Appendix C: Assumptions underlying the scenarios
C.1.1 Products considered
Three sources of unconventional of oil and gas are considered as part of this study namely:
- Gas extracted from onshore sources using hydraulic fracturing;
- Associated liquids extracted from onshore sources using similar recovery techniques; and
- Coal bed methane.
The evidence base suggests that the focus for developers is shale gas development with associated liquids as a secondary priority. That is the reason why we have modelled shale gas and liquids together as liquids is a premium to gas.
The evidence base on coal bed methane is limited, especially in the Scottish context. Resource estimates for CBM are approximate  and thought to be located in the same geographical areas as shale gas/oil and liquids. Based on surface access, geology, development costs and estimated well recovery rates, CBM is currently unlikely to be a major product in Scotland. As such, we have assumed that only two CBM pads would be developed.
C.1.2 Location of resources and use of land
We have only considered resources in the Midland Valley for development as part of this study. The Midland Valley region appears to have the concentration of resources to support an integrated supply chain. We recognise that there are resources available in other parts of Scotland however many are comparatively small and may not individually be cost competitive to develop. A developable area is limited by urbanisation, faulting, water bodies, designated areas, etc. Exploration and production would therefore be limited to accessible areas within the basin as shown in Table C.1.
Production volumes scenarios are derived from the ability to develop pads within the Midland Valley. We also cross-reference the potential outputs of the pads against available resources. UKOOG and their members thought this approach was reasonable.
C.1.3 Resource availability
Assessments of resource availability are derived from BGS (2014) as shown in the Table C.2 below.
We have assumed production volumes based on the number of pads because in the Midland Valley (a highly populated area of Scotland) there are limits to the available space that can be used for UOG resource development. A 'developable' area is limited by urbanisation, faulting, water bodies, designated areas, etc. which limits the number of potential pad developments. We estimate that 20 pads could be developed in the Central scenario, while 31 and 10 could be developed in the High and Low scenarios respectively.
Table C.1 Potential developable area in the Midland Valley.
|Share of basin||Large part of the basin||Large part of the basin||Core of the basin|
|km 2||~ 160 km 2||~ 160 km 2||~ 42 km 2|
Table C.2 Potential total in-place shale oil, shale gas and coal bed methane in the Midland Valley in Scotland.
|Shale gas (tcf)||80.3||134.6||49.4|
|Shale oil (billion Bbl)||6.0||11.2||3.2|
|Coal bed methane (tcf)||22.4||NA||NA|
Source: British Geological Survey (2014) & Independent Expert Scientific Panel (2014).
C.2 Development and production
The table below provides a summary of assumptions on the development and production of UOG across our scenarios.
Table C.3 Summary of the assumptions across our scenarios.
|Number of shale gas pads||No.||20||31||10|
|Of which also producing associated liquids||15||23||8|
|Wells per shale pad||15||30||10|
|Number of CBM pads||2||2||2|
|Wells per CBM pad||15||15||15|
|Expected output per pad|
|Percentage of shale gas pads also producing associated liquids||%||75%||75%||75%|
|Production life of a shale gas well||years||15||15||15|
|Production life of a CBM well||years||12||12||12|
|Start of first production||year||2024||2023||2028|
|End of production||year||2048||2049||2049|
C.3 Cost profiles
C.3.1 Capital costs
The study published by EY in 2014 on shale gas and its supply chain and skills requirements provides a breakdown of the costs of hydraulic fracturing, drilling and completions, waste disposal and storage and transportation. These costs were for a hypothetical pad of 10 vertical wells with four laterals each (total of 40 laterals). In this study, we used the costs provided in the EY study and scaled them in accordance with the number of wells assumed in each scenario.
Furthermore, we added a number of other costs to cover expenditure on planning and licensing, exploration, pad development, decommissioning and aftercare costs. We also added operating expenditure to cover the production phase of the pads. These additional cost categories do not seem to form part of other publicly available studies.
Table C.4 below provides a breakdown of costs for all scenarios. It is worth noting that the costs are allocated to shale gas and associated liquids respectively based on an energy equivalent basis ratio  .
The volumes of associated liquids produced in the low scenario are so low that associated costs are negligible.
Figure C.1 overleaf depicts total annual costs for shale gas and associated liquids on a per pad basis.
Table C.4 Cost breakdown for a given pad in each scenario (totals may not add up due to rounding)
|Shale gas and associated liquids||CBM||Shale gas and associated liquids||CBM||Shale gas and associated liquids||CBM|
|1. Planning and licensing||1.2||1.2||2.5||1.2||0.8||1.2|
|3. Development costs||40.0||40.0||40.0||40.0||20.0||40.0|
|4. Main capex|
|Drilling and Completion|
|Ancillary equipment and service||4.5||4.5||8.9||4.5||3.0||4.5|
|Directional drilling service||2.8||2.8||5.6||2.8||1.9||2.8|
|Drilling fluids and fluids engineering||2.1||2.1||4.3||2.1||1.4||2.1|
|Drill rig fuel||1.7||1.7||3.5||1.7||1.2||1.7|
|Drilling waste management||5.0||5.0||9.9||5.0||3.3||5.0|
|Storage and transportation|
|Water storage and transportation||2.0||2.0||3.9||2.0||1.3||2.0|
|Sub-total (main capex)||123||89||246||89||82||89|
|Total Capex (items 1, 2, 3 & 4)||176||141||299||141||110||141|
C.3.2 Fixed and variable operating costs
The opex is based on a fixed and a variable element. The costs associated with the monitoring of carbon emissions are also included in the operating costs - these are estimated to be £100,000  per year per pad for the duration of the pad's lifespan. We assume that the variable element is linked to production while the fixed element is linked to capex. A breakdown of the variable operating cost is provided below:
Table C.5 Variable operating costs
|Variable opex||All scenarios|
|Shale gas and CBM||£0.25m/bcf|
|Associated liquids||£1.65m/ MMBOE|
The fixed operating cost is 2.5% of annual cumulative capex for shale gas, CBM and associated liquids.
Key to assessing the economic impact of UOG development is the amount spent within the Scottish economy, i.e. localisation. Our assumption is that in the Central scenario (and CBM) 50% of spend is within the Scottish economy, i.e. £2.2 billion. For the High scenario, we would expect 60% of UOG spend to remain in Scotland, i.e. £6.5 billion and for the Low scenario, we would expect 30%, i.e. £0.5 million.
These assumptions are broadly in line with localisation figures used in other sectors, namely the offshore wind and nuclear industries (BVG Associates, 2015) and ( HM Government, 2012).
A North American market exists for construction, labour and procurement of equipment of shale gas and associated liquids. The extent to which the Scottish UOG sector will need to import materials and expertise will depend on how quickly the domestic supply chain can develop to meet the industry's needs and the amount of localisation that is expected to occur in Scotland. Should Scotland become a centre of excellence in shale, it could become self-reliant in expertise which could also provide some potential export opportunities in Europe and elsewhere.
Figure C.1 Shale gas and associated liquids cost profiles (per pad)
Table C.6 Localisation assumptions
|Percentage of cost in Scotland||50%||60%||30%||50%|
We assume that the UOG supply chain would develop as more pads are developed. We also assume there is an element of 'learning by doing' whereby it becomes cheaper to drill subsequent wells.
In terms of efficiency improvements, we assume that there are economies of scale in pad construction. The Central scenario (and CBM pads) benefits from a cost reduction of 5% of capex for five pads after the first pad is built. The High scenario benefits from a cost of reduction of 7% for five pads after the first pad is built. We assume a smaller cost reduction percentage in the Low scenario, i.e. only 3% for three pads after the first pad is built. These assumptions are in line with the approach used by the US Department of Energy for components of energy systems (U.S. Department of Energy, n.d.) A generating technology's learning rate is a weighted average of the learning rates of its component parts. We have not assumed any learning rate for opex.
C.3.5 Community benefits
In the Central, High and Low scenarios, we assume that 4% of total revenues are given to local communities. Table C.8 provides a summary of community benefits payments across our scenarios (including if CBM were to be developed).
C.4 Decommissioning and aftercare
As described in Figure C.10 on the previous page, we assume that the decommissioning and aftercare costs are 25% of drilling and completions costs. This assumption is broadly in line with the IoD study (2013) and industry estimates.
We assume that aftercare costs are £40,000 per year per pad which represent a very small percentage of total drilling completion. See Table C.11 on the previous page.
We have used DECC's latest oil and gas wholesale fossil fuel price assumptions. Given current market prices, our scenarios are based on DECC's low projection scenarios ( DECC, 2015).
In our model, we assume that the volumes produced in Scotland are unlikely to result in movement in international prices. This implies that there is substitution between gas sources rather than gas for other sources. This is consistent with the CCC workstream in that overall usage of hydrocarbons is unchanged.
See Section 4.4.2 for more details.
Table C.7 Efficiency improvement assumptions
|Efficiency improvement assumptions||5%||7%||3%||5%|
Table C.8 Total cumulative benefit payment under 4% Community benefits payments 
|Shale gas and associated liquids||£m||217||663||64|
Table C.9 depicts what community benefits payments may be if operators give 6% of total revenues to local communities.
Table C.9 Total cumulative benefit payment under 6% Community benefits payments 
|Shale gas and associated liquids||£m||325||994||95|
Table C.10 Summary of decommissioning and aftercare assumptions scenario
|Decommissioning cost as a % of drilling and completion||%||24.85%||24.93%||24.68%|
|Aftercare cost per site per year (shale gas only) as a % of drilling and completion||%||0.15%||0.07%||0.32%|
|Number of years to spread over decommissioning||3||2||5|
|Number of years to spread over aftercare||20||20||20|
C.6 Financial assumptions
Table C.11 below provides a summary of our financial assumptions across all three production scenarios.
C.7 Carbon mitigation costs
The Climate change impact study has identified that a number of carbon mitigation technologies would be required in the Central, High and Low scenarios to ensure Scottish emissions targets are not exceeded. The carbon mitigation measures included in the CCC's 'Minimum Necessary Regulation' case are presented in Table C.12.
Table C.11 Summary of financial assumptions across all scenarios
|Salvage value for depreciation||£m||0|
|Corporate tax rate||%||20%|
|Payroll costs as a percentage of Opex||%||22%|
|Commercial interest rate||%||5%|
Table C.12 Carbon mitigation costs by scenario.
|Carbon mitigation technologies||Estimated cost of mitigation||Unit||Type of cost||Central||High||Low||Notes|
|Leak Detection and Repair ( LDAR)||£20,300||/pad/year||Opex||£304,500||£304,500||£304,500||£20,300/pad/year for 15 years|
|Reduced emissions completions ( REC) (per use, equipment can be used numerous times)||£12,500||/well||Development costs||£187,500||£375,000||£125,000||£12,500/well x number of wells|
|Liquids Unloading plunger lift (assumes operates for the final 10 years) Capex||£22,900||/well||Development costs||£343,500||£687,000||£229,000||£22,900/well x number of wells|
|Liquids Unloading plunger lift (assumes operates for the final 10 years) Opex||£1,000||/well||Opex||£150,000||£300,000||£100,000||1,000/well x number of wells for 10 years|
|Dry Seal Compressor||£416,000||/compressor||Development costs||£416,000||£416,000||£416,000||1 compressor/pad|
|Low-flow pneumatic devices||2,480||/device||Development costs||£4,960||£9,930||£2,480||Central: 2 devices/ pad High: 4 devices/pad Low: 1 device/pad|
|Vapour recovery units ( VRU)||£49,800||/pad||Development costs||£49,800||£49,800||£49,800||1 VRU/pad|
|Total (£m) per pad||1.5||2.1||1.2|
|Grand total (£m) for the scenario (all pads)||29.2||66.5||12.3|
Source: Supporting Annex to CCC (2016) Scottish Unconventional Oil and Gas - Compatibility with Scottish Greenhouse Gas emissions targets
For more information on the techniques and technologies which can be employed to mitigate carbon emissions, please refer to the Supporting Annex to CCC (2016) Scottish Unconventional Oil and Gas - Compatibility with Scottish Greenhouse Gas emissions targets.