Future UK Coal & CCS Options Workshop

The UKCCSRC is supported by the Engineering and Physical Sciences Research Council as part of the Research Councils UK Energy Programme

Future UK Coal & CCS Options Workshop Thursday 7 February 2013 at the University of Edinburgh St Trinnean’s Meeting Room, St Leonards Hall, 18 Holyrood Park Road, EH16 5AY

Notes taken by Claire Bastin, University of Leeds1

KEY QUESTIONS a) Will the UK want to build coal plants in the future? (For power, but also chemicals and perhaps SNG too) b) What forms would these coal plants take? (Full CCS from the start, partial CCS, CCS ready?) This will be considered by application and also new build or retrofit including conversion of existing and future gas plants to coal). When will there be a place for underground coal gasification? c) What locations could be used? Cooling, coal delivery, CO2 transport, public acceptance, grid connections etc. d) What capacity are we likely to need to be able to do this? (Know‐how, people, facilities, industry capability, etc.) e) What is needed to keep sites etc. available ‐ a coal + CCS‐ready strategy for UK infrastructure? g) How extensively will biomass be used in new coal plants or in new plants, with CCS? h) What R&D is needed (specifically related to coal) and is this underway?”

1 http://www.see.leeds.ac.uk/people/c.bastin

Workshop notes

Speakers

Opening/Introduction

Mike Farley welcomed attendees. Mike Farley

Context for workshop:  John Hayes MP, UK Energy Minister speaking at WCA meeting ‘putting the coal in coalition’ statement.  Head of Electricity Market Reform and head of OCCS, reiterate thoughts that coal (with CCS) likely to be on the increase in UK electricity production and other industry, and, especially, worldwide.  Coal use stats in brief ~forecast 40‐50% of electricity generated (ref?)

Key questions for the day introduced: a) Will the UK want to build coal plants in the future? (For power, but also chemicals and perhaps SNG too) b) What forms would these coal plants take? (Full CCS from the start, partial CCS, CCS ready?) This will be considered by application and also new build or retrofit including conversion of existing and future gas plants to coal). When will there be a place for underground coal gasification? c) What locations could be used? Cooling, coal delivery, CO2 transport, public acceptance, grid connections etc. d) What capacity are we likely to need to be able to do this? (Know‐how, people, facilities, industry capability, etc.) e) What is needed to keep sites etc. available ‐ a coal + CCS‐ready strategy for UK infrastructure? g) How extensively will biomass be used in new coal plants or in new plants, with CCS? h) What R+D is needed (specifically related to coal) and is this underway?”

Introductions from panel and delegates. Notes on Chatham House rules, i.e. no attributable minutes, but questions addressed and themes developed will be recorded and a report to DECC produced by the chair, Mike Farley.

COAL USAGE

Current uses of coal in UK power and industry. Quantities and locations. Nigel Yaxley Sources of coal, main transport routes. Prices of coal, at point of use. Contributions to make‐up of price (mining, shipping, in‐country transport) Projections on use and price (vs gas) and reserves (by region)

Presentation:

 Coal is fastest growing energy source (BP Statistical Review 2012) worldwide  Coal’s share of energy production ~40%.  Map of coal import/exports shows significant volumes from Australia and Indonesia to China.  For UK, flexibility in coal use volumes comes from flexibility in import arrangements rather than coal production in UK.  Cost of UK coal production and transport (inc e.g. UK Sea Freight Mark‐up), together with distressed coal prices from US (increase in shale gas ‐> lower gas price and increase demand for gas, reduced demand for US coal in US ‐> lower export price) makes it non‐competitive.  International Energy Agency (IEA) outlook (Nov 2012): New policy scenario expects inclusion of climate change mitigation measures e.g. CCS rather than business as usual projections (BAU). May be unrealistically optimistic with regards to CC mitigation measures.  DECC projection on coal use suggests decline in use of coal as feedstock to 2030, with difference in output absorbed by increase in renewables and natural gas.  Reserves: UK reserves in UK 20+ years, resources 100+ years, but unlikely to be exploited. World: Gas 60 yrs reserves/90 years resources. Coal – 114 yrs reserves/2000 yrs resources. NB: political and contested definitions for resources.

Current and future industrial uses of coal ‐ China experience Andrew Minchener

Presentation:

 Global coal consumption rising dramatically especially in China and Asia Pacific. World/China consumption (approx. Mt): 1990:4695/1050 2000:4817/1500 2011: 7792/3700. China’s coal use has more than doubled in the period and accounts for much of the increase in world consumption (Buraya 2012 cited).  Growth also in renewables, but less so than coal. Diversity in energy production but coal use has fuelled China’s economic growth.  China’s coal use: largest % (55) for power, also used for iron and steel, cement production, coal to chemicals e.g. synthetic fuels. Very small % export (0.3%). More ‘spread and diversity’ in uses for coal than typically found in C21st OECD countries.  New plant approval requires 600MW minimum and new environmental controls. Smaller, older plants still form large part of stock, but plan is to remove these.  China’s strategic plan is to focus on technologies which remove GHG and non‐GHG. 2014 emission standards to be introduced to limit mercury, particulates, NOx, SO2  Operational and design phase CFBC & IGCC projects discussed. Timescales from project concept to operational typically 12‐18 months (e.g. IGCC Greengen plant, ). Policy and governance context allows for speedy operationalization.

 Options for CO2 utilisation being explored in e.g. food and beverage market.  Forecast of coal use suggests continued increase to plateau circa. 2030. CCS (or CCU&S) required for emissions to decline.  Summary: China can move quickly in development of coal + CCS projects. Increasingly taking leadership role.

Coal to Liquids, SNG Paul Lawrence

Presentation:

 Proven coal reserves.  Industrial and commercial uses for coal other than for power generation: Coal to liquid & SNG – ‘substitute’ (i.e. rather than synthetic) natural gas  CTL: political, business and economic drivers for CTL especially where coal infrastructure exists  Review of technologies and markets for CTL presented suggests China, Mongolia, USA, Poland (i.. with high coal production and/or infrastructure and use) likely markets for CTL  Barriers include: economic uncertainty, regulatory uncertainty, lack of skills in CTL. EPC – 2‐3 times increase/uncertainty in costs. Long (and relatively untested) project development schedules means uncertainty exacerbated.  Advantages include: tested technology, alternative to crude, can be upgraded to jet/diesel. For coal producing nations, increased energy security.  SNG: Clean (def required) fuel suitable for home use, compatible with natural gas in emissions. Provides opps to monetise otherwise stranded energy (shale gas, biomass, coal bed methane(CBM))  Operating plant – Great Plains, North Dakota, USA.  Discussion on whether CTL/SNG makes economic sense at scale. Very high capital costs and poor/untested ROC.

Why coal is an attractive fuel for a new power plant Steven Marshall

Total specific CO2 emissions for each use (cf natural gas, LNG, shale gas, shale gas+LNG, and gas to liquids) Relative costs (eg per tonne of steel, cement, or MWH of clean electricity) for alternative fuels.

Clean Coal Energy Project: (Partnership ‐ Petrofac, Summit Power, Caledonian Clean Energy)

Presentation:

 Under existing conditions, fossil fuels are required to supply base load energy in UK (and other OECD)

 For UK, coal good option (rather than gas) as security of supply, and relative price stability i.e. when compared

with gas. Gas process are volatile and rising (see slide index linked to 1987)

 To meet CO2 reductions and NOx, SOx legislation, need to have CCS and CO2 abatement technologies in place to continue to use coal.  Two critical points: costs and commercial viability not proven. BAT (IGCC, CCEL) not proven.

Social importance of coal mining, power, heavy industry Philip Pearson Presentation:

 TUC involved in working with Trades Unions in other EU nations e.g. Poland where greater climate scepticism exists.  Coal with CCS projects and opportunities often in former coal mining communities with high levels of deprivation and unemployment.

 Example of Yorkshire & Humber CCS cluster‐ CO2Sense report on economic and commercial viability of project.  CCS offers potential for constructions jobs as well as benefits to the supply chain.  Policy uncertainly makes it difficult to encourage private sector investment (current government does not understand CCS + coal infrastructure).  Energy Intensive Users Group in TUC together with Centre for Low Carbon Futures identified benefits of including investment in EI industry to foster moves towards green economy. Report is available at http://www.tuc.org.uk/tucfiles/52/EIITechnologyInnovation.pdf. Also, clean coal task group produced roadmap available at tuc.org.uk/industrial  Barriers to coal + CCS adoption: lack political leadership, social acceptance, political uncertainty – e.g. industrial policy and energy policy are not in agreement, jobs and skills

Questions/discussion: PANEL: Nigel Yaxley, Andrew Minchener, Paul Lawrence, Steven Q1: Carbon price and tax will ‘kill the patient’ before it happens i.e. will ruin chances for adoption/reduce funding Marshal, Philip Pearson options. Many others in the room supported this view.

R1: Fossil fuel with carbon capture not seen as a low carbon energy option. If it is to be considered as a low carbon option, then should have ‘equal footing’ in policy, governance and funding terms.

R2: Need to establish whether the future for coal is recognised by government.

Currently there is a disconnect even within government departments [CB adds, as noted by PP/TUC]

Q2: (comment) The UK target for renewables (15% by 2020) is a key determining factor for government policy and so future for coal and CCS in some ways dependent on/limited by this.

R1: Agreed. Two issues (i) relationship between EU & UK in terms of establishing targets across Europe (ii) biomass might be a stepping stone/stop gap for coal by keeping existing infrastructure in use whilst technology under development. (NB: comments on environmental cost of shipping biomass). Prospects for UK coal not seen as positive in this light.

R2: Coal is cost competitive and with CCS potentially CO2 competitive too, plus there are other economic benefits (EOR, CTL, SNG) so why isn’t it considered as a viable or comparable option with renewables/gas/nuclear?

Q3: With price competition, isn’t it the case that coal is likely to remain cheaper and more stable than gas?

R1(i): Gas is twice as expensive as coal: gas 2.088 ppkwh coal 0.906 ppkwh at international prices. Forecasts suggest gap widens over time: gas 2.452ppkwh coal 1.066 ppkwh. These prices (from Mott MacDonald) do not include forecasts for price differences with inclusion of carbon tax.

R2(i): What matters is marginal costs: £45/mwh for average CCGT, £25/mwh for average CF power station. Even with carbon price support, this cost benefit applies to 2017 (in coming carbon tax) but not known beyond.

R1(ii): Side issue – not talking about indigenous coal.

R2(ii): There’s a catch 22 situation ‐ bias towards gas leading to policy/investment decisions based on gas even though this might not be best long term solution.

R1(iii): If not considering increase in use of domestic coal, then more than cost of refurb of power station under discussion, also transport, mining, infrastructure.

Comment: Scottish Parliament is ‘at least’ discussing these issues and has added coal and LT potential for CCS to the energy agenda with extended debate on future of coal in Holyrood in January 2013.

[CB addition: Neil Findley MSP for example links employment opportunities and responsible mining to future fuel use. Links also potential for CCS and ‘shambles’ of UK developments on coal with CCS to date http://www.youtube.com/watch?v=kWHyzRqfCi8 and others].

NETWORKING LUNCH

Future Coal Power plants

Presentation: Possible generation mix including Coal Jeremy Carey, SSE

Ref to gridwatch.templar.org

 Wind not appropriate for base load provision required to meet UK demand, even when 4 * current capacity with improved storage facilities (see slide 3 graph)  Based on Mott MacDonald report to CCC 2011 (NB: CB post script – report critiqued for underestimating costs of nuclear, Imperial College 2011, CES 2011)  Post combustion CCGT competitive with IGCC. Nuclear costs unknown  Emissions legislation, CAPital EXpenditure, fossil fuel load, carbon price, public perception and other governance factors combine to make CCGC (prima facie) more favoured than Coal with CCS for mid‐range load  JC propose coal as alternative for base‐load as alternative to nuclear: (i) public perception poor for both (ii) escalation of CAPEX expected for both (iii) gasification of coal options positive as leg re coal fired power generation then not applicable so fewer regulatory unknowns  Future of coal for power generation could be at mine/port side coal to gas options.

Presentation: Modelling of coal in the mix Dennis Gammer, ETI

 Energy System Modelling Environment (ESME) model is a national energy system design tool with sufficient detail to understand system engineering challenges  Adopts least cost optimisation options for modelling to 2050 targets  Probabilistic (CB note: assuming time series, MVA) treatment of uncertainties  Does not account for policy options e.g. no nuclear  Model suggests nuclear least cost option to 2050, unless nuclear not supported then coal with CCS has greater influence in mix

PANEL: Jeremy Carey, Dennis Gammer

Comment 1: Tendency/argument for coal to be applicable for base‐load with gas to supply demand for flexible

Discussion re coal v gas or coal with gas, v nuclear with gas.

Q1: Does the ESME model suggest any significant difference between costs for these two scenarios? i.e. WRT to CAPEX or once policy costs/CAPEX costs removed/levelled

R1: CCS seen as more costly option, hence nuclear favoured in ‘Director’s cut’ least cost optimisation model.

Comment 1: But model depends on DECC figures on coal/gas prices and uncertain costs of nuclear all of which have been questioned.

Q2: Is this in relation to just CCS with coal, or CCS with gas too?

R2: Both but assuming CAPEX higher for CCS with coal

Q3: Is gas more flexible: R3: No and CCS developments must not be seen to reduce flexibility of coal.

Discussion, key points:

 Political and economic questions over e.g. price of wind energy (i.e. not necessarily forecast to fall as expected when 15% renewable targets set).  EMR – not fully understood; subsidy regime complex, electricity price variability, 1st strike price by end 2013  Treasury has agreed £7.6bn to ‘green energy’ from 2020 on top of carbon price support; delivery plan for this suggests funding will not be split between options, but will focussed on cheapest/most likely delivery option (comment: if no viable CCS with coal demonstration projects then funding will likely go to nuclear/renewables)  Future for coal, 3 options: baseload, mid merit energy, off shoots (products, inc syngas, hydrogen, CTL)  CAPEX high so whether mid/baseload options works depends on contracts for difference (CfD) mechanism

Technologies and BAT/standards

Presentation: Technologies available for coal power plant (up to 2025 and beyond) Kirsten Foy, Parsons Brinckerhoff Other technologies inc coal gasification retrofits to CCGTs and UGC

 KF presented technology options for coal  Supercritical and ultra‐supercritical – state of the art power generation up to 55% net efficiency (without CCS). 55% is future expected efficiency

 Circulating fluidised bed  IGCC  Underground coal gasification, CCGT  Emissions control: EST, SCR, FGD (for particulates, NOx SOx removal).  NB: for post combustion removal of carbonates need one CCS per plant regardless of size of plant. For new

need one per 300MW. No regs/guidance on type, size, capture rates in UK as yet, except for emissions limits

which mean roughly half of emissions must be treated from coal and no treatment required for gas.

 Options and retrofit options discussed. Questions re viability of supercritical and better efficiency likelihoods.

 Retrofit to be carbon capture ready would require: Enough space at CCGT site to include coal import and gasification, syngas cleaning including capture plant and balance of plant Design of CCGT to allow for switchover to gasification/integrated gasification  Some retrofits may legally be considered as new builds and so subject to min 300MW regs. E.g. Kingsnorth – no economic benefit for CCS refit  Underground options on gasification plants e.g. at Teesside more viable as above ground options use too much space for existing locations and infrastructure.

Comment: Cost uncertainties mean no ‘clear winner’ Discussion: Improvements in existing technology could improve efficiency by ~10% (ref required) rather than need for ‘new’ technology. CCSa.org – task force for cost reduction important feature of CCS adoption

Andrew Botting, SEPA

Presentation: BAT/Standards required (CO2, H2O, Hg, other emissions to air, water, waste) for each of above

NB: SEPA only regulates the carbon capture plant. Other agencies are responsible for CO2 transport issues (HSE) and CO2 storage (DECC). These aspects are equally complex but are separate issues.

• IED implemented in Scotland from January 2013

• Site specific BATs for all emissions (water, air, waste)

• CO2 capture & storage regulation:

Capture of CO2 for geological storage is a prescribed Part A activity under the 2012 PPC Regulations.

PPC permit required (in combination with combustion plant). No regulation of CO2 emissions but the capture plant is subject to BAT controls (containment, noise etc). CO2 emissions regulated by the EPS (imposed via secondary regulations to the Energy Bill).

Requirements of CO2 Geological Storage Directive (GSD) (plus) implemented by supporting guidance to 1989 Electricity Act Section 36 requirements (planning permission). SEPA is responsible for providing advice to the Scottish Government on such applications in relation to carbon capture readiness and the feasibility of capture technology (for coal fired plant).

PANEL:

Discussion: Who pays? Burners, power generators, gasifiers? Unknown. Project specific. Network approach e.g. White Rose Project might help internalise externalities and unknowns. But then not taken forward.

Comment: Electricity price is not an issue as the marginal price for gas coal does not differ.

Comment: Again key point is that uncertainty (especially re gas price, regulatory framework, emissions, fiscal, taxes, investment, BAT) makes it difficult to forecast future for coal use.

Discussion: Contracts for difference. Options for negotiation on strike price. 2 formats: Technology specific auctions for wind, CCS, nuclear and technology neutral auctions dependant on strike price.

Q1: What is considered capture ready and how does policy view this.

R1: There is clear and detailed guidance available on the requirements to demonstrate CCR for each main CCS technologies.

NB: SEPA reg consideration for emissions, transport (HSE) and storage (DECC) are equally complex but separate issues.

 IED implemented in Scotland from January 2013  Site specific BATs for all emissions (water, air, waste)  Imposed through Energy Bill  Run through main features of legs

 CO2 capture & storage regulation: ‘Capture of CO2 for geological storage is a prescribed Part A activity under the 2012 PPC Regulations. PPC permit required (in combination with combustion plant). No regulation of CO2 emissions but subject to BAT controls (containment, noise etc). Requirements of CO2 Geological Storage Directive (GSD) (plus) implemented by supporting guidance to 1989 Electricity Act Section 36 requirements (planning permission). ‘ SEPA  Key point is that planners (and NGOs etc) want to see achievable emissions limits in plans

PANEL: Andrew Botting, Lesley Sloss, Kirsten Foy Discussion: Who pays? Burners, power generators, gasifiers? Unknown. Project specific. Network approach e.g.

White Rose Project might help internalise externalities and unknowns. But then not taken forward. Comment: Electricity price is not an issue as the marginal price for gas coal does not differ. Comment: Again key point is that uncertainty ( especially re gas price, regulatory framework, emissions, fiscal, taxes, investment, BAT) makes it difficult to forecast future for coal use. Discussion: Contracts for difference. Options for negotiation on strike price. 2 formats: Technology specific auctions for wind, CCS, nuclear and technology neutral auctions dependant on strike price.

Q1: What is considered capture ready and how does policy view this. R1: BAT policy is neutral on CCS readiness – retrofit/new build either applicable. Public acceptance relevant in planning decisions and permitting.

Under discussion: What forms could these coal plants take? (full CCS from start, partial CCS, CCS ready?) Availability of sites for coal power and industrial plant What locations could be used? Cooling, coal delivery, CO2 transport, public acceptance, grid connections etc. Recent experience regarding public acceptance (power plants, mines, CCS projects, pipelines) What is needed to keep sites etc available ‐ a coal +CCS‐ready strategy for UK infrastructure?

Discussion & panel: Sinead Treanor, Jeremy Carey, Steven Marshall Key points:  Public acceptance and stakeholder engagement matters re site locations  Consultation at earliest opportunity and with broadest scope (communities, regulators) essential  Must be a credible economic case  Public and private expenditure and risk  Location matters: strategic, ports, infrastructure, on‐shore/off‐shore storage

BREAK TEA/COFFEE

What R+D is needed (specifically related to coal) and is this underway? Bryony Livesey, Paul Lawrence, Coal power plant Andrew Minchener, Andrew Botting Coal industrial plant Flexibility issues CCS for coal power plant

CCS for coal industrial plant

Key points:  Efficiency versus cost arguments dominant. R&D relating to efficiency gains in capture rather than power generation would bring benefits  Technology developments: warm & hot gad clean up  Coal use is potentially economical as other economic derivatives and EOR etc  Commercial risks, contracts and warranties need to be further developed and explored for R&D funding to be made available  Research on economic option in complex and changing regulatory framework required. Most economic option should then be chosen.

WRAP UP Mike Farley

Close Jon Gibbins