Drax Group plc (OTCPK:DRXGF) Q2 2022 Earnings Conference Call July 26, 2022 4:00 AM ET
Company Participants
Will Gardiner – Chief Executive Officer
Andy Skelton – Chief Financial Officer
Conference Call Participants
John Musk – Royal Bank of Canada
Martin Young – Investec
Mark Freshney – Credit Suisse
Will Gardiner
Thank you, and good morning, everybody. I’m here with Andy Skelton, our Group CFO, and we will take you through the presentation followed by a question-and-answer session.
So I’m going to start on Page 5. So as you all know, our purpose is and continues to be very much at the core of who we are. It’s about enabling a zero carbon, lower-cost energy future. And again, our ambition is to be carbon negative by 2030. Importantly, we continue to be the largest U.K. pure-play renewable power company. And over the most recent period, we generated 11% of all of the U.K. renewable power. And again, we’re also the world’s leading biomass generation and supply company. Over the last 6 months, I would say that global momentum for decarbonization continues to grow in spite of all the challenges that we see around us. And I would say importantly, the importance of carbon removals and the role that Drax can play to deliver them globally is becoming increasingly widely recognized.
The other key message for the last 6 months is we’ve been very focused and I think successful in helping to support security of supply in the U.K., enabling us to generate significant amounts of cash, and that supportive environment is allowing us to accelerate our investments in renewables globally. The final point I would make before I could pick up the sort of the core of the presentation is that the broader stakeholder appreciation of the role that Drax is planning is growing, and we are increasingly well positioned to take advantage of growth opportunities in flexible renewable generation in the U.K. and in biomass and BECCS globally.
Turning to Page 6. We’re making great progress with our strategy and have lots of options for growth, both in the U.K. and globally. We’re making progress on our pellet expansions, on U.K. BECCS and on Cruachan 2. We’re also increasingly excited about the opportunities for BECCS in North America. We’re working on site selection. We see increasing regulatory support and more commercial interest, which should enable us to do projects that will deliver attractive returns. In terms of the end year performance, we’ve had a strong financial and operational performance. Our EBITDA of £225 million is up by 21%.
In pellet production, our output has increased by over 50%. In our generation business, the importance of our secure sustainable dispatchable, renewable power has never been more cleared. And in our customer business, we’ve delivered a good operational performance and strong EBITDA. And as evidence of our confidence in the business and the opportunities in front of us and also in line with our policy on dividends, the Board is expected to recommend an increase in the dividend per share to 21p for the full year, an increase of just under 12% for the year.
Turning to Page 8. Our aim is to be a future positive company. We’re building a long-term sustainable business for strong operational and financial performance that delivers low carbon growth. We’re looking to deliver people positive, nature positive and climate positive outcomes with the well-being of our employees and our communities at the core.
To talk first about people positive. Safety remains our top priority and the increase in recorded incidents in the first half of the year is a challenge that we’re addressing. Our safety culture is very strong. The safety as the top priority requires constant attention. And over the last 12 months, we’ve begun implementing a rigorous HSE improvement plan across North America as well as reiterating our focus across the entire group as we align safety and environmental practices across the business. And we expect investments in training, human resources and capital projects to deliver improved performance.
Turning to nature positive. All of the biomass we produce and use is audited against international biomass and forestry standards to ensure a strong chain of custody, which is fully in line with the best available science from the IPCC and underpinned by international law. And the third leg of our positive story is about climate. Over the last decade, we’ve invested over £2 billion in renewables. And as a result, we’ve reduced our emissions — our CO2 emissions by over 99% more than any other European utility. And now over 99% of our power generation is from renewables, and that accounts for over 97% of our earnings.
And as you know, we have a £3 billion investment program that we intend to carry out over the coming decade. And the BAT program, over 90% of it is invested in renewables or will be invested in renewables. We recognize the need to reduce emissions in our biomass supply chain to the Drax Power Station, and we’re doing that. Over the last 5 years, those emissions have declined by over 20%, or I should say we have reduced those emissions by over 20% and have set ourselves further challenging targets to reduce the residual Scope 1, 2 and 3 emissions that we still have, by 42% relative to 2020 as part of our plan to become carbon negative by 2030.
And we continue to identify opportunities to further reduce emissions at all stages of our supply chain. And in July of this year, we signed a memorandum of understanding with the Japanese shipping company, MOL, to develop wind power technology for using shipping biomass between Canada and Japan.
Let me talk a little bit more about our operations, and I’ll start with our pellet production on Page 10. Operationally, our pellet business continues to develop nicely. Production is up 54% and EBITDA is up 13%. Overall, our costs have been well controlled with significant increases in fuel and utilities as well as the impact of commissioning and optimization significantly offset by reductions in controllable costs, while at the same time, we had kept fiber costs broadly flat.
Our international logistics costs are well protected by our long-term hedge position and our third-party fiber purchases have seen small elements of price escalation. And Andy will take you through more detail around our cost position as it pertains to pellets. At the same time, we’ve commissioned 2 new pellet plants, adding 400,000 tonnes of capacity, and we expect to take a final investment decision up to an additional 500,000 tonnes of new capacity later this year.
Turning to Page 11. We have a high-quality order book with over 21 million tonnes of long-term contracts to high-quality counterparties across Japan, Asia and Europe, with sales revenue of $4.4 billion. And we have ambitions to grow that book, as you know, to 4 million tonnes per year by 2030. And as part of that strategy, we’ve opened a new office in Tokyo a couple of weeks ago to support the growth of our business in Japan and across Asia.
Turning to Page 12 to talk more about generation. Our generation continues — our generation business continues to perform very well, providing 11% of the U.K.’s renewable power. Against the backdrop of increasing concern around European energy security, during the first half of the year, we’ve optimized our biomass generation and logistics based on the amount of available biomass that we can see across the year, providing additional security of supply to the U.K. at times of expected higher demand.
So what does that mean in practice? In practice, this means generating less in this summer when demand is low and reprofiling biomass deliveries to support higher levels of generation in the winter when demand is high. We expect to benefit from incrementally higher power prices and better availability as a result, but we have incurred additional biomass and logistics costs in order to deliver those actions. The integrated nature of our biomass generation pellet production and logistics has been a key enabler of this action, supporting U.K. energy security as well as creating value at a group level.
Turning to system support. That was very strong, particularly at Cruachan given the volatility we saw in the system. Overall, gross profit from system support services increased, and we continue to expect that the value of these services will grow over time as the U.K. energy system becomes more dependent on intermittent and inflexible generation and the role of dispatchable technologies becomes more pronounced. And as you know, coal running was extended by 6 months at the request of the U.K. government, again, to support security of supply. We will receive a fixed fee for that as well as recovery of our costs, but we will not run commercially. And importantly, in doing so, we have not made any changes to our plan or our schedule for BECCS at the Drax Power Station.
Turning to Page 13, talk a bit more about our trading and optimization. Our power sales strategy, which is to sell forward to the extent that there is liquidity in forward markets is unchanged. Between 2022, this year and 2024, we have a strong contracted position on our biomass units, and we’re expect to sell around 14 terawatt hours per year across the ROC and CfD units. We’re fully hedged for ROC sales this year to a large extent hedged next year, while 2024 remains more open, again, due to the lower levels of liquidity to further out one gas. I would note that we expect to deliver 2 planned outages on the ROC units next year. And accordingly, based on current estimates, ROC generation will be incrementally lower as a result.
Finally, to conclude the operational review, I’ll talk about our customers on Page 14. I’m very pleased with the performance of our customer business. The team there has done an outstanding job both operationally and financially to recover from what was a very challenging environment during the pandemic in 2020 and 2021. As you know, we’re repositioning our customer business to focus on its high-quality I&C customer base. Those customers are lower risk than the SME customer base and are more aligned with our corporate purpose of enabling a zero carbon lower-cost energy future. And they’re all consumers of renewable power, which is an increasing demand in the U.K. And as you all know, there is a significant premium emerging for renewable power, which positions us well as the largest generator of renewable power in the U.K.
And with that, I’ll hand it over to Andy to give you a financial review.
Andy Skelton
Thank you, Will. So starting on Slide 16. Adjusted EBITDA of £225 million is a 21% increase on £186 million in the first half of last year. It reflects increased pellet sales, a strong performance across our generation portfolio and improved profitability in our customers’ business. Excluding the gas operations that we disposed of in January ’21, the adjusted EBITDA from continuing operations grew 36%. Whilst we have seen some inflation pressure in our biomass cost base, the integrated nature of our biomass supply chain and operations, combined with long-term contracts that we have in place for fiber, pellet procurement and freight continue to provide a good level of protection from any cost increases.
Further, with indexation of U.K. renewable schemes and price escalators and third-party sales contracts, inflationary pressure in our cost base is offset by revenue growth. We have strong liquidity with available cash and committed undrawn facilities at the end of the period of £539 million. Cash generated from operations of £185 million increased 34%. For maintaining capital discipline, this strong cash generation provides capacity to invest in growth and support the payment of a sustainable and growing dividend in line with our long-standing capital allocation policy.
We closed the period with net debt to adjusted EBITDA of 2.5x and continue to expect this will be significantly below 2x by the end of 2022. Consistent with our policy to pay a dividend, which is sustainable and expected to grow, the Board has resolved to pay an interim dividend of 8.4p per share and expect this to be 40% of a full year dividend of 21p per share, an increase of 11.7% from 2021, and this is subject to continued good operational performance in the second half of the year.
So moving on to Slide 17 and pellet production cost. We’ve produced 2 million tonnes of pellet in the first half of the year, an increase of 54%, which primarily reflect the full 6 months’ worth of production from the clinical plants acquired in April 2021. During the period, we shipped 1 million tonnes to the third parties compared to 400,000 tonnes in the first half of last year and 1.2 million tonnes for the whole of last year. From the start of our cost reduction program in 2018 up until the end of ’21, our FOB production cost reduced $23 a tonne or 14% to $143 a tonne for the full year 2021.
Overall, in the period, our costs have been well controlled. However, we have seen an increase of 2% in the FOB production cost to $146 a tonne. This increase principally reflects the impact of inflation on utility costs, which have increased over 20% and in-country fuel surcharges. So that’s transportation costs of fiber to plant and pellets from plant to port, which have increased over 10%. It also reflects higher average production costs during commissioning of the plants at Demopolis in Alabama and Leola in Arkansas.
Excluding these items, we continue to make progress on our cost reduction initiatives with a small reduction across the balance of production costs. With good fiber availability and taking account the changes in fiber mix by plant, there was no material change in overall fiber costs. During the period, our pellets business provided flexibility in biomass supply to support the reprofile in the biomass generation in Drax Power Station. Whilst this resulted in some additional costs, additional value has been created for the group across the financial year, demonstrating the value of our integrated business model.
We continue to see opportunities for further cost reduction in line with our strategy. These reductions won’t come in a straight line, and we’ll always continue to optimize the value across the group. In addition to the increased production volumes from existing plants during the second half of the year, we expect to take final investment decisions on up to 500,000 tonnes of additional pellet production capacity, continuing the progress towards our aim to develop 8 million tonnes of production capacity by 2030. Further future cost savings will be delivered through widening our sustainable fiber envelope, continued operational efficiencies across production and logistics and development of new technologies and innovation.
Moving on to Slide 18, the adjusted EBITDA bridge. Our pellets business delivered adjusted EBITDA of £45 million, growth of 13% and benefiting primarily from increased volumes. In addition to the increase in FOB production costs, I’d note that margin in the pellet business reflects a mix of whether shipments are made to Drax Power Station or to our third-party customers in the first half of this year, reflecting the acquisition of Pinnacle in April 2021, a higher proportion of pellets were shipped to third parties. Margins on these sales reflect the long-term nature of those contracts and the embedded shipping terms that primarily set versus foster our sales to Drax Power Station.
Margins also impacted by the mix of pellets sourced on third parties are produced by gas. Margin on pellet sourced from third parties reflect that they are pass-through in nature, and they leverage our existing supply chain infrastructure. And finally, I’d note an increased investment in nonproduction costs to support future growth opportunities in North America. In generation, the strong operational performance in biomass and pumped storage hydro was reflected in commercial availability of 86% on the biomass units and a 12% increase in the value of system support services provider.
Against the backdrop of increasing concern around European energy security, we’ve optimized our biomass generation and logistics to reprofile generation from summer to winter to provide additional security of supply at times of expected higher demand. We expect to benefit from incrementally higher power prices in the winter, but have incurred additional costs, both to ensure that we have biomass available at the right time and also to buy back the summer positions.
To enable this delivery profile, which supports the security supply of the winter and to mitigate the financial risk associated with unplanned outage, we expect to run increased base load volume in all 3 ROC units holding the CfD unit to provide resilience in the event of an unplanned outage. The outturn for the full year will therefore reflect operational performance of the ROC units in the second half of the year and the price achieved for any additional CfD generation.
Our customers’ business delivered adjusted EBITDA of £24 million, a significant improvement on the £5 million loss in the first half of ’21, which was impacted by COVID-19 since [indiscernible] in the SME business. Improved profitability includes a mark-to-market benefit from lower customer demand where excess power is being sold back into the wholesale market.
So turning on to Slide 19 and capital investment. CapEx in the period totaled £60 million, and we expect it to be in the range of £290 million to £310 million for the full year. The maintenance CapEx of £70 million to £80 million includes recurring and one-off maintenance at Drax Power Station, our hydro sites and our pellet plants. We continue to evaluate options for our open cycle gas turbine projects. These assets can play an important system support role.
And whilst it’s likely we won’t hold these assets in the longer term, we continue to invest as appropriate in the short to medium term to fulfill our obligations under the capacity market contract and also to maximize value from our investment. We expect that CapEx this year will total up to £120 million. As I noted, we also expect to take FID on 0.5 million tonnes of new pellet capacity during the second half and expect spend this year to be around £10 million.
So moving on to Slide 20 and looking at the balance sheet. We maintain a strong focus on cash flow discipline and maintenance of a robust balance sheet. It provides protection in times of economic uncertainty and a strong platform from which we can execute our growth strategy. Available cash and committed undrawn facilities provides substantial headroom over our short-term liquidity requirements. As expected and reflecting the Pinnacle acquisition, closing net debt to adjusted EBITDA ratio of 2.5x at the end of the period, and that’s calculated on a rolling 12 months EBITDA is above our long-term target of around 2x, but we continue to expect the group’s net debt to adjusted EBITDA ratio will be significantly below 2x by the end of ’22.
Both Fitch and S&P have recently affirmed our corporate credit ratings at BB+ stable. We also have a BBB flat investment-grade corporate rating from DBRS. The quality of our group’s assets, earnings and cash flows provide further opportunities to continue to reduce the margin on our debt in the future. To support our growth ambitions for BECCS and other large-scale infrastructure projects, we saw as much flexibilities possible within the capital structure. During the period, we paid down a £35 million index loan as it matured, and our next maturity is in 2024, ’25. The $500 million U.S. bond is now our most expensive cost of debt with a swapped back rate in £of just under 5%, and it’s fully repayable at par in May of next year. We continue to assess economic opportunities within our capital structure.
So now moving on to Slide 21, sources and uses of cash. Earlier, Will mentioned our plans to invest a further £3 billion this decade in our biomass supply chain, its tactile generation and negative emissions in the U.K., which all underpin our ambition to become a carbon-negative company by 2030. As a reminder, at our CMD last December, we laid out how we think about self-funding these investments through returns generated from the existing business and returns generated by those strategic investments.
So noted our existing business is highly cash generative with strong visibility over a high proportion of long-term index-linked cash flows, we expect that our investment for growth will be underpinned by long-term linked earnings and cash flows and whether that be power and carbon payment schemes for U.K. BECCS, a cap and floor type mechanism for Cruachan 2 or long-term contracts with high-quality counterparties with expansion of our third-party supply business.
So starting with our end of ’22, net debt leverage below 2x. We’ve assumed circa £2 billion of free cash flow from the existing business. Next, the £3 billion of strategic capital investment, the pellet capacity expansion, U.K. BECCS and Cruachan 2. And finally, $1 billion of post-tax cash flow from these strategic capital investments by the end of 2030. There will be a phased contribution based on when projects become operational with the first additional pellet plants in ’24, the first BECCS unit in ’27 and the second BECCS unit and Cruachan 2 in 2030. And these investments are underpinned by high-quality stable earnings and will deliver strong indexing cash flows well beyond 2030.
So overall, this plan delivers a business in 2030 with significant EBITDA expansion, generating significant high-quality free cash flow, returning a growing and sustainable dividend and with a net debt-to-EBITDA leverage significantly less than 2x. This plan also provides the capacity to support additional investment in BECCS outside the U.K. We will always maintain strong capital discipline and the investments will always be subject to appropriate levels of risk and return. We believe that our high-quality strategic portfolio provides a range of options for financing and our base plan is to self-fund these investments without the need for issuing equity.
So finally, moving on to Slide 22 in capital allocation. Our capital allocation policy launched in 2017 has served us well and remains unchanged. We believe that our ambitious growth plan is supportive of maintaining our credit ratings, paying a dividend, which is sustainable and growth throughout the period of strategic investment.
With that, I’ll hand back to Will.
Will Gardiner
Thanks, Andy, and I’d like to just talk a little bit about our strategy, and then we’ll open it up for questions. So turning to Page 24. Drax is undergoing a remarkable transformation and is a growing international business at the heart of the green energy transition. This last half year has shown the value and importance of our business at the heart of the U.K. energy system, supporting an increasingly decarbonized system with dispatchable, renewable power, and we are investing to grow that business.
Equally, the global demand for pellets is growing, and we are investing to meet that demand. And finally, I’m increasingly excited by the opportunities for BECCS globally. Carbon removals are rapidly moving up the agenda. Global policy frameworks are increasingly supportive and we have a leading position with our product in the U.K. and the work we’re doing in the U.S. and beyond. As a responsible business, driven by our purpose of enabling a zero carbon, lower-cost energy future, we are reinvesting the vast majority of our cash flow in renewables to achieve our ambition of becoming a carbon-negative company by 2030.
Turning to Page 25. Our strategy is about positioning Drax for long-term low carbon growth. In February, we laid out a series of milestones against which we could judge our progress in the delivery of our strategy. And as you can see from this slide, we’re making excellent progress.
Let me talk more specifically about BECCS in U.K. on Page 26. In terms of our technology, our FEED study is progressing well, and we’ve commenced early-stage enabling works. I would note that our agreement to provide a winter contingency service to the national grid from our coal units is not expected to have any significant impact on our timetable for BECCS. Secondly, we submitted our planning application as expected. And third, the government’s priority project selection process for gas, hydrogen and industrial CCS projects is well underway.
Earlier this month, the government published a consultation on GGR or greenhouse gas removal business models, which include BECCS. And they will also separately consult on a power BECCS business model, which is quite reflective of its advanced technological readiness and the co-benefits of both power and negative emissions. It is very clear that the government is committed to BECCS and committed to greenhouse gas removals. And we expect to hear more on this as well as see the publication of the bioenergy strategy review in the second half of the year.
Finally, I’d like to say a few words on REMA, the review of energy market arrangements, which also just published that the U.K. government’s long-term plan to identify and implement electricity market reforms to incentivize investment and operation of a secure low carbon electricity system by 2035. Amongst other things, the government and also National Grid and its future energy scenarios, the scenarios include BECCS as part of their base plan, while also indicating that generation capacity will need to increase threefold by 2035 requiring investment of up to £400 billion. And we believe that our flexible renewable and low-carbon generation portfolio is well aligned with these long-term objectives. And I would note that the government’s net zero strategy has previously indicated a requirement of 23 million tonnes of negative emissions by ’24 as well as rising up to 81 million tonnes in 2015.
For context, that would be the equivalent of 5 and then 20 BECCS units of the Drax Power Station. While it’s early days in terms of the consultation, there are multiple options that the government is looking to get inputs on. We think that our position in the system and our strategy is well aligned with whatever that market assessment may go. And critically, I think the investments that the whole energy system requires will need a stable long-term investment framework. And as such, we would expect that REMA will be consistent with enabling that [indiscernible].
Turning to International BECCS on Page 27. We’re making great progress with our international BECCS work. We’ll be getting more specific about our plans, certainly on our technology and building the business case. We’re most active in the U.S., where legislation is moving in a supportive direction and I’ve laid out some of that on the slide. And there is a clear ambition at both the state and federal level to support greenhouse gas removals, including BECCS.
And through the remainder of the year, we’ll continue to engage with policymakers, narrow down region, sites, technology options as well as progress commercial discussions with potential buyers of firm renewable power and negative emissions. I would also say that outside of the U.S., we’re seeing increasing interest in coal to biomass conversions, which we expect also to lead to additional opportunities to provide BECCS.
Finally, on Page 28, a bit on our outlook. So our purpose, enabling a zero carbon, lower-cost energy future remains at our core. As does our ambition of becoming a carbon-negative company by 2030. And our strategy is now designed to deliver growth in 3 areas: pellet sales, negative emissions and dispatchable, renewable power. Fundamentally, I’m extremely excited about the future of Drax. We sit in front of a massive energy transition globally that will require our biomass, our BECCS and our ability to generate and sell renewable power and system support. We have a unique position with our portfolio of the assets, and we are increasingly positioning the company as a growing international business at the heart of the green energy transition.
Thank you for listening, and Andy and I are happy to take any of your questions. Why don’t we start with live questions, and then we’ll also take the ones that — written ones that may come in from those of you on the webcast.
Question-and-Answer Session
Operator
[Operator Instructions] Your first telephone question today is from John Musk from Royal Bank of Canada.
John Musk
That’s great. So yes, three questions. Firstly, on the pellet costs and the slight increase that we see there. Really just to get your sort of thoughts on how achievable the previous targets now are. So I think we had a target of $130 per tonne for the end of next year and then $100 per tonne in 2027. Yes. Are they still achievable? And I guess secondary to that, are they still the right targets given the inflationary pressures we’re seeing around the world and also given the power price environment that we’ve got in the U.K., do those targets still makes sense to you?
And then secondly, on the CapEx, obviously, it’s increased with the OCGT spend of £120 million in there. But I think like-for-like, it’s actually gone down. Seemingly the CapEx on the FEED study, the BECCS and the CapEx on some of the pellet plants is lower than what we were guided at the full year. So what’s going on there? Are they just sort of slightly delayed in terms of the CapEx on those projects?
Will Gardiner
Okay. Yes. I think we lost you a little bit at the end there, John. But I think the question was, are we changing our CapEx guidance in terms of some of the things other than the open cycles. I’m going to actually ask Andy to answer both the pellet cost question and also the CapEx question.
Andy Skelton
So on the pellet cost, John, as you saw in the first half, we’ve had the inflation pressures on utilities and fuel surcharges, which I expect will continue through the second half of this year. And to some extent, the commissioning of Demopolis and Leola will have some costs in the second half as well. And we have been, as we know, optimizing to make sure that we can support the generation reprofiling and that means we incur some costs. But ultimately, for the group, there’s value there, and that makes absolute sense to do it. So clearly, the exit run rate that we leave this year will be higher than we previously thought.
But I think the important thing is that the opportunities for cost reductions haven’t changed. And we’ve always said that those cost reductions won’t come in a straight line. And clearly, we’ve made very good progress since the start of that program, but we’ll continue to focus on taking costs out of the pellets and believe there’s opportunity to do that. To your second point, though, $100 a tonne was set in a context of £50 of megawatt hour power prices, and that’s not well in line right now. So maximizing value means that you need to access pellets at the right time and get them to the right place. And if it takes extra cost to do that, but create value for the group, then that’s something that we will continue to do.
So no change in the opportunity to take cost out, opportunity to optimize and create value and some short-term inflationary pressures. On the capital, it’s just a phasing thing there. And I think of when the FIDs on new pellet plants happen, so we expect now 1 before the end of the year. And so the spend is slightly lower. And I think what was the second piece of that was power and the FEED study. I think the FEED study, John, there’s no slowdown there. It’s progressing according to plan, just slightly lower value than we had previously expected to spend to date, but no change in those projects.
Operator
The next question comes from the line of Martin Young from Investec.
Martin Young
I’ve got a couple of questions as well. Can I just continue firstly, on the pellet cost issue that John — yes, mentioned totally buy into the idea that the opportunity for cost reduction is still there. But if various component parts of the cost of a pellet has gone up, surely, we should be looking at rebasing the $100 per tonne target — maybe by not a lot, but yes, maybe to $105, $110, that type of number. Is that a reasonable way to be thinking about it?
And then the second question was about what you were saying in respect of output in calendar year 2023. Do I interpret those comments saying there will be a significant step down in the ROC units, but given that everything is pretty much driven by biomass availability, you’d get the CfD unit back up to about 5 terawatt hours’ worth of output, meaning you only have to do 9 across the 3 ROC units to get to the 14%. So this is not a case of you guiding down on actual generation from the entire plant. This is just you telling us that the ROC performance of 2022 is unlikely to be repeated in 2023.
Will Gardiner
Maybe I’ll take the second one. The second, probably easy, Martin. I think you’ve answered the question very well. So I think the way you described it is right. We wanted to make sure that people were aware or I’m sure you are aware of it to sort of highlight those 2 outages because it does impact the where and which units will generate and the timing of it. So — but that shouldn’t — again, the major constraint we have on overall generation is the availability of pellets, right? So I think you’ve got that one right. And then maybe I’ll go back to Andy again on the pellet cost.
Andy Skelton
Yes. I mean we’ve always had inflation in our pellet cost base. It’s just the cost reductions we’ve made about strict. That inflation is harder to do in the current environment. And if you look at where those costs are, they’re on utilities, and they’re on bunker fuels. So that’s a common theme right now. And I guess if you’re in a world of higher utility costs and higher bunker fuel costs probably in a higher commodity price environment and in the whole picture for Drax, that extra cost in the pellet doesn’t – isn’t a huge concern and in a higher commodity price environment, continued opportunity to optimize.
So I’m not – like we’re not formally moving our pellet target right now, but clearly, chasing the $100 a tonne and giving up commercial value for the group doesn’t make sense. We’ll do the best thing to maximize value for the group, but there’s always going to be value in taking costs out of that pellet cost base. And as you know, the opportunity still remain to do that, and we’ll keep focused on that.
Operator
[Operator Instructions] The next question is from the line of Mark Freshney from CS.
Mark Freshney
Firstly, on cost inflation for the CapEx projects. I mean clearly, OCGTs would have been largely fixed. But I’m thinking in terms of what your FEED studies are showing for some of the capital cost. And secondly, I was intrigued a couple of weeks ago by Ofgem’s balancing market review and the work they had done with ESO and some of the, as they call it, immoderate bidding behavior by generators. And it’s pretty clear that Ofgem is going to have to intervene in that market to stop scarcity pricing somehow. I was just wondered — I just wondered on your thoughts regarding that investigation and how that may impact the dispatch of some of the Drax units, if at all.
Will Gardiner
Thanks for those questions, Mark. Let me — I’ll start with the cost inflation. So I think you’re right. The open cycles are largely fixed. I think we’re in a reasonable phase there. FEED study, we haven’t got any numbers to give you guys yet on that. I think you’re right. We would expect that relative to where we were a couple of years ago, there will be inflation in some of those numbers. But I think importantly, if you think about the long-term sort of value or sort of drivers of value across the best investments, it’s really the sort of long term, that the operating cost is probably in some ways more relevant than the capital costs over the lifetime. And so to Andy’s point, we continue to try to make and find ways to make sure we keep the pellet and fuel cost down, and that’s the sort of very much of our focus.
But again, as we finish those FEED studies, we will again incorporate those numbers into our plans for what it costs and then the returns that will be required. In terms of the balancing market review, I mean, the Ofgem wants to make sure that people are operating in the markets as they should do. And as you noted, they are sort of continuing to investigate some things that happened there. How they end up responding to sort of where that market is, I mean, it remains to be seen. I think that the value and the importance of system support and values of dispatchable power — yes, continues to be important. And I think, again, obviously, we are always dispatching those in ways that are compliant and consistent with the way the rules of the market work, and we’ll continue to do that.
Mark Freshney
And if I could just have a follow-up, Will. Would it also be fair to say that increasingly you’re running baseload stents during winter for unit reliability and to squeeze any output out? So actually, balancing market activity and two shifting is going to be a lot less relevant for yourself, certainly, once you have divested — sorry, potentially dealt with options for the OCGTs.
Will Gardiner
No, I think that’s fair, Mark, a couple of points. One is, again, just to make sure it’s crystal clear. On coal, we’re not running those commercially, so that we will not be earning balancing market or prompt level pricing on those. That’s the way the contract has been set up. So I think that’s important. As you say, we’ll be running more base load across the winter on the ROC units. Again, so the less opportunity to be operating in the BM. And as you know, we’re holding back the CfD unit as a reserve in the event of outages. So again, I would agree with your comments. Yes.
Operator
There are no more telephone question at this time. I hand back for the web questions.
Will Gardiner
Okay. Let me — I will — why don’t I read out the questions, and then I will ask Andy to answer that probably. Yes.
So the first question from Ahmed Farman. Can you please give us some guidance on where you expect biomass FOB by year-end? What were the buyback costs on CfD units in the first half? And what are your expectations on these costs for the second half?
Andy Skelton
I think guidance of the first part on the biomass cost by year-end. On the CfD units, I mean, the cost of buying back of CfD units is very significant. But clearly, it’s only done based on the reprofiling and we expect this value as a whole in doing that. But most of that reprofiling has been done in the first half of the year. So we’ll incur less cost in the second half of the year, I would expect. But so it’s a significant cost, but value overall for the group.
Will Gardiner
Second question from Andy Wilson. Has there been any further discussions with the winter contingency going beyond this winter if the war continues? And if so, how would that affect the BECCS’s timetable? Is there a space to build BECCS with the coal units still up?
So the answer to the first part of that question is that no, there has not been any discussion about running cost at the end of March of next year. If so, I mean, clearly, that sort of moving down on March becomes difficult for a bunch of different reasons, including the BECCS’s timetable, including sort of maintaining the core units, et cetera. So it will be quite difficult for us to do that. And the final point, is there a space to build BECCS with the coal units still up? And the answer to that is no.
Next question from Verity. Chart — does the chart on Page 21 on investment include the open cycle or the OCGT completion?
It doesn’t include any U.S. BECCS expansion.
And you have a target for U.S. BECCS now. So how would you think about financing this? Why don’t I ask Andy to look at the first 2 and I’ll answer the third piece, right? So yes.
Andy Skelton
So the chart, it’s the same as the one that shows the December, Verity, so it doesn’t include the OCGTs. But I think on the point that we don’t expect to be the holder of those in the long term, any CapEx that goes out would be recovered. So in that whole period, I don’t think it would impact the ending position. And you’re right that it doesn’t include any U.S. BECCS expansion. So I think we had noted that because of the leverage at the end of the period and the strong cash flow. And clearly, things have meant since December further positively that we have the capacity for further investment, which would include the U.S. BECCS.
Will Gardiner
Yes. No, I’d just reiterate on the last point, Verity. I mean I think we haven’t formally updated and the chart that you see there is the one we showed back in the corporate Capital Markets Day. But there’s no question that given where our cash flow — expected cash flow’s interaction has gotten to, we would be able to finance on our balance sheet, one, if not more BECCS units in the U.S. and really depends on overall. How we finance BECCS outside of the U.K. will obviously depend upon our ambition about which we would expect to talk more at the Capital Markets Day, which is not formally scheduled but probably will be in November.
Another question from Ahmed. Could you talk about the impact of the cost inflation that you’re highlighting today on the economics and CapEx of your future BECCS projects?
So why don’t I take that one on that side. I think the — I talked a little bit about the CapEx already. So maybe back up. I mean the way that we expect the project to work in the U.K. is that we ultimately will negotiate a CfD contract with the U.K. government that will compensate us for a combination of the power on the carbon removals. And that will be very much based on the cost of the projects, and it will include — which will have to account for both where our costs have gotten to at the time the contract is completed, but also where we expect cost to be over the life of that contract, right? And that, we’re doing a lot of internal work on that ourselves now. We have not begun talking to government about that. Obviously, we still need to see the formal BECCS business models, and that’s yet to come, but that’s our current expectation is that ultimately that contract will be based on our cost base and the expected return that we would discuss and negotiate with government, right?
Outside of the U.S. — sorry, outside of the U.K., the projects we’re looking at in the U.S. and elsewhere might have a similar type arrangement or they might be more commercially based, meaning that, yes, we believe that there are markets in the U.S. where there’s a attractive demand for both carbon removals as well as 24/7 firm green power. It effectively will allow us to sort of do this on a more commercial, probably a long-term PPA type basis, where the — we negotiate those contracts on a commercial basis with uptakers of both the carbon removals and the power, and we would aim to make sure that we get a fair deal for us, a fair deal for them that allows us to earn the right return on our capital.
And then the next question from Verity again. For the customers’ business, how much of the return to profitability came from the sale of forward hedged power not required by the customers? And I’ll hand that one over to Andy. Yes.
Andy Skelton
So if you look at £24 million versus a loss of £5 million in the period last year, that’s around 30 improvement, £10 million to £15 million of that we flagged as being the COVID impact last year. So that leaves another circa £15 million, and the majority of that is on the sale of back of that power. Now there has been, and we continue to focus on managing our costs within our customers’ business. And over the last 12 months, we’ve closed offices in Cardiff and Oxford. So some of that is cost reduction and focus on that, but a large part of it the mark-to-market on those sales.
Will Gardiner
So a question from Tim Ashton. Are you able to give any feel for how cost competitive U.K. BECCS will be relative to competing decarbonization plans or what the noncash advantages would be if U.K. government decided to back that one climate change investment, right?
So a couple of thoughts on this. One is that the overall sort of cost base we’ve been discussing or the sort of the target price we would expect to get for the combination of 1 megawatt hour of power and 1 tonne of carbon removal is broadly speaking about £150. Again, as you know, relative to where the power price is today, that’s a pretty attractive package. And also, I should say, more — to be more clear, relative to the power price and the price of carbon, right, it’s a quite attractive bundle, right? So you’re basically getting a megawatt hour of power and a tonne of carbon removal for much less than need to get that power in the market and that CO2. So that’s one metric to look at. And obviously, who knows where that will be over a 10- or 15-year lifetime.
The other one to look at is what’s the relative cost of other carbon removal technologies. And if you look at what direct air capture players are selling their government renewal for, they’re getting north of $500 a tonne, right? So again, I think our technology is quite attractive relative to those. But fundamentally, I think the key point for me is that the — one of the things that’s become — is clear to me and becomes always more clear to me is the importance of the Drax Power Station to the overall U.K. power system. And having that sort of asset running, delivering today, renewable power in the future, carbon-negative power is going to be critical to the U.K. system because of the dispatchable nature of that power. So we think it’s a very good value for the investment.
Maybe the final point I would make is we’ve done a bunch of work, which I’m sure is on our website, which basically sort of describes how Drax project is a very low-cost way economically for the overall economy, very low-cost way of decarbonizing to the nature of multiple billions, less expensive than other options. And I guess, final point is, if the government is — well, I should say, yes, the government is absolutely serious about leveling up. And the jobs benefits, the supply chain benefits, the U.K. innovation benefits of having Drax Power Station are quite significant and would be a critical part of any decarbonization efforts in the number, which will be, I think, critical to the U.K. developing a next-generation green economy in the north of England.
Okay. It looks like that’s all the questions. So thank you all very much for joining us, and you know how to get in touch with us if you have more questions or want to follow up later. Thanks very much, and have a good day.
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