Challenges

Australia is a party to the Paris Agreement, however it is yet to enshrine its commitments into law. As a result, and given little policy guidance from the Federal Government, interested parties are left with little policy certainty on emissions reduction. That said, most of the Australian States have committed to carbon emission targets.

Energy and climate policy uncertainty has been a feature of Federal politics for well-over a decade, but this uncertainty is likely to subside in the wake of the recent 2022 federal election. Despite the uncertainty which comes with a change in government, the newly-elected Albanese Government brings with it a commitment to loftier carbon emission reduction targets and a comprehensive ‘Powering Australia’ plan set to reform the Australian electricity market. Since the election, the Australian Government has passed the Climate Change Act 2022 (Cth), enshrining in legislation a 43% carbon emission reduction target¹ and laying the foundation for the Powering Australia plan.² Under that plan, ‘Commonwealth PPAs’ are touted as a key driver for supporting renewable energy and job creation in the public sector.³ This commitment by the Australian Government demonstrates a growing appetite for renewable energy and, specifically, PPAs.

The strong business led growth of PPA uptake since 2020 indicates that the challenge posed by this uncertainty can be overcome, even as the national debate on the role of coal generation continues to make headlines and divide political parties.

The primary barriers to corporate PPA uptake in the Australian market are procedural difficulties and transaction costs. BRC-A’s State of the Market 2021 Report found that buyer organisations experienced internal challenges such as understanding PPAs and their internal processes and building organisational support. Data drawn from BRC-A’s national survey identified that the key challenges faced by buyers and developers are difficulty in the execution process (rated ‘high’ or ‘very high’ difficulty), transaction costs (rated ‘moderate-to-high’) and the duration of the PPA execution process (60% of buyers reported that the process was longer than 18 months).⁴ On a more general level, Australia continues to feature a complex regime for renewable energy, with a range of Federal and State Government laws and policy mechanisms that apply. Regulatory challenges therefore place some limitations on the implementation of PPAs without using a retailer.

Footnotes

[1] Climate Change Act 2022 (Cth) s 10.
[2] See, eg, Explanatory Memorandum, Climate Change Bill 2022 (Cth), 8 [13].
[3] RepuTex Energy, ‘The economic impact of the ALP’s Powering Australia Plan’ (Report, December 2021) 17 
[4] BRC-A State of the Market Report 2021 (n 5) 18-20.

Private production of electricity in Bahrain requires authorization from the relevant government authorities in Bahrain (either through legislation or concessions).

The current Electricity Law allows for the private generation of power. Each IPP scheme, however, requires a written authorization from the relevant minister and an approval from the Cabinet. As the law was drafted at a time when renewable energy was yet to be considered a viable alternative source of energy, this scheme is not suitable to stimulate private investments in renewable energy as it is geared towards large-scale conventional power plants, where fuel input is an important consideration.

Renewable energy technologies have substantively matured, the costs have declined, and the options have improved.

To stimulate investment in renewable energy, the current law needs to loosen its requirements and allow private deployment of renewable energy plants without an extensive prior authorization process from the government. [1]

The laws in Bahrain do not authorize exporting onsite generated energy to the main grid. To stimulate investments in renewable energy, especially by households and commercial users, it is important to allow renewable energy plants to export the excess power to the grid.

Under the current legal framework and market structure, EWA is the sole buyer and distributor of electricity in Bahrain. To motivate private developers to invest in renewable energy, there needs to be a mechanism whereby private investors are able to sell the power produced from renewable sources and generate income. The key components of such mechanism are price and guarantee of purchase of electricity from renewable sources. Thus, it is important to set a policy that will define a purchase price for electricity from renewable sources and guarantee the purchase of such electricity. Such policies can be either feed-in tariff policy, or auctions or public competitive tenders. [2]

Electricity in Bahrain is mainly produced from natural gas, and, as a result, the cost of power generation depends highly on the gas price. Therefore, according to estimations of planned gar price increases, the cost of electricity supply will increase even more with time. [3]

In addition to the above, another technical and financial challenge Bahrain faces is the inefficient electricity production system, and the reinjection of a relatively large quantity of gas to support enhanced oil recovery. As a result, Bahrain uses almost three-quarters of its primary energy for electricity production, energy industry own use and non-energy use. [4]

Although Bahrain has attempted to subsidize electricity tariffs, that in itself is not efficient. In this regard, and as a way to overcome the same, EWA along with the SEA have introduced, and are implementing, the National Energy Efficiency Action Plan (“NEEAP”) whereby they are moving towards using less energy for the same output or service, cutting costs in the long-run. [5]

[1] The Kingdom of Bahrain National Renewable energy Action Plan (NREAP) (Sustainable Energy Unit, Bahrain, January 2017)
[2] ibid.
[3] No. (4).
[4] No. (4).
[5] ibid.

An important regulatory challenge for CPPAs with a fixed price comes from the subsidy regime. As outlined in detail below, the most important subsidy mechanism in Belgium is a green certificate scheme. The goal of the green certificate scheme is to ensure that renewable energy projects are not loss-making. The amount of green certificates a producer is entitled to can therefore fluctuate over time, depending on the electricity price. In these circumstances, a developer of a renewable energy project may be reluctant to enter into a CPPA with a fixed price. This is because if the electricity market price increases, the project developer may receive less green certificates, while the price at which he sells his electricity remains the same, resulting in a loss.

On a more general level, it is noted that developers of renewable energy projects are faced with limited availability of sites due to spatial planning restrictions, as well as potential opposition from local residents (NIMBY). 

Various stakeholders have identified the following key challenges to adopting green energy:

1. Subsidised thermal tariff;
2. A general lack of energy information for policy, planning and decision-making;
3. Ineffective private sector participation and low investment in the energy sector possibly due to the lack of clear policy and incentives as well as the previous absence of an impartial regulator to provide a level playing field for the industry;
4. A lack of a detailed renewable energy strategy;
5. A lack of trained personnel in the energy sector;
6. The focus is mainly on base-load energy supply, transmission grid reliability, service delivery, financial turnaround and rural electrification. 

Many of the challenges mentioned above gradually being overcome by the establishment of BERA.

Financial

There is a financial risk associated to the corporate PPAs considering the uncertainty of future energy prices. The price of the spot energy market, which is currently calculated on an hourly basis, takes into consideration several variables such as hydrological conditions, power demand, entrance of new players, among numerous others. Prices may rise significantly and directly affect the parties; or they may decrease and become a competitive disadvantage. This risk may be mitigated by means of a price review mechanism agreed between the parties.

Planning

Considering the long-term structure of corporate PPAs, the offtaker needs to estimate its power consumption level, taking into consideration the possible growth in its consumption, as accurately as possible, otherwise some divergences between the planned and the actual consumption rate may occur. To mitigate this risk, it’s important to establish contractual mechanisms that can absorb some variations regarding the initial planned amount, such as defining a contracted amount limited to a percentage of the global charge, or contracting a diversified portfolio, with different term and delivery conditions, to minimize any exposure.

Counterpart

Corporate PPAs are used by developers to obtain funding for the construction of their facilities and delivery of the agreed power. Until the generator’s facilities are completed there’s a risk of delays or issues in the construction of the plant and, therefore, in the delivery of the contracted power supply. To mitigate this risk, it’s important to analyze the developer’s background and its capability of delivering the project on time and include provisions in the PPA regarding construction and delivery milestones. Another way to mitigate this risk is asking the developer to present a performance bond.

Performance

Renewable sources, especially wind and solar, are intermittent and, therefore, may generate contractual exposures for the offtaker or the generator, depending on the contract structure. The Brazilian power market has been mitigating this risk by contracting an energy broker that may provide the remaining power when the renewable sources included in the corporate PPA do not perform as expected. Additionally, corporate PPAs in Brazil generally contain specific provisions regarding supply obligations and guarantees.

Submarket

The Brazilian power market is divided into four submarkets, which may present different spot prices among them. So if the consumer is in a different submarket of the generator, even if the amount produced is the same as the amount consumed, there may be some positive or negative amounts that need to be settled. This difference between submarket prices may create risks for both the offtaker and the generator. To minimize these risks one strategy is purchasing electricity from a generator that is located in the same submarket of the offtaker; but this alternative is not always available due to certain conditions, including technical and geographical ones. An alternative that has been used by the power market to address this matter is including energy brokers in the PPA contractual structure to manage the submarket risk, due to their diversified portfolio. Another alternative is including provisions that anticipate the costs of submarket swaps, so both parties have more predictability and may better allocate their risks.

Technical (Connection)

The exponential increase of renewable power projects in Brazil in the last few years, especially in certain regions of the country (ie northeast region), has created an outlet issue for all such generated power, since the current power transmission infrastructure in Brazil is not sufficient to accommodate all the projects that have already been authorized by ANEEL. In this sense, one of the main risks for power projects under development in Brazil is the attainment of the relevant authorization to connect to the grid. As an effort to minimize such risk and restriction, ANEEL has been adopting certain measures to improve the transmission flow margin, including the promotion of new Transmission Auctions, which are set to take place over the new few years. The purpose of these auctions is to attract investments for improvements and expansion of the Brazilian power transmission grid infrastructure.

The accelerated increase in renewable generation in the north of the country has led to lack of adequate transmission infrastructure which represents the major technical challenge. This has resulted in financial pressure for renewable energy projects due to energy curtailments and the decoupling of energy prices between injection and withdrawal points.

This has prevented some generators from being able to fulfil the PPAs they have entered into, although so far these have only been isolated cases.  

To overcome this situation, the government is taking several measures. On December 2021, the National Electric Coordinator awarded a consortium with the project Kimal-Lo Aguirre, a transmission line of 1,500 km that will be able to transport 3,000 MW of nominal energy from the north to central Chile. In addition, a bidding process to build 2 GW of storage capacity was recently announced.

Also, the government submitted a bill of law on energy transition before the Congress that seeks to make more efficient the expansion of transmission infrastructure. In addition, Law No. 21,505 was enacted in 2022, which promotes the storage of electric energy, and modifications are currently being made to the regulation that establishes how power is remunerated, which is key to the deployment of energy storage in Chile. 

Notwithstanding the challenges, Chile has a state policy committed to the energy transition, which promotes the adoption of green energies. According to the Framework Law on Climate Change, by 2050 at the latest, greenhouse gas emissions neutrality must be achieved, and for the energy sector, the goal set by the government is that by 2030, 80% of energy should come from renewable sources and by 2050, 100% of energy generated should be zero emissions.

Social issues with ethnic communities

As a multicultural country, Colombian natural resources used to produce clean energy are almost always around or in the territory of ethnic communities (i.e. wind in La Guajira, hydroelectric projects in Antioquia). Before undertaking any activity of exploration or exploitation of natural resources, which are on the lands of these peoples, a prior consultation (consulta previa) should be carried out with the affected community to guarantees their effective participation, through a scenario aimed at guaranteeing their fundamental rights. This process might take longer than expected and without its achievement it is impossible to obtain the permits and licenses required for the project. Projects which have successfully achieved this process have hired NGOs, and private agencies to advise them on the process. 

Environmental issues

As a rule, the use of exploitation of renewable natural resources requires the prior granting of a permit, authorization or concession by the competent environmental authority. In certain parts of Colombia, environmental entities take a lot of time to analyze and issue environmental licenses. It is important to file license and permits papers as soon a feasible in order to avoid delays.

Interconnection procedure

Domestic law enables vertical integration between generation, distribution and retailing activities. Thus, the grid owner might have an incentive to obstruct access. Additionally, grid technical conditions might impose an additional challenge for the interconnection of a new renewable generation unit because in such cases the regulator might require a prior investment from the grid owner to update or expand the grid before authorizing the interconnection.

The governmental support in the Czech Republic which has been enormous before 2010 is since then being reduced and vast majority of "green bonuses" is no longer effective (exceptions are listed in Subsidies). Also the green energy is now being further taxed.

Further issue is quite lengthy and complicated building process in the Czech Republic (i.e. obtaining all necessary permits etc.).

Generators are still facing financial and political problems because:

• government has imposed subsidies on utilities in Egypt;
• there are no restrictions on carbon emissions and therefore no need for buyers to adopt green energy solutions; and
• short-term renewable energy project feasibility has been affected due to the current economic situation (devaluation of the Egyptian pound and increased interest rates).

This has led to an increase in levelized cost of electricity (LCOE) for renewable energy while government electricity prices have yet to adjust.

To compensate the current challenges, regulators have provided other benefits to generators such as the RECs or no grid connection fees under certain conditions. However, it remains politically challenging to remove the subsidies provided to consumers.

The major challenge for businesses adopting green energy is a lack of comprehensive regulation of cPPAs. As the concept is new to the Ethiopian energy market, sector-specific incentives are not available, and this deters corporations from adopting green energy policies. This challenge could be overcome by formulating laws and regulation specifically addressing cPPAs and providing incentives for those companies ready to meet their energy needs from renewable energy sources.  

The challenges with respect to the developers of new wind parks have mainly related to:

• long duration of the permitting (including appeals) processes;
• regional concentration of the wind production on the west coast due to permitting restrictions in the eastern part of Finland;
• bottlenecks of transmission grid capacity. 

With respect to the long permitting processes, the Finnish government has already introduced a temporary fast-track system for environmental and water permit procedures and certain appeal processes related to the green transition projects. The legislation regarding the fast-tracking of green transition projects entered into force in January 2023.

Further, the new Governmental Programme includes the following targets to tackle some of the above challenges:

• reduction of duplicate complaints and reducing the possibility of complaints between authorities;
• ensuring resources and better management of Administrative Courts;
• resourcing sufficiently the permitting of electricity grid investments.

In relation to the transmission grid capacity, the Finnish electricity TSO Fingrid Oyj announced during the spring 2023 that new grid connections at more than one MW are not permitted to connect to the main grid or distribution network (this does not apply to connection agreements made before 1 May 2023). The temporary restrictions are imposed due to the dramatic growth in wind power and the regional concentration on the west coast that poses a challenge to the stability of power plants and the power system as a whole. Lifting of these restrictions requires new main grid connections that are to be completed in the west coast region in 2027 and 2028. Also, temporary production output limitations in some areas have been (and may be) imposed by Fingrid to maintain the transmission grid stability.

French companies cannot receive guarantee of origins for the green electricity purchased from a facility benefitting from a contract for difference mechanism (see National support scheme).

Some fear that French companies will turn to foreign producers to buy abroad the green electricity they need.

Corporations adopting green energy are still facing the strong part that nuclear energy holds in France. France has indeed a particular position towards nuclear energy, which provided a stable power price and still has the largest share in the French energy landscape (currently around 70% compared to around 10% globally).  Despite the growing attractiveness of renewable energy in France and corporate PPAs, it is quite difficult to estimate the share nuclear energy will hold in the French energy mix in the near future (2025-2030).

Moreover, as corporate PPAs are still quite recent in France, companies may have been confronted to the lack of a standardized contract or market practice rules strongly implemented in France. However, in order to address this matter, France Energie Eolienne (FEE) has published at the end of 2019 its standard corporate renewable power purchase agreement, available in open source. This is the result of one year of work and was elaborated by a special FEE working group and in collaboration with various stakeholders in the energy sector, such as producers, consumers, lenders, investors, lawyers, tax specialists.

The challenges for corporations in adopting green energy are largely of a financial nature. In general, renewable energy generators are only willing to sell renewable electricity to corporations by way of "direct marketing", where they can be certain they will receive the market price in return for the electricity they provide, as well as the financial support payment (which a generator would otherwise receive from the network operator for the utilisation of the "market premium" (for new installations)). For these reasons, and until market prices of renewable installations reach (or at least come close to) grid parity, corporations are often reluctant to use corporate PPAs unless they are specifically willing to pay a higher price for green labelled energy.    

However, as financial support under the "market premium" method has reduced substantially since the introduction of a tendering process to determine the "market premium" (with support of 0 Euroct./kWh in some of the recent offshore wind auctions), it is likely that corporate PPAs will start to play a greater role for renewable energy generators and corporate buyers. Also, the development of standardised documentation and potential amendments to the prohibition of multiple sales (Doppelvermarktungsverbot) under the German Renewable Energy Act may further support the development of this market.

In general terms, except for the energy price crisis that affects all industries and consumers, the renewables industry is still facing major roadblocks in the areas of legislation, planning and grid capacity.

CPPAs compete for projects with state support schemes. The most recent Irish support schemes for commercial scale renewables have introduced new measures which may increase the attractiveness of such support schemes for generators. The key developments are that the Terms and Conditions for the third Renewable Energy Support Scheme (RESS 3) and for the first Offshore Renewable Energy Support Scheme (ORESS 1) introduced indexation and compensation for certain unrealised available energy which were not available in the earlier RESS schemes.

For RESS 3, there will be annual indexation of 30% of the Strike Price in accordance with the Harmonised Index of Consumer Prices.

For O-RESS, there will be a one-time blended indexation of 100% of the strike price (components of which may be upwards only) triggered by the later issuance of notice to proceed under its construction contracts or 18 months after the project has received certain permissions. In addition, O-RESS projects will also benefit from annual indexation of 30% of the Strike Price in accordance with the Harmonised Index of Consumer Prices.

As corporates will look to cPPAs as a hedge against rising electricity prices, competing with these indexation provisions may be problematic subject to any downward pressure indexation puts on prices bid into the relevant auctions due to reducing the inflation risk that projects must carry.

In addition, RESS 3 and ORESS also provide for unrealised available energy compensation (UAEC). This is compensation up to a project’s strike price in circumstances where it is curtailed or there is oversupply, however, it is not available for constraints and connection outages. As curtailment is an issue in Ireland and oversupply may become an issue once offshore projects become operational, this is a significant change. Corporates may have difficulty matching such a benefit; however, this change may also put downward pressure on prices bid into the RESS due to reducing the risks that developers must carry.

Consequently, it will be interesting to see the effect that these changes have on the cPPA market particularly following the RESS 3 auction.

The main factors hindering the spread of corporate PPAs in Italy are, inter alia: (i) the absence of any incentives; (ii) the absence of support to the aggregation of demand; and (iii) the low discounts offered by awarded applicants in capacity auctions under the New RES Decree.

In addition, one of the major challenges that needs to be addressed is the streamlining of the planning and authorisation process, which has been burdensome due to the highly fragmented regional procedures and different levels of support from local authorities, especially in some of the regions that boast the highest levels of solar irradiation.

• Green energy sources tend to be intermittent/unreliable such that corporations are rarely able to rely exclusively on a green solution to meet their power needs. This is particularly the case for solar power, which, in the absence of affordable storage facilities, can only provide a solution during daylight hours. Many corporates adopt a hybrid approach and will also explore how to use net-metering to sell back excess supply.
• Most technologies require significant space to be efficiently developed. Unless corporates or generating entities own their premises or land on which to develop a generating plant, corporations and/or generating entities have to lease or acquire the required space. This can be a significant challenge, particularly for foreign-owned corporations. Acquisition of land for the purposes of generating power also requires significant engagement with the local community to ensure the investment/development is well received.
• High upfront costs for most technologies in terms of equipment and personnel. Difficulty with logistics and some supply networks can mean equipment is difficult to maintain, and spares may not be readily available or properly stored.
• The corporate PPA market is only now opening up in Kenya, and the regulatory controls are untested and somewhat ambiguous. It is seemingly likely that regulatory reform will follow in the next few years as stakeholders interpret the applicable legislation. This uncertain and/or changing regulatory landscape can sometimes make it difficult for corporates to commit to PPAs with substantial terms.   
• Emerging local capacity in the development, operation and maintenance sectors coupled with obligations to develop and use local content.
• Proper enforcement of standards and regulations.  Particularly in the solar space, there is a proliferation of sub-standard solar energy technologies and equipment. There is also a lack of availability of affordable power storage solutions.

Interventions

• For some time, the Kenya Revenue Authority offered tax exemptions for certain solar-PV equipment (though this was reviewed in 2020). Permanent exemptions which applied to a wider range of technologies would assist in managing the substantial up-front costs.
• The Energy Act now permits net metering and as a means of opening the market to corporates who may be considering a solar solution, but were previously unable to sell excess generated power back to the grid. Further improvements on this issue would see the government offer/regulate low-cost wheeling arrangements to facilitate wheeling of power where there is excess supply from a corporate.
• KPLC could explore how to use virtual PPAs and sleeved PPAs to increase revenue and maintain market position.
• Regular review of standards for energy technologies and equipment and genuine and consistent enforcement of regulations and standards.
• Implementation of programs and initiatives to develop local capacity. Incentives could also be offered to corporates to provide training and/or upskill individuals.

The main problem is that the current administration is not in favour of private participation in the energy industry and would like to have the State-owned CFE controlling the market. There have not been any changes in the laws, yet, but the is new policy has created uncertainty. However, the market since the reform of 2013 has evolved to an open market structure with solid regulations, and it is unlikely that this new government could change the rules to give back to CFE an integrated monopoly. 

For instance, most of the Self-Supply projects are renewables. The regulations allow that these projects have a cost benefit in the transmission and distribution of electricity. The new government has indicated that these benefits are currently under review and may be terminated. However, there are legal mechanisms available to fight against such measures.

• Some of the implementing decrees of law No. 13-09 have not yet come into force, in particular the ministerial order identifying the map of areas for the development of solar projects. Therefore, no solar project can be authorized by the Ministry.
• The Moroccan national electricity grid has reached its capacity limits in certain regions.
• It is not possible today to sell electricity to the distributors connected to the medium-voltage grid.

These challenges are currently addressed in the draft reform of Law No. 13-09 (see Regulatory changes).

Some of the challenges to corporations adopting green energy are as follows:

Technical

• lack of capacity to install, operate and maintain green energy systems;
• poor retention of trained personnel in the national renewable energy sector;
• the lack of local training, which jeopardises the operation of small-scale projects scattered all over the country.

Political

• consolidation of the political environment;
• lack of a political and strategic framework to motivate the development of green energy; and
• lack of inter-ministry coordination.

Financial

• lack of involvement by the banking sector in promotion, assessment and implementation of green energy programs;
• no government instruments to improve the credit and mitigate the risk of credit by third parties; and
• need for revision of taxes and import duties on equipment intended to exploit green energy.

Regulatory

• insufficient green energy regulatory framework; and
• poor harmonization of the existing regulatory framework with the future regulatory framework.

These challenges can be overcome by:

• institutional capacity building, both of public and private institutions’ human capital;
• improvement of the regulatory framework, in order to make it more enforceable and effective;
• granting tax benefits, to make the acquisition of green energy equipment easier;
• establishment of financing schemes, to provide access to easy credit;
• education, training and establishment of good working conditions.

Financial

The substantial upfront investment needed for renewable infrastructure can deter corporations. However, government incentives, subsidies, and innovative financial options like cPPAs alleviate these financial burdens, allowing companies to transition without substantial upfront costs.

Technical – grid integration and congestion

Intermittent renewable energy sources present a technical hurdle, further exacerbated by the Netherlands' insufficient grid capacity. Network congestion can result in increased electricity prices and restricted reliability. The Netherlands is investing in grid expansion, smart grid technologies, demand response, and storage solutions to tackle these issues effectively.

Regulatory

The complex nature of environmental and other permissions can stall the speed of a renewable project development. The Dutch government is expected to provide clear guidelines and facilitate public-private partnerships to streamline regulatory procedures, including challenges like nitrogen permissions, and noise and sound regulations.

Political

Spatial planning restrictions and local opposition due to the high population density add complexity to onshore projects. As a result, new wind farms are primarily offshore. For onshore projects, compulsory local resident participation is often mandated to mitigate conflicts. These participation requirements, although making projects more complex, offer a way to engage communities and resolve disputes.

Overcoming these multifaceted challenges in the Netherlands requires a concerted effort from the government, private sector, and local communities. Policies that incentivise green energy adoption, technological advancements, and increased public awareness are all pivotal to meeting the stringent renewable targets and transitioning to a more sustainable energy future.

We see the following short/medium term challenges for corporations adopting green energy:

• New Zealand does not currently have a legislative or other form of comprehensive framework dealing with Energy Attribute Certificates (as contemplated by the IREC standard). This adds to the challenges of substantiating green claims with regard to energy consumption. There are examples of private sector certification and trading schemes that have been established in an attempt to address this challenge. Ultimately, this is a matter which will need to be addressed by future New Zealand governments.
• The New Zealand Carbon Price under the Emissions Trading Scheme is recognised to be below the market price in other jurisdictions (reducing the incentive to adopt green energy). There are also significant free allocations of New Zealand Carbon Credits for heavy emitters.
• On the supply side of the equation, developers of renewable generation face several technical challenges including at the grid connection phase because of capacity constraints and more generally arising from transportation issues given New Zealand's geography and population density/spread (the majority of New Zealand's population lives in the North Island whereas historically much of the renewable generation is located in the South Island). With regard to connection issues, relevant agencies and the grid operator (Transpower) are aware of these challenges and have taken steps to provide greater certainty to developers (for example, Transpower has recently overhauled its grid connection process).
• For developers of renewable generation who rely on third-party debt financing, reducing exposure to merchant risk is a key consideration for debt providers lending money for renewables/storage projects.
• Finally, market participants have noted a degree of uncertainty created due to government/regulatory issues such as the lack of a regulatory framework for offshore wind and the extent to which government is likely to directly invest in new generation such as the Lake Onslow Pump Hydro Scheme.

This depends on the green energy segment/industry in the Norwegian market. To mention some regulatory challenges in the short/medium term for a selection of "new green industries":

Offshore wind

The first concession areas for licenses to develop and build offshore wind turbines in the areas Utsira Nord and Sørlige Nordsjø II (Phase I) were released on 29 March 2023. The application deadlines for both areas have been postponed from 1 September 2023 until 1 November 2023 for now, based on pending clarifications with ESA. The government has initiated workstreams covering Statnett's work to expand and develop the grid system in Norway to meet the new industry requirements, NVE's work to identify new areas to be developed as future offshore wind areas (around 20 new areas to be investigated and released for new license processes in 2025), ongoing work related to amendments in the Ocean Energy Act and regulation/regulatory framework needs to be adapted by the government and the Parliament (related to projects outside the Norwegian baseline; if within the baseline the current Energy Act will apply).

The Norwegian support scheme will be rendered through long-term CfDs/contracts for the difference between the Norwegian state and the consortia/participator winning the auction or the license allocation.

Since the government has decided to establish radials in the first phase to connect to the Norwegian mainland, the  projects will end up being more expensive to build. The grid infrastructure both from the seabed/offshore constructions to the mainland and onshore locally in the municipality to the regional grid will need a lot of upgrade and newbuilds to ensure that Norway will be able to use the new offshore energy production onshore (either through power-2 X chains to other renewable sources or stand-alone).

Solar

The regulatory framework in Norway needs to be developed and adapted by the government and Parliament for this new green industry to become a success in Norway. The current regulatory framework and grid system is not sufficient for the growth and development of the solar industry. On 12 June 2023, Parliament instructed the government to work on an overall action plan, including to prepare the regulatory framework and resolve certain solar-resolutions to make it easier to share solar electricity between buildings, require that new buildings or state-owned buildings must install solar or other local energy sources to ensure the local energy production is intensified, and increase the MW threshold allowed to be produced in addition to put more decision-making authority on the municipalities under the Planning and Building Act. These "solar package" resolutions from the government are expected early 2024.

Hydrogen

The government has announced its support plan (billions of support to build hydrogen factories), to reach the goal of net zero emission in Norway. The challenge lies within political and financial decision-making, including that the government actually starts actively supporting this new industry and develops a sufficient regulatory framework that also considers the safety of handling and transporting hydrogen. We expect positive steps and changes in this industry within the next few months.

Politically and financially, Peru is currently facing a scenario of surplus installed capacity which, to date, reaches almost 30% pre Covid-19 (the international recommended level is around 30%). Energy prices are still dropping due to the Covid-19 crisis and investments in the sector have followed that same trend, which is expected to gradually reverse towards 2021 as the mining sector is recovering from plummeting metal prices and large mining projects.

Despite this, RER projects granted by the government during the 2010-2016 term are scheduled to start operations between 2017-2021. The guaranteed revenue scheme committed by the government will ensure profitability.

Towards 2023, appetite for new energy investments should resume and grow thanks to increasing energy demand levels Investment in hydropower is highly likely. However, viability of RER projects will greatly depend on (i) continued government support and the development and introduction of new technologies that will allow green energy to compete with other cheaper sources of energy.

One of the most relevant obstacles faced by energy projects is the process of obtaining permits and approvals. The government recently amended the regulatory framework with the goal of making administrative proceedings more efficient. However, the real challenge is implementing these changes.

Finally, the so-called “social license” is also one of the most challenging issues for energy projects. Not only do energy projects need to meet regulations but they also need to seek social acceptance. Establishing workable relationships with the local population is key to any energy project success.

The main obstacles at the moment include the standard cPPA's requirement concerning the counterparty’s strong financial standing and respective contractual collateral to be established, which narrows potential offtakers to major companies. The Polish windfall tax regulations are also applicable to cPPAs and are basically depriving the generators of the revenues exceeding the statutory price cap level (regardless of the mutually and consensually agreed price levels by parties to the cPPA). Other challenges include the dynamically changing regulations.  

For the past few years, investors also predominantly participated in the auction system (CfD scheme). This support is provided in the form of contract for difference where generators are paid the difference (if any) between the auction bid and the market price (specifically defined price published by the Polish Power Exchange). However, as the prices of electric energy increased, more investors turned to cPPAs as an instrument to securing financing of investments that is more favourable than auctions.

Corporations wanting to shift to green energy may face some challenges, namely the time-lag until Commercial Operation Date (COD).

The Portuguese government has set ambitious targets as regards renewable energy, which may lead, in the medium or long term, to a downward impact on electricity market prices. Furthermore, the growing trend – especially as regards solar power – has led to a shortage in grid capacity.

The current economic and social landscape poses a pending threat of volatility in prices, which reflects particularly in the energy market.

Coming soon.

In recent years, there has been uncertainty and debate regarding the licensing and registration requirements for generators (particularly regarding whether certain own use, embedded generation and de minimis exemptions were applicable or not). However, recent regulatory updates (as recent as April this year), have introduced a series of exemptions for generators from licensing (as above) which has clarified the position substantially.

In addition, the Minister of Mineral Resources and Energy has approved that NERSA may process licence applications for the following self-generation facilities of above 1MW even if they are not in compliance with the Integrated Resource Plan, 2019 ("IRP 2019"):

• a generation facility that is connected to the national grid, in circumstances in which the generation facility supplies electricity to a single customer and there is no wheeling of that electricity through the national grid; and/or
• a generation facility that is connected to the national grid, in circumstances in which the generation facility is operated solely to supply a single customer or related customers by transporting electricity through the national grid where wheeling arrangements are in place between all affected parties.

Previously, if not in compliance with the IRP 2019, prospective applicants were required to obtain Ministerial approval for deviation from the IRP 2019 before applying to NERSA for a licence. This has, to some degree, simplified the process for applicants regarding the above facilities.

In addition to this, there was a fair amount of uncertainty around the role that energy or battery storage could play in the energy matrix in South Africa. Thankfully, the regulations on New Generation Capacity have further been amended, inter alia, to allow for the procurement of new generation capacity by other organs of state, active in the energy sector which specifically includes generation capacity derived from energy storage.

• Plant development risk: time-lag between closing the PPA and Commercial Operation Date (COD) of the plant. Parties may wish to ensure that the seller and the facility/works are insured throughout the construction period (and not only after commencement of the supply period (ie following COD).
• Grid access congestion: to avoid overcapacity in terms of connection permits and grid access, the Spanish government published Royal Decree 1183/2020, which creates a simpler and more transparent process, regulating, among other things, capacity auctions. However, to date no capacity auctions have been held so far and it is not clear yet how the awarding criteria will work in practice.
• Regulatory risk: renewable energy legislation in Spain has suffered a series of drastic changes in the recent years as a consequence of decarbonization policies, COVID-19 and volatility of prices due to the war in Ukraine. Parties may wish to limit change in law coming into effect after the date of the agreement, and to exclude those changes in law which may be foreseeable. Change in law clauses usually regulate the renegotiation of the PPA if the change in law has created a significant unbalance in the economic situation of the parties under the PPA.
• Political risk: COVID-19 and the war in Ukraine have already led to recent regulatory changes affecting PPAs (as further explained in section 7 below). Volatility of prices has not stopped, so more regulatory changes are foreseeable in the near future. The EU is working on a major structural reform of the electricity market, which may affect Spain with independence of the “Iberian Exceptionality” which has already implied a reduction on the energy prices as explained in section 7 below.
• Price risk: volatility in energy prices may result, in a long-term contract, in an unforeseen market scenario that cause a substantial imbalance of the contract. As explained in the previous paragraphs, a solution could be the introduction of specific price review clauses (eg change in law) for those extreme hardship imbalance scenarios.
• Force majeure: COVID-19 has increased the importance of force majeure in PPAs. After the pandemic, it has become a must to include specific provisions in the PPAs to tackle the effects of the pandemic. One of the major consequences of the pandemic is the problems that some generators are facing with delays in equipment supply. This situation has, in some cases, created a delay in achieving COD and thus, negotiations around COD long stop date and force majeure have become fierce in the recent times.

Sweden's aim to establish a solely renewable energy power system is not without challenge both from a policy and regulatory perspective as well as operationally.

Policy and regulatory challenges include:

• ensuring that market design is adequate enough to encourage the flexibility that renewable energy requires;
• making sure that there is an adequate security of supply; and
• ensuring that the current distribution and transmission infrastructure can adapt.

The operational system will also need to make changes to expand network infrastructure, ensure that systems are stable and balance the new forms of supply and demand given that the transmission infrastructure has been around for a long time.

There are a number of solutions to overcome these challenges that Sweden can look to, including exploring expanding areas of artificial intelligence, battery storage and battery storage. Transmission infrastructure will require modernisation to accommodate the additional renewable energy capacity which will vary in frequency when compare with more conventional energy sources. With the very quick build-out of wind power in Sweden, capacity shortage in the national grid has also become an issue. For some projects such as offshore wind power projects, the cost of connecting the project to the grid may become prohibitive.

One of the major challenges remains financial since the installation costs of renewable energy production units from green energies, for self-consumption and professional use, are very high. Some companies do not have the means to finance them, especially in terms of self-financing (30% equity commitment).

To remedy this shortcoming, some leasing companies have already financed (even in an isolated way) some photovoltaic installations. Moreover, Tunisia is in the process of setting up a pilot scheme for financing photovoltaic projects by leasing, given that certain conditions for this implementation are now quite favorable, (setting up guarantee funds, international refinancing lines, the participation of international donors).

Another challenge is contractual. PPAs in Tunisia are adhesion contracts (standard contracts approved by the Ministry of Energy). It is the public body (licensing authority, the ministry in charge of energy, STEG) that sets the main conditions of the PPAs, since the producers of electricity from green energies can only sell it to STEG.

Also the process of obtaining the authorizations is at some level long and complicated.

• Stipulation of, and regular review of, the Uganda Renewable Energy Feed-in Tariff for sales to the grid of electricity generated by renewable energy systems of up to a maximum capacity of 20Mw as a means of providing a fixed tariff based on levelized costs of production for a guaranteed period of time encourages predictability and transparency in determining the tariff.
• Introduction of a Uniform System of Accounts (USoA) to enable the regulator easier assess an entity’s financial performance and foster an understanding of the cost of providing services in the industry for a fair and reasonable determination of electricity tariffs.  That is:
  • Considering that the electricity tariffs paid by customers are a composite of the costs incurred in the generation, transmission and distribution of electricity, availability of accurate and consistent information on the cost of providing the electricity supplied, through the USoA, simplifies tariff determination.
  • Due to ring-fencing rules, electricity consumers are protected from bearing undue costs that are attributed to other (non-electricity related) businesses that Electricity Regulatory Authority (ERA) licensed companies may be engaged.
• The willingness by the Electricity Regulatory Authority to engage in bi-lateral discussions regarding applications enables investors to reach workable solutions where varying views are held.

There are a variety of challenges facing the adoption of renewable energy by corporates in the Middle East, including:

• Conservatism - renewable energy is a relatively new development in the region and there has been a reluctance to move away from traditional conventional (hydrocarbon fuelled) generation. However, this attitude is changing. Nevertheless, it may take some time for some countries to fully embrace renewables and for corporates to trust that renewable energy can meet their energy needs in a reliable and affordable manner.
• Subsidised markets - a potential issue in some Middle Eastern countries is that big corporate energy consumers subsidise the cost of energy for smaller businesses and/or private consumers through paying higher tariffs. Should the big corporates enter into private PPAs and effectively go "off-grid", this will result in less income for governments to provide these subsidies. As a result, some Middle Eastern governments have been reluctant to allow large scale self-generation projects. Electricity subsidies are however either being reviewed, reduced or removed in numerous Middle Eastern countries, so this issue may fall away.
• Financial incentives - electricity prices are already low in many countries across the Middle East. This presents a challenge to the corporate PPA market, as the prices being offered by developers to corporate off-takers must be attractive enough to encourage them to take the risk of investing in a private renewable energy facility. Low market prices also present a test to the developers as they want to see a certain level of profitability in the projects they undertake. Finding the balance between offering a compelling price to a corporate off-taker and making an acceptable profit, could be challenging. As mentioned above, there are indications that electricity subsidies will be reduced in some Middle Eastern countries which may mean this balance becomes easier to achieve as standard electricity prices increase.
• Grid suitability - some Middle Eastern countries do not have transmission systems (or grid operators) able to handle a large amount of intermittent renewable energy generation. Whilst some countries have already upgraded their grids to deal with additional intermittent generation (Jordan with its 'Green Corridor', for example), this will be an ongoing task as more capacity is added to the grids (at both local and national levels).
• Regulations - the Middle East is dominated by markets where a government owned utility has a monopoly on the offtake of electricity. Only where there are specific laws and regulations allowing for it, may self-generation and corporate offtake projects be possible. Regulations and law enabling the export and sale of excess power to the grid are quite limited in some countries (such as Saudi Arabia), meaning privately developed projects might be a less attractive proposition where power unconsumed cannot be sold.
• Funding issues - given the Middle Eastern corporate PPA market is relatively new, finding banks willing to lend directly to projects with somewhat untested structures may prove difficult. This will particularly be the case with international banks where they do not already have a relationship with the developer or corporate. In addition, corporate off-takers might not be willing and or able to give the type of payment security that lenders typically expect on non-limited recourse financed energy projects in the region. It may therefore be that alternative sources of finance and/or funding arrangements need to be considered.

Brexit sheds legal and contractual uncertainties on the future of PPAs in GB. It remains unclear whether the EU Clean Energy Package will be implemented or whether GB will adopt a new regulatory framework. In the case of a hard Brexit, where GB leaves both the EU and EEA, GB would be released from its renewable energy targets under the Renewable Energy Directive (Directive 2009/28/EC and Directive (EU) 2018/2001) and from EU state aid restrictions.

Nevertheless, the Government has indicated that it will transpose existing EU state aid law into domestic law upon withdrawal by virtue of an implementing act under the European Union (Withdrawal) Act 2018. Under the current draft State Aid (EU Exit) Regulations 2019, laid before Parliament on 21 January 2019, the Competition and Markets Authority (CMA) will be the responsible authority for EU state aid provisions and decisions implemented into UK law. The CMA will generally continue the role of the Commission in its authorization and investigation powers, and state aid approved by the Commission or given under a block exemption prior to Brexit will not need to be approved again by the CMA.

The Government has prepared the Electricity (Guarantees of Origin of Electricity Produced from Renewable Energy Sources) (Amendment) (EU Exit) Regulations 2018, which upon a no-deal withdrawal will ensure that GoOs issued in EU Member States continue to be recognised in GB. Furthermore, GB will continue to issue GoOs to eligible GB renewable generators (REGOs).

A notice issued by the Commission dated 7 March 2018, however, states that following a no-deal withdrawal, GoOs issued in GB will cease to be recognised in the EU-27 Member States.

More generally, EU energy law will cease to apply to GB and its electricity markets will be decoupled from the Internal Energy Market (IEM), which means that cross-border flows of electricity will no longer be governed by EU legislation. GB has sought to mitigate this impact by enacting the European Union (Withdrawal) Act 2018, which will transpose all EU law into UK national law. In the case of a no-deal withdrawal, however, the inability to enforce any necessary cooperation with EU institutions may render these laws ineffective to an extent.

In summary, there may be some scope for GB to diverge from the current EU renewables regime over time, however, GB may be expected to voluntarily align with this, and such development may be covered by a future cooperation or trade agreement.

Market Price Risk

Corporate buyers entering into a Virtual PPA face the risk that wholesale market prices for energy will decline below the contract price or strike price such that significant amounts will be payable by the corporate buyer to the generator.  Virtual PPAs may include terms which require the generator to share in potential revenues or limit potential market price risk with a floor or a collar.      

Counterparty Credit Risk

Many generators are today offering Virtual PPAs as to a portion of a renewable generation project such that the project will by necessity have other customers. The impact of a breach by such other customer could put the economic viability of the project in question or prompt action by the financing parties. Thus, in addition to the credit risk of the generator, each customer bears some credit risk as to the other customers of the project.   

Changing Regulation

The regulation of the energy industry in the US continues to change based on high-level policy considerations such as the appropriate level of regulation or the integration of new technologies.  Frequent changes can have a negative impact on development. For example, there are certain federal incentives that benefit owners of renewable generation assets (known as Production Tax Credits or PTCs and the Investment Tax Credits or ITCs). Monetizing these existing incentives represents significant economic value which has spurred development over time.  However, they are typically extended or reauthorized for a limited term of a few years such that generators are often racing the existing sunset date and development decreases as they approach.      

Accounting Treatment

Virtual PPAs may result in mark-to-market or derivative accounting treatment on the books of the relevant corporate buyer. 

Technology Risk

By electing to purchase power from a specific generation facility under a Virtual PPA or a traditional PPA, the reliability of supply to that corporate buyer then becomes subject to the performance of the particular technology and equipment selected and maintained by the generator. 

The National Renewable Policy published in August 2019 summarizes challenges facing IPP/generators and the whole energy sector, in particular renewable energy sector, as follows:

Financial

• Limited incentives like electricity banking, trading, net metering for third-party access.
• While solar products are duty free, the country does not have fiscal incentives in place for investors, such as feed-in tariffs, tax rebates and renewable energy certificates, which have proven to be key drivers of renewables in European markets.

Regulatory and Administrative

• Limited clear tariff structure for renewable energy projects. Without clear tariff structures for grid-connected green projects, conflict is always likely between IPPs and the Zimbabwe Energy Supply Authority (ZESA), which owns the grid and is also a competitor.
• Inadequate regulatory framework for third-party sale of power.
• Uncertainty with regards to PPA structures as well as the procurement framework.
• High production costs affecting the economic viability of renewable energy projects.
• Inadequate institutional structures dedicated to renewable energy projects.
• Absence of clarity on the approvals and timelines for development of renewable energy projects and the responsible agencies for the same.
• Lengthy and complex administrative approval processes (which may take as much as 12 months in some cases).
• Land acquisition related issues, especially for projects that need large tracts of land. 

Other reported challenges generally are as follows:

• In general, Zimbabwe has a high political risk profile, which makes it an unattractive destination for IPPs who need foreign funding to undertake projects in Zimbabwe. Where such funding is available, the insurance risk premiums may be prohibitive.
• Technical challenges relating to poor quality of (mainly) solar equipment and technologies imported by IPPs, including lack of skilled installers of most green energy technologies, resulting in high failure of such equipment.
• Shortage of foreign currency in Zimbabwe in general has been an insurmountable challenge for many IPPs. First, a financial model not denominated in foreign currency (ie in local Zimbabwean currency) is difficult to justify when most investments require foreign currency. This is compounded by the fact that ZESA/ZETDC do not pay for power that has been supplied to them from domestic sources in foreign currency, notwithstanding that the tariff set in a PPA (in particular in Physical PPA/Wheeling PPA/Sleeved PPAs) is in foreign currency. As such, many PPAs have become “unbankable.”
• Due to lack foreign currency in Zimbabwe, there’s no guarantee for most investors that they will be able to repatriate their profits and capital from Zimbabwe.
• The above also gives rise to domestic currency to foreign currency convertibility issues, meaning that even if the investor has adequate local currency to import equipment, or repatriate its profits, there is simply no foreign currency liquidity in the market.
• Policy uncertainty regarding whether or not government will grant support to IPP power projects in the form of an IPP implementation agreement to guarantee balance of payments or payments in foreign currency. It’s reported that ZESA imports USD20 million worth of electricity from neighboring countries, mainly Zambia and Mozambique. Ironically, up to 30% of the imports come from IPPs in those countries, compared to only 1.5% domestic IPP contribution. This amount could be used to give IPPs the necessary guarantees in foreign currency they require to unlock foreign investor funding. This lack of support has, therefore, left many PPAs in limbo.
• There’s also a perception that because the utility is also a major player in the energy market, there’s a general difficulty with negotiating PPAs with them as they most often than not have entrenched positions based on the prevailing law eg refusal to pay for power in foreign currency. 

Practical solutions

• As stated previously, cPPAs are seen as increasingly allowing IPP/generators the opportunity to negotiate directly with corporate buyers, thus bypassing some of these challenges mentioned above, particularly where the corporate buyer is an exporter and therefore has its source of foreign currency.
• Further, if government support were to be given to guarantee payments in foreign currency, that may unlock funding from investors who will have a recourse in case of non-payments.
• Codifying incentives in law may also assist in improving viability of renewable energy projects. For instance, the National Renewable Policy suggests the following incentives in respect of sale of power to third-party grid access:̶
  • Indiscriminative open access to the grid to be granted to renewable energy producers or beneficiaries.̶
  • Priority dispatch to be granted to renewable energy producers.̶
  • An Energy banking facility to be extended by the utility for solar and wind generators.̶
  • Utility and the IPPs to enter into wheeling-agreements based on agreed models. This is seen as a nod to cPPAs in their many varieties.̶
  • Any wheeling agreements to be approved by ZERA within four months from the date of notification of the policy.
  • A net metering facility to be extended to beneficiaries, namely the consumers availing net metering facility.