Annual Financial Report

Drax Group PLC

26 February 2026

 

26 February 2026

DRAX GROUP PLC (Symbol: DRX)

FULL YEAR RESULTS FOR THE TWELVE MONTHS ENDED 31 DECEMBER 2025

Record levels of renewable generation

Twelve months ended 31 December	2025	2024
Key financial performance measures
Adjusted EBITDA(1/2/3) (£ million)	947	1,064
Net debt(4) (£ million)	784	992
Adjusted basic EPS(1) (pence)	137.7	128.4
Dividend per share (pence)	29.0	26.0
Total financial performance measures
Operating profit (£ million)	241	850
Profit before tax (£ million)	190	753

Drax Group CEO, Will Gardiner, said: "In 2025, we produced more renewable power than ever before, delivering energy security for the UK. Our colleagues and supply chain partners work around the clock to help keep the lights on for millions of the UK's households and businesses, no matter the weather.

"The signing of the new low carbon dispatchable CfD is an inflection point for the Group. It provides the foundation for us to keep supporting the UK with the flexible, renewable power it needs for security of supply this decade and beyond.

"The energy transition and growth in AI are creating opportunities for us to invest and grow our business further in line with the country's energy needs. We are making good progress on this with our initial investments in Battery Energy Storage Systems (BESS), which we see as an attractive market. We will continue to explore options to invest in flexible and renewable energy, creating value for stakeholders and attractive returns for shareholders in line with our capital allocation policy."

Highlights

·      Strong operational and underlying financial performance across the Group

·      Record levels of renewable generation - 6% of UK power, 11% of UK renewables

·      Record levels of pellets produced - 5% increase vs. 2024

·      Strong Adj. EBITDA with Adj. EPS growth benefiting from share buybacks and lower net finance costs

·      Reduction in operating profit primarily reflects non-cash charge for impairments of £378 million

·      Signing of low carbon dispatchable CfD for Drax Power Station

·      Strong balance sheet

·      £942 million of cash and committed facilities, 0.8x Net debt to Adj. EBITDA

·      Sustainable and growing dividend

·      Full year dividend up 11.5% to 29.0 pence per share (2024: 26.0 pence per share)

·      Return of surplus capital beyond investment requirements, in line with capital allocation policy

·      £300 million share buyback programme completed October 2025

·      £450 million three-year buyback extension commenced, supported by c.£0.5 billion working capital inflow from end of Renewables Obligation scheme in 2027

·      Strategy - c.£0.5 billion of commitments in 710MW of BESS developments and Flexitricity acquisition

Financial outlook

·      Full year 2026 expectations for Adj. EBITDA in line with analyst consensus estimates⁽⁵⁾

Targeting post 2027 Adj. EBITDA of £600-700m pa - Pellet Production, Biomass Generation and FlexGen⁽⁶⁾

·      Pellet Production - positioned to capture value in supply chain as a producer, user and seller of biomass

·      US operations highly integrated with Drax Power Station

·      More challenging outlook for Canadian operations, reviewing strategic options to maximise value

·      Biomass Generation - low carbon dispatchable CfD supports UK energy security and provides increased visibility

·      FlexGen - Pumped Storage, Hydro, Open Cycle Gas Turbines (OCGTs) and Energy Solutions

·      Growing system need supports improved outlook

·      Aligning structures, systems and performance culture to support the Group's growth

·      Structure cost base and resource to support low carbon dispatchable CfD, growth strategy and value creation

·      Targeting annual structural savings of >£150 million pa from 2027 vs. 2024 base

Targeting c.£3 billion of free cash flow from existing business pre growth investment (2025-2031)⁽⁷⁾

·      c.£0.5 billion of £3 billion target delivered in 2025

·      c.£0.5 billion working capital inflow expected following end of Renewables Obligation (RO) scheme

·      Over £1 billion to be returned to shareholders through dividends and share buybacks

·      Up to c.£2 billion investment in growth - Drax Power Station site, FlexGen (incl. c.£0.5 billion of BESS commitments) and other flexible, renewable generation opportunities

Opportunities to invest in energy transition and AI growth

·    Drax Power Station - largest power station in UK with 4GW of grid capacity

·      Developing options for 1.2GW-scale data centre with first goal of 100MW from 2027 subject to necessary consents and a full assessment of capital cost and investment case, as well as establishment of the commercial and development structures

·      Potential for additional system support services and generation

·      FlexGen - targeting GW-scale pipeline of BESS opportunities and optimisation capabilities

·      710MW in development - physical assets (Apatura) and tolling agreements (Fidra, Zenobē, subject to FID)

·      Acquisition of optimisation platform (Flexitricity, expected completion around March 2026)

·      Total commitments c.£0.5 billion

·    Assessing further opportunities for investment in flexible, renewable generation

Disciplined capital allocation policy supports investment for growth and returns to shareholders

·      Optionality underpinned by strong balance sheet

·      Investment to maintain and grow asset base, targeting returns significantly in excess of WACC

·      Sustainable and growing dividend

·      Nine consecutive years of growth with average annual increase >11% pa

·      Return of surplus capital beyond current investment requirements, as at 24 February 2026:

·      c.£558 million of share buybacks since 2017 - c.94 million shares purchased for an average price of c.£5.9/share

·      c.£57 million of current £450 million share buyback complete

·      Total number of voting rights, excluding treasury shares, was c.338 million

Sustainability remains a priority

·      CDP A rating for forestry and climate - top 4% of 22,000+ companies making disclosures

·      MSCI A rating

·      Other developments

·      Launched Sustainability Framework

·      Climate Transition Plan published

·      Full alignment to TCFD

·      Enhanced alignment to TNFD

·      SBTi targets to 2040 validated (2026)

·      Launched Biomass Tracker tool (2026)

Operating and financial review

£ million	2025	2024
Adj. EBITDA	947	1,064
Pellet Production	129	143
Biomass Generation	725	814
Pumped Storage and Hydro	111	138
Energy Solutions - Industrial & Commercial (I&C)	54	81
Energy Solutions - Small and Medium-sized Enterprise (SME)	(5)	(30)
Flexible Generation & Energy Solutions	160	188
Elimini	(37)	(47)
Innovation, Capital Projects and Other	(31)	(34)

Pellet Production - North American supply chain supporting UK energy security and sales to third parties

·      Record year for production - 4.2Mt (2024: 4.0Mt) - 5% increase

·    Reduction in Pellet Production Adj. EBITDA

·      Progress in cost reduction in US business resulting in lower Pellet Production revenues under established intercompany pricing methodology but lower biomass costs for UK Generation, a net benefit to the Group

·      On a like-for-like sales price basis 2025 Pellet Production Adj. EBITDA increased vs. 2024

·      Canadian operations - constrained Canadian fibre market, lower margins - commencing strategic review of options

Biomass Generation - UK energy security with dispatchable renewable generation and system support services

·    Record levels of renewable generation 15.0TWh (2024: 14.6TWh) and continuing system support role

·      Incremental generation in December 2025 responding to system need

·      Lower achieved power prices vs. 2024, partially offset by lower Electricity Generator Levy and other savings

·      No major planned outage in 2025 (single planned outage in 2026)

·    Strong contracted power

·      As at 24 February 2026 c.£1.0 billion of forward power sales between 2026 and 2028 on RO biomass, pumped storage and hydro generation assets - 13.3TWh at an average price of £78.0/MWh^(8/9)

·      RO generation - fully hedged in 2026 and substantially hedged to March 2027

Contracted power sales as at 24 February 2026	2026	2027	2028
Net RO, hydro and gas (TWh)(8)	10.9	2.1	0.2
Average achieved £ per MWh(9)	77.8	79.5	71.3
CfD (TWh)	2.2	-	-

FlexGen (comprising the reportable segments Flexible Generation & Energy Solutions) - flexible generation and system support services

·      Pumped Storage and Hydro - strong system support performance, inclusive of major planned outages

·      Cruachan planned outage programme - inlet valves upgrade and super grid transformer

·      Cruachan forced outage

·      Units 3 and 4 currently unavailable due to a grid connection failure in late December 2025 caused by assets owed by Scottish network operator SPEN. Drax working with SPEN to restore the connection

·      Currently awaiting timetable for repair programme to be provided by SPEN

·      Progressing planned outage work on unit 3, minimising overall downtime

·      OCGTs - all three units delayed, primarily due to grid connections

·      First unit (Hirwaun) commenced commissioning October 2025, Drax expects to take commercial control March 2026

·      Drax now expects to retain these grid balancing assets as part of FlexGen portfolio

·      Energy Solutions

·      I&C - similar margin to 2024, reduction in volume

·      Route-to-market for c.2,000 embedded generators - over 800MW

·      Continued development of system support services via demand-side response, and electric vehicle services

·      Opus (SME) business wind down largely complete

Other financial information

Capital investment

·      Capital investment of £202 million (2024: £321 million)

·      Growth - £98 million - Apatura BESS assets, Cruachan inlet valves upgrade and super grid transformer, and OCGTs

·      Maintenance and other - £104 million - no major planned biomass outage

·      2026 expected capital investment of c.£210-250 million

·      Growth - c.£100 million - primarily BESS, Cruachan inlet valves upgrade and super grid transformer, and OCGTs

·      Maintenance and other - c.£130 million - inclusive of Drax Power Station major planned outage on one unit

Cash and balance sheet

·      Strong cash conversion with cash generated from operations of £1,000 million (2024: £1,135 million)

·      Net working capital inflow of £86 million (2024: £122 million)

·      Net debt of £784 million (31 December 2024: £992 million), including cash and cash equivalents of £302 million (31 December 2024: £356 million)

·      £450 million Revolving Credit Facility extended to 2028, c.£171 million term-loans extension completed, new £190 million term-loan agreed (undrawn at 31 December 2025)

Impairments and charges

·    Canadian pellet business and paused Longview pellet project (£337 million) - lower expected margins, constrained Canadian fibre market and future demand from Drax Power Station covered by US Pellet Production business

·    UK BECCS (£48 million) - retain option for long-term development pending appropriate commercial and regulatory support for carbon removals in the UK

Notes:

(1)   Financial performance measures prefixed with "Adjusted/Adj." are stated after adjusting for exceptional items and certain remeasurements (including certain costs in relation to the disposal of the Opus Energy SME meters, impairments of Longview, UK BECCS, and Canadian pellets, transformation and restructuring costs and change in fair value of financial instruments).

(2)   Earnings before interest, tax, depreciation, amortisation, other gains and losses and impairment of non-current assets, excluding the impact of exceptional items and certain remeasurements, earnings from associates and earnings attributable to non-controlling interests.

(3)   In January 2023, the UK Government introduced the Electricity Generator Levy (EGL) which runs to 31 March 2028. The EGL applies to the three biomass units operating under the RO scheme and run-of-river hydro operations. It does not apply to the Contract for Difference (CfD) biomass or pumped storage hydro units. EGL is included in Adj. EBITDA and was £nil in 2025 (2024: £161 million).

(4)   Net debt is calculated by taking the Group's borrowings, adjusting for the impact of associated hedging instruments, lease liabilities and subtracting cash and cash equivalents. Net debt excludes the share of borrowings, lease liabilities and cash and cash equivalents attributable to non-controlling interests. Borrowings includes external financial debt, such as loan notes, term-loans and amounts drawn in cash under revolving credit facilities. Net debt does not include financial liabilities such as pension obligations, trade and other payables, working capital facilities linked directly to specific payables that provide short extension of payment terms of less than 12 months and balances related to supply chain finance. Net debt includes the impact of any cash collateral receipts from counterparties or cash collateral posted to counterparties.

(5)   As of 20 February 2026, analyst consensus for 2026 Adj. EBITDA was £662 million, with a range of £629 - £684 million. The details of this consensus are displayed on the Group's website.
Consensus - Drax Global

(6)   Excludes Options for Growth, including development expenditure in Elimini, Innovation, Capital Projects and Other cash flows from new investments.

(7)   Includes targets for post 2027 Adj. EBITDA, c.£0.5 billion working capital inflow from end of RO scheme, committed and maintenance capex, interest, taxes and EGL.

(8)   Presented net of cost of closing out gas positions at maturity and replacing with forward power sales.

(9)   Includes de minimis structured power sales in 2026, 2027 and 2028 (forward gas sales as a proxy for forward power), transacted for the purpose of accessing additional liquidity for forward sales and highly correlated to forward power prices.

Forward Looking Statements

This announcement may contain certain statements, expectations, statistics, projections and other information that are, or may be, forward-looking. The accuracy and completeness of all such statements, including, without limitation, statements regarding the future financial position, strategy, projected costs, plans, beliefs, and objectives for the management of future operations of Drax Group plc ("Drax") and its subsidiaries ("the Group"), are not warranted or guaranteed. By their nature, forward-looking statements involve risk and uncertainty because they relate to events and depend on circumstances that may occur in the future. Although Drax believes that the statements, expectations, statistics and projections and other information reflected in such statements are reasonable, they reflect Drax's current view and no assurance can be given that they will prove to be correct. Such events and statements involve risks and uncertainties. Actual results and outcomes may differ materially from those expressed or implied by those forward-looking statements.

There are a number of factors, many of which are beyond the control of the Group, which could cause actual results and developments to differ materially from those expressed or implied by such forward-looking statements. These include, but are not limited to, factors such as: future revenues being lower than expected; increasing competitive pressures in the industry; uncertainty as to future investment and support achieved in enabling the realisation of strategic aims and objectives; and/or general economic conditions or conditions affecting the relevant industry, both domestically and internationally, being less favourable than expected, including the impact of prevailing economic and political uncertainty; the impact of conflicts around the world; the impact of cyber-attacks on IT and systems infrastructure (whether operated directly by Drax or through third parties); the impact of strikes; the impact of adverse weather conditions or events such as wildfires; and changes to the regulatory and compliance environment within which the Group operates. We do not intend to publicly update or revise these projections or other forward-looking statements to reflect events or circumstances after the date hereof, and we do not assume any responsibility for doing so.

Webcast arrangements

Management will host a webcast presentation for analysts and investors at 9.00am (GMT), on Thursday 26 February 2026.

The presentation can be accessed remotely via a live webcast link, as detailed below. After the meeting, the webcast recording will be made available and access details of this recording are also set out below.

A copy of the presentation will be made available from 7:00am (GMT) on Thursday 26 February 2026 for download at: https://www.drax.com/results-reports-presentations/

Event Title:	Drax Group plc - Full Year Results 2025
Event Date:	Thursday 26 February 2026
Event Time:	9:00am (GMT)
Webcast Live Event Link:	https://sparklive.lseg.com/DraxGroup/events/040c5009-459c-4213-9610-1794266ffe22/full-year-results-for-the-twelve-months-ended-31-december-2025
Conference Call and Pre-register Link:	Full year results for the twelve months ended 31 December 2025 Registration Page!

For further information, please contact: [e-mail]

Website:

www.drax.com

Chair's statement

Andrea Bertone
Chair

Introduction

2025 was a strong year for the Group. Operationally, we produced large volumes of flexible and renewable energy to the UK, supporting energy security, and backed up by our North American supply chain. Financially, our earnings and cash flows were strong, supporting a strong balance sheet, investment in the business and returns to shareholders.

Strategy

Between 2025 and 2031, we aim to deliver c.£3 billion of free cash flow from the business which can support investment in energy security, data centres, and flexible, renewable energy in the UK, underpinning long-term value creation and attractive returns for shareholders.

Reflecting growing UK power demand, combined with an increased reliance on intermittent and inflexible generation, Drax expects to grow its FlexGen portfolio which can support energy security and the continued deployment of renewables. We see battery energy storage systems (BESS) as an important new technology for our FlexGen portfolio and are developing a gigawatt (GW)-scale pipeline of opportunities. Since October 2025, Drax has signed an agreement to acquire three BESS projects which, when fully commissioned, will provide capacity totalling 260MW, and an asset optimisation platform. We also agreed long-term tolling agreements for a further 450MW. The Group is assessing options for other renewables, which can complement its FlexGen model.

The Group is also focused on options to maximise value from the Drax Power Station site. This could utilise multiple generation technologies - including its existing biomass generation as well as flexible, renewable energy, to continue to support energy security. This could also, potentially, meet the power demands of a large-scale data centre.

In November 2025, we signed a low carbon dispatchable CfD with the UK Government to cover all four biomass units at Drax Power Station over the period April 2027 to March 2031. This was a significant milestone for the Group and will help support UK energy security into the 2030s and deliver a net saving for consumers compared to alternative sources of dispatchable generation.

People and values

Throughout the year I continued to engage with stakeholders, including shareholders and colleagues, regulators and suppliers.

I would like to thank all colleagues for their hard work, dedication, and expertise in helping us deliver a strong result in 2025, and their continued commitment to our purpose and the delivery of our strategy. Will Gardiner and I continue to enjoy meeting colleagues and attending the employee MyVoice Forums, which always provide open, rich conversations on a wide range of topics and which help to inform Board discussions.

Following the signing of the low carbon dispatchable CfD, we are working to put in place the right organisation and operating models, combined with a high-performance culture which can support growth and success in the future. As a result, during 2025, the Group commenced a reorganisation process on changes to roles in certain areas of the business. This process will continue in 2026.

Governance, compliance and sustainability

Good governance, compliance and sustainability are prerequisites for a well-run company and long-term success.

We recognise the importance of these matters and over the last five years we have continued to invest in governance and compliance functions as the footprint of the business has grown. Progress is a journey and there are always opportunities to evolve and improve.

In August 2025, the UK's Financial Conduct Authority (FCA) commenced an investigation into the Company, covering the period January 2022 to March 2024, relating to certain historical statements regarding Drax's biomass sourcing and the compliance of Drax's 2021, 2022 and 2023 Annual Reports with the Listing Rules and Disclosure Guidance and Transparency Rules. This process is ongoing, and we will continue to co-operate with the FCA as part of their investigation.

In December 2025, the Group was awarded an A rating by CDP for its carbon and forestry reporting. This is a year-on-year improvement and reflects the Group's continued commitment to sustainability in its widest sense. This places Drax in the top 4% of those companies that the CDP reports on globally.

Board changes

In December 2024, Andy Skelton, Chief Financial Officer (CFO), announced his intention to retire from the Board and his role as CFO. Andy continued to work until August 2025 and stepped down from the Board on 1 September 2025 and retired from the Group in December 2025. I would like to thank Andy for his outstanding service to the Group over the past six years.

Throughout 2025, the Nomination Committee worked on the recruitment of Andy's replacement, and on 1 September 2025 we were delighted to welcome Frank Lemmink as the new CFO. Frank has held senior finance and risk management roles over a 20-year international career with Shell plc. Frank's experience includes upstream energy with responsibility for business performance, strategies for long-term, sustainable growth and performance, and he has also worked in renewables and energy solutions, M&A, and internal audit. Frank's experience is invaluable as we develop our plans for the Group.

In February 2026, we were pleased to appoint Mark Clare as a Non-Executive Director.

Finally, Nicola Hodson stepped down from the Board in May 2025. I would like to thank Nicola for her contribution to Drax.

Summary

In 2025, we generated a record level of renewable generation across our portfolio of flexible and renewable generation assets as we continue to play an important role in the UK energy system, supporting energy security. This has resulted in a strong financial performance and returns to shareholders.

At the same time, we have made good progress with our strategy, which is well aligned with our purpose and the challenge of energy security, affordability, and decarbonisation (the energy trilemma). We are excited for the opportunities that 2026 and beyond will bring, as we seek to deliver long-term value creation for stakeholders and realise our purpose of enabling a zero carbon, lower cost energy future.

Andrea Bertone
Chair
25 February 2026

CEO's review

Will Gardiner
CEO

Introduction

Energy security, affordability, and decarbonisation remained important themes in 2025 and at Drax - which sits at the heart of the UK energy system - we are continuing to play our part in addressing these issues.

In 2025, we delivered a strong operational and financial performance, providing the reliable renewable electricity, flexibility, and system support services that the grid needs.

During 2025, Drax was the sixth largest source of power, the third largest source of dispatchable power, and the second largest source of renewable energy in the UK. Our dispatchable 24/7 generation portfolio, backed up by our resilient North American supply chain, enables us to supply large-scale reliable renewable power to the UK. And through our flexibility, we are an enabler of more renewables on the system, supporting lower overall system costs and decarbonisation.

In 2025, we also celebrated 60 years of operations at Cruachan Power Station and 10 years of operations for our Pellet Production business in the US South. These milestones show our continuing long-term support for energy security and the advancement of renewable energy. I would like to thank all our dedicated colleagues in these businesses and across the Group for their continued professionalism and commitment.

The 'Future Energy Scenarios' report, published by NESO, shows a potential doubling of electricity demand over the next 25 years as electrification supports decarbonisation and economic growth. Our four operational power stations are helping to meet this challenge and we are developing a further three Open Cycle Gas Turbine (OCGT) and three BESS projects, with additional tolling agreements.

We also see more opportunities to meet this rise in demand and, to that end, we are continuing to develop options for investment in flexible, renewable energy and for the utilisation of the 4GW Drax Power Station site. The latter could utilise multiple generation technologies - including its existing biomass generation, as well as other flexible, renewable energy - to continue to support energy security. Using multiple technologies also has the potential to meet the power demands of a large-scale data centre and, in the long term, has the potential for carbon removals from bioenergy with carbon capture and storage (BECCS), subject to the right Government policies and commercial arrangements.

The Group is also assessing options for other renewables, which can complement its FlexGen model.

These opportunities are built on a firm base. Our balance sheet is strong, and the business is generating significant free cash flow. We stand ready to invest in our strategy and opportunities to create value from our asset base, and will be disciplined on capital allocation, as we seek to maximise shareholder value.

Safety

Safety must always be a primary focus, and, in 2025, we have not performed at the level we expect. The Total Recordable Incident Rate (TRIR) was 0.33 (2024: 0.24). The increase is partly attributable to the disposal of the Opus Energy business, where a significant number of hours were worked with a very low incident rate. We also continue to track leading indicators of near miss and hazard identification rates, where performance has been much stronger, in addition to the lagging TRIR indicator, and these both represent key targets for the Group.

Summary of 2025

Adjusted EBITDA of £947 million, represents an 11% decrease on 2024 (£1,064 million). This reflects a strong operational and financial performance, with a continued high level of renewable power generation and system support services, partially offsetting lower average achieved power prices.

Our balance sheet is strong, with total cash and committed facilities of £942 million and Net debt of £784 million. Net debt to Adjusted EBITDA is less than 1 times - significantly below the Group's target of around 2 times.

In line with our policy to pay a sustainable and growing dividend, the Group plans to pay a total dividend for 2025 of 29.0 pence per share. This is an increase of over 11% on 2024 (26.0 pence per share). Since the policy's inception in 2017, the annual average rate of dividend growth has been c.11%.

Throughout the year, the Group has remained focused on shareholder value. In October 2025, the Group completed a £300 million share buyback programme, which had commenced in August 2024. The Group subsequently began a £450 million share buyback programme (first announced in July 2025), with an initial £75 million tranche. In aggregate, during 2025, the share buyback programmes have purchased c.34 million shares for c.£221 million. When combined with dividend payments this represents total returns to shareholders of c.£317 million during 2025.

Low carbon dispatchable CfD

In November 2025, Drax signed a low carbon dispatchable CfD with the UK Government to provide c.6TWh of biomass generation pa between April 2027 and March 2031 - equivalent to c.30% of baseload output - with a strike price of £109.90/ MWh (2012 real). In addition, we have the option to produce merchant generation above the cap, and provide system support and ancillary services.

The agreement includes a mechanism for Drax to request up to 500MW to power a data centre during this period. This mechanism is subject to agreement with the UK Government, taking into account factors including value for money for consumers, energy security, and sustainability.

We expect the contract to provide increased visibility on EBITDA from the asset between 2027 and 2031. We also believe that Drax Power Station will continue to play a long-term role in the UK energy system through the 2030s.

Flexible Generation & Energy Solutions (FlexGen)

Pumped Storage and Hydro

Adjusted EBITDA was £111 million (2024: £138 million). During 2025, we progressed a major programme of planned outage works at Cruachan Power Station. This included an upgrade to the main inlet valves on all four units, in addition to a programme of works to upgrade transformers that completed in January 2026.

Taking into account this planned programme of outage we believe that this represents a good underlying performance, and reflects continued demand for dispatchable and renewable power generation and system support services.

Work continues on the £80 million investment to refurbish and upgrade units 3 and 4 through to 2027. This is underpinned by a 15-year Capacity Market agreement worth over £220 million in revenue. The work is expected to add 40MW of additional capacity by 2027 and improve unit operations.

OCGTs

In the first half of 2026, we expect to take control of Hirwaun Power, the first of three new OCGTs. The second and third sites are expected to commence commissioning in 2026, which is later than originally planned, primarily due to delays in grid connection by the relevant authorities.

The OCGTs will provide combined capacity of c.900MW and be remunerated under 15-year Capacity Market agreements, worth over £260 million in revenue. This is in addition to revenues from peak power generation and system support services.

We have previously considered divestment of these assets, once commissioned, but the changing generation mix in the UK means that flexible generation assets will become more important to the energy transition. This increased value informs our decision to retain these grid-balancing assets in the portfolio once commissioned.

Energy Solutions

Adjusted EBITDA in Energy Solutions was £49 million (2024: £51 million) comprised of £54 million from our Industrial and Commercial (I&C) and renewables services business (2024: £81 million) partially offset by a loss of £5 million from our Small- and Medium-sized Enterprise (SME) business (Opus) (2024: a loss of £30 million).

Alongside supplying renewable energy, our I&C business is increasingly active in the provision of value-adding services. These services include asset optimisation and a route-to-market for around 2,000 embedded third-party renewable assets with capacity of over 800MW.

In May 2025, the Group completed the sale of the remaining non-core Opus Energy SME customer meter points. We expect the sale to be supportive of the Group's target for post-2027 Adjusted EBITDA, with a leaner and more focused I&C business better able to support customers' energy needs and decarbonisation objectives.

Pellet Production

Adjusted EBITDA of £129 million was a 10% decrease on 2024 (£143 million), although production increased incrementally and included the full-year impact of the expansion of the Aliceville pellet plant (commissioned in H1 2024).

The lower level of EBITDA reflects the cost-plus transfer pricing methodology used for biomass supplied from operations in the US South to Drax Power Station. Under this established arrangement, if the Pellet Production business reduces its cost base, its sales revenues to the UK business also reduce, resulting in lower Adjusted EBITDA. The offset to this is a lower cost of biomass for Drax Power Station, which results in higher EBITDA at the Group level. This situation illustrates the benefit of the integrated value chain between operations in the US South and Drax Power Station, and our ongoing focus on opportunities to reduce cost.

The Group's Canadian business, which primarily sells pellets into Asia under legacy contracts, is more challenged, and we continue to assess options to improve its financial performance. This contributed to the decision, announced in December 2025, to close the pellet plant in Williams Lake, British Columbia. In addition, we closed two small satellite plants in the US, with volumes consolidated into larger plants in the region.

Separately, reflecting lower biomass requirements under the low carbon dispatchable CfD, the Group does not currently expect to invest in additional capacity - including the paused Longview project in Washington State (US) - in the short to medium term.

Drax Power Station

Adjusted EBITDA of £725 million was a decrease of 11% on 2024 (£814 million). This reflects a combination of lower forward contracted prices compared to 2024, partially offset by a continued high level of generation and value from renewable certificates. In addition, there were no major planned outages in 2025.

Between October 2024 and September 2025 (the most recent period for which data is available), Drax Power Station generated over 5% of the UK's electricity and around 10% of its renewable power. During this period, it produced, on average, 19% of the UK's renewable power at times of peak demand and on certain days over 50%.

During 2025, low wind speeds led to lower proportions of wind generation and higher demand for electricity from Drax Power Station, illustrating its ongoing importance to security of supply in the UK.

The Group remains focused on opportunities to maximise value from its existing asset base. In March 2025, we entered into a 20-year joint venture agreement with Power Minerals Limited that will allow for the development of a facility adjacent to Drax Power Station. This facility which will process pulverised fuel ash into a material which can be sold to the construction industry and used in the production of cement with a lower carbon footprint.

The new facility is expected to begin operations by the end of 2026, and we believe the project could generate incremental Adjusted EBITDA of c.£5 million pa for Drax post-2027 through to 2046. There is no capital investment required by Drax.

Development expenditure

Development expenditure of £74 million in 2025 was a reduction of 5% on 2024 (£78 million). This reflects a significant reduction in the Elimini business, following one-off costs during its establishment in 2024 and minimal spend on BECCS, partially offset by additional OCGT commissioning costs.

The current regulatory environment in the UK and US makes the risk-return profile on carbon removal projects less attractive in the short term. Through its Elimini business, the Group continues to see carbon removals via biomass and other technologies as a cost-effective way to deliver both energy security and high integrity carbon removals at scale. Accordingly, the Group will maintain its options for long-term development in the carbon removals market but expects to commit limited resources for the foreseeable future. Elimini will also support the development of new biomass markets.

Reflecting these considerations, the Group expects future development costs to increasingly focus on more short- and medium-term opportunities in FlexGen and Drax Power Station.

Adjusted EBITDA and free cash flow targets from the existing business

The Group continues to target post-2027 Adjusted EBITDA of £600-700 million pa before development expenditure.

Reflecting growing UK power demand, combined with an increased system reliance on intermittent and inflexible generation, Drax expects to grow its FlexGen portfolio to comprise a greater proportion of total Adjusted EBITDA over time.

Drax is targeting free cash flow of c.£3 billion (2025-2031), based on strong cash flows from the current business (2025-2026), together with targeted Adjusted EBITDA (2027-2031), plus working capital, less maintenance capital expenditure, interest and tax.

The Group's capital allocation policy is unchanged. Drax expects to initially allocate more than £1 billion of free cash flow to shareholder returns (2025-2031). This is inclusive of the ongoing £450 million three-year share buyback programme, and the continuation of its long-standing policy to pay a sustainable and growing dividend.

Drax expects to allocate up to c.£2 billion to incremental investment, primarily in the flexible and renewable energy the UK needs, as well as opportunities to maximise value from the Drax Power Station site.

Returns to shareholders and investment for growth follow a capital ranking process which aims to maximise risk adjusted returns to shareholders.

Putting in place the structures to allow the Group to succeed and grow

Delivery of the Group's targets and strategy is underpinned by disciplined cost management and an operating model adapted to reflect the structure of the new low carbon dispatchable CfD, combined with a high-performance culture.

Options to invest in growth - FlexGen - flexible and renewable energy

The continued decarbonisation of the UK power system and new sources of demand, are leading to a greater reliance on intermittent renewables. The system is becoming cleaner but more volatile, driving a growing need for dispatchable power and system support services. This creates long-term earnings opportunities for, and value from, the Group's FlexGen assets. While the trend is clear, it is hard to forecast from year-to-year, being dependent on weather and associated renewable activity as much as underlying commodity prices.

This position informs the Group's view on the value of its FlexGen portfolio and opportunities for growth, which can support energy security and the continued deployment of renewables. Since acquiring the pumped storage and hydro assets in 2018, utilisation of these assets has increased significantly, delivering a five-year payback on investment.

In addition to its existing operational assets and developments, the Group sees BESS as an important new technology for its FlexGen portfolio. Adding fast response capabilities to existing long-duration pumped storage and OCGT assets, BESS could allow the portfolio to provide a wider range of system support services to the grid.

Drax is developing a GW-scale pipeline of BESS opportunities. These comprise both physical assets and the capabilities to optimise third-party assets by providing route-to-market, floor, and tolling structures. These can complement its existing route-to-market offering for renewable assets in Energy Solutions.

In October 2025, Drax signed an agreement with Apatura to acquire three BESS projects for £157.2 million which, when fully commissioned, will provide capacity totalling 260MW. In January 2026, Drax announced the acquisition of Flexitricity for £36 million, providing an optimisation platform for the development of the Group's FlexGen portfolio, including BESS. Also in January 2026, Drax agreed a 10-year tolling agreement with Fidra, which gives the Group operational control and dispatch rights over 250MW of new BESS capacity from 2028, and a 15-year tolling agreement with Zenobē, which gives the Group operational control and dispatch rights over 200MW of new BESS capacity from 2028.

The Group is also assessing options for other renewables projects to complement its FlexGen model.

Options to invest in growth - Drax Power Station site

The Drax Power Station site comprises over 1,000 acres and 4GW of capacity and grid access, with 2.6GW of active dispatchable generation, cooling systems, and proximity to the UK fibre network.

The Group is actively evaluating options to utilise inactive legacy units to provide system support services. For example, by using power from the system to spin these inactive turbines we can synchronise them to the system and use their physical mass to provide inertia, thereby helping to stabilise the system.

Drax is also considering a range of options for the site which could utilise its existing land, grid access, active generation, cooling solutions, site security, location, and skilled workforce to meet the needs of data centre developers.

Drax is preparing a planning application to support the potential option for a first phase data centre of c.100MW on land identified at Drax Power Station. This could use the existing infrastructure and transformers previously used to support coal generation to import power directly from the grid (front-of-the-meter). This could support the operation of a data centre at Drax Power Station as soon as 2027, subject to the necessary consents and agreements.

In the long term, Drax is developing options for over 1GW of data centre capacity. This could utilise existing generation capabilities at Drax Power Station to provide a distributed (behind-the-meter) energy solution with around-the-clock renewable power directly to a data centre under a long-term Power Purchase Agreement, subject to necessary consents and agreements.

Any decision to develop data centres at Drax Power Station will require a full assessment of the capital cost and investment case, as well as establishing the commercial and development structures.

Pellet Production

As a part of the Group's post-2027 targets, the low carbon dispatchable CfD at Drax Power Station is expected to utilise c.2Mt of own-use pellets from the US South (in addition to third-party volumes). This, together with existing sales to third parties, primarily in Asia, provides a good underpin to the current level of value generated for the Group from Pellet Production.

Long-term development of biomass and carbon markets

In the long term, Drax remains positive on the role of biomass in industrial decarbonisation and carbon removals via its Elimini business. Drax continues to assess options for own-use and third-party sales, from existing and new markets, including Sustainable Aviation Fuel (SAF), which could represent a new market opportunity through the 2030s.

Sustainability

In addition to delivering a strong operational and financial performance and value for shareholders, the Group has remained focused on the development of its sustainability programme. In 2025, we launched a new Sustainability Framework, Biomass Sourcing Policy, and a Climate Transition Plan.

As a purpose-led organisation, our growth should lead to positive outcomes for climate, nature, and people. Our operations can help sustain more healthy, safe, and economically viable working forests that continue to provide jobs and opportunities in communities where we operate.

Working in partnership with industry, communities, scientists, and civil society organisations will be vital to achieving our ambitions. We aim to work openly and constructively with these groups to help deliver improvements.

We are fully aligned with the Task Force on Climate-related Financial Disclosures (TCFD). We are also an early-adopter of the Taskforce on Nature-related Financial Disclosures (TNFD). In addition, we are members of the Taskforce on Inequality and Social-related Financial Disclosures (TISFD) Alliance. These independent taskforces align directly with the three pillars of our new Sustainability Framework; Climate, Nature, and People. We are also a signatory to the UN Global Compact (UNGC) and we are committed to promoting the UNGC principles concerning respect for human rights, labour rights, the environment, and anti-corruption.

Drax is one of the world's largest users of sustainable biomass for energy generation. We are committed to ensuring the woody biomass we source comes from forests managed in accordance with standards designed to support their health and growth over the long term. Forests in the areas where Drax sources material are subject to national and regional regulation and are typically supported, and independently monitored for compliance, by forest certification schemes. These include the Forestry Stewardship Council® (FSC®) (FSC C123692), the Sustainable Forestry Initiative (SFI) (SFI marks are registered marks owned by the Sustainable Forestry Initiative Inc.), and the Programme for the Endorsement of Forest Certification® (PEFC) (PEFC/29-31-286).

We supplement this regulation through our own Biomass Sourcing Policy and supply chain checks. This includes third-party verification under the Sustainable Biomass Program (SBP), in respect of woody biomass used at Drax Power Station, which is also fully compliant with the UK Government's rule on the use of sustainable biomass.

Outlook

We are continuing to target post-2027 Adjusted EBITDA of £600-700 million pa from our FlexGen, Pellet Production, and Biomass Generation businesses, maximising value from the business today, while continuing to identify opportunities for growth across our strategies for flexible, renewable energy.

We will continue to apply our capital allocation policy with a focus on balance sheet strength, investment in the core business, and a sustainable and growing dividend. To the extent there are residual cash flows beyond the current needs of the Group, we will also consider additional returns to shareholders.

Through a disciplined approach to capital allocation and development costs, we expect to create opportunities for investment in growth and value creation, underpinned by strong cash generation and attractive returns for shareholders.

Will Gardiner
CEO
25 February 2026

CFO's financial review

Frank Lemmink
CFO

		Year end 31 December
		2025	2024
Financial performance (£m)	Total gross profit	1,513	1,877
	Operating expenses	(641)	(761)
	Depreciation, amortisation and impairment of non-current assets	(621)	(256)
	Other	(10)	(10)
	Total operating profit	241	850
	Exceptional items and certain remeasurements	430	(50)
	Adjusted operating profit	671	800
	Adjusted depreciation, amortisation and similar charges and share of losses from associates	275	264
	Adjusted EBITDA	947	1,064
Capital expenditure (£m)	Capital expenditure	202	321
Cash and Net debt (£m unless otherwise stated)	Cash generated from operations	1,000	1,135
	Net debt	784	992
	Net debt to Adjusted EBITDA (times)	0.8	0.9
	Cash and committed facilities	942	806
Earnings (pence per share)	Adjusted basic	137.7	128.4
	Total basic	20.7	137.5
Distributions (pence per share)	Interim dividend	11.6	10.4
	Proposed final dividend	17.4	15.6
	Total dividend	29.0	26.0

Throughout this document we distinguish between Adjusted measures and Total measures, which are calculated in accordance with International Financial Reporting Standards (IFRS). We calculate Adjusted financial performance measures, which exclude income statement volatility from derivative financial instruments and the impact of exceptional items. This allows management and stakeholders to better compare the performance of the Group between the current and previous period without the effects of this volatility and one-off or non-operational items. Adjusted financial performance measures are described in more detail in the APMs glossary, with a reconciliation to their closest IFRS equivalents in note 4. Return on Capital Employed (ROCE) is calculated as Adjusted operating profit divided by the average of opening and closing capital employed (capital employed is gross assets less current liabilities). Tables in this financial review may not add down or across due to rounding.

Introduction

Adjusted EBITDA of £947 million represents strong operational and underlying financial performance across all segments of our business. The decrease compared to £1,064 million in 2024 primarily reflects a lower achieved power price. Total operating profit was impacted by impairments, as discussed in the 'Total operating profit' section. During the period, we generated cash from operations of £1,000 million (2024: £1,135 million). Our Net debt: Adjusted EBITDA ratio of 0.8 times (2024: 0.9 times) remains significantly below our long-term target of around 2 times and during the year we further strengthened our balance sheet, extending the average maturity of our debt and extending the Revolving Credit Facility (RCF) by a year to 2028.

Financial performance

Adjusted EBITDA by business

Flexible Generation & Energy Solutions (FlexGen)

Adjusted EBITDA in our Hydro business of £111 million reduced compared to 2024 (£138 million), reflecting planned outage work at Cruachan Power Station as part of refurbishment and upgrade works.

Adjusted EBITDA in Energy Solutions of £49 million (2024: £51 million) comprised £54 million from our I&C and renewables services business (2024: £81 million) partially offset by a loss of £5 million from our Small and Medium-sized Enterprise (SME) business (Opus) (2024: a loss of £30 million). I&C and renewables services earnings reflect a similar margin on contracted power prices to 2024. The sale of the remaining meter points in the SME business completed in May 2025. The wind down of this business is now substantially complete.

Pellet Production

Adjusted EBITDA of £129 million was below 2024 (£143 million). The reduction reflects the cost-plus transfer pricing methodology for shipments to Drax Power Station. This means that cost savings in the Pellet Production business lead to a lower transfer price, impacting Adjusted EBITDA. Production in the period totalled 4.2Mt, a record volume for the business (2024: 4.0Mt). Shipments totalled 5.1Mt (2024: 5.1Mt). Of the 5.1Mt shipped, 3.1Mt was to Drax Power Station (2024: 3.0Mt). During the period, 1.0Mt of pellets were acquired from third parties (2024: 1.1Mt).

The US business has performed well, with record production volumes and margins commensurate with our long-term targets. The legacy contracts in the Canadian business mean profitability here is lower, and this is an area of focus for the Group, as discussed in the CEO review.

Impairments in relation to the Pellet Production business are documented in the 'Total operating profit' section.

Biomass Generation

Adjusted EBITDA from Biomass Generation was £725 million (2024: £814 million), partially offset by a continued high level of generation and value from renewable certificates. In addition, there were no major planned outages in 2025.

Drax Power Station produced 15.0TWh (2024: 14.6TWh) of electricity, a record year for biomass generation and making it the UK's largest single source of renewable energy during the period.

Options for Growth (Innovation, Capital Projects, and Other)

Development expenditure in 2025 totalled £74 million (2024: £78 million). The reduction reflects the timing of large capital projects, as described in the CEO review, and therefore a reduction in the associated spend. We will continue to be disciplined in the capital and development expenditure deployed to these projects.

In Other, intra-group eliminations moved to a credit of £7 million in 2025 from a charge of £3 million in 2024, predominantly due to a reduction in the volume of pellets in transit compared to the previous year end.

Total operating profit

Total operating profit was £241 million, compared to £850 million in 2024. In addition to the factors discussed above, Exceptional items and certain remeasurements also reduced, from a credit of £50 million in 2024 to a charge of £430 million in 2025. This was attributable to impairments, gas prices, and foreign exchange movements. Impairments were recognised for certain pellet assets and UK BECCS, whilst continuing depreciation and amortisation was similar year-on-year.

In Pellet Production, impairment and related charges in Northern Pellets (Canadian business) were £198 million. Charges in relation to the Longview project were £138 million and UK BECCS impairments were £48 million. All of these were classed as exceptional items. The impairment to Northern Pellets was driven by a lower growth outlook for the global pellet market after 2027, particularly in Europe. Linked to this, the development project at Longview was paused and no development is expected in the near term. Whilst UK BECCS is still an attractive option for the Group in the long term, the current political environment and absence of an appropriate regulatory framework has led to a reduction in the likelihood of the project proceeding in the short- to medium-term. Accordingly, the capitalised value has been impaired.

Further information on other Exceptional items and certain remeasurements can be found in note 4.

Profit after tax and Earnings per share

Total net finance and foreign exchange costs for 2025 were £52 million, a reduction from 2024 (£97 million). Of the reduction, £24 million was attributable to capitalisation of interest, £15 million in foreign exchange, and £7 million as a result of lower costs in relation to the Energy Solutions receivables monetisation facility. This was partially offset by a £2 million reduction in interest received. At 31 December 2025, the weighted average interest rate payable on the Group's borrowings was 5.4% (31 December 2024: 5.4%).

The Adjusted effective tax rate for 2025 of 22% is lower than 2024 (30%), with a key factor being a £nil charge for EGL in the current year (2024: £161 million) reflecting lower achieved power prices. EGL is not allowable for corporation tax purposes and the corporation tax impact of this reduction in EGL was 6%. The Adjusted effective tax rate is below the headline corporation tax rate in the UK of 25% because of benefits from the UK Patent Box Regime, partially offset by non-deductible expenses. The exceptional items and certain remeasurements tax credit of £16 million all related to deferred tax and was the net of deferred tax on all non-Canadian exceptional items and certain remeasurements partially offset by the non-allowable Canadian impairment charge and derecognition of Canadian deferred tax assets.

Adjusted basic EPS was 137.7 pence (2024: 128.4 pence) and Total basic EPS was 20.7 pence (2024: 137.5 pence). The average number of shares used in these calculations was 352.8 million (2024: 383.2 million). The number of outstanding shares at 31 December 2025 was 340.4 million, an 8% reduction on 31 December 2024 (369.9 million), reflecting the ongoing share buyback programme.

Capital allocation

Our capital allocation policy remains unchanged and focused on balance sheet strength, investment in the core business, a sustainable and growing dividend and, to the extent there are residual cash flows beyond the current needs of the Group, additional returns to shareholders.

Maintain credit rating

During the first half of 2025 the Group extended the maturity of the undrawn £450 million RCF and in July two term loans totalling c.£171 million were extended from 2027 to 2028. During December the Group signed a £190 million term loan with an interest rate of Sterling Overnight Index Average (SONIA) plus a customary margin. The facility has an option at Drax's discretion to extend by two six-month periods. The facility was undrawn at 31 December 2025 but was subsequently fully drawn in January 2026.

In August 2025 the CAD term-loan of £109 million was repaid. In October 2025 the remaining £125 million of the 2025 Euro bond was repaid. In January 2026, term loans totalling £62 million were repaid.

During the second quarter of 2025, the Group's Issuer Credit Ratings were reaffirmed as 'BB+' by Fitch and S&P and as 'BBB (low)' by DBRS, with a Stable Outlook in each case.

Invest in core business - capital expenditure

Capital expenditure of £202 million (2024: £321 million) consists of £98 million of growth expenditure, £72 million of maintenance, and £32 million of Other (including HSE and IT). Of the £98 million growth expenditure, £26 million related to BESS assets (2024: £nil) and £23 million related to the OCGTs (2024: £90 million). The first of the three OCGTs, Hirwaun, is expected to be under the Group's commercial control shortly and the other two units are expected to commence commissioning during 2026. Growth expenditure also included £15 million in relation to the ongoing upgrade of Cruachan units 3 and 4 (2024: £34 million).

In October 2025 we announced we had signed an agreement with Apatura to acquire three BESS projects for £157.2 million. Completion of the acquisition of the first two projects occurred in 2025 and completion of the third project is expected soon.

Sustainable and growing dividend

The Board expects to pay a dividend for the 2025 financial year of 29.0 pence per ordinary share, an 11.5% increase on 2024, consistent with our policy to pay a dividend which is sustainable and expected to grow. As has been our practice, 40% of the expected full year dividend, or 11.6 pence per ordinary share was paid as an interim dividend. Subject to approval at the 2026 Annual General Meeting, the final dividend will be paid on 15 May 2026.

Return surplus capital beyond current investment requirements

In October 2025, the Group completed a £300 million share buyback programme which had commenced in August 2024. The Group subsequently began a £450 million share buyback programme (first announced in July 2025), with an initial £75 million tranche. In aggregate, during 2025, the share buyback programmes have purchased c.34 million shares for c.£221 million. When combined with dividend payments this represents total returns to shareholders of c.£317 million during 2025.

During 2026, to 24 February 2026, the Group has repurchased £22 million. We expect the 2025 programme to conclude by the end of 2028.

Cash and Net debt

Net cash movements

Cash generated from operations, inclusive of working capital, was £1,000 million (2024: £1,135 million). The net working capital inflow of £86 million (2024: £122 million) predominantly reflects a reduction in inventory and receivables, partially offset by a decrease in payables.

Cash outflows on purchases of property, plant and equipment and intangibles include repayments of deferred letters of credit from previous periods. This led to a cash outflow of £294 million, more than the amount capitalised in the period of £202 million.

Liquidity

Cash and committed facilities of £942 million at 31 December 2025 (31 December 2024: £806 million) provided substantial headroom over our short-term liquidity requirements. No cash has been drawn under our RCFs since 2018.

Net debt and Net debt to Adjusted EBITDA

	31 December 2025 £m	31 December 2024 £m
Cash and cash equivalents	302	356
Current borrowings	(61)	(119)
Non-current borrowings	(918)	(1,058)
Impact of hedging instruments and NCI	(8)	(55)
Lease liabilities	(99)	(117)
Net debt	(784)	(992)
Adjusted EBITDA	947	1,064
Net debt to Adjusted EBITDA	0.8	0.9

Going concern and viability

The Group's operational and underlying financial performance in 2025 was strong. Cash and committed facilities at 31 December 2025 provides substantial headroom over our short-term liquidity requirements.

The Group refreshes its business plan and forecasts throughout the year, including scenario modelling designed to test the resilience of the Group's financial position and performance to several possible downside cases. Based on its review of the latest forecast, the Board is satisfied that the Group has sufficient headroom in its cash and committed facilities and covenants, combined with available mitigating actions, to be able to meet its liabilities as they fall due across a range of scenarios.

Consequently, the Directors have a reasonable expectation that the Group will continue to be in existence for a period of at least twelve months from the date of the approval of the financial statements and have therefore adopted the going concern basis. Further, the Directors have a reasonable expectation that the Group will be able to continue in operation over the five-year period of the viability assessment, as documented in the Viability Statement.

Other matters

In January 2026, the Group announced the acquisition of Flexitricity, an asset optimisation platform, for c.£36 million. Completion is expected in Q1 2026 and is conditional on completion of regulatory approvals and processes.

In January 2026, the Group announced a 10-year tolling agreement with Fidra for 250MW (500MWh) of BESS, expected to commence in 2028.

In February 2026, the Group announced a 15-year tolling agreement with Zenobē for 200MW (800MWh) of BESS, expected to commence in 2028.

Frank Lemmink
CFO
25 February 2026

Directors' responsibilities statement

The Directors are responsible for preparing the Annual Report and the Financial Statements in accordance with applicable law and regulations.

Company law requires the Directors to prepare financial statements for each financial year. Under that law the Directors are required to prepare the group financial statements in accordance with United Kingdom adopted international accounting standards in conformity with the requirements of the Companies Act 2006 and United Kingdom adopted International Accounting Standards and have elected to prepare the Parent Company financial statements in accordance with United Kingdom Generally Accepted Accounting Practice (United Kingdom Accounting Standards and applicable law), set out in FRS 101 - Reduced Disclosure Framework. Under company law the Directors must not approve the accounts unless they are satisfied that they give a true and fair view of the state of affairs of the Company and of the profit or loss of the Company for that period.

In preparing the Parent Company financial statements, the Directors are required to:

- select suitable accounting policies and then apply them consistently;

- make judgements and accounting estimates that are reasonable and prudent;

- state whether applicable UK Accounting Standards have been followed, subject to any material departures disclosed and explained in the financial statements; and

- prepare the financial statements on the going concern basis unless it is inappropriate to presume that the Company will continue in business.

In preparing the Group financial statements, International Accounting Standard 1 requires that Directors:

- properly select and apply accounting policies;

- present information, including accounting policies, in a manner that provides relevant, reliable, comparable and understandable information;

- provide additional disclosures when compliance with the specific requirements in IFRS are insufficient to enable users to understand the impact of particular transactions, other events and conditions on the entity's financial position and financial performance; and

- make an assessment of the Company's ability to continue as a going concern.

The Directors are responsible for keeping adequate accounting records that are sufficient to show and explain the Company's transactions and disclose with reasonable accuracy at any time the financial position of the Company and enable them to ensure that the financial statements comply with the Companies Act 2006. They are also responsible for safeguarding the assets of the Company and hence for taking reasonable steps for the prevention and detection of fraud and other irregularities.

The Directors are responsible for the maintenance and integrity of the corporate and financial information included on the Company's website. Legislation in the United Kingdom governing the preparation and dissemination of financial statements may differ from legislation in other jurisdictions.

Responsibility statement

We confirm that to the best of our knowledge:

- the financial statements, prepared in accordance with the relevant financial reporting framework, give a true and fair view of the assets, liabilities, financial position, and profit or loss of the Company and the undertakings included in the consolidation taken as a whole;

- the Strategic report includes a fair review of the development and performance of the business and the position of the Company and the undertakings included in the consolidation taken as a whole, together with a description of the principal risks and uncertainties that they face; and

- the Annual Report and financial statements, taken as a whole, are fair, balanced and understandable and provide the information necessary for shareholders to assess the Company's position, performance, business model, and strategy.

This responsibility statement was approved by the Board of Directors on 25 February 2026 and is signed on its behalf by:

Will Gardiner
CEO

Consolidated financial statements

Consolidated income statement

		Year ended 31 December 2025				Year ended 31 December 2024
	Notes	Adjusted results (1) £m	Exceptional items and certain remeasurements £m	Total results £m		Adjusted results (1) £m	Exceptional items and certain remeasurements £m	Total  results £m
Revenue	2	5,355.4	35.3	5,390.7		6,081.2	81.3	6,162.5
Cost of sales		(3,793.8)	(84.0)	(3,877.8)		(4,130.1)	4.9	(4,125.2)
Electricity Generator Levy		-	-	-		(160.8)	-	(160.8)
Gross profit/(loss)		1,561.6	(48.7)	1,512.9		1,790.3	86.2	1,876.5
Operating and administrative expenses		(614.6)	(23.3)	(637.9)		(698.5)	(22.1)	(720.6)
Impairment of financial assets		0.5	(3.8)	(3.3)		(27.3)	(12.7)	(40.0)
Depreciation		(228.9)	-	(228.9)		(224.8)	-	(224.8)
Amortisation		(14.2)	-	(14.2)		(17.0)	-	(17.0)
Impairment of non-current assets	3	(27.2)	(350.5)	(377.7)		(11.8)	(2.6)	(14.4)
Other (losses)/gains		(4.4)	(3.6)	(8.0)		(8.5)	1.2	(7.3)
Share of losses from associates		(1.6)	-	(1.6)		(2.2)	-	(2.2)
Operating profit/(loss)		671.2	(429.9)	241.3		800.2	50.0	850.2
Foreign exchange gains/(losses)		8.2	(2.4)	5.8		(9.4)	-	(9.4)
Interest payable and similar charges		(73.9)	(1.5)	(75.4)		(106.9)	(0.6)	(107.5)
Interest receivable and similar gains		17.8	-	17.8		20.1	-	20.1
Profit/(loss) before tax		623.3	(433.8)	189.5		704.0	49.4	753.4
Total tax (charge)/credit		(137.6)	16.3	(121.3)		(213.0)	(14.9)	(227.9)
Profit/(loss) for the period		485.7	(417.5)	68.2		491.0	34.5	525.5
Attributable to:
Owners of the parent company		485.8	(412.8)	73.0		492.1	34.5	526.6
Non-controlling interests		(0.1)	(4.7)	(4.8)		(1.1)	-	(1.1)
Earnings per share		Pence		Pence		Pence		Pence
For net profit for the period attributable to owners of the parent company
- Basic earnings per share		137.7		20.7		128.4		137.5
- Diluted earnings per share		134.5		20.2		126.0		134.8

(1)  Adjusted results are stated after adjusting for exceptional items and certain remeasurements. See note 4 for further details.

Consolidated statement of comprehensive income

	Notes	Year ended 31 December
		2025 £m	2024 £m
Profit for the period		68.2	525.5
Items that will not be subsequently reclassified to profit or loss:
Remeasurement of defined benefit pension surplus		(2.8)	5.5
Deferred tax on remeasurement of defined benefit pension surplus		0.7	(1.3)
Items that may be subsequently reclassified to profit or loss:
Exchange differences on translation of foreign operations attributable to owners of the parent company	6	(66.8)	(6.6)
Exchange differences on translation of foreign operations attributable to non-controlling interests		(0.2)	(0.8)
Net fair value losses on financial assets at fair value through other comprehensive income		(18.5)	(25.5)
Net fair value losses on financial assets at fair value through other comprehensive income reclassified to profit or loss		18.5	25.5
Net fair value (losses)/gains on cost of hedging		(21.9)	6.8
Deferred tax on cost of hedging		5.4	(1.7)
Net fair value gains/(losses) on cash flow hedges		39.6	(49.0)
Net losses on cash flow hedges reclassified to profit or loss		(145.1)	(242.9)
Deferred tax on cash flow hedges		26.4	73.0
Other comprehensive expense		(164.7)	(217.0)
Total comprehensive (expense)/income for the year		(96.5)	308.5
Attributable to:
Owners of the parent company		(91.5)	310.4
Non-controlling interests		(5.0)	(1.9)

Consolidated balance sheet

	Notes	As at 31 December
		2025 £m	2024 £m
Assets
Non-current assets
Goodwill		396.2	415.1
Intangible assets		42.7	68.1
Property, plant and equipment		2,427.2	2,802.0
Right-of-use assets		69.6	100.9
Investments		-	3.6
Retirement benefit surplus		23.8	24.7
Deferred tax assets		37.0	48.6
Derivative financial instruments		24.4	81.7
		3,020.9	3,544.7
Current assets
Inventories		223.8	302.0
Renewable certificate assets		542.1	540.0
Trade and other receivables and contract assets		337.8	470.3
Derivative financial instruments		68.6	175.6
Current tax assets		0.1	-
Cash and cash equivalents		302.1	356.0
		1,474.5	1,843.9
Liabilities
Current liabilities
Trade and other payables and contract liabilities		(1,090.9)	(1,289.1)
Lease liabilities		(28.2)	(26.0)
Current tax liabilities		-	(9.6)
Borrowings		(61.3)	(119.0)
Provisions		(17.6)	(20.2)
Derivative financial instruments		(174.2)	(71.1)
		(1,372.2)	(1,535.0)
Net current assets		102.3	308.9
Non-current liabilities
Borrowings		(917.7)	(1,057.7)
Lease liabilities		(70.4)	(90.5)
Provisions		(85.0)	(75.7)
Deferred tax liabilities		(261.3)	(280.4)
Derivative financial instruments		(75.6)	(262.2)
		(1,410.0)	(1,766.5)
Net assets		1,713.2	2,087.1
Shareholders' equity
Issued equity	6	49.9	49.4
Share premium	6	448.5	443.8
Hedge reserve		(63.1)	(7.9)
Cost of hedging reserve		(12.8)	6.9
Other reserves	6	179.8	467.0
Retained profits		1,110.9	1,118.1
Total equity attributable to owners of the parent company		1,713.2	2,077.3
Non-controlling interests		-	9.8
Total shareholders' equity		1,713.2	2,087.1

The Consolidated financial statements of Drax Group plc, registered number 5562053, were approved and authorised for issue by the Board of Directors on 25 February 2026.

Signed on behalf of the Board of Directors: 

Frank Lemmink
CFO

Consolidated statement of changes in equity

	Issued equity  £m	Share premium  £m	Hedge reserve  £m	Cost of hedging  £m	Other reserves  £m	Retained profits  £m	Non- controlling interests £m	Total £m
At 1 January 2024	49.1	441.2	207.4	18.7	588.2	666.4	12.0	1,983.0
Profit/(loss) for the year	-	-	-	-	-	526.6	(1.1)	525.5
Other comprehensive (expense)/income	-	-	(218.9)	5.1	(6.6)	4.2	(0.8)	(217.0)
Total comprehensive (expense)/income for the year	-	-	(218.9)	5.1	(6.6)	530.8	(1.9)	308.5
Equity dividends paid	-	-	-	-	-	(93.5)	-	(93.5)
Issue of share capital (note 6)	0.3	2.6	-	-	-	-	-	2.9
Distributions to non-controlling interests	-	-	-	-	-	-	(0.3)	(0.3)
Repurchase of own shares through share buyback programmes (note 6)	-	-	-	-	(115.4)	-	-	(115.4)
Total transactions with the owners in their capacity as owner	0.3	2.6	-	-	(115.4)	(93.5)	(0.3)	(206.3)
Movements on cash flow hedges released directly from equity	-	-	4.8	-	-	-	-	4.8
Deferred tax on cash flow hedges released directly from equity	-	-	(1.2)	-	-	-	-	(1.2)
Movements on cost of hedging released directly from equity	-	-	-	(22.6)	-	-	-	(22.6)
Deferred tax on cost of hedging released directly from equity	-	-	-	5.7	-	-	-	5.7
Movement in equity associated with share‑based payments	-	-	-	-	0.8	13.0	-	13.8
Deferred tax on share-based payments released directly from equity	-	-	-	-	-	1.4	-	1.4
At 1 January 2025	49.4	443.8	(7.9)	6.9	467.0	1,118.1	9.8	2,087.1
Profit/(loss) for the year	-	-	-	-	-	73.0	(4.8)	68.2
Other comprehensive expense	-	-	(79.1)	(16.5)	(66.8)	(2.1)	(0.2)	(164.7)
Total comprehensive (expense)/income for the year	-	-	(79.1)	(16.5)	(66.8)	70.9	(5.0)	(96.5)
Equity dividends paid	-	-	-	-	-	(95.7)	-	(95.7)
Issue of share capital (note 6)	0.5	4.7	-	-	(0.2)	-	-	5.0
Movement in equity associated with forward contracts to purchase own shares to satisfy share-based payment arrangements	-	-	-	-	-	(7.2)	-	(7.2)
Own shares utilised to satisfy share-based payment arrangements (note 6)	-	-	-	-	0.9	(0.9)	-	-
Distributions to non-controlling interests	-	-	-	-	-	-	(1.2)	(1.2)
Acquisition of non-controlling interests without a change in control	-	-	-	-	-	2.9	(3.6)	(0.7)
Repurchase of own shares through share buyback programmes (note 6)	-	-	-	-	(221.1)	-	-	(221.1)
Total transactions with the owners in their capacity as owner	0.5	4.7	-	-	(220.4)	(100.9)	(4.8)	(320.9)
Movements on cash flow hedges released directly from equity	-	-	31.8	-	-	-	-	31.8
Deferred tax on cash flow hedges released directly from equity	-	-	(7.9)	-	-	-	-	(7.9)
Movements on cost of hedging released directly from equity	-	-	-	(4.3)	-	-	-	(4.3)
Deferred tax on cost of hedging released directly from equity	-	-	-	1.1	-	-	-	1.1
Movement in equity associated with share‑based payments	-	-	-	-	-	15.7	-	15.7
Deferred tax on share-based payments released directly from equity	-	-	-	-	-	7.1	-	7.1
At 31 December 2025	49.9	448.5	(63.1)	(12.8)	179.8	1,110.9	-	1,713.2

Consolidated cash flow statement

	Notes	Year ended 31 December
		2025 £m	2024 £m
Cash generated from operations	5	999.5	1,135.1
Income taxes paid		(109.5)	(193.6)
Interest paid		(96.4)	(99.5)
Interest received		16.4	17.5
Net cash from operating activities		810.0	859.5
Cash flows from investing activities
Purchases of property, plant and equipment		(282.0)	(379.8)
Purchases of intangible assets		(12.2)	(7.7)
Proceeds from the sale of property, plant and equipment		9.0	0.5
Contributions to associates		(2.0)	(2.9)
Net cash used in investing activities		(287.2)	(389.9)
Cash flows from financing activities
Equity dividends paid		(95.7)	(93.5)
Distributions to non-controlling interests		(1.2)	(0.1)
Proceeds from issue of share capital		5.0	2.7
Repurchase of own shares through share buyback programmes	6	(221.1)	(115.4)
Drawdown of borrowings		-	731.8
Repayment of borrowings		(233.6)	(949.2)
Gross receipt of financing derivatives		233.2	198.3
Gross payment of financing derivatives		(237.2)	(229.8)
Payment of principal of lease liabilities		(28.1)	(27.4)
Other financing costs paid		(0.2)	(9.0)
Net cash absorbed by financing activities		(578.9)	(491.6)
Net decrease in cash and cash equivalents		(56.1)	(22.0)
Cash and cash equivalents at 1 January		356.0	379.5
Effect of changes in foreign exchange rates		2.2	(1.5)
Cash and cash equivalents at 31 December		302.1	356.0

Non-cash transactions recognised in the Consolidated income statement are reconciled to operating cash flows as part of the disclosure provided in note 5. Further details of the cash flow impact of exceptional items can be found in note 4.

1. Segmental reporting

Reportable segments are presented in a manner consistent with internal reporting provided to the chief operating decision maker which is considered to be the Executive Committee. The Group is organised into four businesses. The Executive Committee reviews the performance of each of these businesses separately, and each represents a reportable segment:

- Pellet Production: production and subsequent sale of biomass pellets from the Group's processing facilities in North America

- Biomass Generation: generation and sale of electricity from the Group's biomass assets in the UK 

- Flexible Generation: generation and sale of electricity from pumped storage, run-of-river hydro and OCGT assets, and the processing and sale of waste-derived pellets, in the UK

- Energy Solutions: supply of electricity to non-domestic customers in the UK

Operating costs that can be reasonably allocated to the activities of a reportable segment are included within the results of that reportable segment. Central corporate and commercial functions provide certain specialist and shared services, including optimisation of the Group's positions. Central corporate and commercial function costs that cannot be reasonably allocated to the activities of a reportable segment are included within Innovation, capital projects and other. Innovation, capital projects and other is not a reportable segment as it provides central support function activities to the Group, however it is included in the information presented below to enable reconciliation of the segmental amounts presented to the consolidated IFRS results recognised in these Consolidated financial statements.

Given the principal activity of the Group is a generator and seller of electricity, the Consolidated income statement includes all revenue from sales of electricity during the period. Where the Group is acting as the principal in a sales transaction and electricity is purchased rather than generated to fulfil that sale, either due to operational or other requirements, the cost of this purchase is recorded within cost of sales.

When defining gross profit within the Consolidated financial statements, the Group follows the principal trading considerations applied by its Pellet Production, Biomass Generation, Flexible Generation and Energy Solutions businesses when making a sale. In respect of the Pellet Production business, this reflects the direct costs of production, being fibre, fuel and drying costs, direct freight and port costs, or third-party pellet purchases. In respect of the Biomass Generation and Flexible Generation businesses, this reflects the direct costs of the commodities required to generate power or the direct cost of purchasing power, the relevant grid connection costs that arise, and the Electricity Generator Levy (EGL) arising on applicable renewable and low-carbon generation. In respect of the Energy Solutions business, this reflects the direct costs of supply, being the costs of the power or gas supplied, together with costs levied on suppliers such as network costs, broker costs and renewables incentive mechanisms.

Accordingly, cost of sales excludes indirect overheads and staff costs (presented within operating and administrative expenses), and depreciation (presented separately on the face of the Consolidated income statement).

The accounting policies applied for the purpose of measuring the reportable segments' profits or losses, assets and liabilities are the same as those used in measuring the corresponding amounts in the Consolidated financial statements.

EGL applies to the Group's three biomass units operating under the Renewables Obligation (RO) scheme and its run-of-river hydro operations. It does not apply to the Group's Contract for Difference (CfD) biomass unit or its pumped storage hydro operations. The EGL applies at a rate of 45% to receipts from in-scope forms of wholesale electricity generation that exceed a defined benchmark level, after the deduction of certain allowable costs, from 1 January 2023 to 31 March 2028.

The Group determined that EGL should be treated as a levy under IFRIC 21 'Levies', rather than as a tax under IAS 12 'Income taxes'. Therefore, the cost is recognised above gross profit. A liability for a levy is recognised once the obligating event, being the activity that triggers the payment of the levy, has occurred. EGL is triggered based on average generation receipts for in-scope revenue schemes over a reporting period being higher than the threshold set in the legislation. A liability is recognised if the average actual generation receipts to date in a financial period are above the threshold. The threshold rises annually in April, in line with the UK Consumer Price Index (CPI). The threshold at 31 December 2025 was £79.95 per MWh (2024: £77.94 per MWh). The assessment is based on receipts above this threshold after adjusting for allowable costs. No expense for EGL has been recognised in the current period due to the average actual generation receipts in the period being below the threshold.

Seasonality of trading

The primary activities of the Group are affected by seasonality. Demand in the UK for electricity is typically higher in the winter period (October to March) when temperatures are lower, which drives higher prices and higher levels of generation. Conversely, demand is typically lower in the summer months (April to September) when temperatures are milder, and therefore prices and levels of generation are generally lower.

This trend is experienced by all of the Group's UK-based businesses, as they operate within the UK electricity market. It is most notable within the Biomass Generation business due to its scale and the flexible operation of its thermal generation plant.

The Pellet Production business incurs certain costs that are higher in winter months due to the impact of weather conditions, such as fibre drying costs and heating costs. Production volumes and margins are typically higher in the summer months. The business is protected from demand fluctuations due to seasonality by regular production and dispatch schedules under its contracts with customers, both intra-group and externally.

Segment revenues and results

The following is an analysis of the Group's performance by reportable segment and any other information necessary to enable reconciliation to the Group's total IFRS results recognised for the year ended 31 December 2025. Revenue for each segment is split between sales to external parties and inter-segment sales. Inter-segment sales are eliminated in the intra-group eliminations column along with any adjustments required for unrealised profits (primarily inventory purchased by the Biomass Generation segment from the Pellet Production segment that is still held as inventory at the reporting date).

Adjusted EBITDA by reportable segment is presented in note 4.

	Year ended 31 December 2025
	Pellet Production £m	Biomass Generation £m	Flexible Generation £m	Energy Solutions £m	Innovation, capital projects and other £m	Intra-group eliminations £m	Adjusted results £m	Exceptional items and certain re-measurements £m	Total results £m
Revenue
External sales	329.3	2,314.7	78.1	2,633.3	-	-	5,355.4	35.3	5,390.7
Inter-segment sales	574.1	2,090.4	93.4	-	-	(2,757.9)	-	-	-
Total revenue	903.4	4,405.1	171.5	2,633.3	-	(2,757.9)	5,355.4	35.3	5,390.7
Cost of sales	(550.9)	(3,453.6)	(24.5)	(2,524.6)	(6.9)	2,766.7	(3,793.8)	(84.0)	(3,877.8)
Gross profit/(loss)	352.5	951.5	147.0	108.7	(6.9)	8.8	1,561.6	(48.7)	1,512.9
Operating and administrative expenses	(222.2)	(225.8)	(36.1)	(60.8)	(67.4)	(2.3)	(614.6)	(23.3)	(637.9)
Impairment of financial assets	-	(0.3)	-	0.8	-	-	0.5	(3.8)	(3.3)
Depreciation	(95.7)	(105.3)	(19.2)	(0.9)	(7.0)	(0.8)	(228.9)	-	(228.9)
Amortisation	(4.3)	(3.9)	-	(4.2)	(1.8)	-	(14.2)	-	(14.2)
Impairment of non-current assets	(25.6)	-	-	-	(1.6)	-	(27.2)	(350.5)	(377.7)
Other (losses)/gains	(7.0)	(0.2)	(0.8)	-	3.6	-	(4.4)	(3.6)	(8.0)
Share of losses from associates	(1.6)	-	-	-	-	-	(1.6)	-	(1.6)
Operating (loss)/profit	(3.9)	616.0	90.9	43.6	(81.1)	5.7	671.2	(429.9)	241.3

Further information on the main revenue streams of each segment is presented in note 2.

The following is an analysis of the Group's performance by reportable segment for the year ended 31 December 2024:

	Year ended 31 December 2024
	Pellet Production £m	Biomass Generation £m	Flexible Generation £m	Energy Solutions £m	Innovation, capital projects and other £m	Intra-group eliminations £m	Adjusted results £m		Exceptional items and certain remeasurements £m		Total results £m
Revenue
External sales	340.1	1,880.7	74.3	3,786.1	-	-	6,081.2		81.3		6,162.5
Inter-segment sales	602.0	3,040.0	148.5	-	-	(3,790.5)	-		-		-
Total revenue	942.1	4,920.7	222.8	3,786.1	-	(3,790.5)	6,081.2		81.3		6,162.5
Cost of sales	(562.1)	(3,685.5)	(46.2)	(3,625.0)	-	3,788.7	(4,130.1)		4.9		(4,125.2)
Electricity Generator Levy	-	(150.2)	(10.6)	-	-	-	(160.8)		-		(160.8)
Gross profit/(loss)	380.0	1,085.0	166.0	161.1	-	(1.8)	1,790.3		86.2		1,876.5
Operating and administrative expenses	(236.7)	(268.6)	(28.4)	(85.5)	(78.1)	(1.2)	(698.5)		(22.1)		(720.6)
Impairment of financial assets	-	(2.9)	-	(24.4)	-	-	(27.3)		(12.7)		(40.0)
Depreciation	(102.7)	(97.7)	(17.1)	(0.7)	(5.8)	(0.8)	(224.8)		-		(224.8)
Amortisation	(4.5)	(2.9)	-	(7.3)	(2.3)	-	(17.0)		-		(17.0)
Impairment of non-current assets	(3.3)	(0.1)	-	-	(8.4)	-	(11.8)		(2.6)		(14.4)
Other (losses)/gains	(4.1)	(4.6)	0.2	-	-	-	(8.5)		1.2		(7.3)
Share of losses from associates	(1.3)	-	-	-	(0.9)	-	(2.2)		-		(2.2)
Operating profit/(loss)	27.4	708.2	120.7	43.2	(95.5)	(3.8)		800.2		50.0		850.2

Assets and working capital are monitored on a consolidated basis; however, capital expenditure is monitored by segment.

As at 31 December	Capital expenditure on intangible assets			Capital expenditure on property, plant and equipment
	2025 £m	2024 £m		2025 £m	Restated (1) 2024 £m
Pellet Production	-	-		54.5	100.2
Biomass Generation	-	0.5		38.3	67.9
Flexible Generation	-	-		84.8	137.0
Energy Solutions	3.3	3.8		1.0	0.3
Innovation, capital projects and other	9.6	2.6		10.3	8.5
Total	12.9	6.9		188.9	313.9

(1)   The definition of capital expenditure has been updated in the current period to align with the way the information is presented to the Executive Committee. Capitalised interest and plant spares are now excluded from the definition of capital expenditure. In the year ended 31 December 2024 there was £1.7 million of capitalised interest (Pellet Production £0.1 million and Flexible Generation £1.6 million) and £9.9 million of capitalised plant spares (Pellet Production £4.5 million, Biomass Generation £4.6 million and Flexible Generation £0.8 million) that were included in the amounts presented in the 2024 Consolidated financial statements. Comparative amounts in the table above have been restated to exclude capitalised interest and capitalised plant spares.

Total cash outflows in relation to capital expenditure during the year were £294.2 million (2024: £387.5 million). In the current year, the cash outflow in relation to property, plant and equipment is higher than the cost capitalised, predominantly as a result of a decrease in creditors relating to capital expenditure within the year.

Intra-group trading

Intra-group transactions are carried out at management's best estimate of arm's-length, commercial terms that, where possible, equate to market prices. The impact of all intra-group transactions, including any unrealised profit arising, is eliminated on consolidation.

Analysis of revenue from intra-group trading is provided in the table below:

	Intra-group trading revenue
	Year ended 31 December
	2025 £m	2024 £m
Pellet Production segment sale of biomass pellets and provided associated services to the Biomass Generation segment	574.1	602.0
Biomass Generation segment sale of electricity, gas and renewable certificate assets to the Energy Solutions segment	2,007.0	2,928.7
Biomass Generation segment sale of electricity to the Flexible Generation segment	16.2	36.5
Biomass Generation segment sale of biomass pellets to the Pellet Production segment	67.2	74.8
Flexible Generation segment sale of electricity and renewable certificate assets to the Biomass Generation segment	90.1	145.9
Flexible Generation segment sale of electricity to the Energy Solutions segment	3.3	2.6
Total inter-segment sales (note 2)	2,757.9	3,790.5

Major customers

There was no individual customer, in either the current or previous financial year, that represented 10% or more of total revenue.

Geographical analysis of revenue and non-current assets

The geographic information analyses the Group's revenue and non-current assets by the entity's country of domicile. In presenting the geographic information, segment revenue has been based on the geographic location of customers and segment assets were based on the geographic location of the assets.

The Group's external revenue and non-current assets for the Biomass Generation, Flexible Generation and Energy Solutions segments are all UK-based. The Pellet Production segment has third-party pellet sales to both the UK and other locations around the world. The Pellet Production segment's non-current assets are located in North America, in both Canada and the US.

	Revenue (based on location of customer)
	Year ended 31 December
	2025 £m	2024 £m
North America (Canada and US)	8.4	7.9
Europe (excluding UK)	7.5	25.8
Asia	251.2	242.5
UK	5,123.6	5,886.3
Total	5,390.7	6,162.5

	Non-current assets (1) (based on asset's location)
	As at 31 December
	2025 £m	2024 £m
Canada	84.2	356.5
US	541.6	698.9
Asia	0.2	0.2
UK	2,309.7	2,334.1
Total	2,935.7	3,389.7

(1)   Non-current assets comprise goodwill, intangible assets, property, plant and equipment, right-of-use assets and investments.

2. Revenue

Accounting policy

Revenue represents amounts receivable for goods or services provided to customers in the normal course of business, net of trade discounts, VAT and other sales-related taxes and excludes transactions between Group companies. Revenue is presented gross in the Consolidated income statement when the Group controls the specified good or service prior to the transfer to the customer. When the Group is acting primarily as an agent, revenue is recognised on a net basis.

A summary of the Group's principal revenue streams, along with the nature and timing of performance obligations, payment terms, methods of recognising revenue, and any estimation uncertainties, is given in the table below.

The majority of the Group's revenue is within the scope of IFRS 15. The other sources of the Group's revenue outside the scope of IFRS 15 comprise gains and losses on certain non-hedge accounted derivatives, the ineffective portion of certain hedge accounted derivatives, amounts reclassified to revenue for gains and losses on hedge accounted UK inflation swaps, Contract for Difference (CfD) income, and income from the UK Government's Energy Bills Discount Scheme (EBDS). See note 4 for further details on gains and losses on derivatives. Gains and losses recognised in the Consolidated income statement on derivative contracts that are entered to hedge a revenue item are presented within the same revenue stream line as the revenue item they are intending to hedge.

	Year ended 31 December 2025				Year ended 31 December 2024
	Adjusted results £m	Exceptional items and certain remeasurements £m	Total results £m		Adjusted results £m	Exceptional items and certain remeasurements £m	Total results £m
Revenue from contracts with customers	5,163.0	(25.9)	5,137.1		5,918.2	(6.9)	5,911.3
Other revenue	192.4	61.2	253.6		163.0	88.2	251.2
Total revenue	5,355.4	35.3	5,390.7		6,081.2	81.3	6,162.5

Revenue stream (Segment)	Nature and timing of performance obligations, including significant payment terms	Method of recognising revenue, including any estimation uncertainties
Pellet sales (Pellet Production)	The Group's Pellet Production business produces biomass pellets which are sold to external customers. Customers generally obtain control of the pellets at the point the pellets are loaded onto the shipping vessel. Where freight is also arranged for the customer, these sales are known as cost, insurance and freight (CIF) sales. The freight component is considered a separate performance obligation. Invoices are raised in line with contractual terms and are usually payable within 4-10 days.	Revenue is recognised at the point that the pellets are loaded onto the shipping vessel. The amount of revenue recognised is based on the contracted price and volume of the pellets. For CIF sales, revenue for the freight portion is recognised over the period the vessel sails.
Electricity sales (Biomass Generation and Flexible Generation)	The Group's Biomass Generation and Flexible Generation businesses have contracts for wholesale electricity sales. Performance obligations, being the supply of electricity, are met either via generation or through the procurement of electricity from counterparties. The performance obligations for these contracts are deemed to be a series of distinct goods that are substantially the same and transfer consecutively. Control is deemed to have transferred to the customer at the point that the electricity has been supplied in accordance with the contractual terms. Invoices for electricity are typically raised on the fifth banking day following the month of supply, in line with the Grid Trade Master Agreement (GTMA) contractual terms, and are payable on the fifth banking day following the date of invoice.	Revenues from sales contracts fulfilled through generation are recognised at a point in time based upon metered output at rates specified under contractual terms. Revenue from sales contracts fulfilled through procured electricity is recognised at the point at which this electricity or gas is supplied to the counterparty in accordance with the contractual terms at rates specified under the contract. These are recognised under the output method, whereby revenue is recognised based on the value transferred to the customer.
Renewable certificate sales (Biomass Generation, Flexible Generation and Energy Solutions)	Renewables Obligation Certificates (ROCs) and Renewable Energy Guarantees of Origin (REGOs) are sold to counterparties at a point in time. ROCs sold are invoiced in line with contractual terms and are usually payable within two to five days. Invoices for REGOs are raised in line with contractual terms and are usually payable within 7-30 days.	External ROC and REGO sales are recognised at the point the relevant renewable certificates are transferred to the counterparty.
CfD income (Biomass Generation)	The Group's Biomass Generation business is party to a CfD with the Low Carbon Contracts Company (LCCC), a UK Government-owned entity responsible for delivering elements of the UK Government's Electricity Market Reform programme. Under the contract, the Group receives income in respect of electricity dispatched from a specific biomass-fuelled generating unit. Invoices are raised 7-10 days following the date of supply and are settled within 28 days.	The Group recognises the income arising from the CfD in the Consolidated income statement as a component of revenue at the point the Group meets its performance obligation under the CfD agreement. This is considered to be the point at which the relevant generation is delivered. See CfD income section below for further details.
Ancillary services (Biomass Generation and Flexible Generation)	Ancillary services refer to the provision of a range of system support services to National Grid. Most contracts are for the delivery of a specific service either continually or on an ad-hoc basis over a period of time. Invoices are raised and subsequently settled in line with the National Grid company ancillary services settlement calendar, typically monthly.	Revenue is recognised over time for ancillary services as the Group provides the service of either being available and ready to support the UK Electricity Grid or providing a service when called upon to support the UK Electricity Grid. Revenue is recognised over time by reference to the stage of completion of the contractual performance obligations, which for stand ready performance obligations are calculated by reference to the amount of the contract term that has elapsed. Revenue recognised for providing services when called upon are recognised over the time the service is being provided to support the UK Electricity Grid. Depending on contract terms, this approach may require judgement in estimating probable future outcomes when the amount of consideration the Group is entitled to is variable based on its performance over a period of time.
Electricity and gas sales (Energy Solutions)	The Group's Energy Solutions business sells electricity and gas directly to non-domestic customers. Energy supplied is measured based upon metered consumption and contractual rates. The Energy Solutions business also has long-term contracts for the sale of electricity and gas, which are a series of distinct goods or services that are substantially the same and have the same pattern of transfer and are a performance obligation that is deemed as being satisfied over time in line with the progress of the contracts. Invoices are raised in line with contractual terms which for most customers is monthly. Payment is generally due between 28-90 days.	Revenue is recognised on the supply of electricity or gas when a contract exists, supply has taken place, a quantifiable price has been established or can be determined, and the amounts receivable are expected to be recovered. Where supply has taken place but has not yet been measured or billed, revenue is estimated based on consumption statistics and selling price estimates and is recognised as accrued income. This estimate is not considered to be a key source of estimation uncertainty because historical experience has demonstrated that these estimates are materially accurate based on the subsequent billings and settlements. Where contracts for the sale of electricity and gas are held, revenue is recognised in line with the progress of the contracts. Revenue recognised for fixed price contracts is based on the input method. Revenue is recognised based on the costs incurred and the estimated margin to be obtained over the life of the contract. For variable price contracts revenue is recognised based on the output method. Revenue is recognised based on the volume supplied and the contracted price. Assumptions are applied consistently but third-party costs can vary, therefore actual outcomes may vary from initial estimates.
EBDS income (Energy Solutions)	The UK Government introduced the EBDS running from 1 April 2023 to 31 March 2024. Under this scheme, energy supplied to eligible non-domestic customers had a discount applied to each unit of electricity and gas. Certain customers were eligible for higher levels of support dependent on the sector in which they operated. The discount provided was then able to be claimed back from the UK Government by the supplier. Payment was due 10 days post submission of a claim, which typically occurred monthly.	The discounted price of electricity and gas supplied under EBDS was recognised in revenue as it was supplied. The amount claimed back from the UK Government was recognised within revenue over the same period as the underlying discounted revenue it related to was recognised. The revenue received from the UK Government is included in the EBDS income line in the table below. The Group did not recognise any additional revenue from the scheme than it would have done had it not been introduced.
Other income (All segments)	Other income is derived from the sale of goods. The customer obtains control typically at the point of delivery to their premises or upon collection. Invoices are raised in line with contractual terms. The majority of invoices are raised quarterly and are payable within 30 days.	Revenue is recognised at the point the control of the goods is transferred to the customer.

Renewable certificate sales

The generation and sale of renewable certificates, primarily ROCs and REGOs, is a key driver of the Group's financial performance.

During the year, the Group made sales and related purchases of ROCs to help optimise its working capital position. External sales of ROCs in the table below includes £237.5 million of such sales (2024: £50.8 million), with a similar value reflected in cost of sales. The renewable certificate sales revenue in the Biomass Generation business of £931.0 million has increased compared to the prior year (2024: £739.3 million) primarily as a result of the increase in these ROC sales.

CfD income

The income is calculated by reference to a strike price per MWh. The base year for the strike price was 2012 and it increases each year in line with the UK Consumer Price Index (CPI) and changes in system balancing costs. The strike price at 31 December 2025 was £142.24 per MWh (2024: £138.16 per MWh).

When market prices (based on average traded prices in the preceding season) are above or below the strike price, the Group makes an additional payment to or receives additional income from LCCC equivalent to the difference between that market power price and the strike price, for each MWh produced from the relevant generating unit. Such payments or receipts are in addition to amounts received from the sale of the associated power in the wholesale market.

Further analysis of revenue for the current and prior year is provided in the table below:

	Year ended 31 December 2025				Year ended 31 December 2024
	External £m	Inter-segment £m	Total £m		External £m	Inter-segment £m	Total £m
Pellet Production
Pellet sales	320.1	574.1	894.2		329.6	597.5	927.1
Other income	9.2	-	9.2		10.5	4.5	15.0
Total Pellet Production	329.3	574.1	903.4		340.1	602.0	942.1
Biomass Generation
Electricity and gas sales	1,582.8	1,599.6	3,182.4		1,426.6	2,510.7	3,937.3
Renewable certificate sales	507.4	423.6	931.0		284.8	454.5	739.3
CfD income	192.4	-	192.4		148.6	-	148.6
Ancillary services	18.0	-	18.0		18.7	-	18.7
Other income	14.1	67.2	81.3		2.0	74.8	76.8
Total Biomass Generation	2,314.7	2,090.4	4,405.1		1,880.7	3,040.0	4,920.7
Flexible Generation
Electricity sales	28.8	83.8	112.6		22.1	141.2	163.3
Renewable certificate sales	-	9.6	9.6		-	7.3	7.3
Ancillary services	21.2	-	21.2		24.2	-	24.2
Other income	28.1	-	28.1		28.0	-	28.0
Total Flexible Generation	78.1	93.4	171.5		74.3	148.5	222.8
Energy Solutions
Electricity and gas sales	2,619.5	-	2,619.5		3,734.0	-	3,734.0
EBDS income	-	-	-		14.4	-	14.4
Renewable certificate sales	13.8	-	13.8		37.4	-	37.4
Other income	-	-	-		0.3	-	0.3
Total Energy Solutions	2,633.3	-	2,633.3		3,786.1	-	3,786.1
Elimination of inter-segment sales	-	(2,757.9)	(2,757.9)		-	(3,790.5)	(3,790.5)
Total consolidated revenue in Adjusted results	5,355.4	-	5,355.4		6,081.2	-	6,081.2
Certain remeasurements	35.3	-	35.3		81.3	-	81.3
Total consolidated revenue in Total results	5,390.7	-	5,390.7		6,162.5	-	6,162.5

Revenue recognised in Adjusted results of £5,355.4 million (2024: £6,081.2 million) differs from revenue recognised in Total results of £5,390.7 million (2024: £6,162.5 million) due to certain remeasurement gains of £35.3 million (2024: £81.3 million), comprised of gains and losses on derivative contracts that are used to manage risk exposures associated with the Group's revenue not designated into hedge accounting relationships under IFRS 9, and hedge ineffectiveness on hedge accounting relationships reclassified to profit or loss. See note 4 for further details on certain remeasurements included within revenue.

Revenue recognised in the period that was included within contract liabilities at the start of the year was £23.1 million (2024: £16.8 million).

Revenue recognised in the period from performance obligations satisfied or partly satisfied in the previous period was £nil (2024: £nil).

The Group's Biomass Generation and Flexible Generation segments have contracts for wholesale electricity sales. Performance obligations, being the supply of electricity, are met either via electricity generation or through the procurement of electricity from counterparties. Where electricity is procured from counterparties to meet this obligation, the electricity sale is presented on a gross basis with the cost of buying the electricity presented in cost of sales and the sale of this electricity presented in revenue. If external purchases of power were presented net within external revenue this would have reduced external revenue by £1,044.8 million to £4,345.9 million (2024: by £1,072.9 million to £5,089.6 million) with a corresponding decrease in external cost of sales.

For most customer contracts the Group is eligible for, and applies, the practical expedient available under IFRS 15 and has not disclosed information related to the transaction price allocated to remaining performance obligations. This applies to revenue where either the right to receive consideration from the customers is at an amount that corresponds directly with the value transferred to the customer for the Group's performance completed to date, or the contract's original expected duration is less than one year. For the Group's fixed price energy supply contracts that have an original expected duration of more than one year, the aggregate amount of the transaction price allocated to performance obligations that are unsatisfied at the end of the reporting period is shown in the table below.

	Year ended 31 December
	2025 £m	2024 £m
Amounts expected to be recognised as revenue:
Within one year	105.8	127.0
Within one to two years	28.5	18.4
Within two to three years	4.9	1.2
Transaction price allocated to performance obligations that are unsatisfied at the end of the reporting period	139.2	146.6

3. Impairment review of non-current assets

Accounting policy

Goodwill is tested for impairment at least annually. For the purpose of impairment testing, goodwill is allocated to each of the Group's cash-generating units (CGUs) or group of CGUs expected to benefit from the synergies of the business combination.

A CGU is the smallest identifiable group of assets that generates cash inflows that are largely independent of the cash inflows from other assets or groups of assets. CGUs are identified consistently from period to period unless there is a change in the period that would impact the Group's CGUs. The Group's CGUs are reassessed should any such changes occur.

The Group reviews its non-current assets (and, where appropriate, groups of assets combined into a CGU) whenever there is an indication that an impairment loss may have been suffered. The Group assesses the existence of indicators of impairment at the end of each reporting period.

If an indication of potential impairment exists, the recoverable amount of the asset or CGU in question is assessed with reference to the present value of the future cash flows expected to be derived from the continuing use of the asset or CGU (value in use), or the expected price that would be received if the asset or CGU were sold to a market participant (fair value less costs of disposal). The recoverable amount of an asset or CGU is the higher of its fair value less costs of disposal (FVLCD) and its value in use (ViU). The initial assessment of the recoverable amount is normally based on ViU unless FVLCD is considered more appropriate.

The future cash flows used in ViU calculations are based on the approved long-term forecasts that support the Board and executive management's strategic planning process and include all expected costs necessary to generate the cash inflows from the CGU's assets in their current state and condition, including an allocation of centrally managed costs. Future cash flows include, where relevant, contracted cash flows arising from the Group's forward hedging activities and as a result the carrying amount of each CGU includes the fair value of those hedges.

Assessments of future cash flows consider relevant environmental and climate change factors. In particular, macro-economic, commodity price and third-party cost assumptions reflect considerations in respect of the impact of climate change, growth in renewable technologies, electrification and the impact of relevant policies on longer-term supply and demand profiles.

As required by IAS 36, the additional value that could be obtained from enhancing the Group's assets and the potential benefit of any future restructuring or reorganisation that the Group is not yet committed to, is not reflected in the ViU calculation.

In determining ViU, the estimated future cash flows are discounted to present value using a pre-tax nominal discount rate reflecting the specific risks attributable to the asset or CGU in question.

When calculating FVLCD, the method most appropriate for an individual asset or CGU is considered. This is generally either based on available market information on prices or comparable transactions, or a discounted cash flow method, similar to ViU, but including the impact of all relevant factors a market participant would consider.

If the recoverable amount is less than the carrying amount in the Consolidated financial statements, an impairment charge is recognised to reduce the carrying amount of the asset or CGU to the estimated recoverable amount. Any impairment loss is recognised immediately in the Consolidated income statement.

Individual assets are considered for impairment where possible. If individual assets do not generate cash inflows that are largely independent, the recoverable amount is determined for the CGU to which the asset belongs. Where possible, corporate assets are allocated to an individual CGU on a reasonable and consistent basis. Where corporate assets cannot be allocated to an individual CGU on a reasonable and consistent basis, they are included in the carrying amount of the smallest group of CGUs to which they can be allocated on a reasonable and consistent basis.

An impairment loss relating to a CGU is allocated first to the carrying amount of any goodwill allocated to the CGU and then to the other assets pro-rata on the basis of the carrying amount of each asset. When allocating an impairment loss to the other assets in the CGU, if the recoverable amount of an individual asset within that CGU is determinable, the impairment loss allocated to the individual asset is limited to reducing the asset's carrying value to its individual recoverable amount. If this results in the impairment loss allocated to an asset being less than its pro-rata share, the excess is allocated on a pro-rata basis to the remaining assets in the CGU. An impairment loss recognised for goodwill is not reversed in a subsequent period. Non-financial assets other than goodwill that have an impairment loss recognised are reviewed in subsequent reporting periods for possible reversal of the impairment. Where an impairment reversal is identified, this is reversed immediately in the Consolidated income statement.

The table below details the Group's reportable segments, the CGUs within those segments and the value of any goodwill allocated to them.

CGUs

Segment name	CGUs contained within segment	As at 31 December 2025
		Goodwill £m
Pellet Production	Northern Pellets	-
	Biomass (Southern Pellets)	156.7
Biomass Generation	Biomass (Drax Power Station)	-
Flexible Generation	Lanark	11.3
	Galloway	40.1
	Cruachan	26.9
	Hirwaun	-
	Millbrook	-
	Progress	-
	Daldowie	-
Energy Solutions	Drax Energy Solutions	161.2
	Opus Energy	-
		396.2

Previously, the Group's pellet production activities in Canada and the US formed a single CGU (Pellet Operations), reflecting management's integration of the Group's Canadian and US pellet plants into one combined business following the Pinnacle acquisition in 2021, with pellets from the Canadian pellet plants (Northern Pellets) and the US pellet plants (Southern Pellets) being used interchangeably to fulfil third-party customer contracts and internally at Drax Power Station, with biomass generation forming a separate CGU (Drax Power Station). During 2025, market conditions changed significantly. Expected future demand for biomass pellets declined following changes to the UK support schemes, with reduced volumes under the low carbon dispatchable CfD agreed in November 2025, despite this agreement providing greater certainty over the future of Drax Power Station. At the same time, global pellet supply increased, particularly from Southeast Asia, and Canadian fibre availability was affected by tariffs. In the second half of 2025, the Group restructured its pellet operations, with its US pellet plants now dedicated to supplying Drax Power Station and its Canadian pellet plants focused on third-party customers. This operational change required a reassessment of the Groups CGUs and resulted in Northern Pellets and Southern Pellets being assessed separately, as their cash flows are now independent.

The Group's US pellet plants now operate solely to supply Drax Power Station, and therefore do not generate cash inflows independently from Drax Power Station. Due to their whole output being used internally, and the absence of an active external market for their output, from 2025, the US pellet plants and the biomass generation activities at Drax Power Station are assessed together as a single Biomass CGU.

Goodwill arising from the 2021 Pinnacle acquisition was previously allocated to the Pellet Operations CGU. Following the change in CGU structure, this goodwill has been reallocated between Northern Pellets and Southern Pellets using a relative fair value approach, in accordance with IAS 36. This resulted in C$15.7 million (£8.4 million based on exchange rates at the time of reallocation) being allocated to Northern Pellets and US$210.8 million (£156.7 million based on exchange rates at the time of reallocation) being allocated to Southern Pellets. As Southern Pellets is within the Pellet Production segment but forms part of the Biomass CGU, goodwill allocated to Southern Pellets is also tested at the Southern Pellets level to ensure allocation and testing of goodwill does not take place at a level higher than an operating segment.

There are no changes to any other CGUs from the prior year.

In respect of the Flexible Generation segment, the Group generally considers the smallest groups of assets that generate independent cash inflows to be the individual sites that share common infrastructure and control functions.

In respect of the Energy Solutions segment, the smallest groups of assets that generate independent cash inflows are the operating entities within the business, Drax Energy Solutions and Opus Energy.

The Group's Innovation, capital projects and other operations provides central support functions to the Group's main business activities and does not earn revenues and therefore does not meet the definition of a CGU. However, as explained above, corporate assets are considered for impairment individually where possible or as part of a CGU, and relevant centrally managed costs are allocated to each CGU on a reasonable and consistent basis.

Assessment of indicators of impairment for CGUs to which no goodwill is allocated

Full impairment reviews were performed on all CGUs to which goodwill had been allocated (see Impairment review section below). For CGUs to which no goodwill is allocated, impairment reviews are only performed if impairment indicators are identified.

In determining whether impairment indicators existed in respect of these CGUs, the Group considered changes in market prices for commodities, foreign currency exchange rates, changes in macro-economic conditions, potential impacts of climate change and regulatory requirements since the previous reporting date, and their potential impact on the Group's long-term planning models and future forecast cash flows. Given the relatively consistent macro-economic conditions compared to the prior year end, as well as falling interest rates, these are not considered to be impairment indicators. Commodity prices have been relatively stable (e.g. power and gas) since the prior year end. The Group's generation activities in CGUs to which no goodwill is allocated are less sensitive to power price changes due to generation activities being more dependent on the spread between gas and power prices. Further, a high proportion of the Group's income is not linked to power prices, such as income from renewable certificates, system support and ancillary services. From the factors considered above, no impairment indicators were noted.

Whilst the commissioning date for the assets in the Hirwaun, Millbrook and Progress CGUs have been delayed, this was not considered an impairment indicator as the cash flow impact of these delays is not significant.

There were no impairment indicators present for the Opus Energy, Hirwaun, Millbrook, Progress or Daldowie CGUs and accordingly no impairment review was performed for these CGUs in the current year.

Impairment review

For the purpose of impairment reviews, the recoverable amounts of the CGUs, or groups of CGUs, are measured using ViU or FVLCD. ViU is calculated based on a discounted cash flow method using the Group's established planning models. FVLCD uses a market price or comparable recent market transaction where possible. Where this information is not available FVLCD is also based on a discounted cash flow method using the Group's established planning models as a base, but adjusting for impacts or changes that a market participant would factor in. These calculations depend on a broad range of assumptions, the most significant of which are outlined below for each CGU, or group of CGUs, to which an impairment test has been performed in the current year. The bases of these estimates are outlined below.

CGU	Calculation method used to determine recoverable amount	Significant assumptions for ViU or FVLCD calculation	Management's bases for determining estimates used in ViU or FVLCD calculation
Northern Pellets	FVLCD	- Production costs - Production volumes - Sales volumes - Sales prices - Central costs - Discount rate	- Future production costs are estimated based on a combination of current and historical costs, inflation expectations and maintenance/operating assumptions - Production volumes are estimated based on the sales volumes agreed under contractual pellet supply arrangements entered into with third parties as well as forecast sales volumes, taking into account planned and unplanned downtime provisions, and fibre availability - Sales volumes are estimated based on contractual pellet supply arrangements entered into with third parties and assumed further contracted volumes after current contracts expire based on third-party market demand forecasts and current contract negotiations - Sales prices are forecast based on contractual sales agreements and an assumed market price after current contracts expire based on third-party market forecasts and current contract negotiations - Central costs are estimated based on historical costs and adjustments that a third-party market participant could reasonably expect to implement - See below for details of the basis used to estimate discount rates
Biomass	ViU	- Power prices - Biomass support mechanisms - Post-March 2031 income - Pellet costs (self-supply and third-party) - Pellet production volumes - Ancillary income - Volume of generation - Discount rate	- Power revenue is derived from hedged power sales, future wholesale energy price estimates and an assumption of additional value added through the balancing market and optimisation - Future wholesale energy price estimates are based on market traded power prices for around three years (the period they are liquid), gas market prices as a proxy for power for another two years, then the Group's long-term power price forecast, which is prepared using externally provided gas price forecasts and demand inputs - Biomass support mechanism income is based on the terms of existing biomass support schemes applicable to Drax Power Station for the period up to March 2027 and for the period April 2027 to March 2031 are based on the agreed terms of the low carbon dispatchable CfD agreement with the UK Government - Post-March 2031 biomass generation income is based on the assumption that the levels of income forecast under the low carbon dispatchable CfD agreement for the period April 2027 to March 2031 will continue at a similar level of value up to 2039 - Self-supply pellet production costs are estimated based on a combination of current and historical costs, inflation expectations and maintenance/operating assumptions - Third-party pellet costs are based on historical third-party pellet supply contracts, current pricing and offers, and ongoing negotiations - Pellet production volumes are estimated based on a combination of the capacity of the plant, current and historical volumes produced, planned and unplanned downtime provisions, and fibre availability - Ancillary income assumptions are based on past performance and current agreed prices with National Grid - Volume of generation is based on renewable support scheme terms and power price forecasts - See below for details of the basis used to estimate discount rates
Lanark, Galloway and Cruachan	ViU	- Power prices - Ancillary income - Volume of generation - Discount rate	- Power revenue is derived from hedged power sales, future wholesale energy price estimates and an assumption of additional value added through the balancing market and optimisation - Future wholesale energy price estimates are based on market traded power prices for around three years (the period they are liquid), gas market prices as a proxy for power for another two years, then the Group's long-term power price forecast, which is prepared using externally provided gas price forecasts and demand inputs - Ancillary income assumptions are based on past performance and current agreed prices with National Grid - Volume of generation for the run-of-river hydro assets is derived from historical rainfall averages - Volume of generation for Cruachan is based on forecast volatility in power prices and assumed weather patterns - See below for details of the basis used to estimate discount rates
Drax Energy Solutions	ViU	- Customer margins - Supply volumes - Third-party cost estimates - Renewables services growth rates - Discount rate	- Customer margins are estimated based on current contracted prices and on current and previously achieved profitability - The expectation of future organic supply volumes is based on past performance and management's expectations of market developments - Third-party cost estimates are based on a combination of externally published rates, management analysis of key market input assumptions, and forecasts from external experts - Renewables services growth is based on assumptions about the growth of relevant markets, such as electric vehicles - See below for details of the basis used to estimate discount rates

For the Northern Pellets CGU, FVLCD was higher than ViU. FVLCD was determined by discounting the post-tax cash flows that a third-party market participant would be expected to be able to generate from the CGU, less any costs of disposal. The cash flows used in calculating the FVLCD were based on management's detailed cash flows in the Group's established planning models, but adjusted for changes, primarily to reduce central costs, that a market participant with a different structure and requirements would be able to achieve.

For the Drax Energy Solutions CGU, management has projected detailed cash flows based on a period of five years, with cash flows beyond the five-year period taken into perpetuity using a long-term growth rate of 2%. For all other CGUs, management has projected detailed cash flows based on a period of 15 years, except for the Biomass CGU whose cash flows are forecast for 14 years in line with the useful economic life of Drax Power Station, which is to 2039. Whilst these periods are longer than the five-year period specified by IAS 36, and the period the Group assesses viability over in the Viability statement, they align with the Group's long-term strategic planning and takes into account future structural changes forecast within the generation and pellet production industries, as well as expected developments in the pellet production industry. These longer-term structural changes are mainly linked to climate change and the impact of changing weather patterns (including increased rain fall from storms and drier summer months for the run-of-river hydro CGUs and the impact on plant downtime and supply chains due to extreme weather events for the Northern Pellets and Biomass CGUs), the impact of decarbonisation and the transition to more renewable forms of energy and Net Zero, the impact of subsidy and support regimes, and the impact of repairs and maintenance expenditure which is not uniform across the lives of assets. Using a period of only five years for detailed cash flow forecasts could materially overstate or understate the recoverable amounts of these CGUs as the impact of these factors in periods after five years can be significant. The Northern Pellets CGU also has long term contracts that can be in excess of 10 years which further supports using a period greater than five years.

Where possible, for relevant commodities, forecasts are based on either contracted prices, particularly for the Northern Pellets and Biomass CGUs where the Group has a number of longer-term contracts to support the prices used, or observable market curves. Beyond the liquid portion of forward curves, internally constructed price curves are benchmarked against third-party market analysis to validate the reasonableness of the assumptions used. Management continually reassesses forecasting accuracy, considering changes in circumstances and whether forecasting differences were as a result of events that could not reasonably be foreseen at the date of the forecast. These reviews support the accuracy of management's forecasts. This supports the use of detailed forecast periods of longer than five years.

Where management has projected detailed cash flows based on a period of 15 years (Northern Pellets, Lanark, Galloway and Cruachan), cash flows beyond the 15-year period are taken into perpetuity using a long-term growth rate of 2%. The long-term growth rate is based on prudent expectations of market share and profitability along with more general macro-economic factors which were obtained from the Group's established planning model along with external macro-economic forecasts. The long-term growth rate does not exceed the relevant long-term average growth rate for each of the industries in which the Group operates.

The discount rates used for each CGU are calculated with input from third-party experts and reflect the weighted average cost of capital derived using the Capital Asset Pricing Model (CAPM). The estimations use a risk-free rate based on Government bonds, market participant capital structures and beta estimates adjusted for the specific circumstances and risk factors affecting the industry and markets in which the CGU operates (taking into account relevant peer data sets). The CAPM calculates a post-tax discount rate which is applied to post-tax cash flows. An iterative computation using pre-tax cash flows is then performed to derive an equivalent pre-tax discount rate.

Further details on the assessments for each group of CGU as well as sensitivities for reasonably possible changes in key assumptions at the date of the impairment test are given below. Where reasonably possible changes in key assumptions would result in a material adjustment to the carrying value of a CGU, these are disclosed as a key source of estimation uncertainty.

The carrying amount, length of detailed cash flows, pre-tax discount rate and the perpetuity growth rate, where applicable, used in the calculation of each CGU's recoverable amount are set out in the table below:

CGU	Carrying amount including allocated goodwill £m	Length of detailed cash flows £m	Pre-tax discount rate	Perpetuity growth rate
Northern Pellets	84.2	15 years	19.3%	2.0%
Biomass	1,412.3	14 years	11.5%	n/a
Drax Energy Solutions	178.2	5 years	9.2%	2.0%
Lanark	44.3	15 years	8.0%	2.0%
Galloway	174.2	15 years	8.0%	2.0%
Cruachan	298.6	15 years	8.0%	2.0%

Northern Pellets

The Northern Pellets CGU produces and sells biomass pellets to third-party customers. Market conditions during 2025 significantly reduced expected future demand, driven by changes and expiries in UK and Dutch support schemes, including lower contracted volumes under the low carbon dispatchable CfD effective from April 2027. Global supply has also increased, particularly from Southeast Asia, and fibre availability in Canada has been affected by tariffs. As a result, Northern Pellets has refocused on third-party sales, and expectations for its future growth have reduced.

The recoverable amount of the CGU, based on FVLCD, was less than its carrying value of £278.3 million, resulting in an impairment charge of £194.1 million. Assets for which ViU is determinable or FVLCD is measurable have not been impaired below these values. Goodwill was written down to £nil, with the remaining impairment allocated across other assets on a pro-rata basis. This resulted in an impairment of £8.5 million being allocated to goodwill and £185.6 million to other assets.

Following the impairment, the CGU's carrying value equals its recoverable amount. Assets with determinable fair values above their carrying value were not impaired, while assets without a measurable recoverable amount were written down to £nil. The carrying value remains sensitive to key assumptions in the FVLCD model.

Reasonably possible downside changes in assumptions from those used in the FVLCD calculation include a 50% reduction in assumed central cost savings, combined with a 7% decrease in pellet sales contract renewal prices, an increase in the pre-tax discount rate from 19.3% to 30.8% (equivalent to an increase in the post-tax discount rate from 15.0% to 18.0%), and a reasonably possible 30% decrease in the fair value determined for the individual assets that were not allocated an impairment loss. This combination of reasonably possible changes would result in an increase in the impairment recognised of £27.1 million and a corresponding reduction in the carrying value of the Northern Pellets CGU.

Reasonably possible upside changes in assumptions from those used in the FVLCD calculation include a 7% increase in pellet sales contract renewal prices, combined with a decrease in the pre-tax discount rate from 19.3% to 15.0% (equivalent to a decrease in the post-tax discount rate from 15.0% to 12.0%). This combination of reasonably possible changes would result in a reduction in the impairment recognised of £72.6 million and a corresponding increase in the carrying value of the Northern Pellets CGU.

Accordingly, the FVLCD assumptions for this CGU have been identified as a key source of estimation uncertainty.

Biomass

The Biomass CGU is principally focused on renewable biomass electricity generation, including its integrated pellet supply chain. Given the allocated goodwill, a full impairment assessment has been performed. The cash flows between April 2027 and March 2031 reflect management's best estimate of earnings based on the terms of the low carbon dispatchable CfD agreement signed in November 2025. The expected income beyond March 2031 to the cessation of operations in 2039, in line with the current end of station life of Drax Power Station, is based on the assumption that earnings will continue at a similar level to those under the low carbon dispatchable CfD. No value has currently been included in the ViU calculation for disposing of the site and assets in 2039 due to the uncertainty over the value that could be achieved as a result of a lack of comparable transactions for a large-scale generation site with a live grid connection. If a value was included this would further increase the headroom.

The ViU of the Biomass CGU was in excess of its carrying amount. The ViU of Southern Pellets was also in excess of its carrying amount when testing the goodwill allocated to Southern Pellets at a segment level or below.

The Biomass CGU has a carrying value at 31 December 2025 of £1,412.3 million. A combination of reasonably possible changes in certain assumptions used in the value in use model could lead to a material adjustment to this carrying value.

These include: an average 27% decrease in power prices over the period of the low carbon dispatchable CfD agreement from April 2027 to March 2031, combined with a 90-day outage of one of the units under the Renewables Obligation scheme in 2026, an increase in biomass production costs of US$7 per tonne, an increase in the pre-tax discount rate from 11.5% to 23.7% (equivalent to an increase in the post-tax discount rate from 7.5% to 8.3%), and operations to cease in March 2031 at the end of the low carbon dispatchable CfD agreement. This combination of reasonably possible changes in the key inputs to the value in use model would lead to an impairment of £650.1 million. Therefore, reasonably possible assumptions in the ViU calculation of the Biomass CGU have been identified as a key source of estimation uncertainty.

Drax Energy Solutions

This segment is principally focused on renewable electricity sales to industrial and commercial (I&C) customers and providing other renewables services.

The ViU of the Drax Energy Solutions CGU was in excess of its carrying amount. A reasonably possible increase in the pre-tax discount rate to 12.5% combined with factoring in a reduction in forecast gross margin by 10%, 0% perpetuity growth rate and a reduction in growth of forecast income from the electric vehicles business, equivalent to a 50% reduction in future forecast earnings, would reduce the headroom by £331.0 million. This would not result in an impairment. Whilst reasonably possible changes in assumptions would reduce the headroom, they would not result in the recoverable amount being lower than the carrying value. As such management does not believe that any reasonably possible changes in the key assumptions would result in an adjustment to the carrying value of the Drax Energy Solutions CGU.

Lanark, Galloway and Cruachan

These CGUs are engaged in run-of-river hydro and pumped storage power generation. The ViU for all three CGUs (Lanark, Galloway and Cruachan) were in excess of their carrying amounts.

For the Cruachan CGU, a reasonably possible 25% average power price reduction combined with an increase in the pre-tax discount rate to 8.7%, and less favourable weather patterns, resulting in a reduction in value from market volatility, would reduce the headroom by £758.2 million. This would not result in an impairment. For the Lanark CGU, a reasonably possible 25% average power price reduction combined with an increase in the pre-tax discount rate to 8.7% and a low rainfall year, based on historical lows, every one in three years, would reduce the headroom by £26.3 million. This would not result in an impairment. Whilst reasonably possible changes in assumptions for the Lanark and Cruachan CGUs would reduce the headroom, they would not result in the recoverable amounts being lower than the carrying values. As such the Group does not believe that any reasonably possible changes in the key assumptions would result in an adjustment to the carrying values of either the Lanark or Cruachan CGUs.

For the Galloway CGU, a reasonably possible 25% average power price reduction combined with an increase in the pre-tax discount rate to 8.7% and a low rainfall year, based on historical lows, every one in three years, would result in an impairment of £5.9 million. The Galloway CGU is sensitive to reasonably possible changes in the key assumptions. Whilst reasonably possible changes to assumptions would result in an adjustment to the carrying value of the Galloway CGU, they would not result in a material adjustment to its carrying value and so it is not considered a key source of estimation uncertainty as defined by IAS 1.

Impairment of non-current assets

Longview

During 2025, an impairment loss of £108.8 million has been recognised relating to the Group's Longview pellet plant development project (Longview). Due to reduced expectations around global pellet demand in the short to medium term, in part as a result of the reduced volumes of biomass generation agreed under the low carbon dispatchable CfD contract, the decision has been taken to pause this development and no development of the site is expected in the near term.

The capitalised Longview assets have been impaired to their recoverable amount of £13.7 million (principally the value of the land at the site). This recoverable amount has been estimated after considering the level of customisation and general market conditions. If the Group is able to return assets to suppliers; or achieve third-party sales; or find internal use for parts and spares at the Group's other pellet plants; or if any scrap value achieved exceeds the costs of disposal, then the recovery value could be higher. If an average recovery value of 40% on plant and equipment had been assumed, this would result in a decrease in the impairment recognised of £29.5 million and a corresponding increase in the carrying value of the Longview assets.

As such the assumptions regarding the recoverable amount of Longview plant and equipment have been identified as a key source of estimation uncertainty.

A separate onerous contract provision for the Longview fibre purchase contracts has been recognised.

UK BECCS

Given the current political environment and the lack of development of an appropriate regulatory framework to support the investment required for UK BECCS, the Group has refocused its investment priorities on nearer term opportunities with more balanced risk-return profiles and therefore has rationalised its level of investment in carbon capture opportunities. Whilst UK BECCS is still an attractive option for the Group long term and management still believes that the development of BECCS at Drax Power Station is important to the UK's Net Zero strategy, the full carrying amount of the development project of £47.6 million has been impaired due to the reduced likelihood of the project proceeding in the short to medium term. Although not expected in the near term, if an appropriate regulatory framework were to be developed and the political environment was to become more supportive of large-scale capital investment in UK BECCS, increasing the likelihood of the project progressing, a reversal of the impairment of certain UK BECCS costs may be required.

Impairment	Year ended 31 December 2025						Year ended 31 December 2024
	Longview £m	UK BECCS £m	Northern Pellets £m	Other assets £m	Total £m		Opus Energy £m	Other assets £m	Total £m
Investment in associate	-	-	3.6	-	3.6		-	4.6	4.6
Goodwill - cost	-	-	8.5	-	8.5		-	-	-
Property, plant and equipment - accumulated depreciation and impairment	108.8	47.6	139.3	26.1	321.8		-	6.1	6.1
Right-of-use assets - accumulated depreciation and impairment	-	-	20.1	-	20.1		-	0.1	0.1
Intangible assets excluding goodwill - accumulated amortisation and impairment	-	-	22.6	1.1	23.7		2.6	-	2.6
Other receivables	-	-	-	-	-		-	1.0	1.0
Total impairment of non-current assets	108.8	47.6	194.1	27.2	377.7		2.6	11.8	14.4

The total non-current asset impairment charge for the year of £377.7 million (2024: £14.4 million) is recognised in the impairment of non-current assets line in the Consolidated income statement. £350.5 million (2024: £2.6 million) of impairment directly relating to Longview, UK BECCS and Northern Pellets (2024: Opus Energy transaction and related restructuring) was treated as exceptional. See note 4 for further details.

4. Alternative performance measures

This note provides details of all APMs used, each APM's closest IFRS equivalent, the reason why the APM is used by the Group and a definition of how each APM is calculated.

The Group presents Adjusted results in the Consolidated income statement. Management believes that this approach is useful as it provides a clear and consistent view of underlying trading performance. Exceptional items and certain remeasurements are excluded from Adjusted results and are presented in a separate column in the Consolidated income statement. The Group believes that this presentation provides useful information about the financial performance of the business and is consistent with the way the Board and executive management assess the performance of the business.

The Group has a policy and framework for the determination of transactions to be presented as exceptional. Exceptional items are excluded from Adjusted results as they are transactions that are deemed to be one-off or unlikely to reoccur in future years due to their nature, size, the expected frequency of similar events, or the commercial context. By excluding these amounts, this provides users of the Consolidated financial statements with a more representative view of the results of the Group and enables comparisons with other reporting periods as it excludes amounts from activities or transactions that are not likely to reoccur. All transactions presented as exceptional are approved by the Audit Committee.

In these Consolidated financial statements, the following transactions have been designated as exceptional items and presented separately:

- Opus Energy sale of meter points and restructuring: Costs and credits arising as a result of the transaction to sell the majority of the non-core Opus Energy SME customer meter points and related strategic restructuring to reflect the reduced size of the Opus Energy SME business and Energy Solutions' focus on core I&C customers and renewables services (Energy Solutions, 2024 and 2025). See below for further details.

- Impairment of Longview and related costs: Asset impairment charges of £108.8 million (see note 3), the recognition of provisions for onerous fibre contracts of £22.0 million and £8.1 million of other costs relating to the Group's decision to pause the Longview development project (Pellet Production, 2025).

- Impairment of UK BECCS: Impairment of capitalised development costs relating to the Group's UK BECCS development project (Biomass Generation, 2025). See note 3 for further details.

- Impairment of Northern Pellets CGU and related costs: Asset impairment charges of £194.1 million (see note 3) and related costs of £3.7 million within the Group's Northern Pellets business (Pellet Production, 2025). See note 3 for further details on the impairment of the Northern Pellets CGU.

- Change in the fair value of contingent consideration (Flexible Generation, 2025).

- Transformation and restructuring (all segments, 2025). See below for further details.

Certain remeasurements comprise fair value gains and losses on derivative contracts to the extent that those contracts do not qualify for hedge accounting, or hedge accounting is not effective, and those gains or losses are either i) unrealised and relate to derivative contracts with a maturity in future periods, or ii) are realised in relation to the maturity of derivative contracts in the current period. Management believes adjusting for fair value gains and losses recognised on derivative contracts provides users of the Consolidated financial statements with useful information, as this removes volatility caused by movements in market prices over the life of the derivative contracts. Gains and losses on derivative contracts prior to maturity generally reflect the difference between the contracted price and the current market price, which management does not believe provides meaningful information as the Group is not entering contracts with the intention of creating value from changes in market prices.

The Group regards all of its forward contracting activity to represent economic hedges to secure prices and rates, and lock in value for its future expected pellet production, generation or energy supply activities. The contracted price is therefore deemed relevant and representative of the Group and its performance, rather than how the contracted price compares to prevailing market prices, as the Group is not seeking to make trading profits on these derivative contracts through market price movements. The effect of excluding certain remeasurements from Adjusted results is that commodity sales and purchases are recognised in Adjusted results in the period they are intended to hedge at their contracted prices i.e. at the all-in-hedged amount paid or received in respect of the delivery of the commodity in question. It also results in the total impact of financial contracts being recognised in Adjusted results on maturity, being the period they are intended to hedge. Management believes this better reflects the performance of the business as it more accurately represents the intention for entering derivative contracts.

Movements on derivative financial instruments which do not qualify for hedge accounting, or where hedge accounting is ineffective, are shown in the table below. During 2025 the amounts recognised were predominantly due to fair value gains recognised on foreign exchange contracts on matured trades, due to GBP weakening against USD when compared to the original trade dates, and the realisation of losses on maturity of inflation and commodity hedges.

Further details on the Group's derivative financial instruments are provided in Section 7.

The effective tax rate on exceptional items of 2.2% during the current year is lower than the standard corporation tax rate applicable in the relevant jurisdictions as a result of the non-deductibility of the impairment of non-current assets within the Northern Pellets CGU, and the related derecognition of deferred tax assets in Canada as a result of this. The Group does not believe tax deductions will be recognised for these items in the future.

	Year ended 31 December
	2025 £m	2024 £m
Exceptional items:
Opus Energy sale of meter points and restructuring	(1.1)	(59.5)
Impairment of Longview and related costs	(138.0)	-
Impairment of UK BECCS	(47.6)	-
Impairment of Northern Pellets CGU and related costs	(197.8)	-
Change in fair value of contingent consideration	(9.4)	-
Transformation and restructuring	(9.4)	-
Exceptional items included within operating profit	(403.3)	(59.5)
Interest expense relating to Longview	(0.9)	-
Exceptional items included within profit before tax	(404.2)	(59.5)
Tax on exceptional items	8.9	14.8
Exceptional items after tax	(395.3)	(44.7)
Certain remeasurements:
Net derivative fair value remeasurements included in revenue	24.9	11.9
Net derivative remeasurements realised on maturity included in revenue	8.4	77.6
Net hedge ineffectiveness recognised in revenue	2.0	(8.2)
Net derivative fair value remeasurements included in cost of sales	(55.4)	45.3
Net derivative remeasurements realised on maturity included in cost of sales	(6.5)	(17.1)
Certain remeasurements included within operating profit	(26.6)	109.5
Net derivative remeasurements realised on maturity included in interest payable and similar charges	0.3	(0.6)
Net amounts reclassified due to the hedged cash flows no longer expected to occur included in interest payable and similar charges	(0.9)	-
Net derivative fair value remeasurements included in foreign exchange gains	1.2	-
Net hedge ineffectiveness recognised in foreign exchange losses	(3.6)	-
Certain remeasurements included in profit before tax	(29.6)	108.9
Tax on certain remeasurements	7.4	(29.7)
Certain remeasurements after tax	(22.2)	79.2
Reconciliation of profit for the period:
Adjusted profit for the period	485.7	491.0
Exceptional items after tax	(395.3)	(44.7)
Certain remeasurements after tax	(22.2)	79.2
Total profit for the period	68.2	525.5

Opus Energy sale of meter points and restructuring

In May 2025 the Group completed the sale of its non-core SME customer meter points, a process which commenced in 2024 with the sale of the majority of its SME customer meter points to EDF Energy Customers Limited and concluded with the sale of the residual SME customer supply meter points and related receivables to Pozitive Energy Limited. All SME supply meter points have now been disposed of. An employee consultation process has also been completed resulting in a reduction in headcount to reflect a focus on core industrial and commercial (I&C) and renewables services. The Group incurred costs of redundancies in order to reduce the headcount in the Opus Energy business and holds a redundancy provision at 31 December 2025 in respect of in scope colleagues who had not yet left the Group.

The gains and losses described above that have been recognised in the period on the transaction and related restructuring have been classified as exceptional. Further details of the amounts recognised as exceptional are detailed below:

	Year ended 31 December
	2025 £m	2024 £m
Consideration received for customer meter points	3.6	9.6
Net liabilities/(assets) disposed of directly related to the transferred customers	2.2	(8.4)
Profit on disposal of customer meter points - included in other gains and losses	5.8	1.2
Other losses incurred as a direct result of the transaction and restructuring
Redundancy, transaction and migration costs - included in operating and administrative expenses	(2.6)	(9.2)
Onerous contracts provision, impairment of prepaid commissions and final commission settlement on retained customers - included in cost of sales	-	(23.3)
Fair value movements on receivables relating to customers transferred to EDF - included in operating and administrative expenses	(0.5)	(12.9)
Impairment of trade receivables - included in impairment losses on financial assets	(3.8)	(12.7)
Impairment of non-current assets (note 3) - included in impairment of non-current assets	-	(2.6)
Net loss recognised as a result of the transaction	(1.1)	(59.5)

During the current year the Group had a net cash outflow of £1.1 million in respect of the Opus Energy transaction. This comprised a cash inflow of £3.6 million of consideration received and a cash outflow of £4.7 million in respect of redundancy, transaction and migration costs paid out in the year. The cash flows relating to the transaction have been recognised within operating cash flows in the Consolidated cash flow statement.

Transformation and restructuring

The Group has commenced a significant transformation programme ("Future Focus") centred around growth, efficiency and performance culture. As part of this programme, the organisational structure has been redesigned in order to deliver an appropriate cost base under the low carbon dispatchable CfD agreement from April 2027. This transformation programme commenced in 2025 and is expected to run through to the end of 2026. The costs incurred in the year primarily relate to employee severance costs and related consultancy costs.

For each item designated as exceptional or as a certain remeasurement, the table below summarises the impact of the item on Adjusted and Total profit after tax, Basic EPS and Net cash from operating activities.

	Year ended 31 December 2025
	Revenue £m	Gross profit £m	Operating profit £m	Profit before tax £m	Tax (charge)/ credit £m	Profit/ (loss) for the period £m	Basic earnings per share Pence	Net cash from operating activities £m
Total results IFRS measure	5,390.7	1,512.9	241.3	189.5	(121.3)	68.2	20.7	810.0
Certain remeasurements:
Net fair value remeasurement on derivative contracts	(35.3)	26.6	26.6	29.6	(7.4)	22.2	6.3	-
Exceptional items:
Opus Energy sale of meter points and restructuring	-	-	1.1	1.1	-	1.1	0.3	1.1
Impairment of Longview and related costs	-	22.0	138.0	138.9	(34.7)	104.2	29.5	0.9
Impairment of UK BECCS	-	-	47.6	47.6	(11.9)	35.7	10.1	-
Impairment of Northern Pellets CGU and related costs	-	0.1	197.8	197.8	42.5	240.3	66.8	0.5
Change in fair value of contingent consideration	-	-	9.4	9.4	(2.4)	7.0	2.0	-
Transformation and restructuring	-	-	9.4	9.4	(2.4)	7.0	2.0	5.8
Total	(35.3)	48.7	429.9	433.8	(16.3)	417.5	117.0	8.3
Adjusted results totals	5,355.4	1,561.6	671.2	623.3	(137.6)	485.7	137.7	818.3

	Year ended 31 December 2024
	Revenue £m	Gross profit £m	Operating profit £m	Profit before tax £m	Tax (charge)/ credit £m	Profit/ (loss) for the period £m	Basic earnings/ (loss) per share Pence	Net cash from operating activities £m
Total results IFRS measure	6,162.5	1,876.5	850.2	753.4	(227.9)	525.5	137.5	859.5
Certain remeasurements:
Net fair value remeasurement on derivative contracts	(81.3)	(109.5)	(109.5)	(108.9)	29.7	(79.2)	(20.7)	-
Exceptional items:
Opus Energy sale of meter points and restructuring	-	23.3	59.5	59.5	(14.8)	44.7	11.6	(9.6)
Total	(81.3)	(86.2)	(50.0)	(49.4)	14.9	(34.5)	(9.1)	(9.6)
Adjusted results totals	6,081.2	1,790.3	800.2	704.0	(213.0)	491.0	128.4	849.9

Adjusted EBITDA

Adjusted EBITDA is a key measure of financial performance for the Group. A reconciliation from Adjusted operating profit from the Consolidated income statement is shown below:

	Year ended 31 December 2025
	Attributable to
	Owners of the parent company £m	Non-controlling interests £m	Total £m
Adjusted operating profit/(loss)	671.3	(0.1)	671.2
Depreciation and amortisation	242.1	1.0	243.1
Other losses	4.4	-	4.4
Share of losses from associates	1.6	-	1.6
Impairment of non-current assets	27.2	-	27.2
Adjusted EBITDA	946.6	0.9	947.5

	Year ended 31 December 2024
	Attributable to
	Owners of the parent company £m	Non-controlling interests £m	Total £m
Adjusted operating profit/(loss)	801.3	(1.1)	800.2
Depreciation and amortisation	240.4	1.4	241.8
Other losses	8.5	-	8.5
Share of losses from associates	2.2	-	2.2
Impairment of non-current assets	11.8	-	11.8
Adjusted EBITDA	1,064.2	0.3	1,064.5

	Year ended 31 December
	2025 £m	2024 £m
Segment Adjusted EBITDA:
Pellet Production	129.4	143.0
Biomass Generation	725.4	813.5
Flexible Generation	110.9	137.6
Energy Solutions	48.7	51.2
Innovation, capital projects and other	(74.3)	(78.1)
Intra-group eliminations	6.5	(3.0)
Total Adjusted EBITDA	946.6	1,064.2

Net debt

The below table reconciles the Group's Net debt:

	As at 31 December
	2025 £m	2024 £m
Borrowings	(979.0)	(1,176.7)
Lease liabilities	(98.6)	(116.5)
Cash and cash equivalents	302.1	356.0
Net cash, borrowings and lease liabilities	(775.5)	(937.2)
Non-controlling interests' share of cash and cash equivalents in non-wholly owned subsidiaries	(0.6)	(0.8)
Non-controlling interests' share of lease liabilities in non-wholly owned subsidiaries	0.4	0.5
Impact of hedging instruments	(7.9)	(54.2)
Net debt	(783.6)	(991.7)

The table below reconciles Net debt in terms of changes in these balances across the year:

	Year ended 31 December
	2025 £m	2024 £m
Net debt at 1 January	(991.7)	(1,219.7)
Decrease in cash and cash equivalents	(53.9)	(23.5)
Decrease/(increase) in non-controlling interests' share of cash and cash equivalents in non-wholly owned subsidiaries	0.2	(0.5)
Decrease in borrowings	197.7	248.6
Decrease in lease liabilities	17.9	19.3
(Decrease)/increase in non-controlling interests' share of lease liabilities in non-wholly owned subsidiaries	(0.1)	0.5
Movement in the impact of hedging instruments	46.3	(16.4)
Net debt at 31 December	(783.6)	(991.7)

As explained in the Basis of preparation, the Group has a long-term target for Net debt to Adjusted EBITDA of around 2.0 times.

	As at 31 December
	2025	2024
Adjusted EBITDA (£m)	946.6	1,064.2
Net debt (£m)	(783.6)	(991.7)
Net debt to Adjusted EBITDA ratio	0.8	0.9

Cash and committed facilities

The below table reconciles the Group's available cash and committed facilities:

	As at 31 December
	2025 £m	2024 £m
Cash and cash equivalents	302.1	356.0
RCF available but not utilised(1)	450.0	450.0
Term loan agreed but not drawn	190.0	-
Total cash and committed facilities	942.1	806.0

(1)   The Group holds a £450.0 million RCF facility. As at 31 December 2025, the Group had no cash or non-cash drawings under the RCF (31 December 2024: no cash or non-cash drawings).

Capital expenditure

The Group's definition of capital expenditure was updated in the year to exclude capitalised borrowing costs and capital plant spares (see note 1 for further details of this change). The table below shows the reconciliation between capital expenditure in note 1 and the additions to property, plant and equipment and intangible assets:

	Year ended 31 December
	2025 £m	2024 £m
Capital additions	232.5	332.4
Capitalised borrowing costs in period	(26.0)	(1.7)
Capital plant spares additions	(4.7)	(9.9)
Total capital expenditure (note 1)	201.8	320.8

APM	Closest IFRS equivalent measure	Purpose	Definition
Adjusted results	Total results	The Group's Adjusted results are consistent with the way the Board and executive management assess the performance of the Group. Adjusted results are intended to reflect the underlying trading performance of the Group's businesses and are presented to assist users of the Consolidated financial statements in evaluating the Group's trading performance and performance against strategic objectives on a consistent basis. Adjusted results excludes exceptional items and certain remeasurements. Exceptional items are those transactions that, by their nature, do not reflect the trading performance of the Group in the period. Certain remeasurements comprise fair value gains and losses that do not qualify for hedge accounting (or hedge accounting is not effective). The Group regards all of its forward contracting activity to represent economic hedges and therefore by excluding the volatility caused by recognising fair value gains and losses prior to maturity of the contracts, the Group can reflect these contracts at the contracted prices on maturity, reflecting the intended purpose of entering these contracts and the Group's underlying performance. Adjusted results are the metrics used in the calculation of Adjusted basic EPS and Adjusted diluted EPS.	Total results measured in accordance with IFRS excluding the impact of exceptional items and certain remeasurements. Exceptional items and certain remeasurements are defined above.
Adjusted EBITDA	Operating profit(1)	Adjusted EBITDA is the primary measure used by the Board and executive management to assess the financial performance of the Group as it provides a more comparable assessment of the Group's year-on-year trading performance. It is also a key metric used by the investor community to assess the performance of the Group's operations.	Earnings before interest, tax, depreciation, amortisation, other gains and losses and impairment of non-current assets, excluding the impact of exceptional items and certain remeasurements. Adjusted EBITDA excludes any earnings from associates or attributable to non‑controlling interests.
Adjusted basic EPS	Basic EPS	Adjusted basic EPS represents the amount of Adjusted earnings (Adjusted profit after tax) attributable to each ordinary share outstanding.	Adjusted basic EPS is calculated by dividing the Group's Adjusted earnings attributable to owners of the parent company (Adjusted profit after tax) by the weighted average number of ordinary shares outstanding during the period.
Adjusted diluted EPS	Diluted EPS	Adjusted diluted EPS demonstrates the impact upon the Adjusted basic EPS if all outstanding share options, that are expected to vest on their future maturity dates and where the shares are considered to be dilutive, were exercised and treated as ordinary shares as at the reporting date.	Adjusted diluted EPS is calculated by dividing the Group's Adjusted earnings (Adjusted profit after tax) attributable to owners of the parent company by the weighted average number of ordinary shares outstanding during the period and dilutive potential ordinary shares outstanding under share plans during the period.
Borrowings	n/a(2)	Borrowings provides information relating to the Group's use of debt. It is a key measure of leverage and provides information on the sources of liquidity for the Group.	Borrowings includes external financial debt, such as loan notes, term loans and amounts drawn in cash under revolving credit facilities (RCFs). Borrowings does not include other financial liabilities such as pension obligations, trade and other payables including supply chain finance, lease liabilities calculated in accordance with IFRS 16, and working capital facilities linked directly to specific payables (such as credit cards and deferred letters of credit) that provide a short extension of payment terms of less than 12 months (see note 5).
Net debt	Borrowings and lease liabilities less cash and cash equivalents	Net debt is a key measure of the Group's liquidity and its ability to manage its financial obligations. Net debt is used as a basis by debt rating agencies to assess credit risk, and in the calculation of the Group's financial covenant requirements. The impact of hedging instruments included within Net debt shows the economic substance of the Net debt position, in terms of actual expected future cash flows to settle that debt.	Borrowings (as defined above) including the impact of hedging instruments, and lease liabilities calculated in accordance with IFRS 16 less cash and cash equivalents. Net debt excludes the proportion of cash, lease liabilities and borrowings in non-wholly owned entities that would be attributable to the non-controlling interests. Net debt includes the impact of foreign currency hedging instruments, meaning that any borrowings that have associated hedging instruments in place are adjusted to reflect those borrowings at the hedged rate. Net debt includes the impact of any cash collateral receipts from counterparties or cash collateral posted to counterparties.
Net debt to Adjusted EBITDA ratio	Borrowings and lease liabilities less cash and cash equivalents divided by operating profit(1)	The Net debt to Adjusted EBITDA ratio is a debt ratio that gives an indication of how many years it would take the Group to pay back its debt if Net debt and Adjusted EBITDA are held constant. The Group has a long-term target for Net debt to Adjusted EBITDA of around 2.0 times.	Net debt divided by Adjusted EBITDA for the last twelve months expressed as a multiple.
Cash and committed facilities	Cash and cash equivalents	This is a key measure of the Group's available liquidity and the Group's ability to manage its current obligations. It shows the value of cash available to the Group in a short period of time.	Total cash and cash equivalents plus the value of the Group's committed but undrawn facilities (including the Group's RCF, loan facilities and the Energy Solutions non-recourse trade receivables monetisation facility, to the extent that there are eligible receivables available to utilise undrawn amounts).
Capital expenditure(3)	Property, plant and equipment (PPE) additions and intangible asset additions	Used to show the Group's total spend on PPE and intangible assets in a year.	PPE additions plus intangible asset additions, excluding capitalised borrowing costs and capital plant spare additions.

(1)   Operating profit is presented in the Group's Consolidated income statement; however, it is not defined per IFRS. It is a generally accepted measure of profit.

(2)   Borrowings are presented in the Group's Consolidated balance sheet; they are a commonly used balance sheet line item heading; however, borrowings are not defined by IFRS, therefore the Group's borrowings may not be comparable to borrowings presented by other companies.

(3)   During 2025, the definition of Capital expenditure has been updated to align with the way the information is currently presented to the Board and executive management. The definition now excludes capitalised borrowing costs and capital plant spare additions. See the capital expenditure by segment table in note 1 for further details of this change.

5. Notes to the Consolidated cash flow statement

Accounting policy

In accordance with IAS 7 the Group has elected to classify cash flows from interest paid and interest received as cash flows from operating activities, dividends paid as cash flows from financing activities, and dividends received as cash flows from investing activities. The interest repayments on lease liabilities are included within interest paid, and the lease principal repayments are presented within cash flows from financing activities. Payments for short-term and low value leases are included within cash flows from operating activities.

Cash generated from operations

Cash generated from operations is the starting point of the Group's Consolidated cash flow statement. The table below makes adjustments for any non-cash accounting items to reconcile the Group's net profit for the year to the amount of cash generated from the Group's operations.

	Year ended 31 December
	2025 £m	2024 £m
Profit for the period	68.2	525.5
Adjustments for:
Interest payable and similar charges(1)	75.7	107.5
Interest receivable and similar gains	(17.8)	(20.1)
Tax charge	121.3	227.9
Movement in provision for research and development tax credits	2.0	(2.0)
Share of losses from associates	1.6	2.2
Depreciation of property, plant and equipment	202.0	196.7
Depreciation of right-of-use assets(1)	28.6	28.1
Amortisation of intangible assets	14.2	17.0
Impairment of non-current assets	377.7	14.4
Losses on disposal of non-current assets	5.4	11.2
Other losses	9.4	1.7
Certain remeasurements of derivative contracts(2)	23.4	(89.3)
Non-cash charge for share-based payments	15.7	14.0
Effect of changes in foreign exchange rates	(13.6)	(21.9)
Operating cash flows before movement in working capital	913.8	1,012.9
Changes in working capital:
Decrease in inventories	76.5	25.2
Decrease in receivables	136.2	392.2
Decrease in payables	(110.2)	(142.7)
Net movement in derivative-related collateral	(24.5)	83.7
Increase in provisions	10.4	11.5
Increase in renewable certificate assets	(2.1)	(247.8)
Total cash released from working capital	86.3	122.1
Pension service charge less contributions paid	(0.6)	0.1
Cash generated from operations	999.5	1,135.1

(1)   Included within the adjustments above are interest charged on lease liabilities of £0.3 million and depreciation charged on right-of-use assets of £1.7 million in relation to the Group's salary sacrifice EV scheme. These costs are presented within staff costs within operating and administrative expenses in the Consolidated income statement.

(2)   Certain remeasurements of derivative contracts includes the effect of non-cash unrealised gains and losses recognised in the Consolidated income statement and their subsequent cash realisation. It also includes the cash and non-cash impact of deferring and recycling gains and losses on derivative contracts designated into hedge relationships under IFRS 9, where the gain or loss is held in the hedge reserve and then released to the Consolidated income statement in the period the hedged transaction occurs.

The most significant factors contributing to cash generated from operations are explained in further detail below.

The £23.4 million inflow due to the adjustment for certain remeasurements for derivative contracts in the current year (2024: £89.3 million outflow) mainly relates to unrealised fair value losses (2024: unrealised fair value gains) on open derivative contracts offset by cash payments on maturing trades.

Cash collateral is sometimes paid or received in relation to the Group's commodity and treasury trading activities. When derivative positions are out of the money for the Group, collateral may be required to be paid to the counterparty. When derivative positions are in the money, collateral may be received from counterparties. These positions reverse when mark-to-market positions reduce, or contracts are settled, and the collateral is returned.

The Group has had a net cash outflow of £24.5 million from derivative-related collateral during the year, as trades have matured and mark-to-market positions have reduced (2024: £83.7 million inflow). As at 31 December 2025, the Group held £nil (2024: £9.8 million) in cash collateral receipts recognised in payables, and had posted £19.4 million (2024: £4.7 million) of cash collateral payments recognised in receivables.

The Group actively manages its liquidity requirements. This includes managing collateral associated with the hedging of power and other commodities, as well as other contractual arrangements. Under certain arrangements the Group is able to use non-cash collateral, such as letters of credit and surety bonds, that may otherwise have required cash collateral. The Group utilised £14.5 million (2024: £14.5 million) of letters of credit and £20.0 million (2024: £30.0 million) of surety bonds to cover commodity trading collateral requirements. Letters of credit and surety bonds utilised at the reporting date have reduced the requirement for cash collateral payments, which has increased the amount by which receivables have decreased.

The Group has a strong focus on cash flow discipline and managing liquidity. The Group enhances its working capital position by managing payables, receivables, inventories and renewable certificate assets to make sure the working capital committed is closely aligned with operational requirements. The impact of these actions on the cash flows of the Group is included within the further detail explained below.

The table below sets out the key arrangements utilised by the Group to manage elements of its working capital:

	As at 31 December 2025 £m	As at 31 December 2024 £m	Inflow/ (outflow) £m
Receivables monetisation	348.4(1)	400.0	(51.6)
ROC monetisation sales	50.0	-	50.0
Deferred letters of credit	(73.2)	(150.3)	(77.1)

(1)   As at 31 December 2025 the Group had sold £275.6 million (2024: £386.3 million) of receivables under this facility. At 31 December 2025 the Group had recognised an amount payable to the facility provider of £72.8 million (2024: £13.7 million), being the movement in the receivables sold compared to the prior month. This amount was paid to the facility provider in January 2026, so as at 31 December 2025 the utilisation of the facility was £348.4 million (2024: £400.0 million).

None of the balances in the table above are included within the Group's definition of Net debt or borrowings (see note 4 for further details on Net debt). The receivables monetisation facility is non-recourse in nature and therefore there is no future liability associated with these amounts. Through standard ROC sales and ROC purchase arrangements the Group is able to manage the working capital cycle of inflows and outflows of these assets. The supply chain finance and deferred letters of credit facilities are linked directly to specific payables. The deferred letters of credit facilities provide a short extension of payment terms of less than 12 months. The impact of these facilities on the cash flows of the Group is explained further below.

The cash inflow of £76.5 million (2024: £25.2 million) as a result of the decrease in inventories primarily results from higher generation in December at Drax Power Station and the timing of shipments.

The overall cash inflow of £136.2 million (2024: £392.2 million) due to lower receivables in the current year is primarily a result of a reduction in energy prices compared to the prior year.

The Energy Solutions segment has access to a receivables monetisation facility which enables it to accelerate cash flows associated with amounts receivable from energy supply customers on a non-recourse basis. During the year the maturity of the facility was extended to March 2030, from March 2027. The Group now has the option to set the facility limit between £300.0 million and £400.0 million, subject to lender approval. Upon the Group's request, the lender agreed to reduce the facility limit to £350.0 million from August 2025 in line with the lower receivables balances in the Energy Solutions business. The limit was £350.0 million as at 31 December 2025 (31 December 2024: £400.0 million).

Payables have decreased from the prior year, with a cash outflow of £110.2 million (2024: £142.7 million). This is due to a reduction in other payables as the deferred letters of credit have reduced in relation to OCGT capital expenditure now that the assets are nearing completion. The decrease in payables is also due to the reduction in energy supply accruals compared to the prior year as the value of REGOs has reduced year-on-year. Certain of the Group's suppliers are able to access a supply chain finance facility provided by a bank, for which funds can be accelerated in advance of normal payment terms. At 31 December 2025, the Group had trade payables of £62.6 million (2024: £38.4 million) related to this. The facility does not directly impact the Group's working capital, as payment terms remain unaltered with the Group and would remain the same should the facility fall away.

The Group also has access to deferred letters of credit facilities under which the Group benefits from an extension to payment terms of less than 12 months for a fee. The amount outstanding under these facilities at 31 December 2025 was £73.2 million (2024: £150.3 million). Of the total deferred letters of credit, £42.4 million (2024: £92.8 million) were utilised for capital expenditure and £30.8 million (2024: £57.5 million) were utilised for trade payables. Utilisation of these payment facilities impacted the purchases of property, plant and equipment line in the Consolidated cash flow statement and the movement in payables line above.

The movement in renewable certificate assets during the year includes a combination of generation, utilisation, purchases and sales. Cash from renewable certificates, and in particular ROCs, is typically realised several months after they are earned; however, through standard ROC sales and ROC purchase arrangements the Group is able to manage the working capital cycle of inflows and outflows of these assets. At 31 December 2025, the Group had cash inflows of £50.0 million (2024: £nil) from using these standard renewable certificate sales.

Changes in liabilities arising from financing cash flows

A reconciliation of the movements in liabilities arising from financing activities as a result of both cash and non-cash movements is provided below:

	Borrowings £m	Lease liabilities £m	Hedging instruments(1) £m	Obligation to purchase own shares £m	Total £m
At 1 January 2025	1,176.7	116.5	41.0	-	1,334.2
Cash flows from financing activities	(233.8)	(28.1)	(4.0)	-	(265.9)
Effect of changes in foreign exchange rates	32.1	(5.9)	(33.5)	-	(7.3)
Other movements	4.0	16.1	2.3	7.3	29.7
At 31 December 2025	979.0	98.6	5.8	7.3	1,090.7

	Borrowings £m	Lease liabilities £m	Hedging instruments(1) £m	Total £m
At 1 January 2024	1,425.3	135.8	32.5	1,593.6
Cash flows from financing activities	(226.4)	(27.4)	(31.5)	(285.3)
Effect of changes in foreign exchange rates	(30.7)	1.1	18.3	(11.3)
Other movements	8.5	7.0	21.7	37.2
At 31 December 2024	1,176.7	116.5	41.0	1,334.2

(1)   Hedging instruments include both financial assets and financial liabilities used to hedge liabilities arising from financing activities. At 31 December 2025 hedging instruments include £4.9 million (2024: £nil) of financial assets and £10.7 million (2024: £41.0 million) of financial liabilities.

Other movements on borrowings principally relate to interest. Other movements on lease liabilities principally relate to discounting and additions in the year. Other movements on hedging instruments include cross-currency interest rate swaps that are hedging both principal and interest payments on borrowings. Interest payments are classified as operating cash flows in the Consolidated cash flow statement. As such, fair value movements and cash settlements relating to the interest payments on these hedges are recognised within the other movements line above. Other movements on obligation to purchase own shares represent an initial liability of £7.2 million and £0.1 million of interest charged in relation to this liability.

6. Equity and reserves

The Group's ordinary share capital reflects the total number of shares in issue, which are publicly traded on the London Stock Exchange.

Accounting policy

Ordinary shares are classified as equity as evidenced by their residual interest in the assets of the Company after deducting its liabilities. Incremental costs directly attributable to the issue of new shares or options are shown in equity as a deduction, net of tax, from the proceeds.

Issued equity

	As at 31 December
	2025  £m	2024 £m
Issued and fully paid:
432,171,763 ordinary shares of 11  pence each (2024: 427,770,766)	49.9	49.4

The movement in allotted and fully paid share capital of the Company during the year was as follows:

	Year ended 31 December
	2025 (number)	2024 (number)
At 1 January	427,770,766	424,923,406
Issued in respect of employee share schemes	4,400,997	2,847,360
At 31 December	432,171,763	427,770,766

The Company has only one class of shares, which are ordinary shares of 11  pence each, carrying no right to fixed income. Throughout the year, shares were issued in satisfaction of options vesting in accordance with the rules of the Group's employee share schemes.

During the year 2,611,059 shares were issued at a weighted average exercise price of 190.2 pence per share in respect of options vesting on employee share purchase schemes and 1,789,938 shares were issued in respect of share options vesting on share awards with no exercise price.

Own shares reserve

The own shares reserve represents shares of Drax Group plc purchased under share buyback programmes and held by the Company as Treasury shares, or shares of Drax Group plc held by the EBT for the purpose of satisfying employee share plan awards. The EBT is treated as an extension of the Company and therefore the Group, in accordance with IFRS 10.

The cost of the shares held by the EBT or the Company are recognised as a deduction from equity until the shares are issued to employees under share awards, cancelled, reissued or disposed of. The amount deducted from equity includes any incremental directly attributable costs. No gain or loss is recognised in the Consolidated income statement on the purchase, sale, issue or cancellation of the Company's own equity instruments. Where the Company has entered into a forward contract and has an obligation to purchase a fixed amount of its own shares for a fixed price, the present value of this obligation is recognised as a deduction to equity, within retained earnings, and a corresponding liability is recognised. The unwinding of the discount is included in interest payable and similar charges in the Consolidated income statement. Once the shares have been received under this forward contract, the deduction to equity within retained earnings is transferred to the own shares reserve.

As at 31 December 2025, the own shares reserve comprises 91.8 million (2024: 57.8 million) shares at a value of £534.6 million (2024: £314.2 million) held in treasury, and nil (2024: nil) shares held by the EBT.

During the year, the EBT subscribed for 1.8 million of new shares at nominal value for a total of £0.2 million, which were subsequently issued to employees to satisfy share plan awards during the year.

Share buyback programme

On 31 July 2025, the Group announced a £450 million share buyback programme, to commence immediately following the completion of the £300 million share buyback programme that took place between 2024 and 2025.

	Year ended 31 December 2025			Year ended 31 December 2024
	Number of shares (million)	Total net cost £m		Number of shares (million)	Total net cost £m
Shares repurchased:
£300 million buyback programme	29.4	185.7		17.8	115.4
£450 million buyback programme	4.7	35.4		-	-
Total	34.1	221.1		17.8	115.4
Price paid per share:	Pence			Pence
Average	644.7			645.6
Range	Between 544.3 and 833.3			Between 618.8 and 673.9

The £300 million share buyback programme completed on 8 October 2025. The £450 million programme is ongoing. As at 24 February 2026, under the £450 million share buyback programme, 2.5 million shares have been repurchased at a total net cost of £21.9 million.

Shares purchased under these share buyback programmes are held in treasury within the own shares reserve awaiting reissue or cancellation and have no voting rights attached to them. The shares purchased by the Group have not been cancelled and so continue to be included in the issued shares in the above table.

Share premium

The share premium account reflects amounts received in respect of issued share capital that exceeds the nominal value of the shares issued, net of incremental transaction costs and tax, that are directly attributable to the issue of new shares. Movements in the share premium reserve during the year reflect amounts received above the nominal value on the issue of shares under employee share schemes.

	Year ended 31 December
	2025 £m	2024 £m
At 1 January	443.8	441.2
Issue of share capital	4.7	2.6
At 31 December	448.5	443.8

Other reserves

	Capital redemption reserve £m	Translation reserve £m	Merger reserve £m	Own shares reserve £m	Total other reserves £m
At 1 January 2024	1.5	75.5	710.8	(199.6)	588.2
Exchange differences on translation of foreign operations	-	(6.6)	-	-	(6.6)
Own shares utilised to satisfy share-based payment arrangements	-	-	-	0.8	0.8
Repurchase of own shares through share buyback programmes	-	-	-	(115.4)	(115.4)
At 1 January 2025	1.5	68.9	710.8	(314.2)	467.0
Exchange differences on translation of foreign operations	-	(66.8)	-	-	(66.8)
Issue of share capital	-	-	-	(0.2)	(0.2)
Own shares utilised to satisfy share-based payment arrangements	-	-	-	0.9	0.9
Repurchase of own shares through share buyback programmes	-	-	-	(221.1)	(221.1)
At 31 December 2025	1.5	2.1	710.8	(534.6)	179.8

The capital redemption and own shares reserves initially arose when the Group completed previous share buyback programmes. The own shares reserve comprises 91.8 million shares at a value of £534.6 million held in treasury. The 91.8 million (2024: 57.8 million) shares held within the own shares reserve have no voting rights attached to them.

Exchange differences relating to the translation of the net assets of the Group's US and Canadian subsidiaries from their functional currencies (USD and CAD) into sterling for presentation in these Consolidated financial statements are recognised in the translation reserve.

Glossary

Ancillary services

Services provided to National Grid used for balancing supply and demand or maintaining secure electricity supplies within acceptable limits. They are described in Connection Condition 8 of the Grid Code.

Availability

Average percentage of time the units were available for generation.

BECCS

Bioenergy with carbon capture and storage, with carbon resulting from power generation captured and stored.

BESS

Battery energy storage system.

Biogenic carbon cycle

Biogenic refers to something that is produced by, or originates from, a living organism. The biogenic carbon cycle is the natural process of plants and animals releasing CO2 into the atmosphere through respiration and decomposition, and plants absorbing CO2 via photosynthesis.

Biomass

Organic material of non-fossil origin, including organic waste, that can be converted into bioenergy through combustion. The Group uses sawmill and other wood industry residues and forest residuals (which includes low-grade roundwood, thinnings, branches and tops) in the form of compressed wood pellets, to generate electricity at Drax Power Station or sell the pellets to third parties.

Branches and tops

Tops, bark, and limbs of trees that have been left behind post-harvest.

Capacity Market

Part of the UK Government's Electricity Market Reform, the Capacity Market is intended to ensure security of electricity supply by providing a payment for reliable sources of capacity.

Carbon capture and storage (CCS)

The process of trapping or collecting carbon emissions from a large-scale source and then permanently storing them.

CCC

The UK's Climate Change Committee.

CDR

Carbon dioxide removal.

Contracts for Difference (CfD)

A mechanism to support investment in low-carbon electricity generation. The CfD works by stabilising revenues for generators at a fixed-price level known as the "strike price". Generators will receive revenue from selling their electricity into the market as usual; however, when the market reference price is below the strike price, they also receive a top-up payment for the additional amount. Conversely, if the reference price is above the strike price, the generator must pay back the difference.

Combined Cycle Gas Turbines (CCGT)

A form of highly efficient energy generation technology that combines a gas-fired turbine with a steam turbine.

Department for Energy Security and Net Zero (DESNZ)

The UK Government Department that provides dedicated leadership focused on delivering security of energy supply, ensuring properly functioning markets, greater energy efficiency and seizing the opportunities of net zero to lead the world in new green industries.

Dispatchable power

An electricity generator produces dispatchable power when the power can be ramped up and down, or switched on or off, at short notice to provide (or dispatch) a flexible response to changes in electricity demand. Biomass, pumped storage, coal, oil, and gas electricity generation can meet these criteria and hence can be dispatchable power sources. Nuclear can be dispatched against an agreed schedule but is not flexible. Wind and solar electricity cannot be scheduled and hence are not dispatchable. An electricity system requires sufficient dispatchable power to operate and remain safe.

EBDS

The UK Government's Energy Bills Discount Scheme.

EGL

The Electricity Generator Levy.

ENGO

Environmental NGO.

ESG

Environmental, Social and Governance.

First Nations

Any of the groups of indigenous peoples in Canada.

FlexGen

The reportable segments Flexible Generation and Energy Solutions.

Forced outage/Unplanned outage

Any reduction in plant availability, excluding planned outages.

FSC^®

Forest Stewardship Council: an international NGO which promotes responsible management of the world's forests.

Frequency response

The automatic change in generation output, or in demand, to maintain a system frequency of 50Hz.

GHG

Greenhouse gas.

Grid charges

Includes transmission network use of system charges (TNUoS), balancing services use of system charges (BSUoS) and distribution use of system charges (DUoS).

IAB

Independent Advisory Board, comprising scientists, academics, and forestry experts who provide independent challenge, insight and advice into the Group's activities.

IFRS

International Financial Reporting Standards.

Lost Time Incident Rate (LTIR)

The frequency rate is calculated on the following basis: (fatalities and lost time injuries)/hours worked x 100,000. Lost time injuries are defined as occurrences where the injured party is absent from work for more than 24 hours.

Low-grade roundwood

Low-grade roundwood is material which does not satisfy the quality standards set by the timber industry and is rejected by a sawmill.

NGO

Non-governmental organisation.

Near Miss and Hazard Identification Rate (NMHIR)

NMHIR is the total number of near miss and hazard identification reports logged per 100,000 hours worked.

NESO

National Energy System Operator. The energy system operator for the UK.

Non-woody biomass

Biomass not derived from wood, for example non-woody processing residues.

Open Cycle Gas Turbine (OCGT)

A free-standing gas turbine, using compressed air, to generate electricity.

Planned outage

A period during which scheduled maintenance is executed according to the plan set at the outset of the year.

PEFC

Programme for the Endorsement of Forest Certification: an independent, non-profit, non-governmental organisation that promotes sustainable forest management through independent third-party certification.

REGO

The Renewable Energy Guarantees of Origin (REGO) scheme provides certificates called REGOs which demonstrate electricity has been generated from renewable sources.

Reserve

Generation or demand available to be dispatched by the System Operator to correct a generation/demand imbalance, normally at two or more minutes' notice.

Responsibly sourced biomass

Biomass that delivers climate, nature, and people positive outcomes, adhering to strict compliance, traceability, and third-party certification standards, where relevant.

ROC

A Renewables Obligation Certificate (ROC) is a certificate issued to an accredited generator for electricity generated from eligible renewable sources.

Salvage trees

Trees that are felled because they have defective stems, are ill or damaged (e.g. pest, insects, fungus, wind, storms, fires, etc.).

Sawmill and wood industry residues

Woody material produced during the processing of wood at the sawmill, such as sawdust, shavings, chips, and offcuts.

SBP

Sustainable Biomass Program: a certification system designed for woody biomass used in industrial energy production.

Summer

The calendar months April to September.

Sustainable biomass

Biomass which complies with the definition of "sustainable source", Schedule 3, Land Criteria, UK Renewables Obligation Order 2015.

System operator

National Grid Electricity Transmission. Responsible for the co-ordination of electricity flows onto and over the transmission system, balancing generation supply and user demand.

TCFD

Task Force on Climate-related Financial Disclosures.

Thinning

Wood from a silvicultural operation where the main objective is to reduce the density of trees in a stand, improve the quality and growth of the forest, producing saleable trees and forest health improvements.

TNFD

Taskforce on Nature-related Financial Disclosures.

Total Recordable Incident Rate (TRIR)

The frequency rate is calculated on the following basis: (fatalities, lost time injuries and worse than first aid injuries)/hours worked x 100,000.

Total results

Financial performance measures prefixed with "Total" are calculated in accordance with IFRS.

Total shareholder return (TSR)

A measure of the performance of a company's shares over time. It combines the rise or fall of the share price and dividends paid to shareholders to show the total return to shareholders over a particular period.

UK ETS

The UK Emissions Trading Scheme is a mechanism introduced across the UK to reduce carbon emissions; the scheme is capable of being extended to cover all greenhouse gas emissions.

Winter

The calendar months October to March.

 

END