Emissions regulations are reshaping the U.K. and Irish energy markets.
As U.S. policymakers consider how to tackle the challenge of greenhouse-gas constraints, the U.K.’s approach to the problem offers instructive examples.
EU leaders agreed to reduce combined CO2 emissions to 8 percent below 1990 levels by 2012. The U.K. is one of very few countries intending to exceed its Kyoto target of a 12.5 percent reduction in CO2 emissions below 1990 levels. The U.K. National Allocation Plan (NAP) for Phase II (2008-2012) expects to achieve a reduction of 23.6 percent. The European Commission accepted this Phase II NAP without amendment.
The British government has allocated free emissions credits to all sectors in the U.K., based on a business-as-usual scenario (BAU)—with one exception. Large electricity producers (LEPs) received an allocation 30.3 percent below a BAU scenario. A number of LEPs are considered to be good-quality combined heat and power (CHP) facilities, and will receive a full allocation for the CHP portion of their output. But the CO2 allocations given to large electricity producers (LEPs) will not be sufficient to cover the emitted quantities. The LEPs will need to purchase extra allowances.
More broadly, retirements and restrictions on coal-plant generation will cause resource-adequacy concerns in the region, raising the need for generating capacity additions by 2010. The U.K. will not be able to meet its renewables target. Gas-fired generation is expected to be the major source of power in the future Great Britain Energy Market (GBEM) resource mix, with clean coal and nuclear also contributing to fuel diversity.
Off-peak market prices likely will increase as a consequence of more expensive gas-fired generation setting the market prices during the off-peak hours with the retirement of major baseload generation. Volatility in power prices caused by variations in load and natural-gas prices is a key risk to be examined in integrated resource-planning activity.
In Great Britain, 34 percent of the total installed capacity is coal-fired, and approximately 30 percent of the total generation is met by coal. Going forward in the study period, the ratio of generation/installed capacity declines dramatically as the operation of most of the existing coal stations is constrained by the emission limits imposed by the Large Plant Construction Directive (LCPD).
Nevertheless, coal will remain an important source of fuel for electricity generation in the GBEM market. Coal’s share in total generation falls to an average of 26 percent during the years with LCPD operation restrictions, in 2008 and 2015. The share of coal generation likely will increase and stay around 30 percent between 2016 and 2020 as new clean-coal plants come on line to replace some of the 2015 retired capacity. The share declines to an average of 24 percent during the remaining years of the study period (see Figure 2).
With the expected retirement of the existing coal fleet, new baseload generation must be built, and more than 5 GW of new coal plants already have been proposed. The U.K. government is investigating clean-coal technologies, and discussing providing subsidies for the pilot carbon capture and storage (CCS) projects at Hatfield Colliery and Peterhead IGCC.
As coal faces rising constraints, other energy sources will become more important in U.K. electricity markets. Gas-fired generation will rise from its current levels (34 percent) to around 45 percent by the end of the study period. New peaking plants likely will be using natural gas rather than gasoil, contributing to increased gas-fired generation.
Also, Global Energy has simulated a high renewables case where enough capacity to meet the renewables targets is assumed to be built (see Figure 3). Generation from renewables is expected to constitute 7.4 percent of total U.K. generation by 2010 and 14.2 percent by 2020. Renewables includes the categories wind, biomass, co-generation, landfill gas, sewage gas, hydro, and other.
Similarly, in the All Island Electricity Market (Ireland) gas, coal, and renewables will continue to be the main sources of generation. A new coal plant with CCS likely will be built in the Republic of Ireland (RoI) after 2020 to reduce the dependence on gas. Figure 4 exhibits the reference case’s generation forecast for the AIEM.
Forecasts of generation from renewables in the RoI put it at 14.6 percent of total generation in 2010, which is in line with the Irish government’s renewables target. By 2020, the renewables share is 23.7 percent, short of the 30-percent target (see Figure 5).
The GBEM has witnessed substantial activity over the last two years, due mainly to the introduction of the Emission Trading Scheme (ETS) in 2005, volatile natural-gas prices, and increasingly frequent cold snaps and heat waves.
Under the ETS, generation companies now factor the CO2 allowance cost into generation costs for electricity production, causing a rise in the price of wholesale electricity. Relatively low gas prices and increased coal prices due to high CO2 costs have reduced the margin between coal and gas prices, making generation from coal and gas very competitive during much of 2005 (see Figure 1).
The U.K.’s CO2 emission volumes likely will rise between the years 2015 and 2020 (see Figure 6). The retiring nuclear fleet in the GBEM, which was carbon free, will be replaced by gas and coal generation emitting higher CO2 volumes. This effect is magnified because new coal plants, assumed to replace the ones that have retired as a consequence of the LCPD, have flue-gas desulfurization (FGD) equipment and thus acid-gas emissions limits do not limit their running hours.
According to the U.K. NAP for Phase 2, LEPs will be allocated 107.42 metric tons CO2e per annum. from 2008 to 2012. Given the results of the reference case, LEPs will be short of carbon allowances (see Figure 7).
NBP prices and CO2 allowance prices have been the two main drivers in Great Britain during the years 2005 and 2006. This is expected to continue as coal and gas will remain the fuels at the margin, with gas-fired generation increasing its share in the medium to long term. Going forward, new market drivers such as emission-reduction targets are expected to make the future GBEM uncertain. The study reference case and scenario forecasts attempt to quantify this uncertainty.
The average wholesale electricity market price in GBEM was 36 £/MWh in 2005 and 38 £/MWh in 2006. In 2006, the system had supply problems mainly due to nuclear outages and a combination of other outages and unusual weather conditions that caused the general increase in prices (e.g., a heat wave in July 2006).
Similar forces will drive prices in the future. In Great Britain, 15.5 GW of base load and 3.3 GW of peak capacity will be retired by the end of 2015. This is equivalent to 23 percent of total installed capacity in the GBEM. Perhaps more alarming is the nature of generation being retired—nuclear and coal. By 2015, 6.5 GW of nuclear capacity, which is one of the most secure and cheap generation sources today, will disappear. A further 9 GW of coal generation will be forced to close down due to environmental restrictions introduced by the LCPD.
Furthermore, the U.K. will need more peaking capacity than ever with increasing renewable capacity. About 6.5 GW of installed windpower capacity by 2015 will necessitate peak-power supply to balance its volatility. According to our forecast, 1.8 GW of peak capacity will be needed by 2015, 5.2 GW by 2018, and 7.7 GW by the end of the study period.
Currently, no new peaking plants are proposed in the GBEM. Consequently, the system is expected to get really tight in 2015, with average on-peak prices reaching over £86/MWh during winter peak hours.
Peak-power prices on average will rise by about 33 percent from 2008 to 2011 compared with 2007 prices. Average peak prices increase to £42/MWh between the years 2012 to 2018. For the balance of the forecast, 2018 through 2031, on-peak prices increase driven mainly by the rising natural-gas price forecast.
Additions and Subtractions
In Great Britain, Glendoe hydro station (100 MW), Marchwood combined-cycle gas plant (850 MW), and approximately 1.3 GW of wind generation is under construction. These additions will not be sufficient to replace the retiring fleet and restore healthy reserve margins. On the other hand, new power-plant project announcements indicate leading players are preparing to build new power stations in Great Britain.
Currently, 12.5 GW worth of new gas-fired plant projects and around 4 GW of new coal-fired plant projects have been announced. Recently, Scottish Power announced its plans to convert Longannet and Cockenzie to clean-coal technology, which is equivalent to an additional 6 GW of new coal-fired generation.
Most announced projects are in the pre-proposal stage, and the sponsors’ date announcements likely will prove to be optimistic. Realistically, however, around 2.5 GW of the capacity announced will be built by 2015. A further 12 GW of renewable energy is forecasted to come on line in Great Britain by 2015.
These capacity additions in the short term will be sufficient in terms of megawatts to maintain reserve margin levels of around 20 percent. The longer-term outlook is more pessimistic—particularly if nuclear-plant retirements proceed as planned.
Approximately 20 percent of total generation in the GBEM is met by nuclear plants. Installed nuclear capacity in Great Britain totals 11.5 GW— 14 percent of the country’s total capacity. Around 6.5 GW of Great Britain’s nuclear capacity is scheduled to retire between 2008 and 2015 and another 1.1 GW by 2020, reducing the total installed nuclear capacity in the GBEM by almost two-thirds, to 3.9 GW.
As in the United States, a growing consensus among U.K. industry players and the current government encourages the construction of new nuclear plants to replace the retiring fleet and provide zero-carbon generating capacity. And also like the United States, private investors are nervous about committing to nuclear construction in the absence of clear government support.
The future of nuclear power represents a pivotal variable affecting long-term supply security in the U.K. and the United States. And as carbon constraints intensify, gas demand rises and reserve margins shrink, volatility in power prices will become a major risk affecting resource-planning activities on both sides of the Atlantic Ocean.