Category Archives: Energy and Natural Resources

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An Insight Into Carbon Capture Investment in the UK

In connection with its ambition to capture and store up to 10Mt of CO2 per year by 2030, the UK government is looking to identify at least two carbon capture, usage, and storage (CCUS) clusters suited to deployment in the mid-2020s as part of its Cluster Sequencing Process.

The intention is to support the deployment of CCUS projects at a number of industrial clusters, with the potential for these clusters to be expanded into a UK carbon network as users connect to the shared transport and storage (T&S) infrastructure.

The six largest industrial clusters by the level of CO2 emissions are at Humberside, South Wales, Merseyside, Grangemouth, Southampton, and Teeside.

These account for a significant proportion of the UK’s industrial CO2 emissions and are considered to offer the most potential in terms of shared CCUS infrastructure.

UK Industrial Clusters Map
Source: Industrial Decarbonisation Strategy March 2021 and NAEI 2018 data. It does not capture non-ETS emissions in a cluster.

CCUS Business Models

The UK government published an update to its CCUS business models in May 2021. It is through these business models that the UK government seeks to support the deployment of CCUS projects.

The cost of the shared T&S infrastructure is passed through to connecting carbon capture projects by way of a regulated T&S fee. These projects in turn benefit from support under Dispatchable Power Agreements and Industrial Carbon Capture Contracts.

The UK government is also looking at a business model to support “blue” hydrogen production at CCUS clusters. The intention is for shared T&S infrastructure to have sufficient capacity to enable the expansion of the CCUS cluster. 

CCUS Business Model

T&S Regulatory Investment Business Model (TRI Model)

The T&S company is responsible for the development, construction, financing, operation, maintenance, expansion, and decommissioning of the T&S infrastructure.

The UK government’s proposed TRI Model involves a licence being granted to the T&S company pursuant to which it receives an “allowed revenue” by charging users a regulated T&S fee to have their captured CO2 transported and stored.

The UK government is also considering incentives linked to availability, leakage rates, and connection of additional users, as well as reopeners for one-off material changes in expenditure outside the control of the T&S company. A regulator will be responsible for administering the licence and monitoring the performance of the T&S company.

It is recognised that the T&S infrastructure may be underutilised until more carbon capture projects are completed and connected to the shared T&S infrastructure, resulting in the T&S company collecting less than its allowed revenue in T&S fees.

The UK government is proposing to include mitigating measures in the TRI Model such as shaping the allowed revenue profile to align with expected utilisation build-up and providing for allowed revenue to be deferred and “rolled up” if connecting carbon capture projects are delayed.

The UK government also intends to make a contingent mechanism available to protect the T&S company’s revenues and a Government Support Package (GSP) to protect against specific high impact low probability risks.

Industrial Carbon Capture Contracts (ICC Contracts)

It is intended that CO2 emitters in sectors such as chemicals, refining, steel, and cement will invest in industrial carbon capture and connect to the shared T&S infrastructure.

In order to incentivise investment in industrial carbon capture, the UK government proposes to grant contracts that provide the CO2 emitter with a payment per tonne of captured CO2 to cover operational costs, T&S fees, and repayment of capital with a rate of return. The UK government is also looking at providing other support such as capital grants.

Dispatchable Power Agreements (DPAs)

The UK government intends to support the deployment of dispatchable power stations with carbon capture through contracts based on the contracts for difference (CfDs) used for renewables.

The proposed DPA provides availability payments for revenue certainty and variable payments to ensure that power stations with carbon capture dispatch ahead of unabated power stations by accounting for the additional costs associated with carbon capture.

It is through the DPA that the investor recovers the cost of T&S fees and capital invested in carbon capture, together with a rate of return.


T&S infrastructure investment is dependent on carbon capture projects being completed and connected. In turn, carbon capture projects are dependent on the T&S infrastructure being available.

It is through the expansion of the CCUS cluster that the T&S infrastructure can be used efficiently and costs per tonne of CO2 reduced.

Pipeline capacity and connection arrangements will be important when it comes to expanding the CCUS cluster and making full use of the shared T&S infrastructure.

The UK government is looking to mitigate risks associated with interdependency through mitigating measures and a contingent mechanism (see above), but investment in T&S infrastructure and carbon capture projects will necessarily take into account the other projects making up the CCUS cluster and potential expansion of the CCUS cluster. Individual projects are not able to stand on their own, notwithstanding that mitigating measures and a contingent mechanism may be used to plug gaps.

It is through the Cluster Sequencing Process that the UK government aims to support the efficient deployment of CCUS. Those projects which form part of a “Track 1” cluster will have the first opportunity to be considered for support.

The UK government announced on 30 July 2021 that five clusters met the eligibility criteria set out in its Cluster Sequencing Process.

These clusters are referred to as DelpHYnus, HyNet, the East Coast Cluster (ECC), the V Net Zero (VNZ) Cluster, and the Scottish Cluster. The UK government expects to announce “Track 1” clusters from 25 October 2021.

Carbon Pricing and Carbon Border Adjustment

In practice, policies to reduce CO2 emissions and incentivise CCUS will not work if carbon-intensive industry relocates to countries with less stringent climate regulations (or where there are stringent climate regulations but these are not enforced effectively).

There is no point in reducing CO2 emissions in the UK by shifting emissions to other countries. There needs to be a reduction in global CO2 emissions.

The proposed business models effectively pass the cost associated with CCUS through to UK taxpayers and consumers, but what happens after this support falls away?

If operational costs and T&S fees are no longer supported by UK taxpayers and consumers, continuing to capture carbon and connect to the T&S infrastructure will represent an additional cost for CO2 emitters.

This in turn has consequences for the shared T&S infrastructure.

UK carbon pricing and activism on the part of shareholders and consumers provides an incentive for CO2 emitters to continue to capture carbon and connect to the T&S infrastructure, but there is a question as to whether this will be sufficient if countries with less stringent climate regulations offer a cheaper alternative.

This is not just an issue for the UK and there has been a push for coordinated action across countries to reduce global CO2 emissions.

It is important to look at the global supply chain and ensure that CO2 emissions are not just shifted to countries where there are less stringent climate regulations.

If global supply chains are used to import materials or components from such countries at a lower cost we will just be shifting CO2 emissions, so measures such as ESG reporting will be needed to improve standards across the global supply chain.

ESG reporting offers to provide transparency with respect to the carbon footprint of a company’s global supply chain, enabling consumers and investors to distinguish between businesses that shift CO2 emissions to other countries and those that do not.

The FCA is currently consulting on extending climate-related disclosure requirements to more listed companies and institutional investors are voting against management at companies failing to address environmental issues.

However, so long as businesses can reduce costs by importing materials or components from countries with less stringent climate regulations there will be an issue with CO2 emissions being shifted to such countries.

In order to address this, countries have been looking at carbon border adjustments whereby imports from countries with less stringent climate regulations will face an additional charge to level the playing field.

If the UK government were to introduce a carbon border adjustment, it would be able to impose a higher cost on CO2 emitters without shifting CO2 emissions to other countries.

This would incentivise the expansion of the CCUS clusters without direct support from UK taxpayers and consumers. UK exporters will still be at a disadvantage in international markets when competing against companies that do not have to reduce their CO2 emissions, but coordination across countries in terms of carbon border adjustments will mitigate this.

The cost associated with reducing CO2 emissions still lands with the consumer in the form of higher prices, but CO2 emitters and global supply chains would be incentivised through the competitive market to minimise the cost of reducing their CO2 emissions.

This could, in turn, result in opportunities for CCUS clusters that are able to capture, transport, and store CO2 at a relatively low cost (i.e. companies may invest in, or source materials or components from, plants or production facilities at a CCUS cluster in the UK rather than those in countries with less stringent climate regulations if the carbon border adjustment outweighs the cost of carbon capture, transport, and storage at the CCUS cluster). This would have a real impact on global CO2 emissions.

Investment in Carbon Capture

There is a move away from carbon-intensive industries to renewables and CCUS as banks, private equity firms and other financial investors look at aligning their lending and investment portfolios with net-zero emissions.

In particular, some 53 banks from 27 countries representing almost a quarter of global banking assets have committed to aligning their lending and investment portfolios with net-zero emissions by 2050 as part of the Net-Zero Banking Alliance and there is an initiative to develop a standard for banks to measure and report on their social and environmental impact.

There has been a lot of interest in CCUS and the expectation is that significant financing will be available to support projects which are aligned with reducing CO2 emissions. Industrial companies and oil majors are also looking at investment in CCUS. 


The fact that the UK government’s proposed business models are based on existing regulated asset base models and contracts for difference is positive for investors.

The decision to invest in T&S infrastructure or to provide financing will rest on confidence in the revenue that will be allowed under the TRI Model, the status of the different projects making up the CCUS cluster, and the extent to which mitigating measures and contingent mechanisms will plug any gaps that may arise.

CO2 emitters and other investors in carbon capture will look at that the ICC Contract and whether it covers operational costs, T&S fees, and repayment of capital together with a rate of return.

The term of the ICC Contract will be important and, to the extent that the carbon capture equipment is still operational after the ICC Contract falls away, CO2 emitters and investors will be looking at carbon pricing and potential measures such as carbon border adjustments to ensure that there is long term demand for CCUS without relying on direct support from the UK government and consumers.

In the long term, these measures could lead to opportunities for CCUS clusters that are able to capture, transport, and store CO2 at a relatively low cost.

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The UK Offshore oil and gas industry – current challenges and recent trends

The UK’s offshore oil and gas industry has undergone a torrid few years, starting even before the oil price crash of 2014. The industry has of course been here before and has demonstrated itself to be adaptable and resilient. In 2014, with oil prices which had averaged over $100 for several years, production was 1.4 million barrels of oil equivalent (boe) a day, down from a peak of almost 3 million boe a day in 1999, while operating expenditure was through the roof, production efficiency was poor and exploration was at historically low levels, offering little prospect of staving off a slow decline.

Since then the price has crashed to lows below $30, recovering somewhat to the mid-$50s.  The scale of the crisis hitting the industry is demonstrated by the fact that for the first time since the offshore industry began production in 1968, tax revenues in the tax year ending 2016 were net negative i.e. the government paid out £24 million more in tax relief than it received in taxes, while the industry took in less cash than it spent in 2016, for the fourth year in row. With minimal attention in the national press, the brutal discipline of the marketplace has cut the workforce supporting the offshore industry from 450,000 to 330,000 with wave after wave of redundancies.

As a result of relentless pressure on contractor rates, down-manning and the pruning of discretionary spending, operating costs have fallen from an average of £18 a barrel in 2014 to £11.30 last year while a focus on production efficiency has led to an improvement from 65% to 71% over the same period. This improvement in production efficiency, as well as record levels of capital investment approved while the oil price was still above $100, has resulted in a turnaround in production which has been on the increase for the first time in many years: the 322 oil, gas and condensate fields currently in production produced over 1.7 million boe per day in 2016.  However, new investment is very dependent on the oil price.  Professor Alex Kemp, a leading oil economist based at the University of Aberdeen, argues that at $50 a barrel, new investment activity is stifled and few projects pass investment hurdle rates. Even if Brent crude reaches $60 a barrel, it will be helpful butit is not going to transform the industry as there will still be many fields which remain uneconomic. In the longer term further cost reductions and/or price increases are needed to enhance activity further.

As capital investment is expected to continue to fall from its peak in 2014, the improvement in production levels is likely to be a short-lived respite and total production is expected to begin to fall again within a couple of years, depending on the timing of start-ups.  Nine new fields started up in 2016 including Cygnus, Solan, Laggan and Tormore, but only two new fields were approved, though the forecasts for 2017 are slightly better. With just 23 exploration and appraisal wells being spudded in 2013, down from highs of over 100 in the mid-2000s, discovering new fields to replace those reaching the end of their life is increasingly challenging.  Most new discoveries are small, expected to produce between 10 and 30 million boe, though some of 2016’s start-ups are exceptions – Cygnus is expected to supply 5% of UK gas demand at its peak while Laggan and Tormore have estimated reserves of 170 million barrels. It’s worth remembering, also, that UK domestic production is still meeting around two-thirds of our oil demand and more than half of our gas demand.

While dealing with the day to day pressures of this financial shock, the industry has also been getting to grips with an overhaul of its regulatory regime.  In 2013, recognising the problems facing the industry even then, the government appointed Sir Ian Wood to review existing regulation to see if it was fit for purpose.  He recommended a new tri-partite relationship between the industry, a new better-resourced and independent regulator, and the Treasury representing the interest of the nation in its hydrocarbon resources, to make the most of the remaining reserves of the UK Continental Shelf (UKCS).

Swiftly implementing the recommendations of the Wood Review, which reported in February 2014, the government established a new regulator, the Oil & Gas Authority (“OGA”), initially in April 2015 as a government agency and since May 2016 as a government company.  The OGA is designed to regulate, influence and promote the offshore sector in a manner better suited to the challenges of an ageing basin, with numerous marginal fields dependent on a network of highly-interconnected infrastructure which is reaching the end of its life.  The industry has new legal obligations, incorporated into the Petroleum Act 1998 by the Infrastructure Act 2015, to seek to maximise economic recovery of hydrocarbons in the UK’s territorial waters and Continental Shelf, in particular through collaboration with other industry players, and to comply with a Strategy produced by the regulator to achieve that end, known as “MER UK”.

The OGA has taken over many of the powers and responsibilities formerly held by the Offshore Licensing Unit of DECC, including the power to award licences and grant field development approvals, but the Energy Act 2016 has also given it new powers and greater resources, funded by a significant industry levy.  The new powers include powers to attend industry meetings, to request a broad range of information, and to give non-binding recommendations to resolve disputes.  The OGA also has a greater range of sanctions to impose on those who fail to comply with their obligations under the licence or the MER UK Strategy, including powers to impose fines of up to £1 million and to issue enforcement notices, in addition to the existing powers to revoke, or partially revoke, licences and remove operators.  While the OGA can neither rewrite existing contracts, nor force licensees to invest, it can declare that reliance on existing legal rights is contrary to MER UK, and require licensees who do not wish to invest to divest or relinquish the relevant assets. While such draconian interventions are likely to be rare, and the OGA has to bear in mind the need not to deter investment in the UK, there is a degree of nervousness in the industry as to how the OGA will exercise its very broad discretion.

So far the signals are that the OGA will seek to influence and encourage far more than to compel. This is important. From its relatively recent establishment, the OGA has hit the ground running, having issued a large number of subsidiary strategy documents and delivery plans, as well as establishing a wide-ranging stewardship survey to measure the performance of operators and enable it to benchmark performance, prioritise its regulatory activities, and to develop regional plans for the development of many of the currently uneconomic discoveries.  It has also funded seismic studies to open up new exploration possibilities and is investing in better technology to store and share data.  The organisation is less than 180 people and so will not be able to solve all of the industry’s problems but its proactive approach is showing signs of success – it claims to have successfully intervened in more than 70 cases already to enable development of discoveries, extensions of field life, unblocking of commercial issues, cost savings and improved plant operations.

A significant legal issue for the industry is how to balance its new statutory duty to collaborate to achieve MER UK with its duties to comply with competition law – this is likely to require more frequent substantive analysis of competition law issues to determine whether or not proposals for collaboration, particularly between operators rather than vertical collaboration between operators and the supply chain, are justifiable on competition grounds.

Not all is gloom. The oil and gas industry is resilient and has been at the cliff edge before. A degree of stability in the oil price, closing the valuation gap between buyers and sellers, has enabled something of a resurgence in oil and gas M&A activity.  In the last six months, deals have been signed over almost £5 billion worth of North Sea assets, including Shell’s recent £3billion sale of North Sea assets to Chrysaor, the £993million acquisition of Ithaca Energy by Israeli-based Delek Group and BP’s disposal of an interest in Magnus to Enquest for £68million. Recent transactions have also shown a new appetite for banks to lend and private equity to invest in the sector (the Chrysaor deal was backed by EIG Partners as well with a reserve-based lending package from a consortium of banks while Blackstone and Bluewater Energy have put over £400million into Siccar Point Energy).  One of the factors in enabling deals to proceed is the use of innovative structures, such as those offering upside for the seller (for example, in the Shell/Chrysaor deal, an additional $600 million is payable contingent on the average price of oil between 2018 and 2021 exceeding $60 a barrel and a further $180 million contingent payment is dependent on future discoveries by Chrysoar). The sharing of decommissioning liability is also key to transactions since many assets are at the point where their remaining production will not generate sufficient tax capacity to offset decommissioning costs and allow full relief of those costs: Shell has reportedly accepted continued decommissioning liability of $1bn (about 25% of the total cost) of the assets sold to Chrysaor while in its transaction with Enquest, BP has retained the decommissioning liability. EnQuest will pay BP additional deferred consideration of 7.5% of the actual decommissioning costs on an after tax basis, subject to a cap equal to the amount of cumulative positive cash flows received by EnQuest from the transaction assets.

Given the maturity of the basin and its financial challenges, decommissioning is one of the most significant issues facing the industry over the next decades but also a substantial opportunity for the development of a strong specialist supply chain.  There are about 250 fixed installations, 250 subsea installations, 5000 wells and 3000 pipelines in the UK sector of the North Sea, with much of that infrastructure being well past its original design life. There is evidence that the oil price crash has resulted in some acceleration of decisions to cease production, but this should not be overstated – while COP dates for 72 assets were brought forward in 2016, 33 were deferred and 135 remained the same.  Decommissioning expenditure is currently running at over £1billion annually and it is estimated that over the next ten years around £17.6 billion will be spent on decommissioning. A key plank of the OGA’s activity is to reduce decommissioning costs and therefore the cost to the Exchequer of decommissioning tax relief.  Collaboration between operators and the supply chain over best practice and the use of new technology and between operators on multi-well programmes will form part of this initiative but there are also new legal obligations for licensees to consult the OGA before submitting decommissioning programmes for approval. Lawyers are awaiting revised guidelines from BEIS, which now has responsibility for approval of decommissioning programmes, and from the OGA, to see how this process will work in practice. Reducing decommissioning costs will also reduce the ever increasing burden of decommissioning security, required to protect licensees from joint and several liability for the execution of decommissioning programmes, and vendors from the risk of being brought back to conduct decommissioning under the wide powers of Part IV of the Petroleum Act 1998.

Technology however, will absolutely be the key to the continued success of the sector, demonstrated by the opening in Aberdeen of the Oil and Gas Technology Centre, but along with high-tech tools and innovative methods, the industry is continuing to focus on more efficient ways of working to keep costs down, especially through collaboration under the auspices of Oil & Gas UK and other trade bodies. 2017 sees the industry in a more optimistic mood, but aware of the challenges that lie ahead.

Evaluating and Managing Environmental Risk in Real Estate and M&A Transactions in the United States

The complex environmental regulatory regime in the United States can raise a variety of legal and financial risks in real estate or corporate acquisitions.  Accordingly, lawyers should understand the nature of potential environmental liabilities for different transactions, the relevant facts, and how to structure environmental due diligence tools to provide clients meaningful advice.

Tailoring Environmental Due Diligence to the Transaction

Environmental due diligence is not a “one-size-fits-all” activity.  The type of transaction, and the client’s objectives, often dictate the appropriate scope of due diligence.

Transactions take a variety of forms, such as the purchase or lease of real property, acquisition of the assets of operating businesses or facilities, stock acquisitions, corporate mergers and divestitures.  In real estate acquisitions, primary environmental due diligence concerns include identifying potential contamination, and either protecting against cleanup liability or evaluating remediation methods.  These transactions usually rely on Phase 1 and 2 environmental site assessments to identify contamination, help establish landowner liability protections, and assess cleanup strategies.  Analyzing other environmental regulatory constraints on site development may also be prudent.

Conversely, acquisitions of operating businesses or facilities, or corporate transactions such as stock deals and mergers, raise additional environmental due diligence concerns.  These include evaluating the target company or facility’s regulatory compliance status, the availability of permits to conduct and grow the business, and capital and operating costs needed to achieve compliance, implement permit conditions, and satisfy other environmental requirements.  For these deals, evaluating regulatory compliance and permitting issues may be equally, if not more, important than contamination concerns.

Superfund Liability and Defenses

In the U.S., fear of liability for contaminated property is largely driven by the federal Comprehensive Environmental Response, Compensation and Liability Act of 1980 (“CERCLA” or “Superfund”).  CERCLA establishes four categories of parties liable for the release or threat of release of hazardous substances into the environment, including current facility owners or operators, former owners or operators at the time of disposal, those who arrange for hazardous substance disposal at a facility, and those who transport hazardous substances to a facility for disposal.   Superfund liability can be severe, as it is retroactive, strict (i.e., regardless of fault), and joint and several.

Moreover, CERCLA offers only very limited defenses for landowners.  The most useful of these is the bona fide prospective purchaser (“BFPP”) defense.  This provision allows prospective purchasers to acquire facilities that the purchaser knows to be contaminated while avoiding Superfund liability.  To establish the defense, the purchaser must satisfy several conditions.  Pre-acquisition conditions include taking title to the facility after January 11, 2002 and after all disposal occurred; making “all appropriate inquiry” into the former uses and ownership of the facility consistent with good commercial and customary standards; and not being a potentially liable party or affiliated with such a party through certain relationships.  The purchaser must also comply with several post-acquisition requirements, including making legally required notices; taking reasonable steps to stop continuing releases, prevent future releases, and limit exposure; cooperating with persons performing remediation; complying with any land use restrictions or institutional controls; and responding to governmental information requests.  (Tenants may also utilize the BFPP defense in certain situations.)

Although the BFPP defense provides a valuable tool to protect against Superfund liability when obtaining contaminated property, the defense does not protect against potential liability under other federal or state environmental statutes. It is also not a defense to claims under other liability schemes such as tort, occupational safety and health laws, or breach of contract.

All Appropriate Inquiry (“AAI”) – Phase 1 Environmental Site Assessments

While all of the statutory requirements must be satisfied to support the BFPP defense, the primary objective of environmental due diligence in the U.S. involves performing AAI.  In 2005, the U.S. Environmental Protection Agency (“EPA”) published a rule, 40 C.F.R. Part 312, establishing the regulatory requirements for AAI.  In coordination with EPA, the standard-setting organization ASTM International revised its existing standard for Phase 1 environmental site assessments (“ESAs”) to comport with the Rule.  In practice, purchasers seeking to perform AAI do so by following the ASTM Phase 1 standard (currently E1527-13).

Phase 1 ESAs are non-invasive property investigations that seek to identify and document recognized environmental conditions (“RECs”) indicating a release or threat of release of a CERCLA hazardous substance (or petroleum, which is not regulated by CERCLA). Unlike Phase 2 investigations, Phase 1 ESAs do not include sampling and analysis of environmental media.  In addition to establishing one of the CERCLA BFPP defense conditions, a Phase 1 ESA (perhaps combined with Phase 2 testing) may also provide insight into possible common law and toxic tort risks posed by acquiring property, should the investigations identify contamination that could impact residential neighborhoods, potable water sources, or other sensitive receptors.

Most AAI tasks must be undertaken by an “environmental professional” meeting certain qualifications, or someone under his or her direct supervision. Basic Phase 2 elements include interviews with the current site owner, any occupiers likely to handle hazardous substances, state or local government officials, and potentially others; review of historical information sources (e.g., aerial photographs, fire insurance maps, land title records, and building permits) dating back to the earlier of 1940 or the property’s earliest developed use; review of federal, state and local regulatory agency records involving the property and other sites within defined search radii; and visual inspection of the property and of adjoining properties.  In addition, the standard calls for certain information from the user of the Phase 1 (typically the prospective purchaser), such as a review of title and judicial records for environmental cleanup liens and activity and use limitations; any specialized knowledge the user may have of the property and surrounding area; and whether the purchase price reflects any discount for contamination. The environmental professional must document the evaluation in a written report containing, among other things, the professional’s opinion as to whether conditions indicative of a release or threatened release exist, and a list of any data gaps and their significance.

Although Phase 1 ESAs have become extremely commonplace in environmental due diligence, a few important points are worth noting.  First, to satisfy the AAI rule a Phase 1 must be completed no sooner than one year prior to property acquisition, and certain elements must be completed or updated within six months before acquisition.  Also, remember that Phase 1 ESAs are designed to identify potential contamination, and do not evaluate other environmental issues (e.g., the presence of asbestos or lead-based paint in buildings, mold damage, or wetlands and other natural constraints on site development) unless expressly added as “non-scope” items.  In addition, given increasing scientific knowledge and regulatory concern regarding the potential for certain contaminants (such as those associated with petroleum and chlorinated solvent releases) to volatilize and enter occupied structures in vapor form, a 2013 update to the ASTM Phase 1 standard now requires evaluating the vapor intrusion pathway as part of identifying RECs.  Finally, as mentioned above, the BFPP defense requires more than satisfying AAI; the purchaser must meet several post-acquisition conditions as well.

Phase 2 ESAs – Evaluating Contamination and other Due Diligence Concerns

When a Phase 1 ESA identifies one or more RECs at a property, the next step often involves performing invasive “Phase 2” testing to confirm the presence and extent of any contamination.  Information from Phase 2 ESAs can serve several due diligence purposes, including deciding whether to proceed with or terminate the transaction; identifying post-acquisition tasks to satisfy the BFPP “reasonable steps” condition; allocating environmental responsibility through contract provisions such as purchase price adjustments, indemnities, cleanup obligations, and environmental insurance; developing remediation strategies and cost estimates to obtain liability protection through federal or state voluntary “brownfield” cleanup programs; and identifying natural or other constraints to site development.

Given their varying objectives, Phase 2 ESAs, unlike Phase 1 investigations, typically do not follow a single protocol.  A Phase 2 investigation may involve one or more of several elements, such as collecting samples of soil, groundwater, soil gas, indoor air, or other environmental media for laboratory analysis; searching for underground tanks, vaults, and other subsurface structures using geophysical techniques; evaluating the presence and extent of environmental conditions inside structures such as asbestos-containing materials, lead-based paint, mold, and radon; and identifying potential site development constraints such as wetlands, endangered species, and cultural or historic resources.

Phase 1 and 2 ESA Practical Considerations

To protect their interests, both parties in a real estate or corporate transaction should negotiate access provisions governing the performance of Phase 1 and 2 ESAs during due diligence.  These provisions should cover issues including, at a minimum, submission of a work plan for  owner approval; permissible entry times, pre-entry notice requirements, and non-interference with ongoing site operations; restoration of any property damage; compliance with applicable law and proper disposal of any investigation-derived waste; provision of split samples, test results, and reports to the site owner; and insurance and indemnification related to liability arising from the investigations.

Access provisions should also address confidentiality of environmental due diligence results.  Generally, owners require buyers to keep due diligence data and reports confidential, but buyers should seek certain exceptions including the ability to share results with lenders, counsel, and other due diligence team members (who may also be required to keep the results confidential), and to make disclosures if required by law (in which case the owner will want to control the reporting process).

Aside from access and confidentiality issues, parties planning to perform Phase 1 and 2 ESAs should keep a few other points in mind.  First, although Phase 1 and 2 ESAs can be performed concurrently, it is better to use Phase 1 results to develop the Phase 2 scope.  Also, take care when identifying and retaining an environmental consultant for the due diligence team.  Phase 1 and 2 investigations can vary significantly in scope and extent, and therefore potential consultants and firms should be evaluated for the necessary experience and skills appropriate to the type of site and anticipated tasks.  In addition, carefully review and negotiate consultant proposals regarding cost structure, markup of subcontractor and other expenses, anticipated timing for deliverables, and “boilerplate” terms and conditions such as insurance coverages, indemnity provisions, limits on liability, and confidentiality.

Evaluating Regulatory Compliance in Acquiring Ongoing Operations

In addition to assessing potential site contamination and development constraints, acquisition of an active facility or business requires evaluating the target’s compliance status with environmental regulatory requirements. These evaluations typically include issues such as whether the business or facility holds all permits and other approvals necessary to continue operations; whether these authorizations can or will need to be transferred as part of the transaction; and whether the business or facility currently has any significant noncompliance, or a history of noncompliance, with regulatory requirements or permit conditions (as evidenced by notices of violation, penalty assessments, administrative or judicial orders, consent decrees, etc.).

Depending on the type of operation, regulatory programs to evaluate for compliance issues may include, among others, air pollution control, wastewater and stormwater discharges, solid and hazardous waste management, emergency planning and community right-to-know reporting, management of storage tanks, use of pesticides, and maintenance and removal of asbestos-containing building materials.  Information on a business or facility’s compliance status may be found by reviewing facility and agency files, interviewing the target’s environmental health and safety personnel, and searching agency on-line databases.  In addition to identifying regulatory noncompliance issues, the due diligence effort should also attempt to estimate the potential costs of bringing the business or facility back into compliance.

Wrapping Up

Environmental due diligence in real estate and corporate transactions can be a complex and time-consuming task.  To make this process as efficient and productive as possible, tailor the scope of the diligence effort to the type of transaction, the client’s objectives, and the time and resources available to complete the process before closing.  Assembling a qualified and experienced team of technical and legal professionals to lead the diligence effort can help ensure that the client goes into a transaction with eyes wide open to potential environmental pitfalls.

Implications of the United Kingdom Leaving the European Union on Climate Change and Energy Law

Introductory Comments

  1. The purpose of this document is to chart the possible implications of the United Kingdom exiting the European Union on Climate Change and Energy Law.
  2. It is at this early stage, of course, of paramount importance to recognise that much of this evaluation is made against a backdrop of uncertainty: the terms, time-scale, and process of ‘Brexit’ are, as yet, largely unknown.
  3. This said, however, the value of this evaluation comes from its setting out the likely affected areas, and in raising awareness of the complexity which Brexit will yield.


  1. The principal issue which it will be necessary for the UK government to address following the referendum decision in favour of an exit from the EU is the resultant legislative lacuna. As will be detailed below, there are various EU Directives and Regulations which are focussed on addressing climate change concerns and, similarly, the EU has also ventured into energy law. To leave the EU, it is presumed, will be to see the repeal or disapplication of EU laws, and so it will be necessary for the UK government to consider its preferred position on the way to replace (or otherwise deal with) these laws.
  2. The UK is a whole comprised of nations with various devolved powers, as well as varied political, legal, and social characteristics. This structural make-up is likely to result in differing approaches to legislating on hitherto EU-led areas in the event of Brexit. Each devolved nation, to the extent that it is capable, may prefer different approaches to dealing with the legislative questions raised by an exit from the EU. It has also, rightly, suggested that the matter will be complicated by the UK’s relationship with the Crown Dependency of Gibraltar, and the Sovereign Base areas in Cyprus.
  3. It is trite to say that environmental concerns (which are addressed by environmental legislation) are international concerns which generally do not respect national boundaries. For this reason, it has often been recited that environmental concerns need to be addressed at an international level: it is nonsensical to legislate on an individualistic basis when the source or nature of the matter at hand cannot thereby be appropriately or meaningfully managed.
  4. This international characteristic of environmental law is perhaps all the greater in the context of climate change. When we speak of climate change, we are not discussing specific climates or biomes, but rather changes to the global climate. The global climate can be understood as a closed system where cause and effect operates on a global scale. Consequently, the EU, as a community of nations, has understandably considered itself competent and justified to legislate on climate change issues.
  5. This global awareness of climate issues can be very clearly seen through the negotiations at the COP21 UN Climate Change Conference in Paris, which resulted in the ambition of “[h]olding the increase in global temperatures to well below 2°C above pre-industrial levels and to pursue efforts to limit the temperature increase to 1.5°C…recognising that this would significantly reduce the risks and impacts of climate change”.[1]
  6. Energy law similarly has an international flavour. Bradbrook defines energy law as ‘the allocation of rights and duties concerning the exploitation of all energy resources between individuals, between individuals and the government, between governments and between states.’[2]
  7. With the benefit of hindsight, it is perhaps somewhat surprising that EU energy policy and regulation has not always engaged with its environmental characteristics. As Bell, McGillivray, and Pedersen suggest, ‘[h]istorically, EU environmental policy has had little to say about energy, and equally EU energy policy has had little impact on its environmental policy.’[3] Energy law incorporates issues to do with competition, intellectual property, tax, and free movement more generally. Whilst this note does not suggest that this position is now entirely reversed – certainly these aspects of energy law remain very significant – we do believe that there is an increased awareness of the environmental impact of energy use and production. This awareness is shared by producers, distributors, and consumers, and so it is now inevitable that environmental concerns (with all their associated international facets) will influence energy law and policy.
  8. In any event, for the purpose of this article, it is worth highlighting the inherent link between the energy sector and climate change. Indeed, the energy sector is the most significant source of carbon emissions in the EU, amounting to around one-third of total emissions.

Impacted Legislation

  1. Owing to the various recognised causes of climate change (which is to say, owing to the numerous sources of greenhouse gas emissions) the EU legislative portfolio seeking to address climate change is broad and engages with a range of different issues. Often, these legislative measures impact on the European energy sector, and so it is useful to deal with these two ideas together.
  2. Perhaps the most well-known EU legislative measure addressing climate change is Directive 2003/87/EC establishing a scheme for greenhouse gas emission allowance trading within the Community. This Directive endeavoured to facilitate Member States in fulfilling their commitments under the Kyoto Protocol to reduce the aggregate emissions of greenhouse gases. This Directive has been supplemented by Directive 2009/29/EC, which extends the commitment to reduce emissions. The position under the most recent Directive is much in line with the ’20-20-20 targets’: at least a 20 percent reduction in greenhouse gas emissions in the EU by 2020 compared to 1990 levels.
  3. These Directives go on to set out details of how the emission allowance trading market should operate. The 2009 Directive explains that installations which carry out stipulated activities resulting in emissions must hold a permit. Member States are required to submit their proposed allocation plans to the European Commission. The objective of the EU is the efficient but proactive reduction in emissions, and to this end it is stated that the number of allowances shall be decreased year-on-year.
  4. Subsequent legislative measures, such as Regulation 1031/2010, have been enacted to facilitate the effective operation of the emission allowance trading scheme. This 2010 Regulation explains how the auctioning process of allowances which are not allocated “free of charge” should be administered and operated. Similarly, Regulation 920/2010 has been implemented to establish a system of standardised registries and electronic databases which oversee and monitor how allowances are issued, held, transferred, and cancelled within the scheme.
  5. In an attempt to highlight the economic basis of the emissions allowance trading scheme, whilst also demonstrating the global concern which climate change poses, Directive 2004/101/EC establishes that joint implementation and clean development mechanisms may be used within the scheme.
  6. In order to work progressively toward these legislated objectives, a number of ancillary measures have been adopted. For example, Decision 280/2004/EC, implemented by Commission Decision 2005/166 establishes a mechanism for monitoring EU greenhouse gas emissions. This mechanism is devised and implemented by national and Community programmes, with Member States then being required to present annual reports to the Commission of their emissions. Much of the rationale behind this Decision was to enable the EU to comply with its commitments under the Kyoto Protocol.
  7. As mentioned above, the link between the environment and energy policy has become more pronounced in the minds of the EU legislature, and this can be seen through another aspect of the 20-20-20 package: a 20% share for renewables in EU energy production, and a 20% improvement in energy efficiency from 2007 levels.
  8. The link between energy and climate change is most clearly demonstrated through Directive 2009/28/EC which seeks to promote the use of energy from renewable sources. Across the EU, it requires that 20% of energy consumed must be derived from renewable sources. Obviously, the basis for this Directive is not simply to reduce the emissions of greenhouse gases: there are ‘many benefits, including the utilisation of local energy sources, increased local security of energy supply, shorter transport distances, and reduced energy transmission losses. Such decentralisation also fosters community development and cohesion by providing income sources and creating jobs locally.’[4] That said, however, the Directive itself understandably recognises the correlative benefits for Member States seeking to attain their emission reduction targets.
  9. For the purposes of this article, this 2009 Directive is particularly interesting because it advocates establishing mandatory national targets for the contributions of energy from renewable sources. In the case of the UK, the national overall target for the share of energy from renewable sources by 2020 is 15% (as compared with the 1.3% share of 2005). A point of contention amongst environmental lawyers is that this target, whilst it is characterised as ‘binding’, does not attract sanctions or infringement proceedings should the Member State fail to reach it. Therefore, an interesting question may be raised by Brexit: would the UK nevertheless be bound to fulfil its quasi-contractual obligations, and if so, how ‘binding’ is that target in any event.
  10. The EU has recognised that another significant source of emissions which may be regulated on a pan-European level is transportation. Regulation (EC) No 443/2009 sets out emission performance standards for new passenger cars as part of the Community’s broader approach to reduce CO2 emissions from vehicles. Directive 2009/30/EC seeks to monitor and reduce greenhouse gas emissions through establishing environmental standards for fuel.
  11. This theme of the EU legislating and thus impacting on individual consumers is also evident in various Directives relating to energy usage. Directive 2012/27/EU, for example, establishes a framework for labelling and consumer information regarding energy consumption for energy-related (including household) products. Directive 2010/31/EU seeks to improve the energy performance and efficiency of buildings.
  12. It makes sense, as part of this article, to mention also the central pieces of European legislation concerned with air quality: CO2 is not the only emission which has an environmental impact.
  13. Directive 2001/81/EC sets the upper limits for Member States’ emissions of certain atmospheric pollutants (including sulphur dioxide, nitrogen oxides, and volatile organic compounds). This Directive is supplemented by Directive 2010/75/EU which seeks to control and reduce the emissions from large combustion plants.  This Industrial Emissions Directive, in much the same way as Directive 2009/29/EC (the emission reduction Directive outlined above), requires various installations undertaking specified industrial activities to operate in accordance with a permit which is issued by the Member State authorities.
  14. The general health impacts, as well as the environmental impacts, of improved air quality are clearly considered in Directive 2008/50/EC on ambient air quality and clear air for Europe. This 2008 Directive imposes limits for Member States for various pollutants and particulates in outdoor air. This Directive has self-evident implications on the UK, and it is well-publicised – for example in the ClientEarth judgment of the Supreme Court[5] – that in many urban areas these targets are not being met.

Implications of the UK’s Exit from the EU

  1. Turning now to the implications for the UK of leaving the EU, it is again necessary to stress that much of what follows is unavoidably generalised.
  2. There is first the very obvious detriment to the UK that after it leaves the EU, then it will equally be unable to negotiate and seek to influence the EU’s approach to environmental regulation. This disadvantage is magnified when one considers that the UK will (perhaps) nevertheless remain obliged to meet certain targets established by the EU or by international treaties, such as (heretofore) the Kyoto Protocol. It would be a regrettable situation for the UK to be bound to meet various objectives but have no influence in the process determining how those targets should be achieved. It is also the case that the UK may be less inclined to adopt stringent and taxing targets for itself if there were not European pressures to do so.
  3. On the other side of the coin, if and when the UK were to leave the EU, then there is an argument that the EU’s climate change and energy policies would suffer. The UK has a recognised positive impact in steering EU policy in a more demanding, conscientious and sustainable direction. There is a worry that if the UK were to leave the negotiating table, then Member States for whom environmental concerns are subordinate to economic prosperity may come to the fore. This point is likely to be borne out in the context of ongoing UNFCCC negotiations: without the UK, the EU may be inclined to adopt a weakened stance, and similarly, the UK’s position is likely to be diminished. One of the defining justifications for the EU is that it is greater than the sum of its parts, and that argument is particularly prevalent on the global stage.
  4. It is submitted here that the UK is likely to want to continue being able trade within the EU emissions trading scheme so as to attain its obligations imposed by international treaties and agreements. For example, if the Paris Agreement is ratified, then the ambitious global targets will require exactly such an international response.
  5. There is a suggestion that if the UK were to leave the EU, it could nevertheless opt-in to the emissions trading scheme. Iceland, Norway and Lichtenstein have each signed up to the scheme, and the suggestion is that the UK could do the same, thus preserving the commercial impetus underpinning continued climate change action in industry. This said, there is still the potential concern relating to how influential the UK would be in formulating EU ETS policy if it were no longer an EU Member State.
  6. Much the same argument can be raised with regard to the 2009 Directive promoting the use of renewable energy sources. This Directive envisages joint projects, with the common objective of increasing proportional energy production from renewable sources. These projects may be between Member States or entered into with third countries. Obviously, this latter point is worth noting because it could mitigate any disruptive effects arising from Brexit on long-term international projects. So long as the conditions for third party joint projects would be met, the Member States of the EU may not be deterred from entering into joint projects with the UK.
  7. There are also a number of arguments which suggest that Brexit might not be as damaging to the UK’s climate change and energy policies as is feared. The Climate Change Act 2008 is the flagship piece of national legislation on this issue, most significantly setting out a duty ‘to ensure that the net UK carbon account for the year 2050 is at least 80% lower than the 1990 baseline.’[6] This legislative target is remarkably ambitious, and indicates that the UK’s national (and, therefore, individual) commitment to sustainable development is genuine and proactive.
  8. Further, Simon Moore at Policy Exchange raises the interesting argument that the UK,  through being compelled to meet EU targets on investment in renewable energy sources, may in fact struggle to meet the decarbonisation target.[7] Meeting the renewable energy target may have a deleterious effect on the UK’s prospects to reduce its carbon account because it commits the bulk of the UK’s efforts and resources in one specific way, at the expense of encouraging broader innovation and investment in low-carbon alternatives.

Concluding Remarks

  1. The overwhelming majority (between 80-90%) of the UK’s environmental legislation is derived from EU legislation, and so the potential impact of Brexit on climate change and energy policy in the UK is huge.
  2. This note has mapped the major pieces of EU legislation which concern specifically climate change and energy, and suggested potential (if chiefly generalised) impacts should a no-vote be delivered in the referendum. The chief impact of Brexit will, understandably, be confusion, and whilst it will be possible to resolve much of this uncertainty over the course of time through a combination of legislating and negotiating, this note questions whether any potential outcomes would be worth that confusion from an environmental and sustainability perspective. When considering climate change policy and energy policy, it seems that there would have been far more advantages to remaining within the EU.
  3. One cannot escape the fact that climate change and the finite nature of non-renewable energy sources are (at least) a pan-European problem. Further, it is true that acting on climate change, and the move toward sustainable energy sourcing, demand a holistic and collaborative approach, and for this reason the arguments for the UK staying in the EU were very strong. Indeed, in the context of the environment as a whole, the dis-benefits of Brexit are writ large.

[1]     Article 2(1)(a), Paris Agreement (2015, COP21 UNFCCC).

[2]     AJ Bradbrook, ‘Energy Law as an Academic Discipline’ (1996) 14: 2 JERL 194.

[3]     S Bell, D McGillivray, and O Pedersen, Environmental Law (8th ed, OUP 2013) 554.

[4]     Directive 2009/28/EC of 23 April 2009 on the promotion of the use of energy from renewable sources [2009] OJ L140/16, para (6).

[5]     R (on the application of ClientEarth) v Secretary of State for the Environment, Food and Rural Affairs [2015] UKSC 28.

[6]     Section 1, Climate Change Act 2008.

[7]     S Moore, ‘2020 Hindsight: Does the renewable energy target help the UK decarbonise?’ Policy Exchange (2011, London).

Environmental Legal Risk in Mergers and/or Acquisitions

 I. Background

As a consequence of the promulgation of Environmental Laws in México over the past five years, the topic of risk and environmental liability has become a major issue of merger and acquisition operations.

Moreover, in this type of operation, it is crucial to take into account the very nature of the transaction in question so as to fully understand the risk and liability corresponding to each project.

II. Modalities

Basically, we have two main types of modalities: A) the purchase-sale of stocks and B) the purchase-sale of assets.

  • Purchase-Sale of Stocks

In this case, past, present and future environmental liability is acquired fully by the purchaser, independently of the fact that liability for the seller may be agreed to for past irregularities, such as the case of soil contamination.

Inasmuch as the legal personality of the corporation remains intact and, therefore, the new owner shall be liable for the facts and/or omissions implied by violations.

  • Purchase-Sale of Assets

In this case, personal liability ends since it is not acquired by the corporation and, consequently, legal personality is extinguished.  Subsisting are solely real liabilities, procte rem, as, for example, soil contamination.

Therefore, environmental liability pursue the item, that is, the property.

It is of major importance to review the possibility of assigning the rights of the corresponding permits, licenses or concessions so as to validate their transfer before the legal personality of the corporate entity in charge thereof is terminated.

Once having distinguished between the modalities of transaction in question, I list below the legal actions to be reviewed so as to carry out precise and proper environmental due diligence.

III. Analysis of the Legal Actions to be Follower

  • Ad Hoc Check List

It is quite common to see that the majority of our colleagues use standard forms applying to all merger and acquisition operations, thereby committing a big mistake, given the fact liability for the hotel industry is not the same as for the chemical industry.

It is our opinion that a specific checklist must be worked out for the industry in question.

  • Study Phase 1 vs. Legal Review

In particular, it is often used for the parties involved in this type of transaction to measure environmental risk by solely carrying out a Phase 1 study.  The problem lies in the fact that, though it is true the aforementioned reports deals with the risk level of the company´s operation vis-à-vis soil contamination, it does not deal with the scope and validity of the environmental permits required to operate nor with the risk of revocation and/or closure thereof.

  • Measurement of Risk and Liability

To resolve the environmental legal-risk factor of operations, it is essential to do an exhaustive legal review of the permits the company and/or industry needs to operate.

This will allow us to prepare an integral strategy, which, on the one hand, allows us to reliably measure environmental legal risk, and, on the other hand, with this hard data, leads to an integral strategy of regularization, should such be necessary.

  • Measurable Costs

After all is said and done, an integral legal report must provide us with the: i) legal risk of the operation; ii) legal liability of the parties; iii) parameters of the fines and/or administrative sanctions that might be levied for existing environmental irregularities; iv) approximate costs of the regularization of the company.

IV. Conclusions

  • The growing legal regime of environmental liability in Mexico makes it essential to do an exhaustive review of compliance in the area applicable to all mergers and acquisitions.
  • It is crucial to fully understand the type of modality of the transaction in question.
  • An exhaustive legal review is fundamental to measuring legal risk, as well as the scope of the civil, environmental, administrative and/or criminal liability of the parties involved in the transaction.
  • The elaboration of a report at the level of compliance and limit of environmental liability is essential, as are parameters of the cost of regularization.
  • In the case, contamination is found in the site, there must be ex profeso clauses within the contract.
  • Finally, in the interest of avoiding lawsuits brought for unreviewed defects and unnecessary risk in mergers and acquisitions, the involvement of an environmental expert with more than 20 years knowledge and proven

Recent Change of Regulations and Practice in Construction and Energy in Japan

Introduction – Tightness in the Construction Industry

Recently, a number of events have kept the construction industry very busy in Japan, including the clean-up and rebuilding after a number of large scale earthquakes and various construction activity in the build up to the 2020 Tokyo Olympics.  The Olympics have spurred not only the construction of public facilities and infrastructure, but also many private projects planned for completion by 2020 on the expectation of an influx of foreign visitors.  Rehabilitation and reconstruction after the 2011 East Japan Earthquake and tsunami is still ongoing, but in April this year, half of the island of Kyushu, Japan’s fourth biggest island was also hit by series of large earthquakes.  This has put pressure on an already tight construction industry with serious shortages of workers and materials.  Industry insiders appear concerned about uncertainties related to the forecasting of construction cost.  In these circumstances, some local governments are beginning to defer less urgent public works projects until after 2020, in order to avoid unexpected cost increases.

The Japanese government has also taken measures to help relieve the shortage of construction workers, including by deregulation of foreign construction workers.  Until one year ago, it was not allowed to use foreign workers at construction sites except for training purposes and the training period was limited to three years at most.  However, as of April 1, 2015, the foreign workers who have completed training to work at a construction site are now allowed to continue working for several years beyond the three year limit.  This deregulation is, however, effective only until March 31, 2021, which means that such foreign workers will presently be allowed to work on construction sites only until shortly after the Tokyo Olympics.

Aside from construction related to the Olympics and reconstruction following earthquakes, there has also been a gradual increase in PPP/PFI projects in Japan, a number of changes in the regulation of the renewable energy market, and a new infrastructure fund market.

Increase of PPP/PFI

The Japanese government has been promoting PPP (Public Private Partnership) and PFI (Private Finance Initiative) projects since the PFI Act was enacted in 1999, with limited success.  In 2011, the government introduced a concession scheme, under which a private project company may be granted with the right to operate publicly owned facility and to gain income from the operation.  The first concession project was the project to operate two airports in the Osaka area for 44 years. Operation by the private project company has commenced in April this year.  Since the concession fee of this project was quite high (about 2.2 trillion yen) the winning consortium included 30 large companies in the Osaka area in addition to Orix Corporation Group, a leading Japanese financial services group, and VINCI Airports, a French airport concession company.  An interesting aspect of this tender project was that it was truly opened up to foreign bidders, with efforts made to accommodate and attract such bidders, something that has not been the case to-date for infrastructure projects in Japan.  Following this airport concession tender project, we expect there will be more PPP/PFI projects that are opened up for foreign companies to more easily participate.

The Japanese government has been taking many other measures to stimulate the use of PPP/PFI projects in addition to concessions.  One effective measure was the request issued by the Cabinet Office in December of 2015, addressed to the government authorities and the major local governments.  It requested them to put a priority on PPP/PFI schemes when planning public projects and also for each authority and large local government to prepare and issue guidelines stipulating the procedure for utilizing PFI/PPP schemes.  Under a PPP/PFI process, a private company or consortium conducting PFI/PPP projects is chosen through a bid process in which proposals from bidders are evaluated for factors other than simply price, including design, construction plan, operation plan, financial plan and risk mitigation measures.  As a result of these measures, it is highly likely that we will see more public projects taking this kind of bidding process.

Following the first concession project for the airports in Osaka, a number of other airport concession projects are currently in the process of bidding or preparation for tender.  The Cabinet Office also plans to expand the concession projects to other types of infrastructure.  The most likely candidates are water supply facilities, waste water treatment facilities, toll roads and sports facilities.  Concession tender projects have already commenced for a toll road in Aichi Prefecture and a waste water treatment facility in Hamamatsu City.

PFI projects are typically financed using project finance, under which the project company procures finance from banks under limited recourse loans.  The banks obtain security on every asset and right owned by the project company.  One of the characteristics of Japanese PFI finance schemes is that bankruptcy remoteness is not strongly emphasized.  In PFI project, a project company is usually formed as a stock company (kabushiki kaisha) and the major consortium members are required to hold its shares throughout the project period.  Mezzanine finance is rarely used in PFI projects.  However, the PFI Fund, which was established under the revised PFI Act tends to actively provide mezzanine finance to PFI projects.  This fund was established in 2013 by both government and private companies, for the aim of procuring finance for concession projects and other PFI projects in which the project company is to be run independently.  So far, the fund has provided or decided to fund a total of 15 PFI projects.

Renewable Energy

In Japan, the Feed-in Tariff (FIT) Act came into force in July 2012.  Since then, the number of renewable energy projects, especially solar power projects, has increased tremendously.  The key concept of the Act is that the local electric utility companies are obliged to purchase renewable energy at a certain fixed procurement price.  The types of renewable energy covered by the Act include solar power, wind power, water power, geothermal power and biomass energy.  The Act and this system are supervised by the Agency of Natural Resources and Energy, an agency of the Ministry of Economy, Trade and Industry (“METI”).  The fixed purchase price and fixed period, which are determined and announced by the Minister of METI every fiscal year based on the opinion of the committee specially established for calculation of purchase price.  The fixed purchase price tends to decrease gradually over time.  As an example, the purchase price for mega-solar electricity rapidly decreased from JPY 40/kWh in 2012 to JPY 24/kWh in 2016.

Project finance is regularly used to finance renewable energy projects.  The project company is usually formed as godo kaisha, which offers an advantage over a kabushiki kaisha in terms of bankruptcy remoteness.  Investors commonly invest in the project company under a silent partnership (tokumei kumiai).  For this reason, renewable energy project financing is similar to real estate finance rather than other PFI project financing schemes.

For the last three years, the number of solar power projects has dramatically increased mainly due to the ease with which photovoltaic plants can be constructed compared with other types of renewable energy plants.  The Japanese government appears to be attempting to now lead production of renewable energy away from solar power projects to other types of renewable energy projects, such as wind power, water power, geothermal power and biomass energy.  One of the major issues of practice under the FIT Act is that the authorizations of renewable energy were granted by METI to many more solar power projects than was originally anticipated, but many approved projects have failed to reach operation.  A change in the Act has been proposed to the Diet in order to more quickly eliminate projects that are delayed and promote other projects that are able to come online sooner.  If the proposed change passes the Diet, approvals already granted may be cancelled if the project company fails to execute a grid connection contract with the relevant utility company by April 1, 2018.  It is also planned to decrease the burden of environmental assessment for other types of renewable energy projects, such as wind power.  The dramatic fall in the purchase price of energy produced by mega-solar power plants, from JPY 40/kW in 2012 to JPY 24/kW in 2016, also reflects this change in government policy.  Nevertheless, many still view solar power projects as viable financially, despite the removal of such incentives.

Many solar power projects that were approved in the first three years after the beginning of the FIT system, are moving from the development and construction stage to an operation stage.  Some of these projects will be owned by infrastructure funds after commencement of operation, some of which will be listed.  When the FIT Act first came into force, there were many unclear points and it was difficult to evaluate the potential risks during the development period and the following 20 year operation period.  Now, however, the situation has become much clearer and more stable, making the solar power market less risky and more suitable for fund-based investment in many ways.

Infrastructure Fund Market

In order to introduce more private finance into infrastructure projects in Japan, in April 2015, Tokyo Stock Exchange, Inc. established a market specifically for infrastructure funds.  The projects to be listed with this market are in principle limited to projects that have been in operation for more than one year and are producing a stable income.  The system of this market is similar to the J-REIT (Japan Real Estate Investment Trust) system, a market that opened on the Tokyo Stock Exchange in 2001 specifically for real estate investment.  For both markets, investment corporations (toushi houjin) and investment trusts (toushi shintaku) established under Japanese law can be listed.  However, one important difference from the J-REIT market is that foreign infrastructure funds can also be listed on this infrastructure market.  Considering the important role of the operator, timely disclosures are required of the operator of the assets.  In the case of domestic funds, it is also required to disclose the criteria for selection of an operator.  Foreign infrastructure funds may be listed to the Tokyo Stock Exchange only in conjunction with listing to a foreign financial instruments exchange.

In the one year since the infrastructure market was opened, there has been no IPO yet. One of the major reasons for this is that tax incentives were afforded only for a period of 10 years to infrastructure funds, which invest more than 50% in renewable energy projects, while the life of solar power facilities under tax treatment is 17 years.  In April 2016, however, tax reforms came into effect that extended the tax incentive period from 10 years to 20 years.  After this, the first IPO of an infrastructure fund, Takara Reven Infra Investment Company, was approved by the Tokyo Stock Exchange and is scheduled to be listed on June 2, 2016.  It has been announced that the Takara Reven Fund will invest primarily in solar power projects.  It is also predicted that several other infrastructure funds dealing mostly with solar power projects, such as Ichigo Holdings and Sparks Group for example, are to be listed within this year.  It is anticipated that initially, at least, this infrastructure market will be utilized mostly by solar power project funds.  Over time, however, it is expected that domestic and foreign funds investing into various types of infrastructure, including PFI/PPP projects, will be listed before long.

Closing – Other trends

Recently, there were two pieces of news concerning defects of construction work that rocked the construction world in Japan.  One was that Toyo Tire & Rubber Co., Ltd., one of the world biggest tire and rubber companies, had used fraudulent data to obtain a certification of seismic isolation rubber from a government authority.  The other was the news of piling work on a large multistory residential building built by Sumitomo Mitsui Construction Co., Ltd., one of Japan’s largest general contractors, together with its subcontractors, causing the building to begin leaning.  This will undoubtedly result in greater scrutiny of supervision and compliance across the construction industry.

Environmental requirements are also becoming increasingly strict in Japan.  In July 2015, a new piece of legislation was promulgated that require certain type of buildings, such as new non-residential buildings larger than 2,000㎡, to meet specified standards for energy consumption, without which, construction will not be approved.

Gas Regulations of Bangladesh

The Gas Act, 2010 (“the Gas Act” or “the Act”) has been passed to regulate the transmission, distribution, marketing, supply and storage of natural gas and liquid hydrocarbon in the land territory of Bangladesh and in its determined sea boundaries and economic zones. The Act has been enacted in Bangla language and no official English translation is available yet. The objective, according to the preamble to the Act, is to ensure the proper and appropriate use of the regulated substance. The exploration and production of natural gas and the related resources are not regulated by the Gas Act.

The authority that has been empowered to apply the provisions of the Gas Act is the Bangladesh Energy Regulatory Commission (BERC), which has been established pursuant to the Bangladesh Energy Regulatory Commission Act, 2003.

The term “gas” is defined in the Gas Act to include Natural Gas, Natural Gas Liquid (NGL), Liquefied Natural Gas (LNG), Compressed Natural Gas (CNG), Synthetic Natural Gas (SNG), Liquefied Petroleum Gas (LPG), Coal Bed Methane (CBM), Underground Coal Gasification (UCG), or such natural mixture of hydrocarbon which is formed by the transformation into gaseous elements due to normal temperature and pressure.

According to the Gas Act, a licence from the BERC is required for conducting the following activities:

  1. transmission, marketing and distribution, supply, storage, delivery to various classes of customers,  transportation, sale or transfer by any other approved method of gas and other commodities prepared by processing of gas or other associated substance;
  2. any survey, test or research and development activities related to transmission, marketing and distribution, supply and storage of gas or related to any other work which is supplemental, relevant or is a consequence of the same.
  3. construction of  pipelines for transmission, distribution, supply and storage of gas; and
  4. establishment and operation of a CNG refuelling station, a factory to convert vehicles to CNG-driven vehicles, a business in LPG or LNG.

The Gas Act sets out the following obligations that a distributor of gas must adhere to:

  1. maintaining the quality, pressure, environment and safety of gas in accordance with the methods determined by the BERC;
  2. following the principle of non-discrimination between customers of the same class;
  3. installing meters for measuring gas quantity;
  4. ensuring appropriate maintenance and repair of distribution pipeline, and regulating and metering stations (RMS); and
  5.  installing distribution pipelines to connect consumers to the main pipeline and increasing the capacity of existing distribution pipelines;

The Act provides that the licensee would have the power to limit or suspend or disconnect gas supply if:

  1. the lives and properties of the people of the area concerned are in danger;
  2. an operational defect is discovered in the gas network;
  3. there is a gas crisis at a national level;
  4. unpaid arrears are not settled;
  5. illegal use of gas is taking place;
  6. gas meter is tampered or gas is used through a bypassed line;
  7. need arises to establish priority between gas users; or
  8. gas is used in such a manner that the efficiency of gas use prescribed by the Government or BERC is not satisfied.

As gas crisis is common in Bangladesh from time to time, and particularly during the winter season, the gas distribution companies (which are wholly state-owned) invoke this provision to limit or suspend gas supply to industrial customers.

Regarding the business of supply and storage of gas, the Gas Act provides that except for supply and storage of gas under a Production Sharing Contract (PSC), the price for supply and storage of gas will be determined by the BERC in accordance with the provisions of the Bangladesh Energy Regulatory Commission Act, 2003.

The Gas Act provides that the following factors must be considered before constructing or installation of a gas pipeline:

  1. an evaluation of the demand for gas of different classes of consumers;
  2. the need to construct the proposed pipeline;
  3. whether sufficient gas can be supplied;
  4. the location of the proposed pipeline in relation to the consumers;
  5. the timeline for construction of the pipeline;
  6. a plan/design of how the final consumer will connect to the gas network;
  7. the financial implications of installing the gas connection;
  8. practical plans with regard to the cost of resettlement in case of acquisition of land, environmental aspects and matters related to security;
    (i) the technology and technical skills required;
    (j) the total cost of the project and details of the source of financing;
  9. a loan repayment schedule; and
    (l) matters related to socio-economic development.

The Gas Act has created certain offences, which are punishable by imprisonment and fine. The maximum period of imprisonment under the Act may be up to 10 years and the maximum fine may be up to Taka one million. A person, who is not the principal offender, but who has aided or abetted in the commission of an offence may also be punished under the Act.

The offences created under the Act include:

  • using gas by bypassing the meter and creating a direct line between the supply line and the internal line;
  • tampering with the meter so as to show underuse of the gas;
  • using gas by using unauthorized supply line;
  • installing, without the written consent of the licensee, any line for the purpose of extracting gas or accepting such a gas connection, using the gas connection for a purpose other than that for which the gas connection was given, exceeding the stipulated monthly load of gas prescribed at the time of taking the connection or stealing condensate in any way from a condensate pipeline;
  • establishing, without a licence, a CNG refuelling station or a CNG conversion workshop; exceeding, on the part of a CNG refuelling station, the pressure of gas specified by the Government or selling gas by tampering with the meter;
  • destroying or sabotaging a condensate, CNG or LPG establishment or a gas system management business or a gas industry business;
  • refusing entry to or restricting access to a representative of a gas distribution or supply authority in the performance of his duty, to the place where the gas connection is installed or to its equipment or confining him beyond the entrance;
  • stealing a pipeline, meter, regulator or any other object which belongs to an establishment that transmits, distributes or supplies gas, or intentionally causing harm to such objects;
  • buying or selling gas pipeline, meter, regulator or any such object.

A person or organisation, even if convicted and punished for any offence under the Gas Act, will not be relieved of the debt owed to a gas distributor or supplier.

Prior to the Gas Act, there was no statute specifically regulating transmission, distribution, marketing, supply and storage of natural gas and liquid hydrocarbon. These matters used to be regulated under the generally applicable petroleum laws and regulations. With the new gas regulations, it remains to be seen how they are applied by the regulator and how they impact the efficiency, governance and sustainability of the gas sector.

Waste-to-Energy in Vietnam

The treatment of municipal solid waste (“MSW”) is difficult for local authorities.  Thanks to the development of new technologies, however, MSW is becoming a serious source of renewable energy.  Vietnam began to shape its regulations and policies to develop solid waste power plants (“SWPP”) in 2012. Several investment incentives and favorable policies have now been issued to attract the private sector.  This Article discusses regulations on SWPPs and power purchase agreements (“PPA”).

Legislation and PPAs.

The policies and regulations are mainly set out in Decision 31/2014/QD-TTg of the Prime Minister dated May 5, 2014 (“Decision 31”), Circular 32/2015/TT-BCT of the Ministry of Industry and Trade (“MOIT”) dated October 8, 2015 (“Circular 32”) and Decree 118/2015/ND-CP of the Government dated November 12, 2015 (“Decree 181”). According to Decision 31, the Group of Vietnam Electricity (briefly called EVN)–a state-owned corporation–is responsible to purchase the entire output of electricity generated from SWPPs. This policy assures investors that output can be sold. The sales, however, must be made according to a statutory PPA template set out in Circular 32. Although Circular 32 allows the contracting parties to change the template in order to reflect their agreement, the main contents must be consistent with the template.

Price factors.

The price, of course, is a fundamental factor for the investor to make its investment decision. The price of electricity can vary widely, depending on the method of power generation.  For example, the current price of electricity generated from direct combustion of solid waste is US$10.05 cents per kWh. By contrast, the current price of electricity that power plants using gas generated from gasification can charge is only US$7.28 cents per kWh. These prices exclude VAT. Interestingly, prices can be adjusted by reference to the VND-US$ exchange rate.  Recognition of exchange rate variation is a large assurance for foreign investors as it mitigates losses or risks resulting from devaluation of the Vietnamese dong during the project life.  In addition to the price of electricity billable to EVN, a power plant that qualifies for financial benefits under the Clean Development Mechanism (“CDM”) pursuant to the Kyoto Protocol of which Vietnam is a signatory, has yet another source of income.

Term of PPA.

The term of the PPA is 20 years commencing from the date on which the commercial operation begins. Oddly, it is uncertain whether the PPA can be renewed after its expiry.  A large-scale SWPP will often require a substantial amount of capital. The question whether the price is sufficient to recover the investment capital and to earn reasonable profits within a 20-year period requires careful consideration and assessment.  The investor should seek the MOIT’s consent to extend the term of the PPA if there are any concerns and questions relating to the payback period. Agreement on extension of the term should be incorporated into the PPA.

The seller (power plant) may decide to participate in the competitive market for the generation of electricity. In such case, the seller must send a 120-day notice to EVN, and the PPA will be terminated after the 120-day period. If so, the seller and EVN will then need to enter into other contractual arrangements under which the price of electricity will be determined on a competitive basis (not based on a fixed price).

A PPA can also be terminated following a force majeure event if the condition lasts for more than one year.  Thus, the concept of a “force majeure event” should be well-defined.

Settlement of disputes. 

A dispute must first be addressed through amicable negotiation. If the contracting parties fail to reach an agreement, the dispute can be referred to the Electricity Regulatory Authority (“ERA”) or to a body agreed by the contracting parties. The PPA relates to EVN, a state-owned corporation under the MOIT’s administration.  The ERA is also a state body controlled and managed by the MOIT.  In case of a dispute, the ERA’s independence may be compromised.  It may be impractical for the contracting parties to choose an independent body at the time of a dispute.  The choice of independent arbitration at the outset seems to be more practical.

Governing law.

The PPA is governed by Vietnamese law. Although Vietnamese law provides certain protections and guarantees, these statutory protections may be seen to be insufficient if the PPA relates to foreign investors.  It is common that foreign investors will seek other contractual protections. These contractual protections can be incorporated into the PPA in order to ensure that their interests are protected. As the PPA involves state-related entities, a private owner of an SWPP should consider and incorporate the following matters into the PPA: (i) waiver of sovereign immunity; (ii) protection against changes in the law; (iii) investment incentives; (iv) government’s guarantee; (v) government’s force majeure events; (vi) subsequent increases of price (if possible); (vii) optional renewal of PPA after its expiry (if desirable); (viii) settlement of disputes through an independent body.

Investment incentives.

SWPPs are classified as “especially preferential projects” and so are entitled to several important incentives: exemption and reduction of land rental and land levies, favorable state loans and tax incentives (eg, import duty exemption for, say, machinery imported to create the project’s fixed assets). Import duty exemptions can also apply to materials, raw materials and semi-finished products that are unavailable in Vietnam and that must be imported. Preferential corporate income tax rates, corporate income tax reduction and tax holidays can also apply. These investment incentives can be obtained and documented during the licensing process.

Licensing process.

The municipal or provincial People’s Committees (“PC”) are authorized to issue investment registration certificates and other operational licenses to WSPPs.  Before issuing licenses, the PC will often consult with other ministries (mainly the MOIT, the Ministry of Natural Resources and Environment and the Ministry of Science and Technology).  Among other conditions, a solid waste power project must be included in the national master plan. If a potential project is not included in the national master plan, the investor must seek the MOIT’s consent.  The MOIT is authorized to evaluate solid waste power projects. The statutory duration for the MOIT to evaluate a project is 30 business days.  The MOIT may engage independent and professional consultants to evaluate a SWPP.  The owner of an approved SWPP can commence construction of its plant only after it has obtained a construction permit. This requirement applies to most power projects, and not just to SWPPs.


Currently, household waste, commercial and industrial and hospital wastes are collected and transported by non-profit entities owned by the state or by commercial companies. The current treatment of solid waste is mostly to recycle it or to discharge it into open garbage dumps. However, the volume of solid waste has increased in both big cities and industrial zones. As a result, garbage dumps have become overloaded and the current practice has become inappropriate. There are serious environmental issues to consider (eg, negative impact on underground or surface water, spread of disease, unsustainable usage of land, etc.). The situation requires local authorities to find alternative solutions in order to mange and treat waste.  Although the development of SWPPs is more expensive in comparison with other methods, there are positive factors: treatment of waste is faster, it does not require a substantial amount of land, and the operating costs are not significant. More importantly, waste can be managed and treated on a sustainable basis and environmental issues can be managed. The Government is seeking technical and financial assistance and aid from government and non-government organizations. In parallel, the Government also encourages the private sector to develop SWPPs. Another option is the development of small scale SWPPs. This seems to be practical and realistic. For the investor, a small scale plant does not require a large amount of investment capital. For the Government, it will help Vietnam to learn important technologies and to gain valuable experience.

Contaminated Lands in Italy

Albeit the “polluter pays” principle regime, the innocent owner is still in an uncomfortable position in our Country.  A way to the future.

Most of the queries posed principally by international investors to corporate and environmental lawyers when analysing the risks of a transaction involving contaminated lands in Italy, relates to the concrete application of the “polluter pays” principle.

Clients are interested in understanding to what extent an “innocent owner” may be involved in the costly and lengthy remediation proceedings related to a contaminated land, knowing that the Italian bureaucratic apparatus is mammoth and, therefore, not being inclined to take on the burdens of such a proceedings.

What Italian lawyers tend to affirm, to this end, is that while in general terms in Italy the “polluter pays” principle applies fully in Italy, the Italian environmental legal system provides for some notable exceptions and corrections to such principle, involving the “innocent owner” of a contaminated land in the expenses for the cleanup and remediation procedures.

Such exceptions are grounded on the fact that there is a number of cases where the “polluter” cannot practically be identified, is unable (for example due to its insolvency status) or simply omits to carry out the remediation actions provided for by the Italian legal system: in all these cases, the Italian regulator had different possibilities to face the situation and retrieve the resources to tackle the activities that are needed.

Obviously the first possibility was to put the remediation burden of the “orphan” contaminated sites on the public agencies, which – in essence – means that the burden would be distributed among the people living within the territorial ambit where the contaminated site is located and correspondent to the local agency jurisdiction.  However, clearly, this solution had the upside of finding always an entity “responsible” (in a general way, but not in connection to a liability) which would have taken care of the remediation costs, but it looked objectively unjust, considering that the population of a determined area, already possibly affected directly by the consequences of contamination, would have been subject to an economic burden to eliminate the source of its own damage.

With a view to facing this inconsistency and to mitigating the relevant economic impact, the Italian legal system has searched and found a different corrective measure, by attaching at least a part of the cost to the subject which – to a certain extent – somehow enjoys the site and, therefore, is (or should be) interested in its remediation and reinstatement into environmentally sound conditions: the owner, on the assumption it be completely innocent with respect to the contamination and regardless of the fact that it was aware of the existence of the contamination itself at the date of the acquisition of the title or thereafter.  The rationale to such measure is to trigger the owner (innocent) to carry out voluntarily the remediation measures necessary to reinstate the property to its original state, or at least to an acceptable state under a risk assessment approach connected to the target use of the property itself, putting a threaten of enforcement of the corrective measure invented by the law.

The contents of this corrective measure – which was introduced for the first time in the first regulations on waste in 1997 – has progressively changed and is now crystallised in the Environmental Consolidated Act as a “real lien” (onere reale) which consist of an encumbrance on the property to which a “special privilege of the credit” (privilegio speciale immobiliare) is attached.

In practice what happens is that the local authority (typically the Municipality) is entitled to register in the Land Registry (where all Italian properties are listed) and in the city planning destination certificate (where also all Italian real estate are registered) the existence and the contents of such encumbrances, evidencing the kind of contamination, the existence of a cleanup obligation (such lien being registered after the approval of the cleanup design) with a view to both rending the lien public and compel the innocent owner to act.

In the unfortunate event that the innocent owner does not take any action, the Municipality can enforce the privilege of the credit and can claim for the reimbursement of the expenses of the remediation activities – which, in this case, would be completed by the Municipality itself – as a consequence of a specific administrative proceeding which has to explain – providing sufficient grounds – the fact that the real polluter (liable for the contamination of the site in the first instance) was not traced or could not be forced to pay for the cleanup expenses.

The innocent owner’s “liability” (under a legal standpoint it is questionable whether this be a real liability, in consideration of its objective character completely disconnected from fault) cannot exceed the fair market value of the site, which needs to be calculated after the remediation proceedings is completed.

As a meagre consolation for the “innocent owner” itself in case it refuses to pays the relevant costs and suffers the expropriation of the land is represented by the recourse to the polluter for the correspondent refund (which in theory, should the agency have carried out the proceeding properly be at this stage really far from reality).

What is interesting is that the national jurisprudence on the “innocent owner” duties tended to expand its liability in the recent years in Italy considering the innocent owner a sort of deep pocket’s player and tending to impose effective active obligations on the same.  Some decisions of the Italian administrative Courts – under the pressure of the agencies which lacked the money to face the remediation costs – had imposed to the innocent owners obligations to perform the remediation activities rather than to reimburse the costs sustained by the agencies themselves.

Luckily a wise stop to this enlarging interpretation was firmly put by the European Court of Justice (referred to by the Council of State in its Plenary Assembly) which confirmed the strict interpretation of the corrective measures of the Italian legal system, limiting it to the consequences of the existence of the “real lien” on the land (onere reale) and the legal privilege of the credit (privilegio speciale immobiliare) to the payment of costs or to the consequent enforcement in case of default.

Specifically on the 4th of March 2015 the third Chamber of the European Court of Justice issued the decision in the case no. C-534/13 related to a preliminary ruling on the interpretation of the “polluter pays” principle stating that in cases where it is impossible to identify the polluter of a plot of land or to cause that person to adopt remedial measures, the competent authority cannot require the owner of the land (who is not responsible for the pollution) to adopt preventive and remedial measures, that person being required merely to reimburse the costs relating to the measures undertaken by the competent authority within the limit of the market value of the site, determined after those measures have been carried out.

Too little time has passed to see whether the agencies and the national courts have completely abided by the educations of the European Court of Justice which – this time – has ruled favouring a more certain scenario for innocent owners of contaminated sites, enhancing the chances of the international investors to rely on their lawyers advice which, more and more, should be addressed to comfort and reassurance.

We are certainly on this side and believe that the enterprises have a proper full right to invest where the environmental law is interpreted according to its rationale, providing the elements to assess all the risks in carrying out extraordinary real estate or M&A  transactions in Italy and taking the appropriate measures to face them.

The rise of Solar Power in the Netherlands


Solar power is booming in the Netherlands. In the past years the number of Photovoltaics power (“Solar PV”) has increased tremendously. The Statistics Netherlands has estimated that the total amount of Solar PV has increased from 90 Mw in 2010 to 1048 Mw in 2014.[1] It is expected that the amount of Solar PV will continue to grow rapidly in the coming years.

In September 2013 more than 40 Dutch organizations have signed the Agreement on Energy for Sustainable Growth. This agreement marked the start of a transition to a sustainable future in the Netherlands. The agreement aims to increase the proportion of energy generated from renewable sources from 4.4% in 2013 to 14% in 2020 and 16% in 2023. The Dutch government has implemented a variety of measures in order to meet these sustainability goals.

Despite the advancing technological developments, renewable energy is still more expensive than fossil energy. Various measures are therefore required to expedite the introduction of renewable energy solutions. In this article the most important measures will be discussed which the Dutch government has taken in order to expedite the implementation of Solar PV in the Netherlands.

Solar PV

Solar cells, also called PV, convert sunlight directly into electricity and can be installed on rooftops or can be ground based. Investing in Solar PV has become increasingly more interesting in the Netherlands. The costs of Solar PV have dropped in the past years and the installation of PV installations has become user-friendlier. However, this is not the main reason why the amount of Solar PV has increased rapidly in the past years in the Netherlands. The growing investments in Solar PV power are mainly due to a number of measures taken by the Dutch government and are expected to continue growing in the coming years.


In the Netherlands the main support instrument for Solar PV power is the so-called SDE+ scheme. The SDE+ scheme is a premium feed-in scheme, which provides producers of renewable energy financial compensation for the production of energy. The production of Solar PV is usually more expensive than the production of fossil energy. The difference between the cost price of fossil energy and Solar PV is the so-called unprofitable component. The SDE+ scheme compensates producers of renewable energy for the unprofitable component for a period of 15 years. The amount of SDE subsidy is dependent upon the development of the cost price of fossil energy. A high fossil energy price implies a low SDE+ subsidy, whereas a low fossil energy price implies that the renewable energy producer will receive a higher compensation from the buyer.

In spring 2016 the budget for the SDE+ scheme is EUR 4 billion. The SDE+ scheme encompasses a system of phased admission with escalating base tariffs, which favors low cost renewable energy options. The primary target groups for SDE+ subsidies are companies, institutions and non-profit organizations. Only projects connected to a large-scale energy connection (> 3*80 Amp) are eligible to the SDE+ subsidy. Energy producers with a small energy connection (< 3*80 Amp) may consider acquiring a large-scale energy connection in order to be eligible for the SDE+ subsidy. However, the costs for acquiring a large-scale energy connection can be considerable.


Net-metering is particularly interesting for small-scale energy projects in the Netherlands, in particular for residential housing. Small-scale energy projects entail Solar PV producers with a small-scale energy connection (3*80 Amp). Net-metering is the physical compensation of Solar PV production during a period of time and basically means that the electricity meter turns backward when produced Solar PV energy is supplied to the grid. The renewable energy can be fed in to the grid and withdrawn from the energy consumption. The amount of energy which can be fed in to the grid cannot be higher than the amount of energy consumed from the grid. For small-scale renewable energy producers, energy taxes only apply to the net electricity consumption. The net energy consumption is the difference between the electricity obtained from and fed-in to the grid.

Following the principle of non-discrimination, the access to supply solar energy to the grid must be granted to small-scale energy suppliers. Grid operators are generally obliged to develop the grid to provide sufficient capacity for the access and transmission of electricity.

A different legal regime is applicable to energy producers with a large-scale energy connection (> 3*80 Amp). Contrary to projects with a small-scale energy connection, projects with a large-scale energy connection do not have the statutory right to feed energy to the grid. Large Solar PV projects can supply energy to the grid but need to negotiate a contract with an energy supplier. Renewable energy producers with a large-scale connection fall within a less restrictive legal regime. A more restrictive legal regime is only applicable to small-scale energy suppliers.

Tax benefits for collective production of renewable energy

Besides the SDE+ scheme and net-metering, investments in Solar PV are supported via loans and various tax benefits in the Netherlands. One of the most interesting tax benefits is provided in the scheme reduced tariff for collective production of renewable energy (“Verlaagd tarief voor collectieve opwek”). This scheme provides associations of owners and cooperative associations the possibility to jointly produce renewable energy with certain tax benefits. Participants of this collective scheme jointly invest in a renewable energy installation. It is required that all participants are resident in a postal code area close to the energy installation. The jointly produced energy is subsequently being sold to an energy supplier. The energy sold to the energy supplier is credited to the energy bill of the participants to the scheme. It must be clear what share each participant has in the renewable energy installation in order to correctly benefit from this tax advantage.


Solar energy is booming in the Netherlands. The increasing investments in Solar PV installations in the Netherlands are mainly due to the measures taken by the Dutch government. In this article the SDE+ Scheme, net-metering and the scheme reduced tariff for collective production of renewably energy have been discussed. All three measures have made a contribution to the current growth in Solar PV in the Netherlands. Although the growing investments in Solar PV are a very positive development, the Netherlands still lags behind the sustainability goals. In 2014 the proportion of energy generated from renewable sources was only around 5,5%. This proportion must be 14% in the 2020. The measures taken by the Dutch government and the required investments in order to meet the 2020 goals make the Netherlands a very interesting opportunity to invest in Solar PV.

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