The Impact of Shale Gas on Energy Markets

Written Evidence Submitted by the Tyndall Centre for Climate Change Research, University of Manchester (ISG 30)

Executive Summary

Tyndall Manchester has been investigating the climate change implications of shale gas developments for the past two years. We have raised concerns around the cumulative quantities of emissions that may be released by the extraction and combustion of shale gas and the implications for climate change mitigation of a widespread expansion of the industry in two reports. The most recent report (Broderick et al., 2011) contains research of relevance to two specific questions raised by the committee, namely:

i. What are the effects on investment in lower-carbon energy technologies?

ii. What is the potential impact on climate change objectives of greater use of shale gas?

This submission is a précis of the conclusions drawn by Broderick et al (2011) with additional material from a forthcoming report (Broderick and Anderson, 2012) examining the impact of shale gas on US energy system emissions. We conclude that the issues of lock-in to unabated gas generation, the importance of other drivers of US emissions reductions and the consequence of export of displaced fossil fuels, indicate that novel sources of gas production are problematic from climate change mitigation. It is clear that the production of fossil fuels of all sorts needs to be curtailed in the absence of strict and coordinated international greenhouse gas emissions caps.

Ultimately, the UK’s international commitments, under the Copenhagen Accord and Cancun Agreements, cannot be reconciled with the large scale exploitation of shale gas, even with carbon capture and storage. In many respects the response of the UK Government to the prospect of indigenous shale gas production is a bellwether of the veracity or otherwise of the UK’s commitments and leadership on climate change.

i) What are the effects on investment in lower-carbon energy technologies?

1. The Energy and Climate Change Committee (2011) has previously noted that a substantial move to exploit newshale gas reserves could attract investment that might otherwise go to renewable energy. The 2011 report states that "…shale gas has the potential to shift the balance in the energy markets that the Department has tried to create away from low carbon electricity generation".

2. In our updated report (Broderick et al. 2011) we estimated the potential scale of such a diversion by assessing the capital costs of gas powerstations burning the output of a mature shale gas industry (i.e. 9bcm/year sustained over a 20 year time period). We refer the committee to section 3.4 of Broderick et al. (2011) for full details and summarise the conclusions below.

3. In total, potential resource substitution was found to be £19bn to £31bn, depending upon the discount rate applied to future investment. The higher figure relates to a Treasury Green Book discount rate of 3.5%, arguably the most appropriate rate for assessing public policy.

4. Table 3.11, reproduced below, illustrates the scale of potential wind energy foregone if capital is diverted to shale gas. Given the need for climate mitigation, the costs of CCGTs with carbon capture and storage (CCS) was also considered. CCS has an energy penalty in operation, in the order of 10% to 20% hence 7GW capacity could be sustained with 9bcm/year gas, and substantially increases capital costs. In the absence of large scale demonstration plants there are considerable uncertainties in the technology’s cost and efficiency parameters.

Table 3.11: Investment equivalents in gas and renewable capacity  

10% Discount rate

3.5% Discount rate

8GW CCGT

7GW CCGT +CCS

8GW CCGT

7GW CCGT +CCS

Onshore wind (GW)

12.5

16.5

16.8

20.8

Onshore wind (3MW turbines)

4,172

5,503

5,594

6,925

Offshore wind (GW)

7.0

9.2

9.4

11.6

Offshore wind (5MW turbines)

1,401

1,849

1,879

2,326

5. The potential scale of displacement is comparable to the 2020 ranges in UK Renewable Energy Road Map; 10-13 GW onshore wind and 11-18 GW offshore (potentially 40 GW).

6. If the cost of CCS is included and a 3.5% public discount rate used, then the equivalent 21 GW of onshore wind capacity could generate up to 27% more electricity per annum considering representative capacity factors of 70% for gas and 30% for wind. 12GW of offshore turbine capacity would be expected to generate 5% less electricity than the equivalent gas infrastructure.

7. So as not to renege on UK climate change commitments, it is imperative that investment is directed towards very low and zero carbon energy infrastructure. Construction without CCS would place much greater pressure on other parts of the economy to decarbonise and risk gas infrastructure worth £19 to £26bn becoming ‘stranded assets’. However, as we describe below it cannot be assumed that CCS will provide sufficient levels of abatement for gas-fired electricity to continue to be a major energy source in the long term.

8. Our analysis considered only capital costs, not operating costs; a simplification that significantly favoured gas over wind as the latter has much lower operating costs as a percentage of total costs. The levelised cost estimates for gas CCGT (Parsons Brinkerhoff, 2011), with 10% discount rate, suggest that fuel costs account for 88% of the total cost per MWh of electricity. In contrast, the operating costs for wind generation make up only 6% of total costs (Arup 2011). Costs of transmission and distribution infrastructure for both gas and electricity were also excluded.

ii) What is the potential impact on climate change objectives of greater use of shale gas?

9. Much of the discussion on the climate change impact of shale gas centres on its relative emissions intensity compared with other fuel sources. This issue is of interest, but must not distract from the most climatically relevant issue of absolute quantities of emissions from the global energy system.

10. There are important concerns about the possibility of additional climate change impacts from gas produced by hydraulic fracturing; this remains a contentious topic in the academic literature. Life cycle analysis studies include inter alia emissions from energy required to produce and distribute the gas, for instance those embodied in water transported to the well pad, and releases of methane itself to the atmosphere both deliberately and inadvertently during the full fuel production, transmission and distribution cycle.

11. Methane is a more potent GHG than CO2 but with a shorter atmospheric life span, with the potential to substantially influence the conclusions drawn by a given study. A conversion factor is required to relate the climate change impact of fugitive methane emissions to the carbon dioxide emissions from other activities and a number of different metrics are available to compare the impact of different greenhouse gases. A gas’s contribution to global warming depends upon its absorption of infrared radiation, its longevity and its ability to influence other atmospheric components physically and chemically. The most widely used metric is the Global Warming Potential (GWP) which is the ratio of the change in radiation balance from a pulse release of a given gas, integrated over a specified future time period, against the same change for a release of the same mass of carbon dioxide. GWP is frequently used in climate policy as a way of comparing well mixed, long lived greenhouse gases like carbon dioxide, nitrous oxide and methane. Typically a one hundred year time period is used for the calculation and revised estimates of GWPs are prepared as atmospheric science progresses. Whilst, these conversion factors are not inherent properties of the gas, their selection can have significant impacts on the conclusions drawn by research and policy.

12. There has been some dispute in the scientific literature of the appropriate GWP timescale to use when comparing conventional with unconventional gas production techniques. There is also a shortage of independent primary research on the actual quantities of such emissions, and many studies use the same underlying empirical data that is recognised to be limited in scope and applicability. Our previous research provides a fuller discussion of this topic (Broderick et al. 2011, Section 3.2.4) as well as an estimate of the additional emissions due to hydraulic fracturing. This estimate is compared with others in a review prepared for the European Commission DG Clima (AEA 2012). A recent comparative statistical approach has concluded that it is difficult to distinguish between the life cycle emissions impact of different gas production and distribution methods and that attention should be paid to energy system impacts (Weber & Clavin 2012).

13. Regardless of the unavoidably contextual framing of life cycle GHG impact, either per unit of gas produced or per unit of electricity generated, the direct carbon content of shale gas means that its widespread use would is incompatible with the UK’s international climate change commitments.

14. The absolute necessity of decarbonisation means that technologies with orders of magnitude lower emissions are required to provide energy to UK households and industry in the short to medium term. The Committee on Climate Change (2008) has advised "that any path to an 80% reduction by 2050 requires that electricity generation is almost entirely decarbonised by 2030". Decarbonisation of the electrical supply is an effective way of rapidly reducing emissions. Renewable supply technologies, with very low associated emissions, are available now and are compatible with existing infrastructure. The efficiency of transport and heating can be improved through the deployment of new electric vehicle and heat pump technologies respectively.

15. Understanding timescales is pivotal from a cumulative emission (carbon budget) perspective. The CCC argues that the transition to a very low carbon grid, with an intensity of the order of 50g CO2/kWh, should take place by 2030. Scenarios described by the MARKAL economic optimisation model identify this point as being on the way to a zero carbon grid soon after. It is worth noting that the CCC acknowledges a low probability of keeping below 2°C of warming on the basis of their budgets, this is despite their assumption of unrealistically early global peaking dates (~2016).

16. Accounting for an emissions floor for food production and making fair (but still very challenging) allowance for emissions from non-Annex 1 nations, Anderson and Bows (2011, C+6 scenario) find that complete decarbonisation of Annex 1 energy systems must be accomplished rapidly (i.e. within a decade) for even a 50% chance of avoiding 2°C of warming.

17. It is sometimes argued that shale gas could be burned safely in the short term, however this is not the case. Given that shale gas is yet to be exploited commercially outside the US, limitations on the availability of equipment mean that it is very unlikely it could provide other than a marginal contribution to UK supply before 2020. However, gas fired power stations produce emissions of approximately 440gCO2e/kWh of electricity and typically have a lifespan of over 25 years. Therefore, unless allied with carbon capture and storage (CCS) technologies, as yet unproven at a large scale, all new powerstations intended to burn shale gas would need to cease generating within five to fifteen years of construction, and at the latest be decommissioned by 2030. Green Alliance scenarios (2011) indicate that if there is a second "dash for gas", emissions from the grid could still be 302gCO2e/kWh in 2030 necessitating 95% deployment of CCS to meet our fourth period emissions budgets (2023-2027). In this respect, the "golden age" may turn out to be a gilded cage, locking the UK into a high carbon future

18. Even CCS is problematic when such low carbon electricity is required. At commercial scale CCS will be significantly less than 100% effective at capturing carbon dioxide. Moreover, it will always add costs to electricity production by reducing the efficiency of the power station requiring additional energy input in transportation and injection of the captured carbon dioxide. Best case emissions performance for gas CCS is in the range 35-75gCO2/kWh (80-90% capture efficiency on 55% efficient CCGT with 10% energy penalty for capture).

19. CCS therefore also increases the net quantity of upstream emissions of gas or coal production and transport; reduced efficiency means that greater quantities of fuel must be used for equal electricity output, increasing emissions over and above those from the fuel combustion. For unconventional gas production these have the potential to be significant if mitigation is not in place; Broderick et al (2011) estimate up to an additional 17gCO2e/MJ of gas produced, equivalent to an additional 120gCO2e per kWh of electricity generated depending upon mitigation during production.

20. With regards to using shale gas for heating purposes, the CCC (2008) note that as the grid decarbonises it is "more carbon efficient to provide hot water and space heating with electricity than with gas burned in a condensing boiler". Non-energy uses accounted for less than 1% of total UK demand for natural gas in 2010 (DUKES 2010). It is therefore reasonable to assume that new gas production in the UK will be combusted and, in the absence of carbon capture and storage, released to the atmosphere.

21. Shale gas has the potential to contribute substantial additional emissions to the atmosphere. Global estimates of reserves suggest this may be up to 30% of a global emissions budget with a 50% chance of avoiding dangerous climate change (Broderick et al. 2011, Section 3.3.2).

22. Substitution between fuel sources cannot necessarily be assumed to reduce emissions in absolute terms. Our forthcoming report (Broderick and Anderson, 2012) explores the CO2 emissions consequences of fuel switching in the US power sector using two simple methodologies. The analysis presented is conditional upon its internal assumptions, but provides an indication of the scale of potential impacts. It suggests that emissions avoided at a national scale due to fuel switching in the power sector may be up to half of the total reduction in US energy system CO2 emissions of 8.6% since their peak in 2005. Since 2007, the production of shale gas in large volumes has substantially reduced the wholesale price of natural gas in the US. The suppression of gas prices through shale gas availability is a plausible causative mechanism for at least part of this reduction in emissions. Although we were not able to isolate the proportion of fuel switching due to this effect other studies note that between 35% and 50% of the difference between peak and present power sector emissions may be due to shale gas price effects. Substantial increases in renewable generation and capacity appear to have had an effect of similar magnitude through policy and cost competitiveness. Air quality regulations, energy efficiency and demand management, and the impact of the recession are cited to have played a considerable part in driving this change.

23. It is essential to note that there has also been a substantial increase in coal exports from the US over this same time period. Without a meaningful cap on global carbon emissions, the exploitation of shale gas reserves is likely to increase total emissions. For this not to be the case, consumption of displaced fuels must be reduced globally and remain suppressed indefinitely, in effect displaced coal must stay in the ground. Our calculations suggest that more than half of the potential emissions avoided in the US power sector may actually have been exported as coal. Summing the quantity of implicit emissions exported over the period 2008 to 2011 suggests that approximately 340 MtCO2 of the 650 MtCO2 of potential emissions avoided may be added elsewhere. It is clear that the production of fossil fuels of all sorts needs to be curtailed in the absence of strict and coordinated international GHG emissions caps.

References

AEA (2012) Climate impact of potential shale gas production in the EU. Reference number: CLIMA.C.1./ETU/2011/0039r.

Anderson, K. and A. Bows (2011). "Beyond 'dangerous' climate change: emission scenarios for a new world." Philosophical Transactions of the Royal Society A: Mathematical, Physical and Engineering Sciences 369(1934): 20-44.

Arup (2011) Review of the generation costs and deployment potential of renewable electricity technologies in the UK , Study Report REP001, Department of Energy and Climate Change, London

Broderick, J. et al. (2011) Shale gas: an updated assessment of environmental and climate change impacts. A report commissioned by the Co-operative and undertaken by researchers at the Tyndall Centre, University of Manchester.

Broderick, J. & Anderson, K. (2012) Has US Shale Gas Reduced CO2 Emissions?, A report commissioned by the Co-operative and undertaken by researchers at the Tyndall Centre, University of Manchester.

Committee on Climate Change (2008) Building a Low-Carbon Economy - the UK’s Contribution to Tackling Climate Change, The Stationery Office, London.

Green Alliance (2011) Avoiding gas lock-in: Why a second dash for gas is not in the UK’s interest, Available at http://www.green-alliance.org.uk/grea_p.aspx?id=5857

Parsons Brinkerhoff (2011) Electricity Generation Cost Model - 2011 Update Revision 1, Department of Energy and Climate Change, London

Weber, C.L. & Clavin, C. (2012) Life Cycle Carbon Footprint of Shale Gas: Review of Evidence and Implications. Environmental Science & Technology, 46(11), pp.5688–5695

October 2012

Prepared 25th October 2012