Business, Energy and Industrial Strategy Committee
Oral evidence: Decarbonisation of the UK power sector, HC 283
Tuesday 22 November 2022
Ordered by the House of Commons to be published on 22 November 2022.
Members present: Darren Jones (Chair); Bim Afolami; Tonia Antoniazzi; Alan Brown; Ruth Edwards; Mark Jenkinson; Andy McDonald; Charlotte Nichols; Mark Pawsey; and Alexander Stafford.
Questions 73 to 136
Witnesses
I: Matthew Williamson, UK Head of Hydrogen, BP; Catherine Raw, Managing Director, SSE Thermal; Olivia Powis, Head of UK Office, Carbon Capture and Storage Association; Phil MacDonald, Chief Operating Officer, Ember.
Witnesses: Matthew Williamson, Catherine Raw, Olivia Powis and Phil MacDonald.
Q73 Chair: Welcome to this morning’s session of the Business, Energy and Industrial Strategy Committee for our second Tuesday of evidence for our decarbonisation of the power sector inquiry.
We have two panels this morning. The first will be looking at the role of fossil fuels, and the second will be looking at biomass. In the first panel this morning, we are delighted to welcome Catherine Raw, the managing director of SSE Thermal, Matthew Williamson, the UK head of hydrogen for British Petroleum, Olivia Powis, head of the UK office at the Carbon Capture and Storage Association, and Phil MacDonald, the chief operating officer at the energy think tank Ember. Good morning to all of you.
Before we dive into the questions around decarbonisation of the power sector from a technology perspective, Matthew Williamson, could I come to you first on the autumn statement last Thursday, just to get your views on the record about some of the changes that were announced? Specifically in terms of the windfall tax, BP has said that it is going to pay $2.5 billion in tax this year. If it was not for the loophole that was put in for investment into drilling for further oil and gas, how much more tax would you have paid this financial year?
Matthew Williamson: I am not an expert in the tax implications of the statement, so it is our tax and financial teams who will be working that out. I do not have an answer on that for you today. Looking at the statement in its entirety, we were very pleased to see the mention of CCUS and, therefore, the inferred importance of CCUS to the Government. That is a key part of our UK future investment plans.
Q74 Chair: How do you know that you were going to pay $2.5 billion this tax year, if BP said that to the public?
Matthew Williamson: That will have come through our finance and tax teams, who will have done the maths, based on the previous energy profits levy announcement.
Q75 Chair: So why can you not tell me the answer to my question if they could figure that bit out? Originally, if you had to pay 100% of the windfall tax, that would be X dollars, but you were given a loophole whereby, if you used some of that profit to invest in oil and gas drilling, you would not have to pay that in tax, which is why you get to Y dollars. What I am trying to understand is the differential. That is a pretty simple calculation, is it not?
Matthew Williamson: It is not a calculation that I have with me and I cannot give you an answer. The North Sea ringfence is a separate part of the business to the rest of the UK, so there are added complications when trying to work out the overall tax position of UK and the North Sea, and that is not something that I am expert in. Low-carbon energy is my area of specialty.
Q76 Chair: You were told in advance that we were interested in this question, were you not?
Matthew Williamson: I would have provided the answer if it was available to me.
Q77 Chair: Maybe you can ask your colleagues at BP to write to us with the answer, because I am sure that they know it.
BP has also announced that it is going to buy back shares this financial year, 2021-22, to the value of $8.5 billion. How does that compare to how much BP has invested in low-carbon technology?
Matthew Williamson: There is an overall financial plan laid out by the board and executive team. From a capital spend perspective, we are moving away from hydrocarbons to non-hydrocarbons, so about a 30% spend on non-hydrocarbon investment now moving up to 40% by 2025, and then 50% by 2030.
Q78 Chair: Just to help me understand, in financial year 2021-22, you are paying $8.5 billion to buy back your own shares. How much, in dollars, in financial year 2021-22, are you investing in renewable technologies?
Matthew Williamson: I cannot give you an exact number. All I can say is that, for this year, we are looking at approximately 30% of spend in non-hydrocarbon investments. I do not have the breakdown for renewables.
Q79 Chair: You just told me that the renewables bit was your expertise and you still cannot answer my question.
Matthew Williamson: I can answer many questions around low carbon, but the specifics of the budget breakdown is not data that I have with me.
Q80 Chair: You say that 30% of spend will go into renewables.
Matthew Williamson: That is into non-hydrocarbons, so it covers bioenergy, renewables, hydrogen, CCUS and EV charging.
Q81 Chair: So 30% of spend is what in dollars?
Matthew Williamson: I do not have that number.
Q82 Chair: I mean, 30% of $10 could be very little; 30% of $100 billion is a lot. I am just trying to understand how much you are investing.
Matthew Williamson: By way of scale, we have announced plans to invest £18 billion in the UK by the end of the decade, so that is the sense of scale of how much we are investing.
Q83 Chair: Surely you understand why I am a bit disappointed by your answers. You are here before the Select Committee to talk about investment in renewables and investment in fossil fuels, and we need to understand the difference, but you do not seem to be able to answer any of my questions on the amount you are investing.
Matthew Williamson: My brief was around decarbonisation of power in the UK.
Q84 Chair: I understand your brief, but you work for BP. You will have lots of people who work with you in tax, in legal, in policy and in regulatory, no doubt including a huge budget for external consultants. Did you not prepare for this session before you came today? Did you not get any help from your colleagues at BP?
Matthew Williamson: We certainly prepared for this session, but not for those questions that you have asked.
Q85 Chair: Is that because you do not want to answer them or because you cannot answer them?
Matthew Williamson: It is because I cannot answer them.
Q86 Charlotte Nichols: The International Energy Agency has said that, if the world is to get on a net-zero pathway, beyond projects already committed to as of 2021, there is no need for new oil and gas fields. Do you accept this and, if so, will you be following its recommended pathway?
Matthew Williamson: We have laid out our net-zero ambition and aims, which, we believe, are consistent with the goals of the Paris agreement, including efforts to limit climate change to 1.5 degrees. As part of that, we have already announced that we will be reducing our hydrocarbon production by 40% by 2030 and, as I have already said, we are ramping up our spend on non-hydrocarbon as part of that transition.
Q87 Charlotte Nichols: Do you accept what the International Energy Agency said—that there is no need for new oil and gas fields?
Matthew Williamson: We will need to spend money on oil and gas fields to maintain them and, depending on what the demand is for oil and gas, there may need to be new investment.
Q88 Charlotte Nichols: To what extent are your plans to reduce fossil fuel production primarily based on selling producing assets to other companies? How do we prevent vital gas assets from being sold to private firms that have less exposure to scrutiny and are less transparent?
Matthew Williamson: Whenever BP sells an asset, we go through a due diligence process on the buyer to make sure that they are appropriate buyers of our assets.
Q89 Charlotte Nichols: How much capital expenditure have you invested in renewables and low carbon compared to fossil fuels in the UK this year?
Matthew Williamson: I do not have a UK-specific number. The overall group number is 30% on non-hydrocarbons.
Q90 Charlotte Nichols: What are your investment plans for next year?
Matthew Williamson: We plan to increase to 40% non-hydrocarbons by 2025.
Q91 Charlotte Nichols: You said that you will be investing £18 billion in the UK by 2030. Can you set out how much of your investment is planned to go into renewables as a source of power to the grid, green hydrogen, blue hydrogen, on your downstream business and electrification, and on oil and gas?
Matthew Williamson: I cannot give you the cost numbers, but I can give you the capacity numbers. We have announced the acquisition of acreage from an offshore wind perspective of 6 gigawatts with our partner. From a blue hydrogen perspective, we hope to have 1 gigawatt of production by 2030, and then, from a green hydrogen perspective, 500 megawatts of production by 2030.
Q92 Charlotte Nichols: What about in terms of oil and gas and electrification?
Matthew Williamson: I do not have those numbers.
Q93 Chair: I am still shocked that you do not have the numbers for anything. You said that you cannot answer them. Is that because you are not allowed to answer them or because you have not been given them?
Matthew Williamson: I do not have those numbers.
Chair: You have not been given them.
Matthew Williamson: I have not been given those numbers.
Q94 Chair: Why have you not been given them? Did you ask for them?
Matthew Williamson: I prepared to answer questions on low-carbon projects. I do not have the full breakdown of our spend.
Chair: Did you ask for them?
Matthew Williamson: No, I did not.
Q95 Alan Brown: If I start with Phil MacDonald, Ember produced a report and some analysis in which you believe that the UK power sector can transition from 40% reliance on gas to just 1% by 2030, with estimated savings of £93 billion. What are these savings based on? What would be required to happen to facilitate such a faster phase-out of unabated gas?
Phil MacDonald: The default now is gas phase-out by 2035. That is the path that we are already on, but we can move a little more quickly and move to 2030 to try to get almost a full gas phase-out by then, just based off the incredible growth we are seeing in wind and solar. This was more than a lot of the models were predicting, but particularly offshore wind, as you see the incredible cost reductions there, is just outcompeting gas. More and more investment is coming in, and that means that we can move a little more quickly and maybe get to 2030 at a power sector decarb.
Q96 Alan Brown: I noted that, to get there, you are estimating that that would require an additional 90 gigawatts of wind and solar to come onstream by 2030. At the moment, we have 15 gigawatts of onshore, 11 gigawatts of offshore, and 14 gigawatts of solar PV, so we have only 40 gigawatts in total with these technologies at the moment. You think that an additional 90 gigawatts can be delivered by 2030, including grid upgrades, consenting and all the rest of it. Is that realistic?
Phil MacDonald: I think it is. When you look at not just our modelling, but that of National Grid or the Climate Change Committee, the scale-up in how quickly wind is being deployed is phenomenal. Year on year, we are adding more and more.
We have now reached this tipping point with wind and solar, where they are so much cheaper than gas. This year, we are seeing offshore wind between six and nine times cheaper compared to gas. The money is behind it and, suddenly, after years of gradual build, we are now accelerating, so it is realistic. That is not just our figures, but National Grid and the Climate Change Committee are also saying it.
Q97 Alan Brown: National Grid ESO is not allowing for anything like that in its future scenarios by 2030.
Phil MacDonald: By 2030, National Grid still sees 70% of power generation coming from wind and solar, so the scale-up that we are asking for is to add just another 10% on top of that. It is not a big difference, although it is more ambitious, for sure.
Q98 Alan Brown: I am all in favour of deployment of renewables at scale; it would be great, but it is just that deliverability and the timescale. What is the basis of the cost savings of £93 billion?
Phil MacDonald: That is looking at the cost of gas, which, as we know, has really spiked over the last year, but when you look forward, although they are going to remain very volatile, we see gas prices being very high for the duration of this decade, even if perhaps lower than today. When you look at that, we could carry on with a system based on 40% of our generation coming from gas, but we could instead switch to bring that down to 1% by the end of the decade, and the savings from not having to spend that money on burning that gas is where that £93 billion comes from.
Q99 Alan Brown: Catherine, do you agree with the assessment that such a scenario is possible? We got the suggestion of 2030 there. Are the Government even on track for phasing out unabated gas by 2035 and has enough been done?
Catherine Raw: The key question is around installed capacity rather than generation. The challenge that you have with renewable power is that it is intermittent, and so what happens when the wind is not blowing or the sun is not shining? When we look at what the system needs, it needs sufficient backup capacity, at scale, to be able to meet demand when demand happens, particularly around winter peaks. Whether it is at 1% generation in 2035, it is more about what your installed capacity is that can turn on for that 1% of time when it is required.
Between now and 2035, the question has to be whether we are moving quickly enough to replace existing unabated gas with low-carbon equivalents. If we are, I can foresee any scenario. Essentially, it is the pace at which we can move. The technology exists and the will from industry exists. It is just a case of getting the policy, getting the planning and consenting, and getting these things built. That is the biggest challenge between now and 2035.
Q100 Alan Brown: Has enough been done to get there? Are we on track to phase out unabated gas by 2035?
Catherine Raw: That is a difficult question. If we continue at the pace that we are at today, the answer is probably no. When we look at our own portfolio and our own fleet, we see two power stations continuing to operate post 2030. We see the phase-out of our other power stations because they are being replaced by low-carbon alternatives. That is power CCS and hydrogen. If we do not see that happening in the next three to four years, we are going to have to make decisions around security of supply as to whether to extend the life of our existing fleet, because that will take investment.
We are at a critical juncture at this point as to whether we can pick up the pace and accelerate in order to invest and build those new low-carbon alternatives, so that they are coming online in 2027, 2028 and 2029, and to then be able to deliver into the next decade.
Q101 Alan Brown: If you look at the energy mix, it has been reported that, in terms of nuclear, the Government are maybe going to take a 50% stake in Sizewell C, and certainly EDF gave evidence to the Science and Technology Committee to that effect. We know that nuclear was very heavily trailed last week after the statement. Are the Government doing enough and engaging enough in terms of getting CCS over the line? I know that Acorn is a reserve cluster, so what does “reserve” mean? Has enough been done to drive this change in unabated gas?
Catherine Raw: I go back to my point about pace. The challenge with nuclear is that it takes time. While nuclear is a solution—and I do not have a judgment on whether it is the right or the wrong solution—it is about whether it can be built quickly enough and deliver. Also, it is not flexible. It is baseload capacity, so I go back to my point about needing flexible capacity.
The nuclear discussion is a separate one that can run in parallel, but it does not address the key issue, which is where this flexible capacity is going to come from when you need it and how quickly we can bring it on.
Again, I will go back to my original statement, which is the pace and the lack of clarity, for example, on the Scottish cluster. It was identified as a reserve 1 cluster; it now looks like it is a track 2 cluster. We are being advised that we will be notified next year as to what that pipeline and that process look like.
For the moment, we are spending on moving the feed and the engineering forward without any clarity as to the timing of that cluster process, whether the Scottish cluster is there and whether Peterhead, which is the CCS station that we have in the Acorn cluster, is going to move ahead.
I should add that the biggest challenge SSE has is that we have been here before, insofar as Peterhead had a CCS plan in partnership with Shell between 2012 and 2015, and then, at the final hurdle, the funding was pulled. That is our concern, when we look at investing and putting risk capital into these projects. It is that clarity of ambition, of pipeline and of when the decisions are going to be made. Clearly, the last six months have not been great for that.
Q102 Alan Brown: Is there a cut-off date where you need that clarity to be able to progress?
Catherine Raw: It is when we can bring it into operation. As of now, we can see a timeline that brings it on in the second half of 2028, but that assumes a final investment decision coming in 2024, which means that we have to get the detailed engineering and all the planning consents. We have just put our application in. We are working on a timeline that says second half of 2028, but, when we, essentially, make decisions, we can make them for only so long without clarity as to whether that investment is going to come to fruition.
Q103 Chair: Can I just check that I properly understand some of the things that you said? You said “power CCS”. Does that mean a gas power station with CCS, which you are classifying as low carbon because you hope the technology will capture the carbon? Is that right?
Catherine Raw: Yes. The technology should be capturing at least 95%, and we are working on R&D now with the Translational Energy Research Centre of the University of Sheffield, as well as the Mongstad facility, as to whether we can increase that any further and make sure that we are capturing ramp-up and ramp-down periods to give that power the dispatchability required.
That is why we call it low carbon—because, essentially, we are capturing at least 95% of those carbon emissions, which are then going into the transport and storage infrastructure and being stored below the North Sea. That is the plan. We call it power CCS because the carbon capture and storage cluster is much more than just any one power station.
If you look at the east coast cluster, at the Scottish cluster or at HyNet, we are, as an industrial consortium, all having to work together in order to tap into that infrastructure. Whether it is the hard-to-abate industries, whether it is blue hydrogen or whether it is power CCS, we are all users of the same infrastructure. All I am trying to do is to distinguish specifically what I am responsible for, which is power CCS.
Q104 Chair: Did you want to comment on the windfall tax on electricity generators and what that means for those investment plans?
Catherine Raw: If you want me to comment on it, I shall. SSE clearly believes in paying our fair share. We have signed up. We are perfectly supportive of well-designed taxes that deliver to society. The only comment that I will make around this levy is that it feels like an unintended consequence and slightly counterintuitive that, effectively, investment by oil and gas companies is favoured over investment by renewables companies. That is the only statement that I will make on the tax.
Chair: You will be pleased to know that I agree with you, but there we are.
Q105 Andy McDonald: Can I keep on the issue of CCS and explore that a little further? I just want to ask a broader question. Can we have a decarbonised electricity system without CCS? Renewables are going to be providing 75% of our electricity, and nuclear, with Hinkley Point and Sizewell C, perhaps the balance. What space is there for CCS given this? What is the prospect for electrolysis hydrogen production? I wonder whether Olivia might want to comment.
Olivia Powis: We have seen huge growth in renewables and will continue to do so, as well as in nuclear. I would point back to the sixth carbon budget analysis from the Climate Change Committee, which noted that as much as 10 gigawatts of power CCUS may be required by 2035, but that is contingent on successes being made more widely across the UK decarbonisation agenda. We need technological advancement on battery storage, for example.
In the progress report this year, there are many areas that reduce potential power demand, and progress was not seen as much as they had anticipated, but, in other areas, such as electric vehicles, which increased power demand, growth was on track.
To the points that Catherine made, we will need power CCUS to provide that flexible power for when renewables are not generating. It will be there as part of a package of flexible low-carbon generation.
Phil MacDonald: You can build a future power system without CCS. That is possible and you can model that out. It is just that each technology you remove adds a little more risk. If we cannot do CCS, we have to do lots more hydrogen, which is also an immature technology that we need to deploy. It is that kind of balance, in that it probably reduces risk for the Government to be pushing forward with both hydrogen and CCS, and testing them out now to see if they can feasibly work and contribute.
Q106 Andy McDonald: If we establish that CCS is the way to go, can we explore how achievable this is at scale? We have had evidence before from Dr Joffe from the Climate Change Committee. We asked him how confident he was about getting a deployable facility at scale in sufficient time for 2035, and he said, “I do not think we know … Gas generation, even without CCS, is expensive. Gas with CCS is even more expensive … In terms of the technology, I have some confidence but not full confidence”. What do you make of that assessment? Are we going to have the technology in time?
Phil MacDonald: Demonstrations around the world of CCS have had mixed success, so there is a big risk. If we can get to 95% capture rates and run a power station, and it is cheap enough to do that, that is great, but we need to demonstrate that and to get to the point of testing it. CCS has been talked about for decades now, and it really needs to get to the point of it being demonstrated and shown that it can work.
Catherine Raw: I am going to quote a CCSA report, so that is why I was pointing to Olivia. Having just come back from COP 27, it is very clear that CCS is established as a mainstream low-carbon technology. We have multiple countries across the world already operating carbon capture and storage plants. If I quote the CCSA report, we have 30 projects in operation. We have 11 under construction. We have 153 in development. There was a quote and I cannot remember the number. I was looking for it before I came in, but something like over 30 countries have carbon capture and storage as part of their net-zero transition plan, so this is not an unusual thing. This is not a front-edge, out-there technology.
From SSE’s own experience, we deployed a pilot CCS at our Ferrybridge coal power plant back in 2012 and 2013. BEIS funded £6 million of the £20 million to do it. We had a 90% capture rate. We are now over a decade on from that, with multiple projects in operation that can prove that 95% capture rate.
The areas of risk are around dispatchability. Many of the existing CCS or carbon capture with amine solvents are operating at a flat rate. They do not see the ramp-ups and ramp-downs associated with dispatchable power, which is why we are now spending to do the research and development in order to understand the implications of that and make sure that it does not reduce overall capture rates.
This is not a question of whether the technology exists; the technology is proven. It is how we are going to use that technology and whether it delivers relative to expectations.
Q107 Andy McDonald: Can I just take you to that? You mentioned those 13 projects, which have captured a total of 39 million tonnes of CO2 per year. That is about one‑10,000th of the 36 billion tonnes that emitters have added to the atmosphere in 2021 alone. We saw in Japan the liquefaction of hydrogen from brown coal in Australia, but we have not seen any evidence as to how that was produced.
You talk about this being established. Can you point to one particular example where that is working efficiently and you are getting those capture rates? My understanding is that they are not at 90% yet. We are building to it.
Catherine Raw: There is a coal power plant in Canada, and I cannot remember the name right off the top of my head, but I can get it for you. That has been established for at least five years and is running as we speak. I will get that information for you, but there is currently at least one in operation that I know of.
Q108 Andy McDonald: Could I specifically ask about what progress SSE and BP are making at Net Zero Teesside and at the Keadby 3 operations? Perhaps we could have an update. How much carbon are those sites going to be able to capture? Matthew, do you want to give us an update on that?
Matthew Williamson: There are three key areas of progress on the NZT power plant. First, we are in front‑end engineering design and we are working with two contractor groups to get to the best and most competitive detailed design for that project.
Secondly, we are going through the planning permission process, so we have been through the examination phase for the DCO process and have been very pleased with the amount of public support we are getting in the Teesside area from that. Thirdly, we are working with BEIS on the dispatchable power agreement, which will ensure that the plants are available and will run at mid-merit when renewable power is not available.
The cluster is on track for a 2027 start-up, and the power station will be part of that.
Q109 Andy McDonald: You say “the cluster”, so you are talking about the east coast cluster.
Matthew Williamson: Yes, of which the NZT power station will feed into the Teesside part.
Catherine Raw: We are in the same process, so Keadby 3 is, essentially, following that same pathway. We are currently going through the feed with a consortium of OEMs. We were selected in the phase 2 due diligence process by BEIS. We are now in that process, just as Matthew described. We are going through that engagement on the dispatchable power agreement and, again, we are also anticipating, were the timeline to go as BEIS is indicating, that we would be making our investment decisions, followed by a commercial operation by the second half of 2027.
Q110 Andy McDonald: Gas has shot up. How does that impact in terms of your plans for CCS? Does that play out?
Catherine Raw: Our long-term pricing does not factor in today’s prices. We are looking at third-party analysis, so when we look at gas prices and their implications they do not change the investment case. Importantly, you also have to consider what the alternative technologies and their costs are. It is absolutely right that renewables is the lowest-cost form of low-carbon generation. It is absolutely right that the system should be dominated by renewables. We are really just focusing on flexible capacity at scale, and so hydrogen is the alternative. When you look at the levelised cost of hydrogen, you still see CCS as competitive.
Q111 Andy McDonald: If I were to say that CCS just provides an opportunity for the fossil fuel industry to carry on as per, you would say that that is not the position and that the focus is very much on renewables.
Catherine Raw: It is for SSE. We do not take any side on this. We are the biggest offshore wind developer in the world at the moment, but what we recognise is that you need flexible capacity.
Q112 Andy McDonald: Matthew, how would you answer the charge, from a BP perspective, that this is just giving you an excuse to carry on as normal?
Matthew Williamson: There will not be that much gas that goes through these power stations. They are really for intermittency, so it is not like they are baseload power. The gas will go through them only when there are low renewable requirements.
If I look at our investment portfolio in power in the UK, we are looking at 6 gigawatts of offshore wind—renewable—and less than a gigawatt of gas with CCUS abatement currently. We do see the future very much in renewables, but with gasified power and CCUS providing the intermittency cover.
Q113 Andy McDonald: Catherine mentioned the Peterhead project. Was White Rose the previous one? Could I just ask all the panel about the current state of the Government’s policy in relation to CCS for it to be deployed at scale? Can you say a little bit about the targets and whether you consider those that currently exist sufficient?
Olivia Powis: The targets are sufficient to have a 2035 net‑zero electricity grid goal, to have two clusters operational by the mid-2020s and another two by 2030, and to have one operational plant by the mid-2020s, but, if we are to deliver all that, we need to move quickly. The programme has slipped a bit, but we are still able to keep it on track and meet those deadlines, although we do have to move quickly.
We need to hold regular funded CCS contract allocation rounds and to have that written into the legislative policy framework. We need the Energy Security Bill with that legislation for CCUS and hydrogen to pass through in order that all the CCUS business models right across the value chain—so for CCUS power, but also for industrial CO2 transport and storage—can be implemented by Government. That is on the critical path. It will also give the formal powers to Ofgem as the regulator for the CO2 networks, ensuring that there is a legislative basis there to execute the business models, including greenhouse gas removals, as part of an evolved UK emissions trading system.
We have heard about the permitting. We need to accelerate permitting and construction of the infrastructure, and to rapidly bring additional storage capacity to a commercial level of readiness through licensing, so finalising the business models but launching the next track 2 cluster process. We had track 1. We have the first two clusters, but the phase 2 process needs to move to the next stage and we need the track 2 announcement.
That will give the industry the confidence that this will be an entire industry in the UK; it is not looking just at the first two clusters, but it will be all of them. We need to move forward quickly and to have that. We were meant to have it in the first half of this year. We are now towards the end of this year. It needs to come very soon to signal to the supply chain.
Catherine mentioned being at COP last week. Many other countries are now moving forward, including the US, Denmark and Canada. There are lots of announcements moving forward, and the UK is in danger of falling behind if we do not get these last pieces of the puzzle in place.
Q114 Andy McDonald: I would specifically like to pick up on that last point about the comparison with other nation states. How do we compare? You said that the States is racing ahead of us in terms of investment and policy.
Olivia Powis: The UK is really well positioned, particularly in Europe. We have one-third of Europe’s storage capacity. We have 78 gigatonnes available, which is more than the combined European Union states and surpassed only by Norway. We have announced six licensed storage areas, and 13 are currently under review by the NSTA. We have this world-leading regulatory and legislative system and business models, and everyone commented in the last two weeks on what a good approach and framework we have.
The US has passed the Inflation Reduction Act, and investors are looking there and elsewhere. There will be a market in terms of creating low-carbon products, such as low-carbon steel and low-carbon cement, and the supply chain to build this will go to where the money is. The UK has the ability and the natural geological assets to do this, but we need to make sure that we do not fall behind. We are at risk of losing that first mover advantage.
Matthew Williamson: We would agree that, if you will permit me a World Cup analogy, we have qualified for the finals, because we had an ambitious target and we started on projects early, but the real competition starts now. It is about the amount of investment support and progressing things like the Energy Bill, which has the mechanisms that enable transport and storage of CO2, and enable a hydrogen business model, so that those ambitions can then become real projects.
Certainly, when we look at our portfolio of projects, our UK projects are leading from a hydrogen and CCS perspective, but they will continue to lead only if we all move together quickly, and that includes the Energy Bill and laying out the future rounds for CCUS and hydrogen.
Q115 Andy McDonald: We need to take the public with us on this journey, so I would like you to apply your minds to what the problems and pitfalls there are. There is certainly an argument to be won with the public, but, in terms of these opportunities, Matthew, what are you doing to ensure that the employment opportunities that these projects provide are properly delivered and that they do provide skilled, secure and, I would say, unionised employment for a skilled workforce?
Could you perhaps address those two issues—the extent to which we need to get the public on board, but also the engagement in terms of employment opportunities?
Matthew Williamson: There are two things around the jobs side of it. The first is around making sure that we have skilled people to go into the jobs. In Teesside, there is a big legacy chemical and steel business, and lots of very good skills that are very transferable to hydrogen production and CCUS. We are also trying to make sure that the new generation is part of that as well.
Part of our long-term plan in Teesside is to go into primary schools to get children, at the earliest age, interested in low-carbon technology and engineering, and then to with work with the local college on its low-carbon energy centre.
Q116 Andy McDonald: You just mentioned schools and colleges. You have not mentioned trade unions once.
Matthew Williamson: We are very happy to work with everybody in the Teesside area. I know that my colleague Andy has previously had a conversation with you, and so we are very open to conversations about how to get mobilisation of the best skills in Teesside into these new projects.
Q117 Andy McDonald: I can arrange that meeting, should you so wish. If you will commit to that discussion with trade unions, that would be very valuable, because they are keen to participate. Would you agree to that?
Matthew Williamson: We are always happy to talk. Moving on to supply chains, the buildout of the UK renewable business was great from a power generation perspective, but less good from a local supply chain perspective.
One thing that we are trying to do is to get ahead of when we need bits of kit built. We are now reaching out to the supply chain well ahead of when we start the project. We have over 100 suppliers interested, of which 100 are businesses of 500 people or fewer. We are not seeing just the very big businesses, but small and medium-sized enterprises as well, which are interested and want to tool up for hydrogen and CCUS work.
Q118 Andy McDonald: It has to be at a cost, and we are going to be looking to the paying public to play their part here. I do not know what thought is being given to how you take people with you on this journey.
Olivia Powis: We have done some analysis in terms of looking at new jobs created. These are highly skilled new jobs, around 30,000 and peaking at up to 40,000, but the real benefit is in protecting existing jobs. These are industries in our industrial heartlands where the clusters are located, and we will be protecting around 50,000 jobs there, enabling those industries to find a way to decarbonise and to continue operating. Otherwise, they may not be able to continue, as they would not be able to reach net zero, and it gives them an option to do that, but also then to capture the low-carbon market, so to be the suppliers of low-carbon cement and low-carbon steel in the future.
Catherine Raw: Can I just support that? As a practical case study, Keadby is a great example. The town there was created by the coal power plant in the 1950s, and we have seen the energy transition in action when you look at Keadby.
The original power station closed in the 1990s, and what we now call Keadby 1 was built—a gas power station. We are now in the process of commissioning Keadby 2, which is the most efficient unabated gas power station in Europe. We are then looking to deliver Keadby 3, which is gas CCS. What we are ensuring is that that community continues to thrive, that the jobs are there for generations, and that they are part of that future, not part of the past.
Then, as Olivia talks about, the interconnection with the industrial clusters means that the act of putting in this low-carbon infrastructure not only supports your existing industries and stops them from closing down, but also encourages new industries to access that infrastructure, so it will attract a new low-carbon economy into those regions.
In the Scottish cluster, we now have Grangemouth and INEOS. Grangemouth is coming into it, so you have big emitters and big employers, but really being able to protect and then develop and grow those industrial areas is the way that we are committed to delivering a just transition. It is not just for the existing employees and the communities, but it is also about giving them a future and being able to grow those communities as part of it.
Q119 Mark Pawsey: We have already heard a couple of references to hydrogen from our witnesses today. Mr MacDonald said that, if we cannot do CCS, we will have to do more hydrogen. I wonder if I might ask each of our witnesses what the role of hydrogen is in a decarbonised power system. Should we be focusing on blue hydrogen or green hydrogen? Olivia, would you care to share one or two thoughts on that?
Olivia Powis: As noted by the National Infrastructure Commission and the Climate Change Committee, hydrogen has the potential to play a role in providing mid-merit and peaking capacity. Many companies are now designing and providing hydrogen-ready turbines and components that can switch to low-carbon hydrogen. Several large-scale projects are being developed by both of the track 1 clusters. There is a role in it and it will be there to be considered in close partnership with hydrogen production projects such as Triton Power in the Humber.
In the near term, in answer to your question about what it would look like, it will predominantly be sourced from CCUS-produced hydrogen, but we anticipate that this will shift over time as renewables dominate the energy system and electrolyser capacity is grown. Blue hydrogen provides the option for us to move in the near term and to enable that production of hydrogen before moving on to green hydrogen, once there are sufficient renewables.
A concerted effort is required to get there. We need to establish the business models for hydrogen generation and, more importantly, for hydrogen transport and storage. The business models are out for consultation at the moment.
Q120 Mark Pawsey: Catherine, SSE is developing hydrogen production and hydrogen electricity generation. Tell us a bit about the projects that you have. Are they green or are they blue?
Catherine Raw: As a company, we sit across the value chain. As I said, we are already the largest developer of offshore renewables in the UK, so we see hydrogen production as a good route to market for our renewables capacity as it grows. Green hydrogen production is a priority for the company.
In the thermal business, which is the business I am responsible for, when we look at our low-carbon future, how we move away from unabated hydrogen is as important to us as CCS. Where we see the opportunities are around storage. An important thing about hydrogen, in order to bring that levelised cost of hydrogen down, is how you can store it and load shed it for power. What I mean by that is generating and producing hydrogen when power is cheap, and then using hydrogen when power is expensive in order to deliver that peaking capacity.
The challenge with hydrogen as an energy vector is that it is not that efficient. Burning hydrogen that you have had to use electricity to make does not make sense on the face of it, but, if you are making that hydrogen during periods of high wind overnight, when there is low demand, so you are using excess capacity to make it, you are then able to store it and you can use peaking capacity in order to burn it when it is required. Then you can create a real value chain.
The challenge is that we have to prove that model. At the moment, policy is focused just on production. We have a business model for production. What we do not have is a transport and storage model, and we do not really have any examples of just how storage can change the levelised cost of hydrogen overall over time. That is something that we are very focused on being able to prove.
When you look at these industrial clusters, if you can put renewables and blue hydrogen together to deliver consistent, steady production of hydrogen, and combine it with storage and then with different types of demand—industrial demand and intermittent power demand—what you create is a system, just as the gas system exists today, in order to be able to then deliver value over time.
That is where hydrogen needs to go. It is much earlier stage than CCS. It does not have the clarity of policy and we are not going to see a T&S business model until 2025, which means that, if you want to deliver those 2030 or 2035 targets, it is just too long. You are not going to get there in time.
Phil MacDonald: Even this year, arguably, you could see green hydrogen competing with blue hydrogen. As the gas price spikes, you are immediately seeing that getting hydrogen from gas is becoming more and more expensive, so there is more and more potential for green hydrogen, coupled with the fact that, through the 2020s, the UK is increasingly going to have a surplus of electricity at some points of the year, and that is building up and up in all of the National Grid scenarios. By 2030, we are a major exporter of electricity.
If you have all that excess electricity, there is a real incentive to do something with it, and that can be turned into green hydrogen, if you have the electrolyser capacity, the desalination and all the technology that goes behind it. While you may already, with the gas price spike, be seeing it begin to be cost competitive, there is a lot of tech behind it that needs to be invested in.
There does seem to be enormous potential with that. It is now this balance point between gas, CCS and hydrogen, and whether that turns into blue hydrogen, for what the Government are investing in going forward.
Q121 Mark Pawsey: Matthew, you are developing a hydrogen plant at Teesside. Tell us a bit about that.
Matthew Williamson: We are developing a blue hydrogen plant and also a green hydrogen plant, because you have the resources, which are CO2 storage and offshore wind, available. The blue hydrogen plant starts off bigger, meaning a lower cost per unit, which is important from an overall cost efficiency perspective.
Most of that hydrogen will go into industrial consumption rather than power, although some of it will go to utilities that are providing heat and power in the Teesside area. From a power sector perspective, we would see hydrogen having a bigger role later on. In the first instance, it is really about industrial customers, and it is the mixture of blue and green, depending on what the lowest cost is and how we can do it as quickly as possible.
Q122 Mark Pawsey: Catherine, you said that there is no clarity of policy, but we saw, in August last year, the Government’s hydrogen strategy. Why is that not setting the framework that you would like to see for the future of this technology?
Catherine Raw: I should clarify “clarity”. There is ambition and there are targets, but how we achieve those targets and whether they are then sufficient to deliver the flexible capacity required to get to net zero by 2035 is where we lack clarity. Again, I go back to that transport and storage business model. In order to deliver the hydrogen production that is going to get used, you have to have some kind of T&S model.
Q123 Mark Pawsey: Has the UK fallen back? Were we leaders and have we lost a leading edge? The Financial Times tell us that the chief executive of Johnson Matthey said that the UK had lost its leading position. Is he right?
Catherine Raw: This goes back to the point that Olivia made, which is a good example. The Inflation Reduction Act lowers the cost of hydrogen, through tax incentives, which now makes it as competitive as any other form of power.
What you have seen is that projects are now moving forward, investment decisions are being made, and OEMs are moving to other countries where they see the future clarity being delivered. That is where the UK risks falling behind. It is because if you cannot make an investment decision and start construction, you are, essentially, just sitting on your hands and waiting.
Q124 Mark Pawsey: Matthew, you are making those investments. BP has made those decisions. You are investing, and so, presumably, you are comfortable with the Government’s ambition in this area.
Matthew Williamson: To be clear, we are making the investments in the early design phase of these projects. We will not be taking sanction until the legislation is passed, like the Energy Bill that puts into law the mechanisms that support CCUS and hydrogen. We need those put in place, and that will allow us to do the first projects.
Q125 Mark Pawsey: So you are saying that, until that legislation takes place, you are sitting on your hands in the way that Catherine has just described.
Matthew Williamson: Yes.
Q126 Mark Pawsey: Do you see any signals from Government that they are taking this seriously and moving at pace to provide you with that clarity?
Matthew Williamson: Every time we speak to an official or a Minister from BEIS, they assure us that things will move, and that is what we hope to hear.
Q127 Mark Pawsey: But you are not convinced.
Matthew Williamson: I am convinced that it will happen. I am just not sure about the pace and the scale.
Q128 Mark Pawsey: Do you agree that we have lost the lead that we once had and that others are moving more quickly?
Matthew Williamson: No, I do not believe that we have lost the lead, but we will if we do not take decisions quickly.
Q129 Mark Pawsey: You said that the plant that you are developing at Teesside generates blue hydrogen, but we heard from Phil earlier that we are going to have high gas prices for the rest of the decade, which is splitting existing natural gas. It is going to be expensive and, according to the Climate Change Committee, it is only 85% effective in reducing emissions. It is not net zero by any means.
We heard from Catherine that she is happy enough to accept a 90% capture rate, so 10% emissions. Yours is going to be higher than that.
Matthew Williamson: The blue hydrogen plant will be capturing over 95% of the CO2.
Q130 Mark Pawsey: You do not agree with the Climate Change Committee, then, that blue hydrogen has lifecycle emissions savings of only 85%. You think they are wrong.
Matthew Williamson: The number that I was quoting was the amount of carbon capture, which is part of the carbon emissions from an energy chain. The three key inputs to calculating the carbon impacts of a hydrogen plant are, first, the carbon-intensive natural gas that goes into it, so whether we are operating our gas fields in a good way with low methane intensity; secondly, the amount of CO2 that we capture, and 95% is industry leading and where we need to be; and lastly the carbon content of the power that goes in to drive some of the ancillary systems. With designing for a world-class hydrogen plant, you can see a similar carbon reduction for blue hydrogen and green hydrogen.
Q131 Mark Pawsey: But you are never going to get to a 100%, entirely decarbonised energy system.
Matthew Williamson: CCUS, together with hydrogen, can get us to net zero, so it is a combination of the two. It is not going to be one on its own.
Q132 Bim Afolami: I want to talk about the review of electricity market arrangements, otherwise affectionately known as REMA, but I just wanted to ask Ms Raw one question on hydrogen. I am thinking about this question particularly with your fund management background. What is the economic opportunity for the UK if we get this right? How significant is it?
Catherine Raw: It could be very significant, for two reasons. One is the ability to export the expertise—from a UK plc perspective, to apply the learnings from the UK globally. You could, effectively, grow business exponentially, because the thing about green hydrogen in particular is that it is very scalable. You are able to then scale hydrogen globally, particularly where your resources—your sun and your wind—are able to do that.
The second is the ability to export hydrogen. We would need to weigh up our competitive position relative to other countries, but that is very much defined by policy and by pace. Also, when you look at offshore wind, there is that trite phrase that we are the Saudi Arabia of wind. We could grow that capacity quickly and, therefore, accelerate and be ahead of the game versus solar or green hydrogen, for example, in Africa or the Middle East. Those would be the two ways that the UK could benefit from the hydrogen economy.
Q133 Bim Afolami: It is very good to hear the “Saudi Arabia of wind” phrase again; we have missed it in these halls.
On REMA, this is, first of all, to you again, Ms Raw, but I would like comments from others on this particular point. What outcomes are required from REMA to ensure that investment support schemes such as the capacity market bring forward the optimal technology mix at a cost that is viable or affordable?
Catherine Raw: To reinforce the point that you just made, market reform is required in order to prepare us for a renewables-led system, which our current system is not designed for. That just reinforces what you said. In order to create this low-carbon, renewables-led energy system, we need a market that reflects that.
There are three things that I would focus on in terms of delivering that. The first would be around non-flex low-carbon generation—by that, I mean renewables, but it covers multiple forms of renewables—and how you provide investment certainty over time. From our perspective, it would be rolling out and extending the CfD structure that exists today. That can be voluntary. In terms of a lot of the discussions that went into the levy, being able to disconnect renewables from the gas market and deliver that investment certainty over time is where the CfD benefits.
The second thing would be the capacity mechanism. That is around how you design it in such a way that it supports low‑carbon alternatives. At the moment, the way the system is working for CCS and hydrogen, for example, is that we would sit outside of the capacity mechanism, through a dispatchable power agreement.
When you look at, potentially, peaker power, OCGTs powered by hydrogen rather than gas, they would be selling into the capacity mechanism. You need to ensure that the mechanism is designed such that they would be preferred to unabated gas. If you do not have hydrogen at a cost-competitive level yet, relative to gas, how would you do that? That is a fundamental issue.
The third largest one is around how you keep the cost of capital as low as possible to deliver the £350 billion, which is what SSE estimates, of capital that is required to deliver net zero. Fundamentally, when you step back and ask, “What does REMA need to deliver?”, it needs to deliver a structure that allows that investment to take place at as low a cost of capital as possible.
Q134 Bim Afolami: Do any of the other witnesses have any comments that are differing to that or in addition?
Phil MacDonald: Going beyond the energy market reform, there are a lot of other blockages. There is a real blockage in planning. The time it takes to get a wind farm from entering the pipeline all the way to being deployed is far too long. There needs to be some kind of way of making that more efficient. There is also, again outside the market, the issue of transmission and making sure that, if all this power is going to be being produced in the north and the big population centres are in the south, that transmission can get the electricity to where it is needed. Those are two really key things that sit outside the electricity market format and have not been addressed yet.
Q135 Bim Afolami: To go back to the market reform, the Government have created bespoke support schemes for CCS and hydrogen. Certain think-tanks, as I am sure other have as well, argue that, by limiting competition between these technologies, the Government risk procuring a sort of weird mix of technologies and, therefore, making themselves vulnerable to lots of lobbying from lots of different people trying to get their technology to be the number 1. Therefore, perhaps the Government should just have a single mechanism that is one-size-fits-all to limit that. Do you think that that makes sense?
Phil MacDonald: I would argue the counter. With the example of things like offshore wind, at some point you have to pick winners. It might be expensive to begin with, but you have to test them for it. It is very difficult to design a model that can support these two very different technologies, particularly in the way they are transported and stored. It is very difficult to design one single thing that would equally boost them.
Matthew Williamson: It is clearly a very different energy system than we have had previously. Underpinning it has to be renewables, but that puts requirements on the system around flexibility and stability that maybe have not been there in the past. That needs to be a key output of whatever the energy design process is. Transport of energy, be that via electrons, hydrogen or gas, is an important part of that, as we move energy around the country. A lot of the energy is not where we need it as consumers. That is going to be an important cost input into the lowest, most reliable and flexible system.
Q136 Bim Afolami: Ms Powis, you have been admirably restrained. Is there anything you would like to add or comment on?
Olivia Powis: I do not think so, beyond what has already been said. The future power system needs to be looked at as a whole. Back to the role of power CCS, we need to consider the reductions in network reinforcements, reducing the overall balancing costs as a result of scaling up the proportion of renewables on the system. When we look at the whole package, we should consider the role that each of these technologies is going to play.
Chair: I am afraid that we have timed out, but I want to leave you with a question that I am going to write to you about afterwards. A lot of these questions assume CCS is going to work and we are going to deliver it on time. One thing we are interested in is the technology roadmap that the Government need to follow and the key milestones. Do you, or any others watching, have evidence around some of the milestones or contingencies that we need to think about?
I suppose that scenario 1 is that it all works, we get it up and running in time and everyone is happy. Scenario 2 is that we are late. What does that mean for investment decisions elsewhere in the power sector? Scenario 3 is that CCS works, but we do not build the infrastructure to deliver it. Scenario 4 is that CCS does not work in the way we want it to for power generation.
I would be keen to see if there is any evidence, from you or others, that could maybe illustrate what that means in terms of investment case decisions that need to be made around the alternatives that then have to happen if those scenarios come to reality. I will leave you with that open-ended question, I am afraid, because of time. Thank you to all four of you for coming in and for your answers today.