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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.

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.

In 2018, the German government appointed a Commission on Growth, Structural Change and Employment, known as the Kohlekommission or Coal Commission with the task of evaluating a roadmap for the phase-out of coal-fired power production in Germany. The Coal Commission’s conclusions have now been published, setting the agenda for the next stage of the German energy transition (Energiewende).

Germany has been a pioneer of the mass deployment of wind and solar power generation. In 2018, its share of electricity generated from renewables (40.3 percent) exceeded that generated from coal (37.5 percent) for the first time. But 37.5 percent is still a lot of coal-fired power. On 26 January 2019, the Coal Commission passed its final (non-binding) resolution accompanied by a 336 page report. We summarise the effect of implementing its recommendations below.

1. Phase-out of coal-fired power production by 2038

The Coal Commission recommends the end of 2038 as the deadline for the phase-out of coal-fired power production in Germany. An integrated “opening clause” enables the phase-out date to be brought forward to 2035 in consultation with the operators if the electricity market, labor market and economic situation allow. This will be reviewed in 2032. In 2023, 2026 and 2029, the phase-out plan will also be evaluated in terms of security of supply, electricity prices, jobs and climate targets.

2. Gradual shutdown of coal power plants

At the end of 2017, Germany had operational coal power plants with a net capacity of 42.6 gigawatts (GW). They are gradually being taken off the grid anyway, however, the phase-out is supposed to be implemented earlier. 12.5 GW are expected to be taken off the grid by 2022, of which 3.1 GW are fed-in by lignite power plants that are particularly harmful to the climate. By 2030, no more than 17.0 GW may remain on the market. By 2038, all coal-fired power plants are to be shut down.

3. Compensation for (potentially) increasing electricity prices for consumers

To compensate for any increase in electricity prices triggered by the phase-out, the Coal Commission recommends reducing grid charges for private households from 2023 on. These grid charges can account for about a fifth of private households’ electricity bills, and the Coal Commission even goes so far as to suggest a subsidy for these network charges. The compensation would amount to approximately EUR 2 billion per year. But there shall be no new levies or taxes.

4. Compensation for (potentially) increasing electricity prices for companies

Energy-intensive industries are to be permanently relieved of costs arising from the price of CO2 pollution rights that coal and gas-fired power plants have to buy under the EU Emissions Trading Scheme (EU allowances). The current relief scheme for these indirect costs will expire in 2020. The government wants to apply to the EU (under state aid rules) for an extension of this compensation. Most recently, the relief amounted to almost EUR 300 million per year. Since EU allowances have become significantly more expensive, the sum will be higher in the future. The so-called electricity price compensation is to be extended until 2030.

5. Financial support for coal mining regions

Coal mining regions affected by the coal phase-out are to receive structural aids (Strukturhilfen) amounting to approximately EUR 40 billion by 2040. In addition to numerous transport projects, the establishment of federal authorities is being encouraged, which could create around 5,000 new jobs within the next ten years. Also, an investment subsidy for entrepreneurs is proposed.

According to the Coal Commission’s proposal, the aid could follow the Berlin/Bonn Act, which mitigated the impact of relocating the capital from Bonn to Berlin. By the end of April 2019, the cornerstones for a law of measures shall be in place that specifies how the German government will precisely promote structural change. Future federal governments of the individual German states are to be bound to it. The Coal Commission estimates the individual costs at EUR 1.3 billion per year over 20 years. In addition, EUR 0.7 billion is to be provided to the federal states that are not tied to specific projects. Furthermore, a special financing programme as well as an immediate programme amounting to EUR 1.5 billion in total will be set to improve the transport system. These expenses are already included in the federal budget until 2021.

6. Compensation for lignite power plants

The Coal Commission recommends contractual arrangements with power plant operators and compensation for decommissioning up to 2030, which should include both compensation for operators and socially acceptable arrangements. The older a lignite power plant is, the less compensation will be paid. If there is no contractual agreement with the operators by July 2020, the exit shall be subject to regulatory law also including compensation.

The Coal Commission also suggests that the amount of compensation should be based on amounts already paid in the past. Lignite power plants have already been taken off the grid and transferred to a reserve for climate protection purposes in the past. At that time, around EUR 600 million were paid per GW output. Of the currently more than 40 GW of coal-fired power plants still connected to the grid, about 21.8 GW are fuelled with lignite.

7. Compensation for hard coal power plants

There shall also be compensation here. However, since these power plants yield less return, a decommissioning premium shall be obtained by a series of tenders. In simple terms, this could work as follows. The German government specifies how much capacity is to be decommissioned. Power plant operators apply for this with bids for compensation. In each tender, whoever demands the lowest compensation or saves the most CO2 by shutting down the power plant will win the contract.

8. Support of coal workers and symbolic preservation of Hambacher Forst

For employees in the coal industry aged 58 and over who have to bridge the time until retirement, there will be an adjustment allowance and compensation for pension losses. Estimated costs amount to up to EUR 5 billion which employers and the state could jointly bear. Terminations of employment for operational reasons are excluded. There should be training and further education for younger employees, placement in other jobs and help with wage losses.

A piece of forest at the Hambach open-cast mine has become a symbol of the anti-coal movement. The report states that the Coal Commission considers it desirable that the Hambach Forest should remain. RWE wants to cut down the forest for brown-coal mining which was stopped by court order. Other villages and areas are also affected by opencast mining. The Coal Commission recommends a dialogue with the affected areas on the resettlements in order to avoid social and economic hardship.

9. Hedge of power supply

In order to avert the risk of blackouts due to a lack of electricity generation, the security of supply should be monitored more closely. The approval of more environmentally friendly gas-fired power plants is to be accelerated. Besides, investment incentives shall be created.

Conclusion

The publication of the Coal Commission’s report is only the start of the process of coal phase-out. In order to implement the recommendations into national and therefore binding law, many details will have to be worked out, and both the German government and parliament have to agree on their adoption. Nevertheless, it marks a hugely important step in the Energiewende, as Germany moves from merely being a champion of renewable power generation to pointing the way towards the kind of net zero carbon economy that climate science shows that we need to achieve sooner rather than later.

On 5 February 2019, Dentons held its
fourth annual workshop on investing in European renewables. Here we outline
some of the key messages that emerged.

Setting the scene

At first glance, these should be happy
days for the European renewables sector. Energy from renewable sources (RES) is
firmly established in the mainstream of the power industry. Installation costs
for wind and solar continue to drop: having fallen already by 75 percent in
2010-2017, PV costs are projected to fall by more than half again in 2015-2025.
Mindful of their international and in some cases also their domestic
commitments, governments have been setting some ambitious renewables targets
for 2030 and beyond. Even the IEA, once a notably sceptical voice on
renewables, has predicted that wind will be the largest source for power
generation in Europe by 2027.

But of course life is never that simple.
The days when the industry could sustain strong growth in revenues and
profitability just by chasing the fattest feed-in tariffs, surfing the waves of
subsidy as they washed across Europe, are long past. With maturity, the sector
faces more complex problems. It must grapple with the fundamentals of commodity
markets; sell itself to new classes of customers and investors; and work with
governments, regulators and system operators to exploit the new technologies
that can make whole power systems work in more sustainable and efficient ways.
And whilst the broad outlines of the next stages in the energy transition are
widely accepted, the details of how best to achieve it remain a matter of
debate.

Country snapshots

No two jurisdictions in Europe present
the sector with quite the same opportunities or challenges. Dentons lawyers
gave brief sketches of the renewables sectors in their home markets, covering
12 of the 20 countries featured in Investing
in renewable energy projects in Europe – Dentons’ Guide 2019. We
summarise below the key talking points from their presentations (the slides
from which can be accessed here).

Germany produced more electricity from renewables than from coal for the
first time in 2018. The growth in RES capacity may not be so large in 2019, but
if buildout rates are slowing down a little, the Energiewende overall is changing gear rather than coming to a halt.
The new financial support mechanisms are functioning well. The recently
announced conclusions of the German government’s Coal Commission
point the way to a complete phase-out of coal-fired generation. The publication
of an action plan for grid expansion further indicates the German
government’s continuing commitment to taking the energy transition into its
next phase, and interest is strong from other sectors of industry, as the
activities of German companies in the e-mobility and hydrogen sectors show.

In France,
the government plans to more than double wind and solar capacity by 2023, with
a further doubling of solar and 50 percent expansion of wind in the following
five years to 2028. Auction mechanisms have succeeded in bringing down the
price of supporting RES. Procedural changes should reduce the potential for
objectors to delay projects. At the same time, it is worth remembering that the
initial trigger for the gilets jaunes
protests was an increase in carbon taxes: in France as elsewhere, there is an
inevitable tension between the need to adopt policies to avert the “end of
the world” and the need of ordinary citizens to survive financially until
the “end of the month”.

The market fundamentals for the RES
sector in Turkey remain strong –
notably, growing demand for power and a strong government commitment to
reducing dependence on imported fuel.  At
present, the regulatory regime favours either very large (1 GW+) or quite small
(up to 1 MW) projects.  For the latter,
there is a feed-in tariff / premium support mechanism; for the former, support
is based on auctions. It is unfortunate that two of these were cancelled in
2018 – one of which would have included the country’s first offshore wind
project – but it is hoped that these will be reinstated.

In Poland,
2019 should be a very busy year for RES projects, as the government focuses on
meeting its 2020 RES targets. After a period in which various measures were
taken to discourage onshore wind, auctions will be focused on solar and onshore
wind. As in many markets, the longer term future depends on electricity market
reform to integrate large amounts of intermittent renewable power.

Italy has set itself ambitious plans for increasing its share of RES to
2030, focused on wind and solar. At present, it is a little less clear how
these will be supported in terms of any public subsidy. On the other hand, the
secondary market remains active, and Italy is one of the jurisdictions where
there is considerable excitement around the prospect of subsidy-free
developments, possibly financed in part by arrangements with non-utility
industrial offtakers (corporate PPAs).

The Czech
Republic and Slovakia
demonstrate some of the same features as the Italian market, in slightly more
extreme form. The boom years were some time ago, and for the moment, these
jurisdictions present secondary market, rather than development opportunities.
As in Italy and some other jurisdictions, the authorities are now investigating
whether the subsidies of some existing projects were properly awarded – did
they, for example, commission exactly when they claim to have commissioned?
Careful due diligence is therefore required when assessing acquisition
opportunities.

In the UK, the renewables industry faces some challenges as a result of
Brexit, particular if the UK leaves the EU with no deal. However, the
government has recently committed to continue to hold subsidy auctions with a
focus on offshore wind every two years, and – with a third of UK power already
coming from RES – it is starting to address the decarbonisation of the heat and
transport sectors. For those technologies without the prospect of new regulated
support (solar and onshore wind), apart from a proposed new “smart export
guarantee” for sub-5 MW projects, the position is starting to improve as
steps are taken to make grid charging rules work better for storage and
progress is made towards developing corporate PPA models that work in a
subsidy-free market.

In the Netherlands, the government continues to contest the case brought
by the Urgenda Foundation and others (and now twice upheld by the Dutch
courts), that it is legally obliged to reduce greenhouse gas emissions by 25
percent against a 1990 baseline by 2020. But it has in any event allocated
generous subsidies to RES, including €10 billion under the SDE+ regime this
year. As in the UK and Germany, offshore wind is set to grow strongly in the
next few years.

Spain is another jurisdiction where interest in corporate PPAs is high,
particularly among projects that have not secured support in the auction-based
regime that began to operate in 2017. Some projects that did secure such
support face a challenge to meet their commissioning deadlines. For those with
deep pockets, there are opportunities to secure grid capacity where earlier
developers’ rights have expired. There are separate incentives for
self-consumption and projects in the Spanish islands.

For the renewables industry in Russia, progress has been slow for many
years. Local content requirements and a bureaucratic, highly centralised power
regime, have not helped, and the method of procuring RES power, being based on
capacity and capital expendture, also sets it apart from other jurisdictions.
But there are signs that the pace is starting to pick up. There are good
prospects for self-consumption projects up to 25 MW, and for the energy from
waste sector.

The renewables sector in Ukraine continues to attract
international investment, driven by attractive feed-in tariffs and exemptions
from import VAT. This looks set to continue under the new auction-based support
regime that will take effect from 2020, but the industry’s resources will be
stretched to meet the end-of-2019 deadline for projects to be eligible for
subsidies under the old regime.

Alongside our own colleagues, industry
stakeholders contributed insights in keynote speeches and a panel discussion
(the slides from the keynote speeches can be accessed here
and here). 

Conclusions

The broad, long-term direction for the
renewables industry appears to be set, and in the right direction. As always,
stability of regulation will be an important factor in realising the sector’s
potential. But increasingly, its success will depend on the development of new
investment approaches – not only to RES projects themselves, but to the
development of the grid and of technology to make it work more efficiently,
harnessing the power of big data, and facilitating new market models.

If you would like to discuss any of the issues raised in this post, or any other aspect of European renewables, please get in touch with any of the lawyers listed in our guide, or your usual Dentons contact.

Climate and energy issues are clearly very important to many voters, even if what the parties say on these issues may be unlikely ultimately to be a decisive factor in determining the outcome of the election. This is the first UK general election to take place since:

• the world reached 1 degree C of
  warming from pre-industrial levels in 2017;
• the Intergovernmental Panel on
  Climate Change issued a report in
  October 2018 showing the importance of keeping global warming to 1.5 degrees C
  – which probably means achieving net zero greenhouse gas (GHG) emissions by 2050; and
• the UK Climate Change Act 2008 (CCA 2008) was amended
  (in June 2019) to reflect a version of that 2050 net zero target (UK net
  emissions, as defined in that legislation, are to be “at least 100%
  below” 1990 levels by 2050).

The target

The new CCA 2008 target was set on the recommendation of the Committee on Climate Change (CCC) in a report of May 2019. The CCC pointed out that:

• current policies across the full range of relevant sectors (including energy, transport, agriculture and the built environment) are unlikely to deliver even the 80% reduction on 1990 GHG emissions required by the CCA 2008 in its original form;
• the way that the CCA 2008 regime currently measures net emissions does not take account of emissions for which the UK economy is responsible but which are released into the atmosphere outside its borders (emissions from international flights and shipping to and from UK destinations and from e.g. factories in other countries that make goods consumed in the UK), but it does take account of UK carbon offsetting – so far the CCC’s recommendations for changes in these areas (see the report and also here) have not been implemented;
• it should be possible to achieve a net zero GHG emissions target by 2050 (even one that was more strictly defined to include e.g. international aviation and shipping emissions), and to do so at no greater net cost than achieving the previous 80% reduction target (up to 2% of GDP);
• this will, however, require massive efforts on the part of government, a range of industries, and individual consumers.

The CCC divides the additional efforts on top of current policies into two categories, of “further ambition” and “speculative” options.

• In the former category are things like achieving 90% low carbon heating (current level – 4%); quadrupling low-carbon power generation capacity; having all new cars and vans on the road electric by 2030 or 2035 rather than the current target of 2040; installing hundreds of thousands of public EV charging points; and a 20% reduction in consumption of beef, lamb or dairy. Carbon capture, usage and storage (CCUS) is seen as a crucial technology, supplying some of the flexible low carbon power; helping to halve emissions from industrial process heat; supplying hydrogen to use as a substitute for hydrocarbons in other industrial processes and powering trains and HGVs; and helping to generate negative emissions by combining the carbon neutral use of sustainable biomass to generate power with capture and storage of the CO₂ emitted (BECCS).
• All the “further ambition” options together would get us to a 96% GHG emissions reduction by 2050. We would need to make some of the “speculative options” work to achieve the rest. They include deeper reductions in meat and dairy consumption (50%); direct air carbon capture and storage (DACCS, at present largely experimental); limiting the increase in passenger flights to 20-40% above 2005 levels; and using synthetic carbon-neutral fuels to power aviation (a blend of hydrogen and CO₂ captured from the air using DACCS).

Common areas of energy and
climate policy discussion

It is interesting to see how far each party is prepared to go, in manifestos that to a greater or lesser extent are aiming to sell themselves to a wide electoral audience, in confronting some of the hard choices that future governments in the UK and elsewhere will have to face if they are to meet net zero targets.

In the table below we have summarised the policies of six parties relating to energy and climate matters, as stated in their respective 2019 manifestos. We have selected the Conservative, Labour, Liberal Democrat, Green and Scottish National Parties, and Plaid Cymru (the Party of Wales). All were represented in the previous House of Commons, and all represent constituencies within the GB electricity and gas markets (Northern Ireland’s energy markets being separate).

Energy is not a ring-fenced area of policy. It has a major interface with transport, for example. And not every party covers exactly the same areas in its manifesto discussion of energy and climate change matters. The table focuses on what may be thought of as core energy areas, on which all six manifestos put forward policies. Below the table, we draw out some of the areas that are more distinctive to one or more parties.

Summary table of key energy and climate policies discussed in the
six parties’ manifestos

Where do the parties’ approaches differ?

Some of the differences between the parties will be apparent from the table. But we note some further points that distinguish their approaches below.

The energy and climate change section of the Conservative manifesto is less expansive than the others. But the party is presenting itself as continuing with current government policies, presumably including the output of a large crop of recent energy-related consultations in areas such as nuclear power, CCUS and energy efficiency in buildings.

Labour’s energy policy is closely linked to its broader plans for taking certain utility industries back into public ownership, and for investing very large amounts of public money in infrastructure projects. For them, and for the Green Party, facilitating energy transition is part of a process of bringing about wider social and economic changes.

• They have proposed the creation of a National Energy Agency to own and maintain “the national grid infrastructure” and oversee delivery of decarbonisation targets, as well as new Regional Energy Agencies to replace existing distribution network operators and hold “statutory responsibility for decarbonising heat and reducing fuel poverty”. The supply businesses of the “Big Six energy companies will be brought into public ownership”.
• Their plans for very substantial public funding of infrastructure include a £400 billion National Transformation Fund, £250 billion of which will be directed to a Green Transformation Fund. Apparently in addition, a National Investment Bank and Regional Development Banks, would provide “£250 billion of lending for enterprise, infrastructure and innovation over 10 years”.

The Liberal Democrats have a number of policies focused on devolving net zero powers and responsibilities to local authorities. They would “regulate financial services to encourage green investments”; and “end support from UK Export Finance for fossil fuel-related activities”. They also focus on reducing the climate impact of aviation “by reforming the taxation of international flights to focus on those who fly the most, while reducing costs for those who take one or two international return flights per year” and “placing a moratorium on the development of new runways (net) in the UK”.

As one would expect, energy and climate change issues are perhaps most prominent and fully integrated into the overall programme for government put forward by the Green Party. As the summary table above indicates, they tend to go furthest in any given area of activity that could promote net zero: they even propose to plant more than 10 times as many trees as the next strongest advocates of this form of carbon sink (700 million as against 60 million). But perhaps the most notable feature of their manifesto in this respect is that they appear to be the only one of these parties advocating comprehensive carbon tax reform (a prospect that may be facilitated by Brexit). They would apply a carbon tax to “all fossil fuel imports and domestic extraction, based on [GHG] emissions produced when the fuel is burnt” and on “imported energy, based on its embedded emissions”, with a view to “rendering coal, oil and gas financially unviable as cheaper renewable energies take their place”. The tax would also cover “meat and dairy products over the next ten years”. Revenues would be recycled in particular ways – for example to fund a “universal basic income” and provide transitional assistance to farmers. It is to be expected that most political parties do not promote new forms of taxation in their manifestos, but the general lack of engagement with the notion of a progressive and redistributive carbon tax, which has been presented by Policy Exchange last year in the UK and has strong support from many economists, is unfortunate.

The SNP and Plaid Cymru focus on the importance of taking forward projects in their own countries (e.g. the Swansea Bay and other tidal lagoons in the case of Plaid Cymru). Their manifestos recognise that in the absence of full Scottish and Welsh independence or increased powers of the devolved Scottish and Welsh administrations in respect of energy and climate change matters, the most they can do is to apply pressure to the new UK government. For example, the SNP manifesto includes a “demand” for the “ring-fencing of oil and gas receipts [i.e. taxes on oil and gas companies currently paid to the UK government], creating a Net Zero Fund, to help pay for the energy transition through investment” in areas such as renewables, EVs and CCUS.

Beyond 12 December

It is not our job to rank what the parties have said about their intentions in relation to energy and climate change matters, or to try to use the manifestos as a basis for predicting whose proposed programme would be most likely to succeed in achieving the CCA 2008 net zero target. In any event, election manifestos are not usually detailed statements of policy, and what these manifestos say about energy and climate matters is generally no exception to that rule.

However, we do offer a view on what the
key elements of any future government’s plans for achieving a net zero target
must include, and this is summarised in the diagram below.

High-level political consensus on strategic choices: You need to start with clear objectives that command support across a sufficiently broad base. It’s important to be ambitious, and for those ambitions to be consistent with the net zero target. But most net zero policies will need to be delivered across the lifespan of multiple Parliaments, and the best way to enable their implementation to survive changes of government is if they command a good measure of cross-party support in the first place. Clear answers to all the questions highlighted at the side (top left) of the diagram (what/how/when/who pays?) is essential, and the more controversial those answers are likely to be, the more you need to have an honest debate about them at the outset. (There are obvious parallels here with the debate over funding social care in the long term.)

Relentless, joined-up regulatory decision-making: Turning high level net zero policy into regulation isn’t easy.

• Everything in the energy sector interacts with everything else, often in unexpected ways.
• The regulatory regime, particularly as embodied in licences and industry codes, has become almost impossibly complex, and is seen as being a barrier to innovation. BEIS and Ofgem have now acknowledged this, but the scope of possible reforms is still unclear and it is going to take a number of years, at least as regards industry codes.
• Increasingly, net zero regulation has to embrace things and organisations that aren’t subject to energy sector rules to achieve results: data ownership (and monetisation), for example, or financial reporting of climate risks – not to speak of car ownership, planting trees and not eating beef.
• Overall policy consistency is crucial (and harder to achieve than it sounds), but inevitably there has to be room to be flexible on some points over time.
• Some would argue that neither the statutory duties of Ofgem as regulator of the downstream gas and electricity sectors, nor the remit of the Oil & Gas Authority as regulator of the upstream oil and gas industry in the UK, are as consistent as they should be a net zero target. This point is controversial, but probably needs to be considered more deeply and transparently from a political and technical standpoint than has so far been the case.

Vibrant, competitive markets: Alongside effective regulation, the need for competitive markets also becomes more acute. Even the largely nationalised energy sector envisaged in Labour policy statements would need competitive markets (e.g. in equipment manufacture) to supply it. In the market structure that we have at present, ensuring effective competition is key to Ofgem’s mission, and there are clear indications of market failure or immaturity in areas such as the financing of energy efficiency or heat networks. Looking beyond the traditional energy market, it will be a lot easier to achieve a target of 100% new EVs when there are a good many more models to choose from than at present – but will that happen without some regulatory “encouragement”?

Consumers (voters) engaged: So far, decarbonisation has largely taken consumers for granted. As a whole, at least on the electricity side, they have had the costs of various forms of subsidy, levied in the first instance on suppliers, passed through to them (or not, if they Energy Intensive Industries). Some have been the recipients of supplier-funded energy efficiency measures. Now, we need them all to become more actively engaged in energy markets, and potentially to make some big spending decisions and lifestyle changes in the name of net zero. We can talk about showing them what the benefits are clearly and sending price signals, but will that work? Remember, these are the same people who for years didn’t switch energy suppliers when they were losing significant amounts of money by sticking with their existing provider. The winning policies will be those that are approved by behavioural scientists, as well as economists. In the end, as the arrows in the diagram suggest, it may come back to the political level: not for nothing do some now speak of the energy transition involving democratisation, alongside the more familiar decarbonisation, decentralisation and digitalisation of energy.

What next?

The party manifestos suggest that any future government will recognise net zero as a priority. All their programmes in this area will require major efforts to implement. The UK has a number of achievements to be proud of to date, such as the rapid expansion of its renewables sector and the adoption of the net zero target itself. But the scale and complexity of the challenges highlighted by the CCC’s report mean that whatever happens on 12 December 2019, there can be no room for complacency on any aspect of energy and climate change policy.

This
post was prepared with the assistance of our London Energy team solicitor
apprentice, Megan Goacher.

We are running a series of events to discuss net zero policies and their impact on energy and related sectors during 2019-20. Please get in touch with the author or join the Dentons Net Zero Energy Community on LinkedIn if you would like to learn more about these events.

There is a broad
consensus among economists that, globally, over time, reaching net zero greenhouse
gas emissions by 2050 will cost less than not reaching net zero.[1] In
that very broad, long-term, high-level sense, it is clear that there is no
conflict between carbon neutrality and economic interests. But if everybody
thought it was already in their economic interests to aim for net zero today,
we would probably not be so far off track from achieving that goal as we
currently are.[2]
  

Researchers
working within the framework set by the Intergovernmental Panel on Climate Change
(IPCC) have mapped out four indicative pathways to net zero.[3] They
all involve at least halving global consumption of fossil fuels by 2040. That
is not quite the future that most oil majors, and governments with a stake in
the industry, seem to be planning for.[4]
Others argue that net zero in 2050 is compatible with fossil fuels still
dominating the global energy sector at that time, but that this would depend on
massive shifts in investment – for example, into new technology to reduce the
carbon footprint of fossil fuel extraction, hydrocarbon supply chains and use
of fossil fuels. The majority of the industry is as yet not visibly committed
to such shifts.[5]

To persuade
people to take action that seems to be against their economic interests, at
least in the short term, you need to change the balance of incentives.

Again, the economists have a straightforward answer: you put a price on carbon. You make it more expensive to produce and/or consume fossil fuels and products with a heavy carbon footprint. People then pay up front for the otherwise unpriced damage caused by their emissions, which means that they have a reason to choose lower carbon products and forms of energy.

There is no
shortage of support for the principle of carbon pricing, which has been
endorsed by royalty, the European Commission and senior bankers, to name but a
few.[6] However,
in practice, existing carbon price mechanisms have had limited effect, and
there are serious risks in seeking to decarbonise with policy instruments that
could impose significant costs on those least able to afford them. Any tax
based on consumption risks having a regressive effect, and people with
proportionally more carbon-intensive lifestyles often lack the financial means
to switch to lower carbon options. The gilets
jaunes protests in France began with an increase in carbon taxes.[7]

Carbon pricing
may take the form of a straight tax on emissions, or of an emissions trading
scheme. The former is arguably the better approach. For example, setting a tax
rate is not always easy, but it is easier to make adjustments to a tax than to a
market mechanism, where it can be difficult to recover from an initial
miscalculation of the optimum number of emissions allowances to issue at the
outset, as in the case of the EU Emissions Trading Scheme (EU ETS).

The ideal carbon
tax would be economy-wide, and have three further key features. 

• The price of emissions would
  start considerably higher than in most current carbon pricing schemes, and
  increase over time in a carefully calibrated way.[8]  
• To ensure popular support, government
  would pay back some or all of the tax receipts in the form of a “carbon
  dividend” in a fiscally redistributive way.[9]
• To make it possible to start
  with a national, rather than a global version of the tax, and to avoid exporting
  the taxing country’s emissions to countries without a carbon tax, it would be
  necessary to charge a “border carbon adjustment” tariff on goods
  imported from jurisdictions with no equivalent tax.

Such an approach
has plenty of heavyweight intellectual support.

• Just over a year ago, the Wall
  Street Journal carried a self-styled “largest public statement of
  economists in history” in which no fewer than 3,558 US economists espoused
  something along these lines that was proposed from a US perspective. This is
  the “Baker-Schultz” plan, re-branded in February 2020 as the
  “Bipartisan Climate Roadmap”.[10]
• In October 2017, leading UK
  regulatory economist Dieter Helm put a carbon tax at the heart of his report to
  the UK government on how to address the rising cost of energy in the context of
  its climate change policy goals.[11]
• In July 2018, the UK think tank
  Policy Exchange produced The Future of
  Carbon Pricing: Implementing an independent carbon tax with dividends in the UK,
  with a foreword jointly authored by a former Labour Chancellor of the Exchequer
  and a former Conservative Foreign Secretary.[12]

Of course, any
attempt to implement such a tax would need to address a great many issues, both
in terms of high level design and practicalities.

• Do you just tax fossil fuels,
  or do you also tax products in whose manufacture fossil fuels have been
  consumed? In the case of fossil fuels, at what point(s) in the chain between
  the upstream producer and the final downstream user should the tax be levied? For
  example, you could impose a tax on upstream hydrocarbon producers or refinery
  operators that was based just on the emissions from their activities, rather
  than from the presumed activities of end-users of refined petroleum products, such
  as electricity generators or motorists.
• At whatever point(s) a tax is
  applied, at what rate should it be levied? What assumptions about the emissions
  intensity of downstream processing and/or use should underpin the calculation
  of that rate? How do you ensure that the imposition of the tax, and any
  increase in the rate, has the desired effect of incentivising changes in
  behaviour (i.e. shifts to lower carbon technology)? Will taxing the ultimate
  consumer more heavily incentivise the upstream or midstream operator to reduce
  emissions from flaring or fugitive methane? If I fill up my car with fuel from
  a retailer who promises to offset the emissions that my driving will cause,
  should I get a rebate on the tax element of my purchase?
• Tax law has a natural tendency
  to become complicated. Take for example the Climate Change Levy (CCL) legislation,
  that supplements the EU ETS in UK domestic law. In outline, this is quite a simple
  scheme: electricity and certain fossil fuels are “taxable
  commodities” and a levy is charged on “taxable supplies” of
  them. But quite quickly, the desire to incentivise, protect, or discourage
  particular activities turns the scheme into an abstruse and intricate mesh of
  exemptions, exclusions, and exceptions from exemptions or exclusions.
• Both fossil fuels and products
  manufactured using them are traded internationally, but carbon taxing is
  currently national (or in the case of the EU ETS, regional), and is likely to
  remain so for the foreseeable future. In order to encourage other countries to
  adopt similar regimes, and to stop its domestic industry being undercut until
  they have done so, a taxing country will want to impose a carbon border
  adjustment on imports. This may involve charging tax at a point further down
  the value chain than would be the case with domestic industry. For example: you
  apply a domestic carbon tax on electricity, which increases the costs of
  aluminium smelters, so you need to apply the carbon border adjustment to
  imports of aluminium from a country that does not levy a similar carbon tax on
  electricity or aluminium production.
• But suppose there are two
  aluminium producers in the aluminium exporting country: one powered entirely by
  renewable energy, and the other by a coal-fired power station. And suppose that
  some of the aluminium that reaches the aluminium importing country arrives in
  the form of finished products. If two identical stepladders are imported, one
  made of “brown” aluminium and the other of “green”
  aluminium, the tariff charged on the latter should be lower.

This prompts
some further reflections on the kind of system that is needed. 

• To work well, our hypothetical
  carbon tax needs to be very granular. That means handling a lot of data, and
  mining that data for insights – for example, about how particular applications
  of the tax affect the behaviour of particular groups or economic sectors.
• You will also need to be able
  to keep records. Suppose somebody is awarded a rebate but it turns out they
  should not have had it. Suppose you want to allow people to borrow against
  their future carbon dividends in order to invest in making their homes more
  energy efficient. You may well want to track supply chain emissions – including
  for the oil & gas industry itself.   
• Very soon, you are looking at
  information flows that are too numerous and diverse to be managed by a central
  counterparty.
• This points to a system that
  can facilitate large numbers of transactions automatically, within set
  parameters – in other words, smart contracts.
• That system must be very
  secure, and capable of encouraging parties who do not have direct contact with
  each other to trust each other.
• Above all, you need a system
  that records, in immutable form, every transaction that is made within it.

This sounds like
a job for some kind of distributed ledger technology (sometimes, but strictly
inaccurately, referred to by the generic label “blockchain”). No
jurisdiction in the world has yet implemented the ideal version of a carbon
tax. But if and when they do, it should arguably be a data-rich, deeply
digitalised, regime that can be integrated with smartphones and the internet of
things: capable of tracking individual products through the supply chain, and
perhaps distinguishing between hydrocarbons from different sources on the basis
of the emissions intensity of the processes by which they have been extracted,
transported and refined.

The Policy
Exchange paper referred to above highlights the role of “blockchain”
in this regard. It also points out that the UK’s withdrawal from the EU provides
it with a potential opportunity to strike out on a new course in terms of
carbon pricing. Research by the UK energy regulator Ofgem shows that even the
UK’s existing carbon pricing tools, the much-criticised EU ETS and its domestic
supplement, the Carbon Price Support element of the CCL, have been the single
most effective regulatory driver of decarbonisation in the UK power sector.[13]

However, a government
consultation issued in May 2019 on the future of UK carbon pricing was
essentially focused on how to replace the EU-derived existing regime with
something similar but UK-only.[14]
It made no reference to the kind of ideas put forward by Policy Exchange, the
3,558 US economists, or Prof. Helm as regards a carbon tax. It is to be hoped
that the new government will be prepared to reconsider this approach and look
seriously at some of those ideas.[15] At
the same time, the UK government will need to think how to respond to the EU’s
plans, as part of the European Green Deal proposals of the new European
Commission President, Ursula von der Leyen,[16]
to establish an EU border carbon adjustment to avoid “carbon leakage”
through the importing of cheaper products of energy intensive industries from
countries with weaker carbon emissions controls.[17]   

In the energy
sector, distributed ledger technology, smart contracts and related innovations
are not just of interest to wonkish proponents of better carbon pricing. Oil companies
and others in the sector have a keen interest in all these developments, because
they have the potential to save them huge amounts of money.[18]

• By exploiting existing sub-surface
  data, upstream oil and gas players can make the exploration process less
  hit-and-miss by identifying good prospects and likely dry holes before drilling.
  Earlier this year, the UK Oil & Gas Authority released 130 terabytes of
  data about the North Sea. They think that making good use of this data could
  reduce exploration costs by 20%.[19] 
• Using blockchain and smart
  contracts they can reduce the costs and cost-overruns of building new infrastructure
  – some would argue, by up to 50%.
• There is potential to make
  upstream facilities operate more efficiently by making better use of all the
  data they gather.  Wood MacKenzie
  estimate that US shale producers could reduce operating expenses by 10% and add
  $25 billion of value by putting mature wells on smart production management
  systems.[20]
• Physical oil and petroleum
  product trading can be made much more efficient by replacing the old
  paper-based trade finance system with a distributed ledger.[21]  

It is perfectly
possible to find oil and gas industry veterans who are sceptical of these
developments. But their reason is not that they doubt the technology. Their
response tends to be more along the lines of: “It sounds great, but when
the oil price is high, we don’t need to cut costs, and when it’s low, we have
other things to worry about”.

However, a
digitalised carbon tax could provide the constant, incremental pressure that is
needed to get the industry to exploit the power of digitalisation to
decarbonise.   

And the industry
needs to do this, because it faces all sorts of other challenges. By some
measures, its energy return on investment is declining.[22]
It may become vulnerable to climate change litigation. It may face competition
from lower carbon alternatives that are cheaper and more effective substitutes
for what it offers than are currently available.[23] But
if the industry saves costs, it will become less risky, and it will be more
able to invest in areas where its expertise will be crucial, like hydrogen and
carbon capture and storage, that can give it a longer-term future.

Bring on the
smart carbon tax of the future, then, and everyone should be a winner. In the
meantime, even if the fully digitalised and personalised kind of platform
outlined above lies too far in the future to be relied on as the only way
forward, there is still plenty of scope to make more widespread use of carbon
pricing, at higher and therefore more incentivising levels, and with
redistribution and carbon border adjustment elements – and there is a strong
case for doing so urgently.

The author is
extremely grateful to the World Energy Council (Austria) and the Organisation
for Security and Co-operation in Europe for inviting him to speak on the
subject of “carbon neutrality vs. economic interests” at the 2^nd
Vienna Energy Strategy Dialogue in November 2019 (which was themed around
“The Impact of Big Data in Energy, Security and Society”). This
article is a version of his contribution on that occasion.

[1] The proposition that, as regards climate
change, mitigation of undesirable outcomes before they materialise is cheaper
than adaptation to them once they have arrived, was authoritatively stated in the
Stern Review of the Economics of Climate Change, commissioned by the UK
government and published in 2006. The UK government’s independent advisory body
on climate change, the Committee on Climate Change, found in its 2019 report recommending the adoption of a “net
zero” target for UK greenhouse gas emissions in 2050 that this would not cost any more than the
previous statutory target of an 80% reduction against 1990 levels (itself
partly triggered by Stern’s conclusions).

[2] The gap between the emissions trajectories
of current and announced policies and what is needed to avert unacceptable
adverse impacts of climate change has been highlighted in many places, including
the IPCC’s 2018 special report on Global Warming of 1.5ºC and the UN Environment Programme’s 2019 Emissions Gap
Report.

[3] See page 90 of the Committee on Climate Change report on net zero for graphics and full citation.

[4] See for example The Production
Gap Report
(2019), produced by the Stockholm Environment Institute and others.

[5] See for example the International Energy
Agency’s 2020 report, The Oil and
Gas Industry in Energy Transitions, and a number of publications by consultancy Thunder Said Energy.

[6] See for example the article by Gillian Tett
in the Financial Times, UK edition for 24 January 2020, “The world needs a
Libor for carbon pricing”.

[7] See for example the article by Philip
Stephens in the Financial Times, UK edition for 24 January 2020, “How
populism will heat up the climate fight”.

[8] See the Report of the High-Level Commission
on Carbon Prices chaired by Joseph Stiglitz and Nicholas Stern (Carbon Pricing
Leadership Coalition, May 2017): https://www.carbonpricingleadership.org/report-of-the-highlevel-commission-on-carbon-prices. Among the Commission’s conclusions: “Countries may choose different instruments
to implement their climate policies, depending on national and local
circumstances and on the support they receive. Based on industry and policy
experience, and the literature reviewed, duly considering the respective
strengths and limitations of these information sources, this Commission
concludes that the explicit carbon-price level consistent with achieving the
Paris temperature target is at least
US$40–80/tCO₂ by 2020 and US$50–100/tCO₂ by 2030,
provided a supportive policy environment is in place.” (Emphasis added.)

[9] For an analysis of the different ways of
implementing a “carbon dividend”, see D. Klenert, L. Mattauch, E.
Combet, O. Edenhofer, C. Hepburn, R. Rafaty and N. Stern, “Making Carbon
Pricing Work for Citizens”, Nature 8 (2018), 669-677.

[10] The “Economists’
Statement on Carbon Dividends” was signed by, amongst many others, 4 former
Chairs of the Federal Reserve, 27 Nobel Laureate Economists and 15 Former
Chairs of the Council of Economic Advisers. See now also https://clcouncil.org/Bipartisan-Climate-Roadmap.pdf.

[11] Helm’s report was commissioned by the then Secretary of State for
Business, Energy and Industrial Strategy, Greg Clark. At the time of writing, the
government had yet to issue a substantive response to it.

[12] See https://policyexchange.org.uk/wp-content/uploads/2018/07/The-Future-of-Carbon-Pricing.pdf.

[13] Ofgem, State of the
Energy Market 2019,
page 129 (figure 5.10).

[14] See https://www.gov.uk/government/consultations/the-future-of-uk-carbon-pricing.

[15] At the time of writing, a government
response had not yet been issued in respect of the majority of this
consultation.

[16] See https://ec.europa.eu/info/strategy/priorities-2019-2024/european-green-deal_en.

[17] For commentary, see Sandbag’s report, The A-B-C of BCAs An overview of the issues around
introducing Border Carbon Adjustments in the EU. The ultimate relationship between the UK
as a whole and the EU ETS remains to be determined, but the agreement between
the UK and the EU on the UK’s withdrawal from the EU requires the EU ETS rules
to continue to be applied in Northern Ireland as part of the basis for
continuing the operation of the Single Electricity Market on the island of
Ireland. If the EU border carbon adjustment is implemented as part of the EU
ETS regime, the UK may be under pressure to adopt a similar measure.

[18] For a general survey of the distributed
ledger technology and its potential applications in the energy sector, see https://www.dentons.com/en/insights/guides-reports-and-whitepapers/2018/october/1/global-energy-game-changers-block-chain-in-the-energy-sector.

[19] See https://www.ogauthority.co.uk/news-publications/news/2019/the-oil-and-gas-authority-launches-one-of-the-largest-ever-public-data-releases/.

[20] See https://www.woodmac.com/press-releases/digitalisation-in-us-lower-48/.

[21] There are various
examples in the publication cited in note 19 above, but see also https://www.gazprom-neft.com/press-center/news/gazprom-neft-and-s7-airlines-become-the-first-companies-in-russia-to-move-to-blockchain-technology-i/.

[22] See https://www.sciencedaily.com/releases/2019/07/190711114846.htm.

[23] See https://www.climateliabilitynews.org/2019/12/23/climate-litigation-threat-financial-filings/.

On 2 March 2020, the UK Government issued a consultation on proposed changes to the contracts for difference (CfD) regime of support for renewable electricity generators. The item that attracted most attention was that onshore wind (in GB as a whole, rather than just on Scottish islands) and solar will be allowed to apply for CfDs again in 2021, but there are other points worth noting too. There are proposals to change aspects of the CfD regime relating to offshore wind and biomass conversions, as well as cross-cutting proposals (on areas including negative pricing, non-delivery incentives and “supply chain plans”) that would affect all technologies.

Offshore for net zero

The CfD regime is becoming mature. It was first consulted
on in 2010; was legislated for in 2013/2014; saw the first, “FID
enabling”, contracts awarded in 2014; and held its first auction in 2015. Already,
more than 20 projects with CfDs have been commissioned and are receiving
payments under them. They have a combined capacity of more than 4 GW. A further
10 GW is expected to be added by 2026, based on the delivery of projects that
were awarded CfDs in the first three auctions. Offshore wind is, increasingly, the
dominant technology in the CfD portfolio.

As of June 2019, the UK has a target of net zero emissions
by 2050. And before then, the government wants to achieve 30 GW (as per the
March 2019 Offshore
Wind Sector Deal), or even 40 GW (as per the December
2019 Conservative manifesto) of offshore wind capacity by 2030. The most
recent CfD auction saw just
under 5.5 GW of offshore capacity awarded CfDs for delivery between 2023 and
2025, but – assuming that this is all delivered – can such levels of
activity be sustained? Even if they are, with auctions occurring every two years
and projects bidding to deliver in five or six years’ time, it is not certain
that the higher of the two 2030 targets would be reached.

Get off the bottom and go with the float

Although the costs of offshore projects have fallen
significantly, and it has become feasible to build them much further from the
shore than was once the case, there are concerns about whether it will be
possible to fulfil the high ambitions for 2030 while relying entirely on
monopile, jacket or suction bucket foundations into which the turbine tower is
built. These “fixed bottom” arrays cannot readily be deployed in
waters more than 60 metres deep. As the industry grows, and occupies more of
the available areas of shallower water, the cumulative impact of each new
project on e.g. seabird mortality increases, potentially
posing more problems under nature conservation legislation. The Crown
Estate recently
announced a plan-level Habitats Regulations Assessment of its fourth
leasing round of sites for offshore wind development, with a view to addressing
these issues.  

So the government would like to stimulate more rapid
adoption of floating offshore wind technology. Just as the construction of
North Sea oil rigs progressed from fixed bottom to floating structures, the
expectation is that offshore wind can do the same. If it does so successfully, it
will become possible to locate turbines over a wider area. This would reduce
cumulative adverse environmental impacts and likely increase security of supply
(reducing the risk of loss of generation because the wind happens to have
slackened or stopped blowing in the areas where turbines are located). The
consultation document also suggests that floating turbines could provide clean
electricity for offshore oil and gas infrastructure. Moreover, with an eye to
export markets, at a global level, the technology will become much more useful in
markets such as Japan and California that do not have shallow coastal waters.

Floating wind can of course already apply for a CfD, but in
its current state of development, the technology is unlikely to win against
fixed bottom and the other technologies that it would compete against in the
“Pot 2” category. At present, the CfD regulations do not recognise
floating offshore wind as a separate technology. The government proposes to
change that, by introducing a new concept of a “floating offshore wind CfD
Unit” – defined as consisting entirely of floating turbines. It would then
be possible in future auctions to set a framework that effectively reserved part
of the budget to such units – or at least ensured that they were not in direct
competition with low-cost fixed bottom developments.

In a class of its own?

The government proposes to retain the current 1500 MW cap
on phased offshore wind projects, “to strike a balance between economies
of scale and facilitating new entrants to the market”. But a final notable
proposal in relation to offshore wind is that in future auctions, offshore wind
projects might only compete against each other, rather than – as previously –
against other “Pot 2” technologies such as advanced conversion
technologies, or against “Pot 1” technologies like onshore wind and
solar. Whilst it is arguable that offshore wind no longer fits the “less
established” designation of Pot 2, the very large scale of the fixed
bottom projects now coming forward does make it somewhat mismatched with other
technologies. As the consultation document notes, such a restructuring of the
Pots would require “regulatory approval”, but there is plenty of
precedent for mechanisms designed to offer support specifically to offshore
wind projects being approved under the EU state aid rules, and there is unlikely
to be any lack of competition for CfDs in an offshore-wind only category.

Meanwhile, back on dry
land…

The extent to which the fortunes of the onshore wind
industry have been restored by this consultation should not be overstated.
Previous governments took more than one decision that curbed its growth. As
well as deciding not to include onshore wind in the second and third CfD
allocation rounds (unless they were on remote Scottish islands, in the case of
the third round), and accelerating the closure of the previous subsidy regime,
the Renewables Obligation (RO see here
and here),
they adopted a planning
policy that restricted the pipeline of new consented projects in England. The
promise to include onshore wind and solar in the next allocation round, to be
held in 2021, does not change that.

However, it is still likely that a significant number of
consented sites have been “awaiting construction” primarily because
of the lack of RO or CfD support or any adequate substitute for the revenue
stability they provide. There should be plenty of competition for the next
auction in Pot 1, not least in Scotland, where there is plenty of wind and there
has been no Scottish Government policy similarly restricting the pipelines of
consented projects since the closure of the RO. The consultation notes that, although
there are unsubsidised “merchant” solar and onshore wind projects being
constructed, “there is a risk that if we were to rely on merchant
deployment of these technologies alone at this point in time, we may not see
the rate and scale of new projects needed in the near term to support
decarbonisation of the power sector and meet the net zero commitment at low
cost”.

The consultation does not suggest how much money might be
offered to the part of any future auction in which onshore wind and solar would
compete (“Pot 1”). We note, however, that there are some illustrative
figures in the accompanying impact assessment (albeit they are expressly
“not an indication of future allocation round parameters”) that seem
to envisage that in a future round where about the same amount of offshore wind
was awarded CfDs as was the case in the third allocation round (5.5 GW, with
strike prices of £45/MWh at 2012 prices), 300 and 700 MW of onshore solar and
onshore wind might be similarly successful (with strike prices of £33 and
£34/MWh). In the first CfD auction in 2015, the largest successful solar
project was 19 MW – today, the whole of a hypothetical 300 MW of solar CfD
capacity could be swallowed by a
single development.

It’s not just about the
clean energy

The consultation also focuses on the importance of renewables
projects benefiting local communities. It proposes updating existing
guidance and creating a register of projects’ community benefits. It also cites
some examples of good practice and asks for further ideas in this area.
Previously, it has proved difficult, particularly for larger commercial projects,
to deliver what might be the most obvious community benefit (cheap, clean,
locally-generated power) directly to the communities that host them, because of
the way that the GB electricity industry and its licensing and network charging
regimes are structured. But it may be that the commoditisation of battery
storage could help going forward.

A key element for CfD projects with a capacity of more
than 300 MW has been the requirement to submit a “supply chain
plan” as part of the application process. The intention has been to
ensure that the development of the renewables industry – and the offshore wind
sector in particular – delivers some benefit to the UK industrial base. The
consultation notes that Ministers can take account of an applicant’s failure to
implement a supply chain plan when considering subsequent applications. Potentially,
all partners with a 20% or greater share in a project can find themselves
excluded from an allocation round as a result. It further notes that the government
wants to ensure that the regime contributes to the Grand
Challenges of its Industrial Policy and “advances the low carbon
economy in places which stand to benefit the most by boosting productivity,
driving regional growth”. It is therefore asking how it could strengthen
the supply chain policy so as to ensure it remains “fit for purpose”.

Among the possibilities mentioned in the consultation
document are: increasing the quality of supply chain plan commitments and
closer monitoring of their implementation; extending the requirement to provide
a supply chain plan to projects below the current 300MW threshold; and “considering
the carbon intensity within supply chains and how this could be measured and/or
reported, and taken into account, as we transition to a net zero economy”.
The last of these points reflects a familiar tension between free markets /
free trade and environmental policy that the EU
Green Deal also seeks to address, and that could, potentially, be resolved
by a scheme
of carbon pricing that incorporated border adjustments on goods imported from
countries with less stringent carbon emissions regimes.

After the end of coal-fired power – the end of its
afterlife

A significant chunk of current CfD funding (as of RO
funding before it) goes to former coal-fired capacity that has been converted
to burn biomass. The CfDs awarded to biomass conversion projects have a shorter
duration than other renewable CfDs, being scheduled to end in 2027. The
government is “reviewing the role of biomass conversions and…seeks views
on the proposal to exclude new biomass conversions from future CfD allocation
rounds”. The consultation document points out that “since the government’s
2012 Bioenergy Strategy we have been clear that coal-to-biomass conversions
have been supported as a transitional, rather than long-term technology”
and that those “which are not otherwise subsidised may apply to
participate in the Capacity Market”.

What does this mean? At present, there are only five
coal-fired plants remaining in operation in the GB market. Of these, Fiddler’s
Ferry and Aberthaw B are scheduled to close by the end of March 2020. Drax
recently announced
that its remaining coal-fired units would not operate beyond 2022. The
operators of West Burton B and Ratcliffe have yet to announce plans to close
them before the government’s deadline of the end of 2025 for ceasing GB
coal-fired generation. That deadline, although confirmed
policy, has yet to be specifically enacted as legislation, although limits
imposed by EU law on the eligibility of higher emissions fossil fuel plant to
participate in capacity markets are expected to make it hard for them to
operate economically (a consultation
of July 2019 that sought to address the detail of implementing this restriction
has yet to see a government response).

Against this background, one can see why it is possible that some remaining or recently closed coal-fired plants might be interested in the prospects of biomass conversion. The attraction of biomass in the earlier phases of promoting renewable electricity generation, and particularly in the form of conversion from coal, was that it could deliver large amounts of renewable power that was not intermittent (like wind and solar) and made use of existing generation and transmission infrastructure. At the same time, there has always been a debate about how truly sustainable the burning of large amounts of solid biomass can be, particularly if it is imported from e.g. the other side of the Atlantic. Then again, if it is accepted that biomass combustion can be carbon neutral, combining it with carbon capture, use and storage (to make so-called BECCS), offers the prospect of “negative emissions”, as part of the drive to offset some of the hard-to-remove emissions that would otherwise stop us meeting the net zero target.

Since the government is considering the CfD as a mechanism for funding CCUS power projects, would it be legitimate to infer that the government does not expect future BECCS projects to be conversions of coal-fired plant? Not necessarily: the CfD legislation currently treats “biomass conversion” and “CCS” (the latter being defined without reference to the fuel that is used to power it) as distinct categories of “eligible generating station”. So it may be that excluding biomass conversions from future auctions would still leave the way open for a BECCS CfD.

Clearing the road to 2030

The government plans to hold the next allocation round in
2021 and to hold subsequent rounds every two years thereafter. In order to
further provide long-term certainty to developers investing in bringing forward
new projects and to support the level of ambition needed to meet the 2050 net
zero target, it proposes to extend the CfD legislation’s definition of
“delivery years” to go as far as 31st March 2030.

It’s never too early to think about decommissioning

There are already almost 2,000 offshore wind turbines in
the sea around the UK. Decommissioning costs for those in operation or
construction in 2017 alone has been estimated at £1.28bn-£3.64bn (in 2017
prices). Against this background the government wants “to ensure
developers give appropriate consideration to decommissioning during the
development stage”, so as to minimise the risk to taxpayers of the government
having to act as decommissioner of last resort, and it is considering “whether
it would be appropriate to include specific decommissioning obligations in the
CfD regime”.

Administrative strike prices

The government is considering changing the method that it
uses to calculate the administrative strike prices that function as
“reserve prices” in CfD auctions. The current method produces administrative
strike prices that are too far adrift from auction bids for some technologies.

Never mind the carrot, is the stick big enough?

The government is considering sharpening the incentives to
deliver CfD projects, and do so on time. It is concerned that as “prices
come down and the greater benefit of CfDs shifts from providing subsidy towards
offering the support for successful applicants to secure finance for their
projects, there may be an increasing risk that a generator does not proceed to
deliver on its contract but considers it preferable to deliver on a merchant or
other basis”. This, the government says, would be unfair on other
generators who might have wanted to make use of the CfD support if they had had
the opportunity. It proposes to extend by three years the period during which
the site of a project that has allowed its CfD to lapse or had it terminated is
“sterilised” for the purposes of a further auction.

Consultees are invited to suggest other potential
mechanisms to guard against non-delivery. One model that is mentioned is that
of bid bonds such as are used in the Capacity Market (applicants pay an amount
based on the project’s capacity, to be forfeited if it is not delivered under
the CfD regime).

Negative pricing

One of the things that has changed over the last five
years is the extent to which increasing amounts of intermittent renewable
capacity is driving – and is, in the future, expected to drive – negative
pricing in wholesale electricity markets. In 2015, the government thought that
this might happen 0.5% of the time in 2035. With 30 GW or more of offshore
wind, it now thinks it could happen 4.5% of the time.

As part of its clearance of the CfD regime under the state
aid rules, the European Commission required that support should be capped at
the level of the strike price in periods of negative pricing, and that if these
persist for six hours or more, “the difference amount under the CFD
Contract will be set to zero for the entirety of that period”. The
government would now like to remove any incentive on CfD generators to generate
when there is oversupply in the market. It therefore proposes to “extend
the existing negative pricing rule so that difference payments are not paid to
CfD generators when the Intermittent Market Reference Price is negative”.

What else is in store?

One of the ways that CfD generators might, at least
hypothetically, wish to mitigate the risks associated with periods of negative
pricing – and one of the ways in which they might be able to play a part in
restricting the incidence of such periods – would be if they could generate,
but not immediately export (or be treated as having exported) their power, by
making use of storage facilities. Storage is, more generally, as the
consultation document acknowledges, “a means to mitigate some of the
potential negative impacts of intermittent renewable generation on the system”.

The government therefore asks three quite open-ended
questions: “What storage solutions could generators wish to co-locate with
CfD projects over the lifetime of the CfD contract? What, if any, barriers are
there to co-location of electricity storage with CfD projects? What, if
anything, could be changed in the CfD scheme to facilitate the colocation of
storage with CfD projects?”.

Co-location of storage with renewables projects already
takes place in the GB market. Some large wind projects (onshore and offshore) have
relatively small associated small storage facilities. Some smaller projects
such as solar farms have proportionately larger amounts of associated battery
capacity. Their storage facilities can enable these projects to earn
supplementary revenues in the ancillary services markets or the Capacity Market,
and help to optimise their assets in other ways.

What is arguably missing are incentives for the
development of much larger scale facilities that could be capable of absorbing,
for example, a significant proportion of several windy nights’ worth of
offshore wind generation for which there is no immediate demand. Also useful,
perhaps, would be incentives to develop commercial scale electrolysis
facilities into which surplus power could be diverted for conversion into
“green” hydrogen that could be substituted for hydrocarbons in power,
heat or transport applications. But whether the CfD regime would be a suitable
vehicle for such incentives (and, if so how it would need to be adapted to provide
them), is another question.  

Conclusion

The two most prominent pillars of GB’s early 2010s Electricity
Market Reform regime, CfDs and the Capacity Market, are now established
features of the landscape. The present CfD consultation, and the recent five
year review of the Capacity Market, appear to confirm that no fundamental
changes to or replacement of either regime (such as was proposed
by Dieter Helm) is planned – although it should be noted that the
consultation on effectively
replacing CfDs as the subsidy route for new nuclear projects, which would
be a significant change to the EMR vision, has yet to be responded to by
government (nuclear goes essentially unmentioned in the present consultation
document).

At the same time, there is a recognition that – like any
element in the complex ecosystem of energy regulation – the performance of the
CfD regime needs constant monitoring, and there is a willingness to consider
potential improvements. As the regime enters its second decade (counting from
the first consultation) or its second five years (counting from the first
auction), this is not a bad place to be.

The consequences of the COVID-19 outbreak for the energy sector have been wide reaching, with issues such as workers self-isolating, rig closures and disrupted supply chains. Several oil and gas companies have become increasingly concerned that this will result in an inability to fulfil their contractual obligations, causing a surge of enquires related to invoking the “force majeure” provision of contracts. As force majeure is a contractual concept under English law (though not under certain civil law regimes), each case has to be regarded on its own individual merits.

In practice, force majeure clauses may have a variety of forms, some of which are further detailed below, but the overarching principle is that an unprecedented event has occurred, which prevents a party from actually performing its contractual obligations (rather than it is more expensive to do so) and typically that force majeure event is the sole cause of the party’s inability to perform. This may clearly be more of an issue where performance is also influenced by the recent crash in the oil price (which would not qualify as force majeure). In addition, the party relying on force majeure would usually have to take steps to mitigate the effects of a force majeure event – the spread of COVID-19, or government announcements regarding the risks, do not in themselves constitute force majeure.

Current events are particularly notable when contrasted against the Ebola outbreak of 2014 where the government controls were similar (and potentially qualified as a change in law causing force majeure) but the impact was much more localised, allowing greater opportunities for international companies in particular to withdraw employees or otherwise mitigate the effects of force majeure.

Force majeure is distinguished from the English common law doctrine of frustration, which requires a more stringent standard of proof to be met, with the requirement being it has become impossible to perform the contract, rather than merely more difficult. For this reason, it is often more feasible to invoke a force majeure provision, provided that the contract allows for it.

There are four considerations to be made when attempting to rely upon a force majeure clause:

• Are there specific references to “epidemic,” “pandemic,” “acts of God” or “acts of government” in the definition of force majeure event?
• What are the conditions that must be met in order to invoke the clause?
• What would the contractual consequences be if the clause were to be invoked? This could include termination of contract, suspension of particular contractual obligations (e.g. take-or-pay liabilities), extensions of time or allocation of losses.
• Is there any interaction with mandatory local law? It is vital to ensure that enforcing any force majeure provisions would not contravene any legislation in the jurisdiction in which the contract is based.

The table below sets out some of the different applications of force majeure in oil and gas industry standard contracts, varying from the “exhaustive list” approach of LOGIC contracts, to the somewhat more restrictive approach of the AIPN JOA, which covers only “lockouts, and other industrial disturbances.”

Force majeure and COVID-19 in various oil and gas industry standard agreements

Next steps

Given the widespread effects of COVID-19, it is important to clarify whether force majeure is applicable in your contracts and to consider an appropriate legal strategy early. Incorrectly invoking force majeure may itself amount to a repudiatory breach and there might be better contractual ways to deal with the current disruption to your operations. If you are currently negotiating a new contract, or conducting due diligence, you should review carefully any proposed force majeure clause and other contractual terms to consider if risks in respect of COVID-19 are appropriately addressed.

If you have any concerns in relation to your oil and gas contracts or require specific assistance with any of the points noted above, please contact a member of the Dentons Energy team.