Planning Scotland's Seas: 2013 - The Scottish Marine Protected Area Project – Developing the Evidence Base tor Impact Assessments and the Sustainability Appraisal Final Report

C.10. Oil and Gas

C.10.1 Introduction

This appendix provides an overview of existing and potential future activity for the oil and gas sector relating to Scottish waters and outlines the methods used to assess the impacts of potential MPAs on this sector.

C.10.2 Sector Definition

This sector relates to the extraction of oil and gas in the sub-sea environment largely from offshore reserves. Oil reserves include both oil and the liquids and liquefied products obtained from gas fields, gas-condensate fields and from the associated gas in oil fields. Gas reserves are the quantity of gas expected to be available for sale from dry gas fields, gas-condensate fields and oil fields with associated gas. For this assessment, activity within this sector includes exploration, production, interconnectors and gas storage ( i.e. the 'upstream' oil and gas sector).

C.10.3 Overview of Existing Activity

Information sources used in the assessment are listed in Table C10.1.

Table C10.1 Oil and Gas information sources.

Scale	Information Available	Date	Source
Scotland	All pipelines and cables	Current	SeaZone Solutions Ltd and UKDEAL
UK	Oil pipelines - Subsea pipelines and umbilical's related to the petroleum industry.	Current	UKDEAL
UK	Gas Pipeline Feeder (shapefile)	Current	National Grid
UK	Oil and gas employment	2012	Oil and Gas UK 2012 Economic reports: http://www.oilandgasuk.co.uk/2012economic_report.cfm
Scotland	Revenues and production from Scottish Sea areas (2005-2008). Oil, gas and NGL production and revenue (2005-2008) for all Scottish waters and regional breakdown.	2005-2008	Baxter et al (2011)
UK	Distribution of hydrocarbon fields (polygon)	Current	UKDEAL
UK	Locations and attributes of Hydrocarbon Blocks within UK Waters (polygon)	Current	UKDEAL
UK	UKCS Quads - Location and Attributes of DTI determined fields and arbitrary circular markers for undetermined fields (significant discoveries) (polygon)	Current	UKDEAL
UK	Current licence blocks (polygon)	Current	UKDEAL
UK	Surface infrastructure (Oil & Gas) - locations of platforms, FPSOs, buoys etc. (point)	Current	UKDEAL
UK	Subsea infrastructure (Oil & Gas) - locations of manifolds, tees, anchors etc. (point)	Current	UKDEAL
UK	Location of wells (point)	Current	UKDEAL
UK	Location of 25/26/27th Round Conditional Awards (licence blocks offered subject to clarification and agreement of licensing terms ) (polygon)		UKDEAL
UK	Underground coal gasification licences (polygon)	Current	Coal Authority
UK	Digest of UK Energy Statistics	2012	DECC
UK	Oil and Gas production up to 2011	2011	DECC ( https://www.gov.uk/oil-and-gas-uk-field-data)

C10.3.1 Location and intensity of activity

There is extensive infrastructure associated with oil and gas developments in Scotland, including seabed and platform mounted production facilities and networks of pipelines bringing oil and gas ashore for processing (Baxter et al, 2011; Figure C13). It is estimated that there is approximately 12,800km of oil and gas pipeline in Scottish waters with the majority of pipelines outwith the 12nm limit ( i.e. offshore). Virtually all hydrocarbon fields, platforms, pipelines and infrastructure occur within the central and northern North Sea and to the West of Shetland. The North Sea fields are generally mature, but there is the potential for significant new development to occur West of Shetland, particularly associated with the Laggan-Tormore fields.

Information on the production of oil, natural gas liquids (NGL) and gas from Scottish Sea areas between 2005 and 2008 are provided by Baxter et al (2011) and are shown in Table C10.2. The values show that production levels of Oil and Gas have remained roughly constant between 2005 and 2008, although there was a reduction in the tonnage of NGL in 2008 compared to previous years.

Table C10.2 Production and revenues from oil and gas from Scottish sea areas between 2005-2008

Production	2005	2006	2007	2008
Oil (tonnage)	56,751,985	51,734,343	54,900,487	53,081,406
NGL (tonnage)	5,439,147	5,458,028	5,551,411	4,435,130
Gas (therms) millions	18,218	16,311	17,200	19,606
Revenue	2005	2006	2007	2008
Oil (£M)	12,165	13,389	14,805	20,137
NGL (£M)	1,238	1,528	1,596	1,672
Gas (£M)	4,406	5,581	5,052	6,934
Total (£M)	17,809	20,498	21,454	28,744

(Source: Baxter et al. 2011)

Indicative figures for crude oil production from hydrocarbon fields which lie within the waters off Scotland have been estimated using offshore crude oil production data from the DECC website ^[44] (2009 = 61,341,301 tonnes; 2010 = 57,895,697 tonnes).

It was not possible to estimate dry gas or NGL production for 2009 and 2010 as production is not allocated to individual hydrocarbon fields (Clive Evans, DECC, pers. comm.).

C.10.3.2 Economic value and employment

The oil and gas industry is the principal source of fuel and power for Scotland, meeting more than 58% of the primary energy need in Scotland in 2008 (Baxter et al, 2011). The sector is the largest industrial contributor to the UK's GVA; the GVA of the upstream oil and gas sector ( i.e. not including the value added by the supply chain) in the UK in 2010 was estimated at £32 billion. In 2011, supply chain exports were in the range of £6 billion (Oil and Gas UK, 2012a). Information on the total revenue from oil, natural gas liquids (NGL) is provided in Table C10.1. The table shows that the total revenue from oil, NGL and gas progressively increased between 2005 and 2008.

The industry is a major employer. It was estimated that in 2010, the oil and gas industry provided employment for about 440,000 people across the UK, these comprised of 32,000 being directly employed by oil and gas companies and major contractors. Exploration and extraction of oils and gas from the UKCS accounted for the majority of these jobs, providing around 340,000 jobs in 2010, plus 207,000 employed in the wider supply chain and 100,000 in jobs induced by the economic activities of employees. An additional 100,000 jobs were estimated to be supported by the oil and gas supply chain's growing export business, bringing the total employment provided by the sector to about 440,000 jobs in 2010 (Oil and Gas UK, 2012a). About 45% of the 340,000 UKCS related jobs ( i.e. about 153,000) are located in Scotland not only in major cities such as Aberdeen, but across the whole of Scotland including the remoter areas of the country (Oil and Gas UK, 2012a). This data is three years old and is currently being updated. It is expected that employment will have risen and will continue to rise due to the increased investment and total expenditure in the past three years (Oil and Gas UK, 2012a).

C10.3.3. Future trends

Information on future trends relates to the UK and disaggregation of this data to regional (Scottish) level is not possible.

It has been estimated that in 2020, 70% of primary energy in the UK is still expected to come from oil and gas. The UKCS has the potential to satisfy about 50% of the UK's oil and gas demand in 2020, if the current rate of investment is sustained (Oil and Gas UK, 2012a). However, the amount of oil and gas imported into the UK is also likely to increase. By 2015, around 25% of the UK's annual gas demand is likely to be met by imports (increasing from 20% in 2008). Given the prediction for increasing dependence on imported gas, subsea gas storage facilities and associated pipelines are also likely to increase (Saunders et al, 2011), although no new gas storage is currently planned for Scottish waters.

Over 41 billion boe (barrels of oil equivalent) have been recovered so far from the UKCS, and a further overall recovery of 15 to 24 billion boe is forecast (Oil and Gas UK, 2012a). These are mainly in discoveries awaiting development, areas under current licence or regions where oil can be expected to be found but has not yet been explored (Baxter et al, 2011). Based on the average price of oil and gas forecast by the Energy Information Administration between 2009 and 2030, the wholesale gross value of these remaining reserves may be between £650 billion to £1.1 trillion (Baxter et al, 2011). A significant area of unexploited gas reserves lies to the West of Shetland and a new gas export pipeline from this area is currently being built to support output from the Laggan (about 125km West of Shetland) and Tormore (about 15km further South West) fields, scheduled to start production in 2014 (Baxter et al, 2011).

Image C10.1 shows oil and gas production levels in recent years and DECC's current (October 2012) projections ( DECC, 2013). A substantial decrease in oil and gas production in the UK since 1998 and the projected 5% decrease from 2018 to 2030 ( DECC 2013) is seen. The production projections for 2013 -2018 are consistent with those published by DECC at http://www.gov.uk/oil-and-gas-uk-field-data.

Around 500 individual structures (including platforms and tie backs) will be decommissioned over the next three decades (Saunders et al, 2011; Oil and Gas UK, 2012a). However, some depleted oil and gas fields, and oil and gas infrastructure, may potentially be used in the emerging CCS sector (see Section C5). From 2012 onwards, decommissioning expenditure for existing facilities is projected to be £28.7 billion by 2040, with a further £4.3 billion projected for new investments during the same period (Oil and Gas UK, 2012a). Over the next five years (2012-2017), total forecast decommissioning expenditure is £4.5 billion (Oil and Gas UK, 2012b).

Image C10.1. Actual and Projected UK Oil and Gas Production 1998-2030.

Source DECC, 2013.

'The production projections for 2013-2018 are consistent with those published by DECC at https://www.gov.uk/oil-and-gas-uk-field-data

C.10.4 Assumptions on Future Activity

Future oil and gas development depends on the presence of exploitable resources and the economic viability of development. Information on proposed front-end development activity (resource surveys and test wells) is available from awards made under DECC's oil and gas licensing rounds. However, it is difficult to anticipate the extent to which this front end activity might subsequently lead to development projects. Furthermore, information from recent and current licensing rounds provides a relatively short-term view of future activity. Over the next twenty years or so, it is possible that a further 10 or more licensing rounds will be announced by DECC (based on an average of a new round every 18 months to 2 years). In the light of these uncertainties, the MCZ IA (Finding Sanctuary et al, 2012) developed a series of assumptions on the scale of future activity based on awards made under the 26 ^th and 27 ^th oil and gas licensing rounds and these assumptions have largely been followed for the purposes of this assessment.

A significant proportion of existing oil and gas infrastructure will be decommissioned over the next 20 years. Information on draft and approved decommissioning programmes is available from DECC ^[45] . However, this provides only a short-term view on future decommissioning activity. DECC has indicated that, using current projections, around 41% of active oil and gas fields that overlap spatially with MPA proposals are expected to be decommissioned in the period 2014 to 2034 (E. Pizzolla, DECC, pers. comm).

It has been assumed that no new gas storage sites and no new gas interconnector projects are developed in waters off Scotland within the assessment period.

C.10.5 Potential Interactions with MPA Features

Infrastructure for the exploration and drilling for oil and gas may interact with MPA features in a number of ways. Seismic surveys in the exploration for oil and gas can cause significant impacts or disturbance to a variety of marine species, particularly fish. The installation of drilling infrastructure and drilling activities will have direct impacts on local benthic features. Benthic species may suffer lethal effects of surface and sub-surface abrasion and penetration. Disturbance and smothering may occur with the dispersion and deposition of drill cuttings, although this is dependent on hydrodynamic conditions and the particle size of the drill cuttings. Noise disturbance will also result from drilling activities. Once installed, the presence of drilling infrastructure has the potential to interrupt hydrodynamic processes and change local patters of sediment erosion and deposition. Scour protection to avoid potentially adverse impacts associated with erosion may involve replacing the original soft sediment on the seabed with a rocky substrate, inducing changes in habitat and community structure. Once in place drilling infrastructure may present a barrier to the movement of mobile species and may potentially result in death or injury by collision ( JNCC & NE, 2011).

Trenching and burying of pipelines for the transport of oil and gas causes short-term disturbance to the benthic habitat along the route of the pipeline, after which the seabed would be re-colonised. If pipelines are laid directly on the seabed, they may disrupt the hydrodynamic regime and alter the natural transport of sediment within the area. Concrete mattresses may be utilised to stabilise pipelines, resulting in a permanent loss of soft sediment habitat and a shift to hard substrate. In areas of sand waves, sand crests may be 'shaved' to flatten the seabed for better pipeline installation, altering geomorphological characteristics of the area ( JNCC & NE, 2011).

Oil spills can impact all habitat types, although areas of low wave energy are more vulnerable than high energy areas that can naturally disperse oil quickly. In addition to oil pollution, discharges of formation water, crude oil and other production chemicals may affect the surrounding environment if not managed in accordance with best practice.

C.10.6 Assumptions on Cost Impacts for Scenarios

It is assumed that the impact of oil and gas activity on MPA features will be managed under the existing licensing frameworks. Two scenarios ('lower' and 'upper') have been developed to capture the possible costs of MPA proposals to the oil and gas sector. These scenarios include potential costs associated with additional assessments required to inform licensing and permitting decisions and associated survey requirements.

It has been assumed that there will be no review of existing licences or permits, although where operators of existing installations apply for new licences or permits, these applications will be considered against the conservation objectives for features for which MPAs may have been designated.

It has been assumed that a range of additional management measures will be required to minimise impact to sensitive habitats, including a requirement for additional survey to inform measures such as micro-siting of infrastructure.

It has not been possible to estimate the cost impacts for decommissioning activity at a site level associated with additional assessments required to inform licensing and permitting decisions, associated survey requirements, or potential additional mitigation measures, because the location of fields that will be decommissioned during the assessment period is confidential. An assessment of the potential cost of additional assessments required to inform licensing and permitting decisions [and associated survey requirements] has been prepared at a national level based on assumptions.

An intermediate ('best') estimate for each site has been based on SNH/ JNCC current views on management options and judgements made by the study team. The assumptions do not pre-judge any future site-specific licensing decisions. After MPA designation, the management of activities in MPAs will be decided on a site-by-site basis and may differ from the assumptions in this assessment.

Management measures applied under the lower and upper scenarios are detailed below. Specific management measure assumptions for each scenario by MPA (including the intermediate scenario) are defined in the MPA Site Reports (Table 4, Appendix E).

Lower Scenario

• Additional costs will be incurred for new oil and gas licence and permit applications in assessing potential impacts to MPA features for 26 ^th and 27 ^th oil and gas licensing round awards within licensing blocks overlapping with MPA features;
• Additional costs will be incurred for decommissioning consents in assessing potential impacts to MPA features where the oil and gas fields to be decommissioned overlap with MPA features; and
• Mitigation measures may be required for non- OSPAR/BAP features ranging from:
  ˉ No additional mitigation required beyond existing good practice;
  ˉ Minimising alterations to seabed habitat; any deposited material should meet local habitat type;
  ˉ Micro-siting of infrastructure in areas of reduced sponge density, drawing on data held by JNCC and collected by operators; and
  ˉ Treat cuttings that use oil-based muds on site.

Upper Scenario

• Additional costs will be incurred for new oil and gas licence and permit applications in assessing potential impacts to MPA features for 26th and 27th oil and gas licensing round awards within licensing blocks overlapping with MPA features;
• Additional costs will be incurred for decommissioning consents in assessing potential impacts to MPA features where the oil and gas fields to be decommissioned overlap with MPA features;
• Additional survey costs will be incurred to inform new licence applications where management measures involving micro-siting are required; and
• Mitigation measures may be required for some OSPAR/BAP features ^[46] for which adequate protection is not currently achieved and all non- OSPAR/BAP features ranging from:
  ˉ No additional mitigation required beyond existing good practice;
  ˉ Avoidance of development in sensitive habitats;
  ˉ Skip and ship of drill cuttings (transporting all drill cuttings to shore for disposal; i.e. water-based muds and oil-based muds);
  ˉ Micro-siting of drill spud sites; development infrastructure such as jackets, anchors, manifolds and drill templates (optimising the layout of infrastructure in order to avoid sensitive/protected features); and
  ˉ Re-routeing of new pipelines to avoid moderately or highly sensitive MPA features.

C.10.7 Assessment Methods

Additional Licensing and Permitting Costs

Where exploration or development activity occurs within the vicinity of features proposed for designation within MPA proposals, it will be necessary for the developer to provide information to DECC to determine whether such activity poses a significant risk to the achievement of the conservation objectives for those features.

The assessment does not include any additional costs that may be incurred for assessment of environmental impact of projects for which consent is currently being sought. This is because these costs will be incurred before the start of the period covered by the assessment (2014) and are therefore considered to be sunk costs.

For licensing and permitting costs associated with new development activity that may be incurred from 2014 onwards, there are a number of stages to the licensing and permitting process and costs may be incurred at various points in this process (see Table C10.3 below from Annex H11 of Finding Sanctuary et al, 2012). In order to estimate the potential number of future developments and stages at which additional assessments might be required, the following assumptions have been made:

• Where the oil and gas licensing blocks with awards under the 26 ^th or 27 ^th licensing rounds which overlap with MPA features comprise blocks with 'significant discoveries' or 'fallow blocks and discoveries' ^[47] :
  ˉ For 26 ^th licensing round awards, it is assumed that they will have already completed phase 1 (see Table C10.3) by 2014 but that all awards will complete phases 2 and 3 during the assessment period (cost assumed to fall in 2016);
  ˉ For 27 ^th licensing round awards, it is assumed that they will complete phases 1 to 3 (see Table C10.3) during the assessment period (cost for phase 1 assumed to fall in 2016; cost for phases 2 and 3 assumed to fall in 2018);
  ˉ For 26 ^th and 27 ^th licensing round awards, it is assumed that 50% of awards proceed to complete phases 4, 5 and 6 within the assessment period (cost for 26 ^th round awards assumed to fall in 2022; cost for 27 ^th round awards assumed to fall in 2024)
• Where the oil and gas licensing blocks with awards under the 26 ^th or 27 ^th licensing rounds which overlap with MPA features comprise blocks that do not have significant discoveries, fallow blocks or fallow discoveries:
  ˉ It is assumed that these awards will complete phases 1 to 3 only (see Table C10.3) during the assessment period (cost for 26 ^th licensing round - phase 1 assumed to fall in 2016; cost for phases 2 and 3 assumed to fall in 2018; cost for 27 ^th licensing round - phase 1 assumed to fall in 2018; cost for phases 2 and 3 assumed to fall in 2020).

Where decommissioning activity occurs within the vicinity of features proposed for designation within MPA proposals, it will be necessary for the developer to provide information to DECC to determine whether such activity poses a significant risk to the achievement of the conservation objectives for those features. DECC has indicated that potentially 15 out of the 36 active oil and gas fields that overlap spatially with MPA proposals are expected to be decommissioned in the period 2014 to 2033 (E. Pizzolla, DECC, pers. comm). In the absence of information on the timing of decommissioning, it has been assumed that additional assessments will be undertaken in 2024 (the midpoint of the assessment period).

Additional survey costs

It has been assumed that additional survey costs will be incurred where there is a requirement for micro-siting to be implemented regarding the location of the well (all phases). The cost of these additional surveys has been estimated as £230k per survey (based on indicative cost estimate supplied by Oil & Gas UK, 2013). It has also been assumed that, should an award proceed to phases 4 to 6, additional survey costs will be incurred where there is a requirement for micro-siting of pipelines (see mitigation measures below); this cost has been estimated at £580k per survey (Oil & Gas UK, 2013).

Mitigation Measures

Where mitigation measures are required, it is assumed that the following additional costs may be incurred (based on indicative cost estimates supplied by Oil & Gas UK, 2013):

• Skip and ship of drill cuttings (transporting all drill cuttings to shore for disposal; i.e. water-based muds and oil-based muds) - £650k per well; and
• Re-routeing of new pipelines - £2 million per km of additional pipeline (10% of distance to the landward edge of the feature or MPA boundary) ^[48] .

Quantifying costs associated with micro-siting wells has not been possible (only survey costs have been quantified as outlined above). It has also not been possible to quantify costs associated with the treatment of cuttings that use oil-based muds on site; however, this process is already considered good practice and unlikely to incur an additional cost.

It should be noted that relocation of a well to a new site may not be possible and the use of directional drilling limits the depth to which a site can be drilled. An indicative cost (provided by Oil & Gas UK, 2013) suggests three extra days of drilling would equate to an additional cost of £1.3 million. However, it has not been possible to incorporate this potential cost impact into this assessment due to uncertainties regarding the nature of individual projects.

Cost of Uncertainty and Delays

The designation of NC MPAs has the potential to increase the time taken to determine licence applications and to negatively affect investor confidence. It has not been possible to quantify these potential impacts.

Table C10.3 The anticipated additional requirements and costs for the assessment of environmental impact in future licence applications for the oil and gas sector arising as a result of MPAs (from Annex H11 of Finding Sanctuary et al, 2012)

Time period (number of years) over which each development phase occurs, in consecutive order	List of permits and applications that already take place in each development phase, for which it is assumed that an assessment of environmental impact is undertaken (which will need to include an assessment of impact upon MPA features)	Estimated additional resource inputs and cost arising as a result of MPA designation ( e.g. £/day) for the entire phase*	Estimated additional cost (£m) for the entire phase as a result of MPA designation (one-off cost per application)
0.5 years Surveys and evaluation (phase one)	Up to 15 permits including consent to survey (Petroleum Operations Notice (PON) 14A)	£1,000 consultancy fees (2 days at £500/day) £1,000 additional input of staff time by the operator (2 days at £500/day)	0.002
0.25 years Drilling and exploration (phase two)	PON15b for drilling - this is both a chemical permit and determination of whether an Environmental Statement is required Environmental Statement (if required) Oil Pollution Emergency Plan (OPEP) for drilling and well test Chemical permit for drilling and well test Consent to locate rig The Offshore Petroleum Activities (Oil Pollution Prevention and Control) Regulations 2005 (OPPC) permit for drilling and well test	£2,000 consultancy fees (4 days at £500/day) £2,000 additional input of staff time by the operator (4 days at £500/day)	0.004
0.25 years Drilling and appraisal (phase three)	PON15b for drilling - this is both a chemical permit and determination of whether an Environmental Statement is required Environmental Statement (if required) OPEP for drilling and well test Chemical permit for drilling and well test Consent to locate rig OPPC permit for drilling and well test	£2,000 consultancy fees (4 days at £500/day) £2,000 additional input of staff time by the operator (4 days at £500/day)	0.004
0.25 years Development (phase four)	PON15c for pipelines - this is both a chemical permit and determination of whether an Environmental Statement is required Environmental Statement (if required) OPPC permit Chemical permit Registration Pipeline Works Authorisation Consent to locate Consent to deposit materials	£2,000 consultancy fees (4 days at £500/day) £2,000 additional input of staff time by the operator (4 days at £500/day)	0.004
19 years Operation and production (phase five)	PON15d for production operations - this is both a chemical permit and determination of whether an Environmental Statement is required Environmental Statement (if required) Emissions trading permit Chemical permit Radioactive sources permit OPEP Consent to flare Consent to vent OPPC permit Waste management plan UK Oil Payment Programme certificate	£500/permit/yr. Assuming 20 permit applications are submitted in the 20 year period of the IA, the additional cost comprises: £10,000 consultancy fees £10,000 additional input of staff time by the operator	0.02
20 years + Maintenance (phase six)	PON15f for well interventions - this is both a chemical permit and determination of whether an Environmental Statement is required Environmental Statement (if required) Pipeline Works Authorisation Consent to locate Chemical permit	£1,000 consultancy fees (2 days at £500/day) £1,000 additional input of staff time by the operator (2 days at £500/day)	0.002
20 years + Decommissioning (phase seven)	PON15e for decommissioning - this is both a chemical permit and determination of whether an Environmental Statement is required Environmental Statement (if required) Baseline environmental survey Marine Licence under Marine & Coastal Access Act (covering decommissioning activities, e.g. removal/deposit and/or disposal of infrastructure from the seabed) Consent to locate Evaluate with regulator Decommissioning programme OPPC permit Chemical permit	£1,000 consultancy fees (2 days at £500/day) £1,000 additional input of staff time by the operator (2 days at £500/day)	0.002

* Data supplied by Oil and Gas UK, August and September 2011

C.10.8 Limitations

• Uncertainty concerning the location, scale and timing of future development activity, particularly in later years of the assessment period;
• Uncertainty concerning the location and timing of decommissioning activity, particularly in later years of the assessment period;
• Uncertainty concerning the cost impact of project delays associated with additional assessment and monitoring requirements; and
• Uncertainty concerning nature of any possible mitigation measures and implications for future investment.

C.10.9 References

Baxter, J.M., Boyd, I.L., Cox, M., Donald, A.E., Malcolm, S.J., Miles, H., Miller, B., Moffat, C.F., (Editors), 2011. Scotland's Marine Atlas: Information for the national marine plan. Marine Scotland, Edinburgh.

Department for Energy and Climate Change ( DECC). 2013. UKCS Oil and Gas Production Projections. https://www.gov.uk/government/uploads/system/uploads/attachment_data/file/136390/production_projections.pdf

Finding Sanctuary, Irish Seas Conservation Zones, Net Gain and Balanced Seas, 2012. Impact

Assessment materials in support of the Regional Marine Conservation Zone Projects' Recommendations. Annex H11 Oil, Gas and Carbon Capture and Storage.

JNCC and NE, 2011. General advice on assessing potential impacts of and mitigation for human activities on MCZ features, using existing regulation and legislation. Advice from the Joint Nature Conservation Committee and Natural England to the Regional MCZ Projects. June 2011. 107pp.

Oil and Gas UK. 2012a. Economic Report 2012.
http://www.oilandgasuk.co.uk/cmsfiles/modules/ publications/pdfs/EC030.pdf

Oil and Gas UK 2012b. 2012 Decommissioning Insight.
http://www.oilandgasuk.co.uk/cmsfiles/modules/publications/pdfs/OP073.pdf

Saunders, J., Tinch, R., Ozdemiroglu, E. & Hull, S., 2011. Valuing the Marine Estate and UK Seas: Dynamic Baseline Assessment (draft). Marine Estate Research Report for The Crown Estate.