Is your supply exempt – Any supply from renewable sources is automatically exempt from CCL, as is domestic or charitable non-business use. If your organisation is defined as an energy intensive user or a horticulture user, your supply may qualify for partial exemption. The Climate Change Levy (CCL) exemption schemes for renewables and combined heat and power (CHP) are closed. Levy exemption certificates (LECs), which were issued under these schemes, were only issued to electricity generated from CHP generators before 1 April 2013 and renewables generators before 1 August 2015. Transitional arrangements were in place until 1 April 2018 for a supplier to use these LECs to evidence the exemption. Ofgem was responsible for administering the CCL exemptions for renewables and CHP in Great Britain on behalf of HM Revenue and Customs (HMRC) through a certification scheme. Under this scheme Ofgem issued LECs to eligible generators which were ultimately passed through to suppliers as the evidence needed to demonstrate to HMRC that electricity supplied to UK business customers is CCL exempt. It was then the final recipient of electricity supplied that could benefit from the tax exemption. More information on the Climate Change Levy can be found on the HMRC website As the UK pursues a goal of “Net Zero” greenhouse gas emissions by 2050, the UK’s Oil and Gas Authority (OGA) has been focusing on “integrating” the North Sea’s established oil and gas industry with its rapidly growing offshore wind sector and nascent carbon capture and storage (CCS) and hydrogen projects. Recent publications have given this process added impetus. In this article, we look at the prospects for synergies between the upstream industry and renewables. Context On 6 May 2020, the OGA published a consultation on proposed revisions to its Strategy. In previous articles we have reviewed the consultation and the proposed changes as a whole (see The OGA in Energy Transition: UK aims for upstream oil and gas regulation in line with “net zero” goals), explored the general themes of CCS, hydrogen, repurposing of upstream assets, platform electrification, gas-to-wire and offshore wind (see Evolution of Oil & Gas: The OGA’s Net Zero Goals), and looked in more detail at the subject of CCS from an upstream perspective (see The OGA’s Net Zero Goals: in-depth view of CCS and the upstream industry). The OGA’s consultation proposed that the Strategy’s Central Obligation of maximising the economic recovery of petroleum should remain the same, but with an additional limb (b) which would require relevant persons to assist the Secretary of State in meeting the Net Zero Target. The consultation document comments that this new limb is based on the idea that “relevant persons” (i.e. the industry) are “uniquely” placed to assist with reducing emissions and supporting projects in the transition to a low carbon economy. The consultation highlights platform electrification as one way that the industry can do this. The term “electrification” in this context is slightly misleading, in the sense that platforms are already powered by electricity. What is being referred to here is moving to a position where that electricity, rather than being produced by high carbon, on-platform generating equipment, is supplied from lower carbon sources – notably onshore or offshore renewable electricity generators. On 16 June 2020, about halfway through the period when the OGA’s Strategy proposals were out to consultation, Oil and Gas UK (OGUK) published a report entitled The Pathway to Net Zero: Production Emissions Targets. This notes that upstream emissions account for 4% of UK greenhouse gas emissions and that the bulk of those emissions come from offshore power generation. It also highlights the potential for full or partial electrification of offshore assets, localised CCS on individual assets, integration of offshore hubs, and electrification of onshore terminals and processing plants. The report’s focus on collective innovation and coordinated effort between industry and government is consistent with the OGA’s proposals in its consultation. About a week after the Strategy consultation concluded, the OGA published its UKCS Energy Integration: Final Report (6 August 2020) (Final Report). For the purposes of this article, the key headlines in the Final Report are:

• “Offshore O&G installations emit ~10MtCO2 e p.a. to generate power (~10% of the UK total energy supply emissions). Platform electrification will be key to cutting upstream O&G emissions, and to the industry’s social licence to operate. Offshore electrification may unlock the faster growth of renewables, expansion of offshore transmission infrastructure, and establishment of floating windpower technologies in the UK, contributing to offshore renewables’ 75GW capacity ambition by 2050.”

This is a bold vision, and its achievability depends on many factors. Here, we focus on some of the potential barriers to such integration from an energy lawyer’s perspective. Platform electrification By far the most prominent technological focus of the proposed changes to the Strategy is on carbon capture and storage (CCS) – no doubt, in part, because it has been identified as a key and as yet under-developed element of decarbonisation of the wider economy in which upstream assets have a central role to play as CO2 stores. CCS also features more prominently in the Final Report. However, the Strategy consultation document mentions platform electrification as many times as CCS as a way to reduce greenhouse gas emissions as far as reasonable by considering all applicable options for existing and new developments. Moreover, the Final Report contains a detailed Annex on “offshore electrification”, as well as one on CCS, which between them give the clearest insight yet into the OGA’s vision for integrating high and low carbon industries in the UKCS. As both the OGUK report and the Final Report note, upstream platforms are huge consumers of energy, nearly all of which is currently produced through the burning of fossil fuels. Most UK platforms are powered by on-site gas turbines which, on average, consume 5% of all gas produced at the well-head. Globally, combustion-related carbon emissions from platforms have been estimated at around 200 million tonnes of CO2 per year, roughly equivalent to the total emissions of Vietnam.¹ In a mature basin such as the North Sea, which is likely to be relying for an increasing proportion of its output on secondary and tertiary, rather than primary recovery, the industry’s power requirements for extraction are likely to grow. Reducing the reliance on gas turbines by adding or substituting renewable sources of electricity, therefore, has clear environmental benefits, but there can be economic advantages too. Less gas used to power generators means more gas that can be sold to market or re-injected into wells to maximise oil recovery. Removing the need for on-platform power generators results in space saved on rigs, and could lead to lower capital expenditure to offset the power connection cost.² For this reason, platform electrification is a more attractive economic option for greenfield sites compared to brownfield sites, which will require higher costs to retrofit. Moreover, there are health and safety benefits for those working offshore, with reduced noise, vibrations and fumes. Carbon pricing – or the potential for it to apply more extensively in the upstream sector – may be another consideration that favours electrification. No or fewer CO2 emissions from offshore generators would mean reducing or eliminating their potential costs of emitting carbon. At present, unlike fossil-fuel power generators onshore, the upstream industry benefits from “free allocation” of allowances under the EU Emissions Trading System (ETS). In the UKCS, the gas they use to generate power is not subject to the “carbon price support” rate of the UK’s climate change levy (CCL). Upstream power generation activities have, therefore, not been subject to a carbon price. However, the EU ETS “carbon leakage list” (CLL) that determines which sectors receive free allocation of allowances is about to become less generous: when EU ETS Phase 4 begins in 2021, it will still cover emissions produced by the extraction of oil, but not those produced by the extraction of gas. Although the UK is no longer in the EU and its plans for carbon pricing after 2020 when the Brexit transition period ends are not finally fixed, the government has indicated its preference for a UK ETS that would follow the same approach as the EU ETS Phase 4 CLL. This could change. However, over time, further extension of UK carbon pricing to upstream generation (e.g. through the carbon price support rate of CCL) is also possible. It is not surprising, therefore, that the Final Report highlights future carbon pricing policy as a key determinant of the economic feasibility of electrification projects. This is particularly true of what the Final Report calls “brownfield” projects – those that would replace existing offshore fossil-fuelled generation with new sources (onshore or offshore) of renewable power. Shore-to-platform electrification Platform electrification is not a new idea. Norway’s Troll A gas platform has been electrified since it came onstream in 1996, with power from an onshore generation plant reaching the platform via an undersea cable. Such “shore-to-platform” arrangements are currently the most common form of electrification in the North Sea. Benefiting from the overwhelmingly renewable mix of Norwegian power generation (dominated by hydroelectricity), the Johan Sverdrup field in Norway emits just 0.67kg of CO2 per barrel of oil produced, around 4% of the world average.³ The Netherlands also utilises shore-to-platform electricity on one of its rigs. The benefits of being connected to the onshore electricity grid include high security of supply and reliability. In the UKCS, shore-to-platform electrification is currently being considered in the West of Shetland (WoS) area. Shetland Council and the Oil and Gas Technology Centre (OGTC) are working together to create a new Energy Hub on the islands, which will examine how electrification can help the area’s offshore assets reach Net Zero by 2030. On 30 July 2020, Ofgem confirmed that it was satisfied that a final decision had been taken on the proposed 440MW Viking wind farm on Shetland,⁴ thereby unlocking Ofgem’s conditional approval for the planned Shetland to Mainland High Voltage Direct Current (HVDC) Interconnector, and making it more likely that some of the renewable electricity produced by wind farms on Shetland could in future be made available to offshore platforms. Several upstream players all have assets in the region that could potentially benefit.⁵ For the majority of UKCS platforms, however, shore-to-platform technologies are unlikely to be a viable option – at least as far as power from UK onshore generators is concerned. The cost-benefit estimates in the relevant Annex to the Final Report show onshore electrification opex costs for electrification from the UK shore that are almost double those for offshore electrification or supply from Norway. Away from Shetland, it is less common to find the same potential for using new UK onshore renewable generating capacity to supply relatively closely located upstream assets that are also new, or at any rate have a long operational life ahead of them. Diverting the output of existing grid-connected renewable generating capacity to offshore platforms is more likely to reduce green energy available for end users onshore, and thus reduce the net benefit in terms of reducing carbon emissions. An upstream player that wished to demonstrate strongly its support for net zero objectives might prefer to take any shore-to-platform supply of green power specifically from new renewable generating capacity, so as to be able to satisfy the criterion of “additionality” that is central to many renewable corporate power purchase agreements (i.e. that without the corporate customer’s long-term commitment to purchase the generator’s output, the generator’s project would not have been built). This reinforces the need to control project costs by finding sources of onshore generation that are closely located to upstream assets whose residual life is well matched to those of the generator’s if this model of integration is to succeed. The Final Report also contemplates the possibility that connections to new power interconnectors, such as the North Sea Network link between the UK and Norway, could bring power to platforms further from shore than current shore-to-platform technologies allow. One drawback of connecting to HVDC cables may be the likely need to install a DC-AC converter on the platform, with the accompanying costs and loss of space that this will bring. However, considerations of practicality and commercial feasibility are not the only potential barriers to shore-to-platform approaches to electrification. There are also potential regulatory obstacles – or at least gaps. For example, at present, the development of the offshore wind industry has given rise to a regime where licences for offshore-to-shore transmission links are issued on a competitive basis through the offshore transmission operator (OFTO) tender process, with the winning bidder assuming ownership of transmission assets that have invariably been constructed by the wind farm developer, but which are not permitted to be permanently operated by a generator because of electricity sector “unbundling” rules. If it was thought appropriate to apply a similar model to shore-to-platform links, the existing regulatory framework would need to be adapted, because it is based on a statutory concept of “offshore transmission” that appears only to include the offshore transmission of electricity generated offshore, not onshore generated electricity going offshore.⁶ The regulatory changes that would be required to facilitate any use of interconnectors in platform electrification would be likely to be significant still. Interconnectors are currently treated as connections between the transmission systems of different countries, rather than being able to convey power directly to end users, and the UK’s existing interconnectors all currently connect to the onshore part of the grid. However, an open letter published by Ofgem on 12 August 2020 indicates that it is maybe prepared to think again about other models, including “multi-purpose interconnectors”, that “could link interconnectors with offshore renewable generation, and might form part of a potential North Seas grid”. That said, one potentially substantial advantage of shore-to-platform electrification for any upstream players not constrained by concerns for “additionality” would be that it should in one way or another allow them to be supplied with “100% renewable” power that is also always available (subject to any problems with the transmission cables). This is because being connected to the onshore grid means being connected to the output of a huge number of generators, and a large number of suppliers offering, in various forms, packages of electricity that can all be counted in one way or another as green, rather than perhaps one or two sources of intermittent offshore renewable electricity as might be the case with an offshore electrification option (see further below). Electrification through offshore wind While shore-to platform electrification could be viable for some UKCS platforms, the use of offshore wind is starting to look as if it may be a more attractive option for a majority of installations. The possibility of integrating offshore wind turbines into the power supply of offshore platforms has been considered in several contexts, at least as a method to supplement generation from existing gas generators. In respect of platforms which are further offshore or otherwise isolated from existing grid infrastructure, electrification through offshore wind installations has the potential advantage of not requiring installation of long subsea cables to ensure connection to the onshore grid. There are already a number of areas where existing or planned offshore wind farms are located close to upstream assets, and the scope for co-location appears set to increase as interest in floating offshore wind technology grows – with the offshore wind sector in many respects following the same journey from fixed to floating platforms that the oil and gas industry went through in past decades. For example, notwithstanding the work on possible shore-to-platform links in the WoS area noted above, it may also be that WoS, with its relatively deep water and early stage of development as an oil and gas area, is well suited to the deployment of floating offshore wind. The problem, of course, is that at present a connection to an offshore wind farm is not a complete substitute for on-platform generation in the way that a shore-to-platform supply could be, because offshore wind turbines generate intermittently and their output cannot be adjusted up and down in the way that a gas turbine can. In other words, you would probably need both technologies in order to ensure security of supply, and the intermittent nature of wind and the different stages of oil field exploitation give rise to significant variability of operating conditions. This presents challenges when identifying the optimal size and operating parameters of the parallel renewable and fossil-fuel generating capacity that would be required for a given platform (particularly in a “greenfield” scenario). From a “maximum low carbon” point of view, it may be that the need for fossil-fuelled generation could be reduced or eliminated by connecting more wind generating capacity than is required at any one time and storing excess energy in batteries or in the form of hydrogen (produced by using the excess electricity to electrolyse water), which could then be used to supply or generate electricity when the wind turbines are not generating enough, or at all. However, it is not in any sense clear whether, or how soon, such options are likely to be feasible in this context (a combination of gas and wind power may be likely to be a materially cheaper option for some time). Although pollution reduction and sustainability considerations are key drivers for platform electrification, the primary objective for a platform operator remains the continuous and safe production of hydrocarbons with minimum risk of plant failure. Offering high reliability, compactness and dynamic flexibility, gas turbines remain the leading offshore electrification technology: it seems that, for the foreseeable future, offshore wind is more likely to complement than to replace them. On the NCS, Hywind Tampen is being developed by Equinor and its project partners on Snørre and Gullfaks. Located some 140 kilometres offshore (260-300 metre water-depth), the 11 floating offshore wind turbines, with a combined capacity of 88MW, will supplement existing gas turbine facilities on the Snørre and Gullfaks platforms with an estimated CO2 emission reduction of 200k tons/year. While managing various (and often competing) stakeholder priorities, developers of similar projects will need to consider the apportionment of interests and associated rights and responsibilities within the project documents. For instance, the project documents will need to account for the dynamic interplay between the operator of the offshore platform and the operator of the offshore wind farm. Subject to applicable regulatory developments (including carbon pricing), the contractual framework may seek to prescribe the circumstances in which the platform operator has flexibility to take gas (including, for example, asset integrity or economic reasons). For the offshore wind side of such arrangements, it is possible to envisage a number of different possible ownership and contractual structures.

• Upstream platform operators (or some or all of the participants in one or more upstream joint ventures) could choose to build and operate the wind turbines themselves (not least in view of the increasing design synergies between the two technologies noted above) or they could contract with a third party generator/supplier of offshore wind power.
• A given set of wind turbines could either be “captive” generators, dedicated to a particular upstream platform (or platforms), or they could have the ability to supply other users (including potentially those onshore).
• In order for the wind farm project sponsor(s) to manage effectively offtake risk (and ensure project bankability), the power purchase agreement with the platform operator (offtaker) may prescribe “take or pay” provisions, giving the platform operator flexibility to take such delivery as may (from time to time) be dictated by its operational needs, on the condition that it pays for volumes which would otherwise be delivered. This may be particularly likely in a “captive generator” scenario with a third party wind farm operator. On the other hand, a wind farm with more export options may have an incentive to divert its production away from the upstream platform and sell its output elsewhere, or reserve flexibility to connect to existing or upgraded OFTO arrangements. This optionality would require detailed consideration of the contractual framework and applicable regulatory obligations.
• One potential advantage of floating turbines could be their ability to be deployed in more than one location over their operational life. In principle, this could open up the possibility that they could supply platforms with a shorter remaining operational life than their own, and then move on to supply another. However, it remains to be seen whether this approach would be feasible in terms of relocation costs (including reuse of connecting cables), and there would also be questions around the bankability of a business model based on a series of PPAs with different counterparties and associated offtaker creditworthiness issues.
• For renewable generators without ties to the upstream industry, the key question for the moment may be how the premium that upstream platforms are prepared to pay for green electricity compares to the strike price that the generators think they can achieve in an allocation round for Contracts for Difference (CfD) subsidising renewable electricity. Then again, just as at least some offshore wind farms that export (or plan to export) all their output to the onshore grid are taking a conscious decision to divide their output between a CfD-subsidised and a subsidy-free, merchant element, it may be that some developers would be attracted to developing projects that blended an element of “guaranteed” income under a contract with an upstream platform with exports further afield on a CfD or merchant basis.

The OGA in its Final Report also raises a number of relevant regulatory questions.

• How could wind power and oil and gas electrification timelines be better aligned, given the shorter lifetime of oil and gas assets?
• How could “access to seabed” be managed if proposed wind farms were to be installed on licensed oil and gas acreage?
• Could “route to market” decisions be simplified if wind farm developments are for sole supply of oil and gas installations?
• Could surveys and results of an oil and gas environmental impact assessment be used (where applicable) to satisfy requirements of wind farms in the vicinity of installations?

We will shortly be publishing more on the prospects for floating offshore wind in general, addressing in more detail some of the commercial and regulatory challenges it faces to scale up, regardless of how useful it may be in the near term as a solution for platform electrification. Additional offshore generation technologies which could support platform electrification While offshore wind appears to be the preferred method of electrification for most platforms in the medium to long term, there are some other technologies that may prove useful in reaching Net Zero. A number of companies are developing technologies for floating solar PV panels, although to date these have mostly been deployed on inland lakes, dams and shallow coastal waters. Work is now underway to develop panels that can withstand the harsh conditions of the open North Sea. The Zon-op-Zee project in the Netherlands “remained stable and intact in all conditions” as it weathered winds of up to 62 knots and waves more than five metres high during Storm Ciara in early 2020⁷, albeit that conditions in the North Sea can be more severe than this. Flying kites are another niche form of power that may be appropriate for certain platforms. These have been suggested for installations that are in water too deep for fixed offshore wind turbines but for which floating wind turbines are not economic. Shell has recently invested in Makani, an Alphabet subsidiary that has piloted the technology off the Norwegian coast. These kites look similar to airplanes and are attached to buoys on the sea surface. Rotors attached to the wings spin in the wind to generate electricity as the kite flies round in a loop. These kites can be produced at a fraction of the cost of a floating wind turbine, but large-scale generation using this technology is at least five to 10 years away, according to BloombergNEF.⁸ In the immediate term, Premier Oil and the OGTC are piloting the use of Ocean Power Technologies’ PB3 PowerBuoy® on Premier’s Huntington field. This is a moored buoy that captures power from the motion of ocean waves to allow it to provide monitoring capabilities and protect subsea architecture. The technology will monitor the local environment and alert ships of the field’s safety zone as a potential solution to help with their future decommissioning. The buoy constantly recharges itself by harvesting energy from waves, operating in depths from 20 up to 3,000 metres⁹ . Powering on-board or sea-bed sensors, it enables real-time data transfer and communication with remote facilities. When paired up with different payload configurations, the buoys will be able to support small field developments or act as a charging/communications hub for Autonomous Underwater Vehicle (AUV) applications.¹⁰ Gas-to-Wire Gas-to-wire as a concept involves the offshore combustion of gas to generate power which can then be exported to the onshore grid using existing offshore wind transmission infrastructure or through bespoke transmission systems. In certain circumstances, the transmission of gas-generated power may be more economical or feasible for an upstream company than the transportation of gas. Gas-to-wire has a more obvious affinity with the original, and still fundamental, objective of the OGA Strategy (maximising the economic recovery of petroleum or MER) than it does with the proposed new Net Zero additions to the Strategy. Perhaps for this reason, it is not explicitly mentioned in the OGA’s recent consultation, and it is less prominent in its Final Report than platform electrification. However, its potential has previously been highlighted by the OGA and it is not necessarily incompatible with the pursuit of Net Zero objectives.¹¹ There is increasing interest in gas-to-wire as a solution for companies accessing undeveloped or stranded gas reserves e.g. remote pools or tight gas plays where such reserves would otherwise be uneconomic to develop with conventional (pipeline) access to market. One possible model would see mobile platforms fitted with aeroderivative gas turbines connecting to these marginal assets to produce electricity, and moving on to the next asset as each one is fully depleted. Gas-to-wire could play a part in extending the economic viability of late-life assets where production is declining by potentially providing a more cost-effective means to monetise the remaining gas by converting it into power. Extending the life of assets in this way could also help defer expensive decommissioning costs. Another use would be for it simply to provide an extra revenue stream for companies and reduce future opex costs, particularly with regard to costs associated with the export of gas e.g. compression. Much depends on whether transmission of power or transportation of gas is more economically or technically feasible in any given circumstances. On its own, a gas-to-wire project is unlikely to assist directly in the achievement of Net Zero. In theory, gas-to-wire could be used in conjunction with CCS to provide low carbon, but non-renewable power. However, it is unclear whether carbon capture offshore and from the kinds of generating equipment concerned would be cost-effective. There is also the possibility that the offshore combustion of gas for the production of electricity to be exported onshore via offshore wind cable capacity could free up existing gas export pipelines for use on CCS projects involving onshore emitters. However, the principal use of a gas-to-wire project would likely be to fulfil a company’s obligation under the Strategy to maximise the economic recovery of otherwise unrecoverable petroleum – for example, by extending asset life to avoid “domino effects” when one of a number of interlinked assets is decommissioned. It is yet to be seen how the OGA would prioritise the competing obligations of a company with respect to compliance with the Central Obligation (i) as it stands, and (ii) with the likely addition of the further obligation to contribute towards Net Zero. Given the unincorporated joint venture nature of the majority of offshore oil and gas operations, a key component in the implementation of any gas-to-wire project will be obtaining the consent of the joint venture parties. It is unlikely that existing JOAs include provision for the re-purposing of late-life assets for gas-to-wire. Such proposals will not suit every industry participant and there are key differences between marketing gas and power: many upstream participants will be less familiar with the power sector. Oil and gas companies that are interested in the concept will likely want to start discussing any such proposals with their JOA parties as soon as possible to get an understanding as to the level of agreement within the JV regarding using gas-to-wire to develop further gas reserves or as a means of extending the economic viability of late-life assets, as well as coupling it with CCS technology. Similarly, JV parties that may not want to pursue a gas-to-wire project and are in the minority in terms of voting power and/or JV participating interest will likely want to understand what protections are afforded to them under the JOA. Before any question of JOA provision arises, the potential feasibility of gas-to-wire for any upstream asset is likely to depend to a large extent on there being nearby existing or proposed offshore wind transmission infrastructure with some spare capacity. Unless a gas-to-wire project can make use of such infrastructure, the capex costs involved in an oil and gas company developing its own transmission system for the electricity it generates may be prohibitively high unless the asset is located close to the shore. The location of a company’s assets is therefore key. Currently, the areas of focus for potential gas-to-wire projects – as promoted by the OGA – are the Southern North Sea and East Irish Sea where existing oil and gas and offshore wind infrastructure already co-exist in close proximity to one another (the OGA has highlighted 15 cases where an upstream hub is within 10-50km of an existing or planned offshore wind farm in these areas).¹² Additionally, not all platforms will be suitable to host a gas turbine with sufficient capacity to make a gas-to-wire project commercially viable. Without its own dedicated power export cable, a gas-to-wire project would depend on (i) the willingness of a wind farm owner or OFTO to accept additional power generation and (ii) the spare capacity in existing offshore wind transmission systems. Neither of these points is necessarily straightforward.

• Wind farm owners and OFTOs are used to a model in which they only have each other to think about: one generator, and one transmission operator, per offshore link. OFTOs are not like onshore grid operators which are used to coping with multiple power flows and all kinds of generation and demand. Introducing a second generator using a different technology is a significant complication to their business model – and that of those who finance them.
• Taking a positive view, one could point to the fact that the OFTO would be transmitting more electricity. However, precisely because wind generation is intermittent and they only have one generator customer each, OFTOs are currently remunerated largely on the basis of their availability, rather than on a £/MWh basis for power actually transmitted.
• Looking at things from the offshore wind farm’s perspective, perhaps it could strike more advantageous commercial arrangements with those who purchase its power if it were packaged together with that of the gas-to-wire generator – potentially converting its intermittent output into baseload generation if the gas-to-wire generator flexed its generation up and down so as to mirror the troughs and peaks of wind power output? In one sense, there is nothing to stop any wind farm operator entering into such an arrangement with a gas-fired generator already connected to the grid elsewhere. The only advantage of doing so with a gas-to-wire generator would be if its operating costs were materially lower than those of equivalent existing onshore units. It is not clear whether this would be the case. The offshore gas generator will inevitably have some new infrastructure costs that its onshore counterpart would not. On the other hand, its gas supply will not come with all the same associated transport and processing costs, and it may have a carbon pricing advantage – although this could be eroded (see above on UK ETS and carbon price support).
• Joining forces with a gas-to-wire generator could also have disadvantages for a wind farm operator, if it were a party to a CfD or other arrangement that relied on its output being 100% renewable. At the very least, some bespoke metering arrangements would be required.
• Currently, over the course of a year, the average offshore transmission link only utilises 40% of its capacity so, on the face of it, there is plenty of capacity available for gas-to-wire. The problem is that the wind farms are generally incentivised to generate and export power whenever they can, and their output, although predictable within certain parameters over the course of a year, fluctuates significantly from day to day and hour to hour with changes in the weather. The OGA’s study of gas-to-wire assumes that wind output would take priority in allocating scarce capacity on any transmission link, but it says little about any possible efficiency and other impacts on the upstream generator or the gas extraction activities that lie behind it of flexing its generation in this way.

Assuming that agreement could be reached with a wind farm owner or OFTO, if there is insufficient capacity in existing transmission assets to allow the gas-to-wire and renewable generators to export their power for much of the time, there appear to be two options: (i) reinforcement of the existing assets; or (ii) a regime that allocates scarce transmission capacity between the two generators in a pre-determined way. If reinforcement of existing assets is required in order to facilitate offshore gas-power generation, an oil and gas company would likely need to make a connection application to the National Electricity System Operator (NETSO). The NETSO may request that an OFTO make additional capacity available to the new generator. If requested, the OFTO is required to offer terms to the NETSO for providing the additional capacity (so long as it does not exceed 20% of the initial capital cost). However, it is not clear how realistic a prospect this is, as the interactions with the OFTO regime are not straightforward and, in any event, reinforcement is unlikely to be achievable without additional capex in most cases. The amount of spare capacity in OFTO assets, including the variation of such capacity on a day-to-day basis, and the cost of any required reinforcement as well as the unknown willingness of stakeholders in existing OFTO assets to allow alterations to be made to existing infrastructure all add additional complexity to any potential gas-to-wire project, quite possibly making many such projects uneconomic. There may also be technical challenges to having mixed generation at OFTO connection points that may need to be overcome (for example, separate metering of the gas-fired generator’s output to that of the output from the wind farm for which the wind power generator is entitled to receive subsidies). An offshore generating station other than a wind farm, which generates power for the onshore grid rather than to power upstream industry processes, is currently a regulatory anomaly. With respect to the current oil and gas regulatory regime, licences for the exploration and production of petroleum granted pursuant to the Petroleum Act 1998 do not expressly provide for the licensee to obtain consent from the OGA to use natural gas for power generation. Currently, a licensee is required to obtain consent from the OGA for the flaring of gas or for re-injection for the purposes of creating or increasing well pressure, so it is likely that OGA consent would also be needed for the use of gas for offshore power generation of a commercial nature. We consider that such consent would be separate from any approval given at the development stage for an operator to use natural gas from the well as fuel gas for production operations, particularly given the larger volumes that would be involved and that such gas-generated power would be for onward supply and commercial gain. Therefore, there may need to be an amendment to the current statutory licence terms to cater for such consent to be given. Further questions also arise as to the rules under which gas-to-wire would be consented for planning/environmental purposes. Would it need a generating licence under the Electricity Act 1989? (Answer: yes, unless its output was below 50MW or it sought and obtained from ministers an individual exemption from the requirement to hold such a licence.) What rules on non-CO2 emissions would apply to it? What changes may be required to electricity industry codes in respect of it? There are, in short, many legal, as well as practical questions to consider in relation to gas-to-wire, and it is not yet clear whether the “size of the prize” in commercial terms is such as to motivate regulators to answer them all. Conclusion While the OGA’s consultation focuses primarily on utilising CCS or hydrogen projects as a way of helping the wider economy to decarbonise, platform electrification and gas-to-wire could help certain upstream players comply with the Net Zero obligation whilst also maximising their recovery of economically recoverable petroleum. The Final Report contains some very interesting ideas about how these concepts could be developed. However, such projects raise fundamental considerations of practicality and commercial feasibility whilst also requiring some regulatory changes before they could become a reality. However, the regulatory/political will to make such changes may exist. For example, to the extent that the offshore transmission regime contributes to any of the obstacles or uncertainties considered above, it should be noted that the government has recently kicked off a review of the current regime. Although this is being done more with a view to facilitating the government’s very ambitious 2030 offshore wind targets than with the needs of oil and gas power supply in mind, it is possible that some of the challenges that the upstream industry faces could be alleviated by any forthcoming burst of new legislative and regulatory activity in this area.

1. Wood Mackenzie: “Why powering oil and gas platforms with renewables makes sense”, October 2019
2. Energy Voice: “Shetland Energy Hub aims for hundreds of jobs and to make giant oilfields ‘net zero by 2030’”, 24 June 2020, https://www.energyvoice.com/otherenergy/248006/energy-hub-hopes-to-make-giant-west-of-shetland-oilfields-net-zero-by-2030/
3. See Electricity Act 1989, section 6C(5).
4. Recharge News: “World’s first offshore solar array rides out storm Ciara off Netherlands”, 16 February 2020, https://www.rechargenews.com/transition/worlds-first-offshore-solar-array-rides-out-storm-ciara-off-netherlands/2-1-757022
5. Bloomberg: “Flying Wind Turbines Make Their First Trip Offshore in Norway”, 15 August 2019, https://www.bloomberg.com/news/articles/2019-08-15/flying-wind-power-turbine-makes-first-trip-offshore-in-norway
6. Offshore Engineer: “Premier Oil Testing PB3 PowerBuoy in the North Sea”, 23 August 2019, https://www.oedigital.com/news/469883-premier-oil-testing-pb3-powerbuoy-in-the-north-sea

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