Preliminary Results

RNS Number : 7753X

Drax Group PLC

21 February 2012

 



21 February 2012                 

DRAX GROUP PLC (Symbol: DRX)

PRELIMINARY RESULTS FOR THE YEAR ENDED 31 DECEMBER 2011

Ready to invest and become a predominantly biomass fuelled generator

Year ended 31 December	2011	2010
Key financial performance measures
EBITDA (£ million) (1)	334	392
Underlying earnings per share (pence) (2)	55.5	63.9
Total dividends (pence per share) (3)	27.8	32.0
Statutory accounting measures
Profit before tax (£ million)	338	255
Reported earnings per share (pence) (4)	127	52

Financial and Operational Highlights

·     2011 profits maximised by continued operational excellence

·     Strong hedge in place for 2012 at good margins; although little market visibility beyond 2013

·     Haven Power growth on track; currently c.20% of forward sales (January 2011: 11%)

·     Strong balance sheet with £225 million net cash at 31 December 2011

·     Tight control of operating costs and capital expenditure

Biomass Highlights

·     Preparation for biomass expansion now well advanced

-  Extensive combustion trials in 2011 - confident of technical ability to be predominantly biomass fuelled

-  Good progress on fuel procurement - focusing on balancing flexibility with security of supply

·     Ready to expand significantly our renewable capacity with appropriate regulatory support

-  Awaiting Government's conclusion on new levels of support for biomass

Dorothy Thompson, Chief Executive of Drax, said:

"We delivered an excellent performance across the business in 2011, with continued good operations and tight cost control contributing to good financial results in a volatile market. We have a strong balance sheet, which provides a solid foundation for future investment in the business.

"We continue to operate at less than our installed renewable biomass capacity because of the current low level of regulatory support. However, the results of our biomass combustion trials give us full confidence in our technical capability to become predominantly biomass fuelled.

"In 2011, as part of a review of renewables support, Government announced its intention to incentivise from 2013 the most cost effective renewable technologies, including increased support for electricity fuelled by sustainable biomass in existing coal-fired power stations. With a moderate uplift in the proposed support level we could, over time, maximise the potential for producing this low cost renewable electricity.

"Drax is ready to transform itself into a predominantly renewable generator, but to do so we need appropriate regulatory support, and to that end we look forward to the timely conclusion of the Government's current review."

Strategic Capital Investment Plan

·     Limited commitment for 2012 (£50 million) to secure full benefit from existing co-firing facilities

-  Storage and plant modifications to enable qualification for enhanced co-firing support

·     Further investment dependent on appropriate regulatory support and strong investment case

·     Components of potential capital investment:

-  Biomass capacity development (up to a further £450 million)

§ Increase Drax site capacity to become predominantly biomass fuelled

§ Supply chain investments to secure strategic biomass supplies

-  Industrial Emissions Directive compliance (c.£200 million)

·     Evaluation of optimal funding solution on-going

-  Strong balance sheet provides a good foundation for funding requirements

2011 Review

Financial

·     EBITDA for 2011 down 15% at £334 million

-  2011 profits maximised by continued operational excellence and tight cost control

·     Underlying earnings per share decreased 13% to 56 pence

-  Reported earnings per share increased 144% to 127 pence, reflecting exceptional tax credit

·     Eurobond tax position agreed in April 2011

-  Exceptional tax credit of £198 million includes full recognition of Eurobond agreement
(£180 million) plus other legacy tax issues now resolved (£18 million)

·     Strong balance sheet

-  Net cash at 31 December 2011 of £225 million (31 December 2010: £204 million,
including £117 million ring-fenced tax cash)

-  Bank refinancing completed in July 2011

·     Total dividends of 27.8 pence per share, or £101 million (2010: 32.0 pence per share,
or £117 million), in line with our policy to distribute 50% of underlying earnings

-  Final dividend of 11.8 pence per share, or £43 million

Operational

Year ended 31 December	2011	2010
Key operational performance measures
Total recordable injury rate (5)	0.10	0.26
Forced outage rate (%)	5.8	3.4
Availability (%)	88	92
Electrical output (net sales) (TWh)	26.4	26.4

·      Maintaining world class standards of safety and availability

·     High output due to good availability and plant despatch economics

-  Drax load factor 80%, compared with average of 34% and 40% for other coal and gas plant respectively ⁽⁶⁾

·     Good progress with biomass research and development work

-  High biomass burn and plant flexibility with biomass well demonstrated

-  Advanced understanding of chemistry dynamics

-  Final results due H2 2012, including: efficiency and load ranges, biomass fuel optionality and biomass / coal NOx performance

Notes:

(1)   EBITDA is profit before interest, tax, depreciation, amortisation, gains/losses on disposal of property, plant and equipment and unrealised gains/losses on derivative contracts.

(2)   2011 underlying earnings per share exclude unrealised gains on derivative contracts of £90 million (2010: unrealised losses of £61 million) and the associated tax, and the exceptional tax credit of £198 million.

(3)   Based on the number of shares in issue as at 31 December 2011 and 2010 respectively.

(4)   2011 reported earnings include the exceptional tax credit of £198 million, equivalent to 54 pence per share.

(5)   Calculated as (lost time injuries + worse than first aid injuries) / hours worked x 100,000.

(6)   Drax estimate of average load factor for January to December 2011 based on settlement data.

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Forward Looking Statements

This announcement may contain certain statements, statistics and projections 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 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 expectations reflected in such statements are reasonable, no assurance can be given that such expectations will prove to be correct. 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 factors include, but are not limited to, factors such as: future revenues being lower than expected; increasing competitive pressures in the industry; and/or general economic conditions or conditions affecting the relevant industry, both domestically and internationally, being less favourable than expected. 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.

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Management Presentation and Conference Call

Management will host a presentation for analysts and investors at 9:00am (UK Time) today, Tuesday 21 February 2012, at UBS, 1 Finsbury Avenue, London EC2M 2PP.

The meeting can also be accessed remotely via a conference call or alternatively via a live webcast, as detailed below.  After the meeting, a video webcast and recordings of the call will be made available and access details for these recordings are also set out below.

A copy of the presentation will be made available from 7:00am (UK time) today, Tuesday 21 February 2012 for download at:

www.draxgroup.plc.uk>>investors>>results and reports>>IR presentations>>2012

or use the link http://www.draxgroup.plc.uk/investor/results_and_reports/presentations

Event Title	Drax Group plc: Preliminary Results
Event Date	Tuesday 21 February 2012
Event Time	9:00am (UK time)
UK Call In Number	0800 368 1917
International Call In Number	+ 44 (0) 20 3140 0723
US Call In Number	[phone]
Webcast Live Event Link	http://cache.cantos.com/webcast/static/ec2/4000/5275/6662/10055/Lobby/default.htm
Instant Replay
UK Call In Number	0800 368 1890
International Call In Number	[phone]
US Call In Number	[phone]
Passcode	382761#
Start Date	Tuesday 21 February 2012
Delete Date	Tuesday 20 March 2012
Video Webcast
Start Date	Tuesday 21 February 2012
Delete Date	Monday 18 February 2013
Archive Link	http://cache.cantos.com/webcast/static/ec2/4000/5275/6662/10055/Lobby/default.htm

For further information please contact:

	On the day	Thereafter
Drax Group plc Michael Scott, Investor Relations     Melanie Wedgbury, Media Contact	[phone] [phone]	[phone] [phone]
Brunswick Michael Harrison	[phone]
Website: www.draxgroup.plc.uk

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Chairman's introduction

During 2011, we delivered strong operational performance across the business. Although we experienced a good deal of uncertainty in the power-related commodity markets, I am pleased to report earnings (EBITDA) for 2011 of £334 million (2010: £392 million) and an operating profit of £366 million (2010: £279 million). In accordance with our dividend policy, the Board proposes a final dividend in respect of 2011 of 11.8 pence per share, equivalent to £43 million. This would give a total dividend for the year of 27.8 pence per share (2010: 32.0 pence per share).

We continue to make progress in reducing our carbon footprint, something which is now well embedded in and central to our business strategy. In just a matter of weeks we will embark on the last stage of the largest steam turbine modernisation programme in UK history, which brings with it a carbon dioxide emissions saving of one million tonnes a year.

Haven Power Limited, our electricity retail company serving business customers, made good progress implementing its IT business platform which is critical to realising its growth ambitions. We are delighted with the growth achieved in 2011 and the real value that the Group is now deriving from the company's success. It complements well our existing trading capabilities and provides a credit efficient, direct sales channel for an increasing proportion of our power.

Electricity generation from sustainable biomass remains our focus and we continue to believe that this technology has considerable potential and an important role as a low carbon, cost effective, reliable and flexible source of renewable power for the UK. I am delighted to say that our view is being echoed by those in Government and elsewhere, which is encouraging.

We have continued to work with the Government throughout the year to advance the case for sustainable biomass and secure an appropriate level of support. We have welcomed the dialogue that we have been afforded and appreciate the extensive work undertaken by the Government on the biomass agenda.

We have enhanced our technical and commercial expertise in the emerging biomass energy sector and we are ready to increase greatly our electricity generation from sustainable biomass. However, we will only do so if the regulatory regime, including the economics of the support offered, is attractive for our shareholders.

On more governance-related matters and in line with the guidance given in the UK Corporate Governance Code (the "Code"), I should like to comment on how the principles relating to the role and effectiveness of the Board have been applied.

There is a clear division of responsibilities between myself as Chairman and our Chief Executive, Dorothy Thompson. We have a clear statement on which matters are reserved for the Board and those which are delegated, and these are reviewed at least annually. Our non-executive directors play a major role in challenging constructively the Group's management, particularly on matters of strategy and its development.

In recent years through our formal, rigorous and transparent selection process, we have endeavoured to ensure that those appointed to the Board have complementary skills, experience and knowledge in order to improve the quality of the Board and its decision making. Following publication of the Davies Report, Women on Boards, in February 2011, the Board considered the recommendations of both the Davies Report and the Financial Reporting Council consultation on possible changes to the Code. Consequently, we established a policy to ensure that gender diversity is one of the factors taken into account when considering future appointments to the Board and other senior appointments.

Throughout the business I believe we have made significant progress during 2011 and my sincere thanks go to all Group staff for their hard work and commitment, without which none of this year's achievements would have been possible.

Chief Executive's statement

Introduction

The business performed well in 2011 against a backdrop of volatile commodity markets and significant regulatory developments. In our generation and retail businesses, we maintained our focus on excellence in operations, tight cost control and disciplined capital project execution.

Preparation for our biomass expansion is now well advanced. We completed extensive combustion trials in 2011, and are now confident in our technical ability to be predominantly biomass fuelled. However, it is important to note that moving ahead with our plans remains dependent on securing appropriate regulatory support and a strong investment case.

Good financial results, the successful conclusion, in April, to the Group's Eurobond financing structure and the bank refinancing we completed in July, leave us with a strong balance sheet which provides a solid foundation for future investment in the business.

Strategy

Our vision for Drax is to be a bold, customer oriented power generation and retail business, driven by biomass innovation. We have two key strategic initiatives to enable us to achieve our vision, namely, our project to convert Drax Power Station into a predominantly biomass fuelled generating asset, subject to securing the necessary regulatory support, and our programme for the expansion of Haven Power Limited ("Haven Power").

Commodity markets

A number of significant global events in 2011 combined to create uncertainty in the commodity markets in which we operate.

The gas market continued to be the dominant factor in driving power prices. Both the unrest in North Africa and the Middle East and the incident at one of Japan's nuclear power stations which increased the country's demand for liquefied natural gas ("LNG"), contributed to increasing gas prices through the middle of the year. Thereafter, exceptionally mild weather in the fourth quarter saw gas prices come under pressure and begin to fall.

Coal prices moved within a relatively narrow range throughout the year.

Carbon prices reached their lowest point for two years amid fears for the Eurozone economies. Looking ahead, the introduction of the carbon price support mechanism by the UK Government from April 2013 is likely to erode the competitive position in the market of our coal-fired generation business, but at the same time it strengthens the case for biomass generation.

Overall, gas prices were resilient through much of the year and we saw improving dark green spreads, the difference between the price of power and the cost of coal and carbon, for coal-fired generators. In the last quarter of the year, however, spreads began to drift down as the unusually mild weather for the time of year continued.

Bark spreads for co-firing, the difference between power price and renewable support and the cost of biomass, remained weak, with most traded biomass commanding lower margins than coal.

Retail performance

Haven Power is meeting our growth expectations with over double the retail sales of 2010 during 2011. The growth has been driven largely by our progression in the industrial and commercial ("I&C") market, supported by the implementation of a new IT platform which is working well. An excellent standard of customer service is central to our proposition for this business, and we were pleased to see recognition of that through being ranked No. 1 for customer satisfaction in the small and medium enterprise ("SME") market 2011 Datamonitor Survey.

Selling our output through Haven Power provides a credit efficient route to market for our power sales compared to the wholesale electricity market. These sales, when secured at a fixed price, provide a hedge against adverse power price movements. Currently, some 20% of our forward sales are through Haven Power.

Although Haven Power made a small loss in 2011, we remain on track with our target to break-even in this business from 2013.

Operating performance

Following a record year for operating performance in 2010, we continued to deliver industry-leading performance in 2011. As in previous years, our availability and reliability throughout 2011 meant that we were able to deliver value to the business through providing flexible generation output and balancing services to the System Operator, National Grid, in support of system stability and security.

The single unit outage for 2011 was completed in good time, especially given the complexity of some of the renewal work undertaken. Our safety statistics continue to be industry-leading, with the best performance on total recordable injury rate since we began using the measure in 2005.

For the year, our forced outage rate, which measures any reduction in plant availability excluding planned outages, is in line with our long-term target of 5%, which has been set through extensive benchmarking with UK and international coal-fired plant to determine the optimum balance between performance and cost. We delivered this operating performance whilst keeping a tight control on costs.

We continued to work on increasing our burn of fuels which have a higher margin or lower carbon footprint over the standard bituminous coal which we burn. These advantaged fuels (petcoke, pond fines and commercial biomass) accounted for 9% of the total fuel burnt during the year.

We are furthering our work on the options available to us for compliance with the more stringent emissions standards of the Industrial Emissions Directive ("IED") from 2016. The key factors in determining the optimal solution for compliance are plant flexibility, with some technologies such as selective catalytic reduction ("SCR") allowing more flexibility than others, and fuel mix. Accordingly, the level of biomass burn is an important consideration.

We currently estimate the cost of compliance with the IED, including SCR, to be in the order of £200 million (see Strategic capital investment plan).

Renewable output and research and development

Our biomass co-firing facility operated well during the year, but at less than full capacity. Unfortunately, due to the low level of renewable support available for co-firing, much of the biomass available for purchase was not economic to burn. This severely limited our commercial burn of biomass, with less than half of our co-firing capacity being used for commercial electricity generation.

During the year we extended our research and development work with combustion trials of a wide variety of sustainable biomass materials at different throughputs and under varying operating conditions. We burnt significant volumes of uneconomic biomass to support our research and development, but the associated cost was necessary to support these critical trials.

The results of the trials to date have been encouraging and we have confidence in the technical capability to become predominantly biomass fuelled.

Through the trials we achieved high levels of biomass burn over sustained periods, during which time we were also able to demonstrate the plant's flexibility. We have an advanced understanding of the chemistry dynamics and we have been working closely with third party experts to understand any longer term plant efficiency or capacity reduction implications.

We have also extended our research and development work to cover more fuels and further analysis of the likely emissions of nitrogen oxides, to help determine the optimal solution for IED compliance as described earlier. The final results of these trials are due in the second half of 2012.

The final support level under the regulatory framework is the main driving force which will determine the mix of sustainable biomass materials and supply contract tenors, which in turn determines the extent to which we co-fire and, therefore, the performance of the plant itself.

Further carbon abatement

In addition to the carbon dioxide ("CO₂") savings through burning biomass in place of coal, savings were made through efficiency improvements, with the progress of our turbine upgrade project making a key contribution. The low pressure and high pressure turbine modules of five of our six generating units have now been replaced and are operating as expected, which means we are approaching an overall efficiency for the power station of 40%.

With only three low pressure turbine modules to be replaced during the first of two unit outages in 2012 we are nearing completion of the project, which commenced in 2007. On completion, the improved efficiency of the power station will lead to a reduction in CO₂ emissions of one million tonnes a year.

In February 2011, in conjunction with Alstom UK Limited and National Grid Carbon Limited, we lodged an application for European funding for a new, stand-alone 426MW oxy-fired carbon capture and storage demonstration project based at the Drax Power Station site. Following consideration by the UK Government the project was one of seven put forward to the European Investment Bank in May 2011 for further consideration. In January 2012, industrial gases provider, BOC (a member of The Linde Group), joined the consortium, further strengthening the project. The outcome of the application for European funding will not be known until the second half of 2012.

Legislative and regulatory framework

In July 2011, the Electricity Market Reform ("EMR") White Paper was published. The White Paper represents a major change for the electricity sector. We do, however, believe that reform of the electricity market is essential to creating the right environment to stimulate the huge investment necessary to provide adequate, affordable and sustainable supplies of electricity into the 2020s and beyond.

In December, an EMR Technical Update was published, providing further detail on the Government's preferred options for market reform. The document confirmed the intention to implement a market-based capacity auction with the aim of ensuring capacity availability. A more detailed design of the mechanism will be developed during this year.

Within the EMR, a new, low carbon support mechanism, Feed-in Tariff with Contracts for Difference ("FiT CfD") has also been confirmed. This will replace the Renewables Obligation in 2017 for new renewable generation facilities, but not those already in operation. It is proposed that both the capacity mechanism and the FiT CfD arrangements will be run by a single central body, the System Operator.

The 2011 Budget confirmed the introduction of a carbon price support mechanism, as part of the EMR, which we are against. We believe there is potential for conflict with the existing EU Emissions Trading System ("EU ETS") and given the cap and trade nature of the EU ETS, the floor price will have no impact on overall CO₂ emissions, since any reduction in the UK's emissions will simply result in higher emissions elsewhere in the EU. We also believe that the introduction of price support will, in all likelihood, distort the wholesale market. Nevertheless, we have actively engaged with the Government on the detail and design of the mechanism.

In advance of the renewable support arrangements proposed under the EMR, the much awaited consultation on the future support levels for renewable technologies from 2013 was published by the Government in October. This will apply to all renewable generation facilities accredited before April 2017.

We were particularly pleased to see recognition in the consultation of the strategically important role that sustainably sourced biomass electricity can play in the future UK renewable energy mix. In seeking to maximise the deployment of the cheapest renewable technologies, specific support levels or bands have been proposed for the increased use of sustainable biomass in existing coal-fired power stations through enhanced co-firing and full conversion.

The new bands have been created in recognition of the greater capital investment that is required to either co-fire large volumes of biomass or convert existing coal-fired stations to burn solely biomass.

The proposed support level for enhanced co-firing will enable us to increase our sustainable biomass burn. However, to maximise our potential and secure our renewable output out to 2020 and beyond we require a moderate uplift on the proposed level of support. This would guarantee that this cost effective form of renewable generation will be available to help meet the UK's 2020 targets and will lead to lower electricity prices for the UK consumer, who will otherwise bear the cost of the more expensive alternatives.

In addition to our focus on sustainable biomass co-firing, we have been working with Siemens Project Ventures on our dedicated biomass developments. We expressed disappointment with the proposed level of support for this technology, which makes the investment case for the independent generators highly challenging. The development planned for the Drax Power Station site has proved the most challenging for a number of reasons, including its inland location which increases logistics costs. Given the significant financial liability that we would face were we to delay our investment decision until we have certainty over the final support level for dedicated biomass we have decided to cancel the project.

We are exploring a number of options available to us for structuring the development planned for the Port of Immingham site so as to make it a viable proposition.

We participated fully during the Government's consultation process with a view to securing appropriate support to progress our biomass plans and now that the consultation has closed we await the Government's response, which we expect to be published in the Spring.

Biomass supply chain and sustainability

Establishing the biomass supply chain logistics and procuring sustainable biomass against our robust sustainability policy are critical components of our work to deliver a biomass future for the Group. Despite the immature and bespoke nature of the supply chain, we believe we will be able to secure sufficient sustainable biomass to meet our ambition to become a predominantly biomass fuelled generator.

There are four strands to our fuel contracting strategy. We are looking to secure term rights to sustainable biomass through both direct contracts for delivered biomass pellets and contracts for unprocessed fibre to provide greater security over the fibre source. In order to enhance the security of supply from such contracts we are also exploring direct investment in biomass pellet plants.

We will also engage in spot and shorter term opportunistic purchases, with the ability to cope with a wide fuel envelope being key to securing value in this market.

We will try to develop further UK sources of fuel. Although this is likely to remain a small proportion of our total fuel mix. Despite targeting various geographies and fibre sources, we expect to see an early concentration in North America.

All our biomass is procured against our own industry-leading, robust sustainability criteria, which include greenhouse gas emission reduction requirements, and habitats and biodiversity protection, as well as socio-economic considerations in the source areas. A programme of independent audits ensures all our suppliers comply with our sustainability criteria.

We firmly believe that robust, mandatory sustainability criteria are vital to maintain and enhance public acceptance, and ensure that sustainable practices are implemented. Assessment of the full life cycle carbon footprint of biomass, that is, from field to furnace, is now well developed, especially in the UK where a mandatory life cycle standard comes into effect in 2013.

We are now in our fifth year of calculating the life cycle carbon footprint of all the biomass we procure and we are confident that our sustainable biomass fuel sourcing strategy will meet the current mandatory standard which will ensure we continue to earn regulatory support from April 2013. Our calculations show that the range of sustainable biomass materials we have burnt over the last few years has a far lower carbon footprint than that of fossil fuel-fired generating plant. In 2011, the average greenhouse gas saving resulting from burning biomass in place of coal was 81%, compared to the EU fossil fuel comparator.

Strategic capital investment plan

As described above, the proposed support level for enhanced co-firing will enable us to increase our sustainable biomass burn. However, our existing co-firing capacity of 12.5% of our output is insufficient to meet the proposed threshold of 15% of output necessary to receive enhanced co-firing support. Therefore, to secure the full benefit from our existing co-firing facilities, we have committed to invest £50 million in 2012 in new biomass storage and other limited plant modifications to provide the capability to produce up to 20% of our output from co-firing sustainable biomass, so enabling qualification for the enhanced co-firing band. In doing so, we will only burn biomass which is economic, that is, which commands higher margins than coal.

We have also made good progress on the strategic capital investment plan for further biomass expansion. However, it is important to note again that further investment remains dependent on securing appropriate regulatory support and a strong investment case. The principal components of the plan are the further development of our biomass capability and IED compliance.

There are two phases to the development of our biomass capability. Phase 1 is the committed investment of £50 million to secure the full benefit from our existing co-firing facilities as described above.

Phase 2 requires significant further investment in the range of £400-£450 million. Much of this investment will be in additional fuel storage and handling facilities at Drax Power Station as well as further investment in plant modifications. There may also be investment in the biomass supply chain to enhance security of supply for strategic fuel supplies.

As described in Operating performance above, we currently estimate the cost of IED compliance, including SCR, to be in the order of £200 million.

It is important to recognise that if we are in a position to progress our strategic investment plan, our strong balance sheet, with net cash of £225 million at year end, provides a good foundation for our funding requirements. Other important considerations for funding include working capital, our credit rating and our trading strategy. We expect that, with an appropriate level of support and a strong investment case, we would be able to finance our investment plans and begin the transformation of Drax into a predominantly biomass fuelled generator.

Our people

Our people are a key resource and we consider it a priority to deliver excellent people leadership across our operations. Throughout the Group we share the values of honesty, energy, achievement and team spirit. We have a responsibility to our people and we recognise that engaging and motivating them leads to better business performance.

Looking ahead

We enter 2012 with a strong hedge from forward power sales, which were secured at good margins. However, there is little visibility in our markets beyond 2013.

In addition, whereas for Phase II of the EU ETS (2008 - 2012) we have an allocation of 9.5 million tonnes of CO₂ emissions allowances per annum under the UK National Allocation Plan, we will not receive any allocation in Phase III (2013 - 2020). We will also have the increased cost impact of the introduction of the carbon price support mechanism from April 2013. Both of these influences are recognised in market forecasts.

We intend to continue our hard work to deliver leading operating and cost performance and to retain our focus on building options to burn advantaged fuel.

With a commitment to delivering value to our shareholders, we will continue our dialogue with the Government on the legislative and regulatory agenda. We will continue with our preparations to become predominantly biomass fuelled. However, our plans are dependent upon appropriate regulatory support and proving a strong investment case. With such, we are ready to make a significant, timely and cost effective contribution to reducing CO₂ emissions, whilst retaining reliable and flexible capacity on the system.

There is now recognition of the strategically important role that sustainable biomass has to play in the future renewable energy mix of the UK. We have long advocated the benefits of biomass as a source of renewable electricity, key amongst them being the ability to deliver cost effective and reliable low carbon electricity. Through transforming Drax into a predominantly renewable generator fuelled by sustainable biomass we will not only secure large volumes of cost effective renewable generation for the consumer, but also make a significant contribution to meeting the UK's 2020 climate change targets.

Commodity markets

A number of significant global events during 2011 have impacted to increase uncertainty in the commodity markets in which we operate. The price of oil is a key driver of wholesale price. In mainland Europe, gas prices are linked under contract to oil prices, and given that the UK imports a significant amount of gas and that gas is used to generate around 45% of the UK electricity, any changes in wholesale gas prices will impact wholesale electricity prices. The trends in commodity prices witnessed in 2010 and 2011 are described further in the following paragraphs.

Gas

The unrest in North Africa and the Middle East during the first half of 2011 put upward pressure on oil markets despite fears of an economic downturn. This in turn drove up gas prices which were then further strengthened by the increase in demand following the Japanese earthquake, and Germany's decision to close its older nuclear plants. The Japanese earthquake reduced market perceptions of liquefied natural gas ("LNG") availability. Gas prices held during the Summer, before softening during the final quarter of the year as demand was far lower than market expectation as a result of the mild winter experienced in the UK and Europe. This was compounded by the Eurozone crisis which further reduced gas demand. LNG and shale gas remain key drivers of the long-term gas markets. Shale gas is largely a US phenomenon in the near-term. Horizontal drilling technology has advanced, but research papers remain divided on the marginal cost and available volumes at the lower end of the cost scale. However, the US has significant reserves that could enable it to become relatively self sufficient. This could reduce its LNG requirements, freeing up more volume for the Asian and European markets depending on their relative market price. In the longer term, other countries such as China may also exploit potentially large shale gas reserves. However, developments outside the US are in their infancy and will, therefore, have little impact in the short- to medium-term. Furthermore, demand for gas is rising rapidly so that even with the possibility of increased shale gas production, global markets may well remain strong.

Power

During 2010, power demand was relatively stable. There was a small increase in demand in the first quarter of the year, and demand reached record levels in December, although on both occasions this was most likely a result of the unseasonably cold weather. To balance this, on the supply side significant new gas-fired capacity came on line and there were some plant closures. Power prices continued to be driven by the gas market during 2011 increasing over the first half of the year, before stabilising and then dropping in the final quarter as gas prices weakened.

Coal

Following a continued period of price stability through the first half of 2010, coal prices increased significantly in the final months of the year. This reflected tightening in the Pacific market with severe weather causing constraints on production in Australia, Indonesia and Colombia. In addition, strong Asian demand for Atlantic coal, particularly from China, continued to support EU prices. Asian demand continued to influence the global steam coal market during 2011. China is the most significant player in this market with current consumption estimates at 2 billion tonnes per annum. US exports to Europe were circa 150% higher year on year for the first half of 2011 due to increased German demand following the closure of its older nuclear plant, and relatively high gas prices across the continent. Prices reduced slightly towards the end of the year as a result of lower demand levels during the mild winter.

Carbon

Carbon prices traded in a fairly narrow range throughout 2010, with a small increase experienced in the second half of the year. Carbon prices remained fairly flat at the start of 2011 before rising in the immediate aftermath of the Japanese earthquake. Prices dropped sharply in the second half of 2011, reaching two year lows in late November amid fears for the Eurozone economies. With any Phase II surplus bankable into Phase III, pricing seems largely driven by political and macroeconomic factors, such as the renewable generation build rate and the pace of economic recovery.

Biomass

Types of biomass

Biomass used in energy production comes in many different forms, but the important characteristics shared by the wide range of biomass fuels are that they can be renewable and can be sustainable and that they would often be discarded if not used to produce energy. The three common types of biomass used to generate electricity are agricultural residues, forestry products and residues, and energy crops. Recovered materials offer another, very useful, source of biomass.

Agricultural residues 

The by-products of food production, such as straw, oat husks, peanut husks, grape flour, cocoa shells, olive cake and many more, can all be used as biomass for energy production. Importantly, because they are by-products of food production they do not reduce the amount of land available for farming, and they are readily available. Residues from non-food crops, such as cork fines, can also be used. By placing a value on what may be an unwanted by-product of farming, the use of biomass to produce energy provides a new income stream for farmers and supports UK farming.

Forestry products and residues

Sustainably produced woody biomass can be produced from managed forests and forestry residues, such as bark, thinnings, tree tops and branches that are often discarded after trees are felled for timber.

Energy crops 

These are crops that are planted specifically for the purpose of producing energy. Energy crops include short rotation coppice willow and miscanthus, commonly known as elephant grass. Since the start of the UK's Energy Crop Scheme in 2000, thousands of hectares of miscanthus and other short rotation coppice crops have been planted in the UK alone and there is the potential to increase this.

Recovered materials

Recovered wood is an example of a material that could be used as a biomass fuel. The construction and demolition sectors are very large producers of recoverable wood.

Availability of biomass

Biomass is a diverse, readily available and plentiful fuel source. According to the International Energy Agency, biomass is the fourth largest energy resource in the world after oil, coal and gas. It estimates that by 2050 sustainable sources of biomass could be enough to supply the world with 10%-20% of its primary energy requirements.

The EU has indicated that the use of biomass will double over the next few years, and be responsible for around a half of the total effort in reaching the EU's 20% renewable energy target by 2020. In the UK, AEA Technology has estimated that by 2020 sustainable biomass could meet 20% of our primary energy demand and by 2030 this could more than double or even treble.

Operational and financial performance

Introduction

EBITDA was £334 million for the year ended 31 December 2011 compared to £392 million in 2010 and underlying basic earnings per share were 56 pence compared to 64 pence last year.

Our 2011 profit is in line with expectations, which increased during the year with an improvement in the trading environment, although commodity prices did soften towards the end of the period. Earnings were below 2010 levels, which benefited from the accelerated hedge which we put in place during 2008 when wholesale margins were higher. We have continued to exercise tight control over our cost base and our spend on capital projects. 2011 was a record year for health and safety performance at Drax and we have been supported by strong operational performance.

Our retail business, Haven Power Limited ("Haven Power"), is meeting our growth expectations, with sales of 3.3TWh compared to 1.4TWh in 2010, largely as a result of the planned growth in its industrial and commercial ("I&C") customer base, along with a continued increase in the volumes sold to the small and medium enterprise market ("SME").

In April, we were pleased to report that we had reached agreement with HMRC over the Eurobond tax position, resulting in cash tax relief of £180 million. This has enabled us to release £148 million of cash to the business so far, with a further £32 million to follow over the coming years as we utilise the remaining losses.

In July, we completed the refinancing of our letter of credit, working capital and term loan facilities, which were due to mature in December 2012. These facilities were replaced by a £310 million revolving credit facility, maturing in April 2014, with the term loan repaid in full out of cash on hand.

At the upcoming Annual General Meeting, the Board will recommend a final dividend for 2011 of 11.8 pence per share, taking total dividends for the year to 27.8 pence per share, or £101 million.

This review includes further explanation and commentary in relation to our principal performance indicators and the results for the year.

Results of business

	Year ended 31 December 2011 £m	Year ended 31 December 2010 £m
Total revenue	1,835.9	1,648.4
Fuel costs in respect of generation(1)	(1,020.8)	(840.9)
Cost of power purchases(2)	(172.3)	(165.8)
Grid charges(3)	(117.6)	(82.2)
Other retail costs(4)	(24.4)	(9.0)
Total cost of sales	(1,335.1)	(1,097.9)
Gross profit	500.8	550.5
Other operating and administrative expenses excluding depreciation, amortisation and unrealised gains/(losses) on derivative contracts(5)	(167.2)	(158.6)
EBITDA(6)	333.6	391.9
Depreciation, amortisation and loss on disposal of property, plant and equipment	(57.2)	(52.2)
Unrealised gains/(losses) on derivative contracts	89.8	(60.5)
Operating profit	366.2	279.2
Net finance costs	(28.1)	(24.3)
Profit before tax	338.1	254.9
Tax credit/(charge)
- Before exceptional items and impact of corporation tax rate change	(87.5)	(74.1)
- Impact of change in rate of corporation tax on deferred tax	16.1	7.6
- Exceptional items	197.9	-
Tax credit/(charge)	126.5	(66.5)
Profit for the year attributable to equity shareholders	464.6	188.4
Earnings per share	pence per share	pence per share
- Statutory basic	127	52
- Statutory diluted	126	52
- Underlying basic(7)	56	64
- Underlying diluted(7)	55	64

All results relate to continuing operations.

Notes:

(1) Fuel costs in respect of generation predominantly comprise coal, sustainable biomass and carbon dioxide ("CO₂") emissions allowances, together with petcoke and oil.

(2) Cost of power purchases represents power purchased in the market.

(3) Grid charges include transmission network use of system charges ("TNUoS"), balancing services use of system charges ("BSUoS") and distribution use of system charges ("DUoS").

(4) Other retail costs include broker fees, ROCs, metering and LECs.

(5) Other operating and administrative expenses excluding depreciation, amortisation and unrealised gains and losses on derivative contracts include salaries, maintenance costs and other administrative expenses.

(6) EBITDA is defined as profit before interest, tax, depreciation, amortisation, gains and losses on disposal of property, plant and equipment and unrealised gains and losses on derivative contracts.

(7) Calculated using underlying earnings, being profit attributable to equity shareholders adjusted to exclude the after tax impact of unrealised gains and losses on derivative contracts, and exceptional items.

Generation results

Revenue

Total generation revenue for the year ended 31 December 2011 was £1,735 million compared to £1,596 million in 2010. Total generation revenue in 2011 includes power sales of £1,641 million (2010: £1,528 million), ROC and LEC sales of £69 million (2010: £25 million), ancillary services income of £17 million (2010: £35 million) and other income of £8 million (2010: £8 million).

Higher power sales in 2011 resulted from an increase in the average wholesale achieved electricity price for the year ended 31 December 2011 to £55.6 per MWh, compared to £51.6 per MWh in 2010. Our average achieved price of electricity reflects our contracted position, as well as higher power prices on average during the year as a whole, but particularly in the first half when markets felt the impact of the Japanese earthquake and the unrest in North Africa and the Middle East. Net power sold was 26.4TWh in both 2011 and 2010.

ROC and LEC sales have increased from £25 million in 2010 to £69 million in 2011 as a result of an increase in sustainable biomass burn during 2010, which increased the number of ROCs available for sale during 2011. In addition, we have sold a number of current compliance period ROCs, thereby benefiting earlier than usual from sustainable biomass burnt during 2011.

Ancillary services income includes revenue from the Firm Frequency. Response contracts in place with National Grid during 2010. Whilst these contracts gave us certainty of income and more predictable despatch during the Summer months in 2010, their benefit was somewhat offset by the fact that we had less potential to profit from the Balancing Mechanism, where we add value through the plant's flexibility and reliability. For 2011, whilst we had no contract in place with National Grid, we have continued to play a key role supporting the system, and earning appropriate margins from these activities.

Other income includes the sale of by-products (ash and gypsum).

Fuel costs (coal, sustainable biomass and other fuels)

Fuel costs were £1,021 million in 2011, compared to £841 million in 2010.

The average cost of fuel per MWh (excluding CO₂ emissions allowances) was £33.3 for the year ended 31 December 2011, compared to £25.7 in 2010. The increase in average fuel prices was driven by fuel mix, in particular higher sustainable biomass burn following the research and development work described in the Chief Executive's statement and by commodity price movements, especially coal.

We burnt approximately 9.1 million tonnes of coal in the year ended 31 December 2011, compared to approximately 9.4 million tonnes in 2010. This coal was purchased from a variety of domestic and international sources under either fixed or variable priced contracts with different maturities. Coal represented around 87% of total fuel burnt (by heat content) in 2011 and 88% in 2010.

In 2011, we burnt 1.3 million tonnes of sustainable biomass (2010: 0.9 million tonnes) representing 9% of total fuel burnt by heat content (2010: 6%). This increase is a result of the research and development work described in the Chief Executive's statement. We also burnt 0.1 million tonnes of petcoke (2010: 0.2 million tonnes) and 0.6 million tonnes of pond fines (2010: 0.4 million tonnes).

Our petcoke burn volume is driven by its pricing relative to coal. Pond fines is a coal mining residue, which trades at a significant discount to coal, and requires specific blending and handling techniques to burn in large volumes.

The increases in our sustainable biomass and pond fines burn in 2011, demonstrate further improvements in our ability to manage a wider fuel mix.

Fuel costs (CO₂ emissions allowances)

For Phase II of the EU ETS (2008-2012), Drax has an allocation of 9.5 million tonnes of CO₂ emissions allowances per annum under the UK NAP. We purchase CO₂ emissions allowances under fixed price contracts with different maturity dates from a variety of domestic and international sources.

Our CO₂ emissions allowances requirement for the year ended 31 December 2011, in excess of those allocated under the UK NAP, was approximately 11.9 million tonnes compared to approximately 12.9 million tonnes in 2010. This was a result of plant efficiency improvements and higher levels of sustainable biomass burn than in 2010, to achieve the same level of generation.

Our average price of carbon is a function of the timing of purchases under fixed price contracts in the forward and near-term markets. The average price expensed for purchased CO₂ emissions allowances during the year ended 31 December 2011 was £12.0 per tonne compared to £12.6 per tonne in 2010. The majority of our 2011 carbon requirement was contracted during 2010 and the first half of 2011 when prices were higher than in the second half of 2011 (see Commodity markets). This is in line with our hedging strategy to purchase carbon when we sell the related power.

Cost of power purchases

We purchase power in the market when the cost of power in the market is below our marginal cost of production in respect of power previously contracted for generation and delivery by us, and to cover any shortfall in generation. For the year ended 31 December 2011, the cost of purchased power for the generation business was £172 million, compared to £165 million incurred in 2010, as a result of the higher power prices in 2011 as described in Commodity markets.

Grid charges

Grid charges for generation for the year ended 31 December 2011 were £58 million, compared to £54 million in the year ended 31 December 2010. The slight increase resulted from an increase in the £/MWh charged by National Grid reflecting the impact of additional variable generation, such as wind turbines, on their costs to balance the system.

Biomass research and development work

The biomass research and development work described in the Chief Executive's statement cost around £19 million in 2011. This includes £11 million within generation gross margin (the impact of burning uneconomic biomass principally), operating costs of £3 million (e.g. expert technical advice in relation to biomass combustion and chemistry) and capital investment of £5 million (new conveyors and fuel handling infrastructure).

We believe this work has placed Drax in the best possible position to deliver a step change as quickly and efficiently as possible in the volumes of sustainable biomass we burn, if support is at an appropriate level.

As a result of these factors, generation gross profit for the year ended 31 December 2011 was £484 million compared to £536 million in 2010.

Operating and administrative expenses

Generation other operating and administrative expenses before depreciation and amortisation were £148 million for the year ended 31 December 2011, compared to £143 million in 2010. The cost increase of £5 million largely reflects the biomass investment in research and development work described above.

Generation EBITDA for the year ended 31 December 2011 was, therefore, £336 million compared to £393 million in 2010.

Retail results

Revenue

Retail revenue of £276 million for the year ended 31 December 2011 was 123% higher than the revenue of £124 million for the year ended 31 December 2010. This substantial growth is in line with our strategy to grow Haven Power, with retail sales being a credit efficient alternative to selling power in the wholesale market. The growth in sales has been secured at satisfactory margins and good credit quality.

Retail sales volumes have increased from 1.4TWh in the year ended 31 December 2010 to 3.3TWh in 2011 following planned growth in the I&C customer base and continued growth in SME customer volumes.

Cost of power purchases

Retail cost of power purchases were £171 million for the year ended 31 December 2011 compared to £71 million for the year ended 31 December 2010. Haven Power purchases power in the wholesale market for delivery to its retail customers. The vast majority of these purchases are from Drax Power Limited and are eliminated on a group basis. The increase in retail cost of power purchases is a result of the significant increase in sales volumes and power prices.

Grid charges

Haven Power incurred £60 million of grid charges during the year ended 31 December 2011 and £28 million during the year ended 31 December 2010. Charges have increased as a result of higher sales volumes together with substantial increases in the rates charged by the distribution network operators.

Other retail costs

Other retail costs include broker fees, ROCs, LECs and metering and were £29 million in the year ended 31 December 2011, compared to £11 million in 2010. In addition to higher volumes, costs have increased in 2011 due to the much larger than expected uptake of the subsidy for solar photovoltaic panels, which has resulted in very large increases to the FiT levelisation costs being charged to suppliers.

Retail gross profit for the year ended 31 December 2011 was £16 million compared to £15 million in 2010. Although sales volumes have increased significantly, margins within the I&C market remain relatively low.

Operating and administrative expenses

Retail operating and administrative expenses excluding depreciation and amortisation were £19 million for the year ended 31 December 2011, £3 million higher than for 2010. The increase largely relates to staff costs following the growth in the business and certain entry costs into the I&C market.

As a result, retail EBITDA for both the years ended 31 December 2011 and 2010 was a loss of £2 million.

We remain on track to achieve our target of break even EBITDA for this business from 2013.

Central costs

Depreciation and amortisation

Depreciation and amortisation was £57 million for the year ended 31 December 2011 and £52 million for the year ended 31 December 2010. 2011 includes a full year of depreciation for the co-firing facility, which was commissioned part-way through 2010.

Unrealised gains and losses on derivative contracts

The Group recognises unrealised gains and losses on forward contracts which meet the definition of derivatives under IFRSs. Where possible, we take the own use exemption for derivative contracts entered into and held for our own purchase, sale or usage requirements, including forward domestic coal and biomass contracts.

As such, the movement in the net unrealised gains and losses recognised in the balance sheet principally relate to the mark-to-market of our forward contracts for power. The following table shows the movements in unrealised gains and losses and where they are recorded in our financial statements.

	Year ended 31 December 2011 £m	Year ended 31 December 2010 £m
Net unrealised (losses)/gains in the balance sheet at 1 January	(61.0)	234.1
Unrealised gains/(losses) recognised in the income statement	89.8	(60.5)
Fair value gains/(losses) recognised in the hedge reserve (a component of equity)	2.6	(232.6)
Premium on options sold	(0.7)	(2.0)
Net unrealised gains/(losses) in the balance sheet at 31 December	30.7	(61.0)

The trends in forward power prices, which largely determine the movements in our net unrealised gains and losses position are described within the Commodity markets section.

During 2010, power prices increased, such that the difference between power that had been contracted but had yet to be delivered and the market price had narrowed considerably at 31 December 2010, reducing the unrealised gain in the balance sheet. In addition, following a period of coal price stability during the first half of 2010, prices increased significantly in the final months of the year, driving an increase in the unrealised losses on our financial coal contracts, which expose us to floating prices. Together these factors resulted in an unrealised loss in the balance sheet of £61 million at 31 December 2010.

During 2011, power prices fell significantly in the final quarter. As a result, the average price of power that had been contracted but had yet to be delivered at 31 December 2011 was higher than market prices, driving an increase in the unrealised gain in the balance sheet. Coal prices also continued to rise during the first quarter of 2011, before stabilising over the remainder of the year. A number of the financial coal contracts in place at 31 December 2010 unwound during the year as the contracts matured, thereby reducing the unrealised losses at 31 December 2011.

This combination of factors drove the recognition of an unrealised gain of £31 million in the balance sheet at 31 December 2011.

The unrealised gains recognised in the income statement of £90 million for the year ended 31 December 2011 and unrealised losses of £61 million in 2010 arise from mark-to-market movements on our derivative contracts which do not qualify for hedge accounting; largely financial coal and foreign exchange.

Mark-to-market movements on most of our derivative contracts, considered to be effective hedges, have been recognised through the hedge reserve, a component of shareholders' equity in the balance sheet. Movements in unrealised gains and losses recognised in the hedge reserve are mainly the result of unwinding mark-to-market positions relating to power delivered during a reporting period, and the recording of mark-to-market positions on power yet to be delivered at the end of that period. The net unrealised gain recognised through the hedge reserve in the year ended 31 December 2011 was £3 million, compared to net unrealised losses of £233 million in 2010.

In considering mark-to-market movements, it is important to recognise that profitability is driven by our strategy to deliver market level dark green spreads, not by the absolute price of electricity at any given date.

After allowing for the unrealised gains and losses on derivative contracts, depreciation and amortisation, operating profit for the year ended 31 December 2011 was £366 million compared to £279 million in 2010.

Interest

Net finance costs for the year ended 31 December 2011 were £28 million compared with £24 million in 2010. The unwind of deferred finance costs in relation to our previous bank facilities was accelerated to reflect their reduced term following the refinancing (see Capital resources and refinancing). This resulted in a one-time interest charge of £3 million in the year to 31 December 2011.

Tax

The tax charge before exceptional items for the year ended 31 December 2011 was £71 million (an effective rate of 21%), compared to £67 million in 2010 (an effective rate of 26%). Tax for 2011 includes the impact of the reduction in corporation tax rate from April 2011 on current and deferred tax liabilities and of the reduction in corporation tax rate from April 2012 on deferred tax liabilities.

Under the Group's previous financing structure, a subsidiary company was partially funded by a Eurobond payable to another group company, which was unwound in 2008, potentially accelerating additional tax losses with a cash tax benefit of up to £220 million. The Group began utilising these potential losses in 2008, with cash saved notionally ring-fenced, and no benefit recognised prior to agreement with HMRC.

In April 2011, we reached agreement with HMRC over the Eurobond tax position which will result in the release of £180 million cash tax relief. As at 31 December 2011, we had released £148 million of cash saved to date to the business and will release a further £32 million over the coming years as we utilise the remaining losses.

The exceptional tax credit of £198 million includes full recognition of the Eurobond settlement of £180 million and a further £18 million in relation to other legacy issues, being the release of historic tax provisions no longer required following settlement of these issues.

As a result of the above factors, profit attributable to equity shareholders for the year ended 31 December 2011 was £465 million compared to £188 million in 2010, and basic and diluted earnings per share were 127 pence and 126 pence respectively, compared to 52 pence in 2010.

Underlying profit attributable to equity shareholders (that is profit excluding the after tax impact of unrealised gains and losses on derivative contracts, and exceptional items) was £202 million for the year ended 31 December 2011, compared to £233 million in 2010. Underlying basic and diluted earnings per share were 56 pence and 55 pence respectively in 2011, compared to 64 pence in 2010.

Other key factors affecting the business

Outages and plant utilisation levels

	Year ended 31 December 2011	Year ended 31 December 2010
Electrical output (net sales) (TWh)	26.4	26.4
Load factor (%)	79.7	79.7
Availability (%)	88.4	92.1
Winter forced outage rate (%)	3.9	2.4
Forced outage rate (%)	5.8	3.4
Planned outage rate (%)	6.2	4.6
Total outage rate(1) (%)	11.6	7.9

Notes:

(1) The forced outage rate is expressed as a percentage of planned capacity available (that is, it includes a reduction for planned losses). The planned outage rate is expressed as a percentage of registered capacity. Accordingly, the aggregation of the forced outage rate and planned outage rate will not equate to the total outage rate.

The load factor and electrical output were 79.7% and 26.4TWh respectively for both years ended 31 December 2011 and 2010. We continued to demonstrate our leadership position in the coal-fired generation sector with plant availability of 88.4% for the year ended 31 December 2011, compared to 92.1% in 2010.

The forced outage and Winter forced outage rates for the year ended 31 December 2011 were 5.8% and 3.9% respectively, compared to 3.4% and 2.4% in 2010 which was a record year. 2011 forced outage rate remains consistent with our long-term target of circa 5%.

The planned outage rate achieved for the year ended 31 December 2011 was 6.2%, compared to 4.6% in 2010, with one major planned outage completed in both years. Our maintenance regime includes a major planned outage for each of our six units once every four years. Consequently, there is an irregular pattern to planned outages and associated expenditure, since in two of the four years two units will each undergo a major planned outage. Two units will undergo a major planned outage in 2012.

Health and safety

2011 was a record year for Drax in terms of our health and safety performance. Our lost time injury rate and total recordable injury rate were 0.08 and 0.10 respectively for the year ended 31 December 2011 compared to 0.13 and 0.26 respectively in 2010. Our safety record continues to be industry-leading and was delivered alongside a significant amount of project activity. We continue with our commitment to deliver a positive health and safety culture.

Liquidity and capital resources

Net cash was £225 million as at 31 December 2011, compared to £204 million at 31 December 2010, following the refinancing in July 2011, and the repayment of £135 million of borrowings (see Capital resources and refinancing). Cash and short-term deposits were £233 million as at 31 December 2011, compared to £331 million at 31 December 2010. An analysis of cash flows for both years is set out in the following table.

Analysis of cash flows

	Year ended 31 December 2011 £m	Year ended 31 December 2010 £m
Cash generated from operations	281.9	484.7
Income taxes paid	(67.7)	(56.1)
Other gains	0.7	2.0
Net interest paid	(16.4)	(19.5)
Net cash from operating activities	198.5	411.1
Cash flows from investing activities
Purchases of property, plant and equipment	(43.8)	(62.3)
Short-term investments	65.0	(40.0)
Net cash generated from/(used in) investing activities	21.2	(102.3)
Cash flows from financing activities
Equity dividends paid	(123.7)	(86.5)
Repayment of borrowings	(135.4)	(65.2)
New borrowings	10.0	-
Other financing costs paid	(3.8)	(1.5)
Net cash used in financing activities	(252.9)	(153.2)
Net (decrease)/increase in cash and cash equivalents	(33.2)	155.6
Cash at 1 January	236.0	80.4
Cash at 31 December	202.8	236.0
Short-term investments at 31 December	30.0	95.0
Borrowings at 31 December	(7.6)	(127.0)
Net cash at 31 December	225.2	204.0

Cash generated from operations was £282 million in the year ended 31 December 2011, compared to £485 million in 2010. The decrease was largely the result of a fall of £58 million in EBITDA and a working capital outflow of £51 million in 2011, compared to an inflow of £115 million in 2010.

The working capital outflow of £51 million in 2011 includes an increase of £24 million in the value of coal stocks, resulting from an additional 0.2 million tonnes of stock held at the end of 2011, and higher coal prices during the period (see Fuel costs - coal, sustainable biomass and other fuels). The remaining net outflow includes a lower carbon creditor (£21 million), reflecting the timings of payments with respect to our 2011 liability and a fall in the cost of carbon over the year (see Fuel costs - CO₂ emissions allowances). The working capital inflow in 2010 largely reflects a decrease in coal stocks of 1.6 million tonnes (£84 million), resulting from higher than expected generation over the corresponding period.

Income taxes paid were £68 million in the year ended 31 December 2011, compared to £56 million in 2010. 2011 payments include settlement of the 2010 liability, as well as payments on account for 2011.

Net cash flows from investing activities includes payments in respect of capital expenditure of £44 million for the year ended 31 December 2011 and £62 million in 2010 (see Capital expenditure). 2011 includes a reduction in short-term investments of £65 million (2010: additional £40 million), comprising short-term deposits with a maturity of more than three months at inception.

Net cash used in financing activities was £253 million in the year ended 31 December 2011, compared to £153 million in 2010. The 2011 amount includes equity dividends paid of £124 million and term loan repayments of £135 million, net of new borrowings of £10 million drawn down against the revolving credit facility. The 2010 amount includes equity dividends paid of £87 million and term loan repayments of £65 million (see Capital resources and refinancing).

The decrease in cash and cash equivalents was therefore £33 million in the year ended 31 December 2011, compared to an increase of £156 million in 2010. The Group's policy is to invest available cash in short-term bank, building society or other low risk deposits.

Capital resources and refinancing

In July 2011, we completed the refinancing of our letter of credit, working capital and term loan facilities, which were due to mature in December 2012. These facilities were replaced with a £310 million revolving credit facility which matures in April 2014, and which can be used for both letters of credit and working capital purposes. The margin over LIBOR on our new facility has reduced from 3.5% to 2%.

Scheduled debt repayments of £34 million were made at 30 June 2011 and the remaining term loan balance of £101 million was repaid in full upon refinancing. During 2010 scheduled debt repayments were £65 million.

The unwind of the deferred finance costs in relation to the previous banking facilities has been accelerated to reflect their reduced term, resulting in a one-time interest charge of £3 million in the year to 31 December 2011.

£10 million has been drawn down against the new revolving credit facility during the year and remained in place at 31 December 2011.

Going concern

The Group's business activities, together with the factors likely to affect future developments, performance and position including principal risks and uncertainties are set out in this Business review. Our cash flows and borrowing facilities are described above.

We have significant headroom in our banking facilities, and a recent history of cash generation, strong covenant compliance, and good visibility in near-term forecasts, due to our progressive hedging strategy. Our Business Plan, taking account of reasonably possible changes in trading performance, shows that we should be able to operate within the level of our current banking facilities.

Accordingly, the directors have a reasonable expectation that the Group has adequate resources to continue in operational existence for the foreseeable future, and continue to adopt the going concern basis of accounting when preparing these financial statements.

Seasonality of borrowing

Our business is seasonal with higher electricity prices and despatch in the Winter period and lower despatch in the Summer months, when prices are lower and plant availability is affected by planned outages.

Accordingly, cash flow during the Summer months is materially reduced due to the combined effect of lower prices and output, while maintenance expenditures are increased during this period due to major planned outages. The Group's £310 million revolving credit facility assists in managing the cash low points in the cycle where required. See Capital resources and refinancing.

Capital expenditure

Fixed asset additions were £45 million in the year ended 31 December 2011, compared to £59 million in 2010. This includes expenditure of £8 million (£20 million in 2010) on our major strategic carbon abatement project, the turbine upgrade, and £5 million of expenditure on new conveyors and fuel handling infrastructure in support of our biomass research and development work (2010: £nil).

In relation to the turbine upgrade project, we expect to invest up to £100 million to upgrade the high pressure and low pressure turbine modules on all six generating units to improve efficiency. With a double unit outage scheduled for 2012, the turbine upgrade programme will be completed. Expenditure remains in line with budget.

We will continue to evaluate other investment opportunities which may result in additional capital expenditure (see Chief Executive's statement, Strategic capital investment plan).

Creditor payment policy and practice

Terms of payment are agreed with suppliers when negotiating each transaction and the Group's policy is to abide by those terms and pay creditors when sums owing fall due for payment, provided that the suppliers also comply with all relevant terms and conditions. Drax Group plc, the parent company of the Group, has no trade creditors. In respect of Group activities, the amounts due to trade creditors at 31 December 2011 represented approximately 22 days of average daily purchases through the year (2010: 21 days). The figure is based upon the ratio of amounts owed to trade creditors against the amounts the Group was invoiced by suppliers during the financial year.

Future developments

Strategic capital investment plan

The Chief Executive's statement describes how preparation for our biomass expansion is now well advanced. Whilst moving ahead with our plans remains dependent on securing appropriate regulatory support and on proving a strong investment case, we have also made good progress with the work to scope out the capital investment plan for the project. The principal components of the plan include potential investments in development of the Drax site biomass capacity, the biomass supply chain, and in Industrial Emissions Directive ("IED") compliance.

	£m
Committed investment:
Biomass capacity development (Phase 1)
- secure full benefit from existing co-firing facilities	£50m
Dependent on appropriate ROC support and strong investment case:
Biomass capacity development (Phase 2)
- increase Drax site capacity to predominantly biomass	c. £250m
- pellet plants to provide fuel security	£150m-£200m
IED compliance
- estimate of plant retrofit cost	c. £200m
Net cash at December 2011	£225m

More information on the various components of the capital investment plan can be found in the Chief Executive's statement.

It is important to recognise that if we are in a position to progress, our strong balance sheet, with net cash of £225 million at year end, provides a good foundation for our funding requirements.

Positions under contract for 2012, 2013 and 2014

We continue to follow our stated trading strategy of making steady forward power sales with corresponding purchases of CO₂ emissions allowances and fuel purchases. Our aim is to deliver market level dark green spreads across all traded market periods and, as part of this strategy, we retain power to be sold into the prompt (within season) power markets.

As at 15 February 2012, the positions under contract for 2012, 2013 and 2014 were as follows:

 

	2012	2013	2014
Power sales (TWh) comprising:	22.0	9.1	3.0
- Fixed price power sales (TWh) at an average achieved price (per MWh)	15.1 at £54.5	6.5 at £52.7	0.4 at £57.6
- Fixed margin and structured power sales (TWh)	6.9	2.6	2.6
CO2 emissions allowances hedged, including UK NAP allocation, market purchases, structured contracts, and benefit of biomass co-firing (TWh equivalent)	21.8	9.1	3.1
Solid fuel at fixed price/hedged, including structured contracts (TWh equivalent)	22.6	11.0	11.1

Fixed price power sales include approximately 1.0TWh supplied in the period 1 January 2012 to  15 February 2012 under the five and a quarter year baseload contract which commenced on 1 October 2007 and the five year 300MW baseload contract which commenced on 1 October 2010, both with Centrica.

Fixed margin power sales include approximately 6.9TWh in 2012 and, 2.6TWh in both 2013 and 2014 in connection with the above contracts.

Under these contracts the Group will supply power on terms which include Centrica paying for coal, based on international coal prices, and delivering matching CO₂ emissions allowances amounting in aggregate to approximately 7.2 million tonnes in 2012, and approximately 2.4 million tonnes in both 2013 and 2014.

The contracts provide the Group with a series of fixed dark green spreads, with the spreads in the first contract having been agreed in the first quarter of 2006 and those in the second contract having been agreed in October 2009.

Distributions

Distribution policy

Subject to the provisions of the Companies Act, the Group may by ordinary resolution from time to time declare dividends not exceeding the amount recommended by the Board. The Board may pay interim dividends whenever the financial position of the Group, in the opinion of the Board, justifies the payment.

The Board has previously committed to a pay-out ratio of 50% of underlying earnings (being profit attributable to equity shareholders adjusted to exclude the after tax impact of unrealised gains and losses on derivative contracts, and exceptional items) in each year. Underlying earnings per share were 56 pence on this basis for the year ended 31 December 2011.

Dividends paid

On 21 February 2011, the Board resolved, subject to approval by shareholders at the Annual General Meeting ("AGM") on 13 April 2011, to pay a final dividend for the year ended 31 December 2010 of 17.9 pence per share (£65 million). The final dividend was subsequently paid on 13 May 2011.

On 1 August 2011, the Board resolved to pay an interim dividend for the six months ended 30 June 2011 of 16.0 pence per share (£58 million), representing 50% of underlying earnings for the period. The interim dividend was subsequently paid on 14 October 2011.

Dividends proposed

At the forthcoming AGM the Board will recommend to shareholders that a resolution is passed to approve payment of a final dividend for the year ended 31 December 2011 of 11.8 pence per share (£43 million), payable on or before 11 May 2012. Shares will be marked ex-dividend on 25 April 2012.

Principal risks and uncertainties

The effective management of risks within the Group underpins the delivery of our key priorities. The Group has a comprehensive structure of governance controls in place to manage risks. Policies have been established in key areas of the business such as trading, treasury, production and health and safety to ensure that these risks are managed in a controlled manner and in accordance with the Board's appetite for risk.

Internal control and risk management

The Board is responsible for the Group's system of internal control and for reviewing its effectiveness. A process has been established for identifying, evaluating and managing the significant risks faced by the Group and this has been in place for the year under review up to the date of approval of the 2011 Annual report and accounts. The process is designed to manage rather than eliminate the risk of failure to achieve business objectives, and can only provide reasonable, not absolute, assurance against material misstatement or loss.

Risk management committees

There are five risk management committees:

1          Treasury and commodity risk management committee

2          Safety, health, environmental and production integrity committee

3          New business risk management committee

4          Corporate risk management committee

5          Haven Power risk management committee

Each Committee is responsible for ensuring that all risks associated with their specific area of the business are identified, analysed and managed systematically and appropriately. Each Committee has terms of reference that requires it to ensure that systems and controls are approved, implemented and monitored to ensure that activities are commensurate with the risk appetite established by the Board, are adequately resourced and comply with applicable legal and regulatory requirements. Each risk committee contains at least one member of the Executive Committee.

Risk management process

The key elements of the risk management process are as follows:

Risk identification - risks faced by the Group are identified during the formulation of the Business Plan. Senior management and risk owners, with the assistance of the risk management committees, periodically review the risks to ensure that the risk management processes and controls in their area are appropriate and effective, and that new risks are identified.

Risk analysis - the basic causes of each risk are considered, and the impact and likelihood of its materialising is assessed. Risk registers are used to document the risks identified, level of severity and probability, ownership and mitigation measures for each risk. The risk registers are reviewed by the risk management committees on a quarterly basis. Risks are then logged with reference to impact and probability.

Risk monitoring and assurance - the Board is ultimately responsible for this system of risk management and internal control. The Audit Committee reviews financial information and the suitability of internal controls on behalf of the Board. Risk management committees assist the executive directors in the operation and implementation of the risk management process, and provide a source of assurance to the Audit Committee that the process is operating effectively.

Internal control

In addition, the Group has comprehensive and well defined control policies with clear structures, delegated authority levels and accountabilities.

The Group has a system of planning and monitoring, which incorporates Board approval of a rolling five year Business Plan and approval, towards the end of each year, of operating and capital expenditure budgets for the year ahead. Performance against the budget is subsequently monitored and reported to the Board on a monthly basis. The Board also receives monthly reports on trading risk exposure as compared to the pre-set limits, and monitors overall Group performance against a Balanced Corporate Scorecard which shows progress against a set of financial, operating, safety and other targets set at the start of the year. Performance is reported formally to shareholders through the publication of Group results. Operational management makes frequent reports on performance to the executive directors.

The Group also has processes in place for business continuity and emergency planning.

Through the Audit Committee, the Board has implemented a programme of internal audit reviews of different aspects of the Group's activities. The programme, which is reviewed and updated annually, is designed so that, over time, all facets of the business are reviewed to ensure appropriate systems of control are in place and are working effectively or, where they are not, deficiencies are rectified by timely and appropriate action. In agreeing the actions to be taken in response to each report, the aim is always to embed internal controls, including measures intended effectively to identify and manage risk, within each area of the Group's operations. In parallel with its work in relation to internal audit, the Audit Committee also satisfies itself that an action plan, for dealing with points raised by the external auditors in their yearly management letter is being properly addressed by management.

With the assistance of the Audit Committee, the Board has reviewed the effectiveness of the system of internal control. It has reviewed the reports of the Audit Committee, which has considered all significant aspects of internal control including financial, operational, trading, compliance, social, environmental and ethical risks in accordance with the "Internal Control: Guidance for Directors on the UK Corporate Governance Code".

Following its review, the Board determined that it was not aware of any significant deficiency or material weakness in the system of internal control.

Commodity market risk

Context

We experienced a great deal of uncertainty in power-related commodity markets during 2011

Risk

- We are exposed to the effect of fluctuations in commodity prices, particularly the price of electricity and gas, the price of coal and sustainable biomass (and other fuels), and the price of CO₂ emissions allowances.

Potential impact

- Volatility in financial results.

Associated objective and key priorities

- Maximise the value of the Drax business.

- Maximise profitability from our coal generation capacity.

Examples of mitigating activities

- Well understood progressive hedging strategy, forward power sales with corresponding purchases of fuel and CO₂ emissions allowances when profitable to do so.

Counterparty risk

Context

The recent recession and uncertain economic growth potentially impact on counterparty risk

Risk

- We rely on third party suppliers for the delivery of fuel and other goods and services. We purchase a significant quantity of our coal under contracts with a number of large UK suppliers, so are exposed to the risk of non-performance by these suppliers.

- We enter into fixed price and fixed margin contracts for the sale of electricity to a number of counterparties, so are exposed to the risk of failure of one or more of these counterparties.

Potential impact

- Additional costs associated with securing fuel and other goods and services from other suppliers.

- Failure to secure coal from other suppliers resulting in limitation of operations.

- Adverse effect on cash flow and earnings arising from the failure of one or more of the counterparties to whom we sell power.

Associated objective and key priorities

- Maximise the value of the Drax business.

Examples of mitigating activities

- Diversified coal supply in terms of source and counterparties.

- Good portion of purchases at market indexed prices (no mark-to-market exposure).

- Diversified logistics routes.

- Target to optimise holding of coal stocks.

- Close monitoring and reporting of concentration risk in suppliers.

- Full suite of power counterparties with strong credit ratings.

- Close monitoring and reporting of concentration risk in power counterparties.

- Trading contracts generally include provisions that force counterparties to post collateral if they drop below investment grade.

Ratings risk

Context

Our business model currently has investment grade debt although we could operate as sub-investment grade with actions that have been implemented

Risk

Our investment grade debt rating currently underpins our ability to deliver optimal value from our existing trading strategy. A downgrade of our debt rating to sub-investment grade would require a modified trading strategy.

Potential impact

- Requirement to post collateral for trading positions.

- Additional restrictions within facilities agreements.

Associated objective and key priorities

- Maintain an optimal supporting capital structure (which can either be investment or sub-investment grade debt with appropriate trading strategy)

Examples of mitigating activities

- Refinement to trading strategy to trade on credit efficient terms.

- Grow direct sales through Haven Power, our electricity supply business.

- Additional access to collateral through the £135 million trading facility signed in 2010.

Electricity wholesale market risk

Context

Liquidity in the market for wholesale electricity is dependent on there being a sufficient number of counterparties willing to trade actively

Risk

- Changes in the market structure or consolidation of the existing generation and supply businesses in the UK could result in a reduction in the number of active participants in the market with whom we are able to trade.

Potential impact

- Inability to hedge short- to medium-term exposure to electricity prices through wholesale market trading.

- Increased exposure to short-term market volatility.

- Inability to sell all of our output.

- Lower revenues and increased costs to achieve trading objectives.

Associated objective and key priorities

- Grow our retail customer base.

- Maximise the value of the Drax business.

- Maximise profitability from our coal generation capacity

Examples of mitigating activities

- Grow direct sales through Haven Power, our electricity supply business.

- Initiatives to be active, responsive and provide good credit towards counterparties make Drax an attractive business partner.

- Oppose structural changes that impact our market access, such as clearing and margining.

- Work with other independent generators (via Independent Generators Group) to achieve positive market and regulatory changes to improve liquidity.

Biomass strategy risk

Context

Sustainable biomass is well placed to provide the UK with low cost and flexible renewable power, and contribute to meeting carbon reduction targets

Risk

- We may not secure an appropriate regulatory framework and specific support mechanisms from Government, which underpin the economics of sustainable biomass.

- From April 2013, in order for the sustainable biomass we burn to qualify for support under the Government's renewables support mechanism, we will have to demonstrate that it meets pre-determined sustainability standards. Those sustainability standards may be tightened over time, and there is a risk that we may sign long-term supply contracts which meet the current standard but fail to meet a future standard.

- Most of the sustainable biomass that we can procure is priced in foreign currency which increases our exposure to fluctuations against sterling and poses a risk to profitability.

- There are relatively few sustainable biomass suppliers in the market leading to concentration of supply risk. A supply disruption from one could impact on our generation capacity.

- We could fail to secure sustainable biomass supplies and logistics arrangements which meet our hurdle return rates and sustainability criteria.

Potential impact

- Inability to progress the biomass growth strategy.

Associated objective and key priorities

- Progress our biomass strategy.

Examples of mitigating activities

- Engage with Government to obtain the right framework and grandfathered support from April 2013 including the grandfathering of fuel supply contracts.

- Hedge currency exposures or secure contracts in sterling to the extent that it's appropriate.

- Advanced discussions with several large creditworthy suppliers, building new relationships and exploring new green field projects.

- Contract with suppliers where a robust operational plant and logistics infrastructure is already in place; work with new suppliers to help develop such infrastructure.

Plant operating risk

Context

Forced outages impact on our ability to generate electricity

Risk

- Forced outages may be caused by the underperformance or outright failure of our power generation plant, or transmission assets or other equipment and components including the IT systems used to operate the plant or conduct trading activities. The duration of forced outages is influenced by the lead time to manufacture and procure replacement components and to carry out repairs.

Potential impact

- Lower revenues.

- Increased costs and contractual penalties.

- Adverse effect on financial results.

Associated objective and key priorities

- Maintain operational excellence.

Examples of mitigating activities

- Comprehensive risk-based plant investment and maintenance programme.

- Target to optimise holding of spare components for use in the event of plant failure particularly long lead time items.

- Business continuity plan for IT systems.

Regulatory and political risk

Context

The Government's market reform agenda is driven predominantly by the need to move to a sustainable, low carbon energy sector which delivers affordable supplies to customers whilst maintaining security of supply over the longer term. Laws and regulations are many and complex, are frequently changing, and becoming ever more stringent, particularly in relation to environmental matters

Risk

- The Government's Energy Market Reform package, including the Carbon Price Support mechanism which will be introduced by HM Treasury from April 2013, will result in coal generation becoming progressively and relatively less economic than other major forms of generation like gas, nuclear and renewables.

- The EU, UK and local environmental and health and safety laws and regulations cover many aspects of our operations including limits on emissions to air and water, noise, soil/groundwater contamination, waste, and health and safety standards.

Potential impact

- Less funding available for plant retrofit/investment costs to meet increasingly stringent environmental requirements.

- Lower load factors/generation levels.

- Adverse effect on financial results.

Associated objective and key priorities

- Progress our biomass strategy.

- Maintain operational excellence.

Examples of mitigating activities

- Deliver our biomass strategy.

- Briefing, representation and engagement at EU and UK level.

- Development of abatement and alternative generation options.

- Regular third party assurance over system effectiveness.

- Strong safety culture and related training.

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; and

- the management report, which is incorporated into the Directors' 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.

Dorothy Thompson                                          Tony Quinlan

Chief Executive                                      Finance Director

20 February 2012

Consolidated income statement

			Years ended 31 December
		Notes	2011 £m	2010 £m
	Revenue		1,835.9	1,648.4
	Fuel costs in respect of generation		(1,020.8)	(840.9)
	Cost of power purchases		(172.3)	(165.8)
	Grid charges		(117.6)	(82.2)
	Other retail costs		(24.4)	(9.0)
	Total cost of sales		(1,335.1)	(1,097.9)
	Gross profit		500.8	550.5
	Other operating and administrative expenses		(224.4)	(210.8)
	Unrealised gains/(losses) on derivative contracts		89.8	(60.5)
	Operating profit		366.2	279.2
	Interest payable and similar charges		(30.3)	(26.5)
	Interest receivable		2.2	2.2
	Profit before tax		338.1	254.9
	Tax:
	- Before exceptional items	5	(71.4)	(66.5)
	- Exceptional items	5	197.9	-
			126.5	(66.5)
	Profit for the year attributable to equity holders		464.6	188.4

Earnings per share		pence	pence
- Basic	7	127	52
- Diluted	7	126	52

All results relate to continuing operations.

Underlying earnings and underlying earnings per share are set out in note 7.

Consolidated statement of comprehensive income

		Years ended 31 December
	Notes	2011 £m	2010 £m
Profit for the year		464.6	188.4
Actuarial losses on defined benefit pension scheme		(3.7)	(6.2)
Deferred tax on actuarial losses on defined benefit pension scheme	5	0.9	1.7
Fair value gains/(losses) on cash flow hedges		2.6	(232.6)
Deferred tax on cash flow hedges before corporation tax rate change	5	(0.7)	65.1
Impact of corporation tax rate change on deferred tax on cash flow hedges	5	1.9	0.6
Other comprehensive income/(expense)		1.0	(171.4)
Total comprehensive income for the year attributable to equity holders		465.6	17.0

Consolidated balance sheet

		As at 31 December
	Notes	2011 £m	2010 £m
Assets
Non-current assets
Intangible assets - goodwill		10.7	10.7
Property, plant and equipment		1,195.7	1,184.2
Derivative financial instruments		11.0	25.8
		1,217.4	1,220.7
Current assets
Inventories		137.6	116.6
ROC assets		32.1	33.1
Trade and other receivables		269.3	233.0
Derivative financial instruments		120.6	112.6
Short-term investments		30.0	95.0
Cash and cash equivalents		202.8	236.0
		792.4	826.3
Liabilities
Current liabilities
Trade and other payables		292.8	285.0
Current tax liabilities		33.8	189.7
Borrowings		7.1	61.7
Derivative financial instruments		95.6	197.9
		429.3	734.3
Net current assets		363.1	92.0
Non-current liabilities
Borrowings		0.5	65.3
Derivative financial instruments		5.3	1.5
Provisions		30.5	6.4
Deferred tax liabilities		203.8	244.2
Retirement benefit obligations		37.0	37.3
		277.1	354.7
Net assets		1,303.4	958.0
Shareholders' equity
Issued equity		42.1	42.1
Capital redemption reserve		1.5	1.5
Share premium		420.7	420.7
Merger reserve		710.8	710.8
Hedge reserve		63.3	59.5
Retained profits/(accumulated losses)		65.0	(276.6)
Total shareholders' equity		1,303.4	958.0

Consolidated statement of changes in equity

	Issued equity £m	Capital redemption reserve £m	Share premium £m	Merger reserve £m	Hedge reserve £m	Retained profits/ (accumulated losses) £m	Total £m
At 1 January 2010	42.1	1.5	420.7	710.8	226.4	(376.8)	1,024.7
Profit for the year	-	-	-	-	-	188.4	188.4
Other comprehensive expense	-	-	-	-	(166.9)	(4.5)	(171.4)
Total comprehensive (expense)/income for the year	-	-	-	-	(166.9)	183.9	17.0
Equity dividends paid (note 6)	-	-	-	-	-	(86.5)	(86.5)
Movement in equity associated with share-based payments	-	-	-	-	-	2.8	2.8
At 1 January 2011	42.1	1.5	420.7	710.8	59.5	(276.6)	958.0
Profit for the year	-	-	-	-	-	464.6	464.6
Other comprehensive income/(expense)	-	-	-	-	3.8	(2.8)	1.0
Total comprehensive income for the year	-	-	-	-	3.8	461.8	465.6
Equity dividends paid (note 6)	-	-	-	-	-	(123.7)	(123.7)
Movement in equity associated with share-based payments	-	-	-	-	-	3.5	3.5
At 31 December 2011	42.1	1.5	420.7	710.8	63.3	65.0	1,303.4

Consolidated cash flow statement

		Years ended 31 December
	Notes	2011 £m	2010 £m
Cash generated from operations	8	281.9	484.7
Income taxes paid		(67.7)	(56.1)
Other gains		0.7	2.0
Interest paid		(18.9)	(23.0)
Interest received		2.5	3.5
Net cash from operating activities		198.5	411.1
Cash flows from investing activities
Purchases of property, plant and equipment		(43.8)	(62.3)
Short-term investments		65.0	(40.0)
Net cash generated from/(used in) investing activities		21.2	(102.3)
Cash flows from financing activities
Equity dividends paid	6	(123.7)	(86.5)
Repayment of borrowings		(135.4)	(65.2)
New borrowings		10.0	-
Other financing costs paid		(3.8)	(1.5)
Net cash used in financing activities		(252.9)	(153.2)
Net (decrease)/increase in cash and cash equivalents		(33.2)	155.6
Cash and cash equivalents at 1 January		236.0	80.4
Cash and cash equivalents at 31 December		202.8	236.0

Notes to the consolidated financial statements

1. General information

The consolidated financial information for Drax Group plc (the "Company") and its subsidiaries (together "the Group") set out in this preliminary announcement has been derived from the audited consolidated financial statements of the Group for the year ended 31 December 2011 (the "financial statements").  

This preliminary announcement does not constitute the full financial statements prepared in accordance with International Financial Reporting Standards ("IFRSs"). The financial statements were approved by the Board of directors on 20 February 2012. Statutory accounts for 2010 have been delivered to the Registrar of Companies and those for 2011 will be delivered in due course.

The report of the auditors on the financial statements was unqualified, did not draw attention to any matters by way of emphasis without qualifying their report, and did not contain a statement under Section 498 (2) or (3) of the Companies Act 2006 or equivalent preceding legislation.

2. Basis of preparation

The financial statements have been prepared in accordance with IFRSs adopted by the European Union and therefore the consolidated financial statements comply with Article 4 of the EU IAS Regulations.

The financial statements have been prepared on a going concern basis, and on the historical cost basis, except for certain financial assets and liabilities that have been measured at fair value.

3. Summary of significant accounting policies

The principal accounting policies adopted in the preparation of these financial statements are set in the 2011 Annual report and accounts. These policies have been consistently applied to both years presented, unless otherwise stated.

4. Segmental reporting

Information reported to the Board and for the purposes of assessing performance and making investment decisions is organised into two operating segments. The Group's operating segments under IFRS 8 are as follows:

Generation - The generation of electricity at Drax Power Station.

Retail - The supply of electricity to retail customers in the small and medium enterprise and industrial and commercial markets.

The measure of profit or loss for each reportable segment, presented to the Board on a regular basis is EBITDA. Assets and working capital are monitored on a Group basis, with no separate disclosure of asset by segment made in the management accounts, and hence no separate asset disclosure is provided here.

Segment revenues and results

The following is an analysis of the Group's results by reporting segment for the year ended 31 December 2011:

	Year ended 31 December 2011
	Generation £m	Retail £m	Eliminations £m	Consolidated £m
Revenue
External sales	1,560.4	275.5	-	1,835.9
Inter-segment sales	174.8	-	(174.8)	-
Total revenue	1,735.2	275.5	(174.8)	1,835.9
Result
Segment EBITDA	336.1	(2.5)	-	333.6
Central costs
Depreciation, amortisation and loss on disposal of property, plant and equipment				(57.2)
Unrealised gains on derivative contracts				89.8
Operating profit				366.2
Net finance costs				(28.1)
Profit before tax				338.1

The following is an analysis of the Group's results by reporting segment for the year ended 31 December 2010:

	Year ended 31 December 2010
	Generation £m	Retail £m	Eliminations £m	Consolidated £m
Revenue
External sales	1,524.1	124.3	-	1,648.4
Inter-segment sales	71.9	-	(71.9)	-
Total revenue	1,596.0	124.3	(71.9)	1,648.4
Result
Segment EBITDA	393.4	(1.5)	-	391.9
Central costs
Depreciation, amortisation and loss on disposal of property, plant and equipment				(52.2)
Unrealised losses on derivative contracts				(60.5)
Operating profit				279.2
Net finance costs				(24.3)
Profit before tax				254.9

The accounting policies of the reportable segments are the same as the Group's accounting policies. All revenue and results arise from operations within Great Britain, therefore no separate geographical segments are reported. The revenue and results of both segments are subject to seasonality as detailed in the Operational and financial performance review - Seasonality of borrowing.

Major customers

Total revenue for the year ended 31 December 2011 includes amounts of £482.4 million and £228.5 million (2010: £307.0 million, £295.6 million and £159.1 million) derived from two customers (2010: three customers), each representing 10% or more of the Group's revenue for the year. All of these revenues arose in the generation segment.

5. Taxation

The income tax expense reflects the estimated effective tax rate on profit before tax for the Group for the year ended 31 December 2011 and the movement in the deferred tax balance in the year, so far as it relates to items recognised in the income statement.

Exceptional items

Under the Group's previous financing structure, Drax Holdings Limited (a subsidiary company) was partially funded by a Eurobond payable to another group company. This Eurobond debt structure was unwound in 2008, potentially accelerating additional tax losses with a cash tax benefit of up to £220 million. Because of the risks related to the unwinding of the Eurobond structure, no benefit was recognised in the Group's financial statements prior to agreement with HMRC.

On 5 April 2011, we reached agreement with HMRC, resulting in the resolution of the Eurobond tax position and certain smaller legacy tax matters. Accordingly, we have recognised an exceptional tax credit of £197.9 million in the income statement. This includes a current tax credit of £149.5 million and a deferred tax credit of £48.4 million.

Changes in the rate of corporation tax

Following the announcement of the 2011 Budget, the Finance Act 2011 (the "Act") was enacted by Parliament in July 2011. The Act confirmed reductions in the rate of corporation tax from 27% to 26% from April 2011, and from 26% to 25% from April 2012, both of which were enacted during the year. In addition, in the 2011 budget, the Government proposed further reductions in the rate of corporation tax from 25% to 23% by 2014. These proposals had not been substantively enacted at the balance sheet date. It is currently expected that each future Finance Bill will reduce the corporation tax rate by 1% until the rate of 23% is effective.

	Years ended 31 December
	2011 £m	2010 £m
Tax (credit)/charge comprises:
Current tax before exceptional items	61.3	88.5
Deferred tax before exceptional items:
- Before impact of corporation tax rate change	26.2	(14.4)
- Impact of corporation tax rate change	(16.1)	(7.6)
Tax charge before exceptional items	71.4	66.5
Exceptional items:
- Current tax	(149.5)	-
- Deferred tax	(48.4)	-
Exceptional items	(197.9)	-
Total tax (credit)/charge	(126.5)	66.5

	Years ended 31 December
	2011 £m	2010 £m
Tax on items (credited)/charged to other comprehensive income:
Deferred tax on actuarial losses on defined benefit pension scheme	(0.9)	(1.7)
Deferred tax on cash flow hedges	0.7	(65.1)
Impact of corporation tax rate change on deferred tax on cash flow hedges	(1.9)	(0.6)
	(2.1)	(67.4)

The tax differs from the standard rate of corporation tax in the UK of 26.5% (2010: 28%). The differences are explained below:

	Years ended 31 December
	2011 £m	2010 £m
Profit before tax	338.1	254.9
Profit before tax multiplied by the rate of corporation tax in the UK of 26.5% (2010: 28%)	89.6	71.4
Effects of:
Adjustments in respect of prior periods	(3.8)	(0.5)
Expenses not deductible for tax purposes	1.3	1.5
Other	0.4	1.7
Change to corporation tax rate	(16.1)	(7.6)
Total tax charge before exceptional items	71.4	66.5
Exceptional items	(197.9)	-
Total tax (credit)/charge	(126.5)	66.5

6. Dividends

	Years ended 31 December
	2011 £m	2010 £m
Amounts recognised as distributions to equity holders in the year (based on the number of shares in issue at the record date):
Interim dividend for the year ended 31 December 2011 of 16.0 pence per share paid on 14 October 2011 (2010: 14.1 pence per share paid on 15 October 2010)	58.4	51.5
Final dividend for the year ended 31 December 2010 of 17.9 pence per share paid on 13 May 2011 (2010: 9.6 pence per share paid on 14 May 2010)	65.3	35.0
	123.7	86.5

At the forthcoming Annual General Meeting the Board will recommend to shareholders that a resolution is passed to approve payment of a final dividend for the year ended 31 December 2011 of 11.8 pence per share (equivalent to approximately £43.1 million) payable on or before 11 May 2012. The final dividend has not been included as a liability as at 31 December 2011.

7. Earnings per share

Basic earnings per share is calculated by dividing the earnings attributable to ordinary shareholders by the weighted average number of ordinary shares outstanding during the year. In calculating diluted earnings per share the weighted average number of ordinary shares outstanding during the year is adjusted, when relevant, to take account of outstanding share options in relation to the Group's Approved Savings-Related Share Option Plan ("SAYE Plan") and contingently issuable shares under the Group's Executive Share Incentive Plan ("ESIP") and Bonus Matching Plan ("BMP"). The underlying earnings per share has been calculated after excluding the after tax impact of marking to market derivative contracts which are not hedged, and exceptional items.

Reconciliations of the earnings and weighted average number of shares used in the calculation are set out below:

	Years ended 31 December
	2011 £m	2010 £m
Earnings:
Earnings attributable to equity holders of the Company for the purposes of basic and diluted earnings	464.6	188.4
After tax impact of unrealised gains and losses on derivative contracts	(64.3)	44.6
Exceptional items (note 5)	(197.9)	-
Underlying earnings attributable to equity holders of the Company	202.4	233.0

	Years ended 31 December
	2011	2010
Number of shares:
Weighted average number of ordinary shares for the purposes of basic earnings per share (millions)	364.9	364.9
Effect of dilutive potential ordinary shares under share plans	2.6	0.7
Weighted average number of ordinary shares for the purposes of diluted earnings per share (millions)	367.5	365.6
Earnings per share - basic (pence)	127	52
Earnings per share - diluted (pence)	126	52
Underlying earnings per share - basic (pence)	56	64
Underlying earnings per share - diluted (pence)	55	64

 

8. Cash generated from operations

	Years ended 31 December
	2011 £m	2010 £m
Profit for the year	464.6	188.4
Adjustments for:
Interest payable and similar charges	30.3	26.5
Interest receivable	(2.2)	(2.2)
Tax (credit)/charge	(126.5)	66.5
Depreciation and loss on disposal of property, plant and equipment	57.2	52.2
Unrealised (gains)/losses on derivative contracts	(89.8)	60.5
Defined benefit pension scheme current service cost	5.4	4.3
Non-cash charge for share-based payments	3.5	2.8
Operating cash flows before movement in working capital	342.5	399.0
Changes in working capital
(Increase)/decrease in inventories	(21.0)	77.6
Increase in receivables	(36.6)	(25.4)
Increase in payables	6.4	62.5
Total (increase)/decrease in working capital	(51.2)	114.7
Decrease/(increase) in ROC assets	1.0	(21.4)
Defined benefit pension scheme contributions	(10.4)	(7.6)
Cash generated from operations	281.9	484.7

9. Reconciliation of net cash/(debt)

	Years ended 31 December
	2011 £m	2010 £m
Net cash/(debt) at 1 January	204.0	(54.4)
(Decrease)/increase in cash and cash equivalents	(33.2)	155.6
(Decrease)/increase in short-term investments	(65.0)	40.0
Decrease in borrowings	119.4	62.8
Net cash at 31 December	225.2	204.0

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.

Average achieved price

Power revenues divided by volume of net sales (includes imbalance charges).

Average capture price

Revenue derived from bilateral contracts divided by volume of net merchant sales.

Balancing Mechanism

The sub-set of the market through which the System Operator can call upon additional generation/consumption or reduce generation/consumption, through market participants' bids and offers, in order to balance the system minute by minute.

Baseload

Running 24 hours per day, seven days per week remaining permanently synchronised to the system.

Bilateral contracts

Contracts with counterparties and power exchange trades.

Company

Drax Group plc.

Dark green spread

The difference between the price available in the market for sales of electricity and the marginal cost of production (being the cost of coal and other fuels including CO₂ emissions allowances).

Direct injection co-firing

The process whereby biomass is fed directly (that is, avoiding the pulverising mills) to the burners situated in the boiler walls.

EBITDA

Profit before interest, tax, depreciation and amortisation, gains/(losses) on disposal of property, plant and equipment and unrealised gains/(losses) on derivative contracts.

EU ETS

The EU Emissions Trading Scheme is a mechanism introduced across the EU to reduce emissions of CO₂; the scheme is capable of being extended to cover all greenhouse gas emissions.

Feed-in Tariff with Contracts for Difference (FiT CfD)

A long-term contract set at a fixed level where variable payments are made to ensure the generator receives an agreed tariff (assuming they sell their electricity at the market price). The Feed-in Tariff payment would be made in addition to the generator's revenues from selling electricity in the market. The FiT CfD can be a two-way mechanism that has the potential to see generators return money to consumers if electricity prices are higher than the agreed tariff.

Forced outage

Any reduction in plant availability excluding planned outages.

Forced outage rate

The capacity which is not available due to forced outages or restrictions expressed as a percentage of the maximum theoretical capacity, less planned outage capacity.

Frequency response service

Services purchased by National Grid to maintain system frequency.

Grid charges

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

Group

Drax Group plc and its subsidiaries.

IFRSs

International Financial Reporting Standards.

LECs

Levy Exemption Certificates. Evidence of Climate Change Levy exempt electricity supplies generated from qualifying renewable sources.

Load factor

Net sent out generation as a percentage of maximum sales.

Lost time injury rate

The frequency rate is calculated on the following basis: 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.

Net Balancing Mechanism

Net volumes attributable to accepted bids and offers in the Balancing Mechanism.

Net cash/(debt)

Comprises cash and cash equivalents, short-term investments less overdrafts and borrowings net of deferred finance costs.

Net merchant sales

Net volumes attributable to bilateral contracts and power exchange trades.

Net sales

The aggregate of net merchant sales and net Balancing Mechanism.

Occupational health and safety assessment series (OHSAS)

The OHSAS specification gives requirements for an occupational health and safety management system to enable an organisation to control occupational health and safety risks and improve its performance.

Planned outage

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

Planned outage rate

The capacity not available due to planned outages expressed as a percentage of the maximum theoretical capacity.

Pond fines

Coal dust and waste coal from the cleaning and screening process which can be used for coal-fired power generation.

Power exchange trades

Power sales or purchases transacted on the APX UK power trading platform.

Power revenues

The aggregate of bilateral contracts and Balancing Mechanism income/expense.

ROCs

Renewables Obligation Certificates.

Summer

The calendar months April to September.

Technical availability

Total availability after planned and forced outages.

Through-the-mill co-firing

The process whereby biomass passes first through the pulverising mills before going to the burners situated in the boiler walls.

Total recordable injury rate (TRIR)

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

UK NAP

UK National Allocation Plan.

Underlying earnings per share

Calculated as profit attributable to equity holders, adjusted to exclude the after tax impact of unrealised gains and losses on derivative contracts, and exceptional items, divided by the weighted average number of ordinary shares outstanding during the period.

Winter

The calendar months October to March.

 

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