UK Extractive Industries Transparency Initiative (EITI)
Source: data.gov.uk (2021-09-09)

The Extractive Industries Transparency Initiative (EITI) is an international standard for openness around the management of revenues from natural resources. It is designed to improve accountability and public trust for the revenues paid and received for a country’s oil, gas and mineral resources.

The Extractive Industries Transparency Initiative (EITI) reports covering payments and data for the UK extractives sector and a reconciliation of payments made by oil, gas, mining and quarrying companies for the UK extraction of raw materials and government receipts are now available on the [UK EITI website](https://www.ukeiti.org/about-us).

To access the data via the [UK EITI website](https://www.ukeiti.org/publications-reports), please put a tick in the “UK EITI Reports” box and click on the “Filter” box. Each UK EITI payments report will be listed. When you double click on the report title a list of the related data will also be listed and accessible.

UNITED KINGDOM EXTRACTIVE
INDUSTRIES TRANSPARENCY
INITIATIVE (UK EITI)

UK EITI Report for 2015

March 2017

This Report has been prepared by UK EITI Multi-Stakeholder Group (MSG) charged
with the implementation of the Extractive Industries Transparency Initiative in the
United Kingdom in collaboration with the Independent Administrator (IA). This Report
has been prepared within the context of EITI reporting and is published for information
purposes. The figures included within the report have not been subject to specific
audit procedures and accordingly neither the MSG nor the IA take responsibility for
any loss which may be incurred by any other party, should they rely on figures
included within this report if such figures were later discovered not to be accurate.

UK EITI report for 2015
Table of Contents
1. EXECUTIVE SUMMARY ....................................................................................... 5
2. INFORMATION ON THE UK EXTRACTIVE INDUSTRIES ................................... 9
2.1. The Extractive Industries in the UK ................................................................ 9
2.2. Oil and Gas .................................................................................................. 23
2.3. Mining and Quarrying ................................................................................... 43
2.4. The UK’s Budget and Audit Processes ......................................................... 60
3. APPROACH AND METHODOLOGY .................................................................. 61
3.1. Payment Streams ......................................................................................... 61
3.2. Government Agencies .................................................................................. 63
3.3. Materiality Threshold .................................................................................... 63
3.4. Data Collection, Completeness and Reliability ............................................. 63
3.5. Reconciliation Scope and Methodology ........................................................ 66
3.6. Beneficial Ownership ................................................................................... 69
3.7. Recommendations ....................................................................................... 70
4. RECONCILIATION RESULTS ............................................................................ 71
4.1. Reconciled Extractive Payments to Government in 2015 by Oil & Gas
companies .................................................................................................... 72
4.2. Reconciled Extractive Payments to Government in 2015 by Other Mining
& Quarrying companies ................................................................................ 75
5. INDEPENDENT ADMINISTRATOR’S RECOMMENDATIONS TO THE MSG .... 77
5.1. Lessons Learned from the 2015 EITI Reconciliation Exercise ...................... 77
5.2. Follow up of Recommendations of 2014 EITI Reconciliation Exercise ......... 80
ANNEXES .............................................................................................................. 82
Annex 1: Beneficial Ownership Declaration Form................................................ 82
Annex 2: Reporting Templates ............................................................................ 83

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UK EITI report for 2015
LIST OF ABBREVIATIONS
AMRI
Annual Minerals Raised Inquiry
AP
Accounting Period
BBL
Balgzand–Bacton Line
BEIS
Department for Business, Energy & Industrial Strategy
BGS
British Geological Survey
billion
one thousand million or 109
BMAPA British Marine Aggregate Producers Association
BO
Beneficial ownership
boe
barrel of oil equivalent
Brent
as applied to trading, the standard quality of oil in Europe and elsewhere
comprising a blend of four North Sea crudes from the Brent, Ekofisk,
Forties and Oseberg fields
CA
Coal Authority
CNS
Central North Sea
CT
Corporation Tax
DCLG
Department for Communities and Local Government
DECC
Department of Energy & Climate Change (now part of BEIS)
DfE
Department for the Economy
DRD
Decommissioning Relief Deed
EITI
Extractive Industries Transparency Initiative
EU
European Union
FYAs
First Year Allowances
GB
Great Britain
GDP
Gross Domestic Product
GVA
Gross Value Added
HM
Her Majesty’s
HMRC Her Majesty’s Revenue and Customs
IA
Independent Administrator
IUK
Zeebrugge–Bacton Interconnector
LNG
Liquefied Natural Gas
LPA
Local Planning Authority
MEA
Mineral Extraction Allowance
MMO
Marine Management Organisation
MPA
Mineral Planning Authority
MPL
Mineral Prospecting Licence
MSG
UK EITI Multi-Stakeholder Group
mtoe
million tonnes of oil equivalent
NAO
National Audit Office
NGLs
Natural Gas Liquids
NIEA
Northern Ireland Environment Agency
NPPF
National Planning Policy Framework
NRW
Natural Resources Wales
NYM
North York Moors
OBR
Office for Budget Responsibility

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UK EITI report for 2015
LIST OF ABBREVIATIONS
OGA
Oil & Gas Authority (as inheritor body of most oil and gas functions from
DECC)
ONS
Office for National Statistics
PEDL
Petroleum Exploration and Development Licence
PEP
Politically Exposed Person
PMA
Plant and Machinery Allowances
PRT
Petroleum Revenue Tax
PSC
People with Significant Control
QIP
Quarterly Instalment Payment
RDA
Research and Development Allowance
RFCT
Ring Fence Corporation Tax
RFES
Ring Fence Expenditure Supplement
SC
Supplementary Charge
SEPA
Scottish Environment Protection Agency
SI
Statutory Instrument
SPD
Supplementary Petroleum Duty
TCE
The Crown Estate
ToR
Terms of Reference
UCG
Underground Coal Gasification
UK
United Kingdom
UKCS
UK Continental Shelf

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UK EITI report for 2015
1. EXECUTIVE SUMMARY
In May 2013, the UK Government publicly committed to implementing the Extractive
Industries Transparency Initiative (EITI) and, in October 2014, the UK officially
became an implementing country by gaining candidacy status.
EITI is a global standard of transparency that requires oil, gas and mining
companies to disclose their payments to government agencies and for the
reconciliation of these payments with government receipts from these companies.
The initiative aims to encourage governments to be more transparent in publicising
the benefits they receive from their country’s natural resources. It also aims to
improve public understanding of the industries involved and inform public debate
over the management of a country’s natural resources.
EITI is a stakeholder-led initiative, overseen by a Multi-Stakeholder Group (MSG)
consisting of representatives from industry, civil society and government. The UK
MSG is committed to transparency and implementing the EITI global standard. It is
pleased to present the second UK EITI report for publication.
This report contains detailed information relating to a net total of £904 million of
revenues received by UK Government agencies from extractive companies in 2015,
for a range of payments included within the scope of EITI. The report shows a
breakdown of this total between the oil and gas and mining and quarrying sectors,
by the different payment types and by the Government agencies that received those
payments. A total of 42 oil and gas companies and 18 mining and quarrying
companies participated in compiling the report, showing a high level of industry
participation for 2015. The MSG is grateful to all those companies which participated
in the process this year and will continue to work towards full compliance in future
years.
Separate to EITI and complementing the information in this report, a number of
companies have started reporting their 2015 payments to governments, including
the UK government, under the EU Accounting and Transparency Directives.
The extractives sector in the UK
The extractive industries are an important sector in the UK, contributing a gross
value added (GVA) of £16.7 billion in 2015 to the UK economy. The oil and gas
industry accounts for the great majority of the sector’s GVA.
In 2015, the UK was the world’s 21st largest producer of oil and gas, supporting
hundreds of thousands of jobs in Scotland and across the country. The sector was
responsible for direct employment of 38,100 people, with many more supported in
the industry’s supply chain. However, 2015 saw a dramatic fall in the global oil price,

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UK EITI report for 2015
from $99/barrel on average in 2014 to $52/barrel on average in 2015. This
represented a challenging period for the industry globally, with activity and
investment in the UK reducing significantly. This resulted in lower payments to
government compared with 2014.
Mining and quarrying in the UK involves a diverse range of significant mineral
deposits for construction, industrial and metal uses, as well as coal. Mining and
quarrying are important regional and rural employers, with 2,000 employed in coal
mining, 7,400 in quarrying and 7,700 in the operation of gravel and sand pits, mining
of clays and kaolin in 2015.
Reconciliation
The two tables below summarise the reconciled extractive industry payments to and
repayments by UK Government agencies in 2015. All material differences have
been reconciled. The body of this report explains the methodology used to reach
these figures, as well as the explanation for repayments and unreconciled figures.
Summaries of Extractive Industries Payments to/refunds from UK Government
in 20151

Payment stream:
Petroleum
Licence
Fees
OGA
Levy
PRT
RFCT &
SC
Mainstream
CT
Payments
to TCE
Payments
to TCE
Payments
to CA
Total
payments
Type of payee:
Oil &
Gas
Oil &
Gas
Oil &
Gas
Oil &
Gas
Other
Mining &
Quarrying
Oil &
Gas
Other
Mining &
Quarrying
Other
Mining &
Quarrying
All
Recipient:
OGA OGA
HMRC
HMRC
HMRC
TCE
TCE
CA
All
Total reported by government
agencies
66.11
8.49 -498.25 1,278.07
33.26
5.69
21.62
0.80
915.79
Total reported by government
agencies for out-of-scope
extractive companies*
8.15
0.71
0.00
0.76
0.00
1.42
0.13
0.65
11.82
Total reported by government
agencies for in-scope
extractive companies
57.96
7.78 -498.25 1,277.32
33.26
4.27
21.48
0.15
903.96
Total reported by in-scope
extractive companies
57.96
7.78 -498.26 1,277.32
33.25
4.27
21.48
0.14
903.95
Net unreconciled difference**
0.00
0.00
0.01
0.00
0.00
0.00
0.00
0.00
0.01
(in £ million)
1 Payments for petroleum licence fees and field-level petroleum revenue tax payments and
applicable payments to TCE are included in the online disclosure of project level payments and
repayments at https://www.gov.uk/government/publications/extractive-industries-transparency-
initiative-payments-report-2015

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UK EITI report for 2015
Type of payee:
Oil &
Gas
Other
Mining &
Quarrying
All
All
All
All
All
Recipient:
All
All
OGA
HMRC
TCE
CA
All
Total reported by government
agencies
860.12
55.67
74.60
813.08
27.31
0.80
915.79
Total reported by government
agencies for out-of-scope
extractive companies*
11.04
0.78
8.86
0.76
1.56
0.65
11.82
Total reported by government
agencies for in-scope
extractive companies
849.08
54.89
65.74
812.33
25.75
0.15
903.96
Total reported by in-scope
extractive companies
849.07
54.88
65.74
812.31
25.75
0.14
903.95
Net unreconciled difference**
0.01
0.00
0.00
0.01
0.00
0.00
0.01
(in £ million)

* Out-of-scope companies comprise those out of scope of the reconciliation because their
payments were below the agreed materiality thresholds and those with material payments that
declined to participate in the reconciliation process.
** All net unreconciled differences are below the materiality deviation agreed by the MSG
Additional changes to the process
Oil and gas
For this year’s report, HMRC provided a list of oil and gas companies in scope of
EITI which made material payments. This allowed the Independent Administrator
(IA) to limit requests to those oil and gas companies in scope for 2015.
Following a thorough review of the first year’s reconciliation process and addressing
specific recommendations by the IA, the MSG agreed two key amendments to the
oil and gas reconciliation:
1. Bringing into scope payments to The Crown Estate (TCE) for pipeline easements
(rights to route pipelines across the foreshore) from those companies extracting
oil and gas in the UK.
2. Targeting the reconciliation of payments to the Oil and Gas Authority (OGA). It
was decided that companies comprising the top 80% of payments to the OGA
(for petroleum licences and the OGA Levy) should be reconciled, with unilateral
reporting of government receipts for the remaining companies. This resulted in
some of the smaller companies falling out of scope of the reconciliation process.

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UK EITI report for 2015
Other mining and quarrying
Unlike the oil and gas industry, the rest of the mining and quarrying sector is not
subject to a special tax regime for extraction and production. Other mining and
quarrying companies are instead subject to the general UK corporate tax regime
which can result in them paying a single amount for corporation tax which covers
both extractive and, where relevant, non-extractive activities. This means that,
whereas HMRC can confirm which companies made material payments relating to
the extraction of oil and gas, it is unable to identify which other mining and quarrying
companies make material payments of corporation tax related to their extraction
activities.
The MSG’s review of the first report resulted in a new methodology for the sector.
The number of mining and quarrying companies from which information was
requested this year has been refined to ensure that only those thought to be making
significant payments to government are included. All companies making material
payments to TCE and the Coal Authority have been included, along with other larger
businesses in the mining and quarrying sector. The MSG considers this to result in
data which are more representative of the sector. The MSG is committed to
reviewing the methodology to avoid asking companies that make very minor
payments to participate.
Beneficial ownership
The report includes information on beneficial ownership in sub-section 3.6 and
Annex 1 below. Contributions in this area have shown an increase from last year,
with 15 private companies responding, 6 of which provided relevant information or
links. This compared with only 1 of 13 private companies providing material
beneficial ownership information for 2014.

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UK EITI report for 2015
2. INFORMATION ON THE UK EXTRACTIVE INDUSTRIES

2.1. The Extractive Industries in the UK
The extractive sector has made a sizeable contribution to the UK economy for many
years, supporting substantial added value in downstream industries and related
supply chains in addition to its direct output. As illustrated in Figure 1, below, by far
the largest economic contribution comes from oil and gas production even though
the value of that sector has more than halved in recent years. There is currently no
UK state participation in the extractive industries.
Figure 1. Extractive industry Gross Value Added (GVA)1

In some of the summary information below, coal is grouped with oil and gas (where
data are available for fossil fuels but not for other parts of the sector). However, for
most of this chapter, oil and gas (Section 2.2) are treated separately from mining
and quarrying, including coal (Section 2.3). In addition, it should be noted that the
phrase “mining and quarrying” as used in UK national statistics embraces the whole
UK extractive sector including oil and gas production as well as coal production.
1 Source: ONS, UK GDP, preliminary estimate: Oct to Dec 2016, published 26 January 2017
https://www.ons.gov.uk/releases/ukgdppreliminaryestimateocttodec2016

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UK EITI report for 2015
Mining support services are also included in this sector. Some of the data reported
below include those activities while other data exclude them.
2.1.1. Value of the sector
The table below shows GVA in millions of pounds for the main components of the
mining and quarrying sector as reported in UK national statistics. As just noted, this
sector includes fossil fuel production, other mining and quarrying and mining support
service activities. The table covers the years 2011–15 and gives for each subsector
its percentage share of total UK GVA in 2015. It also shows the whole sector’s GVA
as a percentage of national gross domestic product (GDP) for each year.1
Gross Value Added (£ million)
Year
Mining
of coal
and
lignite
Extraction
of crude
petroleum
and natural
gas
Other
mining
and
quarrying
Mining
support
service
activities
Total
mining
and
quarrying
etc.
Total
GVA
Total
GDP
Total

(A)
(B)
(C)
(D)
(E) = (A)–
(D)
(F)
(G)
(E) / (G)
2011
399
26,528
2,523
2,669
32,119 1,452,075 1,628,274
2.00%
2012
359
22,151
3,076
2,811
28,397 1,495,576 1,675,044
1.70%
2013
200
21,861
2,902
2,406
27,369 1,551,553 1,739,563
1.60%
2014
125
18,534
2,860
2,286
23,805 1,624,276 1,822,480
1.30%
2015
86
11,464
2,932
2,242
16,724 1,663,792 1,870,693
0.90%
%*
0.0%
0.7%
0.2%
0.1%
1.0%
100.0%

* The percentages in this row are shares of total GVA for all industries in 2015.
Source: ONS, UK GDP, preliminary estimate: Oct to Dec 2016, published 26 January 2017.
https://www.ons.gov.uk/releases/ukgdppreliminaryestimateocttodec2016
https://www.ons.gov.uk/economy/nationalaccounts/uksectoraccounts/datasets/unitedkingdomecon
omicaccountsmainaggregates
The following table gives a finer breakdown of the sector in 2015 to give a sense of
the scale of activity in each subsector. Although the data in both this table and the
one above are sourced from official Office of National Statistics (ONS) data, they are
not identical. Note that in value terms support service activities are almost entirely
related to extraction of petroleum and natural gas.
1 Generally, in this chapter, unlike in the ONS table and some other official sources, a
terminological distinction is made between “oil and gas” and “[other] mining and quarrying”, the
latter comprising the extraction of coal and of all non-hydrocarbon minerals, and excluding oil and
gas. In this report, unlike last year’s, we have not excluded mining support service activities from
the total for the sector when calculating its contribution to GDP.

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UK EITI report for 2015
Mining and quarrying including oil and gas production: 2015
SIC
07
Code Description
Number of
enterprises
Approximate
GVA at basic
prices
(aGVA)
Total
employment
costs
Number
£ million
£ million
06
Extraction of crude petroleum and natural
gas
98
8,034
2,709
09.1
Support activities for petroleum and natural
gas extraction
252
2,914
2,058
08.11 Quarrying of ornamental and building stone,
limestone, gypsum, chalk and slate
235
916
488
08.12 Operation of gravel and sand pits; mining of
clays and kaolin
180
950
390
08.92 Extraction of peat
19
25
12
08.93 Extraction of salt
8
55
29
09.9
Support activities for other mining and
quarrying
125
41
46
B
Mining and quarrying
1,189
13,290
5,930
Source: Annual Business Survey; Release Date 10 November 2016.

2.1.2. Government revenues
UK Government accounts cover the period April–March rather than a calendar year,
so some of the data on government revenues reported in this chapter are of
necessity on a financial year basis. Where possible, calendar year data are (also)
provided, as in the table below.

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UK EITI report for 2015
UK Government revenues from upstream oil and gas
£
million
Total
Corporation
Tax
Of
which
offshore
Petroleum
Revenue
Tax
Total
Upstream
Oil and
Gas
Total
HMRC
receipts
Upstream Oil
and Gas
Share of Total
(%)

(A)
(B)
(C) = (A) +
(B)
(D)
(E) = (C) / (D)
2011-12
43,130
8,840
2,032
10,872 472,315
2.3%
2012-13
40,482
4,412
1,737
6,149 473,777
1.3%
2013-14
40,327
3,556
1,118
4,674 493,646
0.9%
2014-15
43,005
2,073
77
2,150 515,348
0.4%
2015-16
44,410
538
-562
(24) 533,686
0.0%

2011
43,231
8,270
1,775
10,045 469,554
2.1%
2012
40,725
5,847
2,106
7,953 470,766
1.7%
2013
40,417
3,881
1,296
5,177 489,333
1.1%
2014
41,577
2,538
569
3,107 506,570
0.6%
2015
44,932
934
-553
381 528,288
0.1%
Source: HM Revenue & Customs (HMRC), Tax Receipts and National Insurance Contributions for
the UK, https://www.gov.uk/government/statistics/hmrc-tax-and-nics-receipts-for-the-uk.
The table above includes estimates of the amounts of ring fence corporation tax
(RFCT) paid annually in respect of UK upstream oil and gas production activities,
i.e. the exploration and production stage (described for simplicity as “offshore” CT),
and of petroleum revenue tax (PRT). UK Government accounts are compiled on a
financial year basis and the figures reported above are consistent with the annual
totals reported in them.
There are differences between the totals reported above for RFCT/SC and PRT,
based on published HMRC statistics, and the post-reconciliation totals reported
elsewhere in this report. These totals and the differences, which are explained
below, are as follows:
(in £ million)
Reconciled total
Total above
Variance
Variance %
of reconciled
total
RFCT & SC
1,278
934
344
26.9%
PRT
-498
-553
55
11.0%

The difference for RFCT/SC is partly explained by the fact that HMRC’s published
statistics do not include interest, which is included within the scope of EITI. Equally,
when companies make payments they are not obliged to inform HMRC whether the
payments relate to an upstream, RFCT/SC liability or a downstream, non-ring fence

| P a g e 12

UK EITI report for 2015
liability. Some companies do tell HMRC when they make a payment what liability it
relates to, but others do not. HMRC undertakes work to try to understand which
payments relate to upstream activities and which do not, but it does not do a full
reconciliation of the figures with the companies.
For PRT, the discrepancy is primarily the result of timing differences between
payments and repayments being made and the date that they are recorded on
HMRC’s systems.
Because corporation tax is levied on company level profits and companies can be
engaged in both extractive and non-extractive activities, it is not possible to identify
how much CT is paid by other extractive industries (i.e. those engaged in mining
and quarrying). Estimates of the CT paid by the mining and quarrying sector are
published annually by HM Revenue and Customs (HMRC) and include oil and gas
and mining support service activities. They are on a liability basis for financial years
rather than a cash basis for calendar years; the latest published estimate relates to
2014-15. 1 In addition to taxation, the extractive sector in the UK pays relatively
small amounts to government by way of licence fees and other levies. These
payments are summarised later in this sub-section.
The level of government revenues from taxes on production of oil and gas is
dependent on rates of taxation and adjusted profitability which is driven by a
combination of production volumes, commodity prices and cost levels. Historical
data by financial year since 1976/77 on upstream oil and gas taxes, including
petroleum licence fees, are shown in constant price terms in Figure 2. The chart
also shows the average level of oil prices (measured by the Brent crude benchmark)
since that is a key determinant of the changes in revenues.
1 HMRC August 2016, Corporation Tax Statistics, Table 11.7,
https://www.gov.uk/government/statistics/analyses-of-corporation-tax-receipts-and-liabilities-
document-august-2015

| P a g e 13

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UK EITI report for 2015
Section 1061 payments are made (in England, plus equivalent payments made
elsewhere in the UK) to local authorities relating to the granting of planning
permission for mining operations to cover, for example, local road and infrastructure
improvements. These are the only payments currently mandated by Government
that could possibly constitute social expenditure by extractive companies.
There are no non-monetary arrangements between extractive companies and the
government in the UK.
Forecasts of UK Government oil and gas revenues are published by the
independent Office for Budget Responsibility (OBR), covering the medium-term
budget horizon (currently to 2021/22) and longer-term outlook (most recently to
2040/41).2 The OBR also publishes details of its underlying forecasts of oil and gas
production, prices and expenditure broken down between exploration and appraisal,
development capital expenditure, operating costs and decommissioning costs.
For projections of future oil and gas production volumes, and the production outlook
for coal and non-hydrocarbon minerals, see sections 2.2 and 2.3 respectively.
Total public sector current receipts (excluding public sector banks) in calendar year
2015 amounted to £674,208 million3 including a net total of £904 million (or 0.1%)
received from extractive companies.
2.1.3. Exports
Up-to-date official trade data are not available for non-fossil fuel minerals. Data are
available for fossil fuels. Data on the volume and value of exports (and imports) of
fossil fuels are tabulated below, together with the volume and value of indigenous
production.4 The UK exports coal, oil and natural gas but, with the decline in
indigenous production of all three fossil fuels, imports more and is thus overall a net
importer of each.

1 Section 106 of the Town and Country Planning Act 1990.
2 OBR, Economic and Fiscal Outlook, November 2016,
http://budgetresponsibility.org.uk/efo/economic-and-fiscal-outlook-november-2016/; OBR, Fiscal
Sustainability Report, June 2015, http://budgetresponsibility.org.uk/fsr/fiscal-sustainability-report-
june-2015/
3 Source: ONS, Public sector current receipts: Appendix D, 21 March 2017,
https://www.ons.gov.uk/economy/governmentpublicsectorandtaxes/publicsectorfinance/datasets/a
ppendixdpublicsectorcurrentreceipts
4 Source: BEIS, Digest of UK Energy Statistics 2016,
https://www.gov.uk/government/collections/digest-of-uk-energy-statistics-dukes

| P a g e 15

UK EITI report for 2015

Volume of exports (mtoe)
Value of exports (£ million)
Year
Coal
Oil
Natural Gas
Oil & Gas
Coal
Oil
Natural Gas
Oil & Gas
2011 0.370 36.770
15.794
52.565
60 16,830
3,555
20,385
2012 0.368 33.837
12.384
46.221
55 16,435
2,715
19,150
2013 0.447 36.192
9.429
45.622
90 17,460
2,510
19,970
2014 0.319 33.774
11.013
44.787
55 14,630
2,005
16,635
2015 0.290 36.813
13.893
50.706
45
9,920
2,265
12,185

Volume of imports (mtoe)
Value of imports (£ million)
Year
Coal
Oil
Natural Gas
Oil & Gas
Coal
Oil
Natural Gas
Oil & Gas
2011 21.399 63.471
50.600
114.071
3,050 30,115
9,630
39,745
2012 29.061 66.090
47.250
113.340
3,315 31,270
10,045
41,315
2013 32.122 64.489
46.011
110.500
3,235 30,010
10,985
40,995
2014 27.581 58.676
41.001
99.677
2,260 24,070
7,250
31,320
2015 15.950 55.278
42.337
97.615
1,015 13,365
7,240
20,605

Volume of net exports (mtoe)
Value of net exports (£ million)
Year
Coal
Oil Natural Gas
Oil & Gas
Coal
Oil Natural Gas
Oil & Gas
2011 (21.029) (26.701)
(34.805)
(61.506)
(2,990) (13,285)
(6,075)
(19,360)
2012 (28.693) (32.253)
(34.867)
(67.119)
(3,260) (14,835)
(7,330)
(22,165)
2013 (31.675) (28.297)
(36.582)
(64.878)
(3,145) (12,550)
(8,475)
(21,025)
2014 (27.262) (24.902)
(29.988)
(54.890)
(2,205)
(9,440)
(5,245)
(14,685)
2015 (15.661) (18.465)
(28.444)
(46.909)
(970)
(3,445)
(4,975)
(8,420)

Volume of indigenous production (mtoe)
Value of indigenous production (£ million)
Year
Coal
Oil Natural Gas
Oil & Gas
Coal
Oil Natural Gas Oil & Gas
2011 11.532 56.902
45.289
102.191
1,175
26,525
7,890
34,415
2012 10.583 48.756
38.925
87.681
990
23,685
7,840
31,525
2013
7.973 44.468
36.523
80.991
500
21,330
7,755
29,085
2014
7.289 43.705
36.831
80.537
440
18,185
6,655
24,840
2015
5.384 49.544
39.622
89.165
285
12,260
5,815
18,075
Source: Digest of UK Energy Statistics 2016.

As noted above, data for 2015 on the volume and value of exports, imports and
production of non-fossil fuel minerals are not yet available. 2015 data for specific
minerals are due to be incorporated into the British Geological Survey (BGS) UK
Minerals Yearbook 2016 from the Annual Minerals Raised Inquiry (AMRI), carried
out by the Office for National Statistics (ONS) for the Department of Communities
and Local Government (DCLG), and should become available during 2017. For the
latest available data, for 2014, see Section 2.3.

| P a g e 16

UK EITI report for 2015
The value of UK Exports of Goods and Services (Balance of Payments basis) in
calendar year 2015 amounted to £517,446 million1 including £12,185 million (or
2.4%) from Coal, Oil and Natural Gas.
2.1.4. Employment
The table below gives estimates of the total UK workforce (in thousands) directly
supported by the UK mining and quarrying sector including its major sub-sectors. It
also shows the estimates for 2015 as shares of the total workforce for all industries.
The extractive industries are typically capital- rather than labour-intensive and
correspondingly represent a significantly smaller share of the workforce than of
GVA.
Workforce estimates from Business Register and Employment Survey
(thousand)
Mining of coal
and lignite;
Extraction of
crude
petrol/gas [SIC
(2007) Divisions
05-06]
Mining of metal
ores; Other
mining and
quarrying [SIC
(2007) Divisions
07-08]
Mining
support
service
activities [SIC
(2007) Division
09]
Total
mining &
quarrying
etc. [SIC
(2007)
Section B]
Total
Industries
[SIC (2007)
Sections A-T]
2011
21
19
25
65
31,440
2012
24
22
30
76
31,788
2013
22
18
30
70
32,156
2014
21
17
29
68
33,204
2015
20
21
30
70
33,739
2015 %
0.1%
0.1%
0.1%
0.2%
100.0%
Source: ONS, https://www.ons.gov.uk/releases/uklabourmarketstatisticsdec2016
The following table shows estimates (in thousands) of extractive industry
employment in Great Britain (GB) (excluding Northern Ireland) between 2011 and
2015 (inclusive) at a finer level of disaggregation than is available for the workforce
estimates for the United Kingdom (UK).
1 Source: ONS, UK trade: Jan 2017, 10 March 2017,
https://www.ons.gov.uk/economy/nationalaccounts/balanceofpayments/bulletins/uktrade/jan2017

| P a g e 17

UK EITI report for 2015
Extractive industry employment in GB and UK (in thousands)
SIC
2007
2011 2012 2013 2014 2015
GB
05101
Deep coal mines
3.6
3.9
2.2
1.6
0.9
GB
05102
Open cast coal working
2.8
2.9
2.4
1.3
1.1
GB 05
Mining of coal
6.4
6.9
4.6
2.9
2.0
GB 06
Extraction of crude petroleum and natural
gas
13.2 15.6 15.5 16.6 15.7
GB
08110
Quarrying of ornamental and building
stone; limestone; gypsum; chalk and slate
6.2
6.9
4.9
6.7
7.4
GB
08120
Operation of gravel and sand pits; mining
of clays and kaolin
8.5
8.7
7.0
7.1
7.7
GB 081 Quarrying of stone; sand and clay
14.7 15.5 12.0 13.8 15.1
GB
08930
Extraction of salt
0.3
0.3
0.3
0.4
0.4
GB
08990
Other mining and quarrying n.e.c.
1.1
2.1
1.1
1.1
1.3
GB 089 Mining and quarrying n.e.c.
2.5
3.9
2.4
2.7
3.2
GB 08
Other mining and quarrying (other
than mining of metal ores)
17.1 19.4 14.4 16.4 18.3
GB 091 Support activities for petroleum and
natural gas extraction
20.8 22.3 21.2 25.1 22.4
GB 099 Support activities for other mining and
quarrying
0.3
0.6
0.4
0.3
0.4
GB 09
Mining support service activities
21.1 22.9 21.6 25.4 22.9
GB 05–
09
Total Extractive Industries
57.8 64.8 56.1 61.3 58.9

GB 06,
09
of which Oil and Gas Extraction and
Support Services
34.0 37.9 36.7 41.7 38.1

UK 05,
06
Mining of coal and lignite; Extraction
of crude petrol/gas
20.5 23.5 21.8 21.0 19.5
UK 07,
08
Mining of metal ores; Other mining and
quarrying
19.3 22.0 18.3 17.5 22.8
UK 09
Mining support service activities
24.8 30.0 30.3 29.5 31.8
UK 05–
09
Total Extractive Industries
64.5 75.5 70.3 68.0 74.0
Source: ONS, Business Register and Employment
Survey
GB
https://www.ons.gov.uk/employmentandlabourmarket/peopleinwork/employ
mentandemployeetypes/datasets/industry235digitsicbusinessregisterandem
ploymentsurveybrestable2
UK
https://www.ons.gov.uk/employmentandlabourmarket/peopleinwork/employ
mentandemployeetypes/bulletins/uklabourmarket/september2016

| P a g e 18

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(thousand) (share)
North East
2
3%
North West
2
2%
Yorkshire and The Humber
4
6%
East Midlands
6
8%
West Midlands
2
3%
East of England
2
3%
South East
4
5%
London
4
5%
South West
5
6%
Wales
2
3%
Scotland
38
53%
Northern Ireland
2
3%
United Kingdom
72
100%
2015
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
_P a g e  19


UK EITI report for 2015
The majority of coal production comes from sites in Scotland, England and South
Wales, as mapped by the Coal Authority.1 The mining and quarrying of non-
hydrocarbon minerals are widely distributed across the UK. There are no significant
hard-rock aggregate deposits in the South and East of England, so these materials
are transported for use in these regions from further afield in the Midlands and
South West in particular.
For further details of the geographical location of UK oil, gas and minerals
production, see sections 2.2 and 2.3.
2.1.6. UK fossil fuel production and UK energy demand
UK production of fossil fuels has been, and continues to be, significant in terms of
meeting UK energy demand. This is particularly true of oil and gas but, nowadays,
much less so for coal. While the share of total demand represented by fossil fuels
has been declining, they still account for more than four fifths of total primary energy
demand. With higher UK production and historically low UK demand, in 2015 UK
fossil fuel production was equivalent to almost half of total UK energy demand. This
is illustrated in the charts below:
Figure 4. UK fossil fuel production and primary energy demand

Source: Energy Trends Table 1.3
1 Coal Authority, Interactive Map, http://mapapps2.bgs.ac.uk/coalauthority/home.html

| P a g e 20

UK EITI report for 2015

Figure 5. Destination of UK oil production and sources of UK supply, 2015

Source: Digest of UK Energy Statistics (DUKES), July 2016 [principally Table G4]

| P a g e 21

UK EITI report for 2015
Figure 6. UK monthly gas supply

Figure 7. Sources of UK gas supply on a rolling 12 month basis

Source for both charts: Energy Trends Tables 4.2 and 4.3

| P a g e 22

UK EITI report for 2015
2.2. Oil and Gas
2.2.1. Production
The UK’s oil and gas sector is dominated by production from offshore areas, which
account for virtually all of UK output.1 Production of natural gas began in 1967 with
the West Sole field in the Southern North Sea. Offshore oil production began with
the Argyll field in the Central North Sea (CNS) in 1975.
Combined oil and gas production volumes peaked in 1999 at 4.6 million barrels of oil
equivalent (boe) per day and have since declined to 1.6 million boe/day in 2015,
split roughly 60:40 between oil production and natural gas production (Figure 8).
Figure 8. UK oil and net gas production2

The OGA publishes data relating to production of UK oil and gas, including
production data for individual fields, current and historical production figures,
production projections, and tables and charts on UKCS income and expenditure.3
1 Wytch Farm in Dorset, England, is the only substantial onshore field and is partly covered by a
“seaward” licence; the drilling sites are onshore, but some of the wells extend under Poole
Harbour. Wytch Farm is here treated as offshore.
2 Source: OGA, https://www.ogauthority.co.uk/data-centre/data-downloads-and-
publications/production-data/. Net natural gas production equals gross production less producers’
own use, i.e. the gas used in the course of production of oil and gas and therefore not available for
sale to end users.
3 OGA, https://www.ogauthority.co.uk/data-centre/data-downloads-and-publications/

| P a g e 23

UK EITI report for 2015
2.2.2. Background and recent developments
At the start of the industry in the 1960s and 1970s production was dominated by a
small number of very large, profitable fields, such as Forties, Brent, Ninian and
Piper, and the development of key offshore infrastructure pipelines. UKCS
production now comes from a large number (over 300) of predominantly small fields
and others that are much more technically complex to produce from, both of which
tend to increase unit development and production costs. The overall level of
production has fallen significantly, especially in the last decade – a consequence of
natural reservoir decline in existing fields combined with fewer/smaller
developments. This decline was arrested in 2014; 2015 witnessed the first year-on-
year production growth since 1999 on account of a few new large developments and
improvements in production efficiency of older installations. Figure 9 illustrates this
for crude oil production. Note that the annual aggregates of field-level data charted
here do not coincide exactly with the totals used elsewhere in this report.
Figure 9. UK oil production by start-up year of field1

1 Source: OGA, https://www.ogauthority.co.uk/data-centre/data-downloads-and-
publications/production-data/

| P a g e 24

UK EITI report for 2015
As shown in the following table, which displays the annual average oil price in
dollars per barrel and pounds per barrel from 2011 to 2015 (inclusive), 2015 saw a
dramatic fall in the global oil price, from $99/barrel on average in 2014 to $52/barrel
on average in 2015.
Annual average oil price (Brent crude spot price)1
2011
2012
2013
2014
2015
$/barrel
111
112
109
99
52
£/barrel
69
71
70
60
34
Total upstream expenditure peaked in 2014 at £27.8 billion and is estimated to have
fallen to £20.8 billion in 2015 as companies cut discretionary spending in the face of
low oil prices. The year 2015 saw development consent for 5 new fields and 10
incremental projects and also saw the cessation of production from 16 fields. It was
also the third consecutive year of negative cash flow, i.e. post-tax income was less
than expenditure. Profitability was at a historic low since records began in 1997.2
The UK is still a significant oil and gas producer, being responsible for 1.1% of
global output of oil and gas. In 2015, the UK was the 21st largest producer of oil and
gas globally (ranked 21st for oil and 22nd for gas production).3
2.2.3. Reserves and forecasts
A total of 43 billion barrels of oil equivalent (boe) had been produced from the UKCS
by the end of 2015. The OGA estimates remaining recoverable hydrocarbon
resources from the UKCS to be between 10 and 20 billion boe.4 Full details of the
assumptions underpinning forthcoming years in the Budget cycle relating to
projected production, commodity prices and revenue forecasts are provided by the
independent OBR.5
Exploration activity in 2015 was at an all-time low since the start of offshore
exploration in the mid-1960s. Only 13 offshore exploration wells (including
1 Sources: http://www.imf.org/external/np/res/commod/index.aspx ($ oil price) and
http://www.bankofengland.co.uk/statistics/Pages/default.aspx (£/$ exchange rate).
2 ONS profitability of UK companies dataset,
https://www.ons.gov.uk/economy/nationalaccounts/uksectoraccounts/datasets/profitabilityofukcom
panies
3 BP, Statistical Review of World Energy, 2016, http://www.bp.com/en/global/corporate/energy-
economics/statistical-review-of-world-energy.html
4 OGA, Reserves and Resources, https://www.ogauthority.co.uk/data-centre/data-downloads-and-
publications/reserves-and-resources/
5 OBR, http://budgetresponsibility.org.uk/

| P a g e 25

UK EITI report for 2015
sidetracks) were drilled in the year. Discovered volumes are thought to have been
around 150 million boe, an improvement on recent years, but still below the 10-year
average.1 Cumulative reserves produced to date are catching up with cumulative
resources discovered to date (Figure 10) and the number of fields discovered but
not yet developed is dwindling – an important issue for the long-term future of the
UKCS.
Figure 10. Recoverable UKCS reserves discovered and reserves produced2

Forecasts of future production rates vary. Oil & Gas UK predicts that production will
continue to increase in the near term, with the start-up of some very large projects
more than offsetting anticipated decline from existing fields. By contrast, the OGA’s
central projection is for a return to declining production after increases seen in 2015
and 2016 (Figure 11).
1 Oil & Gas UK, Activity Survey 2016, http://oilandgasuk.co.uk/
2 Underlying data from Wood Mackenzie, Upstream Data Tool,
http://www.woodmac.com/content/portal/energy/highlights/wk4_Nov_13/Upstream%20Data%20To
ol.pdf; chart showing up to 2013 from Oil & Gas UK, Economic Report 2014,
http://oilandgasuk.co.uk/wp-content/uploads/2015/05/EC041.pdf, p. 28.

| P a g e 26

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_P a g e  27
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UK EITI report for 2015

Oil and gas (whether domestically produced or imported) provide over 70% of the
UK’s total primary energy needs and, despite policy objectives and measures
supporting the use of alternative energy sources, the Department for Business,
Energy and Industrial Strategy (BEIS)1 expects this percentage to stay stable up to
2030 under current policies.
2.2.5. Employment
In addition to direct employment in oil and gas companies there are a significant
number of jobs in companies providing support activities. Official estimates for both
are tabulated below.
Direct employment [GB not UK]
Thousands
2011 2012 2013 2014 2015
Oil and Gas Extraction
13.2
15.6
15.5
16.6
15.7
Support activities for petroleum and natural gas extraction
20.8
22.3
21.2
25.1
22.4
Oil and Gas Extraction and Support Services
34.0
37.9
36.7
41.7
38.1
Source: Business Register and Employment Survey.
http://www.ons.gov.uk/employmentandlabourmarket/peopleinwork/employmentandemployeetypes/
datasets/industry235digitsicbusinessregisterandemploymentsurveybrestable2
Additional information on employment in the UK oil and gas industry, including the
UK supply chain, is published by Oil & Gas UK.2 This information includes estimates
of the indirect and induced jobs that depend on the UK’s upstream oil and gas
sector in thousands from 2013 to 2015 (inclusive).3
Latest Oil & Gas UK estimates
Thousands
2013
2014
2015
Direct
36,600
41,700
38,200
Indirect
198,100
201,000
160,600
Induced
206,200
211,100
170,800
Total employment
440,900
453,800
369,700
1 Department set up in July 2016 combining parts of the Department for Business, Innovation and
Skills (BIS) with the Department of Energy and Climate Change (DECC).
2 http://oilandgasuk.co.uk/
3 http://oilandgasuk.co.uk/oil-gas-uk-figures-show-impact-of-oil-price-downturn-on-jobs/

| P a g e 28

UK EITI report for 2015
2.2.6. Legal framework and licensing1
The Petroleum Act 19982 vests rights to oil and gas (petroleum) resources in the
Crown. The government grants petroleum licences, giving exclusive rights to
“search and bore and get” petroleum (mineral oil, natural gas and any associated
hydrocarbons) over a limited area for a limited period. There are separate licensing
regimes for offshore (seaward) and onshore (landward) areas, with distinct licences
in each. In Northern Ireland, the Petroleum (Production) Act (Northern Ireland)
19643 vests the property in oil and gas in Northern Ireland, with certain exceptions,
in the Department for the Economy (DfE).
Before 1 April 2015 petroleum licences were awarded by the Department of Energy
and Climate Change (DECC). Since then a newly established independent
regulator, the Oil and Gas Authority (OGA), has been the licensing authority in all
areas other than onshore Northern Ireland, where the Northern Ireland Executive
has retained responsibility.
Northern Ireland’s offshore waters are subject to the same licensing regime as the
rest of the continental shelf. The OGA publishes oil and gas licences and licence
reports for GB and the UKCS.4 The OGA also publishes offshore and onshore
maps. The interactive maps allow users to find the co-ordinates of each licence and
download individual licences.5 Older licences have not all been scanned, so some
are not available online, but copies may be requested from the OGA.
The Northern Ireland DfE issues separate onshore licences independently of the
OGA and publishes current licences and a map showing licence areas.6
The OGA works to maximise economic recovery of the nation’s petroleum
resources. The government has essential pre-requisites for licence applicants, such
as requiring the would-be licensee to have a fixed place of business within the UK.
1 This sub-section draws on OGA, Oil and gas: petroleum licensing guidance,
https://www.ogauthority.co.uk/licensing-consents/overview/
2 Petroleum Act 1998, www.legislation.gov.uk/ukpga/1998/17/contents
3 Petroleum (Production) Act (Northern Ireland) 1964,
http://www.legislation.gov.uk/apni/1964/28/contents
4 OGA, https://www.ogauthority.co.uk/data-centre/data-downloads-and-publications/licence-data/
5 https://www.ogauthority.co.uk/data-centre/interactive-maps-and-tools/
6 DfE, Petroleum licensing, https://www.economy-ni.gov.uk/articles/petroleum-licensing

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Award and transfer of licences
Licences are awarded during regular competitive onshore and offshore licensing
rounds once the OGA has been satisfied that the licensee has met the necessary
technical and financial requirements.1 This method of licensing aims to optimise
recovery of the UK’s remaining petroleum resources. Out-of-round licence
applications are possible but only in exceptional circumstances and there were no
non-trivial deviations from the applicable legal and regulatory framework governing
licence transfers and awards during 2015. Licensing rounds are announced in the
Official Journal of the European Union and assessed against a publicly announced
set of criteria.2
Each licence takes the form of a deed, which binds the licensee (either a single
company or several working together and bound under joint and several liability) to
obey the licence conditions regardless of whether or not they are using the licence
at any given moment. The OGA (and DECC previously) regulates the transfer and
sale of licences in order to enforce its policy objectives.
Licence applications and interests attract fees and charges payable by the applicant
or licensee. Each licence carries an annual charge, commonly called a rental.
Rentals serve the double purpose of incentivising licensees to work their whole
licensed areas and to surrender acreage they do not intend to exploit. Rentals are
due every year on the licence anniversary, and are charged at a variable rate on
each square kilometre that the licence covers at that date. The rates are set out in
the licence document at award.
Licence conditions and types of licences
Each licence contains detailed terms and conditions, but not all regulation is
contained in the licence. The Petroleum Act 1998 requires these conditions — called
model clauses — to be published first in secondary legislation except in particular
cases.3 In recent years, the model clauses have also been set out in full in the
licence document.
Production licences are valid for a sequence of periods, or terms. These terms
mirror the typical life cycle of a field: exploration, appraisal and production, and
1 OGA documentation of award rounds is available at https://www.ogauthority.co.uk/licensing-
consents/licensing-rounds/
2 See for example http://eur-lex.europa.eu/legal-
content/EN/TXT/PDF/?uri=CELEX:52014XG0620(01)&from=EN for the announcement of the 14th
landward licensing round including the assessment criteria.
3 Petroleum Licensing (Exploration and Production) (Landward Areas) Regulations 2014,
http://www.legislation.gov.uk/uksi/2014/xx-xxxx-xxxx/contents/made

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provide that each licence will expire automatically at the end of each term, unless
the licensee has sufficiently progressed to warrant a move into the next term. The
duration of each term depends on the type of the licence.
The OGA publishes additional information about the different types of licences, their
normal duration and different phases of the licensing lifecycle.1
While landward licences confer the right to search for, bore and extract petroleum
on areas under licence, they do not exempt the licensee from other legal or
regulatory requirements, including a need to obtain access rights from landowners
or planning permission from relevant local authorities, or to conform to health and
safety regulations.
In Northern Ireland, there is only one type of petroleum licence, which has broadly
similar terms and condition to onshore GB Petroleum Exploration and Development
Licences (PEDLs) but also some differences.2
2.2.7. The oil and gas tax regime
Introduction
As the UK’s oil and gas industry has developed over the last 40 years, successive
governments have developed a tax regime designed to ensure that the nation
receives a fair share of the profits from the exploitation of its oil and gas reserves. At
the same time, the regime aims to support maximising the economic recovery of the
UK’s remaining hydrocarbon resources.
In 2015, the fiscal regime which applied to oil and gas extractive activities comprised
three separate taxes: Petroleum Revenue Tax (PRT), Ring Fence Corporation Tax
(RFCT) and the Supplementary Charge (SC).
The tax regimes
PRT
PRT is a tax on oil and gas production from the UK and UKCS. It is a field-based
tax, which means that the profits from individual oil fields are calculated and
subjected to tax separately. Companies do not aggregate their profits from different
fields and cannot normally set off losses from one field against profits from another.
PRT was introduced by the Oil Taxation Act 1975 and was abolished in Finance Act
1993 for all fields given development consent on or after 16 March 1993. This
means that fields that were given development consent after this date are not
subject to PRT.
1 OGA, https://www.ogauthority.co.uk/licensing-consents/overview/.
2 https://www.economy-ni.gov.uk/articles/petroleum-licensing.

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In 2015, PRT was charged at 50%.1
RFCT
RFCT is a tax charged on the profits a company earns from carrying out oil and gas
related activities. This can include exploration, development and production
activities. The profits chargeable to RFCT are calculated in the same way as for
mainstream CT, but with some different rules relating to certain allowances, interest
and transfer pricing. RFCT is charged at the company level, unlike PRT which is
charged at the field level. This means that where a company has several different oil
fields, it aggregates the profits from all those fields, and where any of the fields
makes a loss, that loss can be set against profits from another field. The total profit
across all fields in which a company operates is then charged to RFCT.
The ring fence separates the oil and gas related activities of a company from any
other activities of the company. It was introduced in the Oil Taxation Act 1975, and it
means that if a company also carries on other activities which are not related to oil
and gas extraction (this could include downstream oil and gas activity such as oil
refining, or other completely separate activities), it will pay mainstream corporation
tax (CT) on the profits of those other activities. Profits in the ring fence are taxed at
30%. This is higher than the main rate of CT for other activities which was 21% at
the start of 2015, falling to 20% from 1 April 2015. If a company makes a loss on
non-ring fence activities, it cannot set that loss against its ring fence profits (ring
fence losses can be set against non-ring fence profits).
If a company makes a small profit (less than £300,000) on its ring fence activities, it
pays tax at the small profits rate of 19% on those profits. If its profits are between
£300,000 and £1,500,000 it can claim Marginal Relief, to remove the cliff-edge
between 19% and 30% as soon as its profits are above £300,000.
SC
SC is an additional tax on a company’s adjusted ring fence profits. It was introduced
in 2002. Like RFCT it is charged at the company level. The starting point for
calculating the SC is the company’s profits subject to RFCT. These profits are then
adjusted to remove any finance costs, which are not allowed as a deduction for SC
purposes. The company may, however, be able to reduce its profits subject to the
SC by virtue of certain allowances: the Investment Allowance and Cluster Area
1 In Finance Act 2015, the rate was reduced to 35% with effect from 1 January 2016. However,
this was superseded by the Chancellor’s announcement at Budget 2016, that from 1 January 2016
the PRT rate would be permanently reduced to 0%. As a result, from this date, no company will
pay PRT. However, it is important to note that PRT has not been abolished in legislation.
Companies will still have to record and declare their profits and may claim relief for losses
incurred.

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Allowance, and the Onshore Allowance, which are outlined below. The company’s
adjusted ring fence profits are then charged to SC. In 2015 the rate of SC was
20%.1
Summary of rates for 2015
• PRT – 50%
• RFCT – 30%
• SC – 20%
Interaction
PRT is an allowable deduction in calculating profits subject to RFCT and SC.
Equally, any refund of PRT is a taxable receipt for RFCT and SC purposes. RFCT
and SC are charged on the same profit base, so neither is allowable as a deduction
in calculating the profits chargeable to the other.
This means that the overall net tax burden was 75% on income from fields paying
PRT, and 50% for fields that were not paying PRT (ignoring any adjustment for
finance costs and allowances). An example of this is shown below:

PRT field
Non-PRT field
Profit
£1,000
£1,000
PRT at 50%
(£500)
-
Profits after PRT
£500
£1000
RFCT at 30%
(£150)
(£300)
SC at 20%
(£100)
(£200)
Profit after tax
£250
£500
Total tax (PRT+RFCT+SC)
(£750)
(£500)
Tax as a % of profit
75%
50%
There have been various changes to the tax rates for PRT, RFCT and SC. PRT
peaked at 75%, was reduced to 50% by Finance Act 1993, and as noted above, was
permanently zero-rated at Budget 2016. Mainstream CT rates have been reduced
substantially since 2008, but the RFCT rate has remained at 30%, creating a
differential between the two. SC has varied between 10% and 32% since its
introduction.
Previously, there was also a royalty levied at 12.5% of “well head value”. This was
abolished in 2002 as it distorted investment incentives. Supplementary Petroleum
Duty (SPD) existed in 1981 and 1982. Advance PRT was also payable between 1
January 1983 and 31 December 1986.
1 The rate of SC was reduced to 10% at Budget 2016, for chargeable periods ending after 31
December 2015.

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Allowances
There are various allowances that apply to reduce the amount of PRT, RFCT or SC
that a company has to pay.
PRT allowances
A number of allowances used to be available under the PRT regime to prevent an
excessive PRT burden falling on smaller, more economically marginal fields. Oil
Allowance was the only one that was still relevant in 2015. Oil Allowance ensures
that for at least the first 10 years of a field's life a substantial slice of production is
free from PRT. The available amounts are converted each chargeable period into a
“cash equivalent” which then reduces the liability to PRT.
RFCT allowances
Capital allowances
Capital allowances are a feature of the mainstream CT regime (and are also
available in relation to income tax). For CT purposes, the general rule is that capital
expenditure is not allowed as a deduction for tax purposes. This means that profits
chargeable to CT cannot be reduced by depreciation or similar expenses. The
capital allowance regime exists to provide some relief for capital expenditure
incurred.
There are particular allowances available for companies carrying on a ring fence
trade. These allowances mean that in practice, virtually all capital expenditure
incurred by oil and gas companies for the purposes of their ring fence trades will
qualify.
There are three types of allowance which are commonly relevant for companies
carrying on a ring fence trade. These are the Research and Development Allowance
(RDA), Mineral Extraction Allowance (MEA) and Plant and Machinery Allowances
(PMA). RDA and MEA tend to be relevant to companies incurring capital
expenditure on exploring for, appraising and gaining access to oil and gas during the
pre-production phase. PMAs are available on capital expenditure on items of plant
or machinery used in the ring fence trade. Mostly these are 100% First Year
Allowances (FYAs), which allow the full amount of the expenditure to be written off
for tax purposes in the accounting period in which the expenditure is incurred.
Ring Fence Expenditure Supplement (RFES)
RFES is designed to assist companies which do not yet have sufficient RFCT profits
against which to set their exploration, appraisal and development costs. The RFES
currently increases the value of unused expenditure carried forward from one
accounting period to the next by a compound 10% a year for a maximum of 10

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years (6 years prior to 2014). The company can elect which periods it wants to claim
RFES for. They do not have to be consecutive years.
SC allowances
Cluster Area Allowance
Legislation in the Finance Act 2015 introduced a new Cluster Area Allowance, which
aims to support large development projects in areas of high pressure and high
temperature, encouraging exploration and appraisal in the surrounding area (or
“cluster”). The allowance is generated by incurring capital expenditure within the
cluster area. The value of the allowance is 62.5% of the capital expenditure
incurred. Any allowance generated is carried forward year on year until it is
activated. Allowance is activated by production income from the cluster area. Once
the allowance has been activated it is set against profits subject to the SC, so that
any such profits are only subject to RFCT at 30%. Cluster areas are determined as
such by the OGA, and the only area determined by the end of 2015 was the
Culzean Cluster Area in the CNS.
Onshore Allowance
The Onshore Allowance was introduced in Finance Act 2014 to provide support for
the early development of onshore oil and gas projects which were economic but not
commercially viable at the prevailing tax rates. The onshore allowance covers both
conventional and unconventional hydrocarbons and replaces all existing field
allowances for onshore projects. The allowance works in a similar way to Cluster
Area Allowance: it is generated by capital expenditure, in an amount equal to 75% of
that capital expenditure. Once the allowance is activated by production income in
relation to an onshore site, the allowance is used to reduce the adjusted ring fence
profits which are subject to SC.
Field Allowance
In recent years, the discoveries and subsequent developments on the UKCS have
been increasingly small in size (less than 50 million boe, many of them as small as
25 million boe or less), and/or technically challenging. These fields were not
commercially viable at the previously prevailing tax rates. The Field Allowance was
therefore introduced in 2009 based on the physical characteristics of qualifying fields
(or in the case of the brownfield allowance, based on project economics). By the end
of 2014 there were a total of seven different categories of field that were eligible.
The Field Allowance gives an amount of production income that can be earned free
of the SC. The Field Allowance is only a relief against SC, so the full profit from the
field is always charged to RFCT at the full 30% rate (and to PRT for applicable
incremental projects).

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Investment Allowance
The existing system of offshore field allowances was replaced by a single
Investment Allowance in Finance Act 2015. Similarly to the Cluster Area and
Onshore Allowances, the Investment Allowance is generated by capital expenditure
incurred in relation to a qualifying oil field. The amount of allowance generated is
equal to 62.5% of qualifying capital expenditure. Investment Allowance is activated
by production income from the field, unlike Cluster Area Allowances, which can be
activated by income from any field in a designated cluster. Once activated, it is used
to reduce the adjusted ring fence profits chargeable to the SC.
The definition of qualifying expenditure for Investment Allowance and Cluster Area
Allowance is being extended. As a result, certain types of operating and leasing
expenditure incurred on or after 8 October 2015 may also be able to generate the
allowances.
Losses
There was a dramatic drop in the oil price during the second half of 2014 and 2015.
This meant that some previously profitable companies started to make losses,
particularly because the UKCS is a relatively high cost basin in which to operate. It
is also a mature basin, with production having started in the late 1960s, so
increasing numbers of fields are now in, or approaching, the decommissioning
stage. Decommissioning costs can be substantial, which can also push companies
into making a loss.
When a company makes a loss, it may be able to get relief for that loss through the
tax system. Loss relief is not unique to the oil and gas regime: it is a feature of
income tax, mainstream CT and other regimes too. Broadly, loss relief works by
allowing a loss made in one period to be set off, in certain circumstances, against
profits in the same or other periods.
PRT
As explained above, PRT is a field level tax, so loss relief is normally only available
against profits from the same field. The loss can be carried back and set against
profits of the field in previous periods, most recent period first, or carried forward to
set against future profits, earliest period first. The loss is set against the profit before
Oil Allowance. Only once all carry back and carry forward options are exhausted for
that participator and there are no further profits against which the loss can be set,
following cessation of production, can the loss then be relieved against profits of
earlier participators in the field. If there are still any unrelieved losses, they can be
relieved against profits from another field.

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Where a field has made an assessable profit, and paid tax in one period, and then
has subsequently made a loss and the participator has chosen to carry the loss
back, it could generate a repayment of tax.
RFCT
Where a company makes a loss for RFCT purposes, it can also choose how to treat
that loss. The default position is that the loss is carried forward to set against future
profits of the ring fence trade. However, the loss can also be set off against other
(non-ring fence) profits arising in the year, or it can be carried back to set against the
profits earned in previous years. Alternatively, where a company is part of a
corporate group, it can surrender the loss to another company making a profit in the
same period.
Under the normal rules, losses can only be carried back against profits arising in the
previous year. However, these time limits are extended where the trade has ceased,
in which case the loss may be carried back up to three years. For ring fence trades,
this time limit may be extended further where the loss is incurred as a result of
decommissioning expenditure. In such situations, the loss may be carried back to
any period ending on or after 17 April 2002, regardless of whether trade has ceased.
SC
SC is calculated on the same basis as RFCT, but with adjustment for finance costs.
However, there is no loss relief for SC per se. Rather, if a company makes a RFCT
loss, and elects to carry it forward or backward, it will reduce the RFCT profits, and
therefore the profit subject to SC of the subsequent or previous period will also be
reduced, potentially to nil.
Companies can only generate a refund where tax has already been paid. If a
company has not paid tax in a previous year because it has not previously made a
profit, it will not be able to carry the loss back, and will have to relieve it in one of the
other ways outlined above.
Variations in tax payments and repayments
The amount of tax paid by a company can vary year on year for a number of
reasons. Perhaps most obviously, changes in tax rates will affect the amount of tax
paid. In recent years, the rates of PRT and SC have both dropped, reducing the
amount payable under these taxes. The level of profits (or losses) made by a
company will also vary year on year. Factors such as capital expenditure incurred
both on decommissioning and on exploration and investment can reduce profits, and
variations in the oil price will have a substantial impact on trading receipts. Equally,
as explained above, while a company may make a profit in a year, if it has a loss to

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set against that profit, the amount of tax payable may fall, or indeed lead to a
repayment of tax.
Companies are charged to PRT for chargeable periods of 6 months, running from 1
January to 30 June, and 1 July to 31 December. Companies’ profits are charged to
RFCT and SC for accounting periods (APs). APs normally last for one year,
although they can sometimes be shorter. Different companies have different APs,
although commonly calendar or financial years are used.
PRT payments
There is a system of instalments and payments on account for paying PRT. The first
instalment is due two months into a chargeable period, and 5 subsequent
instalments are due each month thereafter. The amount of each instalment is 1/8 of
the payment on account for the previous chargeable period. However, companies
do not have to make an instalment payment if during the month in question they did
not deliver any oil, or a relevant appropriation of the oil won from the field, or receive
any chargeable tariff receipts.
Two months after the end of the chargeable period, a payment on account must be
made. The amount of this depends on the income, expenditure and allowances in
the relevant period. Finally, any further PRT due, which could be as a result of
HMRC rejecting an expenditure claim, for example, must be paid within 6 months of
the end of the chargeable period. From 2016, as the PRT rate is reduced to nil, no
PRT payments will be made.
RFCT/ SC payments
The rules for payment of RFCT and SC differ from the payment rules for mainstream
CT. Companies paying RFCT and SC, which would otherwise make payments
under the mainstream CT quarterly instalment payments (QIPs) regime, instead pay
their RFCT/SC in three payments: 6 months and 13 days from the start of the AP, 3
months after the first payment, and 14 days from the end of the AP. This means the
payments are due earlier than under mainstream CT rules. Where the AP is a year
in length, the three payments should be of equal amounts.
This report covers payments made in the 2015 calendar year. As a result of the
payment regimes described here, the tax due for a particular year may not relate
directly to the payments made in the year.
Decommissioning
Decommissioning is an inherent cost of doing business in the UKCS. As a result, tax
relief is given for decommissioning costs at the point that they are incurred and the
decommissioning is carried out (for accounting purposes a company will make an

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annual provision, but this cannot be deducted for tax purposes as the cash has yet
to be spent).
If decommissioning expenditure produces an overall loss for a year, then, as
explained above, the loss may be carried back against previous ring fence profits of
that company, as far as 2002 for RFCT and SC, and almost indefinitely against field
profits for PRT. Based on 2015 tax rates, losses generated by decommissioning
costs and carried back to be offset against previous profits will be relieved at 20%
for SC and 30% for RFCT in non-PRT paying fields. The rate of relief for PRT fields
is up to 75%. The amount of relief available is limited to the taxable profits of the
relevant field/company, and in economic terms represents a repayment of tax that
has been overpaid through the profitable life of the company or field.
Decommissioning Relief Deeds (DRDs)
In 2013 the government introduced legislation giving it the statutory authority to sign
contracts (DRDs) with companies operating in the UK and UKCS. The aim of the
DRD is to provide certainty over decommissioning tax relief.
The DRD works by guaranteeing the amount of tax relief due on decommissioning
expenditure in perpetuity, based on the relief available at Finance Act 2013. It
provides a payment from the Exchequer to compensate companies for adverse
changes to the tax relief available on decommissioning expenditure (but not due to
changes in tax rates) compared to those that existed in 2013. The DRD will also pay
out to a company that picks up the decommissioning liabilities of another company
that has defaulted under its Petroleum Act 1988 obligations to ensure the company
incurring the default expenditure is able to get relief. This provides industry with
certainty over the availability of decommissioning tax relief in future years, and has
unlocked additional investment capital in the UKCS.
Looking ahead: Driving Investment
At Budget 2014 the government committed to review the oil and gas fiscal regime.
Over 2014, HM Treasury (HMT) sought views on how the government should best
adapt the regime to the changing economics of the UKCS, create fiscal stability,
help the UKCS compete for investment and simplify the regime to support
maximising the economic recovery of the UK’s oil and gas resources.
In December 2014, the government published Driving Investment – a long-term plan
to reform the oil and gas fiscal regime.1 The conclusion was that, although the
fundamentals of the fiscal regime remained sound, significant change was needed
1
https://www.gov.uk/government/uploads/system/uploads/attachment_data/file/xx-xxxx-xxxx/PU1721_Dri
ving_investment_-_a_plan_to_reform_the_oil_and_gas_fiscal_regime.pdf

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within the ring fence in order to continue to attract investment. Some of the
highlights from the plan are set out below:
Policy-making principles
Driving Investment established three principles for future policy-making, in order to
balance the government’s twin objectives of maximising economic recovery of its
hydrocarbon resources and achieving a fair return for the nation on those resources.
Firstly, the overall tax burden would need to fall as the basin matured and new
projects became ever more marginal. Secondly, when making judgments about
fiscal policy, the government would consider the wider economic benefits of oil and
gas production, such as jobs, investment and exports, in addition to revenues.
Finally, when judging what constitutes a fair return for the nation, the government
would take account of the global competitiveness of commercial opportunities in the
UK and UKCS, and take account of both commodity prices and costs. The
government reaffirmed its commitment to these principles at Autumn Statement
2016. 1
Exploration - Driving Investment noted that exploration activity in the UKCS had
been falling for some time. In 2015, the government announced £20 million funding
for seismic surveys, in order to improve understanding of under-explored areas of
the UKCS. The data from these surveys has been made available to industry and
academia.2
Infrastructure - The government considered options for reforming the fiscal
treatment of infrastructure and consulted with industry in 2015. The government
announced at Budget 2016 that it would extend the investment and cluster area
allowances to cover tariff income.
Decommissioning - At Budget 2016, the government provided certainty that
companies will be able to access tax relief on their costs when they retain
decommissioning liabilities for an asset after a sale, to encourage new entrants for
late-life assets and the development of late-life business models. This was provided
by an HMRC technical note, 3 published alongside the Budget. The government also
announced it would build on the new decommissioning powers of the Oil and Gas
Authority (OGA) by undertaking further work with the OGA and industry to reduce
overall decommissioning costs, to deliver significant savings for industry and the
1 https://www.gov.uk/government/publications/autumn-statement-2016-documents/autumn-
statement-2016
2 A further £20 million for a second round of seismic surveys was announced at Budget 2016.
3 https://www.gov.uk/government/publications/oil-and-gas-companies-tax-relief-for-
decommissioning-expenditure/oil-and-gas- companies-tax-relief-for-decommissioning-expenditure

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Exchequer. If significant progress could be made, the government would explore
whether decommissioning tax relief could better encourage transfers of late-life
assets.
2.2.8. Payments to the OGA
The Petroleum Act 1998 vests in the Crown all rights to petroleum resources in GB
and on the UK Continental Shelf. The Act gives the OGA (formerly the Secretary of
State) powers to grant licences that confer exclusive rights to “search and bore for
and get” petroleum. Each of these licences confers such rights over a limited area
and for a limited period. Licences are awarded in periodic “rounds” subject to a
requirement that the holder will make annual payments (known as ‘licence rental
fees’). These payments are calculated on the basis of the area under licence and
incorporate an escalating scale of pre-determined rates per square kilometre. This is
to encourage licensee companies to relinquish acreage not undergoing productive
activity, thus making it available for relicensing to other potential interested
applicants. The vast majority of licence rental fees come from offshore licensing.
Receipts of petroleum licences under the Petroleum Act 1998 are collected by the
OGA (formerly DECC) for payment to the Consolidated Fund.
The OGA Levy was introduced with effect from 1 October 20151 and part-funds the
OGA, which became an Executive Agency of DECC on 1 April 2015 and a
Government-owned company on 1 October 2016.
2.2.9. Shale gas
Research by the BGS indicates that there are potentially large volumes of shale gas
beneath the UK. Further exploration is required before the full extent of these
resources is known and the amount of gas that is technically and commercially
recoverable can be estimated.
UK licence and fiscal terms do not generally differentiate between conventional and
unconventional hydrocarbon activities. For example, the Onshore Allowance (an
allowance against the SC which ensures that otherwise economic developments are
not uncommercial) is applicable to both new conventional oil and gas as well as to
shale gas developments. As PEDLs do not grant automatic rights to operations such
as drilling or hydraulic fracturing, any company looking to develop shale will also
need to obtain all necessary permissions, like planning and environmental permits.
In addition, a further range of measures specific to hydraulic fracturing and the shale
industry have been put in place to ensure that exploration is safe and
1 https://www.ogauthority.co.uk/regulatory-framework/legislative-context/industry-levy/

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environmentally sound. The Infrastructure Act 2015 specifies thirteen conditions that
need to be met before a hydraulic fracturing consent will be issued, including public
notification and a scheme to provide financial or other benefit for the local area. The
government has also put in place regulations which ensure that high-volume
hydraulic fracturing cannot take place within 1,200 metres beneath the surface of
National Parks, the Broads, Areas of Outstanding Natural Beauty, World Heritage
Sites and areas that are most vulnerable to groundwater pollution.
A number of companies holding PEDLs in England are developing shale gas
projects. North Yorkshire County Council has granted Third Energy permission to
hydraulically fracture an existing vertical well at its Kirby Misperton site, to give an
early indication of flow rates.1 On 6 October 2016, the Secretary of State for
Communities and Local Government published his decision on Cuadrilla’s appeals
relating to exploratory wells, hydraulic fracturing and monitoring works at Preston
New Road and Roseacre Wood, Lancashire.2 Nottinghamshire County Council has
approved an application to drill an exploratory well at the Springs Road site.3 The
application did not include plans for hydraulic fracturing.
The government has announced that it will create a Shale Wealth Fund to ensure
that communities which host shale sites can share the benefits of shale
development. Funding for the Shale Wealth Fund will consist of up to 10% of tax
revenues arising from shale gas production.4 On 25 October 2016, the government
recently a consultation seeking views on the delivery method and priorities of the
Shale Wealth Fund.5
In the Autumn Statement 2016, it was announced that the Shale Wealth Fund will
provide up to £1 billion of additional resources to local communities, over and above
industry schemes and other sources of government funding. Local communities will
benefit first and determine how the money is spent in their area.
The licensing of onshore oil and gas extraction underlying Scotland is devolved to
the Scottish Parliament, in addition to responsibility for the planning and
1 http://www.northyorks.gov.uk/32467
2 https://www.gov.uk/government/publications/recovered-appeals-cuadrilla-bowland-ltd-and-
cuadrilla-elswick-ltd-refs-3134386-3130923-3134385-and-3130924-6-october-2016
3 http://www.nottinghamshire.gov.uk/planning-and-environment/shale-gas-development/shale-gas-
development/latest-news/councillors-approve-planning-application-for-county-s-first-exploratory-
shale-gas-wells
4https://www.gov.uk/government/uploads/system/uploads/attachment_data/file/544241/shale_weal
th_fund_final_pdf-a.pdf
5 https://www.gov.uk/government/consultations/shale-wealth-fund

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UK EITI report for 2015
environmental aspects of the onshore oil and gas regime. In January 2015, the
Scottish Government announced a moratorium on granting planning and
environmental consents for unconventional oil and gas developments in Scotland
pending a comprehensive programme of research and a public consultation.1
On 27 February 2015, the government published the paper: Powers for a purpose:
Towards a lasting devolution settlement for Wales.2 One of the commitments was
that the licensing of onshore oil and gas extraction underlying Wales will be
devolved. These powers complement the Welsh Assembly’s existing planning
powers, and allow Welsh Ministers to take a strategic view of future licensing in
Wales. In February 2015 Welsh Minister for Natural Resources, Carl Sargeant
issued a new direction to Mineral Planning Authorities (MPAs) requiring them to
notify him of any planning application where unconventional extraction techniques
such as fracking are proposed. This direction only applies if the MPA plans to
approve the application and gives the Minister an opportunity to consider calling it in
for review.3
2.3. Mining and Quarrying4
2.3.1. Production
The UK has relatively diverse and large deposits of minerals that have been
historically mined. Key sectors include:
• energy minerals – coal;
• construction minerals – aggregates, brick clay and cement raw materials;
• industrial minerals – kaolin (china clay) and ball clay, silica sand, gypsum,
potash, salt, industrial carbonates, fluorspar and barytes;
• metal minerals – tungsten, gold.
The largest bulk market for non-energy minerals is construction. Industrial minerals
extracted and used in the UK range from those used primarily domestically (for
example, silica sand and limestone for glassmaking, iron and steel manufacture)
and minerals such as kaolin, ball clay and potash, which have significant
1 http://www.gov.scot/Topics/Business-Industry/Energy/onshoreoilandgas;
http://news.gov.scot/news/moratorium-called-on-fracking
2 https://www.gov.uk/government/publications/powers-for-a-purpose-towards-a-lasting-devolution-
settlement-for-wales
3 http://gov.wales/topics/planning/policy/dear-cpo-letters/unconventional-oil-and-gas/?lang+en
4 Unless noted otherwise, in this section of the chapter, mining and quarrying include coal but
exclude oil and gas extraction.

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7KH8.0LQHUDOV25% threshold is calculated by reference to the nominal value of the shares in
the company in the case of a company with share capital. If the company does not
have a share capital, this condition is met by an individual holding a right to share in
more than 25% of the entity’s capital or profits.
Control shall be defined consistently with the interpretative provisions applying to the
new public register of persons with significant control of UK companies introduced in
the Small Business, Enterprise and Employment Act 2015 (the “PSC Register”).
A person with significant control over a company is defined as an individual that
(either alone or as one of a number of joint holders of the share or right in question)
meets one of the following conditions:
1. The individual holds, directly or indirectly, more than 25% of the shares in the
company. The 25% threshold is calculated with reference to the nominal value
of the shares in the case of a company with share capital. If the company does
not have a share capital, the condition is met by an individual holding a right to
share in more than 25% of the entity’s capital or profits.
2. The individual holds, directly or indirectly, more than 25% of the voting rights in
the company. Voting rights held by the company itself are disregarded for this
purpose.
3. The individual holds the right, directly or indirectly, to appoint or remove a
majority of the board of directors of the company.
4. The individual has the right to exercise, or actually exercises, significant
influence or control over the company. (The Secretary of State for Business,
Energy and Industrial Strategy is required to issue guidance on the meaning of
‘significant influence or control’ and regard must be had to that guidance in
interpreting this condition).
5. The trustees of a trust or the members of a firm that is not a legal person meet
one or more of the other specified conditions in their capacity as such or would
do if they were individuals, and the individual has the right to exercise, or
actually exercises, significant control or influence over the activities of that trust
or firm.

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UK EITI report for 2015
Beneficial ownership disclosure
Identity of beneficial owner

Full name as it appears on national identity
card

Month and year of birth

Nationality

Country of residence

Date when beneficial interest was acquired
Service address

Method of Control
Select from:
1. The individual holds, directly or indirectly, more than 25% of the shares in
the company. The 25% threshold is calculated with reference to the nominal
value of the shares in the case of a company with share capital. If the
company does not have a share capital, the condition is met by an individual
holding a right to share in more than 25% of the entity’s capital or profits.
2. The individual holds, directly or indirectly, more than 25% of the voting
rights in the company. Voting rights held by the company itself are
disregarded for this purpose.
3. The individual holds the right, directly or indirectly, to appoint or remove a
majority of the board of directors of the company.
4. The individual has the right to exercise, or actually exercises, significant
influence or control over the company. (The Secretary of State for Business,
Energy and Industrial Strategy is required to issue guidance on the meaning
of ‘significant influence or control’ and regard must be had to that guidance in
interpreting this condition).
5. The trustees of a trust or the members of a firm that is not a legal person
meet one or more of the other specified conditions in their capacity as such or
would do if they were individuals, and the individual has the right to exercise,
or actually exercises, significant control or influence over the activities of that
trust or firm.
Politically exposed person (PEP) definition
In accordance with the decision of the UK EITI MSG, for the purposes of the UK
EITI, declarations are required in respect of PEPs who directly or indirectly
ultimately own or control more than five per cent (5%) of a company that (a) is
reporting material payments to the UK Government under the UK EITI and (b) is not
a publicly listed company, or a wholly owned subsidiary of a publicly listed company.
UK EITI has adopted the EU's definition of politically exposed person as described
in the new EU Fourth Money Laundering Directive. The term ‘politically exposed
person’ means a natural person who is or who has been entrusted with prominent
public functions and includes the following:
a) heads of State, heads of government, ministers and deputy or assistant
ministers;
b) members of parliament or of similar legislative bodies;
c) members of the governing bodies of political parties;
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UK EITI report for 2015
d) members of supreme courts, of constitutional courts or of other high-level
judicial bodies, the decisions of which are not subject to further appeal, except
in exceptional circumstances;
e) members of courts of auditors or of the boards of central banks;
f) ambassadors, chargés d’affaires and high-ranking officers in the armed forces;
g) members of the administrative, management or supervisory bodies of State-
owned enterprises;
h) directors, deputy directors and members of the board or equivalent function of
an international organisation.
No public function referred to in points (a) to (h) shall be understood as covering
middle-ranking or more junior officials.
“Family members” includes the following:
(i)
the spouse;
(ii)
any person considered as equivalent to the spouse;
(iii) the children and their spouses or persons considered as equivalent to the
spouse;
(iv) the parents.
Persons known to be “close associates” means:
(i) any natural person who is known to have joint beneficial ownership of legal
entities or legal arrangements, or any other close business relations, with a
person referred to in points (i) to (vii);
(ii) any natural person who has sole beneficial ownership of a legal entity or legal
arrangement which is known to have been set up for the benefit de facto of the
person referred to in points (i) to (vii).
The [>5%] threshold is calculated by reference to the nominal value of the shares in
the company in the case of a company with share capital. If the company does not
have a share capital, this condition is met by an individual holding a right to share in
[more than 5%] of the entity’s capital or profits.
Disclosures in relation to PEP beneficial owners reflect the actual knowledge of the
company based on the information available to the company in the ordinary course
of business, i.e. with no requirement for incremental due diligence.
PEP disclosure
Identity of PEP:
Full name as it appears on national identity card

Month and year of birth

Nationality

Country of residence

Date when beneficial interest was acquired

Service address

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UK EITI report for 2015
Political Connection
Name of public office holder

Public office position and role

Date when office was assumed

Date when office was left, if applicable

If the PEP beneficial owner is not the public office
holder, PEP beneficial owner’s connection with the
public office holder

Attestation
Select one of the following:
1. Full Attestation
“I, undersigned, for and on behalf of [company], confirm that all information provided in the above
beneficial ownership declaration is, to the best of my knowledge, accurate and reliable.”
Attestation prepared by:
[Name, Position]
Sign or tick box:

2. Qualified Attestation
“I, undersigned, for and on behalf of [company], confirm that all information provided in the above
beneficial ownership declaration is, to the best of my knowledge, accurate and reliable, subject to
the following qualifications:

Information was not received from one or more beneficial owners; and/or

One of more beneficial owners did not give satisfactory consent for the
disclosure of information; and/or

Other – please specify.”
Attestation prepared by: [Name, Position]
Sign or tick box:

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