General commodity market conditions
Commodity market conditions were generally favourable for Drax in the first half of the year. During the third quarter, trading conditions continued to improve primarily as a consequence of low capacity reserve margins in the electricity market. However, in the last quarter we saw dark green spreads narrow and significant falls in power, coal and CO2 emissions allowances prices. These trends in forward power, coal and CO2 emissions allowances prices, are illustrated in the charts below, and described further in the following paragraphs.
Price of electricity
The table below shows the average achieved electricity price we realised for the years ended 31 December 2008 and 31 December 2007, together with the market closing price on the last day of each season illustrated.
Commodity market conditions were generally favourable for Drax in the first half of the year. During the third quarter, trading conditions continued to improve primarily as a consequence of low capacity reserve margins in the electricity market. However, in the last quarter we saw dark green spreads narrow and significant falls in power, coal and CO2 emissions allowances prices. These trends in forward power, coal and CO2 emissions allowances prices, are illustrated in the charts below, and described further in the following paragraphs.
Price of electricity
The table below shows the average achieved electricity price we realised for the years ended 31 December 2008 and 31 December 2007, together with the market closing price on the last day of each season illustrated.
| Year ended 31 December 2008 |
Year ended 31 December 2007 |
|
|---|---|---|
| Average achieved price | 58.3 | 45.3 |
| (£/MWh) | ||
| 2008 | 2007 | |
| Summer baseload market close | 55.8 | 23.0 |
| (£/MWh) | ||
| 2008/2009 | 2007/2008 | |
| Winter baseload market close | 106.9 | 40.4 |
| (£/MWh) |
Average achieved price for the year ended 31 December 2008 was
£58.3 per MWh compared to £45.3 per MWh in 2007. Average capture
price (being the price attained prior to Balancing Mechanism
activity) for the year ended 31 December 2008 was £57.4 per MWh
compared to £44.2 per MWh in 2007. The forward baseload power
prices for Summer 2009 and Winter 2009/2010 were approximately
£37.1 per MWh and £46.3 per MWh respectively as at 20 February
2009.
The increase in average achieved price primarily followed the impact of forward sales contracts secured in the last six months of 2007 and through the first six months of 2008, during which time power prices were generally increasing relative to the levels of late 2006 and early 2007, for power delivered in 2008.
Increasing power prices through the early part of 2008 followed strengthening oil and gas prices. High power prices were sustained through the third quarter, with fears that outages, Large Combustion Plant Directive (“LCPD”) constraints and delays in Flue Gas Desulphurisation (“FGD”) installations at other UK generating plant might result in a capacity shortfall.
Power price falls towards the end of the year followed weaker oil and gas prices. In addition, other plants returned to service, which allayed fears of a capacity shortfall, and peak electricity demand fell, reflecting the economic climate.
Spot prices for internationally traded coal delivered into North-West Europe (as reflected by the TFS API 2 index) increased dramatically over the second half of 2007, reaching US$127 per tonne by the end of the year. Spot prices continued to increase to record levels over the first six months of 2008, reaching US$218 per tonne by 30 June 2008. Price increases were driven by continued tight markets for both coal and freight, caused by strong demand from China, India and Japan, combined with some production and logistical issues in China, as well as South Africa and Australia. However, spot coal prices fell significantly over the final quarter, down to US$81 per tonne by 31 December 2008, as supply constraints eased in both the coal and freight markets. The fall in coal prices was partially offset by the depreciation of sterling against the US dollar through the second half of 2008.
We also burn biomass, petcoke and fuel oil, although coal comprised around 93% of total fuel costs in the year ended 31 December 2008 (excluding CO2 emissions allowances) compared to 95% in 2007, primarily as a result of improved fuel diversity. The average cost of fuel per MWh (excluding CO2 emissions allowances) was £25.1 for the year ended 31 December 2008, compared to £18.5 in 2007, with high coal prices in the first nine months of 2008 relative to the levels of last year.
Our CO2 emissions allowances requirement for the year ended 31 December 2008, in excess of those allocated under the UK NAP, was approximately 12.8 million tonnes compared to approximately 7.6 million tonnes in 2007, as a result of the lower UK NAP allocation and higher generation, partially offset by plant efficiency improvements and increased biomass burn.
The price for Phase I CO2 emissions allowances began 2007 at approximately €6.6 per tonne, and as a result of over-supply, fell steadily over the first six months to €0.13 per tonne on 30 June 2007, subsequently falling away further to €0.04 per tonne by 31 December 2007.
The price for Phase II CO2 emissions allowances began 2008 at approximately €22.4 per tonne, and in common with power and coal prices rose steadily over the first half of the year to €28.4 per tonne at 30 June 2008. However, carbon prices also fell significantly over the final quarter, down to €15.4 per tonne by 31 December 2008, as commodity prices fell back and industrial demand reduced in response to the economic climate.
As a result, the average price expensed for purchased CO2 emissions allowances during the year ended 31 December 2008 was £17.4 per tonne (equivalent to £223 million), compared to £1.5 per tonne in 2007 (equivalent to £11 million).
The increase in average achieved price primarily followed the impact of forward sales contracts secured in the last six months of 2007 and through the first six months of 2008, during which time power prices were generally increasing relative to the levels of late 2006 and early 2007, for power delivered in 2008.
Increasing power prices through the early part of 2008 followed strengthening oil and gas prices. High power prices were sustained through the third quarter, with fears that outages, Large Combustion Plant Directive (“LCPD”) constraints and delays in Flue Gas Desulphurisation (“FGD”) installations at other UK generating plant might result in a capacity shortfall.
Power price falls towards the end of the year followed weaker oil and gas prices. In addition, other plants returned to service, which allayed fears of a capacity shortfall, and peak electricity demand fell, reflecting the economic climate.
Price of coal and other fuels
We burnt approximately 9.5 million tonnes of coal in the year ended 31 December 2008 compared to approximately 9.8 million tonnes in 2007. This coal was purchased from a variety of domestic and international sources under either fixed or variable priced contracts with different maturities.Spot prices for internationally traded coal delivered into North-West Europe (as reflected by the TFS API 2 index) increased dramatically over the second half of 2007, reaching US$127 per tonne by the end of the year. Spot prices continued to increase to record levels over the first six months of 2008, reaching US$218 per tonne by 30 June 2008. Price increases were driven by continued tight markets for both coal and freight, caused by strong demand from China, India and Japan, combined with some production and logistical issues in China, as well as South Africa and Australia. However, spot coal prices fell significantly over the final quarter, down to US$81 per tonne by 31 December 2008, as supply constraints eased in both the coal and freight markets. The fall in coal prices was partially offset by the depreciation of sterling against the US dollar through the second half of 2008.
We also burn biomass, petcoke and fuel oil, although coal comprised around 93% of total fuel costs in the year ended 31 December 2008 (excluding CO2 emissions allowances) compared to 95% in 2007, primarily as a result of improved fuel diversity. The average cost of fuel per MWh (excluding CO2 emissions allowances) was £25.1 for the year ended 31 December 2008, compared to £18.5 in 2007, with high coal prices in the first nine months of 2008 relative to the levels of last year.
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, compared to 14.6 million tonnes per annum for Phase I (2005–2007).Our CO2 emissions allowances requirement for the year ended 31 December 2008, in excess of those allocated under the UK NAP, was approximately 12.8 million tonnes compared to approximately 7.6 million tonnes in 2007, as a result of the lower UK NAP allocation and higher generation, partially offset by plant efficiency improvements and increased biomass burn.
The price for Phase I CO2 emissions allowances began 2007 at approximately €6.6 per tonne, and as a result of over-supply, fell steadily over the first six months to €0.13 per tonne on 30 June 2007, subsequently falling away further to €0.04 per tonne by 31 December 2007.
The price for Phase II CO2 emissions allowances began 2008 at approximately €22.4 per tonne, and in common with power and coal prices rose steadily over the first half of the year to €28.4 per tonne at 30 June 2008. However, carbon prices also fell significantly over the final quarter, down to €15.4 per tonne by 31 December 2008, as commodity prices fell back and industrial demand reduced in response to the economic climate.
As a result, the average price expensed for purchased CO2 emissions allowances during the year ended 31 December 2008 was £17.4 per tonne (equivalent to £223 million), compared to £1.5 per tonne in 2007 (equivalent to £11 million).
Outages and plant utilisation levels
| Year ended 31 December 2008 |
Year ended 31 December 2007 |
|
|---|---|---|
| Electrical output (net sales) (TWh) | 25.4 | 24.9 |
| Load factor (%) | 76.3 | 75.0 |
| Availability (%) | 85.8 | 85.7 |
| Winter forced outage rate (%) | 6.5 | 4.2 |
| Forced outage rate (%) | 5.8 | 6.9 |
| Planned outage rate (%) | 8.9 | 8.1 |
| Total outage rate(1) (%) | 14.2 | 14.3 |
Notes:
The load factor for the year ended 31 December 2008 was 76.3% compared to 75.0% in 2007. The improvement arises from an increase in electrical output (net sales) to 25.4TWh in 2008 compared with 24.9TWh in 2007, with higher generation in 2008 in what have historically been low margin periods. Commodity market conditions through the Summer were such that it was profitable to generate these additional volumes, albeit at moderate margins.
Plant availability was approximately 86% for both years ended 31 December 2007 and 2008.
The planned outage rate achieved for the year ended 31 December 2008 was 8.9% compared to 8.1% in 2007. 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 major planned outages were completed in both 2007 and 2008.
The forced outage rate for the year ended 31 December 2008 was 5.8%, compared to 6.9% in 2007.
The Winter forced outage rate was 6.5% for the year ended 31 December 2008, compared to 4.2% in 2007.
- 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 for the year ended 31 December 2008 was 76.3% compared to 75.0% in 2007. The improvement arises from an increase in electrical output (net sales) to 25.4TWh in 2008 compared with 24.9TWh in 2007, with higher generation in 2008 in what have historically been low margin periods. Commodity market conditions through the Summer were such that it was profitable to generate these additional volumes, albeit at moderate margins.
Plant availability was approximately 86% for both years ended 31 December 2007 and 2008.
The planned outage rate achieved for the year ended 31 December 2008 was 8.9% compared to 8.1% in 2007. 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 major planned outages were completed in both 2007 and 2008.
The forced outage rate for the year ended 31 December 2008 was 5.8%, compared to 6.9% in 2007.
The Winter forced outage rate was 6.5% for the year ended 31 December 2008, compared to 4.2% in 2007.
Health and safety
Our lost time injury rate was 0.10 for the year ended 31 December 2008 compared to 0.34 in 2007. This continues to demonstrate that the safety programmes implemented in the last few years are becoming well entrenched and are delivering sound performance. Our safety record compares favourably with our sector peers and international benchmarks.
Attaining leading performance in health and safety
Our safety record continues to compare favourably with that of our sector peers and international benchmarks. Safety programmes are now becoming well entrenched and we are seeing the results through sound performance.