The summer witnessed several significant developments in the renewables sector. In a blow to the government’s decarbonisation policy, and despite the August announcement increasing the budget for the Contract for Difference (CfD) support scheme Allocation Round 5 (AR5) by £22 million to total £227 million, inflationary pressures meant that no offshore wind projects (fixed or floating) participated in the round. However, the excess budget due to the absence of offshore wind bids in the established technology auction pot instead resulted in the success of a significant amount of solar PV (over 1.9 GW) and onshore wind (over 1.7 GW) projects.
With the focus on the cost of “green levies”, the government also took the opportunity to review its previous renewables support scheme, the Renewables Obligation (RO), which is now closed to new applications. The RO places an obligation on electricity suppliers who must procure a certain number of RO certificates (ROCs) annually or pay a “buy-out price”. ROCs are issued to RO accredited generators of renewable electricity and so the sale of these to obligated suppliers or in the market provides additional revenue to generators, in addition to the power price. However, supplier insolvencies resulted in some suppliers not meeting their obligations, leading to a funding shortfall which was mutualised between the remaining suppliers and ultimately recovered from consumers. To protect RO funds, the energy regulator Ofgem published guidance requiring that, from the next compliance year, suppliers in Great Britain will be required to either hold ROCs or to ringfence RO receipts in one or more RO Credit Cover Mechanisms on a quarterly basis. The change is anticipated to impact suppliers’ working capital. Separately, on 31 July, the Department for Energy Security and Net Zero (DESNZ) opened a call for evidence on Introducing Fixed Price Certificates (FPCs) to reduce ROC price volatility for stakeholders. It seeks input, in particular, on potential FPC models and pricing arrangements. The consultation is an important market development. The move to FPCs may reduce the price of certificates and therefore the revenue generators receive, as the government is considering changes to indexation (moving from RPI to CPI) and to the so-called “headroom” arrangements which currently ensure a shortfall of ROCs, underpinning demand and their price in the market. Depending on the government’s selected option, there may be implications for existing power purchase and ROC trading arrangements, as well as potential implications under generator financing arrangements.
Looking at wind power specifically, new tendering rules have been announced by The Crown Estate for Offshore Wind Leasing Round 5 for new floating offshore wind projects in the Celtic Sea. These include requirements for bidders to demonstrate social and environmental value, and how they will integrate ports into the deployment of turbines. The auction design has also been changed to an “ascending clock” model for increased transparency around other bids. The formal launch of Round 5 is expected later this year.
Planning reform has also been high on the agenda over the summer. In July, the Department for Levelling Up, Housing and Communities (DLUHC) launched an "overhaul of planning" to speed up project delivery with a consultation on reform to the Nationally Significant Infrastructure Projects (NSIP) to make the consenting process "faster, greener, and more resilient by 2025". Proposals include a new fast-track route to consent and strengthening the role of local communities as “key consultees”.
Significantly, after much speculation regarding its onshore wind policy, on 5 September the government confirmed that it intends to amend planning rules to “speed up” approval for onshore wind projects if they can demonstrate local community support. The National Planning Policy Framework has been updated accordingly and in the autumn, the government is expected to publish its response to the DESNZ consultation on best practice for developer-community engagement and how to “broaden benefits packages for areas that agree to have local onshore wind farms”. For example, revised packages might include energy bill discounts or funding for facilities such as EV charging points.
Finally, biomass as an important source of renewable energy and sustainable products remains in the spotlight with DESNZ’s publication of its Biomass Strategy 2023 policy paper. The paper sets out government plans to prioritise use of wastes and residues (in ways that do not conflict with other land uses), biomass with carbon capture and storage (BECCS) (see further below), and establish “clear, enforceable and transparent sustainability criteria”. The strategy also focuses on how to maintain both domestic and imported biomass supply as projected demand grows. The government confirms that it will consult on how to ensure that biomass is sourced sustainably and with appropriate certification, avoiding significant negative impacts on forest carbon stocks. It further aims to minimise carbon and supply chain greenhouse gas emissions, and ensure those emissions are adequately accounted for and independently verified.
In July, the government launched its new flagship body, Great British Nuclear (GBN), which it has tasked with delivering its long-term nuclear programme and the ambition to deliver up to 24GW of nuclear power by 2050. As a first priority, GBN is administering a competitive process for selecting small modular reactor (SMR) technologies to receive government support, with a view to enabling Final Investment Decisions (FID) for those technologies by 2029. This competitive technology selection process was launched in mid-July and the deadline for interested parties to submit a selection questionnaire passed on 23 August 2023. As a next step, GBN will continue with the “down-selection phase”, due to be completed by Autumn 2023, in which it will select technologies meeting the eligibility criteria to proceed on to the “invitation to negotiate phase”.
Separately, the government released additional tranches of previously allocated funding to accelerate preparations for the construction of the new Sizewell C nuclear power plant in Suffolk. Seeking to reassure private investors of its commitment to the project and the wider nuclear industry, the government made £170 million available in August, along with a further £341 million, noting that the injection of funds “bolstered” its pledge to reach FID this Parliament. Taken together with the Regulated Asset Base finance model, which launched in late 2022, the government suggested this funding would also “help attract potential private investment into new nuclear projects”.
3. Energy Markets
DESNZ published several significant policy announcements relevant to retail and wholesale electricity markets over the summer. Following an unprecedented number of suppliers exiting the market in 2021 and 2022 which cost consumers over £5 billion, retail market reform has been a priority for government. July saw the publication of a policy paper, Delivering a Better Energy Retail Market which reiterated the need for targeted reforms (rather than an overhaul of the regulatory framework). The paper foreshadows, amongst other things, a consultation on the future of the default tariff cap and measures to encourage innovation in retail energy products, with a consultation on options for reform expected later this year. Accompanying this policy paper, the government published:
- a Call for evidence on a more innovative retail market to consider barriers to innovation, with a commitment to follow up with policy proposals for consultation later in 2023;
- a Call for evidence on domestic consumers with non-domestic energy supply contracts;
- a Response to a Call for evidence on third party intermediaries, with further consultation likely later this year;
- a Response to Call for evidence on the transparency of carbon content in energy products considered responses to questions on the “green tariffs” framework. This will be taken forward under the Call for evidence on a more innovative retail market (mentioned above) or under the Review of Electricity Market Arrangements (REMA) programme. A broader review of the Renewable Energy Guarantee of Origin Scheme is also underway;
- a Response to Call for evidence on electricity licence exemptions (albeit three years after the original call was published). A key question posed by the consultation was whether licence exempt generators and suppliers contribute a fair share of policy and network costs. These costs are generally levied on licensed entities and so avoidance of these has benefited the economics of on-site and private wire schemes. Whilst no concrete next steps were outlined in the response, this issue may be revisited as part of the government’s wider objective to “rebalance” costs as between electricity and gas bills.
In addition, Ofgem, published a Call for input into the development of a competition framework for the domestic retail market, seeking views on how it defines and measures a competitive energy (electricity and gas) retail market. Recognising that achieving net zero will require greater consumer participation in demand-side flexibility (also called demand-side response or DSR), in August, it published a Call for input on engaging domestic consumers in energy flexibility. Separately, Ofgem and the government also launched a consultation on a new regulatory framework for heat networks, focusing on consumer protection measures in particular and with the aim of ensuring consumers receive comparable standards to those in the gas and electricity sector.
In July, following consultations on strengthening financial resilience in the retail market, the regulator published its Decision on introducing a minimum capital requirement and ringfencing customer credit balances applicable to domestic energy suppliers. This includes a decision to introduce a common minimum capital floor of £0 adjusted net assets per dual fuel customer equivalent and a capital target of £115 per domestic dual fuel equivalent customer from 31 March 2025, supported by a capitalisation plan framework. It will also modify the licence so that Ofgem can direct suppliers to ringfence customer credit balances when in the customer interest.
In relation to trading over electricity interconnectors, the consultation response on trading arrangements in the GB wholesale electricity market proposed reintroducing a single GB clearing price in the day-ahead timeframe in order to support more efficient trade over electricity interconnectors. The government determined this policy would enable the development of new cross-border arrangements envisaged under the EU-UK Trade and Cooperation Agreement (TCA) and multi-region loose volume coupling. This is however subject to the approval of the Specialised Committee on Energy, which was established under the TCA. We anticipate further consultations in relation to wholesale markets, with a further consultation by the government expected in the autumn as part of its REMA programme.
4. Energy networks
As the government aims to completely decarbonise the electricity sector by 2035, the issue of connections and grid capacity has continued to climb up the energy agenda, with developers of clean energy projects complaining of lengthy (and costly) delays as they wait for grid connections. In August, DESNZ published a report by Electricity Networks Commissioner (ENC) Nick Winser, which focused on accelerating the delivery of transmission infrastructure. More than 230GW of generation projects are said to be in the connection queue compared to 80GW of generation currently in the grid, resulting in renewable energy developers and other network customers receiving connection offers for the 2030s, slowing the energy transition. Recommendations include streamlining the planning processes to “fast track” strategic grid projects, assessing the scope for new short-term and long-term regional flexibility markets, and tasking the new Future Systems Operator (currently the subject of a second consultation and due to launch in 2024) with forecasting likely energy supply and demand, thereby anticipating what, and where, cabling will be required. Following a review of the report, the then Secretary of State, Grant Shapps, highlighted in his letter the government’s intention to publish a Connections Action Plan later this year, providing more detail on existing initiatives along with the ENC’s longer-term recommendations.
The imperatives set out in the ENC report appear very much in sync with those driving other key stakeholders over the summer. In June, the National Grid Energy Systems Operator launched a Connections Reform consultation regarding design options for a “new agile, future-proofed connection process”. It also introduced a set of targeted reforms to “speed up connections to the electricity grid”, and will now demote generators in the queue if they fail to hit project milestones, making way for those ready to connect. Ofgem, too, has focused considerable attention on network issues, launching a policy review in May “to speed up low-carbon energy schemes connecting to the electricity transmission grid”. In July, it shortlisted four potential operators bidding for three links in its “biggest ever” Offshore Transmission Tender Round (valued at £2bn), noting that “the next two years will see a surge in Offshore Transmission Operators coming to market” as the government seeks to boost offshore wind capacity. At the same time, DESNZ published its response to the Offshore Transmission Network Review and began working with Ofgem on a proposed Regulatory Framework for multi-purpose interconnectors. The operation of these subsea electricity cables linking offshore generation to the UK shore, and the UK to neighbouring markets, will soon become a licensable activity (once the Energy Bill 2022/23 is enacted).
Away from electricity, Ofgem has also approved £95.3 million investment in 10 innovative “demonstrator” projects focused on energy networks. The funding includes £33m for work led by National Gas Transmission to adapt existing gas compression units to enable hydrogen to be fed into the UK’s National Transmission System. Whilst it remains unclear to what extent, and how quickly, the gas networks sector will need to adapt to the reduced use of natural gas to align with net zero targets, in July Ofgem announced that it has decided to develop a “medium term ex-ante framework” for gas network price control, starting in 2026. However, Ofgem did seek to reassure gas network companies that the design of the new medium-term price control will be broadly comparable to the existing control known as RIIO-2, and that companies should continue to develop cost forecasts as required under the existing gas price controls.
Important progress was made over the summer in relation to low carbon hydrogen production, transportation networks and storage.
With regard to production, following a lengthy engagement process with industry, the government published the terms of the Low Carbon Hydrogen Agreement (LCHA), the contract under which hydrogen producers will receive revenue support for both CCS-enabled and electrolytic hydrogen volumes. Some concessions were made as compared with the positions published previously and industry will be examining these closely as projects move towards FID.
In parallel, projects are moving forward in the allocation processes for the entry into LCHAs. In particular, on 16 August, DESNZ shortlisted 17 projects totalling 262 MWs to move forward to negotiations for support under the Hydrogen Business Model/Net Zero Hydrogen Fund in the first electrolytic hydrogen production allocation round (HAR1). Negotiations will now commence with successful projects to be announced in Q4 2023.
The next electrolytic allocation round (HAR2) is also expected to launch in Q4 2023, targeting the award of contracts of up to 750MW in capacity by early 2025, although no further update on the structure of this has yet been issued following a Market Engagement exercise in May. Notably, HAR2 may encompass other non-CCS enabled production technologies such as advanced gasification of biomass and/or waste and pyrolysis to hydrogen and solid carbon technologies, subject to meeting the requisite Technology Readiness Levels. Together HAR1 and HAR2 are expected to deliver the government’s ambition of up to 1GW of electrolytic hydrogen production capacity in construction or operation by 2025.
The government is also seeking evidence on the transition to price-based competitive allocation for LCHAs in the mid-2020s for specified non-CCS hydrogen production technologies, as soon as legislation and market conditions allow.
In relation to hydrogen transportation and storage, DESNZ published two documents outlining its response to the 2022 consultation and the government’s minded-to positions; an important step towards putting the business models in place by 2025. The minded to high-level design for the onshore hydrogen transport business model is a Regulated Asset Base under the existing Gas Act 1986 gas transporter licence alongside a new, external subsidy mechanism in the form of private law revenue support contracts, to top up any shortfalls in revenues. In relation to the hydrogen storage business model design, the government proposes a 15-year private law contract providing a revenue “floor” to mitigate demand risk for storage providers, an incentive to maximise sales to users and a mechanism to give the subsidy provider a potential share of the “upside”. It anticipates the initial focus for support to be geological storage, though it is “minded to retain optionality to support above-ground storage where it faces similar market barriers.”
These documents also highlight the need for a strategic planning function and envisage a role for the Future System Operator in the medium-term, but in the short term, government will publish a “hydrogen networks pathway” in Q4.
In addition, a further consultation on blending hydrogen into the natural gas distribution network is expected shortly, to enable a decision to be taken before year.
Finally, to close a gap in the UK’s regulatory framework for offshore hydrogen pipelines and storage, the government published its response to the Offshore Hydrogen Regulation Consultation in early September. Secondary legislation will be introduced this autumn to extend the existing offshore regime under the Petroleum Act 1998 (for pipelines) and the Energy Act 2008 (for storage) to hydrogen, making the North Sea Transition Authority the relevant consenting authority and bringing this infrastructure within scope of the UK’s existing environmental legislation.
Separately, following comments over the summer by former Energy and Net Zero Secretary Grant Shapps that the funding mechanism for the hydrogen business models should not “see people’s household bills unnecessarily bashed”, in early September the government was successful in passing an amendment to the Energy Bill which provides powers to introduce a levy via secondary legislation on gas shippers (and not directly on gas and electricity consumers). We expect that the government will launch a consultation on the new hydrogen funding mechanism once the Energy Bill is enacted to determine whether this power should be exercised and, if so, how the funding mechanism might be structured.
 This figure was adjusted following the withdrawal of 3 projects: Gigastack, Dolphyn and Quill 2.
6. Carbon Capture and storage
The summer months saw updates on the CO2 transport and storage (T&S) business model and on the Track-2 CCUS Cluster Sequencing process to identify two further CO2 T&S networks for delivery by 2030 (Track-2), as well as a consultation in relation to exemptions from the requirement to hold an economic licence, and numerous commercial reports on the sector.
In June, DESNZ set out its updated proposals for the business model for carbon dioxide T&S, adding further detail on the structure and terms of the licence for CO2 T&S, plus additional information on the government support package and revenue support agreement. At the same time, DESNZ updated its response to the August 2021 consultation on plans to establish a decommissioning regime for CO2 T&S networks. Building on its original response, the department provided clarification on a number of issues, including the methodology for calculating the decommissioning estimate.
In an update to industry on the Track-2 cluster sequencing process published by DESNZ at the end of July, it was confirmed that the Acorn and Viking T&S systems continued to be best placed to meet the government’s eligibility criteria. Both projects will now each proceed to the next stages of the assessment process, with a view to each project forming a CCUS cluster. However, the government has reserved the right to re-engage with other T&S systems that submitted an expression of interest for Track-2, if “significant delivery challenges arise” with either the Acorn or Viking T&S systems.
July also saw the publication of reports commissioned and published by DESNZ on the UK’s industrial CCUS supply chain capabilities and opportunities for economic growth in the UK’s CCUS industry.
Finally, in mid-August, DESNZ launched a call for evidence to inform its policy and proposals relating to regulations on exemptions to be granted from the requirement to hold a CO2 T&S economic licence. The call for evidence will close on 11 October 2023.
7. Greenhouse gas removals (GRRs) and Bioenergy with Carbon Capture and Storage (BECCS)
The government continues to give engineered GGRs and BECCS technologies significant prominence in the UK’s path to net zero. Its response to the GGR Business Model Consultation, published the end of June, is arguably the world’s most detailed GGR market development and subsidy policy. The government identifies a Negative Emissions CfD model as its optimal policy to support a diverse range of GGR technologies in the UK, including Direct Air Carbon Capture and Storage (DACCS) and BECCS. Its response further recognises the need to standardise monitoring, reporting and verification of GGRs, as well as develop CO2 T&S infrastructure. Aligned with widespread industry support, the government will also consider options to build a compliance market for negative emissions, such as by integrating GGRs into the UK Emission Trading Scheme (ETS).
Well-regulated BECCS projects can provide additional sources of genuine GGRs, low-carbon energy, and other sustainable products. The government indicates in its Biomass Strategy, which it published in August, that there are no “insurmountable scientific barriers to the net removal of CO2 from the atmosphere and subsequent permanent geological storage via BECCS”. Indeed, a large proportion of the government’s ambition to generate at least 5 MtCO2 per year of GGRs by 2030 will come from BECCS projects. Its Biomass Strategy estimates that the carbon removal efficiency of power BECCS could be between 65-85%, after accounting for supply chain emissions and carbon losses that are not captured by living matter.
The government is still developing a dual CfD support mechanism for BECCS projects—comprised of both a CfDe (which values the electricity generated) and a CfDc (which values the carbon stored and associated negative emissions)—in addition to a contract-based business model for the wider GGR sector. It states that it will only support BECCS systems that deliver net GGRs, based on full life-cycle assessments (irrespective of where those emissions occur in the supply chain). Ideally, the government indicates that BECCS projects should provide valuable, low-carbon co-products or services alongside GGRs. It may also consider prioritising other uses of BECCS technologies, such as hydrogen BECCS or biokerosene BECCS for use as sustainable aviation fuels.
8. UK Emissions Trading Scheme
The UK ETS Authority (the Authority) proposed several changes to UK ETS in July 2023, as part of its response to the Developing the UK ETS Consultation that closed in June 2022. Firstly, it is intended that the UK ETS cap be lowered to align with the UK’s net zero target. This corresponds to between 887 and 997 million allowances in the period to 2030 (a reduction of around 30-35% from the UK’s current legislated cap of 1365 million allowances). Beginning from 2024, annual caps will become progressively tighter until they reach 50 million allowances in 2030. The Authority plans to release 53.5 million additional allowances—between 2024 and 2027—from reserve pots into the market to ensure a smooth transition toward the net zero cap. We expect this release will, in turn, partially counteract higher UK allowances prices over the period.
Secondly, the Authority will set the Industry Cap at 40% of the overall cap (3% above the current Industry Cap). This higher limit on the quantity of free UK allowances will shield sectors most at risk of carbon leakage. However, it will lower average UK allowance prices, compared with carbon prices in the EU and parts of the US. These lower carbon prices may reduce the attractiveness to invest in UK energy transition or CCUS projects, compared to EU or US projects. Notwithstanding this, the Authority intends to phase out distribution of free allowances to aviation operators—and transitioning to full auctioning in 2026—because it deems the aviation sector’s exposure to carbon leakage as minimal. While it develops proposals on how the UK ETS should treat use of SAFs, those fuels will continue to be zero rated under the UK ETS.
Thirdly, the Authority gradually plans to extend the UK ETS to cover additional sectors. This includes domestic shipping from 2026, energy from waste (EfW) and waste incineration sectors from 2028 (but progressively phased in from 2026), and CO2 venting emissions from upstream oil and gas activities from 2025. The Authority will explore and implement appropriate MRV standards for these expanded sectors. It also intends to expand the UK ETS to recognise non-pipeline transport of CO2, including by ship, rail, and road. This recognition aims to enable UK ETS operators to use non-pipeline transport for CO2 storage purposes to mitigate UK ETS liabilities. The UK government’s recent provisional application of the London Protocol also removes an additional regulatory barrier to cross-border transfers of CO2.
Fourth, the Authority considers integrating GGRs into the UK ETS as a suitable long-term objective. Subject to further consultation, as described above, the Authority also intends to include engineered GGRs in the UK ETS. It will consult further this year on how to appropriately design the market to accommodate engineered and nature-based GGRs, as well as appropriate eligibility requirements, and the timing for such integration. With these proposed changes, a key concern is ensuring sufficient regulatory alignment with the EU ETS to facilitate future linking.
9. Voluntary carbon markets
Simultaneously, voluntary carbon markets (VCMs)—in which companies and other private actors trade carbon credits on a voluntary basis—are playing expansive roles to promote liquid and scalable investment in emissions reductions. Governance infrastructure—designed to establish demand and supply-side integrity standards—is ratcheting ambition and investor confidence in VCMs. For example, in June, the Voluntary Carbon Markets Initiative (VCMI) published its Claims Code of Practice for companies to use carbon credits and make credible net zero claims. Its three tiers of claims—Platinum, Gold, and Silver—recognise investments in emissions reductions beyond those necessary to meet science-aligned net zero targets. In July, the Integrity Council for the Voluntary Carbon Market (ICVCM) also published its full Assessment Framework criteria for high-integrity carbon credits. Programmes complying with the ICVCM’s Core Carbon Principles (CCPs) can use the CCP-Eligible label on specific categories of credits approved as meeting the CCPs.
10. Oil & Gas
In July, the Prime Minister confirmed government plans to grant “hundreds” of new UK oil and gas licenses. He argued that continuing to leverage North Sea fossil fuel will help secure the government’s strategic objective to make Britain more “energy independent” and “reduce reliance on hostile states”. The licensing process, overseen by the North Sea Transition Authority (NSTA), will involve a climate compatibility test, but also give operators more flexibility to apply for new licences close to areas where drilling is already permitted. In the government’s view, this added flexibility could unlock “vital reserves which can be brought online faster due to existing infrastructure and previous relevant assessments”. The NSTA is currently continuing the 33rd offshore oil and gas licensing round, with the first new licences expected to be awarded in autumn.
In addition, it also launched a call for evidence inviting views on the appropriateness of the oil and gas sector’s taxation regime. Specific input is sought on current measures such as the Petroleum Revenue Tax, Ring Fence Corporation Tax, and Supplementary Charge. With existing North Sea oil and gas assets approaching end of life, the call for evidence also requests views on fiscal barriers to the “repurposing of assets for the deployment of lower carbon technologies”, including hydrogen, offshore renewables, and CCUS.
Also in July, the government announced a further consultation on the technical details and practical application of the Energy Profits Levy (EPL) Energy Security Investment Mechanism (ESIM). The government confirmed its plans to permanently disapply the EPL if average oil and gas prices are both at, or below, the ESIM price threshold for two consecutive quarters. Through this consultation, the government endeavours to understand the appropriateness of its approach to calculating the reference price, the frequency with which the ESIM is triggered, and the optimal approach to phasing out EPL.
11. Sustainable Fuels: Aviation & Shipping
With demand for international travel returning to pre-Covid levels, in July the government used its Jet Zero: One Year On policy paper to restate its commitment to decarbonise the UK aviation sector and deliver Net Zero emissions by 2050. Building a UK Sustainable Aviation Fuel (SAF) industry remains central to that ambition, and positive steps in this direction include a second application round of the £165m Advanced Fuels Fund for the construction of five SAF plants by 2025, and plans for the UK’s first SAF Clearing House to be launched later in 2023 to coordinate testing and certification of SAFs.
However, the government has also acknowledged that proper support mechanisms are necessary if a successful UK SAF market is to develop. It has now pledged to design and implement a revenue certainty mechanism for new SAF production facilities by 2026. Proposing that the mechanism be funded by industry, a consultation is due to be launched in the first half of 2024. At the same time, government is currently considering responses to a second consultation on a proposed SAF mandate which would require jet fuel suppliers to blend SAF into aviation fuel from 2025, achieving at least 10% SAF in the total aviation fuel mix by 2030. It is expected to share its views on the mandate by the end of this year, along with details of the scheme design and specific SAF targets. Initial targets will need to be realistic—trade association Fuels Industry UK has cautioned that any mandate above 0.5% as a proportion of jet fuel in 2025 would be “unattainable”. In addition, the sector will be hoping for clarity on which feedstocks will be prioritised.
The maritime industry, too, has seen some movement over the summer with the government issuing its response to a Transport Committee report calling for a more coordinated policy framework to drive decarbonisation of shipping. Agreeing that more needs to be done to accelerate progress, in June the government established a new Maritime Council and underlined its intention to deliver an updated and “action-focused” Clean Maritime Plan by the end of 2023 with indicative targets and a “roadmap to zero greenhouse gas emissions by 2050.” That plan will be informed by the 2022 Domestic Maritime Decarbonisation consultation. The government published responses in July, noting significant industry support for “alternative fuels as the best way to reduce emissions”, and hydrogen and ammonia fuels in particular.
Rapidly evolving policy environments inevitably bring risks as well as opportunities. Whilst significant political and economic uncertainties may persist until the next general election, some green shoots are apparent. Inflation is predicted to fall markedly by the end of the year, and earlier this month the Office of National Statistics revised UK GDP upwards by almost 2%, suggesting a faster economic recovery from the Covid pandemic—and stronger UK economic outlook—than previously anticipated.
At the same time, the drive towards net zero is galvanising. This is fundamentally reshaping the global energy sector as decarbonisation policies around the world develop at an unprecedented rate. The UK has traditionally been a leader in this field, having decarbonised its economy more rapidly than any other G20 country. It was also the first major economy to legislate net zero targets by 2050 and remains the world’s largest producer of offshore wind energy. In addition, the UK possesses significant expertise and institutional knowledge in other forms of low-carbon energy, infrastructure, and green finance.
Together, these factors signal that investment prospects in the UK energy sector remain positive overall. The policies and regulatory changes announced over the summer will require further scrutiny. However, they do offer some cause for optimism that the UK remains committed to a more secure, affordable, and decarbonised UK energy sector.