REG - Drax Group Plc - Annual Financial Report
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RNS Number : 4527U 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 (https://www.drax.com/investors/consensus/)
(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/
(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
(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!
(https://uk01.l.antigena.com/l/dq4B8cOmuubnHkJRRgreREPoi4KPKUCcmAVO_ddU33Cpfdcy_~Li2ZuWOME21Dwe0934fDbQ-ozBs1XabQkvffKJaCLvYOO3lXu18L2acNzJIbze9MIlkK_Clmiw38gWIyMnueKmi49-YmlvYrgk_CYTsTVuCtrjdg50wdaVhRG~y-e54m)
For further information, please contact: Christopher.laing@fticonsulting.com
(mailto:Christopher.laing@fticonsulting.com)
Website: www.drax.com (http://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 275 264
from associates
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 31 December 2024
£m £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 Exceptional Total Adjusted Exceptional
results ((1)) items and results results ((1)) items and Total
£m certain £m £m certain results
remeasurements remeasurements £m
£m £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 2024
£m £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 6 (66.8) (6.6)
owners of the parent company
Exchange differences on translation of foreign operations attributable to (0.2) (0.8)
non-controlling interests
Net fair value losses on financial assets at fair value through other (18.5) (25.5)
comprehensive income
Net fair value losses on financial assets at fair value through other 18.5 25.5
comprehensive income reclassified to profit or loss
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 2024
£m £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 Share Hedge Cost of Other Retained Non- Total
equity premium reserve hedging reserves profits controlling £m
£m £m £m £m £m £m interests
£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 - - - - - (7.2) - (7.2)
satisfy share-based payment arrangements
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 2024
£m £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 Biomass Flexible Energy Innovation, Intra-group Adjusted Exceptional Total
Production Generation Generation Solutions capital eliminations results items results
£m £m £m £m projects and £m £m and certain £m
other re-measurements
£m £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 Biomass Flexible Energy Innovation, Intra-group Adjusted Exceptional Total
Production Generation Generation Solutions capital eliminations results items results
£m £m £m £m projects and £m £m and certain £m
other remeasurements
£m £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 2024 2025 Restated ((1))
£m £m £m 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
Ye
ar
en
de
d
31
De
ce
mb
er
2025 2024
£m £m
Pellet Production segment sale of biomass pellets and provided associated 574.1 602.0
services to the Biomass Generation segment
Biomass Generation segment sale of electricity, gas and renewable 2,007.0 2,928.7
certificate assets to the Energy Solutions segment
Biomass Generation segment sale of electricity to the Flexible Generation 16.2 36.5
segment
Biomass Generation segment sale of biomass pellets to the Pellet Production 67.2 74.8
segment
Flexible Generation segment sale of electricity and renewable certificate 90.1 145.9
assets to the Biomass Generation segment
Flexible Generation segment sale of electricity to the Energy Solutions 3.3 2.6
segment
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)
Ye
ar
en
de
d
31
De
ce
mb
er
2025 2024
£m £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
De
ce
mb
er
2025 2024
£m £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 Exceptional Total Adjusted Exceptional Total
results items and results results items and results
£m certain £m £m certain £m
remeasurements remeasurements
£m £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 Method of recognising revenue, including any estimation uncertainties
terms
Pellet sales (Pellet Production) The Group's Pellet Production business produces biomass pellets which are sold Revenue is recognised at the point that the pellets are loaded onto the
to external customers. Customers generally obtain control of the pellets at shipping vessel. The amount of revenue recognised is based on the contracted
the point the pellets are loaded onto the shipping vessel. price and volume of the pellets.
Where freight is also arranged for the customer, these sales are known as For CIF sales, revenue for the freight portion is recognised over the period
cost, insurance and freight (CIF) sales. The freight component is considered a the vessel sails.
separate performance obligation.
Invoices are raised in line with contractual terms and are usually payable
within 4-10 days.
Electricity sales (Biomass Generation and Flexible Generation) The Group's Biomass Generation and Flexible Generation businesses have Revenues from sales contracts fulfilled through generation are recognised at
contracts for wholesale electricity sales. Performance obligations, being the a point in time based upon metered output at rates specified under
supply of electricity, are met either via generation or through the contractual terms.
procurement of electricity from counterparties. The performance obligations
for these contracts are deemed to be a series of distinct goods that are Revenue from sales contracts fulfilled through procured electricity is
substantially the same and transfer consecutively. Control is deemed to have recognised at the point at which this electricity or gas is supplied to the
transferred to the customer at the point that the electricity has been counterparty in accordance with the contractual terms at rates specified under
supplied in accordance with the contractual terms. the contract.
Invoices for electricity are typically raised on the fifth banking day These are recognised under the output method, whereby revenue is recognised
following the month of supply, in line with the Grid Trade Master Agreement based on the value transferred to the customer.
(GTMA) contractual terms, and are payable on the fifth banking day following
the date of invoice.
Renewable certificate sales (Biomass Generation, Flexible Generation and Renewables Obligation Certificates (ROCs) and Renewable Energy Guarantees External ROC and REGO sales are recognised at the point the relevant
Energy Solutions) of Origin (REGOs) are sold to counterparties at a point in time. renewable certificates are transferred to the counterparty.
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.
CfD income (Biomass Generation) The Group's Biomass Generation business is party to a CfD with the Low Carbon The Group recognises the income arising from the CfD in the Consolidated
Contracts Company (LCCC), a UK Government-owned entity responsible for income statement as a component of revenue at the point the Group meets its
delivering elements of the UK Government's Electricity Market Reform performance obligation under the CfD agreement. This is considered to be the
programme. Under the contract, the Group receives income in respect of point at which the relevant generation is delivered.
electricity dispatched from a specific biomass-fuelled generating unit.
See CfD income section below for further details.
Invoices are raised 7-10 days following the date of supply and are settled
within 28 days.
Ancillary services (Biomass Generation and Flexible Generation) Ancillary services refer to the provision of a range of system support Revenue is recognised over time for ancillary services as the Group provides
services to National Grid. Most contracts are for the delivery of a specific the service of either being available and ready to support the UK Electricity
service either continually or on an ad-hoc basis over a period of time. Grid or providing a service when called upon to support the UK Electricity
Grid.
Invoices are raised and subsequently settled in line with the National Grid
company ancillary services settlement calendar, typically monthly. 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 Revenue is recognised on the supply of electricity or gas when a contract
non-domestic customers. Energy supplied is measured based upon metered exists, supply has taken place, a quantifiable price has been established or
consumption and contractual rates. can be determined, and the amounts receivable are expected to be recovered.
The Energy Solutions business also has long-term contracts for the sale of Where supply has taken place but has not yet been measured or billed, revenue
electricity and gas, which are a series of distinct goods or services that are is estimated based on consumption statistics and selling price estimates
substantially the same and have the same pattern of transfer and are a and is recognised as accrued income. This estimate is not considered to be a
performance obligation that is deemed as being satisfied over time in line key source of estimation uncertainty because historical experience has
with the progress of the contracts. demonstrated that these estimates are materially accurate based on the
subsequent billings and settlements.
Invoices are raised in line with contractual terms which for most customers is
monthly. Payment is generally due between 28-90 days. 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 The discounted price of electricity and gas supplied under EBDS was recognised
2024. Under this scheme, energy supplied to eligible non-domestic customers in revenue as it was supplied. The amount claimed back from
had a discount applied to each unit of electricity and gas. Certain customers the UK Government was recognised within revenue over the same period as the
were eligible for higher levels of support dependent on the sector in which underlying discounted revenue it related to was recognised.
they operated. The discount provided was then able to be claimed back from the
UK Government by the supplier. 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
Payment was due 10 days post submission of a claim, which typically occurred from the scheme than it would have done had it not been introduced.
monthly.
Other income (All segments) Other income is derived from the sale of goods. The customer obtains control Revenue is recognised at the point the control of the goods is transferred to
typically at the point of delivery to their premises or upon collection. the customer.
Invoices are raised in line with contractual terms. The majority of invoices
are raised quarterly and are payable within 30 days.
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 Inter-segment Total External Inter-segment Total
£m £m £m £m £m £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 2024
£m £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 139.2 146.6
the end of the reporting period
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 - Future production costs are estimated based on a combination of current and
historical costs, inflation expectations and maintenance/operating assumptions
- Production volumes
- Production volumes are estimated based on the sales volumes agreed under
- Sales volumes contractual pellet supply arrangements entered into with third parties as well
as forecast sales volumes, taking into account planned and unplanned downtime
- Sales prices provisions, and fibre availability
- Central costs - Sales volumes are estimated based on contractual pellet supply arrangements
entered into with third parties and assumed further contracted volumes after
- Discount rate 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 - Power revenue is derived from hedged power sales, future wholesale energy
price estimates and an assumption of additional value added through the
- Biomass support mechanisms balancing market and optimisation
- Post-March 2031 income - Future wholesale energy price estimates are based on market traded power
prices for around three years (the period they are liquid), gas market prices
- Pellet costs (self-supply and third-party) 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
- Pellet production volumes forecasts and demand inputs
- Ancillary income - 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
- Volume of generation 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
- Discount rate
- 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 - Power revenue is derived from hedged power sales, future wholesale energy
price estimates and an assumption of additional value added through the
- Ancillary income balancing market and optimisation
- Volume of generation - Future wholesale energy price estimates are based on market traded power
prices for around three years (the period they are liquid), gas market prices
- Discount rate 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 - Customer margins are estimated based on current contracted prices and on
current and previously achieved profitability
- Supply volumes
- The expectation of future organic supply volumes is based on past
- Third-party cost estimates performance and management's expectations of market developments
- Renewables services growth rates - Third-party cost estimates are based on a combination of externally
published rates, management analysis of key market input assumptions,
- Discount rate 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 Length of Pre-tax Perpetuity
amount detailed discount growth rate
including cash flows rate
allocated £m
goodwill
£m
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 UK BECCS Northern Pellets Other assets Total Opus Energy Other Total
£m £m £m £m £m £m assets £m
£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 - - 22.6 1.1 23.7 2.6 - 2.6
and impairment
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 2024
£m £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 0.3 (0.6)
payable and similar charges
Net amounts reclassified due to the hedged cash flows no longer expected to (0.9) -
occur included in interest payable and similar charges
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 2024
£m £m
Consideration received for customer meter points 3.6 9.6
Net liabilities/(assets) disposed of directly related to the transferred 2.2 (8.4)
customers
Profit on disposal of customer meter points - included in other gains and 5.8 1.2
losses
Other losses incurred as a direct result of the transaction and restructuring
Redundancy, transaction and migration costs - included in operating and (2.6) (9.2)
administrative expenses
Onerous contracts provision, impairment of prepaid commissions and final - (23.3)
commission settlement on retained customers - included in cost of sales
Fair value movements on receivables relating to customers transferred to EDF - (0.5) (12.9)
included in operating and administrative expenses
Impairment of trade receivables - included in impairment losses on financial (3.8) (12.7)
assets
Impairment of non-current assets (note 3) - included in impairment of - (2.6)
non-current assets
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 Gross Operating Profit Tax (charge)/ Profit/ Basic Net cash from
profit
credit
(loss)
£m
profit before tax
earnings operating
£m
£m for the
£m £m
per share activities
period
Pence £m
£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 Gross Operating Profit Tax Profit/ Basic Net cash from
profit
(charge)/
(loss)
£m
profit before tax
credit
earnings/ operating
£m
for the
(loss)
£m £m £m
activities
period per share
£m
£m Pence
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
Att
rib
uta
ble
to
Owners of the Non-controlling Total
parent company interests £m
£m £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
Att
rib
uta
ble
to
Owners of the Non-controlling Total
parent company interests £m
£m £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 2024
£m £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 2024
£m £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 (0.6) (0.8)
owned subsidiaries
Non-controlling interests' share of lease liabilities in non-wholly owned 0.4 0.5
subsidiaries
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 2024
£m £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 0.2 (0.5)
equivalents in non-wholly owned subsidiaries
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 (0.1) 0.5
in non-wholly owned subsidiaries
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 2024
£m £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 2024
£m £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 Total results measured in accordance with IFRS excluding the impact
executive management assess the performance of the Group. Adjusted results are of exceptional items and certain remeasurements.
intended to reflect the underlying trading performance of the Group's
businesses and are presented to assist users of the Consolidated financial Exceptional items and certain remeasurements are defined above.
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.
Adjusted EBITDA Operating profit((1)) Adjusted EBITDA is the primary measure used by the Board and executive Earnings before interest, tax, depreciation, amortisation, other gains and
management to assess the financial performance of the Group as it provides a losses and impairment of non-current assets, excluding the impact of
more comparable assessment of the Group's year-on-year trading performance. It exceptional items and certain remeasurements.
is also a key metric used by the investor community to assess the performance
of the Group's operations. 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 Adjusted basic EPS is calculated by dividing the Group's Adjusted earnings
after tax) attributable to each ordinary share outstanding. 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 Adjusted diluted EPS is calculated by dividing the Group's Adjusted earnings
all outstanding share options, that are expected to vest on their future (Adjusted profit after tax) attributable to owners of the parent company by
maturity dates and where the shares are considered to be dilutive, were the weighted average number of ordinary shares outstanding during the period
exercised and treated as ordinary shares as at the reporting date. 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 Borrowings includes external financial debt, such as loan notes, term loans
key measure of leverage and provides information on the sources of liquidity and amounts drawn in cash under revolving credit facilities (RCFs). Borrowings
for the Group. 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 Borrowings (as defined above) including the impact of hedging instruments, and
its financial obligations. lease liabilities calculated in accordance with IFRS 16 less cash and cash
equivalents.
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. Net debt excludes the proportion of cash, lease liabilities and borrowings in
non-wholly owned entities that would be attributable to the non-controlling
The impact of hedging instruments included within Net debt shows the economic interests.
substance of the Net debt position, in terms of actual expected future cash
flows to settle that debt. 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 The Net debt to Adjusted EBITDA ratio is a debt ratio that gives an indication Net debt divided by Adjusted EBITDA for the last twelve months expressed as a
operating profit((1)) of how many years it would take the Group to pay back its debt if Net debt and multiple.
Adjusted EBITDA are held constant.
The Group has a long-term target for Net debt to Adjusted EBITDA of around 2.0
times.
Cash and committed facilities Cash and cash equivalents This is a key measure of the Group's available liquidity and the Group's Total cash and cash equivalents plus the value of the Group's committed but
ability to manage its current obligations. undrawn facilities (including the Group's RCF, loan facilities and the Energy
Solutions non-recourse trade receivables monetisation facility, to the extent
It shows the value of cash available to the Group in a short period of time. 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 2024
£m £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 As at Inflow/
31 December 31 December (outflow)
2025 2024 £m
£m £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 Lease Hedging Obligation to Total
£m liabilities instruments((1)) purchase own £m
£m £m shares
£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 Lease Hedging Total
£m liabilities instruments((1)) £m
£m £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 2024
£m £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 2024
(number) (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 Total net cost Number of shares Total net cost
(million) £m (million) £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 2024
£m £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 Translation Merger Own shares Total other
redemption reserve reserve reserve reserves
reserve £m £m £m £m
£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.
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