building supply” (Section 42b EnWG). This model aims to facilitate the supply of solar electricity produced by landlords or third parties with a solar plant for shared building supply (Gebäudestromanlage) to tenants (both residential and commercial) or other end consumers (e.g., lessees) within the building, without significant bureaucracy. The legislator estimates the practical relevance of shared building supply to be up to 80,000 buildings in Germany.

The shared building supply is a distinct on-site supply model alongside the tenant electricity model. However, unlike the tenant electricity model, the new shared building supply does not entail the obligation of the plant operator to secure the entire supply of residual electricity to end consumers (which must instead be obtained by the end consumers themselves). Additionally, the operator of the rooftop plant is not subject to any supplier obligations under the EnWG (e.g., billing and information obligations under Sections 40 and 40b EnWG).

Plant operators of solar plants for shared building supply must enter into a “building electricity usage agreement” (Gebäudestromnutzungsvertrag) with the end consumers in the building, the detailed contents of which are regulated by Section 42b (2) EnWG.

Acceleration of grid connections​

Statutory right for the installation of cables (Section 11a EEG)​

For the realization of grid connection cables, Solar Package 1 establishes a new obligation for landowners to tolerate such installations. According to new Section 11a EEG, owners and other beneficiaries of properties owned by public landowners are now obliged to tolerate the laying, installation, maintenance/replacement, and operation of electrical cables, control and communication lines, and other facilities for connecting RES plants, energy storage systems, or plants for the production or storage of green hydrogen to the public grid.

The obligation to tolerate such uses not only applies to public land but also to public roads. There are exceptions to the right to lay lines if this usage conflicts with national and alliance defense interests. For the usage of the land, a one-off payment of 5% of the market value of the respective area of the protective strip used must be paid to the landowners.

While the new obligation to tolerate such uses for grid connection is important for project developments as it facilitates the process of securing land, its scope of application was considerably reduced during the legislative procedures by limiting the obligation to publicly owned land only. The securing of areas of private land for grid connections, which often proves time-consuming in practice, therefore remains unaffected by this new legal regulation and will still be required in the future.

Statutory right for crossing and overturning areas required for onshore wind projects (Section 11b EEG)

Similar to the obligation to tolerate the installation of electricity cables (as mentioned earlier), the Solar Package 1 introduces an obligation to tolerate in relation to the realization of onshore wind projects. According to Section 11b EEG, owners and other authorized users of land are required to tolerate the crossing and overturning of the land required for the construction and dismantling of wind turbines. To compensate for the crossing, a payment of EUR 28 per month per hectare, along with the obligation to restore the land to its original condition, is provided for by law; overturning, on the other hand, is free of charge. Again, the obligation to tolerate only applies to public landowners.

Transparency and standardization of the Technical Connection Conditions (Technische Anschlussbedingungen – “TAB”)​

The Solar Package 1 includes improvements to the technical regulations for grid connections:

Publication of the TAB: Since January 1, 2023, German distribution grid operators have been obliged to operate a joint internet platform (www.vnbdigital.de) and must now also publish the applicable Technical Connection Conditions (TAB) on this platform as of January 1, 2025, ensuring access to the TAB, explanatory notes, and possible amendments for everyone. These new transparency requirements aim to simplify project developments and grid connection projects by enabling quick access to the relevant TAB and identification of any special characteristics for grid connection realization.

Standardization of TAB: The new regulation of Section 19 (1a) EnWG introduces statutory requirements for the permissible content of TAB to standardize them, especially considering the current 850 different distribution system operators in Germany. This standardization aims to reduce the bureaucracy associated with grid connection projects.

About the authors

Dr. Maximilian Uibeleisen is a partner at McDermott Will & Emery’s German energy & infrastructure team and a member of the firm’s global energy and project finance team.

Maximilian focuses his practice on clients working around energy and infrastructure, with particular experience in advising corporates and financial investors with regard to the development and acquisition and sale of energy and infrastructure assets.

He has a particular focus on the renewable energy sector, where he has advised for almost 20 years on a large number of project developments and transactions relating to all different kinds of renewables facilities (including offshore and onshore wind, solar, biomass, geothermal) as well as energy transition (e.g. green hydrogen and battery storage).

Next to this work in the energy sector, Maximilian frequently advises in other infrastructure sectors, including in the German motorway PPP sector, the chemicals sector and in relation to digital infrastructure assets.

He studied law at the universities of Tübingen, Münster and Berlin (Dr. iur.) and holds a master degree (LL.M.) from Nottingham Trent University, and was admitted to the German bar in 2006. Lastly, he is the author of various German and international publications and is co-author of one of the leading German commentaries on energy law.

Dr. Simon Groneberg is a counsel at McDermott Will & Emery’s German energy & infrastructure team and a member of the firm’s global energy and project finance team.

Simon specializes on advising national and international clients on energy, hydrogen and infrastructure projects as well as regulatory matters. He has comprehensive experience in advising on project developments as well as M&A transactions in these sectors.

He has particular experience with renewable energy projects (e.g. offshore and onshore wind farms and solar farms) and energy storage projects. Simon advised on a number of project developments and transaction in the renewable sector focusing on all regulatory and public law aspects in relation to the permitting, grid connection and remuneration situation of renewable energy projects. Simon has experience in negotiating of project related agreements like direct marketing agreements or power purchase agreements (PPAs). He also regularly advises clients on other matters of the energy transition and the implementation of net-zero strategies of companies.

La entrada Overview Of The Solar Package 1 se publicó primero en We turn good projects into great deals - Green Dealflow.

This guide takes a look at the solar project development process, from the initial assessments and design phase to regulatory requirements, financing options, construction, and maintenance.

Preliminary project assessments​​

Step one in the development process of developing utility-scale solar is to do the preliminary assessments, which involve identifying the best location for the project and assessing the feasibility.

Site selection​

Finding the right location is essential for any solar project to achieve maximum efficiency and keeping costs low. A feasible location of photovoltaic (PV) systems must consider certain elements:

• Solar radiation: An ideal site should have an abundance of radiation, meaning it receives plenty of unrestricted sunlight throughout the day, but the area should not be too hot either, as solar panels work best between 15C and 35C. Hotter temperatures will cause the solar panels to degrade faster.
• Site accessibility: The location should be easily accessible for construction workers and their equipment, not to forget suitable conditions for the solar panels.
• Land topography: The location terrain should preferably be flat with no trees bordering the site to ensure optimal conditions during and after construction.
• Soil conditions: The structural design and construction costs can vary depending on how the soil on the site is. No one wants to work in a swamp.
• Grid connection: One of the most important things, if not the most important, of any project is the grid connection. Very few investors want to take a change on a project where the grid connection is uncertain or maybe very far away from being granted.
• Social impact: An increasingly important aspect to consider when developing a solar farm is to research the local dynamics and attitudes in the area, since more and more governments are requiring solar parks to be in harmony with the local surroundings and communities.

Project Feasibility​

Unless you can’t live without extreme financial risk, a feasibility study is needed to review the economic viability of the project. This typically includes:

• A financial analysis: This includes evaluating the costs and benefits of the project to determine if the project will be financially viable.
• A technical analysis: This includes evaluating the site’s technical feasibility, including the electrical infrastructure, soil conditions, and topography, as also noted in the site selection.
• An environmental impact assessment (EIA): This part is to ensure the sustainability of PV projects by means of engaging in a process of evaluating and predicting the potential environmental effects and socio-economic impacts associated with the establishment, construction, and operation of a solar energy project 
• A market analysis: Developing in a new market or a new municipality? Gaining a comprehensive understanding of the local incentives, fees, regulations, competition etc. is important. Evaluating these aspects is important to fully determine the overall site’s attractiveness.

Design and engineering​

Great, the preliminary assessments have shown that the project is viable to develop. Then what? Then system design and engineering can start.

With the site’s physical and technical characteristics in mind, the following things should now be given more thought:

Component selection: The design of the solar project must consider the type of components used, including solar panels, inverters, and mounting and tracking systems. The selection of components is based on operational and budgetary requirements.

Solar panel orientation and tilt: The solar panel’s orientation and tilt are important factors in optimizing the system’s energy production. The optimal orientation and tilt of the panels are determined by considering the site’s conditions, including climate, shading, and latitude.

Electrical and structural design​

The electrical and structural design of the solar project involves planning the electrical layout and plant sizing, including grid connection and integration.

The design should consider solar power quality considerations, such as harmonics and power factors, to ensure that the system meets grid interconnection requirements. The structural design should consider the wind and snow loads on the solar panels and other equipment.

Project permits and approvals​

To get a utility-scale solar project fully on track, a series of permits and approvals must be obtained to continue. The local authorizations required typically include zoning approvals and land use permits.

Environmental permits​

The location of a proposed solar project will determine how difficult it will be to attain a valid environmental permit with different countries having different regulations in place.

It’s important for developers to determine – as early as possible – whether they will be required to obtain such permits. This information should be available on local authority websites.

Figuring out whether you’ll require a permit means conducting an environmental impact assessment (EIA) which will evaluate the effects of the project on the surrounding wildlife and habitats – in some cases, a wildlife and habitat protection plan may need to be developed.

Grid connection & interconnection agreements​​

The grid connection and interconnection agreements are essential components of the solar project development process.

Utility coordination and technical requirements must be thoroughly understood to ensure that the project is compliant with the relevant regulations. Communication with utility companies should be started as soon as possible and finalized before construction begins.

Financing solar projects​

There are several viable solar financing options open to developers, that we will introduce on a more overall level below. For a more comprehensive overview, you can read our article on how to finance your solar project.

Procurement process​

Compiling a request for proposals is where this stage starts. An RPF is a formal bid document that outlines the PV requirements to service providers such as solar installation services, as well as the contract terms and the bidding process. 

This can be a lengthy process taking anywhere from a few months to a year, involving several different parties from project leaders to lawyers, energy managers to site managers.

After the RFP has been administered, proposal meetings and site tours can be made. Well-defined criteria should be evaluated before supplier and contractor selections are made and contract negotiations are entered.

Construction and installation​

With permits and financing secured, the construction and installation phase of a solar project can commence.

This phase is where the physical solar panels and equipment are installed on-site and connected to the power grid. It includes several key steps that require careful planning and execution.

Project operation and maintenance​

Once the solar project is in operation, it’s important to maintain it ensuring continued performance and longevity. The operation & maintenance (O&M) phase is a critical stage of the project lifecycle that ensures the system operates as efficiently as possible throughout its lifespan.

Monitoring system performance​

To maintain high efficiency of the solar park, it is important to monitor system performance namely, monitoring the energy output of the solar panels and the performance of the inverters.

Remote monitoring systems and performance data analysis can be used to identify any issues or defects with components. Analyzing performance data helps to identify areas where improvements can be made to increase efficiency.

Preventive maintenance​

Preventive maintenance is an essential part of O&M. Regular maintenance checks, including automated monitoring and servicing, can help to maximize efficiency, reduce downtime, meet regulatory requirements, and extend the lifespan of equipment.

This can include checking for loose connections, inspecting cables and wiring, and cleaning the solar panels.

Reactive maintenance and repairs​

Despite regular preventive maintenance, unexpected issues can still arise that require reactive maintenance and repairs.

Automated monitoring can provide troubleshooting and diagnostics that alert a project team of any malfunctions or inconsistencies. Plans should be in place for scenarios that demand reactive maintenance and repairs, and component replacements should be ready on-site to expedite repairs in the event of a component failure.

La entrada The Grand Guide To Solar Project Development se publicó primero en We turn good projects into great deals - Green Dealflow.

Introduction​

Photovoltaic solar projects have become a conventional asset class. The technology is proven at scale, the revenue stream looks and feels like an annuity, and with mainstream customers like Walmart and your local utility, the sizzle has faded.

In recent years, investors have flocked to the space hoping to seize on the final few opportunities for high returns coupled with infrastructure-like stability. As the market matured, margins compressed and double-digit returns are now likely permanently in the past. Still looking for sizzle, investors, now comfortable with solar as a generating asset, are exploring ways to invest earlier in the development cycle. The increased risk ought to provide increased yields, or so the thinking goes.

Happy to oblige, developers have been offering up their development pipelines for sale. These pipelines promise attractive returns, and the offerings are timely. With the federal Investment Tax Credit set to step down at the end of the year, projects must commence construction by December 31, 2019, in order to take advantage of the current 30 percent tax credit. Adding to the frenzy is a sense that we may be approaching market saturation for investment-grade offtake. 

Projects with strong contracted revenue streams from investment-grade-rated counterparties are scarce, and offtake tenures, once a standard 20-25 years, continue to plummet. Given these circumstances, the market will continue to see increased investment in solar platforms and development pipelines. The question inevitably arises whether the investment community understands solar development assets as well as it understands solar operating assets. If the glossy investor presentations in circulation now are any indication, the answer is no. 

This is part one of a four-part series exploring how to value and diligence a solar development pipeline. This series will consider commercial and industrial (C&I) and utility-scale pipelines and will not address residential pipelines. 

Beyond “Bragawatts”​

Development pipeline and operating portfolios are measured in megawatts. Generally, investments in solar portfolios at the stages of either “notice to proceed” (NTP) or “commercial operation date” (COD) are assumed to be de-risked. System sizes tend to decrease slightly from NTP to COD, but these changes typically do not go beyond post-closing quibbles over liquidated damages. 

Development pipelines, on the other hand, are a mixed bag of risks. Pipelines tend to include (in order of declining risk): early-stage assets, later-stage assets, and “NTP-ready” assets. Since attrition occurs as projects move from the early stage to the NTP-ready phase, developers looking to sell their pipelines often provide their views on the pull-through rate for projects in their pipelines.

A common way to think of a pull-through rate is in the context of the offtake agreement. The offtake agreement, often a power-purchase agreement (PPA), is the centerpiece of the solar project. Developers pour an enormous amount of sweat equity into acquiring offtake. Sales cycles for unsolicited PPAs last anywhere from three months to three years. Sophisticated off-takers hold competitive RFP processes that reward bidders who are willing to build projects below cost in the hope that they will be awarded follow-on business.

With the exception of feed-in tariffs directly with a utility, offtake agreements are bespoke products of painstaking negotiation. Rightfully, many developers consider the PPA to be their biggest value-add and the most critical element of a project’s success. 

Therefore, a potential investor may see pipelines broken down into PPA-related categories for the purposes of determining attrition. For instance, a common set of categories and pull-through rates would be as follows: Projects in the “proposal” stage have a 5 percent likelihood of success; projects in the “term sheet” stage have a 30 percent likelihood of success; projects in the “negotiation” stage have a 50 percent likelihood of success; and projects in the “executed PPA” stage have a 75 percent likelihood of success. This approach is elegant in its simplicity while maintaining just enough number-crunching for an analyst. 

If you are thinking that it probably takes more than a few short clicks to get to the probability-weighted megawatt number of a development pipeline, you’d be right. 

Every individual solar project has four pillars on which it succeeds:

• Pillar I: Revenue streams 
• Pillar II: Interconnection
• Pillar III: Site Control
• Pillar IV: Permitting

A fault in any of the four could represent a binary risk to a project. In order to value a pipeline, one must diligence each of the four pillars and be able to assign a stage of development to each project for each pillar. Complicating matters, within a single pipeline there is often a stunning lack of standardization across the project documents that govern the four pillars. Interconnection requirements vary by utility, down to the feeder. Permitting requirements vary by jurisdiction, down to the subdivision. And site control is, well, site-specific. This article will explore the first pillar of project success, and revenue streams, and end with a bonus section on geographic diversity. 

Pillar I: Revenue streams

Structure and authority​

Within a single development pipeline, you may encounter the following types of offtake agreements:

• Feed-in tariff (a project directly with a utility)
• Net-metered PPA (a project sited on or off the off-taker’s premises)  
• “Behind-the-meter” PPA (a project sited on the off-taker’s premises)  
• Contract for differences (a project sited remotely from the off-taker)
• Community solar agreement (with subscription agreements)

Because each of these agreements relies on specific statutory authorities, legal review is essential. This post will not address the legal considerations of the terms and conditions of PPAs. Instead, we will focus on the nature of the offtake agreement and raise certain considerations for pipeline valuation.  

Feed-in-tariff​

Feed-in tariff: This agreement generally represents the least amount of risk. The off-taker is a utility that likely maintains an investment-grade rating, the agreement is drafted by a sophisticated party, and the agreement itself is sanctioned by the authority having jurisdiction. Therefore, early diligence questions may be limited to any deadlines associated with the commissioning of the system and ensuring that the project generally complies with the terms of the feed-in tariff. Additionally, look out for hefty performance and payment assurance provisions that require substantial bonding, a letter of credit or cash collateral.

Net-metered PPA​

This PPA is executed pursuant to a net-metering tariff authorized by the state public utilities commission or public services commission and implemented by the utility. It is important here to ensure that the PPA and the project are structured in accordance with the applicable net metering tariff and all eligibility requirements are met including timely submission of application. Net metering tariffs vary by state and, in some cases, by the utility territory.

Additionally, some states have multiple net-metering tariffs. It is not unusual to find that an executed PPA may not fit within the confines of the net-metering tariff that the developer intends to use. This increases regulatory risk and may require redevelopment, transforming a later-stage asset to an early-stage asset. It is particularly important to understand the applicable net-metering rules related to system size, co-location of multiple systems, remoteness from the off-taker, and the eligibility of the off-taker itself.

Behind-the-meter PPA​

This is a bilateral agreement between the system owner and the off-taker for a system located on the off-taker’s property. The primary diligence question here is whether behind-the-meter PPAs are enforceable in the jurisdiction where the system is set to reside. If so, these agreements can be the simplest on which to perform due diligence. Generally, the off-taker also grants site control for the project, which also streamlines review.

Risk for these projects may be particularly concentrated on the individual off-taker, as the single counterparty responsible for the revenue from and access to the system. What’s more, because the system is generally sited on the off-taker’s land or roof, in the event of termination or at the expiration of the PPA, alternative offtake opportunities may be limited.   

Contract for differences (CFD)​

This is used for projects sited remotely from the off-taker but within the same utility or regional transmission organization (e.g., PJM) territory. The CFD provides a fixed-for-floating rate and the agreement may indicate that it is for the physical delivery of power at the node. It is important to consult with a legal expert when reviewing this contract to ensure compliance with Dodd-Frank and other applicable regulations.

Community solar​

This offtake arrangement (often a form of net metering) is enjoying popularity at the moment. “Community solar” is used to designate a wide variety of project configurations in the development community. If often means a structure whereby the system owner sells electricity to the utility, provided that the system owner is able to amass a certain amount of subscribers within the utility’s territory. Compliance with the precise statutory authority and the utility’s guidance is critical here.

Early diligence should reveal the number of subscriptions and the total megawatts subscribed, as well as the number of subscriptions and total megawatts required to be subscribed in order to commence construction and achieve commercial operation. Additionally, there may be quota limitations with regard to certain classes of subscribers.

PPA tenure and price​

Twenty years used to be the gold standard for solar deals. Recently, as the cost to deploy solar has fallen, so too have PPA tenures. Today, 10-year tenures are not unusual. Conversely, the useful life of photovoltaic systems continues to lengthen and the degradation of the panels themselves is lessening. 

Thus, in order to recognize the true value of the system (and to stay competitive), investors are assigning value to the “tail period” after the expiration of the PPA. Some considerations for tail-period valuation are listed below.

Offtakers​

Most investors know to diligence the creditworthiness of the off-taker in order to determine a default rate. In recent years, many investment-grade rated off-takers have made significant renewable procurements (as seen in splashy PR campaigns and Super Bowl ads). There is growing concern that investment-grade rated offtake is no longer readily available in the market. Therefore, many investors are now investing in projects with unrated off-takers or off-takers with below-investment-grade credit. Shadow ratings are gaining acceptance. 

Another important consideration is the PPA price. If the PPA rate is lower than the avoided cost of energy, a default is less likely. If, on the other hand, the developer were to be so lucky as to have executed a PPA with a rate above the avoided cost of energy (maybe even with an escalator), it is important to consider the possibility an economic default. Finally, if a default is a genuine concern, attention should be paid to the location of the system and possible alternative offtake arrangements.

Environmental Incentives​

Projects that rely heavily on SRECs or other incentives present their own set of diligence considerations. If the incentives, like SRECs, are based on production, the yield of the system is critical. Therefore, it is important to check the developer’s yield assumptions, if provided. Engaging an engineer to review the early energy models for larger projects is most prudent.

Another consideration is that the value of tradable incentives, like SRECs, fluctuates over time. Thus, the value of the asset changes over time. This could be a critical consideration for an asset in early-stage development that relies heavily on SRECs for its economics, particularly in a state where the renewable portfolio standard is set to decline. Such fluctuations in value could mean that an otherwise normal development delay of six to nine months poses a binary threat to the economics of the project.

Finally, if the incentive is grant-based, it is important to understand, at least in broad strokes, how the grant is awarded and recognized, which may affect the tax and accounting treatment of a project.  

Stages of development

Given the diverse array of offtake varieties, it is not surprising that there is no industry standard for stages of development related to a PPA. Therefore, when considering the acquisition of a pipeline or platform, it is important to understand how the developer categorizes its own development stages. Additionally, investors ought to consider their own monetization strategy for the assets in the pipeline in order to determine the relative importance of the offtake. 

For instance, is the investor intending to build, own, and operate the assets? Is the investor looking to sell the assets at COD? Or is there a strategy to obtain large amounts of megawatts for a different type of exit? If you have the answer to these questions during the diligence process, the relative value of the stages of development for the PPA may emerge much more clearly. 

In our next post, we will discuss the second pillar: interconnection.

Bonus section: Geographic diversity (does it matter?)

Geographic diversity is a classic tool for spreading risk. For residential solar portfolios, geographic diversity is of central importance. For C&I and utility-scale solar, investors ought to consider a few additional layers of diversity:

1. Region or regional transmission organization (in order to mitigate against fluctuations in the avoided cost of energy and any changes to grid-based incentives)
2. State (in order to mitigate against regulatory and RPS risk)
3. Region within the state (in order to mitigate against weather phenomena)
4. Utility territory (in order to mitigate against interconnection and congestion risk)

In addition to geography, it is important to ask whether the off-takers are diverse. For instance, a portfolio may include 100 projects across 15 states. But if there are only three unique off-takers for all of those projects and/or all the off-takers are in the same industry, the geographic diversity does little to mitigate the concentrated off-take risk. This must be compared against any cost savings that may occur in a pipeline with few off-takers, such as lower transaction costs and more efficient asset management.

Additionally, diversity of offtake type (i.e., net-metered PPAs, CFDs, feed-in tariffs, etc.) may help to mitigate against regulatory risk. Diversity is key, and geographic diversity is just the beginning of the inquiry.

Read the second installment here.

The series was written by Leslie Hodge, an associate at Mintz, Levin, Cohn, Ferris, Glovsky, and Popeo. It was first published by Greentech Media. Hodge’s practice focuses on energy project finance, general commercial transactions, startup and corporate matters, contract disputes, and litigation.

La entrada How To Value A Solar Development Pipeline ​ se publicó primero en We turn good projects into great deals - Green Dealflow.

Between a massive oversupply of new panels, falling prices, and rising costs, solar decommissioning has become more expensive than many utilities and other solar owners initially planned for. Solar owners need to fully understand the costs associated with decommissioning and put realistic strategies in place.

Market forces are demanding more realistic solar decommissioning plans

While the dramatic drop in the price of solar over the last decade has helped solar proliferate, it has also created challenges for solar owners ready to replace or recycle older panels. Existing decommissioning plans too often rest on assumptions that are no longer true.

First, the massive oversupply of new solar modules currently sitting in warehouses is a cost sink that utilities can no longer afford to ignore. The glut is spurring solar owners to repower existing panels, sell to secondary markets, or recycle their extra panels. 

At the same time, prices of new solar modules continue to decline; they’re forecast to fall to as little as 10 cents per watt by the end of 2024. That’s squeezing the secondary market. With prices for new modules so low, the demand for used panels has slackened. “A lot of decommissioning plans rely on the fact that they get paid for used modules, and I see that slowly degrading,” says Dwight Clark, director of compliance and recycling technology at We Recycle Solar. 

We Recycle Solar, which has a multi-pronged business that includes solar decommissioning and panel recycling, estimates that the average cost just to truck and handle panels being decommissioned is between five and seven cents per watt. That estimate doesn’t include actual recycling or reselling costs. Consequently, reselling used panels may generate little or no profit at all.

It’s not as though secondary markets for used solar panels have evaporated completely, Clark adds. “If they’re still good modules, there’s always a home for them somewhere in the worldwide market,” Clark said. The question, though, is whether the revenue that solar project owners anticipated in the decommissioning plan is anywhere near what’s realistic and whether the project owner can even access global secondary markets. 

Rising labor costs and the negative effects of inflation are also upending revenue and cost estimates in decommissioning plans. Without a thoughtful decommissioning plan, the costs and lack of financial return may come as a nasty surprise for solar owners.

Decommissioning requires detailed plans and frequent updates ​

More rigorous planning will help solar owners understand the costs and potential return on investment for decommissioned solar panels. Clark recommends three key components, taking inspiration from outside the solar industry.

Drill into the details

Too often, Clark says, he sees decommissioning plans that make sweeping assumptions or fail to account for entire cost categories. Solar decommissioning plans need to consider all of the costs, from renting and transporting the equipment necessary to return the land to its former use to labor to fuel to packaging and shipping decommissioned panels. And, Clark warns, solar owners can’t assume that all of their decommissioned panels are going to be reusable. That’s not realistic. They need a plan and an associated cost estimate for how to handle panels that need to be disposed of.

Clark points to the U.S. Environmental Protection Agency’s Resource Conservation and Recovery Act (RCRA) Closure Cost Estimate as a realistic way to look at decommissioning. The granular level of detail required in plans to close hazardous waste treatment facilities can help solar owners improve the accuracy of their decommissioning plans

Update decommissioning plans to account for market changes

These recent solar industry trends emphasize something solar project owners should have already known: Decommissioning plans are only as good as the information they use. That information must be updated frequently to account for inevitable market changes. 

“The proper way to do a decommissioning cost estimate is to write a work plan and say here’s what we’re specifically going to do, and here’s what each step costs. So, if you have to rent an excavator for two weeks at $1,500 a week, you’ll have to adjust if diesel prices increase by $1 in two years,” Clark says. “You should do the same for labor and transport and other costs. You need to really do a detailed work plan and a detailed cost estimate and then adjust it annually.” 

Those updates should also include the changing cost of solar panels on the secondary market to avoid surprises down the line.

Plan to fund decommissioning plans

It’s not enough to develop an accurate and detailed cost estimate; it’s also vital to plan for funding it. That’s where solar project owners can turn to the broader utility industry for inspiration.

Best practices for reliable decommissioning costs are standard in the utility world and can guide solar owners in developing a plan. “Utilities are used to having permits and bonds for decommissioning other power assets. They know they’ll have to dig up dirt around an oil tank that’s being decommissioned,” Clark says. “They understand these things and they have well-developed environmental departments. These are things that many solar-only people just don’t grasp.”

Embracing a more rigorous and detailed approach to decommissioning solar power plants gives owners and investors clarity on costs and project ROI. It also ensures there are no financial surprises when it comes time to repower or shut down a plant. And for the industry, it’s an important and necessary step toward the maturity expected of a mainstream energy provider. 

Learn more about We Recycle Solar by visiting their website, or check out how we help developers find the ideal investors for their solar projects.

La entrada How To Craft A Solar Panel Decommissioning Plan​ se publicó primero en We turn good projects into great deals - Green Dealflow.

Co-location and its benefits​

Given the numerous benefits of co-locating energy storage with solar or wind projects, it’s surprising that such schemes aren’t more common.

Co-locating allows power to be stored when the wind isn’t blowing or the sun isn’t shining. Additionally, co-located projects offer a price arbitrage opportunity, where power is bought during off-peak hours (when grid prices are lowest) and then stored for use during peak hours (when grid electricity prices are highest).

These projects can also provide grid services like ‘dynamic containment,’ which involves catching and containing any deviations in energy frequency caused by events like the loss of a generator. Moreover, solar plus storage is particularly seen as a way to mitigate the risk of yield and profit compression (known as the ‘solar capture rate’), which refers to the continuous reduction in energy prices when the sun is shining and more solar assets enter the market.

Co-location increases investment returns​

Other benefits of co-location include an increase in the return on investment from renewable projects by reducing the capital outlay required – that is, fewer wind turbines or solar panels are needed to generate the same revenue.

Meanwhile, capital and operational costs can also be reduced by sharing existing infrastructure, land, and grid connections. Combining storage and generation assets also allows more effective utilization of connected grid capacity. As a consequence, the savviest investment funds are taking the step of retrofitting storage to their existing renewables projects. For example, last year it emerged that Next Energy Solar Fund would be retrofitting its 11MW North Norfolk solar farm with a 6MW/12MWh battery system.

Given the multiple benefits of co-location, why aren’t more wind and solar projects linked with storage systems? A key reason is that subsidies for wind and solar projects artificially reduced the high cost of projects and meant that there was less incentive for project developers to do everything possible to optimize the value of projects.

Are declining subsidies incentivizing co-location?​

Now policymakers are providing less by way of subsidy for renewable energy projects so there is a greater onus on project developers to find ways of making schemes more attractive to investors and an effective way of doing this is by co-locating wind and solar with storage. For example, data from the US Energy Information Administration shows that total renewable-related subsidies were about $15.5 billion for both FY 2010 and FY 2013, then dropped to $6.7 billion in FY 2016 (see graph below).

Indeed, even if project developers are not planning to co-locate storage with wind and solar projects at the outset, they are now being advised to ‘future-proof’ their project by ensuring leases, for example, allow for a battery facility in addition to the main generation facility. Developers are also being encouraged to structure planning applications in such a way that they cater to potential battery add-ons in the future as this will maximize the value of the asset.

Yet barriers to co-located wind and storage projects remain. While corporate power purchase agreements (PPAs) have been flagged as offering a potential route to market for co-located assets, there is concern that the greater flexibility offered by co-located assets will result in PPAs that involve much higher premiums – because the extra flexibility is priced in – and this could be off-putting for potential corporate customers.

Hybrid PPAs offer a solution​

One potential solution is the development of hybrid PPAs. There are concerns that negotiating a contract for a hybrid PPA will be more complicated than treating assets as standalone and setting up separate routes to market for each asset. However, the counterargument is that the ability of co-located sites to guarantee more output and meet both peak and baseload energy requirements will enable operators of co-located sites to get a better price for their energy output.

Yet, despite an element of uncertainty about the best way forward for co-located projects, they will be the norm in the future. The appeal to investors of such projects is beyond doubt – witness Intersect Power confirming the $3.1 billion financial close of one of the US’ largest ever solar-storage portfolios, which included the Oberon I and II projects in California, which total approximately 685 MWp of solar and around 1GWh of battery energy storage.

Meanwhile, earlier this year, Copenhagen Infrastructure Partners, on behalf of its Flagship Funds, entered into a partnership with Amberside Energy with a view to developing 2GW of solar and battery storage projects in the UK. Elsewhere, in January, NextEnergy Capital launched a new fund, NextPower V ESG (NPV ESG), which will invest in solar and energy storage assets in OECD [Organisation for Economic Co-operation and Development] countries. NPV ESG is targeting capital commitments of $1.5 billion with a $2 billion ceiling.

The rise of the ‘power couple’​

This is just the start. Co-located solar and storage, which has been dubbed by some market observers as the ‘power couple’, is set to take off. DNV has predicted that, within a decade, around one-fifth of all PV will be installed alongside dedicated storage, and by 2050, this will have risen to 50 percent of all PV. DNV says that, by mid-century, the total installed global solar capacity will amount to 9.5TW, with a further 5TW of solar + storage capacity.

With renewable energy developers less able to rely on government subsidies to make projects viable, and with investors looking to ‘future-proof’ renewables, co-location will be a key consideration when seeking to maximize the value of wind and solar assets.

Want to read more about storage? Read Ben’s article on the 4 alternatives to lithium-ion batteries that are currently exciting investors, or Tamarindo’s Energy Storage Report Intelligence Briefing.

About the author

Ben Cook is the Insights Director at Tamarindo. Tamarindo delivers insights, connections, and communications for the global energy transition. He heads up Tamarindo’s Energy Storage Report. An experienced editor and journalist, he has worked as a writer and contributor for national newspapers, including The Guardian and The Times. He also spent six years as the Madrid-based editor of a legal magazine and website and previously worked as chief editor for a Paris-based legal and financial ratings agency. He has also previously worked as chief editor for a Milan-headquartered legal publisher.

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The Aid Decree​

On July 14, the Senate renewed its confidence in the Government by definitively approving, in the text dismissed by the Chamber, the bill for the conversion, with modifications, of the Decree-Law no. 50 of 17 May 2022, published in the Official Gazette on 15 July 2022 general series – no. 164 (also known as the “ Aid Decree ”).

This is a measure aimed at adopting measures to combat the systemic effects caused by the Ukrainian crisis, in particular with regard to national energy policies, business productivity, and investment attraction.

With regard to the energy sector, with a view to encouraging the production of energy from renewable sources, articles 6 and 7 of the Aid Decree introduced rules for further simplification of the authorization procedures for the construction and operation of plants powered by renewable sources.

Speeding up identification of suitable areas​

Article 6, paragraph 1 of the Aid Decree – in amending article 20, paragraph 4 of Legislative Decree No. 199 of 8 November 2021 (the ” Legislative Decree 199/2021 “) – aims to speed up the process of identifying surfaces and areas suitable for the installation of renewable energy plants, giving the Department for Regional Affairs and Autonomies the possibility of exercising state substitute power in the event of failure by the Regions to adopt laws aimed at delineating suitable areas within the deadline provided for by the legislation in force.

The provision also affects Article 20, paragraph 8 of Legislative Decree 199/2021, extending the number of areas that can be classified by law as suitable for the construction and operation of renewable plants pending the identification of suitable areas by of the Regions.

Specifically, in light of the changes introduced as a result of Article 6 of the Aid Decree:

Exceptions to the ordinary authorization procedure​

It should be remembered that Article 22 of Legislative Decree 199/2021, with reference to the construction and operation of plants for the production of energy from renewable sources in suitable areas, has introduced some exceptions to the ordinary authorization procedure. Specifically, with reference to these projects:

• The competent authority in landscape matters expresses itself with a mandatory non-binding opinion and once the deadline for the expression of the non-binding opinion has expired, the competent administration in any case provides for the authorization application;
• the terms of the authorization procedures for installations in suitable areas are reduced by one-third.

More on exemptions​

Article 6 of the Aid Decree has explicitly extended the scope of these exceptions, stating that they apply to electrical infrastructures connecting renewable energy plants and to those necessary for developing the national transmission grid, provided they are strictly functional to increasing energy production from renewable sources.

The decree also adopts incentive measures, specifically in paragraphs 2 quarter and quinques, to encourage new projects and interventions that promote social, economic, and productive development in municipalities with areas under concession for geothermal energy production. Starting January 1, 2023, holders of concessions for constructing and managing these plants, under Legislative Decree no. 287 of December 29, 2003, and law no. 99 of July 23, 2009, must pay a contribution of €0.05 for each kilowatt hour of electricity produced by the corresponding geothermal plant. Within ninety days of the Aid Decree’s entry into force, the Minister of Economic Development will issue a decree.

The decree also introduces further simplifications for tourist and spa facilities. For 24 months from the conversion law’s entry into force, these facilities can implement new photovoltaic projects with ground-mounted modules up to 1,000 kWp using the administrative DILA (sworn declaration of start of works) regime. These projects must be aimed at using self-produced energy for the needs of the facilities, located outside historical centers, and not under protection according to Legislative Decree 42/2004 (see Article 6, paragraph 2 septies of the Aid Decree).

Finally, Article 6 of the Aid Decree requires the Ministry of Culture, within sixty days of the conversion law’s entry into force, to establish uniform criteria for evaluating renewable energy plant projects. This aims to streamline proceedings and ensure that any negative assessments are well-founded, reflecting stringent and proven needs for cultural or landscape protection, in line with the specific characteristics of different territories.

Article 7​

Article 7 of the Aid Decree introduces significant innovations, simplifying procedures for authorizing plants that produce electricity from renewable sources.

These changes primarily affect projects that require an Environmental Impact Assessment (EIA) under state jurisdiction.

Specifically, the decree establishes that in the authorization procedures for renewable energy plants, if the project requires an EIA at the state level, the Council of Ministers’ resolutions will replace the EIA provision for all purposes, even in cases of conflicting assessments by the relevant environmental authorities.

The Presidents of the concerned Regions and Autonomous Provinces participate in the Council of Ministers’ meetings to express the position of their administration and the non-state administrations involved in the authorization process, but they do not have voting rights.

The Council of Ministers’ resolutions are then incorporated into the single authorization procedure, which the competent administration must conclude within sixty days. If the Council of Ministers decides to issue the EIA provision and the sixty-day period passes without action, the authorization is automatically deemed issued.

More on Article 7​

Furthermore, article 7 of the Aid Decree intervenes in various ways on the authorization procedures connected to the construction and operation of renewable plants, providing that:

• for the construction of plants other than those fueled by biomass, including biogas plants and plants for the production of biomethane of new construction, and for photovoltaic plants, the proponent, when submitting the application for authorization, can request the declaration of public utility and the affixing of the preordained constraint to the expropriation of the areas affected by the construction of the plant and related works.
• the simplified authorization procedure (PAS) for the construction and operation of photovoltaic systems up to 20 MW located in quarries or lots of quarries not susceptible to further exploitation may also concern the location in “portions of quarries”, it being understood that the same they must not be susceptible to further exploitation.
• with regard to ceased quarries and mines, not recovered or abandoned or in conditions of environmental degradation considered suitable areas pursuant to the law for the installation of plants for the production of electricity from renewable sources, portions of quarries and mines not susceptible to further exploitation.
• with regard to the standard that subjects to PAS the installation of photovoltaic systems with a power of up to 10 MW in floating mode on the water mirror of reservoirs and reservoirs, including water reservoirs in disused quarries, the plants in question can be placed also in the water reservoirs in the quarries in operation (see the modification of article 9 – ter of the Energy Decree).

Furthermore, it is appropriate to point out that with the provisions referred to in Article 7 – bis of the Aid Decree, the deadline for the start of work for the interventions carried out under a qualification issued under Article 12 of the Legislative Decree n. 387 of 29 December 2003 is set for three years from the issue of the relative qualification.

The Aid Decree therefore follows the path already outlined by the Simplifications Decree and the Energy Decree, demonstrating a unitary, albeit fragmented, intention of the legislator towards promoting the consumption of energy from renewable sources.

About the author

Italian-qualified lawyer, Tommaso has fifteen years of extensive experience in domestic, cross-border border, and multi- jurisdiction mergers and acquisitions, joint ventures, corporate finance, and private equity transactions involving both listed and privately held companies. He has particular expertise in transactions in highly regulated activities as well as in the infrastructure sector and, in particular, in the energy, transport, water, and waste sectors. His experience also includes assistance in favor of developers and lenders in relation to development projects in the energy sector, with particular reference to renewable energy assets (solar, biomass, wind, hydrogen) and transport infrastructure (electricity and gas transport, electricity and gas distribution, gas storage and LNG plants). He has extensive experience in the negotiation and drafting of M&A contracts, facility agreements, EPC, O&M, PPA contracts, and supply contracts in the public and private sectors. Tommaso has an LL.M Master’s Degree in Business & Corporate Law at City Birmingham University and has more than 15 years of experience in primary international law firms in London, Milan, and Dubai. Tommaso is an Italian native speaker and is fluent in English and Spanish

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Does larger always mean better?​

For Tier-1 PV manufacturers, larger formats offer clear benefits. By adapting equipment, they can produce 600 W modules as quickly as 400 W ones, effectively increasing production capacity. This shift could widen the gap between larger producers and smaller ones unable to keep up.

While these high power ratings are impressive, they often stem from size increases rather than groundbreaking innovations. The introduction of half-cut cells enabled this shift, with further improvements in interconnection strategies and reduced cell gaps contributing to increased active surface area. For manufacturers heavily invested in PERC technology, larger formats offer a way to boost energy yield and lower LCOE at the project level, providing value comparable to other innovations.

Promises and concerns​

Manufacturers claim that larger modules not only optimize their costs but also reduce system design expenses, leading to lower LCOE at the project level. One key promise is that more powerful modules will reduce costs for trackers and racking systems. With proper orientation, racking only needs minor adjustments to accommodate more modules, thereby maximizing watts per pile.

Another benefit is that cut cells, multibusbar interconnection, and twin-module designs lower module voltage, allowing more energy capacity within the same space. For example, Canadian Solar’s new Series 7 modules enable over 30 modules per string, pushing power per string up to 20.2 kW, compared to 12.2 kW from older models.

However, concerns have arisen over the increased size. Thinner front glass makes some modules more fragile, though manufacturers like Trina Solar have addressed this with reinforced metal frames. Higher currents from lower voltage modules also raise the risk of hotspots, though design innovations aim to mitigate this. Additionally, the size and weight of these modules pose challenges in shipping and installation, although manufacturers have optimized packaging and installation methods to manage these issues.

Big and bigger modules​

The industry’s shift to larger wafers has divided it into camps: those supporting the 182 mm wafer and those pushing for the 210 mm wafer. While manufacturers are hedging their bets by preparing for both sizes, the choice between them involves trade-offs. The 210 mm wafer offers a significant power increase but requires major system redesigns, whereas the 182 mm wafer provides a more gradual, less disruptive path to higher energy yields.

Trina Solar’s case study of its Vertex module, using 210 mm cells, showed a 35.8% increase in power per string compared to a competitor’s 182 mm module. This translated into substantial savings in materials and installation costs. However, the larger 210 mm modules necessitate redesigns at the tracker, inverter, and system levels, which introduces uncertainty and higher risks.

In contrast, 182 mm modules, which still deliver power outputs well above 500 W, require only minor adjustments to existing components and layouts. This makes them the most mature and bankable product currently available, with many in the industry favoring this less disruptive option.

Conclusion: The future of large PV modules

As the industry continues to evolve, both 182 mm and 210 mm wafer sizes are here to stay. Analysts predict that these two formats will dominate the market by 2025, with 210 mm gradually gaining ground as it establishes itself. While larger modules offer significant benefits, their adoption will depend on the ability of manufacturers and project developers to navigate the associated risks and challenges.

In the short term, the 182 mm format appears to be the safer, more reliable option, while the 210 mm format represents a bold step into new territory. The future success of these larger modules will hinge on their ability to deliver on their promises while maintaining cost-effectiveness and reliability.

La entrada Are Bigger PV Modules Better?​ se publicó primero en We turn good projects into great deals - Green Dealflow.