Global Energy Blog 

The authors advise on energy projects at the Chilean law firm Larraín Rencoret Urzúa.  In September 2018 it was announced that, following a vote by the partners of Dentons, it was expected that Larraín Rencoret Urzúa would shortly be combining with Dentons.

In the 1980s, Chile was one of the pioneers of electricity market liberalization. More recently, benefiting from both the strength of its regulatory culture and its exceptional renewable energy resources, its non-hydro renewables sector has enjoyed spectacular growth, particularly in the form of solar projects – and there is more to come.

1.         Policy and law

Chile was the first country to privatize its formerly state-owned electricity industry. Through Decree-Law (DFL) No. 1, enacted in 1982 (the General Law of Electricity Services or LGSE), Chile introduced a deep reform to the electricity sector, obliging vertical and horizontal unbundling of generation, transmission and distribution. This led to large-scale private investment, and introduced competition into the generation sector. A minimum global cost operation model was established, and generation companies were encouraged to enter freely into supply contracts with non-regulated customers and distribution companies (regulated customers).

In recent years, Chile has aggressively pursued an ambitious program to move the country’s energy matrix towards non-conventional renewable resources (NCRE: i.e. renewable electricity generation technologies other than large-scale hydropower). The government’s energy policy encourages supply, security, efficiency and sustainability.

As a first step, in 2004, and as a result of its successful economic development, Chile introduced several legal changes in the industry, which have brought new investment in the electricity generation field and major possibilities for the transmission sector, especially in the interconnection of the two major electricity transmission systems (Central Interconnected System “SIC” and Norte Grande Interconnected System “SING”). As a first critical step, changes to the LGSE, made official in March 2004 through Law No. 19,940, modified several aspects of the market affecting all generators by introducing new elements, especially those applicable to NCRE. In particular, small-scale NCRE generators can now participate more aggressively in the electricity market, as they are partially or totally exempt from transmission charges.

Likewise, Law No. 20,257, better known as the Non-Conventional Renewable Energy Law, which came into force on April 1, 2008, introduced a requirement on all electricity companies selling electricity to final customers to ensure that a certain proportion of the electricity they sell comes from NCRE. A power company unable to comply with this obligation must pay a penalty for each MWh short of this requirement. As of 2013, with the enactment of Law No. 20,698, known as the 20/25 Law, which amended Law No. 20,257, Chile’s objective is that, by 2025, 20 percent of the electricity produced in Chile will come from NCRE sources.

On October 14, 2013, Law No. 20,701 was published in the Official Gazette, amending the LGSE, simplifying the procedure for obtaining an electricity concession (a key step in the development of new substations, electricity network infrastructure and hydroelectric plants: see section 3 below). This new framework was a response to the need for speeding up the procedure and timeframe necessary to obtain an electricity concession, providing more certainty to the system. In summary:

• the process to obtain a provisional electricity concession has been simplified and the timeframe adjusted;

• there is more clarity as to the observations and challenges that those against the project can make;

• the notification process was amended; a simplified and faster judicial procedure has been introduced;

• the process of valuing land or real estate has been amended; and

• potential conflicts between different concessions have been amended.

On February 7, 2014 Law No. 20,726 amended the LGSE, in order to study and promote the interconnection of the SIC and the SING systems. The government stated that this interconnection between SING and SIC would allow the transfer of surpluses produced in the northern part of Chile to its central zones. That interconnection, which was successfully carried out at the end of 2017, should reduce electricity system costs by US$1.1 billion. The interconnection of the two systems is also expected to boost the development of renewable energies and to reduce uncertainty for operators while increasing competition.

ln 2016, Law No. 20,936 (the Transmission Law) redefined the constituent parts of the national transmission system and created the Independent Coordinator of the National Electricity System (the CISEN). Under this law, which was published on July 20, 2016, the Chilean government aims to contribute to the timely expansion of the electricity transmission network. The Transmission Law heightens the role of the government in the electricity sector, granting it greater capacity to execute electricity infrastructure planning, expand the system and determine and manage the creation of land strips for the installation of new structures related to transmission lines. Regarding the CISEN, it has among its duties the coordination of operations, determination of the marginal costs of electricity, to assure open access to the transmission systems, to maintain global safety, and to coordinate economic transactions between agents, determining the marginal cost of electricity and economic transfers among the organizations that it coordinates.

Finally, it is important to mention the project to reform the Water Code that could affect any new hydroelectric project in Chile. The aim of the pending bill would be to reduce water shortages, proposing a series of regulatory changes. Specifically, it proposes an increase in state control, which could affect the legal certainty necessary for the development of economic activities, and would seek to change the legal nature of existing water rights, undermining property rights. This reform aims to change the perpetuity of water rights (DAA). The reform provides that the use of the DAA will have a maximum duration of 30 years, transforming the DAA into a simple administrative concession. In addition, the reform aims to create grounds for revocation, which could affect existing DAAs.

2.         Organization of the market

The electricity market in Chile has been designed in such a way that investment and operation of the electricity infrastructure is carried out by private operators, promoting economic efficiency through competitive markets, in all non-monopolistic segments. Thus, generation, transmission and distribution activities have been separated in the electricity market, each having a different regulatory environment.

The distribution and the transmission segments are both regulated and have service obligations and prices fixed in accordance with efficient cost standards. In the generation sector, a competitive system has been established based on marginal cost pricing (peak load pricing), whereby consumers pay one price for energy and one price for capacity (power) associated with peak demand hours.

According to the National Commission of Energy (CNE), Chile’s power generation for September 2018 was 5,972GWh, comprised of: thermoelectric 57 percent, conventional hydroelectric 23 percent and NCRE 20 percent. It is the fifth-largest consumer of energy in South America.

The wholesale electricity market comprises generation companies that trade energy and capacity between them, depending on the supply contracts they have entered into. Companies capable of generating more than the amount they have committed in contracts sell to companies with a generation capacity below what they have contracted with their customers. The CISEN determines physical and economic transfers (sales and purchases) and – in the case of energy – valued on an hourly basis at the marginal cost resulting from the operation of the system during that hour.

3.         Authorization to construct and operate generation facilities

While no governmental authorization has to be obtained in order to construct and operate generation facilities, power utilities usually obtain electricity concessions to acquire fundamental rights to protect their investment. A classic key right is the imposition of a right of way over the land whose owners are reluctant to grant rights of way through voluntary agreements. These electric concessions, however, are only available for the construction and development of hydropower plants, substations and transmission lines. These rights of way are fundamental to allow the power company to secure the transport of electricity to the national grid. Notwithstanding the above, authorizations under the Environmental Law, the Land Use Planning Law and the Municipality Law may be required when building a power plant or generation facility.

The Environmental Law (Law No. 19,300, as amended by Law No. 20,417, enforceable since January 26, 2010) establishes a regulatory framework applicable to projects with an environmental impact (article 10 of the Environmental Law and article 3 of its regulation determines the projects that must be submitted to the environmental impact assessment process, among which are power plants with output capacity in excess of 3MW). These projects may force the developer to request and obtain an environmental approval resolution (RCA). In the event of infringement of the obligations established in the RCAs, the Environmental Superintendence may impose the following sanctions: verbal warning, fines of up to US$10 million, revocation of the approval or closure of the facilities.

We do not refer to other permits that must be obtained in advance of developing a generation facility project, such as land use planning permits, water rights or geothermal exploration or exploitation concessions.

According to information provided by the CNE, by October 2018, 56 power generation projects were under construction. Together they represent a capacity of 2,838MW and are expected to start operation between July 2017 and October 2022.

4.         Alternative energy sources

According to the CNE, in September 2018, 20 percent of Chile’s power generation came from NCRE. In this respect, Chilean law contains incentives as well as obligations to foster the use of renewable energies. Law No. 19,940, Law No. 20,257 and the regulations contained in Supreme Decree No. 244 (which regulates the NCRE based in small generation units of up to 9MW, known as “PMG” or “PMGD” depending on the type of network to which they are connected) create the conditions necessary for the development of NCRE, encouraging power generation based on alternative energy sources.

Incentives

NCRE power facilities with less than 20MW may sell their output capacity to the spot market without having to pay (totally or partially) tolls to transmission companies (with differentiated treatment for units of up to 9MW and those between 9MW and 20MW). As regards PMG (only if classified as NCRE) and PMGD, Chilean law incentivizes the development of this kind of energy source, granting them the possibility to decide whether to sell energy at the spot market price (marginal cost) or at a fixed price. Another incentive to this kind of projects is that all PMG and PMGD will operate with auto dispatch, meaning that the owner or operator of the respective PMG or PMGD will be responsible for determining the power and energy to be injected into the distribution network to which it is connected (coordinated with the CISEN).

Obligations

As noted above, by Law No. 20,257, all electricity companies selling energy to final customers must ensure that a given percentage (20 percent) of the energy they sell comes from an NCRE source. In fact, this target was met some seven years ahead of schedule, because, in 2018, 20 percent of the withdrawals of the power companies will have been injected into the system from NCRE sources. However, already in 2015, the government had published a long-term energy policy (to 2050), which aims, amongst other things, to reach renewables (NCRE + conventional hydropower) shares of electricity generation of 60 percent by 2035 and at least 70 percent by 2050.

New and exclusive bidding process for NCRE

Since 2015, the Ministry of Energy has been obliged to carry out a public bidding process every year for energy coming from NCRE sources, which will help to reach the quotas of NCRE required by law. This competitive mechanism aims to improve the financing conditions of NCRE, and has the followings characteristics:

• the public bidding process can be implemented separately for each transmission system in up to two bidding periods per year. The amount of energy will depend on the projections for the fulfillment of NCRE quotas for the next three years;

• each participant in the bidding process shall submit an offer including the amount of energy (GWh) and a price (US$/MWh); and

• the project will be awarded to the cheapest bid until the necessary amount of energy is reached, considering a maximum price equal to the average cost of the most efficient generation technology of the electric system that can be installed in the long term.

5.         Other incentives

Two major undertakings have been launched for the purpose of introducing incentives on NCRE: improvement of the regulatory framework of the electricity market and the implementation of direct support mechanisms for investment initiatives in NCRE:

a. The proposed changes to the regulatory framework intend, among other things, to create the conditions to implement a portfolio of NCRE projects to accelerate the development of the market; to eliminate the barriers that frequently impede innovation; and to generate confidence in the electricity market regarding this type of technology. This is partially achieved by the government enacting the law for the development of NCRE (Law No. 20,257 amended by Law No. 20,698).

b. On the other hand, as declared by the current Environment Minister, since the ratifying of the United Nations Framework Convention on Climate Change (UNFCCC) in 1994 and the signature of the Kyoto Protocol in 2002, Chile has actively engaged in the establishment of national policies in response to climate change. In this regard, it is important to mention Law No. 20,780, which established a new annual tax on emissions from CO2, SO2, NOx and particulate matter (PM) sources. It is aimed at facilities with boilers or turbines that, together, add up to a heat output of at least 50 megawatts thermal (MWth). This tax is called a “green tax” since it would be an incentive for the growth of NCRE projects. Specifically, Chile’s green tax targets large factories and the electricity sector, covering an important percentage of the nation’s carbon emissions. In the case of PM, NOx and SO2 emissions into the air, the taxes will be the equivalent of US$0.1 per ton produced or the corresponding proportion of said pollutants, increasing the result by applying a formula that takes into account the social cost of pollution such as costs associated with the health of the population. In the case of CO2 emissions, the tax is equivalent to US$5 for each ton emitted. In order to determine the tax burden, the Chilean Environmental Superintendency will certify in March of each year a number of emissions by each taxpayer or contributor during the previous calendar year. Each taxpayer or contributor who uses any source that results in emissions, for any reason, shall install and obtain certification for a continuous emissions monitoring system for PM, CO2, SO2, and NOx. This tax will be assessed and paid on an annual basis for the emissions of the prior year, beginning in 2018 for the 2017 emissions.

6.         Energy Goals

One remarkable aim in the energy sector, which was included in Law No. 20,936 mentioned in section 1 above, is to define and incorporate electricity storage systems along with generation and transmission facilities, and to organize all the electricity system (including storage) under the CISEN. The Chilean regulatory framework does not currently support electricity storage in a particular way but grants the CISEN broad powers and the ability to allocate permanent funds for research, development and innovation in energy storage. In the coming months, the Chilean authorities must publish the special regulations for the functioning of the CISEN and particularly on how it will use the available funds. In this regard, a new regulatory decree (“Reglamento de Coordinación y Operación”) is already under discussion between the Ministry of Energy and key private players.

The vision of Chile’s energy sector is reflected by its whole legal framework and regulatory system. That vision is also reflected by Chile’s Energy Agenda to 2050. By the year 2050, the vision is to have a reliable, inclusive, competitive and sustainable energy sector. Chile’s development must be respectful of people, of the environment and of productivity, and must ensure continuous improvement of living conditions. The aim is to evolve towards sustainable energy in all its dimensions, on the basis of the attributes of reliability, inclusiveness, competitiveness and environmental sustainability. Chile’s energy infrastructure shall cause low environmental impact. Such impact should be avoided or, if not, then mitigated and compensated. The energy system must stand out as an example of low greenhouse gases emissions and as an instrument to promote and comply with international climate-related agreements.

Cyprus’ long standing plans to import gas to the island have taken a big step forward with the release on 5 October 2018 of a request for proposals to design, construct, procure, commission, operate and maintain an LNG import facility at Vasilikos Bay, Cyprus (the Project).

It is interesting to note that (unlike previous tenders for LNG imports to Cyprus) the infrastructure is being tendered for separately to the LNG supply. DEFA expects to issue a request for expressions of interest for LNG supply to the market later this year, with a full RfP to follow in early 2019.

Overview of Project

The RfP divides the Project into three distinct elements:

• “The engineering, procurement and construction of the offshore and onshore infrastructure, including the gas transmission pipeline and associated facilities;
• The procurement and commissioning of a floating storage and regasification unit (FSRU), through the purchase of an existing FSRU, design and construction of a new-build FSRU, or conversion of an LNG Carrier and, if applicable, provision of a floating storage unit (FSU); and
  
• The Operations and Maintenance (O&M) of the infrastructure and FSRU for a period of 20 years.”

The following points are worth drawing out:

1. the Project must be completed by 30 November 2020;
2. initially, all gas imported through the facility will be sold on by DEFA to the Electricity Authority of Cyprus (EAC, the state owned electricity company, which owns and operates the Vasilikos power station adjacent to the proposed site of the facility). The Vasilikos plant is currently running on heavy fuel oil, but will burn gas once the Project is complete.
3. DEFA has incorporated a special purpose vehicle, Natural Gas Infrastructure Company of Cyprus, for the Project. The SPV will contract with the successful bidder for the construction and O&M services; and will own the LNG import facility once constructed;
4. DEFA will contract directly with suppliers for the LNG supply; and will acquire capacity in the facility from the SPV. The risk allocation between the various agreements that will need to be entered into between DEFA, the SPV, the LNG supplier and EAC will be a critical issue for the success of the project.
5. DEFA will have an option to take over certain elements of the offshore and onshore O&M services at different stages of the Project;
6. as part of the onshore infrastructure, the contractor will be required to install a “natural gas buffer solution”. The design of this piece of infrastructure is left for the contractor to propose, but could for example include a pipeline array. The intention behind this requirement is to ensure that the FSRU and pipeline infrastructure is capable of achieving the flexibility of gas supply required to meet the operational requirements of the Vasilikos plant.

Funding

The Project has an approved budget of €300m for the initial capex, and €200m for O&M costs over the 20 year term. The initial capex will be part funded by an EU grant under the Connecting Europe Facility, with the remainder expected to be funded wholly or in part by debt finance. It is not yet clear whether EAC will invest equity into the Project – reference is made to EAC taking up to a 30% interest in the SPV at a later date.

Key issues

From our team’s experience of working on similar projects in Cyprus, key issues for the success of the Project may include:

1. credit support to be provided by Cyprus stakeholders (DEFA / EAC / the government) and the successful bidder. It is interesting to note that the government of Cyprus will be issuing a government guarantee to support the debt financing;
2. the possibility (and timing) of DEFA selling gas to other buyers in the future, and the implications for EAC’s gas take from the facility;
3. EAC’s ability to pass through the costs it incurs by generating electricity from gas to electricity consumers under the Cypriot regulatory regime;
4. the flexibility of gas supply required to meet the operational requirements of the Vasilikos plant (see the previous comments regarding the buffer solution). This will be particularly important given the expected trend towards increased levels of renewable generation and consequential impact on required flexibility of thermal plants on the system;
5. the impact of additional delivery points for piped gas to other buyers/plants;
6. the expected timeframe for the conversion of the Vasilikos plant’s turbines to gas, and commissioning of the gas-firing equipment;
7. impact of any electricity system operator requirements – e.g. regarding new electricity market rules in Cyprus.

Dentons: Cyprus / LNG experience

Dentons has unparalleled experience of working on LNG projects in Cyprus, having advised DEFA for a number of years on the potential long term import of LNG to Cyprus, and subsequently on shorter term interim gas supply arrangements; and MECIT on the commercialisation of the Aphrodite Field in the Cyprus EEZ through the development of a proposed onshore LNG liquefaction and export project at Vasilikos.

The team has a particular focus in advising on international LNG import projects. Team members are advising, or have advised on, LNG import projects in Ghana, the Caribbean, Jamaica, Pakistan, Jordan and Malta.

On 18 September, Dentons hosted an Energy Institute event in our London office with the title “The Clash of Digitalisations”. Speakers from Upside Energy, Powervault and Mixergy spoke about the Pete Project, an initiative funded by Innovate UK, that is exploring the potential of domestic hot water tanks and batteries to provide flexibility services to National Grid.  Fascinating as the technological and energy-regulatory aspects of this kind of household demand-side response aggregation services are, a key common theme of the evening was the central role played in them by the analysis of large amounts of “personal data”, and whether recent changes in privacy legislation help or hinder the development of such services.  We produced this short article to put that discussion in context.

The General Data Protection Regulation (GDPR) came into force across the European Union (EU) on 25 May 2018 and is intended to overhaul the way that companies collect and use personal data. GDPR puts the onus on companies to ensure that they have a lawful basis to collect and process personal data. It also requires mechanisms to allow data subjects to exercise the new rights available to them under GDPR.

Breach reporting requirements have been strengthened with a requirement to report most breaches to the relevant supervisory authority within 72 hours. Supervisory authorities have increased enforcement powers including the ability to impose fines of 20 million Euros or 4% of total worldwide annual turnover.

Compliance with the requirements of GDPR presents a particular challenge within the energy sector. One high profile example is in connection with the use of smart meters and smart grids. Smart grids when combined with smart metering systems automatically monitor energy usage, adjust to changes in energy supply and provide real-time information on consumer energy consumption. The EU aims to have 80% of electricity meters converted to smart meters by 2020. As such, the volume of personal data collected in the energy sector is set to increase.

What is Big Data?

Big data has been defined in various ways including by reference to the “three V’s”. This refers to volume being the size of the dataset, velocity being the real-time nature of the data and variety referring to the different sources of the data.

However, this definition does not accurately describe all big data. An alternative is to define big data as an extremely large data set that cannot be analysed using traditional methods. Instead such big data is analysed using alternative methods (such as machine learning) in order to reveal trends, patterns, interactions and other information that can be used to inform decision-making and business strategy.

The key to big data is the analysis and resulting output. Big data analytics can be achieved using machine learning where computers are taught to “think” by creating mathematical algorithms based on accumulated data. Machine learning falls broadly into two categories, supervised and unsupervised. Supervised learning involves a training phase to develop algorithms by mapping specific datasets to pre-determined outputs. Alternatively machine learning can be unsupervised where algorithms are created by the machine to find patterns within the input data without being instructed what to look for specifically.

Big data is a particular issue following the Facebook / Cambridge Analytica story and the public concern about mass data capture and exploitation.

Below, we consider the 7 key issues surrounding big data from a data protection perspective within the energy sector.

Key issues

1. Fairness and transparency

One of the principles of GDPR is that personal data must be processed in a fair and transparent manner.

In practice this means that companies processing personal data must provide a privacy notice to individuals that sets out how and why personal data is being processed. This raises a practical issue in connection with big data analytics because often the purposes of processing are not always known at the outset.

In addition, machine learning algorithms are often conducted in what is known as a “black box”. This means that the algorithm itself is unknown to the data controller and cannot be interrogated to determine how the output was selected or decision made. This likely means that the privacy notice may not be GDPR compliant.

2. Lawful basis for processing

The processing of personal data must have a lawful basis at the outset. There are a number of legal bases available (listed out in A6 and A9 GDPR).

Consent is unlikely to be an option when big data analytics are involved. The analysis of big data sets is often conducted to discover trends within that data set and if those trends were known prior to the analysis, the analysis would not need to be conducted. Machine learning algorithms are often impossible for humans to understand as they cannot be translated into an intelligible form without losing their meaning.  Consent must be freely given, specific, informed and unambiguous to be valid under GDPR. If the information regarding how personal data is processed cannot be understood then this cannot be translated into a meaningful consent.

In addition, under GDPR, data subjects have the right to withdraw consent and have a company cease processing their personal data. This would be difficult, if not impossible, in a big data context if the machine-learning algorithm is opaque and there is no ability to segregate personal data relating to a specific individual. As such, consent is highly unlikely to be a viable lawful basis for processing big data.

A potential alternative would be reliance on “legitimate interests”. This is available where processing of personal data is necessary for the pursuance of the legitimate interests of the company determining how and why the personal data is held and processed. The legitimate interests of the company need to be balanced against the interests, rights and freedoms of the individual (with particular care taken where data relates to children). A legitimate interests assessment should be conducted to determine whether legitimate interests can be relied upon. This should be documented.

An issue with legitimate interests as a basis for processing big data is that processing must be “necessary” for the purpose pursued by the company. In some instances big data analytics are pursued because the output may reveal a new correlation of interest. However, processing data because it may be “interesting” is unlikely to be sufficient to qualify as a legitimate interest that needs to be pursued by the controller.

3. Purpose limitation

GDPR requires that personal data be collected for specified, explicit and legitimate purposes and not further processed in an incompatible manner.

Big data analytics by their very nature often result in processing of data for new and novel purposes. These may be incompatible with the original purpose for which the data was collected. The issue then arises as to how and when privacy notices should be refreshed and brought to the attention of individuals.

Where material changes are made to a privacy notice or the reasons and methods by which personal data are processed these need to be actively brought to the attention of the data subject in advance of the processing. If the novel purposes or outcome is not known prior to analysis of the personal data then there is no logical way for a privacy notice to be refreshed or brought to the attention of an individual.

In addition, the personal data may have been obtained in bulk from a third party. This poses an additional challenge as it may be difficult or difficult to contact those individuals to whom the personal data relates.

4. Data minimisation

Big data analytics involves the collection and use of extremely large quantities of information. This is potentially problematic from a data minimisation perspective because GDPR requires that personal data held and processed should be limited to the minimum required for the purposes for which they were collected.

However, there are solutions to this issue. Personal data could be anonymised such that individuals are no longer identifiable from the information. A benefit of big data analytics is that it is often not dependent on the identification of specific individuals but rather of overall trends within the data population. Once personal data is anonymised it is no longer “personal data” for the purposes of GDPR and could be used and analysed as needed without the requirement for further refreshed privacy notices or legitimate interest assessments in relation to such processing. However data subjects should be told how their data may be used including that it may be anonymised and the purposes of subsequent usage.

5. Individual rights

There are practical issues around how data subjects can exercise their rights under GDPR in relation to big data. Data subjects have various rights under GDPR including the right to request confirmation that their personal data is being processed, access copies of personal data held, to correct inaccuracies, the “right to be forgotten”, to restrict processing, to have personal data “ported” to another entity and the right to object to processing.

The exercise of many of these rights requires business systems and processes that enable the identification and segregation of personal data relating to a specific individual. If personal data is being processed within an opaque algorithm then segregation of that personal data (e.g. to erase it) will be difficult.

Given the quantities of personal data held in the context of big data any exercise of individual privacy rights is likely to be a time consuming exercise and potentially a costly administrative burden.

There are also specific rules on automated decisions which are made concerning an individual that may have a legal (for example a mortgage rejection or acceptance) or other similarly significant effect. In practice this would involve explicitly referencing the automated decision-making within a privacy or other notice and gaining the explicit consent of the data subject (unless it is necessary for performance of a contract or otherwise authorised by EU or Member State law). As discussed above, consent is a tricky concept in connection with big data analytics and gaining a meaningful consent to the proposed automated decision making would be difficult.

Depending on the nature of the automated decision-making and its effect on the individual, one argument may be that the decision does not have a legal or similarly significant effect on the data subject. This would need to be carefully considered in the context of the automated decision-making and the effect on the individual.

6. Accuracy

GDPR requires that personal data held be accurate and that every reasonable step must be taken to ensure that personal data is accurate (and suitably erased or rectified to remove inaccuracies).

Whilst a level of inaccuracy may have minimal impact where large data sets are analysed to reveal general trends, there will be a significant impact when processing is used to analyse a specific individual.

An additional issue is that drawing conclusions or correlations from large data sets, even if the data itself is accurate, may still lead to inaccurate conclusions. This is a particular problem where the input data is not representative of the entire population.

The machine-learning algorithm may include hidden biases that will lead to inaccurate predictions. Consider Ethics Committee input and user testing to mitigate this risk.

Although there is no quick fix to rectify inaccuracies in data sets, the above highlights the importance of ensuring personal data and other information are both accurate and representative of the population sampled to ensure that the outputs and conclusions drawn from big data analytics are accurate.

7. Security

Security and the risk of hacking and data breaches are inherent to any business that is processing personal data. This risk is only increased where the personal data held consists of extremely large quantities of personal data. Any high profile organisation that holds large quantities of personal data will be a bigger target for hackers and also at higher risk of human error within the business resulting in the inadvertent loss of personal data.

It is therefore essential that companies within the energy sector review security measures and procedures to minimise the ability of hackers to breach systems and any resulting impact of a data breach. This will inevitably involve a combination of upgrades to security systems and regular training to ensure staff know how to hold and transmit personal data and what to do in the event of a breach.

Conclusion

The energy sector faces significant challenges if it wants to both utilise and benefit from large data sets available to it, comply with GDPR and protect the rights of individuals.

However, despite the challenges, the benefits of big data analytics for both the company and the individual in the energy sector mean that solutions to these issues must be considered in order to facilitate the growth of domestic demand-side response services, to manage energy consumption more efficiently and respond to changes in local usage and give individuals greater visibility and control over their individual energy consumption. A balance needs to be found between the needs of the sector and privacy of individuals, and a proper GDPR analysis can help you achieve that.

Decarbonising the UK’s heat supply is a massive challenge, but like other aspects of the energy transition, it also presents significant opportunities for investors, developers, consumers and others. On 3 July 2018, an Energy Breakfast event at Dentons’ London office explored the subject of investing in low carbon heat.  The speakers were Richard Taylor of E4Tech, co-authors of a recent study on future heat infrastructure costs for the National Infrastructure Commission (NIC), Stuart Allison of Vattenfall’s newly established UK heat business, Jenny Curtis of Amber Infrastructure and Nick Allen of the Department for Business, Energy and Industrial Strategy (BEIS).  We summarise here some of the key issues from their presentations and the lively discussion that followed, as well as one or two related subsequent developments.

Why decarbonising heat is important – and difficult

It may seem perverse to try to debate policy on any form of artificial heating at a time when much of the UK has been enjoying near-record high temperatures for what feels like several weeks, but it was only a few months ago that the country saw an almost equally notably cold start to spring. The heat sector, at present mostly fuelled by burning natural gas, accounts for about one-third of UK greenhouse gas emissions.  The sector’s emissions will have to be largely, if not completely, eliminated by 2050 if the UK is to meet the emissions reduction targets set under the Climate Change Act 2008 – let alone the more demanding targets that may flow from the 2015 UNFCCC Paris Agreement objective of keeping increases in average global temperatures well below 2^oC.

One way of decarbonising heat would be to substitute hydrogen for methane as a fuel. It is possible to mix some hydrogen (or biomethane) with natural gas and still use existing pipeline networks and appliances.  But full decarbonisation by this route would require significant investment at both the wholesale and end user levels (replacement of metal with plastic pipes, new boilers).  And that is just the start.  The hydrogen has to be produced on a large scale – probably using methane as a feedstock, which would produce a stream of CO₂ that would need to be captured and either stored or used in a way that avoids its being released into the atmosphere: in other words, more investment in substantial infrastructure, and the commercialisation of technologies (such as CCS) which have so far been slow to develop, even though they would appear to be an important part of the future of the oil and gas industry.  Significant changes to existing downstream gas regulation are also be required, to accommodate both blending of hydrogen with methane and full conversion.  And all this assumes that popular misconceptions about the safety of hydrogen do not prevent its widespread deployment.

Alternatively, decarbonisation of heat could be achieved by switching from boilers to a system built around heat pumps and storage, and running the heat pumps on decarbonised electricity. This would require significant action at the wholesale level (e.g. additional generating and network capacity) and a radical change in infrastructure at the end user level (e.g. each household either acquires a heat pump of its own or becomes part of a district heat network attached to a much larger heat pump).

Between the scenarios focused primarily on hydrogen or electrification, there are some hybrid options, and it is arguable that the replacement of existing natural gas-based heating could efficiently take different forms in different parts of the country (for example, those areas not connected to the existing gas grid are likely to be more cost-effectively served by heat pumps than by hydrogen). But it is clear that unlike in the case of electricity generation, where the Government has been able to adopt a broad policy of encouraging a range of low carbon technologies and regulating the pipeline of new capacity by adjusting the level of subsidy and the ease or difficulty of obtaining planning permission for each of them, in relation to heat it is likely to have to make some fundamental, long-term choices at the outset between the competing pathways to decarbonisation.  Put at its starkest, in the next 30 years, existing gas pipeline networks are likely to have either to decarbonise or cease to operate.

All of this points to the conclusion that decarbonising heat will be harder than decarbonising the generation of electricity.  At the wholesale or system level, it will be very hard for Government to avoid making major strategic choices between competing heat technology options, rather than just letting the technology mix evolve within a managed framework.  End users will have to take (or be coerced into taking) a much more active role in the heat decarbonising process than the vast majority of them have had to play in decarbonising electricity.  Finally, as further explained below, the interaction of decarbonising heat with adjacent areas of activity is likely to be harder to predict and manage.

Expert assessments

In one sense, none of this is news. In the ten years since the Climate Change Act, the independent Committee on Climate Change (CCC) have repeatedly highlighted the challenges of the heat sector in their reports.  In their latest progress report to Parliament, published on 28 June 2018, the CCC invite the Government to “apply the lessons of the past decade or risk a poor deal for the public in the next”.  Examples from the heat sector feature in support of each of the four key messages that the report delivers: support the simple, low-cost options; commit to effective regulation and strict enforcement; end the chopping and changing of policy; and act now to keep long-term options open.

The CCC note that progress on decarbonisation to date has been heavily focused on electricity generation. Heat and other sectors will need to catch up if the fourth and fifth carbon budgets (set under the Climate Change Act for the years 2023-2027 and 2028-2032 as staging posts on the way to the final 2050 target of 80% emissions reduction against 1990 levels) are to be met.

The CCC identify a number of specific actions required of Government to be on track to meet the fourth and fifth carbon budgets.  In the shorter term, they highlight the need for further action to deliver cost-effective uptake of low-carbon heat, including low-carbon heat networks in heat-dense areas (e.g. cities) and increased injection of biomethane into the gas grid.

The long-term choice between heat decarbonisation technologies and the desirability of low-regrets measures such as energy efficiency measures and low carbon heat networks in areas of dense heat demand are reviewed in an Imperial College report for the CCC (the executive summary of which was published alongside the CCC’s 28 June 2018 report as well as in E4Tech / Element Energy’s report for the NIC.  Both cite the CCC’s 2016 visual representation of these measures and choices.  Element Energy / E4Tech’s version of this is reproduced below.

In his presentation of the E4Tech / Element Energy conclusions, Richard Taylor stressed that although the hydrogen scenarios appeared to be slightly cheaper, significant uncertainties remained around the level of additional costs associated with each of the long-term options, shown below in comparison with the “no change” option of maintaining a natural-gas based heating sector.

Both reports have a wealth of more detailed analysis.  For example, this chart from the Imperial College report highlights the potential implications for the optimal levels of installed capacity in the electricity generation sector of different heat technology / intensity of emissions reduction scenarios (the figures 30, 10 and 0 underneath each bar refer to target CO₂ emissions in Mt).  Unsurprisingly, significantly more capacity is required in the electricity based scenarios, but it is also interesting, for example, how much the nuclear element in the mix varies between options, and that even the electricity based scenarios include a substantial hydrogen component in the form of open and combined cycle gas turbine plant using hydrogen rather than natural gas as a fuel.

All of this, and related issues such as the role of “flexibility” technologies (some of which, like thermal storage of energy, have implications for both the heating and power production technology mix and the way that heat and power networks are developed) highlights the interdependency of infrastructure investment choices across different parts of the energy sector.  The CCC are clear on what this means. They observe: “If emissions from heating are to be largely eliminated by 2050, a national programme to switch buildings on the gas grid to low-carbon heating would need to begin by around 2030 at the latest, requiring Government decisions on the route forward to be made by the mid-2020s.” (emphasis added).  At the same time, they highlight one of the obvious points that threatens the taking of that decision in the timeframe that they recommend, noting that “There will be important questions to be resolved around how to pay for heat decarbonisation.”

Heat networks: how low is the low-hanging fruit hanging?

Why is the development of heat networks identified as a “low regrets” option for the shorter-term, more or less regardless of what choices the Government may make about heat in the longer term? A heat network is a system comprising a heat production unit and a network of pipes and heat exchangers through which the heat that it produces is distributed, in the form of steam or hot water, to the heating and hot water appliances in a number of different customers’ premises (rather than each customer’s system of such appliances having its own heat production unit).

The concept of a heat network is technology-neutral. The heat production unit could, for example be a boiler (fuelled by methane, woodchips or hydrogen) or a heat-pump (sourcing its heat from the air, the ground, or a body of water such as a river or lake, or the water that collects in old mine workings).  Broadly speaking, whatever technology you use to produce heat, in areas where the demand for heat is sufficiently dense, it is likely to be more efficient (and – where the technology involves combustion –to result in lower carbon emissions) if the heat is generated in bulk and distributed to individual buildings or households around a local network (as steam or hot water) rather than each building or household having its own heat production equipment (e.g. boiler or heat pump).

Heat networks are obviously easiest to install when a building is first constructed, although retrofitting may also be cost effective in some cases.  If care is taken in designing a heat network, it may well also be possible to switch between heat production technologies at a lower overall cost at a network level than it would be for an individual building or household to do so (for example, by replacing a single large gas-fired unit with a single large heat pump or a hydrogen-fired unit, rather than replacing the heat production equipment in each individual customer’s premises). Moreover, consumer research commissioned by BEIS shows that those served by heat networks are overall as satisfied with their heating as those who are not.

Heat networks, then, have much to commend them.  There is considerable investor interest in heat networks.  BEIS has even published a list of 10 infrastructure investors who are actively interested in investing in them.  Planning policy both at central and local government level has for many years encouraged the installation of heat networks in new residential and commercial developments and the seeking out by those building new thermal electricity generating plant of potential network uses for their waste heat.  And yet, at present, only 2% of UK demand is connected to a heat network, although as much as 20% of demand may be sufficiently densely located to benefit from a heat network solution.  An increase in heat network capacity features in all three clean growth pathways in the BEIS Clean Growth Strategy.  But connecting 20% of demand to a heat network by 2050 would imply an annual growth rate of 8-10%.  Will this be feasible?

The short answer is: feasible, yes – but not easy, for a number of reasons.

• Complexity:  It is easier for a developer to arrange a gas supply to a group of new premises and fit each of them with its own natural gas-fired boiler than to establish a heat network to serve them.  Opting for a network solution immediately raises a series of questions and requires a much wider range of issues to be taken into account.  Who will design, build, own and operate the network?  Whoever does each of these things, more contracts will need to be negotiated than for a non-network solution, where all that is needed is a gas connection and a contract to supply / fit some boilers.  In many new developments, there are a lot of different stakeholder interests to balance (the developer, others with responsibility for the network, different landlord and tenant interests, local authorities and so on).  If the same organisation does not have responsibility for all aspects of the network, agreement will have to be reached on a whole series of risk allocations.  One common solution is for a developer to install a network but then to seek to recover some of the expense of doing so by selling it (or the right to operate it) to an energy services company (ESCO), but the building of a network by a party that will not operate it in the long-term can result in poor quality installation.
• Lack of standardisation: Heat network projects can therefore quickly develop lengthy risk registers, but there is no universal approach to or methodology for allocating those risks, and, as a result, not as much standardisation of contractual provision – on terms that strike a fair balance between competing stakeholder interests – as is desirable to keep costs under control in a sector where most transactions have a relatively small value.
• Economics: The economics of what may at first appear to be promising heat network projects sometimes do not quite stack up. The relatively small size of transactions can make it hard to leverage debt in.
• Perceived shortcomings of the technology: Notwithstanding that there appears to be no overall problem of customer satisfaction with heat networks, concerns remain about the lack of customer control (e.g. over heating, in networks where the necessary valves have not been fitted in individual premises).  As in any consumer market, one or two prominent bad reports, e.g. of poor service or over-charging, can unfairly skew stakeholders’ views of the technology as a whole.

However, none of these problems is insuperable and, as we shall see below, steps are being taken to address all of them.

Go Dutch – and regulate for growth?

Discussion about the UK’s failure – so far – to make the most of heat network opportunities often includes reference to other countries, including a number in Continental Europe, where their use is widespread and longstanding. The inference is that since we have failed to see the benefits of heat networks for so long, it will be an uphill struggle to do better now: it’s too late for us to become Denmark / Poland / [insert your European heat network exemplar country of choice].

However, Vattenfall’s experience suggests that it is possible to spread heat networks through a major European city, starting from scratch. Before 1994, Amsterdam had no significant heat network provision.  Since then, starting with the use of waste heat from a new energy from waste plant, the city has been steadily building out a heat network which is expected to help it to go “gas-free” by 2050 –  and the trend is spreading elsewhere in the Netherlands as well.

There are perhaps only three major structural differences between the UK and Netherlands markets. The first is that the supply of natural gas in the Netherlands is taxed more heavily, providing an additional economic incentive for heat networks, particularly those using non-methane energy sources.  The second is that strategic planning for the rollout of heat networks in Amsterdam is considerably facilitated by a joint venture between a Vattenfall entity and the city itself.  The third is that heat supply / networks are regulated in the same way as electricity and gas networks / supply.

In the UK, the heat networks sector is not currently subject to the same kind of regulations as comparable services such as electricity and gas, and this has raised concerns about standards of quality and consumer protection.

The Heat Network (Metering and Billing) Regulations 2014 offer some consumer protection including by imposing billing obligations and the requirement for all new heat network customers to be given a heat meter, however they do not provide for a standard of customer service or recourse to an independent complaints review process for unsatisfied customers.

The heat network industry also has its own consumer protection scheme, the Heat Trust, which sets a common standard for the quality and level of customer service, and provides for a complaints handlings system, including access to an independent complaints review by way of access to the Energy Ombudsman. However, the scheme has no statutory underpinning, membership of it is voluntary and it currently only covers a small proportion of the existing heat network customer base.

In December 2017, the Competitions and Markets Authority (CMA) announced they were launching a market study into domestic heat networks to ensure that consumers using heat networks are getting a good deal.  The study set out to examine whether consumers are aware of the costs of heat networks both before and after moving into a property; whether heat networks are natural monopolies and the impacts of offering different incentives for builders, operators and customers of heat networks; and the prices, services quality and reliability of heat networks.

• The CMA published its initial findings on 10 May 2018.It notes that, overall, the average prices on the majority of heat networks within the sample considered were the same or lower than that of comparable gas-heating, and the overall satisfaction (and dissatisfaction) of customers was in line with that of consumers not on heat networks. Nevertheless, there were instances of poor service quality and cases where customers were paying “considerably more” than for non-network heat.
• The CMA is concerned that the factors driving instances of poor performance or unduly high pricing should not become “embedded”, to the detriment of customers, as the sector expands.  Specifically, it looks at “misaligned incentives between property developers, heat network operators and customers of heat networks”; the monopoly nature of heat networks and the delivery models used for them; and lack of transparency on prices “both pre-transaction and during residency”.
• It finds that regulation is needed to ensure that heat network customers receive levels of protection comparable to those afforded to customers in the gas and electricity sector.  The report recommends the introduction of a statutory framework, which would give formal powers to a sector regulator.  This conclusion echoes some of the recommendations and analysis of a 2017 report by Citizens Advice Scotland.
• The CMA’s recommendations also go beyond the imposition of a regulatory framework for network operators to encompass possible changes to planning and building regulations, leasehold arrangements and property sales disclosures (including energy performance certificates) to take into account the specifics of heat networks. Changes to regulations in this area would give greater pre-contractual transparency to purchasers and tenants of properties to understand the implications of living in properties serviced by heat networks.

A consultation on the CMA’s initial findings closed on 31 May 2018, with a full report expected by the end of the summer. There is clearly at least a substantial body of opinion in the industry that supports the conclusion that it would benefit from sectoral regulation: a well-designed regulatory scheme, rather than unduly burdening operators, would boost consumer confidence and help the industry to expand.  Regulation could ultimately mean that operators’ returns may be capped, but the predictability that comes with well-designed and administered regulation could encourage investment.  There would likely be other benefits as well: operators in economically regulated industries are typically also given a range of statutory powers that makes it considerably easier for them to do their jobs – such as compulsory purchase powers and “statutory undertaker” rights under legislation governing planning and street works.

It seems unlikely that a sectoral regulation scheme for heat networks could be introduced without primary legislation, and there must be some doubt as to whether the Government will find the policy resource and Parliamentary time necessary to put such legislation in place in the short term.  For the moment, the CMA has decided not to launch a formal “market investigation” – a step which would open up the possibility of imposing some remedies (but probably not an overall scheme of regulation) on the sector itself for any adverse effects on competition it found.  However, the CMA has reserved the right to revisit this decision and those setting up heat network schemes may do well to take account of the conclusions of the current market study in any event.

More immediate Government support

Attention to the CMA’s work and its possible inconclusive outcome in the short term should not distract from the valuable work that BEIS has been undertaking to remove or reduce some of the other key barriers to expansion of the sector.

Earlier in 2018, BEIS provided details of a scheme to provide “gap funding” for heat network projects. The Heat Networks Investment Project (HNIP) is the vehicle for disbursing £320 million of Government money that was first earmarked for this use some time ago, building on the results of an earlier pilot scheme, and leveraging in about “£1 billion of private and other investment”.

Following the appointment of a delivery partner, the scheme will formally launch in the autumn. Funding may take the form of grants, corporate loans or project loans.  A number of criteria (both economic and technical / environmental) have been established for applicants to satisfy, perhaps the most important of which are those relating to “additionality”, designed to demonstrate that the applicant’s project would not go ahead without HNIP support – either because it could not otherwise raise the capital or achieve an adequate IRR, or because it would not otherwise be possible to fund additional technical or commercial features that are not required through planning obligations.

On the same day as our Energy Breakfast took place, BEIS published over 750 pages of useful guidance for those contemplating heat network schemes, comprising:

• guidance on strategic and commercial case development;
• some template heads of terms for use by local authorities;
• economic and financial guidance on assessing projects;
• guidance on relevant procurement and state aid considerations;
• a project manager’s guide to stakeholder engagement; and
• guidance for those looking at combined heat and power solutions, in respect of the regulatory and commercial aspects of a project’s electricity output.

The intention is that HNIP funding will create a pipeline of investable projects that will help the sector to become self-sustaining by 2021. As ever, success will lie in the quality of the implementation, but HNIP is a well-designed scheme that addresses many of the key issues facing heat network projects.

Two other initiatives, not focused on heat networks, but also aimed at reducing barriers to lower carbon heat investments in the near term, are also worth mentioning.

• On 5 July 2018, BEIS published a response to consultation the confirmed the Government’s intention to help to introduce a support scheme to “overcome key barriers, and increase industry confidence to identify and invest in opportunities for recovering heat from industrial processes” (the Industrial Heat Recovery Support Programme).
• As part of a series of reforms to the Renewable Heat Incentive (RHI) subsidy regime for domestic premises, BEIS has brought into force changes to the rules on third party funding for heat pumps and other renewable heating systems. From 27 June 2018, under a procedure known as “assignment of rights”, the owners of such systems may assign the RHI subsidy payments to which they are entitled to a “nominated registered investor”.  A model form of contract will be provided for doing so.  It remains to be seen whether this will have the desired effect of encouraging more third party finance of heat pump installation and therefore materially greater uptake of heat pumps as a technology.

A long-term, holistic approach

At a time when it is easy to criticise Government for an apparent lack of action on some aspects of energy policy, this series of concrete steps taken towards encouraging investment in low carbon heat is a positive development in an area where action is much needed and has been long awaited.  Of course, much also remains to be done.  For example, the CCC point out that:

• there is no financial support framework for heat pumps and biomethane in place yet for the period after 2021 (when the current funding for the RHI comes to an end – the RHI as currently constituted being dependent on direct Government grants rather than a more or less automatic system of funding from a levy on energy suppliers like the historic renewable electricity generation subsidy schemes, the Renewables Obligation and Feed-inTariffs);
• international comparisons suggest that the use-based payments for renewable heat systems such as the RHI might not be the ideal way of encouraging uptake and that a system of capital payments may be preferable;
• whilst the Government’s acknowledgment of the need to look at the long-term technology options for moving towards a much lower carbon heat sector and to make some choices between them is welcome, there needs to be a more formal governance framework to drive enduring decisions on heat infrastructure in the early 2020s.

In short, Government has made a good start, but must follow through.  Moreover, in looking at the next steps for heat policy, Government and others need to take a holistic approach.

• We noted earlier the apparent importance of hydrogen in all three long-term heat decarbonisation pathways. Work carried out by Alstom also indicates the potential for hydrogen (which is much more energy dense than any battery) to be used in fuel cells to replace diesel as the fuel for trains on lines that have not been electrified and that it may never make sense to electrify.  Is there not a case for incentivising the large-scale production of hydrogen (and CCS for the associated CO₂ by-product) – perhaps through a contract for difference where the strike price is benchmarked against wholesale natural gas prices?
• Government is not just responsible for energy and transport policy. It has other, currently under-used levers at its disposal to encourage technologies that will decarbonise heat.  The embedding in building standards of tougher rules on energy efficiency and an absolute requirement for low carbon heat supply to be part of all new buildings (and the rigorous enforcement of such standards), are obvious – but as yet untaken – steps that would increase demand for low carbon heating technology.  There is of course an important interaction between energy efficiency improvements and heat networks, particularly in retrofitting situations where significant reductions in heat demand driven by improved building energy efficiency could undermine the business case for a marginal heat network project.
• With as with other areas of energy policy, sharper incentives from carbon pricing would speed up decarbonisation. In the heat sector, ways of preventing any higher taxation of gas from increasing the burdens on vulnerable customers would have to be part of the package.
• Finally, any long-term decision-making by Government or the private sector will also have to consider the need to accommodate, and perhaps encourage, the introduction of new business models, and the possibility that the market of the future may, and perhaps should, be less uniform than it is at present.  Now, most consumers buy kWh (or cylinders) of gas (or in some cases, heat) and kWh of electricity (with a few of them generating a proportion of their electricity demand).  Energy efficiency is largely a separate market, with the occasional imposition on gas and electricity suppliers of obligations to undertake a certain amount of more or less targeted energy efficiency improvement works for consumers.  In the future, consumers might specify a set of outputs (e.g. availability of up to X amount of electricity, maintenance of indoor temperatures within a certain range) and sets of constraints or variables (e.g. payment profiles, willingness to allow the installation of particular equipment or energy efficiency measures, or to accept occasional deviations from the prescribed temperature range) and invite a range of suppliers to offer them a monthly price for home energy-related services for a certain period of time.  These services could include anything from utility supplies of energy to the installation of new energy production equipment or energy efficiency measures.  In a market where it will become ever easier for consumers to become “prosumers”, generating, storing and using their own electricity, companies that currently simply retail electricity and gas to consumers on a £/kWh basis may need to diversify their offering and learn a number of new skills if they are to maintain their relevance play a full part in the energy transition of the heat sector.

If you would like to explore any of the issues raised in this post further with us, please get in touch.

The assistance of Jennifer Cranston, a trainee in our London office, in the preparation of this post, is gratefully acknowledged.

A Dentons team from the UK, Germany, the Netherlands and Turkey had a good day at Intersolar Europe towards the end of June, which is a great conference for meeting old friends and making new connections.

For those who didn’t make the trip to Munich, here are a few thoughts on the key talking points.

• Solar PV is clearly a very healthy industry – there were over 850 exhibitors, spread over 6 exhibition halls. The panel manufacturers were particularly impressive, with Canadian Solar, SMA and others having large stands.

 

• Key new target markets in Europe include Ireland (with a subsidy policy decision expected to be announced imminently); Spain (driven by merchant sales and PPAs, rather then Government tenders); and France (where the industry is increasingly being seen as a Government priority with its #PlaceAuSoleil plan).

 

• Competition remains fierce, with Q-Cells (Hanwha) announcing its new half-cell technology (winning the conference award for innovation), and a number of suppliers (e.g. Jinko and First Solar) marketing panels with increased efficiency.

 

• Storage attracts attention, but is still not part of the mainstream – the focus was much more towards smart vehicle charging (with the conference running alongside the Smarter-E convention), than having batteries within the home itself (or indeed on a commercial scale).

 

• There is continued uncertainty regarding the future of solar panel anti-dumping – the current EU measures expire in September, though there is the possibility of a further review (extending existing minimum import prices for at least a year). The EU restrictions also have potential to be part of a global trend, with the US currently reviewing its position on solar cells and modules with the possibility of a 25% tariff.

 

• There is quite a bit of concern about the recent sudden withdrawal of Chinese subsidies. Given the huge growth in new domestic projects in recent years this perhaps points towards greater exports and falling prices (together with the possibility of a limited number of panel supplier insolvencies). There may be some local government subsidies available, though many projects will be put on hold.

We have been seeing a number of these issues first-hand on our current projects. Do get in touch if you would like to discuss any of them.

In a judgment dated 22 June 2018, the High Court (Lavender J) dismissed a challenge brought by a number of electricity generators (the Claimants) against a decision of the Gas and Electricity Markets Authority (Ofgem) to approve proposed modifications to the Connection and Use of System Code (CUSC), under which charges for use of the GB transmission network are levied.

Ofgem’s decision

The modification proposals were formally made in May 2016; Ofgem’s decision was taken in June 2017; and it came into force on 1 April 2018. Its most noted effect was to remove (over a three year period) a key element of the revenues of small “embedded” generators (i.e. those connected to a distribution network rather than directly to the transmission network).

Under one part of the transmission charging framework, known as the Transmission Demand Residual (TDR) charge, payments are effectively made in respect of the amount by which the supply of power from small embedded generators reduces consumption of electricity from other, mostly transmission-connected, sources in the periods of peak demand (known as “Triads”) from which the charge is calculated. These negative charges, commonly referred to as “Triad payments”, are typically made to electricity suppliers (as the small embedded generators themselves are not parties to the transmission charging arrangements), but the suppliers typically pass on about 90% of their value.

The overall costs of the transmission network have increased significantly in recent years. So too have TDR charges and the amount of Triad payments accruing to small embedded generators.  The Claimants, some of whom had made the development of small generating plants designed to capture Triad payments into a business model, argued that the system was rewarding them fairly for reducing the need for investment in the transmission network.  Ofgem, drawing on work that had been done in preparing the CUSC modifications and a series of consultations leading up to its decision, formed the view that the small embedded generators were being rewarded excessively, ultimately at the expense of consumers of electricity.  Whilst Ofgem acknowledged that they do make some positive contributions in reducing the amount of reinforcement necessary at Grid Supply Points, it drastically reduced the level of transmission charging related benefits that will be available to them in the future.

The judgment

The judgment of Lavender J is worth reading.  At 36 pages, it is as concise a free-standing account of both the issues and the decision-making process as you are likely to find.

The Claimants were refused permission to challenge Ofgem’s decision on grounds of irrationality. Their remaining grounds were that Ofgem failed to take account of material considerations and/or facts; and that the decision unjustifiably discriminated against the small embedded generators.

On the first point, Lavender J found that rather than failing to take account of a material consideration by not understanding the argument the Claimants were making, Ofgem had engaged adequately with them and disagreed with their assessment of the contribution made by small embedded generation. (This had been in part a battle of expert economic appraisals, in which Ofgem’s decision was buttressed by LCP/Frontier Economics whilst the Claimants found support in criticisms of Ofgem’s approach made by NERA/Imperial College.)  It was also not an error of law for Ofgem to require the Claimants to provide evidence in support of their case rather than making its own inquiries to find such evidence.

The second point had two limbs. The Claimants argued that Ofgem should have treated them in the same way as providers of behind the meter generation (BTMG) and commercial demand side response (DSR), which, like them, reduce a supplier’s net demand for electricity – but that it had not done so.  They also argued that it was unlawfully discriminatory to treat small embedded generators as if they were in a comparable position to transmission-connected generators – when they were not.

The judge was satisfied that “looking in the round” there was “enough of a relevant difference between” small embedded generators and BTMG / commercial DSR on the one hand and transmission-connected generators on the other, to justify their different treatment by Ofgem.

What next?

On a reading of the judgment with no more knowledge of the parties’ submissions than the judgment itself reveals, it does not seem very likely that it will be successfully appealed. Some readers may disagree with some of the judge’s reasoning, for example in support of his findings of “relevant differences” between the small embedded generators and BTMG / commercial DSR / transmission-connected generators.  But as he points out, there will be scope to remedy any perceived unfairness in the context of Ofgem’s ongoing Targeted Charging Review: Significant Code Review.

Ultimately this is one of those judicial review cases that serves as a reminder of the limits of judicial review as a mechanism for challenging decisions by economic regulators, as the court deferred to the expert regulator and did not appear to have thought that there was anything so bad in the decision under challenge or its results as to justify any attempt to use the essentially procedural categories of judicial review more creatively to strike it down. One can speculate whether the reasoning, if not the result, would have been different if Ofgem’s decision had been one that was subject to review by the Competition and Markets Authority rather than the court (like another recent Ofgem decision on a CUSC modification in the case of EDF Energy (Thermal Generation) Ltd v. Gas and Electricity Markets Authority, but even that process does not amount to a substantive reopening of the decision that is being challenged.

When the CUSC modification was originally proposed, some may have felt that it was an attack on the small embedded generators by those seeking to develop new transmission-connected generation. For them, the Triad revenues of smaller generators enabled the latter to bid down the clearing price in Capacity Market auctions to a level which made it impossible for e.g. new combined cycle gas turbine projects to stay in the auction – thus losing their chance of a subsidy that would allow them to be built.

However, two years on, the most recent Capacity Market auctions have not produced the higher clearing prices that might have been expected if the price was effectively set by small embedded generators and the latter depended to a material extent on the Triad payments they were about to lose as a result of Ofgem’s decision. This would suggest either that small embedded generators had more confidence in the Claimants’ case than appears to have been justified; or that, for whatever reason, Ofgem’s decision may be less harmful to their interests than it may at first have seemed.

Meanwhile, Ofgem’s Targeted Charging Review has a long way to run, and it will be interesting to see whether it reaches its conclusion without legal challenge or two along the way.

In the 2004 case of U.S. Department of Transportation v. Public Citizen,[1] the Supreme Court established an important limiting principle under the National Environmental Policy Act (NEPA) on the extent to which a federal agency must consider indirect environmental effects in completing NEPA-required reviews of planned agency action. It held that unless an agency has statutory authority categorically to prevent a particular environmental effect, its order cannot be viewed as a legally relevant cause of that effect, thus relieving it of any obligation to gather or consider information on the effect.[2]

As in Public Citizen, this principle often comes into play where the actions of two or more governmental agencies have a role in potentially “causing” a particular environmental effect. If the agency with NEPA responsibilities lacks statutory authority categorically to prevent the indirect effect, it has no obligation to evaluate it under NEPA.[3]

Public Citizen receives substantial play in the orders of the Federal Energy Regulatory Commission (FERC) authorizing pipeline and gas infrastructure under Sections 3 and 7 of the Natural Gas Act (NGA).[4] As the shale gas boom and accompanying buildout of increased gas-fired power generation and LNG export capability have spurred unprecedented demand for new pipelines and gas infrastructure in recent years, they also have sparked unprecedented opposition to gas infrastructure projects by well-organized and well-funded environmental groups like the Sierra Club promoting a climate change/renewable energy agenda.

Such opposition leans heavily on challenges to the sufficiency of the Commission’s reviews under NEPA, giving special emphasis to the claim that, in evaluating new pipeline projects to serve power generation load, FERC must consider the effects on climate change of greenhouse gas emissions (GHG) from the end use of the gas in the power plants served by the pipeline.

Relying on Public Citizen, FERC for the most part[5] has not attempted to quantify such indirect environmental effects, maintaining that its authorization of a pipeline is not the legally relevant cause of the GHG emissions resulting from downstream consumption of natural gas in power plants.

The D.C. Circuit Panel Decision in Sabal Trail

But in the recent case of Sierra Club v. FERC,[6] the majority of a panel of the D.C. Circuit disagreed. In reviewing FERC’s authorization of the Sabal Trail Pipeline designed to serve new gas-fired power plants in Florida, the panel held that the GHG emissions from the power plants are an indirect effect of FERC’s order approving the pipeline and that “because FERC could deny a pipeline certificate on the ground that the pipeline would be too harmful to the environment, the agency is a ‘legally relevant cause’ of the direct and indirect environmental effects of pipelines it approves. Public Citizen thus did not excuse FERC from considering these indirect effects.” [7]

The panel vacated and remanded FERC’s order authorizing construction and operation of the pipeline, pending FERC’s completion and review of the additional environmental studies on the power plant GHG emissions.[8]

In a strong dissent, Judge Janice Rogers Brown disputed the majority’s application of Public Citizen. Relying chiefly on a trilogy of recent D.C. Circuit decisions that had rejected the need for FERC to undertake NEPA consideration of downstream GHG emissions in its authorization of LNG export terminals,[9] Judge Brown pointed out that in those cases: “we held the occurrence of a downstream environmental effect, contingent upon the issuance of a license from another agency with the sole authority to authorize the source of those downstream effects, cannot be attributed to the Commission; its actions ‘cannot be considered a legally relevant cause of the effect for NEPA purposes.'”[10]

While the downstream effects in the LNG terminal cases were contingent on DOE’s authorizing exports of natural gas, the downstream effects in Sabal Trail were contingent upon authorization of the construction and operation of the power plants by the Florida Power Plant Siting Board, a duly authorized agency of the state of Florida with exclusive authority over the licensing of new power plants in Florida. Without the licensing of the power plants, there would be no power plant operations and no resulting GHG emissions.

Significance of Sabal Trail

Sabal Trail is significant on multiple levels. On a practical level, the vacatur and remand to FERC opens a Pandora’s box of NEPA review for the Commission. Although FERC’s environmental staff has performed upper-bound estimates of GHG emissions from downstream gas use associated with new gas pipeline projects since mid-2016, there are no readily available standards to guide such determinations, and its assessments to date have not been tested on judicial review.

The additional required analysis has the potential not only to further delay an already burdened FERC approval process, but also to inject added complexity in sorting out (i) the proper estimates of GHG emissions to use in determining the impact of using gas in the power plants; (ii) the significance of such GHG emissions, especially since there are no readily available metrics to gauge “significance;” and (iii) whether the Commission  should employ the “Social Cost of Carbon” tool developed by the Obama-era Council on Environmental Quality,[11] now withdrawn by executive order[12] in favor of reliance on the metrics set forth in OMB Circular A-4,[13] to evaluate the impact of the GHG emissions and the benefits and detriments generally of a proposed pipeline project.

These challenges portend greater uncertainty and possibly increased likelihood of error in the commission’s evaluations, potentially heightening investor risk in pipeline projects and dampening deployment of capital in the pipeline sector.

Efforts to reach consensus on the proper response to Sabal Trail in the proceedings on remand have already divided the Commission along party lines. In its March 14, 2018, Order on Remand Reinstating Certificate and Abandonment Authorization, the three-Republican majority adhered to the methodology the Commission environmental staff first introduced in mid-2016, employing upper-bound estimates of GHG emissions with explanations of the inherent difficulty in providing more granular detail. It also declined, as in past orders, to employ the Social Cost of Carbon tool, noting the inherent difficulties of meaningfully employing the Social Cost of Carbon in the Commission’s decision-making.[14]

Lastly, the majority questioned whether the Commission has authority to deny a certificate because of concerns about GHG emissions from the end use of gas, noting that Congress or the executive branch, not the Commission, is responsible for deciding national policy on the end use of natural gas.[15]

The two Democratic Commissioners dissented separately, asserting that the order on remand should have included more granular assumptions in the evaluation of GHG emissions, adopted the Social Cost of Carbon to evaluate both the impact of GHG emissions from downstream gas use and the public convenience and necessity of projects generally, and determined that the impact on climate change of GHG emissions from downstream gas use must be factored into the determination of the public convenience and necessity of a new project.[16]

But far and away, Sabal Trail‘s greatest significance is that the panel majority’s application of Public Citizen does not appear defensible, making the case worthy of U.S. Supreme Court review, especially in light of the current administration’s desire to expedite the authorization and construction of new infrastructure. If Sabal Trail is reviewed and reversed by the Supreme Court, FERC will have a far clearer path through its NEPA process in pipeline certificate cases.

Where the Sabal Trail Panel Majority May Have Gone Wrong

The panel majority appears to have misapplied Public Citizen in two separate respects: (i) on the statutory authority of FERC, in presupposing that the Commission has authority under the NGA to deny a pipeline certificate because of concerns about GHG emissions from the end use of the gas transported by a pipeline, and (ii) on causation, as noted by Judge Brown, in wrongly attributing to FERC causation of GHG emissions by the power plants served by the FERC-authorized pipeline, when a separate state agency had sole authority to license the construction and operation of the power plants that are the source of such emissions, and categorically to prevent such emissions by refusing to issue a license.

Whether FERC has statutory authority to deny a pipeline because of concerns about GHG emissions from power plants served by the pipeline

Although the panel majority correctly articulated the touchstone of Public Citizen that “[a]n agency has no obligation to gather or consider environmental information if it has no statutory authority to act on that information,”[17] it failed to apply that limitation in the context of the Commission’s statutory authority to act on the information claimed to be necessary.

To justify collecting information on downstream power plant emissions, the panel needed first to determine that the Commission has statutory authority to deny a certificate to a new pipeline because of concerns about the effects on climate change of GHG emissions from the power plants proposed to be served by the pipeline. Because the panel majority never addressed that issue, the statutory authority element of Public Citizen is missing.

The proffered justification that “FERC could deny a pipeline certificate on the ground that the pipeline would be too harmful to the environment”[18] is insufficient, as it fails to define FERC’s statutory authority in the context of the specific information sought on downstream GHG emissions from the end use of the gas.

Having no express statutory authority to regulate the end use of gas, the Commission’s power to affect end use in certificate cases derives from its authority under Section 7(e) to determine that a proposed service is required by “the public convenience and necessity.” However, the precedent to date indicates that the Commission’s latitude in exercising such authority is limited, confined to furthering Congress’ purpose in enacting the NGA to assure interstate consumers “an adequate and reliable supply of gas at reasonable prices.”[19]

For example, in the leading case, FPC v. Transcontinental Gas Pipe Line Corp.,[20] the Supreme Court upheld the authority of the Federal Power Commission (FERC’s predecessor) to deny a certificate for the transportation of gas from the Gulf Coast to New York City to alleviate inner-city air pollution because of the Commission’s overriding concerns about the end use of the gas for power generation.

Because other fuels could be readily substituted for natural gas under steam boilers, the Commission  determined that using a wasting resource like gas in power plants was an “inferior use,” whose adverse effects on the availability and price of gas to other interstate consumers would be exacerbated if power plant supply deals like the one proposed in Transco were allowed to proliferate.[21]

Whereas the basis for the Commission’s exercise of authority in Transco can be readily linked to the NGA’s statutory purpose and, as the Supreme Court found in Transco, to Congress’ intent in the 1942 amendments to NGA Section 7 to permit the Commission to take account of the potential “economic waste” of gas in exercising its certificate authority,[22] no such statutory grounding is evident to support the notion of denying a pipeline certificate because of concerns about the effects on climate change of emissions from the end use of the gas transported by the pipeline.

Nowhere does the NGA authorize the Commission to regulate the emissions of downstream gas users, much less establish de facto emissions standards for such users to address climate change through exercise of its authority under Section 7(e) to condition or deny pipeline certificates. Lacking any apparent statutory authority to deny a new pipeline based on GHG emissions by downstream gas users, it appears that the Commission had no obligation under NEPA to gather or consider information on power plant GHG emissions in authorizing the Sabal Trail Pipeline.

Whether authorization to operate the pipeline or authorization to operate the power plants is the legally relevant cause of the GHG emissions from the power plants

Judge Brown’s dissent correctly explains why Public Citizen requires that FERC’s certificate order not be found the “legally relevant” cause of the GHG emissions of the power plants served by the Sabal Trail Pipeline. Instead, as Judge Brown explained, the legally relevant cause is the authorization granted by the Florida Power Plant Siting Board to construct and operate the power plants.

Simply put, the GHG emissions are the byproduct of power plant operations and would not occur separate and apart from the licensing of the power plants by the Florida Power Plant Siting Board. And only the Siting Board, not FERC, has the legal authority to prevent such operations. True, the denial of a FERC certificate could make power plant operations more difficult, but it would not affect the legal authority of the owners to continue operations using other supplies of natural gas or alternative fuels to run the generating equipment.

In these circumstances, the chain of causation as to the Commission’s responsibility is broken, meaning that the GHG emissions cannot be attributed to its action. Accordingly, it was not required to consider the indirect effects of GHG emissions from operation of the power plants in its review of the pipeline certificate application under NEPA.

Lastly, to end where we started, Public Citizen is on point. The issue there was whether the Federal Motor Carrier Safety Administration (FMCSA) was required to consider the environmental effects of increased truck traffic between the U.S. and Mexico in instituting its truck inspection program following President Clinton’s lifting of the moratorium on the entry of Mexican trucks into the US. Because the FMCSA lacked statutory authority categorically to prevent the cross-border operations of Mexican trucks, the court determined that it was not the relevant cause of such environmental effects.

Similarly, in Sabal Trail, the issue is whether FERC must consider the environmental effects from the operation of power plants served by a gas pipeline in authorizing the pipeline. By the reasoning of Public Citizen, because FERC lacks the statutory authority categorically to prevent the operation of such power plants, it cannot be viewed as the legally relevant cause of the environmental effects of such operations.

Conclusion

Reversal of Sabal Trail will help to restore rationality to the NEPA review process for new gas pipelines. The panel majority’s suggestion that a new pipeline “causes” new power plants served by the pipeline reverses the commercial reality of project development, putting the fuel supply cart before the market demand horse as the determinant of new pipeline expansions. The fact is that new pipelines do not get proposed or built without market demand for the gas proposed to be transported.

Reversal will also restore restraint in the conception of FERC’s statutory authority to act in the “public convenience and necessity” under NGA Section 7(e). As Transco suggests, FERC’s authority to affect the end use of gas is limited to actions related to advancing the NGA’s statutory purpose; it does not include the power to control directly or indirectly the GHG emissions of downstream end users of gas. Not that control of such emissions is not important or is in some way affected with the “public interest” — it is just that Congress or other agencies, not FERC, have the authority to regulate them.

Lastly, reversal will restore a sensible understanding of Public Citizen. As Judge Brown points out, where another agency has the authority categorically to prevent the GHG emissions from power plants served by a new pipeline by refusing to issue the license for construction and operation of the power plants, FERC’s more limited action in authorizing a pipeline to serve the power plants cannot be viewed as a legally relevant cause of such emissions.

Such recognition of FERC’s authority as limited will also extend comity to requisite state and federal agency actions in the integrated resource planning of new power generation at the state level and the air permitting process at the state and federal levels for GHG and other emissions from power plant operations.

The original version of this article was published by Law360.  James M. Costan is a partner in Dentons’ energy practice. Jay represents clients on a wide range of public utility and energy matters, including energy transactions and federal and state regulation of the sale and transmission of electricity, natural gas and LNG and the licensing of energy projects.  The opinions expressed are those of the author(s) and do not necessarily reflect the views of the firm, its clients, or Portfolio Media Inc., or any of its or their respective affiliates. This article is for general information purposes and is not intended to be and should not be taken as legal advice.

[1] 541 U.S. 752 (2004) (Public Citizen).

[2] Id. at 767-69.

[3] Sierra Club v. FERC, 827 F.3d 36, 49 (D.C. Cir. 2016) (Freeport).

[4] 15 U.S.C. §§ 717b and 717f.

[5] In mid-2016, FERC environmental staff started preparing “upper-bound” estimates of GHG emissions from downstream gas use to support NEPA reviews. Such estimates assume that the full delivery capacity of the pipeline will be consumed 24/7 for gas-fired power generation.

[6] 867 F.3d 1357 (D.C. Cir. 2017) (Sabal Trail).

[7] Id. at 1373 (citations omitted).

[8] The vacatur and remand had minimal effect on pipeline operations, because most construction had been completed by the time of the D.C. Circuit’s decision in late August 2017. Thereafter, issuance of the mandate was held in abeyance pending completion of the rehearing process in late January and then was stayed until late March, affording FERC sufficient time to complete a supplemental environmental impact statement and issue an order reinstating the Certificate of Public Convenience and Necessity on March 14, 2018. Florida Southeast Connection LLC, 162 FERC ¶ 61,233 (2018) (Order on Remand).

[9] Freeport, supra; Sierra Club v. FERC, 827 F.3d 59 (D.C. Cir. 2016) (Sabine Pass); Earth Reports Inc. v. FERC, 828 F.3d 949 (D.C. Cir. 2016) (Earth Reports).

[10] Sabal Trail, 867 F.3d at 1381 (Judge Brown dissenting), quoting Freeport, 827 F.3d at 47, Sabine Pass, 827 F.3d at 68; and Earth Reports, 828 F.3d at 952.

[11] See 81 Fed. Reg. 51866 (Aug. 5, 2016), Final Guidance for Federal Departments and Agencies on Consideration of Greenhouse Gas Emissions and the Effects of Climate Change in National Environmental Policy Act Reviews, available at https://www.federalregister.gov/documents/2016/08/05/2016-18620/final-guidance-for-federal-departments-and-agencies-on-consideration-of-greenhouse-gas-emissions-and.

[12] See 82 Fed. Reg. 16576 (April 5, 2017), Withdrawal of Final Guidance for Federal Departments and Agencies on Consideration of Greenhouse Gas Emissions and the Effects of Climate Change in National Environmental Policy Act Reviews, available at https://www.federalregister.gov/documents/2017/04/05/2017-06770/withdrawal-of-final-guidance-for-federal-departments-and-agencies-on-consideration-of-greenhouse-gas.

[13] https://www.transportation.gov/sites/dot.gov/files/docs/OMBW020Circular0/020No.0/020A-4.pdf.

[14] Order on Remand at PP 22-51.

[15] Id. at P 29.

[16] Id. (separate dissents of Commissioners LaFleur and Glick).

[17] Sabal Trail, 867 F.3d at 1372, citing Public Citizen, 541 U.S. at 767-68.

[18] Id. at 1373.

[19] E.g., California v. Southland Royalty Co., 436 U.S. 519, 523 (1978); NAACP v. FPC, 425 U.S. 662, 669-70 (1976).

[20] 365 U.S. 1 (1961) (Transco).

[21] Similar concerns about the need to husband gas supply for high priority end uses drove the Commission ‘s directive that pipelines institute end-use curtailment plans to address the nationwide gas shortage in the 1970s. See FPC v. Louisiana Power & Light Co., 406 U.S. 621 (1972).

[22] Transco, 365 U.S. at 10-22.

 

In any solar PV development in emerging markets (whether in Africa, Latin America or elsewhere) attention is immediately drawn to project revenues. Government or utility tender packages focus on mark-ups to power purchase agreements with the offtaker, the strength of any government support agreement, and the terms of any other credit support. It is not uncommon for a project to be well advanced before the developer turns to the “less exciting” project agreements, with land rights frequently one of the most problematic. The site may be split over dozens of parcels of land (many of which are either stuck in probate or not properly registered), the model form of lease may be unintelligible, or the land sporadically crossed by grazing animals.

Most project stakeholders are either invested and actively interested in the success of the project (e.g. the offtaker), or experienced and sophisticated counterparties (e.g. EPC contractors) – the lessor(s) of land rights may be less equipped to quickly agree the required documents.

Recently we have been working on a number of solar PV projects across Africa in jurisdictions with a limited track record of international project finance. Key areas in which we often find that a landowner’s model form of lease does not provide sufficient protection for the project are listed below. Although we have used terminology that will be familiar to lawyers used to common law systems, the same issues arise – and should ultimately be capable of being resolved – in any legal system.

Term 

The term of the lease should be sufficient to cover the asset life of the project, the term of key approvals (e.g. the generation licence, planning permission) and any decommissioning period (whether after an early termination or expiry of the term).  If asset life is extended then ideally the lessee will also have the option to extend the term of the lease.

Pre-conditions/early obligations 

The lease rental payments are ideally structured in such a manner that they are not payable until all government authorisations and permits and third party consents required for the development and operation of the project have been obtained. If early works are required (e.g. an environmental impact assessment) in order to be granted the necessary permits then the lease will need to cater for this or such works will need to be authorised under a separate lease, lease option or licence.

Easements  

If the route of the cable connecting the project to the grid is not included in the site and the Lessor has rights over the relevant land, the Lessor should grant the Lessee and any third party nominated by it easements over the land as required for the connection of the solar PV plant to the relevant electricity transmission lines. Similar rights may also be needed to allow a route from the site to the public highway for construction and maintenance. For these purposes it is critical to confirm that all local land which may be required for an easement is in the control of the Lessor.

Permitted Use  

The Lessee should be allowed to carry out activities related to, in connection with, or for the purpose of, the design (including site appraisal), construction, operation (including export of power), maintenance and decommissioning (and handover, if applicable) of the solar PV plant.

The site subject to the lease should also be sufficient for project use, i.e. it should cover the solar PV panels, ancillary equipment (including e.g. inverters, CCTV and substations).

Lessor’s covenant  

The Lessor should not do or permit to be done any act which has or may have the effect of reducing or interfering with the capability of the power station to generate its maximum potential of electricity. This may extend to limiting rights to cross the site, including prohibiting the grazing of livestock (to the extent not needed by the Lessee to avoid grass cutting), and providing assurances that neighboring land will not shadow the site (e.g. with new buildings or trees).

To the extent that the Lessor is a government agency it may also be reasonable for it to provide assurances that third parties (e.g. local farmers) will not attempt to access the site, possibly alongside local content and/or community benefit provision to ensure local support.

Pre-existing liabilities 

The Lessor should be liable for, and should indemnify the Lessee against, any pre-existing liabilities associated with the site (e.g. environment liabilities). Where possible the Lessor may also need to do its own property searches and title checks (e.g. to check there is no compulsory purchase order affecting the site).

Termination 

Ideally the Lessor shall either have no right to terminate the lease, or its termination rights should be restricted to failure to pay rents (if not cured within a reasonable period upon notice) – remedies for other breaches by the Lessee should be compensation rather than termination.

Direct Agreement

The Lessor will need to covenant that it will at the request and reasonable cost of the Lessee enter into a direct agreement with any lender providing financing for the project such that the lender has a right to step in and novate before the Lessor exercises its rights under the lease, including any right to terminate the lease (if any) or re-enter the site.

The authors are grateful to Gillian Goldsworthy, Senior Associate in the Real Estate team of Dentons’ London office, for her assistance with this piece

 

 

 

 

 

 

 

 

On 27 February 2018 the CJEU issued its judgment in the Western Sahara Campaign case (Case C-266/16). In a short judgment, the court held that the 2006 partnership agreement in the fisheries sector (Fisheries Agreement) and a 2013 protocol to that agreement are inapplicable to the territory of Western Sahara. This was because including Western Sahara within the scope of these agreements would be contrary to “rules of general international law applicable in relations between the EU and Morocco”, particularly the principle of self-determination, and to the UN Convention on the Law of the Sea.

Why are we writing about fish in an Energy blog? As we explained in an earlier post on this case, the international law principles on which it turns are potentially relevant to other agreements about natural resources in areas where local populations claim rights of self-determination.

By interpreting the Fisheries Agreement and the 2013 protocol in this way, the CJEU did not have to determine whether agreements that did deal with resources in Western Sahara would be valid under EU and international law (a question Advocate General Wathelet answered in the negative). Nevertheless, the court’s willingness to invoke and apply international law principles, in particular that of self-determination, is an interesting demonstration of the possible impact of those principles. This may well be of broader importance with regard to agreements that purport to deal with other territories whose populations assert – or may in future assert and gain support for – the right to self-determination.

The court’s judgment relies heavily on its December 2016 judgment in Polisario (Case C-104/16), issued after the request for a preliminary ruling was made in Western Sahara. In Polisario, the court had held that the Euro-Mediterranean “association” agreement (the Association Agreement), as well as a Liberalisation Agreement (concerning liberalisation measures on agricultural and fishery products) had to be interpreted, in accordance with international law, as not applicable to the territory of Western Sahara. The Association Agreement and Liberalisation Agreement were initially also included in the Western Sahara reference, but in light of Polisario those aspects were withdrawn by the English High Court.

When interpreting the scope of the Fisheries Agreement and the 2013 protocol, AG Wathelet had considered that, unlike the agreements addressed in Polisario, the Fisheries Agreement and the 2013 protocol were applicable to Western Sahara and its adjacent waters. He reached this view on several bases, finding it was “manifestly established” that the parties intended the agreements to include Western Sahara, that their subsequent agreements and actions were consistent with this interpretation, and that it was also supported by the genesis of the agreements and previous similar agreements.

The court took a different view (without reference to the AG’s Opinion). First, noting the Fisheries Agreement is stated to be applicable to “the territory of Morocco”, the court held that this concept should be construed as meaning “the geographical area over which the Kingdom of Morocco exercises the fullness of the powers granted to sovereign entities by international law, to the exclusion of any other territory, such as that of Western Sahara”. It stated that, if Western Sahara were to be included within the scope of the agreement, that would be “contrary to certain rules of general international law that are applicable in relations between [the EU and Morocco], namely the principle of self-determination”.

The Fisheries Agreement also refers to “waters falling within the sovereignty or jurisdiction” of Morocco. Referring to the UN Convention on the Law of the Sea, the court noted a coastal state is entitled to exercise sovereignty exclusively over the waters adjacent to its territory and forming part of its territorial sea or exclusive economic zone. Given Western Sahara did not form part of the “territory of Morocco”, the waters adjacent to it equally did not form part of the Moroccan fishing zone referred to in the agreement. A similar conclusion followed with regard to the 2013 protocol’s scope.

While more closely tied to the text of the fisheries agreements than the AG’s Opinion, the judgment suggests the court may seek to arrive at an interpretation of such agreements that respects international law insofar as possible. It is therefore a significant restatement of the importance of international law principles, particularly self-determination, to questions regarding sovereignty over natural resources in occupied territories, and therefore has potential ramifications for international agreements which purport to deal with such resources.

Legislation to impose a price cap on domestic energy bills was introduced into Parliament on 26 February 2018. The accompanying announcements from the Department for Business, Energy and Industrial Strategy (BEIS) indicate that the new regime will be in place by Winter 2018-19. This may feel like the end of a long story, and in a sense it is, but it is also the beginning of a new phase for GB retail energy markets: one in which, for the first time in many years, price regulation is likely to play a significant role in shaping the domestic energy supply market – albeit on an explicitly temporary basis.

How did we get here?

Theresa May singled out energy companies who “punish loyalty with higher prices” in her Conservative Party conference speech in October 2017, and a draft of the Domestic Gas and Electricity (Tariff Cap) Bill was published shortly afterwards. The House of Commons Select Committee that scrutinises the work of BEIS then examined the draft Bill, and produced a broadly favourable report on it in January 2018 (both the Committee’s report and the feedback on the draft Bill that they gathered from a range of stakeholders can be found here).

Going further back, the Bill represents unfinished business from the Competition and Markets Authority (CMA) investigation of the GB energy supply markets that concluded in 2016. The instigation of that investigation by the sector regulator, the Gas and Electricity Markets Authority (Ofgem), almost four years ago, was itself the culmination of years of public debate about energy prices and the allegedly excessive profits made by GB utilities.

The CMA found “an overarching feature of weak [domestic] customer response which, in turn, gives suppliers a position of unilateral market power concerning their inactive customer base which they are able to exploit through their pricing policies or otherwise”. In particular, huge numbers of customers of the “Big 6” suppliers who showed little interest in or awareness of the possibility of shopping around for a better deal, found themselves on high “standard variable tariffs” (SVTs). As a result, the CMA identified “customer detriment associated with high prices” of “about £1.4 billion a year on average for the period 2012 to 2015 with an upwards trend”. However, the CMA panel that conducted the investigation decided (by a 4:1 majority) not to impose a price cap to address the harm to SVT customers generally – although they did decide in favour of a price cap for customers supplied through a prepayment meter (PPM). For others, the majority of the panel concluded that measures designed to increase the chances of those on SVTs signing up for a better deal were enough.

The CMA’s conclusions failed to satisfy the public and political appetite for dramatic regulatory action. This was partly because in the period following the CMA’s report, average Big 6 SVTs showed little or no sign of decreasing, while their cheapest tariffs seemed to be increasing, and partly because many of those on high SVTs were also economically or digitally disadvantaged. Poorer customers appeared to be subsidising offers of more competitive prices to the more affluent – or perhaps the larger suppliers were just not very efficient. As the impact assessment published alongside the Bill (a more vigorous and forcefully expressed document than many of its kind) puts it: “a majority of people lose out, with disproportionate impact on the vulnerable”. These – and other, more overtly political reasons – made the move towards a cap unstoppable, notwithstanding the counter-argument that protecting those who didn’t shop around would be likely to result in higher prices for those who did, undermining the development of a properly competitive supply market in the longer term. Interestingly, during the course of the Select Committee’s inquiry, more industry voices than might previously have been expected came out in favour of a cap. (For a sober economist’s justification of the cap, see the evidence given by Professor Martin Cave, who was the dissenting member of the original CMA panel, to the Select Committee.) The charts and table below, published (or derived from data published) on Ofgem’s website in December 2017, tell their own story.

Where exactly are we now?

The Bill follows the text of the draft Bill closely. The table below sets out the key features of the tariff cap regime in the draft Bill and the Bill as introduced, and how the substantive changes from the draft correspond to recommendations made by the Select Committee in its report.

Key feature of draft Bill	Select Committee recommendation	Revised feature in Bill
As soon as practicable after Royal Assent, Ofgem must include conditions in electricity and gas supply licences to cap SVT and “default rates” (tariff cap conditions).	The Committee favours an “absolute cap” rather than one expressed in relation to the level of suppliers’ non-SVT / default rate tariffs.	The Bill remains silent on the precise form and level of the tariff, which are left to Ofgem to determine. A new provision emphasises that the cap will apply to all supply licences and contracts, whenever entered into.
Ofgem can subsequently modify, but not abolish, tariff cap conditions.	N/a	N/a
Ofgem must: (a) consult, and allow 28 days for feedback, on the proposed tariff cap conditions or any later proposed modifications; (b) allow at least 56 days between publication of definitive tariff cap conditions / later modifications and their coming into effect.	N/a	N/a
Ofgem is to have regard to five matters in setting / modifying tariff cap conditions – the need to: (a) protect existing and future customers on SVTs and default rates; (b) incentivise suppliers to be more efficient; (c) set the cap at a level that enables effective retail competition; (d) maintain incentives for customers to switch; (e) ensure that suppliers who operate efficiently can finance their licensed activities.	To deter legal challenge to Ofgem’s decisions, Government should clarify that all five objectives do not have to be satisfied at once. In particular, Government and Ofgem should minimise the risk of challenge arising from the likely short-term reduction in switching when the cap first comes into force and its (perhaps inevitable) reduction in the incentives for some customers to switch.	Matter (a) is elevated to an overarching objective, in aiming to achieve which, Ofgem is to have regard to matters (b) to (e). A new sub-section provides that the cap does not include charges that are part of the SVT / default rate, but are not regularly paid by the majority of customers who pay that rate.
Tariff cap conditions do not apply where: (a) customers benefit from the PPM cap introduced by the CMA or any replacement for it; or (b) electricity is supplied on a “green tariff” that meets the standards set out in electricity supply licences.	The exemption for green tariffs should be strengthened to avoid gaming by suppliers moving customers onto “loosely defined green tariffs” and should not apply where there was no substantial benefit to the environment or the consumer has not actively chosen the tariff. Green gas tariffs should also get the same treatment.	The references to PPM caps and green electricity tariffs have been replaced by more generic wording on: (a) caps imposed in relation to vulnerable customers; and (b) SVTs that apply only if chosen by customers and that appear to Ofgem to support the production of electricity or gas from renewable sources. No doubt partly to acknowledge the fact that there is no current “standard” for green gas tariffs in gas supply licences, Ofgem is given more time to provide for exemption (b).
Starting in 2020, and for as long as the cap remains in place (see below), Ofgem must, by 31 August, annually review “whether conditions are in place for effective competition for domestic supply contracts” and report to BEIS (report to be published by 31 October each year). The Secretary of State (SoS) must consider the report and publish a statement on whether the SoS considers the conditions for effective supply competition are in place.	The Government should not seek to define what is meant by “effective competition” before a cap is in place, but the SoS’s decisions should be based on “the minimum requirements that overcharging and the differential [between SVTs and cheapest tariffs] are substantially reduced, fairness is improved, and vulnerable customers are protected”.	A new provision: at least once every 6 months while the cap remains in place, Ofgem must: (a) review the level at which the cap is set; and (b) state whether, as a result of that review, it proposes to change the level at which the cap is set. The Bill does not include any further definition of “effective competition”.
The cap ceases to have effect at the end of 2020 unless the SoS concludes that conditions of effective supply competition are not yet in place. In that case the cap remains in effect for 2021 and the Ofgem report / SoS statement process is repeated in 2021 and – if the SoS considers conditions of effective competition are still not in place then – again in 2022 (but with a final “sunset” for the cap at the end of 2023 in any event).	N/a	N/a

 

It will be immediately obvious from the above summary that the Bill leaves Ofgem with the hard work of actually setting the cap and drafting the standard licence conditions that will give it effect, and balancing a number of potentially conflicting objectives as it does so. From first publication of proposed tariff cap conditions to their entry into force is likely to take at least 4 months (allowing for one month to consider feedback from the initial consultation). Consultation that takes place before the Bill receives Royal Assent is permitted.

Accordingly, having the new regime in place by Winter 2018-19 looks achievable. Even with Parliamentary timetables dominated by Brexit legislation, it should not be too difficult to find the relatively short amount of time required to debate this Bill, given the broad consensus behind the cap.

Will Parliament be happy to leave it to Ofgem to come up with the all-important numbers? It should: Ofgem is an independent economic regulator (whose independence from political control remains, at least for the moment, guaranteed by EU law). The potential to disrupt delivery of the cap may lie rather with the energy suppliers themselves, or anyone else who may seek to challenge Ofgem’s eventual decision on the level of the cap or other related licence provisions in the courts.

Some suppliers tried to persuade the Select Committee that Ofgem’s decisions on the cap should be subject to a right of appeal to the CMA, rather than only being challengeable by way of judicial review by a court. Their representations unsurprisingly emphasised the benefits of the CMA’s expertise and faster-track procedures more than what they may have perceived as the higher threshold that has to be satisfied for a court to entertain a challenge by way of judicial review or the narrower administrative law grounds on which a court can determine that a decision that is subject to judicial review is sufficiently flawed to be struck down and remitted to the decision-maker (here Ofgem) to reconsider.

In a number of ways, the legislation has been constructed so as to reduce the risk of a successful challenge: Ofgem has been given a fairly clear (if by no means simple) job to do in a particular context, and a court may well be slow to second-guess e.g. the regulator’s judgments when prioritising the competing objectives it must bear in mind when setting the tariff cap (see above).  But even if JR remains the only route for a challenge in the Bill as enacted, the possibility that a challenge will be launched cannot be ruled out, since if the calculations made by the CMA and others are even half right, there is a lot of money at stake here for some suppliers.

What next?

Whether or not Ofgem has to defend any of its tariff cap decisions in court, this new function is going to be a significant item of work for the regulator over at least the next two and a half – and possibly as many as five – years. This is likely to have a number of consequences.

It is hard to see how Ofgem can make judgments about e.g. how “to ensure that holders of supply licences who operate efficiently are able to finance activities authorised by the licence” without potentially routinely engaging with those suppliers on the commercial costs of their businesses in a degree of detail, and level of intensity, to which they are unaccustomed as part of “business as usual” activity. Consideration of the efficient costs of operation is normally what Ofgem does in relation to the natural monopoly businesses of transmission and distribution, not the competitive business of supply (although of course, it is a founding premise of the tariff cap regime that competition is not working properly in the domestic supply sector). Inevitably, individual suppliers will assert that their businesses do not fit particular assumptions Ofgem may make: yet the legislation explicitly precludes making “different provision for different holders of supply licences”.

Perhaps the only way to avoid this level of regulatory attention would be for suppliers unilaterally to follow in the direction proposed by Centrica during the course of the Select Committee’s inquiry as an alternative to a tariff cap, by not having SVTs or default tariffs; but that in itself would not be without its challenges, not least from a customer engagement perspective.

The partial re-regulation of domestic tariffs is by no means the only significant regulatory development that will occur in the energy supply sector over the period when the tariff cap is in force. Government and others have been at pains to stress that changes such as the rollout of smart meters and the introduction of market-wide half-hourly settlement, that could enhance competition in energy supply markets, are not to be seen as reasons not to have the cap. Recent history suggests that the number of such obligations on suppliers only moves in one direction: up. And unlike in the case of “pass-through” costs such as network operator charges, obligations like market-wide half-hourly settlement may be inescapable, but there is likely to be plenty of scope for argument over how much they should cost suppliers to comply, against a background of reduced SVT revenues. Meanwhile, Ofgem has opened up the whole question of the place of suppliers in the regulatory architecture with a call for evidence (November 2017) on the future of supply market arrangements.

Whatever happens, there is a strong chance that Ofgem’s performance, in the eyes of most politicians and the public, will be seen as overwhelmingly focused through the lens of the tariff cap and its impact on SVT customers’ bills. The next few years will not be easy either for the regulators or the regulated.

UPDATE – 6 MARCH 2018

Ofgem has published a letter setting out its timetable for developing the tariff cap condition, as well as its other ongoing work to protect vulnerable customers from overcharging.  A series of working papers is promised over the next few months, with draft licence conditions being issued in August 2018 and the tariff cap being in force by the end of the year – subject to the progress of the Bill.

UPDATES – OFGEM WORKING PAPERS

12 March 2018: Ofgem has published its first working paper on how it will go about setting the tariff cap, drawing heavily on earlier work in the context of the cap for the protection of vulnerable consumers.

28 March 2018: Ofgem has published its second tariff cap working paper.  This deals with the possible use of a “market basket” of competitive tariffs to set or adjust the tariff cap – and provisionally concludes that such an approach is not one to follow here.

9 April 2018: Ofgem has published its third tariff cap working paper.  This deals with “headroom” – i.e. “an amount above the efficient level of costs, which could be used to enable competition to co-exist with the cap”.

19 April 2018: Ofgem has published two more tariff cap working papers.  The fourth working paper is concerned with how the tariff cap will take account of the economic and social policy costs faced by suppliers.  The fifth working paper considers in more detail one of the reference price methodologies first outlined in the second working paper.

UPDATE – CONSULTATION ISSUED ON 25 MAY 2018

Today Ofgem published a consultation consisting of an “overview” and 14 Appendices (altogether more than 400 pages).  Ofgem explains that the consultation does not propose at what level the cap should be, but explains how it might go about setting the cap.  Once the Bill has received Royal Assent, a further, statutory consultation is expected to be issued in August 2018, enabling the cap to “come into force by the end of this year so that it is place to provide protection to consumers this winter”.